ORDER NO. 97-371

ENTERED SEP 18 1997

This Is An Electronic Copy

BEFORE THE PUBLIC UTILITY COMMISSION

OF OREGON

UE 94 (Phase II)

DISPOSITION: STIPULATED AFOR REJECTED;

COMMISSION CONFERENCE SCHEDULED

Summary

In this order, we reject a stipulated alternative form of regulation (AFOR) plan submitted by PacifiCorp, dba Pacific Power and Light Company (PacifiCorp) and the Public Interest Parties, consisting of the Citizens’ Utility Board, Natural Resources Defense Council, Oregon Department of Energy, and Northwest Conservation Act Coalition. After our review, we believe that the stipulated agreement, if adopted, would likely result in higher rates than would be charged under traditional regulation. Accordingly, we conclude that despite particular benefits that could result, the stipulated AFOR fails to provide adequate customer benefits as required by ORS 757.210(2)(b).

We do not close this docket, however. In this era of emerging competition within the electric power industry, we believe that it is in the public interest to further pursue other regulatory options with PacifiCorp. Accordingly, we have scheduled a conference in this matter to obtain further comment from the parties regarding several areas of inquiry identified in this order.

Procedural Background

PacifiCorp initiated this case on September 1, 1995, with the filing of revised tariff schedules designed to increase rates to its Oregon retail electric customers. It also requested the approval of an alternative form of regulation (AFOR) plan, as authorized under ORS 757.210(2). The company proposed that the AFOR become effective with its new tariff schedules and continue for a term of five years.

At the request of the parties, this case was divided into two phases. Phase I was limited to revenue requirement issues under traditional regulation (including rate spread and rate design). Phase II was designed to address AFOR issues, decoupling, service quality standards, system benefit charges, and renewable resource incentives.

On July 10, 1996, the Commission concluded Phase I by adopting a stipulation between PacifiCorp and Staff for a 4 percent rate increase, effective July 15, 1996. See Order No. 96-175. The order also identified seven contested issues: rate spread, street lighting, Upper Klamath River Basin/United States Bureau of Reclamation allocation, decoupling, system benefit charge, functionalized billing, and service quality standards. The Commission resolved the first two issues consistently with recommendations of Staff and PacifiCorp, and deferred the last five issues for resolution in Phase II.

On October 23, 1996, PacifiCorp and the Public Interest Parties (collectively referred to as the Joint Parties) filed with the Commission a stipulated AFOR. The Joint Parties entered into the stipulation for the purpose of resolving all outstanding Phase II issues. The parties proposed that the stipulated AFOR replace traditional rate of return regulation for Pacific for a five-year period, beginning July 1, 1996.

On January 23, 1997, Michael Grant, an Administrative Law Judge (ALJ) for the Commission, held a hearing on this matter in Salem, Oregon. James Fell and Kathryn McDowell, attorneys, appeared on behalf of PacifiCorp. Paul Graham, Assistant Attorney General, appeared on behalf of Staff. Keith Kutler, attorney, appeared on behalf of OCFUR. Melinda Horgan, attorney, appeared on behalf of Industrial Customers of Northwest Utilities (ICNU).

On February 21, 1997, the parties filed simultaneous opening briefs in this matter. The parties later filed simultaneous reply briefs on March 7, 1997.

On March 20, 1997, ALJ Grant issued a ruling holding Phase II in abeyance until after the 1997 Oregon Legislative Assembly had adjourned. The ruling noted that the Legislature was considering several bills and legislative concepts to restructure the electric industry. Accordingly, the ruling concluded that it would be prudent to delay any decision on alternative ratemaking proposals until after it became apparent whether the Legislature intended to address related issues. The Legislative Assembly subsequently adjourned on July 4, 1997, without enacting any restructuring proposal.

Based on the record in this matter, the Commission enters the following:

FINDINGS

The electric power industry is in the process of significant change. Current wholesale power prices are significantly lower than the embedded, or average, cost of utility supplied power. Surplus generating capacity in the western United States, combined with increasing competition among wholesale suppliers, has reduced the price utilities must pay for power on the open market.

These changes have created significant pressure to open retail electricity markets to competition. Many industrial and commercial customers desire the ability to choose among service providers. Expanding competition in the electric industry to all customers could result in lower prices and a greater variety of service options.

Oregon Legislation

To assist the transition of the electric power industry in Oregon from a regulated monopoly environment, the 1995 Legislative Assembly enacted HB 2846. That bill, codified as ORS 757.210(2), authorizes this Commission to approve an alternative form of regulation (AFOR) plan for electric utilities. In the statute, the Legislature provided this Commission with the flexibility to set rates and revenues and determine a method for changes in rates and revenues using alternatives to cost-of-service rate regulation. ORS 757.210(2)(b) provides:

Any alternative form of regulation plan shall include provisions to ensure that the plan operates in the interests of utility customers and the public generally, results in rates that are just and reasonable, and may include provisions establishing a reasonable range for rate of return on investment. In approving a plan, the commission shall, at a minimum, consider whether the plan:

Promotes increased efficiencies and cost control;

Is consistent with least-cost resources acquisition policies;

Is consistent with maintenance of safe, adequate and reliable service; and

Is beneficial to utility customers generally, for example, by minimizing utility rates.

Stipulated AFOR Plan

With its September 1, 1995, rate filing, PacifiCorp filed a proposed AFOR plan pursuant to ORS 757.210(2). Noting the changing environment within the electric industry, PacifiCorp stated that the plan placed more emphasis on performance than traditional cost-based regulation and proposed that the Commission approve it as a transitional step toward a more competitive electric industry.

Following negotiations and settlement discussions, PacifiCorp modified its original proposal and entered into a stipulation with the Public Interest Parties entitled "Oregon Alternative Regulation Settlement Proposal." The Joint Parties propose that the stipulated AFOR replace traditional rate of return regulation for PacifiCorp for a five-year period, beginning July 1, 1996. The complete stipulated AFOR is attached as Appendix A. For purposes of our discussion, we summarize its major features below:

1. Term of Plan: The Joint Parties propose a five-year trial period for the AFOR plan, with the option of extending the mechanism an additional five years. PacifiCorp or the Commission may, at any time, initiate a reevaluation of all aspects of the stipulated AFOR in case of major industry change or corporate structural change, or if the company fails to maintain minimum bond ratings (See Section 13, infra).

2. Initial Price Change: The Joint Parties propose that the 4 percent overall price increase approved in Order No. 96-175 should remain in place.

3. Annual Price Change: Under the stipulated AFOR, PacifiCorp would be allowed to implement annual price adjustments in years two through five. The maximum percentage annual change would be established by an index based on the forecast change in the GDP Price Index, offset by a productivity adjustment. The productivity adjustment would be 0.75 percent for generation and transmission functions, and 0.3 percent for distribution. The company agrees to limit the overall increase to 2 percent in any one year and to a total of 6 percent over years two through five.

PacifiCorp may choose to request less than the allowed price increase and may request a price decrease at any time. The company would apply any index-based price decrease on a mandatory basis except when earnings are below the earnings band (See Section 5, infra).

To compute any annual price change, PacifiCorp would separate its Oregon revenue requirement into three components: Generation - $372.7 million; Transmission - $98.0 million; and Distribution - $226.5 million. This functionalized separation will be the basis for the development of an average functionalized price per kWh, which would be adjusted annually.

The generation price per kWh for each of the years two through five would be a weighted average of the indexed generation component, as described above, and a proxy market rate of 25 mills. The proxy market rate would be given weights of 2 percent, 4 percent, 6 percent, and 8 percent in years two through five, respectively.

4. Revenue Cap for Distribution Revenues: The Joint Parties propose that a revenue cap be applied to distribution revenues. Under this mechanism, temperature adjusted actual sales revenues for each major customer class would be compared to a predetermined revenue cap for that class. Any differences would be collected in a balancing account for distribution (collection) the following year.

5. Earnings Band: The Joint Parties propose to use an earnings band with ranges from 7.75 percent to 14.75 percent return on equity (ROE) for the annual earnings review. If the ROE falls outside the earnings band, PacifiCorp would share the difference with customers on a 50/50 basis as either a credit or a surcharge. The earnings band would be adjusted annually based upon monthly average changes to interest rates and industry betas. The capital structure will consist of 46.3 percent long-term debt, 7.1 percent preferred stock and 46.6 percent common equity, and will remain constant for the term of the AFOR.

6. Annual Earnings Review: The Joint Parties propose that PacifiCorp provide an annual earnings report for the most recent prior calendar year by April 30 of each year, beginning in 1998. The report would be used to demonstrate PacifiCorp’s earnings as measured by ROE and to verify that the company’s earnings are within the formalized earnings band.

7. Adjustments for Major Events: The Joint Parties propose that certain changes to PacifiCorp’s costs caused by "major events" outside the company’s control be reflected in any annual price change. "Major events" are limited to changes in Federal/State/Local taxes, including the enactment of an energy related tax.

8. Rate Design: The Joint Parties propose that AFOR price design changes would be applied on a roughly uniform percentage basis to all binding elements for residential and small commercial customers. Irrigation price increases will be applied to the energy charge only. Large commercial and industrial customers would see price increases through changes to the demand charges only.

9. Service Quality Standards: The Joint Parties propose the AFOR include five service quality performance measures, as well as penalties for poor performance. Repeated failures to meet standards would be grounds for termination of the AFOR. PacifiCorp would pay any penalties through rate reductions or any other methods deemed appropriate by the Commission. The five service quality standards are: customer satisfaction, average customer outage duration, average customer outage frequency, average customer momentary outage frequency, and major safety violations. Each standard contains corresponding baselines, and penalties would increase in three block segments for each measure, to a maximum penalty ranging from $150,000 to $500,000.

10. Renewable Resources: The Joint Parties propose an incentive to acquire renewable resources at costs that are lower than were projected in PacifiCorp’s 1995 least-cost plan (RAMPP-4). The incentive would apply to projects with levelized costs per kWh at least 10 percent lower than the corresponding cost estimate in RAMPP-4. A maximum of 50MW (PacifiCorp share) would be eligible. The incentive rate would be equal to 50 percent of the difference between the RAMPP-4 cost estimate and the cost estimate of the project at the time it begins commercial operation.

The Joint Parties also propose that any revenue requirement change associated with the Columbia Hills and Foote Creek wind projects, as well as any qualifying projects under the renewable resource incentive, be recovered in the system benefits charge.

11. DSM Acquisition: The parties propose that a mechanism to address Demand Side Management (DSM) cost recovery be continued during the five-year period of the AFOR.

12. System Benefits Charge: The Joint Parties propose a system benefits charge (SBC) on distribution services that would be designed initially to recover all costs of DSM programs and the incentives for the development of renewable resources. Existing Schedules 191 and 192 would remain in effect for DSM activity undertaken through the end of 1996. Revenue requirement changes associated with qualifying renewable resources would also be recovered through the SBC. The SBC would collect DSM costs actually incurred by PacifiCorp. The amount collected each year would be spread to customer classes on an equal percentage basis and collected through an energy charge. The charge would be non-bypassable.

13. Bond Ratings: The Joint Parties propose that, during the term of the AFOR, PacifiCorp maintain bond ratings for senior debt with Moody’s and Standard & Poors (S&P) of at least Baa2 and BBB, respectively. If the company’s bond ratings fall below these levels, either the company or the Commission may request reevaluation and possible termination of the AFOR plan.

14. Rate Spread: The Joint Parties have not reached agreement on the rate spread for AFOR price increases and, therefore, generally propose that the plan include the findings of the Commission’s pending generic cost of service proceeding, docket UM 824.

Positions of the Parties

PacifiCorp and the Public Interest Parties believe that their proposal comports with all four of the legislative standards provided in ORS 757.210(2) and request Commission approval of the plan. First, they argue that the plan promotes increased efficiencies and cost control by basing rates on a general measure of inflation reduced by a productivity offset. Because PacifiCorp would not be able to pass through to customers any specific cost increases under the plan, the Joint Parties maintain that the company would be pressured to pursue efficiencies and reduce costs.

Because the company would not be able to pass through any specific cost increases, the Joint Parties further contend that the stipulated AFOR would reduce PacifiCorp’s incentive to build resources and encourage resource decisions based on efficiency rather than regulatory considerations. The Joint Parties maintain that this and other features of the plan, including a revenue cap for distribution services and system benefits charge, make the stipulated AFOR consistent with least-cost resource acquisition policies.

The Joint Parties further contend that the AFOR plan is consistent with the maintenance of safe, adequate, and reliable service. They note that the stipulated AFOR includes service standards for customer satisfaction, reliability, and safety. These measures, the Joint Parties contend, will provide the Commission the ability to maintain its oversight of safety and service reliability under an alternative regulation scheme. Furthermore, they argue that increased competition and market forces will provide incentives to PacifiCorp to maintain its current levels of customer service under an AFOR.

Finally, the Joint Parties contend their proposal is beneficial to utility customers generally. They argue that the stipulated AFOR requires price decreases if warranted under the price adjustment mechanism and that, because of the productivity offsets, any rate increases will always be less than the general rate of inflation. They further add that any price increase under the adjustment mechanism would be limited to 2 percent per year and 6 percent over the term of the plan. They conclude that the initial 4 percent rate increase approved in Phase I, coupled with a maximum rate increase of 6 percent through the year 2001, guarantees advantageous rates to customers no matter how costs increase during this period.

Staff opposes the stipulation. Staff does not believe that it meets the fourth standard of ORS 757.210(2)(b), which requires that an alternative form of regulation be "beneficial to utility customers generally, for example, by minimizing utility rates." Staff notes that this standard is the most difficult to address, as it involves judgment as to what the future may hold. Nonetheless, it concludes that to satisfy the requirement, any AFOR plan should have a high likelihood that customer rates will be lower over the term of the plan than they would be under existing regulation.

Staff asserts that customer rates under the stipulated AFOR would actually be higher than under traditional regulation. Staff explains that higher rates would likely result due to a combination of three factors: (1) the inclusion of the initial 4 percent rate increase approved in Order No. 96-175; (2) low productivity offsets of 0.75 percent for generation and transmission and 0.3 percent for distribution; and (3) a phase-in of market-based generation rates that would be no more rapid, at best, than under continued traditional regulation. Staff recommends that the AFOR should include an initial rate reduction from the previously authorized 4 percent increase, as well as greater productivity offsets and a more rapid phase-in of market-based rates.

Staff also objects to many of the provisions contained in the plan. It believes that the 25 mill proxy rate for market-based power is too high and recommends the use of an adjusted BPA Priority Firm Rate of 21.2 mills. It opposes the stipulated decoupling mechanism and argues that it does not meet the objective of decoupling the distribution portion of PacifiCorp’s business. It believes that the stipulated earnings band is weighted heavily in the company’s favor and argues that the earnings band would enable PacifiCorp to earn excessive returns relative to the electric utility industry and at the same time increase its rates.

In addition, Staff disagrees with the capital structure and rate of return on equity contained in the stipulated AFOR. It also believes that the adjustment for major events provision should exclude energy taxes, arguing that the risk of a carbon-related tax should remain with the company. To protect ratepayers, Staff further recommends the modification of provisions relating to service quality standards, minimum bond ratings, rate spread and rate design, earnings review, and renewable resource incentives.

ICNU and OCFUR also oppose the adoption of the stipulated AFOR. Both parties contend that it is inappropriate to adopt the five-year plan during the comprehensive restructuring currently underway in the electric industry. They also contend that the stipulated AFOR actually prevents further development of competition because it locks in regulation and price increases for five years and relies on historical power rates and economic indexes that are completely unrelated to market forces.

The parties also believe that the stipulated AFOR would permit PacifiCorp to freely compete in the opening electricity markets and protect the company from risks associated with that activity, but at the same time prohibit customers from accessing the same markets in which PacifiCorp would be free to roam. They contend that, if adopted, the stipulated proposal would institutionalize an anti-competitive and protectionist regulatory barrier to open access.

ICNU further contends that the stipulated AFOR does not meet the statutory criteria set forth in ORS 757.210(2)(b). Like Staff, ICNU believes that rates will most likely increase under the proposed plan, thereby failing to provide adequate benefits to utility customers. It also argues that the plan does not promote efficiencies. ICNU notes that the plan is overly complicated, based on certain assumptions regarding generation costs that may not be accurate, and bases prices on complicated mathematical calculations using arbitrary indices.

J. Tim Watson, a consumer intervenor to these proceedings, does not address the specific provisions of the stipulated AFOR, but rather suggests certain modifications to the plan. First, he notes that the index-based price increase mechanism, coupled with PacifiCorp’s ability to request a price decrease at any time, could result in costs being shifted between customer classes. He explains that the shift of cost and revenue responsibility between classes of customers might occur as PacifiCorp responds to competitive market pressures and attempts to retain customers with service alternatives. Therefore, he believes that an AFOR should include provisions to construct what he terms a "fire wall" to protect captive customers from paying higher prices as a result of rate discounts offered to maintain market share.

Second, Watson is concerned about the proposed five-year term of the AFOR plan. He notes that deregulation within the electric power industry is moving at a much more rapid rate than may have been anticipated by the parties when selecting a five-year period. Given this rapid and continuing change, he suggests that the AFOR include an interim period review. This review, which he believes could be completed at the end of the third year of the plan, would allow the Commission to examine the accuracy of prior assumptions and the continuing need for the AFOR.

CONCLUSIONS
As noted above, the 1995 Legislative Assembly enacted ORS 757.210(2) to make explicit this Commission’s authority to consider alternatives to traditional, cost-of-service regulation for electric utilities. The legislation did not deregulate the utilities, but rather authorized this Commission to implement an alternative form of regulation after a review of four statutory criteria. Those criteria require the plan to promote increased efficiencies and cost control, be consistent with least-cost planning resources acquisition policies and the maintenance of safe, adequate and reliable service, and be beneficial to utility customers generally. For purposes of this decision, our review proceeds no further than this last criterion, i.e., whether the stipulated AFOR provides adequate customer benefits.

Standard of Review

The parties to this proceeding first disagree on the standard of Commission review mandated by ORS 757.210(2)(b)(D). Noting the inherent difficulty in comparing what PacifiCorp’s rates might be under traditional regulation versus what they will be under the stipulated AFOR, the Joint Parties contend that the Commission should judge the rate levels under the stipulation based on a standard of reasonableness given the overall market and inflationary conditions. Staff and ICNU dispute that interpretation. They contend that, to approve a proposed AFOR, the Commission must find that there is a high likelihood that customer rates will be lower over the term of the plan than they would be under existing regulation.

In construing a statutory provision, our task is to determine the intent of the legislature. PGE v. Bureau of Labor and Industries, 317 Or 606 (1993). After our review, we find the Legislature’s intent is clear from the text and context of the statute. ORS 757.210(2)(b) authorizes the Commission to adopt any AFOR plan that includes "provisions to ensure that the plan operates in the interests of utility customers and the public generally and results in rates that are just and reasonable." The statute then provides that, in approving the plan, this Commission shall consider, among other things, whether the plan "is beneficial to utility customers generally, for example, by minimizing utility rates."

The plain language of the statute makes clear that any AFOR plan approved by this Commission must result in just and reasonable rates and be beneficial to utility customers generally. Contrary to the assertion raised by Staff and ICNU, the statute does not mandate that an AFOR provide lower utility rates. Rather, it lists the objective of minimizing rates as an example of one factor this Commission could consider in its determination of whether the plan provides adequate customer benefits. While minimizing utility rates is perhaps one of the most significant benefits an AFOR could provide, we conclude that the Legislature did not intend to prohibit the approval of an AFOR plan that, while maintaining current rate levels that are just and reasonable, provides significant customer benefits such as service quality standards or measures to protect Oregon’s environmental quality.

Customer Benefits

The parties next dispute the level of customer benefits offered by the stipulated AFOR. The Joint Parties first question whether an accurate measure of benefits under the AFOR can be calculated, given the number of speculative assumptions required to produce useful data. That noted, they maintain that an analysis using reasonable assumptions shows that the stipulated AFOR would yield substantial rate reductions compared to traditional regulation. An analysis using the Joint Parties’ assumptions is attached as Appendix B. They also allege that, in addition to lower rates, the stipulated AFOR is beneficial to utility customers with its inclusion of renewable resource incentives and service quality standards.

Staff’s analysis focuses solely on the level of customer rates under the plan and believes that rates would be higher under the Joint Parties’ proposal. Staff challenges the assumptions used by the Joint Parties in asserting rate reductions, specifically the use of a July 1996 rate increase of 9.1 percent for traditional regulation instead of the actual 4 percent increase approved in Order No. 96-021. Using the actual rate increase approved in Phase I and modifying other assumptions, Staff contends that customers would pay approximately $47 million more under the stipulated proposal than under traditional regulation. Staff’s analysis is attached as Appendix C. Due to that reason alone, Staff contends that the stipulated AFOR fails to provide sufficient customer benefits under ORS 757.210(2)(b) and, therefore, should be rejected.

After our review, we reject the Joint Parties’ proposal to use a 9.1 percent rate increase as a starting point in determining what rate levels would be under current regulation. We acknowledge their argument that a comparable capital structure for PacifiCorp would have allegedly supported a larger rate increase in July 1996. However, we cannot overlook the fact that PacifiCorp stipulated to the 4 percent increase we approved in Order No. 96-175. We refuse to overlook a known figure for one that is dependent upon subjective estimates.

Using the actual 4 percent rate figure, we agree with Staff that customer rates would likely be higher under the stipulated AFOR than under continued traditional regulation. We are persuaded by Staff’s estimates regarding the timing and magnitude of traditional rate changes that would occur during the term of the AFOR plan and adopt them.

Based on our finding that there is a high likelihood that customers would pay approximately $47 million more under the Joint Parties’ proposal, we conclude that the stipulated AFOR should be rejected. We have reviewed the other alleged benefits of the proposed AFOR and, even assuming that they would materialize, we find that they are insufficient to overcome this large rate increase. While our approval of an AFOR plan does not hinge on whether it results in lower utility rates, we find that a significant increase in rates under a proposed AFOR can be dispositive in its rejection.

Conference

Accordingly, we reject the Joint Parties’ stipulated AFOR. We also decline to offer PacifiCorp a modified AFOR at this time. Numerous changes have occurred in the electric utility industry since PacifiCorp requested the approval of an AFOR as a transitional step towards competition. Other changes have occurred within PacifiCorp itself, most notably the company’s decision to acquire the Energy Group.

In light of these events, we believe it is prudent to gather additional comments from the parties prior to the possibility of offering PacifiCorp a modified AFOR. Among other things, we are uncertain whether PacifiCorp remains interested in pursuing an AFOR now that we have rejected the stipulation. We also seek guidance from the parties as to what they believe are the continuing benefits of an AFOR in today’s environment. We do not wish to engage in a detailed discussion of what specific terms should be included in an AFOR, e.g., the width of an earning band. Rather, we ask the parties to provide a response to the following questions:

Taking into account current events concerning PacifiCorp and emerging trends in the electric industry, please respond to the following questions:

1. Are the parties still interested in pursuing an AFOR?

If yes:

For which of the following functions, if any, should an indexing mechanism be used for annual price changes: generation? transmission? distribution?

Should the pricing for transmission be consistent with the likely regulatory treatment advocated in the upcoming Independent Grid Operator (IndeGO) filing in November 1997? If so, what process is advocated to ensure consistency?

If the Commission offered an AFOR with indexing applicable to only one or two functions, how should an earnings band be structured? (e.g., with regard to width of band, using earnings of all or just the indexed functions, etc.)

Are the structure and levels of the proposed service quality standards and penalties as advocated still reasonable?

e. Which functions, if any, should be subject to a decoupling mechanism?

Are there other matters that the Commission should first address before exploring an AFOR? If so, what are they?

If a comprehensive AFOR is not adopted or explored further, should the Commission adopt a new regulatory regime that anticipates a transition to a competitive marketplace?

a. If yes, which of the following elements should be implemented?

- System benefits charge

- Renewables incentive

- Service quality standards and penalties

- Bills showing functional components (i.e., generation,

transmission and distribution services) or, alternatively, cost

studies by function or service without showing detail on bills.

Which of the above mechanisms can the Commission initiate and implement without the company's consent?

The parties are directed to provide written responses to these questions by October 6, 1997. All written responses shall be limited to information contained in the existing record and should be served on all parties to this proceeding. Thereafter, this Commission will hold a conference to obtain additional comment and question the parties on their respective responses to the above questions. The conference shall be held as follows:

DATE: October 16, 1997

TIME: 1:30 p.m.

PLACE: Main Hearing Room

Public Utility Commission

550 Capitol Street NE

Salem, OR 97310

The conference will be postponed only if good cause is shown.

ORDER

IT IS ORDERED that:

The stipulated alternative form of regulation (AFOR) plan submitted by PacifiCorp, dba Pacific Power and Light Company, and the Public Interest Parties, consisting of the Citizens’ Utility Board, Natural Resources Defense Council, Oregon Department of Energy, and Northwest Conservation Act Coalition, is rejected.

The parties to this proceeding are directed to provide written responses to the questions set forth above by October 6, 1997.

A conference shall be held in this matter before the Commission on October 16, 1997.

 

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 of 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. A party may appeal this order to a court pursuant to ORS 756.580.