Having developed the revenue requirements for each utility, we proceed to determine revenue allocation to customer classes and rate design for various services. Unbundling requires this process of allocating revenues between customer classes in order to get rates for each customer class. Rate design is required in order to determine the types of rates and services available to customers within a customer class.
As stated previously, AB 1890 limits total rates effective on January 1, 1998 to those shown on June 10, 1996 tariffs. The variations between the utilities’ proposals are therefore limited. In general, the utilities propose to retain current unit rates with the exception of mandated reductions to residential and small commercial rates. The parties also appear to agree that the Commission will have to revisit revenue allocation and rate design issues prior to the end of the transition period in order to develop appropriate rates reflecting the removal of the CTC rate component and the associated revenues.
As we discussed under retail Transmission Rate Stipulations (Sec. III), we adopt ORA’s recommendation to use Edison’s EPMC approach on total revenues.
AB 1890 requires that only those customers who receive the 10% rate reduction--residential and small commercial customers--pay off the costs of the associated rate reduction bonds, which will return the costs of the rate decrease to the utilities. SDG&E proposes that only those customers on its Schedule A be eligible for the discount. ORA proposes that time-of-use customers also receive the discount. SDG&E believes this practice would complicate the administration of AB 1890’s requirements.
Notwithstanding any administrative difficulties which may result, AB 1890 requires that residential and small commercial customers receive the rate reduction. In so doing, it does not distinguish between time-of-use customers and others. We therefore require that the utilities offer the reduction to all residential and small commercial customers, including those who subscribe to time-of-use schedules.
Both the Commission and AB 1890 find that some programs should be funded by way of separate billing charges, among them CARE, public purpose programs such as energy conservation and research and development (R&D) efforts, and nuclear decommissioning costs.
PG&E proposes to allocate the costs of public purpose programs using the system average percent method whereby the CARE program costs are allocated first on an equal cents per kilowatt-hour (kWh) basis then, the remainder is allocated according to the percentage share of the schedule’s present revenue requirements relative to the total present revenue requirements. PG&E states that this method is consistent with the current procedure for allocating such costs.
SDG&E and Edison propose instead to allocate these costs on the basis of equal cents per kWh during the rate freeze period. Edison believes using system average costs would be too complicated. SDG&E refers to its proposal as "easy to administer."
DOD, CIU, and CLECA/CMA oppose SDG&E and Edison’s method for allocating public purpose program costs, believing they will shift costs to high load factor customers. CAC/EPUC takes the same position, arguing that Edison’s allocation would violate the provision in AB 1890 that prohibits cost-shifting.
ORA believes direct access customers, utility full-service customers and bypass customers should pay the same amounts for these types of costs. Accordingly, ORA would calculate the charges as if all customers were served on bundled rates. This means direct access and bypass customers would pay proportionally more than full-service utility customers on the basis of their distribution costs.
We direct the utilities to allocate these program costs using PG&E’s system average percent method, which is closest to current cost allocation methods and therefore accommodates AB 1890’s rates freeze and prohibition against cost-shifting. Although the rate freeze eliminates any practical effect of this decision, we agree with CIU and CLECA/CMA that the cost allocation principles we adopt today will as a practical matter serve as the foundation for future debates, if not the ultimate allocations, following the end of the rate freeze period.
The CTC is the ratemaking mechanism designed to recover uneconomic generating costs and other transition costs. Its level is determined one way or another according to the level of other rate elements and with the limitation imposed by the rate freeze mandated by AB 1890.
The utilities propose to calculate the CTC as the residual cost after calculating all other costs, including the PX price. Thus, the CTC would be equal to the difference between the rate at the rate freeze levels and the combination of all other costs – the PX price, the distribution rate, the transmission rate, the public purpose program surcharge and the nuclear decommissioning surcharge. The resulting actual level of the CTC cannot be known in advance. Accordingly, the utilities propose using real-time pricing and "truing up" the difference after completion of the settlements process with the ISO. Under the utility proposals, each customer would be charged for the CTC according to individual demand on an hourly basis. For direct access customers, the CTC would be calculated using the utility tariff schedule the customer would subscribe to if it were not a direct access customer, that is, the "otherwise applicable rate." Both direct access and full-service utility customers would experience CTC rates that vary in an inverse relationship to the PX price.
ORA, the Energy Commission, Enron and Southern Energy Retail Trading and Marketing (Southern) oppose the utilities’ method of calculating the CTC for a variety of related reasons. Southern observes that under the utilities’ proposal customers who pay market prices for generation supply will always pay the same total price for generation regardless of the PX price, masking hourly changes in the price and failing to provide meaningful price signals. It also observes that customers whose generation prices are fixed will pay a lower total price at the time of system peaks. Southern believes customers will not have an opportunity to reduce their costs by shifting load to lower-priced periods, resulting in less efficient use of the electrical system. Southern proposes that the Commission mitigate this problem by requiring that the CTC be fixed over a specified period. In order to assure the rate freeze is not compromised by this pricing policy, it would have the Commission impose a cap on the CTC. It also proposes to create a balancing account to adjust for forecast errors and the cap.
Enron makes similar comments, believing that by creating distortions in the market the utility proposals will discourage direct access. Enron proposes that the price volatility which would result from utility proposals be mitigated with rate design measures. Enron and Southern propose, as an alternative to averaging the CTC, that marketers be permitted to pay the CTC directly to the utility and to have separate arrangements with their own customers for payment of the CTC. The process would not involve the utilities but be a private arrangement between customers and marketers. Southern also seeks information from the utilities with regard to the class average CTC to implement the proposal. Enron also argues that the utilities offer no rational justification for having the CTC vary with load since CTC recovers fixed costs which do not vary with load.
ORA opposes the utilities’ residual calculation of the CTC proposal, believing that it will make hourly pricing, including "virtual direct access" impossible because customers would be charged the same total rate in each hour of a TOU period. ORA argues this compromises the Commission’s objective to provide customers with market-driven prices signals during the transition period, consistent with D.95-12-063. Like Enron and Southern, ORA recommends calculating the CTC charge for TOU customers as a rolling average for each TOU period in the customer’s billing period based on an average PX price and residual CTC rate calculated for the customer’s otherwise-applicable tariff. The Energy Commission makes similar observations and supports ORA’s recommended alternative.
Edison opposes proposals to forecast the PX price, believing that the task would be too difficult. Edison argues that the alternatives proposed by the parties overlook a potential conflict between AB 1890 and a non-hourly calculation of CTC that could lead some customers to pay a higher-than-tariff energy rate, a circumstance that would violate the rate freeze.
PG&E also raises concerns with averaging the CTC, arguing that it masks the total cost of energy and conflicts with provisions of AB 1890 that provide that direct access customers are not treated differently from utility full-service customers. SDG&E observes that the utilities’ method is the only one proposed on the record that assures customer bills will not change due to CTC collection, as it claims is required by AB 1890.
We understand the concerns raised by the parties with regard to the utilities’ proposals to set the CTC residually. It appears that in fact the result will be to mask or severely distort price signals, creating system inefficiencies, especially among those customers who may be able to shift loads and thereby reduce peak system demand. (The price signals incorporated in existing time-of-use rates of course would be preserved.) And customers will fail to realize cost savings from more efficient use of energy, an outcome which is contrary to our intent and to the intent of AB 1890.
The modifications Enron and Southern made to their proposals late in the proceeding eliminated some of the controversy with the utilities. That is, the utilities may implement their methods for calculating the CTC residually, and still accommodate to some extent marketers’ concerns about CTC variability. However, we believe that these solutions and the utilities’ proposed residual method for calculating CTC would create an extra hurdle that might discourage prospective non-utility energy providers from participating in the California energy market. The utilities’ proposals for real-time residual calculation of CTC would potentially require alternative providers to undertake substantial CTC forecast risk in order to offer attractive energy prices. At a minimum, the utility proposals would increase the degree of sophistication necessary to develop attractive direct access or departing load service arrangements.
To prevent any potential barriers to entry of prospective non-utility energy providers and to ensure implementation of effective time-differentiated price signals that have long been one of the paramount goals of our electric restructuring initiatives, we will reject the utilities’ proposals. Instead, we will modify ORA’s proposal by implementing an averaged, ex-post, energy cost for utility service customers that in turn—through residual calculation—provides an averaged CTC rate for all customers. Calculations of the averaged energy costs and the derived averaged CTC charges will be made for each rate class.
Averaging is done first on a weekly basis, and then a rolling average of usually four weeks is calculated to cover the different monthly billing cycles for different customers. The series of resulting approximately one-month averages of PX energy costs is used to calculate residually the corresponding averaged CTC on a billing-cycle basis. We believe that a month is the minimally-acceptable period for calculating the averaged CTC. However we are open to proposals for longer averaging periods and for proposals that use forecasted PX energy costs. We invite parties to collaborate in a workshop format to reach consensus on a proposal that would have a longer averaging period, and/or use a forecast of PX energy costs, and submit such a proposal to us for our consideration no later than October 1, 1997.
In the weekly averaging, utilities shall use hourly PX energy costs in each week and class load profiles for each rate class (the profiles including both utility service and direct access customers) to calculate an average PX energy cost for utility service customers in that rate group. Because billing cycles span multiple weeks, the average PX price for all calendar weeks from the time of a customer’s previous billing through the week prior to the current billing shall be averaged to obtain a monthly average PX energy cost. The resulting averaged PX energy cost shall be applied to all sales to all utility-service customers served on existing rate schedules in each rate group during the billing month, with the averaged CTC charge calculated residually for each schedule and each billing month. Utilities shall implement this method in such a way that customers receiving service under TOU schedules continue to experience their respective frozen time-differentiated total rate levels. Utilities shall apply a similar averaging methodology to any other non-CTC functional rate components for utility service customers that vary with time.
The result of this approach is akin to an averaged CTC that will not fluctuate wildly over time and will be identical for utility-service (including virtual direct access), direct access and departing load customers taking service under the same tariff schedules used for purposes of CTC benchmarking. For bundled-service customers of the utilities, rates will not rise above frozen levels. We find that this design is consistent with the rate freeze provisions of AB 1890. We do not consider instances where customers voluntarily select a service option, like direct access or virtual direct access, that sometimes produces rates exceeding the rate they would have paid on June 10, 1996 to be in conflict with AB 1890. Customers always have the option of returning to a frozen-rate schedule if they wish.
Our approach is simpler to implement than the utilities’ proposals. Utility proposals involve hourly metering of consumption—or proxying such hourly consumption with load profiles—of all direct access and departing load customers, then real-time residual CTC calculation, and finally application of this changing hourly CTC to the real-time load of each direct access and departing-load customer. In contrast, under the approach we adopt here, transition cost recovery calculation is simplified, because the residually-determined amount is a single, stable amount over monthly calculation periods. However, because the utility billing cycle varies for each customer over the week and month, some lag in the process of issuing bills may be required to accommodate our chosen approach for calculating the CTC. Utilities should address this issue in pro-forma tariffs that will be developed in preparation for the workshop to be held in August.
In previous orders we have addressed how customers who do not participate in direct access may opt for "virtual direct access" by relying on real-time (hourly) meters. In D.95-12-063, the Preferred Policy Decision setting out the framework for electric restructuring, we stated our support for virtual direct access and real-time pricing because it would increase system efficiency and offer customers improved service options. In D.97-05-040, our Direct Access decision, we reiterated these goals. We noted earlier the problem with the utilities’ proposals for calculating CTC that they mask the energy cost signals that customers need in order to take advantage of real-time metering options like virtual direct access. Our adopted levelized CTC calculation methodology in fact expressly is designed to overcome that problem by permitting variations in PX energy costs to "shine through," so to speak. In turn, consumers with real-time metering options like virtual direct access can use that valuable information to lower their total energy costs.
Of course, it will be important for utilities to provide new, virtual direct access services and tariff offerings for their customers that would promote the efficient use of energy. We therefore direct the utilities to propose such services and tariffs in their compliance tariff filings. Section 378 allows utilities to offer to propose new services and tariff offerings that accurately reflect, among other things the costs of providing those services. Such new, virtual direct access services would not be bound by the rate-freeze provisions of AB 1890 that apply to existing services.
Baseline rates provide lower cost electricity for the first units residential customers use. Subsequent units are priced at somewhat higher levels. Low income customers receive discounted rates pursuant to the "CARE" program. The parties address the issue of how to set baseline and CARE rates to include the CTC and retain the rate differentials following the rate freeze period. PG&E and SDG&E propose a rate differential between baseline and other rates for the distribution rate and CTC so that the rate structure after the CTC is removed from the utility’s rates would continue to reflect the CARE and baseline rate structure. Edison proposes the differential be reflected only in the CTC during the term of the rate freeze. ORA argues that Edison’s approach does not properly anticipate the period following the rate freeze with regard to baseline rates. TURN/UCAN add that Edison’s proposal compromises Commission objectives to establish cost-based rates. Under Edison’s proposal, the only difference in rates between baseline customers and other customers would be in the level of the CTC.
Edison comments that customers will pay the same baseline and nonbaseline rates, regardless of the differential, because total rates will not change. Edison proposes to revisit the matter at the end of the rate freeze period.
We agree with ORA and TURN/UCAN that Edison’s proposal to reflect baseline differentials only as part of the CTC is contrary to our objective to promote cost-based rates. We therefore adopt the proposals of PG&E and SDG&E for baseline and CARE rates. Edison shall amend its rate design for baselines rates accordingly.
Edison proposes to impose a separate CARE surcharge on customer bills rather than include the costs and discounts of the CARE program in the public purpose programs surcharge. TURN/UCAN oppose this separate surcharge, arguing that Section 381(a) anticipates the establishment of the public purposes program surcharge to fund programs described in Section 382, among others. CARE is described in Section 382.
We concur with TURN/UCAN’s interpretation of Section 381(a) and direct Edison to include all CARE program costs, including the discount, in the public purpose programs surcharges.
Edison currently has a Domestic Seasonal Rate Adjustment which guarantees that Edison recovers distribution and generation revenues which would otherwise fluctuate seasonally. ORA testified that the adjustment would potentially be anticompetitive because it is not available to competitors who may be subject to seasonal revenue fluctuations as well. ORA argues that differing summer and winter distribution rates could create market distortions that could create subsidies or hurdles for competitors. ORA proposes that Edison should be required to justify any proposed continuation of this adjustment in its tariff filing.
We have some concerns about ratemaking conventions which are designed for the sole purpose of shielding the utilities from risk and which might otherwise create market distortions. We cannot however determine how ORA would have Edison further justify the adjustment. We do not eliminate the adjustment here because doing so may change Edison’s risk, an outcome we have stated we will avoid in this proceeding. We may however reconsider the adjustment in the next proceeding which addresses ratemaking issues for Edison.
The utilities propose to implement the 10% rate reduction for residential and commercial customers by providing a bill credit. While no party objects to the proposal, ORA believes customers who receive the rate reduction and subsequently switch to a tariff not subject to the associated charge for paying off the rate reduction bonds, should refund the original rate reduction amounts.
We reject ORA’s proposal on the basis that it sets up a potentially complex mechanism without any providing any substantial benefit to customers, because the number of customers who are able to take advantage of such a scheme unfairly is likely to be small. The utilities bill credit proposal is adopted.
We also adopt the proposal of the Merced Irrigation District to the effect that a customer who leaves a utility system in order to take service from any other entity which must impose a public purpose program surcharge pursuant to Section 385 shall not pay the initial utility’s surcharge going forward because the customer will be paying the charge to the new entity.
The calculation of PX energy charges is critical to residually determining the CTC. Each utility presented a method for this calculation which forms the basis for the credit provided to direct access customers. Edison proposes using the weighted average of the day-ahead and hour-ahead prices, adjusted for administrative costs, settlements, ancillary services, and congestion fees.
Edison proposes to add settlement costs to the PX energy charge in the following billing periods. Edison is the only party who made detailed proposals on how the PX energy price should be trued up after the ex-post settlement from the ISO/PX are received and how the result should be reflected in customers’ bills. The Commission adopts Edison’s proposal for reflecting ex-post settlements.
Edison also proposes that all customers should pay for the costs of unaccounted for energy. If the ISO bills the utility for all unaccounted for energy, Edison would recover these costs from all customers. If FERC approves the proposal contained in the March 31 FERC filing to allocate unaccounted for energy to scheduling coordinators, the cost of unaccounted for energy should be treated in a similar manner as treatment of settlement costs. Edison proposes to incorporate costs that are assigned to all scheduling coordinators into the PX energy charge and to credit these costs to direct access customers. We will direct that any ISO costs that are assigned exclusively to the utility for services provided on behalf of all customers should be recovered from all customers, regardless of generation provider.
We adopt Edison’s proposal to design and escalate nongeneration rates according to the method approved in its nongeneration PBR decision, and then subtract the transmission rates from the nongeneration rates to arrive at distribution rates. In addition, the utilities’ proposed tariffs should present rate design methods for public purpose programs and nuclear decommissioning costs so that these costs are recovered from customers through non-time differentiated energy charges specific to each rate group.
Edison proposes to adapt its Flexible Pricing Options (FPOs) to accommodate the PX market structure and direct access so that several of its FPOs can remain open to new customers, including direct access customers, upon commencement of the PX. We will adopt these uncontested proposals, which Edison believes are necessary in order for it to administer the FPOs as of January 1, 1998.
CLECA/CMA raised issues concerning Edison’s escalation methodology for nongeneration rates, large power rate design and treatment of interruptible credits.
a. Escalation for Nongeneration PBR Base Rates
CLECA/CMA believe Edison’s proposal to keep T&D demand charges fixed is unwise because it is increases in demand, rather than energy consumption, that cause higher T&D costs.
Due to the rate freeze mandated by AB 1890, Edison was prohibited from escalating customer and demand charges above its June 10, 1996 levels. Therefore, in its PBR filing, all escalation amounts were converted to a cents-per-kWh basis and added entirely to base energy charges. The PBR decision specifically authorized all rates to be escalated by CPI-X. Consistent with the PBR decision, it is reasonable to escalate the energy charges.
Edison’s methodology of converting the escalation of nongeneration PBR base rates entirely into energy charges, even for schedules with demand and customer charges, is consistent with current adopted methodology and is adopted.
b. Aligning Schedule Revenues with the Allocated Revenue
Requirement
In instances where Edison’s development of nongeneration marginal cost-based customer and demand charges produce more revenue than the allocated revenue requirement for a particular schedule, Edison has reduced the nongeneration time-related demand charges to align schedule revenues with the allocated revenue requirement. Without this adjustment, nongeneration energy rates would become negative. Therefore, it is reasonable to reflect this adjustment in the next most variable charges.
In instances where marginal cost-based customer and demand charges for a schedule do not collect the allocated revenue requirement, the imposition of an energy charge is appropriate.
CLECA/CMA suggested using an EPMC factor to increase all transmission and distribution components. This is inconsistent with how the nongeneration PBR base rates, which are escalated to arrive at 1998 rates, are established. Also, adjusting these components would result in prices that deviate from marginal costs. We adopt Edison’s methodology.
c. Edison’s Flexible Pricing Options Should Be Unbundled
and Made Available to Both Bundled Utility Customers
and Direct Access Customers
Edison presented testimony on two aspects of its FPOs. The first aspect is the unbundling of these rate options to make them compatible with the availability of a PX price and the Commission’s desire to have the PX price be reflected in customers’ rates without any mark-up or modification by the utility. The second issue relates to making these options available to direct access customers. Customers who may elect to take service on these options should not be precluded from engaging in direct access transactions. From a technical and ratemaking point of view, there are no impediments to making these options available to direct access customers. Edison plans to present the revised tariffs to accomplish this object in the tariff phase of this proceeding. We adopt Edison’s proposal.
d. Interruptible Credits
Edison has proposed to reflect the interruptible credit in a lower CTC charged to interruptible customers. CLECA/CMA made an alternative proposal to reflect some of this credit in a lower transmission charge. We adopt Edison’s proposal in part because we have no jurisdiction over transmission charges and seek to resolve the matter here.
Edison has proposed to use average loss factors to calculate costs associated with line losses, and to recover these costs from all customers as a non-PBR distribution rate component. PG&E and SDG&E did not address this issue.
CLECA/CMA proposed a formula for computing hourly distribution line loss factors. CLECA/CMA developed these factors from Edison’s average factors used in Edison general rate cases. ORA supports the CLECA/CMA methodology.
Testimony of ORA, CLECA/CMA and Edison concerning the settlements process supports the importance of using accurate hourly allocation factors in minimizing system-wide costs and ensuring accurate cost allocations that avoid cost shifting. We believe CLECA/CMA’s methodology accurately represents these losses and therefore we adopt it. We direct PG&E and SDG&E to file similar proposals for implementing hourly distribution line loss calculations in their Advice Letter filings.
Footnotes are bracketed and in blue