Attch 9_IPCE017_11_StaffComments.doc

LISA D. NORDSTROM
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 5733

Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5983

Attorney for the Commission Staff

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE IDAHO POWER
COMPANY APPLICATION FOR A
REFUNDABLE EMERGENCY ENERGY
CHARGE FOR THE RECOVERY OF
EXTRAORDINARY POWER SUPPLY
EXPENSES.
)
)
)
)
)
)
)
CASE NO. IPC-E-01-7

IN THE MATTER OF THE IDAHO POWER
COMPANY APPLICATION FOR AUTHORITY
TO IMPLEMENT A POWER COST
ADJUSTMENT (PCA) RATE FOR ELECTRIC
SERVICE FROM MAY 1, 2001 THROUGH MAY
15, 2002.
)
)
)
)
)
)
)
CASE NO. IPC-E-01-11

COMMENTS OF THE COMMISSION STAFF

COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its Attorney of record, Lisa D. Nordstrom, Deputy Attorney General, and submits the following comments in response to Commission Order Nos. 28665 and 28685.
On February 23, 2001, Idaho Power Company filed an Application for authority to implement a flat “emergency energy charge” of 1.2737¢ per kilowatt-hour (kWh) applicable to all customer classes for a twelve-month period to recover the Company’s unprecedented $161 million in additional power purchase costs incurred over a ten (10) month period. Although the Company requested that the emergency energy charge become effective March 26, 2001, the Commission suspended the effective date in Order No. 28665 until May 1, 2001. The suspension would allow the Commission time to examine the prudency of the Company’s power purchases, review the Company’s promotion of its conservation policies, and conduct public workshops and hearings.
On March 21, 2001, Idaho Power Company filed an additional Application with the Commission for authority to increase the Power Cost Adjustment (PCA) rate schedule from the existing 0.1371¢ per kilowatt hour (kWh) rate to 0.6152¢ per kWh. If approved, the PCA Application would result in an overall increase of approximately $66.4 million in revenues. The Company has requested an effective date of May 1, 2001.
Because the recovery of off-system purchased power expenses sought by the proposed emergency energy charge are historically included in the Company’s annual PCA filing, the Commission in Order No. 28665 combined the proposed emergency energy charge (IPC-E-01-7) and Power Cost Adjustment (IPC-E-01-11) into a single proceeding to facilitate comprehensive consideration of all components of the PCA. If approved, these two Applications (hereinafter referred to as the “combined PCA filing”) would recover approximately $227.4 million through a flat 1.8889¢ per kWh charge from the Company’s customers for one year.
COMBINED PCA FILING AND ITS PROPOSED IMPACT
Idaho Power rates are adjusted each May subsequent to when the Company files its Power Cost Adjustment (PCA). The PCA is comprised of two major components: 1) excess Company power supply costs during the preceding twelve (12) months, which include off-system power purchases from the regional power market beyond the amount allocated in customer base rates, and 2) the projection of the next year’s power supply costs based on expected Snake River stream flows and storage. The proposed rate increase in Case No. IPC-E-01-11 is primarily based upon below average water flows in Idaho’s hydroelectric system.
Because not all customers pay the same per-kilowatt-hour charge, the proposed 1.8889¢ per kWh charge represents a different percentage increase for each customer class. The approximate percentage impact of this proposed increase for each customer group or class is set out below:

customer group today’s
average rate proposed average rate percentage increase Residential 5.2 cents per kWh 7.1 cents per kWh 34.4% Irrigation 3.9 cents per kWh 5.8 cents per kWh 46.8% Small Commercial 6.4 cents per kWh 8.3 cents per kWh 27.9% Large Commercial 3.7 cents per kWh 5.5 cents per kWh 49.6% Industrial 2.9 cents per kWh 4.7 cents per kWh 62.8%
The combined proposed rate change reflects an average 45.6% increase to current Idaho Power rates. More specifically, the Company’s bill stuffer notifies customers that a typical monthly residential bill for 1,200 kWh will increase from $62.72 to $84.34 if the proposed 1.8889¢ rate increase is approved.
STAFF ANALYSIS
1. THE POWER COST ADJUSTMENT (PCA) MECHANISM
a. Forecast
Staff has reviewed the Company’s calculation of forecast power supply costs and certifies that the Company’s calculations follow the formula prescribed in previous Commission PCA Orders. Attachment 1 depicts April through July Brownlee inflows and shows expected power supply costs to be $132,938,867. This dollar amount is consistent with the results presented by the Company in its filing. After computing the above-normal power supply costs, the forecast amounts to approximately $45.8 million when adjusted for Idaho's jurisdictional share of the increase and the 90/10 sharing between ratepayers and shareholders.
Given the proposed large rate increase required to recover the true-up discussed below, Staff proposes that this amount not be passed on to ratepayers in this year's PCA rate adjustment. The effect of not passing this increase on to ratepayers in the pending PCA adjustment is that it will be deferred with interest to next year's true-up of actual power supply costs. The forecast formula is badly broken because it assumes that market purchases can be made at approximately 2¢/kWh even though this summer's prices are expected to be 30¢/kWh or more. With low water and high market prices the forecast formula severely underestimates expected power supply costs. Idaho Power’s Buy-Back and additional generators will also impact next years power supply costs. Staff believes that the Company's above-normal power supply costs for next year will be substantially higher than the $45.8 million forecast. Staff’s believes that the forecast should not be included in this year's PCA rate adjustment because even without an accurate power supply cost forecast, the proposed PCA true-up far exceeds the 7% benchmark requiring an examination of measures to dull the effects of rate shock. Order No. 24806.
(Case No. IPC-E-92-25).
b. True-Up
Staff has reviewed the Company’s calculation of the 2000-2001 true-up of actual power supply costs and verifies that the calculations have been done correctly. This year's true-up calculation is for 11 months - April 2000 through February 2001. Although March 2001would normally be included, it was left out of this calculation to facilitate early filing of the PCA at the Commission's request. Order No. 28665. Staff expects that March's power supply cost true-up will be included in next years true-up calculation.
The Company’s true-up calculation made two adjustments that the Staff accepts as appropriate. First, the Company adjusted the load change expense for February 2001 to account for differences in “actual firm load” reported in previous months. Second, the Company adjusted the interest calculation on the deferred balance of August, October and February to reflect differences in market purchases, sales, and load change expenses reported in previous months.
Staff proposes two additional adjustments to the true-up calculation. First, Staff proposes that a 5% interest rate be applied to the deferred balances of April 2000 through March 2001. By previous agreement between the Company and Staff, and as demonstrated by actual practice in all previous PCA true-ups, the Commission-approved interest rate for deposits has been used for all months in the PCA year. In its true-up calculation the Company used a 5% interest rate for April - December 2000 and a 6% interest rate for January and February 2001. Staff recommends that the 5% interest rate be used for the entire PCA period to be consistent with past PCA calculations.
Second, Staff recommends that the net purchase and sales costs be adjusted to reflect the numbers found in the box on the attached true-up calculation spreadsheet (Attachment 2). This adjustment is discussed in detail below. (Sec. 3. Audit of Accounts and Trading Activity).
c. PCA Rate Calculation
Attachment 3 details the PCA rate calculation. The “2001-2002 Forecast” section incorporates Staff's recommendation that the power cost forecast be deferred until next year's PCA true-up. Thus, it is shown as "zero".
The middle third of Attachment 3 shows Staff's calculation of the “2000 – 2001 true-up” rate, which is .9883 ¢/kWh. The Company used different amounts of kWh in its rate calculations in its two separate filings. By example, in the emergency surcharge case (Case No. IPC-E-01-7) the Company used normalized 1999 Idaho jurisdictional firm load of 12,632,017. In its second filing (IPC-E-01-11), the Company used 10,802,636 MWh which is the normalized Idaho jurisdictional firm load from the Company's last general rate case. This later amount would be the appropriate number if the established PCA methodology were used. Staff recommends the Commission adopt the Company’s proposal to use normalized 1999 kWh’s (12,770,405 MWh) to calculate the PCA rate. This larger number reduces the rate and consequently the rate increase to customers. If the Company sells the 1999 normalized number of kWh, as it expects to do, the Company will recover all of its true-up costs. This is demonstrated on the bottom portion of Attachment 3 under “Expected PCA Revenues”.
With regard to rate design, Staff proposes that the energy rate for all customers except residential be increased by .9883 ¢/kWh. Staff recommends the residential class rate be increased by the same average amount, but spread over three separate usage blocks. The residential rate design is discussed in detail below. (Sec. 5. "Rate Design Issues and Their Proposed Impact.")
Attachment 4 demonstrates the impact of Staff's recommendations in terms of rate increases to each of Idaho Power’s customer classes. On average, residential customers would pay slightly more than 6 ¢/kWh, which represents a 16.25 % rate increase. Large industrial customers would pay between 3 and 4 ¢/kWh, which represents a rate increase of 30 to 36 %. Staff also recommends that if the Commission approves an overall increase significantly greater than 20%, that it consider amortization of the increase over 2 years.
Staff recommends that the Company's rates become effective May 16, 2001 as opposed to the May 1, 2001 date requested in the PCA filing. The May 16 effective date prevents last years PCA rate and this years PCA rate from simultaneously being in effect for two weeks. It also prevents the proposed PCA rate from expiring two weeks prior to implementing a new PCA rate on May 16, 2002. The May 16 effective date simplifies administration, avoids unnecessary rate changes which could be large percentages and makes the changes easier for customers to understand.
2. RESOURCE PLANNING
a. Idaho Power’s Long-Term and Short-Term Planning
In its combined PCA filing, Idaho Power requests that the rates of Idaho customers be increased to reflect $192.6 million of net purchases and sales made at market prices on their behalf. This represents 85 percent of the total increase requested by the Company. Recent low water conditions have caused a higher than normal reliance on the regional power market. However, even under normal water conditions, the increased cost would have been approximately $171 million, or 75 percent of the total increase requested by the Company. To determine whether these costs have been prudently incurred, Staff believes it is necessary to examine Idaho Power's actions leading up to the high priced purchases, its actions once market prices rose to unprecedented levels, and its actions to mitigate the effects of such high market prices.
To determine whether the Company had set itself on a course for market dependency and whether that dependency placed customers at risk, Staff examined Idaho Power’s long-term planning process prior to the run up in market prices. The Company’s Integrated Resource Plans (IRPs) are the only documented plans that reveal Idaho Power's strategies to meet future loads. Consequently, Staff carefully reviewed all integrated resource plans prepared since 1993.
Staff also examined reports from Western Systems Coordinating Council, North American Electric Reliability Council and Northwest Power Planning Council that addressed the adequacy of generation in the West and Northwest. In particular, Staff was looked for indications that high market prices could occur and that reliance on the market could be risky. Staff was primarily interested in determining how Idaho Power responded to reduce market reliance and exposure to high prices.
Idaho Power’s short-term planning occurs in a less structured way. Its Risk Management Committee and its Board of Directors generally carry out the Company’s short-term decision making. Documentation of the Company’s short-term planning activities, discussions and decision making is reflected in the meeting minutes of these two groups. Staff reviewed the meeting minutes of both groups from May 2000 through the present.
b. Integrated Resource Plans
Since 1989, the Commission has required Idaho Power to prepare integrated resource plans biennially. IRPs are intended to reflect the long term planning strategies of the utility. They are the base line against which the utility’s performance will ordinarily be measured. See Order No. 25260.
Idaho Power’s 1993 IRP
As early as 1993, Idaho Power began planning to rely on power purchases and exchanges to meet its short-term needs. The Company contemplated seasonal and even monthly power exchanges to take advantage of the differences in loads between summer peaking and winter peaking utilities within the western system. Although not commonly utilized at the time, Idaho Power recognized that potential existed for power exchanges between Northwest and Southwest utilities.
Idaho Power’s 1995 IRP
By 1995 restructuring had begun in some parts of the country, energy markets began to emerge, and competition to supply new generation was anticipated. In the 1995 IRP, Idaho Power stated its intention to utilize market purchases to meet its short-term deficits. The Company reasoned that a short-term market purchase strategy would minimize the risks associated with acquisition of new, long-term generation plants.
Staff questioned the availability and risks associated with this strategy, and suggested that more evidence was needed to provide assurance that reliance on market resources would be less costly and just as reliable. Staff believed that reliance on market resources could potentially increase risks, and therefore costs, if power market supplies were short and prices were high. In response, Idaho Power cited the historical evidence of availability of spot market power, then current evidence of an emerging robust wholesale power market in the western region, and the Company’s considerable experience in making substantial purchases and sales of firm power to supply loads. Staff noted that flexibility and the ability to quickly adapt to changes would become more important, and that risk management tools would become more valuable.
Another noteworthy element of the 1995 IRP was Idaho Power’s elimination of its planning reserve. The planning reserve was an extra six percent of generation that the Company previously maintained to account for any type of unexpected condition or event -including unexpectedly high load growth, extreme weather, poor water conditions or unplanned outages. The planning reserve was intended to give the utility a cushion during the time necessary to construct new generation and bring it on line. Because the planning reserve was eliminated, Staff recommended that the Company carefully monitor actual reserves in the future to insure that reliability was maintained and that customers were not jeopardized by the Company being forced to acquire very high priced resources to meet deficits.
Idaho Power’s 1997 IRP
In the 1997 IRP, Idaho Power determined that a seasonal market purchase strategy would be the least expensive method of acquiring additional resources during the following ten years. In 1997, the Company planned average purchases of 150 megawatts of energy in the months of July, August, November and December. These amounts were expected to triple by 2005. In practice, seasonal purchases would be acquired each year in amounts reflecting actual load requirements at that time.
Idaho Power’s two-year action plan included the following actions to purchase seasonal capacity and energy on a year by year basis as needed to serve additional customer load requirements, and expand Idaho Power’s power marketing activity and capability.
The Company expected that during the next two years, energy and capacity would be readily available from the regional power market at a reasonable cost. The new power trading floor, Idaho Power noted, would enable increased trading efficiency and a higher volume of future power purchases and sales. Additionally, the Company expected development of forward pricing and risk management tools to provide new support to the trading function.
It should be noted that the time period during which the 1997 IRP was prepared was one of great uncertainty. Deregulation was underway in some states and was being debated in most others. As with the 1995 IRP, Staff and other members of Idaho Power’s Technical Advisory Panel questioned the risks to customers and the utility associated with planning on increased use of market purchases to meet future load growth. The review panel debated whether the power market would be a reliable, least-cost power supply option for customers compared to utility ownership or long-term contractual purchases.
Idaho Power’s 2000 IRP
Idaho Power was granted a one-year extension to file the 2000 IRP, primarily because of the uncertainty within the electric industry during the intervening three-year period. Unlike previous IRPs, the 2000 IRP was prepared solely by Idaho Power without the input of the Commission Staff, customer groups, or other representatives. Idaho Power provided the draft IRP to Staff for review in March 2000. Staff submitted its comments on the draft on May 4, 2000.

One subject area on which Staff commented was the vulnerability of Idaho Power to conditions outside of its own system. Staff stated the following:
…Staff is concerned about the vulnerability of Idaho Power and its customers to conditions outside of its own system. …One example of this vulnerability could be transmission. Idaho Power addresses constraints within its own system, but has no real control over constraints in surrounding systems that may be even more critical in determining the Company’s ability to import or exchange power seasonally. …Staff and customers would gain greater comfort in knowing that Idaho Power is doing all it can to minimize its vulnerability to conditions outside of its own system.

Staff’s comments specifically mention transmission constraints as one possible source of vulnerability; however, Staff’s primary concern was with the ability of Idaho Power to import sufficient market resources to meet it needs. Staff also noted the risks of relying on the market:
The recent well-publicized brownouts and blackouts in other parts of the country due to failures of the market to be able to actually deliver power when needed and in the amounts needed have heightened the sensitivity of customers towards reliance on the market. The assumption that there will always be ample resources on the market at reasonable prices and that they will be deliverable to Idaho needs to be better supported.

…The availability of seasonal surplus in the region seems to be implicit in Idaho Power’s analysis. If Idaho Power intends to rely on market purchases, it should provide some analysis or evidence to show that enough power will be available when needed and at a reasonable price.

Idaho Power reviewed Staff’s comments, revised the draft IRP, and submitted it to the Commission on June 29, 2000. As in previous IRPs, the Company indicated its intention to rely on the market to meet short-term needs and to satisfy deficits in the event of low water conditions or other unplanned events. The Company’s plan was described in the IRP as follows:
In the 1997 IRP, Idaho Power chose supplemental seasonal energy and capacity purchases as its near-term strategy for meeting customer loads at least cost. That strategy has been successful. Idaho Power has been able to take advantage of abundant supplies of off-system surplus energy and available transmission access to supplement the Company’s own low-cost generation resources.

Idaho Power’s assumption about market prices was a key factor affecting its decision to rely on the market. Estimates of future electric market prices were based on the assumption that during the planning period, energy purchased from the Pacific Northwest would increasingly be generated from combined cycle combustion turbines. Idaho Power’s estimated market price for energy ranged from approximately $37 per MWh in 2000 and to almost $45 per MWh in 2009. Clearly, these prices are far below recent and current market.
In the 2000 IRP, Idaho Power paid particular attention to discussing the future adequacy of its resources and the reasonableness of its median water-planning criterion. For the first time in an IRP, Idaho Power included analysis of a low water scenario. Idaho Power concluded, “…the Company believes it can reasonably expect to acquire short-term resources from the Pacific Northwest in amounts sufficient to satisfy deficiencies during low water conditions.”
After reviewing the draft IRP, Staff commented “…under extremely low water conditions, such as could exist for only one or a few years, Staff is concerned about the transmission constraints to the Northwest. …Staff believes it would be worthwhile to address how Idaho Power would meet load under extremely low water conditions.”
As it turns out, actual water conditions from the summer of 2000 to the present are worse than the “low water” scenario analyzed. Attachment 5 shows a comparison by month from June 2000 through February 2001 between the actual and projected energy deficits under low water conditions. The figure shows that actual deficits far exceeded low water projections for the early part of the summer, and again in January and February. Actual deficits in the other months were close to projections under low water conditions.
Idaho Power’s 2000 IRP was acknowledged by the Commission on December 18, 2000 in Order No. 28583. By this time, market prices had already reached extremely high levels and public appeals were being made throughout the region for customers to conserve so as to minimize the effect of price increases and potential rolling blackouts. The Commission’s order included the following language:
It is now early December 2000 and the Northwest region continues to experience record high prices in the wholesale market. Voluntary conservation is encouraged to reduce the extent of rate increases that will follow purchases at those high prices. For the region it is a wake up call. Creative thinking and planning by utilities and customers may serve to reduce reliance on market purchases to the benefit of both customers and stockholders. Idaho Power and its customers are encouraged to take inventory and stock of available demand side management and conservation opportunities so that rate increases can be mitigated.

c. Reliability Assessments
Staff reviewed the reliability assessments published in the past several years by the North American Electric Reliability Council (NERC) and the Western Systems Coordinating Council (WSCC). While reliability assessments generally only look at whether there will be enough generation and transmission available to meet expected loads irrespective of price, predictions of generation shortages can reasonably lead to expectations of high prices.
Reliability Assessment 1996-2005, North American Electric Reliability Council, October 1996
This assessment was probably the earliest to address market resources, since the market was just beginning to emerge as deregulation was beginning to unfold. The report included a brief discussion warning that prices would rise if the market did not provide adequate resources and that lead times to construct new generation may be too long to quickly respond to market price signals.
Reliability Assessment 1997-2006, North American Electric Reliability Council, October 1997
The following year, NERC’s annual assessment report gave even stronger warnings about the uncertainty that sufficient capacity would be built and the danger that prices would rise as a result. The report noted the reluctance within the industry to commit to new projects and attributed some of the reluctance to the competitive nature of the emerging open electricity market. The report reiterated that price signals would be ineffective for planning purposes because lead times to construct new generation are too long to quickly respond to market price signals. In addition, it was observed that there was no infrastructure in place at that time, either in the planning or operational horizons, to adequately manage the transition from the traditional obligation-to-serve scenario to a completely market-based scenario.
The report concluded that the market could not be relied upon to provide adequate resources until it matured and that certain new requirements may need to be placed on utilities during this transition to inform customers of emerging risks to their supply reliability.
10-Year Coordinated Plan Summary, 1999-2008, Planning and Operation for Electric System Reliability, Western Systems Coordinating Council, October 1999
The WSCC concluded that capacity margins were expected to be adequate, but only if the expected new capacity was built. The WSCC warned that if multiple areas peaked simultaneously, portions of the region might need to issue public appeals for customers to reduce their electricity consumption and that other measures might be necessary to maintain adequate operating reserves. The report warned that should a contingency occur, such as very high peak demands during a period of extreme cold weather, the Pacific Northwest may need to rely on the capability to import power.
Reserve margins in the Southwest were already extremely low and were predicted to drop to near zero unless new generation was added. The report warned that a shortfall in planned generation additions could adversely impact the ability to serve firm peak demand between 2002 and 2006. It was also pointed out that weather extremes and equipment outages could significantly compound the problem.
Assessment of the 2000 Summer Operating Period, Western Systems Coordinating Council, Revised May 25, 2000
Going into the summer of 2000, reliability was expected to be adequate if normal temperatures prevailed during the summer period. However, the report warned that unplanned outages, high temperatures, or simultaneous load peaking could cause problems. The report cautioned that the southwest portion of the WSCC might not have adequate resources to accommodate a widespread severe heat wave or higher than normal generator-forced outages. The report stated that the possible inability to serve all firm peak demands under higher than normal temperatures or higher than normal anticipated forced outage conditions was a result of the continuing trend where peak demand growth had significantly exceeded the amount of new generation facilities being installed.
10-Year Coordinated Plan Summary, 2000-2009, Planning and Operation for Electric System Reliability, Western Systems Coordinating Council, October 2000
At the start of the winter of 2000, projected regional capacity margins for the Northwest Power Pool area were low, but it was believed they would be adequate for the next ten years. However, the report notes that the capacity margin adequacy over the next ten years assumes timely construction of approximately 30,200 MW of net new generation. The capacity margin adequacy also assumes average weather conditions. Both this report and NERC’s 2000-2009 Reliability Assessment warn that should very high peak demands occur during an extreme cold weather period, the Pacific Northwest may need to rely on its capability to import power.
The report also briefly discussed interruptions in California during the summer of 2000. Non-firm peak demand curtailments during the last week of June occurred during a period when portions of the Northwest experienced hot to record-high temperatures and portions of the Southwest were also hot. The high temperatures and the Northwest generator outages limited the ability of these areas to export to California. The report noted that these two experiences demonstrated that even with the assumptions of future generation and transmission expansion projects, statewide and local reliability problems can exist in the short-term.
Reliability Assessment 2000-2009, The Reliability of Bulk Electric Systems in North America, North American Electric Reliability Council, October 2000
This report was prepared following some of the problems in California during the previous summer. It contained much discussion about volatile, high market prices, and provided blunt warnings about the future. The report stated, “As price spikes have indicated in the past, the market price in the short-term may become excessively high. These high prices may result in situations where providers, unsure of recovery of costs, curtail service to customers, or consumers will no longer be able to afford the service. In the absence of an obligation to serve, high market prices may jeopardize continuity of electric service in the sense that unaffordable prices may discourage providers from purchasing and delivering energy to consumers.
The report not only warned about high market prices, it included assessments of what NERC believed should be done to correct the problems and suggested several specific tools that utilities might be able to employ such as interruptible load tariffs, real-time pricing and time-of-day rates.
2000-2001 Winter Assessment, Reliability of Bulk Electricity Supply in North America, North American Electric Reliability Council, November 2000
NERC’s most recent report was prepared early last winter. Projected capacity margins were anticipated to be adequate in the WSCC region. The report points out that during a good water year, the Northwest is generally a net electricity exporter even during the winter season. However, for some contingencies that may occur simultaneously with very high peak demands due to extreme cold weather, the Northwest may need to rely on the capability to import power.
In reaction to the dire predictions for the upcoming winter, numerous organizations including the Northwest Power Pool, Pacific Northwest Utilities Conference Committee, Bonneville Power Administration, Northwest Power Planning Council, Pacific Northwest Security Center, and the Northwest’s utilities began collaborating on a plan for winter readiness. The report briefly discussed this effort.
This report also provided a detailed discussion of the events in California during the summer of 2000. It discussed the various factors that contributed to tight electricity supplies in the real-time energy market. The report also described the various types and frequencies of warnings issued in California throughout the summer.
In addition to discussions about the problems of the past summer and predictions about the coming winter, the report also briefly forecasted conditions expected for the summer of 2001 in California. According to the report, early indications are that next summer will be the same, or, more likely, worse than summer 2000.
d. Northwest Power Planning Council Reports
The Northwest Power Planning Council prepared two reports that Staff believes are relevant to this investigation, the first in the spring of 2000 and the second in the fall of 2000. Important points in each report are summarized below.
Northwest Power Supply Adequacy/Reliability Study, Phase 1 Report, Northwest Power Planning Council, March 6, 2000
This report was prepared by the Council to address conclusions reached by the Bonneville Power Administration’s 1999 Pacific Northwest Loads and Resources Study. The BPA study indicated that over each of the next few winters there is about a one in four chance that generation supply would not be adequate to meet loads. These shortages could be caused by some combination of poor hydro conditions, higher than normal demand due to weather conditions, and unplanned generation outages.
The Council’s found that "the bottom line of this study is that the Council thinks the Northwest needs to start serious discussions about how it can assure adequate power supply during this transitional period in the electric industry." Furthermore, "given the impending potential supply problems, the demand side needs to be addressed as well. Doing so may be more economical than a purely supply-side approach." The Council also recommended that "in the near term, the region may have to look at other mechanisms by which the demand-side can participate in achieving load-resource balance. There are a variety of mechanisms that one could envision. They range from technological means of reducing and/or shifting loads to contracts for shedding loads or perhaps establishing a market for load reductions."
The report discussed what the Council believed were the two options for ensuring an adequate power supply. The first option was to stand back and let the market develop.
There is a school of thought that the best plan is no plan…. If we do experience periods of inadequate power supply, system operators would manage through such situations. First, they would purchase power wherever they could at whatever price. If that proved insufficient, system operators would shed load, probably through rolling blackouts on the substation level so as to maintain the stability of the system as a whole….

Under this “do nothing” approach, the report predicted that tight supplies would increase the price of wholesale power to such high levels that utilities would eventually consider entering into interruptible contracts with some customers, invest in load shifting or load shaving technology and/or invest in standby generation.
The second option envisioned taking "steps to facilitate the development of responses to possible supply inadequacies before they happen."
The Council noted the possibility of high prices and power interruptions, and pointed out that the public may be far less tolerant of interruptions “… attributable to a failure of trusted institutions to carry out their responsibilities,” than to power interruptions attributable to acts of God. The Council suggested that the public’s reaction might be a backlash that delays or reverses the movement toward a more competitive and efficient power system.
The Council went on to suggest several possible alternative for solutions, including real-time pricing, increased use of contracts for load reduction, demand-side bids to provide reserves, DSM technologies that can reduce the peak level of use, and “conventional” conservation.
Study of Western Power Market Prices, Summer 2000, Final Report, October 11,
2000, Northwest Power Planning Council Document 2000-18
As a follow-up to its earlier report, the Council prepared a report analyzing the high market prices in western markets experienced during the summer of 2000. The Council concluded the following:
The Council believes that the market prices seen this summer are a tangible manifestation of the fundamental problems identified in the Council’s power supply adequacy study of last winter. That is, the prices are an indicator of approaching scarcity. This summer, the system, which already is facing tight supplies, has been further stressed by combinations of unusually high loads, poor hydropower conditions, and forced outages of thermal units. There is little in the way of price-responsiveness in demand to mitigate these prices. Those who had available supply were able to ask for and receive high prices. This combination of factors is precisely what leads to the power supply adequacy problems identified in the Council’s earlier study. These factors apply not only to the Northwest but also to the entire Western Interconnected System. There were some additional factors acting this summer related to the design of the California market, but they should not obscure the basic underlying problem. Absent some action, the next similar event could result in not only high prices but also a failure of the system to meet loads.

The Council offered several recommendations for actions to mitigate future high prices and potential power supply problems, including:
Encouraging Greater Use of Risk Mitigation Mechanisms and accelerating efforts to develop the demand side of the market. The Council noted that "risk mitigation comes at a cost, and it is not realistic to be fully hedged for all risk. However, the Council concluded that limitations on forward contracting by California utilities and market participants in the Northwest were a contributing factor in the price extremes of this summer. "While opportunities to enter into forward contracts and other hedging arrangements have existed, it may be that the protracted period of low market prices for electricity lulled some market participants into believing they had no need of such mechanisms.
The Council also warned that the lead time for development of new combined cycle generation, "the region and the West are vulnerable to further price spikes and possible reliability problems. Moreover, it is not certain that the long-term market will support the level of development necessary to assure adequate reliability."
e. Idaho Power’s Short-term Planning Activities
As previously discussed, Idaho Power regularly conducts long-term planning by preparing IRPs. Its short-term planning, however, is not so structured. Staff requested that Idaho Power provide all documentation and evidence to demonstrate its planning activities since completion of the 2000 IRP early last summer. It was at that time that the Company began to incur extraordinarily high power purchase costs. Initially, Idaho Power responded by simply referring to its previous IRPs, transcripts from its 1995 general rate case, the Twin Falls case, the 1992 case adopting the PCA mechanism, and FERC Form 1 reports. None of these documents reflected the types of short-term planning evidence Staff was seeking, nor did any cover the time period in which deferred costs requested for recovery in this case were incurred.
Staff next reviewed the minutes of Idaho Power’s Risk Management Committee meetings. The committee meets approximately weekly, although daily meetings were held for a couple of weeks in December when the market became extremely volatile. This committee’s responsibility is to make decisions about the Company market transactions activities. From its minutes it appears that the Risk Management Committee regularly reviews the surplus and deficiency status of the Company along with current market prices and conditions. The status of system hedging was a topic of discussion at most meetings. The meeting minutes also reflected committee discussions about current market conditions and the unusually high prices.
It was not until the first of August, however, that the minutes reflect consideration of any options other than market purchases. This planning based on the Risk Management Committee minutes is detailed in Staff Confidential Attachment No. 6.
Staff also reviewed minutes of meetings of Idaho Power’s Board of Directors. The Board meets approximately every two months. The meeting minutes regularly indicate discussions about the position of the Company from an operational as well as financial standpoint. Past weather conditions, weather forecasts, Brownlee inflows and snowpack conditions are always presented. It is not apparent until January 17, 2001 that any discussion took place concerning the impacts of the high market prices on the Company, or any plans to pursue supply and demand side options.
f. Idaho Power’s Obligation to Ratepayers
Staff believes that Idaho Power has an obligation to provide quality service to its customers at the lowest possible cost. Idaho Code § 61-301 requires that utilities’ charges be "just and reasonable." Idaho Code § 61-302 further requires that utilities maintain adequate service. In addition, Staff believes that implicit in each utility’s certificate of convenience and necessity is a requirement that the utility make every effort to provide the best service possible at reasonable costs, and to conduct its business in a manner that is in the best interests of the customers it is responsible for serving.
Furthermore, Staff believes that Idaho Power has generally fulfilled its obligation as evidenced by its past record of planning and acquiring resources. The Company has, for many years, planned to meet its short-term deficits and those deficits caused by low water conditions with purchases from the market. In recent years, Staff has warned of the increased risk of heavy reliance on the market. While the Company’s reliance on the market was successful in the past, it proved costly to ratepayers in recent months. Idaho Power had no contingency plans already developed once market prices rose. Furthermore, it was slow in developing them. Unfortunately, much of the damage had already been done before plans were prepared to introduce buyback programs, load management strategies, and new generation. Staff believes that much of this current crisis could have been avoided had the Company depended less on the market.
Nevertheless, Staff believes some continued reliance on the market still may be a reasonable and least cost strategy to meet certain load requirements in the future. However, now that the risks of relying on the market have been demonstrated, plans must be made to safely manage these risks. Markets change quickly and Idaho Power must develop the ability to react in a timely, cost effective way in order to minimize this risk.
g. Conclusions
Based on a review of Idaho Power’s long term and short-term planning activities, NERC and WSCC reliability assessment reports, Power Planning Council reports, and the meeting minutes of its Risk Management Committee and its Board of Directors, Staff concludes the following:
Idaho Power consistently planned, on a long-term basis, to meet seasonal and short-term deficits with purchases from the market. The Company also planned to rely on the market to meet deficits resulting from low water conditions. The Company's purchases from the market this winter were exactly according to its long term integrated resource plans. However, the Company did not expect and did not plan for extremely high market prices even though Staff repeatedly raised questions about the risk associated with market reliance.
Reliability reports of the WSCC and NERC clearly indicated that supply shortages could occur, and under certain circumstances were likely. Although the WSCC and NERC traditionally focus on adequate supply, Staff believes it would have been reasonable to conclude that market prices would be correspondingly high. The WSCC and NERC reports predicted shortfalls as long as five years ago, and included increasingly severe warnings in all of their recent reports.
Reports prepared by the Northwest Power Planning Council in the spring and fall of 2000 contained warnings about supply problems expected to occur in the near term, along with warnings to expect very high market prices.
Idaho Power’s Risk Management Committee, in the face of extremely high market prices this winter, chose to plan on a monthly basis and rely solely on market purchases up until mid-December 2000. The Committee did not begin considering other options to mitigate the effects of high prices until mid-January, and did not take any serious action until the beginning of February. Staff believes that there were numerous signals that should have caused the Company to act sooner. While most of the current programs and actions of Idaho Power are probably appropriate, they were late in coming.
The Company should provide the Commission with a report outlining short-term plans for the summer and winter of 2001. The report should show projected loads, anticipated traditional resources, resources acquired to reduce market exposure, energy provided by each resource, costs, paid for each resource, surplus/deficit energy for summer loads, market resource plans and anticipated cost.
3. AUDIT OF ACCOUNTS AND TRADING ACTIVITY
a. Discussion of the True-Up
Commission Staff audited the True-up portion for the combined filings. Staff reviewed the supporting documentation, filed reports, Board of Director Minutes for Idaho Power Company and IDACORP, and Risk Management Committee Minutes. Staff has concerns with the data inputs to the PCA calculation worksheet, specifically with the Non-Firm Purchases (line 19) and the Surplus Sales (line 20) found in Company Exhibits 1 and 3 of the Case Nos. IPC-E-01-07 and IPC-E-01-11 filings, respectively. In the audit, Staff found that the pricing mechanism for sales and purchases between the operating book and the non-operating book no longer represents an acceptable way to price the transfers included in the PCA filings.
b. Pricing Methodology for Transactions between the Idaho Power Operating
Book and the Idaho Power Non-Operating Book
The operating book represents energy sales and purchases and related transactions for operating purposes of Idaho Power to match regulated system load and resource requirements. The non-operating book represents transactions identified by the Company as those not undertaken to meet system requirements and those made for speculative purposes. This Commission does not directly regulate non-operating transactions.
1. Dow Jones Mid-Columbia Electricity Index
The Company has used the Dow Jones Mid-Columbia Electricity Index (Mid-C) to price day ahead transfers between the Idaho Power Operating book and Non-Operating book. The Mid-C price is defined as the weighted average price of electricity traded at Mid-C, calculated from the electric energy traded for delivery at Mid-C, quoted in dollars per megawatt hour, with the volume in megawatt hours. The Company includes an adjustment to the Mid-C price for transmission between the actual point of delivery and Mid-C.
2. Background
Staff audits the inter-company transactions for the energy-trading portion of Idaho Power in each PCA. As part of Case No. IPC-E-99-3, the implementation of Emerging Issues Task Force (EITF 98-10) provided the initial separation between energy sales and purchases for operating and non-operating purposes for January – March 1999. In that case, Staff accepted the separation for those three months since it was an improvement from no separation and a better method was not identified. Staff also stated that “Due to the potential impact on the PCA of the classification of energy transactions as operating or non-operating, Idaho Power’s classifications and procedures should be reviewed in every PCA case.” (Order No. 28049, page 2.)
In Case No. IPC-E-00-6, the Company filed their Power Cost Adjustment filing for the months April 1999 through March 2000. In Case No. IPC-E-00-6, Staff stated:
During the Utilities Division Staff audit of the true-up portion of the PCA filing, utilities Division Staff audited the non-operating power marketing transactions, along with the operating power marketing transactions and is satisfied that the accounting and reporting procedures in place in reference to Energy Trading are sufficient to provide reasonable results in the Power Cost Adjustment.

At that time, Staff found that using the Mid-C price as the pricing mechanism for day ahead transactions between the operating book and the non-operating book was reasonable. At that time, Staff found that using the Mid-C price was acceptable because it was independent and it closely followed what the Company was actually paying for power purchases, and actually charging for power sales in the day ahead market. Staff determined the prices that the Company both paid and received formed a narrow band around the Mid-C price for the April 1999 through March 2000 PCA year.
c. Current Combined PCA Filing
Based on the information available currently for the combined filings, Case Numbers IPC-E-07-01 and IPC-E-11-01, the Mid-C no longer is reflective of prices paid for power purchases or received for power sales by Idaho Power/IES. The electric market has changed and it appears that Idaho Power/IES has changed its operating activities.
Staff is concerned that Idaho Power has substantially limited long-term power contracts (i.e., in excess of one month) for the system-operating book. The ability to purchase power at a fixed price is a valuable tool for rate stability. In the past, the Company has purchased large amounts of power at relatively inexpensive prices to serve its load. For the month of February 2001, only one contract was for system-operating power purchases that was over a month in length. The Company contends that it is not using long-term contracts because the prices are no longer as favorable as they once were. Staff is concerned with the Company’s apparent failure to properly hedge when shortfalls are known.
However, it is clear that the Non-Operating System continues to use these contracts to its advantage. For example, in the months of June 2000 through August 2000, 30.5% of the Company’s purchases were term purchases of one month or more and 60.2% were day ahead. In the months of January 2001 and February 2001, 15.2% of the Company’s purchases were long term and 70.3% were day ahead. The System is relying heavily on the more expensive day ahead markets than it once was. This is one factor that Staff believes has contributed to the overall increase in costs to ratepayers.
The Company trades electricity for both the system (operating) and for speculative purposes (non-operating). In the past, the Company has used the Dow Jones Mid-C indexes as a surrogate price for the day-ahead contracts for the system. The surrogate was accepted because the actual prices were symmetrical and in a narrow band around the Mid-C index price for the months April 1999 through March 2000.
During the audit of the current filings, Staff found that the Mid-C prices no longer reflects what the Non-Operating System is paying for the power it supplies to the System. There are three primary reasons Staff believes the transfer price should be adjusted and the pricing mechanism reviewed to determine the proper mechanism going forward:
The trading floor is not legally a separate entity at this time. Thus, IEA is part of the regulated utility.
The nature of long-term power contracts and other transactions have changed, increasing the cost to the regulated entity.
Wheeling and transmission issues have not been properly classified to reflect the benefits that should belong to the customers of the regulated operations.

The Trading Floor
The Agreement for Electricity Supply and Management Services Between Idaho Power Company and IDACORP Energy Solutions, LP has not been approved by the Federal Energy Regulatory Commission (FERC) or the Oregon Commission. Therefore it is not in force per the terms of Order No. 28596 approving this Agreement in Case No. IPC-E-00-13. The conditions under which this Agreement was approved have changed and it is proper to make any necessary modifications to the terms of the Agreement before it is allowed to be in force. Likewise, the activities and transactions associated with this Agreement should be reviewed to determine the proper regulatory treatment.
Long-Term Power Contracts and Transactions
Staff conducted a thorough review of each individual transaction for the months of December 2000, January 2001 and February 2001. Based on this review, Staff discovered that the Non-Operating System purchased day-ahead power at a cost much lower than it transferred power to the system. The analysis shows that 155 out of 161 times (over 96%), the system paid more for the power than was paid by the Non-Operating System. (See Staff Confidential Attachment Nos. 7-10.) The Mid-C no longer represents a surrogate price for system power transactions consequently; the Mid-C pricing does not produce rates that are fair, just and reasonable.
For the months of December 2000, January 2001 and February 2001 Staff has re-priced the day-ahead power purchased from the Non-Operating System to the System at the daily weighted average price paid by the Non-Operating System. That way, the System pays exactly what the Non-Operating System pays. The Non-Operating System should not be allowed to profit substantially from the regulated system. Staff believes that the weighted average price is fair and reasonable. It provides incentive to make sure that all trades are sound and reasonable for both the system and non-system transactions with minimal ability to game or manipulate the price. Substantially greater margins on similar transactions for a non-regulated entity compared to a regulated entity is an indicator of an improper pricing mechanism. The magnitude of this adjustment is shown on Staff Confidential Attachments. Staff Confidential Attachment No. 7 shows the daily record for December 2000, Staff Confidential Attachment No. 8 shows the daily record for January 2001, and Staff Confidential Attachment No. 9 shows the daily record for February 2001.
Consistent with the adjustment for the detailed audit for the three months listed above, Staff determined that the rest of the day ahead power for the PCA year should be re-priced using a weighted average monthly price. While not as precise as a daily price, Staff believes it is fairly representative. These months were not audited on a day by day basis due to time constraints. The months of August and September 2000 did not have adjustments, the transfer prices were already at the lower of cost or market, when compared to the weighted average monthly price for purchases, and at the higher of cost or market for sales. This adjustment is shown on Staff Confidential Attachment No. 10 for the months of April through November 2000.
Staff has made adjustments to the day ahead transactions for the months of April 2000 through February 2001, with the exception of the months of August and September, and included them in the Non-Firm Purchases and Surplus Sales, Lines 19 and 20 of the PCA calculation on Company Exhibits 1 and 3 of Case Nos. IPC-E-01-07 and IPC –E-01-11, respectively. The net adjustment, before the jurisdictional and sharing allocations, and without the effect of interest on the deferral balance for the day ahead transactions is ($61,467,386.84). This represents a benefit to the customer. The calculation is summarized on Staff Attachment No. 13.
In December 2000, the Company changed the way the Real Time Transactions were priced. In the past, the transactions always flowed through the system at their actual cost. Now, however, the transactions are priced based on the weighted average price of all real time transactions that touch the Idaho Power system on an hourly basis. According to Staff’s analysis, this has also resulted in overcharges and underpayments in several cases. Staff has re-priced the real time purchase transactions for the months of December 2000 through February 2001 to the lower of the Non System’s cost or market price. Staff has also re-priced the real time sale transactions for the same months using the higher of sales price or market. Staff believes that purchases and sales should be kept separate and that the system should get the benefit of the best price.
The Staff made adjustments to the inter-book real time sales and purchases for the months of December 2000, and January and February 2001. The net adjustment, before the jurisdictional and sharing allocations, and without the effect of interest on the deferral balance, for the real time transactions are ($4,666,381.95). This represents a benefit to the customer. The calculation is shown on Staff Confidential Attachment Nos. 7-10 and summarized on Staff Attachment No. 13.

Classification of Wheeling and Transmission Issues
Staff is concerned that the Non-Operating System is currently profiting from resources that have been provided by ratepayers without proper benefit or compensation to the regulated utility and its customers. An example of this is the use of the transmission network. The Non-Operating System trades a great deal of power that flows through the utility transmission system or relies on the system. If the ratepayers had not paid for the system through regulated rates, the profits for the unregulated trading would be limited. One way the unregulated side of the Company makes money is through the use of a transaction known as a “flip” which requires the receipt of energy at one point and the delivery of energy at another point. This transaction is possible for the unregulated system to perform because of the utility network system. However, the ratepayers that have and continue to pay for the utility network receive nothing. Regulated assets are being used by a non-regulated affiliate without benefits or compensation.
There is precedent to require a sharing of these profits. For example, Intermountain Gas Company passes on to ratepayers the profits from excess capacity that was sold to industrials as segmentation credits in the PGA. The Company marketer, IGI Resources, receives a small amount of the total sale for arranging it.
d. Risk Management Committee
Staff has concerns regarding the Risk Management Committee (Committee, RMC). The RMC maintains general oversight of all energy commodity trading and financial risk for Idaho Power and all the subsidiaries of IDACORP. The Committee consists of the senior officers of IDACORP. The Committee meets regularly to review the profit and loss reports, exposure reports, strategies and program objectives. Decisions of the Committee are made by a simple majority and recorded in the minutes. Minutes are kept and were reviewed by Staff.
According to the Company’s policy, to carry out these responsibilities, the Committee will:
1. Establish the parameters for credit risk, market risk, and other pertinent exposures.
2. Monitor trading activities.
3. Ensure development and communication of trading policies and procedures.
4. Ensure appropriate internal control procedures are established.
5. Specify commodities, and derivative instruments to be utilized.

After a review of the Committee minutes, Staff determined that the Company follows these guidelines in almost all cases. The Committee members meet, analysis is presented that the system is short or long, and the Committee makes a decision regarding the purchases and sales as needed. The purchase and sale information is sent to the energy traders via email and the traders carry out the orders of the RMC immediately. The RMC has all the responsibility to make sure the system has the resources necessary and that they are obtained in the best manner possible.
Staff is concerned that the RMC consists of the same members for both the utility and for the non-regulated operations. Staff review of the RMC minutes indicates that the Committee does not consistently support a mandate to first take care of the system needs before the non-regulated operations, even though this is the stated policy. Based on a review of the minutes, Staff believes that the RMC does not focus enough energy on the utility and as a result, system costs are higher than they otherwise would have been. Evidence of this is presented in Staff Confidential Attachment No. 11 along with the lack of system forward long-term power contracts. Staff has adjusted the amount of the purchased power expenses in January 2001 by the $10,288,386, as shown on Staff Confidential Attachment No. 12, that would have been saved if the RMC had completed the directive.
The Company was initially questioned about the trading floor’s failure to purchase forward for the system as authorized by the RMC. Staff was told on April 4, 2001, by Sharon Hoyd, General Manager of Merchant Finance, that the RMC had failed to communicate to the traders the orders of the RMC to purchase the power. At that point, Staff asked Ms. Hoyd to provide that response in a written format for the files. She assured Staff that the information would come quickly. However, it was not until April 10, 2001 that a written response was received. The response came from Darrel Anderson, Vice President of Finance and Treasurer. According to the offered “reconciliation” (without backup) Mr. Anderson stated that what really happened was that after the first recommendation to purchase power was approved, the RMC changed their minds at the same meeting and decided to not purchase the power after all. According to Mr. Anderson, a motion to that effect was made and passed, yet the person taking the minutes failed to put the second motion in the minutes. Staff believes there are several facts that cannot be overlooked when deciding the ratemaking treatment for these actions.

According to responses to Staff Audit Requests 36, 49 and indirectly referenced in other responses, the system was in a short position for December for all scenarios except normal water.

If the RMC had seconded and passed another motion to not purchase the power, it seems Ms. Hoyd would have remembered that her original recommendation was first accepted and then rejected by the RMC.

Staff has reviewed the analysis presented by Ms. Hoyd for the system needs and it was clear in November that the system would be short in January. Prices were low and there was no conceivable reason to not make those purchases as soon as possible.

The Company was not able to provide to Staff any explanation as to why there would have been another vote after the power purchase had been approved. In other words, the analysis only supported the purchase. There was no analysis presented that showed that the power should not be purchased because it was obvious that even under ideal circumstances the system needed that power.

One explanation as to the lack of discussion in December about January needs is that the RMC believed the purchase had already been made. If in reality the RMC did not authorize the purchase of the power for January, it would know that January would be significantly short. Something else would have needed to be arranged. Nothing else would have been arranged if the RMC thought that it had already been covered.

It is not unheard of for the RMC to change recommendations as information and needs change. In the meeting on February 6, 2001, the RMC made and approved a motion that superseded a motion approved on February 2, 2001. However, this motion was made after new information was obtained and it was clearly recorded in the minutes. In the case of the November meeting, there was no new information cited and there was nothing in the minutes.

Standard procedure dictates that the minutes are reviewed and approved before being put on the record. If an omission of the magnitude suggested by Mr. Anderson actually occurred, someone on the RMC should have noticed and the minutes should have been changed.

If the second vote was made to cancel the forward purchase, no documentation has been presented to justify the change in decision.

It is clear to Staff that an error has been made. It is irrelevant to customers whether RMC changed its vote or whether RMC simply failed to notify the traders with an email authorizing the purchase. All the documentation supports a forward purchase of power for the system. Rationale for a change of vote has not been provided. It is reasonable for Staff to adjust the purchase power expense to reflect the purchase as if it had been made. To do otherwise would pass the result of improper procedure on to customers at their expense. The result of this error should be recorded below the line.
e. Teknecon Energy Risk Advisors, LLC (TERA)
To assist in reviewing the reasonableness of the marketing relationship and the pricing mechanism between Idaho Power and IES, Staff retained the consulting services of Teknecon Energy Risk Advisors, LLC (TERA). Numerous concerns were discussed in the limited time available. The report by TERA on these issues is attached as Staff Confidential Attachment
No. 19. It has been filed as confidential to allow Idaho Power the opportunity to verify that the information is not confidential. Staff anticipates the report will be made public on April 20, 2001.
f. Staff’s Recommendation for Pricing
Staff recommends for the current filings that the following pricing mechanisms apply to all day ahead transactions:
1. Purchases by Idaho Power from the non-operating book for the system should be priced at
the lower of cost or market. Staff recommends that the market price continue to be based on
the Mid-C price or another acceptable pricing mechanism approved by the Commission.
Staff further recommends that the cost be based on the actual cost of the power, using a daily
weighted average of the price actually paid for the power by the non-operating book to third
parties.

2. Sales from Idaho Power from the operating book to the non-operating book should be priced
at the higher of cost or market. Staff recommends that the market price continue to be based
on the Mid-C price or another acceptable pricing mechanism approved by the Commission.
Staff further recommends that the cost be based on the actual price of power sold to third
parties.

These pricing recommendations will provide the ratepayer with the assurance that they will not pay rates based on prices that are unfair, unjust and unreasonable. However, Staff recognizes that these recommendations differ from the practice established in IPC-E-00-13. The contract has not been approved by FERC, the current review shows the procedure may no longer be reasonable and should be modified before it is implemented. To facilitate the changes, Staff recommends the final pricing decisions be made in another phase of this case or that a separate case be opened.
The Staff adjustments, before application of the jurisdictional allocations and the sharing allocation, total $76,422,154.79. This amount also does not take into consideration the effect that the adjustments have on the interest accrued on the deferral balance. The final Staff recommendation is shown on Staff Attachment 2.
Staff recommends the adjusted amount of $10,286,154 be recorded below the line as a non-system adjustment. Staff also recommends that the remaining $66,136,000 be deferred below the line without interest until the second phase or a separate case on pricing can be concluded. The Company, Staff and other parties should meet to discuss the ongoing pricing mechanism and compensation to the ratepayers for the use of regulated assets using these comments and the TERA report as the starting point.
4. RATE DESIGN ISSUES AND THEIR PROPOSED IMPACT
PCA adjustments have historically been passed through equally to all customer classes on a uniform cents-per-kWh basis. Due to the magnitude of the proposed increase in this case, Staff has examined three alternate methods for passing through the PCA surcharge. In each method, the increase would be spread on a cents-per-kWh basis. Staff considered each method in light of its fairness, its ability to be understood and implemented, and its ability to encourage conservation. The three alternatives that were considered were:
A uniform increase in cents-per-kWh for all usage.
This is the method that has historically been used to pass through the PCA surcharge. It is simple and it sets an equal value on all energy.
An increasing block rate based on each customer's historical usage.
The historical method may send a stronger conservation message than the uniform increase because each customer will have an opportunity to remain at a lower block rate. This rate design is also advantageous because each customer has a base that reflects their individual historical energy requirements. Furthermore, it can mitigate high energy costs for low-income ratepayers by offering a block of relatively inexpensive power. It however could be a disadvantage in that it may be somewhat cumbersome to administer. Customers that have already made their home or business efficient and those that lack the financial means to install conservation measures could be disadvantaged by this method. While this method has some inequities, it is based primarily on the fact that each customer has the responsibility to conserve energy for the benefit of all ratepayers and should therefore be rewarded when consumption is reduced.

An increase spread through three inverted blocks.
This method gives each customer an equal share of the lower cost energy from base load generation. That share is equal to the first block. If usage exceeds the first block, the Company is required to run more expensive generation. As load increases, it becomes increasingly more expensive to serve. The last resources available are market purchases, which are very expensive.
a. Residential Rates
All three alternatives were considered for the residential customers. The detail of each method and how each would affect customers at various usage levels are shown in Attachment 16 and discussed below. The customer charge of $2.50 would not change under any proposal and was therefore excluded from the analysis.
1. Uniform Increase
A uniform increase in cents per kWh is simple to implement and understand. Under the Staff proposal, rates would increase uniformly by 0.9883 cents/kWh, from a base rate of 4.9303 cents/kWh to 5.9186 cents/kWh. As shown in Attachment 16, all rates would increase by 20%. An average customer using 1200 kWh per month would see their bill increase from $59.16 to $71.02.
2. Historic Block Rate
In this method, base rates would increase by $0.7906 cents/kWh for usage at or below 90% of a customer's historical usage. For usage that exceeded 90% of historical consumption, rates would be increased by $2.7672 cents/kWh, resulting in rates of 5.7 cents/kWh and 7.7 cents /kWh respectively. If a customer’s usage does not change from historical they would see a 20% increase no matter how much they use. By example, if a ratepayer's monthly usage increased from 1000 to 1200 kWh, their bill would increase from $59.16 to $72.40 or 22.4%. If a ratepayer's usage decreased from 1400 kWh to 1200 kWh, their bill would go from $69.02 to $68.40 or a decrease of 1%.
The inverted rate design based on residential historical use has some appeal for a number of reasons. The first block would be based on each customer's unique circumstances and compare an individual customer’s monthly use with their use in the same period a year ago. Large users would not necessarily see any greater increase than smaller users. Only a customer’s inability to conserve would determine if they would have to pay the higher rate for some of their use. However, over 20% of the customers are estimated to not have a billing history at the same location. It is not clear what would be an appropriate base to use for these customers. The Company also reports that setting up the billing for this method would be difficult and could take an estimated six weeks. For these reasons this method would be more difficult to implement and administer.
This method also may have some equity concerns because each customer base is set on historical use. A customer who has historically been wasteful will find it easier to conserve and obtain a smaller increase. On the other hand a customer who has already made their home very efficient, or one who lacks the means, may find it difficult to make significant changes that would save energy. The customers who are least able to deal with the increase may be the ones who will be hardest hit by it. Customers who heat with natural gas fall into this group. These customers have seen their gas rates increase last year by approximately 60% and may find it difficult to reduce their electric consumption. Their energy uses for refrigeration, cooking, etc. may be less elastic than heating and thus make it more difficult to achieve a 10% reduction.
3. Inverted Three Block Rate
The three-tier inverted block rate increase under Staff's proposal would result in differing rates depending on usage. For usage between 0 and 800 kWh, rates would increase 0.593 cents/kWh over base rates. For usage between 801 and 2000 kWh, rates would increase by 1.186 cents/kWh. Rates would then increase by 2.5481 cents/kWh for all usage over 2000 kWh. The resulting rates would be 5.5, 6.1, and 7.5 cents/kWh respectively. An average customer using 1200 kWh would see a 16% increase in their bill, from $59.16 to $68.65.
Staff believes that the three-tiered inverted block method would give a clear conservation signal and would be easier to implement and administer than the historical block rate. It would impact the large users, namely the electric space-heating customers, with a larger share of the increase.
Of all the energy requirements for a residential customer, space heating is the single largest energy requirement. In the last two years the cost of space heating has increased dramatically for all fuels except electricity. Today, the electric residential rate is actually lower than it was two years ago. Attachment 17 takes a look at the total energy picture of natural gas and electric space heating residential customers. While the electric space heating customer’s energy costs have decreased over the last two years, the energy cost of the natural gas space heating customer has increased by 32%. Attachment 17 also compares the effect that the various PCA rate methods would have on these different space heating customers. Under a uniform rate increase and historical block rate increase, the electric heating customer would see a 5% increase in their energy cost over two years ago. The natural gas heating customer will see a 40% increase.
The vast majority of the power costs in this PCA were incurred during the heating season. Electric space heating was a primary cause of the winter peak and the required market purchases. Only the three-tiered method shifts some of the cost increase to the electric space heating customer, resulting in a 8 to 15% increase to heat pump and resistance space heating customers respectively and a 37% increase in total energy cost to the natural gas space heating customer. For these reasons Staff believes the three-tiered inverted block rate is most appropriate for the residential class.
The results of a bill frequency analysis are shown in Attachments 14 and 15. Attachment 14 shows, for each month, the number of bills that occurred in each of three billing blocks: zero to 800 kWh, 801 to 2000 kWh, and over 2000 kWh. For the year, 44% of the bills occurred in the first block, 43% in the middle block and 12% in the last block. It is clear from looking at the last block that most of these bills occurred in the winter months as a result of space heating demand. There was a much smaller peak in August that presumably was driven by air conditioning load.
Attachment 15 shows that the vast majority (59%) of the kWhs were billed in the first block, 31% of the kWh are billed in the middle block and only 11% in the last block. Again, the majority of the kWh, in the last block occurred in the winter months.
b. Non-Residential Rates
Staff recommends that all rate schedules, except the residential schedule 101, be increased on a uniform cents-per-kWh basis. The historical block rate puts the efficient business at a disadvantage and would reward inefficient operations. The commercial and industrial schedules include a very diverse group of customers and it is not clear how an inverted block rate would affect them. Without an extensive analysis to predict the impact, there is concern about possible unintended consequences. There does not appear to be a clear justification for pricing some of the energy used by a large commercial customer at a higher rate than the energy used by a small customer. A small operation may be able to achieve a 10% reduction in energy use just as easily as a larger user. These customers are fairly sophisticated and the uniform method will provide clear message to conserve wherever it is cost effective. Dealing with the magnitude of this increase will be a significant burden to Idaho businesses and the increased uncertainty of an inverted block rate does not seem to be warranted at this time
c. Conservation Program
Staff proposes that the Company offer a low interest loan program to all its customers for the purpose of energy conservation measures. Staff recognizes that this may be beyond the scope of this proceeding, but feels that it is important to give customers the necessary tools to deal with this increase and to reduce the Company's need to purchase high-priced market power.
The Commission has recently approved a number of Company programs that buy back energy from various customers. The notion of demand side management (DSM) to reduce the need for generation is well established. Although Staff has not worked out the details of this proposal and has not calculated the cost the proposal, we believe that a low interest loan program would be most appropriate at this time and suggest that Staff could work with the Company to develop a workable program.
The IDWR Energy Division reports that in the first three months of 2001 they have approved 300 energy conservation loans. This exceeds the 176 loans that they issued for the entire year of 2000. It is apparent that even before the rate increase, many consumers are interested in efficiency improvements. Staff believes that all customers should be given every opportunity to conserve. Regardless of the pass through method chosen by the Commission. Price signals will be sent to provide incentive for conservation. However, Staff believes that there are still two major barriers to conservation: lack of information and capital.
Consequently, Staff recommends that the Company help reduce these barriers by providing informational assistance and a loan program that would allow customers to borrow at a low interest rate with low initiation fees and amortize the loan over the life of the installed conservation measure. Any viable conservation measure for all classes would be eligible. In effect, this would be a buy-back program offered to all the remaining customers. Customers would then be empowered to reduce their energy use, saving on their bill and reducing the utilities dependence on the market. Staff would be willing to work with the Company to develop a loan program and discuss cost recovery methodology.
Similarly, House Bill 251, recently signed by Governor Kempthorne, allows public building managers to enter into energy saving performance contracts with energy service companies. The contracts allow the entity to upgrade facilities, making them more energy efficient with no up front capital costs. The energy service companies guarantee that the energy savings will pay for the cost of the upgrade. In effect, the utility would be offering a similar service to its customers through the proposed loan program.
In sum, The customer could choose some efficiency upgrade on their home/business that would result in sufficient savings to pay for the upgrade. Their utility bill would be less and the utility would have lower purchased power costs. Staff is confident that this would be an effective tool for customers to reduce their bills and to assist the Company in further reducing their dependence on the market.
5. CUSTOMER NOTICES AND COMMENTS
Customer Notices
When Idaho Power filed its Emergency Energy Charge Application in Case. No. IPC-E-01-07, the accompanying customer notice and the press release both met the requirements of Utility Customer Information Rule No. 102, Notices to Customers of Proposed Changes in Rates (IDAPA 31.21.02). The customer notice was included with bills generated from February 26, 2001 through March 22, 2001. Although the press release filed with the Company’s PCA Application in Case No. IPC-E-01-11 met Rule 102’s requirements, the accompanying customer notice omitted the total dollar amount ($66,457,817) of the requested increase. Because this information is required by Utility Customer Information Rule 102, Idaho Power added a bill message to include the previously omitted total dollar amount of the requested increase. The original customer notice inserts and bill message were included with the billing cycle that began on March 23, 2001 and ends on April 23, 2001.
Written Public Comments
As of April 13, 2001, the Commission had received 233 individual written comments regarding the combined PCA filing and 17 petitions containing a total of 303 signatures. All but ten comments filed object to the increase. Customers noted the rise in natural gas rates, were aware of the California energy crisis and expressed concern for the impact a large electric rate increase would have on Idaho Power customers. Many individuals indicated they thought greedy power companies contrived to increase regional power market prices. Many of the issues raised in the written comments were also discussed at the public hearings and in the section below. In addition to the written comments filed, Consumer Assistance fielded nineteen (19) calls -- all were opposed to the proposed rate increase.
Public Hearing Testimony
To gather public input on the combined PCA filing, the Commission held workshops and public hearings in American Falls, Pocatello, Twin Falls, Caldwell and Boise. Approximately 105 people attended the five workshops and 118 people observed the four hearings. Of those who attended, 41 people testified at the hearings. Many testified they were concerned about the magnitude of the increase and the impact it will have on ratepayers, especially in light of poor crop prices and increased layoffs. Business owners were concerned about their ability to pass increased power costs on to their customers and the impact it would have on their customers. Great concern was expressed about the many elderly, low-income and single mother customers that are more likely to suffer from the proposed rate increase. A few mentioned a trickle-down effect from increased rates that could have far-reaching effects, such as increased food cost. Numerous witnesses requested that the Commission spread any increase out over multiple years to minimize financial hardship to customers.
A considerable number of those who testified were connected to the agricultural industry, either as farmers or equipment suppliers. Most agreed that power was, by far, the largest expense in their budgets and that an increase of the magnitude proposed by Idaho Power would likely put some farmers out of business. Others would probably have to lay off some of their farm workers and delay planned equipment purchases. Several witnesses indicated that time-of-day meters might work for some, but not all, farmers.
Many witnesses questioned the amount of profit that Idaho Power contributed to IdaCorp’s recent sizeable earnings. Although a few witnesses noted Idaho Power’s positive track record, several questioned Idaho Power's inability to see the need for increased generation given Idaho’s population growth and the potential for drought.
To increase generation capacity, some suggested that more hydropower projects be initiated. Other witnesses observed that more non-fossil fuel alternative generating sources should be considered. A few witnesses favored raising the rates paid to co-generators, which are currently based on avoided costs for PURPA contracts, as an incentive for more generation by small producers. Several witnesses also stated that Idaho Power needs to re-initiate conservation programs.
Assistance Programs
Given the rising cost of energy, many people are justifiably concerned about consumers' ability to pay. According to a report issued by the Economic Policy Institute, one out of every three full-time, year-round jobs in Idaho paid wages that put a family of four below the poverty line in 1999. Although the share of jobs that paid poverty-level wages declined over the 1990s, Idaho still has a larger share of poverty-wage jobs than the national average. The Center on Budget & Policy Priorities and the U.S. Census Bureau have noted that poverty in Idaho is decreasing more slowly that the nation as a whole. Idaho is also one of a handful of states in which the rate of those having no health insurance is rising while the rate nationally is falling. Medical expenses are a frequently cited contributor to utility account delinquencies, as people struggle to spread payments among creditors. Furthermore, several companies in the Idaho Power service territory have recently laid-off employees, including Astaris, INEEL, Boise Cascade, Hehr International, HomeBase, Cineplex Odeon, Micron Electronics, Hewlett-Packard and Jabil. For further population, unemployment, and poverty information, please review Attachment No. 18.
Although any rate increase granted will not be effective until after the 2000-2001 winter heating season, Staff is concerned about the availability of financial assistance to customers who are unable to pay their energy bills. The primary source of energy assistance is the Low Income Home Energy Assistance Program (LIHEAP). This year's program is currently scheduled to end May 31, 2001. However, the program’s end date may extended if it appears a need still exists in mid-May and there is still money available for assistance. There are no LIHEAP crisis funds available since all the funds were committed to non-emergency programs such as heating assistance and weatherization. For the 2000-2001 heating season, about $1,061,951 was paid to Idaho Power for 4,975 customers through February 28, 2001.
El Ada, the Community Action agency that serves low-income customers in Boise, Mountain Home and Homedale, expressed concern in late March about the number of utility customers it cannot assist with their utility bills since the Winter Moratorium ended on February 28, 2001. The LIHEAP grant is simply not enough, in many cases, to keep utility service from being disconnected. Although Health and Welfare increased the income eligibility guidelines from 133% to 150% of the National Poverty Level on March 1, 2001, the average benefit grant of $227 was not increased. El Ada reports that cumulative utility bills at the end of the shut-off moratorium period range between $400 and $800, with a high end of $1,000. According to the agency, during one three-day period sixteen families (a total of 45 people--24 children, 5 disabled and seniors, and two terminally ill people) were unable to get their utility service restored. Currently no financial assistance is available if the LIHEAP grant, in combination with other funds that the agency has, is not enough to keep the utility service on. It should be noted that Idaho Power made a $44,000 contribution to El Ada for its weatherization program, but that money is not available for energy assistance.
Idaho Power sponsors Project Share, a fuel-blind energy assistance program administered by the Salvation Army. It is primarily funded by contributions from Idaho customers for a maximum benefit of $150 from October through April. El Ada reported that Project Share received $6,600 in donations for energy assistance on March 1, 2001 but that the entire amount was committed by the end of the day. Project Share currently turns away an average of 35 calls per day. Some emergency assistance is available during the summer and is handled on a case-by-case basis. Idaho Power recently made a contribution of $100,000 to Project Share, but it will not be available for distribution until next October. Other energy assistance providers, such as Sacred Heart and St. Vincent's Church Services, were able to help 51 people last year. However, they are able to help fewer people this year because of the larger amounts needed to keep service connected. In some cases, disconnection is only delayed for 30 days.
Payment Arrangements
To help customers anticipate their power costs, Idaho Power offers the Budget Pay Plan, which allows customers to pay for projected annual usage in twelve (12) monthly installments. Idaho Power has 394,956 Idaho customers with about 47,181 of those customers participating in budget pay plans. The payment amount is normally reviewed and recalculated, if necessary, on the 12-month anniversary of the date the customer began the plan. Staff strongly recommends that Idaho Power adjust all the level payment plans this May to reflect any rate increase granted so that customers do not experience a shortfall.
Customers that are having difficulty paying their utility bill may also make special payment arrangements with the Company. Idaho Power has several payment options, e.g., Preferred Pay, Check by Phone, and electronic or online payment. The somewhat gloomy economic forecast coupled with the proposed rate increase require greater flexibility in Idaho Power Company's collection policies. Although Idaho Power has a good track record of working with customers, it will need to be increasingly flexible and creative in making payment arrangements that are within the customer's ability to pay.
Conservation
There are many conservation and energy savings tips available through Idaho Power's web site located at: http://www.idahopower.com/. Idaho Power may also be reached by telephone at 1-800-488-6151. Additional links to energy issues and conservation sites may be reached through the Public Utilities Commission web site found at: http://www.puc.state.id.us/. Moreover, some of the written comments suggested the Commission consider conservation-friendly rate designs like block rates and time-of-use rates.
Recommendations
Although a gloomy economic picture cannot be used as a reason to deny a rate increase that is reasonable and justified, both the Public Utilities Commission and Idaho Power Company should be sensitive to the impact on customers and do everything possible to minimize the amount of the increase. Staff Recommends:
1. Idaho Power Company should comply with all the requirements of
Rule 102, Notices to Customers of Proposed Changes in Rates in the Utility
Customer Information Rules (IDAPA 31.21.02)
2. Require the company to adjust the Budget Pay plans to reflect the approved rate increase.

SUMMARY OF STAFF RECOMMENDATIONS
The Staff's recommendations are summarized as follows:

1. THE POWER COST ADJUSTMENT (PCA) MECHANISM
( Do not include the forecast in this years PCA rate adjustment.

( Apply 5% interest to the balance in the deferral account for all months of the 2000-2001 true-up.

( Use normalized 1999 Idaho jurisdiction firm load of 12,770,405 MWh to determine the rate.

( The PCA rate for the coming year be .9883(/kWh except for the residential class.

( Staff also recommends that if the Commission approves an overall increase
significantly greater than 20%, that it consider amortization of the increase over 2
years.

( This PCA rate increase should be effective May 16, 2001.

2. RESOURCE PLANNING
( The Company should provide the Commission with a report outlining short-term plans
for the summer and winter of 2001. The report should show projected loads, anticipated
traditional resources, resources acquired to reduce market exposure, energy provided by
each resource, costs paid for each resource, surplus/deficit energy for summer loads,
market resource plans and anticipated purchase cost.

3. AUDIT OF ACCOUNTS AND TRADING ACTIVITY
( Purchases by Idaho Power from the non-operating book for the system should be
priced at the lower of cost or market. Staff recommends that the market price
continue to be based on the Mid-C price or another acceptable pricing mechanism
approved by the Commission. Staff further recommends that the cost be based on the
a daily weighted average of the price actually paid for the power by the non-operating
book to third parties.

( Sales from Idaho Power from the operating book to the non-operating book should be priced at the higher of cost or market. Staff recommends that the market price
continue to be based on the Mid-C price or another acceptable pricing mechanism
approved by the Commission. Staff further recommends that the cost be based on the actual price of power sold to third parties.

( Staff recommends adjustments, before application of the jurisdictional allocations and
the sharing allocation, totaling $76,422,154.79. This amount also does not take into
consideration the effect that the adjustments have on the interest accrued on the
deferral balance. The final Staff recommendation is shown on Staff Attachment 2.

( Staff recommends the adjusted amount of $10,286,154 be recorded below the line as
a non-system adjustment. Staff also recommends that the remaining $66,136,000 be
deferred below the line without interest until the second phase or a separate case on
pricing can be concluded. The Company, Staff and other parties should meet to
discuss the ongoing pricing mechanism and compensation to the ratepayers for the
use of regulated assets using these comments and the TERA report as the starting
point.

4. RATE DESIGN ISSUES AND THEIR PROPOSED IMPACT
( Staff recommends an inverted three-block rate to spread PCA costs to the residential
class. The recommended rate for monthly energy consumption would be 0.593
cents/kWh for consumption of 800 kWh or less; 1.186 cents/kWh for consumption
between 801 and 2000 kWh; and 2.5481cents/kWh for all usage over 2000 kWh.

( Staff recommends a uniform increase of 0.9883 cents/kWh for all non-residential
customers.

( Staff recommends that Staff and the Company work together to develop a low interest
loan program to assist customers in implementing capital intensive, cost effective
energy conservation measures.

5. CUSTOMER NOTICES AND COMMENTS
( Idaho Power Company should comply with all the requirements of
Rule 102, Notices to Customers of Proposed Changes in Rates in the Utility
Customer Information Rules (IDAPA 31.21.02)

( Require the Company to adjust the Budget Pay plans to reflect the approved rate
increase.

Dated at Boise, Idaho, this day of April 2001.

_______________________
Lisa D. Nordstrom
Deputy Attorney General
Technical Staff: Keith Hessing
Rick Sterling
Terri Carlock
Alden Holm
Kathy Stockton
Dave Schunke
Nancy Harman

LN:gdk:i:umisc/comments/ipce01.7_11.Lnkhrpstcdesnh
Idaho Power supplies electricity to approximately 360,000 customers in southern Idaho.
Case No. IPC-E-01-07.
Case No. IPC-E-01-11.
In March 1993, the Commission authorized Idaho Power to file proposed Power Cost Adjustment (PCA) surcharges or rebates to take effect in May each year. Order No. 24806 (Case No. IPC-E-92-25).
In a good water year, Idaho Power may spend less money on spot market purchases than what is included in base rates. Under those circumstances, the money saved from decreased power purchases defrays retail rates in the next PCA.
The Company may recover 90 percent of the difference between the projected power cost and the Commission’s approved base power cost. Order No. 25880.
Typically this forecast is based upon an April 1st projection of April through July Brownlee runoff. Because the Commission requested that Idaho Power file its PCA early, the Company substituted a March 1st projection of the April through July Brownlee runoff.
[(132,938,867-73,079,128) x .85 x .9 = 45,792,700]

Order No. 24806
Order No. 28665
This practice was instituted to simplify the true-up calculation and adopts the interest rate extablished by the Commission at the beginnin of each calendar year.
9.883 mills/kWh is the equivalent of .9883 ¢/kWh.
The Company has subsequently indicated that the correct normalized 1999 Idaho Jurisdictional firm load is 12,770,405 MWh.

Order No. 25260.
Staff letter to Idaho Power, May 4, 2000, p.1.

Id. at p. 2.
Idaho Power IRP, June 29, 2000, p. 35. Case No. IPC-E-00-10.
Idaho Power IRP, June 29, 2000, p. 30. Case No. IPC-E-00-10.
Staff letter to Idaho Power, May 4, 2000, p. 3.
Order No. 28583 at p. 6.
Reliability Assessment 2000-2009, The Reliability of Bulk Electric Systems in North America, North American Electric Reliability Council, October 2000 at pp. 33-35.
Northwest Power Supply Adequacy/Reliability Study, Phase 1 Report, Northwest Power Planning Council, March 6, 2000 at p. 5.
Id. at p. 6.
Id. at p. 6.
Id. at pp. 6-7.
Id. at p. 7.
Study of Western Power Market Prices, Summer 2000, Final Report, October 11, 2000, Northwest Power Planning Council Document 2000-18 at p. 7.
Id. at p. 6.
Id. at p. 6.
Id. at p. 7.
. Comments of the Commission Staff, p. 4.
Although no public hearing was held in American Falls, those who attended the American Falls workshop could testify the following evening at the Pocatello hearing.
“The State of Working America 2000-01,” Economic Policy Institute. September 4, 2000.
The Idaho poverty rate decreased from 13.8% to 13.5% from the 1997-98 to the 1998-99 reporting year. The national poverty rate decreased from 13% to 12.3% during the same time period.
Idahoans without health insurance increased from 17.7% to 18.4% while the national rate of individuals without health insurance declined from 16.2% to 15.9% between the 1997-98 and 1998-99 reporting years.
This change in eligibility was retroactive to December 1, 2000.

STAFF COMMENTS 9 APRIL 16, 2001