Because the restructuring of California's electric services industry has widespread impact and the market structure requires the participation and oversight of the Federal Energy Regulatory Commission, the Commission seeks the building of a California consensus involving the Legislature, the Governor, public and municipal utilities, and customers. This consensus would then be placed before FERC and, with a spirit of cooperative federalism, both agencies would move forward to implement the new market structure no later than January 1, 1998.
In order to provide competing power producers the equal opportunity and ability to deliver their supplies, the Commission adopts the establishment of an independent, statewide transmission system operator. The utilities while retaining ownership of their transmission facilities, will be required to transfer operational control of the facilities to this independent system operator (ISO). The creation of an independent operator will also increase efficiency as it will combine the now separate control functions of three utilities into one entity.
The ISO will control and operate the state's transmission system which includes scheduling the delivery of electric power supplies, ensuring that actual demand is met with sufficient power supplies and that all standards for transmission service are satisfied as well as communicating any problems in delivering power supply to the appropriate parties.
The Commission sets forth operating principles for the ISO which includes that the ISO should have no financial interest in the source of generation. The ISO's independence from and indifference to the source of electricity generation is critical to ensuring nondiscriminatory access to the transmission system.
Because the Federal Energy Regulatory Commission (FERC) has jurisdictional authority over transmission systems, the establishment of the ISO must be approved by FERC. Therefore, the utilities will work with each other and interested parties to construct a proposal for the creation of the ISO to FERC in 130 days. The Commission also requests proposals for ownership and organizational structure of the ISO to be included in the proposal.
This Power Exchange will provide a market for electric power with hourly or half-hourly prices published to electric consumers and other industry participants such as investors or power marketers. With visible price signals wholesale and retail buyers have the ability to make efficient purchasing decisions and to adjust their electric consumption by shifting usage to periods where demand is not as high and thus, power is cheaper.
The Power Exchange will allow power producers to compete on common grounds using transparent rules for bidding into the Exchange. The Power Exchange will then match the bids with bids submitted by utilities, power marketers, brokers or others on behalf of end-use customers, ranking the least-cost bids according to yet-to-be-determined protocols. The Power Exchange will then submit its delivery schedule to the ISO for integration with other schedules submitted under different arrangements.
As with the ISO, the CPUC adopts operating principles for the Power Exchange which includes that the Power Exchange be an independent entity with no financial interest in any source of generation to ensure against discriminatory treatment. The Power Exchange will also be separate from the ISO.
Purchasing from and selling to the Power Exchange is voluntary except for the investor-owned utilities who will bid all their generation output in to the Exchange and purchase all of their requirements to serve full service customers from the Exchange. It is anticipated that California's municipal utilities, independent power producers and out-of-state producers will recognize the economic benefits of selling into the Exchange while municipal utilities, retail aggregators and individual customers as purchasers will find benefit in purchasing from the Exchange.
The utilities will work with each other as well as with interested parties to form a proposal for the creation of the Power Exchange. This proposal will be presented before FERC in 130 days. The Commission also requests proposals for ownership and organizational structure of the Power Exchange to be included in the proposal.
Utilities will continue to have direct control and operation of their distribution system, power production, and procurement of generation services for their full service customers. They will also continue to own, but not operate, their transmission facilities. 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.
The utility will have the obligation to provide distribution service to all customers, and provide least-cost generation service to those customers who do not choose or are not eligible for the Direct Access option.
The CPUC will continue to regulate the rates, terms and conditions of these services. However, the CPUC will reform the way in which it regulates these remaining monopoly services and move away from "cost of service" regulation to Performance Based Ratemaking (PBR). Under PBR, the utilities will have greater flexibility in running their operations, and their shareholders will have a chance to participate in the efficiencies gained or absorb the effects of poor performance. PBRs should improve the quality of service and encourage innovation.
Currently, the majority of California electric consumers buy their electric service from the three largest electric utilities. Generally, this service is provided on a bundled basis meaning that customers pay a single price for electric service including the generation, transmission, and distribution of power.
The CPUC's new market structure provides three avenues for customer choice.
The first avenue for customer choice resides in the increased availability of time-of-use rates. Customers who have time-of-use meters will be able to access pricing information and modify their consumption of electricity accordingly. This allows customers to shift their consumption during high peak demand hours to off-peak hours and receive related cost-savings. Customers will be responsible for the cost of the meter and its installation.
A second avenue under this new market structure, consumers will have the opportunity to negotiate directly with generation providers then arrange for transmission of that power supply with an independent operator of the transmission system. Utilities will continue to operate the distribution system and would provide for delivery. This service option is termed Direct Access because consumers can "directly access" and reap the benefits from a competitive generation market.
A customer may choose to arrange Direct Access contracts or make arrangements with a marketer or broker to negotiate on the customer's behalf.
A first phase of Direct Access will begin no later than January 1, 1998, simultaneous with the implementation of other critical elements to this new market structure. This initial phase will last for twelve months after which there will be no limit on participation in Direct Access service, except for technical constraints. A minimum phase in schedule is provided to ensure all customers have Direct Access no later than 2003.
In this initial phase, a representative number of customers from all customer groups (residential, commercial, industrial and agricultural) will be eligible for participation in Direct Access. The Commission notes that an 8 megawatt limit for aggregation based on peak billing demand is reasonable, but asks the utilities and other parties to recommend additional eligibility parameters.
Notably, small commercial and residential customers will be allowed to combine their peak demand in order to qualify for eligibility.
Those customers who do not choose Direct Access may continue to have the utility purchase generation service simply by keeping their present bundled service.
A five year plan for installing real-time and time-of-use meters for all customers, with exceptions for residential customers, is adopted. Residential customers will not be required to install or purchase such meters, but may do so on a voluntary basis.
The third avenue for customer choice is the opportunity to arrange contracts which manage risks associated with the market clearing prices published by the Power Exchange. Such contracts allow customers to hedge the cost of electricity over time.
The CPUC concludes that market power problems almost certainly will require the existing investor-owned utilities to divest themselves of a substantial portion of their generating assets.
PG&E, SCE and SDG&E are to submit written comments 90 days after the effective date of this decision, on the feasibility, timing and consequences of a corporate restructuring to distinguish utility activities with respect to generation, transmission and distribution, for example, a holding company with three subsidiaries.
Within 90 days of the effective date of this order, PG&E and SCE will file plans to voluntarily divest themselves through spin off or sale to a non-affiliated entity of at least 50% of their fossil generating assets. Incentives are established to encourage divestiture of at least 50% of utility fossil-fueled units.
Until the market structure is fully implemented, all transition costs have been collected, and all customers have direct access, a distribution utility affiliated with a generation company will be prohibited from entering into contracts with an affiliated generator.
In order to prevent utilities from using strategically located assets to manipulate Power Exchange prices in transmission constrained areas, recovery of operating costs is limited to the time prior to establishment of market based rates for reactive power/voltage control or until the unit is market valued (no later than 2003); this limitation will also assist in preventing cross-subsidization.
In a competitive market, utility access to customer information provides a valuable marketing advantage; all suppliers, including the utility, will be required to obtain customer consent for release of billing data on terms that are fair to all competitors in the generation sector.
Rates for customers taking bundled utility service will be capped at the levels established by our January 1, 1996 revenue requirements, without adjustment for inflation, but a portion of the rate will be recovered through a non-bypassable charge called the competition transition charge (CTC). This charge will apply to all customers who take retail service as of the date of this decision or who begin utility service after this decision, whether a customer chooses to receive bundled utility service or select a new electricity provider. The utilities are required to modify their Preliminary Statements to provide notice of the intent to collect retail transition costs.
The CTC is the ratemaking mechanism to recover utility costs identified as transition costs-- the difference between assets whose book values exceed market costs and the identified market value. The benefits of assets whose market value exceeds book value will be used to reduce transition costs. This offset is a way of compensating ratepayers for the loss of continued dedication to public use of these assets.
Utilizing market mechanisms to minimize transition costs, utilities will be allowed the opportunity for full recovery of the transition costs associated with existing power contracts and prior regulatory commitments, as well as accelerated recovery of net book value of undepreciated generation assets combined with a reduced cost of capital.
Utility assets will be required to undergo market valuation by 2003 for inclusion in the transition cost balancing account, and collection will be completed by 2005, except for costs related to ongoing payments for existing contracts. The utility may sell or spin off assets or have them independently appraised and retain ownership to arrive at a market value.
Existing utility contracts with QFs and wholesale providers will be honored, and this power will be taken by the grid consistent with contractual requirements. Transition costs will be calculated as the difference between contractual prices and the Power Exchange price. Qualifying facility short run avoided energy prices will be set at Power Exchange prices.
The adopted recovery mechanism reduces the return on investment-related transition costs, reflecting the reduced degree of risk utilities face in recovering these costs, to ensure that ratepayers benefit and utilities have proper incentives to minimize transition costs. For investment-related transition costs entered into the transition cost balancing account, the embedded cost of debt for the debt portion and 90% of the embedded cost of debt on the equity portion are adopted as reasonable returns.
Within 100 days from the effective date of this decision, PG&E will file an application with a proposal for ratemaking treatment for the Diablo Canyon facility that would price its output at market rates by 2003. SCE is directed to file a ratemaking proposal for Palo Verde within 45 days.
Renegotiation of existing QF contracts is encouraged by allowing shareholders to retain 10% of the net ratepayer benefits resulting from renegotiation.
For fossil-fueled units, 100% of book value (including related contract obligations) is recoverable in the CTC, with all operating costs to be recovered from the market. Utilities are given some opportunity for profit, and allowed limited inclusion of operating costs of necessary for transmission stability.
For hydroelectric and geothermal units, all costs are eligible for CTC recovery, and PBR will be established.
The CPUC recommends that a minimum renewables purchase requirement is the best approach to meet our resource diversity goals. Credits for meeting this requirement would be tradeable and a meaningful penalty for non-compliance would be established. The Working Group is called on to provide the CPUC with additional guidance about the level of the renewables requirement and other implementation details.
The CPUC suggests that the Legislature adopt a nonbypassable "public goods charge" on retail sales to fund public goods research, development, and demonstration and energy efficiency activities. Funding should focus on activities not provided by the competitive market that are in the broader public interest. A specified percentage cap or funding level for the charge are not adopted, but these details as well as an independent administrator of the funds will be considered during the implementation phase. Funding for research in support of regulated utility functions properly remains part of regulated rates and should not be collected as part of the public goods charge.
All electric service providers under CPUC jurisdiction will be required to offer eligible customers baseline rates consistent with 739 and a subsequent ruling will be issued to receive information on how to effectively implement baseline rates under the market structure adopted today.
The CPUC will support legislation authorizing a nonbypassable surcharge, separate from the public goods charge, to collect funding for low-income rate assistance and efficiency programs. Funding for low-income rate assistance should not be capped at current levels but should instead be based on need; funding for low-income efficiency services should be based on a more detailed analysis of the need for these services.
The Women, Minority, Disabled Veteran Business Enterprises statutes and General Order 156 will continue to be applied unless and until the CPUC receives other direction from the Legislature. Procurement by regulated utilities, with the exception of procurement outside the Power Exchange, should be subject to these goals, just as fuel procurement is today. Compliance costs will not be separately identified on customer bills but will continue to be collected within regulated rates.
The Legislature is encouraged to consider whether continuation of utility funding for economic development programs is consistent with a competitive marketplace in the long term; in the interim, these costs should be identified as a line item on customer bills.
Once restructuring is in place, utilities will not be able to pass the costs of rate discounts onto ratepayers, instead shareholders must fund any rate discounts.
Funding for low emission vehicle costs were decided as part of I.91-10-029; these costs should be collected as part of regulated rates and identified as a line item, but will not be part of the public goods charge.
Undergrounding activity remains an appropriate activity of the regulated utility, not subject to competition, and therefore should continue to be collected as part of regulated rates.
The policy adopted today may potentially impact the environment in a number of ways including the reduction of opportunities for energy efficiency incentives and shifting energy production.
Due to this potential for significant environmental impacts, the CPUC directs the preparation of an Environmental Impact Report as set forth under the California Environmental Quality Act (CEQA). This report will present the analysis of the environmental impacts of the CPUC's adopted electric restructure policy, compare environmental effects of alternative policies and, if necessary, identify mitigation measures for any potentially significant impacts.
The CPUC has directed its staff to begin the process of hiring a qualified professional environmental consultant to prepare the EIR.
Each of the utilities will reimburse the CPUC for all costs associated with the preparation of the EIR.
In order to provide the California Legislature with the opportunity to examine the CPUC's policies, implementation will begin 100 days after the effective date of the this decision.
A consolidated procedural approach will also be formed during this 100 day period once the CPUC has developed a "roadmap" for process steps. This roadmap which will lay out a process for restructuring the electric services industry based on the policies promulgated in this decision is expected to be issued for comment in the next 45 days.
The roadmap will set forth a process for managing the issues which will be broadly grouped into four areas each of which will have an assigned commissioner and a staff team. The coordination and oversight of these four issue areas will be the responsibility of a managing commissioner.
As the market the CPUC wishes to foster evolves, so too will the CPUC's role and responsibilities. The CPUC expects to continue to pursue the public interest by monitoring the transition to the restructured industry, undertaking intervention when it is necessary.
It also will continue and expand our role of providing consumer protection and information, and to provide a forum for resolution of customers' complaints about all aspects of electric service. In order to help customers make informed choices, the CPUC expects to conduct customer education, with special attention to ensuring that customers, especially those with limited English-speaking ability or other disadvantages receive correct, reliable and easily understood information. The CPUC's approach to customer education will be more fully discussed in the procedural roadmap.
It will act to see that fairness prevails in the competitive markets established by this decision and that the conditions necessary for fair competition are present.