OR99-033

In December 1998, Portland General Electric (PGE), a regulated public utility serving approximately 650,000 residential, industrial, and commercial customers in Northwest Oregon, applied for restructuring of its operations. PGE now supplies all functions of electric service. It obtains a sufficient supply of electricity to serve its customers through generation in PGE-owned facilities or through purchases from the electric supply market. It provides for transmission of that electricity from the source to PGE's distribution facilities—including wires, poles, and conduits—through which the electricity is delivered to its retail customers. All of these functions are regulated, either by the Public Utility Commission of Oregon or by the Federal Energy Regulatory Commission. All retail customers—residential, industrial, and commercial—pay rates for electricity which are set out in tariffs reviewed by the Commission to determine if they are just and reasonable.

PGE’s application in this case would allow it to divest its supply function. It would sell all of its supply resources, including hydroelectric facilities, gas and coal fired electric plants, and contracts for the purchase and sale of electricity. PGE would retain its transmission and distribution functions. All retail electric customers in PGE's service territory would then have the option of purchasing electricity from Energy Service Providers (ESPs). The ESPs would obtain the electricity by generating it or buying it on the market and would sell it to retail customers at unregulated rates. The ESPs would be certified by the Commission as to their creditworthiness and would be subject to decertification for certain unlawful acts. PGE would provide distribution of the electricity to retail customers over its existing facilities and would charge ESPs for that service at a rate regulated by the Commission. PGE's filing included proposed rates for the company as a distribution-only utility. All customers would also have the option of obtaining electricity from a limited number of "portfolio" offerings supplied by ESPs who would bid for the right to provide the service.

In this order, the Commission examines PGE's application and the arguments and evidence filed in support of it and in opposition to it. The Commission decides not to grant the application in its entirety, for several reasons. The Commission is concerned that residential customers might not fare well in the competitive marketplace at this time because there is no certainty that ESPs will seek the business of residential customers. Rates for residential customers might therefore be unstable and might be higher than they are now. The Commission is also concerned that PGE's proposed sale of its hydroelectric generation facilities, which provide low-cost power, would be detrimental to PGE's customers. Another major concern is that PGE's restructuring proposal could threaten access by residential and small farm customers to low-cost power from the Bonneville Power Administration. The Commission notes, moreover, that PGE's plan is irreversible. If the plan were implemented and significant problems developed, it would not be possible to return to the current system. For these reasons and others set out it in the order, the Commission decides to propose an alternative plan to PGE. It incorporates many of the elements of PGE’s plan but rejects others in favor of features better suited to serve the public interest.

The Commission’s plan allows all industrial and most commercial customers to buy electricity from ESPs at unregulated rates. It does not allow residential customers to do so, but instead provides them with a portfolio of several electric service options, including an environmentally friendly or "green" choice. The portfolio would be managed by PGE, which will take ownership of the power from ESPs. All customers can also choose to take electric service under a cost-of-service rate, which will be regulated by the Commission. An industrial customer who chooses direct access will not be able to return to the cost-of-service rate, but will have available a default rate if the ESP serving it ceases operation. The Commission concludes that its alternative plan will provide protections to residential customers while providing them with choices in obtaining their electric service. At the same time, the Commission’s plan will give larger customers access to the competitive market and its potential benefits.

The Commission’s plan allows PGE to sell its non-hydroelectric resources at an auction, but requires PGE to retain its hydroelectric generation and supply resources, thereby retaining their benefits for Oregon customers. Under the plan, new supply resources will no longer be placed in utility rate base to earn a return for the utility through rates. ESPs and PGE will thus be on equal footing in making decisions on resource development. The plan would protect certain public purposes, such as the development of renewable resources, conservation, and low-income weatherization, through a System Benefits Charge added to the charge PGE makes for distribution. The Commission’s plan continues most of the consumer protections that now effectively shield utility customers from harmful practices. It provides a mechanism for PGE to recover most or all of its investment in assets that it will sell and also to recover the costs of making the transition to the new structure. The order addresses issues relating to PGE's rates under the new structure and notes that PGE must refile its rate case if it chooses to proceed with the restructuring this order approves.

Since this is PGE's application, the plan the Commission approves is optional to the company. It may accept it and proceed toward implementation or it may reject it and retain its present structure. If it chooses to proceed, legislation would be needed to implement the plan. The order notes those portions of the plan where the Commission believes legislation is needed and presents suggestions for the form of such legislation.

The Commission indicates in the order that it is open to consideration of further restructuring of PGE and other electric utilities in Oregon. The experience that will be gained under this plan, if implemented, will help the Commission determine whether additional changes, including direct access to the marketplace for residential customers, are in the public interest. If the plan set out in this order is ultimately implemented, the Commission will monitor it to determine the impact on the public and the need for modifications. The order establishes a monitoring process for that purpose.

On December 1, 1997, Portland General Electric Company (PGE or Company) filed rate schedules in Advice No. 97-20 to be effective January 7, 1998. On January 6, 1998, the Public Utility Commission of Oregon (Commission) issued Order No. 98-015 suspending the Advice pursuant to ORS 759.210 and 759.215 pending an investigation of the propriety and reasonableness of the rates. On June 12, 1998, the Commission issued Order No. 98-237 extending the suspension for an additional period not exceeding three months pursuant to ORS 757.215(1). On September 21, 1998, PGE filed a letter stipulating that the Commission could extend the suspension until no later than January 31, 1999. On September 28, 1998, the Commission issued Order No. 98-389 extending the filing until no later than January 31, 1999.

The Commission conducted a lengthy and thorough process to examine the PGE plan, plans suggested by other parties, and other issues raised in this case. Prehearing conferences were held to identify parties and issues and to establish procedures. The parties are identified in Appendix A. Public comment sessions were held in St. Helens, Beaverton, Portland, and Salem during April 1998 to provide information to the public and receive comment. The Commission also received more than 150 written comments from members of the public. The Commission conducted a public conference on August 3, 1998, to allow proponents of PGE’s plan and of alternative plans to present information.

On August 5, 1998, the Administrative Law Judge granted a motion by the Staff of the PUC (Staff) to establish a separate schedule within this case for consideration of the issues dealing with the proposed auction process for disposing of PGE's supply assets. The Commission will issue a separate order relating to the proposed auction.

An evidentiary hearing was held on October 2, 1998, October 15, 1998, and November 18, 1998, before Allen Scott, Administrative Law Judge for the Commission. Briefs were filed during October, November, and December 1998.

PGE is now a "vertically integrated" regulated electric utility. It generates or purchases electricity to supply to its customers. It provides for transmission of the electricity to its distribution system, through which the electricity is brought to its end-use customers. PGE's application in this case would convert PGE from a vertically integrated electric utility providing regulated supply, transmission, and distribution services into a company providing only regulated transmission and distribution services. Under its plan, PGE would sell at a PUC sanctioned auction all of its energy supply asset portfolio, including generation assets and contracts for the sale, purchase, and exchange of energy supply. PGE has provided a detailed proposal for an auction. PGE would retain most of its distribution and transmission assets, including the wires and other facilities necessary to distribute the power to customers.

If the plan were implemented, PGE would no longer sell electricity to customers. Instead, Energy Service Providers (ESPs) would generate energy themselves or acquire it in the open wholesale market, offer it for sale to customers at unregulated, negotiable prices, and bill and collect from those who purchase the electricity. PGE would deliver the energy to customers over the wires and other distribution facilities it had retained. PGE would charge ESPs for the distribution service under a regulated tariff rate approved by the Commission. The ESPs would be certified by the Commission as to creditworthiness. The ESPs would be required to maintain and enforce a customer bill of rights and to comply with consumer protection laws and some of the Commission’s consumer protection rules. An ESP which violated PGE's tariff or consumer protection laws would be subject to decertification by the Commission.

Under PGE’s plan, all customers—residential, commercial, and industrial—would have direct access to the competitive marketplace in obtaining energy. That is, they could purchase electricity directly from ESPs at unregulated rates. In addition, PGE amended its plan so that all customers would have the option of selecting service from a limited number of "portfolio" offerings supplied by ESPs who would bid for the right to provide the service. PGE would bill the portfolio customers and collect from them. One option within each portfolio would provide a market-based default service for customers who do not choose direct access or a specific portfolio offering. The portfolio for residential customers would provide up to three additional choices, including a variable market rate and a "green power" product. All customers would have the option of returning to a portfolio service from direct access.

PGE's plan also provides for a System Benefits Charge (SBC) collected through its distribution charge to protect funding for public purpose programs supporting low-income weatherization, energy efficiency, and renewable energy programs previously undertaken by the Company. The plan also provides mechanisms for consumer protection and for maintenance of municipal revenues which cities receive from franchise fees charged to utilities. These matters will be addressed below.

PGE believes that implementation of its plan may leave it with "transition costs," which it broadly defines as "prudently incurred costs that cannot be recovered in a competitive marketplace and cannot be mitigated." Principal transition costs may include the difference between the book value of the supply assets PGE will sell under the plan and their market value obtained at the proposed auction. Other transition costs, some related to the supply portfolio and some not related to the portfolio, may be incurred. PGE’s plan provides that 100 percent of transition costs would be recovered by its shareholders over five years at PGE’s authorized rate of return through a fixed rate based on usage. The charge would be included in the tariffed charge PGE makes to ESPs for energy distribution.

Several parties, including the Staff, the Industrial Customers of Northwest Utilities and the Commercial Energy Alliance (ICNU/CEA), the Oregon Intervenor Coalition (OIC), the Citizens’ Utility Board and Northwest Energy Coalition (CUB/NWEC), and Pope & Talbot, Inc., proposed restructuring plans for PGE. These plans differ from PGE’s plan and from each other with respect to the availability of direct access to various customer classes, details of portfolio plans, treatment of PGE’s hydroelectric assets, the handling of transition costs, and other features. These matters are addressed below as necessary to explain our decision.

In considering whether to adopt PGE’s proposal or to approve some other form of restructuring, the Commission is guided by its statutory mandate. ORS 756.040 directs the Commission to "represent the customers of any public utility . . . and the public generally in all controversies respecting rates, valuations, service and all matters of which the commission has jurisdiction." It also directs the Commission to use its powers "to protect such customers, and the public generally, from unjust and unreasonable exactions and practices and to obtain for them adequate service at fair and reasonable rates." ORS 757.020 requires public utilities to furnish "adequate and safe service, equipment and facilities," and to make only "reasonable and just" charges for their service. ORS 757.210 provides that the Commission may examine rates or schedules to determine their "propriety and reasonableness." ORS 757.310 and 757.325 prohibit unjust discrimination and undue preference by public utilities.

These statutes determine our authority and direct us in its exercise. They establish the standards we apply in this order in determining whether a restructuring plan is in the public interest and should be adopted. These standards will continue to guide us unless they are modified by the legislature. Actual implementation of any new plan, however, will require additional statutory authority. We discuss the matters which require legislation throughout the order and in Appendix C.

In considering any proposal for electric restructuring in Oregon, we are also guided by the principles set out in Oregon Governor John Kitzhaber’s "Statement of Principles for Restructuring the Electric Utility Industry" (December 12, 1996). The Governor’s Statement contains the following Overriding Objectives and Necessary Principles:

Principle 1. All Oregonians must have the option to choose their electricity supplier and be provided the information necessary to make an informed choice.

Principle 2. All Oregonians must have access to basic electricity service at a reasonable rate.

Principle 5. Conserving energy and developing renewable resources are essential in protecting Oregon’s environment and sustaining a healthy economy and must continue to be adequately funded.

Principle 6. Low-income Oregonians must have access to competitive markets, and the energy support services currently available to them must be maintained or enhanced.

Principle 7. Utilities should have a fair and reasonable opportunity to recover costs of previous commitments.

Principle 8. Regulation must continue for products and services for which there is no effective competition.

Principle 9. Customers must be protected from any unfair or unscrupulous practices of their electric service providers.

Principle 10. The restructuring of the electric utility industry must not unduly burden local governments.

Principle 11. Any exemption to utilities from open access mandates must be balanced with restrictions on marketing outside their service territories and continuation of public purposes funding.

Where, as here, a utility has applied for restructuring, we will adopt the utility’s plan only if it has shown that the results will be consistent with the statutory mandates we operate under and with the Governor’s Principles. Thus, we will approve PGE’s plan or some alternative only if we conclude that it is in the public interest to do so and specifically in the interest of those whom we are directly mandated to protect: the customers of electric utilities. Necessarily, the interests of the utility involved are subordinate to our focus on the public interest. If we reject PGE's plan, we may nevertheless approve some other form of restructuring which is consistent with these statutes and principles.

PGE and other parties in this case present a two-pronged argument to support restructuring in general and the PGE plan in particular. The first focuses on the benefits of competition. The proponents argue that competition produces greater economic efficiency than regulation by making better use of price signals, by allocating and accounting for risks more appropriately, and by strengthening financial incentives to improve performance. Moreover, the proponents argue that competition will provide choice, which will lead to innovations such as price and product differentiation that would not occur under regulation or would evolve more slowly. Thus, they argue, customers will benefit from reduced or more equitable prices and from improvements in products and services. They note that competitive markets are the rule rather than the exception in our economy and argue that the Commission should therefore not ask whether greater competition is a good idea but whether a basis for the present regulatory scheme still exists.

PGE’s second major argument is that the electric supply system in Oregon and the United States as a whole is now ready for the change to the competitive marketplace. Transmission systems are interconnected and transmission is available to all suppliers on an equal basis. Barriers to trade in electricity have been reduced through open access wholesale tariffs. Electric markets have expanded geographically and the number of competitors potentially able to provide supply service at a location has increased. New generation resources such as gas-fired turbines can be built more cheaply and more quickly, thus lowering barriers to new companies, increasing competition, and allowing greater flexibility in siting plants. The current supply of energy in the Pacific Northwest is adequate and new resources will not be needed for several years. There are enough sites for new plants to support increased capacity as needed. These changes, in PGE's view, mean that the conditions which justified economic regulation of PGE and other electric utilities as vertically integrated energy monopolies no longer exist and PGE's customers have nothing to gain by retention of the present system. The Commission should therefore allow PGE's customers to benefit from these changes by giving them access to the competitive marketplace.

The Commission believes that some form of restructuring of PGE is in the public interest. PGE and other parties present sound arguments, as set out above, to support this conclusion. The market may bring lower prices, greater flexibility, and innovation to an industry. Deregulation in other industries has often provided benefits to the public. We agree also that changes in transmission and technology and in other matters affecting the electric industry make timely a movement toward reduced regulation. We conclude it is in the public interest to move toward greater choice for electric customers through an appropriate restructuring plan.

The Commission is not persuaded, however, that the restructuring plan proposed by PGE is in the public interest. Staff and several other parties have raised cogent arguments against the plan which convince us that a less sweeping revision of the Company’s structure would be in the public interest. Direct access creates risks as well as potential benefits. The market may not develop rapidly or sufficiently, especially for residential and small commercial customers. Pilot programs in Oregon and the experience in other states where restructuring has occurred suggest that suppliers may not rush to serve that portion of the market. Prices thus may not decrease, or may even increase, and the quality and reliability of service may decline. The hoped-for innovations may not occur or may benefit only some customers.

We emphasize that the issue of risk is particularly significant and complex in a case involving an essential service provided to differing groups of customers. We represent, on the one hand, the interests of highly sophisticated industrial and commercial customers. Their size and experience may give them a strong negotiating position. On the other hand, we also represent residential customers who may be vulnerable because they have little knowledge of the utility business and little power to negotiate. The Commission must protect the welfare of all classes of customers.

PGE's plan is a sweeping restructuring of its operation. It would dramatically alter the retail energy supply mechanism and would change other aspects of the system significantly. The scope and scale of the change may increase the potential benefits but may also increase the potential risks. The plan contains no rate cap or other guarantee of price reduction or stability. Prices might decline for some customers but increase for others. Changes in providers and in staffing levels and responsibilities might affect service quality and reliability, with the impact varying among classes of customers. Instability in price and service might become systemic. Perhaps the most significant risk inherent in the plan is that it would be irreversible. If the plan failed to produce the promised benefits or if unanticipated and serious problems occurred, the Commission could not realistically force a re-creation of the system now in place.

We have carefully reviewed the evidence and arguments of PGE and the other parties who predict that the PGE restructuring plan will serve the public interest. Much of it is an abstract and general discussion of the benefits of the market, as we noted above. This evidence and argument do not present a sufficiently strong basis for adoption of PGE's plan. The more specific evidence, such as PGE's estimate of the impact on rates, is not convincing. Staff has pointed out weaknesses in that analysis which make it at best an educated guess. Other evidence supports a conclusion that the near-term impact is uncertain. We are not justified in making an irreversible change based upon such inconclusive evidence.

Our reluctance to adopt PGE's restructuring plan is based partly on the healthy state of the electric supply industry in Oregon. It is serving the public interest very well. The price of electricity in Oregon is relatively low and stable, and the service provided by PGE and other regulated utilities is safe and reliable. According to information in 1997 Utility Statistics, a PUC publication, PGE’s average revenue per kWh sold in 1997 was 4.93 cents. The table below sets out comparable rates for utilities elsewhere in the United States. It shows that PGE’s customers have rates approximately 28 percent below the national average.

Average Revenue per Kilowatt-hour Sold (Cents)
Census Division	1997
New England	10.5
Middle Atlantic	9.8
East North Central	6.5
West North Central	5.9
South Atlantic	6.6
East South Central	5.0
West South Central	6.1
Mountain	5.9
Pacific Contiguous	7.6
Pacific Noncontiguous	11.6
U.S. Average	6.87
Source: Energy Information Administration/Electric Power Monthly March 1998

We note further that the supply base for provision of electric service in Oregon is diversified and efficient. Programs to encourage conservation and energy efficiency are in place and have the support of the public. Customers of public utilities benefit from the significant consumer protection provisions in our law and policy.

We believe the customers of PGE are generally satisfied with the system. There is no clamor among residential customers for dramatic change. In fact, the public sentiment expressed to us at several public comment meetings and in many written communications has been decidedly unfriendly to some important elements of PGE’s plan, especially direct access for residential customers and the sale of PGE’s hydroelectric assets. While these public meetings are not comprehensive measurements of public sentiment, PGE and the other parties who support its plan have provided no persuasive evidence that the public in general seeks a radical change which could imperil the benefits of the present system. Nor have the proponents of PGE's plan shown by more objective means that there are significant flaws in the present system. We cannot justify changes in the system unless we have been convinced that the new structure will be better than what we have. We are not convinced that PGE's plan meets this goal.

We have also reviewed PGE's plan in relation to the Governor's Principles. We agree with Staff that it fails to meet those standards in several particulars. It does not meet Overriding Objective 2 and Necessary Principle 2 because it fails to ensure that smaller customers will benefit from competition and does not give all Oregonians "access to basic electricity service at a reasonable price." PGE's proposed sale of its hydroelectric assets (or their transfer to a trust) does not fully meet the requirement of Overriding Objective 5 that restructuring "Preserve the benefits of our low-cost resources for Oregon customers." Moreover, selling the hydroelectric assets during the relicensing process will not serve to protect Oregon’s environmental quality as required by Overriding Objective 4. We also conclude that PGE's plan does not provide a means by which Oregonians can be "provided the information necessary to make an informed choice" as Necessary Principle 1 requires. Sections of this order setting out our specific conclusions contain more detailed discussions of these Objectives and Principles.

What we want is restructuring that is likely to preserve most of the benefits of the present system and yet move significantly toward retail choice and the benefits it can bring. We describe below an acceptable alternative to PGE's plan which will meet our goals and the Governor's Principles.

Based upon the considerations described above, the Commission will approve a more narrowly drawn change in PGE’s operation. It is not a repudiation of PGE's proposal in its entirety, but takes impetus and some specific elements from that plan, as well as from the other proposals before us. It will provide the opportunity for direct access to industrial and at least some commercial customers (all commercial customers will be afforded direct access if certain implementation issues can be resolved. See discussion in Section XII. D. below). Residential customers will not have direct access at this time. They will, however, have access to a portfolio of options whereby PGE takes title to ESP-provided power and delivers it to customers. The portfolio will bring them the benefits of choice but will protect them from the risks of the open competitive market, at least until sufficient experience is gained to show that full direct access will provide beneficial results. Industrial and larger commercial customers will not have a portfolio option. All customers, however, will have available a regulated cost-of-service rate which will provide service to those who fail to choose another form of service, those who for some reason cannot obtain service under another option, or those who prefer the cost-of-service rate because of its likely stability and predictability.

The restructuring we approve thus takes into account the differing needs of the different consumer classes. It gives choice to all but reduces the risks to the most vulnerable group, smaller customers. As we note below, when we have had more experience with direct access, we will consider broadening the availability of direct access to the smaller customers.

Our decision will allow PGE to divest itself of much of its supply portfolio through an auction. The specific procedures for the auction will be established in a Commission order in the near future. We require some steps by PGE to make certain that sale of these assets does not threaten customers’ access to federal power. Our decision will not, however, allow PGE to sell its hydroelectric assets. We make this decision as a means of assuring that the maximum value of those assets goes to ratepayers. Retention of these assets also reduces the risks that the federal relicensing process now underway for some of these hydroelectric assets (or to begin soon) will be significantly impacted by a sale of the assets. We also provide for recovery of transition costs in a manner and amount that is fair and in keeping with legal constraints imposed upon us by Oregon law. We also provide for consumer protection and adopt a mechanism for protection of funding for certain public purposes that might be seriously jeopardized by restructuring. The proposal we set out will also reduce any chance of deterioration in service reliability.

The plan we offer in this order is an integrated package of many elements, some of which require legislative action for implementation. We have identified the needed legislation in Appendix C. Within 30 days following the conclusion of the 1999 Legislative session, the Commission will notify PGE whether the plan set out in this order or some modification of it may be implemented. We describe this process in more detail at the end of this order.

The restructuring plan we approve in this order meets the statutory mandate we described in Section V. above. The requirement in ORS 756.040 that rates be "fair and reasonable" is met. The evidence establishes that the competitive market for larger customers will be healthy. Sufficient competition will provide reasonable rates for those customers. Our plan incorporates a cost-of-service rate for all customers which will provide a reasonable rate for those who choose it. Residential customers will have the choice of a cost-of-service rate or a portfolio option. That choice will create reasonable rates for these customers. Our plan also meets the directive in ORS 756.040 and 757.020 that service be adequate and safe. PGE, an experienced and competent utility, will remain as the distribution provider and will continue for now to provide metering functions. The reliability of the supply function will also be protected. PGE will continue to supply electricity to many customers, a job it is good at. The ESPs who will also provide electricity will be subject to certification and decertification by the Commission. We believe our plan will not jeopardize safety and reliability.

The restructuring we approve in this order conforms to the Governor's Principles (see Section V. B. above). In our discussion of specific features of the plan throughout this order, we address particular Overriding Objectives and Necessary Principles, such as those relating to public purposes, consumer protection, transition costs, and protection of local governments. Here we provide a summary of how the plan meets the Overriding Objectives and the Necessary Principles.

The first Overriding Objective concerns the achievement of efficiencies and reductions in cost. Our proposal will allow a significant movement toward the competitive marketplace. We expect that the efficiencies and cost savings associated with the marketplace will materialize. The second Overriding Objective requires that restructuring ensure that all customers share the benefits of competition. Our proposal will give all customers choice, either through direct access to suppliers or through a portfolio option which will provide several choices, including the possibility of market-based options. The third Overriding Objective is the protection of environmental quality. Our proposal meets that goal in several ways. It provides for environmentally friendly options for the portfolio, thus allowing customers to choose sources of electricity that may be less harmful to the environment than more traditional sources. Our proposal also seeks to ensure that adoption of environmental protection through the relicensing process for hydroelectric assets will not be delayed or impaired. Our plan also provides a method of funding public purposes, one of which is the development of environmentally benign renewable energy sources.

Overriding Objective Four requires that restructuring not reduce the reliability, safety, and quality of electric service. Our decision will not compromise those public interests in any way. PGE will continue as the distribution utility. It has a fine record of providing reliable and safe distribution service. PGE will also continue to provide metering and other services, at least during a period of transition. Its experience in performing these functions will assure continued safe and reliable service. The final Overriding Objective is the preservation of the benefits of low-cost resources for Oregon customers. Our proposal explicitly accomplishes this objective by requiring PGE to retain its valuable and low-cost hydroelectric assets for the benefit of all classes of customers.

Governor's Principle 1. All Oregonians must have the option to choose their electricity supplier and be provided the information necessary to make an informed choice.

Our plan provides choice either through direct access or portfolio options. The consumer protection plan we approve will ensure that customers have the information they need to make the decisions best for them.

Governor's Principle 2. All Oregonians must have access to basic electricity service at a reasonable rate.

The efficiencies of the competitive market will tend to keep rates reasonable for larger customers. We have also provided for a default provider for larger customers who no longer are purchasing power from their ESP. Our decision to require a cost-of-service rate that will be available to all classes of customers and to require PGE to retain its hydroelectric assets will ensure that all customers have a reasonable rate option.

Governor's Principle 3. The competitive power sales market in Oregon must be a fair one.

Under our restructuring plan, new supply resources will no longer be placed in utility rate base to earn a return for the utility through rates. ESPs and PGE will thus be on equal footing in making decisions on resource development. Moreover, we have made several other decisions to meet this principle. The auction process for the sale of some of PGE's generation assets will be conducted under rules which ensure equal opportunity for potential bidders. The certification process for ESPs will be designed to ensure that entry into the market is accomplished on a fair and objective basis. The rules we will develop to protect consumers against deceptive practices will also ensure fairness in the market.

Governor's Principle 4. Electricity service to Oregonians must remain reliable and safe.

Our decision will comport with this goal. The safety and reliability of the electric supply system depend to a substantial extent upon the quality of the distribution and metering services. PGE, which has long experience and a fine record in providing the distribution and metering functions, will continue to provide these services. The reliability of the supply portion of the system will also be assured. PGE will retain a significant role in supplying electricity. Moreover, the certification process for ESPs will reduce the possibility of service failures on the supply side of the industry.

Governor's Principle 5. Conserving energy and developing renewable resources are essential in protecting Oregon’s environment and sustaining a healthy economy and must continue to be adequately funded.

The System Benefits Charge (SBC) we approve is specifically designed to protect funding for energy conservation and the development of renewable resources. The SBC will provide a stable and predictable source of funding for these programs.

Governor's Principle 6. Low-income Oregonians must have access to competitive markets, and the energy support services currently available to them must be maintained or enhanced.

All customers of PGE will have access to competitive markets, either through direct access to Energy Services Providers or through selection of an option under a portfolio. The SBC described under Principle 5 above will also provide revenue which may be used to aid low-income Oregonians in obtaining weatherization.

Governor's Principle 7. Utilities should have a fair and reasonable opportunity to recover costs of previous commitments.

We have approved a mechanism that allocates to PGE 5 percent of the difference between the market value and the book value of most of its assets. This will allow PGE to recover most or all of its previously incurred costs while encouraging the company to maintain and operate its resources in the most efficient way possible.

Governor's Principle 8. Regulation must continue for products and services for which there is no effective competition.

There is no effective competitive market for distribution of electricity to end users. PGE will continue to perform that function as a fully regulated utility charging a tariffed rate for its services.

Governor's Principle 9. Customers must be protected from any unfair or unscrupulous practices of their electric service providers.

The consumer protection provisions now in effect will remain in place for all residential customers, who will remain customers of PGE, and for those industrial and commercial customers who choose to remain on a regulated cost-of-service rate. Industrial and commercial customers who choose direct access may need new protections. We have developed a comprehensive process for developing and implementing consumer protections for those customers.

Governor's Principle 10. The restructuring of the electric utility industry must not unduly burden local governments.

Restructuring may threaten franchise fees collected by local governments in Oregon. The parties to this proceeding suggested various methods of preserving these revenues. The Commission believes that legislative action is necessary for adoption and implementation of an appropriate method.

Governor's Principle 11. Any exemption to utilities from open access mandates must be balanced with restrictions on marketing outside their service territories and continuation of public purposes funding.

This principle is not directly pertinent to this proceeding, which is a request by PGE to open access. No utility participating in this case has requested an exemption from open access mandates in its own territory.

In its briefs, PGE states that it is reluctant to undertake a plan that resembles the proposal offered by Staff or OIC. It claims that these plans are not actually restructuring plans at all because they deny fundamental change to PGE by requiring it to remain a vertically integrated utility and by denying direct access to small customers. Staff's plan, according to PGE, is "virtually the same economic regulation of monopoly energy supply in Oregon." As a result, PGE claims, Staff’s plan violates Governor's Principle No. 1, which requires that "All Oregonians must have the option to choose their electricity supplier and be provided the information necessary to make an informed choice."

We think that PGE is in error when it derides Staff's plan as no change at all. We think it makes significant changes. The plan we approve in this Order has many of the characteristics of Staff's and CUB's plan. It also, however, incorporates features of PGE's plan. We believe it will benefit the customers in PGE’s service territory. We also believe it conforms to the Governor's Principles. We hope that PGE will adopt it. Ultimately, however, PGE has the choice of either accepting the plan or rejecting it and retaining its present structure.

We believe the plan approved in this order is the best choice for the public in PGE’s service territory at this time. Whether it constitutes a step toward direct access for residential and other small use customers remains to be seen. We have noted the risks that direct access may present to residential customers. It may be that later proceedings will not demonstrate that those risks can be dealt with satisfactorily. It is possible, however, that our experience with the restructuring approved here will indicate that further changes are in the public interest. As residential customers become familiar with having options and with the restructured electric industry, they may want greater choice. Moreover, the experience of other states may give us significant information. We may then work toward providing greater choice through the portfolio system or we may move toward a system of direct access for all. This order is intended to provide flexibility for a move toward greater choice if that is in the public interest. We set out in this order a procedure for an orderly monitoring and review of this plan after implementation to help us determine if additional changes are appropriate.

The plan that we adopt in this case is not intended to be a blueprint for restructuring by other electric utilities in Oregon. We understand that PacifiCorp, for example, has different supply resources and a different operating territory. Any restructuring of its operation might well be different in many respects from the plan we approve in this order. However, although this order treats issues specific to PGE, we intend it to reflect principles that we believe should apply to restructuring by any investor-owned electric utility at this time.

This proceeding presents many legal issues. The parties analyzed nine issues that relate to the Commission’s authority to deal with restructuring, including PGE's duty to serve, the sale of assets, the system benefits charge, stranded costs and benefits, special contracts, Commission authority over ESPs, franchise fees, the hydroelectric trust, and customer differentiation. The parties’ final positions were set out in their briefs. In this Order we draw conclusions on these issues where our decision requires it and indicate the course we will follow in clarifying our authority. Implementation of the plan we approve in this order may require passage of legislation. We address this issue throughout the order. Appendix C to this order summarizes the Commission’s view regarding the necessity for legislation to implement the decisions made in this order.

Below we set out in detail the specific decisions we have made for a form of restructuring of PGE.

PGE proposes to sell all of its supply assets, including generation facilities and supply contracts, in a two-stage auction. The sale of all supply assets is part of PGE’s plan to divest itself of its supply functions and become a regulated distribution and transmission only utility. In support of its request, PGE argues that the sale of the total supply portfolio is in the interest of ratepayers and the general public. It is the method by which transition costs and benefits can be determined with the most certainty. Moreover, PGE claims that the sale is the method by which the highest value for the assets will be attained and the best value brought to all customers. Because the sale will maximize the market value of the portfolio, it will reduce the transition costs which customers may have to pay. PGE also argues that removal of the incumbent utility from the power supply business is necessary to enhance development of the competitive market. PGE asserts that the market is now favorable for the sale of generation assets because demand exceeds supply and companies are seeking to establish strategic positions in key markets. It also points out that healthy general economic conditions in the United States favor conducting the sale now. ICNU argues that sale of the asset portfolio as a whole, rather than piecemeal, will likely bring the best price.

PGE argues that sale of the supply portfolio is consistent with the Governor’s Principles regarding restructuring. The Governor’s Overriding Objectives require that restructuring preserve the benefit of low-cost resources for Oregon customers. PGE argues that this objective does not require that PGE retain the physical assets but only that the benefits of the resources be maintained. If the assets are sold, PGE maintains, the benefits can be retained in financial form and used for the benefit of PGE’s customers. The sale will also, according to PGE, allow competition for the entire supply load of the customers, thereby increasing competition and giving customers the benefit of the inherent value of the supply portfolio and full retail competition.

Staff, CUB, and other parties do not object in principle to the sale of PGE’s non-hydroelectric supply assets. However, Staff and the others ask the Commission to require PGE to retain its hydroelectric assets, both generation and contractual obligations. The sale of the hydroelectric assets, according to Staff, presents various risks that customers and the public should not be subjected to. Staff is concerned that the sale of the hydroelectric assets will not result in receipt of full value because of the Federal Energy Regulatory Commission (FERC) relicensing process now underway (or to begin in the near future) for some of the hydroelectric assets. That process is lengthy and complex and, in Staff’s view, presents uncertainties that may affect the bids of prospective owners. Because the ultimate disposition of the license and the cost of the new license are unknown, the asset value to potential new owners may accordingly be affected. Staff points out that while it may be impossible to assess the exact impact of the relicensing process on the bidding, any dampening of the winning bid would have an impact on rates.

Staff also asserts that the sale of the hydroelectric assets during the relicensing process could harm efforts to protect Oregon’s environment. The facilities involved are located within the Deschutes, Clackamas, and Sandy river basins. The licenses involved were issued many years ago when power generation tended to be emphasized over other resource values. Now, participants are likely to ask for conditions which balance power generation with other public interests, such as protection of fish and wildlife and preservation of recreational resources. In Staff’s view, an attempt to sell a hydroelectric facility during this process will almost inevitably delay the process.

Therefore, there may be a delay in implementation of beneficial changes in license conditions which will balance power generation with fish, wildlife, recreation, and other public uses.

Staff acknowledges the claims of PGE and other parties that FERC will not impede the sale of a hydroelectric facility and transfer of the existing license because of its goal of increasing competition in the wholesale generation market. Staff expresses doubt, however, that FERC’s intentions will prevent harmful delays in the relicensing process. Staff points out, for example, that the length of the relicensing process is a function of often extensive negotiations between the interested parties and the applicant on difficult and contentious issues. Moreover, Staff believes that contentiousness and delay might be increased by uncertainty about how a change in ownership prior to relicensing might affect the status of previously reached agreements. Staff also suggests that the FERC proceedings relating to the sale of PGE’s hydroelectric facilities may be delayed because of intervention by participants in PGE’s relicensing processes.

Staff also argues that retention of hydroelectric assets will benefit the basic cost-of-service rate Staff proposes. For example, the use of those assets to support that rate will reduce reliance on market purchases and on natural gas-fired resources. Since the price of natural gas has varied during the last 20 years, reduction in reliance on that resource will reduce price volatility in the cost-of-service rate. Staff acknowledges that the costs of hydroelectric resources could also change over time because of the necessity for repairs and environmental measures, but argues that the long life of these assets would allow the costs, and thus the rate impacts, to be spread out over a longer period.

Staff also argues that intergenerational inequity might result from PGE's plan. PGE proposes to amortize the net balance of its transition costs over a five-year period. If the hydroelectric resources are divested, customers taking service after the five-year period would not benefit from the proceeds of the sale. Staff claims that it is not reasonable, given the long life of hydroelectric assets, that future customers not share in the benefits of hydroelectric resources. Staff points out that the Governor’s Overriding Objective to "preserve the benefits of our low-cost resources for Oregon customers" does not exclude future citizens from entitlement to the benefits.

PGE and ICNU vigorously oppose Staff’s proposal that PGE be required to retain its hydroelectric assets. These assets are of high value, they assert, especially in relation to book value, and excluding them from the sale will result in higher transition costs to customers. ICNU argues, in fact, that the value of these assets would offset all stranded costs, including Trojan and conservation expenditures. Moreover, minimization or elimination of transition costs will promote direct access and reduce the contentiousness of this proceeding and any others in which transition costs relating to this restructuring application are an issue.

PGE argues that Staff’s concern about the relicensing process is not well-founded. Any prospective buyer, PGE claims, would have no greater risk with respect to relicensing than does PGE. It also points out that FERC is fostering a competitive wholesale generation market and that the sale of hydroelectric assets for use in the competitive wholesale market is consistent with FERC’s goals. Any indication by FERC that a prospective buyer has a greater risk in the relicensing process than the seller would discourage the competitive generation market that FERC seeks to encourage. PGE points out that FERC’s regulations say expressly that it would "decline to adopt a prohibition against transfers during the last five years of a license," noting that "legitimate public interests purposes [are] served by such transfers."

PGE and other proponents of the sale of hydroelectric resources argue that the sale of these assets will not create intergenerational inequity. Present customers will get the benefit of these assets through the transition cost mechanism because the proceeds of the sale will offset transition costs for the non-hydroelectric assets. Moreover, although PGE’s original plan was to amortize the proceeds over a five-year period, PGE points out that the proceeds could be used to fund a smaller, longer-term rate reduction rather than a larger, shorter-term rate reduction. In any event, PGE points out that it was past customers who underwrote the cost and risks of the hydroelectric investments and their claim to the benefits is thus arguably better than that of future generations.

Both PGE and ICNU point out that the Commission has the final say in approving a sale. If the Commission determines that a prospective winning bid, because of relicensing or any other factor, unsatisfactorily values the hydroelectric assets, it can refuse to approve the sale. ICNU suggests that it would be arbitrary and capricious of the Commission to rule now on this issue rather than waiting for the market to offer a price for the assets.

The Commission will approve in concept the sale by PGE of its non-hydroelectric supply resources as set out in its application. Little opposition to that sale was generated during this proceeding. It is a step toward the restructuring of PGE's business and the development of the competitive market. We have been shown no reason to conclude that it will harm the public interest. We note, however, that any sale of utility assets is subject to our approval under ORS. 757.480. Final approval of a sale will be subject to our review of the price and conditions to determine if the sale is in the public interest.

Although we authorize the sale of the non-hydroelectric in concept, we are concerned that our restructuring decision will have an effect on residential customers’ access to federal power. It appears to us that sections 5(b) and 9(c) of the Regional Power Act raise the possibility that residential customers may lose some access to that power under our plan. If PGE decides to adopt the plan we approve in this order, we direct the Company to obtain from BPA a statement as to how BPA will calculate 5(b) net requirements under our restructuring plan (i.e., the provisions relating to direct access and associated company options) and whether restructuring will affect access to federal power under that provision. We also direct PGE to obtain from BPA a statement as to the impact of the sale of resources on the availability of federal power under 9(c). The statement should indicate how BPA would treat each specific proposed resource sale. PGE must submit these BPA statements to the Commission prior to implementation of this restructuring plan. We also will require PGE to hold customers harmless if the sale of a resource results, directly or indirectly, in a reduction in access to federal power by PGE’s customers. That hold harmless agreement shall be filed in writing with the Commission at the time PGE seeks approval for a sale.

We will not, however, approve the sale of PGE's hydroelectric resources. We recognize that it is PGE's goal to divest itself of all of its supply assets and become a regulated transmission- and distribution-only utility. We have no philosophical objection to that goal. However, the interests that we must protect are those of the ratepayers and general public and not those of the utility’s shareholders. We believe this sale presents unacceptable risks to these groups. We believe that the relicensing process underway for some of these assets could negatively impact the price obtained for the assets if they were sold now. An attempt to sell the assets now could also jeopardize worthwhile environmental initiatives by delaying the relicensing process. We are not persuaded that FERC’s initiative to promote a competitive wholesale market would be sufficient to prevent delays in the relicensing process. We also conclude that retention of these assets will preserve the benefits of low-cost resources, our goal and one of the goals set out in the Governor's Principles. Their sale would take them out of our reach and create uncertainty. Retention will also eliminate any suggestion of intergenerational inequity between those who take service now and those who take service after the conclusion of the amortization period for transition costs.

We are not persuaded by the arguments of PGE and ICNU that we can merely reject the sale of the hydroelectric assets if the price does not appear satisfactory. It is true, of course, that we can reject a utility’s proposal to sell an asset if the sale is harmful to the ratepayers. But an indication by us in advance of the auction that we would scrutinize every winning bid for hydroelectric assets to determine if the price is appropriate under some indefinite standard would likely discourage potential bidders from participating and could depress the prices. In any event, given the ongoing relicensing process, we do not think it realistic to assume that we will know with certainty what a satisfactory or "appropriate" price is prior to or after the auction. If the bids are in fact depressed, as the evidence suggests they might be because of the ongoing relicensing process, then the harm will be done, even though we may not be able to precisely assess that harm. We note also that the fact that hydroelectric and non-hydroelectric assets might be sold together would increase the difficulty of determining whether the hydroelectric resources are being properly valued.

We are also not persuaded by the arguments of PGE and ICNU that there is a particular window of opportunity open now for the sale or that the sale of all PGE's assets as a package would enhance the value of the assets. As PGE's expert acknowledges, it is in fact not possible to know precisely the right time to sell an asset. Nor do we believe it is possible to determine with any certainty whether packaging all the assets will bring a better price than selling them in two or more portions. The evidence in the record does not convince the Commission that market conditions are so extraordinary now that we dare not miss the chance to allow sale of the hydroelectric resources. In any event, the other reasons we set out for not allowing the sale of the hydroelectric assets are of greater weight to us than the possible benefit of a doubtful bet on the market.

We are also concerned that, under Section 9(c) of the Regional Power Act, sale of the hydroelectric assets will impact BPA’s residential exchange benefits, a program of considerable value to residential and small farm customers in the state. These benefits have totaled about one billion dollars from 1981 through 1997. The parties have argued this issue from various viewpoints. There is agreement, however, that this Commission and the Oregon Legislature cannot resolve this matter. The fact that we have adopted Staff's portfolio proposal under which PGE would take title to the power and deliver it to the end-use customer probably reduces the risk of loss of the benefits of the Residential Exchange Program. However, the importance of this program to residential and small farm customers is of such significance that we cannot disregard any risk to it. We discuss this issue in more detail later in Section E. 1.

PGE has proposed a "Hydro Trust" as an acceptable alternative to sale of all of its supply portfolio. Under this proposal, PGE would sell to the Trust all of its hydroelectric resources at PGE's net investment in the assets plus any stranded costs (or minus any benefits) remaining after the sale of the balance of PGE's supply portfolio. Using the purchase price as its cost basis, the Hydro Trust would then sell power on the open market, cover its costs, then pass on all net benefits (or costs) to PGE's customers.

PGE suggests that a model for the Hydro Trust could be the Oregon Health Sciences University (OHSU). ORS Chapter 353 creates and defines OHSU’s role as a "public corporation." The statutes give it powers and obligations and exempt it from certain statutes generally applicable to public entities such as local or municipal governments or state agencies, while making other provisions applicable to it. The statutory scheme also grants specific powers to OHSU and its Board of Directors, such as condemnation authority and the authority to request state budget appropriations and to conduct audits. PGE argues that legislation to create a Hydro Trust could be modeled on this scheme. It argues that one of Staff's objections to the Hydro Trust proposal—that it does not provide enough assurance that the benefits of the hydroelectric resources will be used for customers and not diverted to other uses—could be easily addressed through legislation. That legislation could direct the Hydro Trust to use all net benefits for the end-use customer and for no other purpose. Thus, any deviation from this purpose would be subject to legal challenge.

Staff opposes PGE’s Hydro Trust proposal. One of Staff's concerns is that the Hydro Trust Board could use the net benefits for other public purposes. Staff believes that its own proposal to retain the hydroelectric assets would provide greater certainty that the customers would retain the net benefits over time. Staff also believes that the Hydro Trust would put customers at greater market risk than if they were able to purchase the output of the hydroelectric assets at cost. Staff also notes that the Hydro Trust proposal mixes the transition costs (or benefits) from thermal resources in with hydroelectric costs. Staff argues that the thermal transition costs (or benefits) should not be combined with hydroelectric costs but should instead be charged (or credited) to customers through a separate competitive transition charge. Staff also argues that the Hydro Trust allocates hydroelectric benefits to all customers, instead of to those receiving the cost-of-service rate option, and thereby dilutes the benefits to small customers. Moreover, Staff claims that the Hydro Trust proposal does not address the possible impacts of selling or transferring the hydroelectric assets during the relicensing process. As an alternative, Staff suggests that PGE sell the hydroelectric assets to a for-profit entity at book value contingent on the new owner selling at cost to cost-of-service rate customers.

PGE's proposal for a Hydro Trust needs substantial development before we can endorse it. On the one hand, it offers better assurance than sale of the assets that the benefit of the hydroelectric resources would be preserved for PGE's present customer base, one of the goals set out in the Governor's Principles. It would also allow PGE to achieve its goal of divesting itself of its supply resources and functioning as a distribution-only utility. However, we are not ready to agree to that form of restructuring at this point. The structure, operation, and accountability of a Hydro Trust need thorough examination beyond the spare outline set out in the record of this proceeding. In particular, we would want assurance that the benefits of the hydroelectric resources would go to customers of PGE and not to other purposes. Moreover, as we noted above, any delay in the relicensing process caused by a transfer to a Hydro Trust could hamper the implementation of licensing conditions that are designed to further environmental protection and other public benefits.

In any event, as PGE acknowledges, legislative action is required to allow creation of a Hydro Trust. PGE's specific suggestions for such legislation, based upon the statues creating the Oregon Health Sciences University, answer some of our concerns. However, they do not meet all of our concerns and we cannot wholeheartedly endorse the concept in the abbreviated form set out. If PGE is successful in obtaining enabling legislation to give us the authority to create and implement a Hydro Trust in a form that solves all the potential problems we have described, we will consider any reapplication by the Company in light of our specific concerns and our statutory mission discussed throughout this order.

All industrial and larger commercial customers will have the direct access option. It is apparent from the record that these customers desire such direct access. Individually or through aggregation, they tend to be large enough to be very desirable customers for power marketers. The development of a healthy competitive market for these customers is therefore likely. These customers are also well informed about their options, experienced in negotiating with suppliers and in dealing with complex transactions, and are thus able to make sound decisions on their energy supplier. They will be in a position to benefit from the competitive market and to avoid the potential problems. The Commission concludes that it is in the interest of these customers to have direct access. As we note in Section XIII. A. 4 above, we will require PGE to take steps to guarantee that restructuring does not threaten customers’ access to federal power.

The only issue disputed in connection with direct access for commercial customers is whether there should be a minimum load size for eligibility. Staff's original position was that only commercial customers with over 30 kW demand would qualify for direct access. Staff based this recommendation on its general concern that smaller customers would not necessarily share in any of the benefits of the competitive market, in the short term or perhaps long term, because of their relative unattractiveness as customers in comparison with larger customers. Staff’s specific 30 kW line of demarcation between those eligible and those not eligible was based on the difficulty of distinguishing between residential customers and commercial customers who have low demand. Other parties argued that this limitation and Staff’s general differentiation among the customer classes are arbitrary. Staff has since modified its proposal to allow for the possibility that the 30 kW threshold for commercial customers could be removed so that all commercial customers could share in direct access. This change is conditioned, however, upon a determination that "effective customer class definitions can be developed and applied to distinguish between residential and commercial customers." Staff expressed doubt in its briefs that such a distinction could be made as a practical matter.

We agree with Staff that all commercial customers, even smaller ones, should be eligible for direct access provided the differentiation between commercial and residential customers can be maintained. Most of these small commercial customers are experienced in business matters and can evaluate the risks and make informed decisions. However, the problem of actually making the distinction in the real world is significant, as Staff points out. We will, for now, leave the 30 kW threshold in place. We direct Staff and the other parties to work together to attempt to arrive at an agreement on this issue. They should report their conclusions to us within 90 days of issuance of this order. If we are convinced that a working definition has been developed, we will amend this order to allow all commercial customers to have direct access.

PGE, ICNU, and other parties argue that residential customers and small commercial customers should be eligible for direct access. Their arguments focus on the basic restructuring arguments set out in Section VI above regarding the benefits of the competitive market. They argue that allowing direct access to all customers will encourage development of a robust market and will lead to innovative pricing and services. They argue that there is no good reason to deny the opportunity for choice to these specific classes of customers. They claim that a competitive market will exist even for smaller customers and that these customers are capable of making informed choices. Although these parties note that a reduction in rates cannot be guaranteed, they claim that the evidence supports a conclusion that reductions are likely. These parties also claim that the safety and reliability of the system would be maintained under PGE's proposal to allow direct access to all customers and that appropriate consumer protections would continue. They point out that PGE's agreement to include a portfolio in its plan should calm fears about risks to small customers.

Staff and other parties oppose direct access for residential and small commercial customers. They express doubt about the development of a good market for these customers. They are skeptical that customers would obtain any reduction in rates under direct access. Moreover, the availability of direct access to these customers would

undercut the development of a competitive market through the portfolio. They argue that the portfolio options will provide these customers with substantial choice without the risks attendant on direct access.

Residential customers and small commercial customers (less than 30 kW demand) will not have direct access under the plan we will approve, either individually or through aggregation. Our decision to deny direct access to these customers will be controversial. We make it after careful consideration. We base it on the considerations we set out above in our general conclusions (See Section VII above). First, as a class, residential customers, in contrast to industrial and larger commercial customers, do not appear to seek direct access. The tenor of the remarks made at public sessions and in other expressions of public sentiment we have received indicates indifference and even hostility to direct access. The lack of enthusiasm among these customers for direct access is based upon many factors, including fear of rate increases, loss of consumer protection, loss of worthwhile environmental protections, and many other factors. The experience gained through pilot programs in Oregon is also instructive as to the attitude of the public. PGE points out that a significant proportion of residential customers in the PGE pilot program who were aware of the option made a choice for change. However, the fact that most failed to acquaint themselves with the option, despite earnest marketing by the two ESPs who sought their business, suggests that direct access is not a priority to residential customers. That lack of enthusiasm for direct access by residential customers may have contributed to the ultimate decision by those ESPs to reduce or end their participation in the pilot program. Certainly, the termination of participation by the ESPs does not support a contention that residential customers seek direct access. We agree with several parties that the pilot programs are imperfect testing grounds, given their limited scope and duration, but they are better evidence than the suppositions regarding the benefits of restructuring offered by many parties.

We also note that the evidence that a meaningful market for smaller customers exists or will develop is not persuasive. As Staff and CUB point out, ESPs are likely to move first to provide service to industrial and larger commercial customers. That has been the case in the pilot programs in Oregon. That has also been the pattern in other states where some form of direct access has been implemented. Our present low rates may make it unlikely that ESPs will expend substantial resources to attract small customers. The lack of enthusiasm among residential customers, noted above, is likely to work against development of the market. The prospect that there will be only a weak, limited market for residential customers makes the risk of price instability and price increases more than we care to impose on these customers. As we have noted, PGE's speculation about price impacts is not supported by persuasive evidence and is not convincing.

Our decision not to make direct access available to small customers is also founded on our belief that the introduction of a portfolio mechanism will give them many of the promised benefits of direct access while minimizing the risk. Inclusion of a portfolio option in any restructuring plan adopted by the Commission is supported by the parties, including ultimately PGE. A portfolio will offer choices to participants, giving them some control over sources of power and environmental impacts, for example. The maintenance of a default rate based upon cost-of-service will provide a choice for those who seek the stability of traditional regulation. As Staff points out, the competition inherent in a portfolio mechanism will likely increase the pace of innovation. It may also help in the development of a competitive market for these customers. Moreover, it is likely that whoever supplies the energy under a portfolio, PGE or ESPs, will purchase the energy on the wholesale market and thus bring the benefits of wholesale competition to residential customers. We also note and take into account that the response of the public to the portfolio idea has been very positive.

A portfolio option will also reduce the risk of loss of the benefits of the Bonneville Power Authority Residential Exchange Program, which provides substantial rate benefits for residential customers and small farm customers. As we noted above, these benefits have totaled about one billion dollars from 1981 through 1997. The Public Power Council and others suggest that if residential customers were to be served by an entity other than a utility, the benefits might be jeopardized. PGE and other parties downplay the risk. PGE argues that the BPA subscription process will not be "administered in such a way as to penalize customers served by competitive ESPs." Pope & Talbot agrees and adds that PGE can preserve the benefit by assigning the right to serve. Whatever their assessment of the threat, however, most parties acknowledge that this matter is a federal matter not within the jurisdiction of this Commission or the Oregon Legislature. We agree, and thus cautiously treat a threat which we cannot eliminate by our own actions or decisions. Our portfolio structure will reduce the risk of loss of these benefits.

One important question we address is whether the inclusion of a portfolio option for residential and small commercial customers argues for also giving them direct access. Some parties, ICNU in particular, argue forcefully that the presence of a portfolio option for everyone makes direct access no longer the risky matter for small customers that it seemed without that option. However, we have concluded that an attempt to provide both direct access and a portfolio to small customers is not appropriate. It will inevitably make the portfolio service less attractive to providers and thus undercut the development of the portfolio as a means of providing real choice to customers. An ESP may well decide, and logically, that the ability of these customers to abandon the portfolio and go to direct access if the price is better at a particular time will reduce the likelihood that the ESP will make a profit. ESPs may thus opt to stay away from the portfolio, thereby weakening the usefulness of that part of our plan and perhaps throwing small customers into direct access and the risks we are trying to avoid.

We also believe that allowing residential customers to have direct access alongside portfolio options may have a negative impact on the likelihood of maintaining the benefits of the BPA Residential Exchange Program. That risk is one of the reasons we have decided to include a portfolio structure in our plan, as we noted above. Inclusion of the direct access option alongside that portfolio structure may increase the likelihood of loss of the benefits. The benefits are too important to risk merely for the sake of granting direct access to residential customers.

Under the proposals of PGE and ICNU, all customers would have access to a portfolio of offerings. Staff opposes portfolio access for industrial and larger commercial customers. It argues that entry by ESPs into the competitive market would be less likely if customers were offered portfolio options that might have the same pricing choices as direct access. Thus, denial of the portfolio option to industrial and large commercial customers would enhance the potential for development of a competitive power supply to these customers.

The Commission concludes that industrial customers and larger commercial customers (30 kW demand or greater) should not have a portfolio option. Development of the competitive market for these customers could be constrained if ESPs were faced with competition from portfolio options that provided similar prices or conditions. Moreover, as we describe below, our decision in this order will make PGE a reseller of power to portfolio customers. As the reseller, PGE will be allowed to recover the costs incurred in providing power delivery services and the cost associated with the systems and other mechanisms needed to make available and handle the portfolio options. This portion of the overall rate for a portfolio option would be regulated. The direct involvement of PGE, the incumbent utility, in the provision of portfolio power to industrial customers would make it necessary for the Commission to expend resources to guard against the possibility of anti-competitive pricing activities.

The Commission’s decision to have a portfolio option for residential and small commercial customers necessitates resolution of several important issues: management of the portfolio, number and type of options, method of selecting the options, pricing of options, and related matters. Several parties set out their views on the issues. Some of the proposals are detailed while others focus on the issues important to the party and leave other matters to the Commission. We briefly describe the parties’ views below and then set out our conclusions.

PGE argues for a portfolio managed by ESPs containing four market-based options, one of which is a default rate for those not choosing another option. The default rate would not be a cost-of-service rate and would not be offered by PGE. PGE's testimony and briefs are silent on most other portfolio-related issues. ICNU’s portfolio would be quite similar, offering a "limited number of market-based" options and a "green" (environmentally friendly) option. It would be managed by an entity other than PGE. The United Sewerage Agency (USA) also argues that the management of the portfolio would best be handled by an entity other than PGE. USA suggests two or three options, including a renewable power option and a default rate. The Building Owners and Managers Association (BOMA) asks that the portfolio contain base, green, and variable options.

CUB and other parties propose a portfolio that would be product-based. It would contain a basic cost-of-service rate consisting of retained hydroelectric resources, BPA subscription power, and market purchases as necessary. Customers receiving this rate would not see much change from the regulated rate now in place. The portfolio would also offer a small number of renewable energy options. The portfolio would provide for clear comparability among the options so that customers could make informed decisions. The selections would be determined by the Commission or by a customer board.

PG&E Energy Services (PG&EES) does not favor a portfolio, arguing that it would not bring the benefits of competition to customers and that whoever manages it could not adequately represent the interests of the various customers who use the portfolio. If a portfolio is offered, PG&EES believes it should be parallel with direct access, at least for commercial customers. PG&EES argues further that PGE should not be allowed to compete directly through a portfolio, although it might be allowed to do so through an affiliate. Billing and collection should be handled directly by the ESPs to allow them to develop a relationship with the customers. In any event, PG&EES believes that a portfolio option should be viewed as transitional to direct access and not as a desirable permanent part of restructuring.

PacifiCorp supports a portfolio option for residential and small commercial customers but not for larger customers, who would have direct access. It favors an open portfolio model under which no arbitrary limit is imposed on the number of options. It believes the open model would be likely to lead to more innovation and efficiency. It suggests that the ESPs offering the energy should be identified.

The City of Portland supports a regulated portfolio. It asks that the Commission consider the possibility that local governments should have a significant role in managing the portfolio. It argues that local governments would be in a position to guarantee that the operation of the portfolio is non-discriminatory and that the interests of customers are otherwise protected. It points out that the operation of local governments is visible and directly accountable to the people. Eugene Water and Electric Board (EWEB) suggests that the Commission consider performance-based rates before deciding on a portfolio. If the Commission adopts the portfolio approach, EWEB suggests that PGE be required to continue providing meter, billing, and collection services. The Renewable Northwest Project (RNP) asks that the Commission require that the portfolio have several green options, with definitions and details determined by a technical work group.

Staff offers the most complete description of a portfolio proposal. Under Staff's plan, PGE would be the manager and the direct provider of the electric service. The ESPs would sell energy to PGE, although Staff would consider the possibility of ESPs being allowed to market directly. Staff does not set out a specific number of options but notes that the costs of management would increase with the number of options. It suggests that the Commission establish the number and that a panel of customers be convened to identify the sources of the energy.

Under Staff's plan, neither the charges ESPs would make to PGE for energy nor the ESPs’ earnings would be regulated. PGE's share of the ultimate tariff price charged to customers to recover its costs of providing portfolio service and distribution costs would be regulated. Staff designed its proposal so that portfolio customers would share in the benefits of the hydroelectric assets that PGE would retain under Staff's proposal (discussed above in Section XIII. A. 2.). Staff also argues that PGE’s ownership of the power it buys from ESPs would ensure that BPA benefits to residential and small farm customers would be retained. Staff's portfolio would be separate from its proposed cost-of-service rate discussed below.

The Commission decides as follows with respect to the portfolio offering. The portfolio is a separate and distinct service from the cost-of-service rate discussed below. The portfolio will offer no more than four choices to begin with to keep down costs to the portfolio manager. The portfolio will be managed by PGE, which will take ownership of the power from the ESPs. The Company obviously has expertise in matters of this kind and will provide skilled service without the necessity for a difficult transition. This structure is also designed to reduce the risk of loss of access to federal power, an issue we discussed in Section XIII. A. 4., above. Moreover, as we decided in that same section, PGE will retain some supply assets and will be the monopoly distribution utility. Management of the portfolio is part of managing the system.

A consumers’ panel formed at the direction of the Commission will determine the portfolio choices. We make this choice to provide a say to the end-users and to remove the Commission from day-to-day management of the portfolio offering. The offerings will be subject to review and change twice a year by the consumers’ panel. ESPs will supply the power. They will be chosen by a bidding process. The ESPs’ charge to PGE for power will not be regulated. However, PGE's charges for transmission and distribution and for other costs associated with managing the portfolio will be regulated and tariffed in accord with established principles of regulation. Otherwise, the Commission will be involved in the portfolio offerings only if problems needing our resolution occur.

Staff proposes that PGE be required to offer a cost-of-service rate, which would be available to customers in every class. It would also serve as the applicable rate for those making no choice. The cost basis for the rate would derive from the cost of resources retained by PGE, plus market purchases or sales needed to match loads and resources, plus the cost of any BPA purchases dedicated to eligible residential and small farm customers. Transition costs would also be included in the calculation of the rate. The rate would be regulated by the Commission under the statutory standard that rates must be "just and reasonable."

The cost-of-service rate would, in Staff's view, provide a viable option if competition does not develop for the provision of electric service. It would also retain for all customers the option of benefiting from the value of the resources the Commission requires PGE to retain. The cost-of-service rate would also be likely to provide more stability in rates than would any form of market-based rate, such as those occurring under direct access and under the portfolio PGE now agrees to incorporate in its plan. Instability in rates would be a particular problem, Staff believes, for residential customers and especially for low-income customers who might be unable to budget for varying rates. The customer option of choosing the cost-of-service rate may also act as an incentive to portfolio suppliers to keep their rates down. CUB, NWEC, and ICNU support a cost-of-service rate for the same general reasons as Staff. However, these other parties, especially ICNU, disagree with Staff on some significant matters concerning this type of rate.

Under Staff's proposal, residential and small commercial customers could move from the cost-of-service rate to the portfolio and back. Some restrictions, such as a charge or a restriction on the timing of a move, might be imposed to prevent such moves from harming PGE or other customers. The conditions would be set out in the portfolio offers and approved by the Commission. On the other hand, industrial and commercial customers who choose direct access could not move back to the cost-of-service rate. This restriction is designed to prevent industrial customers from switching back and forth based on price in what Staff calls tariff arbitrage based on gaming rather than on efficiencies. Unrestricted switching would, in Staff's view, cause either PGE or other customers harm. Staff suggests, however, that conditions to allow such movements could be developed.

PGE and other parties assail Staff's cost-of-service rate proposal as a vestige of regulation at odds with the movement toward real competition. Moreover, they argue that the cost-of-service rate could distort the market. The assignment of certain supply assets, in this case hydroelectric assets, to serve the one rate could guarantee that the rate is lower than market rates. According to the opponents, such a rate would be artificially low—the product of government fiat rather than the product of efficiency and innovation. Moreover, creation of an artificially low cost-of-service rate by the assignment of hydroelectric assets would unfairly discriminate against those who choose direct access and (under Staff's proposal) forgo the direct benefits of the hydroelectric assets. On the other hand, if the cost-of-service rate were higher than market price, the entity providing it, probably PGE under Staff's plan, would be unable to recover its costs. PGE also argues that a cost-of-service rate is not necessary as a default because a governmental body or other entity could aggregate to provide a default service. PGE also claims that the pressures of the market would cause ESPs to shield customers from the price volatility feared by Staff. In any event, PGE argues, changes in market prices are beneficial as price signals which increase efficiencies.

We adopt a cost-of-service rate. A cost-of-service rate will reduce for all customers the market risk which is one of our primary reasons for not adopting PGE's plan as a whole. It will also provide customers with a stable rate—a matter that is of particular importance to residential customers. We will also adopt Staff's proposal that industrial and commercial customers who choose direct access would not be allowed to go back to the cost-of-service rate. We agree with Staff that such switching, with attendant resource planning and cost effects, could harm both the customers remaining on the cost-of-service rate and the company providing that service.

We will modify Staff's cost-of-service rate proposal, however. Staff’s proposal that the benefit of the hydroelectric assets be allocated solely to the cost-of-service rate has caused much of the controversy on this issue. While we do not agree with the claims of some parties that adoption of that provision would be unlawful discrimination, we do believe that sharing the benefits of the hydroelectric assets among all customers has merit from a policy standpoint. As several parties point out, all customers have paid for the hydroelectric resources through rates and thus have some reason to feel they should share in the benefits. The requirement in the Governor’s Overriding Objective 5 that the benefits of our low-cost resources be preserved for Oregon customers does not distinguish among customers on the basis of what type of service they choose. Moreover, we do not believe that the benefit direct access customers may obtain by choosing to go to the market is certain enough to justify entirely denying to them the benefits of the hydroelectric resources.

Additionally, allocation of the benefits of hydroelectric resources only to cost-of-service rate customers could act to the detriment of those industrial and commercial customers who have selected direct access. It could discourage participation in the market and raise the possibility that direct access might appear to be less viable than it really is. We conclude it would be better to find a way to share among all customers, to some extent at least, the benefits of the hydroelectric assets. We therefore conclude that a billing credit on the Power Delivery Service tariff be given to all customers as a means of spreading the benefits of the hydroelectric assets to them. If PGE accepts our plan, we direct Staff to work with PGE and the other parties to develop a method to equitably share the benefit of the hydroelectric assets among all classes of customers.

The Commission notes that it is necessary to provide a default supplier for customers who choose direct access. Under our decision above, once eligible customers choose direct access, they cannot return to the cost-of-service rate. If there is no default provider, a customer could be without service if, for example, its ESP ceased operation. We direct PGE to undertake a process to select an ESP that will agree to be the default provider. The selection is subject to our approval. When the supplier is selected, it will serve as a default provider for direct access customers. It must agree to serve in the role of default provider for at least one year. PGE will not take title to the power in this instance so that power costs for other customers are not affected by the default service. There will be no time limit on how long a customer can receive service from a default provider. Staff is also directed to coordinate the provisions for obtaining service from the default supplier with the rulemaking proceedings regarding consumer protections discussed in Section XIII. K. below.

PGE broadly defines transition costs as costs that would have been recovered under regulation that can no longer be recovered due to the transition to a competitive market. To be recoverable, PGE says, the costs must have been prudently incurred as part of a utility’s obligation to serve, have been fully mitigated, and be currently included in rates. The general categories, according to PGE, are generating plants, contracts, energy efficiency and Public Utility Regulatory Policy Act (PURPA) obligations, and services that will be discontinued. PGE proposes to collect its transition costs over a five-year period by a fixed charge based on usage included in its tariffed power delivery charge.

The parties generally agree that PGE should be allowed to recover some of its transition costs. They differ, however, with PGE and among themselves, on several matters:

PGE includes in transition costs the FASB 109 asset, a future tax liability payable to the United States Government upon the sale of certain assets. The Company’s calculation of the FASB 109 asset decreases accumulated deferred income taxes by the amount of the tax benefit customers have received, due primarily to accelerated tax depreciation expense. These benefits were flowed through to customers prior to 1981. PGE's calculation excludes recognition of two other tax-related items: excess deferred income taxes created by tax rate reductions, and "Post-ERTA Investment Tax Credits" (ITC) representing an amount of unamortized ITC that remains on the books. PGE argues that certain Internal Revenue Service (IRS) requirements preclude recognition of these items in transition costs and that Staff's proposal to include these amounts in the transition cost calculation could require the Company to immediately owe to the IRS all deferred taxes related to previous accelerated depreciation. PGE suggests that it and Staff request a ruling from the IRS on this issue.

Staff argues that PGE's proposal would recover from customers costs which they have already paid and would retain benefits to which customers would be entitled absent restructuring. Staff argues that any IRS ruling would not determine ratemaking treatment. Even if these amounts cannot be included in transition costs, Staff suggests that the Commission consider adjusting the percentage of recovery it allows PGE as a means of taking into account what customers have already paid relating to the transition costs investments.

Staff also disputes the inclusion of certain other costs in the transition cost recovery mechanism. It argues that capital restructuring costs included by PGE (representing the premium paid by PGE to buy back long-term debt) have not been shown to be the best way to achieve capital restructuring and should not be allowed. PGE argues that these are capital costs which PGE is incurring in an attempt to mitigate its restructuring costs and should therefore be recovered as transition costs.

Staff also objects to inclusion of PGE's Northwest Natural Gas capital contribution costs. PGE maintains that this contract, which was entered into partly in anticipation of construction of additional generation and partly to serve the Beaver power plant, was appropriate for a vertically integrated utility because it helped the company meet anticipated load. Staff believes these costs are not for an investment that is used and useful and should be excluded.

Staff also questions inclusion in transition costs of PGE’s employee retention cost component associated with transferring the billing and collection functions to a different entity. Staff argues that PGE has not proved this retention bonus is necessary to induce personnel to stay with the company. PGE points out that these costs are crucial to it now, because it needs to retain certain employees for an indefinite time and is not even certain that the jobs will be eliminated. It points out that it is a common business practice to incur costs to retain employees under similar circumstances.

ICNU argues against inclusion of the Vansycle Ridge Project in transition costs. The Vansycle Ridge Project is a 22.5 megawatt wind powered generator under construction in Eastern Oregon. PGE has agreed to purchase the output of the project. PGE proposes to include the purchase contract in the supply portfolio it will sell at auction and to include the difference between the purchase price and the contract purchase price in transition costs. ICNU notes that the project is not completed and is not providing service. Accordingly, the prudence of the project and whether it will be used and useful cannot yet be determined. ICNU argues that, while the project should be included in the sale proposed by PGE, the Commission should make no determination as to its inclusion in transition costs until the project is complete and producing power and a review of the prudence of the purchase has been made. It claims that PGE made its commitment to the project after it should have foreseen that the electric industry was moving toward open access and more competitive power purchase prices. ICNU also argues that if continuation of the project was necessary for completion of the Enron merger, shareholders should be responsible for the cost.

PGE responds that the Vansycle Ridge Project was undertaken in 1993, long before it could have anticipated open access and the competitive market. Moreover, the project has long been a part of PGE's Integrated Resource Plan (IRP). The Commission has already reviewed the project and found its costs justified, according to PGE. Its completion was not accomplished merely for merger purposes. PGE also argues that an item need not be operational to be included in transition costs. For all these reasons, PGE believes the decision on prudence can be made in this order and no additional prudence review is needed.

The Commission concludes that Staff's objections to the exclusion of the two tax items and the inclusion of the other specific items in transition costs are sound. Excess deferred income taxes and Post-ERTA ITC amounts will be included in the transition costs calculation; the other items will not be included. Staff may join with PGE in pursuing a ruling from the IRS on the two tax-related matters described above and report the results to us. Because of these changes and others set out in this order, PGE must refile its transition costs estimates and its proposed Competitive Transition Charge (CTC).

We will not include the costs associated with the Vansycle Ridge Project in PGE's transition cost calculation at this time. The project is part of an effort which we have found important to the development of resource knowledge and assessment. We have indicated so, as PGE points out. However, the costs are not currently included in rates. As we noted in Order No. 98-353 (at 9), mitigation of transition costs is based upon prudence. Prudence is determined by the reasonableness of the actions "based on information that was available (or could reasonably have been available) at the time." Our general approbation of the project was not a finding of prudence. We conclude that PGE will have to make a showing of prudence when it seeks to enter the cost of this project into rates through a transition cost charge or otherwise.

Staff and other parties have argued that PGE’s owners should share in the payment of transition costs. Staff's proposal would require direct access customers to pay 80 percent of their share of transition costs as a means of recompensing them for the loss of the benefit of hydroelectric resources under Staff's plan. PGE argues vigorously on policy and legal grounds that it should be allowed recovery of 100 percent of its transition costs. It argues that the proposed auction will establish the value of the assets and is the best way to extract the maximum value of those assets. Moreover, PGE claims that under the auction scenario it needs no incentive to mitigate these costs. It points out, in addition, that no party has alleged that PGE has failed to mitigate its transition costs. It argues that Staff's proposal to allow direct access customers to pay less than their share of transition costs as recompense for their not sharing in the benefits of retained hydroelectric resources is not logical because it makes PGE shareholders pay for a benefit that goes to cost-of-service rate customers. PGE also claims that any decision allowing it less than full recovery would violate Governor's Necessary Principle 7, which requires that a utility be given "a fair and reasonable opportunity to recover costs of its previous commitments."

PGE asserts, in its legal argument, that allowance of anything less than full recovery of transition costs would violate the "takings clause" of the Fifth Amendment of the United States Constitution made applicable to the states by the Fourteenth Amendment. PGE relies on two U.S. Supreme Court decisions, FPC v. Hope Natural Gas Co., and Duquesne Light Co. v. Barasch. These cases mandate that utilities be allowed a fair rate of return taking into account "the risks under a particular rate-setting system and . . . the amount of capital upon which the investors are entitled to earn that return." Hope at 602. The particular method used by the regulatory agency to set rates is not mandated so long as the method used leads to overall results which meet the constitutional standard of providing adequate compensation consistent with the risks allocated to the utility and commensurate with compensation for similar (unregulated) enterprises bearing similar risks. See Duquesne at 313.

According to PGE's analysis of Duquesne, a regulatory body can change its rate setting method prospectively. However, it cannot do so in a way that reallocates risks to investors where investors previously had been denied rewards on their investments. PGE argues that adoption of Staff's proposal for the sharing of transition costs would constitute a prospective change in method which would deny PGE the opportunity to fully recover its investments and obligations. It claims that the Commission has already passed judgment on the prudence of these investments and has determined that PGE may recover in its rates the investment in and costs associated with these assets. If the market value of these assets proves to be less than their book value, denial of full recovery of the difference would be an unconstitutional taking because it results from a mid-stream change in the method of setting rates.

PGE notes that some parties may argue (as indeed Staff does) that the test for an unconstitutional "taking" in the regulatory context is whether the net effect of the regulatory body’s order, rather than the impact of one portion of that order, violates the company’s right to adequate compensation for its investment. PGE argues, however, that the present situation is not like a typical rate case in that there is no other, countervailing, aspect of the proceeding which can "make up" for the confiscation of PGE's right to recover its prudent investments from customers. Thus, an order providing for less than full transition costs recovery would be facially unconstitutional.

Staff indeed argues that PGE’s argument is premature because the issue under Hope and Duquesne is whether the company's rates, as a whole, allow it sufficient revenue. If restructuring is approved, Staff argues, the Commission will take transition costs into account in setting rates. Thus, what Staff describes as the "hypothetical disallowance" of transition costs in this proceeding cannot be said to result in confiscatory rates. Staff also maintains that, in any event, PGE need not accept the Commission’s decision on transition costs but can withdraw its restructuring filing, thus eliminating any chance of confiscatory rates.

PGE responds to Staff's latter argument by asserting that the government may violate the takings clause if it requires a person to give up a constitutional right in exchange for a discretionary benefit conferred by the government. Dolan v. City of Tigard establishes a two-part test to determine constitutionality in this context. PGE applies the test to the facts of the present case as follows: first, there must be an essential nexus between a legitimate state interest and the requirement that PGE accept a discount on recovery of its transition costs; second, there must be a "rough proportionality" between the condition (the discount on transition costs) and the discretionary benefit (permitting PGE to disaggregate and sell its generating assets). PGE avers that, while the first condition might be met, the second clearly is not. PGE notes that one of Staff's justifications for the condition is to provide an incentive for PGE to mitigate its transition costs by getting the best possible price for its generation assets. PGE argues that no such incentive is necessary here because PGE's plan to presently sell the assets at an auction makes any further mitigation impossible.

CUB argues that a sharing of transition costs is appropriate from a policy and legal standpoint. It maintains that restructuring alters the risks of the customers and the utility owners and the relationship between them. Under regulation, shareholders undertook risk which required compensation. On the other hand, customers had no risk and had a guarantee of service from the facilities they supported through the ratemaking process. This interest of customers in receiving the value of the utility’s assets is, in CUB's view, an entitlement which the customers would not enjoy under restructuring such as PGE proposes, where the customers will undertake the risks of the marketplace: price uncertainty and the lack of guaranteed service. Thus, according to CUB, as customers become co-risk takers with utility shareholders, the takings analysis should consider both sides’ interests. This may properly lead, CUB argues, to a sharing of the transition costs and benefits which are incurred due to restructuring.

PGE dismisses CUB's legal argument, noting that CUB supports it with no authority. PGE notes that although it favors passing on transition benefits to customers as a matter of policy, it believes that only the utility has a constitutionally recognized property interest in its generation assets.

Under Staff's plan, customers served under the cost-of-service rate and under the portfolio options would receive all the benefit of the hydroelectric resources. Direct access customers would get none. Staff thus proposed that direct access customers pay a reduced share of transition costs to compensate them for this loss of benefits. As noted in the section above on Hydroelectric Resources (XIII. A. 4.), however, we have decided that all customer classes should share in the benefits of these resources. As a result, one of the main reasons for Staff’s proposed transition costs discount to direct access customers is gone. We see no remaining reason to distinguish among the customers classes as to payment of transition costs.

We believe, however, that there is a strong policy basis for not simply setting recovery of transition costs at 100 percent. We will adopt a policy allocating to PGE 5 percent of the difference between the market value and the book value of most of its assets. First, we believe this approach will give PGE an incentive to mitigate transition costs. It will encourage PGE to continue to manage the assets in the most efficient manner it can. It will also provide a strong incentive to the Company to manage the sale of the assets through an auction in a way which will obtain maximum value. It will be in PGE's direct interest to take whatever steps it can to obtain the highest bids possible. It will thus benefit from encouraging the greatest numbers of bidders. It will also have an incentive to make sure potential purchasers are provided with as much information as possible on even terms and to take whatever other steps it can to assure that there is no hint of unfairness in the process that might depress bids.

We want to make it clear that this mechanism is fair to PGE's customers as well as to the company. The incentive we are giving PGE to get maximum value for its resources will also reduce the transition costs customers must pay or increase the transition benefits in which they will share. We believe this mechanism is more likely to benefit customers than would a mechanism which provided no incentives to the company to mitigate the transition costs. This positive situation is made possible in part because of the relatively high value of our generation resources in the Pacific Northwest. We believe PGE’s non-hydroelectric supply portfolio will likely sell at a price near to or greater than book value and that it is therefore probable that transition costs, if any, will be very small. In any event, our treatment of the transition costs is the method most likely to be fair to both PGE and its customers.

This mechanism is consistent with the policy we set out in Order No. 98-353, our order on the treatment of transition costs for electric utilities. That order clearly indicates that less than full recovery may occur. We set out in that order a list of the factors which would be taken into consideration in determining what recovery level should be allowed (at 11). Substantiation of reasonable mitigation efforts is one of those factors. We also said, at 9: "We may allow less than full recovery of transition costs to ensure that mitigation takes place." This decision is also not a departure from the so-called regulatory compact or from principles of equity. PGE has chosen to seek a change in its structure which would remove it from the retail electric supply business. Its proposal is a voluntary move away from the structure of regulation in which a regulated utility is given the opportunity to recover the costs it incurs to provide service. PGE obviously views restructuring as beneficial to itself, as well as to the public. We believe the treatment of transition costs in this order is not unreasonable in the context of a utility generated restructuring. PGE will have the opportunity to review the plan we approve in this order to determine whether it is in the Company’s interests to proceed. We also note that recovery of transition costs over a five-year period is less risky than recovery over the life of the asset. Our mechanism is thus equitable. We also point out that this mechanism is simple and efficient: it will require no additional demonstration by PGE that it has mitigated the transition costs involved. PGE will thus be spared the costs of lengthy and contentious proceedings to determine whether it has mitigated the costs.

This mechanism is not, as PGE claims, inconsistent with Necessary Principle 7, which states: "Utilities should have a fair and reasonable opportunity to recover costs of previous commitments." The explanatory text to that Principle makes it clear that something less than full recovery may be appropriate: "Any policies which allow for recovery of stranded costs should provide incentives to utilities to reduce those costs, allow for an equitable sharing of those costs and not discourage competition." The mechanism we adopt is designed to meet that directive. Moreover, we note that it is symmetric: PGE will receive 5 percent of any net transition benefits (where the sale price exceeds book value) and could thus receive more than the book value of the investment.

Staff's legal position on the "takings" issue is persuasive. The mechanism we have described is not a "taking" of PGE's property. First, it does not establish PGE's rates, and so it perforce cannot be confiscatory. As we note below, PGE must refile its rate proposal if it accepts the restructuring plan we approve in this order. We will review PGE's rates at that point. PGE's claim that there cannot be an offsetting factor which would make its rates compensatory is incorrect. Under either our proposal or PGE's own restructuring plan, PGE will remain a regulated utility with tariffed rates. It is those rates which will determine whether it has been subjected to an unconstitutional taking. We note, moreover, that the Commission cannot impose any disallowance of transition costs on PGE in this case because it is an application which PGE can withdraw. If it accepts the plan we approve, a taking cannot occur. Thus, the Commission cannot be said to be forcing confiscatory rates on PGE. We do not accept PGE's arguments based on Dolan v. City of Tigard, supra. Assuming for the sake of argument that the case may have application to the context of a regulated utility, we conclude that both parts of the "test" set out therein are met by our decision. PGE's claim that there is not a "rough proportionality" between the possible disallowance of some transition costs (if not fully mitigated) and the discretionary benefit at stake (the restructuring plan) is not persuasive. PGE’s claim that no mitigation of transition costs is possible under its proposed plan is not correct. As we noted above, PGE can do much to properly manage its assets before they are sold and to make certain that the auction produces the maximum value. Moreover, as we also noted above, PGE must view restructuring as beneficial to the company. PGE has not shown that the level of recovery of transition costs we establish in this order is out of proportion to the benefit it anticipates.

Our decision here requires that we determine a value for all of the generation assets which PGE will have discretion to sell in accordance with this order. This is necessary so that there will be no incentive for PGE to attempt to increase its total recovery by selling some assets whose market value is greater than their book value while retaining less valuable assets for full recovery in rates. Once PGE has indicated its intention with respect to the sale of assets, we will undertake an administrative process to evaluate those assets not scheduled for sale. When a resource is sold, or when a more recent estimate of market value is made before the end of the five-year recovery period, the estimate will be subject to a "true-up" to match the sale price or later estimate.

The treatment of transition costs described above will apply to all of PGE's assets except the following. PGE has incurred costs for demand-side management projects. One hundred percent of these costs, which cannot be mitigated, may be recovered. The treatment of the costs associated with the Trojan nuclear plant will not be changed by this order. We have ruled on recovery of those costs and see no reason to alter that treatment. In Order Nos. 95-322, 93-1117, and 93-1763, we allowed PGE to recover only 87 percent of its asset costs relating to Trojan over a period ending in 2011. Our decision here will allow it to continue to recover only those costs authorized in those orders.

PGE asks that its transition costs be collected through a Competitive Transition Charge (CTC) which would amortize the transition costs over five years. The unamortized balance would earn a return at PGE's authorized rate of return. The CTC would feature a balancing account to true up revenues if they do not meet projected revenues. It avers that, given the time value of money, a return of less than its authorized rate would be the equivalent of disallowing a portion of the investment and thus an attempt to require shareholders to absorb some of the costs.

PG&EES claims that PGE's proposal would actually yield more for PGE than its actual transition costs. The authorized rate of return contains, according to PG&EES, a premium for the risk attendant to usual utility operation. The collection of transition costs, however, will not present these risks but is essentially guaranteed. Since recovery is virtually risk free, a rate of return equal to that of a virtually risk-free investment is appropriate. PG&EES suggests that the rate be the current yield on a risk-free, five-year Treasury note.

Staff also proposes that the rate of return be less than PGE's authorized rate of return. Staff notes that the balancing account to true up revenues in PGE's proposal would make transition cost recovery significantly less risky than recovery of other investments included in rate base. Thus, recovery at the authorized rate of return is not justified. Staff sets out several possibilities for an appropriate return: the U.S. Treasury security rate with for a similar amortization period (5.6 percent); PGE's marginal cost of debt (6.991 percent); and PGE's embedded cost of debt (7.36 percent). Of these, Staff suggests that the best choice is PGE's embedded cost of debt.

Staff and other parties note that a recent Oregon Court of Appeals decision in Citizens’ Utility Board v. PUC (referred to as the Trojan case) could implicate the issue of rate of return on stranded or transition costs. The court construed ORS 757.355 (known colloquially as Ballot Measure 9) to allow return of, but not on, prematurely retired plant. Staff notes that the reasoning of the case could be applied to stranded investment. If so, and if the Commission approves a plan in this case that would allow a rate of return on any stranded investment, Staff recommends that the Commission consider supporting corrective legislation. PacifiCorp argues that the Trojan decision does not address recovery of stranded costs but focuses rather on ratemaking issues connected with a plant prematurely retired. PacifiCorp points out that transition costs involve costs of resources that are still providing service, and so should not come within the theory of the case. PacifiCorp argues that if the Trojan rationale is applied to stranded costs, restructuring would subject utility shareholders to significant losses. If so, it suggests legislation will be needed to keep restructuring alive.

The Commission concludes that PGE should accrue interest at less than its authorized rate of return on its transition cost account balances. It is clear that the risk on this recovery is less than on assets still providing service to the company. The balancing account acts to provide considerable assurance that the recovery will be fully accomplished. The short amortization period—five years—also reduces the risk. We cannot, however, say that it is risk free. We therefore conclude that Staff’s proposal to set the rate at PGE's embedded cost of debt is a better choice than PG&EES’s risk-free rate. We note the argument that this treatment may discourage electric restructuring because it could cause shareholders to believe they would lose money if the change were made. Since, however, the recovery is less risky than the risk for ordinary rate base assets, we do not believe shareholders would view it as a loss. We do not believe it will dampen enthusiasm for restructuring. We note that this rate of return on transition cost account balances is symmetric, as is the treatment of transition costs in XIII. I. 2. If PGE's customers owe it money, interest will be accrued at the embedded cost of debt. Conversely, if PGE owes its customers money (through transition "benefits"), it will only be obligated to accrue interest at the same rate.

This reduced rate of return will not apply to costs relating to Trojan. Those costs will continue to be recovered at the company’s authorized rate of return. We believe the facts surrounding the recovery of Trojan costs are substantially different from the facts involved in the recovery of PGE's transition costs resulting from restructuring. As we noted above, in our decisions relating to the treatment of the retirement of Trojan, we allowed PGE to recover only 87 percent of asset costs. That reduced recovery will not change as a result of this order. The recovery is to occur through 2011, as opposed to the five-year amortization period for other transition costs set out in this order. As we noted above, the short recovery period for most of the transition costs reduces the risk and justifies a reduced rate of return. The longer amortization period for Trojan makes the risk greater and justifies the higher rate of return. We also note that allowance of the authorized rate of return for retired plant may provide an incentive to utilities to retire plant, such as Trojan, when it is in the public interest to do so. No such incentive exists for the other transition costs discussed in this order. They are the result of PGE's voluntary quest to restructure itself. As we noted above, we do not believe the reduced rate of return on most assets will provide a disincentive to companies to undertake restructuring.

We note here that our order provides for differing treatment for different types of resources. Under our approved restructuring plan, the company will retain company-owned or contracted-for hydroelectric resources. We will continue to establish rates such that the company has the opportunity to earn its authorized return for investments associated with those resources. PGE may sell other, non-hydroelectric company-owned assets, subject to a showing that the sales price meets the public interest test. In any case, whether PGE sells its non-hydroelectric generating plant or not, any stranded costs or benefits will be amortized over a five-year period and earn a return equal to the company’s embedded cost of debt. Trojan will continue to be amortized according to its present amortization schedule and earn a return equal to the company’s authorized rate of return. These differing treatments respond to the unique aspects of the resources and balance the needs of the company with the public interest. Finally, we note that our decision on rate of return for transition costs is a balanced one—the rate will apply equally if there are transition costs owed to the company or transition benefits owed to the customers.

PGE proposes to collect all transition costs by means of a constant per kWh charge to all customers. ICNU argues that this method is unfair and unjustly discriminatory because it alters the way generation costs have been assigned and collected in the past and thus violates the principles of cost causation. ICNU notes that any transition charges would come from three expense categories associated with current and past generation or generation-saving expenditures: the remaining Trojan obligation; debt service remaining from past demand side management programs; and transition costs resulting from the auction of generation resources. In the past, ICNU claims, PGE's generation costs, including Trojan and conservation expenditures, have been classified as both demand and commodity related charges and assigned to customer classes based upon the results of the marginal cost analysis of PGE's system. PGE's proposal would be a major shift.

ICNU proposes, instead, that all transition costs be assigned to customers to reflect both the capacity and energy requirements necessary to serve a marginal load. Based on PGE's most recent marginal-cost study in UM 827, ICNU proposes that 15 percent of transition costs be assigned to customers based on capacity and the remaining 85 percent assigned based on energy. This method, it argues, stays true to cost causation and marginal cost pricing principles articulated by the Commission.

PGE responds by noting that a change in the way generation costs are assigned and collected is not necessarily unfair or unjustly discriminatory. In this case, the change is required because PGE's plan would take it out of the power supply business and it will have no generation costs to allocate. The equal percent of marginal cost methodology used in the past, which requires that costs for all energy-related services be bundled, is not available. PGE claims ICNU’s proposed allocation of the transition costs is based on a proxy generation cost despite the fact that PGE intends to own no generation, PGE's marginal cost study shows no generation demand costs, and the proposed split has no relation to any capacity values that might underlie the costs. PGE argues, moreover, that the costs involved—Trojan, transition, and conservation—are not directly related to distribution costs but rather to generation and power supply. Therefore, the collection of the costs on an energy basis is sound.

As PGE acknowledges, its proposal is based on the marked difference between the traditional vertically integrated utility and what it proposes to become if its restructuring plan is approved by the Commission. As we approve in this order a substantially different restructuring plan, PGE's proposal needs to be refiled. ICNU’s proposal is also apparently based on assumptions about restructuring that will change because of this order. We will consider this issue if it arises again when PGE refiles its proposal to see if in fact the departures from accepted methods of assignment and collection of costs are warranted.

Smurfit Newsprint Corporation (SNC) asserts that it is exempt from payment of transition costs for the interruptible portion of its load under a special contract with PGE. The original contract became effective in 1986. It provided for a firm load, which SNC makes no claim of exemption for, and an interruptible load, for which it does claim an exemption. SNC avers that the contract allowed PGE to interrupt service to SNC in "such a manner as to allow the Company to avoid both short-term resource additions that may be required to serve SNC and longer-term resource additions that may be required by PGE to provide service to all its customers." Thus, SNC claims, PGE was able to treat its service to SNC as a resource rather than a load and could avoid any sunk commitments to provide the service.

Specifically, SNC asserts, PGE's obligation to serve the interruptible portion extended only to resources that PGE had available at a cost that was less than the energy rate paid by SNC under the contract. If PGE did not have enough power to serve this portion of SNC’s load, or power was too costly, SNC would have to buy in-lieu power from the market or from PGE's high-cost resources. Moreover, PGE had the right, beginning in 1990 (with three-years’ notice), to permanently cease service to SNC’s interruptible load in 25 Mwa increments until SNC’s interruptible load was exhausted. Accordingly, SNC claims, PGE could (and in fact did) substitute service to SNC for development of new resources. PGE thus had no obligation to invest in resources to serve SNC and has not "stranded" any costs associated with serving SNC.

SNC argues also that the contract contained no obligation on SNC's part to repay PGE for sunk commitments if SNC ceased taking service from PGE. SNC entered into these contracts with no reason to think it would face additional and possibly significant charges for the service it obtained under the contracts. Had SNC been aware of that risk, it might have decided not to enter into the contracts. SNC argues that the Commission’s decision in Order No. 98-353 supports its contention:

PGE acknowledges the above provision in Order No. 98-353. It agrees with the treatment of special contract customers in that order and states that it "does not propose to charge special contract customers transition costs in addition to their special contract rates. . . . Under PGE's proposal, special contract customers remain on the special contracts and pay special contract rates during the term of the contract." PGE points out, however, that one-third of the power consumed by SNC under its current contract is not priced under a special contract but under standard rates. This portion of SNC’s load is not subject to Order No. 98-353 and would be subject to transition costs. PGE also asserts that when SNC’s current contract ends, "it becomes a customer for which no special contract is in effect and its entire load becomes subject to transition charges."

It is our understanding that PGE has acknowledged that the portion of SNC’s load now covered under its special contract with PGE is not subject to a transition charge. That is clearly the result dictated by Order No. 98-353. The Commission affirms here that that provision applies to SNC’s existing special contract.

SNC’s position appears to be that, because of its 1986 contract with PGE, it should be exempted from any CTC authorized by the Commission (at least for the interruptible portion of its load). It has not established a basis for this exemption. PGE is correct that customers who come on the system become obligated to pay transition costs. That obligation is not based on prior use of the utility’s generation plants and contracts but on the fact that the investments were made to serve PGE's customers over the lives of the various resources. The obligation to pay transition costs cannot be tied to the utility’s need to build particular resources or to make particular investments. The reality is that no customer’s load can be traced to investments in that fashion. If a customer is served through PGE's distribution system (and so would have been served out of PGE's supply portfolio absent restructuring), it becomes liable for transition costs. The only general exceptions we have made are based either on the fact that the customer does not take power from the system (self-generators) or is served under an existing special contract.

SNC’s argument that its 1986 contract provided PGE with a "resource" because it could terminate the obligation to provide power over a three-year period is not a compelling argument. As we noted above, the obligation to pay transition costs is based on the customer’s status as a PGE customer. It is not a pay back for prior use. SNC’s prior use, or non-use, of the system does not change its present obligation. We do not look back at each customer’s history with the utility and calculate its transition cost obligation accordingly. If SNC’s prior arrangement with PGE was beneficial to PGE, it was also beneficial to SNC, as PGE points out. SNC’s claim that not exempting it from transition costs will effectively raise the rate of its prior special contract is mistaken. Its obligation is not a function of its prior contract nor is it somehow proportionate to or added to the rate set out in that contract. It arises from its present use of the system.

If we were to exempt SNC from paying the CTC now and in the future, the obligation to pay the foregone charges would not fall on PGE but on all the other users of the system. The arguments PGE and SNC make based upon their interpretation of the specific provisions of their contract are not on point. The obligation for payment of transition costs under this order will fall on those using the service. Contracts affect the obligation to pay transition costs only as described in Order No. 98-353. If the parties believe some right exists as between them on this issue, they can pursue legal remedies on their own.

At the beginning of the proceeding, PGE proposed that meter, bill, collect, and response functions (MBCR) be performed by ESPs, a position supported by other parties including ICNU, PG&EES, and Pope & Talbot. During the proceeding, PGE modified its original position on these functions. Its present proposal is in many respects close to the position taken by Staff. Both agree that ownership and maintenance of meters should remain in PGE's hands during the early stages of restructuring. PGE would, however, eventually allow customers to select a different meter service provider so that they could obtain the benefit of innovations in metering technology. Staff doubts that significant changes in metering technology will be available for most customers in the near future and maintains that, in any event, ownership by PGE will not delay innovation.

As to billing and collection, PGE now proposes that portfolio customers be billed by PGE, with the company having the option of "outsourcing" this function if it proves cost-effective to do so. Direct access customers would be billed by ESPs. Staff’s position is that direct access customers should be allowed to receive separate bills from PGE and the ESP or a consolidated bill. Customers on the cost-of-service rate or portfolio service would be billed by PGE.

PGE and Staff agree that response to outage or emergency calls should be PGE's responsibility. However, PGE asks that customers be allowed to call either PGE or the ESP, who would route the call to PGE. Staff asks that the calls be made only to PGE as a means of avoiding confusion. It believes customers should have unambiguous instructions as to whom to call. PGE responds that as a customers of an ESP will be accustomed to dealing directly with the ESP on other matters, it is Staff's requirement that could lead to confusion.

The Commission concludes that metering should remain with PGE initially as a means of smoothing the transition and guaranteeing continued reliability for this key function. We will consider allowing customers the option of choosing another provider early in the process if we are assured that doing so will not present problems. PGE's request that it be allowed to outsource billing and collection for portfolio customers (and for cost-of-service rate customers under our decision earlier in this order) if it is cost-effective to do so is reasonable. ESPs can provide billing and collection services for direct access customers. Direct access customers should be able to receive separate bills as Staff proposes.

Ideally, customer outage and maintenance calls should go to PGE, as Staff proposes. Customers should receive explicit direction to that effect and should not be given the option of calling the ESP. We think it realistic, however, to assume that some customers who are being served by ESPs will inevitably call the ESP in these circumstances. It makes sense that if that occurs, the ESP be allowed to route the call directly to PGE (which is what we understand PGE’s position to be) rather than declining the call and redirecting the customer to call PGE. We direct that ESPs be required to accept such calls and provide a means of directly routing the call to PGE so that response can be made quickly.

PGE and Staff both offered extensive proposals relating to consumer protection and related matters. PGE proposed several measures: a certification process for ESPs; default provisions for customers of an ESP that ceases business; penalties for "slamming" (the unauthorized transferring of customers); a requirement that ESPs enact a customer bill of rights relating to metering, price changes, dispute resolution and other matters; and continuation of the Commission’s Division 21 rules relating to disconnection from service. Staff argues for additional steps, including two or perhaps three rulemaking proceedings. PGE agrees with many of Staff's suggestions in substance but expresses concern that rulemaking would delay implementation of restructuring.

Staff proposes that the Commission be responsible for ESP certification because it has experience and expertise in the subject matter and will continue to oversee both PGE and the interaction between distribution utilities and ESPs. Staff also asks that the Commission bar so-called third party verification procedures for those choosing direct access. It points out that third-party verification has not worked well in telecommunications deregulation. PGE does not oppose Staff's proposal for greater Commission involvement and reduced PGE involvement in the certification process. PGE asks, however, that because of its interest in the creditworthiness of all ESPs, it be allowed to participate and recommend for or against certification of any ESP.

Staff asks the Commission to open a rulemaking docket to develop rules relating to disclosure of price, services, sources of power, and environmental impacts. Staff claims that the PGE pilot program indicates that customers need more information on prices and terms. The rulemaking would determine what specific information should be provided, what entities are best suited to provide the information, and how the information should be provided. Staff favors a requirement that ESPs separately state PGE's distribution charges so that the customer can determine how the ESP deals with PGE's distribution charge. PGE does not object to a requirement for disclosure of power source and environmental impacts. It argues, however, that a requirement that ESPs make detailed price disclosures might impede innovations in service and pricing and might be confusing and impractical. It opposes a rulemaking, arguing that the issues should be dealt with now.

Staff also requests that the Commission open a rulemaking docket to determine how the Commission’s consumer protection rules (Division 21 of OAR 860) should be modified to deal with restructuring and also to consider rules relating to issues that restructuring has made pertinent: the right to electricity, the right to privacy, slamming, the right to change suppliers, and others. PGE opposes rulemaking before the implementation of restructuring, although it does not oppose a rulemaking to adopt statewide policies.

PGE proposed a Consumer Education Plan as part of its restructuring proposal. Staff asks that the Commission require PGE to include in the Plan a discussion, based upon the restructuring plan actually adopted, of the role various market participants will have with respect to consumer education, the funding needed, and source of the funding. It asks that the Consumer Education Plan be submitted soon after a restructuring plan is adopted so that, if necessary, a rulemaking can be initiated to examine options for funding and payment of consumer education programs. PGE asks that its Plan be reviewed in this docket, not in a rulemaking conducted before the plan is implemented.

PGE's original restructuring proposal raised significant consumer protection issues. Some of the opposition to that plan has been based on fear of loss of protections from deceptive practices, discrimination, and other behavior presently prohibited by the Commission’s rules and applicable statutes. Our decision to approve a less sweeping restructuring plan should reduce that fear. Customers who choose the cost-of-service rate or portfolio service will still be customers of PGE and will thus be under the protection of our existing Division 21 rules. At least for now, the only customers who can choose direct access, and thus perhaps lose some consumer protection, will be industrial and larger commercial customers who generally will be less vulnerable to oppressive practices.

Nevertheless, the Commission, by approving the restructuring plan set out in this order, is not abandoning its obligations to the general public, including those who may choose direct access. The Governor's Necessary Principle 9 directs that restructuring maintain protections for customers against "any unfair or unscrupulous practices of their electric service providers." It is clear that restructuring, in the form of a portfolio as well as in the form of direct access, presents some risks to the public, especially at the beginning of the transition process when customers may abandon their relatively stable and predictable relationship to a regulated public utility and instead deal with a company they do not know in order to make choices and take on risks they are not familiar with. Accordingly, we seek to create a process to determine what existing provisions need revision and what new protections need to be adopted.

Staff’s proposal calls for two rulemaking dockets and possibly a third. All of these proposals are substantively sound. We do not want them, however, to delay the actual implementation of restructuring. If PGE indicates that it will proceed with the plan we approve in this order, we direct Staff to expeditiously undertake rulemaking on Division 21 rules and on the matter of prices, services, disclosure of sources and environmental impacts. If those rules are in effect when implementation is proposed, they will of course apply. If not, we will determine whether it is necessary to adopt temporary rules to deal with specific problems or even perhaps to delay implementation of restructuring. We also direct Staff to attempt to coordinate these rulemaking proceedings with similar efforts underway in other western states. The specific issues disputed between Staff and PGE in connection with consumer rules, such as the extent of price disclosure, will be addressed in the rulemaking proceedings and need not be resolved here.

Most of the parties agree that restructuring could endanger funding for various public purposes whose solvency might be placed at risk by the move to the competitive market. Programs for conservation, energy efficiency, low-income weatherization, and the development of renewable resources, for example, might find no home in a competitive environment. The parties note that Governor's Necessary Principle 5 calls for continuation of adequate funding for conservation of energy and development of renewable energy and Governor's Necessary Principle 6 mandates maintenance or enhancement of energy support services for low-income Oregonians. The parties note, moreover, that the Steering Committee of the Comprehensive Review of the Northwest Energy System (Regional Review) recommended that a minimum of 3 percent of the revenue from sales of electricity be dedicated to certain public purposes for a 10-year transition period. The Regional Review also recommended a specific allocation of the funds.

The parties differ on the details of how to provide protection for these public purposes. Staff and others support the idea of a System Benefits Charge (SBC) but differ as to the amount to be collected, the method of collection, the allocation of the funds, and the administration of the funds. Several parties, including Staff and others who support the concept of an SBC, acknowledge that specific legislative authority may be required for an SBC because it may be a tax, or, as ICNU suggests, because ORS 757.335 (Ballot Measure 9) may prohibit charging customers for property not presently used, such as investment in either renewable resources or demand side management measures. Staff asks that the Commission set out the principles it supports to give guidance to the legislature.

The Commission is convinced that the public interest requires the protection of funding for programs supporting and enhancing energy efficiency, renewable energy, and low-income weatherization. An SBC is a mechanism that will provide for sufficient, stable funding spread properly among the customers, all of whom will benefit. It is not clear, however, that we have legal authority to impose such a funding mechanism. We will need explicit legislative authorization before we can adopt and implement an SBC. We will in this order, however, set out our views on the specific principles we believe should be contained in any legislation.

PGE’s proposal calls for a System Benefits Charge (SBC) designed to achieve revenues approximating 3 percent ($26.4 million) of the company’s 1995 retail electric revenues. It proposes that the funds be allocated as set out in the Regional Review: 1.6 percent for cost-effective electricity conservation; 0.43 percent for conservation market transformation; 0.4 percent for low-income weatherization; 0.49 percent for new renewable resources for renewable resource market-transformation; 0.07 percent for distributed renewable resource development and demonstration; and 0.01 percent for renewable resource research. Staff argues that the revenues collected for the fund should be 3 percent of annual retail revenues, beginning with 1999. Some parties suggest that the 3 percent figure be a minimum, others a maximum.

The Commission believes 3 percent, as recommended by the Regional Review, is an appropriate figure. We agree with Staff that the SBC revenue should be 3 percent of annual retail revenues, beginning with 1999. That method will provide protection against inflation and help guarantee the continuing viability of the fund. We also conclude that the allocation set out by the Regional Review is appropriate. The fund may be used only for new projects. Existing demand-side management projects are already in rates and will be paid for through the transition charge. Only those conservation projects that are in PGE's territory should be funded.

One matter of controversy is whether the fund should be collected according to usage or according to the size of the customers’ bill. Proponents of usage as the standard, such as PGE and CUB, argue that use of the bill as the basis may operate as a disincentive to users of more expensive, but perhaps less environmentally harmful, forms of generation. Staff supports a revenue-based charge as the surest way to raise the revenue. It points out that any effect on the purchase of high-cost resources would be minimal. It notes that a usage-based charge presents its own equity issues. It cites, for example, EWEB’s concern that a usage-based mechanism might lead to lower percentage rate increases for high-cost utility customers if a regional SBC were in place.

The Commission favors, at least initially, the revenue-based method of collection as the simplest and most predictable way of collecting the revenue. The record does not indicate that a revenue-based method will have any deleterious effect on the market for higher-cost resources. We will review this matter after the SBC has been in effect to see if changes are needed. If an ESP bills its customers, it will be required to collect the SBC charge. That will necessitate separation by the ESP of its energy charges from any non-energy charges.

The parties presented various proposals for administration of the funds collected through the SBC. PGE notes that it does not have a major stake in how the funds are administered. It proposes that the Northwest Energy Efficiency Alliance and the Oregon Department of Housing be the administrators. Staff proposes a separate Citizens’ Board appointed by the Governor and staffed by the Oregon Office of Energy. Initially, the Board would have authority only in PGE's territory but could be expanded if the SBC is implemented in other parts of the state. A Citizens’ Board would benefit, in Staff's view, from knowledge of Oregon’s overall commitment to the programs to be funded and past achievements in those programs. It would develop cohesive and consistent goals and objectives to further public purposes. Moreover, the Board would provide accountability and consistency. Staff suggests that the Board be allowed to award funds to distribution companies or their subsidiaries during a transition period.

Some parties suggest that other entities, such as the incumbent utility or a unit of local government, have control over aspects of the administration of the SBC. The City of Portland, for example, argues that local governments should be able to set local conservation goals and determine related activities within the context of statewide goals and reporting requirements. EWEB points to its success in developing conservation and renewable programs and suggests that the local utility have the option of either allowing a Board, such as that proposed by Staff, to administer the funds or of retaining the revenues itself for funding and administration of public purposes. The parties who ask the Commission to send the whole matter of the SBC to the legislature for consideration would include the question of the administration of the fund among the issues.

The Commission believes Staff’s proposal for a Governor-appointed Board is the best way to deal with the complex issue of administration of the SBC revenues. Efficiency, public understanding and support, and accountability are most likely to be achieved by entrusting the development of broad policy and procedures to one public entity. The Board would initially have authority only in PGE's territory but should be subject to expansion as necessary if restructuring occurs in other parts of the state. We recognize that local priorities, viewpoints, and expertise should play a role in the actual expenditure of the revenues and that a local governmental entity or local utility may be in a position to enhance that local participation. We suggest that legislation creating the Board contain provisions allowing it to delegate administrative functions to local governments or local utilities.

PGE, ICNU, Staff, and EWEB suggest that large customers be allowed to self-direct investments in energy efficiency measures. Such customers could either be exempted from that portion of SBC charges dedicated to local energy efficiency or could receive a rebate of that amount. ICNU asks that self-direction be available without much bureaucratic intervention. Renewable Northwest Project (RNP) objects to self-direction by large customers on the basis that it would threaten the stability of the already limited funding source. RNP asks, on the other hand, that PGE, or other utilities, be allowed to self-direct funds for renewables, such as the commitment PGE made in the Enron merger to develop 19.5 Mwa of new geothermal resources. It offers a set of criteria for self-direction for the new renewable resources. Staff questions whether a utility implementing retail direct access would actually further public purposes. If the utility is competing for sales and customers with other companies, it would have no incentive to further programs that would increase its costs and reduce its sales. If it becomes a distribution-only utility, it will lack an incentive to further these programs, which have no direct connection to its distribution function. Staff suggests that criteria for renewable resource projects should be developed with the aid of interested parties and perhaps included in legislation.

The Commission concludes that self-direction by large customers is sound. It will allow those customers to expeditiously undertake beneficial projects suited to their circumstances. We do not believe self-direction will threaten the size or stability of the fund generated by the SBC but will only affect, in a positive way, its direction and efficiency. We will not allow self-direction by utilities, however, because we find persuasive Staff's argument that a utility would not have incentives to further the public purposes involved.

The Oregon Energy Coordinators Association (OECA) and Community Action Directors of Oregon (CADO) support the development of a state-level universal energy service fund paid through a meter charge to supplement federal energy assistance moneys. The meter charge would be in addition to the SBC described above. The supporters cite reductions in federal energy assistance funds in recent years and a resulting drop in low-income utility customers receiving assistance. They assert that programs that provide energy assistance save utilities and ratepayers money by reducing costs associated with disconnection and delinquencies. This fund combined with federal funds would total $20 million. The supporters have discussed this proposal with PGE and PacifiCorp, who indicated they could accept a universal service fund of the dimensions proposed by OECA and CADO as part of restructuring. PGE did not oppose this proposal in its testimony or briefs. The supporters acknowledge that the fund they propose would require legislation.

The Commission does not have authority to adopt this proposal. We assume its supporters will make legislative proposals that would provide authority. If the legislature grants the Commission authority to undertake this program, we will expeditiously investigate its implementation.

Utilities pay franchise fees to local governments in Oregon as compensation for special use of local, public rights of way. They are based on the utilities’ gross revenues. The fees are an important part of the revenues of many cities. Governor's Necessary Principle 10 requires that restructuring not unduly burden local governments. Most of the parties agree that under direct access the local governmental entities in PGE's service territory would lose substantial revenue from franchise fees and are in further agreement that some method must be adopted to preserve the revenues. The threat comes about because ESPs or other entities, instead of PGE, would provide power supply and MBCR services. These changes would reduce the company’s gross revenues. PGE argues that applying the franchise fee percentage to its transmission and distribution revenues and to a proxy for the energy revenues collected by ESPs will provide revenues approximately equal to the franchise fees.

The League of Oregon Cities (LOC) and the City of Portland (Portland) argue that PGE's plan is inadequate to protect Oregon cities from a loss of revenue from franchise fees. Portland argues that while PGE's proxy proposal might address the revenue decrease resulting from the removal of the energy component from the utility’s rates, it does not address the revenue reductions caused by fragmentation of utility functions. Moreover, according to Portland, PGE, in its estimate of the effect of its proxy proposal, has provided only an aggregate amount of revenue resulting from application of the proxy rather than figures for individual cities. Portland thus contends that the proxy method will unduly burden some Oregon cities.

Both Portland and LOC suggest that a "volumetric" approach be used to assure that cities are made whole. Under this approach, a rate per kilowatt-hour could be established for each city to ensure that franchise fee payments would continue at a level that would not be harmful to the cities. This approach would offset both basic causes of a potential reduction in franchise fees: the loss of the energy component and the transfer of other functions to the market. Portland points out that other states have begun to use volumetric approaches under circumstances similar to what is before the Commission now and that the Commission has already adopted a volumetric approach for the collection of fees from electric utilities under ORS 756.310.

We agree that the revenues from franchise fees could be sharply reduced because of PGE's restructuring. While the modified form of restructuring we are approving in this order may present a smaller threat to franchise fees than did PGE's original proposal because PGE would continue to provide a bundled service to most customers, the potential losses may still be significant. We do not believe, however, that we have the legal authority to adopt a remedy for the problem in this case. Portland and LOC appear to agree. Staff also questions the Commission’s authority in this matter. It notes that while we did take steps in the PGE and PacifiCorp pilot programs to protect franchise fees by having ESPs pay an imputed franchise fee to the incumbent utility, which paid it to the cities involved, we did so to remove potential bias from the pilot program, not to protect the cities. Staff believes it is uncertain that such a provision would be a sound long-term solution. Staff suggests that a possible legislative solution would be to replace franchise fees based on gross revenue with fees based on the amount of electricity a wires-only company distributes. We assume the affected local governments will ask the legislature to consider that solution. We will not implement this restructuring plan until the legislature has had an opportunity to consider the franchise fee issue.

PGE has several existing special contracts to supply energy to customers. As a means of moving toward direct access, PGE proposes to bundle all of these contracts and sell them to the highest-bidding ESP through a request for proposals. The pricing options and other contract rights would be assigned to the winning ESP and would remain in effect until the contract expires. PGE would include amounts it receives as a transition cost to be recovered under Schedule 125.

ICNU generally supports PGE's plan. However, it argues that customers holding special contracts should have some say in the selection of the new energy provider. It proposes that each customer be allowed to choose as its supplier any of the top five bidding ESPs, provided its choice agrees to meet the second highest bid in the auction. This method would allow the customer to exercise its judgment as to the suitability of a particular power supplier. The requirement that the ESP meet the second highest bid would tend to guarantee service quality and would protect PGE from any significant loss.

PGE opposes ICNU’s suggestion. It argues that this method would effectively break its bundle of contracts into individual contracts. The ESPs’ bids might be reduced because of their knowledge that individual customers could pull out of the group after the auction.

Staff presents a proposal based upon its alternative restructuring plan. PGE would continue to serve special contract customers under the terms of their contracts. Special contract customers could shift to cost-of-service rates or direct access only if the contract permitted. Cost-of-service rates would be determined by including loads served under a special contract rate with the loads of other cost-of-service rate customers. The difference between the cost-of-service rate and the special contract rate would be allocated on an equal percent of total Long Run Incremental Costs or percent of total revenue and collected through a separate adjustment.

PGE's proposal and ICNU’s response are both based upon PGE's restructuring proposal, which would remove PGE from the supply function. As our decision in this case will require PGE to retain some supply assets and to function as a supplier of electricity, those proposals are not pertinent. We conclude that Staff’s position on special contracts is appropriate for the restructuring proposal we approve. It provides continuity for the contract customers by retaining PGE as the provider but also allows some of these customers to share in the restructuring plan by moving to direct access or the cost-of-service rate if their contracts permit.

PGE asks that the Commission, as a means of preventing cross-subsidization between competitive and regulated activities, require that any Oregon utility (investor owned or not) that competes in PGE's territory after restructuring do so only through an affiliate. It points out that even a publicly owned utility, such as EWEB, which opposes the requirement, can still engage in subsidization to the detriment of competition. Staff agrees that this requirement should apply to Oregon investor-owned utilities but would not extend it to publicly owned utilities, whose governing bodies can protect their monopoly customers, or to utilities in other jurisdictions, whose regulators can do so. Staff points out that, in any event, such cross-subsidization by other utilities would actually benefit PGE's customers. EWEB argues that the many legal controls over the operation of municipal utilities, such as rate regulation, public records laws, and limitations on delegation of authority, would make use of an affiliate impossible and would effectively prohibit participation in the program by municipal utilities.

Oregon investor-owned utilities will be eligible to participate only through affiliates. It is much easier to detect and prevent cross-subsidization between two separate entities than between parts of one organization. We will not, however, apply this requirement to publicly owned utilities. As EWEB points out, they operate under substantial restraints that make it unlikely they would subsidize their competitive operations at the expense of their monopoly customers. Moreover, their ability to form affiliates may be doubtful because of legal constraints. We do not want to discourage the entry of competitors by imposing a restriction of questionable efficacy. The affiliate issue can be reconsidered at a later time upon a showing of abuse.

PGE asks the Commission to require that any Oregon utility which competes in PGE's territory must open its service territory to competition. It argues that this requirement is consistent with Governor's Necessary Principle 11, which states:

PacifiCorp opposes the requirement on the grounds that it might inhibit the development of a competitive market. Staff argues that this docket is not the place for the Commission to impose a requirement that is actually designed to force competition in areas other than PGE's territory.

We agree with Staff that the reciprocity requirement, although sound from a policy standpoint, is outside the ambit of this proceeding. Governor's Necessary Principle 11 indicates that a utility seeking an exemption from open access may have to accept a restriction on marketing outside its service territory. PacifiCorp and the other utilities involved in this case are not requesting an exemption from open access in this proceeding and the Principle is thus not pertinent.

PGE initially proposed a revenue requirement of $476 million for the Company operating as a distribution only utility. Thereafter, it modified its proposal by agreeing to offer a portfolio option and to undertake some meter, bill, collection, and response functions. For this reason and because the original test year, 1999, will be out of date, it acknowledges that its revenue requirement must be refiled. It addresses, nonetheless, several specific revenue requirement issues where it disagrees with Staff or other parties. Staff proposed several adjustments to PGE's proposed revenue requirement. Staff agrees that the revenue requirement must be revisited if the Commission adopts any plan other than PGE's original proposal. Staff asks that the Commission nevertheless address in this order the specific disputes it has with PGE over revenue requirement issues so that the principles enunciated can be applied to the newly filed revenue requirement, if any.

As the Commission approves in this order a restructuring scheme quite different from PGE's original or modified proposal, the revenue requirement must be refiled addressing substantially different issues. Many of the matters disputed now may be present in that new revenue requirement, however, so a decision here may be helpful. Where possible, we adopt principles that should be applied in any subsequent filing of PGE's revenue requirement. In some instances, however, the dispute appears to be based so specifically on the facts of PGE's filing, rather than on any general principle we can state, that we will make no decision and enunciate no principle.

This ledger records the costs of general support for PGE's delivery system, including the cost of time and expenses of employees for efforts not specifically linked to activities recorded under a separate ledger. These activities include establishing and monitoring performance indicators and identifying and implementing continuous improvement initiatives. Staff proposes to reduce the amount in this ledger by $2.8 million on the grounds that PGE has not justified a reclassification of expenditures from capital accounts to this ledger account. Staff recommends that the 1997 actual expense in this ledger account be allowed, rather than PGE's proposed 1999 level. PGE's testimony appears to assert that Staff’s adjustment is partly based on a mistaken assumption that PGE had explained only the increase from 1996 to 1997, whereas the changes took place in both 1997 and 1998.

This dispute appears to center on the particular facts and filings involved and may turn on a misunderstanding. If PGE refiles its revenue requirement, perhaps those disputes may no longer be present. We will therefore draw no conclusions on it. We see no principle to be enunciated that could be applied by the parties to a new revenue requirement filing by PGE. If a dispute arises when the new revenue requirement is made by PGE, we will resolve it.

PGE proposes to include costs associated with default by ESPs. It argues that a default would have an enormous impact on PGE and that the risk cannot be eliminated. PGE proposes that it establish a balancing account accruing $312,500 per year, an amount equivalent to the cost to PGE of one of the estimated 50 ESPs defaulting once every 9.28 years. Staff originally opposed the concept because it felt default to be extremely unlikely, but has now agreed that the balancing account approach and amount should be implemented for three years, after which the issue should be reevaluated.

Staff’s proposal for a three-year trial of PGE's proposal is reasonable and is adopted. We will have had experience with the actual operation of ESPs by that time and will be able to make a more informed decision about the need for this protection.

Staff proposed three adjustments. PGE accepts the first—adding to revenue an estimate of test year interest from these programs—and offered a calculation of the appropriate amount. Staff accepts the calculation related to ESFO loans but challenges the estimates for weatherization interest because of the inclusion of promotional concession loans and new loans in 1999 when PGE would no longer be implementing energy efficiency loans.

Staff's second proposed adjustment reduced PGE's rate base by excluding an estimate of the average Weatherization loan balance. PGE claims that the estimated test year Weatherization loan balance is appropriate in rate base because the interest income from the program will be recognized and the program was included in rate base in UE 88. Staff challenges the calculation for the same reasons set out above.

Staff’s third proposed adjustment is to add to revenue an estimate of Zero Interest loan repayments. PGE claims that these loan repayments simply amortize a customer’s loan balance. Because they were included in programs securitized, the amounts are passed through to customers through PGE Tariff 101 (SAVE Tariff). They do not represent revenues to PGE and should be excluded from other revenues. Inclusion will result in unnecessary complications in the true-up mechanism in the SAVE tariff. Staff notes that PGE's proposed tariffs in this case do not include the SAVE Adjustment Mechanism. Since the repayment of these loans will occur over many years, Staff argues that the repayments should be included in revenue.

It is not clear how these specific issues would be affected if PGE makes a new revenue requirement filing based upon the form of restructuring we approve in this order. We do conclude, however, that the principles behind Staff's second and third proposed adjustments are sound and any new revenue requirement filing should take them into account.

PGE proposed $3.964 million in expense for these accounts, which include the costs of environmental remediation, information systems, word processing, communications, copying services and most computer costs. This figure is a 49 percent increase over the actual 1997 level of $2.656 million. PGE asserts that the figure includes important known and measurable changes as well as the effects of PGE's environmental remediation costs. It also claims that the 1997 level was understated because of an accounting error. Staff’s adjustment calculated the allowable expense by using the 1997 level increased by the rate of inflation. It also took into account the fact that PGE is proposing to move from a three-function utility to a one function utility and that PGE had spent only about one fifth of its budget for environmental remediation over the 1994-1997 period. Staff's proposed result would lead to an allowable expense level 5 percent lower than the 1997 adjusted actual amount that supported all three of PGE's functions. Staff asks that the Commission endorse its principle of adjusting for inflation and for the Company’s reduced scope of operation.

This issue will certainly be subject to review under the restructuring plan we are approving. Staff’s method of adjusting these accounts through an inflation factor and a factor based on its form after restructuring seems reasonable. We endorse it in principle. However, the restructuring portion of it will need modification.

Staff proposed various adjustments to the "Wages and Salaries" portion of PGE's proposed revenue requirement. Staff used a three-year wage model to make its adjustments. Staff included wage levels of union employees in its adjustment. Staff noted that normally union wage levels are not an issue because they are a result of arms-length negotiations and contractual obligations. In this case, however, the absence of details specific to PGE’s filed 1999 wage levels made it necessary to include union wage levels in the three-year wage formula used by Staff to obtain a reasonable comparison to PGE’s 1999 estimate. Staff argues that excluding union wages from the three-year wage model adjustment would distort the overall wage estimate, resulting in excessive labor costs.

Staff and PGE agreed that if PGE and the union reach a settlement before the Commission approves PGE’s revenue requirement, the approved revenue requirement should be updated to reflect the contractual union wage escalation rate. PGE and the union have recently agreed on a contract. PGE will supply the information for the update.

Staff also made an adjustment of $550,000 to PGE’s proposed test year overtime costs. Staff’s proposal is tied to Staff's proposed reduction in salary and wage rates of growth. For example, if escalation rates for union wages are reduced from 8.7 percent to 6.2 percent, as Staff has proposed, then overtime costs would be reduced correspondingly. PGE claims, however, that it has taken the more accurate approach of determining historical overtime from 1995 to 1997 for the average employee and applying this amount to test year employees. Since most overtime is related to outages, looking at a three-year historical period will, in PGE's view, reduce any bias caused by a particularly stormy or mild year.

It is apparent that PGE will have to refile the information involved in this dispute if it decides to operate under the restructuring plan that we approve in this order. Much of the dispute relating to wages and salaries appears to be specific to the filing made in this case. According to the testimony, the dispute may also be a result of some misunderstanding by PGE of Staff’s proposed adjustment to overtime costs. We approve Staff’s treatment of these adjustments under the particular facts set out in this case. We do not see any particular principle that can be adopted in this instance, however. If PGE's refiling fails to provide specific detail by employee category, the three-year wage model should be applied as it was to the present filing, including the overtime method.

Staff proposed two adjustments concerning incentive pay. PGE does not challenge Staff’s adjustment to the "Our Teamworks Program" of $1,390,078. Staff also proposed an adjustment of $1,273,200 to the Officer Incentive Plan. PGE claims that this adjustment is inconsistent with past Commission practice (in UE 88, for example), where the Commission allowed inclusion in revenue requirement of the 25 percent portion of the Officer Incentive Plan applicable to non-officers. Staff now accepts the allowance of a portion of the plan covering non-officer employees and asks that the Commission approve the following principle for incentive pay:

Staff proposed a reduction in the A&G costs of nine full-time employees (FTEs) resulting in a revenue requirement adjustment of $321,000. Staff made its calculation through a "trend" analysis under which it used known or forecasted values for customer accounts and customers per FTE in the years 1991 through 1997 to forecast an appropriate account of customers/FTE for 1998, the last year before the company proposed to become a distribution-only utility. The forecasted value was then used to determine the appropriate FTE in 1999.

PGE criticizes this trend analysis. It states that Staff has provided no statistical test to support the use of this analysis and no test to indicate that it produces statistically accurate forecasts. PGE also claims that an appropriate analysis of the level of the A&G FTEs should take into account the specific activities the FTEs support. If the utility provides functions that are in the interest of its customers but that require additional human resource, accounting, and budgeting personnel necessary to support the function, the A&G FTEs would increase even if the number of customers remains constant. Thus, according to PGE, Staff’s trend analysis would penalize such a utility by making an A&G FTE adjustment even if the functions involved were in the best interests of the customer. PGE also asserts that Staff’s method is flawed because it assumes that the rate of increase in efficiency in recent years will continue into the future. PGE asserts that there is no assurance that a past rate of improvement in efficiency will continue.

Staff asks that the Commission adopt Staff’s principle regarding A&G non-union work force:

The Commercial Energy Alliance (CEA) also proposed an adjustment to PGE’s A&G costs. PGE asserts that the CEA analysis ignores many pertinent factors and contains many analytical flaws.

The Commission concludes that Staff’s general approach is consistent with past practice in matters of this kind. It is likely to produce consistent reasonable figures. We adopt Staff’s principle. We do not find CEA’s evidence and argument on this issue persuasive and will not adopt the adjustment it proposes.

Staff proposes adjustments totaling $2,094,000 involving eight ledgers which Staff believes relate to sales and marketing. Staff argues that the activities involved are not appropriate for a distribution-only utility. PGE asserts that, in reality, these costs relate directly to customer assistance, including research on phone system reliability, provision of safety and other technical system information to large commercial and industrial customers, and measurement of PGE’s performance as a distribution company. The parties acknowledge that they have historically disagreed about what constitutes appropriate customer service or assistance expenses. Staff asks that the Commission adopt the following principle:

CEA proposes an adjustment of $5.3 million to PGE’s customer costs. PGE criticizes CEA’s method, which relies on FERC categorization methods, as not appropriate to determine revenue requirement. FERC’s categorization methods are, according to PGE, extremely broad and not intended to be a substitute for examination of the activities supported by these costs.

PGE will have to refile with respect to these issues if it undertakes the restructuring plan we set out in this order. We believe that Staff’s principle is broad and flexible enough to allow for a realistic appraisal of the appropriateness of the costs involved and we adopt it.

Staff proposes a reduction in the allowance for MBCR assets of about 90 percent. Its argument is that PGE will now have to serve a maximum of only about 20 ESPs rather than about 650,000 pre-Customer Choice customers. The adjustment is about $2,393,000. PGE objects to the reduction, claiming that its Customer Information System, which is the main expense involved, will have many functions after the restructuring is in place.

If PGE adopts the restructuring plan that we set out in this order, it will still be serving substantial numbers of customers. This specific dispute involved here no longer appears to be pertinent and we see no principle to be adopted.

Staff proposed to reduce corporate allocations to PGE because, according to Staff, PGE used the 1997 budgeted amounts, which were greater than actual 1997 amounts, in its calculation. Staff used the 1997 actual figures escalated to 1999. This computation leaves an adjustment of $743,000. PGE responds by pointing out that the 1997 actual figures were significantly less than budgeted amounts because of the merger of PGE with Enron, consummated on July 1, 1997. At that time, allocations from Portland General Corporation ceased but allocations from PGE’s new parent, Enron, did not occur during the last half of 1997. PGE claims that Staff has thus taken a very unrepresentative and low number as a basis for test year allocations.

PG&E Energy Services also offers testimony and argument on PGE’s corporate allocations. PG&EES points out the importance of proper cost allocation to prevent cross-subsidization of an unregulated competitive business by the monopoly side of the company. It questions whether PGE’s allocation has properly allocated Enron’s common cost between regulated and competitive products/services. PG&EES questions PGE’s use of the Modified Massachusetts Formula (MMF). It suggests that this allocation method assigns to Portland General 22 percent of Enron’s miscellaneous corporate expenses, even though Portland General accounts for only approximately 7 percent of Enron’s revenues. PG&EES argues that acceptance by FERC of the MMF formula for allocating Enron’s corporate costs to its regulated gas pipelines is irrelevant because PGE is an electric utility not comparable to Enron’s regulated gas businesses. PG&EES asks that the Commission require PGE to submit a "bottom up" cost separation study prior to accepting any proposed allocation of Enron’s corporate overheads to regulated services. PG&EES also criticizes PGE’s allocation of the decommissioning and site management costs of the Trojan nuclear power plant to the distribution function of its business. It argues that the Trojan costs are associated with the generation portion of the business, not the distribution portion. Upon restructuring, according to PG&EES, these costs should be included in the calculation of PGE’s overall transition costs.

PGE responds by pointing out that PGE directly assigns costs from Enron whenever possible. However, if the costs cannot be so assigned, such as the costs of SEC reporting, shareholder services, employee benefits programs, and senior management oversight, it uses the MMF method for allocation. It claims that this formula is appropriate for regulated electric companies as well as for regulated gas companies, because its purpose is to prevent regulated companies from being allocated common overhead costs which should be allocated to competitive and unregulated affiliates. PGE also points to evidence that its cost allocations do not overcharge customers. The evidence, according to PGE, demonstrates the costs with the merger are lower than without the merger. PGE denies that the decommissioning and site management costs of Trojan should be assigned to PGE’s generation business because PGE would not be in the generation business under its restructuring proposal.

If PGE refiles its revenue requirement under the restructuring plan set out in this order, many of the issues described above with respect to corporate allocations may no longer be present. We will therefore not draw any conclusions on this issue.

PGE received cash and other consideration from Westinghouse as a settlement for PGE's lawsuit related to steam generators at Trojan. The settlement provided PGE with some future benefits. Details of the settlement are subject to an order of the U.S. District Court for the Western District of Pennsylvania requiring confidentiality. PGE believes all the consideration should go to shareholders. Staff disputed PGE's position. Staff and PGE entered into a settlement on this issue. The Commission will issue a separate order on this matter in the future.

PGE presented a marginal cost of service study designed to guide the allocation of its revenue requirement and to price utility services. The study is based on the study submitted by PGE in UM 827, but modified to include only distribution costs, to exclude costs of end-user consumer meter reading, billing, and collection functions, and to update costs associated with substation, meter ownership, installation and maintenance, electric service, loadings, and operation and maintenance. PGE claims that the methodology used was approved in UM 827.

CUB challenges PGE’s marginal cost study. It alleges that the studies favor large customers to the disadvantage of smaller customers. First, according to CUB, the study does not take into account the actual prices paid by special contract customers. It thus overstates the percentage of marginal costs paid by industrial customers and requires a more significant increase in residential rates and a greater decrease in industrial rates than is necessary. CUB argues that the Commission’s approval of the theoretical basis for PGE's approach in UM 827 is not approval of the details presented in the present case.

CUB's second claim is that the cost of three-phase conductors should be allocated to those who use them, not to all customers. PGE responds that three-phase lines are necessary for the provision of reliable service to single-phase customers. They increase reliability, reduce the impact of conflicting single-phase loads for single-phase customers, and provide other benefits to single-phase customers. PGE points out that this issue was resolved in PGE's favor in UM 827. CUB does not deny that there is some need for three-phase conductors throughout the system for reliability purposes. It avers, however, that customers who require three-phase service put an additional need on the system for three-phase conductors above that needed for reliability and the additional costs should therefore be allocated to them.

CUB's third argument is that PGE allocates costs to residential customers based on the maximum load the customer might put on the system, while allocating costs to large customers based on the actual load the customer places on the system. PGE explains that it assigns facilities costs to demand-metered customers on the basis of the actual demand imposed on the system as measured by the meters. For customers without demand meters, PGE assigns facilities costs on the basis of design (or expected) demand. PGE claims that evidence in UM 827 shows that this procedure does not over-allocate costs to residential customers and that the Commission did not accept CUB's position in that proceeding.

The Commission concludes that PGE's marginal cost study presented in this case properly uses the methodology we approved in UM 827. We have reviewed the evidence and argument pertaining to the specific application of that methodology questioned by CUB. We conclude that PGE's evidence and argument are persuasive and we accept the conclusions of the study on these issues.

The City of Portland asks that the Commission require PGE to develop separate marginal costs for Option C streetlights (customer owned and maintained). Portland claims that PGE's proposed rates are based upon the costs of its Option B lights, which are customer owned but maintained by PGE. PGE's rationale is that Option B systems are predominant. However, Portland avers that cities are tending to increase their proportion of Option C lights as a means of reducing costs. PGE's methodology, when applied to Option C street light system, thus grossly overstates actual costs.

PGE responds by pointing out that most lights installed on the PGE system as a whole are Option A and Option B lights, that there are not enough differences between Option B and Option C lights to justify different prices, and that a separate class for Option C lights would be too small to be administratively feasible.

Portland also asks that the Commission direct PGE to allow Portland to provide maintenance on municipally owned street lights on PGE distribution poles. Portland uses the same crews for non-maintenance work as are hired by PGE and has the same incentive to maintain safety as PGE. It claims that other utilities permit this practice. PGE demurs from this proposal on safety grounds. It also asks that before this practice is permitted, the cost impact must be thoroughly examined and other streetlighting customers brought into the discussion.

The Commission finds PGE's argument persuasive on the issue of a separate marginal cost study for Option C streetlights. If, in fact, that form of lighting is becoming more common, it may be reasonable in the future to develop separate costs for it. As to maintenance of streetlights, we will for now defer to PGE's judgment regarding the possible safety problems involved. However, Portland may pursue this issue with our Staff and PGE to see if in fact whatever problems exist can be dealt with and whether other municipalities seek to provide that service.

Portland asks that traffic signals be exempt from the Mitigation Adjustment in Schedule PDS-30. The Adjustment is part of a movement in rate design to more closely align individual class rates with marginal costs. Portland claims that traffic signals are a member of "the class of loads contributing the funds for this adjustment." It asks that what it calls this "historical inequity" be ended. PGE claims that exemption would be completely inappropriate because traffic signals "already receive the largest decrease of any class of customers—no other class even comes close."

We conclude that PGE's argument is persuasive and that the requested exemption should not be granted.

PGE offered an analysis of its proposed cost of capital for 1999. The analysis sets out a proposed capital structure and cost for the three components of the structure: long-term debt, preferred stock, and common equity. The analysis is based on the assumption that PGE's restructuring proposal would be in place and that the company would therefore be operating as a transmission- and distribution-only utility without generation and supply assets. PGE forecast its cost of long-term debt to be 7.57 percent, its cost of preferred stock to be 8.432 percent, and its cost of equity (required return on equity) to be 10.6 percent. Staff disputed PGE's capital structure analysis, cost of debt, and cost of equity. ICNU, CEA, and CUB disputed PGE's capital structure and cost of equity. The cost of preferred stock is not in dispute.

The Commission notes that PGE's analysis presumes that it will be operating as a distribution- and transmission-only utility in accord with its application. Much of the criticism from the other parties is necessarily based on the same assumption. If PGE chooses to adopt the plan we approve in this order, it must file a new rate case, including a cost of capital component. Many of the issues presented in the testimony in this case may not exist in the new filing. We will not attempt to decide issues that are now moot. We will, however, draw conclusions where the issue is a general one which might come up in the new rate case.

PGE proposes the following capital structure based upon its restructuring plan: long-term debt—48.99 percent; preferred stock—2.01 percent; common equity—49.00 percent. Staff’s proposed structure, set out in its final brief, is only slightly different: long-term debt—45.30 percent; preferred stock—1.75 percent; common equity—52.95 percent. It is based on the proposition that, at least initially, the capital structure of the distribution-only company will be same as that of the current utility. Staff points out that its proposed capital structure contains slightly more equity than PGE's capital structure and thus would raise the revenue requirement. ICNU/CEA/CUB propose a very different capital structure based on the argument that a distribution-only utility should have a greater proportion of debt than PGE assumes. Their recommended capital structure contains 59 percent long-term debt; 6 percent preferred stock; 35 percent common equity.

We need not address the ICNU/CEA/CUB argument since PGE will not be a distribution-only company under our approved plan. As a generality, Staff's proposal to initially leave the presumed capital structure of a restructured utility the same as it was when it was a vertically integrated utility is sensible and fair. It would, of course, be subject to modification if the need were shown.

PGE forecast a cost of debt of 7.57 percent. Staff’s forecast is 7.36. The difference results from disputes about four issues. We will address the first three together and the fourth, cost of financial swaps, separately.

Initially, PGE included in its long-term debt balance $100 million in new debt it intended to issue in 1998 or 1999. It later decided not to issue the debt and removed it from its capital structure. Staff notes that this change, which affects cost of debt and capital structure, was made late in the proceeding and that it might result in a capital structure that contains too much equity. Staff agrees that if the debt was not issued it should not be included in the capital structure calculation.

PGE also asserts that Staff failed to take into account the fixing of interest rates on some of its pollution control bonds and also ignored certain minor corrections PGE made to its original calculations. Staff acknowledges that the change relating to the pollution bonds should be taken into account. Staff views PGE's corrections with suspicion, however, and does not draw any direct conclusions about them.

PGE will file a new rate case if it decides to adopt the plan we approve. It appears that the three issues discussed in this section will either become moot or will be clarified. We will thus not attempt to make any decision on them here.

In November 1994, PGE entered into two $25 million ten-year notional forward starting rate swaps to hedge the interest rate on $50 million of medium-term notes that PGE expected to issue on May 15, 1995. The effective rate on the swaps was approximately the rate available for medium-term notes in November 1994. The swaps had a mandatory "unwind" date of May 16, 1995, to effect the desired hedge of the medium-term notes. On May 16, 1995, PGE issued $100 million of medium-term notes and unwound the two swaps.

PGE entered into these swaps because it wished to lock in the interest rates on the medium-term notes. It notes that interest rates were volatile in 1994. It claims that these swaps were merely a hedge against an increase in interest rates, similar to locking in a mortgage rate. The effective cost of the two May 1995 long-term debt issues was 8.60 percent and 8.21 percent. If PGE had issued the long-term debt in November 1994, the effective cost would have been between 8.68 percent and 8.99 percent. Thus, PGE claims, it acquired lower-cost debt than it would have in November and it was able to avoid the interest rate risk between November 1994 and May 1995. It claims that the swaps were closely tied to the May 1995 medium-term notes and thus their costs should be recognized in PGE's capital structure. It notes that it was required by its accountants to show that the swaps were tied to specific long-term financing to justify amortizing the costs of the swaps over the life of the related debt. The Commission should determine if such swaps were prudent at the time they were entered and not base a decision on when they are unwound. Refusal by the Commission to recognize costs of swaps such as these will interfere with PGE's ability to manage its long-term debt costs.

Staff opposes the inclusion of the costs of these swaps in PGE's cost of debt. It argues that these swaps were short-term securities because they matured in less than a year. Exclusion of them from cost of debt on that basis is consistent with Commission practice. Staff also challenges PGE's assertion that the swaps were "tied" to the issuance of the medium-term securities issued in May 1995. Staff points out that they were issued by a third party not connected with the medium-term notes and did not require that PGE issue the longer-term notes. Staff also notes that these swaps caused financial losses to PGE of $5 million and suggests that a disincentive to engage in this practice is desirable.

The Commission concludes that Staff's proposal to exclude these swaps from cost of debt is correct. They were short-term securities. We do not find PGE's argument that they were "tied" to the issuance of the longer-term securities persuasive. The accounting treatment these swaps received is not determinative. Whatever PGE's ultimate goal may have been when it issued the securities, they were a separate instrument from the longer-term issuance. We see no reason to depart from our general practice of excluding short-term securities from consideration in determining cost of debt.

PGE performed a Discounted Cash Flow (DCF) analysis, a risk-positioning method, and a Capital Asset Pricing Model (CAPM) analysis to develop its cost of equity recommendation. Its analysis was based on its proposed new structure as a distribution-only utility. Based on these three analyses, it calculated a cost of equity range of 10.3 percent to 10.8 percent, with a point estimate of 10.6 percent. PGE also analyzed decisions of other public utility commissions over the last 12 months and determined that the average authorized return on equity was 11.3 percent. PGE asserts that its analysis is "thorough, well reasoned, understandable, contains no major flaws, and is subject to no controversy concerning accuracy of data or questions pertaining to statistical validity of the results" and must be adopted.

Staff used two Discounted Cash Flow analyses (constant-growth and multi-stage) and a Capital Asset Pricing Model analysis to calculate a cost of equity for PGE. Its conclusion was that the cost of equity of an average integrated electric utility is within the range of 7.6 percent to 9.0 percent, with a point estimate of 8.3 percent. Staff then used a CAPM analysis to calculate a "risk discount" to take into account the difference in risk between a vertically integrated electric utility and a distribution-only firm. The discount takes into account the expectation by the financial markets that a distribution-only firm has lower business risk than a combination distribution/generation firm. It therefore can handle significantly more debt than a combination distribution/generation firm while remaining in the same risk class. Staff calculated the "distribution risk discount" to be 14 percent. This "discount" is applied to the risk premium portion of the CAPM computation of required return on equity, not to the return on equity as a whole. The distribution risk discount when subtracted from the estimated cost of equity for an integrated electric utility leads to Staff’s final cost of equity estimate for PGE of 7.9 percent, based on a range of 7.3 percent to 8.5 percent.

Staff provides a method by which the Commission could determine a specific return on equity for whatever form PGE’s restructuring takes. It sets out equity risk premia for distribution-only, fully integrated, and generation-only versions of PGE. The premium appropriate to whatever new structure is adopted could be added to the risk-free rate to determine a specific rate of return on equity. Thus, Staff suggests that the Commission adopt the risk premia now and determine an absolute value of return of equity when PGE files new rates.

ICNU also offered a cost of equity estimate based on a DCF analysis. It argues, as does Staff, that a distribution only electric utility has less business risk than a company that is also involved in the generation business. ICNU also points out that long-term interest rates are now at multidecade lows, with the 30-year Treasury bond rate at 5.0 percent in December 1998, down from the rate of 5.5 when PGE filed its rebuttal testimony in August 1998. ICNU’s estimate of the appropriate cost of equity is in the range of 8 percent to 9 percent. It argues that PGE's proposed 10.6 percent is excessive for a distribution-only electric utility.

The parties vigorously disputed this issue. The Commission notes that the variation among the proposals for cost of equity is very large: ranging from Staff’s 7.9 percent to the ICNU/CEA/CUB proposal of 8-9 percent to PGE's proposal of 10.6 percent. Given that all three parties use the same recognized analytical tools, this range is significant. Some of the disagreement may flow from a sharp difference of opinion as to whether a distribution-only utility has less risk. There are also some matters which center on specific facts. Since PGE will file a new rate case if it accepts our proposed plan, little would be gained by our attempt to resolve these specific matters. However, there are several broader principles in dispute in connection with the cost of equity issue. We will draw conclusions on those issues to guide the parties in any future filings.

We believe Staff's risk premium approach is sound. It will be a very helpful tool for determining cost of equity if PGE refiles rates and in other proceedings. It lends itself to dealing with different mixes of generation and distribution. It can be used to establish the appropriate equity risk premium for a mix of distribution and generation based on the rate base components in any restructuring proposal. It properly reflects that the cost of equity for a distribution-only company is less than the cost of equity for a traditional vertically integrated utility. We also conclude that the specific values set out in the risk premia table are sound and are adopted. They are set out in this table:

Staff's CAPM analysis is based on a method of estimating beta that the Commission has relied upon for many years. We note PGE's criticisms of Staff’s CAPM analysis, but find them unpersuasive. The evidence establishes that the Fisher-Kamin method is sound because it allows beta to change over time. Moreover, PGE's claim of heteroskedasticity in Staff’s analysis is not convincing. The record establishes that heteroskedasticity does not bias estimates up or down but affects the ability to perform hypothesis tests and the calculation of confidence levels, neither of which were carried out by either Staff or PGE. The evidence establishes, in any event, that PGE's tests for heteroskedasticity cannot properly be used for the Fisher-Kamin procedure. We also conclude that Staff's method of determining the risk-free rate by using data available from open financial markets is sound.

If PGE adopts the plan we have described in this order, we will use the risk premia table to compute its cost of equity. Since this plan will keep PGE in the supply business, and since the level of risk it will have under this plan is difficult to predict, we will use the premium for a fully integrated utility. We reserve, however, the right to review this matter if PGE, because of legislative action or other cause, ultimately adopts a restructuring plan different from the one described in this order.

The Commission also concludes that Staff's DCF analyses are persuasive. They use spot prices for stock prices, in keeping with consistent Commission practice. They also properly use independent forecasts of near-term future dividends and a consistent approach to forecasting long-term dividend growth rates. We also accept Staff's argument that PGE's use of information on the cost of equity allowed by other commissions is not of much value. PGE's cost of equity is determined by the market, not by other regulators.

the Commission will carefully oversee its operation. We direct Staff to conduct the following evaluations:

1. Monitoring of the plan after implementation to determine if changes in ongoing operations under the plan would be in the public interest. We direct Staff to propose a plan for such monitoring when it presents its recommendation on PGE's refiled tariffs.

2. An overall assessment of the plan to determine its effect on all customer classes and on the industry. Since this review will be useful only after the plan has been in effect for some time, we direct Staff to prepare and deliver to us a report 15 months after the plan goes into effect. This directive is not intended to prevent Staff from filing a report on that matter earlier if warranted.

3. Included in the overall assessment of the plan described above should be an analysis of whether direct access should be considered for residential customers (and small commercial customers if they have not been granted direct access pursuant to this order).

1. Portland General Electric Company is a public utility subject to the Commission’s jurisdiction.

2. The restructuring plan filed by PGE in Advice No. 97-20 to be effective January 7, 1998, would not provide just and reasonable rates and would not provide the public with adequate service at fair and reasonable rates. The plan is not in the public interest and should be rejected.

3. The alternative plan the Commission sets out in this order would provide just and reasonable rates and adequate service and is in the public interest.

4. Implementation of the plan we approve in this order is contingent upon the adoption of certain statutory changes by the Oregon Legislature. We have discussed these changes throughout the order and describe them in detail in Appendix C. Within 30 days following the adjournment of the 1999 session of the Oregon Legislature, we will inform PGE and the other parties of our decision as to whether the plan described in this order or some modified plan may be implemented.

5. Within 30 days following our notification to PGE and other parties of what plan, if any, can be implemented, PGE must inform us whether it will accept and implement that plan. If PGE accepts the plan, we direct Staff to expeditiously reconvene the parties in this case to consider implementation issues, including the filing of a rate case. We direct Staff to submit a report on implementation to us within 30 days of the conclusion of these discussions.

1. The tariff revisions filed by Portland General Electric Company on January 7, 1998, as Advice No. 97-20 are permanently suspended.

2. Portland General Electric Company may file revised tariffs consistent with the findings and conclusions in this order.

A party may request rehearing or reconsideration of this order pursuant to ORS 756.561. A request for rehearing or reconsideration must be filed with the Commission within 60 days of the date of service of this order. The request must comply with the requirements in OAR 860-014-0095. A copy of any such request must also be served on each party to the proceeding as provided by OAR 860-013-0070(2). A party may appeal this order to a court pursuant to ORS 756.580.

This concurring opinion is written, not to take issue with anything in the order, but in an effort to provide additional context to the overall effect of the order. Particular attention should be given to the Commission’s emphasis on establishing a retail electricity environment with the flexibility to allow transition to a fuller, more robust contestable market as confidence that all customers will benefit grows.

In its opening brief PGE claimed there were three fundamental decisions the Commission needed to make. 1) whether or not the Commission believed a competitive retail energy services market could be developed for all customers 2) whether all customers would benefit from competition in retail energy supply and 3) whether now was the right time to implement a restructuring plan to achieve these objectives. "If the Commission does not believe that these conditions exist, or that these objectives can be achieved, it should stop right here," PGE wrote, "There is no other point to restructuring."

The company also implied that, rather than adopt the approach of Commission Staff and the Citizens’ Utility Board, we should simply stay with existing regulation.

The Commission, however, adopted neither the PGE proposal nor the Staff/CUB alternative. While the Commission rejects PGE’s proposal as a whole, it does adopt it in part. More importantly, the Commission makes significant changes in the way electricity will be provided and marketed to customers in PGE’s territory. It does not go as far as PGE wanted but it does essentially deregulate generation and it does provide direct access to the customers most likely to benefit from it.

Adoption of these changes is not an inherent criticism of the existing system. In fact, the existing system has served PGE customers quite well, giving them some of the lowest rates in the nation. And it is those low rates that create very different dynamics for the decisions the Commission faced in this proceeding than those of other states where rates, and potential stranded costs, are much higher.

The order is more a recognition that the existing system may not be the most appropriate for the changes that have occurred in the electricity market. At the same time, the uncertainties of an open competitive market and the benefits and risks it would provide the smaller commercial and residential customers led the Commission to take a cautious approach.

The Commission decision in this case is restructuring. It is not complete deregulation. The most significant difference with PGE is disagreement over whether the time is right to expose the small commercial and residential customers to the volatility of an uncertain competitive market and risk the loss of the benefits of the current low-cost resource base. PGE asked us to accept as a given that competition will not only come to all customers, but that, despite the already low rates, it will benefit everyone. We may not have adopted the religious zeal for full-fledged, no-holds-barred, open competition that PGE originally advocated, but throughout the proceeding, consumer concerns have been paramount to the Commission. The order gives the larger customers the benefits of direct access. The smaller customers will get more choices without giving up still needed protections. And all customers retain the benefits of the low-cost hydro system.

The Commission wisely chose not to take an irreversible leap. What it has done in this proceeding though is establish a reasonable launching pad for retail competition. The Commission recognizes in this order that many details still need to be addressed before we can even implement this starting point. However, by opening PGE’s territory to retail competition under the terms of this order, the potential for more competition and greater benefits is preserved while the risks of potential harm are mitigated. Over time the stated objectives of PGE can still be achieved, but it will be done with less risk to customers.

It is still possible that using this order as a starting point, PGE can have an opportunity to exit the supply function responsibility. For example, in the future, instead of PGE maintaining the function of a default supplier offering a cost-based rate, that function might be put up for bid.

PGE currently obtains 70% of its power from the market anyway. In addition, the Commission has decided that all customers will receive the benefits of PGE’s hydro resources, even if they chose another supplier. All residential customers will receive the benefits of BPA power, also regardless of provider. Consequently, once PGE divests itself of the non-hydro assets, the cost-based offering essentially becomes one based upon hydro resources plus market acquisitions. With the benefits of BPA and PGE hydro resources applied to all residential customers, that is the same basis upon which an ESP could be offering supply. Under those circumstances, it seems logical that PGE, with Commission oversight, could just as easily put the cost-of-service provider responsibility up for bid, thus taking itself out of any supply acquisition business.

Just as a place on the portfolio is bid to ESP’s, so could the cost-of-service responsibility. It could even be bid in blocks, enabling more than one ESP to have an opportunity to access residential customers through acquiring this responsibility. Such an approach could potentially provide more competition and greater benefits than full direct access. In a territory such as PGE’s, where the margins are low and the size of the market is limited to the boundaries of one utility, the opportunity to be a default supplier for a substantial number of customers may attract more interest in the residential market than might otherwise be the case.

This is offered not as a proposal, nor as a target, but as an example of how the Commission’s order offers the flexibility to go farther if warranted. The Commission in this order is not precluding other options for the cost-of-service provider besides PGE. Many parties, including staff, acknowledged that possibility during the proceedings.

Similarly, the Commission is not precluding the possibility of PGE divesting its hydro assets. The Hydro Trust is a concept that requires more examination. Its viability depends upon specifics and details of its creation and operation. If the Hydro Trust can be structured in a way that assures the benefits of hydro resources stay with PGE customers, then it may be a welcome possibility.

With the Hydro Trust, divestiture of non-hydro assets, and the bidding out of the cost-of-service supplier responsibilities, PGE could achieve one of its primary goals – exiting from the supply function. And the Commission could still achieve its goal of protecting the small commercial and residential consumer.

The portfolio offering to small commercial and residential customers is also a mechanism that lends itself to evolution to a more contestable market. It can, and should be viewed, as PG&EES suggested – a transition to a direct access market for residential consumers and not necessarily as a permanent part of restructuring. As customers see more options, as their information and their desires for products other than the cost-of-service offering grow, the amount of direct access opportunities can be adjusted appropriately. As customers begin to get accustomed to making more choices, direct access can be added to the portfolio options. As the market matures, more providers enter the residential market, and more customer choose the direct access option, it is possible that full direct access can replace the portfolio.

In many ways the public purposes aspect of this decision was the most problematic. The Commission has rightly concluded that it is more prudent to assure maintenance of these public purposes up front than it is to risk having to try and overcome serious market failures by trying to build public purposes back into the system later. But given that it applies in only PGE’s territory, the decisions were made in less than ideal circumstances. Nevertheless, here again, the Commission decision is a starting point from which parties can proceed to develop something which, in the end, can and should be more dynamic than what is adopted in this order.

Ideally, the approach of establishing a non-bypassable system benefits charge would achieve the best results if established on a state-wide basis. Admittedly, applying it to only one utility creates some inequities. Ratepayers of that utility have to pay a charge that others do not. It also limits the scope of where the funding can be applied, making it less efficient than might otherwise be the case.

In addition, the Commission had to rely on a framework of a regional review process that ended over two years ago. Even though much has changed since then, the recommendations from that process represent a level of consensus in the region. To date no other consensus has emerged to take its place. Consequently the allocation of the funds and the Governor’s appointed citizen board to oversee the fund were adopted as a place to start. There is no inherent conclusion that the allocation is optimal. And the citizen board was adopted in anticipation that it could be adapted to a state-wide system benefits charge in the future.

This is a beginning organizational footprint for public purposes. It should not be interpreted as the definitive answer to the issue. The Commission has set out a set of basic principles for public purposes funding in a more competitive retail environment. However, for the concept of public purposes to succeed in the long run, it will need a vision that goes beyond what we are able to provide as the starting point in this order. Without it, the public purposes funding risks becoming a static, confined and self-perpetuating bureaucracy rather than a dynamic system capable of adapting and evolving with changes in the industry and its markets.

Public purposes funding is a method of providing assurances that those purposes won’t be sacrificed on the altar of competition. At the same time, it should also be seen as a transitional approach that may be altered, reduced, or even eliminated, if we find that the marketplace itself is capable of delivering some of the public purposes. Indeed, one of the goals of the administration of public purposes funding ought to be encouragement of an effective competitive marketplace for delivery of energy efficiency and renewable resources benefits. The decisions on how to do that were not within the scope of what the Commission addressed here. However, developing a competitive market capable of delivering the necessary level of energy efficiency will necessitate an eventual move away from continued reliance on the utility as the primary delivery mechanism. Mechanisms to allow competing energy service providers and their customers access to energy efficiency measures offered or funded by the system benefits charge will need to be developed.

Whether or not we proceed is up to the Legislature and to PGE. Ultimately it is PGE’s option to accept or reject the Commission’s approach. We have chosen a slower road to full retail competition for the small commercial and residential customer. It is one that still offers them some benefits from the changes in the energy market. But more importantly, it is one that offers an opportunity to increase the level of competition as the market evolves. PGE insistence on clinging to an "all or nothing" dictate will deny opportunities to customers. And it will deny the company an opportunity to begin movement toward its own stated goals.

In the attached order, the Commission suggests a restructuring plan that it believes makes the most sense for PGE customers at this time. The order points out that some of the Commission’s proposals will require legislation. The following is a list of legislative issues, as well as: (A) a brief description of subject matter of the legislation; (B) and the specific changes that will be necessary to make the Commission’s proposals law:

3. Authority to allow a system benefits charge (SBC). See pp. 50-53 of the order.

4. Authority to allow a state-level universal service fund. See p. 54 of the order.

Note: The Commission discussed on pp. 22-23 of the order a proposal by PGE that a "Hydro Trust" be created to purchase the company’s hydroelectric assets. PGE notes that legislation would be necessary to create the Trust. The Commission expressed interest in the concept but declined to endorse it at this time.

Equity Risk Premia
	Distribution Only	Fully Integrated	Generation Only
Recommended	232	270	319
High	292	340	401
Low	172	200	236