VI. Commission Review of the Settlements

The primary purpose of this proceeding is to determine the base revenue requirements necessary for SoCalGas' natural gas distribution and SDG&E's electric and gas distribution. As noted above, the Settlements would address our core question in this proceeding by resolving virtually all of the disputed issues in the revenue requirement phase of SoCalGas and SDG&E TY 2004 Cost of Service.

On December 19, 2003, SoCalGas and SDG&E filed Motions for adoption of the settlements on Test Year 2004 revenue requirements. The Settling Parties request that the Commission: (1) adopt the Settlement Agreements; (2) authorize SoCalGas and SDG&E to modify rates for services rendered on and after January 1, 2004, consistent with the terms of the Settlement Agreement; and (3) grant such other and further relief as the Commission finds just and reasonable.

A. The SoCalGas Settlement

Pursuant to Rule 51.1(c) of the Commission's Rules of Practice and Procedure, the motion was filed by SoCalGas, ORA, TURN, UWUA, Local 483, SCGC and Greenlining (collectively the "SoCalGas Settling Parties") addressing Phase One of the above-captioned SoCalGas Cost of Service (COS) proceeding. As required by Rule 51.1(c), Attachment D to the SoCalGas Settlement is a comparison exhibit indicating the effect of the SoCalGas Settlement in relation to SoCalGas' showing and to issues ORA contested. All active parties in the SoCalGas portion of the proceeding are signatories to the SoCalGas settlement. The Settlement is reproduced as Appendix G in this decision.

The SoCalGas Settlement would resolve all issues raised by the Settling Parties regarding SoCalGas' forecast TY 2004 gas distribution revenue requirements, and 2005, 2006, and 2007 gas distribution revenue requirements, with two exceptions. The Settlement includes two unresolved issues for SoCalGas: (1) the method of recovery of fumigation-related costs and (2) the gas resource plan.

The Settlement, as filed on December 19, 2003, provides a 2004 revenue requirement in the amount of $1,457,008,000 which is $70 million less than SoCalGas' final litigation position.

1. Distribution Expense

The Settlement adopts a Distribution Expense of $132,450,000. Major reductions from SoCalGas' original request include $436,000 for freeway/franchise O&M, $998,000 for maturing workforce, and $1,500,000 for leak backlog reduction (SoCalGas will not get the funding increase, but also will leave the leak backlog at the 5 year average 8000). For underground gas storage and gas transmission expense, the Settling Parties agree to utilize the company's forecast.

2. Gas Storage and Transmission Expense

For underground gas storage and gas transmission expense, the Settling Parties agree to utilize the company's estimated test year revenue requirement.

For freeway/franchise Operating and Maintenance Expenses, the Settling Parties agree to reduce SoCalGas' request funding in Account 887 by $436,000.

3. Customer Services

The Settling Parties agree to customer service expenses to $15.6 million less than requested by SoCalGas. The largest reductions from SoCalGas' requests for Customer Services are $7.7 million related to Customer Assistance Expenses, $1.9 million related to Customer Records and Collection Expenses, and $5.1 million related to Customer Installation Expenses.

a) Customer Installation Expense

As part of the Customer Installation Expense, the Settling Parties agree that the funds will allow SoCalGas to replace tin meters at the rate proposed by SoCalGas in the proceeding of approximately 100,000 per year over five years, as well as other planned meter replacements as proposed by SoCalGas, but none of SoCalGas' request for Rockwell meter replacements.11 However, the Settlement allows SoCalGas to redirect replacement work from tin meters to Rockwell meter to the extent that any family or families of Rockwell meters fall outside of allowed accuracy tolerances during the term of this settlement.

b) Customer Records and Collection Expenses

This is a major account dealing with labor and non-labor expenses for the Customer Contact Center, branch office and authorized payment locations, customer billing, credit and collections, bill distribution, bill payment processing and meter reading supervision.

The Settlement adopts a revenue requirement that is $1,944,000 less than requested by SoCalGas, which amounts to adoption of more than half of ORA's proposed adjustments for this account as a whole. The reduction in SoCalGas' request represents a compromise with respect to all the issues as a group, not a resolution of individual issues in this account.

4. Administrative and General Expenses

In Administrative and General expenses, the Settlement reflects $29,495 million less than SoCalGas' end of hearing litigation position. There are eight accounts, with sub-parts, where SoCalGas and ORA had differences of $49.956 million at the end of litigation in Test Year 2004 estimates. Only 50% of SoCalGas' forecast for costs associated with the incentive compensation plan and spot cash awards is included in the Settlement. This represents a reduction of $10.954 million.

5. Corporate and Shared Services

6. Gas Industry Restructuring Implementation

The SoCalGas Settlement defers without prejudice for determination in a proceeding other than this one, SoCalGas request for recovery to capital costs for software development projects to implement the Gas Industry Restructuring.

7. Rate Base

The Settling Parties agree to rate base for SoCalGas of $2.3 billion. This is a reduction of $70 million from SoCalGas' request. TURN sought to decrease SoCalGas' working cash requirement (and rate base) by approximately $87 million on a variety of grounds. The Settling Parties agree to a rate base reduction of $35 million associated with working cash, and an additional $35 million reduction in capital additions, to arrive at the $70 million reduction in rate base.

8. Fumigation Related Costs

The method of recovery of fumigation related costs is one of the two issues not resolved by this settlement. In October 2002, a new Department of Transportation (DOT) regulation terminated the fumigation contractor's authorization to turn-off/turn-on gas meter service before and after performing tented fumigation jobs.13 The Settlement reflects the fumigation funding levels recommended by SoCalGas, but does not resolve whether this cost should be recovered through base rates or through a separate fee that would be charged per fumigation to fumigators or SoCalGas customers of record at locations being fumigated.

SoCalGas and SDG&E have held that only utility employees are qualified to perform gas meter turn-off/turn-on services in their service territories. They sought to recover the costs of the turn-off/turn-on of gas meter service during fumigation through general rates.14 The expense would be allocated among rate classes in the next BCAP. The Utilities argued that turning service off and on is something the utility should perform and it is safety related. They cited § 328, (b), which states "no customer should have to pay separate fees for utilizing services that protect public or customer safety."15

TURN's position was that the utilities could have "but chose not to" train fumigator employees to perform the work, and that the utilities apparently sensed a "growth opportunity."16 TURN argued that the turn-off/turn-on of gas service during fumigations is not a type of basic gas service defined by § 328 because the fumigation companies are not utility customers and tent fumigations are not utility services.17 TURN saw the roll-in of these costs as subsidizing the fumigation industry and recommended that the utilities charge the pest control company directly.18 TURN compared fumigation turn-off/turn-on with wrap and strap services on water heaters and restoring service on earthquake valves when the valve is triggered by an isolated event.19

ORA did not take issue with having the utilities perform the service and the roll-in of costs to rate base. ORA accepted SoCalGas and SDG&E's test year estimate of $3.173 million including both the number of orders and costs. It proposed a one-way balancing account for fumigation turn-offs/turn-on.20 Ratepayers would be refunded any unused funds, and any cost incurred over the maximum allowable would not be recovered from ratepayers. ORA argued for this accounting mechanism because SoCalGas has no experience with this service.21 There is not a sufficient reason to impose a one-way balancing account capping recovery if the estimate is too low yet require a refund if the estimate is too high. Nor do we want the utilities to refuse or discourage safe fumigation services because the number of calls exhausts a one-way balancing account limit. SoCalGas and SDG&E were presumably prepared to respond to all fumigation calls for a fixed estimate in rates and we are prepared to authorize that estimate for Test Year 2004 with the expectation that they will respond to all requests regardless of the forecast.

We consider the turn-off/turn-on of gas service in conjunction with fumigation to be a safety issue and therefore, § 328 is applicable. If an explosion were to occur while the fumigation is being performed, it impacts the safety of all adjacent customers; therefore, public safety is involved. On May 8, 2003, the Commission approved Resolution G-3344, which allowed SoCalGas and SDG&E to temporarily apply Z-Factor treatment to recover the cost of providing this service in its next PBR filing. The issue was to be resolved finally in this proceeding. In Resolution G-3344, we found that charging a separate fee to fumigators or customers would provide an inappropriate incentive for them to perform the turn-off/turn-on service themselves.22

We disagree with TURN's recommendation to charge the fumigator for this service, as it might compel the fumigation companies to bypass the utilities and perform the function themselves, creating a safety issue. We reject TURN's argument that the utilities see the performance of this service as a "growth opportunity." We agree with SoCalGas and SDG&E. This is not a service ratepayers will abuse if there is no extra charge - it is not likely that customers will have their homes fumigated more often if there is no extra charge for the turnoff/turn-on service. The costs associated with fumigation will be recovered through rate base.

There is no adjustment for fumigation related calls; we will use the SoCalGas estimate as forecast in its spreadsheets and as reflected in the Joint Comparison Exhibit, ORA accepted SoCalGas' calculation.23

B. The SDG&E Settlement

Pursuant to Rule 51.1(c) of the Commission's Rules of Practice and Procedure, the motion was filed by SDG&E, ORA, Greenlining, Coral, and CUE (collectively, the "SDG&E settling parties") addressing Phase One of the above-captioned SDG&E COS proceeding. As required by Rule 51.1(c), Attachment D to the SDG&E Settlement is a comparison exhibit indicating the effect of the SDG&E Settlement in relation to SDG&E's showing and to issues ORA contested. The Federal Executive Agencies (FEA) filed a late comment24 in which it supported the SDG&E settlement. The Electric Generator Alliance (EGA), another non-signatory, upon review of the settlement, filed in its comments to the SDG&E Settlement that "the settlement agreements represent a fair and reasonable compromise of the issues contested in these proceedings, and EGA supports the settlements and the associated motions."25 The Settlement is reproduced as Appendix H in this decision.

The immediate impact of Commission approval of the Settlement Agreement will reduce SDG&E's system average electric rates and slightly increase SDG&E's system average gas rates in 2004. Appendix A to the Settlement Agreement describes in summary of earnings format the numerical results of the agreements reached. However, we have made two adjustments to the SDG&E Settlement. We have disallowed the Otay Mesa Pressure Betterment Project and adjusted the San Onofre Nuclear Generating Station (SONGS) revenue to reflect the amount adopted in the Edison GRC proceeding, A.02-05-004, where the SONGS issue was litigated.

SDG&E's combined electric and gas authorized revenue requirement for 2004 will be $957,887 million. As shown in the Settlement Comparison exhibit, SDG&E's final litigation position revenue requirement was $1,029,746,000 ($815,055,000 for electricity and $214,691,000 for gas).

The Settlement Agreement provides for a 2004 revenue requirement in the amount of $965,141,000. For Miscellaneous electric revenues, the Joint Parties agree to a forecast of $37,122,000. This represents a compromise between SDG&E's and ORA's litigation positions.

The Settling Parties agreed to numerous adjustments to SDG&E's request; including reductions of $2,000,000 in Electric Distribution Operating and Maintenance (O&M) Expenses. Tree trimming expenses were reduced by $500,000, SDG&E's requested funding for New Business Construction Managers of $174,000 was reduced; and a reduction was made of $901,000 in O&M for the Sustainable Communities project. O&M expenses include Clearing Accounts, Nuclear Generation, Procurement, Gas Transmission, Distribution, Uncollectibles, Customer Services, Administrative & General, and Franchise Fees.

For SDG&E's gas transmission expense there is no difference; Settling Parties agree to utilize the company's forecast.

Non-settling parties filed responses to the settlements. UCAN filed an extensive opposition to the SDG&E Settlement. UCAN's position as reflected in Exhibit 608 was approximately $47 million lower than ORA. The City of Chula Vista also filed comments opposing the SDG&E Settlement. TURN filed an opening brief as a non-settling party for SDG&E. No other party filed in opposition to the SDG&E Settlements. On April 13, 2004, SDG&E filed a motion seeking leave to file minor errata to the SDG&E partial settlement. On April 27, 2004, UCAN filed a response to this motion, and on April 29, 2004, SDG&E filed a reply. We accept the errata, and affirm the ALJ's May 12, 2004 ruling granting SDG&E's motion.

The SDG&E Settlement would resolve all issues raised by the Settling Parties regarding SDG&E's forecast TY 2004 and 2005, 2006, and 2007 electric and gas distribution revenue requirements, with two exceptions. The Settlement includes two unresolved issues for SDG&E: (1) the method of recovery of fumigation-related costs and (2) the gas resource plan with the exception of the receipt of gas at Otay Mesa.

1. San Onofre Nuclear Generating Station (SONGS) - Electric

SDG&E owns a 20% minority-interest of the San Onofre Nuclear Generating Station (SONGS) along with two other minority-interest owners, the City of Anaheim and City of Riverside. Edison is the majority-owner and the operating agent. Beginning in 1985, the Commission has litigated the O&M and capital expenditures that are billed by Southern California Edison (SCE) to SDG&E in the SCE rate proceedings for consistency and to avoid duplicate litigation.

The Settling Parties agree that SDG&E's level of electric production expense adopted in the final revenue requirement in this proceeding should reflect SDG&E's share of the actual SONGS costs the Commission authorizes in its decision in Phase 1 of the SCE GRC. For purposes of this settlement agreement, the Settling Parties have used ORA's proposed level of nuclear expense, but agree upon the determination in the final decision in Phase 1 of the SCE GRC to serve a late-filed exhibit showing SDG&E's share of the SONGS costs the Commission authorizes in A.02-05-004. With respect to the SONGS cost that SDG&E presented in this proceeding that SCE does not directly bill to SDG&E or that were not addressed in SCE's GRC showing, the Settling Parties have agreed to use SDG&E's forecast of these costs, which total $8 million.

SDG&E filed late-filed Exhibit Number 169 on September 2, 2004 after D.04-07-022 was approved in the SCE GRC.

SDG&E recovers most of its costs for SONGS based upon the Commission's decision in Edison's A.02-05-004. In that proceeding, SDG&E made the following request:26

"In (A.02-05-004), SDG&E requests that the Commission:

· Approve SCE's forecasted SONGS costs as set forth in A.02-05-004.

· Approve $15.806 million as SDG&E's share of SONGS 2 & 3 capital additions for 2004 and authorize SDG&E to reflect this approved amount in calculating the depreciation expense and other costs associated with these capital additions in its Test Year 2004 cost of service proceeding (A.02-12-027/A.02-12-028).

· Approve $67.585 million as SDG&E's share of SONGS 2 & 3 O&M expenses for 2004 (other than refueling outage expenses) and authorize SDG&E to reflect this revenue requirement in rates effective January 1, 2004.

· Approve $12.468 million as SDG&E's share of each SONGS 2 & 3 refueling outage that occurs in 2004 and 2005 and authorize SDG&E to file annual advice letters on November 1, 2003 and November 1, 2004 to specify the number of SONGS refueling outages expected to occur during the following year and the escalated cost per outage.

· Approve $2.635 million as SDG&E's share of SONGS 1 shutdown O&M expenses for 2004 and authorize SDG&E to reflect this revenue requirement in rates effective January 1, 2004."

As a result, in D.04-07-022, the Commission identified the reasonable 2004 capital expenditures and operating and maintenance expenses for SDG&E. The Commission explained its actions as follows:27


"Since SDG&E's costs for SONGS are predicated upon its 20% ownership share, the amounts requested by SDG&E must be adjusted to reflect the corresponding 100% level of capital and O&M costs for SONGS 2 & 3 as well as the amortization period adopted in this decision. We will approve SDG&E's requests as set forth above, subject to the adjustments required to reflect SONGS-related determinations made in this decision."

Based on D.04-07-022, this decision includes $27.648 million for 2004 capital expenditures and $61.067 million for 2004 operating expenses. It should be noted that these costs were based in principle on the text of D.04-07-022, and numerically relied upon the SCE Results of Operation (RO) model for calculations of SONGS costs billed to participants by SCE. While it appears that SCE and SDG&E have an intricate system for billing of SONGS related costs pursuant to their Operating Agreement,28 the costs approved in this Decision reflect not only the deductions that the Commission made in the SCE Decision, but also the costs that SCE deducted in its model to reflect billing to the other participants. This is what ultimately determines the approved revenue requirement.

2. SONGS Costs Not In Edison's Rate Case

a) New Security Requirements

On September 19, 2003, SDG&E served new testimony in Ex. 96 that added to the non-Edison costs in the proceeding the recovery of specific new requirements imposed by the Nuclear Regulatory Commission (NRC) on April 29, 2003, which was significantly after the testimony for Edison's proceeding or this proceeding was served on parties. SDG&E seeks in Ex. 96 to recover its share of the incremental costs associated with the NRC's Order Modifying Licenses adopting new security measures.29 SDG&E sought recovery of $14.469 million, as 2004 capital expenditures and $0.76 million of O&M expenses as its 20% share of total costs.30 We will not consider the 2005 O&M costs because they are beyond the test year for this proceeding.

As a threshold question, we must determine whether we can consider these costs within the scope of this proceeding. In its opening litigation brief, in footnote 124, SDG&E details that Edison entered into an agreement with parties to its proceeding to forgo reflecting the reduced Federal tax liability associated with the Jobs and Growth Tax Relief Reconciliation Act of May 28, 2003, in exchange for also foregoing the recovery of the new costs that result from the April 2003 NRC requirements. SDG&E argues in footnote 123:


"Per D.89-01-040 (p. B-26), the costs SDG&E seeks to recover to comply with the NRC's April 29, 2003 security orders are the proper subject of update testimony. Page B-26 of D.89-01-040 permits parties to serve testimony to address `Known changes due to governmental action such as changes in tax rates, postage rates, or assessed valuation.' The NRC is a governmental entity and the new security orders issued on April 29, 2003 fall clearly within the scope of this rule."31

This authority to update is clearly intended to address the ministerial application of a change for an activity already known to be necessary, and in fact reflects better facts than were used in the original estimate. If, for example mid-way through a rate case tax rates are known to be higher or lower than were used in the initial rate filing, then either ratepayers or shareholders are protected from the effects of a bad estimate by allowing an up-date of the rate.

We find that SDG&E's position fails under this argument for two reasons: first, it relied on a procedure for general rate cases filed in conformance with the rate case processing plan that was adopted and further modified by D.89-01-040, but A.02-12-028 is not such an application. As already discussed, for SDG&E the requirement to file a general rate case for Test Year 1999 was first suspended by D.97-12-041 and it has filed under the less rigorous conditions of a "cost of service" proceeding. The second and most compelling reason is that the new NRC requirements simply are not a "known change" that can be updated, for example, by substituting 39 cents for the current 37 cents charged for postage. These security costs are a previously unknown and new requirement that was not anticipated in SDG&E's filing.

The decision in Edison's application did not decide the question of whether the April 29, 2003 order by the NRC was consistent with the rate case processing plan on September 29, 2003; Edison withdrew its July 15, 2003 motion to establish a balancing account.32 We are deciding the update question for these costs for the first time in this proceeding and we find them not to be an update within the meaning of D.89-01-040. To find totally new mandates to be merely an update could compel us to either delay major proceedings late in the schedule or to unduly rush our review of potentially significant new actions by other government bodies. We reject SDG&E's argument that these costs are includable as an update under Commission practices.

We would otherwise find that SDG&E could file a separate application to seek recovery of the new security obligations that were not anticipated and not forecast at any level of specificity in A.02-12-028. But there is an appropriate and compelling reason why we should consider the recovery of the NRC-imposed program costs now and that is our obligation to provide adequate rates for SDG&E to provide safe and reliable service. The possibility that terrorists33 could target SONGS or any other operating reactor is cause for concern. ORA in its opening litigation brief expressed support for SDG&E's recovery of its share of these costs but pointed out that the costs have not been subject to any reasonableness review34 as would occur if it had sufficient time to examine the Edison specific proposals and the NRC's subsequent approval.

We find that it is in the public's interest for us to consider these costs at this time provided we also safeguard the economic interests of ratepayers.

In its reply brief, SDG&E argued that ORA had the opportunity to review these costs, five weeks from the service of Ex. 96 and the time when the witness testified. SDG&E also argued the testimony is an allowable update and not supplemental. We disagreed above with the characterization of these costs as an update. Even though ORA did not argue that it would have needed to examine the costs with Edison, and not SDG&E, we will emphasize that we want these costs reviewed before we allow final recovery; and in the middle of litigating the entire case for both SoCalGas and SDG&E, we would not have wanted a hurried review of the costs, even had ORA tried to review them. A detailed review here would have been counter to the convention that joint costs are litigated in Edison's proceeding and not in SDG&E's. Edison may have foregone its opportunity for recovery in its test year in A.02-05-004, but any ongoing capital recovery and future O&M expenses are likely to be at issue in Edison's next proceeding. The ratepayers of either company would not have been well served by a rushed review here.

SDG&E provides details of the specific capital expenditures proposed to comply with the NRC requirements in Attachment B to Ex. 96. We will allow SDG&E, subject to refund, to include the Test Year 2004 incremental revenue requirements solely for these expenditures that are beyond the scope of capital expenditures in A.02-05-004. When the Commission has its first opportunity to review the actual program costs, and provide interested parties due process, it will be in a subsequent Edison or joint Edison-SDG&E application, where any over-collection will be refunded by SDG&E to its ratepayers. What we authorize here is a one-way balancing account. We have not reviewed these costs in detail, nor do we have in the record an indication of the NRC's approval that the proposals are adequate. We believe that making the revenue requirement subject to refund is a balance that ensures SDG&E has the revenue to fund its share of the costs as currently forecast and the ratepayers have a 2004 cap of capital expenditures $14.469 million, and $0.76 million of O&M expenses until there is a thorough review with due process.

SDG&E provides details of the specific incremental O&M expenses in Attachment B to Ex. 96. These too are specific costs of $ 0.76 million in 2004 that are incremental to costs recoverable from A.02-05-004. We will allow these incremental security costs in the test year 2004 revenue requirements and require

SDG&E to record these costs in a second balancing account,35 subject to refund, and require supporting documentation to show that the costs are solely attributed to the new security requirements. The estimates are for 43 full-time equivalent positions and related costs; this O&M balancing account may only record these costs, for up to 43 positions, after first accounting for all positions funded in A.02-05-004. As with the capital expenditures, we are granting revenues in rates now, subject to refund at the full amount as forecast, and this balancing account with a cap is a reasonable safeguard for ratepayers in exchange for SDG&E avoiding the requirement to incur these costs without rate relief until a later application could be litigated.

Before we will authorize final recovery of any of these costs, SDG&E36 must make a clear and complete showing that (1) the recorded costs are attributable solely to new security activities and investments that are required by the April 29, 2003 NRC orders; (2) the recorded costs are truly incremental, i.e., they are not included in this Phase 1 decision; (3) if any current (i.e., included in this proceeding) security activities or planned investments are supplanted by compliance with the new NRC requirements, so that costs for those activities and investments are reduced, such cost reductions are properly accounted for; (4) the costs must be incurred by SDG&E and the other plant owners, and not by taxpayers; and (5) the recorded costs are otherwise reasonable. The balancing accounts as authorized in this decision in no way reduce SDG&E's burden of proof to justify the reasonableness of recovering these costs.

b) Other Costs Not Billed by Edison

SDG&E sought recovery of $2.0 million for three items in this application of SONGS costs that are not in the Edison case.37 These costs were unopposed, except for one by UCAN, and are adopted as proposed by SDG&E; they are discussed solely to clarify and distinguish them from the security costs above and the much larger costs that we imported from A.02-05-004 in D.04-07-022.

SDG&E sought to recover costs allocated to it for the Department of Energy's decontamination and decommissioning of uranium enrichment plants. Title XI of the Energy Policy Act of 1992 created a fund for this purpose and SDG&E's 2004 share for its 20% interest in SONGS is $1.166 million. No party disputed this amount.

The second item was $0.807 million in 2004 for SDG&E's share of the cost to store spent fuel (used and no longer useful) from SONGS Unit 1. UCAN argued that 100% of the capital cost of spent fuel storage should be disallowed, because this project was part of the capital spending specifically requested in the Incremental Cost Incentive Proceeding (ICIP) and it was deferred past the ICIP period in large part as a result of ratepayer-funded decommissioning spending at SONGS 1.38 It is not clear that UCAN is targeting this $0.8 million; its comments refer to its positions in A.02-05-004 on fuel storage. We defer to A.02-05-004 for all costs in that proceeding and to the extent we are looking at unique and separate fuel storage costs here, we conclude that SDG&E is seeking current operating costs for storage and these are not the same costs that concerned UCAN in A.02-05-004. We find the $0.8 million in 2004 for SONGS Unit 1 spent fuel storage to be a reasonable test year expense.

The final cost is the $0.020 million ($20,147 to be precise) annual payment to the Department of the Navy for its share for a site easement on Camp Pendleton, where SONGS is located. This cost is reasonable and is adopted.

Finally, SDG&E requested $5 million39 in other costs, for depreciation, taxes and franchise fees, nuclear insurance, uncollectables and rate of return. These are addressed elsewhere and included in the appropriate accounts. Depreciation and return are calculated based upon inclusion of the capital additions from D.04-07-022 to SDG&E's existing plant accounts in the adopted results of operations. Insurance is addressed in administrative and general expenses and the remainder are included in the results of operations in the appropriate accounts.

3. Administrative and General (A&G) Expense

The Settling Parties agree to A&G expense of $122,307,000 ($86,387,000 for electricity and $35,920,000 for gas). The Settlement thus reflects approximately $37 million less than SDG&E's end of hearing litigation position. Only 50% of SDG&E's forecast for costs associated with the incentive compensation plan, the long-term incentive compensation plan and spot cash awards is included in the Settlement. This represents a reduction of $18.086 million.

The Settlement also reflects a decrease in Directors and Officers' liability insurance of $1.055 million, a $0.4 million decrease in Regional Public Affairs funding, a 50% decrease in funding for supplemental pensions (for a reduction of $277,000) and reductions in other benefits as described below. For Medical, Dental and Vision benefits, SDG&E's updated estimates are adopted in the Settlement, subject to a $2.2 million generic adjustment for reduced workforce projections. Other benefits are subject to a $1.74 million adjustment to reflect parties' concerns regarding the appropriateness of including in rates certain benefits such as executive life insurance. The Settlement therefore reflects litigation risks, but also protects against some of SDG&E's major concerns, such as pension contribution requirements and medical cost increase. SDG&E will have a two way balancing account that allows SDG&E to recover minimum-required pension contributions.40

4. Fumigation Related Costs

As we have determined previously in the discussion regarding SoCalGas fumigation related costs, we consider the turn-off/turn-on of gas service in conjunction with fumigation to be a safety issue and therefore, § 328 (b), which states "no customer should have to pay separate fees for utilizing services that protect public or customer safety" is applicable. As we previously stated, we expect SoCalGas and SDG&E to respond to all fumigation calls. We adopt SDG&E's estimates for fumigation related expense which will be recovered through base rates.

5. Electric Distribution

The Settling Parties agree to Electric Distribution expense of $79,319,000. Reductions were made for several items, including: growth-related reduction to tree-trimming expense; elimination of SDG&E's requested funding for New Business Construction Managers; and a reduction in O&M expense for SDG&E's Sustainable Communities project.

a) Vegetation Management

D.98-12-038 (83 CPUC 2d, 363) established a one-way balancing account (under-spending is refunded but over-spending is absorbed by SDG&E) in part because it was an unresolved item. During the proceeding, SDG&E proposed to end the balancing account and argued that it has made a myriad of improvements, whereas, ORA proposed retaining the balancing account.

The Settling Parties agree that no balancing account will be utilized for tree trimming or vegetation management expenses, and adopt SDG&E's forecast in Account 593, and in sub-account 593.2, less a reduction in that sub-account of $500,000 (an adjustment for growth related trims).

By Resolution E-3824, SDG&E and other utilities were directed to respond to then Governor Davis' March 7, 2003 Emergency Proclamation to deal with the impacts of the pine bark beetle infestation. SDG&E cites this as an example of how even after the company filed its application and Ex. 27, "SDG&E anticipates the level of these "risk" trees to be far greater than originally determined, exceeding $3 million in 2003 alone."41 Resolution E-3824 does allow SDG&E to utilize a catastrophic event memorandum account for Bark Beetles, so there is a vehicle for recovering all reasonable actual costs.

Vegetation management is a major expense; it is a major expense subject to significant potential crises: fire, flood, pests and drought. Account 593 is a reasonable compromise of the parties' litigation positions, but we are reluctant to eliminate the balancing account treatment for such a volatile program. We adopt the figures proposed in the settlement, subject to the continued usage of the one-way balancing account, for vegetation management in Test Year 2004.

    b) Sustainable Community Energy Systems

The Sustainable Community Energy Systems is a proposed SDG&E project that would provide funds for the engineering, design, materials, installation, testing, and maintenance of community-based energy strategies, state-of-the-art generation and storage technologies, and advances control devices.

The Settling Parties agree to a reduction in SDG&E's forecast of Account 594 costs of $901,000 in O&M for the Sustainable Communities Project. This O&M reduction is consistent with the Settling Parties recommendation to fund $4.3 million of the SDG&E requested capital for the Sustainable Communities Project.

UCAN expressed concern at the size of the funding request in light of the limited details of the program. It pointed to the lack of any process for "stakeholder" input into the SDG&E program, and argued that SDG&E should explore options for external management by an entity such as the San Diego Regional Energy Office.

We share UCAN's concerns with the current proposal, but find the primary objectives of the program admirable. They include ensuring environmentally sensitive energy solutions, stimulating the distributed generation industry, supporting and partnering with interested developers, and promoting energy and demand savings.

We adopt the proposal in the settlement, but encourage SDG&E in future cost of service or general rate cast proceedings to pursue the refinement of its proposal and to present future proposals in greater detail - the projects that will be pursued, detailed criteria that the company would consistently apply in choosing and serving projects. While we are grateful for SDG&E's interest in pursuing its stated goals, in the future, we need greater assurance that the efforts will serve the interests of all SDG&E ratepayers, and of the broader San Diego community.

6. Otay Mesa Pressure Betterment Project

Although the Settlement left SDG&E's gas resource plan unresolved, it committed to placing the Otay Mesa Pressure Betterment Project in service by December 31, 2004, subject to matters beyond SDG&E's control. In this decision, the Commission disallows any revenue associated with this project.

The Otay Mesa Pressure Betterment Project 2466 would modify SDG&E's gas transmission system to allow multi-directional flow through the Otay Mesa Metering Station (Otay Mesa);42 that means gas could alternatively flow northward from the Mexico and U.S. border into the SDG&E system interconnecting with TGN.43 SDG&E proposed to add $11.531 million to rate base ($3.763 million in 2003 capital expenditures and $ 7.768 million in 200444). ORA did not take issue with the concept of the project, but it did object that until SDG&E has a contract with a gas supplier and approvals from both the Federal Energy Regulatory Commission and the U.S. Department of Energy, the project should not be included in rate base.45

SDG&E responded in its rebuttal testimony, Ex. 93, that the project was delayed, and the costs shifted between 2003 and 2004 still are the same total, and that the rate base addition should be weighted to reflect a July 1 in-service date in 2004. SDG&E did not clarify in Ex. 29, 55, or 93 that TGN is Transportadora de Gas Natural, which is an affiliated company, owned by SDG&E's parent Sempra Energy.46 TGN is the interconnecting company with SDG&E on the Mexico-U.S. border.

In Ex. 55, supplemental testimony served on June 16, 2003, in response to the Scoping Memo, SDG&E explained the role of the Otay Mesa project as follows:


"Although SDG&E can meet its long-term demand growth with the resource plan presented (in Ex. 55), there may be a need for additional infrastructure to accept new supply into the SDG&E system. In the long term, new gas resources may become available from an LNG plant sited in Baja, California, Mexico. SDG&E could use the reliability receipt point at Otay Mesa discussed in (Ex. 29) to take new supplies into the SDG&E system. In the event that this potential supply source develops, SDG&E will need to modify and expand its gas transmission system..." by a forecast of a further $232 million.47 (Emphasis added.)

Additionally, ORA proposed an Over Budgeting Factor adjustment that appears to be derived in the same fashion as the Budget Reduction Factor for gas distribution projects. ORA did a mathematical exercise to average the 1997 - 2002 six-year variance in budget to actual after dropping the highest and lowest. The range is 39.6% to 1.6% and even then the range is from 18.9% to 4.1% for the remaining four data points for an average of 9.7%.48 We do not know from ORA's exhibit, for example, whether every project was always under budget or whether this is a net figure. We also do not know whether managers were over-estimating costs in order to avoid overruns, in essence, looking good by beating an easy target. SDG&E's last rate setting procedure for capital expenditures was for a 1997 test year, so none of the intervening years' budgets relied on by ORA were prepared to withstand the scrutiny of a rate proceeding at the Commission.

The Settlement explicitly includes the Otay Mesa Pressure Betterment Project in capital additions authorized in rate base, within the total revenue requirement amount authorized by the Settlement.

On September 2, 2004, the Commission signed D.04-09-022 which authorized SoCalGas and SDG&E to establish receipt points, as needed, at Otay Mesa, Salt Works Station, Center Road Station, or at other receipt points that may be needed to access regasified Liquified Natural Gas (LNG). SDG&E and SoCalGas were authorized to establish the Otay Mesa receipt point as a joint receipt point into both of their systems, and the interim transportation rate for a shipper delivering gas through Otay Mesa shall consist of the shipper's transportation rate on its local utility, i.e., either the applicable SDG&E or SoCalGas tariff rate.

It is presumed that LNG suppliers will pay the actual system infrastructure costs associated with their projects. Decision 04-09-022 allows LNG suppliers to make application to the Commission to roll costs of system enhancements required for LNG transportation into rate base after the project is complete.

We decline to adopt the Otay Mesa Pressure Betterment Project as part of the capital additions in the Settlement at this time.

7. Gain on Sale of Blythe Property

In 2001, SDG&E sold property for a before tax gain of $22 million that at one time had been accounted for in Plant Held for Future Use, which is a rate base account. This land was acquired in 1975 for the Sundesert Nuclear Generating Station, a facility that was never constructed. There is a long history of the proposed plant, its subsequent abandonment and the ratemaking treatment for many of its costs. Some site-related costs were amortized (recovered) in rates and the balance was in rate base for Future Use until 1984 when a portion of the remaining balance was also amortized and a residual amount, $19.5 million, was removed from rate base. ORA summarized this as "ratepayers have paid: (1) the $45 million of non-site-related costs pursuant to D.90405, (2) the $25.5 million of site-related costs amortized pursuant to D.84-04-041, and (3) a return on a ratebase of $45 million for the period 1979-1984."49 ORA proposed that the gain should be re-allocated (more to ratepayers) and amortized as Miscellaneous Revenues over five-years. ORA re-weighted the allocation based on what it termed "risk exposure." (Ex. 300, p. 2-4.)

SDG&E sold the property in 2001 and allocated the gain between ratepayers and shareholders in proportion to the time the property was in rate base (June 1979 to April 1984) and the time that it was not (April 1984 to November 2001). SDG&E recorded the ratepayer share, as calculated by its method, in its Transition Cost Balancing Account.50 SDG&E cited D.83-12-065 as apposite; it dealt with a property that was a potential power plant site and the Commission allocated a subsequent gain on a shared basis of the time the property was included and then excluded from rate base.51

The Settlement Agreement represents a compromise between SDG&E's and ORA's litigation positions regarding the allocation of gain on sale from the Blythe Sundesert site, rather than an agreement to either party's position. The Commission has recently opened Order Instituting Rulemaking 04-09-003 to consider policies and guidelines regarding the allocation of gains from sales. This Settlement Agreement, as with all settlements, is not binding precedent for any future proceeding.

C. The Greenlining Institute and SoCalGas and SDG&E Side-Settlement Agreement

SoCalGas and SDG&E included in the partial settlements an additional agreement with Greenlining addressing Workforce Diversity, Supplier Diversity, and Philanthropy.52 Greenlining and the applicants are the only parties to the agreements. The agreements between the utilities and Greenlining make four commitments on work force diversity, supplier diversity, philanthropy and annual meetings. Appendix I to this decision incorporates the Greenlining/Sempra Settlement Agreement.

        i. Workforce Diversity

Under the terms of the proposed settlement, SoCalGas and SDG&E would provide to Greenlining workforce diversity data in the same format as provided to Fortune Magazine for its annual diversity survey, unless the Commission mandates a similar format for reporting to the Commission. SoCalGas and SDG&E would make "their very best good faith efforts to be in the top ten `Best Companies for Minorities'" as measured by Fortune Magazine and to be a leader among California Utilities.

        ii. Supplier Diversity

Greenlining wanted 25% of SoCalGas and SDG&E's suppliers to be minority businesses. SoCalGas and SDG&E made no specific commitment in the proposed settlements to Greenlining other than to "continue to discuss the viability of this objective" and to comply with the existing obligations of General Order (GO) 156.53

        iii. Philanthropy

Greenlining proposed in testimony54 that SoCalGas and SDG&E should be ordered by the Commission to make philanthropic contributions equal to either the compensation of the "top ten executives" or 2% of pre-tax earnings, and further, 80% of the contributions should be "allocated to the needy." Under the Settlement Agreement, the Utilities reaffirm their commitment to improve upon their outreach efforts to racial and ethnic minority groups, including low income and underserved communities and to improve upon philanthropic stewardship within each utilities' communities. Additionally, Sempra agrees to provide Greenlining with a detailed reporting of philanthropy with a description of each relevant organization and the total charitable contribution amounts.

        iv. Annual Meetings

SoCalGas and SDG&E committed in the proposed settlement with Greenlining that the chief executive officer of both companies "and/or" the president, and Sempra's senior vice president of human resources will attend an annual meeting with Greenlining to discuss workforce diversity, supplier diversity and philanthropy.

        v. Discussion

We applaud the companies' commitment to improve workforce diversity, supplier diversity and philanthropy. In D.04-07-022, SCE's GRC, with respect to philanthropy, we acknowledged that the Commission has no jurisdiction to order changes to a utilities giving practices and found philanthropy generally to be beyond the scope of the Commission's ratemaking authority.55 We affirm the determinations made in the Edison GRC again here.

Any contributions for any social, political or corporate image-enhancement purposes are made with "shareholder money," that is the earnings that are discretionarily available to the companies to pay dividends or use for other non-utility investments. The only commitment of shareholder earnings enforced by the Commission is the overarching requirement that the shareholders maintain sufficient invested capital to sustain the authorized capital structure of the company to finance its used and useful plant and equipment necessary to serve the ratepayers. We have no authority to enforce ratepayer funding of philanthropy and reject the use of ratepayer funds for philanthropic purposes to eliminate ratepayer funding of donations for any purpose no matter how socially worthwhile.

However, unlike in the Edison GRC proceeding, here the Settlement Agreement does not ask the Commission to link executive compensation with philanthropy. As such, we find no reason why we cannot endorse the settlement as agreed upon by Sempra and Greenlining56. We take this opportunity to commend the companies for working to improve in areas over which this Commission has no jurisdiction through partnerships and collaboration with groups and organizations. With that understanding, we endorse the Sempra/Greenlining Agreement as a Side Settlement Agreement, separate from the SoCalGas and SDG&E Settlement. We include it in Appendix I to this decision.

11 SoCalGas has already replaced all 18,000 tin meters located under structures in its service territory (Ex. 7, p. 32). The proposal here would provide for replacement over five years almost all remaining tin meters (500,000 of the remaining 542,000 tin meters).

12 This is subject to one exception: if the minimum-required contribution in any year exceeds the estimate for that year that SoCalGas provided in its testimony, shareholders will have to pay 20% of the excess.

13 Code of Federal Regulations Title 49, Part 192, Subpart N-Operator Qualifications.

14 Sempra reply brief, pp. 37-38.

15 Code § 328(b).

16 TURN reply brief, p. 12.

17 TURN Reply Brief, p. 13.

18 TURN opening brief, p. 62.

19 TURN opening brief, p. 63.

20 ORA opening brief, p. 73.

21 Id.

22 Resolution G-3344, Finding of Fact 9.

23 Ex. 149, SoCalGas Joint Comparison Exhibit, p. 75.

24 On January 30, 2004, FEA filed a Motion to file late-filed comments on the SDG&E partial settlement. Its comments were limited to indicating its decision to join the settlement.

25 On January 20, 2004, Electric Generation Association filed Comments to the Proposed Settlement at p. 1.

26 D.04-07-022, mimeo., p. 60.

27 D.04-07-022, mimeo., p. 61.

28 The owners of SONGS have various contractual overhead rates that SCE uses to apply to the labor and non-labor elements of SONGS related costs. These rates are detained in the "SONGS Overheads based on the Second Amended San Onofre Operating Agreement."

29 See Ex. 96, Attachment A is the entire April 29, 2003 NRC Order and cover memo entitled "Issuance of Order Requiring Compliance With Revised Design basis treat for Operating Power Reactors."

30 Ex. 96, Table MRO-1 and MRO-2.

31 Sempra opening litigation brief, p. 249 (electronic version) p. 245 (mimeo.).

32 Sempra opening brief, Footnote 124. Further, we may take judicial notice of the motion and its withdrawal in A.02-05-004.

33 The NRC Order (Ex. 96, Att. A, p. 2) refers to "the current threat environment" and the "events of September 11, 2001." We see no reason to be coy in our decision about why we will make an exception to consider these costs at this late stage of the proceeding.

34 ORA opening litigation brief, p. 189.

35 Balancing accounts have an associated expectation of recovery. They are accounts that have been pre-authorized by the Commission, and it is the recorded amounts - and not the creation of the accounts themselves - that the Commission reviews for reasonableness. Memorandum accounts, in contrast, are accounts in which the utilities book amounts for tracking purposes. While the utilities may later ask for recovery of the amounts in those accounts, their recovery is not a given. In this instance we approve the program, but the costs are subject to further review, so a balancing account is the appropriate mechanism.

36 As with most other SONGS costs, this review may be in an Edison proceeding, except for any costs unique to SDG&E that should be addressed in SDG&E's next appropriate rate case.

37 All three items are described in Ex. 38 and Ex. 38-E, pp. MRO-5 through MRO-6.

38 Opening brief - UCAN, p. 300.

39 Ex. 38 and Ex. 38-E.

40 This is subject to one exception: if the minimum-required contribution in any year exceeds the estimate for that year that SDG&E provided in its testimony, shareholders will have to pay 20% of the excess.

41 Ex. 75, p. DLG-45.

42 This gas transmission system should be distinguished from the Otay Mesa generation project, which this Commission recently addressed in D.04-06-011, in R.01-10-024. See decision mimeo., p. 53, ff.

43 Ex. 29, p. MDM-20

44 Ex. 93, p. MDM-3.

45 Ex. 302, p. 23-4.

46 See: Section A: Organizational Structure, Chart B-2, 2002 Annual Affiliate Transaction Report, SDG&E, transmittal dated April 29, 2003 shows that Sempra owns 67% of Transportadora de Gas Natural de Baja California. This report is filed annual with the Energy Division in compliance with D.93-02-019.

47 Ex. 55, pp. DMB-4 and DMB-5.

48 Ex. 302, p. 23-3.

49 Ex. 300, pp. 2-3 and 2-3; and ORA's opening litigation brief, pp. 258-260.

50 Sempra opening litigation brief, pp. 315-318, and Ex. 104.

51 Ex. 104, p. LS-1 and fn. 1.

52 Attachment C to both proposed Settlement Agreements.

53 GO 156: Rules Governing the Development of Programs to Increase Participation of Women, Minority and Disabled Veteran Business Enterprises in Procurement of Contracts from Utilities as Required by Pub. Util. Code §§ 8282 - 8286.

54 Exhibit 900, Updated Testimony of John C. Gamboa, pp. 11-12.

55 See the assigned ALJ's Ruling Denying the Motion of The Greenlining Institute and Latino Issues Forum to Compel Responses to Outstanding Data Requests, dated July 18, 2003. Ruling: "3. Shareholder financed philanthropy is not within the scope of these proceedings."

56 Appendix G of this decision incorporates the Sempra/Greenlining Settlement Agreement.

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