V. Revenue Allocation
Having determined the revenue requirement amount each utility is authorized to collect for itself and CDWR under the 3¢/kWh surcharge, the next step is to establish a rate structure that will enable Edison and PG&E to collect this revenue from its customers. The two principal issues concerning revenue allocation are: (1) the method used to apportion the revenue increase among customer classes; and (2) the treatment of the shortfall which results from exempting residential usage up to 130% of baseline consumption from any increase.
It is equally important to realize what we are not doing. While the incremental revenue created by the surcharge is material when compared to the total revenue of the utilities, in this proceeding, the Commission is not setting aside all previous revenue allocation and rate design. The allocation and rate design issues addressed in this decision are limited to allocation and design of the revenues to be collected pursuant to the surcharge. The underlying rate structure of the utilities will not change. Consequently, in this decision we affect only a fraction, albeit a significant fraction, of the charges imposed on customers. For residential customers, by Legislative order, we exempt approximately half of all sales. The scope of this proceeding does not include a complete revamping of all charges, just this surcharge.
A. Revenue Allocation Methodology
Traditionally, revenue allocation has reflected cost causation. For the last several years, the Commission has allocated revenue based on the fact that the costs of providing service vary with the amount and duration of energy consumption, and with the facilities used to provide service. The Commission also found that it cost a utility more to deliver a kWh of energy during periods of peak demand than during non-peak periods. The fundamental facts underlying such ratemaking have changed. We have a dysfunctional wholesale energy market that has resulted in unconscionable, unlawful wholesale prices, which have increased by staggering proportions since the summer of 2000. These prices bear no relationship to any actual costs incurred in production. In fact, Califonria has experienced Stage 2 and 3 emergencies and rolling outages during off-peak times.
While we acknowledge that the fundamental ratemaking facts have changed, we underscore the fact that the basic costs of production, other than fuel, have not changed. Simply put, the outrageously priced wholesale energy that causes us to take the extraordinary step of imposing this rate surcharge is being produced at the same plants upon which we based our traditional cost allocation procedures. In that respect, the fundamental facts of energy production have not changed. What has changed is that California is beset by wholesale sellers intent upon maximizing revenue without limit, and federal regulators refusing to impose any limitations. The price of wholesale energy is no longer a function of cost of production but rather a function of what price can be extracted from a market subject to manipulation.
Further compounding our dilemma is the fact that CDWR has not yet presented us with cost forecasts for the supply contracts CDWR is negotiating. Absent this data, we must look to other methodology to allocate the revenue to be collected from among the customer classes. Parties have proposed several methods for allocating revenue from the surcharge. We describe these briefly below.
Historic Generation Cost Allocation - this methodology allocates the incremental revenue requirement based on the percent of generation revenues contributed by each customer group prior to adoption of the 3¢/kWh surcharge. Prior to making the allocation, the revenues must be adjusted to remove the effects of the Rate Reduction Bonds transaction and nonfirm service credits to interruptible customers.
On Peak Energy Use/Top 100 hours - these two methods allocate costs based on the customer group's share of either summer on peak energy use or 100 hours of highest system demand.
1999 Power Exchange (PX) Generation Charges - this method allocates revenue requirement by each customer group's contribution to 1999 PX costs
Equal cents per kWh - this method divides the revenue among the customer classes based on the total number of kWhs each class is forecast to consume during calendar year 2001.
Our task here is to devise a rational basis for choosing one alternative revenue allocation methodology over another in a market setting that defies rationality. The record demonstrates that (1) the traditional rules of cost causation are no longer reflected in wholesale energy prices, and (2) there is no reason to believe that any of the suggested alternatives will be better at predicting cost causation in this market.
All but one of the suggested alternatives ignore the simple fact that the price of wholesale energy is completely divorced from cost. The PX prices at least use recent historical data to attempt to predict what prices will be prevalent this year. These prices, however, ignore the CDWR purchases, for good reason, as those prices are not available, as well as the other factors specific to this summer such as drought conditions in the Northwest which will seriously curtail the availability of hydro generation.
Recent price experience, however, suggests that all kWhs will be valuable. In this volatile and dysfunctional market, we cannot predict which kWhs will be more valuable than others. For example, California has experienced blackouts in an off-peak season, at an off-peak time of day. Several actions could further enhance the value of off-peak energy. Customers currently on TOU schedules may engage in more aggressive load shifting, such that off-peak loads increase, decreasing the differential between off-and on-peak. In addition, it is possible that the drought in the Northwest may give us opportunities to run California fossil-fuel-fired generation at night and allow us to sell power to the Northwest. These, and many other possibilities and unanticipated events, all unpredictable in the volatile energy market, could impact the value of energy at particular times.
We recognize that we cannot devise an optimum solution. In choosing among these proposals, at least two parties referred us to the works of preeminent ratemaking expert James C. Bonbright. Mr. Bonbright's teaching provide us comfort but, unfortunately, little concrete guidance:
[R]ate structure problems are far more complex than problems of a fair return even though the latter are by no means elementary; and they are even less amenable to solution by reference to definite principles or rules or rate making. In part, the complexity is due to the mass of technical detail, including the technology of metering, involved in the design and administration of workable rate schedules for different types of utility enterprises. In part it is due to the inability of the rate maker to predict the effect of changes in rates on demand for the services and hence on costs of supply - due, in short, to ignorance of demand functions and cost functions. But in part - and this is the most serious theoretical difficulty - it is due to the necessity, faced alike by public utility managements and by regulating agencies, of taking into account numerous conflicting standards for fairness and functional efficiency in the choice of rate structure. . . . [B]y way of illustration, we may note the conflict between the desirable attribute of simplicity and the otherwise desirable attribute of close conformity to the principle of service at cost. Here, as with other clashes among various desiderata of rate-making policy, the wise choice must be that of a wise compromise; and in reaching this compromise, the practical rate expert would look in vain to any general theory of public utility rates, at least in its present stage of development, for a scientific method of reaching the optimum solution. Bonbright, James C., Principles of Public Utility Rates, p. 288-9 (1961).
Allocating the revenue requirement to customer classes based on the proportion of 2001 forecast total kWh sales to the class drew support from PG&E, ORA, TURN, and Aglet.13 These parties chose the methodology for equity considerations and also because the methodology best reflects the surcharge's primary purpose: to provide funds for CDWR to purchase electricity in the wholesale market at a time when those costs are expected to be higher in all hours of the year as compared to the costs incurred during the same period in previous years.14 The surcharge is in place to provide the additional funds necessary to provide for customers' energy consumption and we have previously determined that generation costs associated specifically with energy consumption are properly recovered using an equal cents per kilowatt hour methodology.15
There is little cost data available on the wholesale purchase costs that will be necessary for this summer and the rest of 2001. The dysfunctional wholesale market has created a unique crisis of unknown duration for California electric customers. No class of customers believes that it is responsible for these price increases, and thus no class of customers wants to pay for increased wholesale electric costs.
ORA equates the rate surcharge to a tax to pay for a disaster or emergency - in this case, the electricity crisis. Applying the surcharge as broadly as possible is the fairest way to apportion the noncost-based price premium being extracted by wholesale generators and should help our choice of apportionment gain the widest public acceptance.
An equal cents per kilowatt-hour is the most equitable revenue allocation methodology as well as the methodology most appropriate to apportioning energy purchase costs to all future energy consumption. This allocation methodology is also simple, understandable, and consistent with our approach for the one cent surcharge adopted in D.01-01-018. Therefore, we find that the revenue requirement associated with the 3¢/kWh surcharge adopted in D.01-03-082 should be allocated among the customer classes16 based on the proportional number of kWhs each class is forecast to consume during calendar year 2001.
B. Revenue Requirement Shortfalls
Having completed the allocation of revenue across the customer classes, we must now address the revenue shortfalls resulting from exemptions to the surcharge. Because the exempt sales will not be contributing the revenue requirement assigned to them via the allocation process, this revenue requirement must be re-allocated to other sales.
1. Usage Under 130% of Baseline
In AB X, the Legislature added section 80110 to the Water Code, effective February 1, 2001:
In no case shall the commission increase the electricity charges in effect on the date that the act that adds this section becomes effective for residential customers for existing baseline quantities or usage by those customers of up to 130 percent of existing baseline quantities, until such time as the department has recovered the costs of power it has procured for the electrical corporation's retail end use customers as provided in this division.
This section exempts 130% of "baseline" usage. Baseline usage is defined in § 739(a). That section requires the Commission to establish a quantity of gas and electricity that is necessary to supply a "significant portion of the reasonable energy needs of the average residential customer." This "baseline quantity" is defined to be between 50 and 60% of average residential consumption, with allowances for seasonal and climatic variations, in § 739(d)(1). The Commission is further directed to require the utilities to file residential rate schedules that provide for the baseline quantity to be the first or lowest block in a increasing block rate structure. In addition, the Commission is directed to "establish an appropriate gradual difference between the rates for the respective blocks of usage." § 739(c)(1). In 1976, the Commission determined the initial baseline quantities in D.86087, 80 CPUC 182. Subsequent revisions and updates to the baseline quantities and applicable rates have been done in the utilities' general rate cases. The currently applicable baseline quantities and rates are set out in PG&E's residential tariff schedules and in Section H.3. of the Edison Preliminary Statement.
Taken together, new Water Code § 80110 and Pub. Util. Code § 739, exempt a significant share of each utility's residential sales. This exemption protects residential consumers under baseline and protects the class as a whole by providing a measure of protection to at least some portion of their service. This statutory exemption raises the issue of how this shortfall should be recovered and from other customers. The shortfall is significant: In Edison's territory, 64% of residential sales are exempt, and 62% are exempt in PG&E's territory.
As ORA states, there are three proposals for allocating this shortfall. The first option is to recover the shortfall within residential rates. The second is to reallocate to all eligible sales, and the third is to allocate the increase to all nonresidential sales.
TURN proposes that the revenue requirement be re-allocated to all non-exempt sales. TURN reasons that (1) the plain language of § 80110 is silent on the issue, and (2) the Legislature knows how to and has prohibited cost shifting when it so desires. Because cost shifting is not prohibited, the Commission should re-allocate the revenue requirement to all non-exempt sales. TURN also offered Exhibit 98 that is an informal analysis from a rate design expert to Senator Bowen, Chair of the Energy, Utilities, and Communications Committee. Exhibit 98 evaluates setting the exemption at 125% versus 150% of baseline, and compares the resulting subsidies of residential customers by nonresidential customers. Inherent in this analysis is the assumption that the shortfall would be allocated to nonresidential customers. Based on Exhibit 98, TURN concludes that the Legislature was well aware of the cost-shifting implications of this exemption. TURN also notes that such a re-allocation would be consistent with treatment of the CARE subsidy.
Aglet also recommends allocation of the shortfall to all customer classes. Aglet argues that: (1) allocation only to residential usage would yield unreasonably high rates in higher tiers, (2) such severe rate changes would be contrary to Bonbright's principles regard stable rates, (3) revenue shortfalls caused by legislative mandates are more like taxes than costs caused by any particular customer class, and (4) allocation to all customer classes would be consistent with allocation of CARE discount costs.
All other parties17 addressing this issue propose to re-allocate the revenue requirement to all residential sales that are not included within the exemption. PG&E states that the Commission's usual practice is, where cost re-allocation is required, to keep such costs with the customer class. PG&E points out that revenue shortfall created by baseline rates is re-allocated solely within the residential class. Edison adds that the Governor in his rate design proposal uses this re-allocation methodology.
Under the re-allocation method supported by most of the parties, the residential customer group would be allocated significantly more of the revenue requirement, and see a significantly greater rate increase. Exhibit 111
shows the following comparison of the rate increase that would result from the competing re-allocation methods for two groups of Edison customers:
Non-exempt All Non-
Residential only Exempt
Residential 22% 9%
Large Power 36% 43%
The residential customers would also see significantly greater changes in prices for higher tier usage. For example, PG&E's E-1 General Residential rate schedule would show the following increases under the two alternatives:
Allocated to Allocated to
Non-Exempt All Non-
Residential only Exempt
Tier 1 (0 - 100%)18 11.419 12.520
Tier 2 (100 - 130%) 13.0 14.32
Tier 3 (130 - 200%) 19.5 16.66
Tier 4 (Over 200%) 28.9 20.30
One of the criteria for desirable rate structure advocated by Professor Bonbright is that the rates are stable, with a minimum of "unexpected changes seriously adverse to existing customers."21 The price increase that a customer would see should the customer's usage move from Tier 2 to Tier 3 spikes dramatically under the "only non-exempt residential" methodology, but is more gradual (although still high) under the other methodology.
Guided once again by Professor Bonbright's directive to make wise choices, we find that re-allocating the revenue requirement associated with sales that are exempt from paying the surcharge solely to the narrow range of remaining residential sales is too severe. The cost of this legislatively-mandated exemption should be broadly assessed across all customer groups. We find that the revenue requirement shortfall caused by applying the 3¢/kWh surcharge approved in D.01-03-082 to sales to residential customers below 130% of baseline shall be re-allocated to all sales other than residential sales below 130% of baseline. Therefore, we adopt the TURN and Aglet method of capturing the revenue shortfall. This method spreads the shortfall to all eligible consumption, including residential sales greater than 130% of baseline. We treat the shortfall in the same way we allocate CARE shortfalls, as a subsidy. The amount is spread to all eligible customer classes on an equal cents per kWh basis.
2. CARE and Medical Baseline Exemption
We also find that the revenue requirement shortfall caused by exempting CARE customers from the 3¢/kWh surcharge approved in D.01-03-082 shall be re-allocated to all sales other than sales subject to the CARE program and residential customers with usage of or less than 130% of baseline.
In D.89-09-044, the Commission implemented modifications to its Low-Income Rate Assistance (LIRA) program that provided a 15% discount to low-income customers, and created a LIRA surcharge to recover the amounts necessary to fund the program. Re Investigation on the Commission's own Motion to Comply with Senate Bill 987 and Realign Residential Rates, Including Baseline Rates, of California Energy Utilities, (1989) 32 CPUC 2d 406, 419. The decision exempted several customer groups from paying the LIRA surcharge primarily due to contractual obligations of the utility, the potential for double-paying, or statutory requirements. In addition, the decision exempted streetlighting:
Street lighting shall also be exempt because such service is ultimately paid for by taxpayers, who will already contribute to the LIRA program as ratepayers. 32 CPUC2d at 416.
The LIRA program was subsequently renamed CARE in § 739.1. Cal- SLA relies on this decision, and others, for the proposition that "street light customers are not to be burdened with revenue allocated from the CARE discount." PG&E disagrees, contending that the previous Commission decision applied to allocating the cost of the discount for low-income service. At issue in this proceeding, in contrast, is allocating the revenue requirement for an overall surcharge.
We agree with PG&E. Whatever may have been the validity of the 1989 justification to exclude street lighting from its fair share of this program, that justification is not applicable here. This allocation is not a revenue requirement necessary to fund the low-income discount program, from which street lighting continues to be exempt, but rather a general surcharge covering procurement of electricity. It should be allocated as broadly as possible to achieve our goal of equity.
The purpose of the medical baseline allowance is to protect those customers with medical conditions that require the use of electricity to protect their health and well being. Current Commission-approved tariffs provide qualifying customers with a medical baseline quantity of approximately 16.5 kWh per day above the standard baseline allowance. Medical baseline allowances are required by § 739(b)(1).22 We also adopt an exemption of the rate increase for this customer class. The utilities' data show that PG&E has approximately 40,044 customers on a medical baseline allowance and Edison has 12,222, for a total of 52,266. Approximately 35% of these customers are in the CARE program and would be exempt from these charges. Because of the extraordinary size of the rate increase, it is reasonable to mitigate the impact to the remaining customers on medical baseline who are among the most vulnerable customer classes. This exemption will be allocated using the same methodology as the CARE exemption. The utilities should reflect the exemption of medical baseline customers in the tariffs they file pursuant to this order.
While no party objects to the medical baseline exemption, it was not discussed at hearing. Therefore, Edison states in its comments and at FOA that it has not included this exemption in its billing system modifications for June 1, 2001. Edison states it can make the billing system changes by August 31, 2001. PG&E states it will be able to implement this exemption into its billing system by June 1 and has already begun expedited work on this relatively limited systems change. Edison should notify all its medical baseline customers by certified letter prior to June 1, 2001 that they are eligible for this exemption and will be given a refund of the surcharges on their September 2001 bills.
3. Direct Access Customers
In this decision, we must consider whether direct access customers should be required to pay any of the rate increase. Direct access customers should be exempt from the surcharge as direct access customers are purchasing their own power and are not relying on the utilities. Furthermore, direct access customers do not contribute to the net short that the CDWR is procuring on behalf of the utilities. The surcharge adopted in D.01-03-082 is intended to provide payment for power purchases and delivery to utility customers. Neither the utilities nor the CDWR procure power for direct access customers. Instead, by definition, direct access customers receive their energy from their Energy Service Provider (ESP). It would be inequitable for direct access customers to pay for both their own cost of procurement and the procurement costs of bundled customers. We do not refer to direct access customers in D.01-03-082 and this surcharge should not apply to direct access customers.
C. Amortization of Rate Increase as of March 27, 2001
We issued D.01-03-082 on March 27, 2001, and stated that the rate increase became effective as of that date. That decision also obligates Edison and PG&E to collect and remit to CDWR a generation-related rate including the 3 cent/kWh surcharge. Today's decision determines the specific rate allocation and design of the surcharge for collection beginning June 1 for PG&E, and June 3 for Edison. During the intervening time, March 27 to the date Edison and PG&E begin applying the surcharge, the rate increase was effective, but not yet collected. PG&E and Edison therefore seek to collect the revenue shortfall from this time period over some period in the future.
Aglet and TURN contend that the rule against retroactive ratemaking prohibits collection of these amounts, because no balancing or memorandum account has yet been established to authorize such collection.23 This point is irrelevant. Section 728 requires the Commission to determine the rate "to be thereafter observed and in force." The right to recover the revenues equivalent to the three-cent surcharge was established by D.01-03-082 and affected only electricity delivered from the effective date of that decision forward. Similarly, the precise charges to be collected from customers to recover those revenues will be effective prospectively after the date of today's decision. We see nothing retroactive here that could possibly violate § 728.
TURN's argument assumes, without citation, that creation of a balancing or memorandum account is the only method whereby the Commission can allow a utility to collect sums at a later date. This is simply not so. At most, what § 728 requires is that there be a prospective authorization to recover the revenues.24 While the Commission often accomplishes this result through balancing or memorandum accounts, that method is not required by § 728.25 Accordingly, we see no possible violation of any prohibition against retroactive ratemaking here.
In its comments on the PD and AD, TURN continues its argument that what we are doing here is inconsistent with past Commission precedent. However, in D.99-11-057, 26 we stated that following the usual practices in creating memorandum accounts is not the sine qua non for avoiding retroactive ratemaking problems. Thus, for example, while it is often our practice to make memorandum accounts effective from and after filing or approval of a specific tariff sheet, D.99-11-057 emphasized that memorandum accounts could become effective before such date without causing retroactive ratemaking problems so long as the effective date of the memorandum account was on or after the date of a sufficient Commission authorization of the related rate increase. As pointed out above, and as Aglet's comments note and then apparently refuse to recognize, D.01-03-082 expressly stated, at page 3: "We adopt this increase effective today." We find neither TURN's nor Aglet's comments persuasive.
Therefore, we determine that the revenue associated with applying the 3¢/kWh surcharge to all non-exempt energy sales from March 27, 2001, to the day utilities begin collecting the surcharge should be added to each utility's revenue requirement. We will authorize the utilities to amortize the unrecovered amount over 12 months, as PG&E proposes. TURN agrees that should the Commission reject its retroactive ratemaking argument, discussed above, then a 12-month amortization period is reasonable. From a standpoint of equity, a three-month summer amortization would undoubtedly cause undue stress on summer rates, which will already be very high. The three-month surcharge also places a severe hardship upon summer intensive industries, especially the agricultural industry, which did not contribute significantly to the shortfall.
