20110408Vol I Oral Argument.pdf

ORIGINAL.BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF AN INVESTIGATION
OF APPROPRIATE COST RECOVERY
MECHANISMS FOR IDAHO POWER'S
ENERGY EFFICIENCY PROGRAS
CASE NO. IPC-E-10-27
BEFORE
COMMISSIONER MACK REDFORD (Presiding)
COMMISSIONER MARSHA SMITH
COMMISSIONER JIM KEMPTON
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PLACE:Commission Hearing Room
472 West Washington
Boise, Idaho
DATE:March 30, 2011
VOLUME I - Pages 1 - 48
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CSB REPORTING
Constance S. Bucy, CSR No. 187
23876 Applewood Way * Wilder, Idaho 83676
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1 APPEARANCES
2 For the Staff:
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For Idaho Power Company:
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For Industrial Customers
of Idaho Power:
Weldon Stutzman, Esq.
Deputy Attorney General
472 West Washington
Boise, Idaho 83720-0074
Lisa D. Nordstrom, Esq.
Idaho Power Company
Post Office Box 70
Boise, Idaho 83707-0070
RICHARDSON & 0' LEARY
by Gregory M. Ads, Esq.
Post Office Box 7218
Boise, Idaho 83702
Benjamin J. Otto, Esq.
Attorney at Law
Idaho Conservation League
Post Office Box 844
Boise, Idaho 83701
For Idaho Conservation
League, the Northwest
Energy Coalition and the
Snake River Alliance:
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APPEARANCES
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1 BOISE, IDAHO, WEDNESDAY, MARCH 30, 2011, 10: 00 A. M.
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4 COMMISSIONER REDFORD: Good morning. I'm
5 going to read a few remarks into the record before we get
6 started. It is 10: 00 a. m. on March 30, 2011, at the
7 Idaho Public Utilities Commission Hearing Room at Boise,
8 Idaho. This is the time and place set for a hearing
9 before the Idaho Public Utili ties Commission in the
10 matter of Idaho Power i s application for an investigation
11 of appropriate cost recovery mechanisms for Idaho Power IS
12 energy efficiency programs under this case, which is Case
13 No. IPC-E- 10-27.
14 My name is Mack Redford, a Commission
15 member. I will serve as the Chairman for this hearing.
16 With me today is Marsha Smith to my left, a Commissioner,
17 and Jim Kempton to my right, Commissioner and Commission
18 President. This proceeding is -- the proceeding in this
19 matter is being taken down by a court reporter. The
20 hearing is for the purpose of taking under consideration
21 a stipulation between Idaho Power Company, the Staff of
22 the Idaho Public Utilities Commission, the Idaho
23 Conservation League, the Northwest Energy Coalition and
24 the Snake River Alliance. These entities are
25 collectively referred to as the parties.
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1 A little background, on October 22, 2010,
2 Idaho Power filed an application requesting that the
3 Commission issue an order accepting the Company i s demand
4 side resource business model and to adjust how the
5 Company recovers the costs of specific demand side
6 management programs. More specifically, the Company
7 proposes to, one, move associated demand response
8 incentive payments into the power cost adjustment, PCA,
9 on a prospective basis beginning on June 1, 2011. Two,
10 to establish a regulatory asset for customer efficiency
11 program incentive costs beginning January 1, 2011, and,
12 three, change the carrying charge on the energy
13 efficiency rider from the customer deposit rate to the
14 Company authorized rate of return.
15 The parties convened a scheduling meeting
16 on January 12, 2011, and adopted a schedule to process
17 the case as set forth in Order No. 32160. During the
18 course of the settlement conference that occurred on
19 February 7, 2011, the parties, or the majority of the
20 parties, reached settlement. Although it participated in
21 the settlement conference, the Industrial Customers of
22 Idaho Power did not sign the stipulation. Also, and
23 although the Idaho Irrigation Pumpers Association did not
24 sign the stipulation, it does not oppose the stipulation.
25 On the 14th of February, 2011, the
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1 Commission issued its procedural Order No. 32178. The
2 Commission at the same time vacated the filing and
3 hearing dates set forth in procedural Order No. 32160.
4 In its stead, the Commission adopted the following
5 schedule: March 4, 2011, comments or prefiled testimony
6 in support or in opposition to the proposed settlement
7 agreement would be filed. March 18, 2011, reply comments
8 or testimony was to be filed. March 18, 2011, reply
9 comments or testimony was to be filed. March 30, 2011,
10 at 10: 00 a. m., hearing for oral argument on the proposed
11 settlement agreement.
12 I wanted to note specifically that the
13 previous order mentioned, had mentioned that the parties
14 could file written testimony, but once the stipulation
15 had been reached, the Commission in reference to written
16 testimony will treat such testimony as comments and no
17 cross-examination will be allowed.
18 If there are no preliminary matters to
19 take up before the hearing at this time, I will take the
20 appearances of the parties, Idaho Power Company, the
21 Commission Staff, the Industrial Customers of Idaho,
22 Idaho Conservation League, Northwest Energy Coalition and
23 Snake River Alliance, Idaho Pumpers Association and the
24 Community Action Partnership Association of Idaho. Who
25 appears for Idaho Power?
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1 MS. NORDSTROM: Good morning, my name is
2 Lisa Nordstrom and I i m appearing on behalf of Idaho
3 Power.
4 COMMISSIONER REDFORD: And who appears for
5 the Public Utilities Commission?
6 MR. STUTZMAN: Thank you, Mr. Chairman,
7 Weldon Stutzman on behalf of the Commission Staff and to
8 my right is Randy Lobb.
9 COMMISSIONER REDFORD: And for Idaho
10 Conservation League.
11 MR. OTTO: Good morning, this is Ben Otto
12 on behalf of the Idaho Conservation League, the Northwest
13 Energy Coalition and the Snake River Alliance, and to my
14 right is Nancy Hirsh who is an employee of the Northwest
15 Energy Coalition and also our expert witness.
16 COMMISSIONER REDFORD: How do you spell
17 that last name?
18 MR. OTTO: Hirsh is H-i-r-s-h.
19 COMMISSIONER REDFORD: Thank you, and who
20 appears for Community Action Partnership Association of
21 Idaho?
22 MR. STUTZMAN: Mr. Chairman?
23 COMMISSIONER REDFORD: Yes.
24 MR. STUTZMAN: Mr. Purdy represents the
25 Community Action Partnership Association of Idaho. He
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1 cannot be here today, but he did ask me to relay CAPAI' s
2 support for the stipulation in reiteration of the
3 comments that CAPAI filed on March 4th, 2011.
4 COMMISSIONER REDFORD: Thank you. Is
5 there anyone up here for Idaho Irrigation Pumpers
6 Association? It doesn't appear that anyone appears for
7 them. As the application was brought by Idaho Power,
8 I'll turn this proceeding over to Lisa Nordstrom.
9 MR. ADAMS: Excuse me, Chairman?
COMMISSIONER REDFORD: Yes.
MR. ADAMS: My name is Greg Adams and
12 I'm here on behalf of the Industrial Customers of Idaho
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Power.
COMMISSIONER REDFORD: Oh, I'm sorry.
MR. ADAMS: That's okay, and to my right I
16 have Dr. Don Reading who is our expert witness.
17 COMMISSIONER REDFORD: Your name again,
18 sir?
19 MR. ADAMS: Greg Adams.
COMMISSIONER REDFORD: That's right, okay.
21 Okay, are there any other parties that I haven't listed
22 that need to make their appearances? Hearing none, I'll
23 turn this matter over to Lisa. I might add that at the
24 close of this hearing, it is the intention of the
25 Commission to close the record and to deliberate in
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1 closed session to finally conclude this matter.
2 Ms. Nordstrom.
3 MS. NORDSTROM: Thank you. Good morning,
4 Chairman Redford and members of the Commission.
5 Cost-effective demand side resources, which include both
6 energy efficiency and demand response programs, are the
7 Company's resources of choice from both a cost and an
8 environmental perspective. The cleanest, most efficient
9 resource in the Company's portfolio is the one that it
10 does not have to build.
11 Since the energy efficiency rider was
12 first implemented, the Company has progressively
13 increased the breath of its DSM and energy efficiency
14 acti vi ties. In 2004, Idaho Power's local delivery
15 programs had fewer than 6,000 megawatt-hours of energy
16 savings and only six megawatts of demand reduction.
17 Compare that to last year, when Idaho Power and its
18 customers achieved more than 172,000 megwatt-hours of
19 energy savings and 336 megawatts of demand response.
20 These are tremendous results and more is yet to be
21 achieved. To continue its pursuit of all cost-effective
22 energy savings, Idaho Power filed this case to remove
23 obstacles inhibiting further progress toward that goal.
24 A settlement was reached with most of the
25 parties to this case and a stipulation was filed earlier
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1 this month. It represents a purposeful and moderate
2 step, not a dramatic policy change. The stipulation
3 agrees to the transfer of demand response incentive
4 payments to the PCA beginning June 1, 2011, and
5 addi tionally, the stipulation allows the impact of this
6 change to be revenue neutral to customer classes until
7 the next Idaho Power general rate case.
8 The stipulation also provides for the
9 establishment of a regulatory asset for incentive
10 payments made for the custom efficiency program beginning
11 January 1, 2011. The asset balance will earn the
12 authorized rate of return until it is placed in rates in
13 a future general rate case and will be amortized over a
14 seven-year period as opposed to the four-year
15 amortization originally proposed by Idaho Power.
16 Finally, the parties agree to leave the
17 carrying charge on the rider balance at the customer
18 deposit rate, instead of the change proposed by the
19 Company, because of diminished concern that Idaho Power
20 would carry a material negative rider balance into the
21 future.
22 Despi te having a $17.6 million rider
23 balance at the end of last year and even though there is
24 more cost-effective energy efficiency and energy savings
25 that can be achieved, the Industrial Customers see no
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1 compelling reason to act. Idaho Power does not agree
2 with their characterization that a negative deferral
3 balance is tantamount to overspending or fiscal
4 mismanagement, particularly when those funds were spent
5 to acquire least-cost peak capacity and energy resources
6 at the Commission's direction. The Commercial and
7 Industrial Customers certainly benefited from this
8 aggressive approach to energy savings, as they received
9 43 percent of the program incentives paid in 2010 from
10 the energy rider. There is no need or support to scale
11 back Idaho Power's demand side resources, which would
12 jeopardize cost-effective savings benefiting all
13 customers.
14 The Company has never expected that the
15 rider revenues and expenses would perfectly balance out
16 over time. Idaho Power's philosophy is to prudently
17 acquire all cost-effective demand side resources and to
18 promote sustainable funding of these programs over time.
19 Rider revenues should not be a cap or a ceiling on demand
20 side investments. The stipulation will allow the balance
21 to be paid off so that the rider level can be reassessed
22 in the future.
23 The Industrial Customers' recommendation
24 permits no demand side resource expense recovery in the
25 same year of expenditure and amounts to a de facto
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1 regulatory asset with a one percent return. This is a
2 significant drag on the Company's cash flows and is not
3 supporti ve of demand response endeavors -- demand side
4 resource endeavors.
5 By contrast, the stipulation advances the
6 acquisition of cost-effective demand side resources by
7 knocking down barriers to further investment. Under the
8 settlement, the regulatory treatment for both supply and
9 demand side resources would recognize prudent investment
10 in assets and provide rate of return ratemaking to each.
11 Additionally, annual power supply-related expenses are
12 properly accounted for in the power cost adjustment.
13 Al though the Industrial Customers fault
14 the stipulation for not addressing specific cost of
15 service treatment, cost of service is an issue that can
16 be more fully addressed in the Company's next general
17 rate case. In the interim, the stipulation ensures that
18 no cost allocation shift will occur between the customer
19 classes.
20 The Company believes that the stipulation
21 is a reasonable compromise by the parties that advances
22 the treatment of the Company's demand side resource
23 investments to a position essentially equivalent to its
24 investments in supply side resources. The seven-year
25 amortization period causes the Company some concern
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1 because of the different risk profile of demand side
2 resources, but strikes a reasonable balance when compared
3 to the overall lives of demand side investments. The
4 Company determined that it could drop its carrying charge
5 request in light of the substantial impact the other
6 agreed-upon actions will have on the rider's negative
7 balance.
8 This stipulation is fully consistent with
9 the prior stipulation approved by the Commission in Case
10 No. IPC-E-09-30. The stipulation in this current case
11 does not seek a general rate change. It only adjusts the
12 PCA and changes the inputs to the rider, both of which
13 are specified exceptions to the rate moratorium as
14 provided under section 5.2 of the stipulation in the
15 09-30 case.
16 In conclusion, approving the stipulation
17 relieves pressure to further increase the rider
18 percentage and provides all essential components to the
19 demand side resource regulatory model as it is
20 implemented here in Idaho, including the opportunity to
21 earn on demand side resource investments. This action
22 better aligns the risk/reward proposition for energy
23 efficiency activities.
24 Finally, the stipulation provides the
25 foundation for continued and robust demand side resource
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1 efforts at Idaho Power. For these reasons, the
2 Commission should approve this stipulation as being in
3 the public interest and the Company requests that the
4 Commission do so. That concludes my prepared remarks and
5 I'm happy to address any questions you have.
6 COMMISSIONER REDFORD: Any there questions
7 from the Commission? Commissioner Smith, any questions?
8 COMMISSIONER SMITH: No.
9 COMMISSIONER REDFORD: Thank you,
10 Ms. Nordstrom. The next person I'll call on is the
11 Staff. Mr. Stutzman.
12 MR. STUTZMAN: Thank you, Mr. Chairman.
13 The Staff agrees with Idaho Power's comments and believes
14 that the stipulation provides a reasonable solution to a
15 very real and practical problem. Idaho Power's
16 unrecovered DSM program costs totaled more than $17
17 million last year and that is expected to grow to over
18 $29 million by the end of 2012 if changes are not made in
19 the way that the programs are funded.
20 Staff believes the stipulation implements
21 reasonable changes so that the deferral balance is
22 reduced fairly quickly. By shifting incentive payments
23 for three DSM programs to the PCA effective June 1st this
24 year and capitalizing approximately $5 million of
25 incentive payments for the custom efficiency program,
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1 Staff expects the deferred DSM cost to be fully recovered
2 by mid 2012. Once that happens, Staff anticipates the
3 energy efficiency rider can be reduced from its current
4 level of 4. 75 percent of customer's base rates.
5 Going forward, the stipulation presents a
6 more balanced approach to recovery of Idaho Power's DSM
7 costs rather than loading everything on to the energy
8 rider. Staff urges the Commission to approve the
9 stipulation.
10 COMMISSIONER REDFORD: Are there questions
11 by the Commission to Mr. Stutzman? Mr. Kempton.
12 COMMISSIONER KEMPTON: Thank you,
13 Mr. Chairman. I have one comment and just a couple of
14 questions more for clarification than anything else. On
15 page 7 of Mr. Lobb' s direct testimony, there's a
16 statement that I wanted to clarify. I'll read it just
17 for the sake of having the information consistent. On
18 that page it reads, "However, because" -- this has to do
19 with the DSM rider, 4.75 percent that we have presently
20 in place. "However, because the funding needed for the
21 Company to pursue all cost-effective DSM programs has
22 grown beyond 5 percent of base revenue, it is attracting
23 unwarranted attention and criticism. Consequently,
24 timely recovery of DSM costs needed to promote
25 acquisition of cost-effective DSM has not occurred."
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1 While I can agree with the first comment,
2 the first sentence, that being if you put it on the
3 customer's bills, they are going to see it as the
4 Commission intended. If they don't like it, they are
5 going to complain about it, as the Commission intended,J
6 but there is no consequence of that that would affect
7 whether DSM costs that have accumulated were not
8 addressed to the Company's satisfaction because of that
9 criticism that's on the bills and so it's just a matter
10 of clarification the Commission in the past has addressed
11 and it's on the record the reasoning in not recovering
12 those costs at that particular time, and so that's the
13 only thing that I have that I want to comment in that
14 area. It's just simply a -- I don't think it's -- I
15 think it was just simply a misstatement in the wording
16 more than it was an intent of how it should apply to that
17 particular issue by Staff, so the other areas throughout
18 this section Staff has agreed to, they have specified
19 that in the custom efficiency program that there is to be
20 limited capitalization and as I understand it, that limit
21 on capitalization refers to the fact that it primarily,
22 perhaps wholly, that's what I wanted to clarify, has to
23 do with, having to do with, Idaho Power's largest energy
24 users, so the classification and the limitation having to
25 do actually with the size of the companies and so my
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1 question, then, to Staff, is that a correct
2 interpretation on my part?
3 MR. STUTZMAN: Yes, Commissioner, that is
4 correct. That custom efficiency program is for the
5 largest customers of Idaho Power.
6 COMMISSIONER KEMPTON: Mr. Chairman,
7 that's all the comments I have and questions.
8 COMMISSIONER REDFORD: Thank you. I'd
9 like to clear up an issue that may come up. When this
10 case was first filed, there was an Order, notice of
11 intervention of deadline and it also provided for a
12 notice of application. This was filed November 24th,
13 2010, and in that Order, it provided under the page 3
14 that you are notified that persons desiring to intervene
15 in this matter for purpose of presenting evidence or
16 cross-examining witnesses at hearing must file a petition
17 to intervene with the Commission.
18 This Order, also, while it didn't
19 specifically specify how testimony would be heard, it did
20 mention testimony and talked about cross-examination.
21 After this hearing or after this notice of application
22 came out, the parties met and at that meeting they
23 entered into the stipulation. As a result of that and in
24 the same case, in Order No. 32160, there was a new
25 procedural Order provided and in this provisional Order,
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1 it was my impression that this was, this Order superseded
2 the previous Order that I just read with regard to
3 testimony and it was recognized that there would be oral
4 argument as opposed to a full hearing whereby testimony
5 would be taken and that the testimony would be treated
6 after that as comments.
7 Mr. Stutzman, is my recollection correct
8 as to the Staff's position?
9 MR. STUTZMAN: Yes. I think all the
10 parties agreed that this was the process that we would
11 follow once the stipulation was reached.
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COMMISSIONER REDFORD: So the testimony
would serve as comments?
MR. STUTZMA: Yes.
COMMISSIONER SMITH: So it's not sworn,
16 it's not going to be cross-examined on?
17 MR. STUTZMAN: Correct.
18 COMMISSIONER SMITH: Okay.
19 COMMISSIONER REDFORD: If you have a
20 comment, Commissioner --
21 COMMISSIONER SMITH: I don't have a
22 comment.
23 COMMISSIONER REDFORD: I have one
24 question, Ms. Nordstrom, before we get to the next
25 parties. When you talked about the carrying charge, it
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1 is my understanding that in the earlier application and
2 throughout the settlement discussions that the charge,
3 the carrying charge, which is now the customer deposit
4 rate would change to the Company's authorized rate of
5 return; am I incorrect?
6 MS. NORDSTROM: That was what the Company
7 originally proposed, particularly if the rider balance
8 was not going to be addressed in a timely manner, because
9 the carrying costs associated with that would be longer
10 than the short-term customer deposit rate. The Company
11 believed that a different rate was more appropriate;
12 however, the settlement that was ultimately reached
13 between the parties agreed that the rate would continue
14 at the customer deposit rate of one percent.
15 COMMISSIONER REDFORD: Okay; so that's off
16 the table?
17 MS. NORDSTROM: It is if the stipulation
18 is approved.
19 COMMISSIONER REDFORD: Thank you. Do you
20 have any questions?
21 COMMISSIONER SMITH: I do not.
22 COMMISSIONER REDFORD: Okay. I'll take
23 the oral argument now of the Idaho Conservation League.
24 Mr. Otto.
25 MR. OTTO: Yes, thank you, Mr.
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COLLOQUY16
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1 Commissioner. I'd like to first start by just
2 rei terating my support for the argument of Idaho Power
3 and the Staff. We obviously agree as signing on the
4 stipulation with comments that were made. I think I want
5 to provide just a short summary of why we believe this is
6 the right step forward. Energy efficiency has changed.
7 It has become much more mature than it has in the past
8 and that's because this Commission has ordered the
9 Company to go after all cost-effective demand side
10 management and the Company has done so. They have done
11 so beyond what the 4.75 percent now will fund. They
12 should be commended for doing that. They're following
13 the Order and they're going out and getting what is
14 cost-effective, prudent resources.
15 The stipulation deals with two classes.
16 It deals with demand side or, sorry, demand response
17 programs. Those have been deemed prudent in, I think,
18 two cases now and a further prudency review is coming up
19 in the recently-filed 2010 DSM spending. The custom
20 efficiency program has been probably their best
21 performer, very cost effective, acquiring lots of
22 resources at a good price. This stipulation recognizes
23 the evolution of those programs and gets the regulatory
24 treatment to follow up.
25 The reason I think capitalization makes
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1 sense is that it begins to put these resources on equal
2 footing as supply side resources. We ask the Company to
3 provide electric service and to incent them to do so, we
4 give their shareholders an opportunity to earn a return
5 on that investment that they make. Now we're asking the
6 Company to provide electric service in the form of demand
7 side management and in order to incent them, we should
8 give them an opportunity to earn a return on those
9 investments as long as they're prudent and as long as
10 they're cost effective and the programs in the
11 stipulation have been and will continue to be available
12 to be reviewed each year.
13 The back balances from my step-back is
14 interesting. There's a lot of money out there that the
15 Company has hanging out unrecovered. I think from my
16 invol vement in the IRP process and on the Energy
17 Efficiency Advisory Group and Nancy, our witness, is also
18 on that group, have seen that there is, and Ms. Nordstrom
19 mentioned there is, other cost-effective DSM out there
20 that the Company could go acquire, but if we don't give
21 them the money to go out and get that, it's very hard to
22 expect them to do it. The back balance is a strain on
23 that and it's a legitimate strain. I mean, you can't
24 really expect somebody to go in debt to get stuff.
25 This stipulation provides a means to start
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1 paying down that back balance, but it doesn't require
2 that it's paid down in two years, but it provides a
3 better accounting treatment so that there's an
4 opportunity to do that. I think it's important to
5 support what are cost-effective programs.
6 As far as whether this will give the
7 ability to reduce the rider balance, as we stated in our
8 testimony, I think that we have to wait and see how
9 things play out after the stipulation is hopefully
10 approved and the Company moves forward. If it is true,
11 and I think it is true, that there is more cost-effective
12 demand side management out there that can be acquired and
13 a sufficient rider level will support that, then that's
14 the right way to go.
15 I guess in closing, I would just ask
16 that -- I recognize that we represent a group of
17 ratepayers. I've spoken with CAPAI's counsel, they
18 represent a lot of low income ratepayers who are
19 tradi tionally concerned about the rates and the costs.
20 We see this as an appropriate step to change the way
21 rates are funded so that in the long-term interests
22 demand side management, the regulatory structure is in
23 place to move forward. The stipulation is the correct
24 step forward, and one last point I just wanted to mention
25 is that Commissioner Kempton raised the point of what is
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1 a limited capitalization, I interpret that as limited in
2 that this is the custom efficiency program. It's one
3 program. It's a very cost-effective program. By taking
4 this kind of step, you can take a case-by-case basis and
5 a very limited approach to whether this makes sense. I
6 thought it was a good moderate step forward, so with
7 that, I'd stand for any questions.
8 COMMISSIONER REDFORD: Thank you. Are
9 there any questions from the Commission?
COMMISSIONER KEMPTON: No.
COMMISSIONER SMITH: No.
12 COMMISSIONER REDFORD: Thank you. I'll
13 turn it over to you, Mr. Adams, on behalf of the
14 Industrial Customers. Are you representing others other
15 than the Industrial Customers or just the Industrial
16 Customers?
17 MR. ADAMS: No, Chairman, I'm just here on
18 behalf of the Industrial Customers of Idaho Power
19 today.
20 COMMISSIONER REDFORD: You have the
21 floor.
22 MR. ADAMS: Thank you, Chairman. I want
23 to thank the Commission for holding oral argument in this
24 case. We think it's a very important case and
25 potentially precedent setting in Idaho. The Company's
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1 motivation for filing the application in this case was
2 two-fold: first, to advance its business and regulatory
3 model for its investments in DSM; and, second, to address
4 the growing negative balance in the EE rider account,
5 which as has already been stated is currently at $17
6 million and is proj ected to be $29 million by the end of
7 2012.
8 The effect of moving some of these
9 programs off of the energy efficiency rider account and
10 into the PCA, or into rate base, is to effectively
11 increase the amount of money that ratepayers will be
12 paying for energy efficiency programs to 6.6 percent of
13 base rates.
14 We disagree with the stipulation and are
15 opposed to it because we don't think it goes far enough
16 in addressing our concerns with the approach to how the
17 Company wants to address the negative balance and how
18 it's essentially proposing to incentivize demand side
19 management programs. Our position is that we recommend
20 the Commission reject the proposal in total or defer
21 determination of the filing until a general rate case
22 where the all issues, including the cost allocation
23 issues that I will discuss later, can be fully vetted.
24 We're opposed to the settlement because we
25 don't think it goes far enough in addressing our
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1 concerns. We don't believe a compelling case has been
2 made to warrant implementing the proposed changes and
3 raising the energy efficiency rider effectively to 6.6
4 percent at this time. Additionally, we're very concerned
5 wi th the precedent that would be set in a dramatic policy
6 shift to incentivize DSM activity without addressing all
7 the relevant issues in a single case.
8 I'm going to first start by talking about
9 the negative balance in the energy efficiency rider
10 account and then I'll talk about the Company's proposal
11 to rate base its custom efficiency program, and then I'll
12 talk a little bit about the cost allocation issues that
13 arise with the result of the stipulation. The negative
14 balance in the energy efficiency rider is currently $17
15 million and it will be $29 million by 2012. That's the
16 amount that Idaho Power has spent in excess of the 4.75
17 percent of base rates it's been authorized to collect
18 through its energy efficiency rider. That amount is $38
19 million that it's collecting in 2011 or, I'm sorry, I
20 think that was in 2010.
21 The DSM expenditures are projected to be
22 $43.4 million a year at this point. That results in a
23 COMMISSIONER REDFORD: How much did you
24 say?
25 MR. ADAMS: I'm sorry, these are 2011
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22 COLLOQUY
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1 figures. My notes were a little jumled there. It's $38
2 million they're collecting in 2011 and it's $43.4 million
3 that they're projected to spend, so that's a $5.5 million
4 shortfall.
5 COMMISSIONER REDFORD: Thank you.
6 MR. ADAMS: Shifting the three demand
7 response programs, the A/C cool credits program, the
8 irrigation peak rewards program and the EnerNOC flexpeak
9 management program to the PCA and eventually base rates
10 and the custom efficiency program into rate base while
11 leaving the rider at 4. 75 percent will eliminate the
12 negati ve balance in two years according to the Company's
13 filing, but it will effectively raise the DSM
14 expendi tures to 6.6 percent of base rates to do so. The
15 stipulating parties argue that simply raising the rider
16 to 6.6 percent will draw too much attention to it, but
17 they seem to have a disagreement amongst themselves as to
18 what is going to happen once that negative balance is
19 paid down.
20 The conservation parties want to leave the
21 rider at 4.75 percent while the other programs are not
22 collected -- are not funded through that rider; whereas,
23 Staff seems to argue that once the negative balance is
24 paid down, the rider percentage will go down. We're
25 opposed to this approach for several reasons. First, no
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23 COLLOQUY
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1 Idaho utility currently collects 6.6 percent of base
2 rates for DSM acti vi ties. Last year Rocky Mountain Power
3 requested to increase its energy efficiency rider to 5.85
4 percent of base rates and the Commission rej ected that
5 request and allowed only 4.74 percent, and just more
6 recently in the general rate case for Rocky Mountain
7 Power, their irrigation load control program was moved
8 into base rates as a systemwide resource and there was a
9 corresponding reduction in the energy efficiency rider.
10 That's very different from what we're proposing to do
11 here, which is to move programs out of the energy
12 efficiency rider, but leave the percentage the same
13 wi thout any determination of whether it would ever come
14 down.
15 Second, while we're supportive of
16 cost-effective DSM, we believe there should be some limit
17 to the funding. The premise of the Company spending over
18 4. 75 percent and the other parties' support of it is the
19 idea that the Commission has mandated Idaho Power to
20 pursue all cost-effective DSM without any limit. Staff
21 witness Randy Lobb cited Order No. 30201 in support of
22 that proposition. That's the Order where the Commission
23 approved -- issued a certificate of public convenience
24 and necessity for the Evander Andrews
25 COMMISSIONER REDFORD: Slow down.
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24 COLLOQUY
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1 MR. ADAMS: Sorry. I have a lot to get
2 through, so I'll slow down.
3 COMMISSIONER REDFORD: Okay, we've got
4 plenty of time.
5 MR. ADAMS: Okay. That's the case where
6 the Commission approved the CPCN for the 170 megawatt
7 Evander Andrews gas peaking plant, and the Commission
8 granted that certificate, but it also stated because the
9 opportunity to pursue cost-effective DSM as an
10 alternative was proposed that the Company should pursue
11 all cost-effective DSM. At that time, though, the energy
12 efficiency rider was set at 1.5 percent of base rates.
13 We don't think that that Order should be read to require
14 the Company to go out and spend far in excess of 4. 75
15 percent of base rates on these programs. We think there
16 needs to be some sort of defined limit and under the
17 other parties' formulation, there is no limit right now.
18 Today we're talking about 6.6 percent, but if there's no
19 limit, who's to say it won't go up to 10 or 20 percent.
20 The Commission stated last year in the
21 NEEA Order where the growing negative balance was an
22 issue, "The rider funds are provided by customers and are
23 not unlimited. The Commission expects rider funds to be
24 used judiciously to ensure customers received tangible
25 benefi ts from their payments to support energy efficiency
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25 COLLOQUY
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1 programs. "
2 The third reason we're not in favor of the
3 way that the Company proposes to treat the negative
4 balance is we don't think that they're doing enough with
5 the $38 million a year they're currently collecting. We
6 have repeatedly requested the Company do more third-party
7 evaluations to verify the cost effectiveness of programs
8 and make them more effective and to de-fund programs that
9 are not performing, and last year in the energy
10 efficiency prudency docket for the 2002 to 2007
11 expenditures, the Commission itself stated, "Idaho Power
12 should seek to employ independent evaluators for all of
13 its DSM programs and take affirmative steps toward
14 achieving measurable improvements in its documentation,
15 verification and record keeping processes."
16 Well, the 2010 DSM report that was just
17 filed contains only nine process evaluations of the 19
18 programs. We don't think that that's enough and these
19 process evaluations, based on my preliminary review of
20 them, don't look at free riderships of the programs and
21 they don't look at verifying the Company's
22 cost-effecti veness analysis for the programs. We think
23 that the Company could do more to identify the programs
24 that are underperforming and make the $38 million go
25 further.
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26 COLLOQUY
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1 Next, I'm going to talk about the
2 Company's business and regulatory model proposal to shift
3 the custom efficiency program into rate base and treat it
4 and "put it" on equal footing with supply side resources.
5 First, I think to provide some context, it's useful to
6 understand what this program is all about. That custom
7 efficiency program involves energy audits, technical
8 training and financial incentives for new construction
9 and retrofit proj ects in commercial and industrial
10 facilities. It had its genesis in 2003 in an Order where
11 the Commission approved of individual industrial
12 customers either being-self directed with their DSM
13 dollars to pursue their own programs or being involved in
14 a cost-sharing program with the Company where the Company
15 and the customers would cost share with an incentive-type
16 mechanism and that's what became the custom efficiency
17 program, but this is not a free rider program and the
18 customers don't simply receive a blank check. They make
19 a matching payment for the upgrade proj ect of 30 percent
20 and the Company pays 70 percent, so when Mrs. Nordstrom
21 says that the Industrial Customers receive 40 percent of
22 all incentive payments, that's a little bit misleading,
23 because the Industrial Customers themselves are actually
24 contributing an additional 30 percent on top of that for
25 demand side savings that are helping the entire system.
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27 COLLOQUY
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1 I would also like to point out that that
2 program achieved, I believe it was, 40 percent of all of
3 the Company's energy savings, 42 percent of all of the
4 energy efficiency savings, in 2010, so it's obviously a
5 very successful program, and if there was any program
6 that we are going to support rate basing, that would
7 certainly be it, but I want to remind the Commission of
8 an Order that Mr. Lobb cited in his testimony regarding
9 incenti vizing the utility. That's Order 24417 where
10 there was an issue before the Commission a long time ago
11 about whether it was proper to actually try to
12 incentivize the utility to earn an enhanced return on its
13 demand side activities.
14 The Commission stated, "The Commission is
15 unconvinced that there is a need for further incentive to
16 justify Company implementation of the proposed DSM
17 program. An electric utility has an obligation to
18 provide reliable least-cost energy service. A utility
19 should not expect to exact additional monies for doing
20 what is otherwise expected of it."
21 The basic premise is that in exchange for
22 providing least-cost service, the Company is entitled the
23 opportunity to recover prudently-incurred costs on assets
24 that are used and useful, plus an opportunity to earn a
25 fair rate of return on its invested capital, so if the
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28 COLLOQUY
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1 DSM dollars are prudently spent, they should be recovered
2 dollar for dollar and if they're investments, they should
3 be recovered just like any other rate base investment
4 that the Company may pursue with an appropriate
5 amortization period.
6 The reason that we oppose the Company's
7 application with regard to the custom efficiency program
8 is that it doesn't treat the custom efficiency program
9 like a normal supply side resource. The Company's
10 application and the stipulation intentionally accelerate
11 the recovery of the capital costs of the equipment
12 purchased. These incentive payments go towards physical
13 equipment, electric motors, for example, that have a
14 specific life that's longer than seven years, which is
15 the amortization period that the Company and the other
16 parties have signed on to in the stipulation.
17 Several years ago, the Commission
18 authorized the Company to capitalize its expenditures on
19 demand side resources and the same issue came up, and in
20 Order No. 27660 at page 4, the Commission only authorized
21 an accelerated amortization period of 12 years for those
22 expendi tures and it did so because the Company didn't own
23 the equipment and because there was regulatory
24 uncertainty during that time with deregulation where
25 utilities were at risk of suffering from stranded assets;
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29 COLLOQUY
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1 in other words, they would never recover that investment.
2 That doesn't exist today.
3 Deregulation and the risk of stranded
4 assets is no longer a viable threat. We recommended in
5 Dr. Reading's testimony that the Commission adopt an
6 accelerated recovery of 12 years, which is a reasonable
7 amount of time and there's Commission precedent for that,
8 and, frankly, our position is consistent with what the
9 Company says it's trying to do. That would put this
10 resource on a -- treat it like a normal supply side
11 resource with a realistic estimated amortization period
12 for the equipment and they would earn a reasonable return
13 on that investment.
14 Next I'm going to go into briefly the cost
15 of service and cost allocation issues that are not
16 addressed by the stipulation that we're concerned with.
17 The cost allocation impact of shifting over $20 million
18 from the energy efficiency rider to -- from the energy
19 efficiency rider to rate base and to base rates should be
20 addressed fully to evaluate the impact of the Company's
21 proposal. We think the Commission should expressly state
22 that they will treat these like system resources in a
23 cost of service study and that the demand-related
24 programs, which are the three demand response programs
25 that address peaking, will be allocated entirely to
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30 COLLOQUY
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1 demand in a cost of service study.
2 If these resources are truly supply side
3 resources, they should be treated as such in a cost of
4 service study and this is consistent with how the
5 Commission treated the irrigation load control program in
6 Rocky Mountain Power's recent general rate case in Order
7 32196.
8 We don't agree with Idaho Power's position
9 in its reply comments that not all parties have had an
10 opportunity to weigh in on this cost of service issue.
11 This case was noticed up last fall and numerous parties
12 have intervened and anyone who is paying attention would
13 know that moving $20 million from the energy efficiency
14 rider, which is spread according to base rates, into the
15 PCA is going to have a significant cost allocation
16 effect.
17 In conclusion, we think that the
18 Commission is faced with this problem where there's a $38
19 million per year already authorized recovery through the
20 energy efficiency rider being inadequate to pay down a
21 growing $17 million negative balance in the energy
22 efficiency rider because of the Company's many piecemeal
23 filings regarding DSM which never address all the
24 relevant issues.
25 Rather than have a single case each year
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31 COLLOQUY
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1 where all the interested parties look at all the money
2 the Company intends to spend on DSM and where that money
3 will come from, we get individual filings for approval of
4 certain programs, such as the NEEA approval last year, in
5 which nobody looks at the overall DSM expenditure and how
6 the Company will recover that expenditure from its
7 customers.
8 We also get filings for prudency
9 determination of expenditures in excess of the amounts
10 collected from the energy efficiency rider without
11 explanation of how the Company will recover those
12 expenses. The result is that the Commission must make
13 decisions that will have a material impact on customers'
14 rates in the abstract without any real analysis of the
15 rate impact.
16 We would request a better approach the
17 Commission could follow is to hold a single comprehensive
18 case each year adjusting the prudency, authorized
19 spending, and the results that the Company proj ects it
20 will achieve with that spending and use in its IRP
21 process and in its plans for future resource acquisition.
22 In that manner, the interested parties can see the costs
23 they will pay for these programs, how they will pay,
24 including the cost of service allocation and what
25 benefi ts they can expect.
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32 COLLOQUY
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1 We respectfully request the Commission
2 reject the Company's application or at least defer
3 determination on the new business plan until the
4 Company's next rate case where all the cost of service
5 issues can be addressed. Al ternati vely, if the
6 Commission addresses the substance of the application in
7 this case, we request that the Commission adopt our
8 recommended modifications to, one, extend the
9 amortization period for the custom efficiency program to
10 12 years; state that the DSM expenses moved into rate
11 base and base rates will be allocated as a systemwide
12 resource rather than to any single customer class; and,
13 third, state that the Company needs to reduce the energy
14 efficiency rider percentage in two years when the
15 negati ve balance is paid down.
16 That concludes my comments and I'm willing
17 to answer any questions that the Commissioners may
18 have.
19 COMMISSIONER REDFORD: Are there any
20 questions from the Commissioners? Mr. Kempton.
21 COMMI S S IONER KEMPTON: I ha ve one, Mr.
22 Chairman. So Mr. Adams, you sort of used interchangeably
23 the term prudency and cost efficiency. Would you care to
24 elaborate a little bit more on exactly what you mean by
25 those two terms?
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33 COLLOQUY
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1 MR. ADAMS: I'm sorry?
2 COMMISSIONER KEMPTON: Prudency on the one
3 hand of a particular program that's adopted and cost
4 efficiency of that same program if it's adopted. Those
5 are terms that you've used interchangeably, so I'm trying
6 to get a handle on whether you see a distinction between
7 prudency in examining a program and cost efficiency in
8 examining a program.
9 MR. ADAMS: Well, I think that prudency
10 would be the step where the Commission looks at whether
11 the Company actually followed through with its plans on
12 the program and whether -- whereas, cost effectiveness is
13 what everyone looks at when you're looking at developing
14 a new program. Ideally, the Commission would determine
15 that a program was prudently -- the expenditures were
16 prudently spent because the program proved cost effective
17 after the fact.
18 COMMISSIONER KEMPTON: When you address
19 the 17 million deficit that Idaho Power has now and the
20 Commission's actions in the past, would you agree that
21 Idaho Power was -- that the Commission examined prudency
22 in terms of going forward with those programs and not
23 halting the programs?
24 MR. ADAMS: I would agree that there has
25 been a prudency determination for the energy efficiency
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34 COLLOQUY
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1 rider funds spent in 2002 to 2007 and 2008 and 2009. To
2 the extent that some of those funds exceeded what was
3 collected on the energy efficiency rider, they've been
4 deemed prudent, although there's been no determination of
5 how they're going to be recovered if they exceed the
6 amount the Company can recover on the rider in the years
7 going forward.
8 COMMISSIONER KEMPTON: Would you also
9 agree that given the qualifications that you have put on
10 prudency in that regard that the cost efficiency of the
11 program can't be determined until out years?
12 MR. ADAMS: Right, the cost effectiveness
13 cannot be determined until after the program has been
14 implemented. You can do a projected cost effectiveness
15 before the fact.
16 COMMISSIONER KEMPTON: Isn't that what you
17 do when you do prudency? Isn't that the projected cost
18 effectiveness, but you don't know what it is until you've
19 actually run the program for awhile so you know what is
20 cost effective and what isn't and that's the time you
21 make a determination whether to eliminate the program?
22 MR. ADAMS: Yes, I would agree.
23 COMMISSIONER KEMPTON: Thank you.
24 COMMISSIONER REDFORD: I have just a
25 couple of questions and they kind of dovetail in with
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35 COLLOQUY
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1 what Commissioner Kempton said. I picked up during your
2 argument that on the one hand, you seem to be arguing
3 that Idaho Power is spending too little, and on the other
4 hand, they're spending too much and it seems to be when I
5 flush all those things together, it's really a matter of
6 a prudency review to determine what spending, whether
7 it's too much or too little, is the real key to this
8 issue; does the money that Idaho Power spent for its DSM
9 and other programs, is it prudent? Am I wrong or is that
10 what your argument is?
11 MR. ADAMS: I didn't mean to say they're
12 spending too little. I must have misspoke if I said
13 that. It's our position that the 4.75 percent should be
14 adequate at this time.
15 COMMISSIONER REDFORD: How do you make
16 that basis? I mean, where do you come up with that idea?
17 MR. ADAMS: Well, in our comments well,
18 in Dr. Reading's testimony, we pointed out a few programs
19 that we believe that the Company could scale back; for
20 example, the A/C cool credits program and the funding for
21 NEEA that was increased last year. We don't believe that
22 all the programs are as cost effective as the others and
23 that the Company can do a better job of paring down its
24 suite to the truly cost-effective programs.
25 COMMISSIONER REDFORD: So we're back again
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36 COLLOQUY
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10
1 to prudency; right? I mean --
2 MR. ADAMS: Well, I think that prudency
3 and cost effectiveness go together. I mean, it's
4 possible in theory for a program to appear to be cost
5 effective at the time that it's implemented and then it
6 doesn't turn out to be cost effective, so it's deemed
7 that the Company's decision at the time was prudent, but
8 that doesn't mean you should continue funding the program
9 going forward, that's
COMMISSIONER REDFORD: So you're
11 suggesting -- oh, go ahead. I cut you off, I'm sorry.
12 MR. ADAMS: No, no.
13 COMMISSIONER REDFORD: It seems to be you
14 have suggested that there ought to be a periodic maybe on
15 a yearly basis that all of these programs should be
16 reviewed to determine whether they have been effectively,
17 been effective, whether they've been cost effective and
18 you get back, then, to the prudency issue; is that what
19 you're suggesting?
20 MR. ADAMS: Yes, we would suggest that the
21 spending that's proj ected for the entire year be looked
22 at in a single case as opposed to just an after-the-fact
23 prudency case and as opposed to doing what we do now
24 where the Company files for approval of individual
25 programs without looking at what impact that has on the
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37 COLLOQUY
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1 overall expenditure and the Company's ability to recover
2 that and how it's going to recover that.
3 COMMISSIONER REDFORD: Isn't that to a
4 certain extent done in the IRP?
5 MR. ADAMS: I don't believe it is and we
6 actually pointed out in our testimony that the Company is
7 currently using a different proj ection for its demand
8 response programs in the IRP process than it's using in
9 this case to justify increased funding for them. It is
lOin Dr. Reading's testimony and I can provide you with the
11 exhibit numbers if you want, but in the discovery in this
12 case, they told us that there was going to be 376
13 megawatts of peak reduction from those three demand
14 response programs they're moving into the PCA in 2011,
15 but in the IRP process, they put an operational limit of
16 330 megawatts on those programs when they were looking at
17 whether they needed to build a new peaking plant and they
18 put a target of 306 megawatts for the same year. That's
19 a 70 megawatt difference. We think that all of these
20 things -- we think that the Company should have to use
21 the same projections in both forums, because otherwise,
22 we're going to be paying for increased demand response
23 funding and a new peaking plant.
24 COMMISSIONER REDFORD: Okay, well, I think
25 I understand, but I don't have any further questions. As
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38 COLLOQUY
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1 a result of Commissioner Kempton's or my questions, do
2 you have any questions, Commissioner?
3 COMMISSIONER SMITH: I do not.
4 COMMISSIONER REDFORD: Thank you. Okay, I
5 will give the parties an opportunity to do a rebuttal
6 statement and then we'll close it off, so then if anybody
7 wants a rebuttal statement, Ms. Nordstrom?
8 MS. NORDSTROM: Thank you. There are a
9 few issues that I would like to address that were raised
10 in Mr. Adams' oral argument. He did indicate that the
11 stipulation does not go far enough to address his
12 clients' concerns and I would point out that the
13 Industrial Customers' concerns are partially addressed by
14 this stipulation. There is a lengthened amortization
15 period from what the Company previously proposed and
16 that's several years longer than the four years that the
17 Company proposed and it was also specified in the
18 stipulation that no costs would be shifted between the
19 customer classes until the issue of cost allocation could
20 be resolved in a general rate case, and the customer
21 classes that were most at risk are Mr. Adams' clients and
22 we specifically attempted to address those concerns and
23 try to come up with a sustainable settlement of this
24 case, so while we understand that it doesn't encompass
25 everything his clients had hoped to achieve, though we
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39 COLLOQUY
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1 did make efforts to address those concerns.
2 COMMISSIONER REDFORD: Mr. Stutzman, do
3 you have any rebuttal?
4 MS. NORDSTROM: May I continue?
5 COMMISSIONER REDFORD: Oh, I'm sorry.
6 MS. NORDSTROM: He also addressed -- well,
7 he spoke about the fact that there's no limit on energy
8 efficiency funding and I do think that there are some
9 practical limits on energy efficiency funding. They're
10 limited by what programs are cost effective and also by
11 the appetite of customers and the Commission to fund
12 them, so Idaho Power doesn't believe that this is an
13 infinite resource, but to the extent that it's cost
14 effective, it's certainly something that should be
15 considered.
16 You know, the Company is also very much
17 aware that without engaging in a vigorous energy
18 efficiency and demand response portfolio that there is
19 not going to be an appetite to build additional plants
20 and/or other types of supply side resources and we
21 understand that that's part of the equation and are
22 looking to come up with a balanced portfolio that suits
23 the needs of our customers.
24 The Industrial Customers also spoke to
25 what i t perceives as a deficient evaluation effort on
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40 COLLOQUY
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1 behalf of the Company. Idaho Power paid particular
2 attention to the Commission's comments and recent orders
3 about the fact that it wished the Company to engage
4 third-party evaluators to evaluate its programs and the
5 Company has made efforts in that regard. In 2010, the
6 Company completed nine process evaluations which
7 encompassed its entire commercial, industrial and
8 irrigation program portfolio. It also completed four
9 process evaluations on its residential energy efficiency
10 programs.
11 Its evaluation plan is detailed in its
12 2010 Supplement 2 of its annual report that was filed
13 with this Commission on March 15th, just 10 days or two
14 weeks ago. I have a copy of that here if you're
15 interested in seeing what has transpired to date, what is
16 planned for this year and what we're anticipating in
17 2012, but it addresses all of our programs and obviously,
18 funding is an issue to do it all in one year, but there
19 is an organized approach to addressing evaluation by
20 third parties for all of the programs in the Company's
21 portfolio.
22 COMMISSIONER REDFORD: Could you make a
23 copy of that available to Mr. Stutzman? You don't need
24 to make it available to all of us.
25 MS. NORDSTROM: It is included in the
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41 COLLOQUY
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1 plan.
2 COMMISSIONER REDFORD: Okay.
3 MS. NORDSTROM: If you would like copies,
4 I could hand them out to you now or save them for later.
5 The Industrial Customers also spoke to the idea that the
6 actual lives of the equipment that is covered in the
7 custom efficiency program don't match the amortization
8 period of this regulatory asset and Mr. Gale's testimony
9 addressed that more specifically, but the experience in
10 the' 90s was that longer periods of amortization,
11 including the 12-year period that Mr. Adams proposes,
12 proved to be unsustainable, because those long-lived
13 assets also created large carrying charge obligations,
14 and while the intent was good to match the regulatory
15 assets and their useful lives together, the practical
16 effect was to inflate the regulatory asset balance with
17 accumulated carrying charges and that was something that
18 caused considerable alarm to the Staff and the Commission
19 in that IPC-E-97-12 proceeding, and that is what we were
20 trying to avoid in this docket was to come up with a
21 mechanism that would be more sustainable in the long
22 term.
23 Mr. Adams also addressed the A/C credit
24 cool program and intimated that somehow it was not cost
25 effecti ve and I would also address your attention to the
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42 COLLOQUY
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1 DSM annual report that was filed a few weeks ago. Page
2 20 of that report lists and details what happens in the
3 A/C cool credit program and the most recent evaluation
4 that was done on that program indicates that the total
5 resource benefit/cost ratio and the utility benefit/cost
6 ratio are both in excess of one; so 1.11, so it is now
7 cost effective.
8 That program had considerable up-front
9 costs and those fixed costs have now been ameliorated to
10 a certain degree with established recruitment and
11 equipment and so demand reduction can be achieved with
12 fewer fixed costs now and that's one reason why the
13 program is now cost effective, and 2010 was the year that
14 the Company anticipated that it would become cost
15 effecti ve and evaluations have borne that out.
16 Mr. Adams also addressed a perceived
17 discrepancy in demand response treatment in the IRP
18 versus other proceedings and I would just point out there
19 that these are relatively new resources to Idaho Power's
20 system, particularly in these quantities. Relative to
21 Idaho Power's system, which as compared to other utility
22 systems nationally, this is a very large percentage of
23 our system and we are really trying to learn how to
24 manage it and optimize it for the benefit of the Company
25 and its customers.
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43 COLLOQUY
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1 There are issues involving customer
2 acceptance, program persistence, optimizing dispatch and
3 optimizing the hours of use for the Company and for
4 system needs that the Company is really trying to address
5 and find a happy medium there, so while there are
6 different numbers that are being used, some are targets,
7 some are the maximum, and then others are where we're at
8 right now, but it's something that we're actively
9 addressing and is a challenge, but we're thrilled with
10 the success of the program, the three programs that
11 provide demand response.
12 With that, I would just reiterate it is
13 the Company's hope that the Commission will adopt the
14 stipulation. Thank you.
15 COMMISSIONER REDFORD: Mr. Stutzman?
16 MR. STUTZMAN: Nothing further,
17 Mr. Chairman.
18 COMMISSIONER REDFORD: Mr. Otto?
19 MR. OTTO: I guess I have a few quick
20 comments. I'd like to first address the -- Mr. Adams
21 raised the notion that maybe the parties were at a
22 different point on whether the rider should be reduced or
23 not and I would say that we actually are not at a
24 different point. I think the Staff in their testimony
25 and in ours said that's a possibility, but that's a
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44 COLLOQUY
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1 future possibility and we need to wait, hopefully approve
2 the stipulation, allow accounting to happen and look at
3 in the future whether that's appropriate.
4 I would also point you to in Ms. Hirsh's
5 direct testimony, the attachments showed some excerpts
6 from the Company's demand side potential study and what
7 that shows is that there is a large amount of economic
8 potential that's out there to be acquired and if we're
9 serious about having the Company go after all
10 cost-effecti ve and prudent DSM, we need to provide
11 regulatory support for them to go do that and I think
12 this stipulation does that.
13 I would also point out that Mr. Adams
14 raised whether they're using the current funding in
15 appropriate ways and he raised both NEEA and the A/C cool
16 credit program. Those cases were brought before the
17 Commission. The Industrial Customers made their
18 arguments, the Commission rejected them and they said
19 that these are programs that we see are cost effective
20 and that the Company should go forward. They should not
21 be now allowed to re-raise those arguments, and finally,
22 I think that going back to what is an appropriate way to
23 spend money and to review those programs, both the IRPAC
24 committee and the EEI committee at the Company review
25 what are good programs, where the Company should spend
CSB REPORTING
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45 COLLOQUY
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1 money, what adj ustments should be made. It's an active
2 process.
3 A lot of those decisions are made on a
4 kilowatt-hour savings and then finding appropriate money
5 to go out and get kilowatt-hour savings. This
6 stipulation helps support that, and on the EM&V issue, we
7 are very concerned that good quality third-party EM&V
8 happens on DSM programs. We believe that the memorandum
9 of understanding between the Staff and the Company
10 addresses that. We think that there is a good plan in
11 place. The Company is moving forward, but that takes
12 time and it also takes money, it takes sufficient funding
13 for them to go do those things, so while we are
14 concerned, we are comfortable with the path that is
15 playing out and encourage the Company to continue to do
16 that.
17 COMMISSIONER REDFORD: Thank you. The
18 Commission does not generally provide for surrebuttal, so
19 we'll take this matter under consideration and deliberate
20 and a decision will be made in due course. If there's
21 nothing else to come before the Commission at this time,
22 I'll declare the hearing at a close, and as I stated, it
23 is our position that the record is closed and we will
24 deliberate in due course.
25 MR. ADAMS: Thank you.
CSB REPORTING
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COMMISSIONER REDFORD: Thank you.
MR. STUTZMAN: Thank you, Mr. Chairman.
(The oral argument concluded at
11:05 a.m.)
CSB REPORTING
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47 COLLOQUY
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1 AUTHENTICATION
2
3
4 This is to certify that the foregoing oral
5 argument held in the matter of an investigation of
6 appropriate cost recovery mechanisms for Idaho Power's
7 energy efficiency programs, commencing at 10: 00 a.m., on
8 Wednesday, March 30, 2011, at the Commission Hearing
9 Room, 472 West Washington Street, Boise, Idaho, is a true
10 and correct transcript of said oral argument and the
11 original thereof for the file of the Commission.
12
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23
ois~u- ~
CONSTANCE S. BUCY
Certified Shorthand Reporter
19 \ \" \ II "r ii,'" \ \ /, L,'_\CE S 1':'1/,'.,.. . c,;r /..:.. ¿( ~ ,\\UlIlll/ll. Û /--~.: ., ",'d~ A""" 0 //
2' ~ ~:/O \ Ir j:\, .i ';';.
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"..... $' f/i.oi"..,.\\\"'" :\ ~ ".:'.'''1 )'4 TE Of '\ ,,'1/ ,"
" /, J I j II i \ \ \ \ \ \ \ \
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CSB REPORTING
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48 AUTHENTICATION