3. Discussion

We discuss the issues in the same order presented in the OIR:

5. CDWR Revenue Requirement

6. Electric Utility Issues

7. Gas Utility Issues

8. Incentive Mechanisms

9. Income Taxes

We conclude by discussing limited other issues raised by parties.

3.1. CDWR Revenue Requirement

CDWR procured electricity on behalf of California's electric utilities during the energy crisis in 2000 and 2001 when utilities were unable to do so themselves. CDWR issued in excess of $10 billion in bonds to finance those purchases. A series of statutes, decisions and agreements now govern recovery of CDWR's costs from utilities and ratepayers of utilities under our jurisdiction.³ A portion of the Settlement (estimated to be $425 million in nominal dollars) will accrue to the benefit of CDWR, and distribution of that Settlement consideration to ratepayers of utilities under our jurisdiction is before us.

Our initial proposal was to continue to use already adopted procedures for treatment of CDWR's revenue requirement, including any reductions from El Paso consideration. (OIR, mimeo., page 10.) Parties make several recommendations on ratemaking treatment. After careful consideration, we are not persuaded to adopt any changes for the reasons explained below.

PG&E and SCE propose that we use the percentages that result from the methodology adopted for allocation of CDWR's statewide revenue requirement in effect for the 2000 and 2001 period, since the settlement essentially addresses allegations and claims arising from activities during this period.⁴ PG&E recommends incorporating these results into the CDWR revenue requirement beginning immediately with the pending CDWR revenue requirement, with incorporations into future CDWR revenue requirements as those benefits are received. SDG&E/SoCalGas propose that the allocation to utilities be determined in the 2001-02 CDWR true-up proceeding using an allocation of Settlement proceeds based on the theory of damages occurring in the 15-month period from March 1, 2000 through May 31, 2001.

We agree with Bower & French, TURN, and CDWR, however, that the allocation percentages should not necessarily remain fixed based on those in effect during the 2000-01 period. Rather, the allocations should change along with changes to the allocation of the CDWR revenue requirement over time to the extent changes are determined reasonable. If no changes are found reasonable, the allocation will remain fixed. As TURN correctly asserts, the refunds should be treated as a reduction in revenue requirement allocated based on the principles in place at the time of the refund without seeking to perform any sort of "true-up" of the allocation in place at the time the overcharges occurred. A "true-up" would add unnecessary and unreasonable complexity, and conflict with updated allocations, if any. Our adopted method is simpler, and consistent with our preference for a minimalist approach. ⁵

Electric Classes recommend that CDWR Settlement consideration be used to retire California state bonds that were issued to cover CDWR's short-term power purchases in 2001. Electric Classes say they prefer bond retirements due to a concern whether both bundled and direct access (DA) customers will benefit equally from reductions in CDWR's revenue requirement due to the complex methodology adopted by the Commission in D.02-11-022 for calculating the DA Cost Responsibility Surcharge (DA CRS). Electric Classes also argue that bond retirement is the most appropriate use of Settlement proceeds since CDWR's El Paso-related damages are attributable mostly to inflated wholesale spot prices from January through June 2001, and are the same costs that the state is recovering through the bonds. The only exception is the $125 million reduction in El Paso long-term contract costs under the Settlement that, according to Electric Classes, should flow through CDWR's long-term contract revenue requirement. Finally, independent of the bond issue, Electric Classes observe that if El Paso refunds are paid out over a full 20 years, there is some chance that refunds will be received after all CDWR obligations have been paid. In this case, Electric Classes recommend that CDWR's portion of the refund flow through to electric utilities with an allocation determined by the Commission at that time.

We decline to modify existing agreements for the reasons stated in CDWR's memorandum submitted at the time of reply comments. As CDWR says, the Allocation Agreement among settling parties governs the consideration to be received under the Settlement, and our Rate Agreement with CDWR governs the Commission's establishment of Bond Charges and Power Charges. The Allocation Agreement is not before this Commission, and we are not persuaded that we should consider amendments to the Rate Agreement.

Moreover, it is beyond the scope of this proceeding to determine whether or not CDWR should retire its bonds. Nonetheless, CDWR will reduce its revenue requirement (either through bond charges or power charges, or some combination of both) by the amount of the El Paso consideration, as CDWR has committed to do in the Settlement. The Commission will then implement the pass through to retail customers of CDWR's reduction in revenue requirement as part of our periodic proceedings to implement revisions to the CDWR revenue requirement.

Finally, TURN recommends that continuous DA customers not receive any portion of the CDWR refunds because, according to TURN, continuous DA customers do not pay the CDWR Power Charge. We agree. Continuous DA customers (e.g., continuous before and after February 1, 2001) were not assessed CDWR bond or power charges. (D.02-11-022.) As a result, they are not due any portion of the El Paso consideration payable to CDWR which we would otherwise pass through to ratepayers.

3.2. Electric Utility Issues

3.2.1. ERRA for SCE and SDG&E

Both SCE and SDG&E (electric operations) have an Energy Resource Recovery Account (ERRA) for procurement costs. As proposed in the OIR, Settlement revenues would be credited to the ERRA to expeditiously reflect Settlement payments as a reduction in procurement costs. (OIR, mimeo., page 12.)

SCE and TURN agree with our proposed treatment. No party disagrees with this approach for SCE. We adopt this method for SCE.

SDG&E also agrees in principle but recommends a variation, which we adopt for SDG&E. SDG&E recommends that the Commission first apply 70% of SDG&E's share of these settlement revenues to the Assembly Bill (AB) 265 subaccount of SDG&E's Transition Cost Balancing Account (TCBA).⁶ This would be for the purpose of focusing the reduction on the AB 265⁷ undercollection. SDG&E proposes that the remaining 30% of SDG&E's share be allocated to the large customer subaccount of the ERRA (ABX1 43). Upon payment in full of the undercollection in SDG&E's AB 265 subaccount, SDG&E says that the balance of all such settlement revenues would then be applied to SDG&E's ERRA as proposed in the OIR.

In support, SDG&E says the Commission denied SDG&E's request to establish a surcharge to recover the AB 265 undercollection and instead instructed SDG&E to eliminate the undercollection by viable options other than a rate increase, citing D.02-12-064. In compliance, SDG&E states that it filed an advice letter (AL 1469-E) outlining a plan to eliminate the undercollection without a rate increase. As part of this plan, SDG&E says it included a proposal to transfer the overcollections in certain balancing accounts to reduce the AB 265 undercollection. In addition, SDG&E says AL 1469-E (approved by the Commission on February 25, 2003) stated that SDG&E would continue to seek opportunities to apply refunds due ratepayers in both FERC and Commission proceedings via a reduction in the AB 265 undercollection.⁸

Consistent with this direction, we have approved several SDG&E proposals to utilize overcollections and refunds from other regulatory accounts to apply toward the AB 265 undercollection. For example, we granted SDG&E's request to proportionately apply 70% of the energy overpayment refunds from CDWR toward reducing the AB 265 undercollection. (Resolution E-3813, issued June 19, 2003.) We approved SDG&E's request to transfer a $21 million refund from the Transmission Revenue Balancing Account Adjustment to the TCBA, where it can be proportionately applied toward the AB 265 undercollection. (AL 1503-E, July 10, 2003.) We also granted SDG&E's request to transfer 2002 year-end overcollections in the Tree Trimming Balancing Account and the Rate Reduction Bond Memorandum Account to directly reduce the AB 265 undercollection. (Resolution E-3798, January 30, 2003.)

We agree with SDG&E that crediting the Settlement revenues to the TCBA first in the manner proposed by SDG&E is consistent with the goal of eliminating SDG&E's AB 265 undercollection. SDG&E's recommendation is also consistent with the minimalist approach recommended in the OIR, utilizes the utility's existing accounting mechanisms to the fullest extent possible, and provides a better alternative to equitably account for the settlement consideration allocated to SDG&E's electric customers.

Only Bower & French disagree, contending that SDG&E remains a co-defendant in class action litigation against El Paso and may be found jointly and severally liable for higher prices paid by ratepayers. Bower & French argue that SDG&E "should not be allowed to hijack any part of the settlement proceeds." (Reply Comments, page 3.)

We are not persuaded that allocating the proceeds as recommended by SDG&E "hijacks" any part of the settlement. The El Paso consideration received by SDG&E for its electric ratepayers will be credited against costs that would otherwise be paid by those ratepayers in the form of higher rates.⁹ Bower & French fail to explain how the adopted allocation would hinder a court from ordering any relief it believes necessary. Similarly, the adopted allocation does not prevent the Commission from ordering any other future equitable allocations or ratemaking treatment, if and as necessary, based on any court action, or other needs identified and decided by the Commission. As a result, SDG&E's proposed allocation meets previously stated Commission objectives, and we adopt it.

3.2.2. PG&E

We proposed in the OIR that PG&E place El Paso Settlement proceeds into an interest bearing memorandum account until two matters are resolved: (1) PG&E's emergence from bankruptcy (Case No. 01-30928-DM in United States Bankruptcy Court for the Northern District of California, with the ratemaking implications to be decided by the Commission in Investigation (I.) 02-04-026), and (2) the pending phase of the rate stabilization proceeding wherein we will "determine the extent and disposition of stranded costs left unrecovered" (D.02-01-001 granting rehearing of D.01-03-082 in Application (A.) 00-11-038 et al., mimeo., page 25). As proposed, the memorandum account balance would be used as a credit or offset to previously unrecovered costs ultimately to be paid by ratepayers. (OIR, mimeo., pages 12-14.) We adopt this approach with further explanation below.

PG&E essentially agrees with this approach, pointing out that the proposed bankruptcy Settlement Agreement (SA) between the Commission staff and PG&E establishes a Regulatory Asset to be amortized over nine years beginning January 1, 2004. PG&E also notes that the proposed SA specifically provides net after-tax consideration from the El Paso Settlement is to be used to reduce the outstanding balance of the Regulatory Asset dollar for dollar. PG&E adds, however, that once the Regulatory Asset is fully amortized, further benefits of the El Paso Settlement, if any, should be given to ratepayers through the authorized electric balancing account(s) in effect at that time.

We cannot decide issues here that concern the proposed bankruptcy SA pending in another proceeding. For this reason, we require that PG&E establish an interest bearing memorandum account where it shall place the proceeds of the El Paso Settlement consideration to be held for PG&E's electric customers consistent with our initial proposal. We further require that PG&E credit these proceeds to benefit its electric ratepayers for costs its ratepayers will otherwise have to pay once determined in either the PG&E bankruptcy proceeding (I.02-04-026) or the rate stabilization proceeding (A.00-11-038 et al.).

Electric Classes are concerned that this approach will unacceptably delay the return of Settlement money to PG&E ratepayers. Electric Classes recommend that the Commission return El Paso proceeds to ratepayers once either of the proceedings is resolved and a final determination is made that PG&E ratepayer obligations for past costs exceed expected Settlement proceeds. Further, Electric Classes recommend that if both the bankruptcy and the rate stabilization proceedings remain unresolved more than nine months after the effective date of the Settlement, the Commission flow through the El Paso refunds directly to ratepayers without additional delay as an equal percentage reduction in the rate surcharges implemented in June 2001. Any discrepancies between this distribution and the allocation the Commission ultimately adopts in conjunction with the final resolution of the bankruptcy can be trued-up, according to Electric Classes, in the allocation of subsequent El Paso refunds after the bankruptcy is resolved.

We decline to adopt the recommendation of Electric Classes. Through application of the memorandum account, we ensure that PG&E rates will be reduced below what they would otherwise be without the El Paso consideration, but we must do so in a coordinated process that properly treats many complex interrelated matters. That is best done through the bankruptcy or rate stabilization proceedings (I.02-04-026 and A.00-11-038 et al.) along with the use of subsequent electric balancing account(s), if required. Once we determine the costs PG&E is entitled to recover, we will be able to ascertain the best way to credit the El Paso consideration to these costs so that it maximizes the benefits to PG&E ratepayers. Moreover, we are committed to resolving the bankruptcy and rate stabilization proceedings as soon as reasonably possible, and expect to do so before receipt of money under the MSA, to the extent feasible.

If El Paso elects the prepayment option, the adopted approach will benefit ratepayers as soon as reasonably possible with the least additional complexity. If the El Paso consideration is paid over 20 years, we will ensure through the appropriate proceeding(s) that a mechanism is adopted to distribute the remainder of the proceeds, as necessary and appropriate.

3.2.3. Direct Access Customers

3.2.3.1. Background and Proposal

The Settlement addresses the damages to ratepayers from extremely high natural gas prices, which also contributed to extremely high electric prices, for the 15 months from March 1, 2000 through May 31, 2001. During this period, a number of customers (and a portion of utilities' system load) did not purchase electricity from utilities but were served by several alternative energy service providers. These customers are called DA customers, and they received a credit on their bill for the utility's wholesale procurement program cost "savings." These savings were the utility's avoided costs (avoided because the utility did not purchase power to serve these customers). The savings were therefore subtracted from the bill that was otherwise applicable under the utilities' tariffs for full-service customers.

For SCE, the DA CRS Tracking Account (as more fully described in SCE's tariff) tracks the difference between: (1) recorded DA CRS Revenues, and (2) authorized DA CRS Obligations. (D.02-11-022 and D.02-12-045.) The authorized DA CRS-related Obligations include the CDWR Bond Charge, the CDWR Power Charge, ongoing Competition Transition Charges (CTC), and its Historical Procurement Charge. (D.02-11-022.)

SDG&E's tariff description is slightly different. The purpose of SDG&E's DA CRS Memorandum Account¹⁰ is to track the shortfall in CDWR Power Charge payments and CTC resulting from the establishment of the interim 2.7 cent/kWh DA CRS rate cap on applicable DA customers pursuant to Commission D.02-11-022 and D.02-12-045. To the extent DA obligations for the sum of the DWR Bond Charge, DWR Power Charge and CTC are not fully recovered from the 2.7 cent/kWh rate cap, the DA CRS Memorandum Account tracks the Power Charge and CTC under-collections. Any shortfall resulting from the DWR Bond Charge is recorded in a separate Bond Charge Balancing Account.

To the extent that the DA customers of the utilities must help pay for the utilities' previously unrecovered costs, the DA customers, just like the full-service customers, should receive as a credit or offset a fair share of the consideration received by the California electric utilities under the Settlement. Therefore, we proposed in the OIR that, for SCE and SDG&E, the proceeds be allocated when paid under the Settlement to the ERRA for full service customers, and the DA CRS tracking or memorandum account for DA customers, based on the relative percentage of full-service and DA to total kWh system deliveries in the preceding 12 months prior to their first receipt of consideration under the MSA. For PG&E, we proposed that the El Paso consideration be placed in a memorandum account for the future benefit of PG&E's ratepayers once the Commission determines the extent to which the full-service ratepayers and DA customers will pay PG&E's previously unrecovered costs. (OIR, mimeo., pages 14-15.)

3.2.3.2. Factual Issues

All parties commenting on this issue agree that use of the DA CRS accounts is the appropriate accounting mechanism for DA customers' share of any refund, but that the extent to which DA customers should share in any refund involves factual issues that may differ among utilities. Other than allocations (which we address below), parties do not convincingly identify any factual issues that would require continued examination in future proceedings. As a result, we decline to adopt a rule that contemplates continued litigation of these matters. We adopt the initial proposal for SCE and SDG&E (with the portion to full service customers split as described above 70/30). We adopt an interest bearing memorandum account for PG&E.

3.2.3.3. Allocation Based On First Receipt

SCE supports the proposal as made in the OIR to base the allocation on the relative percentage of full-service and DA load to total system deliveries in the preceding 12 months prior to their first receipt of consideration under the MSA. SDG&E, Electric Classes and TURN, however, contend that migration may occur between bundled and DA customers, and the percentage allocation should be updated with each receipt of consideration under the MSA. We are not persuaded to perform constant updates.

As SCE says, the purpose of the MSA was to reimburse electric customers for damages resulting from El Paso's behavior when the damages accrued. A reallocation at the time of each refund would be a true-up based on current DA load, and would conflict with the original intent. The proposal in the OIR comes closest to compensating those who were damaged. Moreover, it is a stable and simple method, and is consistent with our preference for a minimalist approach.

3.3. Gas Utility Issues

3.3.1. PGA

Each natural gas utility has a Purchased Gas Account (PGA). The PGA records costs (associated with gas purchased for the utility's Gas Supply Portfolio-i.e., the inventories of gas purchased for resale) and revenues (from the sale of that gas).

We proposed in the OIR that Settlement revenues attributable to core gas customers be credited to the PGA in order to expeditiously reflect the value of the Settlement as a reduction to core gas procurement costs. (OIR, mimeo., page 16.) All parties essentially agree with this approach, which we adopt with slight modification.

PG&E proposes that "up-front" cash be provided to core aggregation and former core subscription customers. For the reasons explained below, we adopt PG&E's "up-front" payment approach (modified to base payments on a net present value) for PG&E, SDG&E, and SoCalGas. As a result, we similarly adopt PG&E's proposal that the first payment under the MSA that would otherwise be recorded to each utility's PGA be recorded net of the limited amounts allocated up-front to some few customers.

Southwest proposes another variation based on its own accounts, which we adopt for Southwest. Southwest proposes that money allocated to its core gas customers be credited as received first to its core fixed cost adjustment mechanism (CFCAM)¹¹ until the CFCAM balance is zero. The remainder would then be applied to the PGA balance. No party opposes Southwest's proposal.

We adopt Southwest's unopposed proposal. As Southwest correctly states, crediting either account will accomplish the purpose of reflecting the value of the Settlement as a reduction to the costs of procuring natural gas for its customers. According to Southwest, it currently has an under-collection in its CFCAM. Applying Settlement proceeds first to the CFCAM (until its balance is zero) will mitigate the rate impact of recovering the undercollected CFCAM balance. Once that balance is zero, Southwest should apply the remainder to the PGA balance. Just as we adopt for the other gas utilities above, the first payment under the MSA that would otherwise be recorded to Southwest's CFCAM should be net of the limited amounts allocated up-front to some few customers.

3.3.2. Core-Elect and Core-Subscription Customers

3.3.2.1. Background and Proposal

During the March 1, 2000 through May 31, 2001 timeframe, some noncore gas customers were served by the utilities' core gas portfolios even though these customers could have otherwise procured their own gas. These noncore customers were called "Core Elect" and "Core-Subscription" customers. To the extent that these customers are still served by the gas utilities' core portfolios, they will receive the benefit of the El Paso consideration by the credit to the gas utilities' PGA (or CFCAM for Southwest). However, during or subsequent to the winter of 2000/2001, some of the noncore customers, who had previously purchased natural gas from the utilities' core portfolios, may have purchased their own natural gas supplies either by choice or because the core subscription option was eliminated before the highest price-spikes were incurred.

We proposed in the OIR that these customers not receive a share of the California natural gas utilities' consideration under the Settlement to the extent they are eligible to submit claims under the Settlement to seek consideration in the Superior Court's claims process for noncore customers. On the other hand, we proposed that noncore customers, who were previously core-elect or core subscription customers during the entire above-mentioned time period but are no longer purchasing their gas from the utilities, be able to submit a request for a refund or credit with the utilities based upon their purchases from the utilities' core portfolios (in therms) during the period at issue, as shown on their bills. We said that the Settlement consideration could be allocated to a fractional-cent per therm for all throughput, with the refund rate treatment as discussed regarding core aggregation. Also, because we proposed to account for the Settlement proceeds allocated to gas customers by initially recording the revenues in the PGA, we further proposed that any refunds or credits by the utilities to these noncore customers should then be booked to the PGA as an expense (which has the effect of reducing the settlement revenues attributable to the remaining core customers). (OIR, mimeo., page 17.)

3.3.2.2. Refund Plan

SDG&E, SoCalGas and TURN agree with the Commission's proposal. PG&E also agrees, but suggests it develop its own refund plan. We adopt our initial proposal, but with PG&E's variation regarding the refund plan for all four gas utilities.

That is, PG&E proposes that it file its own refund plan in lieu of requiring its customers to file a request for a refund. In support, PG&E says its core subscription service ended February 28, 2001, pursuant to the Gas Accord decision, citing D.97-08-055. PG&E proposes that it refund a pro rata share of the Settlement consideration to current PG&E noncore customers who were core subscription customers for some period between March 1, 2000 and February 28, 2001. Once the refund is complete, PG&E says any remaining balance will be transferred to the PGA, consistent with the proposed treatment of the Settlement consideration for bundled core gas customers.

We adopt PG&E's proposal, and direct that PG&E develop and propose a refund plan through an Advice Letter. We similarly require each gas utility with such customers to file an Advice Letter with a proposed refund plan that does not require the customer to first submit a request. As Bower & French say, requiring these customers to apply for a refund to obtain their share of Settlement consideration would entail administrative costs disproportionate to the amount of money to be allocated to this group. We are confident that each utility can develop and propose a reasonable and efficient refund plan that will mitigate the burden on these customers.

Bower & French, however, disagree with PG&E's proposal that these customers receive the full amount of the refund "up-front," while core ratepayers only receive the benefits over time. This concern can be reasonably addressed by requiring that the refund plan reflect the time value of money by use of a net present value. That is, the refund plan should calculate the "up-front" payment based upon a net present value of a reasonable forecast of potential payments using a reasonable proposed discount rate. Each utility's proposed refund plan should include this calculation.¹²

With this net present value adjustment, we adopt PG&E's proposal. This will promote administrative feasibility. PG&E estimates the total refund amount to be about $0.9 million. (PG&E Comments, page 9.) Spreading an estimated $0.9 million over a period of up to 20 years for many noncore customers would otherwise add a level of administrative cost and complexity that is unreasonable, while paying the refund now discounted by a net present value promotes efficiency and equity. As a result, each of the four natural gas utilities should administer the refund to these customers in the near term, with the remaining balance, if any, transferred to the PGA.

Bower & French also disagree with what they characterize as the position of the Commission, SDG&E and SoCalGas that core-elect and core-subscription customers who are eligible to participate in the San Diego Superior Court claims process for noncore gas customers not also receive settlement benefits for the time they were core-elect or core-subscription customers. According to Bower & French, these customers will not be eligible to receive compensation in the claims process for gas purchases while they were core-elect or core-subscription, and should be eligible to participate in the Commission's refund plan.

We agree. That is, to the extent these customers are eligible to submit claims in Superior Court, we expect them to do so, and they will not be eligible for a duplicative refund for the same time period from the utility through the Commission-adopted refund process. However, to the extent they are ineligible to submit claims in Superior Court--including for some portion of the 15-month period--they should be eligible for a pro rata share of the refund paid by the utility.

3.3.3. Core Aggregation Customers

3.3.3.1. Background and Proposal

Some gas consumers were part of the core aggregation program during the March 1, 2000 through May 31, 2001 timeframe. Those core customers, who were then purchasing natural gas from core aggregators but who now purchase natural gas from gas utilities, will receive the benefit of El Paso consideration through amounts utilities credit to their PGA (including the CFCAM for Southwest).

On the other hand, there are certain core customers, who purchased natural gas from core aggregators between March 1, 2000 and May 31, 2001, and who still purchase natural gas from core aggregators. This latter group would not receive the benefit via the credit in the utilities' PGA (or CFCAM). Core aggregation customers, however, pay a core aggregation transportation charge that gas utilities charge for the transportation of gas provided by the core aggregators.

In the OIR we proposed that each natural gas utility with core aggregators transporting natural gas on the utility's facilities book a proportional share of the Settlement consideration attributable to core aggregation customers in a new memorandum account, called the El Paso Settlement Memorandum Account (EPSMA). The EPSMA balance would then be used, at the time of the next appropriate ratemaking proceeding, to partially offset the utility's allocated revenue requirement recoverable through the authorized core aggregation transportation rate. We proposed that these customers receive a proportional share of their California natural gas utility's Settlement consideration based upon their class's share of the utility's total system natural gas throughput, excluding noncore volumes, for the 12 months immediately prior to the time that the utility first receives the consideration. Further, we proposed that the Settlement consideration be allocated to a fractional-cent per therm for all deliveries, excluding noncore, to all customers served by respondents, with the core aggregators' share recorded in the EPSMA until it is credited against the core aggregation transportation charge. (OIR, mimeo., page 18.)

3.3.3.2. EPSMA

SDG&E, SoCalGas, and SPURR/ABAG POWER agree with the Commission's proposal, PG&E offers a variation, and TURN disagrees. We adopt our initial proposal with PG&E's variation and modified by application of a net present value, as explained below. We reject TURN's recommendation, as also explained below.

PG&E proposes to implement the Commission's proposal by allocating a percentage of the total Settlement consideration for PG&E's core gas customers to core aggregation customers.¹³ This amount would be recorded into the EPMSA, and, according to PG&E, incorporated into core aggregation transportation rates in the next Biennial Cost Allocation Proceeding (BCAP) or annual true-up. Further, PG&E proposes that the total amount allocated to core aggregation customers be set aside from the upfront cash amount, so that future deferred payments would be allocated 100% to core procurement customers. PG&E asserts that this would result in transportation rates for approximately 12 months that are lower for core aggregation customers compared to bundled core gas customers, but that in about 12 months the transportation rates paid by core aggregation and core procurement customers would again be equal.

In their reply comments, SPURR/ABAG POWER support PG&E's proposal. Bower & French, however, oppose any "front load" of Settlement consideration to core aggregation customers, saying they should receive settlement benefits on a pro rata basis over time just as other ratepayer groups.

We agree with PG&E and SPURR/ABAG POWER as long as the upfront payment is based on a net present value, just as we adopt for the refund plan for core-elect and core-subscription customers. This approach promotes reasonable administrative feasibility for what is an important but relatively small portion of the Settlement. It will facilitate the ability to set equal core aggregation and core procurement transportation rates paid by these customers within about 12 months. The use of a net present value provides equity among customers. As a result, each of the four gas utilities should file an Advice Letter with the proposed refund plan consistent with this approach.¹⁴

TURN contends that core aggregation customers should not receive a share of the El Paso consideration through a refund on their gas transportation charges. Rather, TURN claims that gas commodity charges for core aggregation customers have been fully unbundled for some time. As such, TURN says these customers did not pay any part of the transporting utility's gas purchase costs, but all their payments went directly to their competitive gas supplier. Therefore, TURN concludes that any refunds for these customers should come from their competitive gas supplier, not from the utility's bundled core customers who paid the entire cost of gas themselves, according to TURN.

We are not persuaded by TURN. Rather, as SPURR/ABAG POWER correctly point out, the MSA is entered into on behalf of all individuals and entities in California that purchased gas during the relevant period. The MSA covers the utilities' core and noncore gas customers, including core aggregation customers.

The Allocation Agreement allocates the consideration separately to core and noncore customers, but among core customers, it makes no distinction between bundled sales and core aggregation customers. Moreover, the Allocation Agreement provides that the percentage allocations set forth in the table in Section 4 "will be distributed by CPUC jurisdictional utilities, for the benefit of their core natural gas...ratepayers, in the form of refunds, disbursements, or credits..." (Allocation Agreement, Section 4(b).) The amounts allocated by the Allocation Agreement to the utilities' core gas customers are not in turn limited to bundled sales customers. Parties to the MSA could have done so, but did not.

Moreover, Settlement consideration is not limited to just those customers who purchased their supplies directly from gas utilities. Noncore customers who purchased their gas from third party suppliers, for example, will get approximately 16.5% of the El Paso consideration. Noncore customers are not required to obtain their portion of the refund from their competitive suppliers, and neither should core aggregation customers be required to obtain their portion from their core aggregators. Indeed, the El Paso consideration is intended for end-customers not suppliers, marketers or core aggregators. No specific allocation is provided in the Settlement for core aggregation customers, and it is reasonable to provide equitable treatment for these customers in the manner we adopt here.

3.3.4. Limited Additional Wholesale Transportation Customers

Six entities buy gas directly from suppliers, pay PG&E for transportation service (as wholesale gas transportation customers of PG&E), and then resell the gas to their own end-use customers.¹⁵ The end-use customers of these six entities suffered harm from high natural gas prices at the California border just as did other customers who will receive consideration under the Settlement, and deserve an equitable portion of the consideration just as do other customers similarly harmed by the high natural gas prices. These six PG&E customers and their end-use customers, however, were not included in the proposed treatment described in the OIR of the Settlement consideration to be received by PG&E.

A supplemental proposed treatment was filed and served for comment. (See Ruling dated August 27, 2003.) PG&E filed comments largely in support. Palo Alto filed reply comments also largely in support. We adopt the treatment described below.

These six customers will be treated in the same manner as core aggregation customers. They will receive a proportional share of PG&E's core settlement consideration based upon the wholesale customer class share of PG&E's total system natural gas throughput, excluding noncore volumes, for the 12 months immediately prior to the time that PG&E first receives the consideration.¹⁶ The allocation to wholesale customers will be taken from the upfront cash allocated to core procurement and core subscription customers (so that future deferred payments will be allocated 100% to core customers). The wholesale share of the settlement will be booked to a subaccount of the EPSMA until the appropriate ratemaking proceeding (i.e., BCAP or annual true-up) where the memorandum account balance can be used to partially offset PG&E's allocated revenue requirement recoverable in the authorized tariff rate for the wholesale transportation charge. This will result in about 1.3% of the Settlement consideration for PG&E's core gas customers being allocated to these six customers.¹⁷ Consistent with our adopted treatment of the core aggregation consideration, the amount allocated to these six wholesale customers will be calculated based on a net present value.¹⁸

3.4. Incentive Mechanisms

The Commission has adopted a variety of incentive regulatory mechanisms for several utilities. These mechanisms are intended to provide utilities with an incentive to further reduce costs or improve services beyond the levels expected (and funded) in either base rate-related proceedings (usually a general rate case or a cost of service proceeding) or energy procurement proceedings (e.g., acquisition of natural gas or electricity). Fundamentally, the utilities are provided an opportunity to negotiate exceptional prices or find various efficiencies, and thereby benefit in part or whole from the incremental savings.

In the OIR, we proposed that the utilities not receive any unintended or unearned benefit or detriment through application of an incentive mechanism in relation to the Settlement. Rather, we proposed that in adopting a recovery mechanism for the Settlement, the determination of any incentive be calculated as if the Settlement payments had not occurred. (OIR, mimeo., page 19.)

No party objects to the proposed treatment, and we adopt the proposal as stated in the OIR. As a result, all consideration received pursuant to the Settlement will be treated in a manner to be neutral with respect to utility incentive mechanisms.

SCE points out that it may request an equitable adjustment to permit it to retain for shareholders the refund of costs SCE will receive pursuant to the Settlement (e.g., attorneys' fees). In support, SCE cites Section 3.3 of the settlement agreement between SCE and the Commission in SCE v. Lynch et al. SCE also says, however, that such request is not properly addressed in this proceeding.

We agree with SCE that the cited settlement agreements support the treatment identified by SCE, and that SCE may seek an adjustment in an appropriate proceeding. We will determine the merits of SCE's requested adjustment when proposed in an appropriate proceeding.

3.5. Income Taxes

In the OIR, we stated our belief that refunds from the Settlement should have no tax effect on utilities. We said that we could not see a basis for utilities to be taxed for any of the consideration under the Settlement because we are requiring that the consideration received by utilities inure to the benefit of their ratepayers. If, nevertheless, utilities are taxed for Settlement consideration, we proposed that utilities be able to adjust the consideration such that only the net revenues be a credit to their ratepayers. Alternatively, we proposed that utilities be made whole by being allowed to recover costs associated with any tax liability for the consideration in the utilities' next ratemaking application before the Commission. (OIR, mimeo., pages 19-20.)

Parties generally agree with the Commission's assessment that there will be no tax effect. As a result, we do not adopt a ratemaking adjustment for any anticipated tax effect. Should an adverse tax effect occur, however, a utility may propose the most efficient treatment at that time. That is, to the extent actual tax payments are later required by the Internal Revenue Service or other governmental taxing authority, a utility may then propose (a) adjustment of the consideration such that only the net revenues are credited to ratepayers, (b) allowing cost recovery of any tax liability in the next appropriate ratemaking proceeding, or (c) authority to create a memo account to track adverse tax implications until addressed in a ratemaking proceeding.

For PG&E, Bower & French say that the proposed bankruptcy SA now provides an after-tax treatment (wherein the net after-tax amount of El Paso consideration will be applied to reduce the Regulatory Asset). Bower & French argue that the full benefit of the El Paso consideration should flow through to ratepayers without any portion begin "siphoned off" for taxes, and that it should be possible to structure the transaction to achieve this goal. For example, they assert that the Commission's proposed accounting should not be adopted if an adverse tax effect results but an alternative should be adopted, such as passing the consideration directly to ratepayers as a rebate or credit.

We decline to adopt their proposal. We expect no adverse tax effect from the El Paso consideration. PG&E tax issues, if any, will be addressed in the bankruptcy proceeding to the extent they are an issue in the proposed SA, and are relevant to the Commission's consideration of the proposed SA, as discussed above. Further, we decline to adopt a rebate or bill credit approach to avoid a problem that we do not reasonably foresee occurring.

3.6. Other Issues

3.6.1. Allocation Percentages

In their initial comments, SDG&E and SoCalGas request additional disclosure of the analysis behind the allocation percentages in the Allocation Agreement. SDG&E/SoCalGas do not, however, identify the party or parties from whom the data should be obtained, nor move to compel disclosure from any specific party or parties.

We decline to order disclosure in general, or specifically name any otherwise unidentified party or parties to disclose the analysis behind the allocation percentages in the Allocation Agreement. The reasonableness of the Allocation agreement, including the allocation percentages, is before the Superior Court and others, not this Commission. Moreover, SDG&E/SoCalGas fail to convince us of the relevance, if any, here. For example, SDG&E/SoCalGas neither explain how they might use such information to modify any recommendation here, nor show how the analysis behind the allocation percentages would benefit our consideration of any issue.

3.6.2. Southwest $2.7 Million Penalty

Southwest proposes that the first $2,691,675 of whatever amount is ultimately allocated for Southwest's core customers be retained by Southwest for the benefit of Southwest's shareholders. In support, Southwest says its shareholders have already compensated Southwest's core customers pursuant to D.02-08-064. We decline to adopt Southwest's proposal.

The disallowance of $2,691,675 in gas procurement cost recovery was "because of imprudent managerial actions during the review period of June 1, 1999 through May 31, 2001." (D.02-08-063, Conclusion of Law 6, mimeo., page 3.) It was not, as Southwest characterizes it, for shareholders and ratepayers to `share the pain' when the true culprit of high prices had not yet been identified. The $2.7 million disallowance is unrelated to the El Paso Settlement.

3.6.3. Payment to Southwest

Southwest also proposes that it be paid first. That is, Southwest urges that the Commission "consider having the entirety of Southwest's allocation distributed out of the initial settlement proceeds paid by El Paso." (Initial Comments, page 4.) In support, Southwest cities administrative efficiency, since, according to Southwest, an estimated $5 million payable to Southwest is dwarfed by the estimated $1.5 billion total proceeds.

While Southwest's portion may not be a large percentage of the total, it is beyond our jurisdiction to redistribute the allocations between utilities. That is a matter regarding the reasonableness of the Settlement, and is before Superior Court.

We may reallocate amounts between ratepayers within a company when reasonable to do so (e.g., the net present value amount paid to core-elect customers, core-subscription customers, core aggregation customers, and six PG&E wholesale transportation customers). Southwest, however, makes no compelling claim that we have jurisdiction to reallocate amounts among utilities. We are not persuaded that we may, or should, do so.

3.6.4. Timing of Rate Adjustments and Appeals

Bower & French propose that Settlement consideration be immediately provided to ratepayers when the times for all appeals of the Superior Court's final approval order have expired, whether or not appeals of the Commission's order are pending. The Commission should not wait for the exhaustion of all appeals of its order, according to Bower & French, since leaving a large amount of money in an escrow account at low interest rates does not make sense. Rather, Bower & French say that the Commission may recapture the consideration by rate increases or surcharges if its determination is later reversed on appeal.

We decline to adopt this proposal. This order is effective immediately, and will remain in effect unless stayed (e.g., by a party seeking a stay here, or in an appellate court, and meeting the high standards for a stay). Consequently, unless this order is stayed, utilities must comply with this order. We simply decline now to prejudge issues related to an application for a stay, if any. As PG&E says, if an issue does arise through an appeal of this decision, we may decide at that time whether it is worth holding up disbursement until the issue is resolved, or to rely on recapture of disbursed amounts, if necessary.