III. Procurement Issues

Much of the debate in these proceedings has focused on the energy procurement practices of the utility distribution companies (UDCs) for their bundled (or full service) customers after the rate freeze ends or the transition period is over.⁴ The UDCs must supply kilowatt-hours (kWh) to their full service customers and must also obtain ancillary services and replacement reserves for the load associated with these customers.⁵

Until the utilities collect their uneconomic transition costs and the rate freeze ends, as it has for SDG&E, rates are fixed at the June 10, 1996 levels. As explained above, these frozen rates, along with a residual component of rates specifically delineated as the Competition Transition Charge (CTC), allow the utilities to accrue the revenues to collect transition costs.

We must determine whether to establish an incentive mechanism to apply to the procurement of the wholesale commodity, to continue to require the UDCs to purchase the commodity through the CalPX, to prescribe specific purchasing guidelines, or to establish reasonableness reviews. The goal of each of these approaches is to ensure that service for bundled customers is provided at reasonable rates. PG&E and SDG&E propose that an electric procurement PBR mechanism be instituted. Several other parties believe that such an incentive mechanism is premature and that the utilities should be required to continue to purchase power from the CalPX or that other specific purchasing guidelines be established.

On October 29, SDG&E, ORA, UCAN, CalPX, Duke Energy Trading and Marketing, LLC, Hafslund Energy Trading, LLC (Hafslund), and California Polar Power brokers, LLC (CALPOL)⁶ (collectively, settling parties) requested that the Commission adopt a settlement agreement that would resolve or otherwise dispose of all issues raised in connection with SDG&E's electric procurement PBR. We will review this settlement under the settlement rules provided in Rule 51 et seq.⁷ These rules provide that any settlement must be found reasonable in light of the whole record, consistent with the law, and in the public interest.

A. Procurement Proposals

1. PG&E

PG&E presents two alternatives for our consideration. PG&E proposes that the Commission should either adopt a prescribed procurement practice, which would require PG&E to procure electricity and ancillary services for bundled customers through a specific mix of purchases in defined markets, or the Commission should adopt an Electric Procurement Incentive Mechanism (EPIM). Either of these alternatives is acceptable to PG&E and would avoid the need for reasonableness reviews.

PG&E states that it is not feasible to obtain 100% of its metered load in the PX day-ahead market. For example, from May 1998 through April 1999, PG&E purchased approximately 10% of its monthly energy needs from the real-time market. Instead, PG&E maintains that a Commission-prescribed procurement practice is acceptable and must allow for sufficient flexibility so that PG&E can adjust to variations in market conditions. The defined markets for purchases would include the PX day-ahead, day-of, and block forward market, the Independent System Operator (ISO) imbalance energy market (also known as the real-time market), and could include the APX. PG&E states that the advantages to this approach include providing a transparent benchmark for ESPs, allowing the pre-established markets more time to become more efficient and robust, minimizing the incentive to take undue risks in the procurement market, and reducing regulatory oversight and review. PG&E categorically rejects the use of traditional reasonableness reviews in assessing procurement practices.

ORA contends that the procurement from the day-ahead market and any resulting charges set by the ISO markets for imbalance energy, ancillary services, unaccounted-for energy, and other costs is an example of a conservative approach that would not require detailed review. ORA would consider costs over a period of time that were above the day-ahead PX price to be a possible indication that a utility has engaged in imprudent or risky procurement practices. Alternatively, ORA would accept PG&E's proposal of procurement guidelines and states that PG&E's identification of the day-ahead PX price plus 2% as being equivalent to and simpler than ORA's offer to deem the PX price for forecasted load plus pass-through of ISO settlement costs as a benchmark for reasonableness. ORA believes that there are too many problems in the evolving marketplace to accept PG&E's alternative proposal for a procurement incentive mechanism.

PG&E proposes that the EPIM would be based on an annual market benchmark, an asymmetric deadband, and 50/50 sharing of savings or costs outside of the deadband between ratepayers and shareholders.

The annual benchmark would consist essentially of all possible costs that PG&E would incur were it to continue to procure the commodity through the PX. As proposed by PG&E, the costs included in the benchmark consist of 1) settlement quality metered load data of bundled customers multiplied by final PX day-ahead zonal market clearing prices, 2) all ISO costs allocated to the PX or to other scheduling coordinators used by PG&E, 3) PX and ISO administrative and other charges allocated to PG&E, and avoided PX and ISO charges that would have been allocated to PG&E had PG&E continued to use the PX exclusively as its scheduling coordinator. The actual costs incurred by PG&E on an annual basis for energy purchases through various markets plus the costs of ancillary services, real-time costs, and other charges by the ISO to the PX and to other scheduling coordinators used by PG&E would then be compared to the benchmark. While PG&E supports using the day-ahead PX market in its benchmark, it would not object to the use of a simple benchmark based on a volume-weighted average of defined markets.

PG&E contends that an asymmetric deadband of three percent above the benchmark is required to account for forecasting errors. As an alternative, PG&E states that the forecasting error can be addressed by adding two percent to the day-ahead market benchmark. PG&E maintains that either of these adjustments are necessary to ensure that, over time, there will be zero gains and losses through the operation of the EPIM. Without such an adjustment, PG&E states that it would lose approximately $10 - $15 million per year, with a risk of losses exceeding $50 million per year. PG&E has proposed various complicated accounting mechanisms to track the shared savings or losses.

PG&E maintains that the EPIM has several benefits, including aligning shareholder and ratepayer interests and encouraging PG&E to continue buying from markets included in the benchmark, which allows these markets to become more efficient and robust. In addition, PG&E states that it provides PG&E with the opportunity to compete for wholesale supplies to lower bundled service costs if bilateral purchases are allowed as part of the PBR and reduces regulatory oversight costs.

2. SDG&E

SDG&E proposes a two-part PBR mechanism. Part A addresses SDG&E's procurement of electricity. Part B addresses SDG&E's administration of existing long-term contracts. SDG&E contends that an electric commodity incentive mechanism is consistent with the intent expressed in the Preferred Policy Decision (D.95-12-063, as modified by D.96-01-009):

Utilities will continue to procure power for those customers who choose not to arrange retail contracts with suppliers and will continue to provide nondiscriminatory distribution services to all customers within their service territories. These procurement and distribution functions of the utilities will remain under our regulation and be subject to incentive regulation. (Id., p. 26.)

Like PG&E, SDG&E maintains that an incentive mechanism is appropriate in order to align the interests of both shareholders and customers, to provide for more efficient utility operations, and to decrease regulatory burdens. SDG&E proposes a volume-weighted multi-part benchmark and equal sharing of gains and losses between customers and shareholders, i.e., 50% to customers, 50% to shareholders.

As proposed, Part A of the Electric PBR would establish a monthly benchmark for electric procurement for bundled customers. SDG&E, at its sole discretion, would purchase energy from any of the PX energy markets, from the ISO's imbalance energy market, or from other parties. SDG&E's purchases to serve metered load would then be compared to the monthly benchmark. If SDG&E's costs were lower than the benchmark, savings would be shared between customers and shareholders. Similarly, if costs were greater than the benchmark, the additional costs would be shared between customers and shareholders. In response to concerns expressed by several parties, SDG&E has modified its proposed energy benchmark to consist of a volume-weighted average of the PX day-ahead market, the PX hour-ahead market, and the imbalance energy market.

SDG&E will continue to obtain ancillary services and replacement reserves for the load associated with its bundled customers. Under the electric PBR proposal, SDG&E would charge customers the final day-ahead and hour-ahead market clearing price for those services, as determined by the ISO, times the respective quantities of the day-ahead and hour-ahead service that the ISO allocates to SDG&E to meet reliability criteria. This ISO-determined charge becomes part of the Part A benchmark. SDG&E contends that since the ISO's market price for ancillary services are objectively determined and because the quantity is determined by the ISO, these charges must be per se reasonable. The costs for ancillary services, on average, are approximately 12% of total energy costs. Under the proposed PBR mechanism, if SDG&E obtains ancillary services at a lower cost than the costs SDG&E would have otherwise paid to the ISO, the savings would be shared with customers. Similarly, if SDG&E were to obtain these services at a higher cost than it would otherwise pay to the ISO, the costs would also be shared with customers.

SDG&E contends that this PBR mechanism delivers several benefits. It provides incentives for SDG&E to serve bundled customers at the lowest possible price and avoids reasonableness reviews. The mechanism is transparent because it is designed around a benchmark that is public and determined by market bidding for load and supply, and it is simple because it is based on reported meter data and public market prices. SDG&E expects that most purchases would be made through the PX, as long as the PX is "efficient and competitive" (SDG&E Opening Brief, p. 9), but would consider any market transaction designed to reduce its costs. Examples of these transactions include purchases or sales in the PX day-ahead or day-of market; energy or ancillary services purchases or sales in the ISO's markets; bilateral purchase or sales from third parties; purchases of incremental transmission to access economic power; and the purchase of Firm Transmission Rights to mitigate the cost of transmission congestion.

SDG&E's Part B of its proposed electric PBR is designed to obtain savings under its existing long-term purchased power contracts by negotiating contract modifications to lower total costs. SDG&E explains that its performance would be measured by comparing the above-market costs to purchase energy and capacity under the contracts as they currently exist with the actual above-market costs incurred under the renegotiated contracts. Savings or costs would be shared between customers and shareholders on a 50/50 basis and would be applied to ongoing transition costs.

SDG&E administers approximately 80 contracts with qualifying facilities (QF), under which it pays the QF for capacity and energy at authorized prices as specified in each contract. SDG&E also purchases energy and capacity from Portland General Electric (PGE) and Public Service of New Mexico (PNM) under long-term arrangements approved by the Commission. SDG&E contends that this incentive mechanism would not apply to the contract restructurings or buyouts contemplated in the Preferred Policy Decision or § 367. SDG&E maintains that this incentive mechanism is required to allow it to capitalize upon short-term opportunities for pricing modifications without relying on the need for Commission approval.

B. Summary of Parties' Positions

Edison recommends that any decision the Commission adopts regarding procurement incentive mechanisms be limited to the parties proposing such a mechanism. Edison intends to provide specific proposals on energy procurement for bundled customers in its rate design filing.⁸ Edison contends that it is essential that UDC flexibility in procurement practices be maintained, but insists that retrospective reasonableness reviews must be avoided.

While parties recognize that there is concern about protecting full service customers with respect to the reasonableness of commodity procurement, a wide range of parties oppose establishing a procurement PBR. For example, TURN, CEC, FEA, State Consumers, Large Users, ARM, WPTF, Farm Bureau, Commonwealth, and New Energy oppose a procurement PBR. Generally, these parties believe that it is premature to establish such a mechanism, since the role of the UDC and default provider issues have yet to be determined.

In particular, ARM, FEA, and Farm Bureau point out that allowing the UDC to become more invested in procurement for bundled customers will make it more difficult to define the role of the UDC and could restrict the Commission's options in the staff study ordered by D.99-10-065. ARM believes that the Commission must determine whether a utility should be a competitor to the ESPs or merely a default supplier before a procurement PBR can or should be implemented. State Consumers and Large Users maintain that the UDC's role is that of a distribution company and that commodity procurement for bundled customers should simply be a pass-through of commodity costs. While ORA believes it is premature to devise utility-specific procurement PBR mechanisms, ORA also maintains the Commission should adopt the settlement regarding SDG&E's proposed mechanism, as described below, with certain restrictions and limitations, in order to allow the Commission to gather empirical data about the efficacy of such a mechanism.

Parties representing both competitors and large users state that a procurement PBR mechanism is antithetical to a competitive market. ORA is also concerned that incentive mechanisms may conflict with the development and maturation of competition in procurement. FEA, ARM, and WPTF acknowledge that functions that remain under monopolies have been subject to a PBR mechanism and that substituting incentives for competition is a stated goal for PBRs. These parties contend, however, that it is not appropriate to substitute regulatory mechanisms for competition in the areas of the marketplace where the Commission hopes to foster competition.

Several parties believe that retail competition will not become vibrant or robust if the UDCs are permitted additional procurement activities. Allowing the UDCs to profit from procurement would provide an incentive to retain customers and place the UDCs in direct competition with the ESPs. Parties representing large users and competitors point out that this result would be harmful to the development of direct access and to meaningful competition. In general, parties contend that the UDCs still have market power and this would frustrate competition.

While TURN, ARM, and CMA recognize that PBR mechanisms have been successfully applied to gas procurement, this did not occur until the restructured gas market had been in place for several years. The UDC did not dominate the gas market to the extent it does the electric market and the maturity of the gas market when incentives were put in place far exceeded the current state of the nascent electric market. Furthermore, ARM and WPTF contend that the PBR would provide an incentive to "game" the market in that the UDC would attempt to maximize returns by purchasing large volumes and buying power in excess of bundled customers' needs. The UDC would then attempt to sell the excess power for a profit, but if it cannot do so, the ratepayers would simply assume 50% of the costs.

Several parties are concerned about the design of the proposed PBR mechanisms. TURN, Weil, CEC, FEA, State Consumers, and Large Users contend that a PBR mechanism can only be effective if the benchmark is exogenous from the actions of the entity against which performance is being evaluated. Unless the UDC has no ability to influence the benchmark, there is no incentive for the UDC to obtain lower prices for power. TURN, for example, does not accept that a UDC, even one of SDG&E's size, cannot influence the market. While SDG&E contends that it does not exercise market power and that its total participation in the market is a small fraction of the total market transactions, TURN argues that actual PX supply and demand data demonstrate that a shift of only 250 megawatts (MW) of load could impact the PX clearing price by over 30%. TURN points out that SDG&E may serve as much as 3,200 MW of default customer demand and could shift approximately 500 MW of that demand between the day-ahead and real-time markets.

ORA supports a settlement approach for SDG&E's procurement PBR, but recommends that PG&E and Edison's procurement costs be subject to a comparison of the costs that would result from reasonable, conservative procurement practices that would not be subject to detailed later review. ORA recommends that the utilities' costs should be compared to scheduling of their day-ahead forecast of bundled service customers' load in the PX day-ahead market and acceptance of any resulting charges by the ISO for imbalance energy, ancillary services, unaccounted for energy, and other costs. Over time, costs greater than the day-ahead market could be viewed as an indication that the utility has procured power imprudently and these costs could be determined to be unreasonable. The State Consumers agree that conservative, simplified pre-approved commodity procurement practices are appropriate and that the utilities should avoid incurring any additional risks beyond these conservative purchasing practices. On the whole, State Consumers agree with PG&E's alternative approach and support the development of commodity procurement guidelines.

Nearly all parties agree that reasonableness reviews are not appropriate. ARM and WPTF disagree with the concept of pre-approved procurement practices unless the Commission has first analyzed and determined the role of utilities in the post-rate freeze market. If the UDCs simply supply their bundled customers with power and do not compete with ESPs, ARM agrees that pre-approved procurement practices are appropriate. However, if utilities are allowed to compete with ESPs for customers then ARM contends that the UDCs must be exposed to exactly the same risks as their competitors.

ARM also maintains that commodity PBR mechanisms will create a perverse incentive to limit load curtailments. UDC-managed load curtailment is instituted to maintain reliability and ARM believes that an expected outcome of these programs will be to reduce prevailing prices in the PX. However, when commodity PBR benchmarks are based, even in part, on PX prices, the implementation of load curtailment would then reduce the benchmark price. A lower benchmark means that it is less likely that the UDC will earn a profit. To the extent that an UDC has discretion in implementing such load curtailments, utility behavior may be influenced by this impact.

C. SDG&E Proposed Settlement

After submission of testimony by all parties, SDG&E began informal settlement discussions regarding a procurement PBR mechanism. A settlement conference was held on September 27, 1999. The parties to the settlement are SDG&E, ORA, UCAN, CalPX, Duke, Hafslund, and CalPol. The settling parties propose this experimental procurement PBR because of SDG&E's relatively small market share and load characteristics and to provide information for future procurement proposals. In addition, unlike the other UDCs, SDG&E has already ended its rate freeze.

The proposed settlement recommends that SDG&E be authorized to purchase up to 20% of the annual electric commodity requirements of its full service customers through bilateral contracts, derivatives, or other transactions outside of the CalPX and ISO imbalance energy markets. At least 80% of its full service requirements would be purchased through the CalPX and ISO through 2004. The settling parties propose a 36-month term for the experimental procurement PBR.

The proposed mechanism measures SDG&E's performance in two markets: the energy market and the ancillary service capacity market. In each market, a benchmark price is established which is then multiplied by an energy consumption or demand measure to arrive at projected cost for that benchmark. The cost estimate is then compared to SDG&E's actual cost in each market for purposes of sharing gains and losses. Gains and losses are subject to progressive sharing of gains and losses, except within the first range, a deadband where all losses are assigned to ratepayers.

The settling parties represent that the proposed procurement PBR promotes development of the direct access market by additionally limiting the provision for purchases outside the CalPX to the percentage of sales in SDG&E's service area that are served by ESP's, , minus generation resources for which SDG&E can affect dispatch, and extending this provision beyond a 20% direct access market share by allowing an additional 10% of SDG&E's purchases to be arranged as contracts for differences, which would be scheduled through the CalPX. Its evaluation, monitoring, and reporting plan provides for the public posting of certain performance results, and provides details of SDG&E's bilateral trades outside the CalPX to the Commission, the CalPX's and ISO's market surveillance organizations, and certain consumer advocates (ORA, TURN, and UCAN). The settlement also includes an interim procurement cost adder to SDG&E's PX charge (pending final resolution in the Revenue Adjustment Proceeding). The settling parties believe that the proposed PBR settlement increases public information about SDG&E's forecasted system conditions and promotes the development of price responsiveness by SDG&E's bundled service customers. The settlement also includes a midterm review, which allows the Commission to modify or terminate the PBR..

PG&E, Edison, CEC, TURN, State Consumers, CIU, FEA, Farm Bureau, ARM, WPTF, CUE, APX, Williams Energy Marketing and Trading Company (Williams), Reliant Energy Power Generation, Inc. (Reliant), and Dynegy, Inc. filed comments on the proposed settlement. The settling parties, CEC, State Consumers, ARM, and APX filed reply comments. ⁹

CUE, Williams and Reliant support the proposed settlement. Edison wants to be sure that the settlement, if adopted, is not construed as precedential for Edison. PG&E opposes the settlement insofar as it can be construed as preventing PG&E from having its own procurement incentive mechanism during the three-year experiment; if this is not the case, PG&E supports the adoption of a procurement PBR for SDG&E.

All other parties oppose the settlement on policy grounds. Similar to their comments on SDG&E's original proposed PBR mechanism, these parties believe that as long as the UDCs are in the position of providing procurement service to bundled service customers, the customers should not be put at risk for potential losses generated from market participation outside this Commission's approved commodity exchanges. In addition, these parties generally believe that even adopting the proposed settlement as an experiment or pilot program would not be productive. Such an experiment would not yield information relevant to other utilities, since, according to these parties, SDG&E's geographic situation is unique with regard to transmission constraints and access to imported energy. Therefore, it is not clear how an analysis of SDG&E's actions under a procurement PBR mechanism can be extrapolated to apply to or provide information on the actions of PG&E and Edison.

State Consumers recommend that if Sempra, SDG&E's parent company wishes to undertake such activities, it should do so through an unregulated affiliate. State Consumers also point out that in D.99-07-018, we considered a similar request in Edison's application for a pilot program for reselling bilateral forward purchases to the CalPX and the ISO. Similar to the pilot program that was rejected in that decision, State Consumers believe that the SDG&E pilot contemplates the UDC engaging in procurement practices that expose ratepayers to financial risks beyond those that would be experienced through current practices.

FEA opposes the proposed settlement and reminds us that one purpose of electric restructuring is to move away from an administrative or regulatory structure to one driven by competitive market forces. Thus, FEA maintains, that the way to do this is to ensure that competitive forces work by taking steps to strengthen the direct access market, such as removing market barriers customers face in signing up with direct access suppliers and ensuring market power abuses are monitored and reported. FEA also contends that there are several problems with the benchmarks for both the energy prices and ancillary service capacity. While FEA agrees that the three-part weighted average benchmark for energy prices is better than the single benchmark originally proposed by SDG&E, FEA argues that the proposed benchmark does not include all relevant energy products or state what the optimal weighting of purchases would be.

TURN, ARM, WPTF, and the CEC argue that it is inappropriate to implement a procurement PBR before the Commission has determined the role of the UDCs in the post-transition market. ARM states that such a PBR could provide SDG&E with an incentive to compete with ESPs, to retain customers, to compromise price transparence, and to manipulate the PX market. ARM argues that shareholder profits are directly tied to the volume of the utility's throughput, which in turn causes the utility to be motivated to actively engage in customer retention efforts. ARM also argues that a procurement PBR does not provide protection for small customers. Because it would stifle competition, the consumer would ultimately be the loser, due to inhibited innovation, and squelched price competition, as well as the need for increased regulatory oversight. Without price transparency, competition cannot flourish, contends ARM, and a utility with a procurement PBR mechanism has every incentive to compromise price transparency, because this could result in greater customer retention, which would lead to increased procurement requirements and the potential for greater PBR profits for its shareholders.

Farm Bureau and the CEC contend that the proposed settlement is premature. CEC also maintains that including ancillary services in the PBR mechanism make it much more complex. Like FEA, the CEC is concerned that the settlement includes an imprecise definition of the ancillary services benchmark. CEC points out that the ancillary services market is much more complex than energy markets and point out that SDG&E could have the opportunity to attempt to manipulate rules for ISO market participants and the ISO Rational Buyer program. The CEC also argues that the prospects for sustained gains by SDG&E for procurement outside of the CalPX is low and that the design of the PBR is stacked against the interests of ratepayers. WPTF agrees that ratepayer benefits will be minimal and that the mechanism will reward SDG&E for engaging in customer retention efforts and using its market power to compete with ESPs.

TURN is also concerned about potential problems with affiliate transactions, particularly because the PBR mechanism would not provide for reasonableness reviews. TURN describes the following scenario: if SDG&E purchased energy from an affiliate at a higher price than the PX, the sharing mechanism would require some portion of that excess payment to be borne by SDG&E's shareholders. However, because the amount borne by shareholders is less than 100%, Sempra as a whole could profit from affiliate sales to SDG&E in spite of the incentives provided to the UDC by the PBR mechanism. TURN argues that these transactions could be complex and difficult to monitor and that even a conventional reasonableness review may not provide adequate consumer protection. TURN is also concerned that there is no quantitative analysis of how the PBR will work in practice.

APX also opposes the proposed settlement, albeit from a very different perspective. APX argues that the Commission should reject the settlement unless we also remove the restrictions imposed on SDG&E's right to trade outside of the CalPX. APX contends that the buy-sell mandate must end with the end of the transition period, which it argues, ends for a particular utility when that utility ends its rate freeze. APX maintains that by continuing the bulk of its trades with CalPX through 2004, the settlement violates the Preferred Policy Decision. APX also believes that the settlement contradicts the Preferred Policy Decision because these restrictions do not acknowledge the role of direct access. Like FEA, APX contends that effective competition from direct access will control the UDC's procurement practices and eliminate the need for trading restrictions.

Dynegy agrees that the settlement should be rejected because it extends the mandatory buy-sell obligation past the period contemplated in electric restructuring legislation. Because SDG&E has collected its transition costs, Dynegy believes SDG&E should immediately be allowed to enter into bilateral contracts. Dynegy also recommends that other indices should be included in benchmarking analyses, although it is amenable to using the PX price for a limited period. Dynegy recommends that the CalPX should be one of many available markets and that the structure of the PX is not truly reflective of open markets. Dynegy argues that mandatory purchasing through the PX also carries with it the requirement to pay the CalPX administrative fee of $.31 per MWh, a fee that would be added to a customer's bill, but that could be negotiated through the bilateral contracting process.

Williams and Reliant believe that retail customers will benefit from SDG&E's ability to make limited purchases outside the CalPX market and that SDG&E's circumstances justify this experiment. Williams also argues that a PBR benchmark is inappropriate and should not be established. While Reliant recognizes that the Commission has yet to rule on the role of the UDC, Reliant does not believe approval of the settlement prejudges the issue. Like APX, Reliant and Williams recommend that the Commission allow for the possibility of gradually increasing the 20% limitation, should we determine that such an increase would assist in the development of a robust market. Reliant also recommends that the Commission retain the ability to modify or terminate the settlement's requirement that the buy mandate extend through 2004. Williams recommends that the buy requirement be eliminated or, at a minimum, not extended beyond March 31, 2002.

D. Mandatory Buy-Sell Requirement and the Transition Period

PG&E, Edison, SDG&E, Weil, and APX contend that the transition period ends simultaneously with the end of each utility's rate freeze period. ARM, WPTF, FEA, State Consumers, Large Users, TURN, and CalPX maintain that these periods are not synonymous. These parties contend the transition period was created not solely for the purposes of stranded generation cost recovery, but also to ensure the evolution of transparent markets with enough depth to allow for meaningful competition. In other words, these parties argue that the CalPX and the ISO must mature sufficiently in order to give the nascent retail direct access market an opportunity to develop robust competition. While these parties recognize that Assembly Bill (AB) 1890 reduced the period contemplated in the Preferred Policy Decision for recovery of stranded costs from five years to four years, they do not agree that the transition period applies only to stranded asset recovery.

The State Consumers, in particular, point to the fact that the ISO and the CalPX are changing institutions, evolving in efforts to enhance price signals, improve efficiencies, and to bring new products to the wholesale market. ARM argues that the buy-sell requirement should only cease after the Commission has promulgated its principles for analyzing competition in retail markets, established measures for the mitigation of market power, and comprehensively unbundled the costs associated with retail electric service from distribution rates.

CalPX strongly advocates that the mandatory buy-sell requirement continue for a defined period of time to ensure that the CalPX has adequate depth and liquidity to foster development of a competitive market. CalPX states that these are critical attributes of a robust, competitive market with reliable price signals. Thus, it is simply premature to end this requirement, regardless of whether one or more utilities have achieved an end to the rate freeze.

Despite the fact that the utilities have divested a substantial amount of their generation assets, State Consumers, TURN, ARM, and WPTF contend that PG&E, Edison, and SDG&E will continue to operate as the largest purchasers in procuring the retail commodity in the wholesale market and, as such, will continue to maintain their monopsony power. Thus, these parties recommend that a mandatory buy element is required, while recognizing that FERC has somewhat relaxed its requirement regarding the mandatory sell element for SDG&E. ¹⁰

State Consumers, CalPX, ARM, and other parties are convinced that this authority does not reach any requirement this Commission may impose as to the retail services the utility provides to its full service customers. These parties also submit that FERC's concern focuses on potential market power in the wholesale generation sector, rather than any market power held by the largest purchases in defined retail areas. Thus, these parties contend that it is within our jurisdiction to assert our consumer protection powers to define those commodity purchase practices applicable to utility commodity service for full service customers. ORA agrees that the mandatory buy-sell requirement should continue for at least the five-year term established in FERC's December 18, 1996 decision (77 FERC ¶ 61,265 at 62,088 (1996)), but contends that it is premature to determine whether the buy-sell requirement should continue beyond this time.

E. Rate Volatility, Rate Capping, and Balanced Payment Plan

Recognizing that there is a strong possibility for volatility in energy prices once the rate freeze has ended, PG&E proposes price caps and argues that expansion of its current bill smoothing program should not be expanded to non-residential customers. Edison and SDG&E make no proposals to mitigate price volatility. With the exception of CAL-SLA, all parties oppose price caps, claiming that such devices will dilute market prices and distort market signals. However, several parties support balanced payment plans (BPPs) to mitigate high prices. They contend that BPPs will allow for customer education about energy prices and increase usage pattern consciousness. Other parties argue that bill smoothing services, such as BPPs, should be confined to ESPs and should not be offered by UDCs. In many respects, the arguments surrounding rate capping are highly correlated to parties' positions on the proper role of the UDC in procurement. To the extent that parties recommend a limited UDC role in procurement or only a "plain vanilla" offering, they generally oppose the UDC's ability to cap rates.

The parties differentiate between rate capping and rate leveling (e.g., BPPs). Under a rate-capping plan, as proposed by PG&E, commodity prices would be capped once prices reach a given level to insulate customers from high prices during times of high demand. The current month's charge is limited to the capped rate with recovery of the amount above the cap collected in the following month. The customer pays interest on the amount deferred to subsequent months and a balancing account is proposed for revenue tracking.

Specifically, PG&E proposes to implement a capping mechanism for default customers with loads under 500 kW to insulate them from high commodity prices. The cap will be triggered when commodity prices over the most recent 30 days are 150% higher than the average PX price over the previous 12-month period. As proposed by PG&E, the capping mechanism is mandatory for all default customers. PG&E proposes rate capping for one year. Ratemaking would occur through the Deferred Procurement Revenue Account (DPRA), which would be established to facilitate treatment of the capping revenues.

Under a balanced payment plan, a customer incurs its actual commodity cost obligation each month but the utility allows the payment to be spread over subsequent months with a true up at year end. Under the BPP, the customer is conscious of energy prices and can act to adjust usage patterns. The primary distinction between rate capping and a BPP is the information a customer receives about prices. The utilities already have BPPs in place for residential customers. PG&E states that 10% of residential customers opt for BPPs.

SDG&E instituted a temporary three-month rate cap at the end of its rate freeze as part of its interim settlement adopted in D.99-06-051. The rate cap has since expired. As part of its interim settlement, SDG&E agreed not to seek a similar rate cap for the summer of 2000; however, it believes that BPPs should continue to be an option for full service customers.

CAL-SLA not only supports rate capping, it also specifically recommends extending the BPP to streetlighting customers. CAL-SLA argues that city governments require balanced payments to mitigate price volatility due to budgetary issues and the fact that cities and local governments cannot adjust the usage patterns for streetlights to respond to fluctuating energy prices. CAL-SLA finds PG&E's argument that it cannot extend the BPP to streetlighting customers because of computer system problems to be unpersuasive given that it can offer it to residential customers and has continued to promote BPP to residential customers. In addition, CAL-SLA points out that both SDG&E and SCE have either offered or have proposed to offer this rate option to streetlighting customers.

While supporting the concept of rate capping, CAL-SLA does not support PG&E's proposed rate cap because it would not sufficiently dampen price volatility since it would not trigger until the 30-day average price exceeds the 12-month rolling average by 150%. CAL-SLA believes that the specifics of rate capping approaches should be litigated in each utility's rate design case but that this proceeding should establish a policy that rate caps should be implemented for small customers of each utility after its rate freeze ends. Farm Bureau also recommends that rate capping and levelized pay plans should be explored in each utility's rate design proceeding in order to better assess the costs and overall rate design impacts.

ORA states that it is open to considering rate capping options as each utility's rate freeze ends, but it would not establish a policy on rate capping in this proceeding. Instead, ORA recommends continued use of existing BPPs as a mechanism to limit volatility.

In direct testimony, the FEA acknowledges that price caps will dilute commodity prices and mute market signals. However, it believes that caps can be allowed as a voluntary competitive option.

State Consumers believe that UDCs should be confined to distribution services and that a vibrant market will not emerge if the UDC continue to undertake additional commodity activities. State Consumers argue that:

"Development of new commodity rate structures, such as capped rates, would dilute the price signal reflected in the hourly value of energy discovered in the exchanges, and would require the UDC to carry costs in excess of the capped charge until later recovered from customers. However our opposition to capped commodity rates does not translate into an opposition for levelized payment plans where the customer incurs an obligation for the current-month commodity costs." (Opening Brief, p. 5.)

TURN supports retention and expansion of balanced payment options but opposes commodity price caps as proposed by PG&E. TURN points out that customers will still pay for higher rates under a rate cap but instead will have price signals dampened, further encouraging inefficient usage patterns. TURN suggests that rather than promoting rate caps, UDCs should instead spend their time developing programs that will allow consumers to see and respond to price signals.

UCAN argues that bill-smoothing activities, including BPPs, are outside of the UDC's core distribution services. UCAN argues that only if the market fails to provide this service should the Commission allow UDCs to provide it.¹¹ UCAN notes that even the CAL-SLA concedes that ESPs are providing bill smoothing products to customers, negating the need for UDC to increase non-distribution services.

Weil opposes mandatory rate caps without further study by PG&E. On cross-examination, Weil established that PG&E conducted no study or analysis of customer preferences for capped commodity costs. Weil does not oppose optional programs designed by utilities to meet identified customer needs for stable prices. In addition, Weil disputes Cal-SLA's assertion that it is unfair and discriminatory not to extend time of use pricing to streetlighting customers.

The CEC opposes all measures that would reduce price responsiveness by masking prices and argues that all customers should be exposed to market prices to induce price responsiveness, which serve to create more effective markets. The CEC makes one exception for low income customers, which it believes should be allowed BPPs and recommends that subsidies to low income customers should be applied after customers have been exposed to prices to allow for price realization. The CEC maintains that UDCs should not be allowed to offer competitive services, especially since the overall question of the role of the UDC has yet to be determined. In addition, the CEC points out that mechanisms to smooth prices could result in higher prices as customers pay interest on the amount deferred to subsequent billing periods. Commonwealth supports the CEC's position on rate capping.

In response, PG&E argues that the Commission should not rely on ESPs to offer bill smoothing products. In addition, PG&E notes that although the CEC opposes all price diluting measures, it does acknowledge the need for bill smoothing for low income customers. PG&E reiterates its argument that expansion of the BPP to non-residential customers will be costly and cumbersome.

F. Discussion

We find that it is premature to adopt a procurement PBR mechanism, either for PG&E or for SDG&E, until the role of the UDC in procurement is determined by this Commission. We declare that the mandatory buy requirement should no longer be confined to just the CalPX, but should be extended to any qualified exchange during the transition period. Permitting use of qualified exchanges other than the CalPX may be beneficial for development of an exogenous benchmark for use in consideration of possible future PBR mechanisms. In addition, we determine that consumers must be aware of the price signals provided by the market. We therefore reject PG&E's rate capping proposals. We agree with TURN that balanced payment plans, which each utility already has in place, offer a bill smoothing effect for residential customers and still allow these customers to be exposed to price signals. We also find that the UDCs may not extend these payment plans to street lighting customers or expand these options in any way until we make a determination as to the role of the utility in the new regime. We are confident that the market will evolve to develop various services and options that will further enhance competition, while dampening price volatility. We discuss each of these determinations below.

We also believe it is important to reiterate our intentions now for the end of the transition period so markets and competition can evolve accordingly. We reaffirm our decision in D.95-12-063 that post transition, we will remove any and all mandatory buy requirements. Post transition, if UDCs have a procurement role, they may procure energy however and wherever the best price for ratepayers may be obtained. We defer the mechanism for ensuring ratepayers do receive the best price to our anticipated proceeding for determination of the procurement role of the UDCs or other proceedings, as appropriate.

1. Procurement Practices

We recognize that during the rate freeze period, the utilities have had incentives to minimize the cost of procurement for bundled customers. This is true because of the headroom concept and the residual calculation of the CTC, discussed above. Any procurement practices that unnecessarily increase the energy charge to customers will necessarily decrease the amount of headroom available, and thus, the amount of revenues available to apply to transition cost recovery. Because CTC revenues will no longer be calculated or collected on a residual basis, this incentive will end when the rate freeze ends.¹² Several approaches to ensure just and reasonable rates have been proposed to maintain incentives for the utilities to continue to make economical purchases on behalf of bundled customers: 1) adopt procurement PBR mechanisms, 2) prescribe procurement guidelines, 3) maintain the mandatory buy requirement, and 4) undertake ex post reasonableness reviews.¹³

We are not convinced that it is either reasonable or prudent to adopt a procurement PBR mechanism now before we have determined whether the utilities will continue to have a procurement role. Although a PBR model may provide incentives for the UDC to reduce procurement costs, we are not yet convinced that it avoids perverse incentives or properly aligns the UDCs' interests with customers' interests. Furthermore, we have not ruled as a Commission on the role of the UDC in supplying default customers. We will not 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. We recognize that such practices may well be difficult to prove and that regulatory oversight of a procurement PBR mechanism could be fraught with difficulties. As the CEC explains, the theory of a valid PBR rests on the identification of an appropriate benchmark that cannot be manipulated. With properly-designed incentive regulation, once an exogenous benchmark is established, little regulatory oversight is required because the interests of shareholders and ratepayers are properly aligned. That is not yet the case here. Despite the contentions of the settling parties as to the various affiliate transaction rules this Commission has implemented, it may be difficult for the Commission and other parties to monitor all the transactions that may take place outside of any FERC-regulated exchanges.¹⁴ Thus, it is necessary to adopt standards for qualified exchanges before proceeding to consider any PBR mechanism.

Furthermore, we are not persuaded that it is reasonable or in the public interest to adopt the settlement at this time. We agree with SDG&E that we should not be swayed because of the number of opposing parties. However, we do not agree that the diversity of opinions regarding the settlement necessarily reflects "an intrinsic fairness and balance of result." (Joint Reply Comments on Settlement, p. 7.) We cannot ignore the fact that a wide range of interests oppose the settlement and do not believe that this purported middle ground approach is in the public interest at this time. Again, we believe that the market is not sufficiently developed to support this approach.¹⁵ Furthermore, 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. We also decline to implement an administrative mechanism that could have a chilling effect on competition.

We acknowledge UCAN's concern that the competitive market is not fully developed for small customers. UCAN believes that SDG&E needs to have the proper incentives to purchase electric service for its bundled customers for the short-term, but recognizes that this may not be necessary in the long-term. We do not wish to adopt short-term fixes now that may or may not provide proper incentives to SDG&E. In addition, we decline to fix an end-point of 2004 for maintaining 80% of SDG&E's procurement through the CalPX. Instead, as noted infra, the end point is much sooner than 2004.

When SDG&E's gas procurement PBR was adopted in 1993 (D.93-06-092, 50 CPUC 2d, 185), it was adopted as an experiment and was developed through a collaborative approach. We note that at this point in gas basin deregulation, 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. Furthermore, we are not sure that this experiment will enable the Commission to determine its success when completed or that the experiment itself does not present unreasonable risks. Instead, as Farm Bureau recommends, 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) to better understand the impacts of this approach. But we are also convinced that other viable exchanges now exist or are forming that can be equally as reliable as the CalPX, could provide lower costs to be passed through to bundled customers, and assist in establishing an exogenous benchmark. In making such a statement we are not criticizing the CalPX, but are instead recognizing fundamental economic theory.

As asserted by Weil, the Commission should now let the buy requirement expire because the justification for it has ended.¹⁶ As Weil observes, the Commission's fundamental goals for the buy requirement were price transparency, mitigation of market power, and reduction of the regulatory burden of CTC reasonableness revenues. Weil posits correctly that, four years after the PPD, "real California markets now feature adequate price transparency outside the CalPX." (Testimony of Weil, Exh. 65 at 2.) He points to NYMEX data for monthly on-peak power blocks, Dow Jones data for daily firm and nonfirm, on-peak and off-peak prices and volumes, data collection and publication by Pricewaterhouse Coopers, California Energy Makrets, Reuters, Bloomberg, Megawatt Daily, Power Markets Week, and Energy Market Report, and the ability of partcipants in the APX to have immediate access to prices and volumes of anonymous, real-time tranactions made through the APX.¹⁷ We concur with Weil's assessment that, as the Commission anticipated in the PPD, market participants have developed means of gaining access to pricing information and are able to compare the advantages and disadvantages of reliance on the CalPX.¹⁸

We agree with SDG&E that unless volumes were to drop precipitously, less volume in the CalPX would not correlate to less transparent price discovery. As he opines, price transparency has much more to do with the similarity of the underlying terms of trade and publishing of the prices at which trades take place. (Testimony of Sakarias, Exh. 38 at 3.) We concur with his assessment of the CalPX's argument that its thin hour-ahead market and other existing limitations require us to continue to support its experimental market: "The real question is whether there is a market for these services. If they are not needed, they should be allowed to die. We should not be putting PX services on a heart-lung machine if the market is saying, it is time to pull the plug." (Id. at 15.) We also find, as asserted by the CEC's witness Jaske, that the continuance of the buy mandate is a factor that prevents the APX getting the liquidity it needs to permit anonymous publication of market clearing prices. (Tr. at 1754-55.) We also concur with the CEC's assessment that measures of depth and liquidity should be applied to the entire market, not its individual players, like the CalPX on APX. Thus we reject CalPX's argument that opening up the mandatory buy requirement to other qualified exchanges will endanger the liquidity and depth of its markets. Price transparency has nothing to do with deep or liquid markets. It has to do with timely public disclosure.

We also agree with Weil that the CalPX price information's value is declining over time. The UDCs are divesting generation to those exempt from the mandatory buy requirement. As he notes, as the CalPX market share declines, market participants will naturally look elsewhere for price and volume data. Therefore, we conclude that the need for price transparency no longer requires that the CalPX be the sole qualified exchange for purposes of the mandatory buy requirement.

We concur with Weil's assessment that our link of price transparency to mitigation of market power has weakened due to utility divestiture of generation. We note that FERC has not expressed concerns regarding buy side market power. Instead, market power concerns have shifted to the new competitive generation owners which are not subject to the mandatory buy requirement. Therefore, the market power mitigation underpining of the CalPX monopoly for purposes of the mandatory buy requirement has eroded.

In addition, we agree with Weil's assessment that changes in the mandatory buy requirement should have no impact on our regulatory burden. As he notes, even with the mandatory buy linked to the CalPX, utilities still have choices to make among different services offered by the CalPX in the day-ahead, hour-ahead and various BFMs and in the ISO imbalance energy markets. Many of these markets were not envisioned within the scope of the PPD's creation of the CalPX and ISO, but have since evolved based on market forces and demand.¹⁹ Indeed, the CalPX BFM is not bilateralized like the day-ahead auction set forth in the PPD. For this reason, we reject CalPX arguments that its matching of supply to demand is a requisite for any California clearinghouse. The Commission is already faced with multiple markets and there is no reason regulatory mechanisms cannot evolve to allow for them. We are convinced the regulatory burden will not be increased by embracing similar markets provided by qualified exchanges. We also concur with Weil's comments that allowing utility purchases through qualified exhanges will lower prices through transaction cost competition, thus accelerating recovery of stranded costs. Thus, we are convinced that the compelling reasons for creation of the CalPX as the sole qualified exchange for purposes of the mandatory buy requirement have been mooted by time and market forces.

We concur with ARM's assessment that there is plenty of competition in today's market and that opening up trading "will supercharge retail access, it will supercharge competition generation, and most importantly it will supercharge competition in trading, which is now being stifled by the current mandate." (Tr. Cazelet at 1343.)

Finally, we find one of the arguments made by the CalPX to rationalize entrenching its current monopoly to instead provide a compelling rationale for breaking it. The CalPX contends that the market needs time to mature so that the CalPX day-ahead, hour-ahead and ISO real-time markets will be quite close in price. It notes that if they differ by more than a small amount, buyers and sellers will shift their trades between these markets until the price gap closes. The CalPX notes that such arbitrage is an essential part of any efficient market structure. It urges us not to impede the movement of trades between these markets so as not to interfere with market efficiency. (Testimony of Kritikson, Exh. 75 at 9.) Yet, by perpetuating the monopoly of the CalPX, we would impede market efficiencies achieved through arbitrage among several qualified exchanges.²⁰ The result would be lower prices for bundled customers set through arbitrage in a variety of markets rather than one artificial set of prices arrived at through circumscribed arbitrage in one market. Thus, market efficiency dictates an expansion of the mandatory buy requirement to other qualified exchanges.

Therefore, we believe that during the remainder of the transition period, the UDCs may procure energy through any qualified exchange. It would be disingenuous to reject rate capping proposals to protect consumers from market forces (see III.F.2. infra) yet protect our regulatory creation, the CalPX, from those same market forces. Once the market is more robust and we have articulated our approach to the default provider issue and the role of the UDC, it may be beneficial to adopt procurement incentives if UDCs continue to have a procurement role. If so, we would recommend a collaborative approach with clearly articulated goals and objectives.

We agree with CUE that a reasonableness review of procurement practices would be a regulatory nightmare. However, we are not convinced that, as currently proposed, the procurement PBR mechanisms are any more attractive. By expanding the mandatory buy requirement to any qualified exchange, we resolve these concerns by also deeming the wholesale price of any qualified exchange reasonable.²² Thus, we find that the UDCs may procure electicity through the CalPX day-ahead, day of and block forward markets and similar markets in qualified exhanges, and the ISO imbalance energy market, and deem the prices paid for these products as reasonable.

We also believe that we should no longer delay reiterating our stance on the mandatory buy requirement post transition period as set forth in the PPD. While we do not intend to prejudge our §390 proceedings or our upcoming consideration of the role of the UDC post transition, market participants need certainty now in order to plan for and achieve robust competition post transition. Once we issue our decision on the role of the UDC, if further modification of today's decision is necessary to protect ratepayer interests, we can sua sponte make such modifications. Waiting until close to the end of the transition period to start a review of our post transition course is too much regulatory lag in the midst of faster moving, evolving competitive market entrants. We must remove barriers to their entry as soon as possible.

In the PPD this Commission set a course toward competition. The purpose of the transition period was to allow markets to evolve so we arrived at that destination by the end of March 2002. Stating now how we intend to deal with the mandatory buy requirement as of April 1, 2002 will further spur competitive market solutions in order for them to be in place by that time. We concur with Weil that in the PPD the Commission has already ordered that the mandatory buy requirement will expire March 31, 2002.

At the time of the PPD we did not envision the advent of such organizations as the APX or NYMEX so quickly.²³ Their creation is evidence that market solutions can evolve to improve on regulatory ones. We wish to foster such market-based creations. Allowing use of qualified exchanges during the transition period will be a spur towards their more robust development by the end of the transition. The PPD permits present use of options other than the CalPX, as well as the use of bilateral contracts, by entities other than the UDCs. Now is the time to declare we are leveling the playing field for all market players post transition and that we meant what we said in the PPD.

In the PPD's Ordering Paragraph 5, we declared that, "At the end of the transition period, when determination of assets which qualify for recovery under the competition transition change has been finalized, the utilities shall be released from any mandatory requirement to bid into or purchase from the Power Exchange." (D.95-12-063 at 219-220 (emphasis added).) We again affirmed our intent to lift the buy requirement effective March 31, 2002 in D.99-07-018. In rejecting Edison's application for a pilot program pre-rate freeze termination for purchases outside the CalPX, we declared "The Preferred Policy Decision allows for the types of purchases Edison describes, but only after the transition period concludes." (Id. at 8.)

While we commend the CalPX on its development of new products, such as its variety of forward markets, we are convinced that allowing competitors and potential competitors to the CalPX to develop further beneficial solutions based on a full range of competitive needs is in the best interest of ratepayers. Direct access customers already have the benefit of using any other exchange. Expanding options for bundled customers now will better set the stage for post transition. Post transition, competitive exchanges and prudent use of bilaterals should place further downward pressure on CalPX prices. It may also produce more innovative products which will create increased levels of demand responsiveness to foster the health of wholesale markets. Once we have determined the role of the UDC, we can then examine the state of development of competitive exchanges and may choose to reconsider whether there is a need for procurement PBRs and/or bands of deemed reasonableness for procurement mixes.

We need to ensure that there is no regulatory gap at the end of the transition period. Elsewhere in this decision we speak to the reasonableness of purchases from PX, qualified exchange and ISO markets. However, at the conclusion of the transition period, we will also allow purchases from beyond these markets. Yet, there may not be a new oversight mechanism (e.g., PBR) in place on April 1, 2002 when the post transition period begins. Until such a new mechanism is in place, only those prices which are deemed per se reasonable herein should continue to be deemed reasonable in the post transition period, absent further Commission order.

In summary, we find that effective immediately at the end of the transition period, the mandatory buy requirement for the UDCs must be eliminated. Full and robust competitive market forces should produce the best rates for all classes of customers.

a) The Scope of the Proceeding as to Procurement Practices

We believe that our actions today regarding the PX and the mandatory buy requirement are within the scope of this proceeding and do not contravene PU Code § 1708.²⁴ As noted in the March 11, 1999 Scoping Memo and Ruling of Assigned Commissioner (ACR) among the ratemaking issues within the scope of this proceeding were whether utilities should utilize "balancing accounts for power cost recovery, whether other regulatory mechanisms provide better incentives, and whether the Commission should conduct reasonableness revenues of utility power purchases." (ACR mimeo. at 2.) The ACR also concluded that "the Commission must determine how the generation rate will be established . . .and the conditions under which the rate will change." (Id. at 3.) The ACR also declared that "The scope of this proceeding will include broad rate design policy and rate design matters which are integral to ending the rate freeze and the development of post transition ratemaking." (Id. at 4.) The ACR declared that the Commission did not anticipate that these applications would explore the wide range of market structure issues, such as the role of the utilities, prospects for their self-dealing and utility monopsony power. However, the ACR stated that "The parties may, however, justify or oppose a proposal on the basis that it would compromise or promote competitive goals as long as the proposal is otherwise within the scope of the proceeding." (Id.) Many parties did so. Indeed, the ALJ requested that parties comment in their opening briefs on "the buy/sell requirement and the interaction with the transition period..." (Tr. Minkin at 1866)

Taken all together, we believe that a proposal to open up the mandatory buy requirement, before the end of the transition period, to other qualified exchanges is a matter integral to the ending of the rate freeze and the development of our post-transition ratemaking. More data from more exchanges will assist the Commission in making its final determination of post-transition rates under the cost allocation methodology set forth later in this decision. The APX in its testimony and briefs in this proceeding has advocated that breaking the PX trading monopoly will promote Commission competitive goals, which falls squarely within the parameters of the ACR. The APX articulated a preference for totally eliminating the mandatory buy requirement or at least to have qualified markets for trading. (Tr. Cazelet at 1343.) The APX testimony also links to our examination of the generation rate and the conditions under which it will change as delineated in the ACR.²⁵ The APX has also advocated for an end of the mandatory buy requirement for SDG&E effective upon the end of its rate freeze. Weil and WPTF have advocated for letting the mandatory buy requirement expire. The UDCs and Weil concur that the rate freeze's end signals the end of a UDC's transition period. We also observe Dynegy recommended that the CalPX be only one of many available markets post rate freeze and argued that the structure of the PX does not reflect open markets truly. In supporting the SDG&E settlement, Williams and Reliant posited that retail customers will benefit from purchases outside the CalPX. Finally, the APX rebuttal testimony is squarely on point with our conclusion that linking the buy requirement only to the PX creates market inefficiencies and stifles innovation and was not extant at the time of the PPD. Therefore, we conclude that in today's order we are acting within the scope of this proceeding as perceived by the parties regarding the CalPX and the mandatory-buy requirement.

We also find that our further expansion of the PPD's mandatory-buy requirement to qualified exchanges does not violate PU Code § 1708. We are acting within the scope of the ACR and have given further notice to the parties by publishing this order two times for comments, the second time sending it to the entire electric restructuring service list in R.94-04-031/I.94-04-032. We have reviewed all comments and reply comments and find no assertions that require us to hold a hearing on this policy matter.²⁶ "[C]hanges in regulatory policy are hardly shocking, they occur with two-week regularity as the Commission issues decisions that continue to mold, apply, and implement the changes affecting the electric industry." Re. San Diego Gas & Electric Co. 68 CPUC2d 434, 448 (1996). (Changing QF policy issues in light of electricity deregulation.) The Commission has observed that, "We are permitted to refine our thinking between one decision and the next." In Re Pacific Telesis Group, 59 CPUC2d 54, 56 (1995) (revising 18% interest rate in 1993 decision to 3.4% interest rate in 1995 decision). We agree that "We clearly have the discretion to change our views after the passage of several years, during which additional proceedings have taken place...." (Id. at 57.) As noted supra, in 1995, when we issued D.95-12-063 (64 CPUC2d 1), no entity similar to the CalPX existed. Therefore, we had to create it. Thereafter, the APX was founded in 1996 and other entities followed, spurred by the opportunities arising from competitive markets. In the interim, we have authorized UDC purchases from various CalPX block forward markets and the ISO imbalance market, none of which were envisioned by the PPD. Therefore, 5½ years later, we continue to refine our thinking regarding the CalPX's monopoly regarding the mandatory-buy requirement and conclude it is appropriate in this proceeding to expand the requirement if other qualified exchanges exist.

2. Rate Capping

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. PG&E believes that these customers expect rate decreases at the end of the rate freeze and that such an unexpected increase could result in "major regulatory and political problems for regulators and the regulated alike." (PG&E Opening Brief, p. 13.)

Although PG&E is worried about possible political ramifications, 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. We are persuaded that 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. The price of electricity fluctuates; thus far, consumers have not been impacted by these fluctuations. Consumers should have the opportunity to respond to such market signals as they see fit, which may include shifting load, conserving power, or procuring the commodity through direct access.

As the market evolves, we would expect ESPs to offer products and services that will allow greater means to smooth bills. 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 or under consideration in other proceedings (see discussion regarding load retention discounts, below). Therefore, we will limit the new products offered by the UDCs to those already authorized, until there is a decision on the role of the UDC. It is reasonable to allow the utilities to continue to offer BPPs to their residential customers. We will not expand this program to streetlighting customers. We agree with UCAN, the CEC, and various competitors that this is a problem for which the marketplace can find a solution. 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. We see no reason to provide further protection from volatility at this time.

3. Definition of the Transition Period for Buy-Sell Requirement

In the Preferred Policy Decision, the Commission required that the UDCs buy and sell power through the CalPX during the transition period. At that time, the Commission anticipated that the transition period would last five years. The fundamental reasons for this approach were the Commission's goals of consumer protection and the development of a deep and transparent market for power. The Preferred Policy Decision states:

These goals of consumer protection, ensuring the integrity of the compensation request protected by the competition transition charge, reduction of the nature and complexity of future regulation, and nurturing the advent and maturing of the market signals suggests that it is useful to think of participation in the Power Exchange in three distinct time frames:

1. the initial period when there is little if any experience with market conditions and functions;

2. the five-year period identified as the transition between the regulatory order which is passing and the competitive climate we seek to foster; and

3. the post transition period.

A refusal to make this distinction imposes the risk of withholding support for infant mechanisms as yet untested by market participation or perpetuating the presence of such supportive structures after customer and supplier sophistication has rendered them unnecessary. (D.95-12-063, as modified by D.96-01-009, mimeo. at pp. 52-53, emphasis added.)

In addition, the Commission determined that allowing the utilities to opt for non-exchange, bilateral contracts, for sales and purchases, would jeopardize the price transparency and reliability of price signals, and the legitimacy of the competition transition charge. The Commission concluded that if the utilities opted to make the bulk of their purchases on behalf of full service customers through bilateral contracts, those customers most vulnerable to market power abuse would have no means of tracking electric power costs. The Preferred Policy Decision states:

Beyond the issues of consumer protection and customer choice, there is the legitimacy of the competition transition charge and its acceptance as a non-bypassable obligation by all classes of users. The issue of generation assets alleged to be stranded would now be plagued with doubt and uncertainty at the precise time when this Commission would be seeking to ensure the acceptance and collection of a non-bypassable competition transition (sic). Again, complex and probing regulatory proceedings might eventually determine the reasonableness of these claims presented by our jurisdictional utilities but the time and delay would protract the transition period and move us away from reliance upon market mechanisms. (Id., mimeo. at pp. 59.)

In this proceeding, we must determine whether the utilities should be released from the buy requirement if stranded costs have been recovered before the end of the four-year transition period. We acknowledge that any generation unit divested to a non-affiliated new owner is free of any obligation to bid into the Exchange (Id. at p. 53.)

The FERC granted SDG&E partial release of its "sell" obligation as it maintains jurisdiction over wholesale transactions. Under the Federal Power Act, FERC has jurisdiction over sales for resale. SDG&E requested authorization to sell power at market-based prices from any source of energy into all markets, including the PX. SDG&E did not ask FERC to modify the buy requirement, only the sell requirement. The September 1999 FERC Decision granted a very limited exemption from the mandatory sell requirement. The scope of this exemption is limited to sales from SDG&E power purchase contracts, and does not exempt any generation it owns or the wholesale commodity from in-system QF contracts. This authority does not reach any requirements this Commission may impose as to the retail services SDG&E provides to its bundled service customers. Therefore, pursuant to our authority over utility energy procurement for retail load, illustrated, for instance, in the series of cases establishing the so-called "Pike County" doctrine,²⁷ it is for this Commission to decide when and under what conditions to terminate the mandatory "buy" requirement.

While the specific rate freeze period applies to individual utilities and represents a period of time during which the utilities can recover stranded costs, that was not the sole objective of establishing the industry-wide transition period. This period is a time in which the market is developing and evolving, constituting a progression from a regulatory regime to one where competitive market forces determine prices. A fundamental component of that changeover hinges on the development of a deep, transparent, reliable commodity spot market. This development will be fostered by use of either the CalPX or any qualified exchange. The Commission anticipated that by the end of this period, the market would be more viable, competitive, and increasingly sophisticated. The collection of a given amount of revenue to pay down sunk costs does not and cannot equate to a finding that California energy markets have reached a competitive state.

The Preferred Policy Decision determined that the fundamental objective of the buy-sell obligation is to create a market with adequate depth and liquidity to assure confidence and increase the number and sophistication of market participants. In addition, the requirement was meant to reduce regulatory burden during the transition period as well as provide integrity for the CTC collected from customers. It is pertinent that we look to the intention of the requirement and whether its reasoning remains valid. We believe it does with the addition of removing any barriers to also use any qualified exchange.

The utilities remain the largest purchasers of power in California. The requirement that they make those purchases through the CalPX or any qualified exchange will attract participants to the market, which in turn will serve to increase market depth. If we were to terminate the buy requirement at this time, retail competition could be hampered. The presence of big buyers attracts generators and ESPs to the market serving to increase liquidity and depth. The buy obligation provides a more level playing field that maintains ESP confidence in the market. As more ESPs participate in the marketplace, more innovation and ingenuity in value-added services will result. As more qualified exchanges enter the market, more innovation and ingenuity in procurement practices will emerge.

As long as any utility continues to collect generation-related transition costs from its customers, it is our responsibility to ensure the integrity of that charge. During the rate freeze, the CTC is derived residually based on energy and other costs; therefore, the validity of the CTC charge is dependent on the reliability of the energy charge. In our view the best means of accomplishing the objective of protecting the integrity of the CTC charge for any utility is to continue the buy requirement until all three utilities have recovered generation-related stranded costs, i.e., until each has ended its respective rate freeze. This way the energy charge will be determined by a transparent market price. Therefore, we conclude that so long as any utility continues to collect generation-related stranded costs which are tied to the rate freeze period, PG&E, Edison, and SDG&E must continue to buy from the Cal PX or a mixture of the Cal PX and any other qualified exchange. This reasoning rests on the possibility that the withdrawal of all purchases from the Cal PX by any one utility may compromise the market price, thus serving to jeopardize the integrity of the competition transition charge for the utilities that remain under a rate freeze. Therefore, we will order that all three utilities 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 ended its rate freeze and ceased collecting generation-related transition costs.

As directed in D.99-10-057, PG&E and Edison must provide monthly forecasts of the rate freeze end once its remaining generation assets have been valued or it begins to record costs in the Accelerated Costs Account of the TCBA. PG&E and Edison must also make an advice letter filing with tariff language and preliminary statements three months prior to the earliest date estimated using the four PX price forecast scenarios. If the utilities do not end their rate freeze early, proposed methodologies and tariff provisions for ending the rate freeze will be filed in September of 2001, three months prior to the end of the rate freeze. 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 will provide the actual rates to be implemented after the rate freeze, as well as the ratemaking mechanisms authorized by D.99-10-057 and this order. The advice letter implementing rate changes will become effective within 30 days of the end of the rate freeze subject to Energy Division determining the advice letter is in compliance with this and subsequent decisions. These advice letters will serve to notify parties and this Commission of the end of the rate freeze for PG&E and Edison.

¹⁰ SDG&E requested approval to enter wholesale markets, other than the CalPX, to sell certain generation, limited to that obtained from certain power purchase contracts. FERC's order granted this limited waiver of the sell requirement, but did not extend its reach to power from SDG&E's own generation or from that obtained from QF contracts. Order Granting Waivers and Conditionally Accepting for Filing Revised Market-Based Rate Tariff (September 10, 1999) in Docket ER99-3426-000 (September 1999 FERC Decision), mimeo. at pp. 4, 5-6.

²⁷ Under the Pike County doctrine, a series of state and federal cases have recognized the right of states to review the prudence of a utility's purchasing decisions. That is, the state cannot refuse to let the utility pass through its wholesale costs based on the unreasonableness of the wholesale rates. However, the state can decide that the utility's decision to pay the wholesale rates was unreasonable in light of the availability of more economical power from alternative sources. The Commission therefore has oversight of power purchases for retail sale. The basis of the "buy" requirement is the Commission's determination that utility purchases through the CalPX are deemed reasonable.