The utilities have historically incurred costs in dispatching power to customers on their systems and managing those dispatching activities to provide high-quality service. With the introduction of direct access, the ISO and PX will take on these activities.
TURN and UCAN argue that the utilities have inappropriately included in their distribution revenue requirements the costs of load dispatching and power purchasing. TURN and UCAN observe that the ISO and PX will be assuming related responsibilities and that the utilities should not be able to include such costs in rates. TURN and UCAN recommend reducing PG&E’s revenue requirement by $10.83 million, SDG&E’s by $5.53 million and Edison’s by $17.02 million for associated costs. ORA objects to SDG&E’s allocating these load dispatching costs in its generation function to the distribution function because this results in asking SDG&E’s regulated business to subsidize its competitive services.
Edison comments that the Commission should not reduce these revenues because the proposal ignores the fact that the utilities will incur additional implementation costs. SDG&E will incur costs associated with "interface" activities with the ISO.
One of our criteria for determining the reasonableness of a proposal is whether it allocates the costs of a given function to that function’s revenue requirement. Here, the utilities propose to include in the distribution revenue requirement the costs of generation dispatch and control. The utilities will no longer conduct generation dispatch and control beginning January 1, 1998. While there may be some uncertainty about the ongoing activities the utilities will conduct in working with the ISO, we are not convinced that the utilities’ activities will differ in any significant respect from those of its generation competitors. Therefore, the dispatch and control "interface" and "implementation" costs will be the responsibility of the ISO and will be included in ISO transmission rates. We therefore follow TURN and UCAN’s recommendations to remove associated costs from the utilities’ revenue requirements for distribution. Assuming these costs should be allocated to transmission, PG&E had already removed the associated $10.83 million from its distribution revenue requirement which therefore requires no further adjustment. Edison makes a reasonable argument in its comments that some load dispatching activities will remain with it after January 1, 1998. Edison did not , however, make an affirmative showing to support allocating the entire load dispatching revenue requirement to distribution. We therefore remove from Edison’s distribution revenue requirement an amount equal to that amount PG&E removes from distribution revenue requirement, $10.83 million. We remove $5.5 million from SDG&E’s distribution revenue requirement the amount of these costs that it included in its March 31 FERC transmission revenue requirement. If FERC concludes that these load dispatch and ISO/PX related costs are distribution costs, rather than transmission costs, then we will reallocate these costs to distribution, consistent with FERC’s findings.
TURN/UCAN propose that the Commission in this proceeding recognize the changes to line extension policy which may be adopted in R.92-03-050. Specifically, they believe line extension allowances should be scaled back to reflect only the distribution revenues, rather than total revenues reflected in current allowances. They also believe changes in line extension allowances should be reflected in revenue requirements adopted here.
ORA and the utilities agree that the Commission should defer this issue to R.92-03-050 the rulemaking associated with this issue. CBIA objects to TURN/UCAN’s proposal, arguing that the Commission does not have adequate evidence in this proceeding to revise existing rules.
We agree that we do not have adequate information here to undertake any changes to line extension rules or the way rates are designed to accommodate rule changes. We will defer consideration of this issue to R.92-03-050 and revisit the issue as it affects revenue requirements in the utilities’ PBR and general rate cases, if necessary.
SDG&E recommends retaining a bundled cost of capital and not unbundling it by functions. It observes that as an integrated company, it does not have separate units issuing their own debt and equity. PG&E and Edison also assume the cost of capital would not change in this proceeding.
TURN and UCAN propose that the Commission initiate a proceeding to develop and implement unbundled costs of capital that will reflect the risks associated with unbundled utility functions. They believe the Commission should make 1998 rates subject to refund for this purpose. TURN and UCAN observe that the Commission earlier declined to unbundle the costs of capital in 1994 because it believed the exercise was premature, suggesting the issue would be reconsidered as rates were unbundled (D.94-11-076).
Edison generally concurs with TURN and UCAN’s procedural recommendation, although it does not agree with their assumption that rates of return are likely to fall.
We agree that the utilities’ authorized cost of capital should ultimately reflect new market structures and the variation in risk between various utility functions. We do not believe the need for such a review, however, is urgent. Edison and SDG&E were excused from comprehensive cost of capital reviews in their PBRs. We will consider unbundling utility cost of capital in the generic cost of capital review proceedings as proposed by PG&E and SDG&E in their comments on the proposed decision and will direct the utilities to file applications on May 8, 1998.
In developing this 1998 revenue requirements, the utilities "escalated" their last authorized revenue requirement to account for the effects of inflation on their costs. SDG&E escalated its revenue requirement for transmission and distribution by using the method adopted by the Commission in its PBR for SDG&E’s total revenue requirement.
ORA opposes SDG&E’s escalation methodology on the basis that the mechanism was designed to address the effects of escalation on the combined company. ORA observes that the results provide estimates of transmission and distribution compared to generation that are out of line with actual ratios. ORA proposes instead to determine the percentage of the transmission and distribution revenue requirements compared to the total 1993 revenue requirement and then applying that percentage to the 1996 authorized base revenue requirement.
SDG&E’s method applies most recently adopted PBR escalation rates and is generally reasonable. We therefore adopt it. However, the record shows that SDG&E used the PBR escalation rates only through 1996. In its opening brief and Exhibit 10, SDG&E stated that it will file updates for the transmission and distribution revenue requirements to reflect the authorized 1997 and proposed 1998 PBR escalation rates later this year. Therefore, we will reflect these adjustments to the authorized distribution revenue requirement effective January 1, 1998 in an advice letter filing SDG&E shall file no later than October 15, 1997.
PG&E’s escalation factor of CPI plus 2% for transmission and distribution revenues and Edison’s non-generation escalation factor as adopted in D.96-09-092 were not controversial, and we adopt them.
Edison, PG&E, and SDG&E currently have CEMAs into which they enter costs incurred during catastrophic events. ORA proposes that Commission eliminate the CEMA for generation costs on the basis that it would provide a competitive advantage to utilities. Edison and PG&E’s proposals are consistent with this recommendation. SDG&E’s distribution revenue requirement appears to have no CEMA costs included in it. We adopt the proposals to eliminate CEMA for generation-related costs for all three utilities, effective January 1, 1998.
Edison, PG&E, and SDG&E currently have HSCLSs into which they enter costs associated with hazardous waste clean-up. ORA recommends that these accounts no longer include the costs of generation-related clean-up. Retaining these accounts for generation-related costs would provide a competitive advantage to the incumbent utilities. We adopt ORA’s proposal to prohibit entries into HSCLS which relate to generation costs, effective January 1, 1998. The resulting adjustment to distribution revenue requirements for Edison is $1.36 million and for PG&E is $.1 million. SDG&E did not include an HSCLS balance in its distribution revenue requirement. Therefore, that revenue requirement needs no associated adjustment.
Edison proposes to allocate to distribution revenue requirement the fixed A&G costs associated with fossil generation. These costs, Edison observes, are those that could otherwise be assigned to generation by way of a multi-factor allocation method. Edison believes intervenors’ recommendation to allocate these fixed costs to generation by way of the multi-factor approach would represent "an improper disallowance of appropriately incurred costs" because they are costs Edison cannot recover in competitive generation markets. It argues that these fixed costs would be incurred whether or not it divests its generation assets and that at least some costs are fixed over a period of time. Since they are reasonably incurred, Edison argues, they must be recoverable in rates.
SDG&E and PG&E also allocated A&G costs to distribution which they could not attribute directly to other functions, changing existing allocations to transmission and distribution. PG&E believes it will not avoid such costs if it divests itself of generation. It argues that allocating residual costs to generation would require PG&E to set generation prices that would not be sustainable in competitive markets. PG&E and SDG&E argue that the assignment of only incremental costs to generation is efficient and does not create competitive advantages because competitors will compete based on their incremental costs.
CAC/EPUC and Farm Bureau object to the utilities’ exclusion of A&G costs from generation accounts. CAC/EPUC observe that PG&E’s justification for its method is unsupported by AB 1890 which requires all "going forward " A&G costs to be included in the generation revenue requirement. AB 1890, according CAC/EPUC, does not refer to "incremental" costs or otherwise distinguish fixed costs in ways which would support the utilities’ reliance on AB 1890.
Enron also believes PG&E has shifted A&G costs from generation to distribution based on past allocations used to set FERC jurisdictional rates. CLECA/CMA argue the utilities should not be permitted to use an incremental approach when it suits their interests, as here, and an embedded one when it doesn’t. CLECA/CMA take issue with the utilities’ position that their distribution fixed costs won’t change after their assets are divided in half. CLECA/CMA also observe that the utilities’ approach is anticompetitive because competing firms must ultimately recover all of their costs, not just those that are incremental, from the market.
ORA believes the utilities’ approach applies incremental ratemaking in an exercise that involves embedded costs. It believes the utilities will be able to recover their fixed generation costs readily in the marketplace for generation.
DOD rejects the utilities’ argument that their proposals are consistent with the Commission’s pricing of telecommunications costs based on "TSLRIC" (total service long-run incremental costs). DOD observes that the Commission has specifically required that TSLRIC include all cost components and that the Commission set TSLRIC without regard to embedded revenue requirements. DOD would propose going forward on that basis, believing that the utilities’ corresponding rates would be considerably lower as a result.
TURN and UCAN propose phasing out generation fixed costs at a rate of 25% annually to recognize that fixed costs are variable over time, that is, they may be reduced according to output.
Edison argues that TURN and UCAN have improperly considered cost reductions already reflected in Edison’s cost studies. It believes UCAN and TURN’s phase-out proposal is unsupported by any study of Edison’s actual costs.
Discussion: Some utility costs do not vary over some period of time. They are incurred notwithstanding the utility’s output. It does not necessarily follow, however, that distribution customers should assume liability for all such costs even if the utilities will continue to incur them. The utilities’ argument that they will be unable to recover these costs in generation markets is not convincing. Their competitors also incur fixed costs. Arguably, competitors’ fixed costs are higher per unit of output than the utilities’ because many competitors will not realize the economies of scale or scope which the utilities enjoy. A utility’s generation system, whether it is owned and operated by the utility or any other entity, will continue to incur fixed costs which must be allocated to generation. Moreover, uneconomic generation costs are to be recovered in the CTC, pursuant to AB 1890, not in distribution rates.
Section 367(c) of AB 1890 requires that all "going forward costs" of fossil plant operation must be recovered "solely from independent Power Exchange Revenues or from contracts with the Independent System Operator." We are unaware of any definition that limits "going forward costs" to incremental costs. In this regard, PG&E’s application of economic theory – that its competitors will decide whether to produce an incremental unit on the basis of their incremental costs – is only part of the story. Over time, all generation firms must recover all costs, including those types of costs which the utilities seek to allocate solely to distribution. Consequently, allocating to distribution customers all fixed costs would create a competitive advantage to the utilities at the expense of captive ratepayers, contrary to our stated objectives and the requirements of AB 1890.
We do not agree that allocating generation fixed costs to the generation component of a utility’s revenue requirement will result in an effective disallowance of reasonable costs. If the utilities retain generation facilities, they may recover fixed costs in energy revenues. Fixed A&G costs may also be recoverable as part of "must-run" contracts with the ISO. Both Edison and PG&E plan to sell substantial portions of their generation systems. However, it is important to remember that each utility will retain some portion of its generation assets for which they should pay a fair share of the common A&G costs at issue here.
If they sell generation facilities, the utilities will have opportunities to reduce their overheads. In addition, the utilities may be able to recover fixed A&G as part of the two-year service contract between utilities and purchasers of generation plant required under Section 363.
The utilities have not demonstrated that every type of fixed cost cannot be reduced, that is, made variable, over the medium term by changes in procurement practices (for example, by contracting out payroll processing) or by offering a related service to other businesses (for example, by selling advertising space in bill envelopes) or by reducing employees (for example, by reducing legal employees to recognize reduced regulatory and legal activities). In effect, the utilities argue that substantial economies of scale exist in their vertically integrated operations, a reasonable assumption. To the extent that it is true, we have no doubt that the utilities and their competitors will take advantage of them with a great deal of inventiveness. As CAC/EPUC observe, however, it is impossible to determine at this time how A&G expenses will change in a competitive market or when the utilities divest their generation.
However, we are persuaded that some of these fixed A&G costs may remain following divestiture and the end of the period during which the utility operates the plant on behalf of a purchaser. On the other hand, we want the utilities to take actions to reduce their costs, especially as a result of divestiture.
It is not our intent to deny utilities an opportunity to recover reasonable costs which they actually must incur, but we must balance this with our need to ensure that ratepayers are not paying for costs that no longer exist. To the extent that the fixed A&G costs we have allocated to generation are truly fixed and continue to exist following this period, we will review and reallocate continuing fixed A&G costs to distribution using a streamlined procedure. No such procedure was proposed in this proceeding. The Assigned Commissioners in this proceeding shall develop a streamlined process for this reallocation by December 16, 1997.
Consistent with the principles we have articulated earlier in this decision, we will not allocate to distribution functions the costs associated with other functions at this time. The utilities have presented no compelling reason to stray from this principle in the case of A&G costs. We therefore reduce the utilities’ proposed distribution revenue requirements as follows:
Edison $25.15 million
PG&E $49 million
SDG&E $ 4.90 million
These amounts are calculated on the basis of multi-factor allocation methods provided by each utility pursuant to ORA’s recommendation.
Edison proposes that all A&G costs related to the San Onofre Nuclear Generating Station (SONGS) and Palo Verde Nuclear Generating Station which were not included in the Incremental Cost Incentive Procedure (ICIP) in the related
settlement decision (see D.96-04-059) should be included in Edison’s distribution revenue requirement. The SONGS settlement agreement is in effect through 2003, past the end of the rate freeze period. The Palo Verde settlement ends at the end of 2001. In each of these settlements, a portion of nuclear A&G costs were not included in ICIP or sunk costs. We reject the approach proposed by Edison to include these costs in distribution for the same reason we have declined to include other types of generation costs in distribution rates. Instead, we direct Edison and SDG&E to file a petition to modify relevant Commission decisions in order to include these A&G costs in ICIP because we believe that these costs are appropriately part of ICIP. To the extent that there are above market ICIP costs, they may be appropriately included in transition costs. That is a matter for resolution in A.96-08-001 et al. We therefore reduce Edison’s proposed distribution revenue requirement by $24.51 million.
Edison would allocate to distribution about $23 million for customer service and marketing costs for its large customers. It believes these costs should be included in distribution rates because, consistent with FERC accounting guidelines, they are incurred to educate customers about electric system health and safety, conservation and economic use of electricity. SDG&E would allocate $5 million to distribution for marketing costs, stating that it refers to the associated activity as "marketing" consistent with the FERC’s system of accounts.
PG&E seeks $15.1 million for marketing costs.
TURN and UCAN propose to remove from revenue requirements all marketing costs associated with positioning the utilities in competitive markets. They would allocate such costs, including overhead costs, to generation customers. They observe that the Commission has removed such "brokering" costs from gas rates, costs which are comparable to those referred to here as "marketing." They also present substantially higher estimates of these costs than those presented by the utilities.
Edison replies that TURN and UCAN have improperly characterized these costs as marketing costs. Edison states it will not be marketing generation with associated funds and observes that it will continue to incur expenses relating to customer service research, bypass options, rate design and customer education. Edison also objects to TURN/UCAN’s "arbitrary" assignment of $12.7 million in common plant and overheads to marketing and customer service expenses. SDG&E responds similarly, arguing that large customers are entitled to receive a high level of customer service during this period of dramatic change.
With the introduction of direct access, utility distribution customers will continue to require a high level of customer service with attendant funding requirements. The matter for resolution here, however, is whether and the extent to which the cost of that service is appropriately assigned to distribution revenue requirements. We share TURN/UCAN’s concern that the utilities have allocated more than a fair share of customer service and marketing costs to distribution. Some of the activities the utilities support with that funding are not related to the distribution system, such as providing information regarding bypass options. Most of the activities arguably fall in all three major functional categories, including research and providing information about company policy, procedures, rate design and billing.
We therefore reduce the utilities’ distribution revenue requirements to reflect customer service and marketing costs that are more appropriately allocated to generation. TURN’s estimates appear to assume that all customer service and marketing costs are related to generation. The utilities make reasonable arguments that some of those costs will continue to be incurred notwithstanding the status of their generation operations. Reviewing their general rate cases, we agree that some of the costs in related accounts will be associated with each utility’s distribution operations. Because the utilities did not fulfill their burden to specify the costs which might be attributable to distribution, we adjust the amounts for Edison and SDG&E by applying their respective multifactor allocations methods. This results in an adjustment of $7.7 million for Edison and $.98 million for SDG&E. In its comments, Edison alleges that allocating a portion of economic development costs to generation would be "contrary to law" because we identified such costs as "nongeneration" in Edison’s PBR order, D.96-09-092. Edison fails to acknowledge, however, that D.96-09-092 allocated all other customer services costs to generation. Our decision here to allocate all customer services costs, including those associated with economic development, across all functions therefore gives Edison the benefit of the doubt. For PG&E we make no adjustment because we removed marketing costs from PG&E’s revenue requirement in its most recent general rate case. We therefore do not adjust PG&E’s distribution revenue requirement here for this item.
Franchise fees are payments made to local governments for the privilege of constructing distribution and transmission facilities in local communities and are based on total revenues. Uncollectibles are those losses associated with customers who fail to pay their electric bills. SDG&E and Edison propose to allocate related costs to distribution and transmission.
ORA proposes that SDG&E and Edison be required to allocate some portion of FF&U to generation, consistent with PG&E’s method. If revenues are reduced as a result of divestiture of generation, FF&U should be reduced accordingly. Therefore, we agree with ORA’s proposal and PG&E’s methodology and allocate to generation one-third of FF&U costs. This results in an adjustment of $7.47 million in Edison’s distribution revenue requirement and $ 6.4 million in SDG&E’s distribution revenue requirement.
TURN/UCAN propose that SDG&E be required to update its "miscellaneous revenue" category, which SDG&E shows as $15 million in this proceeding and which TURN believes the Commission increased in D.95-04-048.
D.95-04-048 adopted a number of changes to increase the miscellaneous revenues. Contrary to TURN’s assumption, however, the changes are credited to SDG&E’s Electric Revenue Adjustment Mechanism (ERAM) balancing account. We therefore reject TURN’s recommendation.
All three utilities propose to create additional balancing accounts with associated "nonbypassable surcharges" to customer bills for costs which they believe are uneconomic and deserving of special consideration.
PG&E proposes to create the nonbypassable charge to recover Diablo Canyon nuclear power plant Incremental Cost Incentive Pricing (ICIP) prices that exceed market prices. PG&E states it is authorized to recover such costs because its cost recovery plan, approved by the Commission, provides that these costs would be recovered through a special mechanism rather than through the CTC.
ORA opposes the account on the basis that generation costs should not be recovered from distribution customers. TURN/UCAN oppose the account arguing that the charge is effectively another CTC except in name. TURN/UCAN believe the above-market ICIP may not be collected as CTC. They also believe the issue is appropriately the subject of Phase 2 of the CTC proceeding.
Edison proposes to create a MAM, a balancing account that would serve as the vehicle for recovery of certain costs related to generation, distribution, public purpose programs, and other functions. Costs entered into the account would be recovered by way of a nonbypassable charge on customer bills, which Edison refers to as the Miscellaneous Adjustment Mechanism Billing Factor (MAMBF). Edison’s MAM would initially be a surcredit or rate reduction of $22.24 million.
Edison includes in the MAM revenues and costs associated with non-utility affiliates, costs associated with nuclear spent fuel storage and Department of Energy fees, low emission vehicles and hazardous waste costs, SONGS 1 shutdown O&M expenses and the gain on the Yuma-Axis settlement. It would also include intervenor funding, and the Reduced Cost Recovery Amount (RCRA), Devers-Palo Verde regulatory costs, past earthquake recovery costs (and other costs entered into the CEMA) and the costs of its fuel oil pipeline. In all, Edison proposes to include the costs associated with 39 different activities into the MAM. Edison argues that none of these costs are readily assigned to functional business segments. Because the Commission has found the costs to be reasonable, Edison believes it should be granted dollar-for-dollar recovery of them by way of a nonbypassable charge.
ORA opposes the MAM on the basis that the MAM would permit Edison to recover through distribution charge costs that are related to generation, including SONGS 1 shutdown O&M, hydroelectric pumped storage costs. ORA argues that this balancing account, like others proposed by the utility, is proposed in the name of "guaranteed cost recovery which derails the allocation process."
CLECA/CMA argue that the MAM circumvents the Commission’s objectives in assigning costs to utility functions and violates the spirit of AB 1890 by ignoring the requirement that rates remain frozen. CLECA/CMA believe the utility proposals are offered with the objective of reducing risk beyond that anticipated by AB 1890 and the Commission’s policy.
TURN/UCAN oppose the MAM, arguing that it includes costs that should not be assigned to distribution customers. They oppose the MAM for the same reason they oppose the Diablo Canyon ICIP charge, namely, that the MAM is a CTC except in name and except in the fact that Edison proposes that the MAM continue after the CTC is eliminated in 2002. TURN and UCAN argue that AB 1890 did not permit a balancing account to recover these costs and that the costs are not distinguishable from any other electric base revenue requirement.
SDG&E also proposes to recover $14.26 million in a MAM account which, like Edison’s MAM, would be charged to distribution customers. SDG&E’s MAM would include four cost components, among them the SONGS I shutdown costs, spent nuclear fuel storage costs, Department of Energy (DOE) decontamination and decommissioning costs and SONGS 2&3 costs not recovered by the ICIP pricing mechanism.
SDG&E supports its request by arguing that the Commission has already authorized recovery of these costs. It observes that it may not be able to recover the costs during the period over which the CTC will be in effect. Its MAM, like Edison’s, would be in effect after the CTC is phased out.
TURN/UCAN and ORA oppose SDG&E’s MAM on the same bases they object to Edison’s MAM. ORA observes that SDG&E’s witness on the subject suggested that these costs can be treated as transition costs. TURN and UCAN argue that the SONGS ICIP costs are appropriately part of SDG&E’s base rate revenue requirement and should not be shielded from risk as part of a nonbypassable charge.
We have stated that one criteria for evaluating parties’ proposals here is whether costs are allocated to the function with which they are associated. Many of the costs in these various accounts are related to generation, public purpose programs, or transmission. The utilities nevertheless propose to allocate the costs to distribution, contrary to our stated policy.
We have also stated our intent to retain existing levels of risk in this proceeding. As the utilities admit, these three accounts are designed to reduce utility risk by guaranteeing recovery of certain costs, some of which are currently recovered under different types of ratemaking mechanisms. The nonbypassable surcharges and associated balancing accounts change the mix of risk the utilities face pursuant to Commission orders and AB 1890, contrary to our stated policy.
The utilities justify including these costs in these accounts on the basis that they have already been approved by the Commission. Our past approval of the reasonableness of these costs, however, does not distinguish them from other costs included in other rates or ratemaking mechanisms. The costs recovered through the CTC and in distribution rates, for example, have already been approved in general rate cases. Whether a utility is required to recover, for example, SONGS O&M costs in generation rates or in a MAM account implies nothing about the reasonableness or unreasonableness of those costs. It merely reflects degree of risk which we believe is appropriate for cost recovery and consistent with AB 1890.
In considering the validity of the proposed surcharges, we consult AB 1890. The statute sets forth a complex and comprehensive regulatory framework for restructuring the electric industry. As part of that framework, it mandates the creation of the CTC, a nonbypassable charge, the purpose of which is to provide the utilities with a reasonable opportunity to recover generation costs that might otherwise become stranded in the new market framework. Specifically, Section 367 identifies the regulatory treatment for various types of costs and finds that "uneconomic costs shall be recovered from all customers on a nonbypassable basis" and be amortized over a period which "shall not extend beyond December 31, 2001," with specified exceptions.
The utilities’ proposals here seek authority to impose nonbypassable charges for generation costs which are not authorized by AB 1890. The utilities characterize as potentially "uneconomic" the costs that would be recovered by the charges. The costs are not listed as exceptions to the general provision that uneconomic generation costs are to be recovered through the CTC and amortized prior to December 31, 2001. In addition, the utilities would retain the proposed surcharges after December 31, 2001, providing a regulatory protection which extends beyond the period anticipated by AB 1890 for recovery of stranded generation costs.
As a matter of policy, we question the fairness of transferring risk to captive customers. As a matter of law, the rule of statutory construction provides that "’where exceptions to a general rule are specified by statute, other exceptions are not to be implied or presumed." (Mutual Life Insurance Co. v. City of Los Angeles, 50 Cal.3d 402, 410 (1990).) The costs which the utilities would include in additional balancing accounts or nonbypassable charges are in addition to the exceptions listed in AB 1890 for recovery by methods other than the CTC. To the extent they might be uneconomic generation costs, they must be recovered through the CTC.
The purpose of this proceeding is to unbundle revenue requirements, not to create new ratemaking mechanisms. Just as we have declined to reduce revenue requirements to reflect lower costs in this proceeding and to eliminate existing balancing accounts, we decline to consider new ratemaking mechanisms. Those ratemaking mechanisms are appropriately topics of other proceedings. We are especially concerned with Edison’s proposal to remove from its PBR $20 million annually in costs related to its pipeline terminal company and to change the existing ratemaking incentive associated with nuclear performance to a mechanism which would guarantee recovery of $14.6 million in annual costs.
Finally, we comment specifically on PG&E’s Diablo Canyon ICIP proposal. We observe that we have never authorized the creation of such a charge either implicitly or explicitly. PG&E’s cost recovery plan did not propose such a surcharge, [ We also clearly limit the scope of our approval of the cost recovery plans: "The [utilities’ cost recovery] plans vary considerably in their level of detail. Our approval … covers only the general framework for cost recovery outlined in AB 1890 and the details necessary to launch the program for cost recovery." (D.96-12-077, slip op. At 5.)] although the plan stated PG&E would not recover associated costs through the CTC. In this proceeding, PG&E provides no legal authority for the charge or analysis to support its imposition. Even if we were to interpret AB 1890 to permit such additional nonbypassable surcharges on customer bills, we would reject this one on the basis that its proponent has failed to meet its burden to support it.
The issue remains as to where the costs of the various utility balancing accounts should be allocated. SDG&E’s proposed MAM included only generation costs. They may be recoverable as part of the CTC or SDG&E’s generation rates and require an associated Commission finding in R.94-04-031. Its proposed revenue requirement for distribution is not therefore not changed. Similarly, PG&E’s regulated (that is, distribution and public program surcharge) revenue requirements do not change because the costs associated with Diablo Canyon which are not related to decommissioning would be ultimately allocated to generation costs or transition costs.
Edison’s proposed MAM includes the costs associated with many activities which are attributable to several functions. TURN/UCAN, CLECA, Farm Bureau, and ORA propose specific treatment of each of the accounts’ components. These parties agree with the appropriate treatment of most costs. Where they do not agree, we adopt ORA’s proposals except with respect to the following costs. Costs associated with DOE D&D fees, SONGS 1 shutdown O&M, and spent nuclear fuel storage should be allocated to nuclear decommissioning. For SDG&E, these same costs should be allocated to nuclear decommissioning. As described in Section VII.F., hazardous substance clean-up and litigation cost accounts should no longer include generation related costs after January 1, 1998. The existing HSCLC balances that are generation-related have the characteristics of a regulatory asset. In addition, the Nuclear Unit Incentive Procedure account also has the characteristics of a regulatory asset. As such, disposition of these generation costs is appropriately considered in A.96-08-001 et al. With these modifications, Edison’s distribution revenue requirement is reduced by $73.51 million. Its public program surcharge revenue requirement is increased by $7.113 million. Its nuclear decommissioning revenue requirement is increased by $19.4 million. Appendix B presents how the many types of costs would be allocated among transmission revenue requirement, distribution revenue requirement, generation, the CTC, the nuclear decommissioning surcharge or the public purpose program surcharge. As Edison points out in its comments, account balances allocated to the distribution revenue requirement are all one-time charges and not ongoing costs which would be included in the PBR indefinitely. They should be treated accordingly and would not be subject to the PBR escalation.
PG&E proposes to replace the existing ECAC and ERAM balancing accounts with a "Transition Revenue Account"(TRA). In effect, the TRA is a balancing account for all costs except those subject to PX pricing and CTC treatment. The TRA would guarantee recovery of the authorized revenue requirements.
ORA opposes the TRA partly on the basis that it is the functional equivalent of the ERAM account. ORA observes the Commission has a separate process for evaluating ERAM and ECAC, which is part of the Electric Tariff Streamlining workshop, consistent with D.96-12-088.
We concur with ORA’s observation that the TRA is not apparently distinguishable from PG&E’s ERAM and that the topic is the subject of more comprehensive review in the Electric Tariff Streamlining effort. Moreover, we are not predisposed toward creating new balancing accounts in this proceeding in any event because to do so would compromise our objective of maintaining existing levels of risk, as we have stated.
We adopt the following distribution revenue requirements for the utilities:
Edison $1.67 billion
PG&E $1.95 billion
SDG&E $501.6 million [ To be updated to reflect the distribution portion of SDG&E’s adopted 1997 and proposed 1998 PBR adjustments in SDG&E’s advice letter filing by October 15, 1997.]
TURN proposes that rates adopted in this proceeding be set subject to refund because the utility proposals were inadequate and require reconsideration at a later time. We do not believe, as the utilities argue, such an approach would necessarily represent retroactive ratemaking. On the other hand, we are not inclined to revisit these issues in 1998 because of resource constraints and because we wish to promote some certainty among industry participants, customers and parties to our proceedings on these matters. In reaching this conclusion we recognize that the utility revenue requirements are not ideal. Nevertheless, we believe they are adequate until we review utility revenue requirements in relevant PBR or general rate case proceedings.
Footnotes are bracketed and in blue