III. PX Pricing Issues

PG&E, Enron and WPTF filed a stipulation with regard to the direct access minimum bill and the public release of all inputs PG&E uses to calculate the PX credit.

With regard to the minimum bill, PG&E explains that all three utilities' tariffs provide that when a direct access customer's PX credit exceeds the amount of the otherwise applicable "bundled" bill (that is, a bill that includes charges for all utility services, such as distribution and transmission), the customer's total utility charges will be equal to zero. Thus, the customer would not receive a negative bill (or credit), even if the PX credit exceeds the total bill. The Commission approved this provision in Resolution E-3510 finding that the zero minimum bill was essentially approved by D.97-08-056. In this proceeding, WPTF proposed eliminating the zero minimum bill arguing that it is a disincentive to direct access. Direct access customers will receive the benefit of PG&E's agreement to eliminate the direct access zero minimum bill from the effective date of this decision through bill credits. The settlement filed herein eliminates the zero minimum bill. PG&E will implement the change directly in bills as soon as its billing system is able to accommodate the change. PG&E also agrees to refund credits to the direct access customer's bill which would not have been charged in the absence of the zero minimum bill provision. Such refunds would not be necessary after the zero minimum bill is implemented on its billing system.

In this proceeding, Enron and WPTF also proposed that the utilities make public any information used to calculate the PX credit. The stipulation they reached with PG&E essentially withdraws this proposal and requires only that PG&E continue to make public that information which it currently provides to interested parties. That information is (1) load profile data; (2) hourly prices; (3) 30-day average prices for each rate schedule (or multiple week averages as the Commission requires); and (4) distribution loss factors.

No party opposes the stipulation between PG&E, Enron and WPTF. The stipulation reasonably resolves issues relating to PG&E's minimum bill and PG&E's disclosure of information used to calculate the PX credit. We therefore adopt it.

The stipulation between Edison, Enron, and WPTF is essentially the same as that presented for PG&E, that is, that Edison will eliminate the minimum bill provisions of its tariffs and will not be required to disclose more information about the PX calculation than it already makes public. We adopt the stipulation.

The stipulation between SDG&E, Enron, and WPTF is essentially the same as that presented for PG&E, that is, that SDG&E will eliminate the minimum bill provisions of its tariffs and will not be required to disclose more information about the PX calculation than it already makes public. We adopt the stipulation.

Under the restructured electricity market in California, customers may subscribe to "bundled service" from the utility distribution company or "direct access" service from a competitive energy provider. Customers who purchase bundled service from the utility pay a PX charge to cover the utility's power supply costs. Customers who elect direct access service receive a credit on their bills called the PX Credit. The credit offsets the energy costs included in the bundled rate.

Issues relating to the calculation of the PX credit were the source of substantial controversy among several parties. Generally, Enron, Commonwealth, and WPTF advocate substantial changes to the existing PX credit. These parties seek modifications to the cost components of the credit, the methodology employed in its computation, and the handling of input data to the calculation. Other intervenors, including DGS, TURN, and ORA, advocate less extensive changes to the credit. Edison, PG&E, and SDG&E defend the existing structure of the credit, but seek certain changes in computation methodologies, as well as Commission authorization for the inclusion of "ex-post market" costs in the PX credit.

Enron, Commonwealth, and WPTF contend that the PX credit as presently constituted needs to include additional cost items in order to reflect the costs utilities incur in providing bundled energy service. Enron believes omission of these costs from the PX credit places competitors in generation markets at a disadvantage because customers who use competitors' services must pay for costs of the utility's power supply, even though they do not use it. Hence, these direct access customers pay twice for power. DGS makes similar comments, arguing that the PX credit must include all costs that are relevant to power generation, including costs of marketing, customer service, rate design, and Administrative and General (A&G). If these costs are not included in the credit, DGS argues, direct access customers pay for them by way of distribution rates although direct access customers make no use of the utility's (generation) procurement services.

In enumerating the costs which it argues are being improperly omitted from the PX credit calculation, Enron distinguishes "internally managed" and "externally managed" costs. "Internally managed" costs are those incurred within a utility's operation, and "externally managed" costs are those billed to a utility by third parties, such as the PX.

Of the internally managed costs, Enron proposes that a share of the cost of forecasting load, dealing with the PX, A&G expenses, taxes, customer service, rate design, and advertising expenses should be reflected in the PX credit. Enron relies on company data to estimate PG&E's annual revenue requirement for procurement activities at $12 million and procurement-related A&G at $7.5 million. Enron states it is unable to calculate comparable figures for Edison and SDG&E because the data was not available in the course of the proceeding. Commonwealth adds that some portion of customer service costs should be considered energy-related and therefore allocated to the PX credit. WPTF and DGS join Enron and Commonwealth in advocating that such "procurement costs" be included in the PX credit.

Edison, PG&E and SDG&E oppose the inclusion of any additional categories of ongoing costs in the PX credit. SDG&E argues that D.97-08-056 and Resolution E-3510 specified the costs to be included in the PX credit. Although the Commission did not use the term "avoided costs" in those documents, SDG&E argues, all of the costs the Commission directed the utilities to include in the PX credit are, in fact, avoidable costs. Similarly, PG&E observes that Enron proposes approval of a fully allocated costing methodology for the PX credit, methodology which the Commission rejected for revenue cycle services in D.98-09-070, finding that such pricing methods were not necessary to assure market entry by competitors.

SDG&E observes that if it were to include a share of internally managed costs in the PX credit, it would have to compete for energy customers. SDG&E argues this would represent a marked departure from the Commission's current market framework, which presumes the utilities are default providers without a competitive role in energy markets. PG&E adds that, if the Commission were to find that additional costs should be included in the PX credit calculation, the record in this proceeding is inadequate to adopt any final calculations.

Edison objects to a review of the PX calculation on the basis that the Coordinating Commissioner's Ruling of May 14, 1998 stated an intent to "expand the scope of the RAP to consider issues which address the accuracy of the PX credits." Edison argues that the term "accuracy" in this context precludes the types of modifications proposed by Enron and others.

Discussion. As a preliminary matter, we find that the proposals of Enron, Commonwealth and WPTF are appropriately considered in this proceeding. We agreed to consider these matters in the scoping memo of this proceeding. Moreover, contrary to the utilities' assumption, our findings in D.97-08-056 did not suggest the matter was resolved once and for all. D.97-08-056 addressed the components of the PX calculation there in only the most cursory fashion. Were we to limit ourselves to an arithmetic verification of the utilities' calculations, we could not take up even the modest changes the utilities propose.

The question for resolution here is whether certain utility direct and overhead costs should be recognized in the credit for the PX or be assumed solely by utility generation customers. Failure to recognize real cost savings in the PX credit, or to require direct access customers to assume costs for which they are not responsible may compromise efforts to promote competitive markets.

No party disputes that energy competitors incur the types of costs Enron would have included in the PX credit or that competitors must ultimately recover those costs in order to remain viable. We have consistently stated our view that firms must recover their long run marginal costs in order to remain viable. Recognizing this, D.98-09-070 directed the utilities to present long run marginal cost studies for their revenue cycle services. The same concerns apply here. If we are to promote competition in generation markets, utility commodity prices must ultimately recognize those costs which the utilities must recover in the long run as any other provider. Our long term strategy is to create an industry structure in which the utilities are one of many competitors. As part of that strategy utility pricing must eliminate any "competitive advantage created by an institutionalized removal of costs otherwise intrinsic to the provision of a service," as DGS' comments describe the utilities' proposals. Future rate design should recognize changes which might occur with regard to the utilities' obligation to serve.

Consistent with our longer term view, we find that Enron makes a reasonable case that some of the costs it identifies may be appropriately included in the PX credit calculation, such as those associated with account managers and customer services representatives. ORA also makes a reasonable case that the costs of self-provision of ancillary services and financing costs for purchasing power from the PX should be added into the PX credit calculation. TURN and DGS join these parties in proposing that the PX credit should recognize additional costs of procurement. No such costs are adequately specified in the record for purposes of ratesetting in this proceeding, however. We will direct the utilities to include the long run marginal costs of these functions in future calculations of the PX credit, that is, in the utilities' 1999 RAP applications. Recognizing that long run marginal cost studies would be a difficult undertaking in the near term, we will require the utilities to use actual April l998-April l999 recorded costs or l999 budgeted or forecasted costs as proxies for long run marginal costs. The actual recorded costs should include allocations of overheads. It is our intent to review these additional PX credit items on an expedited basis in the 1999 RAP.

The record in this proceeding does not permit us to establish rates which recognize long run marginal costs. We adopt the utility proposals with the understanding that they are interim and subject to revision in the next RAP proceeding. There, we will set the PX credit recognizing policy determinations made in other proceedings, such as the post-transition ratemaking applications, the distribution rulemaking, or a rulemaking on market structure should we initiate one in the near future.

Enron proposes that externally managed costs ought to be reflected in the PX credit. Such costs include ongoing expenses such as the ISO Grid Management fee, and a variety of related charges. Other external costs are those related to PX start-up and development expenses, which are not considered ongoing. Enron estimates these costs to be about $45 million for PG&E, a similar amount for Edison, and $10 million for SDG&E through the year 2001.

The utilities do not dispute the appropriateness of including externally managed costs that are ongoing. PG&E claims that all of these costs are either already reflected in the PX credit, or will be if Advice Letter 1781-E-A is approved. Edison and SDG&E also state that their PX crediting procedures recognize these costs. Enron does not contest these claims. The remaining issue is whether the PX startup and development costs should be included in the PX credit.

Enron observes that all energy providers must pay for start-up costs. Under current utility rate design, according to Enron, customers of competitive energy providers pay twice for these costs, once to their energy providers and again to the utilities by way of distribution rates. Commonwealth and WPTF support Enron's proposal. CLECA/CMA argue that including PX startup expenses in the PX credit would be consistent with D.97-08-056 and Resolution E-3510.

Edison, PG&E and SDG&E oppose including PX start-up costs in the PX credit. They assert that the PX is an integral part of the state's restructured electric industry and that, accordingly, all customers should share the expense of creating the PX. The utilities point out that all customers have the option of purchasing power from the PX, and that the PX is the default supplier of energy to all customers. Edison notes that competitors may use the PX as a scheduling coordinator. PG&E observes that, although any scheduling coordinator may purchase power through the PX, only the utilities pay the PX start-up charges.

Edison proposes that, should the Commission find that only bundled customers should bear the PX startup expenses, the Commission also should direct the utilities to recover the costs of Direct Access Service Request (DASR) processing entirely from direct access customers. Presently, all customers share these costs. Enron says there would be no need for such a quid pro quo, because DASR expenses benefit all customers by making it possible for customers to select an energy provider.

TURN, DGS and ORA oppose including PX start-up costs in the PX credit. They argue that all customers should share these costs because the costs were incurred as part of the creation of the restructured, competitive electricity market in California. ORA adds that the position of the PX as the default energy provider in the state distinguishes it from competitive energy providers and from other scheduling coordinators, which are free to enter and leave the market, and which be selective regarding the customers they serve.

Discussion. The implementation of direct access would not have been possible without the implementation of the PX. In D.95-12-063, we found that the PX would "foster and sustain the development of a transparent spot market for the generation of electricity" in order to provide price signals to generators, buyers and consumers. The PX is a source of market price information that may be used in forming direct access contracts. The PX acts as a scheduling coordinator and energy broker. All of these activities benefit direct access customers as well as those purchasing power from the distribution utility. Commission policy provides generally that customers who benefit from a cost should assume liability for the cost. Accordingly, all customers should assume liability for start-up expenses. We will not require the utilities to modify their PX credit calculations to reflect the PX start-up and development costs.

On June 29, 1998, PG&E filed Advice Letter 1781-E in which PG&E proposes to include "Post-Real Time Settlement Costs" in the PX credit. On August 27, 1998, PG&E amended Advice Letter 1781-E-A to specify the post-settlement costs that would be included in the PX credit. The advice letter would incorporate into the PX credit amounts billed to PG&E by the PX after the settlements process for a given day is finished (91 days following the trading day), or amounts billed to PG&E as lump-sum dollar amounts (not identified with a particular day's energy costs). The advice letter specifies charges for black start capability, PX administration, and ISO grid management.

The Assigned Commissioner's Ruling Supplementing Scoping Memo, issued September 24, 1998, incorporated this matter into this proceeding. The advice letter was not protested and no party has opposed the proposed changes here. ORA believes PG&E's existing tariff language already encompasses the "ex-post" costs, but supports the proposed new tariff language as a useful clarification.

Edison states that its existing tariff language is broad enough to include all the costs that are the subjects of PG&E's advice letter. Therefore, Edison states that its tariff will not require any modifications. SDG&E makes the same observation, although SDG&E seeks to alter how it computes these elements of the credit, as discussed below.

D.97-08-056 approved Edison's methodology for the recovery of these "ex-post market" costs in the PX credit. While the utilities' computations may differ, the cost components of the PX credit should be the same for the three companies. Accordingly, we adopt the changes proposed by PG&E in Advice Letter 1781-E-A, except for the inclusion of PX start-up costs in the PX rate, which PG&E is no longer proposing.

In its testimony, PG&E proposed to sponsor an independent audit of the PX credit calculations to be performed monthly by a neutral auditor chosen by the utilities and approved by the Commission. Enron and WTPF raised concerns that the audits would not go far enough to assure correct calculations. SDG&E and Edison did not object to PG&E's proposal as it would affect their own calculations.

After submission of the record, on March 11, l999, PG&E, Edison, SDG&E and WPTF filed a stipulation in this proceeding with a request for its approval and motion for waiver of the Commission's procedural rules which guide the review of settlements.

With regard to waiver of our rules, the parties explain that their late filing resulted from ongoing collaboration and compromise. They ask the Commission to permit parties to address the stipulation in their comment on the proposed decision rather than pursuant to the procedures outlined in Rules 51.1, 51.2 and 51.4. We grant this motion for waiver and have permitted the parties to comment on the stipulation in comments to the ALJ's proposed decision.

The substantive elements of the stipulation set forth a procedure for auditing the utilities' calculation of their respective PX credits. Specifically, it provides that the Commission would select an auditor from a list developed by the utilities and three competitors. The auditor, who would be paid by the utilities, would review the PX calculations for consistency with Commission decisions and provide a monthly report to the Commission in this regard. The utilities will modify the PX credits according to the audit report with the understanding that neither the utilities nor other parties waive their right to challenge the calculation in subsequent revenue adjustment proceedings.

The stipulation does not resolve whether the audit procedure would end with the termination of the rate freeze or continue after that time.

We adopt the stipulation. In doing so, we do not delegate our authority or responsibility to a third party to assure the PX credit calculations are consistent with our orders and are otherwise lawful. The audits will provide additional confidence in the utilities calculations but they will not affect the rights of the Commission, its staff or other parties to review the calculations as the stipulation specifies. We find that this procedure should continue until and unless the Commission directs otherwise and with the understanding that the process for calculating the PX credit may change or be eliminated.

SDG&E proposes to modify the mechanism for ex-post market costs6 by estimating certain inputs. SDG&E says its proposed procedure will improve the accuracy of the PX credit by reducing the effects of the time lag. The time lag occurs because the PX settlements process, which establishes ex-post costs, can take several months. SDG&E provided an example in which ex-post costs incurred in April and based on April demand, are recovered in August when demand is considerably higher. As a result, prices are inaccurate and the utility recovers either too much or too little, depending on the circumstances. SDG&E comments that the problem is worsened by the fact that ex-post costs are much higher than the utilities expected, constituting 10% to 30% of SDG&E's total PX price.

To address the problem, SDG&E proposes to estimate ex-post costs in setting the PX price rather than relying entirely on actual data. The estimates would be calculated using actual unit prices and estimated volumes. The data is available soon after the trading day. SDG&E would incorporate the actual costs into a later month's PX.

No party opposed SDG&E's proposal. Commonwealth, DGS, ORA, and TURN support the SDG&E proposal. Enron and WPTF support the change for SDG&E, and also advocate its use by Edison and PG&E. Edison and PG&E agree in principle with the SDG&E proposal, and are willing to study it. However, PG&E says the PG&E data processing system cannot accommodate such a method. Edison states that the SDG&E proposal would require forecasting certain charges.

Edison's objection to the SDG&E calculation is not compelling. The change would require Edison to estimate only quantities, not prices. Even poor estimates would represent an improvement over existing practice and would be subject to a true up based on actual data, as it becomes available. PG&E's problem is familiar based on its representations in other proceedings with regard to the limitations of its current operations. The SDG&E proposal represents an improvement in the seasonal price signals of the PX rate. We adopt it for SDG&E. We direct Edison to incorporate the change to its PX rate calculations no later than the end of 1999. PG&E already incorporates ex post expenses in its PX credit calculation on a time of use basis.

The parties addressed whether in calculating the PX credit, the utilities should incorporate ex-post expenses based on time of use. PG&E assigns these costs to specific hours of the day, corresponding to billing by the PX. Edison and SDG&E have spread these costs across all hours of the day. Edison offers to switch to the time-of-use methodology. SDG&E advocates retaining its existing method for incorporating these costs into the PX credit.

Commonwealth and TURN recommend that the Commission adopt a time-of-use method. TURN argues that averaging costs across all hours in the month, "means that high ancillary service and imbalance energy costs incurred during peak summer afternoon demand periods end up spread to consumption that takes place in off-peak night and weekend periods. This creates another pricing distortion..."

SDG&E argues that time-of-use treatment of PX bills also introduces distortions, because the PX bills some costs in ways that do not correspond to the time incurred. SDG&E observes, for example, that some PX charges are billed to the first hour of the last day of the month, even though the corresponding services were provided over periods of a month or more.

The PX credit should reflect corresponding costs so far as is practical. Ideally, the utilities would be able to treat "ex-post" costs in ways that avoid any type of pricing distortions. We will direct PG&E and Edison to incorporate the change to the calculation to correspond to time of use. We will not order SDG&E to do so at this time but recognize that the issue may come up in subsequent proceedings as the utilities refine the methods they use to calculate the PX credit.

6 SDG&E states ex-post market costs include Day-Ahead Ancillary Services, Hour-Ahead Ancillary Services, Replacement Reserve, Real Time Energy, Imbalance Energy, Unaccounted-For Energy, and management charges from both the PX and ISO.

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