ORDER NO. 96-224

ENTERED AUG 26 1996

THIS IS AN ELECTRONIC COPY

BEFORE THE PUBLIC UTILITY COMMISSION

OF OREGON

LC 15

In the Matter of the Investigation into )

Least-Cost Planning for Resource Acquisitions by ) ORDER

PORTLAND GENERAL ELECTRIC COMPANY. )

DISPOSITION: PLAN ACKNOWLEDGED WITH MODIFICATIONS

Portland General Electric Company (PGE or company) filed its third integrated resource plan on November 15, 1995, in accordance with Public Utility Commission of Oregon (Commission) Order No. 89-507. On January 31, 1996, PGE filed an addendum to the plan which made several revisions to the plan’s Demand-Side Management (DSM) Action Plan. The company held a series of public meetings prior to filing the plan. About 20 participants representing a range of interests were involved in the process over the 18 months that the plan was under development. PGE briefed the Commission on the plan at a public meeting on December 18, 1995. Staff drafted and circulated for comment a proposed order recommending that the Commission acknowledge PGE’s plan with certain modifications, which are described below. At a special public meeting on June 3, 1996, the Commission considered and adopted Staff’s proposed order.

PROVISIONS OF THE PLAN AND PARTY COMMENTS

PGE’s Least-Cost Plan

PGE’s least-cost plan (LCP or plan), titled 1995-1997 Integrated Resource Plan, consists of two volumes: an executive summary of the plan, including a three-year action plan, and the Technical Report, which describes PGE’s actions and LCP analysis in more detail.

PGE’s LCP describes the following components of the company’s planning process:

Public participation;

 

An assessment of the demand for electricity and the company’s ability to accommodate expected market growth and respond to market uncertainty;

 

Identification and evaluation of demand-side and supply-side resource alternatives to meet future demand;

 

Identification of the most appropriate resource strategy;

 

PGE’s planned actions for 1995, 1996, and 1997 to meet customer needs;

 

Identification of significant external conditions, or signposts, that would lead the company to reassess its course of action.

 

In addition to the traditional components of least-cost planning, PGE’s plan also describes recent changes occurring in the electric utility industry that are affecting the way the company is planning for the future. Competition, deregulation, and technological change are creating more uncertainty in planning for resources over a 20-year planning horizon. As a result, PGE’s current LCP focuses on planning primarily for the next five years and structuring its plan to be flexible and adaptable to a rapidly changing environment.

Plan Components

Load Forecasts. PGE developed five load forecasts in the plan which represent a range of possible future customer demand over the 20-year planning period. The company forecasted demand would grow between 0.5 percent and 3.2 percent annually over the next 20 years. PGE believes the projected range of forecasts is sufficiently broad to cover market demand uncertainty over the long run. In its base modeling assumptions, PGE used the moderate growth future which projects electricity loads will grow by about 1,000 average megawatts (MWa) or 2.0 percent average annual growth over the planning period.

Load-Resource Balance. PGE’s plan shows that under critical water planning the company will experience firm energy deficits over the entire 20-year planning period based on the output of its existing resources. PGE’s current system is adequate to meet projected capacity requirements through 1996. The company is currently relying on purchasing surplus power from California and the desert Southwest to help meet its firm load requirements. PGE estimates the current reserve margin in the Western Systems Coordinating Council (WSCC) region to be about 25 percent falling to about 16 percent over the next 10 years. Since closing the Trojan Nuclear Plant in 1993, PGE’s strategy of meeting load requirements with low-cost short- and medium-term purchases from the wholesale market has resulted in considerable power cost savings for the company and its customers.

Resource Alternatives. PGE used a "portfolio futures" analysis to narrow the list of future resource options to those that would be most economic and most likely to be in the company’s action plan. On the supply side, the list of resource options modeled in PGE’s integrated analysis included market purchases, shared-site facility combined cycle combustion turbines (CCCTs), CCCTs on undeveloped sites, wind resources, and geothermal resources. PGE’s plan evaluated the availability and cost effectiveness of numerous DSM technologies for the residential, commercial, and industrial customer sectors. PGE developed three DSM strategies to include in its integrated analysis. The full, marketing, and low DSM strategies represented varying levels of annual and cumulative DSM acquisitions and varying customer incentive levels.

Analysis. PGE focused its analysis on significant factors that could affect its future resource actions: load and market uncertainty, regulatory change, the regional energy market, natural gas prices, and environmental and externality factors. The company developed "candidate signposts" to represent circumstances it could face in the future. PGE created three categories of signposts--market-related, fuel-related, and externalities--and modeled 16 cases representing the resource actions that best fit the conditions represented by the signposts.

Results. PGE’s plan does not determine a "Preferred Resource Strategy" as it did in its last LCP. This plan focuses on the resource choices selected by its PROSCREEN model for each of the 16 cases modeled over the next five years. Under the case that the company believes "more closely resembled expected conditions" (Case 16), PGE’s analysis shows that the company can rely on the market for all of its incremental needs beyond already planned additions, Beaver Plant repowering, and the low DSM strategy. A shared-facility CCCT and low DSM would be needed in 1999 if higher than expected natural gas prices, a $10 per ton CO₂ tax, or a loss of 5,000 MW of supply in the WSCC region occurs in the near future. The model chose renewables and the full DSM strategy only in cases where a $40 per ton CO₂ tax was imposed.

Action Plan. PGE’s action plan describes the actions the company proposes to take during 1995, 1996, and 1997 based on the results of its LCP analyses and other principles developed during the planning process. On the demand side, PGE developed the following annual DSM targets for the action period: 20 MWa in 1995, 8.1 MWa in 1996, and 7.4 MWa in 1997. The action plan provides specific program energy savings goals and other DSM-related activities planned for each customer sector. On the supply-side, PGE plans to:

Purchase short- and intermediate-term firm energy from the wholesale market to meet load growth and reliability needs;

Implement Beaver Plant repowering;

Implement hydro and Boardman Coal Plant efficiency improvements;

Proceed with siting requirements for Coyote Springs II and Deer Island (shared facility CCCTs) and "construct and operate as determined by the signposts;"

Continue participation, monitoring, and evaluation activities related to renewable resources;

Implement cost-effective improvements to transmission and distribution facilities;

Build a Beaver Plant transmission line, if cost-effective.

 

PGE’s activities planned for 1995-1997 are based on currently expected conditions. PGE developed the signpost concept to identify conditions during the action period that would cause the company to reconsider and possibly modify its planned resource actions. PGE’s action plan describes a public process for periodically reviewing conditions such as gas and energy prices and load growth that could affect its near-term resource decisions.

Comments of the Parties

The Commission and Oregon Department of Energy (ODOE) Staffs (Staff) jointly developed draft recommendations on PGE’s least-cost plan which were distributed to all parties on February 15 and April 15, 1996. Other parties filed comments on the plan as follows: Peter Barab on January 31, 1996; Northwest Conservation Act Coalition (NCAC) on February 1, 1996; Renewable Northwest Project (RNP) on February 1 and March 6, 1996; Citizens’ Utility Board of Oregon (CUB) on February 2, 1996; Community Action Agency (CAO) on February 5, 1996; Northwest Natural Gas Company (NNG) on February 7, 1996; Solar Energy Association of Oregon (SEA of O) on March 6, 1996; and John T. Travers & William H. Nau (Travers & Nau) on March 12, 1996. PGE filed reply comments on March 12, March 26, and April 29, 1996. Parties’ comments are summarized below.

Commission and ODOE Staff Comments. Staff provided final recommendations to all parties on May 15, 1996. Staff recommended acknowledgment of PGE’s plan with the following exceptions, modifications, and recommendations:

1. The Commission should not acknowledge procurement and construction activities to repower the Beaver Plant until PGE updates its analysis.

 

2. The Commission should not acknowledge PGE’s plan to construct and operate the Coyote Springs II and Deer Island projects.

 

3. The Commission should not acknowledge PGE’s plan to "option" the Deer Island facility.

 

4. The Commission should not acknowledge PGE’s plan to build the Beaver Plant transmission line.

 

5. PGE should include the following item under its Supply-Side Actions for Renewable Resources:

 

Continue to work toward completion of the Columbia Hills and Vansycle Ridge wind resource pilot projects. If the company concludes that either project is not technically or economically feasible, then it should explore alternative renewable resource project opportunities (including geothermal) that would provide long-term environmental and resource diversity benefits.

 

6. PGE should further amend its first action item under Market Transformation to state:

 

Support market transformation activities and work with regional collaboratives to improve retail channels for efficient products and practices. The initial areas of focus include new appliances (refrigerators, horizontal axis washers, lighting fixtures) and integrated building design standards.

 

7. PGE should submit a detailed fuel substitution analysis consistent with the Commission’s fuel switching guidelines prior to implementing plans to promote electric end uses such as zonal space heating, if rate recovery is requested for the program.

 

8. PGE should provide a detailed discussion of the status of its hydro relicensing efforts with FERC in its next LCP.

 

9. PGE’s next LCP should include sufficient documentation within the plan and appendices to support the plan’s conclusions and planned actions.

 

Peter Barab’s Comments. Mr. Barab, a PGE residential customer, submitted joint comments on PGE’s LCP (LC 15) and NNG’s draft LCP (LC 17). He criticized the utilities generally for not investing enough in conservation. He urged the Commission to take a "strong position in support of expanded energy conservation programs" and to consider alternative mechanisms for investing in future conservation such as a "Universal System Benefit Charge" (a three percent tax on energy bills). Mr. Barab also commented on PGE’s failure to inform its customers about the company’s planning process. He recommended that PGE notify its customers early about its planning process and invite public input.

RNP Comments. Renewable Northwest Project’s comments recommend that PGE should acquire 50 MWa of renewables as part of its action plan "to aid in the continued orderly development of renewable resources." RNP urged the Commission to "support additional renewable resource development as (1) a hedge against future economic and environmental costs and supply conditions, and (2) to reflect support by PGE’s customers."

CUB Comments. CUB filed comments that made the following recommendations on PGE’s LCP:

1. The Commission should not acknowledge PGE’s DSM resource plan. The company should convene its DSM working group to look for ways to implement significant additional DSM, in particular residential weatherization.

 

2. The Commission should reject the company’s proposal to redirect DSM toward providing customer information. Zonal heat should be rejected as an energy efficiency measure.

 

3. The Commission should reject Coyote Springs II and Deer Island as least-cost resources.

 

4. PGE should go forward with investing in small renewable projects.

 

5. Rates should be reduced.

 

6. The Commission should begin an investigation into other mechanisms, such as a system benefits charge, to fund energy efficiency programs.

 

CAO Comments. Community Action Organization is a private non-profit social service that operates the Low Income Weatherization Program in Washington County. CAO objects to PGE’s reducing its DSM targets in 1996 and 1997 from higher levels achieved in recent years. The agency believes PGE’s DSM Action Plan for 1996 and 1997 will have "extremely adverse effects on low-income customers" and urges the Commission to reject PGE’s proposed DSM activities.

NNG Comments. NNG submitted comments on the zonal heat analysis included in PGE’s LCP. NNG provided an alternative electric zonal versus gas space heating analysis using revised assumptions. The results of NNG’s analysis indicate gas space heating is more cost-effective than electric zonal heating. NNG recommends that the zonal heat analysis be removed from PGE’s LCP.

SEA of O Comments. SEA of O offered the following five recommendations:

1. PGE should assess demand-side programs based on a utility cost perspective when the avoided cost of supply-side resources is also based on utility cost and not total resource cost.

 

2. PGE should immediately allocate surplus revenue from the Trojan settlement to a systems benefits fund for conservation and renewables. PGE should plan to transition to a non-bypassable conservation assessment charge.

 

3. PGE should be required to quantify the value of conservation and renewables in reducing risk and uncertainty, including externalities.

 

4. PGE should be required to provide an action plan which provides specific, quantifiable goals and objectives.

 

5. PGE should adopt a public advisory process which is more receptive to public input. PGE should include public groups in the evaluation and verification of program results.

 

NCAC Comments. NCAC’s comments endorsed the comments submitted by SEA of O and RNP on PGE’s LCP, with a minor exception to SEA of O’s first recommendation. NCAC believes the total resource cost test should be used to evaluate both supply-side and demand-side resources.

Travers & Nau Comments. This partnership is a business advisor to one of the owner/lessors of the combustion turbines at the Beaver Plant. Travers & Nau’s comments on PGE’s LCP provided an alternative analysis of the economics of Beaver repowering. The results of their preliminary analysis indicate that the Beaver repowering option is less economic than continued operation of Beaver in its current configuration. Travers & Nau recommend that the updated study of the Beaver options recommended by Staff should permit Staff to review all important parameters and approaches affecting the result of the updated study.

PGE Reply Comments. PGE responded to parties’ opening comments and recommendations in reply comments filed March 12 and March 26, 1996. On

April 29, 1996, the company provided additional comments on Staff’s recommendations on the plan. PGE agreed to adopt five of Staff’s recommendations (recommendations 5 through 9).

OPINION

Jurisdiction

PGE is a public utility in Oregon, as defined by ORS 757.005, which provides electric service to or for the public.

On April 20, 1989, pursuant to its authority under ORS 756.515, the Commission issued Order No. 89-507 in Docket UM 180 adopting least-cost planning for all energy utilities in Oregon.

Requirements for Least-Cost Planning Under Order No. 89-507

Order No. 89-507 establishes procedural and substantive requirements for least-cost planning and provides for the Commission’s acknowledgment of plans that meet the requirements of the order.

Procedural Requirements. At a minimum, the least-cost planning process must involve the Commission and public prior to making resource decisions rather than after the fact. See Order No. 89-507 at 3.

PGE sought public input during the planning process through a series of 41 meetings over 18 months. Key planning considerations were discussed with interested parties in both technical meetings and broader issues meetings. The company published regular LCP Update newsletters to summarize key issues and notify participants of upcoming meetings and the availability of technical reports. PGE’s mailing list for the planning process included 160 individuals. The active group that regularly attended meetings and provided comments consisted of 15 to 20 participants representing consumer and environmental groups, regulatory organizations, and individuals with an interest in the electric industry. PGE also solicited ideas from its residential, commercial, and industrial customers through a series of customer focus groups. The company invited comment on a draft of its plan before finalizing the document. The public also had several opportunities to comment during the Commission’s review of PGE’s final LCP.

Substantive Requirements. The substantive requirements were set forth in Order No. 89-507 as follows:

1. All resources must be evaluated on a consistent and comparable basis.

 

2. Uncertainty must be considered.

 

3. The primary goal must be least cost to the utility and its ratepayers consistent with the long-run public interest.

 

4. The plan must be consistent with the energy policy of the state of Oregon as expressed in ORS 469.010.

Evaluating Resources on a Consistent and Comparable Basis. PGE’s LCP considered supply-side and demand-side resources on a reasonably comparable and consistent basis. The company assessed available energy efficiency options and supply-side technologies and determined resource priorities using an integrated planning model that selects future resource options based on lowest total resource cost.

Uncertainty. PGE adequately evaluated uncertainty by assessing resource options under a full range of conditions PGE may face in the future. In its analysis, PGE assessed the performance of resource options including DSM and renewables for 16 cases: five cases reflecting a wide range of market supply and demand conditions; five cases with varying natural gas price assumptions; two cases that vary the level of a potential CO₂ tax; and four cases that combine market-, fuel-, or externalities-related assumptions. We disagree with SEA of O that more explicit quantification of the value of conservation and renewables in reducing risk and uncertainty is needed.

Least-Cost Planning Goals. PGE states that the primary goal of its LCP is to identify resource actions that the company may take to provide a safe and reliable power supply for its customers at the lowest possible cost. The results of the plan’s integrated analysis identify the most economic resource options for the range of possible future conditions modeled by the 16 cases in the plan.

Consistency with the state energy policy. Oregon’s energy policy is defined in ORS 469.010. That policy, as it relates to least-cost planning, is to encourage efficient use of energy and to promote energy conservation, sustainable energy resources, and cost-effective energy resources. PGE’s resource plan is consistent with the goals of the state’s energy policy. The company plans to continue its promotion and acquisition of cost-effective energy efficiency, to participate in the development of renewable resource demonstration projects, and to improve the efficiency of its existing hydro and thermal resources.

Commission Decisions on Parties’ Comments

Staff proposes nine recommendations to modify PGE’s filed LCP. We understand that PGE concurs with Staff’s recommendations 5 through 9, which deal with renewable resources, DSM market transformation, fuel substitution (zonal heating), hydro relicensing, and LCP supporting documentation. We agree that those five modifications to the plan should be adopted. We will address Staff’s other recommendations and those of the other parties below.

Staff Recommendations

As detailed below, Staff recommends that we not acknowledge several resource development activities because PGE has not shown that it is reasonable to proceed under current conditions. The company’s analysis demonstrates that repowering Beaver and building the Coyote Springs II and Deer Island projects are the lowest cost options in some circumstances, e.g., if gas prices are higher than expected or a carbon dioxide tax is imposed. PGE labels a change in conditions that triggers a change in its preferred resources or their timing as a "signpost." We believe that the signpost approach is a useful way to deal with uncertainty about the future and agree with PGE’s conclusion that adding these resources in the near term is appropriate in some cases. But we also agree with Staff that the signposts for these activities have not appeared yet and, in the case of the Beaver transmission line, that PGE has not provided the analysis to show that it is reasonable to begin development now.

Therefore, we will not acknowledge PGE’s plans to repower Beaver and build Coyote Springs II, Deer Island, and the Beaver transmission line. PGE can make the case that it is time to proceed on any of these resources in a future least-cost plan or in a filing to amend this or any future plan. We note, however, that acknowledging a decision to begin development of a resource on a stand-alone basis in an amendment to a plan will not always be possible. A full plan integrates the company’s supply- and demand-side options and establishes the best alternatives to purchasing power in the wholesale market. In some cases, PGE will be able to justify its decision to begin development in a plan amendment by showing that market conditions have changed. In other cases, the data used to establish the ranking of the company’s options will be stale, and a new integrated plan will be needed. We will make that determination on a case-by-case basis.

Beaver Repowering. PGE’s leases on the combustion turbines at the Beaver Plant expire in 1999. The company concluded in its LCP that Beaver repowering is the best option to pursue for the plant. Staff argues that PGE’s analysis was based on wholesale market prices that the company now believes are too high. Staff recommends that PGE’s analysis of the Beaver Plant options should be updated before the Commission acknowledges this action item. The analysis should be provided close to the time the company expects to begin the first phase of the project, in order to have the best available information about market conditions. Travers and Nau support Staff’s recommendation and propose that the updated analysis of Beaver options should permit Staff to review all important parameters and approaches affecting the result of the updated study. PGE responds, "While changes in the short-term market price may affect the timing, we believe the basic prudence of repowering is not likely to change. PGE offers to provide the Commission with a report on the continued cost-effectiveness of the Beaver repowering project prior to the procurement and construction phase."

The Commission will not acknowledge at this time the proposed Beaver Plant repowering. We agree with Staff and Travers and Nau that PGE should provide an updated study showing a complete least-cost analysis of any Beaver option the company believes is appropriate to pursue. The study should compare various Beaver options with other resource options including market purchases under a variety of future scenarios, and it should be provided shortly before a commitment to implementation of a Beaver option is made.

Coyote Springs II and Deer Island. Staff recommends that the Commission not acknowledge PGE’s plan to build and operate the Coyote Springs II and Deer Island projects. In its 1995-97 Action Plan, PGE stated that it will construct and operate each project "as determined by the signposts." Staff argues that the company has not clearly identified the conditions (signposts) that will trigger a commitment to either project and recommends that the Commission consider acknowledgment when PGE decides to proceed on either one. CUB recommends that the Commission should reject Coyote Springs II and Deer Island as least-cost resources. PGE replies that its analysis shows that shared-facility CCCTs like the Coyote Springs II and Deer Island projects are the least-cost resources if wholesale purchases become too expensive. The company believes that its action plan for the two projects should be acknowledged and commits to "provide the Commission a report on cost-effectiveness of . . . (the) projects prior to beginning their procurement and construction phases."

We agree with Staff’s recommendation. We are not persuaded by PGE’s argument that it is reasonable to commit to the projects now because both are needed by 2000 in 7 out of 16 cases examined for two reasons. First, the fact that both projects are added by 2000 in almost half the cases modeled doesn’t tell us how likely it is that the resources will be needed. PGE did not assign probabilities to the various cases or otherwise provide any estimate or argument about the likelihood that the two projects will be needed by 2000. Second, the company’s reference to the number of cases in which the two projects are added by 2000 appears to be inconsistent with its signpost approach. We believe PGE’s approach can be characterized as one in which the company follows a particular resource strategy or path until conditions change, i.e., it encounters a signpost. PGE’s current strategy is to meet its needs with existing (or committed resources), low DSM, and power purchases. Assuming that supplies in western markets start increasing to meet growing loads in 1999, PGE would not need to add a CCCT under its current strategy until 2007. The company would not add two shared-facility units like Coyote Springs II and Deer Island by 2000 unless gas prices are much higher than expected or a CO₂ tax is imposed. We see no reason to consider acknowledging a commitment to the two projects until those signposts appear.

Staff further recommends that the Commission not acknowledge PGE’s plan to "option" the Deer Island facility, i.e., complete siting and engineering in order to reduce the lead time for completing the project from four years to about two years. Staff argues that the Energy Facility Siting Council (EFSC) will not issue PGE a site certificate for a resource option in Oregon. Staff also contends that PGE’s approach to valuing the option on Deer Island is faulty and that the company should investigate the possibility of obtaining a resource option from another party. PGE responds that it is prudent to option Deer Island because both Deer Island and Coyote Springs II are needed by 2000 in 7 out of 16 cases analyzed. The company also believes that its financial analysis does provide a reasonable measure of the value of an option on Deer Island.

While we recognize the value of reducing the lead time for the project from four years down to about two years, we must agree with Staff, for two reasons.¹ The first principal reason is that EFSC does not have a process for issuing PGE a site certificate for a resource option. EFSC will not certify Deer Island without a showing that there is a need for power to acquire its output in the near term. Our acknowledgment of a least-cost plan for PGE that includes a commitment to Deer Island would be evidence of the need for power, but, as discussed above, we are not ready to cannot conclude now that the company should build and operate the project within the two-year duration of this planning cycle. Second, Wwe also agree that PGE should examine the possibility of acquiring a resource option from another party. We do not need to resolve the disagreement between Staff and PGE about quantifying the value of an option on Deer Island because our decision not to acknowledge the proposed option does not turn on the precise value. However, we believe a method for valuing options would be a valuable tool in the planning process and encourage the parties to work to improve PGE’s approach for the company’s next plan.

Beaver Transmission Line. Staff recommends that the Commission should not acknowledge PGE’s plan to build the Beaver Plant transmission line. The proposed line would allow PGE to bypass the BPA system. Staff argues that the economic value of the proposed line depends on BPA transmission rates, which are in flux pending the BPA rate case and the restructuring of the regional transmission system. PGE responds that the company is in various stages of analysis and negotiations with BPA on the issue. PGE wants to preserve its option to build the Beaver transmission line if it is cost-effective at the time to do so. PGE offers to provide the Commission with a report on the cost effectiveness of a Beaver Plant transmission line project before beginning procurement and construction.

Since the cost effectiveness of bypassing BPA’s system with a PGE-constructed Beaver transmission line has not been established in PGE’s LCP, we agree with Staff that we should not acknowledge construction of the transmission line until the company demonstrates that the project is cost-effective and is consistent with least-cost planning principles. PGE’s proposed report should make such a demonstration and also show that the company has exhausted transmission pricing alternatives with BPA.

Other Parties’ Comments

Renewable Resources. RNP states that PGE should be required to acquire 50 MWa of renewable resources as a hedge against future natural gas price increases and environmental costs, in addition to completing its wind resource pilot projects. Similarly, CUB states that additional renewable resource acquisitions by PGE would increase the diversity of PGE’s resource mix and, therefore, benefit PGE’s customers.

We believe it is important for PGE to have developmental and operational experience, at the pilot project level, to meet the Commission’s overall UM 550 policy goal for renewable resource development. However, while we believe it is important for PGE to proceed with its current wind pilot projects, and that the additional expense of these projects is justified by the resource assessment and confirmation knowledge which PGE will gain, we do not believe that current market conditions warrant further renewable resource acquisitions. If market conditions change to where renewables become more cost-competitive with PGE’s other resource alternatives, then additional renewable resource acquisitions may be advisable. PGE states that the Vansycle Ridge pilot project is on an expandable site. Furthermore, the Newberry Crater geothermal pilot project being developed by CE Exploration will be expandable. PGE could participate in future expansion at either of these sites if they prove to be economic. Therefore, we believe that PGE is adequately progressing toward meeting the Commission UM 550 goal for renewable resource assessment and confirmation.

Evaluating Resources on a Consistent and Comparable Basis. SEA

of O argues that PGE is inconsistent in its evaluation of supply-side and demand-side resources (DSR). It claims that PGE used a utility cost test for supply-side resources and a total resource cost test for DSR, creating a bias against DSR. SEA of O’s conclusion is based on: 1) the fact that PGE’s near-term avoided costs are based on power purchases, and 2) the contention that the market price of power during a surplus does not reflect the total resource cost of the generating facilities used. SEA of O recommends that PGE assess DSR based on utility cost when the avoided cost of supply-side resources is based on utility cost. NCAC agrees that PGE’s analysis is inconsistent but recommends that total resource cost be used to compare supply-side and demand-side resources.

PGE replies that it used total resource cost to determine the cost effectiveness of both supply-side and demand-side resources. The near-term availability of surplus power, however, affects when deferrable, cost-effective resources--supply-side or demand-side--are acquired during the 20-year planning period.

We disagree with SEA of O’s argument that PGE used different cost tests to evaluate supply-side and demand-side resources. The company used the same avoided cost stream to gauge the cost effectiveness of new generating and demand-side resources (with appropriate modifications for losses and the 10 percent cost advantage on the demand side). SEA of O’s real concern appears to be that PGE is not applying a total resource cost test to its near-term power purchases. But the market price of power is the total resource cost of the incremental generating resource in the wholesale market (except for externalities). During a surplus, the incremental resource is a preexisting generating unit, and the relevant costs for planning purposes--the total resource costs--are its operating costs. The sunk costs are not relevant, even if some customers are still paying for them.

DSM. CUB recommends that the Commission not acknowledge PGE’s DSM resource plan until additional DSM measures are included, particularly in the residential sector. Mr. Barab also recommends that PGE increase its energy conservation goals. CAO objects to PGE’s DSM target reductions, believing the reduced targets for 1996 and 1997 will have an extremely adverse impact on low income customers. CUB also recommends the Commission reject PGE’s proposal to redirect DSM toward providing customer information.

PGE argues that its LCP and energy efficiency targets meet the least-cost planning criteria established by the Commission. Although focusing primarily on actions over the next five years, the company evaluated its resource needs over the required 20-year planning period. The plan shows that under prevailing conditions the company should not acquire deferrable resources during the action plan period, except for low levels of DSM. PGE developed the following three principles in the plan to determine appropriate DSM targets for 1996 and 1997:

1. Acquire savings below short-run marginal costs at a sustainable pace (for discretionary retrofit markets).

 

2. Aggressively pursue economic lost opportunities based on long-run marginal costs.

 

3. Maintain market presence and capability for possible future increases in DSM when justified.

 

Participants in DSM technical discussions agreed that the company’s principles are reasonable for the current plan. PGE revised its DSM targets based on the application of the principles and the recommendations of several public participants. Residential weatherization goals were reduced because weatherization programs are relatively high cost and are discretionary rather than lost opportunity resources.

PGE disagrees with CAO that changes in its weatherization program will have an extreme impact on low income customers. PGE is not reducing its commitment to support community action agencies, nor is it reducing its 50 percent rebate up to $1,000 for cost-effective measures, which is more than double what is required by law. PGE is also maintaining the same budget level for its low income weatherization program as in previous years.

PGE also responds to CUB’s misperception that PGE is eliminating most of its programs with the exception of those that provide information only. PGE is continuing programs with accompanying rebates in residential weatherization, residential efficient water heaters, commercial facilities and new construction, and industrial process. Although rebates have been reduced in some areas, PGE is not eliminating most of its incentive programs.

PGE’s DSM action plan targets and goals are based on the results of the company’s integrated analysis, DSM acquisition principles, and input from PGE’s DSM technical advisory participants. We believe the goals and activities are reasonable. Although it may be difficult for some to accept reductions in PGE’s DSM acquisition levels from those achieved in prior years, PGE is prudent to reduce its DSM levels to be cost-competitive with the lower cost of its other least-cost resource alternatives. We will acknowledge PGE’s 1995-1997 DSM Action Plan.

DSM Funding Mechanisms. CUB, SEA of O, and Mr. Barab recommend that the Commission consider alternative mechanisms such as a systems benefit charge to fund energy efficiency programs (as well as renewables and low income programs). PGE agrees that participation in regional or statewide forums to evaluate new ways to continue the promotion of energy efficiency in the future is important. In its January 31, 1996, revisions to the DSM action plan, PGE added the following objective: "Pursue ways to accomplish Oregon goals for energy efficiency by means other than utility subsidy programs through participation in the Regional Review, PacifiCorp’s Conservation in a Competitive Environment Group and other forums."

We are supportive of the suggestion to explore a DSM alternative funding mechanism for the future. The Commission is fully participating in the Conservation in a Competitive Environment Group, which is focusing its discussions on a statewide DSM funding approach.

Zonal Heating. NNG recommends that the zonal heating analysis be removed from PGE’s LCP. NNG’s comments provided an alternative space heating analysis that indicates that gas space heating is more cost-effective than electric zonal heating. CUB recommends that zonal heating be rejected as an energy efficiency measure. PGE replies that the company has not requested that zonal heating be approved as an energy efficiency program. The company disagrees with some of NNG’s assumptions and the results of the gas company’s analysis. PGE agrees, however, with Staff’s recommendation that the company will submit a fuel substitution analysis consistent with the Commission’s fuel switching guidelines if it chooses to seek rate recovery for a zonal heating program.

It is not necessary at this time to determine which assumptions are more appropriate to use in a zonal versus gas space heat comparison. Updated assumptions will be reviewed by the Commission with an opportunity for public comment if PGE seeks rate recovery for a zonal heating program in the future.

Public Process. Mr. Barab comments that PGE did not inform its customers adequately about the company’s least-cost planning process. He recommends that PGE notify its customers early about its planning process and invite public input. SEA of O suggests that PGE adopt a public process which is more receptive to public input and include public groups in the DSM program evaluation and verification process. PGE believes its planning process represented the various interests of its customers through the individuals and organizations that were invited to participate. PGE also states, however, that the company is open to involving its customers in the planning process and will be examining its public process before beginning its next LCP. In response to SEA of O’s recommendation, PGE asserts that the company is "open to the idea of adding to the Steering Committee composition, using professional program evaluation expertise as the primary criteria."

Although we know PGE expended much effort to involve interested parties and to respond to differing perspectives in its planning process, we agree with Mr. Barab that the company’s customers should have the opportunity to participate in the process. We adopt Mr. Barab’s recommendation that PGE should notify its customers early in the next least-cost planning process about the plan and their opportunity to participate and provide input. Since PGE has no objection to adding more members with DSM program evaluation expertise to its DSM evaluation group, SEA of O and others interested should contact the company about participating in the group.

Action Plan Goals. SEA of O recommends that PGE’s action plan should provide specific, quantifiable goals and objectives for all action items. SEA of O argues that the plan frequently states only that the company will "explore" or "consider" specific actions. The group believes that specifically-defined goals are necessary to evaluate whether PGE is "in compliance" with its action plan.

PGE disagrees with SEA of O that the action plan does not have sufficient quantifiable goals. The action plan includes specific DSM acquisition targets for 1995-1997. The action plan includes a goal to measure penetration rate baselines and set specific improvement goals from the baselines. The plan also identifies a goal of having at least six projects in the commercial new construction area that utilize more efficient design practices and technologies. PGE’s action plan includes commitments to "explore" in areas relating to new technologies and practices. PGE and participants in the technical discussions on the plan believe this type of commitment is more appropriate in areas where there is insufficient history to set meaningful quantifiable goals. PGE argues that "[w]hile compliance approaches can be effective in insuring minimum conformance to standards, they are ineffective in stimulating activity in new areas. Positive reinforcement is a more effective approach in these instances."

We agree with PGE. Specific targets and goals should be included in utilities’ action plans for certain action items such as energy efficiency acquisition levels. However, action plans typically include many activities that do not require quantified goals. We believe this approach is appropriate.

Rate Reduction. CUB recommends that PGE’s rates should be reduced because PGE’s costs of producing power have fallen since rates were set in PGE’s last rate case. PGE responds that a least-cost planning process is not a rate proceeding. We agree with PGE. Commission determination on rate changes will be decided in rate proceedings, not during the LCP acknowledgment process.

Conclusion

PGE’s Least-Cost Plan is acknowledged with the recommendations adopted in this order. The plan meets both the procedural and substantive requirements of Order No. 89-507. Achievement of the objectives in the company’s 1995-1997 Action Plan and the Commission recommendations will contribute meaningfully toward the development of future integrated least-cost planning efforts and acquisition of least-cost resources.

EFFECT OF THE PLAN ON FUTURE RATE-MAKING ACTIONS

Order No. 89-507 sets forth the Commission’s role in reviewing and acknowledging a utility’s least-cost plan, as follows:

The establishment of least-cost planning in Oregon is not intended to alter the basic roles of the Commission and the utility in the regulatory process. The Commission does not intend to usurp the role of utility decision-maker. Utility management will retain full responsibility for making decisions and for accepting the consequences of the decisions. Thus, the utilities will retain their autonomy while having the benefit of the information and opinion contributed by the public and the Commission.

 

Plans submitted by utilities will be reviewed by the Commission for adherence to the principles enunciated in this order and any supplemental orders. If further work on a plan is needed, the Commission will return it to the utility with comments. This process should eventually lead to acknowledgment of the plan.

 

Acknowledgment of a plan means only that the plan seems reasonable to the Commission at the time the acknowledgment is given. As is noted elsewhere in this order, favorable rate-making treatment is not guaranteed by acknowledgment of a plan. Order No. 89-507 at 6 and 11.

 

This order does not constitute a determination on the rate-making treatment of any resource acquisitions or other expenditures undertaken pursuant to PGE’s 1995-1997 Integrated Resource Plan. As a legal matter, the Commission must reserve judgment on all rate-making issues. Notwithstanding these legal requirements, we consider the least-cost planning process to complement the rate-making process. In rate-making proceedings in which the reasonableness of resource acquisitions is considered, the Commission will give considerable weight to utility actions which are consistent with acknowledged least-cost plans. Utilities will also be expected to explain actions they take which may be inconsistent with Commission-acknowledged plans.

CONCLUSIONS

1. PGE is a public utility subject to the jurisdiction of the Commission.

 

2. PGE’s 1995-1997 Integrated Resource Plan, with the modifications adopted herein, reasonably adheres to the principles for least-cost planning set forth in Order No. 89-507. The plan will assist in ensuring that PGE’s customers receive adequate service at fair and reasonable rates and is otherwise in the public interest.

ORDER

IT IS ORDERED that the 1995-1997 Integrated Resource Plan filed by Portland General Electric Company on November 15, 1995, as modified herein, is acknowledged in accordance with the terms of this order and Order No. 89-507.

Made, entered, and effective_________________________.