Decision 96-11-041
In this decision we approve, with certain modifications, the draft tariff proposed by Pacific Gas and Electric Company (PG&E) to implement the interim competitive transition charge (ICTC) authorized in Decision (D.) 96-04-054. The ICTC is intended to recover certain costs related to the restructuring of the electric utility industry.
On February 15, 1996, PG&E filed an emergency motion asking the Commission to adopt a procedure to apply an ICTC to customers who depart its system before the Commission has adopted a final CTC. In D.96-04-054, we rejected certain portions of PG&E's request but endorsed the principles behind the ICTC. Accordingly, we ordered the Commission Advisory and Compliance Division (CACD) to hold a collaboration to bring the affected parties closer to agreement on the details of the ICTC. CACD held the collaboration on April 24-26, 1996, and issued its report on the collaboration (Report) on May 6. After the close of the collaboration, PG&E circulated a proposed tariff (Attachment 2 to the Report). Responding to a suggestion in the Report, the Administrative Law Judge (ALJ) issued a ruling on May 6 allowing comments on the Report. Comments were filed by 22 parties.(1)
The general topic of transition costs and the specific proposal for an interim CTC were addressed in Assembly Bill (AB) 1890 (Stats. 1996, Ch. 854), which Governor Wilson signed on September 23. On September 30, the ALJ issued a ruling asking whether PG&E wished to continue to press its motion for an ICTC after the signing of AB1890, and, if so, whether AB 1890 affected the relief requested in the motion. Comments on these questions were filed by the California Department of General Services (DGS) and UC/CSU, jointly; Chevron USA Products Company (Chevron) and Shell Martinez Refining Company (Shell), jointly; EPUC; MID; and PG&E.
After addressing the need for evidentiary hearings, we will discuss the issues related to PG&E's proposed tariff and the effect of AB 1890 on the proposed ICTC.
The ALJ's ruling of May 6 specifically asked parties to indicate whether they felt evidentiary hearings were necessary, and if so, what facts the party would present to support its position at such hearings. ACWA, Farm Bureau, EPUC, Foster Farms, MID, Praxair, BART, SCWA, and UC/CSU argued in favor of evidentiary hearings. For the most part, the parties presented variations of the argument that evidentiary hearings are necessary to resolve what the party views as disputed issues of fact.
We do not intend to discount those arguments or prejudge those issues, but we will not undertake evidentiary hearings on the ICTC. The ICTC is by definition interim, and will be in effect only until we adopt a final CTC approach. The development of the final CTC will require us to consider in detail the same issues that parties would have us now address in evidentiary hearings on the ICTC. It makes little sense to delay the effectiveness of the ICTC to conduct hearings on issues that we will necessarily consider again in a matter of months.(2)
Moreover, the detailed scrutiny that evidentiary hearings allow would be inappropriate for the interim charge. The ICTC is intended to be in effect for only a short period, and all payments are subject to adjustment as we refine the CTC. As we stated in D.96-04-054, the ICTC will necessarily be "somewhat rough; excessive precision is not required for these purposes." (Slip op. at 16.)
EPUC also argued that the ICTC is a rate increase, and Public Utilities Code (PU) § 454 prevents rates from taking effect until the Commission finds that the rate is justified, notice of the proposed rate is issued, and a hearing on the application is held. This issue was also raised in the applications for rehearing of D.96-04-054, and we are evaluating and addressing that argument in our consideration of the applications for rehearing.
One of the questions raised in the September 30 ruling was whether the enactment of AB 1890 eliminated PG&E's perceived need for an ICTC. PG&E responds that it still believes an ICTC is needed. It contends that customers' efforts to purchase electricity from other sources and evade paying the CTC have continued and intensified. Although some of these activities may fall within the exemptions from CTC created by AB 1890, others do not. PG&E further notes that PU Code § 373(b), added by AB 1890,(3) makes specific provision for a nonbypassable ICTC, subject to the "firewall" described in § 367(e).(4)
We agree that the Legislature has acknowledged the Commission's authority to adopt an ICTC, although the Legislature placed certain restrictions on the details of the ICTC, as we discuss below.
PG&E's proposed ICTC tariff provides a convenient focus for our discussion, although AB 1890 has a significant effect on several of its most important provisions. We will structure our discussion by addressing the issues raised at the collaboration in relation to the tariff, with mention of the effects of AB 1890 where appropriate. For convenient reference, PG&E's proposed tariff, with revision reflecting the provisions of AB 1890, is Attachment A to this decision.
Some of PG&E's customers have multiple connection points that are metered and billed as separate accounts. PG&E has in the past not allowed these customers to aggregate their usage from these multiple accounts to take advantage of more favorable rate schedules. Not surprisingly, these customers argue that if they could not aggregate their usage to obtain lower rates, their load should not be aggregated for purposes of applicability of ICTC. PG&E agreed to accommodate this concern and a related issue raised by BART concerning conjunctive billing. We agree that out of fairness applicability of the ICTC should be determined on an account basis, with appropriate accommodation of conjunctively billed accounts. PG&E's proposed tariff establishes applicability on an account basis without prejudicing BART's rights to conjunctive billing.
PG&E originally proposed to apply the ICTC only to customers with monthly peak loads of more than 500 kilowatts (kW), and in D.96-04-054 we concurred with PG&E's proposed threshold. PG&E now argues, however, that AB 1890 specifies that the ICTC must apply to all who were customers on or after December 20, 1995 (the effective date of our Policy Decision, D.95-12-063). In its comment on the ALJ's September 30 ruling, PG&E asks the Commission to apply the ICTC to customers of all sizes because customers below the 500-kW threshold have already left, and MID has signed agreements with several cities to serve thousands of PG&E customers whose peak loads are well below the 500-kW threshold.
Without regard to the merits of PG&E's request to eliminate the 500-kW threshold, we will not act on that proposal because of the way it was presented. PG&E's original motion proposed that the ICTC would apply only to customers with monthly peak loads of more than 500 kW, and D.96-04-054 approved that proposal. It seems likely that many small customers have stopped following this part of this proceeding because they assumed, in reliance on PG&E's motion and our decision, that it had no relevance to them. PG&E's new proposal would greatly expand the applicability of the ICTC, but a comment on a ruling is not a good vehicle for presenting this proposed expansion. We are very concerned that the affected parties will not receive effective notice of PG&E's proposed expansion, even if they in fact received PG&E's comments. The number of documents produced in connection with this proceeding is enormous, and it is not reasonable to expect every party to read every word of every filing. If PG&E now desires to change the 500-kW limit, it should file and serve a new motion to that effect.
Accordingly, we will here consider how to implement the 500-kW threshold presented in the motion. Parties at the collaboration debated how this criterion should be applied. A simple approach would be to apply the ICTC to departing customers served under PG&E's Schedules E-19 and E-20, since customers served under those schedules generally have demands of more than 500 kW. However, some customers with lesser demands are also apparently served under those schedules. Some parties proposed a criterion of three consecutive months with loads of more than 500 kW, but PG&E feared that many large customers had sufficiently variable demand to avoid meeting that standard. PG&E proposed that one month of demand of more than 500 kW out of the last 12 months would subject a departing customer to ICTC, but others argued that standard would unfairly capture customers with a single demand spike.
For the interim purposes of this decision, we will adopt a variation of PG&E's proposal that attempts to accommodate the stated objection. The ICTC will apply to departing customers who have had monthly demands of more than 500 kW in any two of the preceding 12 months.
In Conclusion of Law 7 of D.96-04-054, we stated, "The ICTC should be collected from any customers who leave the system after December 20, 1995 and before January 1, 1998." Some parties thought the tariff should echo this statement. PG&E objected to including a specific end date in the tariff, which would require the Commission to extend or modify this date if implementation of electric restructuring is not completed by our target date. After the collaboration, PG&E submitted the following proposed tariff language: "The Interim CTC Procedure shall remain in effect until superseded or terminated by the Commission."
PG&E's proposed language is acceptable. We have made clear our firm intent to complete the implementation of electric restructuring by January 1, 1998 or earlier, and the Legislature has echoed that intent. (§ 330(l)(4).) However, we also recognize that not all elements of the restructuring are under the jurisdiction or control of the Commission or the Legislature. Important elements of the Independent System Operator and the Power Exchange, for example, will be determined by the Federal Energy Regulatory Commission. PG&E's proposed language recognizes this limitation and contemplates a smooth transition from the ICTC to the final CTC.
Some parties raised the argument that if a new customer moved into PG&E's service territory, took service from PG&E, and effectively replaced a departed customer who was paying the ICTC, PG&E would double collect the ICTC.
This fear is unfounded. The exit and entry of customers is accounted for in the sales forecast approved by the Commission. The same sales forecast will be used in calculating the ICTC. The only effect of the addition of a new customer is to reduce the transition costs borne by departing, existing, and new customers. The addition of a new customer will reduce transition costs in two ways. First, new customers who take service from PG&E before the implementation date will pay for transition costs initially as part of their bundled rate and later through the final CTC, thus reducing the amounts eventually eligible for transition cost recovery. Second, the added demand created by new customers who commence service after the implementation date may exert upward pressure on the prices of electricity supplied through the Power Exchange and on the market price of generating plants, thus reducing the primary measures of transition costs. (See D.95-12-063, as modified by D.96-01-009 (the Policy Decision), slip op. at 113-116.) Since the revenues from the ICTC will be booked in an ICTC balancing account, any "extra" ICTC will eventually reduce the amount of transition costs to be collected. Both departing and remaining customers are responsible for paying transition costs, and both departing and remaining customers benefit from reductions in transition costs.
In addition, § 369 requires the Commission to develop a mechanism that collects transition costs "from all existing and future consumers," indicating a Legislative intent that new customers' load would also be subject to the CTC unless they qualified for an exemption.
No modification to PG&E's proposed tariff is necessary due to this issue.
PG&E agreed to make one change to its proposed definition of departing load to clarify that it was concerned about customers who switch to another source of electricity, rather than another source of power, such as natural gas or diesel oil. The change of the word "power" to "electricity" excludes customers who switch to other fuels from the definition of departing load. This change appears consistent with § 371, which contemplates that CTC collection would vary with specified changes in usage, including "fuel switching."
We approve PG&E's proposed change, because it clarifies the intended application of the ICTC.
Parties proposed many exceptions to the definition of departing load that would exempt certain customers from the ICTC. Our consideration of these exemptions is guided by two concerns. First, in the Policy Decision we intentionally spread the responsibility for transition costs as broadly as possible. The greater the number of customers who bear this responsibility, the lower the financial effect on individual customers. We were also aware that larger customers have the greatest incentive and ability to leave the utility's system, and we did not want to leave smaller customers, who have the fewest alternatives to service from the utility, to bear the sole responsibility for transition costs. Second, the Legislature has allowed for a number of exemptions in AB 1890, and the ICTC must recognize some of these Legislative exemptions. (§ 373(b).)(5) With these principles in mind, we will briefly address the exemptions proposed by the parties to the collaboration.
Several parties contended that customers who take advantage of alternatives to utility service that existed before December 20, 1995, should not be subject to the ICTC. Stated in this way, this proposal contradicts our determination to institute the CTC "for all customers who are retail customers on or after [December 20, 1995], whether they continue to take bundled service from their current utility or pursue other options." (Policy Decision, slip op. at 110, emphasis added.) AB 1890, however, provides for exemptions that could be viewed as the exercise of existing options. Section 372 provides an exemption to customers served by on site or over-the-fence(6) cogeneration facilities that were operational or committed to construction as of December 20, 1995 for expansion of the facility's capacity by up to 20%. Except for this narrow exemption, we see no reason to change our policy at this time. PG&E should ensure that its proposed tariff accommodates the exemptions provided in § 372(a).
For some time PG&E has been authorized to negotiate special reduced-rate contracts with customers who present a threat of uneconomic bypass, typically, the ability to build a cogeneration or self-generation facility that would allow them to reduce or eliminate service from the utility. Some customers served under these agreements argue that if they decide to build the deferred generation facility, they should be exempt from the ICTC because when they made the economic decision not to build the facility, they had no notice or awareness that they might later be subject to the ICTC.
Thus, the issue is presented: When a bypass deferral contract expires and the customer chooses to proceed to build the deferred generator or to take service from another source, should that customer be subject to the ICTC? Under the broad definition of "departing customer" that we have approved, such a customer would be subject to the ICTC. Customers with bypass deferral contracts are retail customers of PG&E, even though they may pay a discounted retail price for electricity. This conclusion is reinforced by § 372(b)(2), which describes three options available to customers with deferral agreements. Under each of these options, including the option of building the deferred facility, the Legislature makes it clear that the customer would bear some responsibility for an appropriate share of transition costs.
Because cogeneration facilities take a substantial time to develop, some customers may have made significant investments in such facilities as of December 20, 1995. Because some of these facilities may have been planned to lower the cost of electricity by avoiding some of the costs we define as ICTC, the economics of these projects might be confounded by our decision to collect the ICTC from all departing retail customers of PG&E. As a matter of fairness, some parties have urged an exemption for customers who before December 20, 1995 (1) had made a substantial investment in a cogeneration or self-generation project, (2) had begun the permitting process for such a project, or (3) had given notice to the utility of their intent to construct such a project. At the collaboration, PG&E indicated its agreement with the first criterion. However, PG&E's proposed tariff is silent on this issue.
There is widespread support for an exemption for customers who had made substantial investments in cogeneration or self-generation projects before December 20, 1995, and AB 1890 reflects this sentiment. Section 372(a)(2) provides an exemption from transition cost responsibility "for a nonmobile self-cogeneration or cogeneration facility for which the customer was committed to construction as of December 20, 1995," with a restriction that the facility must be substantially operational on or before January 1, 1998. It will, of course, be fairly easy on January 1, 1998, to determine which facilities are substantially operational; it is much more challenging to apply this retrospective standard on a forward-looking basis, as § 373 requires us to do for the ICTC. The difficulty is to develop reasonably objective guidelines for the determination of whether a customer was committed to construction as of December 20, 1995.
We addressed a similar question when we set up the Qualifying Facility Milestone Procedure (QFMP) to allocate scarce transmission capacity among a large number of proposed QF projects that were competing for transmission access. Although the QFMP is not directly transferrable to this situation, some of its elements provide guidance about when a project begins the transition from idea to actuality. At a minimum, to qualify for this exemption, a customer should be able to demonstrate that the elements of "project definition," as stated in section IV.A. of the Fifth Edition of the QFMP (Revised Appendix A to D.87-04-077, reproduced here as Attachment B), had been met as of December 20, 1995. In general, this standard requires proof of site control, project description information, and a preliminary project schedule. As a general rule for applying § 372(a)(2) in the context of the ICTC, customers whose projects had not achieved this level of realization by December 20, 1995, should not receive the benefit of this exemption unless they can present other reliable information showing their commitment to construction. Customers who can show that the required elements of "project definition" were in existence on December 20, 1995 (and not reconstructed after that date for purposes of obtaining this exemption) should be allowed this exemption from the ICTC. As part of the truing up of the ICTC, PG&E shall apply § 372(a)(2)'s objective standard of substantial operation by January 1, 1998 to determine finally which customers were entitled to this exemption.
At the collaboration the City and County of San Francisco argued that customers who had contractual or statutory rights to take power from an entity other than PG&E as of December 20, 1995, should be exempt from the definition of departing customer. These two categories of rights require different analyses.
Contractual rights derive from the agreement of two private parties. Our action of declaring that departing retail customers will be subject to the ICTC is a change in circumstances that the parties have either accounted for in their agreement or not. Whether or not our actions require an alteration of the relative rights of the contracting parties is a matter determined by the specific terms of the contract and applicable contract law. We see no reason why the arrangements between two private parties should alter our intended broad application of the ICTC.
Rights conferred by statute, however, raise other concerns. We have no intent or authority to frustrate the purposes of legislation enacted by Congress or the California Legislature. It is clear that the ICTC tariff must reflect the exemptions stated in §§ 372 and 374 and any specific exemption created by subsequent legislation. Whether or not our action in adopting the ICTC would frustrate the purpose of other existing legislation, however, depends on the specific language of the statute, and no party has presented specific statutory language that is alleged to conflict with the ICTC. Nevertheless, we think it appropriate to respond to San Francisco's concerns and to recognize the existence of statutory rights in PG&E's tariff. We will direct PG&E to add to its tariff a variation on language proposed by San Francisco. The tariff should provide an exemption from the definition of departing load for "reductions in a customer's load that result from the exercise of a statutory right that existed on December 20, 1995."
Some customers take service from both PG&E and federal power agencies. For a number of reasons, deliveries from federal power agencies may vary widely from month to month. These customers seek an exemption from the definition of departing load.
No exemption seems necessary. An important point here is that the reduction in load is not permanent, but is part of normal and continuing variation in the federal deliveries and residual PG&E service. As described in the Report, these customers do not fall within the definition of departing load, since they continue to be PG&E customers under the same arrangements that governed their service from PG&E before December 20, 1995, and any reductions in load that fall within the existing arrangements are not "subsequently served with electricity from a source other than PG&E." This conclusion may not apply if the existing arrangements were altered in a way that reduced service from PG&E and substituted service from another source.
In addition, the concerns raised by these parties may be obviated by the provisions of § 374(b) and (c), which provide exemptions from transition cost responsibility for loads served by preference power purchased from a federal power marketing agency.
MID sought an exemption because of its special rights as an irrigation district. MID may qualify for a portion of the 110-MW exemption granted to irrigation districts in § 374(a)(1). To the extent that MID's request extends beyond this statutory exemption, however, we will not grant the requested exemption here. MID has made similar arguments in its application for rehearing of D.96-04-054, and we will consider and address those arguments in our decision on the applications for rehearing.
Customers who receive service on interruptible rate schedules argue that they should not be subject to the ICTC because their interruptible status means that PG&E did not have to plan to meet their power needs, and accordingly these customers did not contribute to any "stranded" generation costs.
There are several flaws in this argument. If interruptible customers were completely interruptible and had no expectation of service, there might be some logic to this requested exemption. But the interruptible tariffs place limitations on PG&E's ability to cease serving these customers. Moreover, until recently these customers enjoyed service with only rare and brief interruptions, if any. Precisely because PG&E had excess capacity (which we now call "stranded"), these customers have had the benefit of favorable rates without having to incur the costs of interruption. It is disingenuous for these customers to have enjoyed for years the benefits of a system with ample resources, only to seek to foist off on other customers the costs that made those benefits possible. We will not exempt interruptible customers from the ICTC.
Some customers purchase power at retail and resell it to the ultimate consumer. Mobile home park owners and shopping mall owners are two examples of this arrangement. Some of these master meter customers argued for exemption from the ICTC, since they are analogous to power wholesalers.
We reject this proposed exemption. These customers receive service under retail schedules, and they, not their tenants, are the customers of PG&E. They should be subject to the ICTC to the same extent as other retail customers.
A customer who both improved efficiency, thus reducing load, and replaced PG&E as its electric supplier could be subject to an ICTC for the "phantom" load that was eliminated by the efficiency improvements. PG&E agreed to adjust historical demand to account for the portion of the load reduction resulting from efficiency improvements. Section 371 allows for adjustments to the CTC collected from customers based on "changes in usage occurring in the normal course of business," which includes installation of demand-side management equipment or facilities and energy conservation efforts. Although we are not required to incorporate the provisions of § 371 in the ICTC, PG&E's offer is consistent with the spirit of this section. We authorize PG&E to make such adjustments. No alteration of the proposed tariff is necessary to accomplish this adjustment.
In its comments on the September 30 ruling, MID objected to the proposed tariff's treatment of a customer's claims of exemption under §§ 371-374. When a departing customer presents its required notification of its claim of exemption, the tariff gives PG&E the power either to confirm the claimed exemption or to reject the claim and submit the ICTC projection to the customer. MID thinks that a customer's claim of exemption should be honored unless PG&E challenges the claim by filing a motion with the Commission or perhaps with the California Energy Commission.
We appreciate MID's concern, but we prefer to follow the usual practice of giving PG&E the initial responsibility for administering its tariff, including the determination of whether an exemption applies to a particular customer. If PG&E violates its tariffs, the customer may seek to remedy the violation by following the procedure we describe below for resolving disputes about the ICTC projection.
Section 4(A) of PG&E's draft tariff requires a customer to give PG&E notice of its intent to depart. PG&E has shortened the required notice period to 30 days before departure, rather than the 90 days in the tariff accompanying its emergency motion. We approve this change. PG&E also listed specific information to be provided in the notice, and we agree that this is also an improvement. Parties raised concerns about the wording of the provision that makes the ICTC immediately due and payable if notice is not given, but in our view the wording PG&E proposes is acceptable.
PG&E has accommodated parties' requests to allow a customer to obtain an ICTC projection before it decides to leave the system, and this is a worthwhile addition.
Section 4(B) concerns preparation and delivery of the ICTC projection and the procedures for disputing the projection. Some parties objected to the provision stating that a failure to protest in a timely manner is deemed an acceptance of the projection. We find the general framework of this section acceptable, but the procedure proposed by PG&E is confusing and cumbersome.
PG&E proposes that objecting customers would file a "Motion for Evaluation of Interim CTC Projection" in the electric restructuring proceeding. PG&E then states that a "failure to protest" constitutes acceptance of the ICTC projection. Referring to a customer's objection to PG&E's ICTC estimate as both a motion and a protest is confusing because the Commission's Rules of Practice and Procedure describe filings called "motions" and "protests" in very different ways. Under our Rules, a protest objects to an application (Rule 44); a motion requests the Commission or an ALJ to take specific action related to a proceeding (Rule 45(b)).
PG&E's proposed procedure is cumbersome because under our Rules a customer objecting to an estimate that affects only the customer would have to serve its objecting motion on a service list of several hundred parties. (Rule 45(d).)
A greater degree of informality will simplify this process. If a departing customer believes that PG&E's ICTC projection does not comply with the terms and conditions of the ICTC tariff and related decisions, it should notify PG&E in writing of the grounds for its belief within 20 days after receiving the projection. If PG&E does not accept the customer's position, it should respond in writing within 5 days after receiving the customer's notification. PG&E and the customer should then confer to attempt to resolve the differences. If necessary, the parties may also consult with members of our Energy Division to attempt to achieve resolution. If no resolution is reached within 10 days, the customer may then file the motion described in the draft tariff. PG&E and the customer may agree to extend this 10-day period to allow for further negotiations or other resolution techniques. PG&E should amend its tariff to reflect these provisions.
In D.96-04-054 we endorsed PG&E's proposal to require each departing customer to sign an agreement requiring payment of its share of transition costs and waiving jurisdictional objections to collection of those costs. (Id., slip op. at 9-10, 18-19 (Conclusion of Law 6).) PG&E attached an ICTC agreement to its proposed tariff. Section 4(D) of the tariff refers to this agreement.
Some parties objected to the provision of section 4(D) that states that whether a departing customer signs the ICTC agreement or not, the customer will be deemed to have agreed to the terms of the agreement by taking retail service on or after December 20, 1995. This provision echoes the language and intent of D.96-04-054 (slip op. at 10), and is consistent with the intent of AB 1890 that all customers (with defined exceptions) should bear their fair share of transition costs. (See §§ 369, 370.) We have no objection to its inclusion in the tariff.
Parties also objected to having to sign a contract with no termination date. The agreement attempts to delineate the term of the contract in section 1, but this description is necessarily vague, since some of the elements of restructuring, and thus the schedule of implementation, are under the control of other agencies. The customers might feel slightly more comfortable if the agreement states that it will terminate on January 1, 1998 (the date both the Legislature the Commission have set for implementation), subject to annual renewal by PG&E until the effective date of the Commission's final CTC order. PG&E should incorporate such a provision in the agreement.
Parties to the collaboration debated the appropriate interest rate that should apply to payment of refunds and collection of underpayments. Some parties argued that the interest rate should reflect the differences between the costs of capital for PG&E and for the customer; in general, this would mean that PG&E would pay a higher interest rate on refunds than the customer would pay on underpayments.
We conclude that the same interest rate should apply to refunds of overcollections and collection of underpayments. PG&E's tariff proposes to use the rate applied to energy balancing accounts, currently the three-month commercial paper rate. We agree that this is an appropriate rate to apply to refunds and underpayments.
CIU notes that some customers may be unable to make payment of unexpectedly large undercollections in a lump sum. We recognize that this may be a problem, and we direct PG&E to allow such customers a reasonable period to make the payments. Interest on any outstanding balance should accrue at the three-month commercial paper rate until the full sum is paid.
PG&E proposes to give departing customers the choice of calculating an average monthly bill based on the customer's usage over either 12 or 36 months preceding the notice of intent to depart. PG&E also proposes to adjust the ICTC projection to account for improvements in energy efficiency. As we have noted, this provision is consistent with § 371. Although PG&E did not offer its specific proposed tariff language until after the collaboration, we have reviewed these provisions and find them acceptable.
Several related issues arose concerning truing up individual customers' ICTC accounts and adjusting the ICTC. We find it helpful to limit the term "true-up" to the reconciliation of estimated or forecasted elements of the ICTC with the corresponding actual figures that become available either as time passes and the forecasts are supplanted by actual events or as we make our determinations in this and other proceedings. The primary purpose of the true-up is to revise individual customers' ICTC tracking accounts so a customer pays neither too much nor too little of its fair share of interim transition costs. By "adjustments to the ICTC," we mean modifications to the rate used to collect interim transition costs, which may be appropriate as new forecasts replace older ones.
Parties debated whether a true-up was necessary or desirable, whether certainty was more important than accuracy. Some parties argued that the ICTC should function only as a cap on interim transition cost collection, so that the only true-up would be refunds for overcollections.
We agree with the parties favoring a full, two-way true-up. All customers, including departing customers, should bear their fair share of transition costs, but no customer should pay more than its fair share.
Because we intend that the ICTC will be short-lived, true-ups of a customer's ICTC account (i.e., comparing forecasted with actual figures and making appropriate refunds to or additional collections from the customer) need only be made once, when the ICTC is replaced by the final CTC. Additional true-ups during the interim period create an administrative burden and serve no substantial good purpose.
By contrast, interim adjustments to the ICTC should be made as new forecasts are adopted. The actual ICTC customers pay should reflect the most current information available. Many of the components of the method for calculating ICTC we adopt today, such as Energy Cost Adjustment Clause (ECAC) revenues, are forecasted on an annual basis. Thus, it is convenient and appropriate to revise the ICTC as of January 1, 1997, to reflect our adopted forecasts for 1997 for appropriate components of the ICTC calculation. More frequent adjustments to the ICTC are not necessary.
Another type of interim adjustment may also be appropriate. Our proceedings on the final CTC might result in determinations that could affect the application of the ICTC. Thus, adjustments may be appropriate as and if we issue interim decisions on the final CTC.
In Investigation (I.) 89-07-004, we have been considering changes to the way we calculate SRAC. Section 390, however, requires the calculation of short-run avoided energy costs to be based on a specified formula. We will address the application of § 390 in a decision issued in I.89-07-004. The ICTC calculation should reflect any changes we adopt to the SRAC methodology. If adopted, the changes to the SRAC methodology should be incorporated into the January 1, 1997 interim adjustment to the ICTC discussed in the preceding section.
In D.96-04-054, we stated our intention that "all [ICTC] payments will be subject to adjustment when we adopt our final CTC." (Id., slip op. at 16.) As will become clear in our subsequent detailed discussion of our adopted approach to the ICTC, the comparison between the ICTC and the final CTC may not be as direct as we contemplated, and the adjustment of ICTC payments may not be as automatic as we had hoped. We affirm our intent to make such an adjustment, but the details of how to make this adjustment should be considered and decided as part of our determination of the final CTC. It will be much easier to figure out how to make this adjustment when the details of the final CTC are known.
How to calculate the ICTC projection was, not surprisingly, one of the most controversial issues of the collaboration. One of the fundamental disputes was whether the ICTC is intended to allow interim recovery of the elements of the final CTC or to recover during 1996 and 1997 the transition costs currently embedded in bundled rates. The latter interpretation is our intent. In D.96-04-054, we rejected PG&E's proposal to collect a lump-sum payment of a customer's total projected CTC in favor of monthly payments of the ICTC. We also clarified that it was appropriate for the ICTC to consist of the transition costs included in current bundled rates, and we justified ICTC collection in terms of the effects on remaining customers. (D.96-04-054, slip op. at 10-12.) Departing customers, like all other customers, will be subject to the final CTC when we adopt it, and the ICTC is intended merely to collect transition costs from departing customers on roughly the same basis as they are collected in bundled rates from remaining customers, until the final CTC is adopted. It is sufficient for purposes of the ICTC to collect an estimate of the transition costs included in current rates.
Praxair presented a detailed approach to identifying transition costs. It considered generation and certain types of contracts by category, and for each category decided whether the associated costs should be included in the ICTC, and, if so, whether the costs should be included as a credit or debit. For example, geothermal generation costs are included as a debit; fossil generation costs are excluded because Praxair believes that the sale of fossil units will eventually result in a credit to the calculation of final transition costs. The credits and debits are totaled and compared with a measure of the market price for power; the difference is divided by forecasted sales to arrive at the ICTC. Praxair's approach resulted in interim transition costs for 1996 of $1.3 billion.
ACWA provided an approach similar to Praxair's in its written proposal preceding the collaboration. However, ACWA stated that it would limit the ICTC to two cost components, the Diablo Canyon revenue requirements associated with net book value, and the fixed payments to QFs under the long-term standard offers. ACWA estimated that these two items resulted in 1997 transition costs of $3.75 billion.
PG&E took a very different approach. PG&E reasoned that a quick and easy-to-implement approach could be based on the revenue requirements associated with generation assets and contracts. The first step under this approach would be to add up the approved generation-related revenue requirements of four key components: the ECAC, the Annual Energy Rate (AER), the general rate case (GRC), and the Diablo Canyon plant. The resulting total would be reduced by an estimate of the market value of forecasted sales. The resulting estimate of transition costs for 1996 is $2.9 billion.
The contrasts between the different approaches are striking. Praxair's approach follows more closely the discussion of transition costs and the CTC of the Policy Decision. Because it assumes that the ICTC should be an interim estimate of the final CTC, however, it makes some questionable, and from its perspective hopeful, assumptions: It excludes the costs of fossil plants entirely because it assumes that the sale of these plants will completely offset any associated transition costs. It also eliminates the fixed costs of purchases from QFs on the erroneous assumption that those costs would not endure past 1998.
PG&E's approach, on the other hand, reflects the discussion of our Policy Decision only indirectly, if at all. Contrary to the determinations of the Policy Decision, it includes the variable costs of all generation on the theory that the utility's obligation to serve during the interim period will prevent it from shutting down plants that may have uneconomic variable costs. It ignores the possibility that the sale of generation plants during the interim period will reduce transition costs. It does, however, reflect the presence of economic as well as uneconomic generation plants. It also provides a reasonably accurate estimate of the transition costs associated with probably the two largest sources of transition costs: purchases from Diablo Canyon and from QFs.
For purposes of the ICTC, we conclude with some reservations that PG&E's is the superior approach. Although it does not attempt to replicate precisely the final transition costs, it provides a reasonably accurate estimate of the interim costs, the transition cost components of current rates. It has the great virtue of being easily implemented without further proceedings or comments. Although parties may differ over whether revenue requirements are an appropriate basis for calculating transition costs, the actual figures incorporated in PG&E's approach are derived, in an apparently uncontroversial manner, from numbers we have approved in our decisions in several cases. Although the resulting estimate of transition costs and the ICTC calculated from those costs may not be exact, our goal in attempting to develop an ICTC was not to achieve excessive precision but to arrive at a "necessarily somewhat rough" figure for interim purposes. (D.96-04-054, slip op. at 16.) PG&E's approach best accomplishes that goal.
Our reservation about PG&E's approach have to do with its inclusion, in both the ECAC and GRC components, of variable costs of generation. In the Policy Decision, we excluded the variable costs of fossil-fueled generation from the CTC except for units needed for voltage support. (Policy Decision, slip op. at 135.) We overcome this reservation to PG&E's approach on four grounds. First, we agree with the argument that during the interim period, PG&E retains its obligation to meet the power demands of its remaining customers and that meeting this obligation will require use of many of its generation resources. Second, it would be difficult during this transitional period and in this interim context to determine precisely which plants are not needed for voltage support and to segregate the variable costs of those plants. Third, if we are aware that PG&E's quantification of interim transition costs is somewhat overstated, we will be able to compensate to some degree for this overstatement in other components of the ICTC. Finally, including variable costs of generation in the interim transition cost quantification is consistent with our observation that we should strive for accuracy but err on the side of an ICTC that is "high enough to cover all transition costs embedded in current rates" (D.96-04-054, slip op. at 15).
In D.96-04-054, slip op. at 14, we suggested that "today's short-term energy wholesale market conditions, with projections limited to the next 20 months," should be the measure of the extent to which a generation resource or power purchase is uneconomic, and thus part of the ICTC. The parties offered some market price proxies that vary somewhat from the current wholesale market price standard that we suggested.
PG&E urges that a composite of available market indices would come closest to the wholesale market measure the Commission suggested. However, because of its approach to estimating costs and in the spirit of compromise, PG&E recommends using as a proxy the SRAC energy and as-delivered capacity prices approved by the Commission for payments to certain QFs. ACWA also recommends a SRAC proxy. PG&E would calculate the SRAC energy price based on the adopted gas price forecast for 1996 and 1997 and would exclude the operation and maintenance (O&M), geothermal, and cash working capital adders. Even with these exclusions, PG&E acknowledges that the SRAC proxy is likely to be higher than prices in the wholesale market, but believes that this overstatement of market prices fits well with its cost approach, which likely overstates interim transition costs. The advantages of the SRAC proxy are that its values are approved by the Commission, its calculation is open and public, and it has been in use for QF pricing purposes for several years. PG&E agreed that the gas price and as-delivered capacity price forecasts that are inputs to the SRAC proxy would be trued up to reflect actual prices posted in 1996 and 1997. PG&E calculates that the 1996 market price proxy would be 2.89¢ per kilowatt-hour (kWh) under this approach.
Praxair suggests using the Incremental Cost Incentive Pricing (ICIP) PG&E has proposed for its Diablo Canyon power plant in Application (A.) 96-03-054, its Diablo Canyon ratemaking proposal. Praxair suggests that this proxy best approximates the replacement of a large block of generation, and Praxair believes that the ICIP will simulate the market price, including recovery of fixed and variable costs, rather than just the system marginal price. The 1996 market price proxy resulting from this method is 3.46¢ per kWh.
SDG&E proposed using the marginal cost of fossil generation or the system marginal operating cost as a market price proxy. This proposal was not discussed in detail at the collaboration.
We conclude that the SRAC proxy, excluding O&M, geothermal, and cash working capital adders but including as-delivered capacity payments, would be the most transparent and acceptable approach to estimating market prices for purposes of calculating the ICTC.(7) The parties acknowledge that this proxy likely overstates market prices to some degree, but this overstatement has the virtue of compensating for the likely overstatement of interim transition costs in the approach we have adopted. The result will be an acceptable estimate of the net interim transition costs that form the basis for the ICTC. The resulting market price estimate should be revised as gas price forecasts for SRAC energy prices and as-delivered capacity prices for 1997 are adopted.(8)
Three approaches to allocating the ICTC to customer classes were discussed at the collaboration.
PG&E proposed to express the ICTC as a uniform systemwide percentage and to apply that percentage to a reference bill calculated for each departing customer. The percentage would be derived by dividing the net interim transition costs by total PG&E revenues. Using PG&E's assumptions and approaches to ICTC, the systemwide percentage is 39.2%.
Praxair's method focuses more on the cost responsibility of the different customer classes and of the major categories within those classes, such as the three voltage levels--transmission, primary distribution, and secondary distribution--and the firm or nonfirm service options of Schedules E-19 and E-20. Praxair believes that underlying PG&E's uniform systemwide percentage is the unrealistic assumption that all customers depart the system at the same time. An approach based on the departure of small blocks of load would be superior for purposes of allocating the ICTC. In addition, Praxair thinks PG&E's method fails to recognize that large customers' bills reflect relatively larger charges for distribution and transmission services; because Schedule E-19 and E-20 customers have high load factors, their cost-based rates have relatively lower energy and demand rates. Thus, Praxair argues that a uniform systemwide percentage will require departing large customers to pay more than their fair share of interim transition costs.
Praxair's method of allocating interim transmission costs develops an average cents-per-kWh charge for each customer class by applying the ratio of the class's percentage of total revenues to its percentage of total sales to modify the proportion of net interim transition costs to total system sales. Praxair thus calculates separate ICTCs for each customer class and for the different voltage levels and service options (firm v. nonfirm) for Schedule E-20.
ACWA developed a method that it believes accurately estimates the ICTC associated with the departure of a single customer. This method begins by multiplying the ratio of interim transition costs to total revenues by the average rate in cents per kWh that would apply to the departing customer. This "total ICTC responsibility" is reduced by the market price proxy to arrive at the ICTC for that customer.
By the end of the collaboration PG&E had agreed with Praxair that the ICTC should reflect the difference among customer classes, service voltages, and firmness of service. PG&E believes that its approach, which develops the ICTC as a percentage to be applied to the customer's reference (average) bill, provides that differentiation. Interruptible customers, for example, receive lower rates in exchange for their willingness to endure interruptions, and their reference bills and associated ICTC will be proportionately lower. With that clarification, the only difference between PG&E's and Praxair's approaches is that PG&E would apply its percentage to the customer's average monthly bill, while Praxair applies its allocation to the average rate for each customer class. Praxair argues that its approach will tie the ICTC more closely to the costs of generation and purchases, which it presumes to constitute the bulk of transition costs, so that large customers are not forced to bear an unfair share of interim transition costs. By expressing ICTC on a cents-per-kWh basis, however, it appears that Praxair's approach has the opposite effect: Large customers generally have flatter load shapes and pay relatively larger fixed rates and lower energy rates. If the ICTC is tied to energy consumption, these high load-factor customers would appear to bear more than their share under Praxair's approach.
PG&E has shown that its approach recognizes differences in customer classes, voltage levels, and firmness of service, and it appears to be fairer to large customers. Although it would be desirable to avoid applying the ICTC to transmission and distribution charges that are presumably not included in transition costs, that level of precision is beyond the modest goals of our effort to estimate the ICTC. Because large customers' average total rates are less than those of other customer classes, applying the allocation percentage to the average bill should produce less distortion than tying the ICTC to energy consumption. Because high load-factor customers by definition consume much of their total usage during off-peak hours at low time-of-use rates, the average total bill reflects the high load factors of these customers in a way that a pure cent-per-kWh charge does not.
More important, the rates established for large customers are near our equal percent of marginal cost (EPMC) goal. Applying a percentage to the average bill maintains the EPMC relationships among customer classes and among the bill's components; applying the allocation to the energy component only, as Praxair suggests, would lead to distortion of the cost relationships among bill components and among customer classes.
PG&E's approach is also extremely easy to calculate, administer, and understand. For all these reasons, we conclude that PG&E's approach to interim transition cost allocation should be adopted for purposes of the ICTC.
PG&E will maintain individual tracking accounts for customers subject to the ICTC. The accumulated revenues should be accounted for in an ICTC balancing account. The disposition of the funds remaining in this account after the true-up described above will be addressed in our proceeding on the final CTC.
IT IS ORDERED that within 10 days of the date of this decision, Pacific Gas and Electric Company shall revise its proposed "Amendment to the Electric Preliminary Statement--Interim Competition Transition Charge Procedure" and its proposed "Interim Competition Transition Charge Agreement" to comply with the determinations of this decision and submit them as an Advice Letter for approval.
This decision is effective today.
Dated November 26, 1996, at San Francisco, California.
P. GREGORY CONLON
President
DANIEL Wm. FESSLER
JESSIE J. KNIGHT, JR.
JOSIAH L. NEEPER
Commissioners
Commissioner Henry M. Duque, being
necessarily absent, did not participate.
We will file a joint concurring opinion.
/s/ JESSIE J. KNIGHT, JR.
Commissioner
/s/ JOSIAH L. NEEPER
Commissioner
(1) Comments were filed by the Association of California Water Agencies (ACWA); the California Farm Bureau Federation (Farm Bureau); the California Independent Petroleum Association; California Industrial Users (CIU), consisting of Air Liquide America Corporation, Air Products and Chemicals Corporation, Amoco Chemical Company, Anheuser-Busch Companies, BOC Gases, The Chevron Companies, General Motors Corporation, Nabisco, Inc., New United Motors Manufacturing, Inc., Owens-Corning Fiberglass Corporation, Praxair, Inc., and Steelcase, Inc.; the California Manufacturers Association; the Coalition of California Utility Employees; the Division of Ratepayer Advocates; the Energy Producers and Users Coalition (EPUC), consisting of Amoco Production Company, Amoco Energy Trading Corporation, ARCO Products Company, CalResources LLS, Chevron Corporation, Mobil Oil Corporation, Shell Martinez Refining Company, Texaco Inc., and Union Pacific Fuels Inc.; Foster Poultry Farms (Foster Farms); Merced Irrigation District (MID); PG&E; Praxair, Inc.; San Diego Gas & Electric Company; San Francisco Bay Area Rapid Transit District (BART); Sonoma County Water Agency (SWCA); Southern California Edison Company; Southern California Gas Company; Texas-Ohio West, Inc.; Toward Utility Rate Normalization; the United States Department of Energy's Oakland Operations Office; the University of California and the California State University, jointly (UC/CSU); and the Western Area Power Administration, Sierra Nevada Customer Service Region. In addition, Basic Compliance Engineering and Capital Energy Systems submitted letters commenting on the report.
(2) We emphasize that the determinations of this interim opinion are not precedential and do not in any way prejudge the issues raised in various applications for rehearing in this docket or the issues raised in our proceedings to develop a final CTC.
(3) AB 1890 added §§ 330-397 and §§ 840-847 to the PU Code. This decision will refer both to AB 1890 generally and to specific new sections of the PU Code. All section references are to the PU Code.
(4) Section 367(e) creates a "firewall" intended to ensure that the costs associated with CTC exemptions for customers in the residential and small commercial classes are borne only by other customers within those classes, and the costs of exemption for all other classes are recovered only from customers in those other classes.
(5) AB1890's exemptions are set forth in §§ 371, 372, and 374. Section 371 exempts various changes in usage resulting from, for example, business cycles, weather, equipment modifications, or efficiency improvements. Section 372 describes exemptions for cogeneration and self-generation and for bypass deferral agreements. Section 374 covers exemptions for irrigation districts, certain power authorities, and federal preference power purchases. Under § 373(b), only the exemptions provided in §§ 372 and 374 are required to be recognized in the ICTC.
(6) Over-the-fence cogeneration refers to the type of service described in § 218(b), which allows a cogenerator to sell to up to two customers located on property immediately adjacent to the cogenerator's location without becoming "electrical corporations" subject to this Commission's jurisdiction.
(7) The changes to the SRAC methodology required by § 390 and under consideration in I.89-07-004 could substantially alter the components of the SRAC. Even if it is substantially changed, the SRAC will provide a reasonable market proxy for purposes of the ICTC.
(8) These specific components may become irrelevant if the SRAC methodology is substantially changed in I.89-07-004. The January 1, 1997 revision to the market price proxy should adjust appropriate components of the SRAC methodology then in effect.