1. Performance based ratemaking (PBR) promotes desirable utility behavior by rewarding efficient performance.
2. The real-time and time-of-use rate options give customers the ability to reduce their electric bills by shifting their consumption of electricity to off-peak periods when prices are lower.
3. Vertically integrated utilities own and control a majority of generation, transmission, and distribution assets serving the California market.
4. The establishment of an independent system operator (ISO) lessens the potential for owners of the transmission system to favor their own generation facilities over nonutility facilities in providing transmission access.
5. Separation of the ISO and the Power Exchange:
- prevents 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;
- provides transparent information about system operations and congestion;
- aids in eliminating any perception of discriminatory decision making;
- eliminates the perception and the real possibility that the ISO could gain financially by preferring one supplier over another in dispatching generation and scheduling transmission.
6. The mechanisms and protocols for the ISO and Exchange that we suggest demonstrate that our policy goals are attainable, but do not forestall other suggestions or means that achieve the same goals.
7. In California there exist transmission bottlenecks or constraints that might affect the choice of which generators will actually be dispatched.
8. Pricing actual transmission usage at the difference in the locational marginal costs determines fair and efficient use of available transmission without cost-shifting.
9. Transparent information flow is critical to ensuring equal access to transmission capacity.
10. From the perspective of end users, participation in the Exchange is voluntary as soon as the Exchange begins.
11. 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.
12. During the transition period, the participation of the jurisdictional utilities in the Power Exchange will lessen regulatory burdens associated with assets that are non-competitive in a transparent market, ensure that customers that rely upon the distribution utility for procurement receive the benefits of competitive market prices, and provides sufficient depth to the Exchange that its market signals may be relied upon as benchmarks for customer choices.
13. Contracts for differences are private agreements that allow the buyer and seller to allocate the risks associated with market uncertainty and are a way for the customer to hedge the cost of electricity over time.
14. Allowing the aggregation as well as the individual participation of small commercial and residential customers is vital to ensuring that all consumers have the opportunity to participate and benefit from consumer choice.
15. If customer information is provided exclusively to the utility-affiliated generating company, it could give that company an unfair advantage over other competitors.
16. Over a twenty-four hour period the demand for electricity varies dramatically.
17. The revelation of the real-time price of electricity coupled with a rate alternative that allows the customer who is able to respond intelligently will produce savings for any customer who is able to shift demand from peak to off-peak hours and 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.
18. Transparent, reliable price signals will be very important to foster a competitive market during the transition period because customers and suppliers will develop sophistication over time and alternative resources for price information will develop over time.
19. 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. Cost-of-service regulation is no longer compatible with the changing electric industry and is in need of reform.
20. PBR offers flexibility and encourages utilities to focus on their performance, reduce operational cost, increase service quality, and improve productivity. PBR mechanisms should be designed to ensure that safety, quality of service, and reliability are not compromised.
21. By providing financial incentives to utilities through PBR, we will encourage them to operate more efficiently to maximize their profits.
22. The cost of electricity in our state is about 50% above the nation's average rate.
23. Competition in the electricity market will deliver desirable market characteristics that have not been delivered by the regulated market regime of the past.
24. The abuse of market power reduces the societal efficiencies of competition.
25. A competitive market mitigates market power abuse by means of contestibility.
26. A market structure that brings generation competitors into the market and eliminates barriers to entry will reinforce industry contestibility.
27. Control of vertically integrated assets results in barriers to entry if an entity at one stage of the production and delivery process gives preferential treatment to an affiliated entity operating at another stage of the production and delivery process.
28. Provision for an ISO and independent dispatch results in an operational unbundling, in which vertically integrated electric processes are separated and operational control is spread among entities that are independent of the owners of assets in other levels of the chain of production.
29. Utility control of both energy procurement and generation functions might result in vertical market power.
30. Market power can take place at any level of the production chain if there are significant barriers to entry or few market participants.
31. Concentrations of ownership or control of generation facilities can result in market power because a single competitor might control enough assets to alter the supply-demand equilibrium and thus be able to increase prices by withholding generation from the market (decreasing supply).
32. The most direct approach to mitigating market power resulting from concentrations of generating facility ownership is disaggregation of concentrated assets.
33. In an environment where utilities participate in both the regulated and unregulated sides of an industry, a utility might attempt to use funds from its stable and profitable regulated business to gain an advantage in its unregulated businesses through cross-subsidies.
34. Disaggregation is the most effective way to prevent cross-subsidies.
35. Divestiture of the utility's competitive generation assets from its regulated assets is the only structural option which will completely eliminate the utility's ability to engage in improper cross-subsidization.
36. The existence of strategically located assets creates a threat of market power that cannot be mitigated by disaggregation.
37. Net book value means the original cost recorded in the company's books for a particular asset less any accumulated depreciation and adjusted for deferred taxes, and any other asset or liability account which relates to the asset.
38. Many of the high costs of today's electricity result from past regulatory promises made by the Commission regarding the timing of the recovery of depreciation and taxes, past requirements to diversify sources of power by signing long-term contracts that in hindsight have high costs, and the costs incurred by utilities that were reviewed and deemed reasonable when incurred.
39. The competitive market will classify utility generation assets as either economic or uneconomic.
40. A utility asset is uneconomic if its net book value exceeds its market value, and an asset is economic if its market value exceeds its net book value.
41. For a particular utility, its transition costs are the net above-market costs associated with its assets, both economic and uneconomic.
42. Transition costs arise when a plant is unsuccessful in its bid to supply power through the Power Exchange, because if it is unable to sell its power, it has no opportunity to recover its fixed investment costs. Even if a plant is a successful bidder into the Power Exchange, transition costs will also accrue if the market-clearing price paid to successful bidders is too low to allow recovery of the plant's fixed costs.
43. To the extent Diablo Canyon settlement prices are above the prices in the market, as revealed by the Power Exchange, this plant will be uneconomic.
44. QF contract prices may be above the Power Exchange's revealed market prices, and thus the contract will be uneconomic.
45. Prices under utilities' contracts with wholesale providers may be higher or lower than the market price. These contracts may either be uneconomic, increasing transition costs, or economic and available to offset other uneconomic costs.
46. The premium associated with economic assets should be offset against the excess costs of uneconomic assets to reduce the overall level of the utility's transitions costs.
47. Under the current regulatory structure, ratepayers have prepaid income taxes associated with some generation assets.
48. Under the current regulatory structure, we have granted utilities monopoly franchises to provide electricity to the consumers in their service territories, and we have required utilities to provide reliable service on a nondiscriminatory basis to all customers within their territories who requested service. In fulfillment of these responsibilities, utilities developed a portfolio of generation assets by investing in power plants and entering into purchase agreements.
49. Maintaining the financial integrity of the utilities is an important goal of this proceeding.
50. If we do not provide for adequate transition cost recovery, the move to competition may threaten the utilities' financial stability.
51. Assurance of full recovery gives the utility no incentive to minimize transition costs.
52. If the utility is indifferent to the level of transition costs, it would in turn have an incentive to bid low in offering its generation assets' output to buyers in the Power Exchange, with the foreseeable effects of depressing the market-clearing price, squeezing the profit margins of competitors, and further increasing transition costs.
53. Recovery of the transition costs significantly lowers a utility's risk of recovery, because once an asset is market-valued, the utilities will not be subject to the risk that the plants will be found no longer to be used and useful.
54. Applying a reduced rate of return to transaction costs benefits ratepayers because it reduces the transition cost revenues associated with generation plants from the levels that ratepayers would otherwise pay in rates under cost-of-service ratemaking and reduced revenues will also reduce taxes that would otherwise be reflected in rates.
55. By lowering the return on transition costs, we will create an incentive for the utility to minimize transition costs and avoid the undesired consequences associated with full cost recovery.
56. Rate reductions continue to be a primary goal of this proceeding.
57. The rate impacts of transition cost recovery can be mitigated somewhat by a policy of capping rates at the level in effect as of January 1, 1996, without adjustment for inflation.
58. Reducing the return on investment-related transition costs will provide utility management with an incentive to minimize the level of transition costs, and as a result to reduce rates.
59. A market-based approach to calculating transition costs associated with utility assets will produce superior results to an administrative approach.
60. The market value for a sale or spinoff of an asset may be calculated by the sale price, or the stock market value of shares issued to effect a spinoff.
61. Both QFs and utilities may have an incentive to renegotiate their contracts.
62. An approach that involves both a monetary incentive to shareholders and conditions which foster voluntary, nonstandard negotiations will promote renegotiation of QF contracts.
63. The transition costs that arise from regulatory obligations are related to various deferred costs and outstanding balancing account balances the utility has accrued under cost-of-service regulation.
64. If the utility retains ownership of the nuclear facilities after market valuation, it should recover the costs for the decommissioning trust fund.
65. Market valuation of assets through an appraisal approach will provide results superior to an administrative approach because the appraisal approach relies on independent industry experts rather than experts hired to support each party's position, as is common in regulatory proceedings.
66. Concentration of generation ownership in utilities remains a serious unmitigated market power concern.
67. In the MegaNOPR, the FERC proposed that utilities be entitled to recover legitimate and verifiable stranded costs from increased competition in and entry to the wholesale market.
68. Different utilities will have different transaction costs.
69. The recovery of transaction costs should apply to sales to both direct access and utility service customers on a utility service territory basis.
70. Transition costs should be allocated to all customer classes using an equal percentage of marginal cost (EPMC) methodology, unless specific circumstances justify a different approach.
71. Transition cost recovery should not increase the price for electricity, on a kWh basis, above current rate levels in effect as of January 1, 1996, without adjustment for inflation.
72. California's electric utilities have a long history of participating in activities that assist many California citizens.
73. The continued reliance on utilities to achieve social goals may put the utility at a disadvantage in the move toward a more market-based, customer-oriented electric services industry. Subjecting utilities to the cost of programs that their competitors do not bear is not a sustainable strategy.
74. The present mix of renewables on the system has been driven by resource diversity interests on the part of utilities and the Commission's QF policy, which encouraged the growth of independent power production during the 1980s.
75. The Commission's recent policy of encouraging resource diversity through the development of new renewable resources is derived from 701.1 and 701.3.
76. A program of tradeable credits for meeting a minimum renewables purchase requirement will allow buyers and sellers to search the market for the best renewables bargains and to internalize such costs in their prices without the need for a surcharge to fund renewables development.
77. Tradeable credits for meeting a minimum renewables purchase requirement allow retail providers the most flexibility in meeting this requirement.
78. In a restructured environment, evaluating cost-effectiveness on the basis of utility resource deferral may no longer be relevant.
79. Electric utility RD&D programs today support both regulated business functions and public purpose goals.
80. After restructuring, a utility will still have a need to conduct research to support its continuing monopoly functions.
81. Research that serves a broader public interest and that may not be pursued by the monopoly should not be lost in the transition to a more competitive environment.
82. Low-income assistance has limited rate impact.
83. To implement 8281 et seq., General Order (GO) 156 initiated the WMDVBE program in 1987, and established goals for regulated utilities' procurement practices. The goals encourage awards of not less than 15% of all contracts for goods and services to minority-owned businesses and not less than 5% to women-owned businesses. Following a 1990 amendment to the Public Utilities Code, GO 156 was expanded to include disabled veteran-owned businesses.
84. In PG&E's recent Rate Design Window proceeding, we adopted PG&E's proposal that until there is direct access, costs associated with rate discounts should be split between ratepayers and shareholders; once restructuring is in place, 100% of the costs will be borne by shareholders (D.95-10-033).
85. The existence of ERAM gives a utility little incentive to rigorously negotiate the smallest discount necessary to retain a specific customer, because ratepayers effectively compensate the utility for the amount of the discount.
86. Section 740.2 requires the Commission to encourage energy utilities to conduct research on electric and natural gas vehicles, and 740.3 requires the Commission to implement policies to promote and facilitate development of equipment and infrastructure for low-emission vehicles. Section 740.3 also provides for the recovery in rates of costs incurred in the ratepayers' interest.
87. Utility customers, unlike nonutility customers, are able to benefit from LEV expenditures directly through their eligibility for utility LEV programs.
88. Undergrounding is carried out by the utilities under a tariffed program.
89. Undergrounding is a program that the cities and counties of California rely upon as part of their local improvement efforts.
90. In the absence of a finding that a project is exempt, the California Environmental Quality Act requires state agencies to evaluate the environmental impacts of any discretionary project they approve. Further, if an agency determines that a project may have a significant effect on the environment, it must prepare an Environmental Impact Report (EIR).
91. Consumers have been particularly vulnerable to fraud in other newly deregulated industries.
Conclusions of Law
1. Our goals in this proceeding are:
- to offer consumers greater choice in their purchases of energy services.
- to allow competition for traditional monopoly services to flourish where conditions are ripe.
- to transform our oversight of industry segments that are not subject to competitive pressures to performance-based ratemaking.
- to reduce the price California consumers pay for electricity.
- to continue to deliver safe, reliable, and environmentally sensitive energy services.
- to maintain universal, nondiscriminatory availability of electric services to all citizens of this state.
- to maintain the financial integrity of the utilities and provide utilities with a reasonable opportunity to earn a fair return on their investments.
- to continue to further the public good, as perceived by the Legislature and this Commission, by improving the environment, encouraging the diversity of energy sources, and maintaining a variety of important public purpose programs.
2. In obtaining generation services, consumers should be able to choose:
- to contract for generation services, on whatever terms both parties find acceptable, directly with generators or marketers of generation services.
- to aggregate their load with others' to increase their purchasing power.
- to continue to receive generation services from the utility and pay either average cost-based rates or rates based on the prices of the Power Exchange.
3. 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.
4. The FERC must approve the rates, terms and conditions of transmission services provided by the ISO.
5. The vertically integrated electric utility is not compatible with the institutions of a competitive market for electric services. It is necessary to disaggregate the vertically integrated electric utility by separating the elements of generation, transmission and distribution.
6. The functions of the ISO and the Power Exhange should be vested in separate entities, wholly independent of one another.
7. The ISO shall have no financial interest in any source of generation or load, no ownership affiliation with any companies that own those facilities, and no financial interest in the Power Exchange.
8. The ISO shall have the following responsibilities and functions:
- to control the operation of the transmission facilities, oversee transmission activities, and be responsible for providing efficient, reliable service.
- to coordinate day-ahead scheduling and balancing for all users of the transmission grid.
- to provide open and nondiscriminatory access to the transmission grid.
- to determine marginal cost prices, differentiated by location and time, that will apply for purposes of transmission pricing and managing congestion to all users of the transmission system.
- to administer a system of transmission congestion contracts.
- to procure ancillary services needed to support transmission and dispatch.
- to provide comparable service to all users of the transmission system.
- to honor existing transmission contracts.
- to submit protocols to the FERC for transmission congestion management based on simplicity, practicality, and efficiency.
- to ensure that adequate generation capacity is available to maintain frequency and to manage generation and load fluctuations.
- to make system data available quickly and on a comparable basis to all market participants.
9. Fairness dictates honoring existing QF contracts and other existing wholesale power purchase agreements as we move toward a more competitive market.
10. The utility has an obligation to administer its existing QF contracts and existing wholesale power purchase agreements in the best interests of its customers and in a manner that maximizes systemwide benefits and minimizes transition cost accrual.
11. The ISO shall be indifferent, for purposes of resolving the transmission congestion, to the source of generation affected by the constraint.
12. The resolution of transmission congestion shall be open, fair, nondiscriminatory, and efficient.
13. 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.
14. The interests of all Californians requires the creation of a transparent, visible spot market for electric generation.
15. The Power Exchange shall implement nondiscriminatory rules which will permit rival generators to compete on common grounds using transparent rules for bidding into the Exchange.
16. The Power Exchange shall 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 shall be prohibited from owning generation, transmission or distribution facilities and should have no affiliation with any companies that own those facilities. The Power Exchange shall have no financial interest in or ownership ties to the ISO.
17. The Power Exchange shall oversee the ranking of least-cost generation facilities according to established protocols.
18. During the five-year transition period jurisdictional utilities shall be obligated to sell their generation into the Power Exchange and make purchases of electric power needed to supply the needs of their full service customers from the Exchange.
19. During the transition period customers who elect to rely upon a jurisdictional utility to procure electric power as well as distribution services shall be billed by that utility at its cost of purchases from the Power Exchange. At the full service customer's option that bill shall be calculated either on an average cost to the utility for Exchange purchases made during the billing cycle or, if there is appropriate metering equipment, in a calculation in which the Power Exchange price is matched against the time of use in which the customer's consumption occurred.
20. If a jurisdictional utility divests itself of a generation asset to an unaffiliated entity, the subsequent participation of that asset in the Exchange is entirely voluntary on the part of the new owner.
21. Allowing juisdictional utilities to opt for non-Exchange purchases and sales during the transition period disguises pricing information, limits customer choice, and requires contentious regulatory proceedings to validate the dimension and legitimacy of the competition transition charge.
22. The Federal Power Act confers exclusive jurisdiction over rates, terms, and conditions for sales for resale (wholesale sales) on the FERC.
23. Retail sales, even if the power originates out-of-state, are subject to exclusive state jurisdiction.
24. State authority to review reasonableness of wholesale power purchases where a utility has procurement alternatives is firmly established.
25. Customers in all classes should have a fair opportunity to participate in each phase of direct access.
26. Aggregation may include the loads of multiple customers, or a customer may aggregate loads at several sites. Aggregation should be voluntary.
27. Intermediaries will be able to purchase unbundled electricity from individual suppliers and bundle that power with various energy services to meet the customers' needs.
28. Suppliers or third-party intermediaries may install metering equipment on behalf of a customer so long as the meter meets standards adopted for the distribution utility.
29. Utilities will continue to control and operate their distribution system, to own and operate their generation assets (subject to some incentives for divestiture), and to procure generation services for their energy service customers. They will also continue to own, but not operate, their transmission facilities.
30. We will prohibit power purchase contracts and contracts for differences between the distribution utility and its affiliated generating companies.
31. The utility distribution company (UDC) 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.
32. Municipal utilities in California who wish to compete to sell power to retail customers of the investor-owned utilities should provide reciprocal access to customers in the municipal service territories.
33. Utility property, such as a generation asset, that has received revenue recovery through rates is used and useful in the performance of the utility's duties to the public until such time as the Commission determines otherwise. The act of market valuation is not itself sufficient to release the property from its dedication to public use.
34. We cannot have a fully competitive market for generation unless and until we eliminate any significant lingering ability of the former monopoly utility to distort prices or restrict competition in the new competitive market.
35. To ensure contestability in the generation market, we should eliminate any undue competitive advantages to existing firms and eliminate barriers to entry of prospective competitors.
36. Contracts between utility-affiliated generators and the distribution utility should be prohibited.
37. Transition costs should be collected in a manner that is competitively neutral, is fair to all classes of ratepayers, and does not increase rates.
38. The netting of economic and uneconomic assets is a partial way of compensating ratepayers for the loss of continued dedication to public use of economic assets.
39. It would be obviously unfair if, as part of our restructuring, we were to require customers to pick up the costs of high-cost generation without at the same time accounting for the benefits of low-cost generation.
40. The calculation of transition costs should account for prepaid and unpaid deferred taxes related to generating assets.
41. It is fair to compensate the utilities for reasonable investments in needed plants that cannot be effectively recovered in a competitive market.
42. We should develop a process to account for the lingering effects of the regulated market structure during the transition to competition.
43. It is fair to allow utilities to recover capital investments in generating plants and contractual obligations.
44. Utilities should be allowed to recover an appropriate amount of transition costs.
45. Ratepayers should benefit, at least to some degree, from our treatment of transition costs.
46. The principles that ratepayers should benefit from our treatment of transition costs and that utilities should have proper incentives can be accommodated in a recovery mechanism that reduces the return on investment-related transition costs.
47. Ratepayers should not be required to pay utilities all of the revenues they would have recovered in the absence of this reform effort.
48. It is fair to pay shareholders a lower rate of return which appropriately reflects the reduced risk for generating assets.
49. Our approval of rate recovery for the reasonable costs associated with generation plants and other obligations incurred under a regulated industry structure does not mean that customers must produce the same revenues under the new regulatory structure. We are required only to design a rate structure the total impact of which provides the utilities with the opportunity to earn a fair return on their investment.
50. The overall market structure proposed today, including the utilities' recovery of a large portion of transition costs and the opportunity to earn profits in a competitive market, provides shareholders with an adequate opportunity to earn a fair return on their investments.
51. Shareholders should not completely avoid responsibility for costs related to facilities that changing circumstances have made uneconomic.
52. Negotiations for a sale of a utility asset should be conducted at arm's length and the resulting sale price should be generally consistent with other market information.
53. Recovery of retail transition costs should be subject to state jurisdiction. Under the Federal Power Act jurisdiction over retail transition costs lies exclusively with state authorities.
54. Direct access customers should be required, as a condition of the utility's retail distribution tariff, to sign an agreement to pay their share of transition costs and thereby waive any jurisdictional objection they might otherwise raise in any forum.
55. Utilities should be required to modify the Preliminary Statement of their tariffs to provide all current and new customers with notice of our intent to authorize collection of retail transition costs.
56. Using marginal cost pricing for electric services using the EPMC methodology for the allocation of transition costs ensures a fair allocation among all customer classes and prevents inter- and intraclass cost-shifting.
57. The competitive transition charge (CTC) should be assessed on all customers who are retail customers on or after the date of this decision, whether they continue to take bundled service from their current utility or pursue other options.
58. To assure the continued financial integrity of the utilities, and give them an opportunity to be vital market participants in the restructured market following the transition, utilities should recover 100% of CTC.
59. Only regulatory assets related to generation should be included in CTC.
60. Prior to market valuation, fossil fueled generating units should recover 100% of undepreciated, book value.
61. Return levels for CTC associated with fossil fueled units will be set at the embedded cost of debt for the debt portion and 90% of the embedded cost of debt for the equity portion.
62. Operating costs and capital costs not yet incurred for fossil fueled generating units are not eligible for CTC recovery unless the unit is needed for reactive power/voltage control, market based prices for those services are not yet established, and the amounts requested are subject to PBR.
63. If the Exchange clearing price exceeds the costs of running fossil fueled generating units, utilities should be able to earn up to 150 basis points above their authorized return for distribution rate base before additional profits are used to reduce CTC.
64. Hydroelectric and geothermal generating units should remain subject to rate of return regulation and provide their output to the distribution function of the utility through the Exchange, and will be subject to PBR.
65. Revenues from the Exchange in excess of revenue requirements for hydroelectric and geothermal gnerating units should be used to reduce CTC.
66. It is reasonable to adopt 90% of the embedded cost of debt as a reasonable rate of return on the equity portion of the net book value of fossil fueled generation units to reflect the reduced risk. It is reasonable to provide an incentive to the utilities to voluntarily divest their fossil fueled generation assets by granting an increase in the rate of return for the equity component of up to 10 basis points for each 10% of fossil generating capacity divested, provided we have resolved any locational market power concerns associated with the unit and authorize the transfer pursuant to 851.
67. Separate sub-accounts will be used for CTC so that return levels are set appropriately for different assets.
68. The CTC account will be annually adjusted to reflect Exchange clearing prices and to reflect assets that received market valuation.
69. With the exception of CTC arising from existing contracts, no further accumulation of CTC will be allowed after 2003 and collection will be completed by 2005.
70. Given the accelerated depreciation schedule allowed for the SONGS nuclear plants, it is fair to set the rate of return at the embedded cost of debt for the debt share of the utility's capital structure associated with these assets, and at 90% of the embedded cost of debt for the remaining share (equity).
71. Section 455.5 continues to apply to outages of utilities' generating plants that are out of service.
72. The short-run avoided cost energy payments to QFs should be set at the Exchange's clearing price as soon as we are confident the Exchange is functioning properly.
73. Modification of QF contracts will follow our existing principles that the modifications are voluntary on the part of the QF, should reflect ratepayer benefits relative to the most probable stream of payments for that QF without the modification, and should benefit from the flexibility that nonstandard, arm's length negotiations have previously revealed.
74. When a QF contract is renegotiated, shareholders should retain 10% of the resulting ratepayer benefits, which will be reflected by an adjustment to the CTC if the modification is approved by the Commission.
75. Utilities should be allowed to earn a premium, related to the transition costs of fossil plants, based on fossil plants that are sold or spun off to unaffiliated entities.
76. Some ongoing costs, if not recovered from the Exchange, might make a smooth transition to a restructured market difficult: the location of certain non-nuclear generating units provides reactive power/voltage control to the transmission grid and market-based prices or mechanisms for that ancillary service are not yet established.
77. Under the Federal Power Act jurisdiction over retail transition costs lies exclusively with state authorities.
78. The need for public purpose programs will continue after restructuring.
79. Restructuring policies should maintain California's resource diversity for existing resources and encourage development of new renewable resources.
80. The minimum renewables requirement approach will allow the market to provide the most cost-effective renewable resources, without our intervention.
81. Allowing providers to trade in order to meet the renewables requirement may also serve to minimize the stranded costs associated with existing QF contracts by providing new markets for QFs' power.
82. The focus of publicly funded energy efficiency programs should shift to those programs in the broader public interest, for example, programs with market transformation effects and education efforts that would not otherwise be provided by the competitive market.
83. Customer-specific energy efficiency projects should not require future funding from ratepayers, but should instead rely on market-driven funding mechanisms.
84. Continued funding is appropriate for activities that are designed to transform the energy efficiency market and will not naturally be provided by a competitive market.
85. By January 1, 1997, energy efficiency costs should no longer be embedded in electric rates and instead should be collected as part of the public goods charge applied to retail electric sales.
86. Until public funding for DSM activities is removed from rates and collected through a surcharge, an ERAM-type mechanism should be retained to account for energy efficiency impacts.
87. The remaining monopoly utility should no longer use ratepayer funds for generation RD&D.
88. The PGC should collect funds for public goods research only, not funds for regulated or competitive research functions. The monopoly utility should no longer collect ratepayer funds for generation-related research as of January 1, 1997.
89. The PGC should not collect funds to pursue research that the competitive market will provide on its own.
90. By January 1, 1997, the public goods RD&D costs should no longer be embedded in electric rates and instead should be collected as part of the PGC applied to retail electric sales.
91. Until further action by this Commission, all electric service providers under our jurisdiction should be required to offer eligible customers baseline service consistent with 739.
92. Low-income assistance costs should be recovered as a surcharge on electricity use separate from other public goods charges.
93. Funding for low-income rate discounts recovered through a surcharge should not be capped at current levels but should instead be based on need.
94. CARE funds should be used for a customer discount that appears on the bill rather than an after-the-fact refund or rebate.
95. No additional funding or changes to the WMDVBE program are needed for the program to go forward after industry restructuring.
96. Sections 740.4 and 740.7 allow for funding of utility economic development activities to the extent of ratepayer benefit.
97. Our existing guidelines on funding requests for utility economic development programs are adequate.
98. Generation and related procurement outside the Power Exchange by the regulated utility should be subject to WMDVBE statutes and GO 156, just as fuel procurement is today.
99. Revenue shortfalls resulting from new rate discounts offered to avoid customer bypass, attract new business, or retain existing or expanding businesses should be shared until 1998 between ratepayers and shareholders.
100. Once the restructured market has begun in 1998, utilities will not be able to pass the costs of discounts to ratepayers; instead, shareholders should fund any discounts offered to customers.
101. The costs of utility LEV programs should continue to be collected by the regulated utility and identified as a line item on customer bills, as opposed to being collected as part of the PGC.
102. Undergrounding remains an appropriate activity of the regulated utility, not subject to competition, and therefore its costs should be collected through regulated utility rates.
103. The sheer scope controversy of our proposed electric policy favors reviewing the possible environmental impacts of a new industry structure.
104. Preparation of an EIR as opposed to a negative declaration is appropriate in the instant proceeding, because it cannot be seen with a certainty that our proposal will not have an adverse effect on the environment.
105. The restructuring proceeding has an identified potential to impact the environment.
106. An EIR will be prepared for our preferred policy proposal.
107. An initial environmental study is not required.
108. Because we are embarking on the environmental review process, none of the policy proposals in this decision are final. Today's decision constitutes the Commission's identification of preferred policy and the project proposal, which cannot be finally adopted or approved until after we have prepared the EIR and considered its findings.
109. Based on our experience in the telecommunications industry, it would be prudent to establish an independent education entity before the onset of customer choice.
110. Our consumer protection role will be enhanced if we retain the ability to require energy service providers, including marketers, brokers and aggregators, to register with or obtain a license from this Commission.
O R D E R
IT IS ORDERED that:
1. Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), and San Diego Gas & Electric Company (SDG&E) shall work together and with other parties to develop a detailed proposal for submission to the Federal Energy Regulatory Commission (FERC) to establish the independent system operator (ISO) and its protocols and transfer operational control of the utilities' transmission facilities to the ISO. This proposal shall be filed at FERC and simultaneously filed and served in this docket within 130 days after the effective date of this decision. The proposal shall comply with the principles and guidelines for operational issues outlined in Chapter III of this decision and shall include recommendations for ownership, financing, and corporate structure of the ISO.
2. If parties wish to comment on the proposals set forth in Ordering Paragraph 1, they shall file and serve opening comments in this docket no later than 160 days after the effective date of today's decision. Parties shall file and serve reply comments no later than 175 days after the effective date of today's decision.
3. PG&E, SCE, and SDG&E shall work together and with other interested parties to prepare a joint proposal to establish the Power Exchange. This proposal shall follow the policy guidance described in Chapter III and shall include recommendations which address the ownership, financing, corporate structure, pricing mechanisms, and bidding protocols of the Power Exchange. In addition, the proposal shall address communications with the ISO and additional Power Exchange responsibilities, as discussed in Chapter III. PG&E, SCE, and SDG&E shall include recommendations for the ownership, organizational structure, and working capital of the Power Exchange in their proposal. The joint proposal shall be filed at FERC and simultaneously filed and served in this docket no later than 130 days after the effective date of this decision. If parties are unable to agree on a joint proposal, PG&E, SCE, and SDG&E shall file and serve individual proposals in this docket; these proposals shall address the issues outlined above and be filed and served no later than 130 days after the effective date of this decision.
4. Parties may file comments on the proposal set forth in Ordering Paragraph 3 or file proposals of their own. These comments shall be filed and served no later than 160 days after the effective date of this decision. Reply comments shall be filed and served no later than 175 days from the effective date of this decision.
5. For the five-year transition period during which PG&E, SCE, and SDG&E seek recovery of their stranded generation assets and power purchase liabilities, each utility shall bid all of its generation into the Power Exchange and procure electric energy for its full service customers by purchases from the Power Exchange. During the transition period, any generation unit sold by the utilities by way of divestiture to a non-affiliated new owner shall immediately be freed of any obligation to bid into the Power Exchange. At the end of the transition period, when determination of assets which qualify for recovery under the competition transition charge has been finalized, the utilities shall be released from any mandatory requirement to bid into or purchase from the Power Exchange.
6. The initial phase of retail competition, or "direct access," shall be implemented simultaneously with the establishment of a Power Exchange and ISO. At a minimum, PG&E, SCE, and SDG&E shall phase in direct access according to the following schedule:
Total Number MW Available for Participation in Direct Access
||All remaining load
||All remaining load|
PG&E, SCE, and SDG&E shall confer with interested parties to recommend proposals for direct access, including eligibility parameters in the initial phase of direct access, consistent with the principles outlined for direct access and real-time and time-of-use rate options. The proposals shall include recommendations for eligibility parameters for the transition phase and beyond. These proposals shall be filed and served in this docket no later than 30 days from the effective date of this decision. Comments on these proposals may be filed and served within 60 days of the effective date of today's decision. We ask parties to carefully consider whether a continued phase-in schedule is necessary or whether eligibility can be held open to all electricity consumers sooner than five years. Reply comments may be filed and served no later than 75 days from the effective date of this decision.
7. PG&E, SCE, and SDG&E shall not enter into retail contracts to purchase the output of a generation facility that is under their own or any of their affiliates' ownership.
8. PG&E, SCE, and SDG&E shall retain its obligation for least-cost procurement for utility service customers, that is, those who do not elect to procure their own electricity supplies. Least-cost procurement obligations shall be met by purchases through the Power Exchange.
9. PG&E, SCE, and SDG&E shall provide distribution services to direct access customers, but shall no longer be obligated to provide generation services to those customers.
10. We authorize PG&E, SCE, and SDG&E to provide delivery services to direct access customers, under tariffs approved by both FERC and this Commission upon written agreement by the direct access customers to pay their share of retail transition costs, as determined by this Commission.
11. As of January 1, 1998, the distribution utilities shall offer tariffed electric service which references the real-time market clearing price as published by the Power Exchange.
12. PG&E, SCE, and SDG&E shall adhere to the following schedule for meter installation for customers other than those who are categorized within the Domestic, GS-1, and TC-1 customer groups:
||by 1998 when restructuring begins|
||one year after restructuring begins (at least by 1999)|
||2 years after restructuring begins (at least by 2000)|
||3 years after resturcturing begins (at least by 2001)|
||4 years after restructuring begins (at least by 2002)|
13. PG&E, SCE, and SDG&E shall not enter into contracts for differences (CFDs) with their own generation facilities or their affiliated generation facilities.
14. Within 30 days of the effective date of this decision, parties shall file and serve comments in Application (A.) 93-12-029 on whether SCE's pending performance-based ratemaking (PBR) proposal should be amended or not.
15. Within 30 days of the effective date of this decision, parties shall file comments in A.94-03-008 on whether PG&E's pending PBR proposal should be amended or not.
16. We direct the parties to file and serve comments in A.94-01-016 addressing how SCE's proposed Gas Cost Incentive mechanism is impacted by today's decision. These comments are due within 30 days of the effective date of this decision.
17. Within 60 days of the effective date of this decision, PG&E, SCE, and SDG&E shall file new applications, which will be assigned new docket numbers, to establish PBR mechanisms, consistent with the policies outlined in today's decision. Each applicant shall serve all parties on its existing service list. Each application shall include a proposal for a separate distribution and generation PBR. Each application shall include a discussion of strategies to mitigate horizontal market power concerns, including the issue of transition costs.
18. No later than 90 days after the effective date of this decision, PG&E, SCE, and SDG&E shall file and serve written comments in this docket on the feasibility, timing, and consequences of a corporate restructuring premised on distinguishing their activities and assets with respect to generation, transmission, and distribution. These comments shall address a holding company structure with three subsidiaries, but the comments are not limited to this corporate structure. Any interested party may file and serve reply comments no later than 150 days after the effective date of this decision.
19. No later than 90 days after the effective date of this decision, PG&E and SCE shall file a plan to voluntarily divest themselves of at least 50% of their fossil generating assets. This divestiture must be effectuated through a spin-off or outright sale to a non-affiliated entity. Any interested party may file and serve comments on these plans no later than 135 days after the effective date of this decision.
20. Customer-specific information necessary for the distribution functions of the utility shall be made available to all competitors in the generation sector, on terms that are fair to all competitors. All generation providers, including the monopoly utility, shall obtain a customer's consent before accessing any proprietary information about that customer.
21. Transition costs, or the net above-market costs for each utility, shall be determined after offsetting the benefits associated with economic assets against the excess costs of uneconomic assets. This calculation shall also account for deferred taxes.
22. PG&E, SCE, and SDG&E shall each establish a balancing account for competitive transition costs consistent with the directives in this decision. The debt portion of investment-related transition costs shall earn a return equivalent to each utility's embedded cost of debt. Each utility shall establish subaccounts within the transition cost account for the purpose of computing the imputed debt and equity portions of the net book value for each generating asset. The equity portion of investment-related transition costs shall earn a rate of return equivalent to 90% of each utility's embedded cost of debt.
23. PG&E shall file an application within 100 days of the effective date of this decision with its proposal for ratemaking treatment for the Diablo Canyon facility that would price its output at market rates by 2003. The application shall be consistent with the principles for recovery of transition costs, as outlined in this decision, including no rate increases above the January 1, 1996 levels and shall include at least one alternative comparable to that ultimately adopted for SONGS.
24. SCE shall file an application within 100 days with its proposal for a new rate mechanism for Palo Verde, including a proposal for ratemaking treatment comparable to that ultimately adopted for SONGS for rates effective on or before January 1, 1997.
25. Until such time as a market value for utility generation assets is determined, the utilities shall recover through depreciation up to 100% of the net book value of their fossil-fueled generation units through the competition transition charge (CTC). By April 1, 1996, PG&E, SCE, and SDG&E shall each file an application to identify and value the sunk costs of their non-nuclear generation assets.
26. PG&E, SCE, and SDG&E shall file applications no later than September 2, 1996 to estimate their transition costs as of January 1, 1998. These applications shall establish the first annual proceeding to address adjustments to the transition cost balancing account. In their applications, the utilities shall make a showing that they are adhering to our established principles for transition cost collection, as described in this decision.
27. Upon market valuation of an asset, PG&E, SCE, and SDG&E shall file an application pursuant to Public Utilities (PU) Code 851 application to initiate review of the market price, transfer of the asset, and removal of the costs from the PBR benchmark and the CTC balancing account.
28. Transition costs shall be collected through the competition transition charge (CTC) which shall apply to sales to both retail procurement and utility customers on a utility service territory basis. Within 45 days, each utility shall file an advice letter to modify the Preliminary Statement of its tariffs to provide all current and new customers with notice of our intent to authorize collections of retail transition costs. Consistent with Conclusion of Law 54, each Direct Access Customer shall sign an agreement to pay their share of transition costs and thereby waive any jurisdictional objection they might otherwise raise in any forum. The CTC shall be a percentage surcharge on the bill of each customer of the distribution utility, including those served under contracts with nonutility suppliers.
29. Transition costs shall be allocated to all electric customers using the Equal Percentage of Marginal Cost (EPMC) allocation methodology. Transition cost recovery shall be capped so that the price for electricity, on a kWh basis, does not rise above rate levels in effect as of January 1, 1996, without adjustment for inflation.
30. A minimum renewables purchase requirement shall be a condition of certification. Credits for meeting this requirement shall be tradeable.
31. Upon enabling legislation, we shall establish a public goods charge. The public goods charge shall be a surcharge for energy efficiency programs related to market transformation and funding for research related to the broader public good, as discussed in this decision.
32. PG&E, SCE, and SDG&E shall retain a modified Electric Revenue Adjustment Mechanism (ERAM) account until public funding for energy efficiency is removed from rates and collected through a surcharge.
33. Unless and until we determine otherwise, all electric service providers under our jurisdiction shall offer eligible customers baseline rates, consistent with PU Code 739.
34. PG&E, SCE, and SDG&E shall establish a surcharge to recover low-income assistance costs that is separate from other public goods charges, once the appropriate legislation is enacted. CARE funds shall be used to provide a customer discount that is reflected on each monthly bill.
35. PG&E, SCE, and SDG&E shall continue to be held to the goals established in General Order 156.
36. Funding requests for utility economic development programs shall conform to our existing guidelines, consistent with 740.4 and 740.7. Effective January 1, 1997, costs authorized for these activities shall be identified as line items on customer bills.
37. For the transition period, costs associated with rate discounts shall be allocated to both ratepayers and shareholders. Once direct access is in place, shareholders shall be responsible for 100% of any costs or revenue shortfalls stemming from rate discounts offered to customers. These policies do not apply to rate discounts offered in Economic Incentive Areas or Enterprise Zones, as articulated in 740.4 and 740.7. Cost-sharing allocation shall be applied to all special discount cases that come before us during the transition period, including those currently pending. PG&E shall apply the cost allocation adopted in D.95-10-033 to its rate discount contracts. We shall adopt allocation formulas for SCE and SDG&E in the appropriate rate design proceeding.
38. The Commission Advisory and Compliance Division (CACD) shall prepare an Environmental Impact Report (EIR) for our consideration. CACD shall issue a Notice of Preparation of an EIR within 100 days of the effective date of this decision. CACD shall retain the services of a qualified professional environmental consultant, who shall conduct an independent analysis which shall result in the publication of both a Draft and Final EIR. The Final EIR shall be prepared in full compliance with the California Environmental Quality Act (CEQA) and Rule 17.1 of this Commission's Rules of Practice and Procedure.
39. PG&E, SCE, and SDG&E shall reimburse the Commission for its costs in preparing the EIR, including, but not limited to, the costs of retaining an independent consultant who shall be selected solely by CACD. PG&E, SCE, and SDG&E shall share and recover these costs in the manner employed to allocate and recover the Public Utilities Commission Reimbursement Account fees.
40. We will establish an independent education trust modeled after the Telecommunications Education Trust, the purpose of which is to ensure independent, multicultural education, advocacy, and research for small business and residential customers.
This order is effective today.
Dated December 20, 1995, at San Francisco, California.