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D9512063

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III. MARKET STRUCTURE

Introduction

With today's decision we launch California's bid for a market structure that embraces competition in the provision of electric services, offers retail customers choice and flexibility in energy services, and reforms the manner in which we regulate utility monopoly services. Critical to this new market structure is the establishment of a statewide Independent System Operator (ISO) responsible for coordinating the dispatch and delivery of power over the transmission system. In addition, the creation of a regional Power Exchange, charged with the purpose of developing a visible spot market with transparent prices for electricity and open to all suppliers, including out-of-state suppliers and municipal utilities, will enhance efficiencies by introducing competitive pressures into the generation sector. The Power Exchange and the ISO would be two independent and separate entities, the design and operation of which will require approval by FERC.

No later than January 1, 1998, simultaneous with the establishment of the Power Exchange and the ISO, we will advance the opportunities for customer choice in electric services by implementing several options for customer participation in the market. With direct access, customers can choose to purchase power according to default rates or through negotiated terms and conditions directly with competing nonutility generators, or less directly through brokers and marketers. We fully expect that all customers will have the opportunity to enjoy these forms of customer choice no later than five years from the start of our new market structure. Utilities will continue to procure power for those customers who choose not to arrange retail contacts 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.

Our decision today advances federal and state goals of increasing competition in generation and providing open, nondiscriminatory transmission access and service. At the outset, we recognize that establishing a new market structure for electricity in California will require close cooperation and coordination with the Federal Energy Regulatory Commission. The creation of the ISO and the Power Exchange requires exercise of jurisdiction by both this Commission and the FERC under a policy of cooperative federalism. This shared jurisdiction raises the possibility that disgruntled parties may attempt to delay or overturn our decision by claiming that our authority to act is preempted by federal law. Such tactics would be disruptive of reforms which command the broadest support on the record before us. As private decisions they cannot be precluded, nevertheless it is our intention to minimize any provocation by the steps we take today. We begin by acknowledging that the boundaries of federal and state jurisdiction begin to blur in the context of new market structures. Our policy of cooperative federalism embraces our counterparts at the federal level as well as other western jurisdictions. It also manifestly includes market participants who must, in the finally analysis, cooperate actively if a shared vision of a more competitive and productive electric services industry is to be realized. In furtherance of these objectives we now begin a statement of our policy preferences respecting the formation and function of the critical market institutions. We suggest ways of furthering these policies in the context of industry initiatives as well as filings here and at the FERC. Finally, in areas committed to shared jurisdiction or conceded to be within the domain of federal authority, we suggest mechanisms and protocols which would advance the preferences we have identified as in California's interest. Our intention is not to forestall other suggestions or means to achieve these ends, but to demonstrate plausible strategies which have convinced us that our goals are attainable.

We acknowledge that by choosing to cooperate in the development of new market structures, the three major utilities subject to our regulation have removed much of the jurisdictional uncertainty associated with electric restructuring. These utilities have voluntarily agreed to support a consensus model based on transferring control over the transmission system and dispatch operations to the ISO, participating in a Power Exchange, and providing their retail customers with direct access to alternate suppliers. Without this cooperation, it is unlikely that new market structures could be implemented in California in the time frame we propose today.

Even with this level of cooperation, the implementation of the ISO, the Power Exchange, and retail competition raises questions of where jurisdiction lies over cost recovery and regulation of transmission service and sales of power. We suggest ways to coordinate with the FERC on these issues in our discussion of market structure.

We describe this new market structure in the following sections. In Section III.A, we discuss the disaggregation of the utilities' transmission function and the transfer of that function to an ISO, how the ISO is to be established, its critical scheduling and balancing responsibilities, safety and reliability issues, and the financial settlement process. In Section III.B, we describe the Power Exchange which we believe will enhance efficiencies. In Section III.C, we discuss the ownership and structure of the ISO and Power Exchange. Section III.D describes the opportunities for customer choice in electric services. We then turn to Section III.E, where we discuss our continued regulation of the utilities and how Performance Based Ratemaking fits into this process.

A. Disaggregation of the Utilities' Transmission Function and the Establishment of an Independent System Operator

The electric grid is an interconnected system of transmission, distribution and other related facilities. Operation of the electric grid requires that variations in generation supply and demand levels are continuously balanced. Currently, the responsibility for system operation resides with the vertically integrated utilities which also own and control a majority of generation assets and nearly all of the distribution assets serving the California market.

Our May proposals concluded that, at a minimum, it was necessary to disaggregate the vertically integrated electric utility by separating the elements of generation, transmission and distribution. Focusing on market power concerns that arise from the utilities' ownership and control over transmission facilities, we proposed that the utilities transfer the operational control of all transmission facilities to an ISO. Today we affirm this proposal. The establishment of an ISO lessens the potential for owners of the transmission system to favor their own generation facilities over nonutility facilities in providing transmission access. Coupled with FERC's principles of open, nondiscriminatory transmission access, disaggregation of the transmission function will enhance fair competition among generators.

The establishment of the ISO will confer four immediate and lasting advantages upon all users of electricity in California.

  1. The state will achieve a permanent and functional resolution of transmission access disputes between the transmission-owning utilities and those dependent upon access to the system.
  2. There will be a lasting efficiency gain resulting in cost savings due to combining the now distinct control functions of many entities under the auspices of a statewide independent system operator.
  3. There will be an operational efficiency inherent in a transmission network which has no economic interest other than fostering open access and the facilitation of supply from generators irrespective of their ownership.
  4. There will be a consistent pricing system for the use of the common network facilities that prevents cost shifting and supports the competitive market.

1. The ISO is Separate from the Power Exchange

The May pool proposal conceived that in addition to coordinating the transmission system, the ISO would have a second function: making a transparent market for generation with price signals evident to immediate users and long-term investors. The MOU built on the May pool proposal's concept of the ISO by suggesting one significant change: the separation of the ISO from the spot market pool functions, which the MOU assigned to an entity called the Power Exchange.

Parties favoring separation advance two primary reasons to separate the ISO from the pool. First, separation would prevent the ISO from favoring pool transactions over transactions occurring outside the pool or from unfairly restricting the operation of nonpool suppliers in case of grid congestion. Second, separation would provide an opportunity for developing transparent information about system operations and congestion which would aid in eliminating any perception of discriminatory decisionmaking. Parties preferring establishment of a single entity with the responsibilities of an ISO and a power pool assert that the coordination between two separated entities could be complicated. They also argue that the separation would interfere with economic dispatch of generation and would create additional transaction costs.

Because the new market framework must at its conception have the support and confidence of market participants, and because the separate entities will function similarly to and bring the same benefits as a structure which combines the two, we are convinced that these potential problems are best resolved by requiring that the functions of the ISO and the pool be vested in separate entities. The independence of the ISO from the pool reinforces the principle that all market participants are subject to the same protocols regarding allocation and pricing of transmission access along with resolution and pricing of transmission congestion. This separation should eliminate any perception that the ISO could gain financially by preferring one supplier over another in dispatching generation and scheduling transmission.

2. Principles for Operation of the ISO

Under the Federal Power Act the FERC has authority over rates, terms, and conditions of sales for resale and transmission in interstate commerce. Courts have determined that the transmission of electricity, even between two points within a state, making use of interconnected interstate grids falls within the federal interest in interstate commerce. Thus, the FERC must approve rates, terms and conditions of transmission services provided by the ISO. We expect that the ISO will file its own transmission tariff and operating procedures with the FERC. Under state law we must approve transfer of control over the investor-owned utilities' transmission systems and dispatch facilities to the ISO. Following the FERC's approval of the ISO, utilities will need to file for our approval under Public Utilities Code 851 (Fn. 1) to transfer control of their transmission facilities to the ISO.

We authorize PG&E, SCE and SDG&E to work with parties and each other to develop a detailed proposal for submission to the FERC to establish the ISO and its protocols and transfer operational control of the utilities' transmission facilities to the ISO. We fully recognize that these proposals go beyond the minimum requirements specified by FERC and include new, innovative transmission access and pricing approaches. However, we believe that these proposals will amply meet the test of being a conforming, open access system that improves over the minimum requirements in the directions recommended by FERC and necessary for the competitive market. These proposals shall be filed at FERC and simultaneously filed in this docket within 130 days after the effective date of this decision. The filing should incorporate the principles delineated below, which we believe are critical to the successful operation of the ISO.

  1. The ISO will have primary responsibility for the determination of the final operation and dispatch of the system to preserve reliability and achieve the lowest total cost for all uses of the transmission system. The ISO will have control over the operation of the transmission facilities. The participating investor and publicly owned utilities will continue to own those facilities and be responsible for their maintenance.
  2. The ISO will have no financial interest in the Power Exchange or in any source of generation or load. This restriction will ensure that the ISO will have no bias in favor of or against generators who participate in the pool or as suppliers with direct access contracts. The ISO will own no generation, transmission, or distribution facilities and will have no affiliation with any companies that own those facilities.
  3. The ISO will maintain frequency control and comply with all standards of the North American Electric Reliability Council (NERC) and the Western Systems Coordinating Council (WSCC).
  4. The ISO will provide open and nondiscriminatory services and access to the transmission grid for all users of the transmission system, including purchasers and suppliers in transactions arranged through the Power Exchange and suppliers contracting directly with customers, consistent with the principles espoused by FERC in its proposed rulemaking on open access transmission services and stranded costs. (Fn. 2) All market participants will be subject to the same protocols and prices regarding transmission access and treatment of transmission congestion.
  5. The ISO will procure from suppliers ancillary services needed to support transmission and dispatch. Where possible, this procurement should be from suppliers on a non-discriminatory, competitive, unbundled basis. The ISO will offer to users ancillary services either as competitive, unbundled activities, for those services that can be metered and measured separately for individual users, or as cost-effective joint products, for those inherently inseparable network services. (Fn. 3)
  6. The ISO will coordinate day-ahead scheduling and balancing for all uses of the transmission grid. For both the day-ahead schedules and the hourly balancing transactions, the ISO will accept nominations from the market participants. The nominations from the Power Exchange will include the tentative dispatch, the locations of the generation and loads, and the associated bids for generation and loads. The nominations from the bilateral participants must include the amount and timing of power deliveries, along with the source and destination for power transmission. In addition, the ISO will accept from the bilateral participants bids for increments and decrements of nominated inputs or outputs that would be available from the bilateral transaction as needed to redispatch the system. The Power Exchange supplies classified as must take will use the same ISO protocols. (Fn. 4)
  7. The ISO will coordinate the scheduled nominations from the Power Exchange and the bilateral transactions to determine any redispatch that would be necessary to meet the twin objectives of assuring operational reliability and achieving least-cost use of the system. Along with this redispatch, the ISO will determine the locational marginal costs incorporating the cost of generation, losses and congestion that will define the market clearing prices for the Power Exchange and the price of transmission use for the bilateral transactions. The marginal costs of redispatching to provide an increment of load at each location will define the purchase and sale prices through the Power Exchange. The differences in the locational marginal costs between source and destination will define the price of transmission applied to the bilateral transactions. The ISO will notify the Power Exchange and the bilateral participants of the final redispatch for the scheduled nominations and the associated prices that will be charged for transactions. (Fn. 5)
  8. The ISO will coordinate the implementation of the final schedules to adjust as necessary to ensure the reliability and least cost for the actual hourly dispatch. Again, the ISO will accept supply and demand bids from the Power Exchange and increment or decrement bids from the bilateral participants for their transactions. Over the course of the day, the ISO will order any redispatch adjustments as necessary to balance the system. Associated with this actual dispatch, the ISO will again compute locational marginal costs. These actual dispatch locational marginal costs will define the locational prices to apply to any imbalances relative to the scheduled generation and loads. With this pricing, there will be no need for any other limitations or penalties for any participants for load or generation in the actual dispatch.
  9. The revenue collected for transmission use from direct access participants and the Power Exchange will include payments of congestion costs arising from the redispatch of the system in the face of transmission constraints. The ISO will administer a system of transmission congestion contracts to redistribute the congestion payments and provide a set of tradeable instruments to support long-term commercial transactions across locations in the grid.
  10. The ISO will provide a system of open communication of information for the scheduling market. Individual bids and nominations will be confidential, but all other reasonable information on market clearing prices, power flows, the state of the transmission system will be made available to all participants in an appropriate, timely, and non-discriminatory manner. The ISO will also provide information necessary for long-term studies by market participants to support commercial contracting and investment decisions.

3. The ISO's Coordination Responsibilities

a. Scheduling:

On a day-ahead basis, the ISO will schedule the dispatch and delivery of electricity according to suppliers' preferred schedules, which reflect the terms and conditions of bilateral contracts, existing utility contracts with nonutility generators, and transactions mediated through the Power Exchange.

The ISO will have no direct responsibility for dealing either with so-called "must take" units or any generation obligations under existing contracts. These obligations will remain with the contracting parties, including the utilities and any other producers. These parties will have the opportunity and the responsibility to nominate the necessary generation or load either as bilateral transactions or through the Power Exchange with the allowable degree of flexibility for redispatch. Any costs incurred through purchase and sale in the Power Exchange or as a transmission usage charge for a bilateral transaction will remain the responsibility of the contracting parties.

b. Managing Transmission Constraints and Congestion:

In California there exist transmission bottlenecks or constraints that may affect the choice of which generators will actually be dispatched. Effective management of transmission congestion is critical. We note the concern expressed by Professor Paul Joskow with regard to the ISO prioritizing the scheduling of direct access supplies and Power Exchange supplies:

If Power Exchange transactions are not treated identically to "bilateral schedules" for the purposes of allocating scarce transmission capacity and in responding to other network contingencies that require out-of-merit order operations, significant distortions and inequities might result. I am especially concerned that "bilateral schedules" will endeavor to be defined as having first priority for "firm" transmission capacity, while Power Exchange transactions are treated as being "non-firm" residuals. Combined with direct access this could advantage large customers who get direct access first and disadvantage small customers who get it later. It could also disadvantage generators that are committed to sell through the Power Exchange and, eventually, would undermine the Power Exchange as a robust spot market with visible prices and reduce it to a residual energy regulation market. (Fn. 6)

We agree that such a scheduling order could place Power Exchange suppliers at a disadvantage. Such a result would violate the cardinal principle that the ISO should resolve transmission congestion and achieve a least-cost dispatch with total indifference as to the source of generation affected by the constraint.

Pricing actual transmission usage at the difference in the locational marginal costs determines fair and efficient use of available transmission without cost shifting. This efficient transmission pricing also sends the correct signals for needed investment in upgrades to the transmission system. We favor more market-driven mechanisms supported by the open, comparable and nondiscriminatory principles promulgated by FERC, rather than regulatory or administrative approaches.

Transmission congestion contracts for compensation for congestion costs between locations offers a mechanism for providing long-term stability in transmission costs for those market participants who invest in transmission. (Fn. 7) The fixed charges of the existing transmission grid could be recovered through a system of access charges. In principle, these access charges would be equivalent for each utility, at least initially, to the current payments for transmission assets that are in the rate base. A set of feasible transmission congestion contracts for the existing system could be distributed through an auction mechanism which would be open to all market participants, with the auction revenues used to offset the fixed charges for the existing system. We direct the utilities to develop a mechanism for allocating both the fixed charges and allowable transmission congestion contracts for the existing system as well as for prospective investments in transmission upgrades.

c. Real-Time Load Balancing:

System imbalances resulting from differences between scheduled dispatch and actual dispatch must be managed by the ISO as part of its real-time dispatch function. The ISO should ensure that adequate generation capacity is available to maintain frequency and to manage generation and load fluctuations. It will be necessary for the ISO to have physical control of the operation of some generation facilities in order to balance the system and respond to unforeseen circumstances. The ISO must also have the ability to alter the order of dispatch when necessary to maintain system reliability and stability.

Customers will be responsible for the costs of system reliability and ancillary services incurred on their behalf. To the extent ancillary services can be separately identified and metered, the ISO should establish an unbundled list of services. Customers will have the choice of selecting services from that list (in which case the services will be procured by the ISO competitively and customers will be charged according to the ISO's tariffs) or procuring the services independently. For any ancillary services that cannot be separately identified and metered, the ISO will procure necessary services, and the costs should be paid by all users of the system.

d. Maintaining Reliability and Increasing Efficiency:

The ISO should evaluate the physical condition of the transmission grid and report on the ability to continue existing transmission congestion contracts or the opportunities for upgrades needed to maintain reliability or to increase efficiency. However, the principal impetus for transmission investments should come from market forces manifest in the requests from customers who are willing to pay for the upgrades in exchange for incremental transmission congestion contracts and protection from future system congestion costs. In the absence of willing customer requests, investments in the transmission grid should be made only in the case of a showing to the regulators that there has been a market failure leaving important modifications undone because of an inability of market participants to agree on a sharing of the costs and benefits. In the context of cooperative federalism, the regulators and appropriate authorities should maintain the prerogative to authorize the permitting and assign the costs of the investment and the benefits of incremental transmission congestion contracts among the various users of the system.

Since states will continue to be responsible for siting, recommendations for upgrades should be made to the Western Regional Transmission Association (WRTA), FERC, and the Commission. This process may be facilitated by establishment of a Joint Siting Board under Federal Power Act 209.

In this context we reaffirm our full support of the concept and function of Regional Transmission Groups. We will continue to participate in the process associated with the formation and operation of such entities in efforts to ensure efficient investment in new transmission and related facilities.

e. Recovering the Cost of Providing Ancillary Services

In the market structure we adopt today, the suppliers and their intermediaries (including the utility in its procurement role) have the responsibility to match the dispatch of electricity supply with expected customer load according to the terms of their retail or wholesale contracts. The suppliers will schedule dispatch based on forecasted load on a day-ahead basis. On a daily basis, the ISO will coordinate these schedules and manage reserves and transmission congestion to ensure that actual load requirements are met. If actual load requirements do not match the forecasted requirements or, if a supplier fails to produce the scheduled generation, the ISO will balance the load using available supply options such as spinning reserve, or other competitive supplies, including any such services offered through the Power Exchange or from participants in bilateral transactions.

f. Information:

Transparent information flow is critical to ensuring equal access to transmission capacity. Users of the system should have access to information regarding system status, e.g., constraints, load distribution, line losses, and other related information that would be useful in operation of their facilities. The ISO should make system data available quickly and on a comparable basis to all market participants.

4. Jurisdictional Issues Related to the Creation of the ISO

Creating the ISO raises jurisdictional issues, including the questions of who has jurisdiction over unbundled retail transmission and where the line should be drawn between the transmission and distribution functions. In the original and supplemental Notices of Proposed Rulemaking (NOPR) on Stranded Cost Recovery, (Fn. 8) the FERC addressed these issues in the context of discussing its jurisdiction over the transmission component of an unbundled retail wheeling transaction. The FERC distinguished between transmission, which is subject to the FERC's exclusive jurisdiction (except that the FERC is prohibited from ordering retail wheeling) and local distribution, which the FERC found to be subject to exclusive state jurisdiction. The FERC asserted, based on its analysis of Supreme Court cases addressing the scope of transmission in interstate commerce, that all transmission, including the unbundled element of transmission in a retail wheeling transaction, is subject to its rate-setting jurisdiction.

In the Supplemental NOPR, the FERC proposed a functional test to find that all wholesale transmission is subject to exclusive federal jurisdiction, even if the transmission occurs over distribution lines. To determine where the line between transmission and distribution in an unbundled retail sale should be drawn, the draft proposed rulemaking rejected adoption of a "bright line" test, and instead opted for a functional/technical list of factors to be applied on a case-by-case basis. The FERC stated its belief that in most circumstances, some portion of the facilities used to transmit energy from the transmitting utility in closest proximity to the end-user (the former supplier of the bundled product) consists of local distribution facilities.

The FERC invited state commissions to request clarification concerning whether certain facilities are local distribution facilities. Here is our response. Based on the record in this combined proceeding we concur with the suggestion of the utilities that the FERC should rule that facilities transferred to the ISO are FERC-jurisdictional and that those retained by utilities "downstream" of the ISO are local distribution facilities, if used to make retail sales, whether to retained utility customers (bundled) or to direct access customers (unbundled). This test would work for defining jurisdiction in the context of the ISO as well as for the unbundled components of a direct access transaction. It is consistent with the FERC's reasoning in the Supplemental NOPR:

In the case of a distribution-only utility, which is franchised by a State or local government and sells only at retail, all of the circuits (and related wires, transformers, towers, and rights of way) which it owns or operates (regardless of voltage) would be local distribution facilities. (Fn. 9)

The assertion of federal authority over the rates, terms, and conditions of unbundled retail transmission has been challenged, and it is not clear how the FERC (or the courts) will ultimately rule. Whatever the eventual outcome, it is clear that under the new market structure proposed today, the FERC will be regulating a significantly larger portion of transmission revenues than it currently does. We recognize that establishing the ISO will require a fundamental shift in regulation of transmission assets. Currently, we allow utilities to recoup approximately 90% of costs of transmission assets through retail rates. Revenues from rates set by the FERC for wholesale transactions are treated as an offset to the utilities' revenue requirements. Under our proposal, many of these assets will be designated as wholesale since they will be used by the ISO in fulfilling its responsibilities. These assets may of necessity be removed from retail rate base with the corresponding charges reclassified as access charges for the distribution utility. In principle, there should be no difference in the transmission fixed costs charged ultimately to retail customers.

During the transition to the new market structure, we have a strong public interest in ensuring that rates charged for transmission services, which up to now have been subject to our rate-setting authority, continue to be just and reasonable. In particular, we are concerned that cost-shifting from over- or under-collection of revenue could result from dividing jurisdiction over transmission and distribution. We intend to safeguard against revenue over or under collections by participating in the proceedings instituted at FERC to establish the ISO and the Power Exchange.

As part of its review, the FERC will be asked to confirm a designation of certain facilities as local distribution facilities, both for rate purposes and for the purpose of recovering retail stranded costs. It is important that the FERC rule that every retail sale, regardless of whether to a direct access customer or utility service customer, contains a local distribution component to assist California's implementation of a non-bypassable basis for recovery of transition costs. This process will allow both state and federal regulators to review and approve rates while avoiding litigating the question of where transmission ends and distribution begins.

B. The Power Exchange Provides a Visible Market for Generation

The Power Exchange will function as a clearinghouse by providing a transparent market for generation with hourly or half-hourly price signals evident to immediate users and long-term investors. The performance of this function will provide critical information vital to informed market decisions by generators, wholesale buyers, and end-users. (Fn. 10)

  1. The Power Exchange will implement nondiscriminatory rules which will permit rival generators to compete on common grounds using transparent rules for bidding into the Exchange. Generation units outside of California, including those operated by municipal utilities or public power entities, will be welcome to bid into the Exchange. Over time the ability to observe the price information will send the most reliable signals with respect to the need for additional generation as well as cost-cutting steps required to keep existing units competitive.
  2. Wholesale and retail buyers will be able to make efficient purchasing decisions and to modify their electricity consumption in response to immediate price signals.

The market-clearing locational prices can also serve as benchmarks for risk allocation contracts to hedge against market uncertainty or secure long-term price stability. Trends in the market-clearing prices would allow investors to determine the cost-effectiveness of incremental supply and thus facilitate long-term investment decisions. Moreover, customers who are equipped with real-time or time-of-use meters will be able to use real-time pricing information provided by the Power Exchange to judge the attraction of a virtual direct access billing computation and adjust their consumption by shifting usage to off-peak periods of demand. The hourly or half-hourly market price will also be used to settle imbalances due to supply shortages or higher-than-expected demand.

1. Principles of the Power Exchange

We direct PG&E, SCE and SDG&E to work together and with California's municipal and publicly owned utilities and other parties to propose recommendations for the establishment and operation of the Power Exchange. These recommendations should follow the policy guidance we describe below and include proposals for ownership, structure, pricing mechanisms, bidding protocols, and communications with the ISO. The recommendations should be filed at FERC and in this docket within 130 days after the effective date of this decision.

The principles and characteristics of the Power Exchange are similar to those adopted for the ISO.

  1. The Power Exchange will have no financial interest in any source of generation to ensure that it will have no bias in favor of or against specific generators. The Power Exchange will be prohibited from owning generation, transmission or distribution facilities and will have no affiliation with any companies that own those facilities.
  2. The Power Exchange will have no financial interest in or relation to the ISO.
  3. The Power Exchange will be allowed to recover those costs associated with implementing a bid process for generation and establishing a one-hour or half-hour market-clearing price.
  4. The Power Exchange will oversee the ranking of least-cost generation facilities according to established protocols.
  5. The Power Exchange will establish nondiscriminatory and transparent bidding protocols. These protocols will include provisions for unit commitment in the day-ahead schedule and the procedures for payment of any minimum load or start-up costs not covered through the market clearing prices for energy.
  6. The Power Exchange should establish the appropriate computer links necessary for information exchange.

2. Responsibilities of the Power Exchange

The Power Exchange will conduct an auction in which generators will submit bids under transparent bidding procedures. These bids should state the minimum price for which suppliers are willing to dispatch a specified amount of power the next day in hourly or half-hourly time increments. The Power Exchange will then match the generators' bids with demand bids submitted by utilities, brokers, marketers or any authorized entity on behalf of end-use customers. As specified by the ISO, the Power Exchange next will determine and submit a contingent dispatch for generators. Using its established scheduling protocols, the ISO will then integrate the Power Exchange's preferred schedule with the schedule nominations arranged under direct access contracts and communicate system information affecting the submitted dispatch schedules. The Power Exchange will, in turn, notify generators of accepted or revised dispatch schedules.

The market-clearing locational prices will be obtained from the ISO (by a time certain) as part of the integration and coordination of the alternative nominations and bids. Every winning generation bidder will be paid the market-clearing price at its location, which price is consistent with both the bid and the supply and demand equilibrium. (Fn. 11) The Power Exchange will average the locational clearing prices: end use customers served by the Exchange will see one clearing price. The net payments to the Power Exchange will be disbursed through the ISO to pay for transmission losses or as congestion payments under transmission congestion contracts.

3. Participation in the Power Exchange

Recently, we have given considerable thought to the degree to which participation in the Power Exchange should be voluntary. We can find no reason why participation should not be wholly voluntary for all buyers and sellers other than the investor owned utilities jurisdictional to this Commission. A number of factors which we will now describe persuade us that for the five year transition period during which they seek recovery of their stranded generation assets and power purchase liabilities, our investor owned utilities should be required to bid all of their generation into the Power Exchange and satisfy their need for electric energy on behalf of their full service customers with purchases made from the Exchange. (Fn. 12) Such a temporary requirement will dramatically reduce the scope and burden of the regulatory issues associated with determination of the dimension of the assets which are non-competitive in a transparent market, ensure that those customers who elect to rely upon their distribution utility to procure their electric energy will receive the benefits of those competitive market prices, and provide a sufficient depth to the Exchange that its market signals may be relied upon as a benchmark for choices to opt for contracts for differences or direct access arrangements.

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 market signals suggest 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 a 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 and experienced by market participants or perpetuating the presence of such supportive structures after customer and supplier sophistication has rendered them unnecessary. (Fn. 13) Fidelity to the distinction convinces us that in the initial period the jurisdictional utilities must be required to sell their generation into the Exchange and make purchases of electric energy on behalf of full service customers from it. During the transition period, any generation unit sold by the utility by way of divestiture to a non-affiliated new owner will be immediately freed of any obligation to bid into the Exchange. Participation by the new owner will be totally voluntary. At the end of the transition period, when the determination of the assets which qualify for recovery under the competition transition charge has been finalized, the utility will be free of any mandatory requirement that it either sell into or buy out of the Exchange. By that time we anticipate that the sophistication of sellers, brokers, aggregators and end users will have developed equivalent if not superior means of gaining access to pricing information and the comparative advantages and disadvantages of using the Exchange as a market mechanism.

a. The critical role of transparent, reliable price signals:

Looking more closely at the role of the Exchange we find it useful to distinguish the value or benefit which we expect it to confer upon a variety of market participants. On the day it begins to function the Power Exchange will be the market institution in which all generators are able to compete on the basis of short run incremental electricity costs in an open setting and on what is literally a level playing field. Equally important, all buyers of electric energy will derive basic consumer protection in their ability to freely monitor the results of that competition. The transparent price will also be revealed in what we have termed "real time" so that clear market signals can be sent to buyers and end users as to the significant difference in the cost to California's economy of meeting our energy needs at any point in the twenty-four hour day. The value of this pricing revelation will be significant after the first week of Exchange operations, but will grow with the passage of time and the acquisition of experience. (Fn. 14) Once this price is revealed and tracked market participants will begin to develop a confidence and sophistication which will permit them to make key decisions.

(1) The value of price revelation to existing and potential sellers:

Our jurisdictional utilities will gain real experience in determining which of their generating assets clear the market, how frequently, and with what resulting stream of income. As we shall more fully discuss, having this determination made in a open market is critical to gaining end user acceptance of the integrity of the non-bypassable competitive transition charge. Non-utility generators, both within and without California, will be able to use this same information to decide if it is in their self interest to attempt sales into the Exchange or seek direct access customers. Finally, potential generators will see the emergence of a price signal which will point to market opportunities to invest in new generation capacity. As an example, let us suppose a potential market entrant with access to a gas supply and computations which project the cost of generation with a state of the art combined cycle turbine at three cents. Knowledge that the Exchange is clearing eighty percent of the time at three and one half cents and above is precisely the type of information needed to develop a business plan to enter the market and obtain financial backing for such a step. This information is equally vital to a utility or non-utility owner of existing units with respect to the feasibility of a repower.

(2) The value of price revelation to buyers:

Our vision of a market dominated by vigorous competition is wholly dependent upon the availability of timely, reliable and affordable information upon which customer choice can be intelligently made. Throughout this proceeding we have been challenged to devise institutions and protocols which will enable customers of every class and potential load profile to gain the benefits of enhanced competition among generators and the efficiency gains of a unified and independent operator of the transmission network.

While it is relatively easy to trust in the ability of large users to attract the attention of rival sellers, the circumstances of California's residential and small load commercial and agricultural ratepayers cannot be projected with comparable confidence. Throughout our history this Commission has been given the responsibility of fostering the well being of these ratepayers and we cannot abandon them with the simple expedient of dubbing them "customers." At least initially, most observers anticipate that a significant majority of residential and small load commercial and agricultural users will either prefer, or lack competitive alternatives to, reliance upon the local utility to procure electric energy as well as provide distribution and related services. These average ratepayers may be referred to as "full service customers." During the transition period, we have concluded that our greatest contribution to those who initially elect or find no alterative to the status of full service customers is to ensure that they gain access to the competitive price for generation in a manner that is free of cost and confusion. We have accomplished this by our requirement that the distribution utility must simply pass on to these customers the cost of electric energy as revealed by the Exchange over the billing cycle. Full service customers are then given the option to have their bill computed as the average of the Exchange price times consumption or elect the virtual direct access option in which the Exchange price is matched against the time of use in which the customer's consumption occurred.

Customers who desire stability or certainty over time will find the revealed Exchange price signals vital to electing among an enhanced set of options. A customer who, for any reason, desires a price structure which differs from the day by day, hour by hour, revelation in the Exchange will be afforded the opportunity to purchase a financial hedge or "contract for differences" from any counterpart party who may or may not own or have contractual rights to any specific generation. Even more dramatically, such a customer may elect a direct access contract. But irrespective of the alternatives, the only way in which choice can be effectively made is for the potential buyers and sellers to compare the costs, terms and conditions to something readily known and reliably revealed. Until they have gained sufficient experience or devised alternative means to gain discovery over comparable information, that ready available and reliable reference point is the alternative of wholesale transactions revealed through the Exchange.

b. Allowing utilities to opt for non-Exchange purchases and sales during the transition period disguises pricing information and equires contentious regulatory proceedings to validate the dimension and legitimacy of the competition transition charge:

During the transition period both the transparency and reliability of the pricing signals will be seriously compromised unless the jurisdictional utilities are obligated to bid their generation units into the Exchange and procure the electric energy needed to supply their full service customers from it. Consider the most extreme example of an Exchange which is wholly voluntary from the perspective of the jurisdictional utilities on day one. Such a strategy would enable the potential market participants with the most concentrated market power to buy or sell electric energy through bilateral contracts. There would be no price revelation and consequently no price signals manifest to any party who was not a counterpart to such a contract. Even contracting parties would be mostly in the dark for they would have no direct knowledge of the terms contained in other deals.

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 an abuse of market power would have no means of tracking the cost of the electric power. Only by engaging in contentious reasonableness reviews could this Commission eventually establish information which, by that point, would be months if not years old. The virtual direct access option would be taken away from full service customers or rendered functionally useless given their inability to follow real time price signals. The decision of whether to opt for a contract for differences or to bear the cost of a direct access contract would likewise be compromised by an inability to compare the advantages and disadvantages of these strategies to a transparent alternative.

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 end users. The issue of generation assets alleged to have been 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. Again, complex and probing regulatory proceedings might eventually determine the reasonableness of these claims presented by our jurisdictional utilities but the time delay would protract the transition period and move us away from reliance upon market mechanisms.

On the surface many of these concerns would seem to be mitigated if we indulge the assumption that the jurisdictional utilities would shift only a portion of their purchases and sales away from the transparent Exchange market. But to the extent that they diverted their business they would lessen the confidence on the part of all market participants that the volume of Exchange transactions was sufficiently robust as to convey reliable pricing signals. In economic literature this problem is identified as one of "thin markets." Such a development could actually complicate California's experience with the transition period rather than facilitate it.

We can envision regulatory proceedings in which the market signals emerging from such a partially used Exchange would be blended with what were alleged to be proxy indicators developed from wholly or partially unverified sources. Any verification efforts made during the course of a contested proceeding would doubtless compromise the proprietary interests of the non-utility participant in such transactions adding yet another layer of conflict. Equally important, it would not resolve the issue of the appropriate charges to be passed onto to full service customers by the jurisdictional utilities, nor would it withdraw from the realm of conjecture the fairness with which they marketed generation sales which then resulted in a claim for compensation under the transition charge. In the final analysis adding layers of regulatory fixes strikes us a decidedly regressive response to a proceeding launched in the bid to foster and then rely upon market forces.

4. Jurisdictional Issues Related to the Creation of the Power Exchange

The establishment of the Power Exchange will require close coordination between the FERC and this Commission. The Power Exchange will have the function of bringing buyers and sellers together. Although the Power Exchange itself will not "sell" power, it will establish market prices for sales for resale.

The Federal Power Act (FPA) confers exclusive jurisdiction over rates, terms, and conditions for sales for resale (wholesale sales) on the FERC. Retail sales, even if the power originates out-of-state, are subject to exclusive state jurisdiction.

Because the power bid into the Power Exchange may be sold for resale, pricing mechanisms, including bidding protocols, will be subject to FERC's oversight. At the same time, the FERC lacks authority over generation assets that were built to serve retail customers and are currently in retail rate base and reflected in retail rates.

It is our intention to impose incentive ratemaking on certain generation assets. Our authority to apply PBR to generation assets where power from those assets is subject to FERC pricing authority has been questioned. (Fn. 15) In our considered opinion, subjecting the underlying generation assets to a PBR mechanism to ensure reasonable rates does not result in a conflict with the FERC, particularly since the FERC has no authority under the FPA over the generation assets themselves.

The legal framework established by Congress in the FPA did not contemplate the market structure we propose today. Therefore, to foreclose the possibility of litigation and attendant delay of restructuring on this issue, we recommend that the utilities ask, as part of their application to the FERC to establish the Power Exchange, that FERC accept and grant deference to the PBR revenue requirement determined by this Commission for the utilities' generation assets that make sales through the Power Exchange.

C. Ownership and Structure of the Independent System Operator and the Power Exchange

Our restructuring framework rests on the establishment of two entities, the ISO and the Power Exchange, that we have determined must be legally separate from all investor-owned utilities. Issues related to the organizational structure of the entities and who will own them must be addressed prior to seeking FERC's approval of their establishment. The structure of these two entities should be evaluated jointly, because they will be operating in close connection, each depending on the other to perform critical functions. The Power Exchange will be functioning as part of the generation market in which many competitors, including independent generators, utilities, and aggregators, will vie to supply the same commodity. Therefore, to some extent, competition will require efficient operation of the Power Exchange.

If the Power Exchange is to be a for-profit entity, restrictions should be put in place to prevent potential conflict of interests by requiring complete separation of the Exchange from any competitor or bidder in the Exchange. This task may be difficult, since design and operation of the Power Exchange will require significant cooperation among participating parties, and any decision that appears to give an advantage to any bidder could be perceived as a biased decision, reflecting some real or imagined self-interest on the part of the owners of the Exchange. A for-profit Power Exchange would require regulatory oversight to ensure it did not improperly exert its influence over any Exchange transactions. For these reasons, the Power Exchange may be perceived to be more impartial if it is owned and operated by a nonprofit or governmental entity charged solely with creating the most efficient exchange.

The ISO will operate as a monopoly (at least for the foreseeable future) and as such its function will be subject to FERC's regulatory oversight. If the ISO is organized as an investor-owned utility, it could be regulated as other investor-owned utilities are. However, the ISO should not be affiliated with generation providers or any of the utility distribution companies. The ISO could also be created as a nonprofit entity or governmental entity.

For both the Power Exchange and ISO necessary revenues can be acquired from a small fee added to each transaction as a volumetric or cost-based charge. The initial working capital of these entities might be derived from utility contributions, or from a loan approved by the appropriate regulatory agency.

We direct PG&E, SCE and SDG&E to include in their proposals for the establishment of Power Exchange and the ISO recommendations for ownership, organizational structure, and working capital of the two entities.

D. The Opportunity for Customer Choice

The opportunity to choose from an array of goods and services makes it more likely that individual customers make arrangements that meet their particular needs. Today, we move toward an industry which offers three avenues for increased customer choice in electric services.

First, we implement a transitional phase of direct access in which a representative group of retail customers can choose to arrange the purchase of electric generation services at negotiated prices directly from nonutility generation providers, including marketers, brokers, and supply aggregators. We expect that this transitional phase will lead to the availability of direct access to all retail customers.

Second, we make available real-time and time-of-use rate options to customers who have the appropriate metering equipment. Both of these choices provide electricity consumers with the opportunity to make informed decisions about the electric services they wish to receive.

A third choice exists in the opportunity for customers to arrange contracts for differences, which allow the parties to allocate the risks associated with market uncertainty. We discuss these choices in greater detail below.

1. Implementation of Direct Access

In comments to the May proposals and the MOU, most of the parties expressed a preference for the opportunity to purchase generation services at negotiated terms and conditions directly from suppliers, including brokers and marketers. Today's decision makes considerable progress in resolving the concerns expressed by the majority in May about the conditions that were necessary predicates for direct access. We recognize that not all concerns can be satisfied at this stage of the industry's transformation, but at this foundational stage of restructuring we should not be overly prescriptive in attempting to resolve all issues. To a great degree, we must turn to the stakeholders and market participants to discern the problems, define the issues, and recommend appropriate solutions.

No later than January 1, 1998, simultaneous with the implementation of the Power Exchange and the ISO, we will begin a phase-in of direct access. An initial phase of direct access will last for a period of twelve months, after which we will make the direct access option available to all customers at that time and we expect all customers to have that option within five years.

Implementation of this initial phase of direct access provides a measured approach to this new competitive framework and allows the market to (1) address any operational issues, (2) measure the effectiveness of the program, and (3) improve the program in order to offer it to an increasing number of electricity consumers. During the initial phase, and as part of our continued effort to allow retail competition to all market participants, the Commission will evaluate these and other issues. Barring technical concerns, we fully anticipate that a majority, if not all, of California electricity consumers will have the opportunity to purchase generation services directly no later than five years from the implementation of the initial phase of direct access. Each customer class will be represented in each year and phase. In the absence of agreement for earlier implementation, we adopt the following schedule for phasing in direct access for all three investor owned utilities at dates no later than:

Total Number MW Available for Participation in Direct Access Program

Year SCE/PG&E SDG&E
1998 800 200
1999 1,400 350
2000 2,200 550
2001 4,000 1,000
2002 8,000 2,000
2003 All remaining load All remaining load
a. Required Elements of Direct Access

Implementation of direct access will be subject to the following requirements.

  1. Customers in all classes shall have a fair opportunity to participate in each phase of direct access.
  2. Aggregation is voluntary and may include the loads of multiple customers or a customer may aggregate loads at several sites with appropriate identification of location consistent with the requirements of the dispatch. Aggregation may be limited to a particular customer class or may include customers from different classes.
  3. Third-party intermediaries, such as power marketers and brokers, will be able to purchase unbundled electricity from individual suppliers and bundle that with various energy services to meet the customers' specific needs or unique operational requirements.
  4. Suppliers or third-party intermediaries must ensure that appropriate metering equipment is in place.
  5. Supplies arranged by direct access contracts will be scheduled directly with the ISO. Suppliers who have arranged direct access contracts will be required to comply with the operating protocols of the ISO, but they will not be required to disclose any information about their costs of generation or the negotiated price for the sale. They will be allowed to submit increment or decrement bids for use in any redispatch determined by the ISO.
  6. Suppliers or third-party intermediaries and direct access customers will be responsible for the costs of ancillary services and other charges as communicated by the ISO.
b. Eligibility for Direct Access

Of primary concern to consumer groups is the issue of equitable access to the competitive generation market for small customers. Many parties have commented that the phase-in of retail competition as proposed by the MOU would primarily benefit large customers. They argue that the MOU's restrictions on participation disadvantage both small customers and aggregators and their customers who want to pursue retail contracts.

Allowing the aggregation of small commercial and residential customers, as well as the individual participation of small commercial and residential customers, is vital to ensuring that consumers have the opportunity to participate and benefit from consumer choice. Therefore, eligibility in the initial phase of direct access will be open to a representative number customers from all customer groups. We view the MOU's suggestion of an 8 MW threshold limit applied to individual customers and aggregated customer groups for the initial phase as a reasonable eligibility parameter. However, we note parties' reservations similar to those expressed by the Division of Ratepayer Advocates:

The MOU limits eligibility for direct access, but states no principle which supports limited eligibility. Presumably, the justification for limited eligibility lies in technical limits . . . . The Commission should resolve the difference between an unprincipled limit and a principled call for choice by having the parties work to determine what technical problems reduce how many customers can choose their supplier. (Fn. 17)

We direct the utilities to confer with parties and recommend eligibility parameters in the initial phase of direct access.

Parties should carefully consider whether our minimum phase-in schedule is necessary or whether eligibility can be held open to all electricity consumers after the twelve-month initial phase. If a phase-in schedule is deemed necessary, we ask parties to recommend an eligibility phase-in schedule for direct access beyond the initial phase, but not later than the five-year minimum schedule already stated. We do not favor restrictions beyond those necessary due to technical obstacles, though we recognize that some parties may have additional concerns. Modifications to an adopted phase-in schedule will be subject to any changes found necessary in the Commission's review of the initial phase and the parties' recommendations.

As entities not subject to our jurisdiction in these proceedings, municipal utilities and other government entities must make their own decisions with respect to customer choice options, including the availability of physical bilateral contracts.

c. The Utility as Generation Service Provider

Utilities will continue to have direct control and operation of their distribution system, power production, and procurement of generation services for their customers. They will also continue to own, but not operate, their transmission facilities. These utilities are referred to as utility distribution companies (UDCs). In addition to providing distribution service to all customers, the UDCs will serve customers who choose to remain utility service customers. This Commission will continue to regulate the rates, terms, and conditions of those services. We discuss in greater detail our regulation of the UDCs in Section III.E.

After a five-year transition period, UDCs will have the option of purchasing all or a portion of their electric needs from the Power Exchange or from other sources, including nonutility generation providers. They will be able to choose the level of their participation as buyers in the Power Exchange. In serving the load of any customers who do not choose to be direct access customers through another supplier, utility purchases through the Power Exchange will be considered prima facie prudent.

Self-dealing retail contracts prohibited: PG&E, SCE, and SDG&E, as distribution utilities, may not enter into retail contracts to purchase the output of a generation facility that is under their own or any of their affiliates' ownership.

Existing utility generation assets will undergo a Commission-reviewed market valuation process within the first five years of the establishment of the new market structure. After the completion of this process, the utility may still retain ownership of certain generating assets through affiliation. Thus, vertical market power could still exist between the distribution utilities and generation companies through ownership or affiliation.

Furthermore, a distribution utility has access to considerable information about its customers, their load profile and other related data. This information could be very valuable for marketing of generation services and if provided exclusively to the utility-affiliated generating company, could give that company an unfair advantage in the market. To ensure that a distribution utility affiliated with a generation company does not exercise market power abuses in a manner that advantages its generation affiliates, we will prohibit any contracts between the distribution utility and its affiliated generating companies.

d. Service to Direct Access Customers Returning to Utility Service

In this newly restructured industry, some customers will pursue retail contracts with suppliers or intermediaries while other customers will prefer that the utility continue to procure those supplies on their behalf. The UDC will retain its obligation for least-cost procurement for these utility service customers. The UDC's least-cost procurement obligations will be met by purchases through the Power Exchange.

The UDC also has an obligation to provide distribution services to all customers. The UDC will no longer be obligated to plan for or provide generation service to direct access customers.

With respect to the UDC's obligation to serve direct access customers who wish to return to utility service, we are faced with a recommendation contained in the MOU that makes a distinction between residential and non-residential direct access customers.

Nonresidential consumers wishing to return to UDC procurement service: A non-residential consumer who wishes to return to utility service may do so if the utility agrees to accept the nonresidential consumer back and offer service. The rates, terms, and conditions of the service offered the returning nonresidential consumer would be those agreed to by both parties to the negotiation and would be subject to Commission approval. Residential consumers wishing to return to UDC procurement service: For residential consumers who have procured their own power supplies but later wish to return, the UDC will have a tariff that sets forth the rates, terms, and conditions governing the service to which direct access customers could return. The UDC would, to the extent possible, base its "return tariff" on market prices for generation. The UDC would be required to offer the service thirty days after the returning residential consumer has formally notified the UDC of the desire to return. The UDC has the option of negotiating rates, terms, and conditions of return with a returning residential consumer, subject to Commission approval.

We have given these recommendations considerable thought and have decided to reject them. In a mature commodity market, customers daily exercise a right of free entry and exit. The UDC faced with an individual or entity wishing to return as a full service customer need only increase its purchases from the Exchange. Should it be objected that increased demand on the Exchange may occasion the dispatch of a bidder who otherwise would not have cleared the market with the consequence that the payments to all bidders are adjusted to that clearing price, we respond that this an inevitable experience with free markets.

2. Jurisdictional Issues Related to Direct Access

In addition to the federal/state jurisdictional issues of authority over unbundled retail transmission and the demarcation between transmission and distribution discussed above, retail competition also raises the issue of whether a state may order utilities to provide retail customers access to alternate suppliers. The direct access option also raises issues of reciprocity and supply of inexpensive power affecting surrounding states.

a. Authority to Order Direct Access

The attitude of California's three largest investor owned utilities appears to have eliminated the primary jurisdictional issue raised by retail competition, the question of state authority to order utilities to provide retail wheeling services. SCE is a joint sponsor of the MOU and although the recommended market structure may not have represented their preferences, both PG&E and SDG&E appear willing to accept it. We applaud the two non sponsoring utilities for their flexibility. We authorize the utilities to provide delivery services to direct access customers, under tariffs approved by both the FERC and this Commission, upon written agreement by the direct access customer to pay its share of retail stranded costs, as determined by this Commission.

b. Reciprocity

One of the chief objections to retail competition as outlined in the Blue Book was that out-of-state suppliers would have the opportunity to serve California retail customers directly and yet California entities would have no assurance of reciprocal competitive opportunities in neighboring jurisdictions. SCE is on record as suggesting that the FERC could approve a reciprocity provision in the California utilities' open-access transmission tariffs. ( Fn. 18) While we will not preclude a utility from making such a request such action would be without our blessing. The question of the pace and extent of market reform to be undertaken by our sister states is an issue which must be resolved by duly constituted governmental authority in those jurisdictions. We are content to invite the participation by out-of-state generators for it is our desire that the Exchange and the transmission grid be maximized in affording competitive entry into our markets.

There is, however, an issue of reciprocity which arises within California. We have previously acknowledged that we do not have the authority to impose our vision of a reformed and reregulated market on municipal or public power entities. Under legal mandates which we scrupulously respect the governance of these entities and their relation to their customers are committed to their duly constituted governing authorities. But we do have both a right and a responsibility to promote what some have termed a "level playing field" insofar as the well being of California's investor owned utilities are concerned. To this end, we will not require our jurisdictional utilities to tolerate the formation of physical bilateral contracts with customers within their service territories and California municipal or public power generation unless the entities which own that generation extend reciprocal rights to investor owned utilities with respect to their customers.

3. The Option of Real-Time and Time-of-Use Rates

Currently, ratepayers may not be aware of the fundamental fact that over a twenty-four hour period the demand for electricity varies dramatically. The consequence is that utilities invest in and ratepayers defray the cost of a system that must be built to meet peak demands that are generally experienced from two o'clock to six o'clock on any given afternoon. At all other times, the system is underutilized and investment is underproductive.

Most customers purchase electricity at a rate which represents the average cost of electricity. Some customers have the opportunity to purchase electricity at real-time or time-of-use (TOU) rates which allow them to see the price of electricity at specific time periods of the day so that they can alter their electricity use to less expensive time periods or off-peak hours in order to reduce their cost of electricity.

The May pool proposal recommended providing the choice of "virtual direct access" to all customers. Under this option, customers could purchase electricity on a rate scheme reflective of their usage in real-time or time-of-use increments, or alternatively, one which averaged the cost of electricity multiplied by the monthly consumption figure.

We affirm our belief that this billing option constitutes a valuable customer choice and note with pleasure its adoption as part of the restructuring effort in the Australian State of Victoria. With the Exchange publishing market-clearing prices for the various locations, jurisdictional utilities shall offer an optional tariffed electric service which references the appropriate real-time market-clearing price. (Fn. 19) The revelation of the real-time price of electricity coupled with a rate alternative that allows the customer to respond intelligently will produce savings for any customer who is able to shift demand from peak to off-peak hours. The potential that many customers will respond to this opportunity to take significant control over the cost of their consumption will produce a collective benefit, in that demand will be redistributed away from the current peaks. Future generation demands will be forestalled even as existing investments in generation are made more productive. The result is a triple win, embracing the individual consumer of any class who is able to reduce costs by shifting load, the society at large which defers the demand for new generation, and investors in existing plant and equipment who see it put to more productive use.

We direct that the utilities offer real-time rate and time-of-use rate options not later than January 1, 1998. The utilities should propose such an offering to a representative group of customers from all customer classes or to all customers.

a. Real Time Pricing and Time-of-Use Meter Service

We recognize that the availability of time-of-use or real-time pricing options, whether pursued in the context of virtual direct access billing election or direct access contracts, is inhibited by existing technologies and the availability of enabling technology which requires RTP or TOU meters.

We adopt a five year plan for installing the necessary meters for customers other than those who are categorized within the Domestic, GS-1, and TC-1 customer groups. Customers within these three categories will not be required to purchase or install such meters but may do so on a voluntary basis. (Fn. 20) Such a plan is consistent with our adoption of the MOU's phase in schedule for direct access. All utilities should have the same schedule for meter installation. With several significant exceptions, we adopt the following schedule based on maximum demand as a minimum requirement:

500 kW by 1998 when restructuring begins

400 kW one year after restructuring begins - at least by 1999

300 kW two years after restructuring begins - at least by 2000

200 kW three years after restructuring begins - at least by 2001

100 kW four years after restructuring begins - at least by 2002

All customers will be individually responsible for the cost of the meter installation, and can opt to pay for it on their bill in reasonable installments that avoid severe bill impacts or hardships.

Our schedule is not intended to prevent certain customers from enjoying the benefits of real time pricing with or without a financial hedging contract (such as a contract for differences), but rather provides an orderly approach to installation. Those customers who are not yet scheduled for utility meter installation may purchase and install such meters at their own expense, but would not be thereby become eligible for direct access any earlier than their scheduled year. (Fn. 21)

Our primary concern, is that our oversight of the utility includes the assurance that these services meet specific service, safety, and reliability standards. Therefore, we are requiring the investor owned utilities to install the new RTP or TOU meters. Assurances of these standards, in our view, must continue in a competitive market, although they may require our oversight responsibilities. Pending the adoption of performance specifications and protocols which assure the functional quality of such devices, the utility will continue to provide metering service for all utility service customers. We will refer to the Working Group the issues surrounding metering standards. They should also address the confidentiality of customer metering data. We will issue a ruling setting forth the workshop schedule and agenda.

4. Procedural Issues

PG&E, SCE and SDG&E should file their proposals for direct access in this docket within 30 days after the effective date of this decision. In their filings, the utilities should propose an eligibility schedule for both the initial phase of direct access and any subsequent phases. Proposals should reflect the principles for direct access and real-time and time-of-use rate options outlined in this decision. We note that these proposals will require coordination with proposals for the ISO as well as with the proceeding on unbundling of utility transmission and distribution functions.

5. Other Contractual Arrangements

At this time we wish to clearly affirm our encouragement of any contractual arrangements which may prove congenial to consenting traders who wish to manage risks associated with the revelation and realization of the market-clearing prices published by the Power Exchange. Such contracts are called contracts for differences (CFDs) and have been referred to by a variety of parties to our Rulemaking to describe the potential for private agreements that hedge the cost of electricity over time. Our support of contracts for differences is not intended to limit the dynamic of the marketplace in devising financial instruments for the purpose of assuring individual or group users that the economic consequences of their usage of electricity will not depend upon the vagaries of the market-clearing price revealed by the Exchange.

Because they would have an unfair advantage over other traders with regard to their own generation facilities, we prohibit the utilities from arranging CFDs with their own generation facilities and affiliated generation facilities. CFDs arranged by the utilities are subject to Commission review. All other nonutility CFD transactions are outside this Commission's purview.

E. Our Continued Regulation of PG&E, SCE and SDG&E

Our restructured industry would require PG&E, SCE and SDG&E to operate under the competitive forces of the market. To operate efficiently in this environment, participants must be responsive to rapid changes in the market. Existing cost-of-service regulation has become too complex and difficult in many ways to allow us to regulate the utilities properly in this fast-moving industry.

Our goal is to have an improved regulatory process that offers flexibility and encourages utilities to focus on their performance, reduce operational cost, increase service quality, and improve productivity. At the same time, we must ensure that safety, quality of service, and reliability are not compromised. There is broad but not universal consensus that Performance Based Ratemaking (PBR) can accomplish these objectives by providing clear signals to utility managers with respect to their business decisions and helping them make the transition from a tightly regulated structure to one that is more competitive. Under PBR, utility performance is measured against established benchmarks. Superior performance, above the benchmark, would receive financial rewards, and poor performance would result in financial penalties to the shareholders. By providing financial incentives to utilities, we will encourage them to operate more efficiently to maximize their profits.

In the Blue Book proposal, we stated our objective of replacing traditional cost-of-service regulation with PBR in areas where competition is not yet developed. Our objective was to seek new ways to reduce regulatory interference with management decisions and to allow utilities more flexibility in their day-to-day operations. We noted that although cost-of-service regulation has served our regulatory objectives reasonably well in past years, it is no longer compatible with the changing electric industry and is in need of reform. The high cost of electricity in our state compared to the rest of the nation, about 50% above the nation's average rate, gave us a clear indication that the current regulatory scheme was in need of change. Numerous parties to this proceeding have supported our objective of moving away from cost-of-service regulation. Most agree that significant productivity gains can be achieved in the utilities' operation by providing incentives to utilities to focus on their performance. Overall, the existence of an incentive, such as shareholders' financial rewards and penalties, could encourage utility managers to do a better job. The May proposals acknowledged our commitment to PBR and proposed to apply PBR treatment to the operation of utility generation and distribution assets.

Our proposal today reaffirms that commitment. Our policies continue our movement toward a regulatory environment that is based on encouraging efficient operation and improving productivity, rather than on reasonableness reviews and disallowances. In this decision, we emphasize the Commission's commitment to replace cost-of-service regulation with incentive mechanisms. An example of our commitment is the allowance of continuation of several PBR mechanisms that have been adopted on an experimental basis for various aspects of utility operations. In addition, we propose to replace cost-of-service regulation for other aspects of utility operations with PBR. These include utility distribution services and some of the utility-owned generation costs.

At this point, we lay out basic and key principles, consistent with the provisions of Assembly Concurrent Resolution 143, for various incentive mechanisms that would focus on capturing benefits for all electric customers who receive service from PG&E, SCE and SDG&E in our restructured industry. While these principles apply equally to the three utilities, we repeat our earlier assertion that each utility's unique circumstances should be considered in designing a detailed utility specific PBR mechanism. We ask the utilities to file, as set forth later in this discussion, applications to assist us in designing new PBR mechanisms to accommodate the new market structure, and we also ask them to provide comments regarding the impact of our decision on pending PBR applications.

Our proposal today unbundles traditional utility services into generation, transmission, and distribution functions. We propose to replace the traditional cost-of-service regulation with incentive regulation for those utility services that continue to remain under this Commission's oversight after industry restructuring has occurred. Under the new market structure, we see two areas of utility operation that require our continued regulatory oversight and where incentive regulation could appropriately replace cost-of-service regulation. These include utility distribution services and utility-owned generation. Below we describe each mechanism in more detail.

1. Utility Distribution Services

Under the current regulatory structure, utilities own and maintain the electric lines that distribute electricity to end-use customers in their service territories. Utilities are responsible for providing nondiscriminatory distribution services to all customers. In the restructured industry, they would continue their obligation to provide distribution services to all customers, including direct access customers, in their service territories. A distribution PBR would focus on utility performance with emphasis on providing nondiscriminatory access to all customers. It would also focus on ensuring that the utilities continue to provide quality distribution services and do not jeopardize service reliability or safety as it relates to distribution.

2. Utility-Owned Generation Assets During the Transition

Our proposal for a new industry requires that the utilities bid all their generation assets (with the exception of must-take power) into the Power Exchange until 2003. Our proposal also contemplates a five-year transition period during which some utility generation assets will remain under the ownership of the utility and our regulation, while others undergo a market valuation process and possibly a transfer of ownership.

During this interim period, we propose a generation PBR for some utility generation costs, consistent with our instructions for transition costs in Section V. A generation PBR would provide an incentive for the utilities to earn financial rewards for efficient operation of certain generation plants that are necessary for transmission stability.

a. Transfer or Sale of Utility Generating Assets

As described in Section V, the utilities' generating assets will undergo market valuation during a five year period starting on January 1, 1998. During this time, we will continue to have regulatory oversight of utility generation. The MOU appears to assume that market valuation of a generation asset terminates the dedication to public use that is a hallmark of public utility property. The MOU states, "Once a utility asset has been subject to a market valuation . . . , the asset will no longer be utility property subject to [PU] Code Section 851, and the owner will be free to market the power."

We find the MOU's statements about 851 to be incorrect. Section 851 has two paragraphs. The first requires the Commission's approval before a utility may "sell, lease, assign, mortgage, or otherwise dispose of or encumber the whole or any part of its . . . property necessary or useful in the performance of its duties to the public . . . ." The second allows the sale or disposition, without the Commission's prior approval, of "utility property which is not necessary or useful in the performance of [the utility's] duties to the public . . . ." Utility property, such as a generation asset, that has received revenue recovery through rates, is presumed to be used and useful in the performance of the utility's duties to the public. The mere act of undergoing market valuation does not alter that presumption. If the market valuation is undertaken as part of the spinning-off of the generation asset, of course, the Commission would be asked to make the determination required under the first paragraph of 851. Our point is that it is the Commission's determination that utility property is not "necessary or useful" in the performance of the utility's duties to the public, and not the act of market valuation, that releases the property from its dedication to public use.

We therefore emphasize that PG&E, SCE and SDG&E must comply with 851. We also note that utilities' compliance provides this Commission with an opportunity to review and be satisfied that the market valuation process for any given asset was fair and equitable.

3. Procedural Issues

Before the new market structure is implemented, we will continue our regulation of utility generation, transmission and distribution services. During this period, we will allow existing utility PBR programs, specifically SDG&E's base rate and generation and dispatch (G&D) mechanisms, (Fn. 22) to continue, as approved, until transition to a new restructured electric industry has taken place. SDG&E may use existing PBR dockets to request reforms to its PBR needed by 1998.

SCE and PG&E (Fn. 23) filed PBR applications prior to the issuance of the industry restructure. In the case of SCE's transmission and distribution PBR application the Commission has started the review process by holding hearings. We believe the parties, the utility, and our staff have put valuable effort into reviewing SCE's proposal. Therefore, we ask SCE and interested parties to file comments in A. 93-12-029, addressing whether SCE's pending proposal should be amended or reviewed as originally filed. In addition, SCE has filed A.94-01-016, requesting a Gas Cost Incentive Program for certain gas purchases. We direct the parties to file comments regarding this application addressing how this mechanism could be affected by our decision today. Specifically, we ask that the comments include any necessary changes to SCE's pending applications given the outcome of this decision. The Commission has not started its review of PG&E's PBR application A.94-03-008, and PG&E has indicated an intent to amend that application following this decision. We ask parties to file comments in that proceeding addressing whether PG&E's pending application should be amended.

Finally, in submitting their comments for A.93-12-029, A. 94-01-016, and A.94-03-008, we ask the parties to keep in mind that because utility distribution activities will continue to be subject to regulation after the industry restructure, the PBR mechanisms that would be in effect during the interim should be crafted with flexibility to accommodate the changes of the restructured industry. We direct that all comments be filed no later than 30 days from the effective date of this decision. Additionally, PG&E, SCE and SDG&E shall file, no later than 60 days from the effective date of this decision, separate applications for new PBRs for utility distribution and utility-owned generation services consistent with the principles set forth in this decision and in particular Section V.


1 Unless otherwise indicated, all statutory references in this decision are to the Public Utilities Code.

2. Notice of Proposed Rulemaking and Supplemental Notice of Proposed Rulemaking, Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities (Docket No. RM95-8-000); Recovery of Stranded Costs by Public Utilities and Transmitting Utilities (Docket No. RM94-7-001), 60 Fed.Reg. 17662 (April 7, 1995) IV FERC Stats & Regs 32, 514 (1995) [hereinafter referred to as the "MegaNOPR"].

3. The distinction between procurement and provision is critical in identifying what can be unbundled and treated as a competitive service left to individual choice. For example, spinning reserve can be purchased from many sources on a competitive basis, but it may not be possible to separately identify the individual customer uses of spinning reserve. In this case the ISO would pay suppliers the competitive price for spinning reserve and charge all users an allocated share of the total cost of spinning reserve.

4. Must take supplies include all grand fathered generation contracts, including QF's, and nuclear facilities.

5. Implementation of this locational pricing mechanism could embrace a simple "hub-and-spoke" system. The ISO would identify a number of critical locations to serve as system hubs that would be the focal points for pricing and transmission information. All users would incur the necessary transmission charge to move power to or from their nearest hub. Movements of power over longer distances would be on the basis of the differences in the locational prices at the respective hubs.

6. Paul Joskow comments filed on October 23, 1995 to the Coordinating Commissioner's Ruling issued October 12, 1995. (Emphasis in original.)

7. We have the advantage of this innovative approach to transmission through the comments of many parties. One description generally consistent with the approach we recommend can be found in the comments of SDG&E in the FERC Mega NOPR.

8. Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Notice of Proposed Rulemaking, 59 FR 35274 (July 11, 1994), IV FERC Stats. & Regs., Proposed Regulations 32,507.

9. MegaNOPR at 285, n.395.

10. Vesting the Power Exchange with this function involves operation of the pooling mechanism and will require FERC approval. This being said, we see no impediment in federal law to a state commission order requiring investor-owned utilities to use the federally approved Power Exchange as a market mechanism to dispatch electricity generated from assets currently in retail ratebase and subject to the exclusive jurisdiction of the state. Such an order would be well within our authority over the retail electric utility franchise and state electric resource planning.

11. In the hub-and-spoke implementation, the spot price would be the nearest hub price with a transmission charge to move between the customer location and the hub.

12. It is worthy of emphasis that from the perspective of end users no Californian is obliged to depend upon the Power Exchange to set the economic terms of their consumption. Even those who elect to remain as full service customers of the distribution utility are free to engage in contracts for differences with any person or entity who will guarantee a cost structure wholly independent of the clearing price realized by generators who have bid into the Exchange. Even more dramatically, eligible end users can sever themselves from the Exchange and the procurement services of the distribution utility by forming, directly or through a middle-person, a direct access contract so as to shift their load to generation which will be nominated directly into the ISO. So from the buyer's perspective the Power Exchange is a voluntary, optional market institution on day one.

13. Auseful analogy may be made to state and federal laws respecting the issuance of new securities. The integrity of the markets has long been recognized as the key to widespread investor participation and this is particularly true of small investors who lack the means or opportunities to gain access to non-public information. The Securities Act of 1933, 15 U.S.C. 78a et seq. imposes a registration requirement on issuers, underwriters and dealers with respect to new securities. As described by the Securities and Exchange Commission, this registration requirement is intended ". . .to provide adequate and accurate disclosure of material facts concerning the company and the securities it proposes to sell. Thus, investors may make a realistic appraisal of the merits and the securities and then exercise informed judgment in determining whether or not to purchase them." Securities and Exchange Commission, The Work of the SEC 5-8 (1986). The exemptions from the registration requirement are predicated upon a demonstration of sufficient investor sophistication and access to information as to no longer warrant this initial protection.

14. Over time, as transition costs are eliminated and excess capacity diminishes, the clearing price for the electricity commodity will gradually reflect a value for capacity.

15. See Comments of CMA, July 21, 1995.

16. See Section VIII for our discussion of regulatory oversight and consumer protection with respect to supply intermediaries, e.g., marketers and brokers.

17. DRA comments to the MOU, filed October 2, 1995.

18. See, e.g., SCE's Brief, January 31, 1995, p. 70.

19. While efficiency gains would be achieved by requiring that TOU and real-time rates be mandatory, it is our present intention to make them optional. A customer would be given the choice of a rate scheme which reflected usage of electricity in real time or one which averaged the cost of electricity multiplied by the monthly consumption figure.

20. Full service customers who desire to avail themselves of the virtual direct access billing option will have to install an appropriate meter and may elect to pay for it in a lump sum or have the cost deferred over monthly installments added to their bill from the distribution utility. If a customer from an otherwise exempt customer group elects to participate in direct access it will be necessary to arrange for the installation and use of appropriate metering equipment if required by the terms of the direct access contract.

21. So long as the meters installed meet the metering standards (technical specifications) of the distribution utility, customers could have meters installed by others (e.g., suppliers, aggregators, or meter vendors). One means of facilitating this option would be for distribution utilities to develop approved vendor lists once the standards are established.

22. The Commission approved a base rate PBR for SDG&E in D.94-08-023 and a G&D mechanism in D.93-06-092.

23. SCE's Application, A.93-12-029 and PG&E's Application, A.94-03-008 for a Regulatory Reform Initiative

  

Last Modified: 10/17/2007


 
 
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