ORDER NO. 98-353

ENTERED AUG 24 1998

This is an electronic copy. Appendices, footnotes, etc., may not be included.

BEFORE THE PUBLIC UTILITY COMMISSION

OF OREGON

UM 834

In the Matter of an Investigation of )

Transition Costs for Electric Utilities. ) ORDER

DISPOSITION: GUIDELINES ADOPTED

The treatment of transition (or stranded) costs is one of the key issues in introducing retail competition in electricity. The Energy Information Administration recently estimated that transition costs might be as much as $72 to $169 billion for the entire United States and negative $24 to $38 billion for the Northwest. Decisions about the allocation of these costs (or credits) among stakeholders will determine in large part how customers fare under direct access.

This order adopts guidelines for the recovery of transition costs by investor-owned electric utilities under direct access. The guidelines are general and do not provide a formula for computing transition charges. They reflect the policy decisions we can make in a docket that applies to utilities in differing circumstances and that does not provide the context of a particular utility’s unbundled rate filing. We fully expect substantial discussion about implementing the guidelines in any such proceeding to unbundle an individual utility’s rates.

BACKGROUND

The Public Utility Commission of Oregon (Commission) opened this proceeding at a public meeting on January 21, 1997. The Commission held a prehearing conference on February 6, 1997, to discuss procedural issues and adopt a schedule. Participants subsequently submitted issues lists and met informally at a workshop to discuss and clarify their lists. Commission staff summarized the parties’ lists and the Administrative Law Judge distributed a consolidated issues list. Parties filed written proposals specifying their preferred methodology for addressing transition cost issues. Written reply comments were filed by parties wishing to comment on the proposals. A second prehearing conference was held on July 30, 1997, to discuss further procedural issues and to adopt another schedule. Commission staff sent out a draft order on October 24, 1997. Parties filed written comments on the draft order and written replies to the comments. A final draft order was mailed to the Parties on February 27, 1998. A special public meeting was held on March 17, 1998, to consider a final draft of the order. At that public meeting several changes to the order were mandated by the Commissioners. A final order was presented to the Commission at the August 4, 1998, public meeting.

PacifiCorp (Pacific), Portland General Electric (PGE), Enron, Idaho Power Company (IPCO), Northwest Natural Gas Company (Northwest), Washington Water Power (WWP), Eugene Water and Electric Board (EWEB), Citizens’ Utility Board (CUB), International Brotherhood of Electrical Workers (IBEW), Smurfit Newsprint Corporation (SNC), Northwest Conservation Act Coalition (now named Northwest Energy Coalition or NWEC), Don’t Waste Oregon, Industrial Customers of Northwest Utilities (ICNU), Northwest Independent Power Coalition (NIPC), Oregon Committee for Equitable Utility Rates/Oregon Committee for Fair Utility Rates/Industrial Customers of Idaho Power (OCEUR/OCFUR/ICIP\O), Oregon Energy Coordinator’s Association (OECA), Pacific Northwest Generating Cooperative (PNGC), Pope & Talbot, Public Power Council (PPC), U.S. Generating Company (US GEN), Utility Reform Project (URP), PG&E Energy Services, and the staffs of the Commission (Staff) and the Oregon Office of Energy petitioned to intervene and/or filed written comments.

ISSUES LIST, GUIDELINES, AND COMMENTS

Staff’s recommendation to initiate this docket included an initial list of issues to be addressed in this proceeding. Participants proposed modifications to the list in written comments and through discussion at the workshop. On April 2, 1997, the Administrative Law Judge distributed a consolidated issues list. The issues provided a focus for the oral and written comments submitted and the guidelines developed during this proceeding.

We believe the guidelines developed by Staff in response to the issues raised in this proceeding will provide greater clarity and consistency in filings by the electric investor-owned utilities to recover transition costs. We, therefore, adopt the 11 guidelines following the issues identified below.

What is the definition of transition costs?

The transition cost or benefit of an asset is the difference between its book value and its market value. Transition costs occur when an asset’s book value exceeds its market value. Conversely, transition benefits occur when an asset’s market value exceeds its book value. Market value is defined as the price that would be paid for an asset if it were purchased in an open competitive environment.

The assets to be included in the determination of transition costs and benefits are those electric utility investments, including plant and equipment, inventories, unamortized investment tax credits, contractual or other legal obligations, workforce commitments, and regulatory assets and liabilities, properly functionalized to generation or to conservation, that were prudent at the time the obligations were assumed.

Costs incurred in valuing or selling generation assets may also be included if deemed appropriate by the Commission.

Discussion

Staff believes the definition should be comprehensive yet flexible enough to allow room for different methodologies to be used in determining the value of transition costs and benefits.

ICNU defines transition costs as "…the present value of a forecasted stream of future costs of and revenues (and asset returns) from existing facilities and/or contracts prudently acquired by a regulated utility prior to January 1, 1996, to serve its reasonably expected load."

OCEUR/OCFUR/ICIP\O believes that transition costs are a subset of stranded costs and represent only that portion of the utility’s stranded costs that the Commission deems is appropriately recovered from customers. Stranded costs are those costs that a utility would not be able to recover in a fully competitive market. In addition OCEUR/OCFUR/ICIP\O states that "…only the fully mitigated cost of the total of the utility’s high-cost and low-cost assets that exceeds the market price for power counts as a stranded cost and would be eligible for recovery…."

PGE defines transition costs as "…prudently incurred costs that cannot be recovered in a competitive marketplace and cannot be mitigated." PGE divides these costs into three categories: regulatory, generation-related plant and/or power contracts, and distribution- and customer service-related costs.

Staff believes PGE’s definition leaves out the important concept of transition benefits. In addition, Staff is reluctant to include distribution- and customer service-related costs in the general definition. It is not clear to Staff that retail competition will cause any of these costs to become unrecoverable.

Staff additionally believes that electric utility investment includes entitlements to low-cost resources, e.g., resources from the BPA subscription process.

In its comments on the draft order, ICNU asks the Commission to reject the Staff proposal to include resources such as those from BPA’s subscription process in the definition of transition costs. ICNU states that no utility has committed to BPA subscription resources, that such resources are not yet defined or priced, and that they should be considered future commitments.

In its comments on the draft order, PGE states that there is no basis to include entitlements to low-cost resources in transition costs. The company maintains that entitlements are not costs unrecoverable in a competitive world, that they have no value that can be tested in a market, and that they are not costs that have been assumed by the utility. According to PGE, "If power from the BPA subscription process provides benefits to consumers the benefits are immediately available as lower costs at the time they consume the power." PGE further states that the BPA subscription process has not resulted in any concrete proposals and "In any case PGE will have no investment in it."

In its comments on the draft order, CUB agrees with Staff’s position that entitlement to low-cost resources should be considered an element of transition costs. CUB states that under current regulation customers have an entitlement to low-cost BPA resources. CUB takes issue with PGE’s assertion that benefits of low-cost power from BPA are available when customers consume the power. CUB states, "This is not true if PGE is the agent on behalf of their customers in the subscription process and PGE decides not to exercise their customers’ subscription rights."

PacifiCorp would like to exclude historical DSM from transition costs. However, Staff believes that historical DSM should remain in the transition cost category.

ICNU and Pope & Talbot state that the Commission should adopt a policy that Oregon ratepayers should not be forced to pay transition costs incurred by multi-state utilities for generation investments or regulatory assets in other states.

Staff’s position is that it is reasonable to accept a part of the transition costs of generation assets in other jurisdictions that were used to serve customers in this state. Oregon has historically allowed generation-related costs on an allocated basis. Commission Staff works closely with PUC staff in other states to ensure a fair and equitable allocation methodology is used. Whether a specific allocation is reasonable is more appropriately brought up in an individual company’s proceeding.

Commission Conclusions

We agree that a comprehensive and flexible definition of transition costs and benefits should be adopted. The proposed definition provides a background that is used later in the development of other guidelines.

We also accept Staff’s reservations about broadening the definition to include distribution- and customer service-related costs. Any utility claiming these as transition costs must prove its case.

We agree with the position of Staff and CUB that electric utility investment includes entitlements to low-cost resources, including resources from the BPA subscription process. An option to buy federal power at cost can have significant value, as evidenced by the recent exchange settlement negotiations between PGE and BPA. We disagree with ICNU’s assertion that future actions are excludable from consideration in the transition cost calculation. Mitigation, for example, is an accepted concept and refers to future actions, including changes in power supply contracts taken to reduce current obligations. Subscription is an ongoing BPA process for the allocation of federal power. At our January 6, 1998, Public Meeting, Staff shared with us a BPA Subscription proposal to reserve a significant amount of power, up to 1500 AMW, for former residential exchange loads. To the extent that federal power is available to our regulated utilities, for purchase on behalf of, and for the benefit of, their customers, including the residential and small farm customers, the utilities are at risk if they fail to act in the interests of their customers. We agree with Staff that it is appropriate to include the potential benefits of federal power as an offset to transition costs if we find that the utilities did not act in the interests of their customers. An offset to transition costs is not appropriate with respect to federal power to the extent the utilities purchase such power and deliver the benefits to their customers.

Any utility that operates in more than one jurisdiction uses allocations to assign some of its costs. The appropriate place to challenge an allocation methodology is in a company-specific proceeding.

Using the definition of transition costs in the approved guideline above, it follows that historical DSM belongs in transition costs.

How should the value of transition costs be determined?

There are several methodologies that can be used to value transition costs. Each electric utility must be looked at as a unique entity and may require different treatment in the valuation of its transition costs/benefits.

The preferred valuation method is the sale of an asset in an arms-length transaction.

If a forecast is used in a methodology, one or more true-ups may be needed to correct faulty assumptions.

If a present value methodology is used, the time horizon for the calculation should be the economic life of the asset.

Discussion

CUB and NWEC advocate an approach to determining transition costs called the "Financial Expectations Method." This method attempts to calculate how much stranded cost recovery is necessary to enable a utility to satisfy the reasonable expectations of its stockholders and debt owners. This approach requires the modeling of a utility’s financial structure and performance as well as its stockholders’ expectations. CUB and NWEC acknowledge that this is a new approach and that there are questions about how the modeling will work.

PGE believes the market itself is the best indicator of the value of assets. Its preferred basis for determining value is through a market transaction (e.g., actual sale of assets, asset capability, project output, or a system sale -- physical or the financial equivalent). However, the company does not believe that divestiture of assets should be required unless the utility has a dominant position in the wholesale generation market.

ICNU proposes that a utility’s transition costs be calculated as the present value of the utility’s costs, offset by the present value of its revenues, less costs saved through mitigation of the transition costs. ICNU also proposes that the appropriate time horizon over which to measure transition costs be a term of 20 years or a date at which there are no transition costs, whichever is sooner. Additionally, ICNU urges the Commission to adopt the date of January 1, 1996, as the date beyond which new generation investment and long-term purchases are no longer considered eligible for transition cost recovery.

OCEUR/OCFUR/ICIP\O believes a market-based approach that reflects the value of the utility’s assets in the competitive market should be used to quantify stranded costs. It proposes that transition costs equal the difference between the book value and the economic value of a utility’s generating plant. The economic value is determined by the present value of all positive and negative returns produced by a plant over its life.

In its reply comments, Pacific supported the general methodology proposed by ICNU. However, it does not support a transition cost start date. Pacific also believes the "… approach suggested by CUB and NWEC is unsatisfactory because it is overly dependent on subjective or unverifiable assumptions about investor expectations and future company earnings…"

Pope & Talbot, in its reply comments, also generally supported the methodology proposed by ICNU.

In their reply comments, CUB and NWEC take issue with using a time horizon that simply takes transition costs to zero. They state, "After all, it is only in their later years, when fully depreciated, that some of these assets actually start to make much profit. And that profit must not be used to get stranded costs down to zero; if available, it must be used to provide a benefit – a negative stranded cost – to ratepayers who paid for it."

Staff’s preferred valuation method is the sale of an asset in an arms-length transaction. Any asset not valued in this manner should be subjected to an administrative process that forecasts the asset’s costs and revenues over the economic life of the asset. Staff defines "economic life" to be the timeframe over which a resource is economic and viable. In other words, it is cheaper to continue operating the resource, even with maintenance costs and capital additions, than it is to shut it down. The assumptions used in the forecasts should be examined periodically and revised if necessary.

PGE argues that the Commission should not set a date beyond which new generation investment and long-term purchases are no longer considered eligible for transition cost recovery, because it would have a chilling effect on any long-term investments being considered. Pacific supports PGE’s position. Pope & Talbot disagrees, stating that a cut-off would not have a chilling effect if the investment in question is prudent. Staff observes that a cut-off date can be applied in other ways, e.g., as the date at which any sharing of transition costs is presumed to have gone into effect. Staff also argues that it is premature to set a cut-off date, given the uncertainty about when and how restructuring will occur.

CUB proposes to include productivity and labor cost savings in any administrative valuation of transition costs. NWEC questions the possible use of the sale of a portion of an asset to impute the value of the total asset. Staff’s response is that these issues should be raised in company-specific proceedings.

Commission Conclusions

We agree that the preferred valuation method is the sale of an asset in an arms-length transaction. In some cases, however, an asset may have higher value for customers if retained by the utility instead of sold, even in an arms-length transaction. For example, uncertainties surrounding the relicensing of a utility’s hydroelectric facilities may make it inadvisable for the utility to sell them.

The Commission also recognizes that there are significant political, legal, and economic uncertainties concerning the sale of hydroelectric projects. Relicensing at the federal level is the responsibility of the Federal Energy Regulatory Commission (FERC). The FERC relicensing process requires a minimum of five years. FERC licenses must contain conditions that balance power generation with fish, wildlife, recreation, and other uses of the water. In the state of Oregon, FERC-licensed hydro projects are required to obtain a water right and state water quality certification. The 1997 Oregon Legislature passed HB 2119, which mandates a project review process that closely parallels the FERC process. The state process also requires a minimum of five years. An ongoing hydroelectric facility must serve the needs of many different interest groups. The rivers of Oregon and the hydroelectric facilities that use them are integral to the lives of Oregonians. We acknowledge the concerns about selling such an important resource.

We conclude that where an asset is not sold, any needed estimate of transition costs or benefits should be developed through an administrative process that forecasts the asset’s costs and revenues over the economic life of the asset. We also agree that whenever forecasts are used in valuing an asset, the assumptions used in the forecast should be periodically re-examined and the forecast trued-up if necessary.

The use of an administrative process to value assets is inherently less precise than the actual sale of the asset or its output. Forecasts are often incorrect and must be periodically trued-up to correct for faulty assumptions.

We agree that it is premature to set any kind of cut-off date for transition costs. Furthermore, CUB can address productivity and labor cost savings and NWEC can raise its concerns about interpreting the results of a partial asset sale in company-specific proceedings.

Should utilities be required to mitigate transition costs? How can mitigation be measured?

Utilities must make every reasonable effort to mitigate transition costs. The Commission may allow less than full recovery of transition costs under any of the following conditions:

The utility has not made a sufficient showing of mitigation.

The Commission finds that a recovery level of less than 100% provides enough incentive to ensure mitigation.

Discussion

PGE suggests that mitigation should be defined using the precedent established in contract law -- the duty of mitigation under contract law. It states that, in this context, securitization would be a valid mitigation strategy. (Securitization is a method of financing transition costs. This method uses an irrevocable order by a commission that allows the utility to collect a revenue stream associated with the transition costs, on behalf of the securitization bondholders.)

NWEC believes that if securitization is allowed, utilities should receive a lower rate of return for any costs supported by a guaranteed cost-recovery mechanism.

Staff is unconvinced there is any mitigation benefit in securitization because any potential benefit may be more than offset by risks to ratepayers. Securitization is also inconsistent with the principle of forecast true-ups. Staff believes NWEC’s position on securitization should be addressed in company-specific proceedings.

OCEUR/OCFUR/ICIP\O also disagrees with PGE’s securitization proposal. It states that securitization is not "… a meaningful or reasonable mitigation strategy in its own right. First, while securitization may reduce the present cost of a resource, it may do so at the expense of creating a protracted revenue requirement (to retire the debt) well into the future. In this respect, securitization substitutes one stranded cost for another."

Pacific, in its reply comments, states "… the Commission should review a utility’s historical efforts to obtain low costs and efficiencies, as well as prospective efforts to reduce overall stranded costs levels."

In its reply comments, Pope & Talbot states, "It is not sufficient, as suggested by one of the utilities, to simply stop incurring new costs. There is also the obligation to slow or eliminate the costs that have been and are being incurred."

Staff believes that allowing a utility less than full recovery of transition costs can help ensure that mitigation occurs. If a utility has not made a sufficient showing of mitigation it could be penalized by allowing less than 100% recovery. In some instances, the Commission could determine that less than full recovery provides a sufficient incentive to ensure mitigation and no showing of mitigation would be needed.

Staff believes prudency is the appropriate standard for mitigation and that it should be evaluated in company-specific proceedings. ICNU does not agree with the standard that utilities must behave prudently consistent with past practice because this is not an aggressive enough approach.

The Staff commends the parties for suggesting several strategies for mitigation. Some useful suggestions are listed below:

Productivity and labor-cost savings that can be measured based on some agreed-upon index.

Negotiated changes in fuel contracts.

Negotiated changes in PURPA contracts.

IBEW asserts that employees have already made their contribution to mitigation, through utility downsizing, and, therefore, that staffing levels should not be cut to mitigate transition costs. Staff notes that reducing staffing levels is simply one mitigation measure that can be examined in company-specific proceedings on transition costs.

Commission Conclusions

We want to emphasize that utilities have a duty to mitigate transition costs and in mitigating they must behave prudently, meaning that their decisions were reasonable, based on information that was available (or could reasonably have been available) at the time. The Commission has applied this prudency standard for many years in deciding whether to include in rate base the full amount of a utility’s investment in a new resource (as opposed to a standard that, say, focuses on the outcome of the utility’s decisions). ICNU believes that our standard for mitigation should be more aggressive. We expect the utilities to be aggressive in finding ways to mitigate transition costs, but we will not depart from our basic standard. Utilities should expect to show they have maximized the value of their assets and minimized the costs associated with those assets. We may allow less than full recovery of transition costs to ensure that mitigation takes place.

We will review securitization proposals on a case-by-case basis. However, utilities must make every reasonable effort to mitigate transition costs and should not rely on securitization as the only evidence of mitigation.

How should low-cost assets be treated?

Generally, low-cost assets should be netted against high-cost assets. However, specific resources may be reserved when it is in the public interest to do so.

Discussion

All parties agreed that low-cost resources should be netted against high-cost resources.

PacifiCorp recommends deleting the reference to reserving specific resources for public policy purposes. Staff believes that reserving specific resources may be the best way to preserve the benefits of low-cost resources (which is the fifth overriding objective in the Governor’s "Statement of Principles for Restructuring the Electric Utility Industry").

Commission Conclusions

We find that the concept of netting low-cost and high-cost assets is consistent with the definitions adopted in Guideline 1. We also find that specific resources may be reserved when it is in the public interest to do so (see our discussion under Guideline 2). This would be determined in each utility’s restructuring proceedings.

Should utilities be allowed full recovery of transition costs?

The Commission may conclude that full recovery or less than full recovery is in the public interest.

Discussion

OCEUR/OCFUR/ICIP\O states that a number of factors should be taken into consideration in determining whether a utility should be allowed to recover all of its stranded costs. Among them are: 1) the financial impact on the utility that may result from less than full recovery; 2) the impact of a transition charge on the ability of customers to access competitive markets; 3) the magnitude and duration of the charge; and 4) the extent to which the utility has reasonably and aggressively mitigated its stranded costs.

ICNU recommends an equal sharing between shareholder and customer, if the Commission does not adopt a present-value methodology.

CUB and NWEC believe sharing between shareholders and customers is appropriate and the best way to ensure that a utility mitigates stranded costs.

NWEC believes the shareholders of a utility should share risks (including transition costs) if they were compensated above the level of a riskless T-bill rate. NWEC suggested adding the following language: "The recovery level should reflect the previous sharing of risks between shareholders and ratepayers and not provide payment for the consequences of risks which were the responsibility of the utility."

Staff believes NWEC’s proposal should be evaluated in company-specific proceedings.

PGE believes 100% of transition costs that were prudently incurred, mitigated, and verifiable should be recovered. It further believes that both law and equity require full recovery of transition charges.

Pope & Talbot states that utilities should not be allowed full recovery for their claimed transition costs. Pope & Talbot also proposes that shareholders bear all of the risk of load loss unrelated to restructuring, i.e., from plant shutdown, annexation, municipalization, self-generation, and conservation programs. Staff disagrees, arguing that it would be difficult to decide whether or not these events occurred because of restructuring.

IBEW supports full recovery of transition costs by a utility.

Staff agrees with OCEUR/OCFUR/ICIP\O that a number of factors should be taken into consideration in determining what recovery level should be allowed. In the A-Engrossed House Bill 2821, the Commission was required to use the following criteria (which Staff supports):

Require substantiation that reasonable mitigation efforts have been pursued.

Allow recovery for a period not to exceed five years unless the Commission determines another recovery period is in the public interest.

Transition charges should not be so high that direct access is generally more costly than service under cost-based rates.

Avoid unreasonable financial harm to the electric company.

Recovery policies may differ among resources, depending on whether the utility investments or commitments were incurred as a direct result of federal or state statutory mandates.

Commission Conclusions

We agree with OCEUR/OCFUR/ICIP\O and Staff that a number of factors should be taken into consideration in determining what recovery level should be allowed. The factors above, that were included in the A-Engrossed House Bill 2821, provide balance and flexibility, and we will use them in our deliberations when determining the recoverable level of transition costs for an electric utility. In individual company proceedings, parties can argue that other factors should be taken into account. Application of these factors may result in less than full recovery of transition costs in some cases.

We will consider arguments on distinctions parties may wish to draw concerning different resources. If a party can present a convincing case that certain assets should be judged differently in a transition cost calculation (e.g., PURPA contracts), the Commission will consider these differences in setting transition charges for electric utilities.

PGE has raised the issue of whether a Commission decision to allow less than 100 percent recovery of transition costs violates the U.S. or Oregon Constitution. The company claims that less than full recovery is an unconstitutional taking.

The Commission has two responses.

First, PGE’s argument is premature. Courts must judge the constitutionality of rates based on whether those rates, as a whole, allow a utility sufficient revenue for expenses and for capital costs of the business. Federal Power Commission v. Hope Natural Gas Co., 320 US 591, 603 (1944). Recovery of transition costs is only one factor the Commission will consider in setting rates for PGE should the agency approve a restructuring plan for the company. It is impossible, at this point, to determine whether a hypothetical disallowance of some of PGE’s transition costs will result in confiscatory rates.

Second, if the Commission does approve rates for a restructured PGE, and if it disallows recovery of some of the company’s transition costs in doing so, then PGE is free, under current law, to withdraw its rate filing. Unless the Legislative Assembly changes the law to give the Commission the authority to order PGE to restructure on the agency’s terms, there is no danger that the Commission, by disallowing full recovery of transition costs, can force confiscatory rates on the company.

On June 24, 1998, the Court of Appeals of the State of Oregon issued its ruling on the Trojan case, CA A86940. The result of this ruling is the disallowance of a return on the Trojan investment. The Commission and others have asked for a hearing in the Supreme Court of Oregon. Before allowing transition cost recovery to a utility, the Commission will need to review the final decision in the Trojan case to determine what applicability, if any, the decision has to the issue of transition cost recovery.

What time period should be used for recovery?

The time period for recovery should not exceed five years. However, this requirement may be waived if the Commission determines that a longer recovery period will facilitate competitive generation services markets or is otherwise in the public interest. If the five-year period is extended, this extension shall not cause an increase in the utility’s recovery of transition costs above that deemed reasonable by the Commission.

It may be reasonable to vary recovery periods between customer classes and for different types of assets.

Discussion

OCEUR/OCFUR/ICIP\O states that the time period for recovery should be as short as possible (e.g., three to five years).

PGE states that current rates are recovering costs of assets with lives of 15-30 years. It believes that the collection period could be shortened but does not want to artificially increase rates by trying to collect long-lived assets over an arbitrarily short period of recovery.

Staff believes that, depending on the magnitude of the transition cost charge, it may be appropriate to extend the recovery period for certain classes of customers in order to keep their rates at a reasonable level. Therefore, Staff recommends that the Commission allow variance in the recovery period.

Commission Conclusions

We accept Staff’s recommendation for the reasons stated. We also note that the language adopted in Guideline 6 is virtually the same as that adopted in A-Engrossed House Bill 2821.

See the Commission’s Conclusions in Guideline 5 for a discussion on the Commission’s authority to allow a utility to earn a return on its transition costs.

How should transition costs be spread among customer classes?

The allocation of transition costs or benefits will be determined in individual utility rate cases where transition charges or credits are proposed.

Discussion

CUB argues that generation transition costs should be allocated to energy and demand usage based on the load each type of plant was designed to serve. Baseload plant costs would be allocated on energy, but peaking units would be allocated more on demand. OCEUR/OCFUR/ICIP\O believes that no distinction should be made between baseload and peaking resources for allocating transition costs and that CUB’s proposal would shift costs between customer classes. OCEUR/OCFUR/ICIP\O supports the use of a fixed meter charge to recover transition costs and opposes energy charges as unfair because higher load-factor customers would pay a higher percentage of their bills in transition charges than less efficient customers. CUB disagrees, stating that volumetric charges are better suited to match load with the cost incurred to serve it.

PG&E Energy Services and CUB state that transition costs are not marginal costs and that there is no inherent reason that transition costs should be allocated on the basis of the marginal costs of energy and other services. Staff believes that if other unbundled rates are set to eliminate differences in the share of marginal cost paid by different customer classes, then transition charges or credits should be set so that all customer classes are still able to benefit from the move to unbundling and direct access. Pacific states that transition cost charges should not be used to eliminate subsidies. PG&E Energy Services and CUB agree that other considerations may not become evident until transition costs are addressed in utility rate cases. PGE and ICNU both agree that transition costs should be spread so that the end result is fair.

CUB and NWEC believe that each customer class should be responsible for its share of transition costs, so that, for example, if an industrial customer self-generates, other industrial customers would make up the shortfall, not customers in other classes.

Commission Conclusions

We will not adopt standards for the allocation of transition costs or benefits in this proceeding. While the Staff’s condition that those costs or benefits be spread so that all customer classes can benefit from restructuring is appealing, we agree with PG&E Energy Services and CUB that other relevant considerations may well arise in the context of rate cases in which transition charges or credits are proposed.

New customers should pay transition charges on the same basis as existing customers.

Discussion

OCEUR/OCFUR/ICIP\O believes that new customers should not be required to pay transition charges, "since the ‘obligation,’ if any, to pay for stranded costs arises from the utility’s obligation to serve." CUB notes that it would be impractical to assign transition costs on the basis of usage by customers served at the time a resource was acquired and recommends instead that transition costs be collected on the basis of future use. CUB reasons that resources now stranded by competition were built to serve future loads.

Pacific recommends including language in the guideline that would allow the Commission to excuse new customers from the transition cost charge, but NWEC disagrees.

Commission Conclusions

We agree with CUB’s conclusion. New customers in a utility’s service territory should pay transition charges on the same terms as existing customers because the utility’s resources were acquired to meet forecasted loads throughout the lives of the resources. Pacific did not justify its proposal to allow for excusing a new customer from paying transition charges (other than to "…be flexible enough to recognize unique customer circumstances and not stifle benefits from competition."), and we do not adopt it.

Should exit fees be used?

The Commission will allow the use of exit fees. They may be a useful tool for customers who wish to quickly settle their transition cost obligation.

Discussion

Exit fees are a one-time payment of transition costs that a customer would otherwise be obligated to pay over time. Customers have the choice to pay their transition charges over time or in one lump sum. They are not required to pay an exit fee to obtain direct access to alternate generation suppliers.

OCEUR/OCFUR/ICIP\O and ICNU do not believe that exit fees should be used.

PGE states that exit fees should be an option, but not mandatory.

Although Staff acknowledges that there may be disputes over how exit fees will be calculated, it believes such fees should be allowed.

Commission Conclusions

It is the intent of this Commission that all customers pay their fair share of any transition costs. Customers changing generation suppliers under direct access do not leave their obligation behind. Exit fees may be one tool these customers can use to "pay-off" their obligation. We expect the method used to calculate this fee would be determined as part of a utility’s transition cost filing.

Should transition cost charges be non-bypassable?

Transition cost charges shall be non-bypassable to the same extent that utility charges are currently non-bypassable.

Discussion

OCEUR/OCFUR/ICIP\O believes that transition cost charges should be bypassable.

PGE, Pacific and ICNU all state that the charges should by non-bypassable. ICNU would exempt self-generators and businesses that close.

In its reply comments, Pope & Talbot states, "Transition costs should be assessed against all customers of a utility, regardless of rate class, and all who leave the system except those exercising constitutional or statutory rights to self-generate, annex, or municipalize, or close down their operations."

PacifiCorp believes customers should not be able to escape payment of transition charges through activities such as municipalization or annexation.

CUB would define non-bypassable as not being able to bypass transition costs by any means, whether through self-generation or special contract.

Staff also believes that transition cost charges should be non-bypassable. Staff agrees with ICNU and Pope & Talbot that self-generators and businesses that close should be exempt, as well as customers who choose municipalization or annexation. However, self-generators should pay transition cost charges on any power delivered by the local utility, e.g., during maintenance of their facilities.

Commission Conclusions

The Commission agrees that transition cost charges should be non-bypassable. However, it is not our intent in these guidelines to take away any rights now held by customers to avoid utility charges or by utilities to recover their costs or lost revenues from departing customers.

Should self-generators be excused from the transition cost charge?

Self-generators will be excused from transition cost charges. However, if they take power from the system, transition cost charges will be assigned to that power unless exempted on a case-by-case basis.

Discussion

OCEUR/OCFUR/ICIP\O and ICNU believe that all self-generators should be excused from the transition cost charge.

PGE states that all customers who are connected to the electric grid should pay the transition cost charge.

CUB, NWEC, and PGE all state that self-generators should not be excused from transition costs because it encourages customers to make uneconomic choices.

Staff believes that self-generators should be excused from transition cost charges as long as they do not take power from the system. Currently, self-generators do not pay any utility costs if they take no power, and Staff sees no reason to change that in the future.

PacifiCorp supports Staff’s position as it applies to current self-generators but argues that future self-generators should not be excused from transition costs (because it would encourage customers to make uneconomic choices).

SNC claims that, as a self-generator and special contract customer, it has provided PGE with opportunities to displace existing resources and defer acquisition of new resources. SNC argues that since it has been more a resource than a firm load for PGE, it should not incur transition charges when it takes power from the system. Staff questions SNC’s characterization of the service obligation it has placed on PGE and suggests that exceptions to a rule that self-generators pay transition charges when they take power from the system could be made on a case-by-case basis.

Commission Conclusions

We agree that self-generators should not have to pay transition cost charges as long as they take no power from the system. However, to the extent customers purchase power from the utility, they would pay the appropriate transition cost charges unless exempted on a case-by-case basis.

Will special contract customers be required to pay transition cost charges?

Special contract customers will not be required to pay separate transition charges for service under the contract. For service not covered by the special contract or service when there is no special contract in effect for the customer, the transition charges for service to similar non-contract customers will apply, unless exempted on a case-by-case basis.

Discussion

In their reply comments, CUB and NWEC state that customers presently receiving special contracts should not be exempted from transition charges.

Staff notes that special contracts are only allowed for customers meeting specific criteria that justify the contract rate. The customer must have a viable alternative to the utility’s service (such as on-site generation potential or the ability to shift production elsewhere). The contract rate is usually designed to match the customer’s alternative costs, thereby maximizing the customer’s contribution to the utility’s fixed costs. Staff points out that adding a transition charge to the contract rate would produce a total rate exceeding the customer’s alternative costs. Staff therefore recommends that no separate transition charge be applied to service under a special contract. Staff also believes that even if a transition charge is not directly imposed on special contract customers, some portion of the contract rate may be attributed to transition cost recovery. Furthermore, any portion of a special contract customer’s load that is not covered under the contract or not self-generated would be subject to the transition cost charge, as would service after the special contract expires.

SNC argues that it should be exempted from transition charges to the extent that it has not imposed a firm load on PGE under its special contract.

Commission Conclusions

We agree that service under a special contract should not be subject to a separate transition charge. Service not covered by a special contract, including service after the contract expires, would be subject to the same transition charges as comparable non-

contract customers or loads. Smurfit and other customers can argue in specific utility proceedings that they should be exempt from transition charges for service not under a special contract.

ORDER

IT IS ORDERED that the guidelines to be used by electric utilities when they file for recovery of transition costs are adopted.

Made, entered, and effective _________________________.

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 860-14-095. A copy of any such request must also be serve on each party to the proceeding as provided by OAR 860-13-070(2)(a). A party may appeal this order to a court pursuant to ORS 756.580.