IDAHO POWER CO - FORM 8-K - EX-99.1 - IPUC ORDER

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8-K - IDAHO POWER CO	a8-kxidahogrcsettlementord.htm

Exhibit 99.1

Office of the Secretary

Service Date

December 30, 2011

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 IN IDAHO	) ) ) ) ) )	CASE NO. IPC-E-11-08 ORDER NO. 32426

On June 1, 2011, Idaho Power Company filed an Application seeking authority to increase its base rates for electric service by an overall average of 9.9%, or by approximately $83 million per year. On June 22, 2011, the Commission suspended the proposed effective date and issued a Notice of Application. Order No. 32272. On August 5, 2011, the Commission issued its Scheduling Order and set a technical hearing for early December 2011. Order No. 32316. The Scheduling Order also set two settlement conferences for August 31 and September 8, 2011.

All parties attended the settlement conferences. Based upon discussions held during the conferences, all the parties (except one) entered into a Stipulation that proposed to settle most, but not all issues in the rate case. The signing parties agreed to an annual revenue increase of $34 million, or an average rate increase of about 4.07%. The settling parties were unable to settle three issues and agreed that these issues should be presented to the Commission at the technical hearing.

Following three public workshops and three public hearings, the Commission convened its evidentiary hearing on December 5, 2011. As outlined in greater detail below, the Commission approves the Settlement Stipulation with one condition and resolves the remaining disputed issues.

BACKGROUND

A. The Initial Application

Idaho Power serves nearly 500,000 customers in southern Idaho and eastern Oregon. The Company maintained it has invested more than $450 million in infrastructure since its last general rate case in 2008. The Company requested that calendar year 2011 be used as its test year and that the Commission grant the Company a return on its rate base of 8.17%. Application at 5.

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Idaho Power proposed that its monthly service charge for residential and small business customers be increased from $4.00 to $5.00 per month. The Company also proposes to increase the summer-tiered residential rates (but not the winter). The Company also sought authority to modify its residential Schedules 4 and 5 to offer two time-of-day periods for energy charges during the summer and non-summer months. Id. at 3-4.

The Company proposed to implement its new cost-of-service study and to increase the rates for small commercial customers (Schedule 7), industrial customers (Schedule 19), and irrigation (Schedule 24) customers by moving those rates “closer to the cost-of-service for those customer classes.” Id. at 4. Under the original Application, the proposed increases for these three customer classes would be approximately 14.85%. Order No. 32272 at 2. Idaho Power also proposed to increase the rates for each of its four special contract customers (the Idaho National Laboratory, Micron, Simplot and Hoku Materials) by approximately 14.85%.¹

Idaho Power also sought authority to increase the charges for its “overhead costs”²

in Rule H (New Service Attachments, Installations and Alterations). Id. at 5. The Company also calculated its load change adjustment rate (LCAR) at $19.28 per megawatt-hour (MWh) using the methodologies set out in Commission Order No. 32206. Id. at 6. Because of a prior rate moratorium, the Company asked that its rate increase become effective on January 1, 2012.³ Order No. 32272 at 3.

B. Procedural Background

In response to the Notice of Application, the Commission granted intervention to 10 parties including: Idaho Irrigation Pumpers Association (IIPA), Industrial Customers of Idaho Power (ICIP), U.S. Department of Energy (DOE), The Kroger Company, Community Action Partnership Association of Idaho (CAPAI), Micron Technology, Idaho Conservation League (ICL), Snake River Alliance (SRA), NW Energy Coalition and Hoku Materials. The

¹ For Hoku in particular, the Company proposed to increase the rate for the second block demand in energy by 14.84%. Application at 3, Atch. 3.

² Overhead costs are pooled costs that are incurred in the Company's construction process and allocated to Rule H customers. Application at 2, Case No. IPC-E-11-24.

³ The prior rate case stipulation allowed for specific increases such as the Power Cost Adjustment (PCA), the Fixed Cost Adjustment (FCA), recovery of advanced metering deployment, pension expenses, and changes in the Energy Efficiency Rider. Order No. 30978 at 4.

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Commission Staff also participated as a party. The Commission issued its initial Notice of Parties on July 13, 2011, and a Second Amended Notice of Parties on September 6, 2011.

The Commission Staff held three public workshops on September 20, 21, and 22, 2011, in Pocatello, Twin Falls, and Boise, respectively. The Commission also convened public hearings on November 3 and 9, and December 5, 2011, in American Falls, Gooding, and Boise, respectively.

The Commission received more than 100 written comments regarding the Company's proposed rate increase. Most comments were received before the Settlement Stipulation was filed in September 2011. Many of these comments opposed the rate increase citing the bad economy or adverse impact on residential customers with low or fixed incomes. After the Settlement Stipulation was filed, the Commission received four comments - three opposing the rate increase and one urging the Commission to “hold the line.” Only one public witness appeared at the American Falls and Gooding hearings. Five public witnesses testified at the Boise hearing. They generally oppose the rate increase as adversely affecting residential customers with either fixed incomes or all-electric homes.

C. The Partial Settlement

As mentioned above, all the parties with the exception of CAPAI entered into a Stipulation that settled most but not all issues in the rate case. On September 23, 2011, Idaho Power filed a Motion for Approval of the partial settlement. On October 13, 2011, the Commission issued a Notice of Partial Settlement. Order No. 32380.

In the Settlement Stipulation, the signing parties agreed to resolve all issues in the rate case except for the three issues discussed in paragraph No. 7 below. The signing parties agreed that Idaho Power should be allowed to recover $34 million more in annual revenues from its Idaho jurisdiction. This represents a 4.07% overall increase in the Company's annual Idaho base rate revenues instead of the original proposal to increase rates 9.9%. Stipulation at ¶ 6. The signing parties further agreed that the Company's net power supply cost is $208,100,936, which includes $11,252,265 of demand response incentive payment and $23,921,466 of retail sales revenue associated with Hoku's first-block energy sales. Stipulation at ¶ 6(a). The revenue from Hoku's first-block is an offset to power supply expenses in the Company's Power Cost Adjustment (PCA) mechanism. Other elements of the Stipulation include:

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1. Amortization. The signing parties agreed to defer $299,546 in expenses associated with the Bennett Mountain turbine inspection over a four-year period beginning on the date the Company's new base rates become effective. In addition, the parties agreed to a deferral of $436,047 in expenses associated with the “Light Detection and Ranging” (LiDAR) survey over a 10-year period beginning on the date the new base rates become effective. Stipulation at ¶ 6(b).

2. Rate of Return. The signing parties agreed that it would be just and reasonable to allow the Company to earn a 7.86% rate of return on an authorized Idaho jurisdictional rate base of $2,355,906,412. Id. at ¶ 6(c).

3. Rate Spread and Cost of Service. The signing parties agreed that the proposed $34 million annual revenue requirement should be recovered by increasing the rates for each customer class and special contract customers by a uniform percentage instead of using the Company's originally-proposed cost-of-service study. This results in a uniform rate increase of approximately 4.19%.⁴

The signing parties further agreed that Idaho Power's proposed cost-of-service study will be used to determine fixed costs for purposes of the fixed-cost adjustment (FCA) mechanism until such time as the Commission approves a different cost-of-service study. The proposed cost-of-service study is not binding on the signing parties in future cases. Id. at ¶ 7.

4. Rate Design. In determining the individual rates for each tariff schedule and customer class, the signing parties agreed to use the 2011 test year customer billing determinants including the proposed increase in the monthly service charge for residential customers. The parties agreed that the monthly service charge for residential Schedules 1, 3, 4, and 5 should be increased from $4.00 to $5.00 per month. Id. at ¶ 8. The parties also agreed to adopt the Company's proposed rate design including no increase in the winter for the third tier for residential customers.⁵

5. Load Change Adjustment Rate. In calculating the load change adjustment rate (LCAR) to be applied in the Company's PCA mechanism, the parties agreed to use Idaho Power's proposed cost-of-service methodology to determine the energy-related jurisdictional

⁴ The uniform percentage increase of 4.19% is greater than the overall increase of 4.07% because the overall increase does not apply to first-block rates under the Hoku Materials special contract. Stipulation at n.2.

⁵ The energy rates for wintertime residential customers in the first or second tier will increase 3.1%. There will be no rate increase in the energy rate for the third tier of residential customers in the wintertime - those using more than 2,000 kWh per month. Exh. 3 at 1.

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revenue requirement. The resulting LCAR of $18.16 per MWh was developed using 2011 normalized system-wide loads in the amount of 14,822,063 MWh. Id. at ¶ 9.

6. Separate Proceedings. The signing parties also agreed that two issues should be removed from the rate case and resolved in separate proceedings. More specifically, the Company will initiate separate cases related to: (1) increasing the overhead amounts paid by persons or entities requesting new service under the Company's Rule H Line Extension tariff; and (2) deciding whether the Fixed-Cost Adjustment (FCA) pilot program should be made permanent. The parties further agreed that the FCA case should be processed to allow a final Order to be issued no later than March 30, 2012. Id. at ¶ 10.⁶

7. Unresolved Issues. The signing parties were unable to reach agreement on three issues: (1) the amount of funding for the Company's low-income weatherization program; (2) the surcharge level for the Energy Efficiency Rider in Schedule 91 (currently at 4.75%); and (3) the methodology used to assess facility charges for Schedule 19 customers. These unresolved issues were addressed by the parties at the technical hearing. Id. at ¶ 11.

THE TECHNICAL HEARING

A. Motions to Strike

1. Staff Objection to Surrebuttal Testimony. CAPAI's witness Teri Ottens prefiled surrebuttal testimony on November 28, 2011. On December 2, 2011, Staff filed a Motion to Strike Ms. Ottens' surrebuttal testimony. In its Motion, Staff asserted that the Scheduling Order did not allow for the filing of surrebuttal testimony and that CAPAI did not seek procedural relief to file the surrebuttal testimony. Consequently, Staff maintained that the surrebuttal testimony offered “less than seven days before the hearing works a hardship on Staff's preparation for this case.” Staff Motion at 3.

CAPAI filed a response to Staff's Motion that was taken up as a preliminary matter at the hearing. Rule 246, IDAPA 31.01.01.246. In its response, CAPAI insisted as a matter of equity that Ms. Ottens' surrebuttal testimony ought to be entered into the record. The Association insists that it was unaware of Staff's specific objections to CAPAI's proposal to

⁶ Based upon the Stipulation and the lack of any objection, the Commission subsequently granted the Company's Motion to Initiate a Separate Docket to decide the FCA issues. Order No. 32380 at 5. On October 19, 2011, the Company filed a new application addressing the FCA issues. Order No. 32389 (Case No. IPC-E-11-19). On November 21, 2011, the Company filed a separate application regarding its proposed modifications to its Rule H line extension tariff. See Case No. IPC-E-11-24.

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increase the funding for low-income weatherization until Staff's rebuttal testimony was filed on November 17, 2011. In addition, CAPAI argued that the filing of Ms. Ottens surrebuttal testimony did not work a hardship on Staff.

Commission Findings: We affirm our decision made at the beginning of the technical hearing that Ms. Ottens' surrebuttal testimony will be admitted. Tr. at 26. However, we note that as a matter of courtesy, parties that wish to deviate from a scheduling order should notify the other parties to see if an accommodation can be reached and should request Commission permission for the deviation.

2. Objection to Non-expert Testimony. Idaho Power's counsel moved to strike portions of Ms. Ottens' direct testimony concerning “risk” and rate of return. Tr. at 838. Counsel observed that Ms. Ottens conceded that she does not possess expertise in utility ratemaking. In her direct testimony, Ms. Ottens objected to the partial settlement agreement because the proposed or settled rate of return may be too high and the revenue allocation disproportionally impacts low-income customers. Tr. at 759-760. However, she testified that she does not possess “expertise in the areas of utility ratemaking, including calculating a fair and reasonable return.” Tr. at 763. She also testified that she has “no expertise in evaluating a utility's cost-of-service.” Tr. at 773.

Commission Findings: We affirm our decision made at hearing to deny the Motion to Strike. Tr. at 839. We noted that Ms. Ottens' testimony regarding risk, rate of return, and cost-of-service are interspersed with other topics. Rather than attempt to parse or dissect the offending testimony, we find that Ms. Ottens is not an expert in these areas of ratemaking and consequently afford her testimony in these areas little weight.⁷ Tr. at 839.

B. The Proposed Settlement Stipulation

At the technical hearing on December 5, 2011, testimony in support of the partial settlement was offered by Idaho Power; Staff; Kroger; and ICL, SRA and the NW Energy Coalition (collectively referred to as “the Conservation Parties”).8 CAPAI offered testimony opposing the proposed Settlement Stipulation.

⁷We granted Idaho Power's Motion to Strike Ms. Ottens' description of the PCA mechanism because it was contained in a specific portion of her direct testimony. Tr. at 767; 843.

⁸ By letter dated November 30, 2011, the Department of Energy (DOE) asked to be excused from the hearing. The request was granted. Tr. at 13. The DOE letter also stated that the “Department supports the Stipulation and urges [its] adoption by the Commission.”

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1. Idaho Power. Company witness Tim Tatum testified that the Company supports the Settlement Stipulation. He insisted the proposed settlement “provides the Company with the ability to update its rates to better reflect current costs and the ability to economically finance new investments in infrastructure for its system.” Tr. at 32. He observed that the signing parties agreed that the Company's overall rate of return should be set at 7.86%; however, a specific return on equity was not identified as part of the Stipulation. Tr. at 33. He also noted that the Stipulation proposed that base revenues increase by $34 million, or an overall rate increase of about 4.07%. Tr. at 34.

In supporting the Stipulation, Mr. Tatum declared that the Company supported the adjustment to net power supply expense. More specifically, the Stipulation removes approximately $23.9 million as a result of increased PURPA expenses and the Company will recover these costs in the PCA mechanism. Tr. at 37.

Mr. Tatum stated the Stipulation represented a compromise among the signing parties. He testified that the partial settlement is in the public interest and results in just and reasonable rates for customers. Tr. at 32. He concluded that the Stipulation “strikes the right balance between the Company's need for timely cost recovery and the state of the current economy.” Tr. at 36. The Company will continue its “belt tightening” with regard to ongoing expenses while maintaining quality service. Tr. at 37.

2. Staff. Staff witness Randy Lobb testified that the Stipulation represented a reasonable and appropriate settlement of all the revenue issues in the case. Tr. at 705. He noted that the Stipulation provides that the Company's cost of service (COS) study be utilized to establish the fixed costs for the Fixed Cost Adjustment (FCA) mechanism, resets the load change adjustment rate (LCAR) for the Power Cost Adjustment (PCA), and modifies rate components within individual customer classes. However, he observed that the COS was not used to spread the proposed revenue increase among customer classes. Tr. at 701. He calculated that the Stipulation represents about 41% of the Company's original request for an annual increase of $83 million. Tr. at 702.

Mr. Lobb also explained how the Staff evaluated the proposed settlement. In particular, he said the settlement resulted in a “better outcome for customers than could reasonably be anticipated through litigation.” Tr. at 705. Overall, he insisted the Settlement Stipulation “results in both a reasonable overall base rate increase and equitable treatment of all

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customer classes.” Id. He briefly outlined Staff's revenue adjustments in the case and noted that the Stipulation included several of Staff's proposed adjustments including amortizing the Bennett Mountain combustion inspection costs and setting the base level of net power supply expenses for use in the PCA.

He also explained Staff's rationale in accepting a uniform revenue spread instead of using the Company's proposed cost-of-service (COS). Tr. at 713-15. He indicated that using the Company's COS would have resulted in rate increases significantly above the overall averages for irrigators and high load factor industrial customers while residential customers would see increases below the average. He noted the proposed uniform increase for all customer classes “represents a compromise that allowed the parties to achieve a comprehensive revenue requirement settlement.” Tr. at 715. In addition, he maintained that resolving the cost-of-service issue can wait until the Company's next general rate case. Tr. at 717.

Turning to rate design issues, Mr. Lobb explained that Staff supported the increase in the monthly customer charge from $4.00 to $5.00. Tr. at 720. He also stated that Staff supported the proposed change in the residential non-summer energy rate because energy production costs in the non-summer period are lower than the summer period. Tr. at 720-22. In particular, he explained that “maintaining third block non-summer energy rate at its current level will moderate the impact on [customers with all electric homes] while continuing to provide a reasonable price signal. Staff further believe[d] that rural Idaho Power customers with all electric homes have few options to control winter electric consumption when natural gas is not available.” Tr. at 722.

Finally, he noted that Staff supported separating two issues from consideration in this case: the Fixed Cost Adjustment (FCA) mechanism and changes to Rule H line extension tariff. He explained that all the issues associated with the FCA should be heard in a separate docket focusing on the merits of a permanent FCA. Likewise, he thought that the proposed increase in overhead charges for Rule H line extensions should be reviewed in a separate proceeding. Tr. at 724.⁹

3. Kroger and Conservation Parties. Kroger witness Kevin Higgins testified that Kroger fully supported the Stipulation. Tr. at 317. He asserted the Stipulation produces just and

⁹ See supra note 6.

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reasonable rates and urged the Commission to approve the signing parties' Stipulation. Tr. at 323.

The Conservation Parties' witness Nancy Hirsh is the policy director for the NW Energy Coalition. She testified that the Conservation Parties support the Stipulation as a reasonable balance of the competing interests in this case. Tr. at 496. Ms. Hirsh observed the stipulated revenue requirement is less than one-half of Idaho Power's original request which represents a clear benefit to all ratepayers. Tr. at 496-97. However, she said that a “sizeable portion” of the foregone revenue represents power purchases costs under the Public Utility Regulatory Policies Act (PURPA) and will be collected separately through the PCA mechanism. Tr. at 497. PURPA costs may result in potentially large increases in further PCA cases thereby making it more important than ever to promote energy efficiency investments. Id.

In the spirit of compromise, the Conservation Parties supported the stipulated increase being spread equally across all customer classes. “[A]ll else being equal, residential rates should increase less than rates for the irrigation, large commercial, industrial, and special contract customers.” Tr. at 498. Ms. Hirsh specifically noted the Stipulation provided that the Company's proposed cost of service was used for a limited purpose and does “not set a precedent for future cost allocation.” Id.

Ms. Hirsh also supported raising the monthly customer charge for residential customers to $5.00. She stated that raising this rate provides an appropriate conservation price signal and aligns the monthly service charge with other Idaho investor-owned utilities. Tr. at 498-99. The Conservation Parties also supported restricting the rate increase applicable to the wintertime third energy block. “Until more refined data is available, we join the Company and others in assuming this will mitigate rate impacts to electrically heated homes during times when the risks of reducing usage could be high.” Tr. at 499. However, Ms. Hirsh maintained that the concern about rates for the third energy block “points again to the need to target energy efficiency programs to increase energy and bill savings even when the costs of energy production may be modest.” Id.

4. CAPAI. The Community Action Partnership opposed the Settlement Stipulation. CAPAI witness Teri Ottens opposed the partial settlement because it failed to include a funding increase for Idaho Power's low-income weatherization program. Tr. at 754. “CAPAI simply could not justify joining in yet another . . . settlement agreement resulting in yet another rate

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increase without any offsetting provision for low-income customers.” Id. Ms. Ottens acknowledged that there were certain aspects of the settlement that are beneficial to ratepayers, such as the overall rate increase was reduced from the proposed 9.9% to 4.07%. Tr. at 755. However, CAPAI concluded that agreeing to the settlement as proposed would not be in the best interest of low-income customers or residential customers as a whole. Id. CAPAI notes that because of the continuing economic crisis and the fact that poverty rates in Idaho have increased from 12.6% in 2005 to 15.8% in 2010, there are now an additional 25,000 Idahoans under the federal poverty guideline limits. Consequently, the “importance of every low-income program, such as Idaho Power's [Low-Income Weatherization Program], continues to increase.” Tr. at 758.

Commission Findings: Procedural Rule 276 provides that the Commission is not bound by the parties' settlement agreement. IDAPA 31.01.01.276. The Commission may accept, reject or amend a proposed settlement. The Commission will independently review any settlement to determine whether it is fair, just and reasonable; in the public interest; or otherwise in accordance with law or regulatory policy. Id. Moreover, the proponents of a proposed settlement have the burden of showing that the settlement is reasonable and in the public interest. Rule 275, IDAPA 31.01.01.275.

In instances - such as this case - where one or more parties is not a party to the settlement, the Commission may convene an evidentiary hearing to consider the reasonableness of the settlement and whether acceptance of the settlement is just, fair and reasonable. As set out in Rule 275, an opponent of the settlement (such as CAPAI) should be prepared to examine supporting witnesses, offer their own witnesses, or argue against the settlement. Id.

After reviewing the testimony in support and in opposition to the Settlement Stipulation, we find the parties' partial settlement is just, fair and reasonable, with one condition regarding the recovery of facilities charge revenue discussed below. Rule 275. We further find the Stipulation represents a reasonable compromise of the positions held by most of the parties and, but for CAPAI, the Stipulation had broad support among the customer groups. The revenue adjustments reduce the magnitude of the proposed rate increases and benefit all customer classes. In particular, we note that the Settlement Stipulation represents a significant reduction (almost 60%) in the Company's initially-proposed rate increase.

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The Stipulation also contains other benefits for all classes of ratepayers. More specifically, the Stipulation proposes to spread the revenue uniformly by customer class (with the exception of determining fixed costs for the FCA). While we recognize that updating the appropriate cost-of-service for the customer classes is left for the future, we find that a uniform spread is fair and reasonable to all classes. In addition, we are not persuaded by Ms. Ottens' testimony that the settled rate of return is unreasonable, or that existing residential ratepayers are subsidizing the rates for other classes. As she conceded at hearing, Ms. Ottens is not an expert in ratemaking or cost-of-service issues. Tr. at 763, 770, 773. Consequently, her testimony in these areas is afforded little weight. Taken as a whole, CAPAI's primary focus was to increase the funding for low-income weatherization programs. This issue was specifically removed from the Settlement Stipulation and the parties were free to offer evidence on this unresolved issue.

We further find that the Stipulation's provision to not increase the rates for the third tier of residential rates in the winter is appropriate. This means that those residential customers using the highest block of energy in the winter months (more than 2,000 kWh) will not see an increase in the third tier rate. In summary, we conclude the Stipulation is reasonable and in the public interest, and we accept it.

C. Low-Income Weatherization

The next issue in dispute was the appropriate funding level for the Company's low-income weatherization program. Idaho Power's base rates include funding for energy conservation and weatherization projects for eligible low-income residential customers. The current funding level is $1.2 million annually. CAPAI proposed that this amount be increased by 125%, or to $2.7 million annually. The Conservation Parties supported CAPAI's request, while Staff opposed the increase in funding.

1. CAPAI Proposal. Citing continued economic concerns and an increase in Idaho poverty rates, CAPAI asserted the funding level for the Company's low-income weatherization program should be significantly increased to obtain parity with the other large electric utilities in Idaho. Tr. at 755, 760. Ms. Ottens explained that Idaho Power's funding for the low-income weatherization program has not increased since 2003 when it was raised to $1.2 million per year. Until now, CAPAI had not proposed that the Commission increase that funding level because CAPAI focused its efforts on increasing the weatherization funding for the other two large electric utilities: Rocky Mountain and Avista. Tr. at 771-72.

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Since 2003, Avista and Rocky Mountain have increased their funding for weatherization programs. Ms. Ottens calculated that Avista's per capita funding level is approximately $6.69 per customer, while Rocky Mountain's per capita funding level is $5.32 per customer. In contrast, she calculated that Idaho Power's per capita funding for low-income customers is now $3.06. Tr. at 780-81. Consequently, she insisted that this per capita “disparity” between Idaho Power and the other two utilities warrants an increase in Idaho Power's funding for low-income weatherization.

Ms. Ottens maintained that the concept of parity is “a very important principle” in determining the appropriate funding level for Idaho Power's low-income weatherization program. Tr. at 778. She asserted the funding disparity among the three utilities means that Idaho Power's low-income customers are being discriminated against. Tr. at 779.

Ms. Ottens partially relied upon the number of households on the CAP “waiting list” to support her proposal to increase funding. Tr. at 793, 814. More specifically, she pointed to the waiting list in Exhibit 49 and said the number of customers on the waiting list continues to grow. Tr. at 793.

Ms. Ottens testified that CAPAI is aware of Staff's concerns about evaluating the cost-effectiveness of what is referred to as “non-energy benefits.” “These benefits include the many positive effects of [low-income weatherization] programs that do not directly affect energy consumption including such things as reduced billing and collection costs, improved cash flow, reduced bad debt write-off and others.” Tr. at 788. While CAPAI does not oppose evaluating the non-energy benefits, it does not want an evaluation to delay increasing the weatherization funding to $2.7 million per year. Tr. at 789. Delay would mean that the waiting list for weatherization projects would continue to grow. Tr. at 793.

2. Conservation Parties. The Conservation Parties defer to CAPAI's funding proposal but believe the proposed funding level is appropriate given Idaho Power's most recent evaluation contained in its 2010 demand-side management (DSM) annual report. Tr. at 502. Ms. Hirsh testified that the weatherization program should not be viewed as a social program but as a part of an overall DSM program. Tr. at 504. She explained that Idaho Power and its customers all save money from effective low-income weatherization programs by reduction of peak loads, deferral or avoidance of costly new generation, reduction of energy costs for eligible

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customers, reduction of unpaid bills, and avoidance of the cost of disconnecting and reconnecting customers. Tr. at 504-07.

3. Idaho Power. Idaho Power's witness Theresa Drake reported that Idaho Power does not object to increasing the funding for low-income weatherization “provided there is the potential for more cost-effective savings.” Tr. at 62. However, she argued that using the metric of parity alone “is not a good method for determining need, given that demand for [low-income weatherization] services may vary significantly between utilities.” Tr. at 63. More specifically, she stated that increasing the funding for weatherization should be based on need. Tr. at 64. While she agreed that one of the factors in determining need would be the CAP waiting list, she asserted that the waiting list for weatherization projects (Exhibit 49) contained data that is irrelevant and immaterial. In particular, she noted that several of the six community action agencies shown on Exhibit 49 serve citizens outside Idaho Power's service territory. Exhibit 49 also included customers who used non-electric heat sources such as propane, coal, wood, and fuel oil. In addition, the waiting list does not represent eligible customers with projects that will meet the cost-effective criteria. Tr. at 65-66. She said need could be shown by determining the number of customers that are federal income eligible, heat their homes solely with electricity, are on the CAP waiting list, and whose electric consumption could be reduced by a weatherization project. Tr. at 64-65.

Ms. Drake also took issue with CAPAI's assertion that Idaho Power has not increased its funding for low-income weatherization projects since 2003. In particular, she noted that Idaho Power instituted a new weatherization program called “Weatherization Solutions for Eligible Customers” (“Solutions”) in 2008. In 2010, Idaho Power expended more than $220,000 for the program; anticipates spending more than $700,000 in 2011; and has budgeted more than $1.0 million in 2012. Tr. at 70-71. She explained that the eligibility ceiling for Idaho Power's low-income weatherization program is 200% of the federal poverty level, while the income guidelines for Solutions is between 175% and 250% of the federal poverty level. Thus, there is some eligibility overlap between the low-income and the Solutions weatherization programs. Tr. at 70, 92. In addition, Idaho Power committed $125,000 to fund an energy efficiency education program for the Community Action Agencies for customers receiving energy assistance. Tr. at

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71.¹⁰ Finally, all libraries in Idaho Power's service area have energy efficiency kits that may be checked out by patrons. Tr. at 73. Thus, Idaho Power estimates that it will contribute a total of $2.025 million in weatherization and energy programs in 2011 ($1.2 million in low-income weatherization; Solutions at $700,000; and easy savings program at $125,000), and exceed that amount in 2012. Tr. at 71.

4. Staff. Staff witness Stacey Donohue took issue with CAPAI's assertion that funding “parity” justifies a 125% increase in funding level. Tr. at 630. Instead, Ms. Donohue explained that the funding for low-income weatherization should be based on the relative “needs” of customers instead of solely maintaining per capita parity among the three utilities. Tr. at 633. More specifically, she suggested that “need” could more appropriately be determined by examining “the number of low-income customers, number of homes needing weatherization, and poverty rates.” Tr. at 633. Ms. Donohue testified that based on 2009 poverty rates, Avista had the highest poverty rate at 16.1%, Rocky Mountain was at 14.9%, and Idaho Power was at 14.7%. Tr. at 654. On cross-examination, Ms. Donohue also mentioned that need could be influenced by the unemployment rate and cost-effectiveness. Tr. at 656-57. She also acknowledged that parity may be “one of the metrics” for evaluating funding. Tr. at 694.

She took issue with CAPAI's waiting list (Exhibit 49). In its current form, she said it is not very useful in determining the waiting list for Idaho Power customers. Tr. at 658. She recommended the Commission convene public workshops so that the various stakeholders could “identify appropriate methods for measuring need, and establish proportional funding levels.” Tr. at 630.

Staff also opposed increasing the funding level for weatherization based upon concerns regarding the measurement of cost-effectiveness of the Idaho Power program compared to the programs of the other two utilities. Id. Ms. Donohue explained that Staff believes “that cost-effectiveness methodologies, including the treatment of non-energy benefits, should be reasonably similar [among] utilities rather than necessarily 'uniform.' This is the standard for other DSM program cost-effectiveness calculations and Staff sees no reason to modify that approach for low-income programs.” Tr. at 635.

¹⁰ Idaho Power also provides the CAP agencies with pertinent material on saving energy, and provides customers with on-line hourly usage information so that customers can monitor their energy consumption. Tr. at 69.

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She reported that Staff identified “problematic inconsistencies” among the three income programs. It is clear that all three utilities “have very different standards for measuring energy savings, recording measure level data, providing oversight of community action partnership ('CAP') agencies, and calculating cost-effectiveness.” Tr. at 637. Although the CAP agencies implement low-income programs using identical Department of Energy standards, there is a significant discrepancy in the results of the cost-effective calculations. Tr. at 639. In explaining the inconsistencies among the three weatherization programs, she noted that for the year 2010 the utility cost test ratio for Idaho Power's program was 3.27, for Avista it was .66 and for Rocky Mountain it was .66. Tr. at 666, 682. Given these discrepancies, she opposed CAPAI's proposal to increase weatherization funding until Staff, CAPAI, the utilities, and others have a clearer understanding of cost-effectiveness calculations. Id. Ms. Donohue recommended the Commission convene public workshops so the stakeholders can discuss and resolve issues relating to need, implementation methodology, measurements of cost-effectiveness, identification of non-energy benefits, and the appropriate level of annual low-income funding for the three utilities. Tr. at 645.

Commission Findings: Based upon our review of the testimony, we decline CAPAI's suggestion to increase the low-income weatherization funding at this time for several reasons. First, we find that parity alone is not an appropriate measure to determine the funding levels for low-income weatherization programs. Consequently, we are not persuaded by CAPAI's argument that parity demonstrates that the funding for Idaho Power's weatherization needs to be increased at this time. We believe there are a host of factors that should be examined to determine the appropriate need and funding level. The parties in this case have recommended several measurements for determining need such as: unemployment rates, poverty rates, the number of electrically-heated homes, the CAP waiting list, and the cost-effectiveness of projects. We believe these are all appropriate factors in determining need.

Second, although the two programs are funded from different sources, we find that the Company's implementation of the “Solutions” weatherization program cuts against CAPAI's argument that weatherization funding has not increased since 2003. As indicated above, the Company anticipated spending $700,000 for the Solutions program in 2011, and contemplates spending $1.0 million in 2012. Although this program is funded through the Energy Efficiency Rider, the income eligibility for the Solutions program does overlap with the income eligibility

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for the low-income weatherization program. Consequently, we find that Idaho Power's expenditure for weatherization projects for 2012 to be approximately $2.2 million, not including the $125,000 in the education program or the other educational information and tools offered to CAPAI and libraries. In addition, we note that the ARRA provided $31 million for weatherization programs that funded more than 2,000 residential projects across the State, including Idaho Power's service territory. Tr. at 856-57. Thus, we find that funding for Idaho Power's weatherization programs has increased by implementation of Solutions and ARRA.

We further find that Exhibit 49 does not accurately portray the number of Idaho Power households on the project waiting list. As Ms. Ottens conceded on cross-examination, Exhibit 49 contains information not applicable to Idaho Power's service territory and includes households supplied by other electric suppliers. Moreover, Exhibit 49 is not limited to only households with electric space-heating. Tr. at 847; 857-58. Consequently, we direct the parties to discuss other appropriate data gathering mechanisms that would more accurately portray the “waiting lists” for low-income customers for each of the three electric utilities.

Third, we are concerned about the cost-effectiveness of Idaho Power's low-income weatherization program. Because ratepayers fund Idaho Power's weatherization programs, we have a responsibility to ensure that these programs are cost-effective and designed to maximize benefits for all customers. We find it reasonable to open a case and convene public workshops for stakeholders and other interested persons to discuss ways of determining the relative need for low-income weatherization programs. The workshops will also be an effective tool for allowing stakeholders to analyze and evaluate the various cost-effectiveness measures and non-economic benefits derived from low-income weatherization. Consequently, it is our intent to convene public workshops, as soon as possible, to discuss and resolve these weatherization issues.

D. Energy Rider

Several parties disputed the appropriate surcharge rate for the Energy Efficiency Tariff Rider, Schedule 91. The Rider is a monthly charge that funds the Company's energy conservation, efficiency and demand-side management (DSM) programs, which are generally intended to reduce electric consumption that in turn reduces the need for generation.¹¹ Order No. 30560. The current Rider surcharge level is 4.75%. The parties did not agree on whether this

¹¹ Rider-funded programs include: the Solutions low-income weatherization, the air-conditioning cycling, appliance replacement for residential customers; “peak rewards” for irrigation customers; and conservation/efficiency programs for commercial customers. Order Nos. 30560, 30814.

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level remains appropriate. At the technical hearing, Kroger, ICIP, Idaho Power, and Staff offered testimony that the surcharge should be reduced. The Conservation Parties (ICL, SRA, and NW Energy Coalition) recommended that the existing surcharge level be maintained.

1. Kroger. Kroger witness Kevin Higgins proposed reducing the Rider to 3.4%. He calculated in Exhibit 501 that Idaho Power would recover about $39.7 million in costs through the Rider in 2012 at the current rate.¹² Tr. at 319-21. He noted that the Stipulation accepts Idaho Power's proposal to shift $11.2 million of demand response program cost recovery from the Rider into base rates, but no corresponding reduction in the Rider was proposed. Tr. at 317-19.

Mr. Higgins recommended the Commission reduce the Rider level to 3.4% in recognition that the Company will be shifting $11.2 million in demand response program costs from energy efficiency funding into base rates. Tr. at 317. Even with a 3.4% Rider, funding for non-demand response programs would increase by $1.2 million relative to pro forma levels due to the underlying 4.1% rate increase proposed in the Stipulation. Id. He explained that Idaho Power's non-demand response program cost recovery through the Rider at current rates amounts to $28.5 million (for 2012),¹³ and that the Company can still recover this amount - at current rates - with a 3.4% Rider charge. Thus, applying the 3.4% Rider to the stipulated revenue requirement will increase Rider revenues by nearly $1.2 million, to $29.6 million. Tr. at 320. In addition, he calculated that going forward, $5.2 million in Custom Efficiency costs will be booked as a regulatory asset, providing more headroom for non-demand response programs relative to historical funding levels. Tr. at 327-28; 320, n.2.

Mr. Higgins said setting the Rider at 3.4% allows for net growth in funding for non-demand response programs while being mindful of the overall rate impacts being borne by Idaho Power customers. In contrast, shifting $11.2 million from the Rider into base rates while raising those base rates by 4.1 % and not decreasing the Rider unreasonably burdens customers. Tr. at 321.

Mr. Higgins noted that a 3.4% surcharge is equal to the surcharge approved for Rocky Mountain Power in Idaho, and is consistent with the level of percentage surcharges levied elsewhere in the region for energy efficiency cost recovery. Tr. at 322-23. He concluded that

¹² Exhibit No. 501, l.18, col. (c). Mr. Higgins said the calculation is consistent with Idaho Power Rider revenues presented in Idaho Power Exhibits Nos. 47 and 43 and includes expected Rider recovery from Hoku First Block sales effective January 1, 2012.

¹³ Exhibit No. 501, l.18, col. f.

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reducing the Rider to 3.4% will still provide sufficient funds for DSM projects while benefiting customers by lowering the surcharge.

2. ICIP. ICIP witness Don Reading proposed reducing the Rider to 3.8%, or at least to 4.0% as suggested by Staff. Dr. Reading explained that if the Commission were to leave the Rider at 4.75% (as the Conservation Parties' suggest) and after removing $11.3 million of demand response costs, the Company would collect about $7.5 million more than the current, overall DSM expenditure level. Tr. at 422-23. Even though some DSM costs will be collected in base rates rather than though the Rider, the overall rate impact of Idaho Power's proposal on customers is the same as increasing the Rider by $11.3 million. Tr. at 421-22. If the Rider is left at 4.75% and the demand response programs are moved to base rates, customers would effectively be paying the equivalent of a 6.1% Rider. A dollar for dollar reduction in the Rider from removing the $11.3 million demand response incentive programs would equal about a 3.8% Rider. Id.

Dr. Reading said a dollar for dollar “reduction to 3.8% may be an equitable and justifiable path,” particularly because this is how the Commission treated Rocky Mountain Power's Rider after one of Rocky Mountain's conservation programs was removed from the Rider. Tr. at 422. However, he said that the ICIP fully supports the Commission Staff's testimony and recommendation to lower the Rider to 4.0%. Tr. at 422-23.

3. Conservation Parties. The Conservation Parties' witness, Ms. Hirsh, recommended that the Commission keep the Rider at 4.75%. Contrary to what other parties suggest, she said that recovering demand response incentives as power supply expenses does not mean the Commission should reduce the Rider rate. Tr. at 512. She explained that the Rider faces funding pressure because the Commission has directed Idaho Power to pursue all cost-effective energy efficiency. Tr. at 516, 518. However, she calculated that the current Rider level enables the Company to acquire less than 20% of available DSM potential. Tr. at 517-18.

Ms. Hirsh acknowledged that the Stipulation does reduce pressure on the Rider by moving certain costs into base rates. However, she cautioned that significant pressure remains because Idaho Power must fund existing programs, recover the prudently incurred back balance in the Rider account, and provide reasonable “headroom” for planned growth to achieve more economic potential. Tr. at 518. She said that any potential “headroom” will be quickly consumed by ongoing DSM expenses and the need to recover the current Rider balance deficit.

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Tr. at 522. Further, while the Company's current DSM program achievements are laudable, they do not capture all the economic potential energy savings available in the Company's service territory. Tr. at 524.

Ms. Hirsh observed that the Company has identified other cost-effective programs that will require increased program funding. Tr. at 528-31. Further, she said other programs, like that contemplated by the Company's recent agreement with the Idaho Office of Energy Resources for the K-12 Energy Efficiency Project, might further increase cost-effective energy efficiency and require increased program funding. Tr. at 530. Maintaining the Rider funding level now provides the opportunity to meet expectations for increased administrative costs and acquire savings from existing programs and new measures that are preliminarily shown to be cost effective. Tr. at 532. Finally, she said maintaining the current 4.75% Rider will have a negligible impact on customers and will increase each customer's bill by less than $3.36 annually. Tr. at 520.

4. Staff. Staff proposed reducing the Rider to 4.0% of billed revenues. Staff witness Randy Lobb said decreasing the Rider would further reduce the overall rate increase from 4.19% (the stipulated rate increase) to 3.44%. Tr. at 698. Mr. Lobb insisted that moving $16.5 million in annual DSM expenditures into base rates and lowering the Rider still provides more revenue than needed to fund the Company's existing DSM programs. Tr. at 724-25. He stressed that Staff's proposal does not signal a decreased commitment to DSM and energy efficiency. Tr. at 725. Rather, Staff sees the partial shift in DSM cost recovery as an opportunity to increase DSM program funding while simultaneously lessening the impact of the base rate increase in a difficult economy. Id.

Staff witness Donn English echoed Lobb's testimony. He explained that the parties' agreement in the Stipulation to move $11.3 million in DSM incentive payments from the Rider into base rates, produces a net increase of $16.6 million to Rider revenue over 2010 levels, or a 92% increase. Tr. at 560. He noted that Idaho Power collected about $34.6 million in 2010 Rider revenue. Id. He said a 4.0% Rider would bring in about the same amount as the 2010 revenue to fund Rider programs. Additionally, the Commission allowed Idaho Power to account for custom efficiency program incentives as a regulatory asset beginning January 1, 2011, which adds $5.1 million (based on 2010 levels) to Rider revenue. Tr. at 561 (citing Order No. 32245).

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However, Mr. English cautioned against decreasing the Rider below 4.0% to avoid falsely signaling that the Commission and Staff do not support Idaho Power's DSM efforts. Tr. at 563.

Mr. English agreed that Idaho Power has an existing deferral balance in the Rider account of over $8 million because Idaho Power spent more on DSM programs than it collected through the Rider. He testified that a Rider of 4.0% of base revenues will supply sufficient funding to eliminate the Rider account balance in less than one year, and will provide ample revenue for expanding DSM programs. He estimated a 4.0% Rider would provide $9.3 million over 2010 expense levels. Tr. at 566. As programs expand, the Rider rate can be reevaluated.

Mr. English also asserted that reducing the Rider from 4.75% to 4.0% provides rate relief to almost all customers. Tr. at 564. He disputed Ms. Hirsh's statement that leaving the Rider would have a negligible impact on customers. He calculated the average annual impact per customer of the 0.75% difference is $13.72 instead of the $3.36 claimed by Ms. Hirsh. Tr. at 566-67.

5. Idaho Power. Company witness Theresa Drake evaluated the various Rider positions offered by the parties. She opposed Kroger's proposal to reduce the Rider to 3.40% because it seemingly ignores the negative balance in the Rider account and would not adequately support the Company's existing programs. Tr. at 81.

She testified that as of the end of October 2011, Idaho Power had a negative $6 million Rider account balance. Tr. at 75. Ms. Drake analyzed both the 4.75% and 4.0% surcharge levels. Tr. at 76, Exh. 50. She estimated that given current expenditures, a 4.75% Rider yields more than a $5 million balance at the end of 2012 and more than a $35 million balance in 2014. A 4% Rider yields a negative $1 million balance at the end of 2012 and $15.8 million balance at the end of 2014. Id. Regardless of the level ordered by the Commission, Ms. Drake reaffirmed the Company's commitment to energy efficiency initiatives, and the Company's commitment to pursuing all cost-effective energy efficiency. Tr. at 76-77.

Ms. Drake said decreasing the Rider to 4.0% would decrease the Rider's current negative balance while supporting existing and new energy efficiency services. Tr. at 79-80. She said that if a 4.0% Rider level ultimately proved insufficient, the Company would ask the Commission to let the Company increase the funding. Tr. at 81.

Commission Findings: The Rider recommendations range from keeping its current 4.75% level to decreasing it to 3.4%. Based upon our review of the evidence, we find that

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setting the Rider at 4.0% is fair, just, and reasonable. We decline Kroger's and ICIP's recommendation to decrease the Rider to 3.4% or 3.8%. Such reductions would not allow sufficient “headroom” for enhanced funding or extinguish the existing balance in a reasonable time period. Instead, we find a 4.0% Rider level will adequately fund Idaho Power's existing and future DSM programs, and enable the Company to eliminate the negative balance in the Rider account. Further, we find that setting the Rider at 4.0% appropriately balances energy efficiency funding while at the same time providing all customers with lower overall rates. We continue our commitment that the Company should pursue all cost-effective energy efficiencies. If the 4.0% Rider proves to be an insufficient rate to fund future DSM programs, we expect the Company (or other parties) to bring this matter to our attention.

E. Facilities Charge

Idaho Power proposed to lower the facilities charges assessed to certain customers for utility facilities that are installed, owned and maintained beyond Idaho Power's “point of delivery.” Tr. at 217. Idaho Power offered testimony in support of its proposal to lower facilities charges, while ICIP offered testimony for either further reductions in the charge or even transferring ownership of the facilities to customers. In addition, one public witness also requested relief. No other party offered direct testimony on the facilities issue.

1. Idaho Power. Company witness Scott Sparks testified that the Commission last reviewed the facilities charge rates in 1987 in Case No. U-1006-298. Tr. at 216. Mr. Sparks explained that at the Company's option, it may offer facilities charge services to primary and transmission service level customers under Schedules 9 (Large General Service); 19 (Large Power Service); and 24 (Agricultural Irrigation Service). Tr. at 217.¹⁴ Mr. Sparks described the current and proposed monthly facilities charges as follows:



Schedule	Current Monthly Facilities Charge	Proposed Monthly Facilities Charge
9	1.7%	1.41%
19	1.7%	1.41%
24	1.7%	1.41%
15*	1.75%	1.51%
41*	1.75%	1.21%

* See n.14; Tr. at 218.

¹⁴ As of June 1, 2004, customers taking service under Schedule 15 (Dusk to Dawn Customer Lighting) and Schedule 41 (Street Lighting Service) were no longer eligible for facilities charges although some customers continue to pay monthly facilities charges for facilities installed prior to June 1, 2004. Id.

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Mr. Sparks said the Company updated the facilities charge rates using the nine cost components the Commission previously found reasonable during the last review of the charges in 1987. Tr. at 219. These cost components are:

Rate of Return - The rate of return ordered by the Commission in this case.

Booked Depreciation - The straight-line annual depreciation of assets based on a levelized 31-year basis.

Income Taxes - The tax paid on the revenue amount received from the equity portion of the rate of return.

Property Taxes - The tax paid for the distribution facilities. Facilities beyond the delivery point are assessed property taxes.

Other Taxes (Regulatory Fees) - The regulatory fees assessed by the Idaho and Oregon commissions. Part of these fees are tied to investment in facilities installed beyond the delivery point.

Operation and Maintenance (O&M) Expenses - An average O&M rate for all distribution equipment.

Administration and General Expenses - An expense based on total administration as a percentage of total plant investment.

Working Capital - The carrying cost of inventory. Working capital is based on the cost of capital to finance the distribution facilities inventory and the property taxes that the Company pays on its inventory.

Insurance - Reflects Idaho Power's additional cost for insurance premiums resulting from facilities installed beyond the delivery point. This insurance rate covers property, casualty, and worker's compensation. It does not cover failed-facility replacement costs. Tr. at 220-22.

In its direct case, the Company proposed the following values or percentage amounts for each component by rate class:



Cost Components	Schedule 15	Schedules 9/19/24	Schedule 41
Rate of Return	4.81%	4.81%	4.81%
Book Depreciation	3.23%	3.23%	3.23%
Income Taxes	1.9%	1.9%	1.9%
Property Taxes	0.56%	0.56%	0.56%
Other Taxes (Regulatory Fees)	0.14%	0.14%	0.14%
O&M	4.73%	3.58%	1.18%
Administration & General	2.28%	2.28%	2.28%
Working Capital	0.14%	0.14%	0.14%
Insurance	0.32%	0.32%	0.32%
Annual Total	18.1%	17%	14.6%
Monthly Rate	1.51%	1.41%	1.21%

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Source: Tr. at 222.¹⁵

Mr. Sparks said the decreased rate of return is the primary cost component responsible for the proposed rate reduction. Tr. at 223. He estimated that the proposed facilities charge rate reduction will decrease the Company's annual revenue by $1.1 million. He said reducing revenue will increase revenue requirements for each customer class that collects facilities charge revenue (i.e., Schedules 9, 19, and 24). In turn, the energy rates for these customer classes will increase slightly to recover the decreased facilities charge revenue. Id.

On rebuttal, Company witness Warren Kline said customers typically own, operate, and maintain the equipment beyond the Company's delivery point. Id. However, some customers ask the Company to assume these obligations because they lack the capital or expertise to fund, design, install, and maintain necessary facilities, or because they want to take advantage of other benefits covered by the facility charge (e.g., the Company's 24/7 customer service, equipment inventories, and trained personnel ready to respond in emergency situations). Tr. at 140-43. He said that Idaho Power provides facility charge service to about 240 Idaho customers. Tr. at 139.

Mr. Kline said the Company has some mixed-ownership customers left over from the early days of facilities charges. However, the Company dislikes such arrangements and will revisit them as opportunities arise. He said the Company has not allowed mixed-ownership for new facilities since the 1980s. Tr. at 146. He said the Company dislikes mixed-ownership for operational and safety reasons. For example, without a clearly demarcated “end point” where Idaho Power's facilities end and a customer's facilities begin, confusion arises about who is responsible for working on what pieces of equipment. Further, Company personnel may not know of any modifications or repairs a customer may have performed on equipment. Also, the Company adheres to the National Electric Safety Code while customers follow the National Electric Code. These different codes may result in different customer equipment with which the Company and its employees are not familiar. Tr. at 145-48. Mr. Kline said the Company has a few agreements under which it maintains customer-owned facilities, but the Company is migrating away from this arrangement and, on a going forward basis, the Company will not maintain customer-owned facilities. Tr. at 149.

¹⁵ Mr. Sparks said the Schedules 9 and 24 facilities charge rates align with the derived rate for Schedule 19. The Company and the Commission have determined that the Schedule 19 facilities charge rate accurately reflects facilities charge costs under Schedules 9 and 24. Tr. at 222.

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Company witness Michael Youngblood on rebuttal testified about the proposed “buyout option” and ratemaking issues associated with facilities charges. He said that facilities beyond the Company's delivery point are solely for the purpose of meeting the electrical service requirements of an individual customer. Tr. at 240. Accordingly, he asserted it is inappropriate to charge other customers for the investment and maintenance of those facilities.

He explained the Commission-approved methodology for calculating the facilities charge provides a “levelized” rate of cost recovery for customers. In sum, the facilities charge is a levelized method for assigning costs, whereas the cost-of-service approach is a point in time methodology of assigning costs on a non-levelized basis. Tr. at 241. Both are intended to recover, on average, the same amount of revenue over time. Id. Any differences between the non-levelized revenue requirement and the levelized revenue requirement exist as intra-class subsidies between those customers paying facilities charges and those who do not within each customer class. Tr. at 241-42.

Mr. Youngblood said that over time, the levelized revenue methodology recovers the same revenue as a non-levelized methodology. Tr. at 242. The difference is in the timing of the revenue recovery. Tr. at 243 (chart). In the early years, the levelized methodology does not recover the full revenue requirement needed; however, in the later years the levelized methodology recovers the shortfall from the early years. Id.

Mr. Youngblood said it would be complicated and impractical to determine an individual revenue requirement for each customer with facilities beyond the point of delivery. Id. He said with such an approach, the calculated facilities charges would differ for each of the 240 facilities charge customers and each customer's rate would continually change. Tr. at 243-44. While the levelized facilities charge recovery is less than the non-levelized rate in the early years, the revenue shortfall for the individual facilities charge customers is subsidized by the rest of the class. In the later years, when the levelized facilities charge exceeds the necessary revenue requirement, the facilities charge customers “repay” the prior subsidy. Id. These intra-class subsidies are an expected and normal outcome of the levelized ratemaking approach. Tr. at 244-45. Any facilities charge change for an individual customer would change the revenue credit amount received as an offset to the class revenue requirement. Tr. at 245-46. This would necessitate a new revenue requirement determination to adjust the base rates of the entire class. Tr. at 246. Thus, adopting the recommendation of ICIP would require the Company to

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recalculate its revenue requirement for each customer class with a facilities charge whenever an individual customer's facilities charge rate changes. Such an approach would be complicated to administer and require continual changes to class base rates. Id.

Mr. Youngblood also insisted that it is impractical to track the actual depreciation levels for each individual piece of equipment for each customer. Id. The result would be a separate facilities charge rate for each of the thousands of individual equipment pieces for each of the 240 individual facilities charge customers. Tr. 246-48. This ICIP approach would be an administrative nightmare, would be unduly burdensome, and increase the complexity of the facilities charge rate. Tr. at 248. He said the Company does not track depreciation levels for individual facilities for any other customer class or service. Id. Rather, per standard ratemaking practice, the Company averages the actual depreciation levels for a particular level of service or customer class and spreads cost recovery equally to all customers in the class. Id.

Mr. Youngblood explained the Company's proposal to give facilities charge customers the option of buying Company-owned facilities. Id. The Company created a new Rule M (Facilities Charge Service), which would consolidate facility charge rules.¹⁶ This will enable the Company to more efficiently manage tariff issues related to facilities charge services. Id. Under the proposed Rule M, customers may ask to buy Company-owned facilities installed beyond the delivery point. The Commission must approve all sales and they must meet the following conditions:


•	Compliance with Idaho Code § 61-328;


•	No mixed-ownership of facilities;


•	The customer must provide the O&M of all facilities installed beyond the delivery point after the sale; and


•	The customer must pay for the engineering costs for determination of the sale.

Tr. at 251-52. He said Idaho Code § 61-328 provides that the sale of facilities must not adversely impact remaining customers or customer rates. Tr. at 252-53. Further, the Company would need to ensure the appropriate equipment is in place at the delivery point so no equipment failure would degrade the Company's reliability and service to remaining customers. Tr. at 253.

¹⁶ The Company's proposed new Rule M is set out in Exhibit 52.

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If the proposed sale meets these conditions, the Company would make a filing with the Commission asserting that such sale is in the public interest. Id.

He said the Company does not propose a specific methodology for determining the facility sales price. Rather, the Company simply proposes changing its tariffs to allow for the buyout option. Id. He stated that if the Commission approves the Company's Rule M tariff, and if a customer asks to buy facilities, the Company would attempt to agree with the customer on a sales price before bringing the proposed sale to the Commission. Tr. at 253-54. If the Company and customer cannot agree on a price, either of them could ask the Commission to determine the appropriate price. Tr. at 254.

Mr. Youngblood next discussed how Stipulation paragraph 11(c) would operate if the Company were to give away Company-owned facilities as proposed by ICIP. Tr. at 259.¹⁷ He said that if fully depreciated facilities were assigned to customers, the Company would experience a revenue shortfall. Tr. at 259. In that case, the Company would cover the shortfall by increasing rates for Schedule 19 customers. Id.

2. ICIP's Testimony. ICIP witness Don Reading said Idaho Power's cost-of-service study shows the Company expects to collect $6,020,018 in facilities charge revenue for the test year. Tr. at 366. Schedule 19 customers provide 61% of the revenue, Schedule 9 customers provide 26%, and Special Contract Schedule 29 (Simplot's Don Plant) provides 9%. Tr. at 367-68. He criticized Idaho Power's proposal to decrease the facilities charge percentage rate to 17%. Id. He said the annual 17% charge assessed in perpetuity is excessive because the initial investment in equipment will never be amortized or depreciated. Tr. at 376. He maintained that the Company should calculate the percentage rate based on the lower rate of return and other costs contained in the Stipulation. Tr. at 378-79. Most importantly, he argued that the principal amount of the initial facilities investment must be depreciated as the equipment ages, just as the principal amount of any other rate-based asset depreciates over time. Tr. at 378. Absent such treatment, individual customers will subsidize the rest of the customer class and may overinflate Company revenues for depreciated equipment. Tr. at 379-80.

¹⁷ Stipulation paragraph 11(c) states: “Signing Parties agree that any revenue requirement impacts resulting from changes to the facilities charge methodology or changes in property ownership shall be directly assigned to Schedule 19 customers in the form of a base rate increase or reduction so that no other customer classes shall be impacted by any resulting change.”

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Dr. Reading explained that the Company derives the facilities charge rate by using costs from distribution facilities equipment on the Company's side of the meter. Tr. at 380. The Company then identifies the components of standard distribution equipment that it believes should be allocated to an individual customer for use of distribution facilities on the customer's property. Id. He reported the Company has used FERC Form 1 data to calculate the percentage amount for each identified component it believes it would need to recover from an individual customer. Tr. at 380-81. In this manner, the Company calculated the individual components of the facilities charge (income taxes, property taxes, other taxes, O&M, administration and general, working capital, and insurance). Tr. at 381. These components plus the rate of return and depreciation make up the Company's facilities charge to the individual customer.

Dr. Reading said the main flaw in Idaho Power's facilities charge rationale is that the facilities charge does not take depreciation into account even though the facilities charge equipment depreciates in rate base. Tr. at 382-83. He agreed that facilities charge revenues are credited back to the customer's class and reduce the revenue required from that class when rates are set in a general rate case. Tr. at 383. However, he insisted it is unfair for the Company to not use depreciated values to calculate monthly facilities charges. Id. Such treatment amounts to an unfair subsidy from individual facilities charge customers to other ratepayers and could result in the Company being overcompensated for depreciated assets. Tr. at 384-85.

He calculated the average ages of the facilities charge equipment for the primary facilities charge customer classes are 17 years old for Schedule 9, 18 years old for Schedule 19, and 24 years old for Special Contract Schedule 29. Tr. at 389-390. Accordingly, on average customers do not have “newer” equipment and Idaho Power is overcharging individual customers for facilities on their premises. Tr. at 388.

Dr. Reading characterized Idaho Power's proposal to lower the facilities charge from 20.4% to 17.00% annually as a long overdue, “good start.” Tr. at 410. Also, he said the Company should recalculate its proposed facilities charge percentage to match the costs contained in the Stipulation. The corresponding decreases in the FERC Form 1 accounts used to calculate the facilities charge should also be updated to ensure that the charge and its credits back to each customer class match the value of the assets contained in that class's revenue requirement. Id. Further, the revised percentage should be calculated against the depreciated value of the initial investment using appropriate amortization schedules. Tr. at 410-11.

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Dr. Reading next discussed his recommendations for changes to the ownership options for facilities charge equipment. He said that over 15 years at a 14% annual interest rate, the customer pays the Company more than 2.5 times the Company's original cost for the currently installed equipment. Dr. Reading said given this, it would be fair for the Company to assign ownership of facilities charge equipment to existing facilities charge customers (such as Simplot) who have paid overall facilities charge rates of more than 2.5 times the original equipment cost. Id. For existing facilities charge customers who have not paid more than 2.5 times the original cost, Dr. Reading proposed that the Company provide such customers with the option to buy the facilities at depreciated book value for each piece of equipment based on the Company's Commission-approved depreciation schedule. Tr. at 413. Dr. Reading also said the Commission should direct Idaho Power to implement an ownership option which allows the customer to take over ownership of the equipment and pay a “limited facilities charge” for the Company's ongoing O&M expense. Tr. at 413-14.

Dr. Reading also suggested an alternative proposal for a purchase price if the Company believes it cannot calculate the depreciated book value for each piece of equipment based on the Company's Commission-approved depreciation schedule. Tr. at 414. He said the Company could approximate the remaining book value by calculating the initial value of all equipment installed at a customer's facility and applying an appropriate depreciation schedule. Id. If Idaho Power cannot calculate the actual remaining book value, then for simplification and compromise, Dr. Reading recommended the Commission should allow customers to buy the equipment from Idaho Power at a depreciated book value using a 15-year straight-line depreciation schedule. Tr. at 418.

Finally, Dr. Reading recommended the Commission require Idaho Power to inform each facilities charge customer in writing of its facilities charge, the costs over the life of the equipment, and the ownership options. Tr. at 419. He said the Company's notice should disclose payoff amounts at different milestones, effective interest rates and other components of the charge and require written consent from the customer. Id. He said the tariff should clearly state the buyout option, and that a customer can choose to own its distribution facilities (as opposed to providing only the Company with the option to decide whether to sign a customer up for the facilities charge). Tr. at 419-20. He also recommended that Idaho Power allow mixed-ownership between the Company and customers on customer property. Tr. at 420. He said

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mixed-ownership would enable the customer to choose which equipment will be customer-owned or be subject to the facilities charge. Id.

Both ICIP witness Don Sturtevant and Dr. Reading discussed how the facilities charge affects Simplot. Mr. Sturtevant said Simplot supports ICIP's position on the facilities charge. Tr. at 455-56. He said Simplot is one of Idaho Power's largest customers and spends $1.5 million annually on electricity. Tr. at 456-57. He said Simplot has $4.252 million in assets for which it pays an $867,426 annual facilities charge. Tr. at 459. He said Simplot would like to opt-out of the facilities charge, and take on the responsibility for electrical distribution facilities on Simplot property. Tr. at 460-61.

Mr. Sturtevant said that based on Idaho Power Distribution Facilities Reports and an inventory of the equipment that he and Idaho Power undertook, Simplot has 1,609 items on the facilities charge that were installed at a total initial investment of $4,252,088 and an annual charge of $867,426. Tr. at 465-67. He said that Simplot has paid around $14 million or 3.4 times this equipment's installed investment. Tr. at 467. Dr. Reading said Simplot has two, 66-year old items (a transformer and a switch) and these items have been fully depreciated but Simplot would pay 17% in facilities charge. Tr. at 394-95. The average age of all Simplot's facilities charge equipment is 24 years old. Tr. at 467. Mr. Sturtevant said it is unfair for Idaho Power to charge the facilities charge rate in excess of Idaho Power's initial investment.

Mr. Sturtevant calculated the remaining book value of Idaho Power facilities charge equipment at Simplot premises to be: 30-year at $1,753,384; 25-year at $1,432,204; 20-year at $1,145,608; and 15-year at $847,660. Tr. at 468-49. However, he said it would be unfair for Idaho Power to sell this equipment to Simplot for this remaining book value. Tr. at 469. He said 520 items at Simplot plants are over 30 years old, which is 32% of all of Simplot's facilities charge equipment. He insisted that Simplot has paid for the initial value of this equipment more than 3.4 times, and that Idaho Power should immediately give Simplot all the equipment. Id.

Mr. Sturtevant also disagreed with the existing Schedule 19 option to allow facilities charge customers to stop paying the charge. Tr. at 469-71. Although the tariff and the Don Plant Special Contract say Simplot may require Idaho Power to “remove” the facilities, Simplot must pay Idaho Power for the facilities' remaining depreciated value plus the cost to remove them minus a salvage value credit. Tr. at 470. He said nothing allows a customer to buy facilities and

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thereby avoid paying removal costs and other costs that may arise if Idaho Power cannot find a willing buyer for the facilities or otherwise salvage them. Tr. at 470-71.

In conclusion, Mr. Sturtevant said that Simplot has paid for its current facilities charge equipment more than three times; Idaho Power has recovered its initial costs and any authorized rate of return several times; Idaho Power should simply convey the facilities to Simplot, and that the Commission should reform the facilities charge as described by Dr. Reading. Tr. at 479-80.

ICIP witness Del Butler also said the proposed facilities charge is unfair. Tr. at 343. As the former manager of the Don Plant, he calculated it cost Idaho Power $2,619,846.62 for the original equipment at the Don Plant. Id. He said the Don Plant currently pays an annual facilities charge of $534,448.71. He estimated the equipment averages 24.5 years old, and that the Don Plant has 63 pieces of equipment that were installed in 1964, 47 years ago. Tr. at 347. Simplot estimates that, for $2.6 million in currently installed equipment, Simplot has now paid Idaho Power $10,027,224 (which would be even higher if one were to account for the time-value of money). Tr. at 348.

Mr. Butler reiterated that Simplot has paid for its facilities charge equipment more than three times at the Don Plant, and that Idaho Power has more than recovered its initial costs and any authorized rate of return. Tr. at 353. Accordingly, Idaho Power should simply turn ownership of these facilities over to Simplot. Id. He concluded by urging the Commission to reform the facilities charge structure.

Commission Findings: In this rate case, Idaho Power proposed reducing the facilities charge for the approximately 240 customers that are assessed facility charges. The Industrial Customers of Idaho Power (ICIP) and others recommended that the facility charges be further reduced or even eliminated. In addition, the ICIP and Simplot witnesses argued that customers ought to be provided with an opportunity to purchase (or receive) the distribution facilities located on the customer's premises. We first address issues related to the calculation of the facility charge and then address the issue of a customer acquiring its distribution facilities.

1. Cost Components. We first find that the rate of return component of the facilities charge should be updated in this case to reflect the rate of return contained in the Settlement Stipulation. In other words, the return component for calculating the facilities charge should be equivalent to the overall rate of return of 7.86%.

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We further find that the “booked depreciation” component and the income tax component for pooled distribution assets used to calculate the facilities charge should be adjusted. As explained by the Company's witnesses, the “booked value” of distribution facilities is based upon a levelized return and full straight-line depreciation of assets over an average 31-year life. However, under the Company's methodology, the levelized facilities charge after 31 years continues to recover a charge for the rate of return, depreciation, and income tax components. We find that assessing a charge for the rate of return, depreciation, and income tax components for assets that have been fully depreciated is unreasonable. While we reject ICIP's argument that the facilities charge ought to be individually calculated based upon the specific distribution facilities assigned to each of the 240 facility charge customers, we believe that it is neither fair nor reasonable that fully depreciated assets continue to be included in the facilities charge calculation that encompasses the return, depreciation, and income taxes components. Consequently, we direct Idaho Power to recalculate its facilities charge rates based upon the Commission-ordered adjustments to the rate of return, booked depreciation and income tax components.

The Company is directed to file new facilities charge tariffs within fourteen (14) days from the date of this Order. In the interim, the Company shall immediately file conforming tariff schedules that contain rates that produce the approved revenue requirement set out in the Settlement Stipulation (including the initially-proposed reductions in the facilities charge as updated by the proper rate of return) to become effective January 1, 2012.

We next turn to the revenue recovery mechanism contained in the Settlement Stipulation. The parties' Stipulation generally states that any revenue shortfall resulting from changes to the facilities charges shall be directly recovered from Schedule 19 customers “so that no other customer classes shall be impacted by any resulting change.” Stipulation at ¶ 11(c). As discussed above, there are facilities charge customers in Schedules 9, 19, and 24.¹⁸ Although the record does not reveal the revenue impacts (if any) of our adjustments to the cost components for facilities charge adopted above, we find it is unreasonable to charge Schedule 19 customers for the revenue shortfalls caused by changes to the facility charges for Schedules 9 and 24

¹⁸ As noted above, facilities charge customers in Schedules 15 (Dusk to Dawn lighting) and 41 (Street Lighting) are no longer eligible for facilities charges although some customers will continue to pay facilities charges for facilities installed prior to June 1, 2004.

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customers.¹⁹ Any revenue impacts in other schedules should be recovered/adjusted in the applicable customer class. Accordingly, we condition the Settlement Stipulation so that the revenue impact of the adjustments to the facilities charge be restricted to the affected class schedule. Rule 276. We further direct the Company to advise the Commission and the parties of any revenue impacts to the other affected classes when it files conforming tariffs.

We further find it is reasonable and appropriate for the Company to update all the cost components that comprise the facility charges in each future rate case rather than simply subject the cost components to the Company's internal review. Updating the facilities charges in each rate case will allow interested parties to review the underlying costs of each component. Because we have ordered the Company to implement the adjustments to the cost components mentioned above and that the cost components be updated in every rate case, we reject the ICIP proposal that when a customer has paid a certain level of facilities charges (i.e., 2.5 times), then the distribution facilities should be provided to the customer. Even if a facility asset is fully depreciated, there are other costs and expenses (e.g., O&M, inventory) that are reasonably associated with the assets.

2. Option to Purchase. We are persuaded by the testimony offered by the ICIP and other witnesses that customers ought to be provided with an option to purchase distribution facilities dedicated to their specific use and located on their premises. The Company conceded in its rebuttal testimony that customers ought to be able to purchase certain facilities in certain situations. In particular, if a customer wants to bear the responsibility of operating, maintaining and replacing such facilities, then we believe there ought to be an opportunity for the customer to purchase the assets on a case-by-case basis. Pursuant to Idaho Code § 61-328, a proceeding to determine the value of such facilities would be necessary.

To assist the Company and other parties in implementing the option to purchase, we find that there should be no mixed ownership of facilities. In other words, the Company and customer must clearly delineate a new “point of delivery.” We are persuaded that both the utility and the customer should be responsible for the operation and maintenance of facilities on their respective sides of the point of delivery. This demarcation will also serve as the dividing line for the application of applicable safety standards (the National Electric Safety Code for utilities and the National Electric Code for customers). In other words, we find it is not appropriate for there

¹⁹ The same would be true for special contract customers.

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to be facilities of “mixed ownership” on either side of the point of delivery.²⁰ Thus, the point of delivery will delineate those facilities that become the responsibility of the customer, and those facilities that will continue to be the responsibility of the utility. As stated above, we envision that the sale of facilities will occur on a case-by-case basis and that the purchasing price will be based upon the value of the facilities to be transferred to the customers.

Finally, we reject Dr. Reading's suggestion that the Company notify all facilities charge customers of the remaining lives of the assets on the customer's property. We find this requirement to be burdensome, complex, and unnecessary. However, we direct the Company to explain new Rule M to its facilities charge customers and provide each customer with the “Acknowledgement Form” so that customers will be aware of the option to purchase the distribution facilities for which they are assessed facilities charges.

INTERVENOR FUNDING

A. The Petitions

At the conclusion of the technical hearing, the Commission directed parties seeking intervenor funding to file their petitions no later than December 13, 2011. Timely Petitions for Intervenor Funding were filed by the Idaho Conservation League (ICL) on behalf of the three “Conservation Parties (ICL, SRA, and NW Energy Coalition), the Idaho Irrigation Pumpers Association (IIPA or Irrigators), and CAPAI.

ICL is a non-profit organization that works to protect Idaho's environment. ICL (and its two partners) supported the Stipulation and filed testimony regarding both the settlement and the Rider. The three Conservation Parties also participated in the settlement conferences and at the hearing. ICL requested a total of $14,218.40 in intervenor funds: $1,153.40 in witness fees for Ms. Hirsh; and $13,065 in attorney fees. ICL Petition, Exh. A.

CAPAI is a non-profit corporation that represents the six Idaho Community Action Agencies that work to offset the causes and conditions of poverty throughout Idaho. Petition at 6. CAPAI participated in the settlement conferences, opposed the Settlement Stipulation, and offered testimony in support of increasing the funding for low-income weatherization. CAPAI requested a total of $19,755.00: $235 in costs; $2,100 in witness fees; and $17,420 in attorney fees. CAPAI Petition, Exh. A.

²⁰ Those customers that have facilities of mixed ownership are grandfathered.

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The Irrigators are a non-profit corporation representing farmers in southern and central Idaho. The Irrigators issued discovery requests, participated in the settlement conferences, and signed the Settlement Stipulation. IIPA Petition at 2. The Irrigators requested intervenor funding in the amount of $30,477.42: $419.92 in costs; $22,750 in witness fees; and $7,307.50 in attorney fees. IIPA Petition, Exh. A.

B. Standards for Intervenor Funding

Intervenor funding is available pursuant to Idaho Code § 61-617A and Commission Rules 161-165. Section 61-617A(1) declares that it is the “policy of this state to encourage participation at all stages of all proceedings before the commission so that all affected customers receive full and fair representation in those proceedings.” The Commission may award a cumulative amount of intervenor funding not to exceed $40,000 for all intervening parties in a single case.

Commission Rule 162 provides the form and content of petitions for intervenor funding. Each petition must contain: (1) an itemized list of expenses broken down into categories; (2) a statement of the intevenor's proposed findings 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 recommendations differed materially from the testimony and exhibits of the Staff; (6) a statement showing how the intervenor's recommendation or position addressed issues of concern to the general body of the utility users or consumers; and (7) a statement showing the class of customer on whose behalf the intervenor appeared. IDAPA 31.01.01.162.

C. Discussion and Findings

Based upon our review of ICL's Petition, we find its funding request comports with the procedural and substantive requirements of the statute and the rules. We find that the Conservation Parties materially contributed to the Commission's decision-making. Specifically, they joined other parties in supporting the Stipulation and Ms. Hirsh offered pertinent testimony regarding the appropriate level for the Energy Efficiency Rider. Consequently, we find the Conservation Parties' participation added a unique and well-informed perspective to the record. Accordingly, we find it just and reasonable to award the Conservation Parties intervenor funding

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in the amount $14,218. The Conservation Parties' award shall be chargeable to all customer classes. Idaho Code § 61-617A(3).

As outlined above, CAPAI opposed the Settlement Stipulation and proposed that Idaho Power's funding for low-income weatherization be increased by 125%. Although its advocacy did not prevail, CAPAI did contribute to our understanding of low-income weatherization issues. It addressed issues that generally concern low-income residential customers and benefit the general body of ratepayers. Consequently, weighing the requests that were made and the limit on our ability to fund these requests, we find it is appropriate to award CAPAI intervenor funding in the amount of $12,891. CAPAI's award shall be chargeable to the residential classes. Idaho Code § 61-617A(3).

We find that IIPA also materially contributed to our decision-making. Although it did not file testimony, it supported the Settlement Stipulation and actively participated in the discovery and settlement phases of this case. Accordingly, we find it is just and reasonable to award IIPA intervenor funding in the amount of $12,891. This amount shall be chargeable to the irrigation classes. Idaho Code § 61-617A(3).

ULTIMATE FINDINGS OF FACT

AND CONCLUSIONS OF LAW

Idaho Power Company is an electric utility subject to the Commission's regulation under the Public Utilities Law. Idaho Code §§ 61-119 and 61-129. The Company's rates, charges and contracts for electric service in the State of Idaho are subject to the Commission's jurisdiction.

Based upon the record, we find the Company's present rates do not provide it with an opportunity to earn a fair and reasonable return on its investment. Idaho Code § 61-122. Allowing the Company to increase its base rates for electric service by $34 million will provide Idaho Power with the opportunity to earn a fair and reasonable return. Id. The Company is authorized to earn an overall rate of return of 7.86%. We find the partial Settlement Stipulation, as amended, is reasonable and is in the public interest.

We further find the 12-month test year ending December 31, 2011 is the appropriate test year for use in this proceeding. We further find the Company's Idaho electric rate base to be $2,355,906,412 and the Company's net power supply expense is $208,100,936. The

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Commission finds that the other rate design issues contained in the Settlement Stipulation and approved in this Order are fair, just and reasonable.

O R D E R

IT IS HEREBY ORDERED that Idaho Power's Motion for Approval of the Stipulation is granted. The Commission approves the Settlement Stipulation as conditioned by the change in paragraph 11(c).

IT IS FURTHER ORDERED that as set out in the approved Stipulation, Idaho Power is authorized an overall rate of return of 7.86%. The Company is authorized to recover an additional $34 million in annual base revenues.

IT IS FURTHER ORDERED that the Energy Efficiency Rider be set at 4.0%.

IT IS FURTHER ORDERED that CAPAI's request to increase the funding for the Company's low-income weatherization program funded through base rates is denied. The program shall be continued at its current level. The Commission intends to open a generic investigation with public workshops to examine the common issues of need and determining the appropriate mechanisms to measure the cost-effectiveness of low-income weatherization programs.

IT IS FURTHER ORDERED that the Company immediately file new schedules in conformance with the authorized revenue requirement set out in this Order. The facilities charge for customers in Schedules 9, 19, 24, and 66 shall be those proposed by the Company adjusted for the approved rate of return of 7.86%. These schedules shall become effective on January 1, 2012.

IT IS FURTHER ORDERED that the Company modify its facilities charges to account for the authorized rate of return approved in this case of 7.86%. The Company shall also adjust its depreciation and income tax components as set out above. The Company shall file new tariffs in conformance with the facilities charge adjustments set out above within 14 days of the service date of this Order. Any revenue impacts caused by the ordered adjustments to the facilities charges shall be offset by base rate changes to the affected customer class (e.g., Schedules 9, 19, 24). The Company shall advise the Commission of the class revenue changes and supply supporting workpapers.

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IT IS FURTHER ORDERED that the Company shall update the cost components for the facilities charge in all future rate cases. The Company is also directed to provide its Rule M (Facilities Charge Service) tariff to all facilities charge customers.

IT IS FURTHER ORDERED that the Petitions for Intervenor Funding are granted or granted in part. The Conservation Parties are awarded $14,218; CAPAI is awarded $12,891; and IIPA is awarded $12,891.

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-11-08 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. 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 30th day of December 2011.

/s/ Paul Kjellander

PAUL KJELLANDER, PRESIDENT

/s/ Mack A. Redford

MACK A. REDFORD, COMMISSIONER

/s/ Marsha H. Smith

MARSHA H. SMITH, COMMISSIONER

ATTEST:

/s/ Jean D. Jewell

Jean D. Jewell

Commission Secretary

ORDER NO. 32426

IDAHO POWER CO - FORM 8-K - EX-99.1 - IPUC ORDER - January 3, 2012

Attached files

IDAHO POWER CO Reports