ORDER NO. 98-254

ENTERED JUL 01 1998

This is an electronic copy.

BEFORE THE PUBLIC UTILITY COMMISSION

OF OREGON

LC 19

DISPOSITION: PLAN NOT ACKNOWLEDGED

Idaho Power Company (IPCO) filed its Resource Management Report and Least-Cost Plan (LCP or plan) on June 2, 1997. The plan was filed as a single document designed to meet the requirements of both the Public Utility Commission of Oregon (OPUC or Commission) Order No. 89-507 and the Idaho Public Utilities Commission (IPUC) Order No. 22299. The company held a series of meetings with a Technical Advisory Panel prior to the filing of the plan. Nearly thirty interest groups participated in the process during the time the plan was under development.

On July 8, 1997, the staff of the OPUC (staff) sent out a proposed review schedule for IPCO’s LCP. The schedule requested comments on the plan to be returned by August 4, 1997. On August 22, 1997, staff sent out a copy of its final comments and recommendations and a draft proposed order. Staff distributed a final proposed order on September 24, 1997.

Staff presented its analysis of IPCO’s plan to the Commission at its October 8, 1997, public meeting. Staff recommended that the Commission acknowledge the plan, with qualifications. The Commission did not adopt staff’s recommendation and instead voted to not acknowledge Idaho Power Company’s Least-Cost Plan.

PROVISIONS OF THE PLAN AND PARTY COMMENTS

IPCO’s Resource Management Report and Least-Cost Plan

IPCO’s filing consists of five volumes: the overall plan, the economic forecast, the sales and load forecast, the conservation plan, and a technical appendix.

Methodology

The 1997 LCP has been prepared to reflect the changing environment in the electric power industry as it relates to retail competition and deregulation. The goal of this plan is to maintain IPCO’s ability to serve its growing service territory demand for electricity while also ensuring that any resources acquired will be cost effective in the emerging competitive market. The company has chosen to provide for resource flexibility by giving preference to resources which may be acquired for short periods of time and with short lead times. Therefore, in contrast to the 20-year planning period used in previous resource plans, a shorter planning period of 10 years has been selected for the 1997 LCP.

The future demand for electricity by customers in IPCO’s service territory is represented by three load forecasts reflecting a range of load uncertainty during the 1997-2007 planning period. Under normal weather conditions, IPCO’s customers are expected to consume about 1,788 average megawatts in 1997. By 2007, this load is expected to be about 2,028 average megawatts. The 270 average megawatt increase represents a 1.27 percent average annual rate of growth. This load forecast was developed using a variety of economic and demographic variables and represents IPCO’s most probable total load growth during the planning period.

IPCO uses a resource adequacy criterion that requires new system resources to be added whenever they are needed to meet forecast peak demand and energy growth during the planning period, assuming median year streamflows for hydroelectric generation. The peak resource requirement includes a six percent operating reserve in addition to peak load. IPCO plans to use short-term power purchases to meet temporary water-related generation deficiencies. IPCO is able to plan to use short-term purchases because it has summer peaking energy load requirements, while the region’s other utilities have winter peaking requirements. IPCO is connected by transmission to both the Southwest and Northwest regions, enabling the company to purchase power from a large number of sources within the western region.

Historical streamflows at IPCO’s hydroelectric generating plants have been modified for use in the 1997 LCP to reflect anticipated water releases to assist salmon recovery in accordance with the December 1994 Amendments to the Northwest Power Planning Council’s Fish and Wildlife Program.

IPCO projects monthly deficits to occur in July, August, November, and December. These deficits average less than 100 megawatts in 1997 and increase gradually to over 500 megawatts during one month in 2006. The November and December deficits result largely from a modification of streamflows through Hells Canyon required for the fall Chinook salmon spawning period. In 2003, the current seasonal exchange contracts with Seattle City Light and Montana Power Company expire, reducing winter deficits while increasing summer deficits.

Existing Resources

Hydroelectric Generating Facilities

IPCO operates 18 hydroelectric generating plants located on the Snake River and its tributaries, which provide over 60 percent of annual system generation under median water conditions. Together, these hydroelectric facilities provide a total nameplate capacity of 1707 megawatts.

IPCO’s hydroelectric facilities, with the exception of the Clear Lake and Thousand Springs plants, have operated with federal licenses under Federal Energy Regulatory Commission (FERC) jurisdiction. IPCO has begun the process of relicensing these projects at the end of their initial 50-year license period. In 1991, a license renewal was granted by FERC for the Twin Falls project. Applications to relicense the company’s three mid-Snake facilities (Upper Salmon, Lower Salmon, and Bliss) were submitted to the FERC in December 1995. Most recently, the application to relicense the Shoshone Falls project was filed in May 1997. License applications for the remaining hydroelectric facilities will be submitted as follows: 1) C.J. Strike Project to be filed November 1998; 2) Upper and Lower Malad plant to be filed July 2002; and 3) Hells Canyon Complex (Brownlee, Oxbow, and Hells Canyon) to be filed July 2003.

Failure to relicense the existing hydropower projects at reasonable cost would result in loss of generation that currently supports the low rates of IPCO customers. The relicensing process may potentially increase the cost of a project’s generation through additional operating constraints and requirements for environmental protection, mitigation, and enhancement imposed as a condition for relicensing. IPCO is seeking to address these risks through collaborative approaches to relicensing by involving public interest groups and governmental agencies in the preparation of license applications.

Any opportunities to expand the generating capacity at IPCO’s hydroelectric facilities will be determined on a project by project basis within the established relicensing process. No capacity expansions are currently proposed by IPCO in the relicensing applications for the mid-Snake and Shoshone Falls projects.

Thermal Generating System

IPCO shares ownership and output of three coal-fired steam generating plants that provide 1006 megawatts of generating capacity to the company.

IPCO owns a one-third share of the Jim Bridger plant located in Wyoming and operated by PacifiCorp. IPCO’s one-third share currently stands at 697.3 megawatts after a replacement of the turbine runners on one generating unit in 1996 increased plant capacity by 12 megawatts. Similar upgrades to the remaining three units in 1997, 1998, and 1999 will increase IPCO’s share to 709.3 megawatts.

The company’s second coal-fired resource is a 50 percent share, or 260.5 megawatts, of the 521 megawatt Valmy plant located in Nevada and operated by Sierra Pacific Power Company. The third thermal resource is a 10 percent share, or 53 megawatts, of the 530 megawatt coal-fired plant near Boardman, Oregon operated by Portland General Electric Company.

Purchases and Exchanges

IPCO purchases firm resources from independent power producers operating as qualifying facilities (QFs). As of January 1, 1997, there were 68 QF projects, which were delivering 95.5 average megawatts of power to the company.

A current exchange agreement with Montana Power Company provides for the delivery to Montana of 108,000 megawatt-hours from December through February. In return, Montana delivers to Idaho 118,800 megawatt-hours during the June through September period. Under a similar agreement, another 126,000 megawatt-hours is exchanged with Seattle City Light. Both agreements expire in 2003.

Possible Resources

Market Resources

Several market purchases of capacity and energy designed to meet specific forecast resource requirements of IPCO have been included among the company’s new resource options. Short-term market transactions may allow deferral of long-term resource commitments.

Efficiency Improvement Projects

A joint project is proposed with Portland General Electric to upgrade the boiler at the Boardman plant to increase the plant’s efficiency and output. The proposed upgrade will increase the plant capacity by 25 megawatts, and IPCO’s share of plant capacity by 2.5 megawatts.

A proposed upgrade to the distribution capacitor control system will enable IPCO to optimize reactive compensation on the distribution system and maximize capacitor efficiency. A system-wide implementation of the new control system is expected to reduce distribution system losses by 6.3 average megawatts through increased capacitor efficiency.

Gas-fired Generation

Simple cycle combustion turbines are one proposed option. The principal advantages are lower capital costs per kilowatt of electricity, short lead times for siting and construction, relatively low environmental impacts, and the ability to change their level of generation rapidly over the output range. Combustion turbine operating characteristics and cost data used in IPCO’s current planning were taken from the Electric Power Research Institute’s (EPRI) 1995 Technical Assessment Guide for Electricity Supply.

An additional option is the combined cycle combustion turbine (CCCT). Construction costs and operating characteristics for a new CCCT have been based upon the 1996 Northwest Power Planning Council’s Draft fourth Northwest Conservation and Electric Power Plan. The costs assume that the facility is located in proximity to a natural gas pipeline and existing electrical transmission.

Coal-fired Generation

A generic coal-fired plant based on the Valmy plant is one of the company’s resources. For planning purposes, IPCO assumes it be similar in operating characteristics to the existing units and with similar fuel supply.

IPCO has not yet determined a site nor developed site-specific cost data for a pressurized fluidized bed combustion (PFBC) generating facility. PFBC plant capital costs and operating data were derived from EPRI’s 1995 Technical Assessment Guide for Electricity Supply.

Fuel Cells

Fuel cell technology offers lower emissions and higher thermal efficiencies than other fossil-fuel based power generation technology. Individual fuel cells have fairly low output and are usually stacked together to make power plants that can be tailored in size to the utility’s load growth needs. Fuel cell costs and generating characteristics obtained from the EPRI 1995 Technical Assessment Guide have been used for considering fuel cell technology as a resource option in the 1997 LCP.

Demand-side Management (DSM)

IPCO has included no new DSM programs in its resource options. IPCO intends to continue the following programs: Low Income Weatherization Assistance, Oregon Commercial Audit, Oregon Residential Weatherization, Agricultural Choices, and Commercial Lighting. The last two programs are undergoing extensive review and may be modified in the future.

Renewable Energy Technologies

Solar photovoltaic (PV) and wind turbines are the two renewable energy technologies that have been included among the resource options in the current LCP.

IPCO is participating in several efforts to gain a better understanding of photovoltaic and solar thermal technologies. The company is offering some of its customers in remote locations the opportunity to lease photovoltaic systems and is involved in an Environmental Protection Agency and EPRI study to determine the pollution mitigation potential of PV systems. This research includes the monitoring of an 18 kW PV system on the rooftop of IPCO’s corporate headquarters. IPCO, together with several other utilities and government agencies, is participating in the Solar Two demonstration project near Barstow, California, that uses solar thermal technology to generate electricity.

A moderate potential for wind energy development exists within the IPCO service territory. In southern Idaho, most of the wind sites are on ridge tops where extreme cold can affect turbine performance. Also, the remote nature of the known wind sites in Idaho may require large transmission system expenditures in order to access the energy.

Resource Strategies

Four resource strategies have been evaluated for the 1997 LCP. Each strategy incorporates a present level of seasonal market purchases of 150 average megawatts of energy in July, August, November, and December. Beginning in 2003, the company’s current sales contracts and seasonal power exchanges with Seattle City Light and Montana Power expire. Therefore, alternative resource strategies have been evaluated starting in 2003.

Choosing monthly purchases to fill monthly resource deficits has the effect of decreasing the seasonal mismatch of IPCO’s loads and resources. For the purpose of comparing LCP resource strategies, this strategy is represented by a planned addition of 300 megawatts of capacity and energy in the months of July, August, November, and December, which fill resource requirements through 2006.

A second power purchase strategy would acquire annual capacity and energy under firm power purchase agreements starting in the year 2003. This strategy is represented by a planned purchase of 300 megawatts of annual capacity and energy in 2003, which satisfies resource requirements for the remainder of the planning period.

A third possible strategy is the construction or long-term acquisition of CCCT generation beyond 2003. This strategy consists of the planned addition of 336 megawatts of CCCT in 2003, which satisfies new resource requirements through the remainder of the planning period.

The fourth resource strategy considered is the long-term acquisition of coal-fired generation to fill resource needs occurring after 2002. The pressurized fluidized-bed technology was chosen over conventional steam turbine technology for evaluating the coal-fired option, based on its ability to achieve lower sulfur dioxide and nitrous oxide emissions without the need for add-on emission control equipment. This strategy includes the addition of a 340 megawatt PFBC unit in 2003, satisfying resource requirements through the end of the planning period in 2006.

Each of these four strategies was tested using a decision tree analysis that varied two key assumptions: load growth and gas prices.

For its analysis, the company varied annual load growth from 0.6 percent to 2.05 percent. The expected (or base case) annual load growth of 1.27 percent is more than the 1.02 percent forecast in IPCO’s 1995 plan. Each of the three load forecasts was assigned a probability of occurrence. The high, base case, and low forecasts were constructed to have probabilities of 25 percent, 50 percent, and 25 percent, respectively. Gas prices ranged from $1.678/MMBtu to $2.07/MMBtu with $1.95/MMBtu being the expected value. These starting prices were then escalated at various nominal rates (from 2.3 percent to 5.1 percent) to provide low, medium, and high gas price forecasts.

Results

Using the analysis described above, the company determined that the seasonal market purchase strategy produces the lowest expected cost when uncertainties in future loads and future gas and electric market prices have been taken into account.

IPCO’s resource plan cost methodology calculates the level of sulfur dioxide (SO₂), carbon dioxide (CO₂), nitrogen oxides (NO_X), and total suspended particulate (TSP) emissions from thermal generating plants for all resource plans. SO₂ emission costs are included in the calculation of direct utility costs through modeling of the emission allowance system established by the Clean Air Act. The sensitivity of the choice of least-cost resource strategy to external cost adders for CO₂, NO_X, and TSP emissions was investigated for six levels of cost adders, as specified in Commission Order No. 93-695.

A decision tree analysis was performed for each resource strategy with each level of combined emission adders included in the cost evaluation of each strategy. The costs of the resource plans for each acquisition strategy are progressively increased by the emission adders, showing a major impact on resource plan costs even in the case of minimum adders. However, the seasonal market purchase strategy remains the least-cost strategy.

The Two-Year Action Plan

From the results of its analysis, the company proposes a two-year action plan that consists of the following specific items:

Purchase seasonal capacity and energy on a year-by-year basis as needed to serve customer load requirements.

Expand IPCO’s power marketing activity and capability.

Implement system efficiency improvements included in the least-cost resource plan.

Provide support for economic analyses within IPCO’s hydro relicensing process to ensure evaluation of hydroelectric resources on a consistent basis with other resource options.

Participate actively in the IndeGO [Independent Grid Operator] project to facilitate independent operation of the regional transmission grid.

Participate in regional conservation efforts through the Northwest Energy Efficiency Alliance.

Annually update 1997 LCP planning assumptions and conclusions pending regulatory review of current planning requirements.

Comments of the Parties

Commission Staff

Commission Staff recommends acknowledgment of the plan, with the following qualifications:

IPCO Company has used a 10-year planning period, instead of the required 20, for this plan. IPCO states that national and state restructuring of the electric utility industry will change how, and by whom, electric power resources are planned, developed, and acquired in the future. The company uses this as the rationale for the shorter planning period. Commission staff also believes that increasing reliance on market purchases to meet resource needs and the short lead-time to develop new gas-fired generating units support the use of the 10-year planning period. The staff recommends that the Commission allow the shorter planning period for the 1997 Least-Cost Plan.

Step 7 of IPCO’s Two-Year Action Plan calls for an annual update of the 1997 LCP. Staff is uncertain whether this update will be sufficient and reserves judgment until one is submitted.

Commission staff made two recommendations regarding DSM programs in the LC 14 order on IPCO’s 1995 LCP. The first recommendation asked the company to assess new ways of funding and delivering DSM programs to customers who desire greater choices and services. The second recommendation requested that in the next planning cycle, the company should run all DSM programs through its least-cost planning screening model. This analysis would assist in understanding whether the expansion of existing programs would be more or less cost effective than adding new programs to the resource mix. These recommendations were not followed in the preparation of this plan and, in fact, DSM levels are the lowest in several years, with no new DSM programs being proposed for this planning cycle. Staff recommends that IPCO should plan on following the recommendations in the LC 14 order on its 1995 LCP when its next full plan is prepared. If the company is "updating" the 1997 plan, then the recommendations should be implemented in 1999. IPCO can request relief from these recommendations if circumstances change, e.g., a system benefits charge is adopted and/or utilities no longer set DSM targets. Commission staff recommends acknowledgment of the targeted DSM in the 1997 LCP because programs have been reviewed on an ongoing basis for cost effectiveness.

Public Comment

No written comments were received from the public.

OPINION

Jurisdiction

IPCO 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.

Commission and public sector involvement was accomplished through the company’s interaction with its Technical Advisory Panel (TAP). The TAP consisted of nearly thirty organizations and agencies, including consumer groups, environmental organizations, business and governmental planning bodies, and regulatory agencies. The TAP met periodically with company management planners during the preparation and review of the resource plan. IPCO also invited comment on a draft plan before it finalized its LCP, and the public had opportunities to comment on the LCP during the Commission’s review.

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

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

Uncertainty must be considered.

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

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. Commission Order No. 89-507 requires an integration of supply and demand side options. IPCO did not treat DSM like other resource options for modeling purposes. Ongoing DSM savings from prior programs and future savings from the continuation of existing programs were treated as a reduction to load. No new DSM options were modeled against other new resource options. Commission Order No. 89-507 clearly states that:

[t]he goal of least-cost planning is most likely to be attained if all of the options available for providing service are considered and if all the costs are considered. Least-cost planning, as envisioned in this order, requires that broad examination of all choices.

It is clear to this Commission that IPCO has met neither the letter nor the intent of our Order.

Staff made two recommendations regarding DSM programs in Order No. 95-1387 on IPCO’s 1995 LCP. The first recommendation asked the company to assess new ways of funding and delivering DSM programs to customers. The second recommendation requested that in the next planning cycle, the company run all DSM programs through its least-cost planning screening model. These recommendations were not followed in the preparation of this plan. Not only were the recommendations not followed, they were not even addressed. IPCO simply ignored them. The Commission finds this unacceptable. If the company felt there were sufficient reasons not to follow Staff’s recommendations, it should have stated those reasons in its report. The Commission views this as further proof that IPCO has not provided a "…broad examination of all choices" as required in Commission Order No. 89-507.

Uncertainty. The problem facing all planners is the uncertainty of the future environment in which the plan is expected to operate. In this LCP as in its 1995 LCP, IPCO used a decision tree method of analysis whereby probabilities were given discrete values for load growth and gas price escalation. The limitation of this analysis is that the results for any branch of the decision tree were derived with perfect knowledge about future load growth and gas prices. In other words, using this method, an optimal resource selection made in the year 2000 would be done knowing what the load and gas prices were going to be in the year 2006. Clearly, no planner has this kind of foresight. Staff recommended in its comments on the 1993 LCP that IPCO should continue to examine other methods to assess uncertainty. IPCO used the same method in this plan as it did in 1993. Staff continues to have the same concern about this method of analysis, but concedes that the possible risks from choosing the wrong future resource are mitigated because IPCO will require few resource additions over the next 10 years.

Least-Cost Planning Goals. The goal of utility planning is to assure an adequate and reliable supply of energy at the least cost to the utility and its customers consistent with the long-run public interest. This goal has not been met by the company. Although it has performed a thorough examination of the supply-side resources, such an examination has not been afforded the demand-side resources. Therefore, the analysis of the robustness of the planned resource additions using a range of possible futures is inadequate.

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. IPCO’s resource plan calls for increasing the efficiency of the Bridger generating plant through turbine upgrades and increasing capacity and reducing line losses in its distribution system. In addition, the company anticipates using market purchases from existing Western System Coordinating Council resources to meet any immediate capacity or energy deficit. IPCO’s plan places a strong emphasis on increasing the efficiencies of its existing supply-side resources. But IPCO did not properly consider demand-side resources (as discussed above), and therefore, we find that its plan does not comply with Oregon’s energy policy.

Commission Findings

Staff proposes acceptance of the plan with certain qualifications. Staff believes that the DSM targets in the 1997 LCP are reasonable because programs have been reviewed on an ongoing basis for cost effectiveness.

We find we cannot accept Staff’s recommendation. IPCO did not adequately evaluate demand-side resource possibilities and we cannot conclude the Plan reasonably integrates demand-side and supply-side 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 IPCO’s 1997 Least-Cost 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.

Conclusion. The Commission cannot conclude that IPCO’s Least-Cost Plan is reasonable. The Plan does not meet the procedural and substantive requirements of Order No. 89-507. The Plan is not acknowledged.

ORDER

IT IS ORDERED that the 1997 Least-Cost Plan filed by Idaho Power Company on June 7, 1997, not be acknowledged in accordance with Order No. 89-507.

Made, entered, and effective _________________________.

A party may request rehearing or reconsideration of this order pursuant to ORS 756.561. A request for rehearing or reconsideration must be filed with the Commission within 60 days of the date of service of this order. The request must comply with the requirements in OAR 860-14-095. A copy of any such request must also be serve on each party to the proceeding as provided by OAR 860-13-070(2)(a). A party may appeal this order to a court pursuant to ORS 756.580.