Exhibit 99.1

 

BEFORE THE PUBLIC UTILITY COMMISSION

OF OREGON

UE 213

 

In the Matter of   IDAHO POWER COMPANY   Request for a General Rate Revision.

ORDER

 

 

DISPOSITION:  STIPULATION APPROVED IN PART 

I.  INTRODUCTION

This order addresses Idaho Power Company’s (Idaho Power or the Company) request for a general rate revision filed on July 31, 2009.  In this order, we adopt the stipulation filed by the parties, with a few exceptions related to residential rate design.  This order results in an increase of approximately $5 million to Idaho Power’s revenue requirement, an overall rate increase of approximately 15.4 percent.

II.  BACKGROUND AND PROCEDURAL HISTORY

Idaho Power is an electric company and public utility in the State of Oregon within the meaning of ORS 757.005.  The Company provides electric service to approximately 18,000 retail customers within the state, and is subject to the Commission’s jurisdiction with respect to the prices and terms of electric service for Oregon retail customers. 

 

 

On July 31, 2009, Idaho Power filed Advice No. 09-09, an application for revised tariff schedules.  The Company originally requested an increase in its Oregon revenues of $7.3 million, or an overall rate increase of 22.6 percent.[1]  According to the Company, its request is driven by two key drivers:  new investment in electric plant, and differences between growth in Oregon jurisdictional expenses and growth in Oregon jurisdictional revenues.  With respect to new investment, the Company asserts that it invested $800 million in electric plant between 2003 to 2008, investments that have

 

 

 resulted in a 12 percent increase in nameplate capacity since its last general rate case.[2]  The Company also asserts that growth in Oregon expenses has outpaced growth in Oregon revenues by $2.1 million since 2003, so the Company sought an additional
$2.1 million, or a 6.3 percent increase in Oregon revenues, to account for that difference.

On August 21, 2009, a prehearing conference was held and a procedural schedule was established.  At its August 25, 2009, public meeting, the Commission suspended the proposed tariff revisions for a period of nine months pursuant to ORS 757.215.[3] 

During the course of the proceeding, the following parties were granted leave to intervene as parties:  the Oregon Industrial Customers of Idaho Power (OICIP); EP Minerals, LLC; and Portland General Electric Company (PGE).  The Citizens’ Utility Board of Oregon (CUB) intervened in the proceeding as a matter of right under ORS 774.180. 

A public comment hearing was held in Ontario, Oregon, on September 29, 2009.  Numerous customers appeared at the public hearing to object to the proposed rate increase.  The Commission also received dozens of comments objecting to the proposed residential and irrigation rate increases. 

Settlement conferences among the active parties[4] took place on November 4 and 5, 2009.  On December 17, 2009, the parties filed a stipulation (the Stipulation) addressing the issues in this docket.  Although all parties signed the Stipulation, two parties reserved the right to object to specific portions of the agreement:  CUB reserved the right to object to the stipulated design for residential rates, and OICIP expressed concerns about Idaho Power’s Schedule 19 service quality.  On January 19, 2010, CUB and OICIP filed objections with supporting testimony.  Staff and Idaho Power filed joint reply testimony on January 26, 2010.

On January 29, 2010, the parties were asked to address whether OICIP’s objections fell within the scope of this general rate proceeding.[5]  On February 2, 2010, OICIP agreed to remove its service quality issue from this proceeding and pursue it in a separate docket.  As a result, the only formal objection to the Stipulation remaining in this docket is CUB’s objection to the stipulated residential rate design.  No party requested a hearing on CUB’s contested issues, and the parties filed simultaneous briefs on February 3, 2010.

 

 

 

 

 

 

III.  DISCUSSION

We begin with an overview of the Stipulation, and then discuss contested issues.

A.        Overview of the Stipulation

The Stipulation addresses all issues in this docket.  If approved, it would reduce Idaho Power’s proposed increase in test period revenue requirement from
$7.3 million, or 22.6 percent, to approximately $5 million, or 15.4 percent.[6] 

1.                  Rate of Return and Taxes in Rates

The Stipulation sets Idaho Power’s return on equity (ROE) at
10.175 percent, and its overall rate of return at 8.061 percent.  Under the Stipulation, the individual components of the assumed capital structure are as follows:
 

Capital Component	Capitalization	Cost	Weighted Cost
Long-Term Debt	50.20%	5.964%	2.994%
Preferred Stock	0.00%
Common Equity	49.80%	10.175%	5.067%
TOTAL	100.00%		8.061%

 

The parties note that the stipulated rate of return represents a reduction in the Company’s original request of 8.68 percent.  It also represents an increase in the Company’s currently authorized rate of return of 7.83 percent.

2.         Advanced Metering Infrastructure Communication Equipment

The parties agree that capital expense associated with communication equipment acquired to implement the Company’s Advanced Metering Infrastructure (AMI) system should be removed from this docket.  This equipment has not yet been implemented in Idaho Power’s Oregon jurisdiction.  The Company will make a request to recover any prudently incurred investment in the future.[7] 

3.        Net Power Supply Expense

 

 

The Stipulation explains that the Company’s filed case included a level of net power supply expense (NPSE) equivalent to that which is currently reflected in base rates, plus the October portion of the Company’s Annual Power Cost Update (APCU) rate that became effective June 1, 2009.[8]  The parties agree that because the NPSE in that

 

 

 

 

docket was calculated using an April 2009 through March 2010 test period, it is appropriate to adjust the level of NPSE in this case to align with the 2009 calendar-year period.  The parties agree that, on a going forward basis, the level of net power supply expense recovery included in the Company’s base rates is $10.94 per MWh, and that rate will become the base from which future APCU rates will be determined.

 

4.         Pension Expense

Idaho Power’s initial filing included no pension expenses.  On October 20, 2009, the Company filed an application with the Commission requesting permission to account for pension expenses on a cash basis as opposed to an accrual basis, with the goal of recovering such expenses at some point in the future.

Under the Stipulation, Idaho Power would continue to account for pension expense on an accrual basis, a practice consistent with Statement of Financial Accounting Standards (SFAS) 87.  The parties acknowledge that it is not practicable for Idaho Power to account for the difference in capitalized labor charges between jurisdictions with a fixed asset system, but state that Idaho Power has historically capitalized a portion of its labor costs, including SFAS 87 expense.  In order to simulate the historic accounting without creating an undue burden on the Company, the Stipulation would allow Idaho Power to record the capital portion of its SFAS 87 expense as a regulatory asset to be amortized in a manner consistent with the depreciation of electric plant in service and revised by the Commission for inclusion in rates in a subsequent rate proceeding.  The capital portion of pension expense in the fixed-asset system would be removed from net plant to prevent double recovery of pension expenses.

The parties further agree that the stipulated revenue requirement adopted in this rate case includes an SFAS 87 pension expense.  Going forward, the parties agree the Commission should recognize both a regulatory asset associated with the capital portion of pension expense and the non-capital pension expense component when determining the Company’s revenue requirement.  If this provision is adopted, the Company agrees to withdraw its request to account for its pension expense on a cash basis.

5.         Marginal Cost Methodology

The parties agree that the Company’s marginal-cost approach to allocating costs is appropriate and should be adopted with one exception:  at this time, transmission-related revenue requirement should be classified as 75 percent demand-related and 25 percent energy-related for the purpose of allocation to customer classes.

6.         Functionalization of Production Costs

 

 

Idaho Power has historically separated its functionalized, embedded production costs into energy and demand components prior to their allocation.  Instead of this approach, the parties agree that the functionalized production revenue requirement should be allocated directly, on the basis of each schedule’s combined shares of marginal demand and energy costs.

 

 

 

 

 

 

7.         Revenue Spread

The parties agree to implement Staff’s proposed changes to the Company’s rate spread, shown on Exhibit B to the Stipulation.  This rate spread reduces the proportion of revenue requirement Idaho Power originally proposed to allocate to Residential Service, Small General Service, Large General Service-Secondary Voltage Level, and Agricultural Irrigation Service.  The Company’s remaining customer classes receive a larger allocation of revenue requirement than originally proposed, except Large Power Service-Transmission Voltage Level and Area Lighting Service, which continue to receive no increase.

8.         Rate Design

Idaho Power’s proposed rate design included seasonally differentiated rates for residential customers.  With the exception of CUB, the parties agree that Idaho Power’s proposed rate design should be modified in the following manner:

a.         The residential service charge should be increased to only $8.00 per month, rather than Idaho Power’s proposed $10.00 per month.[9] 

b.         The upper end of the first residential usage block should be increased to 1,000 kWh, rather than Idaho Power’s proposed 800 kWh, with the rate charge for the first block remaining the same throughout the year.[10]

c.         The Small General Service (Schedule 7) energy rate inversion point should be elevated from 300 kWh to 500 kWh.  

9.         Other Provisions

As part of the Stipulation, Idaho Power agrees to make changes to a number of its Oregon rules.  The Company also makes various commitments to Schedule 19 customers. 

With the exception of CUB’s objections to the stipulated design for residential rates, the parties agree that the Stipulation results in rates that are fair, just, and reasonable.  The parties agree that no provision of the Stipulation is appropriate for resolving issues in any other proceeding, except as specifically identified therein. 

B.        Objections to the Stipulation

 

In this section, we address CUB’s objections to the stipulated residential rate design and briefly address irrigation rates.  Although all active parties signed the Stipulation, CUB reserved the right to object to the stipulated design for residential rates, and the testimony and briefing supporting the Stipulation on the contested issues

 

 

 

 

was filed by Idaho Power and Staff.  For purposes of this section, Idaho Power and Staff will be referred to as the “Joint Parties.”

 

1.                  Legal Standard

The Commission has the broad powers to set just and reasonable rates.[11]  As with any rate increase, Idaho Power bears the burden to show that a proposed rate change is just and reasonable.[12]  When considering a stipulation, we have the statutory duty to make an independent judgment as to whether any given settlement constitutes a reasonable resolution of the issues.  We may accept a non-unanimous settlement agreement so long as we make an independent finding, supported by substantial competent evidence in the record as a whole, that the settlement will establish just and reasonable rates.[13]

2.                  Residential Rate Design

a.                  Seasonal Rates

                                    i.          Parties’ Positions

CUB challenges the Company’s proposed seasonal rate design for Idaho Power’s residential customers.  Under the proposed design, residential customers using more than 1,000 kWh per month would pay higher rates in the summer, when overall customer usage of the Company’s system peaks.  CUB asserts that the proposed rates may be confusing to customers, and there is no evidence to show that imposing the proposed price signals on winter-peaking residential customers will actually be effective in reducing peak energy consumption.  For residential customers, CUB believes that the development of energy efficiency programs should be a stronger focus than price signals, and CUB questions the effectiveness of Idaho Power’s energy efficiency programs.  CUB also asserts that it is inconsistent to use seasonal rates to send price signals to residential customers during the summer peak, while simultaneously protecting summer-peaking irrigation customers from receiving accurate price signals by capping irrigators’ rates at 75 percent of their cost of service. 

 

Staff and Idaho Power believe seasonal rates for residential customers should be adopted because they serve several purposes:  they move the energy rate closer to the marginal cost of providing energy in the summer and non-summer months, encourage energy efficiency for the residential customer class year-round, and facilitate consistency throughout the Company’s service territory by aligning the residential rate design in both the Company’s Idaho and Oregon jurisdictions.[14]  Staff and Idaho Power assert that the seasonal rates, as designed, will discourage excessive use of refrigerated

 

 

 

 

 

air conditioning in the summer, when power is most expensive for the Company, without being overly burdensome to customers. 

ii.                  Resolution

Idaho Power sought to implement seasonal rates for residential customers in its last general rate case.  We declined to adopt seasonal rates in that docket, finding that Idaho Power failed to demonstrate that residential customers would be likely to respond to higher summer bills in the manner the Company predicted.[15] 

Once again, we decline to adopt the seasonal rates proposed by Idaho Power.  We make no findings in this docket about whether well designed seasonal rates may be appropriate for the Oregon residential customers of Idaho Power.  We recently declined to adopt a new rate design proposal in Portland General Electric Company’s general rate case, choosing instead to open a separate proceeding to consider policy issues, and we do the same here.[16] 

b.                  Tiered Residential Rates

                                    i.          Parties’ Positions

Idaho Power’s residential customers currently have a two-tier inverted block structure in which customers pay one energy charge for the first 300 kWh of energy, and a higher charge for all energy used thereafter.  The Stipulation proposes moving the breakpoint for the second tier from 300 kWh to 1,000 kWh.

CUB asks the Commission to leave the Company’s tiered rates at their current levels.  CUB states that it would ordinarily agree to the higher 1,000 kWh price inversion point, but the magnitude of this rate increase makes it more appropriate to retain the current blocks in order to more evenly spread the increase among residential customers.  Keeping the existing block structure, CUB asserts, will help avoid rate shock at higher levels of usage. 

 

 

Idaho Power explains that modifying the existing block structure will better meet the purpose of the tiered blocks.  The Company asserts that the first energy block is intended to cover a majority of customers’ basic electric usage, such as usage from lighting and home appliances, while the second block is intended to cover more discretionary usage.[17]  The Company’s studies show that the average monthly residential

 

 

 

 

 

 

usage for 2008 was 1,247 kWh, making the 300 kWh breakpoint too low.[18]  In its initial filing, Idaho Power sought to move the price inversion point to 800 kWh, which would capture about 60 percent of average energy use at the lower rate.  As part of the Stipulation, the price inversion point was moved even higher, to 1,000 kWh. 

According to Staff,

[A]lgebraically, and for a fixed revenue target for the residential schedule, the fewer the number of kWh’s that are assessed the higher, tail-block price, the higher that price can be without leading to excess class revenues or without requiring the customer charge and/or the initial block’s rate to be lower than desired.  This feature is important in the current case because the summer costs are so much higher than the yearly average.[19] 

ii.                  Resolution

While we understand the rationale for increasing the size of the first inverted block, under the circumstances of this case we will retain Idaho Power’s current rate design with a 300 kWh first tiered block.  As noted above, we have declined the Joint Parties’ proposal to adopt seasonal rates, concluding instead to first conduct a more thorough examination of residential rate design issues to obtain more information.  Because that investigation may yield useful data relevant to the proper design of tiered rates, we similarly decline the Joint Parties’ proposal here. 

c.                   Customer Service Charge

                                    i.          Parties’ Positions

CUB challenges the stipulated increase in the residential customer service charge.  Idaho Power’s fixed charge for residential customers is currently $5.25 per month.  Idaho Power originally proposed increasing this charge to $10.00.  In the Stipulation, the Joint Parties agree to increase the service charge to $8.00. 

CUB asks the Commission to limit the increase in the basic service charge to $6.50, arguing that increasing the base rate will disproportionately impact customers with low monthly usage.  Moreover, CUB argues, if the Commission wishes to increase the price signals received by customers, it should not move rates from variable to base portions of rates.

 

 

Idaho Power explains that its customer service charge is currently too low.  The charge is intended to recover costs that do not vary with the amount of energy or capacity used, but the service charge has historically undercollected costs.  Increasing the charge would move individual rate components closer to the cost of providing electric service.  The Joint Parties agree that $8.00 represents customer-related costs that are

 

 

 

 

 

appropriately included in the basic customer charge, consistent with Commission precedent.

ii.                  Resolution

We find the stipulated resolution of the residential customer basic charge issue to be reasonable.  CUB does not contest the Joint Parties’ assertion that an $8.00 basic charge fairly represents customer-related costs.  As a general matter, moving customer-related costs into fixed charges is consistent with Commission precedent and we see no reason to deviate from that precedent here.

d.                  Reducing Subsidies to Irrigation Customers

                                    i.          Parties’ Positions

CUB has stipulated to the rate spread portion of the Stipulation, which moves certain customer classes closer to their actual cost of service.  Not all customers are moved to full cost of service, however.  Under the stipulated rate spread, the rate increase for the irrigation class is limited to 75 percent of the irrigators’ cost of service.[20]  The parties agreed to cap the irrigators’ rate at this level to prevent irrigation customers from suffering rate shock. 

CUB states it is willing to agree to the stipulated rate spread because all customer classes should be protected from rate shock.  Nevertheless, CUB feels strongly that the subsidies for irrigators should be removed over time.  Because Idaho Power’s last general rate case was filed in 2004, CUB is concerned that the Company will not file general rate cases on a regular basis.  As a result, it could take an unreasonable amount of time for irrigation rates to reflect irrigators’ actual cost of service.  CUB therefore asks the Commission to gradually eliminate irrigation subsidies through rate spread adjustments in Idaho Power’s APCU and Power Cost Adjustment Mechanism (PCAM) dockets, which occur on an annual basis. 

Idaho Power and Staff disagree with this recommendation.  Idaho Power argues that general rate cases are the appropriate venues for addressing cost allocation and inter-class subsidy issues because they involve full cost-of-service and marginal cost analyses, as well as wide public participation.  APCU and PCAM proceedings, by contrast, are single issue, automatic adjustment clause mechanisms intended for other purposes.  Staff believes the Commission should look at all available opportunities to eliminate subsidies for the irrigation class over time, but does not recommend that the Commission explicitly order any such changes to occur in the APCU and PCAM dockets.

ii.                  Resolution

 

 

Given the limited issues involved in PCAM and APCU dockets, we decline at this time to order rate allocation issues to be addressed in those specific

 

 

 

 

 

dockets.  We agree with Staff, however, that the Commission should look at available opportunities to move Idaho Power customers closer to their cost of service.

e.                   Length of Billing Cycles

                                    i.          Parties’ Positions

Idaho Power seeks to change its definition of “billing cycle” from “27 to 33 days” to “27 to 36 days.”  CUB argues this rule change has the potential to be harmful to customers in a tiered rate structure, because usage in the longer billing cycle will be billed at a higher rate, particularly if seasonal rates are adopted. 

The Joint Parties assert that any issues with the new definition of “billing cycle” can be remedied by a prorating protocol.  In any case, only 0.22 percent of customers would receive bills with 34-36 day billing periods.

ii.                  Resolution

We find the proposed rule change to be reasonable.  The new rule would make Idaho Power’s definition of “billing cycle” consistent in both Oregon and Idaho, and would appear to have little impact on customers, particularly since we have declined at this time to adopt seasonal rates or modifications to Idaho Power’s existing inverted-block structure.

3.                  Irrigation Rates

As noted above, the Commission received robust public comment objecting to Idaho Power’s proposed rate increase, particularly with respect to the proposal to increase irrigation rates by 44.7 percent.  At the September 29, 2009, public comment meeting in Ontario, as well as in written letters and emails, customers expressed dissatisfaction with the proposed increase and explained the difficulty of paying electric bills during this difficult economic period. 

We have carefully reviewed the rate increase in this docket, and the irrigation rates in particular, and find the proposed rate increases for all customer classes to be appropriate.  Given that the Company has waited several years to seek recovery of new investment in rates, we recognize that the rate increases imposed by this order are significant.  While we would prefer not to impose any rate increase on customers during difficult economic times, Idaho Power is entitled to recover in rates the costs of property currently being used to serve customers.  In recognition of the potential rate shock that would be caused by a 44.7 percent increase in irrigation rates, however, the parties have agreed to limit the increase in irrigation rates to 75 percent of the cost of serving the irrigation class.  This limits the increase in irrigation rates to 27.96 percent.  We find this solution to be a reasonable one.

 

 

 

 

 

 

IV.  CONCLUSION

With the exception of the residential rate design issues addressed above, we find that the Stipulation, set forth in Appendix A to this order, will result in rates that are fair, just, and reasonable.  With the exception of the aforementioned issues, the Stipulation is adopted.

V.  ORDER

IT IS ORDERED that:

1.   Advice No. 09-09 is permanently suspended.

2.   With the exception of residential rate design issues noted in this order, the Stipulation by and between the Idaho Power Company; Oregon Industrial Customers of Idaho Power; EP Minerals, LLC; and the Citizens’ Utility Board is adopted.

3.   Idaho Power Company must file new tariffs consistent with this order to be effective no earlier than March 1, 2010.

 

                        Made, entered, and effective  ____________________________.

 

 

______________________________ Lee Beyer Chairman	______________________________ John Savage Commissioner
	______________________________ Ray Baum Commissioner

 

 

 

 

 

 

 

 

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