ORDER NO. 95-1216

ENTERED NOV 20 1995

THIS IS AN ELECTRONIC COPY

BEFORE THE PUBLIC UTILITY COMMISSION

OF OREGON

UE 93

DISPOSITION: STIPULATION APPROVED/REVISED TARIFFS CONDITIONALLY AUTHORIZED

On August 8, 1995, Portland General Electric Company (PGE) filed Advice

No. 95-11, a general tariff revision designed to increase rates to its Oregon electric retail customers, to be effective November 8, 1995. PGE’s original filing sought a net revenue increase of approximately $23.5 million. Taking into account the Regional Power Act (RPA) Exchange Credit and all other adjustment schedules in effect, it would have involved an overall rate increase of 3.2 percent and a residential rate increase of 5.5 percent.

The original proposal contained four major components:

(1) Amortization of deferred Trojan replacement power costs authorized in Docket No. UM 594;

(2) Amortization of deferred power costs authorized in Docket

No. UM 692;

(3) Tracking of fixed costs associated with the Coyote Springs generating plant;

(4) Tracking of the surcharge to PGE’s wheeling and power costs included in the Bonneville Power Administration (BPA) rate increase effective October 1, 1995.

PGE proposed a set of balance sheet offsets as a component of the filing. Under this proposal, the unamortized balance of the power cost deferrals authorized in UM 529,

UM 594, and UM 692 would be offset with the remaining unamortized balance of the "Boardman gain" reserved to ratepayers in Order No. 87-1017 (UE 47/48) as a result of the Boardman asset sale in 1985. The excess of the Boardman gain over the power cost deferrals would be partially offset by an amortization of the AMAX deferral approved in Docket No.

UE 79 relating to costs incurred to terminate a prior coal contract and to obtain a more favorable contract. The remaining Boardman gain after this offset, $1.5 million, would be applied to the unamortized Trojan investment.

If the offset proposal becomes effective, Tariff Schedule 105, which amortizes and collects the UM 529 deferral, will be terminated. That termination will offset approximately half of the price increase associated with Coyote Springs and the BPA rate increase. PGE will wait until its next general price revision to reflect the net increase in its revenue requirement ($7.5 million) resulting from the elimination of the amortization of the Boardman gain and the AMAX deferral and thus customers will continue to receive the benefit of that amount.

PGE asserts that the proposed offset would be a benefit both to it and to its customers. The offset will eliminate interest charges on unamortized power costs that customers would otherwise have to pay. It will thus minimize additional price increases for customers and reduce the frequency of price changes. Customers will also benefit from the indefinite delay in putting into rates the Company’s increased revenue requirement resulting from the offset of the Boardman gain. The offset will also allow PGE to fairly divest itself of what it describes as "regulatory assets." Such assets require a continuation of economic regulation to support their recovery and may thus become the object of dispute among the Company, regulators, and customers. The movement toward competition and increasing customer choice in the electric industry makes it beneficial to all involved to eliminate these assets so that the Company is better prepared to meet new business challenges.

PGE’s proposed tariffs also include the effects of the October 1, 1995, increase in BPA’s Priority Firm (PF) rate and consequent reduction in the Regional Power Act (RPA) Exchange credit. The credit is designed to provide the benefits of low-cost hydropower in the Federal system to the residential and small farm customers of investor-owned utilities and serves to reduce the rates those customers pay.

The rate spread proposed by the Company is designed to move toward rate "parity" among the various customer classes. Parity, in the Company’s view, would be achieved if each customer class were at the same percent of marginal cost. The Company’s evidence shows that residential and irrigation classes tend to have their service priced below parity, while commercial/industrial classes tend to be priced above parity. PGE thus applies the "4-to-1" method adopted in prior Commission orders to move toward parity. Under that approach, residential and irrigation customers receive, on average, four times the percentage increase allotted to medium and large commercial/industrial customers.

Prehearing Conference

On August 21, 1995, Michael Grant, an Administrative Law Judge for the Commission, held a prehearing conference in Salem, Oregon, to identify parties and interested persons and to adopt a procedural schedule. A list of the parties to the proceedings is set forth in Appendix A.

Motion to Dismiss

On September 22, 1995, Administrative Law Judge Grant issued a ruling dismissing certain complaints filed by the Utility Reform Project (URP). Upon reconsideration, Administrative Law Judges Grant and Allen Scott issued a ruling on October 18, 1995, affirming the September 22, 1995, ruling.

Stipulation

On October 13, 1995, staff and PGE entered into a stipulation intended to resolve all issues in this case. The provisions of the stipulation are discussed below. A prehearing conference was held on October 16, 1995, to adjust the schedule based upon the agreement. Staff and PGE later filed a stipulation incorporating the agreement and joint testimony in support of the stipulation.

Hearing

A hearing was scheduled for October 24, 1995, before Administrative Law Judge Scott in Salem. No party requested cross-examination and the record was not opened. Briefs were filed on November 1 and 3, 1995.

FINDINGS OF FACT AND CONCLUSIONS OF LAW

Stipulation

The stipulation between staff and PGE covers all issues in the application by PGE. Its principal provisions are as follows:

1. The recovery of power costs deferred in UM 594 is reduced to a total of $9.1 million plus approximately $2 million in interest to the effective date of the new tariffs. The original proposal was for recovery of $49.18 million.

2. The recovery of power costs deferred in UM 692 is to be the full amount requested, $11.6 million, including interest to the effective date of the new tariffs.

3. A revenue requirement increase of $40.12 million is found to be necessary to track into PGE’s revenue requirement the fixed capital and O&M costs of the Coyote Springs plant and the effects of the 4 percent rate increase implemented by BPA on October 1, 1995. This is a decrease of approximately $3.6 million from the original request.

4. PGE’s offset proposal is accepted with certain modifications. The deferred power costs and interest in UM 529, UM 594, and UM 692 are to be offset against an equivalent amount of Boardman gain. Boardman gain remaining after this offset will be applied against the AMAX coal contract termination payment and the incentive PGE has earned under the SAVE program in PGE Schedule 101. Any remaining Boardman gain will be used to offset Trojan investment.

The use of the SAVE incentive is a modification of the original proposal.

Under Schedule 101, PGE has earned a SAVE incentive for achievements in 1991, 1992, 1993, and 1994 in acquiring savings of kilowatt-hours through energy efficiency programs offered to customers. The total present value of the uncollected SAVE incentive earned over the four years is approximately $29 million. Under the tariff, PGE would collect a portion of the incentive in the year following the energy efficiency achievements and the remainder over a period of 14 years. The stipulation provides that PGE may accelerate for immediate recovery the total SAVE incentives described above. Offsetting the SAVE incentive with an equivalent amount of Boardman gain enabled PGE to propose, and the Commission to allow, a reduction in the Energy Efficiency Adjustment rates charged to customers under Schedule 101, effective November 8, 1995.

The stipulation also contains an agreement that the rate spread and rate design set forth in PGE’s application are appropriate. They employ the marginal costs adopted by the Commission in Order No. 95-322. Even with the application of the 4-to-1 spread in this case, residential prices would remain below parity according to PGE’s figures.

Under the stipulation, the Company’s net revenue increase would be approximately $19.9 million. The rate increase for residential customers without any adjustments would be 6.6 percent. For large industrial customers it would be 1.6 percent. Taking into account changes in BPA’s PF rate and reduction of the RPA Exchange Credit Act, elimination of Schedule 105, and the reduction in the SAVE adjustment rate, the rate increase for residential customers would be 4.7 percent. The increase in BPA’s PF rate and resulting decrease in the Exchange Credit by itself accounts for about half of the increase for residential customers. For large industrial customers the net increase would be 0.6 percent.

Contested Issues

The Citizens’ Utility Board (CUB) and the Utility Reform Project (URP) filed testimony opposing some portions of the stipulation. CUB contests the need for any rate hike and challenges the proposed rate spread as unfair to residential customers. URP also challenges the rate spread; it further asserts that the Coyote Springs plant should not be placed in rate base; finally, it challenges the continued inclusion of Trojan capital cost in rate base.

Need for Rate Increase

CUB makes several arguments intended to show that the proposed rate increase is unnecessary. It asserts, first, that this case is a "general rate case" under OAR 860-22-017, because it affects all or most of a utility’s rate schedules. Therefore, according to CUB, the Commission may consider all facts in evidence and is not limited in its review to those matters set out in the Company’s filing. The burden is on the Company to establish that its proposed rates are just and reasonable. In this case, CUB claims, the Commission is not limited to considering the matters established in UE 88 but may reexamine any relevant material which bears on the issues.

Specifically, CUB argues that the current and projected costs of natural gas and wholesale electricity are significantly lower than what was projected in UE 88, in which PGE’s current rates were established. These lower prices will reduce the cost of PGE’s power plants which operate on gas and will also reduce the cost of wholesale electricity from combustion turbines. As a result, PGE’s power costs will be lower than projected in UE 88. According to CUB, PGE should be able to absorb the costs related to Coyote Springs without raising rates.

CUB also claims that the earnings review submitted by PGE in this case, covering the period April 1, 1994, to March 31, 1995, is not appropriate. It was filed the day before the Company filed its 10Q form with the Securities and Exchange Commission detailing earnings up to June 30, 1995. The 10Q shows a much higher level of earnings than in prior periods, reflecting a reduction in the price of spot purchases. CUB asks that the Commission consider updated and more realistic variable cost projections. According to CUB, if the earnings review were shifted forward by three months, to June 30, 1995, the increased earnings resulting from an increase in customers, an increase in rates, and a decrease in costs owing to cheaper gas and wholesale power costs would result in earnings of 10.15 percent.

CUB argues further that the rate of return set in UE 88 is too high for present conditions. It asserts that the stipulation in UE 88 which resulted in the rate of return was based on treasury rates which were higher than immediately before or after. CUB suggests that if the rate of return were reduced to a "more reasonable" level of 8.95 percent, the revenue requirement would be reduced by $11.87 million. CUB does not ask, however, that the Commission change the rate of return to reflect the current market but rather that it find that as a result of the higher earnings PGE can absorb the Coyote Springs and BPA cost increases without injuring the Company’s earnings.

PGE presents several arguments in response to CUB’s claims. PGE notes first that its proposal in this case is based upon the stipulation adopted by the Commission in Order No. 95-322 (UE 88). The Commission there established the framework for dealing with the costs and benefits related to the Coyote Springs plant. The benefits from variable cost savings resulting from Coyote’s operation were included in the UE 88 revenue requirement. The fixed costs of Coyote were, however, to be "tracked" into the UE 88 approved revenue requirement upon completion of the plant. That is what UE 93 involves. The stipulation in Order No. 95-322 provides specifically as follows:

1. The variable power costs in UE 88 reflect the savings expected with commercial operation of Coyote.

2. At least 90 days prior to the expected on-line date for Coyote, PGE will file to track the projected capital and fixed costs associated with the plant into UE 88 base rates. PGE will provide an affidavit certifying the plant’s capability to operate on a commercial basis prior to any actual price change for Coyote.

3. Neither PGE nor any other party to the stipulation will propose a change to the variable power cost forecast already reflected in base rates, whether related to Coyote or any other issue, with the exception that PGE could propose to reflect the effect of an October 1995 change in the rates charged by the Bonneville Power Administration on its wheeling and purchased power costs.

Based upon the UE 88 stipulation, the filing in the present case uses the revenue requirement adopted in UE 88 changed only for:

1. The fixed costs related to Coyote; and

2. The increased variable power costs resulting from BPA’s October 1995 price increase. Other revenue requirement elements approved by the Commission in UE 88, such as the rate of return on equity, remain the same.

It is PGE’s position that in the present case the Commission should rely on the procedures set out in UE 88 and on the findings made in that case. It should not change the process nor undertake a review of matters soundly fixed by that case. The only complete forecast relevant to Coyote’s first year of operation is, according to PGE, the forecast developed in

UE 88. PGE believes that it is much too soon after UE 88 to review all the cost elements involved in the forecast. PGE argues, additionally, that it has been the Commission’s policy to use the utility’s most recently approved test period revenue requirement as a basis for an earnings review. It cites several of its own cases in support of this view, including Dockets UE 63 and

UE 69, Order No. 87-1357. It criticizes what it characterizes as CUB’s attempt to focus only on cost elements which have declined without regard to possible changes in other elements.

PGE also presented evidence attacking the credibility of factual claims made by CUB. It argues that CUB’s support for claims of reduced natural gas and wholesale electric prices is weak. CUB’s assertion is based on PGE’s actual costs in the first eight months of 1995, a period of system-wide mild weather and good water conditions, according to PGE. That period is not a good basis for a forecast, according to PGE. Moreover, PGE asserts that power costs should be based on a forecast which takes account of the complexity of the problem, rather than on an oversimplified historical approach. PGE accordingly asks that the Commission use the forecast adopted in UE 88.

PGE also counters CUB’s argument that the stipulation in UE 88 relating to the cost of capital was reached at a time when treasuries were at a very high level by providing evidence that most treasuries, such as a seven-year treasury, reached a peak two months after the stipulation. It further argues that the expectation of the markets was that the interest rates would increase significantly or remain close to the levels existing at the time of the stipulation. The actual decline in interest rates was not expected by the markets according to PGE. PGE also argues that CUB’s implied return on equity for PGE of 10.2 percent is below the ROEs authorized since January 1, 1995, throughout the United States. According to PGE, those authorized ROEs range from 10.85 percent to 13.3 percent, with only one below 11 percent.

Finally, PGE objects to CUB’s argument that the earnings review should be updated to June 30, 1995. It asserts that when the filing in this case was made on August 8, 1995, the updated figures to June 30 were not available as a practical matter for use in this case. Although the June 30 results were generally available in the last week of July 1995, updating and normalizing various matters would have taken a minimum of two or three weeks. This process could not be completed prior to the August 8 filing. PGE argues additionally that the attempt to update the figures made by CUB is "simplistic" in that it uses most of the adjustments used by PGE for the 12 months ending March 31, 1995. These adjustments cannot, according to PGE, simply be shifted to a different time period. PGE also argues that CUB’s claim that moving the earnings review period forward would capture increased earnings resulting from an increase in customers and an increase in rates is inaccurate because of PGE’s decoupling mechanism, which provides that increases in revenue above the level allowed in UE 88 would be returned to customers.

Disposition

The Commission is not persuaded by CUB’s arguments relating to the need for a rate increase. CUB is correct, of course, that PGE has the burden of proving that its proposed rates are just and reasonable. CUB is also correct that the Commission is not bound by the Company’s filing and may consider all evidence in the record relevant to the issues. We have done so in this case. We have considered the evidence presented by CUB and the other parties during this proceeding. We have also considered the record in UE 88. UE 88 was a very recent, thoroughly contested rate case which provides a comprehensive analysis of all elements relating to PGE’s costs and revenues. In contrast, the evidence presented by CUB in this case focuses only on certain elements of PGE’s costs. We are satisfied that the UE 88 evidence is a more reliable basis for the decision in this case. The UE 88 based earnings review, the forecast relevant to Coyote Spring’s first year of operation, and other relevant evidence in the record persuade us that the proposed rates are just and reasonable.

Rate Spread

Both CUB and URP criticize the rate spread proposed by PGE and accepted by staff in the stipulation. CUB argues that the method used by PGE to classify distribution plant costs, the "minimum system approach," is unreasonably arbitrary. This method, according to CUB, classifies as customer related some costs which do not vary with the addition or subtraction of a single customer on the margin. CUB proposes a different system called the "basic customer allocation method." That system purportedly classifies costs which vary directly with the addition of a new customer (meters and line drops) as customer-related and other costs which will increase only if the existing system lacks capacity as capacity or demand-related. CUB further argues that the "4-to-1" rate spread accepted in the stipulation would actually, when combined with rate hikes over the last two years and likely future ones, result in a rate increase differential of "7-to-1" to the disadvantage of residential customers.

URP argues that the marginal cost studies used by PGE to develop the rate spread are incorrect. These studies show marginal costs substantially higher for residential or small commercial customers than for medium and large commercial or industrial customers. URP points out, however, that in August 1995, PGE issued a 1995-1997 Integrated Resource Plan (IRP) technical report. This report contains PGE’s current estimates for conservation cost-effectiveness limits (CELs), which are also marginal costs for providing services to customers in each category. According to URP, this study shows that PGE now believes that the marginal cost for each major customer category is about the same. This study should, in URP’s view, be used as the basis for rate spread.

PGE responds to URP’s claims relating to the IRP by pointing out, first, that the report is in draft form and may be subject to revision. Further, PGE argues that the cost-effectiveness limits (CELs) used in the IRP are different from marginal costs used for rate spread. The CELs do not include customer-related costs. Furthermore, the CELs have been adjusted to include some, but not all transmission and distribution costs from the marginal cost study. To exclude certain costs from rate spread would excuse some customers from paying for a portion of the system that they are using. PGE also argues, on a more general basis, that the IRP process and the rate-setting process should be maintained by the Commission as separate proceedings. It notes that the purposes of the processes are different and that attempts to link them might result in "gaming" of one proceeding for reasons relating to the other. PGE also notes that the Commission considered CUB’s "basic customer allocation method" in UE 88 and did not adopt it.

Disposition

The Commission concludes that the rate spread adopted in the stipulation is appropriate. It is in keeping with the general policy we have set out of moving toward parity in rates. In Order No. 95-322 (UE 88), we stated:

With increasing competition in the electric services industry, public policy

dictates continued movement toward rate parity. We believe that the continued use of a 4-to-1 rate spread will help accomplish that goal without subjecting residential customers to rate shock.

 

The studies which formed a basis for the rate spread in this case have been carried out in keeping with our practices and standards. We agree with PGE that the least-cost planning and ratemaking processes should be kept separate, except where they have already been linked, and information from one should not be applied to the other without good reason. In this instance, we are persuaded by PGE’s argument that the marginal cost conclusions in the draft plan do not include customer related costs and include only a portion of transmission and distribution costs. Thus, these marginal costs are not appropriate for consideration in the present case for purposes of determining rate spread because they do not reflect all the costs that each customer class imposes on PGE.

Inclusion of Coyote Springs in Rate Base

URP asks the Commission to decline to allow PGE to place Coyote Springs in rate base. It insists that PGE, when appearing before the Energy Facility Siting Council (EFSC), asserted that the plant would cost under 28 mills/kWh (real levelized 1994 dollars). URP’s argument continues:

PGE is now asking the OPUC to allow it to charge ratepayers far in excess of 28 mills/kWh (1994 dollars) for the output of CoySP. Instead, PGE wants to place the cost of CoySP into ratebase and charge ratepayers the cost of operating it plus depreciation plus return on ratebase. PGE wants to add $168 million to ratebase and charge $8 million CoySP annual depreciation. Assuming a before-tax cost of capital of 14% (9.6% times the applicable gross-up ratio of 1.69), adding CoySP to ratebase will cost ratepayers about $23 million in the first year for return on investment. At a 90% capacity factor, the plant would produce about 1820 GWh per year. Thus, PGE wants to charge ratepayers a premium of about 17 mills/kWh ($31 million/1820 Gwh), in addition to all operating costs. If all costs were levelized, this $31 million would be reduced to about $16 million, based upon a levelized capital cost of $70/kW-year, as expressed in 1995-97 PGE IRP TECHNICAL REPORT, Table 8-3.

These calculations indicate that PGE wishes to charge ratepayers a premium of at least 8 mills/kWh over the cost of CoySP it asserted in the EFSC site certificate proceeding. Instead, PGE should be held to its contention in the EFSC proceeding that the CoySP would be the least-cost resource for ratepayers.

 

PGE responds to URP’s assertions by pointing out that its proposal regarding Coyote Springs is in keeping with traditional rate base treatment. It notes that the theory of "levelizing" the cost of an asset is not appropriate in the current regulatory framework. It also takes exceptions to the calculations provided by URP. PGE provided evidence that Coyote Springs was its least-cost choice, considering both direct cost and indirect costs related to time of completion, when PGE made the decision to proceed. It also provided evidence that the levelized costs of the plant are about 27 mills/kWh and thus do not exceed the estimate made before EFSC.

Disposition

We are not persuaded by URP’s factual assertions or arguments. Its claim that the levelized costs of Coyote Springs exceed the estimate PGE made before the EFSC is not convincing. PGE provided convincing evidence that the levelized costs of the plant will in fact be less than 28 mills/kWh. Moreover, PGE has established by persuasive testimony that Coyote Springs was the Company’s least-cost choice when the Company made the decision to build the plant. The Commission concludes that PGE has established that construction of Coyote Springs was prudent. The evidence provided by PGE shows that the capital costs and fixed operations and maintenance costs associated with the plant are reasonable and justified. PGE also provided the appropriate earnings review, using UE 88 data, and identified the revenue needed to recover the costs. Of course, the recovery of costs will begin only when PGE has certified to the Commission that the plant is operational. The Commission concludes that the treatment of Coyote Springs set out in the proposed stipulation is in keeping with our policies.

We do not find URP’s argument that we adopt a levelization policy persuasive. Levelization would be a fundamental change in our policy relating to inclusion of plant in a utility’s revenue requirement. The record in this case provides neither a sound basis for changing our policy nor a factual basis for properly applying such a policy.

Hardships to Customers

CUB argues that the rate increase proposed in this case would be unfair to residential customers because they have already had rate increases of 7.7 percent this year and 7.9 percent in 1993, and are facing a potential increase of more than 10 percent next year. The latter potential increase is related to the current BPA rate case, which would involve reductions in the residential exchange program. CUB suggests that the rate increase proposed here, combined with the others, will create "rate shock" to residential customers. CUB also points out that the federal government may reduce low-income heating assistance, causing additional hardship to customers who have electric heat. CUB notes that all of these actual and potential increases in utility rates come at a time when wholesale costs are falling.

PGE expresses concern about residential rate increases. However, it notes that it is attempting, with Commission support, to align prices among customer classes more closely with the long-run marginal costs of serving those classes of customers. The impact of this attempt to attain parity has fallen more heavily on residential customers than on other customers. PGE points out that its total average price increases have been significantly less than the increases for residential customers. It also notes that the differential between its residential rates and commercial rates, in absolute terms, is consistent with industry levels. PGE also points out that it is participating in the BPA current rate filing and opposing the proposed elimination of the residential exchange. It argues, however, that BPA’s actions, over which it ultimately has no control, should not be the basis for refusing to include Coyote Springs’ fixed costs in PGE’s revenue requirements.

With respect to energy assistance programs, PGE notes that the rise in residential prices means that the benefits to individuals who install conservation measures are rising in the form of bill savings. On the other hand, however, the system-wide benefits to PGE of pursuing energy efficiency over supply options is falling. PGE suggests that customers will come to realize that it is in their interest to become more energy efficient without the help of programs designed to aid that process.

Disposition

The Commission does not believe that CUB’s arguments provide a basis for denying the rate increase sought here. We are not unmindful of the impact of rate increases on residential customers. Nevertheless, the provisions contained in the stipulation relating to rate spread and inclusion of the costs from Coyote Springs in rates are in keeping with our policies and with our decision in UE 88. It is our policy to make rates cost based. The attempt to achieve parity among customer classes is an appropriate movement toward that goal and should be pursued in this case. Attempts to aid particular classes of customers run counter to the aim of achieving cost-based rates. Moreover, the movement toward parity will reduce the likelihood that large industrial customers will leave the system and shift the revenue recovery burden onto remaining customers, including residential customers. We also note that we do not have statutory authority to direct utilities to undertake programs which mandate discrimination based upon income or age. See Order Nos. 76-039 and 80-728. We would need direction from the legislature to do so.

Trojan Costs

URP argues that Commission should not allow PGE to continue to place the Trojan Nuclear Plant in the rate base. URP bases its argument on ORS 757.355 and the "used and useful" doctrine. PGE responds by noting that it is not seeking recovery of additional costs

associated with Trojan in this proceeding and by pointing out that issues relating to Trojan were resolved in UE 88.

URP’s claim relating to Trojan was presented in UE 88. It was not supported by convincing evidence or argument and was rejected. URP presents no additional evidence or argument here. Its position is not persuasive and should be rejected.

Other Provisions in the Stipulation

The Commission has considered the remainder of the stipulation, including the various adjustments to the amortization proposals set out in the filing as well as other adjustments. We find the adjustments reasonable and approve them. We also find the remainder of the provisions in the stipulation appropriate and we therefore adopt the stipulation in its entirety.

We note that the offset proposal in this case provides significant benefits to ratepayers in that it will save them interest costs and will allow them to continue to benefit from the reduced revenue requirement related to the amortization of the Boardman gain. These benefits convince us that the offset proposal is in the public interest and should be granted.

CONCLUSIONS

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

2. The Commission should adopt the stipulation attached as Appendix B.

3. Based on the record in this case, Portland General Electric Company’s rates that result from the stipulation and the Commission’s conclusions in the body of the order are just and reasonable.

ORDER

IT IS ORDERED that

1. The tariff revisions filed on August 8, 1995, as Advice No. 95-11 are permanently suspended.

2. The stipulation attached as Appendix B is adopted in its entirety.

3. Portland General Electric Company may file revised tariffs consistent with the stipulation and the findings of fact and conclusions in this order to be effective on receipt by the Commission of certification by PGE that the Coyote Springs generating plant is fully operational.

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 OAR 860-14-095. A copy

of any such request must also be served on each party to the proceeding as provided by OAR 860-13-070. A party may appeal this order to a court pursuant to

ORS 756.580.