V. Cost Allocation

A. SoCalGas' Proposed Cost Allocation

SoCalGas proposes to allocate the CEMA costs to customers using the Equal Percent of Marginal Costs (EPMC) method through 2002 and to include the carrying-costs on capital investments made in repairing or replacing the damaged facilities in cost-of-service in the next cost-of-service proceeding. SoCalGas points out that the costs recovered in the CEMA proceedings following the Northridge Earthquake were allocated on the basis of EPMC. (D.95-12-040; D.97-06-064.)

SoCalGas' cost allocation, using the allocation factors adopted in SoCalGas' 1999 Biannual Cost Allocation Proceeding (BCAP) (D.00-04-060)²⁵ results in an allocation of 86.9% to core customers, 10.7% to noncore/wholesale customers, and 2.4% to unbundled storage. (Exhibit 500.)

SoCalGas contends that the costs charged to the CEMA are for repair and replacement of facilities, which are similar to costs routinely included in its cost-of-service. Thus, SoCalGas maintains that these costs should be allocated using the same EPMC method used to allocate other base margin or cost-of-service costs. SoCalGas argues that the Commission adopted the EPMC method to scale marginal cost-based revenues to the authorized base revenue requirement in order to preserve the efficient pricing signals of marginal cost (e.g., encouraging utilities to make efficient capital investment decisions while minimizing the bypass threat), and that adoption of a different cost allocation method, like TURN's proposal, would defeat this purpose.

SoCalGas points out that these costs cannot be considered marginal costs because they are related to providing existing services to existing customers. While acknowledging that CEMA costs are excluded from base margin, SoCalGas argues that they were excluded to address retroactive ratemaking concerns, to avoid speculative forecasts of damage from natural disasters, and to permit expedited rate recovery, not because they are different from other base margin costs. Thus, SoCalGas argues that the costs are not excluded in the base margin proceeding because they are different from other base margin costs but because they are simply too difficult to forecast. SoCalGas also distinguishes the allocation treatment afforded the other exclusions authorized by its PBR, noting that these excluded costs are "fundamentally different" from costs for repairing pipeline facilities and that there are distinct reasons for allocating them among customer classes in a different manner.

SoCalGas also points out that the carrying costs on capital investments associated with these facility and pipeline repairs and replacement will be included as part of base margin in the next cost-of-service proceeding, where, if this methodology is maintained, the costs will be allocated based upon the Long Run Marginal Costs (LRMC) methodology, as adopted in D.92-12-058. SoCalGas points out that if we adopt TURN's functional cost allocation for 2001 and 2002, we will be establishing two different methods for allocating the costs to repair and replace facilities damaged in the El Niño rains.

SoCalGas maintains that TURN's proposed allocation method is contrary to the purpose of § 454.9 because it would expose shareholders to greater risk of cost recovery than the LRMC method, thus undermining the policy of providing the utilities with the strongest incentive to repair damage and restore service as quickly as possible "without concern that shareholders will be held responsible for prudently-incurred costs." SoCalGas also contends that adoption of TURN's proposed allocation method would add unwarranted complexity to future CEMA recovery. It points out that while allocation in this case may be relatively simple because of the discrete nature of the damage, making a functional allocation after a large earthquake would be very difficult and would add time to the processing of claims.

B. TURN's Proposed Cost Allocation

TURN proposes that the costs be allocated on a "functional" basis, i.e., that costs be recovered for facility replacement and repair from customer classes according to the function the facility performed (transmission, distribution, storage), in proportion to the use of those facilities by customer class. In this case, TURN points out that the nature of the costs incurred has been clearly established and that over 80% of the costs incurred were for repairing or replacing transmission lines and storage facilities, which benefit noncore customers more than core customers. Nevertheless, use of the EPMC allocation method results in the assignment of over 80% of the costs to distribution and service-related functions, which costs are assigned in greater percentage to core customers. Thus, arguing that the EPMC inequitably over-allocates costs to core customers and under-allocates costs to other customers and services, TURN would allocate the costs based upon cost causation principles, which would result in more of the costs being assigned to noncore customers. TURN also points out that if the damage had not been properly repaired, storage and transmission would have been greatly impacted but distribution services would have only suffered minor disruptions.

TURN's functional or cost-causation allocation method, using the allocation factors approved in D.00-04-060, allocates 55.5% to core customers, 32.8% to noncore customers, and 11.7% to unbundled storage.

TURN argues that the CEMA is a special ratemaking mechanism and that since CEMA costs are excluded from base margin proceedings, the costs should be allocated on a different basis than EPMC. TURN points out that the CEMA account records actual expenses and revenues collected in rates to cover the authorized expenses and are not forecasted like base margin expenses.

TURN points out that there are 8 categories of exclusions identified in SoCalGas' 1997 PBR decision (D.97-07-054), including cost items, transition costs, and balancing accounts, and that none of the other exclusions are allocated based upon EPMC. TURN argues that there is a "fundamental difference" in the nature and method of collecting exclusions versus base margin costs. It points out that base margin, adopted in SoCalGas' PBR, represents the total revenue requirement associated with the cost of providing customer-related and demand-related services, and is based on historical and forecast costs. Shortfalls are generally borne by SoCalGas shareholders. Exclusions, on the other hand, TURN contends, are beyond SoCalGas' control and the company is guaranteed recovery of actual authorized costs, so these costs are amortized in rates.

TURN maintains that it is inherently unfair to use the EPMC to allocate CEMA account costs because the total system EPMC does not correspond to the allocation among customer classes of any one of the five functional marginal cost components used in the LMRC allocation method. TURN also argues that Commission policy favors allocation corresponding to cost causation wherever costs and customer cost causation can be linked, which promotes fairness among customer classes.

TURN concedes that the EPMC was used in allocating CEMA costs after the Northridge Earthquake, but notes that the issue was not litigated in that case.

C. ORA's Position

ORA does not express a position on the appropriate method of cost allocation.

D. Discussion

We must decide how the CEMA costs should be allocated among the classes of SoCalGas ratepayers. The proposals set forth by SoCalGas and TURN produce very different results, as set forth Jt. Exh. 500. The effect of the two allocation proposals by customer class is summarized as follows:

Customer Class	SoCalGas EPMC Allocation Percentage of Total	TURN Functional Allocation Percentage of Total
Core	86.9%	55.5%
Noncore/wholesale	10.7%	32.8%
Unbundled Storage	2.4%	11.7%

Maintenance, repair, and capital costs associated with pipelines and related facilities are generally considered base margin costs and are included in the utility's base margin proceeding, which, for SoCalGas, is a PBR. The base margin represents the revenue requirement associated with the cost of providing customer-related services and demand-related services. The PBR uses historical costs and forecast costs to establish the revenue requirement. The utilities use the revenue requirement to set rates.

To set rates, the utilities must allocate the revenue requirement among customer classes. This is done now in the BCAP, every two years. Over the past several years, the Commission has used LMRC to make the customer cost allocation. Long run marginal costs are forward looking costs; they reflect the costs that will be incurred to meet new demand for services. As described by SoCalGas, a separate unit cost and cost causation factor or marginal demand measure is developed for each of five functional areas, which results in the allocation of marginal revenues for each customer class. The revenues are totaled to obtain system total marginal cost revenues.

Because the revenue requirement established in the PBR generally will not equal the total marginal cost revenues established in the BCAP, the revenue requirement and the marginal cost revenues need to be reconciled or "scaled" before rates can be established. The Commission adopted the EPMC for this purpose. Under EPMC methodology, each customer class' marginal revenue responsibility is basically determined by multiplying the difference between total system marginal cost revenues and total authorized base margin by the percentage of each class' contribution to system marginal cost revenues. As TURN points out, total system EPMC is used only to reconcile the authorized base margin revenue requirement to the marginal cost revenue; marginal costs and the allocation among customer classes of the five functional marginal cost components are done separately.

In D.00-04-060, we adopted the parties' Joint Recommendation and established the marginal cost revenues and customer class contributions to be used for the BCAP period. Under the formula adopted in the BCAP, a large portion of the marginal costs (44%) are categorized as customer costs. Because core customers pay 98% of customer costs, use of the EMPC allocation method results in the allocation of substantial costs (over 86%) to core customers. (See, D.00-04-060, Table 10, p.1.)

We agree with TURN that while the EPMC cost allocation method may be reasonable for reconciling the revenue requirement with marginal cost revenues, it should not be used for the purpose of allocating costs which were excluded from base margin where, as here, it produces such an inequitable result. The record reflects that only 55% of the costs are attributable to core customers, while the EPMC would allocate 86% to core customers.

We have full discretion in the cost allocation area and are particularly guided by equitable considerations. While we generally use the EPMC method to scale up the revenue requirement to marginal costs, we "have tempered full movement towards EPMC when, in our judgment, the impact on specific customer classes would be unduly detrimental. "(Re Southern California Edison Company (1996) D.96-04-050; 65 CPUC2d 362, 384.) It is important that we do not forget the "primary goal of ratemaking, namely, to achieve rates which reflect the costs that the customer imposes on the system." (Id.)

Our discretion is particularly acute with respect to the allocation of costs excluded from the base margin proceeding, which we have repeatedly acknowledged. SoCalGas' PBR Decision (D.97-07-054) explicitly excludes several cost categories from the PBR mechanism, including CEMA, Hazardous Substance Cost Recovery Account (HSCRA), Low emission Vehicle (LEV) Program, regulatory transition costs, mandated social programs, and others. These costs generally are also excluded from the base margin for other utilities. We explain that these cost categories are excluded because they are beyond the control of SoCalGas' management or are subject to recovery through other ratemaking mechanisms. (Id., mimeo at pp. 42-44.)

As SoCalGas admits, we do not use the EPMC method to allocate the other excluded costs. (Overton; Tr. Vol. 2, p. 269.) Instead, we exercise our discretion to allocate costs on an equitable basis. For example, in Re Southern California Edison Company, we affirmed a prior finding that California Alternative Rates for Energy (CARE) program costs were appropriately allocated on an equal cents per therm basis. ((1996) D.96-04-050; 65 CPUC2d 362.) In that decision, noting that there is no sound theoretical argument for any party's proposed allocation method, we held that "[t]he issue is really one of equity. Under an equal percentage of total bill (or EPMC) allocation, residential and small commercial customers would bear proportionately more of the CARE costs than under an equal centers per kWh allocation method." (Id. at p. 412.)

We conducted a similar analysis and came to a similar conclusion with respect to the allocation of hazardous waste cleanup costs, another PBR exclusion, in Re Southern California Gas Company ((1995) D.95-05-044; 60 CPUC2d 14.)²⁶ In rejecting SoCalGas' argument and adopting DRA's²⁷ and TURN's argument that the hazardous waste cleanup costs should be recovered from all ratepayers on an equal cents per therm basis, we stated that "we are not wedded to handling every [non-PBR] cost on a EPMC basis." (Id., at p. 17.)

In this case, we also noted that "hazardous waste clean up costs are not to be allocated 90% to the core on any basis of cost causation," and, persuaded by DRA's and TURN's equity arguments, specifically looked for the fairest way to allocate the costs. (Id.) On rehearing, we reiterated our view that "while marginal cost principles and EPMC policies may be relevant, we have long recognized that they are not dispositive, and must be tempered with other ratemaking considerations. (D.97-12-112, mimeo, at p. 7; see also, Re Southern California Edison Company (1992), D.92-05-020; 44 Cal.PUC2d 471, 484-485.) We also stated that "[e]conomic efficiency is of course, not the sole consideration in our choice of a revenue requirement reconciliation methodology. Equity considerations remain paramount." (Re Rate Design of Unbundled Gas Utility Service (1986) D.86-12-009; 22 Cal. PUC2d 444, 457; reaffirmed in Re Southern California Edison Company, D.91-12-075; 42 Cal.PUC2d 566, 591.)

While, on rehearing, we ultimately determined that hazardous waste clean-up costs met the criteria for "transition costs," as set forth in the LRMC Decision (D.92-12-058), we made it clear that the costs were properly excluded even if they did not meet that definition. We held that, because transition costs "are intended to promote equity between customer classes," our decision to allocate costs "on the basis of fairness would still be well within the bounds of the transition cost concept outlined in [the LMRC decision.]" (D.97-12-112, mimeo, at p. 13.) We point out that while we may choose to give more weight to the utilities' arguments in support of the EPMC based allocation, "there is no legal requirement that we exercise our discretion in that manner." (Id. at p. 14.)

Similarly here, we find that it would be inequitable to allocate the CEMA costs on the basis of EPMC given the substantial adverse impact on the core customer class, contrary to actual cost causation, and decline to do so. CEMA is a special category of ratemaking cases and should be treated separately. We use our discretion to do so.

SoCalGas' argument that we must use EPMC is not persuasive for several other reasons. First, use of the LRMC for customer cost allocation is not a static event. While some form of the LRMC has generally been used since 1993 to make customer cost allocations, we have deviated from the adopted method in subsequent proceedings. Because of the complexity of the issues and the different equities that result from application of the LRMC in different cases, we often vary our application of the LRMC to take into account the facts of the case before us. For example, we originally adopted the Rental method to estimate the cost of installing the service line, regulator, and meter at the customer's premises. The Rental method has now been replaced by the New Customer Only (NCO) method for all major gas and electric utilities, including SoCalGas, substantially decreasing marginal costs. (See, e.g., D.92-12-057; D.95-12-053; D.96-04-050; D.00-04-060.) For SoCalGas, specifically, we adopted the NCO methodology (D.97-04-082), then changed back to the rental method because of the considerable impact on one customer group. (D.97-08-062.) We also adopted a replacement cost adder to include investments needed to maintain system reliability as well as to serve growth demand in PG&E's BCAP (D.95-12-053), and then declined to include the replacement cost adder in SoCalGas' BCAP pursuant to the parties' Joint Stipulation. (D.00-04-060, mimeo, at p. 37.) Thus, we reject SoCalGas' argument that we are required to use the LMRC methodology of cost recovery, in all cases, without variation.

Second, SoCalGas' argument that carrying costs on the capital investments will be allocated on the basis of LMRC at the next PBR is pure speculation at this point. SoCalGas is certainly able to argue that the cost allocation should be made in this way but it will be up to the Commission to determine the appropriate cost allocation method. Since we believe that the CEMA costs we consider today should be allocated on a non-EPMC basis, it also may be more appropriate to consider future carrying costs as a PBR exclusion and treat them similarly.

Finally, we do not believe that CEMA cost allocation is dictated by prior decisions. We have not previously determined, in a litigated case, the appropriate method of allocating costs approved under a CEMA. In D.95-12-040, we issued an interim opinion, on the basis of a joint proposal by SoCalGas and ORA, allowing SoCalGas a rate increase to cover costs associated with damage that occurred during the Northridge Earthquake, using SoCalGas' proposed EMPC allocation, subject to refund, stating that "we make no final conclusions as to cost allocation." (Id., mimeo at p. 6.) The final decision ordered a ratepayer refund and noted in Ordering Paragraph No. 2 that the refund should be allocated by EPMC. (D.97-06-064, p. 4.) The refund had to be allocated by EPMC since the costs were originally allocated using the EPMC. However, it does not appear that any parties in the proceedings leading up to the final decision contested use of EPMC and the final decision did not address it. We have not addressed the appropriate manner of allocating CEMA costs in other decisions.

Having decided that use of the EPMC method is not a reasonable method of allocating the CEMA costs to customer classes in this case, we must decide the proper method to use. TURN urges that we use its "functional" method. The cost allocation method we have used for most other excluded costs is equal cents per therm, which would seem equally applicable to the CEMA costs. We do not know why TURN has not advocated this method in this case; however, we do not have any evidence on the record to support an equal cents per therm allocation. TURN's functional cost-causation allocation, on the other hand, on the basis of the record facts, is reasonable and satisfies our equity concerns in this case and we adopt it.

We do not agree with SoCalGas' contention that allocating costs by function is contrary to § 454.9 because it would be difficult to administer quickly or because it subjects shareholders to risk. Stating our policy of encouraging utilities to take action immediately after a declared disaster does not mean that we will shield shareholders from all conceivable risk. Further, while SoCalGas makes the generalized statement of increased shareholder risk under TURN's allocation proposal, SoCalGas presented no evidence to quantify the amount, if any, of the risk. SoCalGas' argument also fails for lack of evidence.

However, since we have no record upon which to determine whether a functional allocation may be problematic in other declared disaster cases, we will limit our decision to the facts before us today. The cost allocation we adopt here will not be considered precedent for future decisions.