VIII. Comments on Alternate Proposed Decision
PG&E, Edison, SDG&E, ORA, Large Users, State Consumers, Weil, TURN, Farm Bureau, CalPX, APX, and ARM, filed timely comments on the proposed alternate decision. PG&E, ORA, Large Users, CEC, APX, and TURN, filed timely reply comments. The proposed alternate decision was revised and sent out for a second round of comments to all parties in the proceeding as well as the service list in R.94-04-031 et al. Comments were filed by Farm Bureau, Large Users, CEC, Enron, ORA, State Consumers, SDG&E, APX, PG&E, TURN, Cal PX, ARM, Weil, SCE and PG&E. Reply comments were filed by APX, ARM, WPTF, SDG&E, UCAN, Large Users, CEC, APX, ORA, PG&E, and TURN. We have incorporated comments that provided technical corrections and factual clarifications, as discussed throughout the decision. We have also incorporated comments discussing legal error and have further amplified our discussion regarding cost allocation and rate reduction bonds, but have not made substantive changes to the proposed alternate decision's recommendations in these areas.
1. It is premature to adopt a procurement PBR mechanism at this time because the new market structures are not sufficiently developed and because the Commission has not made determinations as to the role of the UDC in supplying default customers.
2. . We are not convinced that a procurement PBR mechanism avoids perverse incentives or properly aligns the UDCs' interests with customers' interests.
3. We do not intend to implement mechanisms that may have the perverse incentive of encouraging the UDC to retain customers by using unfair practices; e.g., using resources of the monopoly distribution company to retain customers for the procurement function.
4. With properly-designed incentive regulation, once the benchmark is established, little regulatory oversight is required because the interests of shareholders and ratepayers are properly aligned.
5. While a number of parties with divergent interests support the partial SDG&E settlement, a wide range of interests also opposes the settlement.
6. The market is not sufficiently developed to support the proposed settlement and we do not intend to prejudge any action that this Commission or the Legislature might take with regard to default providers or the role of the UDC.
7. When SDG&E's gas procurement PBR was adopted in 1993, gas procurement competition was well developed and several robust, exogenous benchmarks existed that parties agreed were reliable. In other words, gas basin competition was much more mature than the state of electric procurement competition is today.
8. Although the proposed settlement is characterized as an experiment, we are not convinced that this experiment will enable the Commission to determine its success when completed or that the experiment itself does not present unreasonable risks.
9. It is reasonable to require continued purchasing from the CalPX and related markets (including day-ahead, day-of, block forward, and the ISO imbalance energy markets) and to permit utilities to opt also to make purchases from any qualified exchange in order to better understand the impacts of the developing market after the rate freeze.
10. Once the market is more robust and as we consider our approach to the default provider issue and the role of the UDC, it may be beneficial to adopt procurement incentives. During that proceeding, we would recommend a collaborative approach with clearly articulated goals and objectives.
11. By continuing the mandatory buy requirement, we take steps to ensure that the market itself is more robust and competitive. We resolve concerns regarding reasonableness reviews by deeming as reasonable, the prices paid by the utilities for purchases from authorized wholesale markets, specifically the CalPX day-ahead, day-of, and block forward markets, other qualified exchange markets, and the ISO imbalance energy market.
12. The Commission should now let the mandatory buy requirement as to only the Cal PX expire because the justification for limiting purchases by UDCs to only the Cal PX has ended.
13. Adequate price transparency may exist outside the Cal PX.
14. The link of price transparency to mitigation of market power has weakened due to utility divestiture of generation.
15. Changes in the mandatory buy requirement should have no impact on our regulatory burden.
16. Opening up trading now to qualified exchanges will supercharge retail access and competition in generation and trading.
17. Market efficiency dictates an expansion of the mandatory buy requirement to other qualified exhanges.
18. Allowing use of qualified exchanges during the transition period will be a spur towards their more robust development by the end of the transition when the mandatory buy requirement expires completely.
19. The PPD currently permits use of exchange other than the Cal PX, as well as use of bilateral contracts, by entities other than UDCs.
20. Pre-approval of SDG&E's prescribed procurement guidelines at this time implies a sanction of reasonableness and tends to negate the concept of competition. Until we determine the role of the UDC in the post-transition period, we will not prescribe procurement practices other than to say qualified exchanges may now be utilized.
21. We reject PG&E's proposal that it is necessary to cap rates in order to protect residential and small commercial customers from potential price volatility and corresponding rate increases.
22. We did not initiate electric restructuring in order to shield consumers from the market. We agree with Weil and TURN that customers need accurate price signals in order to react and protect themselves against periodic price spikes.
23. Masking prices results in incomplete and inefficient market structure and system demand, and compromises system reliability. Only through accurate price signals can customers understand how their usage impacts the system and make economically efficient choices.
24. Until we determine the role of the UDC in the new market, it is premature to allow the UDC to offer new commodity products and services, other than those already authorized by prior decisions, or which are the subject of other proceedings before the Commission and are not limited or prohibited by this decision.
25. It is reasonable to allow the utilities to continue to offer balanced payment plans to their residential customers. Various programs are already in place to assist low-income customers with their energy bills; e.g., California Alternative Rates for Energy (CARE) provides a rate discount.
26. We will not expand the balanced payment plan program to streetlighting customers, because we prefer that the market develop a solution to this problem.
27. We will require that the UDCs continue to purchase power through the CalPX or any qualified exchange at least until the time when PG&E, Edison, and SDG&E have all ended the rate freeze. That is, the mandatory buy requirement will not end until the rate freeze has ended for all three of the utilities. It is expanded to permit purchases from any qualified exchange as defined herein. Advice letter filings by the UDCs, separately or jointly, should determine whether an exchange is qualified.
28. The presence of large energy purchasers, such as the UDCs, attracts generators and ESPs to the market serving to increase liquidity and depth. The mandatory buy requirement provides a more level playing field that maintains ESP confidence in the market. As more qualified exchanges enter the market, more innovation and ingenuity in procurement practices will emerge.
29. So long as any utility continues to collect stranded costs, all the utilities must continue to buy from the CalPX or any qualified exchange. The total withdrawal of purchases from the Cal PX by any one utility can compromise the market price, thus serving to jeopardize the integrity of the competition transition charge for the utilities that remain under a rate freeze. All three utilities must continue to purchase power from the Cal PX or a mixture of the Cal PX and any qualified exchange at least until the last utility has ceased collecting stranded costs.
30. Pursuant to D.99-10-057, three months prior to the anticipated date the rate freeze will end, or no later than September of 2001, PG&E and Edison must file advice letters informing the Commission and parties of the expected end of the rate freeze. These advice letter filings must include all necessary tariff language and preliminary statements using the four PX price forecast scenarios described in D.99-10-057.
31. In order to promote timely rate changes, we also required PG&E and Edison to file a supplement to this advice letter five days following the date upon which all the criteria for ending the rate freeze have been satisfied. The filing is to provide the actual rates to be implemented after the rate freeze and the ratemaking mechanisms authorized by D.99-10-057 and this order. Due to rate unbundling and the many ratemaking proceedings before the Commission, rates have and will continue to diverge from those in effect when rate were frozen on June 10, 1996. These advice letters will serve to notify parties and this Commission of the end of the rate freeze for PG&E and Edison.
32. At the end of the transition period, effective April 1, 2002, the mandatory buy requirement for UDCs should be eliminated.
33. A post-rate freeze continuation of allocating costs in a manner based on bundled rates is inconsistent with current ratemaking policies. It is inappropriate to continue the EPMC or SAPC methodology to allocate ongoing transition costs because those methodologies are derived from outdated bundled ratemaking methodologies.
34. Transition costs are most appropriately assigned to the generation function. Such a functionalization of costs is consistent with the Commission policy of rate unbundling and cost functionalization.
35. Neither the EPMC method nor the equal cents per kwh method of allocating transition costs fully take into account the way actual generation costs are incurred by class. The top 100 hours methodology appropriately allocates transition costs based on demand.
36. Restructuring implementation costs are costs resulting from the implementation of direct access, the PX, and the ISO. Treatment of these costs is addressed in Pub. Util. Code § 376.
37. In D.99-06-058, we determined that these costs should be allocated using a SAPC methodology during the rate freeze.
38. The restructuring implementation costs themselves are not recoverable after the rate freeze. Pursuant to § 376, the only costs recoverable are the transition costs that were displaced because of recovery of restructuring implementation costs. These costs should not be singled out from other transition costs for separate treatment, but instead should be allocated according to the same methodology as other ongoing transition costs. Therefore, transition costs displaced because of recovery of restructuring implementation costs should be allocated using the cents-per-kilowatt-hour methodology applied on a system-wide basis.
39. We previously considered nuclear decommissioning cost allocation in D.97-08-056, in which the Commission was constrained by the cost shifting provisions of AB 1890.
40. Consistent with our approach to transition cost allocation, nuclear decommissioning costs should be assigned to function. We agree with TURN's and UCAN's argument that nuclear decommissioning costs are most appropriately assigned to the generation function.
41. Once the rate freeze ends, nuclear decommissioning costs should be allocated using a cents-per-kilowatt-hour, usage-based methodology.
42. CARE costs should continue to be allocated on a cents-per-kilowatt-hour basis. For energy efficiency and other non-CARE public purpose programs, we agree that it is reasonable to continue SAPC cost allocation after the rate freeze.
43. New mechanisms must be established to ensure that the UDCs collect the authorized revenue requirement for public purpose programs. We approved the PG&E's PPPRAM and Edison's Public Purpose Program Adjustment Mechanism in D.99-10-057 on an interim basis. We affirm that approval here and establish that these accounts should be two-way balancing accounts. Further issues regarding funding for the period after 2001 should be determined in the public purpose rulemaking, R.98-07-037 or other proceedings, as appropriate.
44. Reliability Must Run (RMR) contracts ensure the ISO's ability to summon generators to provide reliability and system stability when the market fails to provide the necessary support. The RMR contracts are subject to FERC jurisdiction.
45. During the rate freeze period RMR costs are being recovered through the Commission established Transition Revenue Account (TRA). Once the rate freeze terminates the utilities will no longer have the TRA cost recovery mechanism and must seek authorization at the FERC to recover RMR costs
46. D.99-10-057 explicitly stated that FERC has jurisdiction of RMR costs. and defers to the FERC on all related matters. We will not relitigate these matters.
47. The utilities may continue to offer interruptible or curtailable service only until March 31, 2002 pursuant to Section 743.1.
48. Allocating costs related to rate limiters, costs of interruptible programs, and any rate discounts to transition cost recovery is improper and unlawful and misrepresents the costs, since transition costs are defined specifically in § 367.
49. The costs of interruptible discounts rate limiter adjustments, and the power factor adjustment should be included in the distribution rate component on the customer bill.
50. The RGTCOMA tracks transition costs obligations and payments by rate group. During the rate freeze EPMC or SAPC allocators for transition costs should be adjusted for changes in usage patterns pursuant to § 371.
51. The rate freeze must end for all customers at the same time notwithstanding the class transition cost obligations in the RGTCOMA. Rate groups that have not met their transition cost obligation cannot continue to pay these costs after the rate freeze, because such a carry over of costs into the post-rate freeze period is unlawful pursuant to §§ 367(a) and 368(a).
52. Once the rate freeze ends, any credit balances in TCBAfor each utility, including the difference for the amount of CTC revenues authorized for collection and the amount actually collected, mustbe refunded to customers. The funds will accrue interest at the 90-day commercial paper interest rate. The utilities must propose a method to return the over- collected amounts to ratepayers in the first ATCP following the end of the rate freeze.
53. Pursuant to § 841 et seq. and D.97-09-057, SDG&E issued $658 million in rate reduction bonds in December of 1997 in order to finance a 10% rate reduction for eligible customers over the anticipated four-and-a-half year rate freeze period. According to the terms outlined in the Financing Order, the bonds will be fully repaid by 2007 and a charge to repay the bonds appears on the residential and small commercial customer bill until that time.
54. D.97-09-057 requires that excess rate reduction bond revenues, resulting from bonds that were unnecessarily issued, be returned to ratepayers and stated that the excess revenues must bear interest at SDG&E's authorized rate of return.
55. SDG&E could have chosen a more risk adverse approach by issuing the bonds when required as the rate freeze progressed. Instead, SDG&E opted for the riskier approach of issuing all the rate reduction bonds at once understanding that if it issued too many, the excess bond revenue would bear interest at the company's authorized rate of return.
56. We do not agree that SDG&E's proposal for a reduced interest rate, which would result in reduced refunds to ratepayers, is fair or reasonable.
57. A shorter amortization period for excess rate reduction bond revenues would result in SDG&E customers receiving money earlier than a longer amortization period.
58. SDG&E should be held to the same level of accountability for its business decisions as any other entity that enters into an agreement. SDG&E should credit and/or refund to ratepayers the excess rate reduction bond proceeds, which bear an interest rate of SDG&E's authorized rate of return. The credit and/or refund should occur as soon as possible.
59. D.99-10-057 adopted a Purchased Electric Commodity Account (PECA) for Edison, SDG&E, and PG&E to track their purchased energy costs. PECA results in an energy rate that is designed to balance procurement costs and revenues in a given month. The purpose of the PECA account is to track the costs of purchased electricity, not the costs of operating power plants.
60. PG&E does not include a forecast of procurement costs in setting the PECA rate but instead charges a PECA rate based on the past month's costs. PG&E's PECA proposal does not contain enough detail for us to adopt it outright. Because we do not adopt a procurement PBR or rate capping, we need not include the other elements of PECA as proposed by PG&E.
61. The monthly PECA rate should be based on procurement costs incurred to serve customers to whom the rate is applied including a forecast of any procurement costs for which the utility has not received a final bill when the rate is developed, an amortization component to account for prior month over- or under-collections, and a trended sales forecast. The amortization component will allow for true up between actual and recorded costs and revenues. Revenues should be recorded to PECA less franchise fees and uncollectibles and under- or over-collections should earn interest at the short-term commercial paper rate as proposed by PG&E.
62. SDG&E's generation-related franchise fees should be unbundled from distribution rates and collected through the PECA account.
63. SDG&E's proposals to eliminate various accounts after the rate freeze should be adopted. SDG&E's ratemaking proposals, described in Exhibit 11, Chapter IV, that are consistent with this decision should be adopted.
64. When rates are frozen, customers have little incentive to adjust energy usage patterns and remain unmotivated to shift consumption to the low demand times when energy prices are lowest. This is because under the rate freeze customers will pay the same price for energy whether they consume during peak hours when prices are higher due to high demand, or if they consume in the off peak hours when prices are lowest. In addition, since customers are charged for the average energy cost those that have better than average load profiles in effect subsidize those that have worse than average load profiles.
65. It is reasonable to adopt the ORA and CEC proposal that all bundled customers with hourly interval meters be billed using hourly data once the rate freeze ends. This approach is consistent with our long-established policy of increasing customer price responsiveness, advancing market efficiency, and prompting lower energy prices.
66. We will not approve PG&E's proposal to allow customers with interval meters a one-time opportunity to remain on averaged prices once the transition period ends. Such an approach would be inconsistent with the objective of removing intra-class subsidies by having customers charged for the power they actually consume and would undermine our goal of increasing customer response to price signals.
67. In the post rate freeze era, PECA effectively replaces the PX credit approach as the way of setting energy rates. All elements adopted as part of the PX credit during the rate freeze should also be reflected in the post-rate freeze procurement rate. The costs booked to PECA and the resultant rate should reflect all costs adopted as part of the PX credit in the 1999 RAP for each utility. SDG&E should adjust its PECA tariffs accordingly.
68. The modified RAP will address forecast issues, as necessary and the modified ATCP will address reasonableness issues, including a review of procurement costs to the extent costs above the wholesale PX price or qualified exchange rate are included in the PECA.
1. It is not reasonable or prudent to adopt a procurement PBR mechanism at this time.
2. In light of the whole record, it is not reasonable or in the public interest to adopt the proposed SDG&E settlement regarding a procurement PBR mechanism at this time.
3. Pursuant to our authority over utility procurement of energy for retail load, it is for this Commission to decide when and under what conditions to terminate the mandatory buy requirement.
4. Stranded cost recovery was not the sole objective of establishing an industry-wide transition period. The four-year period is a time in which market evolution transpires, constituting a transition from a regulatory environment to one where competitive market forces determine prices. A fundamental component of that transition is the development of a transparent, reliable Power Exchange or other similarly qualified exchanges.
5. So long as any utility continues to collect stranded costs from its customers, it is the responsibility of the Commission to ensure the integrity of that charge. The best means of accomplishing the objective of protecting the integrity of the CTC charge is to continue but expand the mandatory buy requirement to other qualified exchanges.
6. It is premature to relieve the UDCs of the buy obligation before the end of the transition period considering the Commission's ongoing proceedings to investigate broad market structure and competition issues such as the role of the UDC, competition in retail markets, and comprehensive unbundling of retail costs from distribution rates. However, the mandatory buy requirement should be expanded to permit procurement now from any qualified exchange.
7. Until the market is more fully developed at the end of the transition period, totally removing the buy requirement now would distort the operation of the CalPX or any other qualified exchange.
8. A qualified exchange provides continuous trading in either a bid/ask or second price auction type market, equal nondiscriminatory access and a mechanism for timely, anonymous price transparency. Its market-clearing price algorithm or methodology must be publicly available and its prices for each type of market must be publish for such a market at least as frequently as the Cal PX now publishes. It must be subject to audit and record verification, have a compliance unit, and offer similar, unambiguous terms of trade.
9. A qualified exchange cannot be owned, all or in a part, by a California UDC or its affiliates.
10. UDCs must file advice letters detailing how an exchange meets our criteria if it seeks it to be qualified for utility purchases.
11. Advice letters should be processed expeditiously, within a 60-day period.
12. In the Preferred Policy Decision, the Commission has already ordered that the mandatory buy requirement will expire after March 31, 2002. We re-affirm our intent to lift the requirement as of this date. Post transition, until a mechanism for reasonableness review is in place, only prices deemed per se reasonable herein should be deemed reasonable, absent further Commission order.
13. Our actions regarding the Cal PX and other qualified exchanges and the mandatory by requirement are within the scope of this proceeding and do not contravene PU Code §1708.
14. Section 367 generally defines transition costs and establishes the time frame for recovery of uneconomic costs. Section 367(e)(1) requires that transition costs be allocated in substantially the same proportion as on June 10, 1996.
15.
16. After the rate freeze ends, the Commission retains its cost allocation authority, including its authority over allocation of ongoing transition costs, subject to the various provisions of §367(e).
17. It is reasonable for the Commission to use the top 100 hours methodology for allocation of transition costs after the end of the transition period.
18. The § 367(e) provision mandating that transition costs be allocated in substantially the same proportion as similar costs on June 10, 1996 is not in conflict with the § 371 provision mandating allocation adjustments for changes in class energy use patterns.
19. If we were to allow reconciliation of RGTCOMA balances post-rate freeze, this would constitute a carryover of transition costs into the post rate freeze period. Such a carryover of costs is unlawful pursuant to §§ 367(a) and 368(a). The RGTCOMA should be eliminated for each utility.
20. SDG&E understood and agreed to the terms and stated risks embodied in the Financing Order.
21. SB 418 clarifies that the Commission has the authority to address issues regarding excess bond revenues and order alternative treatment, if appropriate. However, SB 418 does not require the Commission to accept SDG&E's preferred solution for a lower interest rate.
22. Section 846.2 provides that the Commission may order a credit to ratepayers of excess rate reduction bond proceeds that is fair and reasonable. SDG&E's request for a lower interest rate than that established in the Financing Order, would not be fair or reasonable for ratepayers. However, it is reasonable that residential and small commercial customers benefit from an immediate bill credit, refund check, or both. This approach is consistent with the requirements of §846.2.
23. The Commission should adopt a shorter amortization period for excess rate reduction bond revenues for SDG&E customers. A shorter amortization period is a fair and reasonable resolution of this question.
24. The Legislature has called for certain rates and optional service to be in place for a specific amount of time; e.g., § 743.1(b) requires that optional interruptible or curtailable service continue at least until March 31, 2002 and that the level of the pricing incentive shall not be altered from the levels in effect on June 10, 1996 until March 31, 2002. This section also states that this Commission is to direct the utilities to continue efforts to reduce rates charged to industrial customers without shifting cost recovery to other customer classes.
25. While we prefer that the utilities not implement or extend rates or discounts that could be competitive, we cannot implement such objectives at this time. Instead, a full record should be developed for our consideration in both A.91-11-024 and A.00-01-009 for SDG&E and Edison, respectively. For PG&E, we expect that issues related to load retention and special rates will be brought forward for our consideration in A.99-03-014.
26. A fundamental objective of electric restructuring has been to increase the customer's ability to respond to market signals serving to foster greater market efficiency, the expectation being that greater efficiencies would serve to prompt lower overall market prices.
27. Consistent with the requirements of D.97-09-057, D.97-11-074, and D.00-02-048, it is reasonable to require Energy Division to conduct an audit of SDG&E's Rate Reduction Bond Memorandum Account and associated savings to ratepayers. We leave it to the assigned Commissioner and ALJ to set the schedule for this audit report.
28. Because the Commission is encouraged to close ratesetting proceedings within 18 months (SB 960, Stats. 1996 Ch. 856), it is reasonable to ensure that the issues addressed in the modified ATCP and RAP proceedings are discrete.
29. This order should be effective today, so that these requirements may be implemented expeditiously.
IT IS ORDERED that:
1. The motion for approval of the Settlement Agreement filed by San Diego Gas & Electric Company (SDG&E), the Office of Ratepayer Advocates, Utility Consumers Action Network, the California Power Exchange (CalPX), Duke Energy Trading and Marketing, L.L.C., Hafslund Energy Trading, LLC, and California Polar Power Brokers LLC on October 27, 1999 is denied.
2. Pacific Gas and Electric Company (PG&E), Southern California Edison Company (Edison), and SDG&E (UDCs) shall continue to procure electricity from the CalPX and related markets (including day-ahead, day-of, block forward, and the Independent System Operator (ISO) imbalance energy markets) or from any qualified exchange until all three utilities have ended their individual rate freeze periods. The UDCs shall not withdraw all purchasing from the Cal PX, but may use a mixture of purchases from it and any qualified exchange.
3. PG&E, Edison and SDG&E shall file an advice letter, separately or jointly, if they seek a determination that an exchange is qualified so as to allow purchases of its products. The exchange may comment on the filing.
4. At the end of the transition period, effective April 1, 2002, the mandatory buy requirement for UDCs shall be eliminated.
5. Pursuant to Decision (D.) 99-10-057, three months prior to the anticipated date the rate freeze will end, or no later than September of 2001, PG&E and Edison shall file advice letters informing the Commission and parties of the expected end of the rate freeze. These advice letter filings shall include all necessary tariff language and preliminary statements using the four Power Exchange price forecast scenarios described in the Phase 1 decision and in conformance with this decision. In order to promote timely rate changes, pursuant to D.99-10-057, PG&E and Edison shall file a supplement to this advice letter five days following the date upon which all the criteria for ending the rate freeze have been satisfied. In these supplemental filings, PG&E and Edison shall provide the actual rates to be implemented after the rate freeze and the ratemaking mechanisms authorized by D.99-10-057 and this order. These advice letters shall serve to notify parties and this Commission of the end of the rate freeze for PG&E and Edison.
6. PG&E, Edison, and SDG&E shall continue to offer balanced payment plans to their residential customers. We shall not adopt expanded balanced payment plans or other form of rate capping, nor shall we expand balanced payment plans to streetlighting customers.
7. The subject utilities shall file or update applications within 60 days of the effective date of this decision which update the top 100 hours methodology for 1998 and 1999 as discussed herein.
8. When the rate freeze ends, transition costs displaced because of recovery of restructuring implementation costs shall be allocated using the top 100 hours methodology applied on a system-wide basis.
9. When the rate freeze ends, nuclear decommissioning costs shall be allocated using a cents-per-kilowatt-hour, usage-based methodology.
10. Costs related to the California Alternative Rates for Energy (CARE) program shall continue to be allocated on a cents-per-kilowatt hour basis after the rate freeze.
11. After the rate freeze, costs related to energy efficiency public purpose programs (or non-CARE public purpose program costs) shall continue to be allocated according to System Average Percent Change (SAPC).
12. We affirm the establishment of the Public Purpose Program Revenue Adjustment Mechanism for PG&E and the Public Purpose Program Adjustment Mechanism for Edison. These accounts shall be two-way balancing accounts.
13. Costs related to rate limiters, costs of interruptible programs, and any rate discounts shall not be recovered as transition costs.
14. The costs of power-factor adjustments, interruptible discounts and rate limiter adjustments shall be included in the distribution rate component on the customer bill.
15. The rate freeze shall end for all customers at the same time notwithstanding the class transition cost obligations in the Rate Group Transition Cost Obligation Memorandum Accounts (RGTCOMA). During the rate freeze EPMC or SAPC allocators for transition costs shall be adjusted for changes in usage patterns pursuant to § 371. The RGTCOMA shall be eliminated for each utility.
16. Once the rate freeze ends, any credit balances in the Transition Cost Balancing Account (TCBA) for each utility, including the difference for the amount of competition transition charge (CTC) revenues authorized for collection and the amount actually collected, shall be refunded to customers. The funds will accrue interest at the 90-day commercial paper interest rate. The utilities shall propose a method to return the over collected CTC to ratepayers in the first Annual Transition Cost Proceeding (ATCP) following the end of the rate freeze.
17. SDG&E shall refund to ratepayers the excess rate reduction bond proceeds which bear an interest rate of SDG&E's authorized rate of return. SDG&E shall refund and/or credit on applicable customer's bills in the next feasible billing cycle for the appropriate amount to reflect the unrealized savings resulting from excess rate reduction bond proceeds, as discussed herein.
18. The monthly Purchased Electric Commodity Account (PECA) rate shall be based on procurement costs incurred to serve customers to whom the rate applies, including a forecast of any procurement costs for which the utility has not received a final bill which the rate is developed for the given month, an amortization component to account for prior month over- or under-collections, and a trended sales forecast. The amortization component will allow for true up between actual and recorded costs and revenues. Revenues shall be recorded to PECA less franchise fees and uncollectibles and under- or over-collections shall earn interest at the short-term commercial paper rate as proposed by PG&E. In the post rate freeze era, PECA effectively replaces the PX credit approach as the way of setting energy rates. All elements adopted as part of the PX credit during the rate freeze shall also be reflected in the post-rate freeze procurement rate. The costs booked to PECA and the resultant rate shall reflect all costs adopted as part of the PX credit in the Application (A.) 99-09-022 et al., the 1999 Revenue Adjustment Proceeding (RAP) for each utility. The utilities shall adjust their respective PECA tariffs accordingly after the 1999 RAP decision is issued.
19. All bundled customers with hourly interval meters shall be billed using hourly data once the rate freeze ends.
20. We adopt a modified RAP and a modified ATCP, as described herein. These proceedings shall be filed according to the timelines established for the 1999 RAP and ATCP proceedings.
21. Because SDG&E has ended its rate freeze, SDG&E shall file an advice letter to implement the provisions of this decision, within 15 days of the effective date of this decision, to be effective when Energy Division determines SDG&E is in compliance.
22. A.99-01-016, A.99-01-019, A.99-01-034, and A.99-02-029 are closed.
This order is effective today.
Dated June 8, 2000, at San Francisco, California.
HENRY M. DUQUE
JOSIAH L. NEEPER
RICHARD A. BILAS
Commissioners
We will file a written dissent.
/s/ CARL W. WOOD
Commissioner
/s/ LORETTA M. LYNCH
President
Commissioners Wood and Lynch's joint dissent will be appended when available.
