HomeMy WebLinkAboutPACE991.RPS.docQ. Please state your name and business address for the record.
A. My name is Rick Sterling. My business address is 472 West Washington Street, Boise, Idaho.
Q. By whom are you employed and in what capacity?
A. I am employed by the Idaho Public Utilities Commission as a Staff engineer.
Q. What is your educational and professional background?
A. I received a Bachelor of Science degree in Civil Engineering from the University of Idaho in 1981 and a Master of Science degree in Civil Engineering from the University of Idaho in 1983. I worked for the Idaho Department of Water Resources from 1983 to 1994. In 1988, I received my Idaho license as a registered professional Civil Engineer. I began working at the Idaho Public Utilities Commission in 1994. During my employment at the Public Utilities Commission, I have attended training at the Institute of Public Utilities at Michigan State University, the Lawrence Berkeley Laboratory, the Electric Power Research Institute, and the New Mexico State University Center for Public Utilities. My duties at the Commission include analysis of utility rate applications, rate design, tariff analysis and resolution of customer complaints.
Q. What is the purpose of your testimony in this case?
A. The purpose of my testimony is to address the network performance standards as proposed by ScottishPower in the testimony of witness Bob Moir. I will also address the issue of whether the proposed merger will have any effect on PacifiCorps water rights or on the water rights of other water users. Finally, I will discuss the impact of the merger on PacifiCorps continued eligibility to participate in the BPA Residential Exchange Program and to the Companys eligibility to participate in the BPA subscription process.
Q. Please summarize your testimony.
A. I begin by discussing the purpose of network reliability standards, defining what reliability standards are, and briefly discussing why they may be necessary. Next, I discuss Idahos current reliability requirement, as well as those that PacifiCorp is required to meet in any other surrounding states. I describe how reliability is typically measured, and summarize the current reliability of PacifiCorps system in Idaho. Next, I summarize the reliability standards proposed by ScottishPower in this case, discussing when the standards will be met, what the penalties will be for not meeting the standards, and where the funds will come from to make the system improvements needed to achieve targeted reliability levels. I discuss the need for establishing accurate baseline reliability data, and describe some of the difficulties in utilizing existing PacifiCorp data. I propose that the Company be subject to additional penalties if reliability drops below baseline levels. Finally, I discuss the value to Idaho customers of improving reliability, and conclude that, while difficult to quantify, the improvements promised by ScottishPower do offer some benefits.
My testimony also discusses the effect of the merger on water rights held by PacifiCorp and on the water rights of other water users in the state. I briefly describe the water rights held by PacifiCorp for its hydro generation plants and the relationship to other water rights on the Bear River. I also discuss the authority of the Commission with regard to water rights issues as spelled out in the Idaho Code. Finally, I discuss my conclusions based on the advice of legal counsel that the merger will have little effect on water rights, and that the Commission has limited jurisdiction in such situations.
I also briefly discuss the issues of whether the proposed merger would affect PacifiCorps continued eligibility to participate in the BPA Residential Exchange Program and the BPA subscription process. I end by concluding that decisions regarding eligibility rest with BPA, the FERC, and perhaps ultimately, the federal courts.
Network Performance Standards
Q. Why are network performance standards an issue in this case?
A. Network performance standards are an issue because they offer a means of insuring that service quality will not deteriorate as a result of the merger. The Commission Staff has been concerned about maintaining and improving service quality for all utilities in the state, both in terms of network performance and in terms of customer service, even before the merger was proposed. Performance standards have already been imposed, for example, on U S WEST in Idaho. The goal of efficient, low cost utility services cannot be achieved by sacrificing reliability and customer service. Performance standards offer a means of protecting customers by holding utilities to measurable levels of performance.
ScottishPower, as a condition of the proposed merger, has proposed a set of network performance standards that it intends to meet, several of which deal with distribution system reliability. Any time a utility proposes to cut costs, concerns naturally arise about whether reliability will be jeopardized. Frequently, the reaction to help alleviate this concern is to impose reliability standards limiting the frequency and duration of outages. Reliability standards also frequently arise in cases where utilities are subject to performance-based ratemaking, so that incentives exist to encourage improved system performance, and penalize deterioration in service. Cost cutting that results from competition between utilities in states where deregulation has been implemented has also commonly led to the introduction of reliability standards. To date, at least a dozen states have implemented reliability standards.
Q. What is the purpose of the network performance standards proposed by ScottishPower?
A. The purpose of the network performance standards is to help to insure that the frequency and duration of both long-term and short-term outages experienced by customers is minimized.
Q. Please explain what you mean by network reliability.
A. There are generally three main elements in an electrical network: generation, transmission, and distribution. Each of these three integrated elements must be reliable to consistently provide reliable service to customers. Reliability of the generation system is generally addressed by maintaining planning reserves in the event of contingencies such as low water conditions or individual plant outages. The risk of generation shortfalls can also be minimized by the ability of utilities to rely on excess capacity available from other generating plants in the region. In addition, generation system reliability is being addressed through FERC proceedings related to ancillary services and the interrelationships between utilities and independent system operators.
Transmission reliability generally refers to reliability of bulk power transfers between generating plants and substations, or in some cases, power transfers between utilities or wheeling across entire utility networks. Transmission reliability standards are set by the National Electric Reliability Council and its regional subgroup, the Western Systems Coordinating Council.
Distribution system reliability relates to that part of the electric network that delivers energy from the transformation points on the transmission system to the customer. The distribution system is generally considered to be anything from the distribution substation to the customer meter. The operation and control of the distribution system is entirely the responsibility of the local utility, thus reliability of this part of the system is within the jurisdiction of state utility commissions.
Q. What type of reliability is your testimony focused on?
A. My testimony will focus only on reliability of the distribution system.
Q. Are there any reliability standards that must currently be met in Idaho?
A. The Idaho Commission requires electric utilities to provide reliable service. They have regularly required utilities to repair or modify facilities to improve reliability where persistent problems have been identified. Nevertheless, there are no specific reliability criteria that electric utilities in Idaho are required to meet. Idaho Code is not specific with regard to reliability and requires that they provide service that shall promote the safety, health, comfort and convenience of its patrons, employees and the public, and as shall be in all respects adequate, efficient, just and reasonable (Idaho Code 61-302). Although most utilities collect data related to the reliability of their systems, there exists no common basis for assessing or reporting system reliability.
Q. Is PacifiCorp currently required to meet reliability standards in any of its other regulated jurisdictions?
A. Yes, PacifiCorp is required to meet reliability standards in two states, Oregon and California.
Oregon reliability standards are one of the features of the Alternative Form of Regulation (AFOR) that was approved by the Oregon Commission effective
July 1, 1998. Oregons AFOR is a form of performance based ratemaking. The Oregon AFOR and service quality measures are intended to provide a mechanism to insure service quality is maintained at current or improved levels subsequent to the implementation of the AFOR. The measures will be effective for a period of ten years. The service quality standards establish minimum acceptable levels for distribution system reliability (SAIDI, SAIFI, and MAIFI), at fault customer complaint frequency, major safety violations, and annual reviews for vegetation management (tree trimming), inspection and maintenance, and other special programs. PacifiCorp and the Oregon Commission staff meet annually to determine reasonable levels of achievement towards meeting the objectives. Included with the service standards are revenue requirement deductions for poor performance, possible return to customers of unspent O&M funds, and possible orders to perform corrective actions. Penalty amounts can be as high as $1 million per measure per year for each of the same three reliability measures as proposed by ScottishPower (SAIDI, SAIFI and MAIFI). The revenue requirement reductions are to be paid by the Company through rate reductions or other methods deemed appropriate by the Oregon Commission. The Companys first report under the Oregon AFOR was filed on
May 1, 1999.
The Company is also subject to reliability standards in California. These standards are primarily recording and reporting requirements that cover system reliability using uniform methods for assessing data on the frequency and duration of system disturbances, circuits that persistently perform poorly, and accidents or incidents affecting reliability. Utilities are also required to submit preventative maintenance plans that address inspections of and replacement criteria for equipment on electric distribution systems.
The Company has also been providing service quality information to the Utah Commission beginning the second quarter of 1998. Some of the information provided relates to distribution system reliability. There are no specific minimum reliability levels that must be met, nor are there any specific penalties for poor reliability.
Q. How is distribution system reliability measured?
A. There have been many measures devised to assess system reliability, but all are generally related to measuring the frequency and the duration of outages. Three of the most common measures of reliability are the following:
System Average Interruption Index (SAIDI)
SAIDI is the average number of minutes in a year that the typical customer is interrupted. It is calculated by dividing the total minutes of sustained customer interruptions by the total number of customers.
System Average Interruption Frequency Index (SAIFI)
SAIFI is the average number of times per year that the typical customer is interrupted by sustained power outages. It is calculated by dividing the total number of sustained customer interruptions by the total number of customers. SAIFI may be calculated for a region or a circuit.
Momentary Average Interruption Frequency Index (MAIFI)
MAIFI is the average number of times per year that the typical customer is interrupted by momentary power outages. It is calculated by dividing the number of momentary customer interruptions by the total number of customers. It differs from SAIFI by tracking only the frequency of momentary, rather than sustained interruptions. ScottishPower proposes to define a momentary interruption as lasting less than five minutes, while a sustained outage would last five minutes or longer.
ScottishPower proposes to use these three measures of reliability for assessment and reporting purposes. These measures, as defined by ScottishPower, appear to conform to the proposed definitions of the Institute of Electrical and Electronics Engineers
(IEEE P1366/D18).
Q. What is the current reliability of PacifiCorps system in Idaho?
A. The reliability of PacifiCorps system in Idaho, as measured by the SAIFI, SAIDI, and MAIFI for each of the past five years is summarized in Exhibit
No. 104. As shown by the data, SAIDI has ranged from approximately one-half hour to well over three hours. Extreme storms and pre-arranged outages account for about one fourth of the total outage duration on average. SAIFI has ranged from approximately 0.6 to 2.8 outages per year. Of these, approximately 20 percent are caused by extreme storms and pre-arranged outages. Finally, MAIFI varies from about 3 to 7 outages per year. Only a small percentage of these momentary outages are attributable to extreme storms or pre-arranged outages.
Q. Does PacifiCorp currently have any reliability targets it tries to meet in Idaho, even though there are no specific requirements of the Commission?
A. Yes, the Company does have internal reliability targets that were developed by the Company in September 1997. The targets for SAIDI, SAIFI and MAIFI were determined by looking at an average of the Companys historical performance over the years 1992-1996. The targets exclude storms and pre-arranged outages. The internal targets are as follows:
SAIDI 127.7 minutes
SAIFI 1.923
MAIFI 3.890
5 Worst Performing Circuits Annually submit a plan to improve performance for these circuits
Q. Is it possible to compare the reliability of PacifiCorps Idaho system to their system in other states or to other utilities systems?
A. It would be possible if the same reliability indices were used, if those indices were defined in exactly the same way, and if the data used in calculating the indices were consistently measured and reported. I do not believe this is usually the case, however. Even within the same utilitys system, data may be collected and reported differently. Moreover, different utilities are very likely to collect and report outage data differently. Consequently, while comparisons may seem easy to do on the surface, I would not recommend them because of the problems I have mentioned. I do not believe a comparison between PacifiCorps reliability and the reliability of other utilities would be valid, and a comparison between PacifiCorps reliability in Idaho versus the reliability in another state would probably only give a general relative difference at best.
Q. What reliability standards are being proposed in this case?
A. ScottishPower proposes to improve SAIDI and SAIFI by 10 percent over baseline levels that would be established shortly after completion of the merger. They also propose to improve MAIFI by five percent over baseline levels. In addition, the Company proposes to annually identify the five worst performing circuits in the state, to submit plans to improve these circuits within two years of when they are first identified, and to reduce the Circuit Performance Indicator (CPI) of these circuits by 20 percent. For power outages because of a fault or damage on PacifiCorps system, the Company proposes to restore supplies on average to 80 percent of customers within three hours.
Q. When will these standards be met?
A. ScottishPower proposes to meet the network performance goals within five years after the completion of the merger.
Q. Do you believe five years is a reasonable period of time in order to achieve the reliability improvements?
A. Yes, I do. Because of the questionable accuracy of existing reliability data, and because of possible differences between how data will be collected in the future versus how it is collected and reported now, I believe a reasonable period of time is needed to establish accurate and fair baselines against which the Companys performance will be judged. In addition, I believe a reasonable period of time is needed in order to make improvements once they have been identified. I believe reliability improvements will actually be achieved gradually over the five-year period, but that five years is a reasonable period of time to allow before judging the Companys progress.
Q. Why is ScottishPower simply proposing certain percentage improvements over existing reliability levels, instead of proposing to achieve specific levels of SAIDI, SAIFI, and MAIFI?
A. There are two primary reasons. First, ScottishPower believes that the reliability data currently collected and reported by PacifiCorp are incomplete and inaccurate. In meetings with Staff, ScottishPower has stated, for example, that they believe that as many as 80 percent of the outages on the PacifiCorp system currently go unreported. ScottishPower anticipates, and Staff agrees, that more accurate reporting may initially cause reliability to appear to be worse, when really it is no worse than before. More accurate reporting would capture outages now going unreported, causing increases in the network reliability indices. With such inaccurate and incomplete data, the real reliability of the system is unknown. An accurate baseline will have to be established before any fixed reliability benchmarks can be set.
Second, geographic and weather-related differences between various parts of PacifiCorps system make it unreasonable to expect the same levels of reliability. Circuits in remote areas or those exposed to severe weather cannot be expected to offer the same level of reliability as circuits in urban areas or areas where weather conditions are milder. It would not be reasonable to propose a single set of reliability measures for PacifiCorps entire system because of the different conditions in each state.
Q. Are these three measures of system reliability sufficient to evaluate service reliability for all customers in Idaho?
A. No, SAIDI, SAIFI, and MAIFI are averages based on the entire PacifiCorp system in Idaho. By definition, the reliability of some circuits will be much better than that indicated by the system average, while some circuits will be considerably worse. The use of system averages can hide problems experienced by individual circuits. In recognition of the fact that system averages cannot identify the worst served customers, ScottishPower proposes to calculate a Circuit Performance Indicator (CPI) for each circuit. The CPI will permit a mathematical comparison and allow ranking between distribution circuits. The CPI is computed using a formula that includes the effects of a circuits SAIDI, SAIFI, MAIFI, and circuit breaker lockouts. Weighting factors are applied to each of the individual indices used in the formula to identify the importance of each index. ScottishPower proposes to identify the five worst performing circuits each year, and to improve their performance by 20 percent as measured by the CPI.
Some system outages will still occur, even with more stringent reliability standards. To minimize customer disruption, ScottishPower proposes to restore supplies on average to 80 percent of customers within three hours for power outages because of a fault or damage on PacifiCorps system. This standard is in addition to the customer service standard that promises to restore power to a customer within 24 hours or be eligible for a direct payment from the Company. (The 24- hour restoration standard is addressed in the testimony of Staff witness Beverly Barker).
Q. What types of outages and interruptions are not included in the proposed standards?
A. ScottishPower proposes to include outages attributable to all causes for purposes of reporting, but to exclude outages caused by certain events for purposes of assessing performance and gauging improvement. Excludable events would be transmission outages, Company-planned interruptions and major events during which the number of outages are more than three standard deviations above average. I support this approach. I believe that it is important to report reliability indices both with and without outages caused by events outside of the utilitys control such as extreme weather, floods, fire, earthquakes or natural disasters. While it is reasonable to exclude these events from the calculation of reliability measures upon which the utilitys performance will be measured, including them in the reporting gives a more complete picture of the extent of outages and permits a fair evaluation of the utilitys response to emergency situations as well as an assessment of the reasonableness of excluding certain events. The subjectivity of the utility can then be examined, and the actual reliability of the system made apparent considering all real world events. The utility is able to exercise some discretion in computing reliability for comparison purposes, but is forced to provide explanation for events not considered in their computations.
Consistent measurement and reporting are crucial in establishing accurate baselines and in gauging progress toward meeting reliability goals. Comparison becomes meaningless if definitions change over time or from place to place. Careful definitions of terms such as extreme weather, and major storm, and uniform methods for measuring the duration of outages and the number of affected customer will be very important.
Q. What penalties does ScottishPower propose if the network reliability standards are not met?
A. ScottishPower proposes a penalty of $1 per customer for each reliability standard not met. In Idaho, this means a penalty of $53,000 for each measure not met, or a combined total of $265,000 if none of the five reliability measures are met (SAIDI, SAIFI, MAIFI, 5 worst performing circuits, and 80% supply restoration standard).
Q. Do you believe that the amount of the proposed penalty provides sufficient incentive for ScottishPower to meet the proposed reliability goals?
A. By itself, the amount of the penalty is not very significant when compared, for example, to the utilitys annual revenue from Idaho customers ($265,000 penalty vs. approximately $150 million total annual operating revenue in Idaho). However, the amount is significant compared to penalties historically assessed by the Commission against utilities in Idaho. If the Company were actually required to pay a penalty this large, it would certainly draw the attention of customers and shareholders alike and would reflect poorly on the Company. I believe the amount of the proposed penalty does provide sufficient incentive to meet reliability standards, although it certainly is not high enough that customers would be fully compensated if the utilitys reliability dropped below current levels. ScottishPowers own analysis indicates that they believe the improvement in reliability, if achieved, has a value of over $60 million annually to its customers throughout its entire system. It seems reasonable to assume that there is no harm to customers if reliability does not change from current levels, but that there would be commensurate harm to customers if, instead, reliability measures decreased by the same amount they are expected to increase. Consequently, I believe the proposed penalties are sufficient if reliability targets are not achieved, but that the Company should be subject to additional penalties if reliability drops below baseline levels. I would propose that those additional penalties be computed using the same methodology used by ScottishPower in estimating the benefits of reducing MAIFI and SAIDI as described in Exhibit No. SP__(AVR-2) of the Supplemental Testimony of Alan Richardson, Utah Docket No. 98-2035-04. [See Sterling Exhibit No. 105].
Q. ScottishPower proposes that any penalty paid for not meeting the reliability goals be placed in the PacifiCorp Foundation. Do you think this is appropriate?
A. No, I do not. While the PacifiCorp Foundation may have noble goals and may be successful in promoting worthy causes, it is completely outside the jurisdiction of the Commission. Funds contributed to the Foundation may be used for any purpose desired, in any location desired. There can be no assurance that Idaho ratepayers will benefit from projects funded by the Foundation, or even that any Foundation programs will be directed to PacifiCorps Idaho customers.
I do agree with the Company, however, that simply refunding money to customers makes little sense. On an individual customer basis, the amount of any refund or credit would be trivial.
I recommend that the Commission withhold judgement on how penalty funds should be used until such time as the penalties, if any, are assessed. At that time, there may be obvious investments needed to correct specific problems for example, or other worthy causes in Idaho that can be identified.
Q. How much money does ScottishPower propose to spend in order to achieve the proposed network improvements?
A. ScottishPower states they will spend approximately $55 million during the five-year implementation period to implement the proposed service standards package that includes the network performance standards in addition to the customer service guarantees. About $32 million of this expenditure is capital investment to be made over the five-year implementation period ($31.1 million for the performance standards and $0.9 million for the customer guarantees). The remaining $23 million are operating expenses. [Exhibit No. 105, Supplemental Testimony of Alan Richardson, Utah Docket No. 98-2035-04, p. 7 at lines 5-11].
Q. What will be the source of funds for the proposed expenditures?
A. ScottishPower states that PacifiCorps overall capital and revenue budgets will not increase as a result of these expenditures. They state this is because ScottishPower will seek to make performance-improving investments which also lead to operational efficiencies. Second, they state, a portion of the committed expenditure will come from modifying or accelerating existing projects contained in PacifiCorps budget (e.g., capital projects to improve worst performing circuits). Third, ScottishPower states it will, in parallel, be seeking other efficiencies in both the capital expenditure program (while delivering the same or improved outputs) and operating expenditures (while delivering improved reliability and service). ScottishPower claims the $55 million expenditure will not have an impact on the rates of customers, and that it will help to mitigate upward cost pressures rather than add to them. [Exhibit No. 105, Supplemental Testimony of Alan Richardson, Utah Docket No. 98-2035-04, p. 7 at lines 11-23].
In my opinion, it is reasonable to pursue the network reliability improvements using the sources of funds described above as long as no additional funds over and above those planned to come from existing PacifiCorp budgets are needed. The proposed expenditures could only affect customers rates if PacifiCorp sought and received approval in a future rate case to recover the investments through rate increases. If the funds needed to achieve the proposed improvements cannot ultimately be obtained through savings, efficiencies, and redirection of existing budgeted funds, then I recommend careful Commission scrutiny if the Company requests to recover these investments through higher rates in a future rate case.
Q. What value will meeting these reliability standards have to Idaho customers?
A. The benefits of improved reliability are difficult to quantify. For a few customers, such as industrial and possibly some commercial and irrigation customers, monetary damages can be estimated. For most customers, however, the dollar impact of an outage is very subjective. It represents more of an inconvenience and an irritation than an actual monetary damage. Despite these difficulties, ScottishPower has attempted to quantify the value of improved system performance. Their analysis concludes that the value of improved reliability is approximately $60 million annually throughout the Companys service territory. [Exhibit No. 105, Supplemental Testimony of Alan Richardson, Utah Docket No. 98-2035-04, Ex. SP__(AVR-2)].
Whether the proposed reliability improvements are indeed worth $60 million to PacifiCorp customers is not critical in my opinion. What is important is that the improvements have a value to Idaho customers at least equal to the amount invested to achieve them and that they are not achieved at the expense of deficiencies in other areas. Whether the Commission approves the merger or not, the Commission still has the authority to set standards for acceptable service and to review the prudency of Company investments. The Commission will have just as much ability to demand quality of service and just as much ability to review prudency after the merger, if approved, as they do now.
Q. In order to gauge the level of improvement in network reliability in the future, it seems necessary to know the current level of network reliability. Do you believe the current level of network reliability is known with certainty?
A. No, in fact, ScottishPowers preliminary review of PacifiCorps reliability data indicates that the existing information is incomplete and inaccurate. ScottishPower has made some attempts to adjust existing reliability data to account for underreporting and weather-related effects that have not consistently been accounted for in the past. In the future, it will be necessary to standardize the measures of reliability to fairly monitor reliability and report it accurately. Some adjustment to existing reliability data and to new data collected in the short-term will be necessary until PacifiCorp is able to consistently and accurately monitor reliability.
Q. How does ScottishPower propose to establish accurate baselines from which improvement can be measured?
A. ScottishPower proposes to use as much existing reliability data as possible, adjusting it for outages believed to be unreported, for major events such as storms, for transmission outages and for data believed to be unreliable. Additional data will be collected annually to supplement existing data and to help establish more accurate baselines. I recommend that Commission Staff be involved in the setting of baselines, and that the baselines used to judge the Companys future performance be subject to Commission approval.
Q. What level and frequency of reporting do you believe will be required?
A. ScottishPower proposes reporting annually to both customers and the Commission. The report to customers will contain an overview of standards, targets and guarantees and will describe performance results for the year. The report will also discuss any new targets PacifiCorp will be applying in the coming year.
The report to be submitted to the Commission will provide more detail. The report will provide a general summary of how PacifiCorp performed according to the standards, targets and guarantees. The report will: (i) provide performance results for each standard, target or guarantee; (ii) identify excluded exceptions; (iii) explain any historical and anticipated trends and events that affected or will affect the measure in the future; (iv) describe any technological advancements in data collection that will significantly change any performance indicator; and (v) discuss any phase-in of new standards, targets or guarantees. If the Company is not meeting a standard, target or guarantee, the report will: (i) provide an analysis of relevant patterns and trends; (ii) describe the cause of the unacceptable performance; (iii) describe the corrective measures undertaken by the Company; (iv) set a target date for completion of the corrective measures; and (v) provide details of any penalty payment due.
I believe the reporting proposed by ScottishPower is reasonable. It appears to be thorough and adequately addresses all important issues and plans for improving performance. If deficiencies in the reporting become evident in the future, the Commission may wish to impose additional reporting requirements.
Q. Do you believe periodic follow-up evaluations will be necessary?
A. Yes, I would propose that annual meetings be planned between the Company and the Commission Staff to review the Companys progress during the previous year, to review the suitability of the performances measures selected and the methods used to calculate and measure them, to review the ability of the Company to collect and report data, to analyze the development of accurate baselines and the integration of old performance data with new data, and to analyze whether the data fairly and accurately represent the performance of the electric network.
Q. PacifiCorp currently has no specific maintenance and inspection requirements in Idaho. Do you believe any are necessary?
A. No, in order to meet the proposed reliability standards, proper maintenance and inspection are a prerequisite. PacifiCorp is required to meet maintenance and inspection requirements in Oregon, and the same guidelines are followed by the Company in the other states served by the Company. In Idaho, the Companys general guideline is to visually inspect 50 percent of the distribution system each year. Detailed inspections are made on a 10-year cycle. I believe the Company is capable of determining proper maintenance and inspection practices and schedules on their own, without specific instructions from the Commission. If problems develop in the future that can be attributed to lack of adequate maintenance or inspection, then the Commission may wish to consider setting maintenance and inspection standards. In any event, I do not believe the setting of maintenance and inspection standards should be used as a crutch to excuse or relieve the Companys responsibility for upholding reliability standards.
Q. Do you believe any additional tree trimming requirements should be imposed?
A. No. Again, proper tree trimming, I believe, is a prerequisite to achieving the reliability levels proposed by ScottishPower. Currently, PacifiCorp generally follows the guidelines outlined in PacifiCorps Vegetation Management Program Specification Manual. The standards outlined in the manual adhere to the American National Standard for Tree Care Operations ANSI A300, and the ISA Trimming Guidelines. Tree trimming standards are part of service performance measures under the AFOR in Oregon. In addition, the Company has recently entered into an agreement with the Oregon Commission with regard to tree trimming practices. In California, D. 97-01-044 establishes tree trimming standards for all California utilities.
As with maintenance and inspection standards, I believe the Company is capable of setting their own internal tree trimming standards subject to the standards listed above, without specific rules or directions from the Commission. Again, if persistent problems or failures of the Company become apparent in the future, the Commission has the ability to impose standards at a future date.
Q. ScottishPower proposes that the network performance goals will be achieved within five years of the completion of the merger. What happens after five years?
A. If the reliability standards are achieved, then I would expect the Company to be required to maintain at least that same level of performance or be subject to penalties. In some cases, it may be appropriate to revise the standards to require an even higher level of performance. If the reliability standards are not achieved, then in addition to the proposed penalties being assessed, I would expect appropriate new targets to be set along with new timeliness for achievement and new penalties. I certainly do not view the proposed network improvements as goals that once reached, cannot be exceeded. Where additional improvement is possible, I expect the Company to pursue it, balancing the value of any further improvements against the cost that must be incurred to achieve them.
Q. Does the Commission currently have the authority to adopt similar network performance standards absent the merger?
A. Yes, the Commission could initiate a case for the purpose of formulating reliability standards if they felt it necessary, even in the absence of any merger.
Water Rights
Q. In the Prehearing Conference for this case, the issue of whether the proposed merger would adversely affect water rights was raised. Has the Staff investigated this issue?
A. Yes, I investigated this issue with the assistance of counsel.
Q. Before discussing the issue and the conclusions of Staffs investigation, please briefly describe the water rights held by PacifiCorp in Idaho.
A. Most of PacifiCorps water rights in Idaho are associated with their plants on the Bear River Grace, Oneida, Cove, Soda, and Soda Springs the Ashton and St. Anthony plants on the Henrys Fork of the Snake, and the Last Chance project on the Last Chance Canal.
The Company holds a series of water rights on the Bear River that stem from licenses, permits or statutory claims. PacifiCorp also holds decreed water rights to divert water from the Bear River for storage in Bear Lake. The general nature of the decreed rights allows the Company to operate, manage and release water from storage for power generation, irrigation and other beneficial uses. At the time of the decree, irrigators on the Bear River agreed to subordinate their irrigation rights in exchange for contractual rights with PacifiCorp (and its predecessor companies) for Bear Lake storage water. Some of those contracts are very long term and can only be terminated by mutual agreement of the parties; others are yearly contracts subject to re-negotiation every year. Most of those irrigators use PacifiCorps water to supplement existing rights, some of which are senior to PacifiCorps rights. In addition to rights associated with the Bear River, PacifiCorp has two water rights on the Snake River at Henrys Fork.
Q. What is the Commissions authority with respect to water rights owned by an electric utility?
A. According to Idaho Code 61-328 any electric utility that owns, controls or operates any property located in Idaho which is used in the generation, transmission, distribution or supply of electric power and energy to the public that sells, assigns or transfers, directly or indirectly, that property must be authorized to do so by the Commission. Clearly, PacifiCorps generation plants in Idaho are subject to the statute, but in addition, the hydropower water rights associated with those facilities, because they are used in the generation of electric power and are considered real property, makes them subject to the statute as well according to counsel. Therefore, before PacifiCorp or ScottishPower can sell or transfer water rights or the control thereof, they must request approval pursuant to Idaho Code 61-328. To grant approval, the Commission must find that the public interest will not be adversely affected, that the cost of and rates for supplying service will not be increased by reason of such transaction, and that the applicant for such acquisition or transfer has the bona fide intent and financial ability to operate and maintain said property in the public service.
In addition, in 1985, the Legislature enacted Idaho Code 61-502B which requires The gain upon sale of a public utilitys water right used for the generation of electricity shall accrue to the benefit of the ratepayers.
Finally, Idaho Code 61-539 specifically precludes the authority of the Commission in instances where the failure or refusal of an electric company to protect its hydropower water rights from loss or depletion to certain junior appropriative rights is involved.
Q. Would the water rights of PacifiCorp or of any other water right holder be adversely affected by the proposed merger?
A. No, not in my opinion based on the advice of counsel. Any statutory license, permit or claim would still be held by PacifiCorp or simply transferred to the succeeding entity with all of the same rights and responsibilities as before the merger. ScottishPower could receive only those rights that PacifiCorp holds and no more. Similarly with decreed water rights, the sale, lease or transfer of a water right transfers no more legal interests in the water right than the original owner holds. In the case of contracts, ScottishPower would be a successor-in-interest, and the legal status of the contracts would not change because of a merger.
As a matter of law according to counsel, the mere fact that PacifiCorp merges with ScottishPower or becomes a wholly owned subsidiary does not change the existing water rights or contracts with water users. Whatever PacifiCorp's water rights and contract rights are before the merger, the legal relationship is unchanged by the merger. PacifiCorps water rights cannot be materially changed or enlarged simply by transferring them to ScottishPower. ScottishPower will have the same water rights as PacifiCorp now enjoys. The only contract holders that may be directly affected may be those water users with year-to-year contracts, as those contracts are subject to re-negotiation.
According to counsel, it appears that the only possible effect of the merger could be on the relationship between the new company and junior appropriators who may have historically been voluntarily allowed by PacifiCorp to use water in times of water shortage without PacifiCorp requiring compensation. The Idaho Constitution gives domestic and irrigation rights preference when water is short, but requires just compensation be made if a non-domestic or non-irrigation right must be shut down, unless the water right has been subordinated. A potential fear then, is that if PacifiCorp had been allowing junior appropriators to use its water in times of shortage without requiring compensation, that ScottishPower might not continue that voluntary practice. In other words, that it might attempt to change the existing working relationship with water users.
So, while there may, in fact, be some threat to other water users, I am advised by counsel that Idaho Code 61-539 makes clear the Commission may not, in any way, make any determination, decision, rule, demand, requirement, or issue any order or decree involving or related to the failure or refusal of an electrical corporation to protect its hydropower water rights from depletion or loss to certain junior appropriators. Thus, the likely concern of irrigators and other water users, if there is one, is clearly not within the jurisdiction of the Commission.
I should also make explicitly clear, however, that the Commission Staff has no evidence that PacifiCorp has, in fact, failed or refused to protect its hydropower water rights.
BPA Residential Exchange Program
Q. In the Prehearing Conference for this case, the Commission advised the parties that it expects the Applicants to address and respond, among other things, to PacifiCorps continued eligibility to participate in the BPA Residential Exchange Program and to the Companys eligibility to participate in the BPA subscription process. Did Staff investigate these issues?
A. Yes, Staff did investigate them to the extent we were able. We did review the eligibility criteria for these programs, but the determination as to whether PacifiCorps eligibility is affected is a legal one that rests outside of the Commission.
Q. Please explain the concerns about PacifiCorps eligibility to continue to participate in the BPA Residential Exchange Program.
A. There appear to be two primary concerns with regard to the Residential Exchange Program. The first is whether PacifiCorp would, after the merger, continue to be considered a Pacific Northwest utility as defined in the Northwest Power Act, and thus eligible to participate in the program. The second concern, if PacifiCorp can continue to participate in the program, is whether the Companys Average System Cost will be computed differently, thus changing the value of the programs benefits to customers.
Q. Does PacifiCorp believe the merger will affect their eligibility to continue to participate in the program?
A. No, they do not. In response to Staff production requests, PacifiCorp states that the transaction does not affect their status as a Pacific Northwest utility as that term is used in the Northwest Power Act (Exhibit No. 106). They admit that the term Pacific Northwest utility is not defined in the statute, and fall back on BPAs historical implementation of the Northwest Power Act. Under BPAs historical implementation, PacifiCorp believes that the relevant consideration has been whether the entity provides state-regulated retail service to residential customers within the Pacific Northwest. Pacific Power and Light Company and Utah Power Company have always met this requirement and have participated in the program since its inception. PacifiCorp further points out that the state in which utilities are incorporated has never been an issue in determining eligibility in the past, and that no other merger or change in ownership or control of other Northwest investor-owned utilities has barred them from participating in the program.
PacifiCorp also notes that BPA is aware of the proposed merger, yet they have continued to negotiate with PacifiCorp concerning resolution of PacifiCorps Residential Exchange rights for the period commencing in October 2001. BPA has made a settlement proposal under which BPA would enter into contracts with investor-owned utilities participating in the Residential Exchange Program for the sale of subscription power in consideration for a waiver of Residential Exchange rights. Discussions are still ongoing between BPA, PacifiCorp, and other investor-owned utilities regarding these issues.
Q. If PacifiCorp is deemed eligible to continue to participate in the program after the merger, please discuss the concern about the effect of calculation of Average System Cost on the value of benefits available to customers.
A. Under the Residential Exchange Program, BPA has developed a methodology for determining the Average System Cost for utilities participating in the program. The Average System Cost is important because it establishes the value of power exchanged by each utility with the lower cost power from BPA. Thus, the Average System Cost indirectly determines the magnitude of benefits ultimately shared by customers of the utility. The concern is whether the pre-merger PacifiCorp Average System Cost will remain the same, or change as a result of the merger.
Q. Will the merger have any effect on PacifiCorps eligibility to participate in the Residential Exchange Program, on the calculation of Average System Cost under the program, or on their eligibility to participate in the BPA subscription process?
A. The Northwest Power Act is not explicit enough to determine with certainty whether PacifiCorps eligibility will be affected or whether the calculation of Average System Cost will change. Although the Commission Staff has no reason to believe that the merger will affect PacifiCorps BPA Exchange eligibility, a determination rests with BPA, the FERC, and perhaps ultimately, the federal courts.
Q. Does this conclude your testimony in this case?
A. Yes, it does.
PAC-E-99-1 STERLING, R (Di) 1
05/18/99 Staff
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