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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO IMPLEMENT RATES FOR
ELECTRIC SERVICE TO INCLUDE
CAPITALIZED CUSTOM EFFICIENCY
INCENTIVE PAYMENTS.
CASE NO. IPC-E-12-24
IDAHO POWER COMPANY
DIRECT TESTIMONY
[.1
MATTHEW T. LARKIN
1 Q. Please state your name and business address.
2 A. My name is Matthew T. Larkin. My business
3 address is 1221 West Idaho Street, Boise, Idaho.
4 Q. By whom are you employed and in what capacity?
5 A. I am employed by Idaho Power Company ("Idaho
6 Power" or "Company") as a Regulatory Analyst II in the
7 Regulatory Affairs Department.
8
Q. Please describe your educational background.
9 A. I received a Bachelor of Business
10 Administration degree in Finance from the University of
11 Oregon in 2007. In 2008, I earned a Master of Business
12 Administration degree from the University of Oregon. I
13 have also attended electric utility ratemaking courses
14 including The Basics: Practical Regulatory Training for the
15 Electric Industry, a course offered through New Mexico
16 State University's Center for Public Utilities, and
17 Introduction to Rate Design and Cost of Service Concepts
18 and Techniques, presented by Electric Utilities
19 Consultants, Inc.
20
Q. Please describe your work experience.
21 A. I began employment with Idaho Power as a
22 Regulatory Analyst I in January 2009. As a Regulatory
23 Analyst I, I provided support for the Company's regulatory
24 activities including compliance reporting, financial
25
LARKIN, DI 1
Idaho Power Company
1 analysis, and the development of revenue forecasts for
2 regulatory filings.
3 In January 2012, I was promoted to Regulatory
4 Analyst II. As a Regulatory Analyst II, my
5 responsibilities have expanded to include the development
6 of complex cost-related studies and the analysis of various
7 strategic regulatory issues.
8 Q. What is the Company requesting in this filing?
9 A. The Company is requesting authorization to
10 begin amortization of a portion of the regulatory asset
11 associated with the Custom Efficiency program.
12 Q. What is the primary objective of the Company's
13 request?
14 A. The primary objective of the Company's request
15 is to establish a ratemaking methodology that places
16 investment in this demand-side resource ("DSR") on equal
17 footing with investment in supply-side resources from a
18 business evaluation perspective. As described later in my
19 testimony, investment in DSR possesses inherently different
20 qualities than investment in supply-side resources that
21 must be recognized through unique ratemaking treatment in
22 order to truly level the playing field between these
23 varying resource types. The Company believes its proposal
24 accomplishes this objective, and allows all stakeholders to
25
LARKIN, DI 2
Idaho Power Company
1 fully realize the benefits of an efficient business model
2 that does not favor one type of resource over another.
3 Q. Please provide an outline of your testimony.
4 A. My testimony begins with a history of the
5 regulatory proceedings that led to the capitalization of
6 Custom Efficiency incentive payments, then proceeds to
7 describe the program itself and its success in achieving
8 cost-effective energy savings. My testimony continues to
9 detail the components of the Company's proposed ratemaking
10 treatment that appropriately account for the inherent
11 differences in DSR and supply-side resources, addressing
12 the proposed carrying charge rate, amortization period,
13 rate of return ("ROR"), and rate implementation. My
14 testimony concludes with the Company's proposed timeline
15 for future amortization requests and outlines the long-term
16 projected customer impact.
17 I. BACKGROUND
18 Q. Please describe the Company's 2010 filing in
19 Case No. IPC-E-10-27.
20 A. The Company's filing in Case No. IPC-E-10-27
21 described the Company's preferred DSR business model. The
22 Company did not request a rate change at the time of
23 filing, but rather sought to gain approval of a regulatory
24 framework that it believed would positively impact the
25 business rationale for acquiring cost-effective DSR. Among
LARKIN, DI 3
Idaho Power Company
1 these requested changes was a proposal to begin
2 capitalizing incentive payments associated with the Custom
3 Efficiency program.
4 Q. Why did the Company request authorization to
5 capitalize a portion of its energy efficiency expenditures?
6 A. As stated on page 12 of the Direct Testimony
7 of Company witness John R. Gale in Case No. IPC-E-10-27,
8 two key components of a successful DSR business model are
9 (1) "timely recovery of out-of-pocket expenditures that
10 appropriately recognizes the time value of money and does
11 not negatively impact cash flow in a significant way," and
12 (2) "the ability to earn on the energy efficiency
13 investments just like any other business activity in which
14 the Company is engaged."' The recovery mechanism in place
15 at that time was insufficient in both of these areas,
16 creating the need for the Company to seek several changes
17 to the regulatory treatment of DSR. The proposed
18 capitalization of Custom Efficiency incentive payments was
19 requested as part of the Company's comprehensive solution.
20 At the time Case No. IPC-E-10-27 was filed, all
21 prudently incurred energy efficiency expenditures were
22 recovered through the Energy Efficiency Rider ("Rider")
23 balancing account. The Company collected revenues
Case No. IPC-E-10-27, Direct Testimony of John R. Gale, p. 12, 11.
8-11 and 14-16.
LARKIN, DI 4
Idaho Power Company
1 associated with this account through the then-current 4.75
2 percent Rider applied against total base charges on
3 customer bills. In theory, this balancing account was
4 established to provide the Company with timely recovery of
5 expenditures associated with energy efficiency. In 2010,
6 however, the Rider balancing account had become
7 increasingly under-funded as expenditures in cost-effective
8 energy efficiency outpaced collection through the Rider,
9 indicating that the then-current 4.75 percent charge was
10 not able to provide timely recovery of all cost-effective
11 energy efficiency expenditures. The Company's proposal to
12 capitalize incentive payments associated with the Custom
13 Efficiency program served to relieve pressure on the Rider
14 balancing account by shifting recovery of these
15 expenditures from the Rider mechanism into base rates,
16 improving the ability of the mechanism to provide timely
17 recovery of prudently-incurred expenses while avoiding an
18 increase in the level of the corresponding Rider charge.
19 In addition to relieving pressure on the Rider
20 balancing account, the proposed capitalization of Custom
21 Efficiency incentive payments was intended to place
22 investment in DSR on par with investment in supply-side
23 resources by allowing the Company the opportunity to earn a
24 fair rate of return on a portion of its DSR investment.
25 While dollar-for-dollar recovery through the Rider
LARKIN, DI 5
Idaho Power Company
1 mechanism provides for timely recovery of energy efficiency
2 expenditures, it does not provide for an earnings
3 opportunity for DSR, which relegates these investments to
4 an inferior status when compared to supply-side resources
5 from a business investment perspective. Through
6 capitalization, DSR and supply-side resources are
7 essentially equivalent from the Company's perspective,
8 resulting in a business model that promotes efficiency in
9 resource selection and does not unduly favor investment in
10 supply-side resources.
11 Q. Was an agreement of the parties reached in
12 Case No. IPC-E-10-27 regarding the Company's proposed
13 modifications to its DSR business model?
14 A. Yes. On March 3, 2011, the Company filed a
15 motion to approve a settlement stipulation ("Stipulation")
16 in Case No. IPC-E-10-27 addressing the issues raised in the
17 Company's initial application. Signatories to the
18 Stipulation included the Company, the Staff ("Staff") of
19 the Idaho Public Utilities Commission ("Commission"), the
20 Community Action Partnership Association of Idaho, the
21 Idaho Conservation League, the NW Energy Coalition, and the
22 Snake River Alliance, collectively referred to as the
23 "Parties".
24
25
LARKIN, DI 6
Idaho Power Company
1 Q. Please describe the terms of the Stipulation
2 related to the regulatory treatment of Custom Efficiency
3 incentive payments.
4 A. Page 3, section 3, paragraph 8, of the
5 Stipulation reads as follows:
6 The Parties agree that the direct
7 incentive payments of the Custom Efficiency
8 program should be capitalized as a
9 regulatory asset beginning January 1, 2011.
10 A carrying charge equal to the current
11 Commission authorized rate of return of 8.18
12 percent will be applied to the balance until
13 the Commission includes the regulatory asset
14 in Company rates as part of its next general
15 rate case. The regulatory asset once placed
16 in rates will earn the current Commission
17 approved authorized rate of return and will
18 be amortized over a seven-year period.
19
20 Q. Did the terms of the Stipulation reflect the
21 Company's initial proposal in Case No. TPC-E-10-27 with
22 respect to the capitalization of Custom Efficiency
23 incentive payments?
24 A. Not entirely. The Company initially proposed
25 a four-year amortization of the regulatory asset; however,
26 in the spirit of compromise, the Company agreed to a seven-
27 year amortization period. Although it agreed to the
28 extended amortization period in the context of the overall
29 settlement package, the Company noted that the risk profile
LARKIN, DI 7
Idaho Power Company
1 of DSR coupled with an extended amortization period was
2 cause for concern.2
3
Q. Did the Commission approve the Stipulation
4 submitted by the Parties in Case No. IPC-E-10-27?
5 A. No. In Order No. 32217, the Commission
6 ultimately did not accept the Stipulation entered into by
7 the Parties. The Commission instead provided temporary
8 relief to the Rider balancing account through a one-time
9 Power Cost Adjustment ("PCA") mechanism surcharge while
10 leaving other issues raised by the Company to be addressed
11 at a later time.
12 Q. Was the capitalization of Custom Efficiency
13 incentive payments addressed in Order No. 32217?
14 A. No, not specifically.
15
Q. What was the Company's response to the
16 issuance of Order No. 32217?
17 A. On April 22, 2011, the Company filed a
18 Petition for Clarification ("Petition") regarding Order No.
19 32217 requesting further guidance on a number of issues,
20 including the Commission's intent with regard to the
21 treatment of Custom Efficiency incentive payments as a
22 regulatory asset. In its Petition, the Company described
23 the Parties' support for the concept of capitalizing energy
24 efficiency investments to earn the Company's authorized
2 Case No. IPC-E-10-27, Reply Testimony of John R. Gale, p. 15, 11.
5-6.
LARKIN, DI 8
Idaho Power Company
1 ROR, and noted that the sole point of disagreement between
2 the Parties with regard to the capitalization of these
3 expenditures was the length of the amortization period.
4 The Company ultimately requested that the Commission "allow
5 Idaho Power to account for incentives paid through the
6 Custom Efficiency program as a regulatory asset beginning
7 January 1, 2011, with an amortization period to be
8 determined by the Commission. "3
9 Q. What was the Commission's ruling in response
10 to the Company's Petition for Clarification in Case No.
11 IPC-E-10-27?
12 A. On May 17, 2011, the Commission issued Order
13 No. 32245 in response to Idaho Power's Petition. With
14 respect to the capitalization of Custom Efficiency
15 incentive payments, the Commission ordered:
16 [T]he Commission will allow Idaho Power to
17 account for incentives paid through the
18 Custom Efficiency program as a regulatory
19 asset beginning January 1, 2011, with an
20 amortization period to be determined later
21 by the Commission.4
22
23 Q. Has the Company accounted for Custom
24 Efficiency incentive payments as a regulatory asset in
25 compliance with the Commission's directive in Order No.
26 32245?
27
Petition for Clarification, Case No. IPC-E-10-27, p. 5, 12.
' Clarification Order No. 32245, Case No. IPC-E--10-27, p. 6, 11.
LARKIN, DI 9
Idaho Power Company
1 A. Yes. The Company has accounted for incentive
2 payments associated with the Custom Efficiency program as a
3 regulatory asset for all incentives paid on or after
4 January 1, 2011.
5 II. PROGRAM DESCRIPTION
6 Q. Please describe the Custom Efficiency program.
7 A. The Custom Efficiency program is designed to
8 provide financial incentives to commercial and industrial
9 customers for implementing customized energy efficiency
10 measures at their sites to reduce electrical usage. These
11 projects include motor rewinds, variable frequency drives,
12 and energy efficient refrigeration, among others.
13 Q. Has the Custom Efficiency program successfully
14 achieved cost-effective energy savings?
15 A. Yes. As detailed in the Demand-Side
16 Management ("DSM") 2011 Annual Report, filed with the
17 Commission on March 15, 2012, the Custom Efficiency program
18 is the Company's largest energy efficiency program in terms
19 of annual kilowatt-hour ("kWh") savings, with approximately
20 68 million kWh saved in 2011 alone. The program is also
21 very attractive from a cost-effectiveness perspective, with
22 a total Utility Cost Test ("UCT") ratio of 7.27 and a Total
23 Resource Cost ("TRC") ratio of 3.09 realized over the life
24 of the program .5 From a one-year perspective, in 2011 the
Demand-Side Management 2011 Annual Report, p. 77.
LARKIN, DI 10
Idaho Power Company
1 program had a UCT ratio of 4.42 and a TRC ratio of 2.37.6
2 The large amount of kWh savings coupled with favorable
3 cost-effectiveness measures indicates that the Custom
4 Efficiency program is one of the Company's most robust and
5 effective programs in its energy efficiency portfolio.
6 Third-party evaluations have recognized the success
7 of the Custom Efficiency program as well. In 2010, the
8 Company commissioned the services of The Cadmus Group,
9 Inc., to perform a process evaluation of the Custom
10 Efficiency program. In addition to providing invaluable
11 information for potential improvements to the program, page
12 2 of the final report noted, "In many ways, the Custom
13 Efficiency program exemplifies a quality efficiency program
14 compared to similar efforts across the country. "7 In 2011,
15 Idaho Power contracted with ADM Associates, Inc., to
16 conduct an impact evaluation and review of the Company's
17 reported energy savings from the Custom Efficiency program
18 for the 2010 calendar year. In conclusion, page 6-2 of the
19 final report noted, "Overall, the Custom Efficiency Program
20 received a high realization rate." Further, on page 1-1,
21
22
23
6 Demand-Side Manaqement 2011 Annual Report, Supplement 1: Cost-
Effectiveness, p. 89.
7 Final Report: Custom Efficiency Process Evaluation Findings and
Recommendations, The Cadmus Group, Inc., February 4, 2011.
LARKIN, DI 11
Idaho Power Company
1 this report states a 94 percent overall energy savings
2 realization rate.8
3 Staff also acknowledged the success of the Custom
4 Efficiency program in its most current review of the
5 Company's 2011 energy efficiency expenditures in Case No.
6 IPC-E-12-15. On page 5, section 1, paragraph 3, of its
7 comments filed June 25, 2012, Staff recommended that the
8 Commission approve expenditures in the Custom Efficiency
9 program as prudently incurred.
10 III. REQUEST FOR RECOVERY
11 A. Amount To Be Amortized.
12 Q. What portion of the Custom Efficiency
13 regulatory asset is the Company requesting to include in
14 rates at this time?
15 A. The Company is proposing to include in rates
16 the portion of the Custom Efficiency regulatory asset
17 associated with incentive payments made during the 2011
18 calendar year plus associated carrying charges. As reported
19 on page 135 of the DSM 2011 Annual Report, incentive
20 payments made in 2011 totaled $7,018,385 prior to the
21 application of carrying charges, which I will discuss later
22 in my testimony.
23
24
Impact Evaluation of 2010 Custom Efficiency Program, ADM
Associates, Inc., November 29, 2011.
LARKIN, DI 12
Idaho Power Company
1 Q. What was the Commission's decision regarding
2 the prudence of 2011 expenditures in the Custom Efficiency
3 program?
4 A. On October 22, 2012, the Commission issued
5 Order No. 32667 in Case No. TPC-E-12-15, approving 2011
6 expenditures in the Custom Efficiency program as prudently
7 incurred. As stated on page 11 of Order No. 32667, "Based
8 on our review of the record and the agreement of Staff and
9 the Company, we find that the Company prudently incurred
10 $7,018,385 in Custom Efficiency Program incentive
11 expenses."
12 Q. Why is the Company proposing to include only
13 the portion of the regulatory asset associated with
14 incentive payments made in 2011?
15 A. In accordance with Order No. 32245 issued in
16 Case No. IPC-E--10-27, the Company has accounted for
17 incentive payments associated with the Custom Efficiency
18 program as a regulatory asset for all payments made to date
19 since January 1, 2011. Consequently, the total current
20 balance of this account reflects payments made in both 2011
21 and 2012. While incentive payments made in 2011 were
22 deemed prudent in Order No. 32667 in Case No. IPC-E-12-15,
23 prudence has not yet been determined for incentive payments
24 made in 2012. Therefore, a request for amortization of the
25 full regulatory asset balance would require the question of
LARKIN, DI 13
Idaho Power Company
1 prudence of 2012 incentive payments to be answered in this
2 proceeding prior to the authorization of amortization. The
3 Company believes that introducing the question of prudence
4 to its request for amortization would add an additional
5 element of complexity and detract from the primary intent
6 of this filing. By requesting to only include in rates
7 incentive payments that have already been deemed prudent,
8 the scope of this filing is limited to the mechanics of
9 rate recovery, leaving the issue of prudence to be
10 addressed in the Company's currently-established DSM review
11 process.
12 B. Carrying Charge.
13 Q. What does the Company believe the Commission
14 should authorize as the carrying charge for the Custom
15 Efficiency regulatory asset?
16 A. Consistent with the Company's proposal in Case
17 No. IPC-E-10-27 and the subsequent Stipulation of the
18 Parties in that case, the Company has calculated associated
19 carrying charges by applying its full authorized ROR to the
20 balance of the Custom Efficiency regulatory asset. The
21 calculated carrying charges reflect the change in the
22 Company's authorized ROR resulting from the Company's 2011
23 general rate case, Case No. IPC-E-11-08.
24
25
LARKIN, DI 14
Idaho Power Company
1 Q. Why does the Company believe the full
2 authorized ROR is the appropriate carrying charge for this
3 asset prior to the commencement of amortization?
4 A. The full authorized ROR is the appropriate
5 carrying charge for this asset because it allows the
6 Company to begin applying its full authorized ROR at the
7 time when investment in DSR becomes used and useful. From
8 an earnings perspective, this places investment in DSR on
9 equal footing with investment in supply-side resources.
10 Q. Please explain further.
11 A. While supply-side resources are being
12 constructed, the Company accrues carrying charges on its
13 investment in the form of the allowance for funds used
14 during construction ("AFUDC") rate. As construction nears
15 completion, the Company has the opportunity to file a
16 request to move the investment from AFUDC into rate base
17 and begin earning its full authorized ROR with an effective
18 date corresponding to the online date of the project. This
19 results in virtually no lag between the completion date of
20 a supply-side resource and the Company's ability to begin
21 earning its full authorized ROR on its investment. In the
22 case of the newly constructed Langley Gulch power plant,
23 for example, official commercial operation began on June
24 29, 2012, with a corresponding rate change effective July
25 1, 2012, reflecting a lag of two days between the used and
LARKIN, DI 15
Idaho Power Company
1 useful date of the plant and the Company's ability to begin
2 earning its full authorized ROR.
3 With capitalized investment in DSR, however, an
4 inherent lag exists between project completion and rate
5 recovery, causing investment in completed projects to
6 remain on the Company's books for a much longer period of
7 time prior to the commencement of amortization. Using 2011
8 expenditures as an example, projects associated with the
9 Custom Efficiency program became used and useful in each
10 month of 2011, while the prudence of associated incentive
11 payments was not determined until the issuance of Order No.
12 32667 on October 22, 2012. This reflects a lag of ten
13 months (for projects completed in December 2011) to twenty-
14 one months (for projects completed in January 2011) between
15 the completion date of the projects and the determination
16 of prudence. Allowing for a full seven-month procedural
17 schedule for the Company's request for amortization, the
18 earliest effective date for an associated rate change is
19 June 1, 2013. This represents a lag between project
20 completion and the commencement of rate recovery that
21 varies between 1.5 and 2.5 years. Without the ability to
22 apply its full authorized ROR as a carrying charge
23 throughout the deferral period, investment in DSR would
24 experience an increased lag between project completion and
25 the ability to begin earning its full authorized ROR, thus
LARKIN, DI 16
Idaho Power Company
1 making these investments inferior to supply-side resources
2 from the perspective of earnings potential.
3 Q. Why is it appropriate to use the full
4 authorized ROR as a carrying charge for the Custom
5 Efficiency regulatory asset while the Rider balancing
6 account that funds other energy efficiency programs accrues
7 interest at the customer deposit rate, currently one
8 percent?9
9 A. In theory, the Rider mechanism is designed to
10 offer real-time recovery of expenses associated with the
11 Company's energy efficiency programs. While it could be
12 argued that the full ROR is the appropriate carrying charge
13 for the Rider balance, the Commission has determined that
14 it is more appropriate to apply the customer deposit rate
15 of one percent. As described above, the capitalization of
16 Custom Efficiency incentive payments results in a lag
17 between project completion and recovery that is years
18 greater than that realized by both Rider-funded energy
19 efficiency programs and supply-side generation resources,
20 which should appropriately be reflected in a higher
21 carrying charge.
22 C. amortization Period.
23 Q. What is the Company's proposed amortization
24 period for the Custom Efficiency regulatory asset?
Case No. GNR-tJ-11-01, Order No. 32109.
LARKIN, DI 17
Idaho Power Company
1 A. The Company proposes an amortization period of
2 four years.
3 Q. Why does the Company believe a four-year
4 amortization period is appropriate?
5 A. The need for a four-year amortization period
6 is primarily driven by the lack of physical Company-owned
7 property backing the non-physical assets on the Company's
8 books. Investment in DSR is inherently different from
9 investment in supply-side resources in that the ownership
10 of physical assets is retained by the customer, not the
11 Company. In the case of supply-side resources, the Company
12 invests in physical assets and retains ownership once the
13 assets are placed in service. This property is tangible,
14 possessing a marketable value throughout its life as well
15 as a potential salvage value upon retirement. Ownership
16 provides the added benefit of tangible valuable assets
17 should the Company be subject to any event that impacts its
18 ability to recover the return of and return on its
19 investment through rates. With DSR, however, the Company
20 invests in customer-specific projects rather than physical
21 assets, and retains no ownership of tangible project-
22 related assets upon completion. While these projects
23 provide cost-effective energy savings, the Company is left
24 with no salvageable assets when the projects are retired,
25 nor does it possess any marketable assets throughout the
LARKIN, DI 18
Idaho Power Company
1 useful life of the projects. This lack of ownership makes
2 investment in DSR inherently riskier than investment in
3 supply-side resources because the assets on the Company's
4 books are not backed by physical property. To account for
5 this risk, the Company is requesting an amortization period
6 of four years to limit the period of time over which these
7 non-physical assets remain on the Company's books.
8 Extending the amortization period beyond four years would
9 compound the risk of eventual recovery and fail to
10 appropriately recognize the unique characteristics of these
11 assets.
12 Q. Why is it inappropriate to amortize the Custom
13 Efficiency regulatory asset over the useful life of the
14 associated Custom Efficiency projects?
15 A. The regulatory asset on the Company's books is
16 not comparable from a ratemaking perspective to the
17 customer-owned physical assets associated with the various
18 Custom Efficiency projects. Through the Custom Efficiency
19 program, the Company is not procuring physical assets;
20 rather, it is purchasing a cost-effective, albeit non-
21 physical, demand-side resource. Its investment does not
22 result in the ownership of long-lived physical assets with
23 a marketable value that depreciate over time, but rather
24 the accrual of a non-physical regulatory asset with no
25 marketable value. If the Company is negatively impacted by
LARKIN, DI 19
Idaho Power Company
1 an event that prevents it from placing the investment in
2 rates, it is left with no marketable asset or method to
3 recoup any of its investment. As described above, this
4 lack of ownership of a physical asset increases the risk of
5 recovery and distinguishes the risk profile of DSR
6 investment from that of the customer-owned physical assets
7 associated with the Custom Efficiency program. For this
8 reason, any parallels drawn between the appropriate
9 amortization period of a physical, customer-owned asset and
10 a non-physical, non-marketable regulatory asset are
11 invalid.
12 Q. Why is it appropriate to apply a shorter
13 amortization period to demand-side assets when the Company
14 believes that DSR and supply-side resources should be on
15 equal footing from a business investment perspective?
16 A. The Company's desire to level the playing
17 field between DSR and supply-side resources is precisely
18 why a shorter amortization period is appropriate for
19 investment in DSR. Supply-side resources offer the ability
20 to immediately modify rates upon project completion and
21 result in Company ownership of physical assets.
22 Alternatively, investment in DSR experiences a prolonged
23 delay between project completion and amortization and does
24 not result in Company ownership of valuable physical
25 assets. These inherent differences must be addressed
LARKIN, DI 20
Idaho Power Company
1 through unique ratemaking treatment in order to put these
2 varying resource types on equal footing within the context
3 of the Company's investment decisions.
4 D. Rate of Return.
5 Q. What is the Company's proposed ROR to be
6 applied at the time of amortization?
7 A. The Company believes that once placed in rates
8 the unamortized balance of the regulatory asset should earn
9 the then-current authorized ROR.
10 Q. Why is the then-current authorized ROR
11 appropriate at the time of amortization?
12 A. The full authorized ROR results in equal
13 treatment between the Company's supply-side and demand-side
14 resources at the time of amortization. Applying an ROR
15 that is anything less than the Company's then-current ROR
16 would devalue investment in DSR relative to investment in
17 supply-side resources with respect to the Company's
18 earnings potential. Additionally, the use of the then-
19 current authorized ROR allows for rates to adjust over time
20 as modified by the Commission to reflect changing
21 circumstances.
22 E. Revenue Requirement Determination.
23
Q. After applying the Company's proposed
24 ratemaking treatment, what is the annual revenue
25 requirement associated with the amortization of this asset?
LARKIN, DI 21
Idaho Power Company
1 A. After applying the Company's proposed carrying
2 charges, rate of return, and amortization period, the
3 resulting annual revenue requirement associated with the
4 amortization of this asset is $2,949,340.
5 Q. Have you prepared an exhibit detailing the
6 calculation of this amount?
7 A. Yes. Exhibit No. 1 details the determination
8 of the annual revenue requirement resulting from the
9 Company's request.
10 Q. Please describe Exhibit No. 1.
11 A. Exhibit No. 1 is comprised of two tables.
12 Table 1 details the accrual of carrying charges at the
13 Company's full authorized ROR between January 2012 and May
14 2013. As listed at the top of column A, the balance as of
15 January 2012 in this account totaled $7,230,724,
16 representing the $7,018,385 of incentive payments made
17 between January and December 2011 plus $212,339 of carrying
18 charges that would have been accrued throughout 2011. As
19 listed at the bottom of column B, 2011 expenditures with
20 associated carrying charges as of May 31, 2013, will total
21 $8,126,504.
22 Table 2 calculates the annual revenue requirement
23 associated with the $8,126,504 regulatory asset balance.
24 The Company is proposing to use the same mid-year rate base
25 convention utilized in rate case filings of calculating the
LARKIN, DI 22
Idaho Power Company
1 return on rate base levels as of the mid-point of the test
2 period. As detailed in columns B through D, this is
3 accomplished by first calculating six months of accumulated
4 amortization according to a 48-month amortization period,
5 calculated at $1,015,813 as listed in column C. This
6 amount is then subtracted from the principal balance of
7 $8,126,504, to determine the mid-year unamortized rate base
8 balance of $7,110,691, listed in column D. The Company's
9 full authorized ROR is then applied to this mid-year amount
10 to calculate a total annual return of $917,714 after tax-
11 gross up, listed in column G. When combined with the
12 annual amortization expense based on a four-year
13 amortization period, the total annual revenue requirement
14 amount associated with the Company's proposal is
15 $2,949,340, listed in column I.
16 F. Allocation and Rate Implementation.
17 Q. What is the Company's proposed jurisdictional
18 allocation of this asset?
19 A. Because this asset reflects amounts paid to
20 Idaho-specific projects, the Company has allocated 100
21 percent of the associated revenue requirement to the Idaho
22 jurisdiction.
23 Q. How does the Company propose to collect the
24 requested amount from customer classes?
25
LARKIN, DI 23
Idaho Power Company
1 A. The Company proposes to collect the revenue
2 requirement associated with the amortization of this asset
3 through a uniform cents-per-kWh charge. This charge will
4 be included as part of the "Annual Adjustment Mechanism"
5 line item on customer bills, which currently contains
6 charges associated with the PCA and the Fixed Cost
7 Adjustment ("FCA") mechanism.
8 Q. what is the rationale for collecting these
9 expenditures through a uniform energy rate?
10 A. As previously stated, the Custom Efficiency
11 program is intended to provide cost-effective energy
12 savings. Because these savings are realized through
13 foregone net power supply expenses associated with a
14 reduction in energy, the appropriate recovery method for
15 investment in this program is through a cents-per-kWh
16 charge. In other words, because the program is energy-
17 related, it logically follows that associated costs should
18 be recovered through an energy rate.
19 Q. Have you prepared an exhibit detailing the
20 calculation of the proposed energy rate and the subsequent
21 customer impact of the Company's proposal?
22 A. Yes. Exhibit No. 2 contains the energy rate
23 and revenue impact by class of the Company's proposal. The
24 resulting rate is 0.0220 cents-per-kWh, representing an
25 overall average increase of 0.32 percent.
LARKIN, DI 24
Idaho Power Company
1 Q. What is the requested effective date for the
2 Company's proposed rate change?
3 A. The Company is requesting an effective date of
4 December 1, 2012, with the expectation that the Commission
5 will suspend that date to provide for additional time to
6 review and implement rates on June 1, 2013. A final
7 effective date of June 1, 2013, will coincide with rate
8 changes associated with the PCA and the FCA.
9 Q. Is the sales and load forecast used to set
10 rates in this initial filing the same forecast that will be
11 used in the upcoming PCA and FCA filings?
12 A. The Company cannot say at this time if the
13 sales and load forecast used in this filing will be the
14 same as that used to prepare the 2013/2014 PCA and FCA
15 filings. The sales and load forecast utilized in the
16 current proposal reflects the most current forecast
17 available, prepared in August 2012 for use in the Company's
18 2013 Integrated Resource Plan. If this forecast changes
19 prior to the Company's PCA and FCA filings in the first
20 quarter of 2013, the Company may request to update Exhibit
21 No. 2 to reflect these changes in order to maintain
22 consistency between the forecasts utilized to set rates
23 effective June 1, 2013.
24
25
LARKIN, DI 25
Idaho Power Company
1 Q. Please describe the accounting entries that
2 will be utilized to record the amortization of the Custom
3 Efficiency regulatory asset.
4 A. The Custom Efficiency regulatory asset is
5 currently recorded in Account 182.317. Commencing June of
6 2013, the Company will credit $169,302 to this account on a
7 monthly basis, and debit Account 908, Energy Efficiency
8 Expenses, by the same amount, for a period of four years.
9 IV. FUTURE RATEMKING TREATMENT
10 Q. What is the Company's proposal for requesting
11 amortization of this regulatory asset in future years?
12 A. The Company proposes to request amortization
13 of prudently incurred Custom Efficiency incentive payments
14 on an annual basis in the same manner as requested in this
15 case. These filings will be made in the first quarter of
16 each year requesting amortization of Custom Efficiency
17 incentive payments deemed prudent by the Commission in the
18 previous year through the Company's separate DSM review
19 process. Additionally, future filings will be simplified
20 to request the inclusion of prudent investment in rates
21 according to the methodology established in this
22 proceeding, eliminating the need to address rate mechanics
23 in the future. This simplified process will allow the
24 Company to file amortization requests associated with
25 Custom Efficiency incentive payments in accordance with
LARKIN, DI 26
Idaho Power Company
1 other annual adjustment mechanisms in early spring,
2 consolidating rate changes and customer communication to
3 correspond with a simultaneous effective date of June 1.
4 Q. What are the advantages of filing amortization
5 requests on an annual basis?
6 A. There are several advantages of filing
7 amortization requests on an annual basis. First, the
8 Company's proposal does not compromise the currently-
9 established process for prudence review of energy
10 efficiency expenditures. Introducing the question of
11 prudence to the request for amortization would overly
12 complicate these proceedings and undermine the separate
13 prudence review process that is already in place.
14 Second, filing each year allows the Company to
15 update rate base amounts annually to reflect accumulated
16 amortization and incremental investment. Rate base will be
17 adjusted downward as unamortized balances decline year-
18 over-year, while corresponding increases to rate base will
19 occur to recognize incremental investment. Additionally,
20 the Company will be able to remove fully amortized assets
21 from rates immediately upon the completion of amortization.
22 This effectively keeps rates current and in-line with
23 fluctuating rate base balances on the Company's books.
24 Third, regular filings limit the lag between
25 expenditure and recovery as much as possible, allowing the
LARKIN, DI 27
Idaho Power Company
1 request for recovery to occur on a consistent basis rather
2 than sporadically at the time of general rate case filings.
3 This will limit carrying charges and promote rate stability
4 by avoiding lumpy requests for recovery of this asset.
5 Q. Please describe the expected rate impact of
6 the Company's proposal over time.
7 A. Under the Company's proposal, the combination
8 of a four-year amortization period and annual filings will
9 result in the stabilization of rates within four years if
10 expenditures in the Custom Efficiency program remain level.
11 As described above, annual adjustments will take into
12 account reductions to rate base due to accumulated
13 amortization, as well as rate base increases associated
14 with incremental investment. After four years, the
15 amortization associated with the Company's initial filing
16 will be removed from rates and a new four-year amortization
17 period will begin for incremental investment made in 2015.
18 Beyond four years, each annual filing will reflect the
19 removal of the full amortization of one year's investment
20 while beginning amortization of a new year's investment,
21 thus stabilizing rates after the initial four-year ramp-up
22 period.
23 Q. Have you prepared an exhibit demonstrating the
24 customer impact of the Company's proposal over time?
25
LARKIN, DI 28
Idaho Power Company
1 A. Yes. Exhibit No. 3 details the long-term rate
2 impact of the Company's proposal assuming investment in the
3 Custom Efficiency program remains at 2011 levels. As shown
4 on the line labeled "Total Annual Revenue Requirement," in
5 2016 the revenue requirement included in rates associated
6 with this asset levels off at approximately $10.2 million.
7 Q. How will the Custom Efficiency regulatory
8 asset be treated in future general rate case proceedings?
9 A. To avoid double-counting, the Company will
10 exclude the Custom Efficiency regulatory asset from rate
11 base in future general rate case filings.
12 Q. How does the Company propose to collect future
13 revenue requirement associated with the amortization of
14 Custom Efficiency incentive payments?
15 A. The Company proposes to annually update the
16 cents-per-kWh charge to be applied to customer bills in the
17 same manner as described on pages 23 and 24 of my
18 testimony.
19 V. CONCLUSION
20 Q. Do you have any concluding thoughts regarding
21 the Company's proposal?
22 A. Yes. As stated by Mr. Gale in Case No. IPC-E-
23 10-27, "The cleanest, most efficient resource in the
24
25
LARKIN, DI 29
Idaho Power Company
1 Company's portfolio is the one it does not have to build."0
2 Through the Custom Efficiency program, the Company has been
3 able to attain verified cost-effective energy savings that
4 benefit the Company and customers through lower net power
5 supply expenses. Unfortunately, current ratemaking
6 standards actually discourage investment in energy
7 efficiency relative to supply-side resources by not taking
8 into account the financial circumstances unique to
9 investment in DSR. The Company believes its proposal
10 addresses this problem with a methodology that strikes a
11 balance between the interests of customers, intervenors,
12 and shareholders. This methodology allows for timely
13 recovery of expenditures and the opportunity to earn a fair
14 and reasonable return, while limiting the long-term impact
15 on customer rates and year-over-year rate fluctuations.
16 The Company believes that its proposal financially
17 encourages an efficient allocation of limited investment
18 dollars and promotes an optimal resource balance that will
19 benefit all of the Company's stakeholders.
20 Q. Does this conclude your testimony?
21 A. Yes.
22
23
24
U Case No. IPC-E-10-27, Direct Testimony of John R. Gale, p. 9, 11.
10-12.
LARKIN, DI 30
Idaho Power Company
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-12-24
IDAHO POWER COMPANY
LARKIN, DI
TESTIMONY
EXHIBIT NO. 1
IDAHO POWER COMPANY
TABLE I
ACCRUED CARRYING CHARGES: 2011 CUSTOM EFFICIENCY INCENTIVE PAYMENTS
IDAHO JURISDICTION
JANUARY 2012 THROUGH MAY 2013
Account 182.317 - Interest Accrual
(A) (B) (C) (D) (E) (F)
(A+B)12
Idaho Cumulative
Beginning Ending Allowed Carrying Interest
MONTH Balance Balance AVG BAL Rate of Return Charges Charges
Jan, 2012* 7,230,724 7,275,420 7,253,072 7.86% 47,508 304,543
Feb 7,275,420 7,322,928 7,299,174 7.86% 47,810 352,353
Mar 7,322,928 7,370,738 7,346,833 7.86% 48,122 400,474
Apr 7,370,738 7,418,859 7,394.798 7.86% 48,436 448,910
May 7,418,859 7,467,295 7,443,077 7.86% 48,752 497,662
June 7,467,295 7,516,047 7,491,671 7.86% 49,070 546,733
July 7,516,047 7,565,118 7,540,583 7.86% 49,391 596,124
Aug 7,565,118 7,614,509 7,589,813 7.86% 49,713 645,837
Sep 7,614,509 7.664,222 7,639,365 7.86% 50,038 695,875
Oct 7,664,222 7,714,260 7,689,241 7.86% 50,365 746,239
Nov 7,714,260 7,764,624 7,739,442 7.86% 50,693 796,933
Dec 7,764,624 7,815,318 7,789,971 7.86% 51,024 847,957
Jan, 2013 7,815,318 7,866,342 7,840,830 7.86% 51,357 899,314
Feb 7,866,342 7,917,699 7,892,021 7.86% 51,693 951,007
Mar 7,917,699 7,969,392 7,943,546 7.86% 52,030 1.003,037
Apr 7,969,392 8,021,422 7,995,407 7.86% 52,370 1,055,407
May 8,021,422 8,073,792 8,047.607 7.86% 52,712 1,108,119
Balance with Interest through May 2013 88,126.504 I
* Reflects prudently-incurred 2011 Custom Efficiency incentive payments of $7,018,385 plus accrued 2011 carrying charges of
$212,339.
Exhibit No. 1
Case No. IPC-E-12-24
M. Larkin, IPC
Page 1 of 2
CO r CA 2: CD CD Cr
o 0 Z
-I'.. 0
0 0
IDAHO POWER COMPANY
TABLE 2
CUSTOM EFFICIENCY AMORTIZATION ANNUAL REVENUE REQUIREMENT
IDAHO JURISDICTION
AMORTIZATION BEGINNING JUNE 1, 2013
A B C D E I
Account Balance as Monthly Six Months Accumulated Mid-Year Unamortized
of May 31, 2013 Amortization Amortization Balance Idaho Authorized ROR
Table 1, Column B A/48 B X 6 A - C Case No. IPC-E-1 1-08 I
$8,126,504 $169,302 $1,015,813 $7,110,691 7.86%
I F C H I I
Pre-Tax Return on Return with Tax Annual Amortization Annual Revenue
Rate Base Gross-Up Expense Requirement
I DXE FXI.642 A/4 G+H I
$558,900 $917,714 $2,031,626 $2,949,340
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-12-24
IDAHO POWER COMPANY
LARKIN, DI
TESTIMONY
EXHIBIT NO. 2
Idaho Power Company
Calculation of Revenue Impact
Class Allocated Custom Efficiency Amortization
State of Idaho
Filed October 31, 2012
(A) (B) (C) (D) (E) (F) (G)
Rate Average Revenue Percent
Line Sch. Number of Normalized Requirement Cents per Current Billed Proposed Revenue
No Tariff Description No. Customers Energy (kWh) Allocation kWh Rate Revenue Billed Revenue Change
Uniform Tariff Rates:
CO r mwmcr
1 Residential Service 1 404,785 4,823,318,996 $1,059,335 0.0220 $417,352,464 $418,411,799 0.25%
2 Master Metered Mobile Home Park 3 23 4,889,668 $1,074 0.0220 $402,015 $403,089 0.27%
3 Residential Service Energy Watch 4 0 0 $0 0.0000 $0 $0 0.00%
4 Residential Service Time-of-Day 5 1,152 13,721,181 $3,014 0.0220 $1,216,033 $1,219,047 0.25%
5 Small General Service 7 27,998 148,988,687 $32,722 0.0220 $16,233,672 $16,266,394 0.20%
6 Large General Service - Secondary 9S 32,283 3,140,350,716 $689,709 0.0220 $195,058,611 $195,748,320 0.35%
7 Large General Service - Primary 91) 189 431,899,796 $94,857 0.0220 $23,086,186 $23,181,043 0.41%
8 Large General Service - Transmission 9T 2 2,712,595 $596 0.0220 $145,088 $145,683 0.41%
9 Dusk to Dawn Lighting 15 0 6,481,376 $1,423 0.0220 $1,231,311 $1,232,735 0.12%
10 Large Power Service - Secondary 19S 1 6,678,959 $1,467 0.0220 $354,845 $356,312 0.41%
11 Large Power Service - Primary 19P 105 2,050,443,491 $450,335 0.0220 $97,221,416 $97,671,750 0.46%
12 Large Power Service - Transmission 19T 3 44,485,107 $9,770 0.0220 $1,998,342 $2,008,112 0.49%
13 Agricultural Irrigation Service 24 17,013 1,695,350,452 $372,346 0.0220 $116,053,614 $116,425,961 0.32%
14 llnmetered General Service 40 1,288 15,807,753 $3,472 0.0220 $1,189,372 $1,192,844 0.29%
15 Street Lighting 41 1,197 23,165,568 $5,088 0.0220 $3,327,180 $3,332,268 0.15%
16 Traffic Control Lighting 42 412 2,981,282 $655 0.0220 $155,372 $156,027 0.42%
17 Total Uniform Tariffs 486,451 12,411,275,627 $2,725,862 $875,025,522 $877,751,384 0.31%
18
19 Special Contracts
20 Micron 26 1 587,867,669 $129,112 0.0220 $23,828,078 $23,957,190 0.54%
21 J R Simplot 29 1 192,687,586 $42,320 0.0220 $7,389,321 $7,431,641 0.57%
22 DOE 30 1 236,974,493 $52,046 0.0220 $9,390,916 $9,442,963 0.55%
23 Hoku 32 1 0 $0 0.0000 $0 $0 0.00%
24 Total Special Contracts 4 1,017,529,748 $223,478 $40,608,315 $40,831,793 0.55%
25
26 Total Idaho Retail Sales 486,455 13,428,805,375 $2,949,340 $915,633,837 $918,583,177 0.32%
Note:
June 1, 2013 - May 31, 2014, Forecast
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-12-24
IDAHO POWER COMPANY
LARKIN, DI
TESTIMONY
EXHIBIT NO. 3
IDAHO POWER COMPANY
LONG-TERM CUSTOMER IMPACT
PROPOSED CUSTOM EFFICIENCY AMORTIZATION
IDAHO JURISDICTION
2013-2018
June 1. 2013 June 1. 2014 June 1. 2015 June 1. 2016 June 1. 2017 June 1. 2018
2011 Exoenditures with Carrvine Charees $8,126,504 $8,126,504 $8,126,504 $8,126,504 $0 $0
Mid-Year Amortization Adjustment $1,015,813 $1,015,813 $1,015,813 $1,015,813 $0 $0
Accumulated Amortization $0 $2,031,626 $4,063,252 $6,094,878 $0 $0
Rate Base Amount $7,110,691 $5,079,065 $3,047,439 $1,015,813 $0 $0
Annual Revenue Requirement $2,949,340 $2,687,136 $2,424,932 $2,162,728 $0 $0
2012 Expenditures with Carrvins Charees $8,126,504 $8,126,504 $8,126,504 $8,126,504 $0
Mid-Year Amortization Adjustment $1,015,813 $1,015,813 $1,015,813 $1,015,813 $0
Accumulated Amortization $0 $2,031,626 $4,063,252 $6,094,878 $0
Rate Base Amount $7,110,691 $5,079,065 $3,047,439 $1,015,813 $0
Annual Revenue Requirement $2,949,340 $2,687,136 $2,424,932 $2,162,728 $0
2013 Expenditures with Carrvine Charees $8,126,504 $8,126,504 $8,126,504 $8,126,504
Mid-Year Amortization Adjustment $1,015,813 $1,015,813 $1,015,813 $1,015,813
Accumulated Amortization $0 $2,031,626 $4,063,252 $6,094,878
Rate Base Amount $7,110,691 $5,079,065 $3,047,439 $1,015,813
Annual Revenue Requirement $2,949,340 $2,687,136 $2,424,932 $2,162,728
2014 Exaendltises with Carrvins Charges $8,126,504 $8,126,504 $8,126,504
Mid-Year Amortization Adjustment $1,015,813 $1,015,813 $1,015,813
Accumulated Amortization $0 $2,031,626 $4,063,252
Rate Base Amount $7,110,691 $5,079,065 $3,047,439
Annual Revenue Requirement $2,949,340 $2,687,136 $2,424,932
2015 ExDendltures with Carrvins Charees $8,126,504 $8,126,504
Mid-Year Amortization Adjustment $1,015,813 $1,015,813
Accumulated Amortization $0 $2,031,626
Rate Base Amount $7,110,691 $5,079,065
Annual Revenue Requirement $2,949,340 $2,687,136
cD0)m
o 5,9 Z
-I"
3
2016 Expenditures with Carrvina Charees
Mid-Year Amortization Adjustment
Accumulated Amortization
Rate Base Amount
Annual Revenue Requirement
$8,126,504
$1,015,813
$0
$7,110,691
$2,949,340
ITOTAL ANNUAL REVENUE REQUIREMENT $2,949,340 $5,636,477 $8,061,409 $10,224,137 $10,224,137 $10,224,137 I