26236.docx

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF IDAHO POWER COMPANY FOR AUTHORITY TO INCREASE ITS RATES AND CHARGES FOR ELECTRIC SERVICE TO CUSTOMERS IN THE STATE OF IDAHO BY INCLUSION OF THE TWIN FALLS PROJECT INVESTMENT AND THE ADDITIONAL SWAN FALLS PROJECT INVESTMENT IN REVENUE REQUIREMENT.
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CASE NO. IPC-E-95-5
ORDER NO. 26236
SYNOPSIS
On May 24, 1995, the Idaho Power Company (Idaho Power; Company) filed an Application for authority to increase its rates and charges for electric service in the state of Idaho by $6,309,116 to reflect the Company’s investment in its Twin Falls hydroelectric project as well as an incremental amount of investment in the Company’s Swan Falls hydroelectric facility.  On August 14, 1995, the Commission conducted an evidentiary hearing at the conclusion of which it issued a bench ruling increasing Idaho Power’s annual revenue requirement by $3,759,695 or 0.88%, subject to refund pending the Commission’s final determination in the matter.  This Order affirms our bench ruling and grants final approval of Idaho Power’s Application.  
BACKGROUND
On March 25, 1991, Idaho Power filed an application with the Commission in Case No. IPC-E-91-4 (the “91-4” case) seeking the assurance that the Company’s investment in its Twin Falls hydroelectric upgrade, once completed, would be included in revenue requirement.  The Company offered a “commitment estimate” of between $42,366,000 and $50,839,000, which it agreed would be the maximum amount of investment that it would seek to include in its revenue requirement.  
On July 22, 1993, the Commission issued Order No. 25021 in 91-4 recognizing that, in the ordinary course of events, Idaho Power would be allowed to recover in its revenue requirement, its prudently incurred investment in the Twin Falls project.  The Commission also accepted Idaho Power’s offer of a commitment estimate to serve as a cap on the amount the Company could ultimately include in revenue requirement for its investment in Twin Falls.  
Rosebud petitioned the Commission for reconsideration of Order No. 25021 on the basis that Idaho Power was favoring its own projects over other resources such as Rosebud’s proposed Mountain Home thermal project.  Rosebud contends that Idaho Power has refused to purchase the output of the Mountain Home project, under the rates and conditions Rosebud desires, pursuant to the Public Utilities Regulatory Policies Act of 1978 (PURPA).  That dispute is the subject of Case No. IPC-E-92-31 which is pending appeal before the Idaho Supreme Court.  On September 24, 1993, the Commission issued Order No. 25160 affirming Order No. 25021.  Rosebud appealed the Commission’s final Orders issued in Case 91-4.  That appeal is also pending before the Idaho Supreme Court.
Idaho Power commenced with the construction of the Twin Falls upgrade in approximately August of 1993.  At approximately the same time, Idaho Power was concluding work on the upgrade of its Swan Falls facility pursuant to Commission Order No. 23520.  The majority of the Company’s investment in the Swan Falls facility was included in Idaho Power’s base rates in Order No. 25880, Case No. IPC-E-94-5 the Company’s most recent general rate case.  Idaho Power made an additional investment in Swan Falls, subsequent to the cut-off date of November 30, 1994 used in that case, which it now seeks to include in its revenue requirement in this proceeding along with its investment in Twin Falls.
In its original Application, Idaho Power stated that its total investment in Twin Falls was $40,886,354 and that its additional investment in Swan Falls was $2,686,354, which would result in an increase to the Company’s revenue requirement of $6,309,116 or 1.48%.
On August 14, 1995, the Commission conducted an evidentiary hearing in this case.  At the conclusion of that hearing, the Commission granted Idaho Power’s request for an interim increase to the Company’s revenue requirement in the amount of $3,759,695, subject to refund pending a final determination by the Commission in this matter.  The Commission also granted Rosebud’s request to submit post-hearing briefing on the issue of whether any of Idaho Power’s investment in the Twin Falls upgrade should be included in the Company’s revenue requirement.  Briefs were ultimately filed by Rosebud and Idaho Power.  The positions of all those parties who actively participated in this case are summarized below.
Positions of Parties
Idaho Power Company:
According to Idaho Power, the Twin Falls project was placed into service on July 27, 1995.  Since that time, the Company asserts, the benefits attributable to the project, including lower fuel costs and increased surplus sales opportunities, have been accruing to Idaho ratepayers through the PCA mechanism.
The Company notes that Twin Falls was completed for less than the cap established by the commitment estimate, accepted by the Commission in 91-4.  The cap under the commitment estimate was $50,839,000.  Idaho Power is proposing an additional investment for Twin Falls of $38,288,324.  Thus, the final amount of Idaho Power’s actual investment in Twin Falls is $12,550,676 less than the cap offered by the Company and adopted by the Commission in Case 91-4.  In calculating the increased revenue requirement attributable to Twin Falls, Idaho Power utilized the 9.199% overall rate of return authorized by the Commission in the last general rate case.
Idaho Power states that the addition of Twin Falls will reduce power supply costs because when the plant is operating, it is either reducing fuel expense by displacing thermal plants, thus eliminating power purchases, or it is providing energy for surplus sales.  The effect is passed through to ratepayers through the PCA.  Idaho Power did not originally propose to adjust any of the base power supply costs in this proceeding.
Unlike Twin Falls, Idaho Power notes, the Company’s additional investment in Swan Falls does not have any effect on power supply costs because that plant is already in service and, therefore, is recognized in the PCA.  
Idaho Power proposes recovering the increased annual revenue requirement from ratepayers through a uniform percentage increase to all customer classes and special contract customers.  The Company further proposes to recover these additional revenues through uniform increases to demand and energy charges on the metered rate schedules and special contract customers and through uniform increases to the charges on non-metered rate schedules.  Idaho Power justifies its revenue allocation and rate design proposal on the basis that a general rate case was recently completed in which a cost of service study was performed and rate relationships among customer classes were changed significantly.  In addition, the Company notes that the overall effect on rates caused by the addition of Twin Falls and the Swan Falls increment is relatively small.
Commission Staff:
Staff agrees with Idaho Power’s request to factor the Twin Falls and incremental Swan Falls investments into revenue requirement, with some modifications.  First, Staff observes that by passing the benefits of reduced power supply costs attributable to Twin Falls through the PCA, ratepayers would only capture 90% of the total benefits because the PCA is structured to only pass through 90% of variations in costs over a base level annually.  Staff proposes that  all of the savings in normalized power supply costs associated with the Twin Falls upgrade should be included in base rates.  Factoring the savings into base rates, Staff contends, would also have the effect of offsetting costs immediately and not delaying a year.  Staff’s proposal would result in rates being based on a new power supply model run.  Idaho Power agrees with Staff’s proposed modification to base rates.
Staff also proposes using a different allocator than proposed by the Company for calculating the jurisdictional allocation of the increased revenue requirement.  The Company proposed the D10 allocator.  Staff proposed using the E10 allocator which was applied to the kWh tax for jurisdictional allocation purposes in the Company’s last general rate case.  The Company also agrees with this modification.
Finally, Staff agrees with the Company’s proposed uniform percentage revenue allocation and rate design proposals given the short amount of time that has elapsed since the last cost of service study conducted by the Company, as well as the fact that the amount of revenue increase involved is relatively insignificant overall.
Staff also made several proposed adjustments to the increased revenue requirements attributable to both Swan Falls and Twin Falls.  Staff made an adjustment to the Accumulated Reserve for Depreciation account for Swan Falls for the incremental depreciation that accrued since the last general rate case (No. IPC-E-94-5) in order to bring the reserve account up to the same point in time as the updated plant account.  This reduced revenue requirement by $520,786.
Finally, Staff proposed an adjustment to the revenue requirement calculation made by the Company to eliminate the effect of grossing up the tax deductible expense amount for taxes using the long-term debt component authorized in a prior Commission Order.  Staff and the Company ultimately agreed to use the composite cost of short-term debt resulting in a decrease to revenue requirement of $597,632.
Staff’s adjustments, to which Idaho Power agrees, result in an increase to the Company’s annual revenue requirement of $3,759,695 or 0.88%.
Idaho Irrigation Pumpers Association (Pumpers):
The Pumpers also object to simply flowing the power supply cost savings resulting from the addition of Twin Falls to the Company’s resource portfolio through the PCA because this would allow the Company to retain 10% of those benefits.  The Pumpers suggest that there are several ways to measure the cost saving effect of Twin Falls.  One possibility would be to measure the effect on the PCA as if the “actual firm load” was allowed to increase by the amount of the Twin Falls generation and keep the other net power supply costs the same as in the last PCA filing.  
The Pumpers’ primary recommendation is to use 23.5 mills/kWh as the target revenue reduction that Idaho Power should receive from increased sales associated with Twin Falls.  According to the Pumpers, the PCA could reflect as much as 12.87 mills of these savings.  The Pumpers propose, therefore, that the difference of 10.63 mills be passed on in the form of a credit in this case.  Multiplying this difference times the 159,800 MWH estimated to be produced from Twin Falls yields a credit of $1,698,674.
Rosebud:
Rosebud contends that the Twin Falls project is not used and useful and that Idaho Power’s investment in the project should not be included in Idaho Power’s revenue requirement.  The essence of Rosebud’s position is that certain changes occurred between the time Idaho Power filed its application in 91-4 and the commencement of construction of Twin Falls in August 1993, rendering the Twin Falls project imprudent.  Rosebud further alleges that Idaho Power had “knowledge” of these changes but did not bring them to the attention of the Commission.  
Specifically, Rosebud asserts that the resource balance used in the calculation of Idaho Power’s avoided costs changed; that the surrogate avoidable resource changed; that the adoption of a PCA for Idaho Power shifted risks from shareholders to ratepayers in a way that invalidates many of the assumptions on which the Commission’s decision in 91-4 was based, and; that impending changes in the regulatory compact under the Notice of Proposed Rule Making (NOPR) issued by the Federal Energy Regulatory Commission (FERC) in April 1995, invalidate other assumptions adopted by the Commission in 91-4.
Rosebud notes that in April of 1993, the Commission Staff used a first deficit year of 1997 in calculating an avoided cost against which to compare Twin Falls.  Rosebud contends that between that time and roughly 3 to 4 months later when Idaho Power commenced construction of Twin Falls, the Company somehow became aware that that deficit year and the avoided cost derived from it, were no longer valid.
Rosebud argues that “Idaho Power enjoys a relationship with the Commission that is very different from that of any QF developer” and that, because of that relationship, the Company has a high degree of accountability to the Commission.  This, Rosebud contends, means that Idaho Power must be expected to “alter its plans when conditions change.”  
Rosebud notes that Idaho Power proposed a first deficit year of 2006 in Case No. IPC-E-93-28 filed in December of 1993 and in the Company’s 1993 Integrated Resource Plan.  Rosebud responds to the Company’s argument that the 2006 date includes Twin Falls by stating that Idaho Power cannot “hide behind the same technicalities that might be invoked by a QF developer with a signed contract” and that the Company “unilaterally selects those resources that go into the least cost plan.”  Rosebud further argues that even removing Twin Falls from the Company’s first deficit year calculations only yields a new date of 2003, according to Idaho Power’s calculations.
Idaho Power proposed a new surrogate avoidable resource (SAR) in December 1993 consisting of a gas-fired, combined cycle combustion turbine (CCCT) with a capacity factor in excess of 90%.  Rosebud states that Twin Falls’ year round average capacity factor is only 42.7% which, Rosebud argues, is evidence that the Company knew that generation technology had changed and that Twin Falls was no longer a prudent investment.  Rosebud suggests that further support for its theory can be found in a Position Paper published by Idaho Power in September of 1993 which found that, based upon the Company’s 1993 IRP, the proposed Shoshone Falls upgrade “may fail to be cost effective when compared to a more stringent market standard.”  
Rosebud also refers to a portion of the Position Paper in which Idaho Power states, essentially, that firm, 90% capacity factor equivalent energy can be purchased at surplus prices plus the cost of a CCCT at about $350/kw; cheaper than Twin Falls.  Rosebud admits that Twin Falls “appears to be economic against the old avoided cost thermal technology with a 42% capacity factor and operating costs below 7 mills/kWh.”
Rosebud argues that, someday, Idaho Power’s customers will be able to acquire energy from suppliers of their choice due to the advent of future policy changes that will be promulgated by the FERC, known loosely as “retail wheeling.”  From this, Rosebud draws the conclusion that Idaho Power will be relieved of its obligation to serve from specific resources and could sell energy and capacity from Twin Falls to any buyer at market price.  If advances in technology render Twin Falls obsolete, Rosebud contends, remaining captive Idaho Power ratepayers will be stuck with the costs of a stranded asset.  
Rosebud argues that under “the FERC policy” the FERC will no longer conduct an economic feasibility analysis in the granting of licenses and that “no future resources will be eligible for cost recovery.”  Rosebud alleges that Idaho Power “knew of these impending changes” prior to starting construction on Twin Falls and somehow manipulated the Commission into sheltering the Company’s shareholders from the risk of non-recovery for a generating assets whose cost renders it unable to meet market standards.
Rosebud also argues that the PCA, which it did not oppose when proposed by Idaho Power, harms ratepayers because, formerly, ratepayers realized the benefit of capacity that they paid for.  Under the PCA, during dry years, the ratepayers lose the value of capacity they have paid for in rates.  The reverse is not true, Rosebud contends, because during wet years, all of the Snake River plants produce excess energy during the spring months.  The value of such energy to the ratepayers is limited to the reduction in fuel costs at Idaho Power’s thermal plants, or to the spot market value at that time, whichever is less.  There is effectively no value for capacity, Rosebud contends.
Rosebud also challenges Idaho Power’s calculation of the capacity value of Twin Falls on the basis that it incorporates no adjustment to reflect the shifting of risk resulting from the PCA.
Finally, Rosebud contends that the capacity factor of Snake River hydro during drought years is quite low in comparison to non-utility thermal generation (using data from the year 1993).  Rosebud states that in 1993, Snake River hydro produced at 65% of capacity while Idaho Power’s Bridger plant and QF’s produced at 100%.  Rosebud concedes that a hydro facility is more valuable for load shaping as compared to newer thermal technologies.  Rosebud argues that a thermal plant is always available for generation while hydro is only available if there is water in the river.
Rosebud concludes that Twin Falls’ capacity should be given no value until at least 2003; the earliest deficit date in Idaho Power’s planning as of August 1993, adjusted for the removal of Twin Falls and the now defunct Meridian generating plant.  Next, Rosebud proposes that capacity factor be adjusted for the effects of wet and dry years to reflect the fact that the PCA shifts risk from shareholders to ratepayers.  Rosebud states that “the cost of dry years has always been greater than the benefit from wet years, because useful capacity is worth more during dry years.”
Rosebud concludes that the Commission should give Idaho Power “every incentive to mitigate its investment, even at the cost of also losing the existing 9 MW of capacity at that site.”  Rosebud recommends that the Commission defer placing Twin Falls into rate base until 2003.  Rosebud further recommends that the Commission signal its approval of efforts by Idaho Power to mitigate its investment in Twin Falls through the firm sale of energy and capacity, or of the physical asset and the FERC license.
FINDINGS
In Order No. 25021, we granted Idaho Power the assurance that “in the ordinary course of events, the Company may expect its investment in the Twin Falls project to be recognized in its revenue requirement, barring unforeseen circumstances of a kind not characteristic of hydroelectric facilities.” Id. at p. 13.  We also accepted the Company’s commitment estimate, with a cap of $50,839,000, as reasonable.  Our decision to grant Idaho Power the foregoing assurance was made only after careful consideration of the costs and benefits attributable to Twin Falls and only after assuring ourselves that the resource compared favorably to what we considered to be a relevant avoided cost benchmark.  We stated:
In this case, the evidence is unrefuted that the Twin Falls project compares favorably to the avoided cost rate.  To be specific, the levelized unit cost of the project is 65% of avoided cost, assuming that the final cost of the project is the construction estimate.  It would, of course, be lower if construction costs are less.  As Idaho Power and Staff note, this comparison is for additional generation only.  If the levelized unit cost for the project’s total output is calculated, it is in the range of 41.8% to 31.4% of avoided cost.
Thus, we find that the evidence clearly establishes Twin Falls to be a cost effective acquisition of new generation.
Id. at pp. 11-12.
Our decision was, of course, based upon the best evidence available at the time and upon the avoided cost rates then in existence.  Because Idaho Power constructed Twin Falls for less than the commitment estimate, there could be no basis now for disallowing the Company to recover its investment unless substantial, competent evidence was presented during the course of this proceeding which clearly shows that circumstances changed subsequent to the issuance of Order No. 25021 that somehow rendered the project imprudent.  As discussed below, we find that no such evidence has been presented.
As Rosebud correctly observes, we compared Twin Falls in the 91-4 case to the published avoided cost rates in existence as of the date we issued Order No. 25021.  The primary thrust of Rosebud’s theory appears to center around the Position Paper issued by Idaho Power in September of 1993 and Idaho Power’s avoided cost filing in Case No. IPC-E-93-28 made in December of 1993; both of which occurred after Idaho Power commenced construction of Twin Falls.  The gist of Rosebud’s theory is, essentially, that Idaho Power knew that its avoided costs had changed prior to the commencement of construction on Twin Falls and this knowledge is evident in the Position Paper and the avoided cost filing.
What Rosebud has failed to point out in either testimony or briefing is the fact that this Commission alone is empowered to determine and establish Idaho Power’s avoided cost rates for the state of Idaho and that the rates against which Twin Falls were compared were in existence until January 14, 1994 at which time this Commission suspended them pending a full review of avoided costs for all of Idaho’s major electric utilities.  It wasn’t until January 31, 1995, 17 months after construction on Twin Falls commenced, that we adopted a new surrogate avoided resource and established new rates for Idaho Power in Order No. 25884 , Case No. IPC-E-93-28.  Incidentally, we adopted a first deficit year for Idaho Power of 1998 in that case, contrary to what Idaho Power proposed in that case as well as in its Position Paper.  Furthermore, Rosebud’s witness in this proceeding, Dr. Richard Slaughter, testified that he did not know how much construction had been completed on Twin Falls at the time we issued Order No. 25884, revising Idaho Power’s avoided cost rates. Tr. p. 99.
The calculation of avoided costs has been characterized as being more art than science.  It is, admittedly, a process that involves a considerable number of subjective assumptions.  Moreover, it is a dynamic process that naturally evolves with changes in technology and changes in the electric utility industry.  Because it is impractical to attempt to review and re-establish avoided cost rates on a daily basis, once rates are set they remain static until changed by this Commission.  In short, regardless of what Idaho Power may believe and declare its avoided costs to be at any given point in time, this Commission is the sole authority for determining and establishing those rates.  
While we ultimately adopted a gas CCCT as Idaho Power’s SAR, we could have chosen to continue with a coal-fired thermal plant.  Until we made our final decision, however, Idaho Power was entitled to rely on the published rates in existence as well as the assurance provided in 91-4.  This is precisely what the Company did and Rosebud’s contention that Idaho Power somehow misled this Commission regarding its avoided costs is utterly without merit.
Once the notion that Idaho Power had “knowledge” that its avoided costs had changed is dispelled, the majority of Rosebud’s arguments fail.  For example, Rosebud’s contention that Idaho Power’s decision to invest in Twin Falls was imprudent because of changes in FERC policy on retail wheeling, presumes that the investment was imprudent when Idaho Power began construction, which we have determined that it was not.  Second, it presumes knowledge of what the FERC’s future policy will be because, as of the date of this Order, the FERC has not yet issued a final ruling on retail wheeling and its associated issues.  Obviously, that “policy” was even less certain in August of 1993.
Regarding Rosebud’s observation that the PCA adopted by this Commission has the effect of shifting risk from shareholders to ratepayers, we agree but also note that this was taken into consideration when we adopted a return on common equity for Idaho Power in the Company’s last general rate case; Case No. IPC-E-94-5.  In any event, ratepayers do not overcompensate the Company for its power supply costs under the PCA because it is simply a balancing account that tracks through the changes in actual expenses associated with variations in hydro conditions.
Finally, regarding Rosebud’s criticism of the capacity factor of Twin Falls, we note that Rosebud makes several inappropriate comparisons.  First, Rosebud compares Snake River hydro to Company owned thermal plants and QF resources.  Many QF resources, however, are hydro plants.  The more relevant comparison is thermal versus hydro.  It is true that when there is insufficient water in the river to operate a hydro plant, there is no capacity value.  When water is available, however, the hydro plant operates at a dramatically lower cost than a thermal resource, i.e., the “fuel” to run the hydro plant is, essentially, free.  A cost effective hydro resource is one whose operational cost advantage over the life of the plant is greater than the cost of providing energy and capacity when no water is available. As Rosebud notes, hydro resources are ideal in following load, and can be firmed by other resources.  
Rosebud’s Exhibit 703 (p.3) shows an average Twin Falls capacity factor of 45% over 67 years of record.  Based on the evidence presented in 91-4, when comparing the cost of Twin Falls project generation at a 42% capacity factor to the all energy avoided cost rate in place in 1993, the life cycle cost of the project was found to be lower.  Rosebud’s testimony regarding capacity factor has not altered the results of the original comparison.  
We find that Rosebud has failed to present substantial, competent evidence that circumstances changed subsequent to the issuance of Order No. 25021 and prior to the start of construction on Twin Falls that rendered the project imprudent.  Regardless of what it believed its avoided costs to be at any point in time, Idaho Power justifiably relied on the assurance given by this Commission in 91-4 in commencing with the construction of Twin Falls.  We further find that the $3,759,695 annual increase to the Company’s revenue requirement agreed to by Staff and the Company reflecting the Twin Falls and incremental Swan Falls investments is fair, just and reasonable.
Intervenor Funding
On August 21, 1995, the Pumpers petitioned for intervenor funding in this case pursuant to Rules 161-170 of the Commission’s Rules of Procedure, IDAPA 31.01.01.  
Idaho Code § 61-617A and Rule 162 of the Commission’s Rules of Procedure provide the framework for awards of intervenor funding.  Section 61-617A provides that the Commission shall rely upon the following considerations in awarding funding to a given intervenor:  (1) whether the intervenor materially contributed to the decision rendered by the Commission; (2) whether the alleged costs of intervention are reasonable in amount and would be a significant financial hardship for the intervenor to incur; (3) whether the recommendation made by the intervenor differed materially from the testimony and exhibits of the Commission Staff; and (4) whether the testimony and participation of the intervenor addressed issues of concern to the general body of users or consumers.
Subsection 5 of this statute provides that intervenors who are in direct competition with the public utility involved in proceedings before the Commission shall not be granted funding. The statute further provides that the total award for all intervening parties combined shall not exceed $25,000.00 in any proceeding.
Rule 162 of the Commission’s Rules of Procedure provides the procedural requirements with which an application for intervenor funding must comply.  The application must contain:  (1) an itemized list of expenses broken down into categories; (2) a statement of the intervenor's proposed finding or recommendation; (3) a statement showing that the costs the intervenor wishes to recover are reasonable; (4) a statement explaining why the costs constitute a significant financial hardship for the intervenor; (5) a statement showing how the intervenor’s proposed finding or recommendation differed materially from the testimony and exhibits of the Commission Staff; (6) a statement showing how the intervenor’s recommendation or position addressed issues of concern to the general body of utility users or customers; and (7) a statement showing the class of customer on whose behalf the intervenor appeared.
Finally, Rule 165 provides that the Commission must find that the intervenor’s presentation materially contributed to the Commission’s decision.
The Pumpers allege that the following fees and costs were incurred in this proceeding:
Legal fees:  24.2 hours at $110.00 per hour.$2662.00
Consultant fees:  51 hours at $95.00 per hour$4845.00
Travel, meals, lodging miscellaneous expense$1728.41
Total$9235.41
The Pumpers, through their witness Anthony Yankel, proposed certain adjustments to the Company’s normalized power supply costs as opposed to Idaho Power’s initial recommendation to flow power supply changes resulting from the inclusion of Twin Falls into the Company’s resource stack, through the PCA.  Idaho Power accepted, in part, the recommendations of Mr. Yankel resulting in a reduced revenue requirement attributable to Twin Falls.
On August 30, 1995, Idaho Power filed a response to the Pumpers’ petition for intervenor funding stating that the Company had no objection to the petition but that, contrary to statements made during the evidentiary hearing, reimbursement for the intervenor funding should come from the irrigation class as provided by Idaho Code § 61-617A and Rule 165(03) of the Commission’s Rules of Procedure.
We find:
The Pumpers’ petition meets the procedural requirements set forth in Idaho Code §61-617A and Rules 161-170 of the Commission’s Rules of Procedure.  The Pumpers made a sufficient showing of financial hardship, took a position that differed materially from the Commission Staff and raised issues of concern to the general body of ratepayers.
Finally, the Pumpers contributed materially to our final decision in this case.  We found their testimony regarding how to capture all of the benefits of reduced power supply costs attributable to the addition of Twin Falls to be helpful.  We find that the amount of intervenor funding requested by the Pumpers is reasonable and hereby award the amount of $9,235.41.  Idaho Power is required to pay the Pumpers this amount within twenty-eight (28) days from the service date of this Order.  We adopt Idaho Power’s proposal, set forth in its response to the Pumpers’ petition, to modify the rates to the irrigation class (Schedule 24) for one year by adding 0.00057 cents per kWh to the energy rates of that schedule, effective as of the date of this Order, to reimburse the Company for the intervenor funding award, pursuant to Rule 165(03) of the Commission’s Rules of Procedure.  This incremental addition to Schedule 24 rates shall be removed after being in effect for one year.
O R D E R
IT IS HEREBY ORDERED that our bench ruling issued on August 14 increasing Idaho Power’s revenue requirement by $3,759,695 is affirmed, consistent with the terms and conditions set forth in this Order.
IT IS FURTHER ORDERED that the petition for intervenor funding filed by the Idaho Irrigation Pumpers Association is hereby granted in the amount of $9,235.41.  Idaho Power is directed to pay theses amounts within twenty-eight (28) days from the service date of this Order and to increase the rates for Schedule 24 by adding 0.00057 cents per kWh to the energy rates of that schedule effective as of the date of this Order for one year.
THIS IS A FINAL ORDER.  Any person interested in this Order (or in issues finally decided by this Order) or in interlocutory Orders previously issued in this Case No. IPC-E-95-5 may petition for reconsideration within twenty-one (21) days of the service date of this Order with regard to any matter decided in this Order or in interlocutory Orders previously issued in this Case No. IPC-E-95-5.  Within seven (7) days after any person has petitioned for reconsideration, any other person may cross-petition for reconsideration.  See Idaho Code § 61-626.
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this                  day of  November 1995.

RALPH NELSON, PRESIDENT

MARSHA H. SMITH, COMMISSIONER

DENNIS S. HANSEN, COMMISSIONER
ATTEST:

Myrna J. Walters
Commission Secretary
vld/O:IPC-E-95-5.bp5