This testimony is presented by William B. Marcus, principal economist of JBS Energy, Inc. on behalf of Toward Utility Rate Normalization and Utility Consumers Action Network. Mr. Marcus has appeared before this Commission on over 70 occasions as well as before about 30 other federal, state, provincial, and local regulatory bodies in the U.S. and Canada. His qualifications are attached.
The testimony is divided into general recommendations for all of the utilities and specific recommendations for the individual utilities. To summarize, TURN and UCAN make the following major recommendations:
Costs of Load Dispatching and Power Purchasing Should No Longer Be Included in Utility Rates Because the Functions Have Been Transferred to the ISO and PX.
All three of the utilities have significant funding in FERC Account 561 (a transmission account) for load dispatching. SDG&E also has funding for dispatching and power purchasing in FERC Account 556, a generation account.[1] This dispatching function is being transferred to the ISO, which will charge transmission rates which recover the cost of providing this service. The power purchasing function which utility dispatchers previously undertook, will be centralized in the PX. Utilities should not be allowed a revenue requirement for this cost when the ISO and PX will actually be providing the service and will be charging for it. The amounts included in current rates for these functions are provided below.
Load Dispatching Costs in Current Rates
Acct 556 Acct 561
SDG&E figures are based on average other gen/trans
1,998 1,734 escalation from 1988-93 and 1.0788 escalation from
1993-96
SCE figures are based on average transmission
- 9,936 escalation from
1992-95 and 1.03 escalation from 1995-97 under PBR
(1.8% rate increase + 1.2% sales growth)
PG&E figures assume average transmission escalation from
- 5,547 1993-96
Administrative and General Costs and general plant overhead associated with these costs should also be removed from current rates.
These costs should be removed from utility revenue requirements as part of the unbundling process, even for those utilities operating under PBR, because they are associated with a change in the utility’s scope of responsibility as a result of restructuring.
Public Purpose Costs Should Be Unbundled from Non-Generation Costs.
PG&E and Edison have specifically unbundled public purpose costs from transmission and distribution costs. SDG&E has not fully unbundled public purpose costs from other non-generation costs, particularly when calculating administrative and general costs.[2] SDG&E’s approach is inappropriate. With the new independent administration of public purpose programs and the different revenue allocation for public purpose costs, these costs must be unbundled and removed from existing PBR mechanisms. Additionally, PG&E should be required to treat CARE administration as a public purpose program cost, consistent with the other utilities, rather than as a distribution cost.
Distribution Costs Themselves Should Be Further Unbundled.
Overall Policy
The function which utilities are calling distribution actually can be further unbundled into five (or more) separate functions. At this time, the Commission should adopt such a functional separation at broad levels, pending further analysis in the revenue cycle unbundling proceeding. The five functions are distribution wires and four essentially retail functions:
To unbundle distribution into these four functions, we simply extract Meter and Customer Accounts costs at the FERC account level, with appropriate allocations of A&G and general plant costs. We recognize that further more detailed analysis of these two cost sections will be required at a later time should the Commission pursue revenue cycle unbundling.
Immediate action to unbundle marketing costs is required, if only on an interim basis, as discussed below.
Marketing Costs Must Be Unbundled Now.
Marketing costs are costs related to selling optional utility services or positioning the utility better in a competitive market. It is critical for fair competition that the utility’s retail or wholesale marketing costs not be charged to all users of distribution wires. These costs should be the responsibility of shareholders in a competitive market. In the alternative, they should be charged only to customers taking generation service from the regulated utility, with a cents per kWh cap based on current rate levels. Any revenue which cannot be recovered from generation service customers as compared to current authorized levels should not be allowed to be recovered. Under this alternative recommendation, marketing costs would be treated similarly to the gas utility brokerage fee.
In the SoCal Gas 1994 test year General Rate Case (GRC), the Commission recognized that the costs of programs or services that only benefit certain classes of customers should be paid by those customers. The Commission was concerned not only with the fairness of having costs paid by those on whose behalf they are incurred, but with preventing potentially anticompetitive subsidies in markets where competition exists or is developing. D.93-12-043, pp. 45-46. As is the case here (due to the rate freeze and the anti-cost shifting language of Section 368(b) of AB 1890), the opportunities for reallocating such costs were limited in the GRC. However, the Commission still stated its intent to “consider this issue in our determinations of the appropriate ratemaking treatment for several types of noncore expenses, including capital investments for noncore services, noncore marketing costs, and load retention efforts.” For the particular marketing programs discussed in that decision, several were approved subject to being reallocated to noncore customers in the next cost allocation proceeding, and one was removed from rates altogether, with SoCal Gas given the opportunity to recover the associated costs for those customers who took advantage of the particular service. D.93-12-043, pp. 132-134. TURN and UCAN believe the logic applied by the Commission in the competitive gas market makes just as much sense as we head into a competitive electric market, and similar steps should be taken to appropriately assign costs here.
For marketing costs, with the exception of Edison, few of these costs are currently contained in authorized utility O&M costs outside of the A&G areas. We extract the amounts allocated to marketing for the utilities, whether in non-DSM Customer Service and Information Accounts 907-912 or in Account 903 (customer accounts) where both PG&E and SDG&E have placed some of these costs. We also recognize that portions of utility A&G should be directly assigned to marketing based on the functions undertaken. However, such direct assignments are difficult to make, particularly given that the utilities have either not provided detailed breakdowns of their A&G costs or have not developed assignments which specifically reflect marketing as a subcategory of costs.
Unfortunately, because they were able to design the required showing for the unbundling process, utilities have made it virtually impossible to extract all marketing costs at this time. When conducting surveys of their own staffs, they by and large did not ask questions as to which A&G costs are related to marketing as opposed to other distribution or administrative functions. The utilities did not allocate any costs to marketing and gave their staffs no instructions to allocate A&G costs to marketing. This failure by the utilities to even examine the issue places intervenors at a distinct disadvantage. We can identify some marketing costs but it is virtually certain that our identification of these costs is not exhaustive and that we have significantly understated them.
We know that Edison has made presentations to customers using regulated utility staff that have offered special deals on non-generation rates to customers if they continue to take generation service from Edison.[4] The regulated staff was clearly engaged in marketing, not distribution wires services, and the costs of its activities should be charged in this way. Performance incentives related to PG&E’s Customer Energy Services Department have in the past included marketing initiatives to keep PG&E more competitive, but PG&E charges none of this department’s A&G costs to marketing.
Based on the information we have been able to uncover, at this time we recommend an interim allocation of 0.25 mills per kWh for marketing for PG&E (about $19 million) 0.5 mills per kWh for SDG&E (about $8 million) and 0.5 mills per kWh for Edison (about $37 million). SDG&E receives a larger allocation than PG&E they have a larger amount of approved marketing costs (in cents per kWh) in rates now than PG&E and because of a direct allocation of A&G costs to marketing. The Edison figure is higher than PG&E’s in recognition that the Commission actually approved $13 million in non-DSM Customer Service and Information (marketing) costs in the last rate case, as opposed to PUC-approved marketing costs of $1.6 million for PG&E and $2.1 million (1996 dollars) for SDG&E.
These costs allocated to marketing should be removed from the revenue requirement entirely. In the alternative, the rate for these costs (capped in cents per kWh) should be charged only to customers who purchase utility generation. Under this alternative, customers using other generation sources should be exempt from this cost, as it is not being undertaken for their benefit, but the cents per kWh cap will prevent costs not recovered from direct access customers from being reallocated to utility service customers.
As well as adopting TURN and UCAN’s interim allocation of costs to marketing, the Commission should give clear direction to the utilities that they must provide better estimates which unbundle marketing costs from distribution in a later phase of this proceeding. The Commission should also state in its decision here that if such unbundling is not done using a credible and fully documented process open to intervenor review, it will order an independent management audit at shareholder expense to determine the appropriate level of unbundled marketing costs. The issue is too critical to let it drop.
Information Services Costs Must Be Unbundled.
A further cost element which requires consideration relates to the cost of acquiring and dispensing information. Utilities have become repositories of large quantities of information on customer characteristics which they acquire because of their status as regulated utilities. The information has very large commercial value to energy marketers. Failure to make this information available to independent marketers will create barriers to entry and fair competition, particularly if utility affiliates can receive this information at no cost.[5]
Many of the costs of collecting, using, and disseminating this information are contained in Customer Accounts expenses and supporting capital plant, and they may overlap in part with revenue cycle costs.
TURN and UCAN believe it is critical for the Commission to determine the cost of acquiring and disseminating this information. Whatever the cost, utility affiliates and independent marketers alike must pay the same cost. Costs which these parties pay should not be included in customer rates. This would prevent the wires companies from creating a profit center out of selling information about customers’ transactions when that information was acquired as a regulated monopoly.
We are conducting further analysis of these costs and hope to develop a more quantitative recommendation in the near future.
Administrative and General Expense and General and Common Plant
Administrative and General expenses and General and Common Plant costs have one feature in common. At least some of these costs cannot be assigned to specific functions and must therefore be allocated among the relevant functions.
For both of these types of costs, the utilities have directly assigned some costs, while choosing methods which allocate the rest of the costs disproportionately to non-generation areas. PG&E in particular, allocated no A&G costs to generation other than those which it directly assigned. The amount that would have been allocated to generation (28.8% of the allocated costs) were instead reallocated to distribution. Edison claims that its common A&G costs are fixed and will not vary if generation is divested. (A. 96-07-009, Ex. SCE-5, p. 11) SDG&E also allocates approximately $15 million in corporate overhead costs, including all of its executive salaries,6 to distribution.
There are several problems with the utilities’ proposals. First, it is reasonable to expect that even if these costs may be fixed in the short run (e.g., a year), they are more likely to be variable in the longer run (e.g., five years). In the short run, it may not be possible to react immediately to cut costs, but in the longer term, a company which does not own as much regulated generation and has transferred much of the operation of its transmission system to the ISO should be assumed to become smaller in size.[7]
Second, by proposing that no costs can be allocated to generation, the utility is assuming that few of its A&G costs can be reduced if generation is divested or shifted to an unregulated affiliate. In the case of PG&E, if we assume that PG&E divested all of its non-nuclear generation, it would reduce its non-A&G labor expenditures by 29% and its gross plant in service (excluding common and general plant) by 31%. However, PG&E assumes that it would cut its A&G expenses in Accounts 920, 921, and 923 by only 12%.
Fundamentally, we believe that the Commission should adopt the assumption that a company’s administrative expenses (or at least the portion paid for by regulated utility ratepayers) will shrink in the long run roughly proportionately to the size of the company. In other words, long-run incremental A&G costs should be assumed to be approximately equal to average A&G costs as a percentage of the size of the utility.
If we do not assume that the long-run incremental A&G cost equals the average A&G cost, the outcome is likely to be bad. The utility will be given less incentive to reduce administration if it can recover those costs from captive distribution customers than if it must face the discipline of the market. Or, it could end up with extra distribution profits that it could keep under PBR if it does reduce the company size. The utility could even possibly create cross-subsidies, charging utility distribution ratepayers for administrative functions which should be charged instead to unregulated affiliates.
The process of administrative cost-cutting may take some time. In other words, the short-run incremental A&G cost may be less than the long-run incremental A&G cost. Under these circumstances, a phased shift of allocated costs from distribution to generation would appropriately reflect that the utility could not reduce costs immediately but could respond over the long run.
TURN and UCAN therefore recommend a phase-in of allocation of A&G costs to generation. All shared costs which are not allocated to generation should have their generation allocation phased in over time, in 25% increments, so that costs are fully allocated to generation by the latest time when the rate freeze could expire in early 2002.[8] This phase-in should be an override to any PBR mechanisms in place, because it recognizes that the utility functions are gradually shifting. To the extent that the utility retains generation, the functions would shift to generation. To the extent it divests generation or spins it off to an unregulated entity, the cost to regulated utility ratepayers would be reduced.
The overallocation of corporate overhead to distribution creates an additional problem related to revenue allocation. It will cause a cost shift from current rate design to make residential customers pay more. Looking at SDG&E’s current rate design, about 41% of its total costs are allocated to residential customers, but 52% of its distribution costs are so allocated. The result of allocating all corporate overhead to the distribution function, together with an EPMC distribution allocation, is that residential customers will pay more of this overhead, while larger customers with more competitive opportunities will pay less. Restructuring is thus consciously being designed by the utilities to impose a residential rate increase for corporate overhead after the rate freeze expires.
There also are severe empirical problems with the individual utilities’ cost allocations. In particular, the utilities do not adequately assign costs actually incurred for generation or for marketing and retail services. We will discuss these issues in more detail below.
Interface Between Rate Reduction Bonds and Unbundling
TURN and UCAN are aware that the utilities have proposed to hold a separate proceeding to evaluate issues associated with implementing the rate reduction bonds (RRB). We are holding most of our comments on RRB issues at that time. However, there is an interface between the mechanics of rate unbundling and the mechanics of applying the RRB to residential and small customers’ bills that we wish to raise here.
If the CPUC decides to issue a financing order under Sec. 841(b), in lieu of finding an alternative method of supplying a 10% rate reduction to residential and small commercial customers, TURN and UCAN believe the revenues from those bonds must be used to pay down a portion of residential and small commercial customers’ share of the CTC. This would require mechanically including a CTC component in all rate components (customer, demand, and energy charges) contained on the customer’s bill.
Unless the CTC (and in particular plant-related components of the CTC) is paid off with RRBs, small customers will not be receiving the benefits they were promised under AB 1890 (in particular income tax reductions on utility plant). The purpose of RRBs is not to pay the utility’s current distribution expenditures. However, without an explicit adjustment to utility rates before applying a 10% reduction, this could happen.
All of the utilities’ current proposals use the RRB revenues to apply a 10% reduction to customer, demand, and energy charges. If a rate component does not contain any CTC, this could end up applying rate reduction bonds to pay non-CTC components of customer bills. Thus, without a specific policy decision by the Commission, utilities could use RRB to pay off their distribution, as well as other, costs that are not related to competitive transition costs. Applying the RRB to non-CTC costs would improperly lengthen the time for paying down small customers’ share of the CTC.
To fix this problem, the RRBs should be used to provide a 10% discount either to the bill as a whole or to each aggregate rate component (customer, energy, or demand charge). However, the entire discount must be charged to CTC. If a rate component does not otherwise contain any CTC (for example, PG&E’s and SDG&E’s small commercial customer charges and SCE’s residential customer charge), and the rate component method is used, then enough CTC must be allocated to that rate component to provide for the 10% discount.
The Commission should also be careful not to allow the RRB to be used for a competitive advantage. The 10% discount should be developed using utility default rates and applied only to CTC. This would prevent any discount to the PX price which would be anticompetitive.
While RRBs will be addressed in detail in a later case, it is important for the Commission to understand here that unbundling implementation mechanics can affect Commission policy.
Unbundling of the Utilities’ Line Extension Allowances
The current line extension allowances are calculated based on the utilities’ base annual revenues, which include components for transmission and generation investments. However, because deregulation will result in the electric utilities’ unbundling of base annual revenues to reflect only their distribution functions, it is appropriate, at a minimum, to scale-down the line extension allowances to reflect only future distribution revenues. Both PG&E and SDG&E have agreed that this is appropriate treatment (in their December 6th filings) of the line extension allowances, while Edison has remained silent on the subject.[9] TURN and UCAN recommend that the Commission recognize this need to unbundle utility line extension allowances (at a minimum) as one of the issues to be decided in the Commission’s R. 92-03-050, and require all parties to work toward this end by year-end of 1997.
This recommendation is the minimum mechanical step that the Commission needs to take to achieve appropriate unbundling. This required minimum step does not supersede TURN and UCAN’s recommendations for further examination of line extension allowances in 1997 in R. 92-03-050.
Unbundling the Utility Cost of Capital to More Accurately Reflect Unbundled Utility Functions
The Commission should as soon as practicable initiate a proceeding to develop and implement unbundled costs of capital that will more accurately reflect the unbundled utility functions. In a perfect world, such unbundling would be in place by January 1, 1998, or whenever unbundled rates and direct access go into effect. However, TURN and UCAN understand that the amount of work that has to be completed in order to have all critical path components in place by the end of this year makes it unlikely that this additional task can be done in time. Fortunately, under the rate freeze mandated by AB 1890, the Commission has the opportunity to make its determination after January 1, 1998 and still have it be effective as of that date. The Commission need only decide that this effort needs to be undertaken at the earliest opportunity, and that the utilities’ base rates as of January 1, 1998 will be set subject to refund, so that more appropriate rates of return consistent with the unbundled utility functions can be calculated and reflected in those base rates.
The issue of unbundling the cost of capital was first raised in the generic 1995 cost of capital proceeding (A.94-05-009, et al.). There the Independent Energy Producers (IEP) presented a proposal for adopting separate costs of capital for generation and non-generation utility activities. The Commission declined to unbundle costs of capital “because it is premature, not because it is economically unsound.” D.94-11-076, pp. 23-24. The Commission strongly suggested that the issue would need to be revisited once “unbundled rates for generation and transmission and distribution functions are closer at hand.” Id., at 24.
The present proceeding will produce the unbundled rates that the Commission was referring to two years ago. In fact, the degree of unbundling that will occur as a result of this proceeding appears to exceed the level the Commission had in mind when it wrote that earlier decision, which preceded the Commission’s electric industry restructuring policy decision (D.95-12-063) by over a year. Therefore once that unbundling is complete, the Commission should determine the appropriate capital structures and rates of return for the unbundled utility functions, and make the necessary adjustments to the utilities’ base rates. We believe that the Commission’s observation in the 1995 cost of capital proceeding still holds true:
Separate entities, whether they are utility departments or unregulated firms, earn separate returns. The utilities are surely aware that, all other things being equal, the rate of return for the surviving monopoly utility will be lower than the bundled . . . return. D.94-11-076, p. 25.
The Commission will need to also make the necessary adjustments to any PBR mechanism that is already in place for any of the unbundled utility activities. If the authorized rate of return that is used in any PBR mechanism as a benchmark or for any other purpose is based on a “bundled” rate of return, it should be replaced with the appropriate “unbundled” rate of return, and the mechanism recalibrated based upon the more specific rate of return.
Bill Formatting Issues
In his Ruling of January 31, 1997, ALJ Weissman reminded parties that this is the proceeding in which parties should address bill formatting issues. TURN and UCAN believe that bill format and the information that is disclosed on the face of a customer’s bill is a critical issue. We urge the Commission to direct that as much meaningful disclosure as possible be required at the outset of the transition period. We also expect that the Commission will need to return to this issue as the needs of customers become clearer, as additional service options become available to broader classes of customers, and as the billing equipment of the utilities’ and their competitors becomes more sophisticated.
The Commission needs to keep in mind that for a competitive market to work, consumers need access to information that is relevant to their decision-making process. The principle is well stated in Congress’ policy declaration at the outset of the Fair Packaging And Labeling Act:
Informed consumers are essential to the fair and efficient functioning of a free market economy. Packages and their labels should enable consumers to obtain accurate information as to the quantity of the contents and should facilitate value comparisons. Therefore, it is hereby declared to be the policy of the Congress to assist consumers and manufacturers in reaching these goals in the marketing of consumer goods. 15 U.S.C. [[section]]1451.
At the outset, we believe PG&E’s proposal for bill itemization in its testimony of December 6, 1996 is a good starting point that, with some modification, could serve as an appropriate level of disclosure. At pages 4-5 and 4-6 of that exhibit, PG&E lists six components that would be separately listed on the bill of a full-service customer. TURN and UCAN propose that, consistent with our testimony on the further unbundling of “distribution” functions into a “wires” function and various marketing functions, the “Distribution Charge” PG&E includes should be broken into at least two sub-components.
Furthermore, the “CTC and Other Nonbypassable Charges” should be further explained based on the percentage of that charge going to various categories of costs. Consumers are entitled to know what they are paying for, and how much (or how little) of their total bill is going to a particular purpose. A general “CTC and Other Charges” category tells the consumer nothing. Four possible subcategories come to mind immediately: Uneconomic nuclear generation; uneconomic fossil fuel generation; uneconomic purchased power contracts; and “other”. The percentage of the charges for each subcategory for each utility should be determined once the outcome of Phase 2 of the stranded asset/CTC proceeding is known. If the utilities convince the Commission that such subcategories cannot be listed and calculated on the individual bill as of January 1, 1998, then the Commission may wish to consider a bill insert that would be solely devoted to providing similar information explaining the nature and amount of these charges. At the outset of the “transition period”, this insert should be required on a monthly basis. Perhaps after a year, the insert could be provided four times a year, as customers may be expected to have become more aware of the charge.
As restructuring continues after 1/1/98, we may expect to see further unbundling and further development of customer billing requirements and technologies. The Commission should also consider further billing format requirements, such as more-detailed breakdowns of the source of generation reflected in the energy charge for full service customers, and the activities covered in the public purpose program charge. However, at the outset TURN and UCAN believe the level of disclosure on billing issues described above would be satisfactory.
We also believe that it would be appropriate to require the PX and all other generation suppliers to periodically provide information to their customers on the sources of their generation (nuclear, coal, gas, hydro, renewable) and its emission profile for nitrogen oxides, sulfur oxides, particulate matter under 10 microns, and carbon dioxide. This information does not need to be on the bill itself, but should be made available to customers twice a year through a bill insert. The information should be submitted to a central agency (we suggest the Energy Commission) where it would be publicly available for all generation suppliers.
Chapter 3: Unbundling Costs for Pacific Gas and Electric
Summary of PG&E Recommendations
TURN recommends that the Commission take the following specific steps for PG&E
PG&E’s 1996 rates contain $5,547,000 in load dispatching costs. These costs together with associated A&G costs ($3,949,000) and general plant costs (a revenue requirement of $2,563,000 based on $14,818,000 of general plant) should be removed from rates, as these costs are now the responsibility of the ISO.[10]
Further Unbundling of Distribution Costs
Unbundled Marketing Costs
Marketing included in O&M costs (aside from A&G) are $1,595,000 in 1993 dollars ($1,648,000 in 1996 dollars), based on the cost of major account representatives included in Account 903. (D. 95-12-055, pp. 41-42, 53) 11
As discussed below, we identify $3,083,000 in A&G costs in Accounts 920, 921, and 923 which should be directly assigned to marketing. A&G costs allocated to marketing are $1,570,000 for a total of $4,653,000 in A&G expenses allocated or assigned to marketing. Marketing is also allocated $16.4 million in general plant, with a revenue requirement of about $2,852,000.
In total, the marketing costs which we have identified are $9,153,000. We believe that our identification is extremely low for reasons discussed below in the section related to A&G costs.
TURN makes a preliminary estimate of unbundled marketing expenses of 0.25 mills per kWh ($18,980,000) for PG&E. This figure is based on twice the level of identified costs rounded to the nearest 0.5 mill per kWh. This reflects that additional marketing costs are likely to be paid by ratepayers but cannot be readily found without a full scale re-examination of PG&E’s A&G costs.
This amount should either be removed from rates or should be collected on a capped cents per kWh basis only from PG&E sales customers with no allocation to direct access customers.
CARE Administrative Expenses Should Be Classified as Public Purpose Program Costs.
Edison and SDG&E propose to unbundle the administrative costs associated with the California Alternate Rates for Energy[12] (CARE) program as public purpose program costs, as well as the costs of low income rate reduction. However, PG&E proposes to leave the administrative costs of CARE as distribution costs. The result is a difference in allocation due to the difference in unbundling. All three utilities propose to spread CARE surcharges to all customers on an equal cents per kWh basis. By treating CARE administration as distribution costs, PG&E allocates these costs to its distribution customers on the basis of EPMC of distribution costs.
TURN opposes PG&E’s proposal. Administrative costs for the CARE program are costs associated with implementing a societal program (similar to the costs of the discounts themselves) and should therefore be spread to all CARE-eligible customers equally.
The Commission has ruled that the costs of low-income programs such as CARE should be allocated based on equity concerns rather than by strict marginal cost theory. The Commission has stated that program costs (for both the discounts and administrative costs) should be spread on an equitable basis among all of the utility’s non-eligible customers, and not to just a single customer class. To meet this end, the Commission has allocated low-income program costs on an equal cents per kWh basis. ( Dec. 96-04-050, pp. 80 and 81; Dec. 94-05-054, p.4).
SoCal Gas was ordered to allocate the LIRA administrative costs in the same way as it allocated the LIRA discount—on an equal cents per therm basis. (Dec. 94-12-052, pp. 58-61)
CARE administration costs are also part of the CARE rate for SDG&E, where they have remained since the 1993 GRC decision. (D. 92-12-019, p. 43)
TURN therefore recommends that the Commission adopt the same treatment of CARE administration costs for PG&E as Edison and SDG&E have proposed and should include them as Public Policy Program costs. The amount reclassified from distribution to PPP is $684,000 in direct costs.[13] Using the methods discussed below, there will be a further allocation of A&G costs and revenue requirement associated with general plant associated with this cost shift. The A&G and general plant allocations presented below reflect this cost reclassification.
Administrative and General Unbundling
Survey and Accounts 920, 921, and 923
PG&E’s unbundling mechanism for A&G costs starts with a survey of what appears to be a subset of its Administrative and General Departments with reference to costs in accounts 920 (A&G salaries), 921 (A&G supplies), and 923 (outside services contracts). Approximately $74 million of the $182 million in costs in these three departments is directly assigned by PG&E.
While the results of PG&E’s survey are not on their own a reasonable basis for assigning A&G costs, we must at least state that by using a departmental survey framework, PG&E gave us far more information than either SDG&E or Edison on A&G costs. It therefore allowed us to find more of the deficiencies in its work. This assisted our investigation. Other utilities should be required to conduct similar surveys.
First, as we saw in PG&E’s 1996 GRC, in its analysis of the Diablo Canyon allocation issue, when the utility has an incentive to assign as few costs as possible to a function, it will tend to underassign costs to that function. (D. 95-12-055, pp. 35-37) Here, if A&G costs are allocated to generation, they must be recovered through market prices and not from captive ratepayers on a regulated basis. Therefore it is in the Company’s interest to keep the costs as low as possible. Let us provide a few examples. It is highly doubtful that the Vice President for Corporate Planning and the Community Relations Department spend none of their time in a way that can be directly assigned to generation.[14] The compensation and benefits department allocated 9% of its time to Diablo Canyon in 1994 but nothing to regulated generation in 1996. We also find it strange that PG&E did not ask the top corporate officers such as the President to provide any allocation of time. The utility’s allocations are not credible, and the company has failed to carry its burden of proof in these areas.
TURN recommends a direct assignment of a minimum of 15% to generation to deal with these serious flaws in PG&E’s analysis. This is about 25% ($5.5 million) more than PG&E’s direct assignment. This reduces the amount of costs which must be allocated by a corresponding amount.
We recommend several other direct assignments to unbundle about $3 million in marketing expenses from directly assigned distribution wires costs. The costs of market planning and marketing should not be charged to all PG&E distribution customers regardless of their generation supplier. They are brokerage and retail costs which all competitors must face and should not be included inside the regulated utility.
First, we directly assigned as marketing costs the $1,750,800 of costs for the Power Market Planning and Energy Trading department which PG&E had directly assigned to the distribution function. Any department called “Power Market Planning” engages in marketing. At least the large preponderance, if not all, of the functions which it undertakes on behalf of PG&E’s distribution customers relate entirely to those customers served by PG&E generation. We also directly assigned as marketing costs one-half of the cost allocated to distribution for the Manager, Employee and Customer Communications and the Communication Media department ($582,000 and $322,000 respectively). Given the responsibility of the customer energy services department for helping to improve PG&E’s competitive position, we also directly assigned one-third of the distribution-related costs of the Senior Vice President of the CES department to marketing ($428,000).
It is not at all clear to us that these assignments are adequate, given that PG&E made no efforts and asked no questions to assign effort to marketing. However, these figures are a bare minimum which we could develop.
Having made these different direct assignments, we come to the allocation step for the remaining $102 million in costs.
The first step was to reduce the allocation of A&G costs to public purpose programs because these programs will be run by an independent administrator so that PG&E’s administrative burden will be reduced in 1998 relative to past years. We judgmentally used a PPP allocator based on 50% of past-year labor instead of the 100% used by PG&E.
The second step was to phase in the generation allocation as described above. In each of the years 1999-2002, 25% of the cost which PG&E shifted from generation to distribution should be shifted back to generation, where PG&E should be at risk of recovering the cost from the market or should reduce the cost upon divestiture. Our allocation factors for these three accounts are shown below and compared to PG&E’s figure.
A&G Allocation Percentages, Accounts 920, 921, and 923
Trans Gen PPP Dist Wires Meters CA Marketin
g
PG&E 1998 9.44% 12.04% 4.67% 73.87% N/A N/A N/A N/A
TURN 1998 9.36% 15.00% 2.56% 73.08% 47.95% 5.44% 17.77% 1.91%
1999 9.36% 19.07% 2.56% 69.01% 43.89% 5.44% 17.77% 1.91%
2000 9.36% 23.13% 2.56% 64.95% 39.82% 5.44% 17.77% 1.91%
2001 9.36% 27.20% 2.56% 60.88% 35.76% 5.44% 17.77% 1.91%
2002 9.36% 31.26% 2.56% 56.82% 31.69% 5.44% 17.77% 1.91%
PG&E uses the allocation percentages from its study to allocate residual amounts in all other accounts except 926 (Pensions and Benefits) and Performance Incentive Payments. We made a minor adjustment to the pensions and benefits allocator, so that it would allocate costs based on utility-wide labor costs (including A&G labor allocated using the 920/921/923 allocator), rather than on labor costs excluding A&G. Our proposed allocator for Account 926 is shown below.
A&G Allocation Percentages, Account 926 and PIP
Trans Gen PPP Dist Wires Meters CA Marketin
g
PG&E 1998 11.3% 27.5% 6.9% 54.4% N/A N/A N/A N/A
TURN 1998 9.09% 25.90% 6.57% 58.44% 34.41% 5.49% 17.94% 0.59%
1999 9.09% 26.51% 6.57% 57.84% 33.81% 5.49% 17.94% 0.59%
2000 9.09% 27.11% 6.57% 57.23% 33.20% 5.49% 17.94% 0.59%
2001 9.09% 27.72% 6.57% 56.63% 32.60% 5.49% 17.94% 0.59%
2002 9.09% 28.32% 6.57% 56.02% 31.99% 5.49% 17.94% 0.59%
Using PG&E’s 1995 A&G costs for illustration, TURN would start out with $10 million more generation costs than PG&E and would shift about $7.9 million per year from distribution to generation over four years. The shift is less than 2% of PG&E’s total A&G costs and about 4.3% of allocated costs per year. By 2002, slightly over $30 million in costs in today’s dollars (about 7% of A&G costs) would be reallocated away from the current utility in recognition of that utility’s smaller size.
Marketing would receive an allocation of $4,653,000 in A&G costs, including the $3,083,000 in directly assigned costs shown above.
Based on our proposal to further unbundle distribution costs into wires, meters, customer accounting, and marketing costs, the temporary excess generation costs are included in the less competitive wires sector pending their phased-in allocation as generation costs.
TURN’s Allocation of PG&E’s 1995 Recorded A&G costs
Excluding RD&D, 1998-2002
Total Transmissi Generati Public Distribut Wires Meters Custome Marketin
on on Purpos ion as r g
e defined Account
by PG&E s
PG&E 426,938 21,594 272,839 n/a n/a n/a n/a
42,904 89,601
TURN
1998 426,936 40,138 269,049
99,957 17,793 176,088 20,703 67,605 4,653
1999 426,936 40,138
108,574 17,793 260,431 167,470 20,703 67,605 4,653
2000 426,936
40,138 117,192 17,793 251,814 158,853 20,703 67,605 4,653
2001
426,936 40,138 125,809 17,793 243,197 150,236 20,703 67,605 4,653
2002
426,936 40,138 134,426 17,793 234,580 141,619 20,703 67,605 4,653
Common and General Plant
Common and General Plant are allocated using PG&E’s general method but using TURN’s 1998 A&G allocator for shared costs.
Within PG&E’s distribution sector, we allocated costs except vehicles to wires, meters, customer accounts, and marketing using a labor allocator. Directly assigned vehicles are allocated only between wires and meters by labor. The results of our analysis for gross plant are given below.
Common and General Plant Allocation (Details on Gross Plant)
Generatio Transmissi Public Distribut Wires Meters Custome Marketi Total
n on Purpos ion per r ng
e PG&E Account
s
PG&E 125,378 30,800 n/a n./a n/a n/a 1,586,31
167,650 1,262,488 6
TURN
Direct 87,936 0
25,739 591,463 339,15 58,244 190,197 3,863 705,138
9
Vehicle 37,229 0 155,67
s 86 182,403 0 26,733 0 0 219,718
Allocat 661,460
ed 99,219 61,918 16,942 483,382 317,19 36,000 117,560 12,624
8
Total 124,886 16,942 812,02 120,97 1,586,31
187,241 1,257,248 6 7 307,757 16,487 6
We allocate about $20 million more to generation than PG&E, largely due to the 15% direct assignment factor for A&G costs. Our allocation for public purpose costs is lower because of the lower labor allocation to reflect independent administration. There is a $16.4 million allocation of plant to unbundled marketing costs. This translates into a revenue requirement (return, taxes, and depreciation) of about $2.85 million.
The table below compares TURN’s and PG&E’s allocations for general and common plant for gross plant, depreciation reserve, deferred ACRS/MACRS taxes, book depreciation, and tax basis for general and common plant as a whole.
General and Common Plant Allocation
Generatio Transmissio Public Distribu Wires Meters Customer Marketin Total
n n Purpos tion Accounts g
e
Gross Plant
TURN 124,886 16,942 16,487 1,586,31
187,241 1,257,24 812,02 120,977 307,757 6
8 6
PG&E 125,378 30,800 1,586,31
167,650 1,262,48 6
8
Depreciation
Reserve
TURN 39,012
61,299 5,083 392,054 253,87 38,055 95,122 5,003 497,449
4
PG&E 39,119
55,420 9,241 393,626 497,406
Deferred ACRS/MACRS
TURN 10,279
14,276 1,329 90,499 59,134 8,705 21,421 1,238 16,383
PG&E 10,316
12,739 2,417 90,909 116,381
Book
Depreciation
TURN 10,534
15,392 1,422 99,372 64,713 9,562 23,755 1,342 126,721
PG&E 10,576
13,745 2,586 99,811 126,718
Tax Basis
TURN 52,091 345,02 7,052 664,587
70,907 7,270 534,319 3 51,324 130,921
PG&E 52,302 13,217 664,586
62,501 536,566
While our general plant allocations in total do not differ markedly from PG&E’s, we allocate more to generation and less to public purpose programs. There is also an allocation of gross plant to marketing expenses which results in a $2,849,000 allocation of general plant revenue requirement to marketing.
Summary of Unbundled Costs
Estimates of distribution wires, meters, customer accounts, and marketing O&M, A&G and general plant costs are illustrated below for the information of the Commission. Marketing costs should be unbundled now based an estimate of 0.25 mill per kWh, as recommended previously, based on our inability to completely identify these costs, and a further analysis of these costs should be conducted. Remaining marketing costs must be identified and removed in later phases of the proceeding.
TURN’s Illustrative Unbundling of Distribution Costs
1998 1999 2000 2001 2002
Direct Administr
O&M ative
and
General
Wires 220,736
176,088 167,470 158,853 150,236 141,61
9
Meters
25,992 20,703 20,703 20,703 20,703 20,703
Custom
er 98,827 67,605 67,605 67,605 67,605 67,605
Accts.
Market
ing 1,648 4,653 4,653 4,653 4,653 4,653
Common
Plant
Gross Depreciat Deferre Return Deprecia Proper Revenue
Plant ion d Tax & tion ty Tax Requiremen
Reserve Income t
Tax
Wires 812,026 138,263
253,874 59,134 68,000 64,713 5,550
Meters
120,977 38,055 8,705 10,113 9,562 825 20,501
Custom 307,757
er 95,122 21,421 26,056 23,755 2,120 51,931
Accts.
Market
ing 16,487 5,003 1,238 1,396 1,342 114 2,852
1998 1999 2000 2001 2002
O&M plus
A&G +
Common
Plant
Distribution 830,882 796,44
Total 822,272 813,661 805,051 1
Wires 535,087 526,470 500,61
517,852 509,235 8
Meters 67,195
67,195 67,195 67,195 67,195
Custom 218,36
er 218,363 218,363 218,363 218,363 3
Accts.
Market
ing 9,154 9,154 9,154 9,154 9,154
Chapter 4: Unbundling Costs for San Diego Gas and Electric
Summary of SDG&E Recommendations
UCAN recommends:
SDG&E includes $1,998,000 in Account 556 (a generation account) and $1,734,000 in Account 561 (a transmission account) for power purchasing and load dispatching. These functions have become the responsibility of the ISO and PX. The costs should be removed from SDG&E’s revenue requirement (the Account 556 costs from generation costs and the Account 561 costs from non-generation costs). Associated A&G costs are $448,000 for Account 556 (based on 3.03% of non-nuclear generation expense assuming that its costs are incurred at the same labor percentage as other generation costs) and $1,245,000 for Account 561 (based on 14.77% of total transmission costs assuming that its costs are incurred at the same labor percentage as other transmission costs).
Marketing Costs
We have identified $2,105,000 in marketing costs ($1.62 million in 1988 dollars escalated) for major account representatives for SDG&E. (D. 92-12-019, pp. 44-46) From SDG&E’s descriptions of its A&G accounts we have not been able to identify specific marketing functions in the main administrative accounts (920/921). SDG&E has directly assigned some of both office space and legal assistance to the combination of marketing and DSM costs, and we recommend an assignment of regulatory commission expenses to marketing below. Total directly assigned marketing costs are $1,495,000, and a labor-related allocation of remaining non-generation costs allocates $1,921,000 of non-generation A&G and payroll tax costs to marketing, making the total $5,521,000. This amounts to 0.35 mills per kWh of sales. Given that these costs are likely to be underestimated because no direct assignments of Account 920 costs have been make to marketing and because we have not allocated common plant to marketing, we recommend a marketing allocation of 0.5 mills per kWh ($7,971,000).
This cost should be removed from rates. Alternatively, it should be allocated on a capped cents per kWh basis only to SDG&E’s sales customers and not to customers taking direct access from other parties.
SDG&E’s Administrative and General Cost Allocation
Accounts 920 and 921
SDG&E’s directly assigns some costs and allocates other costs using a multi-factor allocation.
SDG&E made a conceptual error in its allocation factor based on the number of employees. SDG&E divided generation employees by the total number of employees including administrative employees to develop an allocation factor for those administrative employees. In other words, the employees to be allocated were assigned to non-generation for purposes of developing the allocation. This is circular. They should have been excluded altogether from the calculation of this factor
We do not have data on employees, but we do have data on total labor payments from the 1993 general rate case that can be used to make this allocation. The appropriate multi-factor allocation, excluding A&G labor costs from the denominator, is shown below.
Correction to SDG&E’s Multi-Factor Allocator
1 Total labor (1988 $) D. 92-12-019, App E,
$115,843 p. 11
2 minus A&G labor $ D. 92-12-019, App E,
19,875 p. 11
3 minus nuclear labor (SCE $ D. 92-12-019, App E,
employees) 38,265 p. 4
4 Total SDG&E non A&G labor $ 1 minus 2 minus 3
57,703
5 total production labor $ D. 92-12-019, App E,
51,740 p. 11
6 minus nuclear $ D. 92-12-019, App E,
38,265 p. 17
7 fossil generation labor $ 5 minus 6
13,475
8 fossil labor as % 23.35% 7 divided by 4
9 SDG&E's labor allocator 13.27% per SDG&E Workpaper,
Ch. II, p. 1-2
10 fossil generation gross plant 10.32% per SDG&E Workpaper,
allocator Ch. II, p. 1-2
11 fossil generation operating 26.23% per SDG&E Workpaper,
expenses allocator Ch. II, p. 1-2
12 Multi-factor with revised 19.97% average of 8, 10, and
labor weight 11
13 SDG&E multi-factor 16.60% average of 9, 10, and
11
In addition to the problem with the multi-factor allocator, we disagree substantively with SDG&E’s direct assignment of about $10 million of executive salaries and expenses and corporate governance costs as distribution costs. It is unreasonable to conclude that generation should not be responsible for any of the costs of executives and board members. SDG&E as a utility would not need the same number of executives receiving the same pay from utility ratepayers if it were 20% smaller (as it would be on a multi-factor basis without fossil generation).
We recommend a long-run incremental cost approach to these executive and corporate governance costs. We accept SDG&E’s allocation in 1998 but phase in a 19.97% allocation to generation for these costs over four years, so that 19.97% is allocated there in 2002. If SDG&E divests generation or spins it off to a subsidiary, these costs would be phased out over the same time period. Our recommendation for these accounts, which also factors in our higher multi-factor percentage, is shown below.
Account 920/921 Allocation
Fossil Non-generati
Generation on
SDG&E 10.15% 89.85%
UCAN
1998 12.04% 87.96%
1999 13.70% 86.30%
2000 15.36% 84.64%
2001 17.01% 82.99%
2002 18.67% 81.33%
As mentioned in our general discussion, there is a need for a detailed survey to unbundle (a) A&G costs now charged to ratepayers which should be charged to Enova and other utility affiliates and (b) A&G costs which should be unbundled as marketing costs. The Commission should order such a study for a later phase of this case.
Account 922
We take no issue with SDG&E’s credits for A&G transferred for capital spending.
The A&G benefits transferred are based on the number of employees and should be allocated using a different method. Non-A&G employees are allocated based on the 19.97% factor developed above. A&G labor is allocated based on the Account 920 allocator, since that is where the bulk of A&G labor costs appear. The total utility employee allocator then becomes:
Total Utility Employee Allocator
Generation Non-generati
on
SDG&E 13.37% 86.63%
UCAN
1998 20.45% 79.55%
1999 20.88% 79.12%
2000 21.30% 78.70%
2001 21.73% 78.27%
2002 22.15% 77.85%
Account 923
SDG&E’s allocation of legal services requires revision because SDG&E erroneously assigns electric department legal expenses related to fuels as non-generation costs. These costs should be assigned to generation.
SDG&E also directly assigns some legal expenses as “Marketing” costs which include both DSM and marketing programs. We allocate these costs between public purpose and marketing costs by total labor. The resulting allocations which we recommend are shown below.
Account 923 Legal Allocation
Generatio Public Purpose Marketing Other
n Non-Generation
SDG&E 9.58% 90.42%
UCAN 14.90% 3.89% 1.15% 80.06%
We agree with SDG&E that remaining non-legal expenses in Account 923 should be allocated using the multi-factor method but use our 19.97% generation percentage instead of SDG&E’s 16.60%.
Account 924
We take no issue with SDG&E’s allocation of Account 924 (property insurance).
Account 925
We propose a number of adjustments to Account 925 allocation. First, we allocate 5% of claims administration and legal costs to generation, as generation-related claims exist. Second, the directors and officers insurance is started at SDG&E’s proposed 100% distribution allocation in 1998 but is phased up to a 19.97% multifactor allocation in 2002, for the same reasons that the A&G salary allocation in Account 920 is phased up for executive and corporate governance expenses. SDG&E also allocates certain costs by number of employees and the multi-factor method. We use the same methods but apply our percentages for these costs. The resulting allocations are compared below.
Account 925 Allocation
Non-Nuclear Nuclear Generation in Other
Generation ICIP Non-Generation
SDG&E 4.04% 4.74% 91.22%
UCAN
1998 5.27% 4.74% 89.98%
1999 6.54% 4.74% 88.71%
2000 7.81% 4.74% 87.44%
2001 9.08% 4.74% 86.17%
2002 10.35% 4.74% 84.90%
Account 926
The pensions and benefits allocation is based on number of employees. We use our percentages instead of SDG&E’s figures.
Account 927
SDG&E allocates all future regulatory commission expenses to non-generation. This is inappropriate even after restructuring is complete, unless SDG&E divests generation. There will be issues of accounting, cross-subsidization, and valuation that will come before the Commission. We recommend allocating 15% of regulatory expenses to generation consistent with SDG&E’s current request not to divest its generation. This allocation could be revised if SDG&E divests.
In addition, if we are looking forward into the future, a direct assignment of 25% of these costs should be made to retail marketing, as many future regulatory issues will involve affiliate transactions, cross-subsidies, and the role of utility affiliates and independent providers in retail transactions.
Accounts 929, 931, 935
SDG&E’s space study is used for all three of these accounts. It allocates all corporate services costs as distribution-related. Corporate services costs should be allocated using the Account 920 (administrative salaries) allocator, instead of to being directly assigned to distribution. In other words, space used to house an employee whose time is partly allocated to generation should also be allocated to generation. SDG&E also makes a direct allocation to marketing. This is further sub-allocated by labor cost between marketing and public purpose programs.
The resulting space study allocations are compared below.
UCAN Revised Space Study
Generatio Public Marketing Other Non-Gen
n Purpose
SDG&E 1.5% 98.50%
UCAN
1998 7.48% 6.78% 2.00% 83.74%
1999 8.30% 6.78% 2.00% 82.92%
2000 9.12% 6.78% 2.00% 82.10%
2001 9.94% 6.78% 2.00% 81.28%
2002 10.77% 6.78% 2.00% 80.45%
Again, as part of the future effort to refine A&G cost unbundling, SDG&E should be required to determine if space charged to ratepayers is being used by Enova or if additional marketing costs should be allocated..
These revised space study allocations should be used for Account 931 directly. Accounts 929 and 935 contain other components which require allocation besides the space study. Their allocators are made up partly from the revised space study and partly from other sources. We have not changed any of SDG&E’s proposed allocators for these accounts except the space study.
Account 929 Overall Allocator
Generatio Public Marketing Other Non-Gen
n Purpose
SDG&E 4.06% 95.94%
UCAN
1998 7.64% 3.32% 0.98% 88.06%
1999 8.05% 3.32% 0.98% 87.66%
2000 8.45% 3.32% 0.98% 87.25%
2001 8.85% 3.32% 0.98% 86.85%
2002 9.25% 3.32% 0.98% 86.45%
Account 935 Overall Allocator
Generatio Public Marketing Other Non-Gen
n Purpose
SDG&E 9.31% 90.69%
UCAN
1998 12.20% 3.27% 0.96% 83.57%
1999 12.59% 3.27% 0.96% 83.17%
2000 12.99% 3.27% 0.96% 82.77%
2001 13.39% 3.27% 0.96% 82.38%
2002 13.79% 3.27% 0.96% 81.98%
Account 930
We have four types of adjustments to this account.
First, RD&D expenses should specifically be allocated as public purpose costs rather than non-generation expenses.
Second, SDG&E allocates certain costs by the multi-factor method. We use our multi-factor percentages for these costs.
Third, SDG&E includes $321,000 for abandoned projects. The evidence presented by SDG&E to the Commission does not identify these projects clearly, but they appear to be generation-related, and in fact potentially largely related to SONGS. A Commission decision indicates that $268,000 of these costs may have related to abandonments of capital additions at SONGS. (D. 92-12-019, p. 54) The $268,000 should be directly assigned to SONGS and removed from revenue requirements because any future costs of the same type (abandoned capital additions at SONGS) are recoverable only in the SONGS ICIP price. The failure to remove these costs from rates as SONGS costs at the time that the ICIP was set up appears to be an oversight by the Commission. If deemed recoverable at all rather than allocated to SONGS, these $268,000 of costs should be allocated to generation. Only the remaining abandoned project costs should be allocated using the four-factor method.
Fourth, SDG&E allocates $1,657,000 in shared corporate costs to distribution for stock securities, annual reports, and directors fees and expenses. These costs should be considered long-run incremental costs. The multi-factor generation allocation should be phased in from 1998-2002.
Our results are shown below:
Summary of Account 930 Allocation
Total Fossil Non-generatio SONGS (recovered Public Purpose
Generation n in ICIP) (RD&D)
SDG&E 4.13% 95.87% 0.00% 0.00%
UCAN
1998 4.46% 43.79% 2.56% 49.19%
1999 5.25% 43.00% 2.56% 49.19%
2000 6.04% 42.21% 2.56% 49.19%
2001 6.83% 41.42% 2.56% 49.19%
2002 7.62% 40.63% 2.56% 49.19%
Summary of Results
We recommend the following allocation of the current A&G revenue requirement based on all of the previous adjustments, taken in 1988 dollars and escalated to 1996.[15] We show figures at the current revenue requirement for each of the years from 1998 to 2002 to show the impacts of the long-run incremental cost phase-in of the allocation of certain costs to generation described above.
A&G Generatio Non-Generatio SONGS Costs RD&D directly
except n n now allocated to
franchise recovered public purpose
fee in ICIP
SDG&E 91,452 11,563 79,470 440 0
UCAN
1998 91,452 69,749 729 6,158
14,804
1999 68,858 729 6,158
91,452 15,708
2000 67,967 729 6,158
91,452 16,598
2001 67,076 729 6,158
91,452 17,489
2002 66,186 729 6,158
91,452 18,380
Our generation allocation is $4.2 million higher in 1996 than SDG&E’s. Our total non-generation cost (including RD&D) is $4.5 million less than SDG&E. We remove $289,000 from the revenue requirement currently recovered in the SONGS ICIP which SDG&E has not removed. Approximately $3.6 million (4%) of A&G costs are phased from non-generation to generation over the five year period.
Franchise Fees
SDG&E proposes to allocate all base rate franchise fees and uncollectible expenses as non-generation expenses. This is inappropriate. Franchise fees should essentially follow costs. All rate components (PX, CTC, public goods, transmission, distribution, and its subcomponents such as wires, meters, customer accounts, and marketing) should be assigned their associated franchise fee components.
Payroll Taxes
SDG&E allocates payroll taxes by number of employees. However, it uses the wrong figure for number of employees. The costs should be allocated using the same employee allocator shown in Account 922. The payroll tax allocation is shown below.
Payroll Tax Allocation
Generation Non-Gen % Total $ Generation Non-Gen $
% $
SDG&E 13.94% 86.06%
5,510 768 4,742
UCAN
1998 20.45% 79.55%
5,510 1,127 4,383
1999 20.88% 79.12%
5,510 1,150 4,360
2000 21.30% 78.70%
5,510 1,174 4,336
2001 21.73% 78.27%
5,510 1,197 4,313
2002 22.15% 77.85%
5,510 1,221 4,289
Further Breakdown of Non-Generation A&G and Payroll Tax Costs
Non-generation A&G and payroll tax costs can be broken down, using a labor allocation, into the following components:
UCAN’s Non-Generation A&G Cost and Payroll Tax Breakdown
1993 GRC 1993 GRC Notes 1996
Non-Gene
ration
A&G
Costs
Directly
Assigned
(Legal,
Reg.
Commissi
on,
RD&D
and
Space
Study)
Labor Labor % 1998 1999 2000 2001 2002
Trans. 0 0 0 0 0
Wires 0 0 0 0 0
Meters 0 0 0 0 0
Cust 0 0 0 0 0
Acct.
PPP
6,546 6,546 6,546 6,546 6,546
Marketin
g 1,495 1,495 1,495 1,495 1,495
1996
Non-Gene
ration
A&G
and
Payroll
Tax
Costs
Allocate
d
1998 1999 2000 2001 2002
Trans. 13.18% 9,053
5,727 9,053 9,053 9,053 9,053
Wires 42.21%
18,344 32,655 31,741 30,827 29,913 28,999
Meters 5.71% 1
2,481 3,922 3,922 3,922 3,922 3,922
Cust 31.37% 2
Acct. 13,632 21,550 21,550 21,550 21,550 21,550
PPP 4.74% 3
4,123 3,259 3,259 3,259 3,259 3,259
Marketin 2.80% 2
g 1,215 1,921 1,921 1,921 1,921 1,921
Notes 1996
Total
Non-Gene
ration
A&G
and
Payroll
Tax
Costs
1998 1999 2000 2001 2002
Trans. 9,053
9,053 9,053 9,053 9,053
Wires
32,655 31,741 30,827 29,913 28,999
Meters
3,922 3,922 3,922 3,922 3,922
Cust
Acct. 21,550 21,550 21,550 21,550 21,550
PPP
9,805 9,805 9,805 9,805 9,805
Marketin
g 3,416 3,416 3,416 3,416 3,416
Total
80,401 79,487 78,572 77,658 76,744
Note 1 approxim
ated at
same
labor %
as all
distribu
tion
accounts
Note 2 costs
in
Account
903
relating
to
major
account
executiv
es
discusse
d in D.
92-12-01
9, pp.
44-46,
(assumed
75%
labor),
assigned
to
marketin
g, not
DSM
public
purpose
program
Note 3 Public
Purpose
programs
assigned
1/2
weight
for A&G
labor
allocati
on
because
independ
ent
administ
rator
will
run them
starting
in 1998.
Chapter 5: Unbundling Costs for Southern California Edison
Summary of Recommendations for SCE
For SCE, our recommendations are less extensive because a cost separation method for A&G and common plant costs was adopted in the SCE PBR.
Edison’s Fuel Oil Pipeline Costs Should Be Recovered through the MAM on an Interim Basis in 1998, Pending Further Review by the ISO and in the CTC Proceeding.
Edison owns 120 miles of oil pipelines and associated storage facilities for 16.6 million barrels of oil. Edison alleges that these costs are required to maintain electric service reliability and therefore should be (a) reclassified from generation to the non-generation PBR, contrary to the Commission’s PBR decision, (b) assigned as distribution costs by Edison’s revenue credit method, and (c) allocated to customers using an EPMC distribution allocator.
TURN believes that Edison is raising the issue of how this pipeline company is treated in the wrong case by bringing it up in the cost separation and unbundling proceeding. While we have no objection to an interim method for ratemaking for the pipeline in 1998, the Commission should make no decision in this case that would prejudge the ultimate treatment of the pipeline by the ISO or for CTC purposes.
The issue needs to be examined by the ISO and in the CTC proceeding. If the ISO finds that the fuel oil system is needed for reliability, as Edison now alleges, the appropriate means of recovering its costs is through transmission rates pursuant to an ISO contract, not through distribution rates. The appropriate treatment of the pipeline company also has CTC implications which require further examination.
Additionally, the movement of this pipeline into the non-generation PBR creates a further unbalanced impact on ratepayers. The regulated rate base of this pipeline is declining, as most capital additions have been made for non-utility purposes, so that a rate increase of inflation minus 1.4% would be excessive for these assets. By throwing this extra $20 million of revenue requirements into the non-generation PBR formula, Edison will receive a windfall rate of return on these assets.
In sum, TURN recommends that for 1998, Edison Pipeline and Terminal Company costs be recovered through the Miscellaneous Adjustment Mechanism (MAM), with an equal cents per kWh allocation. These costs should be excluded from the non-generation PBR as they do not belong there. They should not receive an EPMC distribution revenue allocation, because the benefits of system reliability flow to all customers (and are likely to flow disproportionately to industrial and commercial customers if one believes the results of value of service studies presented in a number of previous cases). An EPMC distribution allocation would allocate too many of these costs to residential customers. The Commission should revisit this cost treatment after the ISO makes a decision regarding the need for this facility for reliability and the appropriate contractual terms for it, and/or when the Commission itself makes findings as to the appropriate CTC treatment of this facility after further analysis in the CTC proceeding.
Non-Generation Rate Base for Common Costs Otherwise Allocated to SONGS and Palo Verde
On February 3, 1997, TURN filed a data request with Edison asking for data underlying its calculation of corporate common costs which would have been allocated to SONGS and Palo Verde but which Edison instead proposes to include in non-generation rates because they were allegedly not included in the San Onofre (SONGS) and Palo Verde (PV) settlements. We received the response to the data request on February 27, one day before testimony is due. It indicates that Edison proposes to transfer $67.7 million to non-generation rate base to reflect these costs. TURN has serious concerns regarding Edison’s calculations underlying this figure. We sent out a follow-up data request asking for more information. TURN reserves the right to supplement this testimony prior to hearing to reflect the answers to these data requests and to present its recommendations on this issue.
Load Dispatching Costs
Edison currently recovers $9.9 million in load dispatching costs in Account 561. This function is being transferred to the ISO. This cost, together with associated A&G costs ($6,988,000) and general plant should be removed from utility revenue requirements.
Marketing Costs
It is particularly important to unbundle marketing costs for Edison, as Edison has been willing to use its position as a marketer of regulated services to induce customers to continue to purchase its generation. This was demonstrated by the presentation which Edison made to Los Angeles County which linked discount rates and free meters to continued purchases of Edison generation. Documentation of this presentation was attached to the Prepared Testimony of Michel P. Florio for TURN (Ex. II-107) in Phase 2B of A. 93-12-025 (flexible pricing).
Edison’s last GRC gave it more non-DSM marketing costs in the Customer Service and Information Accounts than either PG&E or SDG&E was authorized in their most recent GRCs. Edison was granted a total of $13,377,000 in 1995 dollars. Of this amount $370,000 was for safety advertising, leaving $13,007,000 in marketing expenses. Escalating this figure upward by 3% for the PBR formula to 1997 dollars, this is $13,397,000. Associated A&G would be $9,422,000, for a total of $22,819,000. This is 0.31 mills per kWh. General plant costs must also be added.
Given that Edison has not conducted a detailed and comprehensive study which would specifically assign A&G costs as marketing-related, TURN recommends unbundling 0.5 mills per kWh as marketing costs pending a future study. This amount is $36,506,000 at Edison’s 1997 sales forecast.
As recommended above, these costs should either be removed from utility revenue requirements or should be charged on a cents per kWh basis only to Edison sales customers with no allocation to direct access customers.
A&G and Common Plant Costs
Edison has allocated a block of A&G costs to generation but claims that upon divestiture these costs must be treated as non-generation costs. These costs should be phased out of non-generation costs over time. If the regulated utility becomes smaller due to divestiture or due to movement of generating plants to unregulated affiliates, A&G costs should be assumed to be reduced, with a phase-out period, as we recommend for PG&E and SDG&E.
Miscellaneous Adjustment Mechanism (MAM) Costs Should Be Reallocated.
Edison proposes to establish a Miscellaneous Adjustment Mechanism Balancing Account (MAM) to recover certain of its costs that are currently being recovered through energy cost adjustment clause (ECAC) billing factors, Base Rates, and the Electric Revenue Adjustment Mechanism (ERAM). Most of the MAM costs have been authorized by the CPUC but will not be recovered through the 1) power exchange, 2) CTC recovery, 3) Edison’s nongeneration PBR, or other pass-through balancing accounts. Edison also wants to include in the MAM an adjustment to reflect energy losses incurred during operation of its electrical system as compared to the estimated losses and load profiles used by the ISO/PX to calculate hourly energy delivery to the utility distribution company (UDC).
We propose three changes relating to Edison’s revenue requirements for MAM-related items.
Edison proposes to allocate all MAM costs to customers based on equal cents per kWh. For certain cost items (i.e., those related to generation), this is appropriate. However, Edison includes in MAM other costs which are not generation-related.
In general, Edison’s MAM accounts can be broken into four categories: 1) generation; 2) distribution, 3) programs similar to those defined as Public Purpose Programs, and 4) undefined. Generation related items, meant to provide energy, should be allocated based on equal cents per kWh. Distribution costs should be allocated based on equal percentage of the marginal costs (EPMC) of distribution. Costs for items similar to public purpose programs should be collected on an equal cents per kWh basis. Finally, because certain of Edison’s costs are not readily defined, TURN proposes a split in allocation method, so that one half of the costs of undefined accounts are spread by EPMC Distribution, and one half by equal cents per kWh.
TURN’s recommendations for Miscellaneous Adjustment Mechanism revenue requirements and cost allocation are given in the table on the next page. Items where TURN differs from Edison on the revenue requirement are listed in bold type.
Finally, Edison proposes balancing account treatment for costs/credits associated with future settlements with the ISO/PX. As these are clearly generation related, TURN recommends allocating these costs/credits based on equal cents per kWh.
TURN Recommendations Regarding Edison's
Miscellaneous Adjustment Mechanism (MAM)
Cost Item Characteristic Allocation Cost
SONGS 1 Shutdown O&M Generation ec/kWh $ 11,458
Yuma Axis Generation ec/kWh $ (1,902)
DOE Decontaminate Generation ec/kWh $
4,633
Spent Nuclear Fuel Generation ec/kWh $
3,263
Fuel Oil Inventory Carrying Generation ec/kWh $
cost 3,689
Catalina Diesel Fuel (net Generation ec/kWh $
of Catalina PX revenue) 1,734 less
Catalina
PX revenue
Nuclear Performance Generation ec/kWh $ 14,595
Incentives*
Hydro Pumped Storage costs Generation Recover Remove
(Remove from MAM) from PX from rates
price
RECLAIM Credits Generation ec/kWh $
155
Devers to Palo Verde 2 Transmission ec/kWh $
abandoned project and generation 2,235
amortization
Edison Pipeline Terminal Generation ec/kWh $ 19,963
Co. cost (move from PBR to
MAM)
Edison Pipeline Terminal Generation ec/kWh $ (1,643)
Co. revenue credit
Women/Minorities/Veterans PPP ec/kWh $
621
Electric Vehicles PPP ec/kWh $
2,616
RD&D Royalties PPP ec/kWh $ (3,119)
DSM Incentives PPP ec/kWh $
1,251
LEV O&M PPP ec/kWh $
5,744
Reduced Cost Recovery Distribution EPMC Dist $(65,996)
Account
Catastrophic Event Distribution EPMC Dist $
3,715
EMF Distribution EPMC Dist $
738
Non utility affiliate credit Unclear split $(11,969)
Hazardous Waste Unclear split $
5,935
Total allocated by equal $ 62,276
cents/kWh less
Catalina
PX revenues
Total allocated by EPMC $(64,560)
dist.
Total for MAM per TURN $ 2,284
less
Catalina
PX revenues
PPP = Public Purpose Program
ec/kWh = Equal Cents per kWh
EPMC Dist = Equal
percentage of marginal cost
of distribution
split = allocate 1/2 to
ec/kWh and 1/2 to EPMC Dist
* Subject to CPUC approval
Baseline Rate Unbundling Method
In the Rate Unbundling Working Group (RWG), TURN recommended that the baseline tier differential for residential rate be allocated to both the distribution and competitive transition cost (CTC) components of the customer bill. This would ensure sufficient revenues to allow for a meaningful tier differential. This proposal was generally followed by PG&E and SDG&E, but not by Edison.
For instance, excluding generation, if the CTC component is 30% of the bill and the distribution rate is 35% of the bill, then the utility will have 65% of the residential bill available to be spread to inverted block rates (PX price, transmission, and PPP programs are excluded from tier differential and included as a discrete line item). However, only applying baseline rates to CTC results in two difficulties. First, instead of having 65% of the revenues to spread for a tier differential in the example above, only 30% of the revenues are available to spread. Second, when the CTC is paid off, the remaining bundled residential energy charge will be a flat or nominally inverted rate, (and the total rate including the customer charge may be an illegal declining block rate) absent further Commission action. PG&E and SDG&E avoided this outcome by applying the baseline tier differential to both distribution and CTC charges.
Edison, on the other hand, proposes to reflect the baseline tier differential only in its residential customers’ CTC charges. TURN opposes Edison’s proposal. By reflecting the baseline tier differential only in CTC charges, Edison’s residential customers are at risk of having a flat or only nominally inverted rate design by the time their portion of the CTC is paid down. As it is paid down, the amount of CTC revenues will not be sufficient to provide a meaningful tier differential. Thus, at the end of the transition period, residential customers could be facing a distribution rate without an inverted tier structure. In the RWG, Edison seemed to acknowledge that its current proposal would necessitate the need for future Commission action to maintain residential baseline rates once the rate freeze ends.
TURN believes that Edison’s current proposal raises significant public policy questions. In essence, Edison is asking that the Commission to adopt a rate design that will require it to be ready to “fix” a future problem so as to maintain the status quo. At the same time, there is a more straightforward approaches available that do not require such Commission action – to wit, including a tier differential in both distribution and CTC rate components. Edison and the Commission can avoid the need for a special future Commission rate proceeding to fix the baseline problem by simply fixing it now and adopting the same rate unbundling as PG&E and SDG&E.[16]
Report on Unbundling the Rates of the California Electric Utilities
Prepared Testimony of
William B. Marcus
JBS Energy, Inc.
311 D Street
West Sacramento
California, USA 95605
tel.
916.372.0534
on behalf of
Toward Utility Rate
Normalization
and
Utility Consumers Action Network
California
Public Utilities Commission
App. 96-12-009 et al.
February 28,
1997
Table of Contents
CHAPTER 1: INTRODUCTION AND SUMMARY 1
CHAPTER 2: GENERAL RECOMMENDATIONS REGARDING UNBUNDLING 4
Costs of Load Dispatching and Power Purchasing Should No Longer Be Included in Utility Rates Because the Functions Have Been Transferred to the ISO and PX. 4
Public Purpose Costs Should Be Unbundled from Non-Generation Costs. 5
Distribution Costs Themselves Should Be Further Unbundled. 5
Overall Policy 5
Marketing Costs Must Be Unbundled Now. 7
Information Services Costs Must Be Unbundled. 10
Administrative and General Expense and General and Common Plant 11
Interface Between Rate Reduction Bonds and Unbundling 14
Unbundling of the Utilities’ Line Extension Allowances 16
Unbundling the Utility Cost of Capital to More Accurately Reflect Unbundled Utility Functions 17
Bill Formatting Issues 18
CHAPTER 3: UNBUNDLING COSTS FOR PACIFIC GAS AND ELECTRIC 21
SUMMARY OF PG&E RECOMMENDATIONS 21
LOAD DISPATCHING 22
FURTHER UNBUNDLING OF DISTRIBUTION COSTS 22
UNBUNDLED MARKETING COSTS 22
CARE ADMINISTRATIVE EXPENSES SHOULD BE CLASSIFIED AS PUBLIC PURPOSE PROGRAM COSTS. 23
ADMINISTRATIVE AND GENERAL UNBUNDLING 24
COMMON AND GENERAL PLANT 29
SUMMARY OF UNBUNDLED COSTS 30
CHAPTER 4: UNBUNDLING COSTS FOR SAN DIEGO GAS AND ELECTRIC 32
SUMMARY OF SDG&E RECOMMENDATIONS 32
LOAD DISPATCHING COSTS 32
MARKETING COSTS 33
SDG&E’S ADMINISTRATIVE AND GENERAL COST AND PAYROLL TAX ALLOCATION 33
FURTHER BREAKDOWN OF NON-GENERATION A&G AND PAYROLL TAX COSTS 42
CHAPTER 5: UNBUNDLING COSTS FOR SOUTHERN CALIFORNIA EDISON 44
SUMMARY OF RECOMMENDATIONS FOR SCE 44
EDISON’S FUEL OIL PIPELINE COSTS SHOULD BE RECOVERED THROUGH THE MAM ON AN INTERIM BASIS IN 1998, PENDING FURTHER REVIEW BY THE ISO AND IN THE CTC PROCEEDING. 45
NON-GENERATION RATE BASE FOR COMMON COSTS OTHERWISE ALLOCATED TO SONGS AND PALO VERDE 46
LOAD DISPATCHING COSTS 47
MARKETING COSTS 47
A&G AND COMMON PLANT COSTS 48
MISCELLANEOUS ADJUSTMENT MECHANISM (MAM) COSTS SHOULD BE REALLOCATED. 48
BASELINE RATE UNBUNDLING METHOD 52