IV. Revenue Allocation Between Customers
Having determined the revenue each utility is authorized to collect from customers, we next design rate structures that will permit the utilities to collect the authorized amounts for themselves and as agents for CDWR. We must decide generally how to allocate the revenue increase among customer classes. We must also allocate the shortfall that results from exempting CARE-eligible customers, medical baseline customers, and residential usage up to 130% of baseline consumption from any increase.
The allocation and rate design adopted today concern only those non-exempt customer classes that will pay the 3¢/per kWh surcharge adopted on March 27th. The underlying rate structure of the utilities will not change. Consequently, this decision affects only part of each customer's electricity bills. By operation of the statutory safe harbor, more than 60% of residential customer sales will be exempt from this and further rate increases.
A. Methodology for Revenue Allocation Among Customers
For the last several years, the Commission's policy has been that rates charged to various types of customers reflect the costs those customers impose on the utilities' systems. However, no customer is causing the exorbitant electricity prices faced by the utilities and CDWR. Thus, it would be unfair to attribute the current wholesale market prices as caused by any particular type of customer.
California's wholesale energy market is irrational, dysfunctional and the prices set in that market are unconscionable and unlawful. These prices bear little, if any, relationship to actual energy production costs. While wholesale prices in California markets have changed and indeed have skyrocketed, the basic costs of production, other than fuel, have not. Simply put, the outrageously priced wholesale energy that forces us to take the extraordinary step of imposing this extraordinary 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 and federal regulators who refuse to impose any limitations on those sellers. The price of wholesale energy bears no relationship to the cost of production, but is rather a function of what price can be extracted from the California market through manipulation.
Without a rational relationship between costs and rates, we must rely more on other factors to allocate the revenue to be collected from electricity customers. The parties to this proceeding presented several options:
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.
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 the 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 units of energy each class is forecast to consume during calendar year 2001.
The Historic Generation Cost allocation proposal and the 1999 PX Generation Charges proposal both suffer from the same flaw. Current costs bear no resemblance to the historic costs that underlie both those methodologies. No party has presented analyses that demonstrate that historic cost information is a reasonable means of allocating current costs, or that these historic cost-based allocations would not substantively change if revised to reflect the costs being incurred today. This concern was addressed by a number of parties, including ORA, which stated the following:
Rather than basing allocations on current conditions, many parties seem to be relying on entirely different conditions such as existed prior to the crisis. They implicitly assume that current cost conditions are similar to those extant when the utilities owned the majority of the generation plants, and when the majority of the generation costs were predictable and orderly. These conditions no longer exist.
Edison and FEA recommend allocating the revenue surcharge based on equal percent of generation costs. The current generation component of rates is based on rates in existence in 1995 before A.B. 1890 went into effect. During various phases of implementation proceedings for A.B. 1890, rate components were unbundled. Components for cost items such as distribution, transmission, CTC and public purpose programs and other costs were subtracted from total rates to determine the generation component on a residual basis. The 1995 rates were partially based on usage and costs from the years before 1995. The data used to calculate the 1995 rates is outdated and a proper calculation of these costs today would almost certainly result in different rates. Calculating the generation component directly would yield a different value than a residual calculation as was done in the unbundling proceedings. While Edison's and FEA's methodology has a surface plausibility, it is based on stale information and customer usage data. Thus, it would be improper to base the allocation of the surcharge on outdated and residually determined generation costs. Current generation costs were calculated under different conditions, when marginal energy costs were below average energy costs. Marginal energy costs (as measured on the spot market) currently far exceed historical average costs. ORA Brief, Page 10
Perhaps the most dramatic illustration of how different costs and conditions are now compared to 1995 is the fact that marginal energy costs for off peak hours were based on inexpensive energy imports in 1995. Currently, energy imports are far from inexpensive and are hard to obtain. ORA Brief, Page 12
We cannot conclude based on the record before us that either the Historic Generation Cost Allocation or the 1999 PX Generation Charges approach will result in an equitable allocation of the costs currently being incurred in California.
The On Peak Energy Use/Top 100 Hours proposals also are problematic. These approaches essentially assign more of the high energy costs being incurred round the clock today to those customers which use the most energy during summer peak hours. As stated by Edison's witness Jazayeri, "...top 100 hours is a method more suitable for allocating capacity costs. And I'm not sure it does a good of allocating energy regulated costs." (Jazayeri, Edison, Tr.,Vol. 18, p.2338)
There is no evidence to suggest that the high costs that have been incurred over the last year, and primarily during the most recent winter and spring, are in any way related to summer peak usage. In fact, CIPA witness McCann stated that prices are currently ten times higher in both summer peak and non-summer peak periods compared to 1999 (CIPA witness McCann, 18 RT 2390-2391). FEA witness Brubaker concurred that prices are consistently higher through all time periods, stating "But costs have gone up in all periods, which is why I think a percentage applied to the existing generation recoveries makes sense. It hits every period, every kilowatt-hour with some responsibility for the additional costs." (FEA witness Brubaker, 19 RT 2504). We cannot find that a method of allocating the current high costs that is based solely on summer peak usage is equitable.
Given that energy costs are high in all time periods, and that there is no compelling evidence to support allocating these costs more to one type of customer than another, we find that applying the surcharge as broadly as possible is the fairest way to apportion the non-cost-based price premium now extracted by sellers in the California wholesale electricity market. The Equal Cents Per Kwh proposal best meets this criterion. We think this methodology will gain the widest public acceptance as all other cost-based fine distinctions among customer classes pale in comparison to the magnitude of the sellers' profit premiums now attaching to every kilowatt sold into California's wholesale market. This is also consistent with the Commission's allocation of the 1 cent/kwh surcharge authorized in January of this year.
In addition to equity, another goal of our rate design is to spur conservation. As addressed in more detail below, the use of the Equal Cents Per Kwh approach, combined with an equally broad allocation of revenue shortfalls, results in substantially higher rates for all classes of customers. Industrial, large and small commercial and non-exempt residential usage will all see rate increases of over 4 cents per kwh, with the non-exempt residential seeing the highest increase. This will promote conservation from all classes of customers.
The other allocation methods rejected by the Commission would have further burdened the non-exempt residential demand, while reducing the increase for other customer classes. This appears inequitable, since the non-exempt residential usage already will see the highest rate increase. Further shifting costs to the non-exempt residential would also appear to undermine conservation incentives as only 11% of total usage (based on 2000 usage data) can be affected by allocating price increases to the non-exempt residential class.
As the chart above demonstrates, the non-exempt residential usage (which is the only portion of residential rates that the Commission may increase) is only about 11% of total system energy deliveries for Edison and PG&E. Further increasing the rates for this 11% of usage, while decreasing the rates for customers with over 60% of total usage would reduce the incentive for conservation for most of the demand of the utilities. The non-exempt residential demand will already see the highest rates of any customer class. Further increasing this disparity, as would happen under the rejected methodologies,
would likely result in less overall conservation than if rates were more evenly matched among customer classes.
Allocating the revenue requirement to customer classes based on the proportion of forecast 2001 sales to the class most closely meets the twin goals of equity and conservation within the parameters set by AB1X's exemption. Moreover, such allocation would 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 than they were during the same portions of previous years.
Certain usage is exempted from rate increases by statute (residential usage up to 130% of baseline) or by our prior decisions (low-income CARE-eligible customers); we address the steps in allocating these revenue shortfalls below.
B. Revenue Requirement Shortfalls
1. Allocating the 130% of Baseline Residential Revenues
Next, we must allocate the revenue shortfalls resulting from exemptions to the surcharge. In AB1X, 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 statute exempts from additional rate increases all residential electricity usage that falls within 130% of "baseline" usage. Baseline usage is defined in Section 739(a). That section requires the Commission to establish a quantity of natural gas and electricity that is necessary to supply a "significant portion of the reasonable energy needs of the average residential customer." The "baseline quantity" is defined to be between 50 and 60 percent of average residential consumption, with allowances for seasonal and climatic variations, Section 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 an increasing block rate structure. Section 739(c)(1). In addition, the Commission is directed to "establish an appropriate gradual difference between the rates for the respective blocks of usage." Section 739(c)(1). In 1986, 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 made in the utilities' general rate cases.
Taken together, new Water Code § 80110 and Pub. Utils. Code § 739, exempt over 60% of residential sales from the 3¢/kWh rate surcharge we authorized March 27th. The resulting shortfall is significant: 64% of all Edison residential sales are exempt, and 62% of all PG&E residential sales are exempt. These use exemptions result in half of all residential customers-those who use less than 130% of baseline-being protected by statute from further rate increases.
TURN proposes that we simply not collect revenues relating to the power purchases which correlate to energy usage by exempt customers. TURN's approach results in revenue requirements insufficient to cover power purchase costs. Thus we will recover these revenue requirements by reallocating the revenue among non-exempt customers. We have before us three proposals for allocating this shortfall. The first is to recover the shortfall within residential rates. The second is to reallocate it to all eligible sales, and the third is to allocate the increase to all non-residential sales.
TURN and Aglet propose that the revenue requirement be re-allocated to all non-exempt sales, observing that § 80110 is silent on the issue. Other parties addressing this issue propose to re-allocate the revenue requirement to non-exempt residential sales only. Under the non-exempt residential only re-allocation method, the residential customer group would be allocated significantly more of the revenue requirement and incurs a significantly greater rate increase. The rate increase for Edison customers for the two methods is as follows:
Allocation to Non-Exempt Residential Only |
Allocation to All Non- 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 experience the following increases under the two alternatives:
Allocating the entire shortfall only to residential customers creates dramatic price increases from Tier 2 to Tier 3 usage. Spreading the exempt-related revenue requirements to all non-exempt customers creates more gradual (although still significant) rate increases in the non-exempt residential customer classes as usage progresses into the higher tiers.
Re-allocating the entire revenue requirement shortfall to remaining residential sales creates rate spikes that are too severe. Moreover, reallocating the entire exempt customer revenue shortfall only to the remaining non-exempt residential customers fails to produce much additional conservation benefit, as discussed in Section IV A. Thus, the shortfall from this exemption should be allocated equally to 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 three major customer groups equally. This method spreads the shortfall one-third to the residential class, one-third to commercial customers and one-third to industrial customers, an outcome that takes a middle path between allocating the shortfall equally to all usage, and proposals by parties to allocate the entire shortfall within the residential class. We believe that this method is the most consistent with the legislative intent of AB1X.13
We note the concerns expressed by the representatives of industrial customers, CLECA, EPUC and CMTA, that our equitable allocation unfairly results in much larger average increases for industrial customers than for residential customers. (May 10 Joint Comments of EPUC, CLECA and CMTA, page 8). However, their argument fails to consider that the majority of residential usage has been statutorily exempted from any rate increases that this Commission might impose. When the prohibition of increasing rates for residential usage up to 130% of baseline is factored in, the cost allocations adopted in this decision result in higher percentage and cent/kWh increases for non-exempt residential usage than for any other customer class, including industrial. Thus, we do not find the concerns of these industrial representatives regarding the equity of our cost allocation to be compelling. If anything, their own arguments, when corrected to account for mandated exemptions, suggest that additional costs could be shifted to non-residential customers.
However, we are convinced by the arguments presented by the California Industrial Users (CIU) that the rate increases adopted today may have a significant negative impact on business and the California economy. (May 10 Comments of CIU, pages 2 and 3). To balance our concern for the economy with our concerns regarding equity and conservation incentives, we will adopt a cap on the average rate increases to be applied to the industrial customer classes of Edison and PG&E. For PG&E, the average rate increase cap for industrial customers will be 12.3¢/kWh, and for Edison it will be 12.9¢/kWh.
2. Allocating CARE and Medical Baseline Exemption Revenues
The revenue requirement shortfall caused by exempting CARE-eligible 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.
The general surcharge we adopt today to pay for extraordinary power costs should be allocated as broadly as possible. However, because of the extraordinary size of the rate increase, it is reasonable to mitigate the impact to the most vulnerable customer classes. This mitigation is consistent with legislative direction in AB1X as well. We therefore direct the utilities to exempt all usage of medical baseline customers from the rate increases adopted in this order. The resulting revenue shortfall will be allocated equally to each of the customer classes, consistent with the allocation of the shortfall from the exemption for 130% of baseline usage.
While no party objects to the medical baseline exemption, it was not discussed at hearing. Therefore, Edison states in its comments and at final oral argument on May 11, 2001 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 23, 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. Exempting Direct Access Customers
The 3 cent/kWh surcharge adopted on March 27 is meant to apply to all generation deliveries on the utilities' systems, including the demand of direct access customers. However, although we authorize the utilities to include the direct access load in calculating the revenue requirement associated with the surcharge, we do not require direct access customers to pay any of the rate increase. Direct access customers are not relying on the utilities or DWR to purchase power on their behalf. The surcharge adopted in D. 01-03-082 is intended to provide payment for DWR purchases which do not include purchases made by direct access customers. By this exemption we intend to "net out" the charges and credits of direct access customers. By refraining from imposing an additional charge on direct access customers we do not intend to cause a windfall through a claim of a credit under the current direct access credit system. Thus, we will proceed to reexamine and redesign the direct access credit system to reflect current structural reality.
As the direct access demand increases the overall revenue requirement associated with the 3¢/kWh surcharge, there will be a shortfall in utility revenues resulting from this decision not to charge any of the rate increase to direct access customers. That shortfall will be allocated on an equal cents/kWh basis to all non-exempt sales. We note that this will likely shift costs to residential consumers since the majority of direct access demand, and thus the majority of the resulting shortfall, is non-residential.
4. Amortizing Rate Surcharges From The Effective Date
In D.01-03-082, we adopted the 3-cent per kilowatt hour rate surcharge effective March 27, 2001. That decision also obligates Edison and PG&E to collect and remit a generation-related rate including the 3¢/kWh surcharge to CDWR. 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 interim between March 27th and the date that 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.
Edison proposes to recover this shortfall by amortizing it over three months. This three-month amortization would effectively increase the three-cent surcharge to five cents. PG&E proposes a twelve-month amortization method, increasing the surcharge to 3.6 cents per kWh over the recovery period.
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.14 Section 728 requires the Commission to determine the rate "to be thereafter observed and in force." The right to recover 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 in this decision that could possibly violate Section 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, Section 728 requires a prospective authorization to recover the revenues. While the Commission often accomplishes this result through balancing or memorandum accounts, that method is not required by Section 728. Accordingly, we see no violation of any prohibition against retroactive ratemaking in allowing the amortization of rate surcharges authorized and effective on March 27, 2001.
In its comments on the proposed decision and alternate proposed decision, TURN continues its arguments that what we are doing here is inconsistent with past Commission precedent. However, in D.99-11-057, 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. 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.
The revenue associated with applying the 3¢/kWh surcharge to all non-exempt energy sales from March 27, 2001 to the date utilities begin collecting the surcharge should be added to the overall revenue requirement allocated among customer classes through this decision. From an equity standpoint, a three month summer amortization would undoubtedly cause undue stress on summer rates, which already will be very high. A three-month surcharge may place a severe hardship upon industries that experience heavy summer electricity usage. We therefore authorize the utilities to amortize the unrecovered amount over twelve months, as PG&E proposes. This shortfall will be allocated consistently with the shortfall allocation for statutory baseline and CARE exemptions.
