20120828Volume V.pdf

ORIGINAL
?DI 1 UG27 PHI :t1t BEFORE THE IDAHO PUBLIC UTILITIES COMMISSIbN
IN THE MATTER OF THE COMMISSION'S
REVIEW OF PURPA QF CONTRACT ) CASE NO.
PROVISIONS INCLUDING THE ) GNR-E-11-03
SURROGATE AVOIDED RESOURCE (SAR)
AND INTEGRATED RESOURCE PLANNING
(IRP) METHODOLOGIES FOR
CALCULATING PUBLISHED AVOIDED
COST RATES.
HEARING BEFORE
COMMISSIONER MARSHA H. SMITH (Presiding)
COMMISSIONER MACK A. REDFORD
COMMISSIONER PAUL KJELLANDER
PLACE: Commission Hearing Room
472 West Washington Street
Boise, Idaho
DATE: August 8, 2012
VOLUME V - Pages 679 919
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• HEDRICK
COURT REPORTING
POST OFFICE BOX 578
BOISE, IDAHO 83701
208-336-9208
TECHNICAL
HEARING
&,, '' 1978
APPEARANCES
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For the Staff:
For Idaho Power Company:
For Avista Corporation:
For PacifiCorp dba Rocky
Mountain Power:
For Idaho Wind Partners I,
LLC:
For The Northwest and
Intermountain Power
Producers Coalition;
Grand View Solar II;
The Board of County
Commissioners of Adams
County, Idaho; J. R. Simplot
Company; Exergy Development
Group of Idaho, LLC; and
Clearwater Paper Corporation:
For Renewable Northwest
Project; Idaho Windfarms,
LLC; and Ridgeline Energy,
LLC:
KRISTINE A. SASSER, Esq.
Deputy Attorney General
472 West Washington
Boise, Idaho 83702
DONOVAN E. WALKER, Esq.
and JASON B. WILLIAMS, Esq.
Idaho Power Company
Post Office Box 70
Boise, Idaho 83707-0070
MICHAEL G. ANDREA, Esq.
Avista Corporation
1411 East Mission Avenue
Spokane, Washington 99202
DANIEL E. SOLANDER, Esq.
Rocky Mountain Power
201 South Main Street, Suite 2300
Salt Lake City, Utah 84111
BENJAMIN J. OTTO, Esq.
Idaho Conservation League
710 North Sixth Street
Boise, Idaho 83702
GIVENS PURSLEY, LLP
by DEBORAH E. NELSON, Esq.
601 West Bannock Street
Boise, Idaho 83702
RICHARDSON & O'LEARY, PLLC
by PETER J. RICHARDSON, Esq.
and GREGORY M. ADAMS, Esq.
Post Office Box 7218
Boise, Idaho 83707
McDEVITT & MILLER, LLP
by DEAN J. MILLER, Esq.
420 West Bannock Street
Boise, Idaho 83702
HEDRICK COURT REPORTING APPEARANCES
P. 0. BOX 578, BOISE, ID 83701
For Mountain Air Projects, UDA LAW FIRM, PC
LLC: by Michael J. Uda, Esq.
7 West Sixth Avenue, Suite 4E
Helena, Montana 59601
For Renewable Energy WILLIAMS BRADBURY, PC
Coalition and Dynamis by RONALD L. WILLIAMS, Esq.
Energy, LLC: 1015 West Hays Street
Boise, Idaho 83702
For Twin Falls Canal Company, CAPITOL LAW GROUP, PLLC
North Side Canal Company, by C. THOMAS ARKOOSH, Esq.
Big Wood Canal Company, and 205 North Tenth Street,
American Falls Reservoir Fourth Floor
District No. 2: Boise, Idaho 83702
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INDEX
WITNESS EXAMINATION BY PAGE
Tessia Park - cont. Mr. Miller (Cross) 679
(Idaho Power) Mr. Uda (Cross) 702
Commissioner Smith 703
Commissioner Kjellander 707
Mr. J. Williams (Redirect) 708
Karl Bokenkamp Sworn 711
(Idaho Power) Mr. Walker (Direct) 713
Prefiled Direct 718
Mr. R. Williams (Cross) 752
Mr. Arkoosh (Cross) 756
Ms. Sasser (Cross) 756
Commissioner Smith 759
Robert Looper Mr. R. Williams (Direct) 762
(Dynamis) Mr. Richardson (Cross) 773
Prefiled Direct 776
Ms. Sasser (Cross) 786
Mr. Walker (Cross) 788
Commissioner Kjellander 790
Mr. Arkoosh (Cross) 791
Mr. Walker (Cross) 793
Louis Zamora Sworn 794
(Twin Falls Canal Company, Mr. Arkoosh (Direct) 795
et al) Prefiled Direct 797
Ms. Sasser (Cross) 805
Mr. Andrea (Cross) 806
Mr. J. Williams (Cross) 807
Richard Guy Ms. Nelson (Direct) 810
(Idaho Wind Partners) Prefiled Direct 812
Ms. Sasser (Cross) 818
Mr. Walker (Cross) 821
Justin Hayes Mr. Otto (Direct) 825
(Idaho Conservation League) Prefiled Direct 827
Donald Schoenbeck Mr. Arkoosh (Direct) 836
(Twin Falls Canal Company, Prefiled Direct 838
et al) Prefiled Rebuttal 883
Mr. Solander (Cross) 897
Ms. Sasser (Cross) 899
Mr. Andrea (Cross) 909
Mr. J. Williams (Cross) 913
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HEDRICK COURT REPORTING INDEX
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1 EXHIBITS
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RRIOMW
PAGE I
3
For Idaho Power Comoan
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7 Sample of AURORA Output Necessary to Premark

5 Determine Avoided Costs, 6 pgs Admit 751

6 8 Comparison of 20-Year Levelized QF Premark
Contract Pricing Admit 751
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16 A Comparison of 20-Yr Levelized Qf Mark 751

8 Contract Pricing Admit 751

9 For Dynamis:

10 1001 Robert Looper Curriculum Vitae, 3 pgs Premark
Admit 786
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1003 Firm Energy Sales Agreement, Dynamis Mark 912

12 Ada County Landfill Project, Pgs 1
and 22-23, 3 pgs
0

13 For Twin Falls Canal Company, et al:
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1101 Donald Schoenbeck Qualifications, 2 pgs Premark

15 Admit [:IY1I

16 1102 Midway Power Production Mark 796
Admit 804

17 For Idaho Conservation League:

18 1701 Request for Production No. 19, 4 pgs Premark
Admit 834
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1702 FERC Order Issuing License, Re: Twin Premark

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Falls Canal Company, North Side Canal Admit 834
Company, Ltd., 25 pgs
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1703 FERC Order Issuing new License, Re: Premark
'A.

Idaho Power Company, 14 pgs Admit 834

23 1704 FERC Notice of Application for Premark
Amendment of License, Idaho Power Admit 834

24 Company, 12 pgs

25 1705 10/11 Idaho Power Biological Assessment Premark
for the Snake River Physa, 17 pgs Admit 834
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BOISE, IDAHO, WEDNESDAY, AUGUST 8, 2012, 9:00 A.M.
COMMISSIONER SMITH: Good morning, ladies and
gentlemen.
I believe we are with your witness.
MR. J. WILLIAMS: Good morning, Madam Chair.
Yes, I'd like to recall Ms. Park.
TESSIA PARK,
produced as a witness at the instance of Idaho Power Company,
having been previously duly sworn, resumed the stand and was
further examined and testified as follows:
COMMISSIONER SMITH: And, Mr. Miller, I think we
are ready for your questions.
MR. MILLER: I am, Madam Chairman, and thank you
and members of the Commission for your considerations
yesterday.
CROSS-EXAMINATION
BY MR. MILLER:
Q. Ms. Park, my name is Joe Miller. I'm going to
ask you a few questions, and I would appreciate it if you would
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listen carefully to each question as I ask it and be sure you
have it well in mind. Would that be agreeable?
A. Yes.
Q. If there are -- any of my questions are in any
way unclear --
MR. MILLER: Randy.
MR. RANDY LOBB: Yes?
MR. MILLER: Could you move?
MR. RANDY LOBB: Sure.
MR. MILLER: Thanks.
MR. MILLER: Seating malfunction.
Q. BY MR. MILLER: If any of my questions are in any
way unclear, please ask me to clarify them before trying to
guess at what I'm trying to ask you. Would that be agreeable?
A. Yes.
Q. And if your lawyer should happen to object to any
of my questions, please let the Commission rule on the
objection before trying to answer the question. Would that be
agreeable?
A. Yes.
Q. So with all those understandings, would that be
an agreeable way for us to proceed with these questions, in
your mind?
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I wasn't quite sure I left with a complete understanding of
your answers, and one question was: How much wind does Langley
Gulch allow Idaho Power to integrate into its system?
A. I don't think I specifically testified to how
much wind Langley Gulch will allow Idaho Power to integrate
into its system.
Q. Do you know the answer to that question?
A. No, I do not.
Q. Okay. Do you have an estimate or just a complete
blank in that area?
A. I couldn't or wouldn't speculate on that at this
time.
Q. All right. Thank you. Another question from
yesterday was whether any QF projects that are owned by any
affiliate of Idaho Power Company would be subject to your
curtailment proposal. I've had a chance to look at Idaho Power
Company's Response to Production Request No. 7, which I believe
is not confidential, sent to Idaho Power by Exergy, and the
Answer to that Interrogatory -- or, Production Request I'll
represent to you lists ten QF projects, all of which are under
ten megawatts in nameplate rating capacity. Would that seem
correct to you?
A. Because I don't have a copy of that available to
me, I'd have to say that that does, subject to verification.
Q. So it's subject to check, you would accept that?
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A. Yes.
Q. And would you accept, subject to check, that all
of those are less than ten megawatts?
A. Like I said, I don't have a copy of it, but if
you're saying that's what the Production Request says, then,
yes, subject to check.
Q. All right. So none of the Idaho Power affiliate-
owned QF projects would be subject to your curtailment
proposal?
A. If those projects are, indeed, under ten average
megawatts, they would not be, or ten megawatts, they would not
be subject to Schedule 74 curtailment.
Q. As I understand it, you filed your direct
testimony on January 12 of 2012. Is that correct?
A. I believe so, but I can't confirm that exact
date.
Q. Okay. Well, let's just for talking purposes say
that's when you filed it. Could you give us an idea of when,
prior to January 12th --
MR. WALKER: Madam Chair, excuse me. Perhaps we
could clarify the date Idaho Power's testimony was filed,
because it was not January 12th.
COMMISSIONER SMITH: My copy is stamped January
31st.
MR. WALKER: Thank you, Madam Chair.
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MR. MILLER: Thank you for that correction,
Mr. Walker. I don't know why I have it wrong.
Q. BY MR. MILLER: But in any event, you filed it
apparently on January 31st?
A. Is that a question?
Q. Yes.
A. As Marsha indicated, it appears that it was
January 31st.
Q. Okay. And approximately when, prior to January
31st, were you given the assignment of preparing that
testimony?
A. I don't recall.
Q. I assume it wasn't the day before.
A. No.
Q. Could you give us an estimate in terms of
weeks?
MR. J. WILLIAMS: Madam Chair, I'm going to
object. I don't see how Ms. Park's preparation of her
testimony is relevant to this proceeding or what she testifies
to.
COMMISSIONER SMITH: Mr. Miller.
MR. MILLER: I think I can ask it in a different
way.
Q. BY MR. MILLER: Sometime prior or for some period
of time prior to January 31st, Idaho Power Company was aware of
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what it's calling its light load problem. Would that be a
correct statement?
A. Yes.
Q. And for approximately how long prior to January
31st had Idaho .Power Company been aware of what it has called
its light load problem?
A. From an operations perspective, I would have to
say probably the last year and a half or so.
Q. Well, during that year-and-a-half period prior to
January 31st, did Idaho Power initiate any sort of informal
process to address low loading contingencies in a collaborative
way with the renewable industry?
A. Can you restate that, please?
Q. Prior to January 31st, did Idaho Power Company
initiate any sort of informal process to address low loading
contingencies in a collaborative way with the renewable
industry?
A. I don't know that we specifically worked
collaboratively with the renewable industry, although we do
work with various entities in the Northwest and in the West
regarding renewable energy and, in particular, intermittent
renewable energy, and how to integrate it into your system.
Q. I thought a few minutes ago we had an
understanding that you would listen to my question and answer
the question that I asked.
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A. I thought I was answering the question you asked.
Q. The question I asked was prior to January 31st,
did Idaho Power initiate any sort of informal process to
address low load contingencies in a collaborative way with the
Idaho renewable industry?
MR. J. WILLIAMS: Madam Chair, that question has
been asked and my witness answered.
COMMISSIONER SMITH: Well, I don't think I've
heard the answer to that precise question, so, Ms. Park, if you
understand the question --
THE WITNESS: Yes, Commissioner.
I think it seems, to me, that you're asking me
that if Idaho Power were to collaboratively specifically with
Idaho --
Q. BY MR. MILLER: With the Idaho renewable
industry.
A. Not specifically, no.
Q. Did you read the Intervenor testimonies that were
filed on or about June 5, 2012?
A. Yes, I have read them.
Q. And after reading those testimonies, did you --
or, did one or more Intervenor witnesses express concerns about
Schedule 74 curtailment proposal?
A. Yes, I would say that some of them had expressed
concerns about it.
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Q. Well after seeing and understanding those
concerns, did Idaho Power initiate any sort of informal process
to address those concerns in a collaborative way?
A. No, Idaho Power did not meet with the parties to
discuss those in a collaborative manner.
Q. Do you have your testimony with you?
A. Yes, I do.
Q. Would you turn to page 4.
Are you with me?
A. Yes.
Q. Thank you. Would you read for us the sentence
that starts on line 5?
A. Because it's restating the previous sentence, I'd
like to start at the line 1 with "while."
Q. I couldn't quite hear you, I'm sorry.
A. Because the starting of the sentence on line 5
starts "in other words," and I'm restating or describing the
previous sentence --
Q. Uh-huh.
A. -- I'd like to start with the previous sentence.
Q. That would be fine, whatever you want to do.
A. "While the Company and the industry are
continuing to develop more robust forecasting tools, it is
still difficult to predict with any accuracy when the wind will
blow and, thus, when wind turbines will generate energy. In
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1 other words, the Company has no way of controlling how.much of
2 this type of energy it will get or when it will get it."
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Q. All right. In that sentence, I'd like to start

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by focusing -- well, let me ask you this:
5 You wrote that testimony, we now know, on January
6 31st?

7 A. It was submitted on January 31st, yes.

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Q. Is that still a correct statement today?

9 A. Yes, it is.

10 Q. I'd like to focus your attention on the phrase

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"no way of controlling" in that last sentence. If I

12 represented to you that on March 26, 2012, Idaho Power
13 curtailed the Rockland Wind Project for a total of three hours

14 and 28 minutes, would you have any reason to disagree with

15 that?

16 A. Subject to verification, no.

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Q. If I represented to you that on March 28, 2012,

18 Idaho Power Company curtailed the Rockland Project for a total
19 of four hours and ten minutes, would you have any reason to

20 disagree with that?

21 A. Again, once subject to verification.

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Q. If I represented to you that on April 1, 2012,

23 Idaho Power curtailed the Rockland Project for a total of one

24 hour and 57 minutes, would you have any reason to disagree with
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A. Like I said, once again, subject to verification, I
no.
Q. If I represented to you that on May -- May 27th,
Idaho Power curtailed the Rockland Wind Project for a total of
19 hours and 11 minutes, would you have any reason to disagree
with that?
A. Once again, I, without having the data, I can't
verify that those are true.
Q. But subject to check, you would accept that?
A. Yeah.
Q. If Irepresented to you that on May 29, 2012,
Idaho Power curtailed the Rockland Project for a total of one
hour and 55 minutes, would you have any reason to disagree with
that?
A. As previously stated, subject to check.
Q. If I represented to you that on July 16, 2012,
Idaho Power curtailed the Rockland Project for a total of five
hours and 14 minutes, would you have any reason to disagree
with that?
A. Once again, subject to verification, subject to
check.
Q. If I represented to you that since March 26,
2012, Idaho Power has curtailed the Rockland Project for a
total of 35 hours and 55 minutes, would you have any reason to
disagree with that?
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A. Once again, subject to check, I would not
disagree.
Q. Do you wish to revise your testimony where you
say that Idaho Power has no way of controlling when it will
receive energy?
A. In my testimony, the "no way of controlling"
meaning that we have no way to dispatch that energy. The fact
that we have implemented Schedule 72 curtailments, which we do
so by limiting the output of facilities, I think that this
testimony still stands that we really have no way of
controlling when they're going to deliver beyond a Schedule 72
curtailment.
Q. Well, you do have the ability to control when you
accept it?
A. Under Schedule 72, yes.
Q. I'd like now to focus on the phrase in that
sentence "or when we" -- "when it will get it." Would you
reread the sentence and get that phrase in your mind?
A. Yes.
Q. Do you have an Exhibit 2201 with you?
A. No, I do not.
Q. Yesterday, I handed an extra copy of that exhibit
to your counsel. Perhaps he could give it to you.
MR. WALKER: Madam Chair, if I may approach.
COMMISSIONER SMITH: You may.
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MR. WALKER: And I would note, for the record,
our -- Idaho Power's cooperation with Mr. Miller.
MR. MILLER: That's an event worth noting.
COMMISSIONER SMITH: I just thought to myself,
There's a first time for everything.
Now if I could just find mine.
Q. BY MR. MILLER: Do you have Exhibit 2201 with
you?
A. Yes, I do.
Q. Okay. Would you turn to page 46. And on
page 46, is there a requirement that the Rockland Project
communicate to Idaho Power daily wind forecast information?
A. There is a requirement that they communicate
estimated generation for the current day.
Q. Would you read into the record that portion of
page 46?
A. Do you want the entire reporting requirement or
just the two statements regarding what they're reporting?
Q. The two statements regarding the wind.
A. It says that they will report in at 10:00 a.m.
and leave the following information: The estimated generation
for the current day, and the estimated generation for the next
day.
Q. So, Idaho Power receives from the Rockland
Project a daily and next-day estimate of its wind production.
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Is that correct?
A. Yes.
Q. Bear with me for a moment. I'd like you now to
go to page 27 and look at Paragraphs 9.3.2 and 9.3.3, just to
get them in your mind.
A. I've read those.
Q. And looking at 9.3.3, I'll just read a portion of
it to you:
The seller will install the necessary equipment
to be able to electronically transmit this wind data and wind
turbine availability status real-time to Idaho Power.
Is it your understanding that Ridgeline does, in
fact, transmit on a continual and instantaneous basis all of
the wind data that is contemplated by Paragraph 9.3?
A. It is my understanding that they do, but I'd need
to verify that that actually, in fact, occurs.
Q. Do you wish to revise your statement in page 4,
line 5, that Idaho Power has no way of knowing when it will
receive wind?
A. No, I do not. I think that when we talk about
getting an estimation of next day's generation output, it can
be a total output. Once again, it's dependent upon whether the
wind actually does occur. And you may get the data
instantaneously when it does occur, but it doesn't do you any
good because you're trying to set up in the day ahead for the
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following days, or as you're trying to deal with the following
hours that you have to be able to meet your obligations to
serve load.
Q. You do receive though, I think you've indicated,
real-time wind data from the Rockland Project, so from minute
to minute, Idaho Power knows precisely what the Rockland
Project is producing. Is that not true?
A. It is true that we do know what the project is
producing, minute to minute. But once again, that doesn't
provide us what we need to be able to balance the system in our
demands to reliably serve the load.
Q. All right, we'll come back to this. There is one
other aspect of Exhibit 2201 I would like to discuss with you.
Would you turn to page 3?
A. I'm on page 3.
Q. You're with me. If you'll now look at
Paragraph 1.1. Are you with me?
A. Yes.
Q. If I can summarize for you and if you think I'm
summarizing incorrectly, please let me know, but as I
understand it, in this paragraph, for the purpose of
calculating mechanical availability, a deduction is made for
hours in which force majeure, forced outage, or failure to
receive energy prevents acceptance of the energy. In other
words, in calculating the mechanical availability, the project
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is not penalized for force majeure hours, forced outage hours,
or failure to receive hours.
Is Idaho Power Company proposing to amend the
firm energy sales agreement such that Schedule 74 curtailment
hours would not cause the project to be in jeopardy of missing
its mechanical availability guarantee?
A. No, at this time, Idaho Power is not proposing
that we would amend this Section 1.1, because --
Q. So if Rockland Wind Project is curtailed and if
the Commission should approve Schedule 74, it would not receive
a -- an assurance that the curtailment hours would not be
counted against its mechanical availability commitment?
A. Because Schedule 74, actually, the regulation
removes Idaho Power's obligation to procure that energy during
the situations as called out in our plan for Schedule 74, if it
were approved, seems, to me, that you could say that we failed
to receive it because we're not obligated to procure it at that
point. But that would be up for the lawyers to decide whether
that was, in fact, how that was interpreted.
Q. Is it your testimony then that further legal
review would be required to answer that question?
A. I'm saying that I wouldn't -- I would leave that
up to the lawyers to decide. That's not my decision.
Q. Well, if there are issues that still need to be
worked out with lawyers, isn't it fair to say that Schedule 74
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has not been fully thought through?
A. I wouldn't characterize it as that.
Q. All right. I'd like now, if you don't mind, to
ask a few questions about proposed Schedule 74 specifically,
which is Exhibit 5 to your testimony. Are you with me?
A. Yes.
Q. In the Definitions section, one of the
definitions is "must-run periods." Who within the Company
would make the determination that the Company is entering into
a must-run period?
A. Our balancing operations group would.
Q. Would that decision be reviewed by a -- any
person at the senior vice president level or higher?
A. No, that would not. They don't get involved in
the day-to-day operations of the system in that manner.
Q. And if we look specifically at the words in the
definition of "must run," we see the words "those periods when
the Company's system load demand in the upcoming hours and days
requires that sufficient base load resources."
As this schedule is written, is there any limit
on the number of hours and days that could be declared to be
must-run periods?
A. Currently as it's written, no. And I would say
that because it's defined by those low loading periods, that,
in and of itself, limits it. As I stated in my rebuttal
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testimony, we really don't foresee that occurring any more than
probably five percent of the time.
Q. Just as a reminder, we are kind of forgetting our
agreement to answer the question that I asked and not some
earlier question.
MR. J. WILLIAMS: Madam Chair, that's
argumentative and he's badgering the witness.
MR. MILLER: I thought it was very polite, but
I'll withdraw.
COMMISSIONER SMITH: Thank you, Miller. I think
the witness needs to give the answer that she thinks fully
answers the question that was asked.
Q. BY MR. MILLER: As it is written, could someone
within the Company declare that the next 30 days are a must-run
period?
A. That could be the case, depending on operational
condition, but I don't believe that that, in practice, is how
that would work because we don't look at it from that
perspective. We only balance and look at the balancing from a
operational perspective based off of day ahead or -- in "day
ahead" we're referring to one or two days before the actual
day. We will look at what the balance of actual resources and
load are in that period, hour by hour.
Q. As it is written, is there any notice to the
Commission or to qualifying facilities that the Company has
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declared a must-run period and its expected length?
A. There is nothing in the Schedule 74 that says
when the must-run period will be declared.
Q. As it is written, is there any opportunity for
the Commission or a qualifying facility to contest the
declaration of a must-run period?
A. No, there is not.
Q. Also in the Definitions section, there is a
definition of "base load resources." Assuming that the Jim
Bridger Plant was operating at 75 percent capacity, would it be
considered a base load resource in that circumstance?
A. Depending on circumstances, it would be hard to
answer that. It depends on what the load is for the following
day or what the ramp is between min load and max load, but we
don't foresee that it will be operating at 75 percent in low
loading periods. That's not typical.
Q. So the -- do I understand correctly then that
whether any of these generating complexes are base load
resources depends on operational circumstance -- operational
circumstances pertaining at any particular time?
A. Because you have to balance the loads to the
resources -- or, the resources to the loads is probably a
better way of saying it -- in that term, the day ahead, you're
looking at the economic stack, obviously, of resources, set
things up to run based off of that to meet those loads, and
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depending on what availability of different resources are, it
could change which ones were considered base load of those
resources.
Q. So maybe I could ask it this way: The resources
listed here are not all always base load resources. It depends
on the circumstances existing at the time?
A. Well, they're all base load resources. The
question is whether they be considered must-run base load
resources on those given days.
Q. All right, I getcha. Then the next section is
entitled Curtailment. Who in the Company would make the
decision to curtail?
A. The operators on shift would make the decision to
curtail if it was in real-time, and they're actually not --
they're limiting output, they are not curtailing to zero.
Q. Say that again.
A. They're limiting output, not curtailing to zero.
Q. You said, "They're limiting output," and I didn't
get the rest of it.
A. They're not curtailing to zero.
Q. I didn't imply that, did I?
A. Well, sometimes "curtailment" means that it goes
to zero, so I just wanted to clarify that.
Q. In that first sentence of the curtailment
section, there is the phrase "next anticipated load." Is that
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the next anticipated load in the next hour or in the next day
or in the next several days?
A. It could be the next day or in a couple of days
out, because you're actually setting up for -- as the markets
are set up, you're actually setting up, in some circumstances,
for three or four days out, depending on what the preschedule
days are for those periods.
Q. As it's written, the proposed Schedule 74 doesn't
tell us how many hours or how many days or doesn't tell us how
the next anticipated load is defined, does it? That would be
an operational thing, I guess?
A. Well, it is an operational thing, yes.
Q. Then would you look at the section entitled
Procedures, Paragraph 2, and there is the phrase "Wherein the
Company is not forced to make base load resources unavailable
for serving the next anticipated load, nor dispatch less
efficient, higher cost reserves to serve the system load."
Do you think a person of ordinary intelligence
can read that sentence and comprehend it?
A. You're asking me to speculate what somebody would
understand or not understand.
Q. Do you think that sentence provides an objective
standard by which a judgment could be made as to whether a
curtailment was proper or improper?
A. I don't know. If you're referring to a legal
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standard, I wouldn't answer whether that -- I don't have the
expertise to answer that question.
Q. Okay. Then let's take a look at the section
titled Notice and Recordkeeping. In the first paragraph, the
second sentence says: As a matter of practice, the Company
shall use commercially reasonable efforts.
What does "commercially reasonable efforts" mean
in this context?
A. From the operations perspective, what that means
is that we will give as much advance notice as we can in
setting up for those next hours.
Q. Is commercially reasonable efforts something less
than best efforts?
A. I don't know that I would say that it's less or
equal to.
Q. Then the tariff provides that the Company shall
maintain a record of curtailment hours, in subparagraph 3?
A. Yes.
Q. Will this be a public record on file at the Idaho
Public Utilities Commission?
A. No.
Q. If it's not a public record, will it be available
to qualifying facilities upon request?
A. Yes, it would be.
Q. To whom should such a request be made?
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A. It would be made to the balancing operations
group at Idaho Power.
Q. And how much time will expire before the Company
responds to such a request?
A. Typically, we respond to those requests as soon
as possible.
Q. Will that record contain any information that
Idaho Power Company considers to be proprietary or
confidential?
A. No, it would not.
Q. Would the record contain any information beyond
the total number of curtailment hours?
A. As stated in this policy, it would include data
regarding the loading of all generating units interconnected to
the Company's system prior to and during each of the periods of
curtailment.
Q. Would it include information sufficient to allow
a qualifying facility sufficient information to make a judgment
as to whether or not the curtailment was proper?
A. I don't know that I can answer whether it would
give you the information to determine that.
Q. Okay.
MR. MILLER: Could I have just a moment?
COMMISSIONER SMITH: Certainly.
Q. BY MR. MILLER: I direct your attention back to
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Exhibit 2201 and ask you to turn to page 60.
A. Page what?
Q. Sixty. Are you with me?
A. Yes.
Q. I won't go through this in detail with you other
than just to ask is it your understanding that all Idaho Power
firm energy sales agreements entered into after the issuance of
Commission Order 30488 contain a similar appendix?
A. I don't know. I'm not that familiar with that
Commission Order, and I don't know that all of them have this
language in them.
MR. MILLER: I think that's all I have.
COMMISSIONER SMITH: Thank you, Mr. Miller.
Mr. Uda.
MR. UDA: Madam Chair, as I said yesterday, I was
hoping that my cocounsel would ask my questions. I think
they've eliminated all but two.
COMMISSIONER SMITH: So your hopes were, well,
19 disappointing.
20 MR. tJDA: They were dashed.
21 COMMISSIONER SMITH: Go ahead.
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HEDRICK COURT REPORTING PARK (X)
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1 CROSS-EXAMINATION
2
3 BY MR. UDA:

Q. Good morning, Ms. Park. My name is Mike Uda. I
5 represent Mountain Air Projects. I just want to ask you a few
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questions related to the application of Schedule 74 to existing

7 contracts.

8
First of all -- and if you don't know the answer

9 to this, just -- it's fine -- but are you aware that existing
10 contracts have had to obtain financing arrangements in order to

11 secure the ability to construct their projects?

12 A. I am not involved in any of that, the finance
13 piece of the arrangements that they make, so generally aware

14 that they would have to have some kind of financing, yes.

15
Q. Right. And I think you've just testified that
16 your anticipation is these must-run periods, light loading

17 periods, whatever we're going to call it, is for approximately

18
five percent of the total hours a year?

19 A. As I stated in my testimony, I can't see that it
20 would be -- or, rebuttal testimony -- that it would exceed five

21 percent of the year.

22
Q. Okay. And so these existing projects right now
23 are receiving revenue from Idaho Power under the terms of their

24 existing contracts. Is that correct?
.
25 A. I would say that's correct.
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Q. And so will the effect of Schedule 74 be, as a
practical matter, to reduce the revenue that is going to be
paid to those projects?
A. It would -- it could potentially, yes.
Q. Okay. So is that not -- strike that.
Under those circumstances, is that not
essentially reduction in the rate that Idaho Power is paying
these existing QFs?
A. I'm not a rate expert, but I would say that
you -- they're still being paid the rate for the generation
that is -- that we're obligated to take.
MR. UDA: Thank you, Madam Chair. No more
questions.
COMMISSIONER SMITH: Okay. I think we're ready
for questions from the Commission.
COMMISSIONER REDFORD: No questions.
COMMISSIONER KJELLANDER: No.
COMMISSIONER SMITH: Well, I think I have a few.
Let's see.
EXAMINATION
BY COMMISSIONER SMITH:
Q. First of all, looking at Exhibit 5, page 2, the
Paragraph 2 under Procedures that Mr. Miller was asking you
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about.
A. Yes.
Q. So my question is what does that mean to you, the
part of the sentence that starts "Is not forced to make"?
A. That means that we wouldn't be forced to take off
base load resources to be able to have additional or to have
another resource standing by should the resources from the QF
not be available to meet those loads the following day.
Q. So, you know, it's early: I'm not grasping this.
Try it one more time.
A. So, one of the situations we get into is as we're
planning for the following day as we're trying to set up our
day-by-day/hour-by-hour load resource balance, we look at the
total amount of generation available during those hours and
what the load is expected to be, and as it ramps up and down
during the day, we have to have the ability to remove resources
or we dispatch them down to meet those load needs or ramp them
up. And there are circumstances where, for example, if wind
was to be forecasted, say it's going to be 400 megawatts in a
given hour, and we planned on that, we took off a base load
resource that may be -- you know, have a discharge -- dispatch
cost of $20 and we took it off, now it's not available to us
for potentially, you know, five, six days, that we would then
incur additional costs above that $20 because that resource
wasn't available and either the wind didn't show up or the
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1 loads were greater and we ended up having to go to the market
2 to cover those or dispatch a higher cost resource.
3
Q. I can see how it might be difficult to condense

4 that into a phrase in a sentence.
5 On page 22 of your direct testimony, you mention
6 "shoulder months" on line 24. Could you be more specific about
7 what you think shoulder months are?

8 A. When we're talking about shoulder months, we're
9 typically talking about the May, June, and more June typically
10 than July; and then sometimes in August, September, depending
11 on -- August, September, October, depending on what loads are

12 doing.
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13 Q. Okay. And are the hours -- let's see where you
mention the hours -- 11:00 p.m. to 6:00 a.m., is that on
15 weekdays only?

16 A. That is -- can also occur on the weekends as

17 well.

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Q. Okay, so it's not just weekends.

19 So I was curious about the five percent estimate
20 you gave. Could you tell me how you came up with that?

21 A. Yeah, because we -- from an operations
22 perspective when we look at, you know, past -- this last past
23 year even, we look at how often we get into the situation where
24 we would even be capable of having -- that the situations would
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that. Those don't occur very often. It is a limited set of

4 circumstances where those would occur, and they really are
5 those shoulder months periods where the, you know -- depending
6 on market conditions, what's available, and what resources

7 there are, what water conditions do, and, of course, what

8 temperatures do.

9
Q. So would you guess that the five percent would be
10 like the ceiling, the maximum amount that could ever be

11 imagined?

12 A. Five percent is based off of -- and I refer to
.
13 this in my testimony -- our current amount of renewable

14 resources we have on the system, but if that number were to
15 climb significantly, the five percent would potentially be
16 higher because we would have more surplus energy during periods

17 at a time when this condition could occur.

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Q. So it's more like an average for today?

19 A. Yes.

20 Q. Okay.

21 COMMISSIONER SMITH: All right, well, I think

22 that's all I have.

23 Oh, yes, Commissioner Kjellander.
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EXAMINATION
BY COMMISSIONER KJELLANDER:
Q. Thank you, Commissioner Smith. Your questions
prompted one that I'd like to build from your questioning, and
that is: With the five percent that you're looking at as sort
of a high end curtailment that you might see today, could you
describe for me what that perfect storm might look like that
would bump that percentage up higher?
A. If we were to receive significantly amount of
quantities more of PURPA energy on the system, especially that
that was predominantly available during the light load or low
loading periods, that would increase it, because a lot of the
intermittent resources, variable resources, the wind, tends to
generate at its highest during the low loading periods.
Significantly more amounts of that would increase the five
percent value.
Q. Then with the contracts that are currently signed
today but aren't constructed, if those are all built, wouldn't
that essentially be a piece of that perfect storm?
A. Yes, it could be.
Q. Okay. Thank you.
COMMISSIONER SMITH: Any redirect?
MR. J. WILLIAMS: Yes, Madam Chair, just a few.
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REDIRECT EXAMINATION
BY MR. J. WILLIAMS:
Q. Ms. Park, yesterday Mr. Williams questioned you
on the capability of Langley Gulch to operate in simple cycle
mode, and some assumptions were made by him in asking you those
questions. I guess I'd just like to clarify.
Can Langley Gulch be operated in simple cycle
mode?
A. Langley Gulch can be operated in a mode similar
to simple cycle mode. It can only do that per manufacturer's
recommendation for about an eight-hour period, and that period
is really intended if the steam plant trips and is not
available, that you would operate the unit as you're trying to
get the steam turbine back.
But from the perspective as it applies to
Schedule 74 and when we would use it and the availability to
run Langley as a simple cycle, the two wouldn't be there. We
wouldn't do that, because in those periods we would take the
unit offline rather than operating it and causing increased
wear and tear on the unit. We would take it offline if we
didn't absolutely need it for energy. And if we needed it for
energy, we wouldn't be in a Schedule 74 light load condition.
Q. Thank you. Mr. Miller rattled off a series of
dates and times in 2012, and I think the culmination, according
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to him, was 35 hours where Idaho Power had curtailed the

2 Rockland Wind Project.

3 Did Idaho Power curtail that project generation

4
to zero for those 35 hours, do you know?

5 A. Their output was limited, but not to zero.

6
Q. Mr. Miller also walked through the contract

7 that's identified as Exhibit 2201, which shows the project is

8 obligated to provide Idaho Power with estimates, forecasts, and
9 real-time data. Are those the same things as providing Idaho

10 Power a schedule of energy deliveries?

11 A. No, they are not, because the schedule of energy
12 deliveries would say that if you were to buy energy on the

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13 market, you'd be guaranteed that you'd receive that energy

14 during those periods of time, and in this case, we're not
15 guaranteed to receive that energy during those periods of time.

16
Q. Mr. Uda and others raised questions about

17 Schedule 74, criticizing the financial and economic impact of

18 implementing Schedule 74 on QF generators. So I guess the
19 question is is Schedule 74 an economic tool that Idaho Power is
20 proposing to implement, or is it more of a reliability tool
21 that the Company is looking to implement?

22 A. Schedule 74 is not an economic tool. It actually
23 protects the customers from increased costs of dispatching

24 units that are not -- would not have normally been dispatched

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25 had you not had the obligation to procure. However, if you
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didn't implement Schedule 74, we didn't have the ability to
implement Schedule 74, and we were actually forced into
positions to take some of these units offline in setting up for
the next day, you could very easily set yourself up for a
reliability situation because you've removed resources that
would have been dispatched that you needed to serve load
potentially and they're now not available. Because you take
Valmy and Bridger, Boardman, offline, they're not available,
contractually, for a period of about seven days.
Q. So if the Commission does not adopt Idaho Power's
proposed Schedule 74, Idaho Power's system could be placed in
jeopardy from a reliability standpoint?
MR. MILLER: Objection.
MR. J. WILLIAMS: I'll withdraw the question. No
more redirect.
COMMISSIONER SMITH: Thank you for your help,
Ms. Park.
THE WITNESS: Thank you.
(The witness left the stand.)
COMMISSIONER SMITH: Let's take a ten-minute
break.
(Recess.)
COMMISSIONER SMITH: So I think, Mr. Walker and
Mr. Williams, we are ready for your next witness.
MR. WALKER: Thank you, Madam Chair. Idaho Power
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calls Mr. Karl Bokenkamp as its next witness.
And, Madam Chair, as -- well, I'll let
Mr. Bokenkamp take the stand, but I do have a procedural matter
to address.
KARL BOKENKAMP,
produced as a witness at the instance of Idaho Power Company,
being first duly sworn, was examined and testified as follows:
MR. WALKER: Madam Chair, we do have, as we
admit -- as I go through the foundation with Mr. Bokenkamp,
there will be handed out some pages from his proposed exhibits
that were previously marked and continuing to be marked on
yellow pages as confidential, contain confidential information,
and before we pass those out, it's -- I apologize, but I'm
uncertain of -- as to every party's status of signing the
protective agreement.
MS. SASSER: I'll -- sorry. I can clarify. All
parties to the case have signed protective agreements on file
with the Commission.
COMMISSIONER SMITH: Well, I think our dilemma is
who's in the room, not who's a party, so --
So will the distribution of these yellow pages
include speaking the numbers aloud, or is it a concern that
only those who have signed the agreement and are covered by its
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MR. WALKER: It's more of the latter of who
actually has the pages. I don't think a -- you know, the pages
contain many numbers. I think, without the context of having
the page, a mention of a few of the numbers would not
necessarily violate any protective agreement or
confidentiality.
COMMISSIONER SMITH: All right. So, will those
of you in the room who have not signed the protective agreement
and are not bound by its provisions please designate by raising
your hand?
VARIOUS AUDIENCE MEMBERS: (Indicating.)
COMMISSIONER SMITH: So now you know who can't
have the yellow pages. Okay, so who is actually going to
distribute them?
So would you raise your hands one more time so
Mr. Williams can know not to give you a yellow sheet.
So, Mr. Williams, are you clear and --
MR. J. WILLIAMS: Yes.
COMMISSIONER SMITH: Thank you very much. We
appreciate that.
So you can start.
MR. WALKER: Thank you, Madam Chair.
I 712 I
HEDRICK COURT REPORTING BOKENKAMP (Di)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
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DIRECT EXAMINATION
BY MR. WALKER:
Q. Could you please state your name and spell your
last name for the record?
A. Karl Bokenkamp. Last name is spelled
B-O-K-E-N-K-A-M-p.
Q. And by whom are you employed and in what
capacity?
A. I'm employed by Idaho Power Company as their
director of operations strategy.
Q. And, Mr. Bokenkamp, did you cause to be filed
your written direct testimony, along with Exhibit 7, Exhibit 8,
in this matter?
A. Yes.
Q. And I guess the cat's out of the bag: You do
have some changes or corrections. Is that correct?
A. Yes, I do.
Q. And that's what's being presently handed out?
A. Yes.
Q. Mr. Bokenkamp, perhaps we can start. Did you --
did you previously file in relation to Idaho Power's Motion for
a Stay an Affidavit attesting to your testimony and also
providing some corrections to that testimony?
A. Yes, I did.
713
HEDRICK COURT REPORTING BOKENKAMP (Di)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
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Q. And do you have that there with you?
A. Ido.
Q. Could you turn to page 2 of your Affidavit and
just state for the record the textual changes that were made
with that Affidavit?
A. Certainly.
Q. On page 13, lines 24 and 25, deletion of the
words "an estimate of."
On page 14, line 1, "31 million" changed to "38
million."
Page 14, line 5, 11 $3" per megawatt hour changed
to three fifty -- "$3.50" per megawatt hour.
And on page 14, line 6, 11 $1.50" per megawatt hour
changed to "$2.10" per megawatt hour.
Q. And do you have any other changes or additions to
your -- to the written portion of your direct testimony?
A. No.
Q. And your Exhibit No. 7, do you have any changes
or corrections to your Exhibit No. 7?
A. Yes, I do. I have three replacement pages for
Exhibit No. 7: The first replacement page is page 2 of six,
the second replacement page is page 5 of six, and the third
replacement page for Exhibit 7 is page 6 of six.
Q. And are those -- are those what have just been
handed to you and what we've been passing out as your
714
HEDRICK COURT REPORTING BOKENKAMP (Di)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
• 1 1 correct -- or, your replacement page 2, page 5, and page 6,

2 Exhibit 7?

3 A. Yes, they are.

4 Q. And on page 2 -- excuse me. And, Mr. Bokenkamp,
5 page 5 and page 6 are what are produced on yellow paper as
6 confidential, containing confidential information?

7 A. Yes.

8 Q. And could you please -- could you briefly
9 describe for us the necessitated change on page 2? Is it
10 completely new numbers or what -- what's the need for

11 replacement?

12 A. Yes, there are a few different numbers. Simply
.
13 what happened was on the title of it, it has Thermal Resource

14 Data Used in 2011 IRP Analysis, and as we reviewed it, some of
15 the heat rates that were listed in the column under Full Load
16 Heat Rate were not the ones that were used in the IRP analysis

17 so I corrected that; and three of the nameplate -- of the

18 entries under Nameplate Rating didn't line up with the ones

19 used in the IRP analysis, so I corrected those.

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Q. And then so is it fair to say then that the need

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for replacement pages 5 and 6 simply reflect the roll-through

22 of those different numbers in the analysis?

23 A. That's correct also.

24 On page 2, I added a footnote, page 2 of six.
.
25 Q. And do you have any other changes or additions to
715
HEDRICK COURT REPORTING BOKENKAMP (Di)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
1 your exhibits, Mr. Bokenkamp?

2 A. Yes, I do, one additional exhibit, which is

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listed as Exhibit 16.
Q. And could you just briefly tell us what -- what
that exhibit depicts?

6 A. That exhibit depicts a comparison between the

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levelized QF contract pricing that was calculated in the --
8 the methodology that was presented to the Commission on

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December 15, 2011, the IRP methodology in that case, and then
10 the comparison to that is the new methodology that we are
11 proposing now, and the numbers there are consistent with the
12 assumptions and changes that were reflected in the numbers that
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13 were included on Stokes Exhibit 9.

14 Q. So this Exhibit No. 16 doesn't contain any new

15 information?

16 A. No, the numbers are the same.

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Q. And so the bars that are labeled "December 15,

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2011, IRP," are those -- those bars all have the same numbers

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from your Exhibit No. 8. Is that correct?

20 A. That's correct.

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Q. And then the bars on this chart that are labeled

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"Proposed," paren, "HIC," closed paren, those are the same

23 numbers from Mr. Stokes's Exhibit No. 9. Is that correct?

24 A. That's correct.
.
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Q. Do you have any other changes or additions to
716
HEDRICK COURT REPORTING BOKENKAMP (Di)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
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your testimony and exhibits?
A. No.
MR. WALKER: Madam Chair, I ask that the
testimony of Mr. Bokenkamp be spread upon the record, and his
exhibits admitted.
COMMISSIONER SMITH: So, first of all, did
everyone who should have a copy of the replacement pages of the
exhibit receive them? Looks like it.
Okay, without objection, we will spread the
prefiled testimony of Mr. Bokenkamp upon the record as if read,
and admit Exhibits 7, 8, and 16.
(The following prefiled direct testimony
of Mr. Bokenkamp is spread upon the record.)
717
HEDRICK COURT REPORTING BOKENKAMP (Di)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
• 1 Q. Please state your name and business address.
2 A. My name is Karl Bokenkamp and 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 the Director of Operations
7 Strategy.
8 Q. Please describe your educational background.
9 A. I received a Bachelor of Science Degree in
10 Mechanical Engineering from the University of Illinois at
11 Urbana-Champaign in 1980. In 1995, I earned a Master of
12 Engineering Degree in Mechanical Engineering from the • 13 University of Idaho and, in 2010, I received a Master of
14 Business Administration from Boise State University. I am
15 a registered Professional Engineer in the state of Arizona,
16 and I have attended the Stone & Webster Utility Management
17 Development Program and the University of Idaho's Utility
18 Executive Course.
19 Q. Please describe your work experience with
20 Idaho Power.
21 A. I was employed by Idaho Power in 1995 as the
22 Director, and then Manager, of Thermal Production. In this
23 position, I was responsible for managing Idaho Power's
24 Thermal Production Department. Primary responsibilities of
25 the department included oversight and control of Idaho
718 BOKENKANP, DI
Idaho Power Company
Power's ownership shares in its three jointly owned coal-
fired generation resources, Bridger, Boardman, and Valmy,
and their associated fuel supplies.
In 2001, I accepted a new position as the Manager of
Power Supply Planning and was later promoted to General
Manager of Power Supply Planning. In this position, I was
responsible for building and managing Power Supply's
Planning Department. This department's responsibilities
included operational planning, load forecasting, stream
flow forecasting, integrated resource planning,
cogeneration and small power producer contract management,
water management/river operations, and gas and coal
contract management.
In 2006, I was promoted to the position of General
Manager, Power Supply Operations and Planning. This
position added operational responsibilities, which included
asset optimization, wholesale electricity, and natural gas
transactions from real-time through multi-year deals as
well as real-time operations and scheduling.
In 2010, I became Idaho Power's Director of
Operations Strategy. In this position, I am responsible
for unifying Idaho Power's operational strategy, including
sustainability, investigating opportunities, trends and
technologies that may impact the utility business, and
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719 BOKENKAMP, DI 2
Idaho Power Company
• 1 positioning the Company for continued success in its
2 rapidly changing industry.
3 Q. What is the purpose of your testimony in this
4 proceeding?
5 A. I will present Idaho Power's proposal for
6 modifications to the existing Integrated Resource Plan-
7 ("IRP") based avoided cost pricing methodology. There are
8 two primary changes I am proposing; they are (1) a change
9 in the methodology used to determine the energy component
10 of avoided cost and (2) a change in the resource type used
11 to establish the capacity component of avoided cost.
12 CURRENT METHODOLOGIES • 13 Q. What avoided cost methodologies are currently
14 approved by the Idaho Public Utilities Commission
15 ("Commission") for determining avoided cost rates for
16 Qualifying Facility ("QF") contracts?
17 A. As discussed more fully in Company witness
18 Mark Stokes' testimony, the Commission has approved two
19 methodologies for establishing a utility's avoided cost and
20 setting rates for QF contracts entered into pursuant to
21 Public Utility Regulatory Policies Act of 1978 ("PURPA")
22 regulations. The two methodologies are the Surrogate
23 Avoided Resource ("SAR") methodology and the IRP
24 methodology.
25 Q. What is the SAR methodology?
720 BOKENKAMP, DI 3
Idaho Power Company
• 1 A. The SAR methodology is a methodology which
2 uses a surrogate or proxy resource to set published, or
3 standard, avoided cost rates. As currently implemented in
4 Idaho, the SAR methodology uses a natural gas-fired
5 combined cycle combustion turbine as the surrogate resource
6 for establishing rates for QF contracts. Published, or
7 standard, rates are required by Federal Energy Regulatory
8 Commission for projects up to 100 kilowatts ("kW").
9 Published rates in Idaho are available to wind and solar
10 QFs with a nameplate capacity up to 100 kW and all other
11 QFs with an output of up to 10 average megawatts ("aMW")
12 per month. All QF projects over 10 aMW and all wind and
13 solar QF projects over 100 kW must use the IRP-based
14 methodology, which provides a basis for developing a
15 negotiated rate.
16 Q. Does the Company have any recommendations
17 regarding the use of the SAR methodology?
18 A. Yes. Idaho Power proposes that the
19 Commission discontinue use of the SAR methodology for
20 establishing avoided cost rates, and instead proposes that
21 the Commission utilize the IRP-based methodology to
22 establish all QF avoided cost rates. The rationale for
23 this position is set forth in more detail in the testimony
24 of Company witness Stokes.
25 Q. What is the IRP methodology?
721
BOKENKAIYIP, DI 4
Idaho Power Company
• 1 A. The IRP methodology is the second of the two
2 methodologies the Commission has approved for establishing
3 a utility's avoided cost pursuant to PURPA. Generally, the
4 IRP-based methodology calculates the projected future cost
5 of Idaho Power's preferred resource portfolio without the
6 QF seeking contract pricing, and then again with the QF
7 seeking contract pricing added to the resource portfolio at
8 zero cost. The difference in cost between the two analyses
9 is divided by the projected QF generation to determine the
10 energy component of avoided cost. The capacity component
11 of avoided cost is determined based on the characteristics
12 of the QFs generation, and it is added to the energy
• 13 component. This methodology produces an estimate of the
14 utility's avoided cost, which is then used as the starting
15 point for negotiating QF contract pricing. Project-
16 specific characteristics are utilized in the pricing
17 analysis and a number of other factors can enter into
18 contract negotiations. Idaho Power's current approach for
19 implementing the IRP methodology was presented to the
20 parties of this case on December 15, 2011, in the
21 Commission's hearing room, and is explained in greater
22 detail in Company witness Stokes' testimony and Stokes'
23 Exhibit No. 3.
24
•25
722 BOKENKANP, DI 5
Idaho Power Company
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1 Q. Is it Idaho Power's position that the IRP
2 methodology is a better estimation of avoided cost than the
3 SAR methodology?
4 A. Yes. The IRP methodology as currently
5 implemented is a significant improvement over the SAR
6 methodology. It is a far more accurate approximation of
7 avoided cost than the more generic SAR methodology. As
8 currently implemented, the IRP methodology begins to take
9 into account some aspects of need, value, and timing of the
10 QF5 proposed generation when establishing the avoided cost
11 rates. One of the most important improvements of the IRP
12 methodology over the SAR methodology is that the IRP
13 methodology incorporates several of the resource-specific
14 characteristics of the proposed QF generation. These
15 include the QF's specific generation output profile, a
16 resource specific capacity factor, the timing of
17 anticipated generation, and a capacity credit based on the
18 anticipated amount of capacity provided during Idaho
19 Power's projected peak-load hours.
20 Q. Do you have any recommendations for changing
21 the current implementation of the IRP methodology?
22 A. Yes. While the IRP methodology as currently
23 implemented by Idaho Power is a significant improvement
24 over the SAR methodology, it still has a number of problems
25 that result in significant harm to Idaho Power's customers.
723 BOKENKI\MP, DI 6
Idaho Power Company
• 1 Q. Could you please provide us with some examples
2 of the problems that exist with the current implementation
3 of the IRP methodology?
4 A. Yes. Although the IRP methodology is a
5 significant improvement over the SAR methodology it does
6 have several flaws that disconnect it from the definition
7 of avoided cost as set forth in federal regulations, which
8 is what the IRP methodology is supposed to be
9 approximating. For example, as currently implemented by
10 Idaho Power:
11 1. The avoided cost produced by the
12 current IRP methodology relies too heavily upon forecasts • 13 of future market prices. Under the current approach,
14 customers take on a significant amount of a market price
15 risk that, but for the QF purchase, they normally would not
16 experience as a customer of Idaho Power.
17 2. The avoided cost produced by the IRP
18 methodology, is largely predicated on making surplus sales
19 at the future market prices developed within the AURORA
20 model. This deviates from the definition of avoided cost,
21 which is focused on the incremental cost to an electric
22 utility of displaced generation or purchases. Projected
23 revenue from surplus sales is never mentioned in the
24 federal regulation definition of avoided cost.
•25
724
BOKENKAMP, DI 7
Idaho Power Company
• 1 3. The present IRP methodology is somewhat
2 static with respect to changes in the resource portfolio.
3 What I mean by this is that the preferred resource
4 portfolio used in the IRP methodology is not updated
5 between IRP cycles. Consequently, the impacts of newly
6 signed QF contracts on Idaho Power's avoided cost are not
7 reflected in subsequent avoided cost calculations until the
8 preferred portfolio is updated in the next IRP cycle.
9 Q. You have mentioned the definition of avoided
10 costs several times, what are you referring to?
11 A. I am referring to the definition of avoided
12 cost found in federal regulations, 18 C.F.R. §
13 292.101(b) (6).
14 Q. How do the federal regulations define
15 avoided cost for purposes of PURPA QF5?
16 A. Federal regulation defines avoided cost as
17 follows:
18 Avoided costs means the incremental costs
19 to an electric utility of electric energy
20 or capacity or both which, but for the
21 purchase from the qualifying facility or
22 qualifying facilities, such utility would
23 generate itself or purchase from another
24 source.
25
26 18 C.F.R. § 292.101(b) (6).
27 Q. What is significant about this definition?
28 A. First of all, the concept of identifying
29 incremental costs the utility would incur, but for the QF
725 BOKENKAMP, DI 8
Idaho Power Company
• 1 purchase, is clearly significant. This concept is the key
2 to developing an avoided cost methodology that accurately
3 calculates avoided cost as contemplated by, and required
4 by, federal law. Another significant aspect of the
5 definition is the absence of any reference to sales in
6 determination of avoided costs.
7 Q. Do you have any other observations or
8 comments of significance about the definition of avoided
9 cost?
10 A. Yes. Keeping with the definition of avoided
11 cost, what Idaho Power is trying to determine is the
12 incremental costs to an electric utility which, but for the
• 13 purchase from the QF, such utility would generate itself or
14 purchase from another source. At a very basic level, this
15 definition implies that the utility needs to incur, or at
16 least expect to incur, a cost in order to have an avoided
17 cost. With this in mind, Idaho Power's proposed revision
18 to the IRP methodology focuses on identifying the
19 incremental costs that its system would incur, but for the
20 QF purchase, to generate power itself or to purchase power
21 from another source. This directly comports with the
22 definition of avoided cost from federal regulations.
23 Since incremental costs change, a proper application of the
24 Code of Federal Regulation's definition of avoided cost
25 results in (1) an hour-by-hour analysis of the period of
726 BOKENKAI'4P, DI 9
Idaho Power Company
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1 interest to determine the avoidable incremental cost during
2 each hour and then (2) a methodology to convert the hourly
3 incremental costs into avoided cost rates. Idaho Power's
4 proposed avoided cost methodology addresses both of these
5 items.
PROPOSED IRP METHODOLOGY MODIFICATIONS

7 Q. Please describe Idaho Power's proposed
8 modifications to the IRP based methodology.
9 A. Idaho Power's proposed modifications to the
10 IRP methodology are as follows:

11 1. A change in the methodology used to
12 determine the energy component of avoided cost. This
13 change is proposed in order to align the methodology with
14 the federal regulation's definition of avoided cost and
15 thereby establish an avoided cost of energy based on the
16 incremental costs the utility would incur, but for the
17 addition of the QF resource;

18 2. A change in the resource type used to
19 establish the capacity component of avoided cost. This
20 change is proposed to align the methodology with the actual
21 costs of capacity that are avoided; and

22 3. Implementation of a queuing process to
23 (1) establish a QF's position in line and (2) identify the
24 QF projects included in Idaho Power's resource portfolio
25 for determining avoided costs in subsequent requests for QF
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BOKENKAMP, DI 10
Idaho Power Company
• 1 contract pricing. Idaho Power's resource portfolio, for
2 purposes of calculating a future avoided cost, can change
3 whenever a QF project enters the queue if that QF is
4 considered as a part of the resource portfolio.
5 Accordingly, the avoided cost of energy and capacity can
6 change for each new QF as a result of the capacity and
7 energy provided by all projects in Idaho Power's portfolio,
8 including any QFs already in the queue. The fact that
9 avoided costs can change as new QF resources are added to
10 the portfolio must be taken into account if avoided cost is
11 to be determined properly.
12 AVOIDED COST OF ENERGY . 13 Q. Please describe in more detail the
14 particular changes you are proposing to the current
15 implementation of the IRP methodology.
16 A. As discussed in Company witness Stokes'
17 testimony, the IRP methodology includes a rate for both the
18 avoided cost of energy and the avoided cost of capacity.
19 In order to align with the required definition of avoided
20 costs, Idaho Power proposes that the avoided cost of energy
21 be based upon the incremental energy cost the utility would
22 incur, but for the QF output. In order to do this, Idaho
23 Power proposes to use the AURORA model to determine the
24 highest displaceable incremental cost being incurred during
25 each hour of the QF's proposed contract term. In Idaho
728 BOKENKAMP, DI 11
Idaho Power Company
• 1 Power's proposal, displaceable incremental costs are
2 limited to (1) incremental costs for Company-owned thermal
3 resources (Bridger, Boardman, Valmy, Langley Gulch, and the
4 gas-fired peakers) that are on-line and operating at above
5 their minimum load level, (2) the incremental cost
6 associated with longer-term firm purchases, and (3) the
7 incremental cost of market purchases as determined by
8 AURORA.
9 Q. Could you explain what you mean when you say
10 that displaceable incremental costs are limited to the
11 incremental costs for Company-owned thermal resources or
12 the incremental costs associated longer-term firm purchases . 13 or market purchases?
14 A. Yes. First, for a resource to be
15 "displaceable" it has to be on-line and capable of staying
16 on-line and further reducing its output. Second, the
17 displaceable incremental costs associated with any longer-
18 term firm purchases or market purchases are set at the
19 market clearing price as determined by the AURORA model on
20 an hour-to-hour basis.
21 Q. How are longer-term firm, non-PURPA, power
22 purchases treated in the model?
23 A. Longer-term firm purchases, such as the PPL
24 EnergyPlus Power Purchase Contract, will be included in
25 Idaho Power's resource portfolio in the AURORA model to
729 BOKENKAMP, DI 12
Idaho Power Company
• 1 determine the avoided cost of energy, and they will be
2 modeled as must run resources. However, during any hours
3 when purchases under these contracts are flowing, the
4 market clearing price determined in AURORA will be used to
5 establish the displaceable incremental cost associated with
6 that firm purchase. For example, if the firm purchase is
7 resold at market price and the QF generation is accepted,
8 then the incremental cost avoided is the net proceeds from
9 the resale of the firm purchase after any transaction-
10 related costs such as transmission costs, losses, etc.
11 However, to simplify the analysis, Idaho Power is proposing
12 to disregard the transaction-related costs and use the
13 AURORA market clearing price to set the displaceable
14 incremental cost for long-term firm, non-PURPA, power
15 purchases whenever they are flowing.
16 Q. You have mentioned that displaceable
17 incremental costs are limited to the incremental costs for
18 Company-owned thermal resources and the incremental costs
19 associated with longer-term firm purchases or market
20 purchases. What about Idaho Power's hydroelectric projects
21 - are their incremental costs considered in the methodology
22 Idaho Power is proposing?
23 A. No. The direct operating expense for Idaho
24 Power's hydroelectric resources during 2011, including an
25 estimate of depreciation (which was over $15 million), was
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BOKENKA['4P, DI 13
Idaho Power Company
• 1 approximately $31 million. Idaho Power's 2011
2 hydroelectric generation was approximately 11 million
3 megawatt-hours ("MWh"). This gives Idaho Power an
4 operating cost in 2011, including depreciation, of
5 approximately $3/MWh. Without considering depreciation,
6 hydro operating expenses are less than $1.50/MWh, and
7 variable costs are even less. Since Idaho Power typically
8 has one or more thermal units on-line, and since the
9 incremental cost of the thermal units always exceed the
10 variable cost of the hydro units, I have not considered the
11 incremental cost of Idaho Power's hydroelectric resources
12 in this methodology. If opportunity costs are included and • 13 shifting hydro generation from one time period to another
14 is considered, the analysis becomes more complicated. In a
15 practical sense, the incremental cost avoided in any given
16 hour, as a result of displacing a MWh of hydroelectric
17 generation during that hour, is very small. With this in
18 mind, the methodology I am proposing does not attempt to
19 incorporate the incremental cost of Idaho Power's
20 hydroelectric projects.
21 Q. Are there times when the incremental cost
22 calculated with Idaho Power's proposed methodology goes to
23 zero?
24 A. Yes, and this is not unrealistic.
25 Considering the minimum load levels established for the
731
BOKENKAMP, DI 14
Idaho Power Company
• 1 thermal generating resources, and the amount of non-
2 dispatchable QF generation on Idaho Power's system, there
3 may be hours during low load periods when Idaho Power's
4 avoidable incremental costs are zero. In fact, there could
5 be times when Idaho Power's avoided incremental costs would
6 be negative. For example, if loads are low and a thermal
7 unit is shutdown in order to accept additional QF
8 generation and then the output of the intermittent QF
9 generation drops off, additional costs could be incurred if
10 the previously shutdown thermal unit is unavailable to
11 replace the QF output. A more expensive unit may have to
12 be started or more expensive market purchases may be • 13 required. In either situation, additional costs are
14 incurred.
15 Q. Do you have an example?
16 A. Yes. As an example, out of a total of
17 157,776 hours in an AURORA simulation for a 22 megawatt
18 ("MW") wind project, the new methodology assigned an
19 avoided cost of $0/MWh in 1,563 hours. This works out to
20 about 1 percent of the time, or 87 hours per year.
21 Q. Would Idaho Power be able to sell the output
22 from the QF during that hour?
23 A. Maybe, but if the model has the Company's
24 available coal-fired units at their minimum loads and if
25 there are not transmission constraints limiting their
732 BOKENKAI'4P, DI 15
Idaho Power Company
• 1 output, then there likely is not a demand for energy at the
2 coal-fired units dispatch prices.
3 Q. Can you provide an example to demonstrate
4 your proposed change in the way the avoided cost of energy
5 is calculated?
6 A. Yes. Idaho Power can look at several
7 different hypothetical cases to illustrate how the
8 methodology will assign incremental costs. For example, in
9 case 1 load is 2,000 MW, the system is balanced, Idaho
10 Power has one or more thermal units in operation, and there
11 are no purchases; in case 2, identical conditions exist
12 with the following exception, a "new" QF generates and
13 delivers one MWh of energy to Idaho Power's system. One of
14 two things must happen for the system to remain balanced -
15 either Idaho Power's resources must reduce output by one
16 MWh or one MWh is sold into the market. If a sale is made,
17 there is no incremental cost to Idaho Power that is
18 avoided. However, if the output of Idaho Power's highest
19 cost on-line thermal resource can be reduced by one MWh,
20 then there is an incremental cost to Idaho Power that can
21 be avoided. If the incremental costs of that unit are
22 $17/MWh for fuel and $3/MWh for variable operations and
23 maintenance, then the avoided cost for that MWh of QF
24 energy is $20/MWh ($17/MWh + $3/MWh).
•25
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BOKENKAMP, DI 16
Idaho Power Company
• I If the on-line thermal resources are at their
2 established minimum load levels, thermal generation cannot
3 be further reduced without taking a unit off-line. In this
4 situation, if a QF produced an additional MWh and Idaho
5 Power took a thermal unit off-line to accommodate the QF
6 generation and then later had to restart the unit because
7 of reduced QF output or increased load, the additional MWh
8 of QF generation could have resulted in Idaho Power
9 actually incurring more costs than it would have without
10 receiving the QF generation. Under these circumstances,
11 the methodology assumes generation at one of the hydro
12 projects is reduced and water is spilled. In this case, • 13 the cost to Idaho Power if it had generated that MWh of
14 energy at one of its hydro projects is essentially zero and
15 the incremental cost avoided is set at $O/MWh for that
16 hour.
17 Assuming a different hypothetical situation, again
18 using two cases: in case 1, load is 3,000 MW, the system
19 is balanced, Idaho Power has one or more thermal units in
20 operation, and purchases are being made to serve load; in
21 case 2, identical conditions exist with the following
22 exception, a "new" QF generates and delivers one MWh of
23 energy to Idaho Power's system. For the system to remain
24 balanced in case 2, one of three things must happen - Idaho
25 Power's resources must reduce output by one MWh, market
734 BOKENKAMP, DI 17
Idaho Power Company
• 1 purchases must be reduced by one MWh, or one MWh must be
2 sold into the market. Like before, if a sale is made, no
3 incremental costs are avoided as a result of receipt of the
4 QF energy. However, if the output of one of Idaho Power's
5 thermal resources is reduced by one MWh, or if the amount
6 of market purchases are reduced by one MWh, then it is
7 possible to identify an incremental cost that the utility
8 would have incurred, but for the "new" QF purchase. In
9 this instance, the incremental cost avoided during that
10 hour is the greater of (1) the incremental cost of the most
11 expensive displaceable thermal resource on-line or (2) the
12 market clearing price during that hour. For example, if
13 the incremental cost of the most expensive thermal unit on-
14 line is $20/MWh (the same unit described earlier) and the
15 most expensive market purchases during the same hour is
16 $30/MWh, then the avoided cost for that MWh of energy is
17 $30/MWh. Alternatively, if the incremental cost of the
18 most expensive thermal unit on-line is $60/MWh (e.g., a
19 simple cycle combustion turbine ("SCCT") with 11,000
20 Btu/kWh heat rate, $5.00/MMBtu natural gas, and variable
21 operations and maintenance ("O&M") costs of $5/MWh) and the
22 cost of market purchases during the same hour is $30/MWh,
23 then the avoided cost for that MWh of energy is $60/MWh.
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735 BOKENKAMP, DI 18
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• 1 Q. Could you summarize how Idaho Power's
2 proposed modification to the calculation of the avoided
3 cost of energy works?
4 A. Yes. To calculate the energy component of
5 avoided cost, the incremental cost for each hour of the
6 proposed QF contract term is determined by analyzing the
7 results of the AURORA analysis as described above. The
8 result of that analysis is a time series of displaceable
9 incremental or avoided costs - one for each hour of the
10 proposed contract term. This time series of hourly avoided
11 costs is then multiplied by the QF's supplied hourly
12 generation profile; e.g., avoided cost in hour 1 x QF
13 forecast generation in hour 1, avoided cost in hour 2 x QF
14 forecast generation in hour 2, etc. These products are
15 then summed over heavy load and light load hours of each
16 month and divided by the corresponding forecast QF
17 generation. The result is a heavy load and light load
18 price for each month of the contract term.
19 Q. How is this any different than the way the
20 avoided cost of energy is currently calculated?
21 A. Under the current methodology, the power
22 supply costs of Idaho Power's resource portfolio are
23 determined by the AURORA model without inclusion of the
24 proposed QF. Then the AURORA model is run a second time
25 with no modifications to the dispatch of Idaho Power's
736 BOKENKAMP, DI 19
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• 1 resources (e.g., Bridger, Boardman, Valmy, Hells Canyon,
2 and all other resources produce the same hourly output they
3 did in the first AURORA simulation) and the proposed QF's
4 generation is added to the resource portfolio at zero cost.
5 Because the load and operation of Idaho Power's resources
6 are the same, the QF generation is used for one of two
7 things - it either displaces a market purchase or supplies
8 a market sale.
9 Under the new methodology, there is only one AURORA
10 model run which is used to determine the displaceable
11 incremental or avoided cost for each hour. These hourly
12 avoided costs and the QF's supplied hourly generation . 13 profile are then used to determine monthly heavy load and
14 light load pricing for the QF contract. Under this
15 methodology, the incremental costs that Idaho Power would
16 have incurred but for the QF generation is the basis for QF
17 contract pricing. In both the current implementation of
18 the IRP methodology and Idaho Power's proposed change to
19 that methodology, QF generation is used to displace
20 purchases. When purchases are displaced, the QF generation
21 is valued at the cost of the displaced purchase. However,
22 in the modified methodology, if the QF generation is not
23 used to displace a purchase (a cost that Idaho Power would
24 have incurred, but for the QF generation), it is used to
25 displace one of Idaho Power's thermal resources (another
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• 1 cost that Idaho Power would have incurred but for the QF
2 generation). Under the proposed methodology, the QF
3 generation is not used to make market sales at AURORA-
4 generated market clearing prices.
5 Q. Could you summarize the differences?
6 A. In summary, the main difference is that in
7 Idaho Power's current implementation of the IRP
8 methodology, the QF generation supports market sales which
9 generate revenues that reduce Idaho Power's calculated
10 power supply costs, essentially valuing the QF generation
11 at AURORA's estimate of future market prices with customers
12 taking all of the price risk. Under the proposed • 13 methodology, the QF generation does not support surplus
14 sales, it is simply valued at the highest displaceable
15 incremental cost Idaho Power is incurring during the hour.
16 Thus, the proposed change focuses on determining the
17 incremental costs that can be avoided by the addition of QF
18 generation, and better aligns with the definition of
19 avoided cost.
20 Under Idaho Power's current implementation of the
21 IRP methodology, the QF receives a guaranteed contract
22 price based on AURORA's estimation of future market prices.
23 This eliminates the QF's risks with respect to future power
24 market prices for the duration of the contract, and Idaho
25 Power's customers have taken on the risk that the value of
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the generation received from the QF will differ from the
QF's contract price. The Company's proposed change to
determine the incremental cost during each hour is a much
better estimation of the costs the utility is capable of
avoiding by taking the QF generation, and comports with the
federal requirements, without shifting all of the future
market risk of the QF transaction onto Idaho Power's
customers.
AVOIDED COST OF CAPACITY
Q. Please describe how the avoided cost of
capacity is determined.
A. The methodology for determining avoided cost
of capacity is the same as that used in Idaho Power's
current implementation of the IRP methodology as described
in Company witness Stokes' testimony.
Q. Does Idaho Power propose to use the same
inputs in the determination of the capacity component of
avoided cost?
A. No. Although the methodology for
determining the capacity component of avoided cost is the
same, Idaho Power proposes that the resource type used to
determine this component of avoided cost be changed from a
combined cycle combustion turbine ('CCCT") to a SCCT.
Idaho Power's need for capacity is driven by summertime
peak-hour loads, typically during the hours of 3:00 p.m. to
739 BOKENKA1'IP, DI 22
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• 1 7:00 p.m. in the month of July. Because a SCCT is
2 typically the lowest cost supply-side resource for this
3 type of service, the fixed cost of a SCCT is a much more
4 appropriate input to use for this purpose than those of a
5 CCCT. Just as the current methodology uses the fixed costs
6 of a CCCT taken directly from the Company's IRP analysis,
7 the Company proposes that the fixed costs of a large frame
8 industrial SCCT, taken directly from the Company's IRP
9 analysis be utilized for determining the capacity component
10 of avoided cost going forward.
11 As noted in Commission Staff comments on Idaho
12 Power's Application for Determination Regarding its Firm
. 13 Energy Sales Agreement with High Mesa Energy, LLC, Case No.
14 IPC-E-11-26, Staff compared the capacity factors for SCCT
15 and CCCT units included in the Company's 20-year resource
16 plan in its 2009 IRP. Staff reported that based on
17 modeling results from the IRP, the capacity factors of the
18 SCCTs ranged from 0 to 14 percent and the capacity factor
19 for Langley Gulch (a CCCT) ranged from 36 to 49 percent,
20 with a 20-year average of 49 percent. This illustrates the
21 fact that while the capital cost of a CCCT is higher, it
22 will dispatch more often because of its higher efficiency
23 (lower heat rate). The higher capital cost of a CCCT
24 "buys" improved efficiency, which results in lower dispatch
is 25 costs, and, subsequently, a higher annual capacity factor
740 BOKENKAMP, DI 23
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• 1 than a SCCT. In summary, a CCCT has higher fixed costs and
2 lower variable costs, and a SCCT has lower fixed costs and
3 higher variable costs.
4 Because the IRP methodology, as currently
5 implemented and as proposed by Idaho Power, includes both
6 capacity and energy components of avoided cost that are
7 determined independently, Idaho Power believes that it is
8 inappropriate to set the capacity component of avoided cost
9 with the capital cost of a CCCT when its need for capacity
10 can be served by a SCCT. As currently proposed, the energy
11 component of avoided cost will be the same regardless of
12 the resource type used to determine the capacity component
S 13 of avoided cost. If a CCCT is used to set the avoided cost
14 of capacity, customers will not receive the benefits
15 associated with a CCCT's higher efficiency.
16 Q. Are you proposing to continue to use the
17 peak-hour capacity factor calculation that is currently
18 utilized?
19 A. Yes. Idaho Power proposes no changes to
20 this approach, which is described by Company witness
21 Stokes.
22 AURORA INPUTS/ASSUMPTIONS
23 Q. Are there any other assumptions or modeling
24 details associated with the proposed changes to the IRP
25 methodology that should be discussed?
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• 1 A. Yes. Idaho Power's proposed change to the
2 IRP methodology focuses on determining the incremental
3 costs to an electric utility of electric energy which, but
4 for the purchase from the QF, such utility would generate
5 itself or purchase from another source. During many hours
6 of the year, Idaho Power's highest displaceable incremental
7 cost will be set by one of its thermal resources. And
8 because a thermal plant's heat rate changes with load, the
9 incremental costs also change with load. However, to
10 simplify the analysis, Idaho Power proposes use of the
11 following assumptions:
12 1. Each thermal unit is assigned one . 13 incremental cost, which will be based on full load
14 operation, which applies all year long regardless of the
15 loading level determined in the AURORA analysis;
16 2. The incremental cost for each thermal
17 unit is updated each year based on the fuel forecasts used
18 in the AURORA analysis; and
19 3. Once the highest displaceable
20 incremental cost is identified for a given hour, any amount
21 of displacement available from that resource (generator,
22 longer-term firm purchase or market purchase) sets the
23 incremental cost for that hour regardless of the volume
24 actually available to be displaceable; e.g., if there are
25 no purchases, and all thermal plants are either off or at
742 BOKENKAMP, DI 25
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• 1 their minimums except for one Bridger unit which is at 10
2 MW above minimum and its incremental cost is $17/MWh, then
3 the incremental cost for that hour is $17/MWh even if the
4 "new" QF that the analysis is being run for is expected to
5 produce 20 MW during that hour. This simplification may
6 introduce some error, but it will always be in favor of the
7 QF since Idaho Power begins with the highest incremental
8 cost resource that is displaceable to set the avoided cost
9 for any hour.
10 Q. Do you have an exhibit that illustrates these
11 concepts?
12 A. Yes, these concepts are illustrated in Exhibit • 13 No. 7. There are six pages to this Exhibit.
14 Q. Will you please explain the purpose of each of
15 the six pages in Exhibit No. 7?
16 A. Yes. Because the details of any avoided cost
17 model at this level of detail can be quite complex and
18 somewhat confusing, I have provided an example that
19 illustrates a number of the details. At a high level, the
20 first four pages of Exhibit No. 7 illustrate the type of
21 data that will either be input to or output from the AURORA
22 model. The last two pages of Exhibit No. 7 are the results
23 of calculations used to determine the hourly incremental
24 cost. This exhibit illustrates how a spreadsheet can be
25 used to calculate an hourly incremental cost.
743 BOKENKAMP, DI 26
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• 1 Page 1 of 6 illustrates the output from AURORA that
2 is used by Idaho Power's proposed methodology to determine
3 the hourly incremental cost. The hourly loading of each
4 coal-fired and gas-fired unit is required, the hourly
5 quantity of longer-term firm purchases and the AURORA-
6 determined quantity of market purchases as well as the
7 AURORA-determined market clearing price are also required.
8 This information is largely used to determine which
9 resource has room to be displaced.
10 Page 2 of 6 illustrates the thermal resource data
11 used to set Idaho Power's minimum load levels and the heat
12 rates used in the determination of each resource's annual . 13 incremental cost.
14 Page 3 of 6 illustrates fuel costs used in the
15 determination of each resource's annual incremental cost.
16 Page 4 of 6 illustrates the variable O&M costs used
17 in the determination of each resource's annual incremental
18 cost, and it identifies the escalation rate used to
19 escalate variable O&M costs.
20 Page 5 of 6 illustrates the results of calculations
21 to determine the annual incremental costs that are used in
22 each year to determine the hourly incremental cost. The
23 calculation is as follows: incremental cost = [heat rate
24 (MMBtu/MWh) x delivered fuel cost ($/MMBtu)] + variable O&M
25 cost ($/NWh) . The input data for heat rate is shown in
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• 1 Btu/kWh; the units are converted to MMBtu/MWh as follows:
2 MMBtu/MWh = (Btu/kWh) x (1 MMBtU/1,000,000 Btu) x (1,000
3 kWh/i MWh).
4 Page 6 of 6 illustrates the result of calculations
5 to determine the hourly incremental cost. First, the
6 thermal resources on-line with displaceable capacity are
7 identified by subtracting the hourly loading from the
8 minimum loading - this occurs under the area labeled
9 "Determine Displaceable Quantity (MW)." Next, under the
10 area labeled "Determine Highest Displaceable Incremental
11 Cost ($/MWh)" for each resource that has displaceable
12 capacity, the incremental cost of that resource as • 13 determined on page 5 of 6 is listed. If the displaceable
14 quantity is zero, then a zero is entered in this section.
15 For longer-term firm purchases and market purchases, if the
16 quantity of either is zero in an hour, then a zero is
17 entered; if either is non-zero in an hour, then the market
18 clearing price is entered. The hourly incremental cost is
19 determined by taking the maximum of the values listed under
20 the area labeled "Determine Highest Displaceable
21 Incremental Cost ($/MWh)."
22 QF QUEUING PROCESS
23 Q. Does Idaho Power have any other proposed
24 changes to the current implementation of the IRP
25 methodology?
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• 1 A. Yes. Idaho Power proposes that any QF5 with
2 signed contracts and any "queued" QFs be included in Idaho
3 Power's resource portfolio for purposes of calculating
4 future avoided costs because they can impact future avoided
5 costs. For purposes of calculating avoided costs, Idaho
6 Power proposes that upon its receipt of a written request
7 from a QF for contract pricing, the QF is designated as
8 "queued."
9 As stated earlier, Idaho Power's resource portfolio,
10 for purposes of calculating a future avoided cost, can
11 change whenever a QF project enters the queue if that QF is
12 considered part of the resource portfolio. If "queued" QFs • 13 and QFs with signed contracts are considered to be part of
14 the resource portfolio, then the calculated avoided cost of
15 energy and capacity can change for each new QF as a result
16 of the total amount of capacity and energy provided by all
17 projects in Idaho Power's portfolio. These changes are not
18 currently reflected in the avoided cost determination from
19 the current methodologies - be it the SAR or the present
20 implementation of the IRP-based methodology - which does
21 not change with the incremental addition of more QF
22 generation. Federal regulations allow for the individual
23 and aggregate value of energy and capacity from QFs on the
24 utility's system to be taken into account when determining
25 avoided cost rates for purchases from QFs. 18 C.F.R. §
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• 1 292.304. This must be taken into account if avoided cost
2 is to be determined properly.
3 Q. Could you please explain?
4 A. Idaho Power's resource portfolio, for
5 purposes of calculating its future avoided cost, can change
6 whenever a new QF project enters the queue if that QF is
7 considered to be part of the resource portfolio. For
8 example, if all QFs with contracts are on-line, and there
9 are no QFs in the queue, an analysis to determine the time
10 series of Idaho Power's avoided costs for use in pricing a
11 QF contract will produce a certain result. However, if
.12 there are five 20 MW QFs in the queue and they are likely • 13 to be built with the next few years, then Idaho Power is
14 proposing they be included in subsequent analyses to
15 determine Idaho Power's avoided costs for use in QF
16 contract pricing because they could have a direct impact on
17 calculations of Idaho Power's future avoided costs.
18 Q. What is the significance of including all QF
19 projects, in the aggregate, into the avoided cost
20 calculation?
21 A. The significance is that Idaho Power's avoided
22 costs change over time. As new resources, QF contracts, or
23 longer-term firm purchases are added to the resource
24 portfolio, Idaho Power's avoided cost can change. The
25 methodology used to calculate avoided costs needs to
747 BOKENKAMP, DI 30
Idaho Power Company
• 1 consider changes in the resource portfolio and the
2 resulting impacts on avoided cost. If changes to the
3 resource portfolio were limited to small changes, then
4 impacts would be minimal. However, Idaho Power has seen
5 large scale increases in the quantity of QF generation
6 under contract in a very short period of time. Significant
7 additions to Idaho Power's resource portfolio, such as the
8 very large amount of QF generation that has been added to
9 Idaho Power's system recently, can change Idaho Power's
10 avoided costs, and the methodology to determine avoided
11 cost must consider these changes.
12 Q. Do you have an exhibit that illustrates the • 13 difference in QF contract rates developed using Idaho
14 Power's current implementation of the IRP methodology and
15 the methodology Idaho Power is proposing?
16 A. Yes. Exhibit No. 8 provides an indication of
17 these differences for several different QF projects - a 20
18 MW baseload project, a 20 MW canal drop project, a 20 MW
19 fixed PV solar project, and a 22 MW wind project. These
20 are the same four projects that Idaho Power used to
21 illustrate its current approach for implementing the IRP
22 methodology, which was presented to the parties of this
23 case on December 15, 2011, in the Commission's hearing
24 room. A copy of that presentation is attached to Company
25 witness Stokes' testimony.
748 BOKENKAMP, DI 31
Idaho Power Company
• 1 The proposed modifications to the IRP-based
2 methodology produce a lower avoided cost of energy for each
3 project. This is expected because the proposed
4 modifications (which are based on identifying the
5 incremental costs to the utility for energy or capacity
6 which, but for the QF purchase, the utility would generate
7 itself or purchase) produce an avoided cost that is based
8 on the incremental cost avoided by displacing one of Idaho
9 Power's thermal generating resources, or avoiding a market
10 purchase. This is in contrast to the current
11 implementation of the IRP methodology which uses the QF
12 output to support market sales or displace purchases which • 13 results in a market-based valuation as opposed to a
14 valuation based upon the definition of avoided cost.
15 The proposed modification to the type of resource
16 used in the avoided cost of capacity calculation results in
17 an avoided cost of capacity that is about 55 percent of
18 that produced by using a CCCT. This is also expected
19 because the capital costs of a SCCT are quite a bit less
20 than the capital costs of a CCCT. The total investment
21 costs for a SCOT and CCCT as identified in Idaho Power's
22 2011 IRP are $790/Kw and $1,380/kW, respectively. Because
23 Idaho Power's capacity needs are driven by summertime peak-
24 load hours, and because a SCCT is an appropriate resource
•25
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Idaho Power Company
• 1 for this service, it reasonable to base the avoided cost of
2 capacity on a SCCT.
3 Q. Do you have any concluding remarks?
4 A. Yes. Idaho Power respectfully requests that
5 the Commission adopt the recommended changes to the IRP
6 methodology as set forth above. These changes align the
7 methodology to the definition of avoided cost from federal
8 regulations, and they help ensure that customers remain
9 indifferent as to whether the utility purchases energy from
10 a QF, or whether it generates the energy itself, or
11 purchases it from another source.
12 Q. Does this conclude your testimony? • A. Yes.
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(The following proceedings were had in
open hearing.)
(Idaho Power Company Exhibit Nos. 7 and 8,
having been premarked for identification, were admitted into
evidence.)
(Idaho Power Company Exhibit No. 16 was
marked for identification and admitted into evidence.)
MR. WALKER: Thank you, Madam Chair.
Mr. Bokenkamp is available for cross-examination.
COMMISSIONER SMITH: Thank you.
Do you have any questions, Mr. Andrea?
MR. ANDREA: No questions, Madam Chair.
COMMISSIONER SMITH: Mr. Solander.
MR. SOLANDER: No questions.
COMMISSIONER SMITH: Mr. Otto.
MR. OTTO: I have no questions.
COMMISSIONER SMITH: Ms. Nelson.
MS. NELSON: No questions, Madam Chair.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: No questions, Madam Chair.
COMMISSIONER SMITH: Mr. Miller? Mr. Uda?
Williams?
MR. R. WILLIAMS: Yes, I have a few questions.
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CROSS-EXAMINATION
BY MR. R. WILLIAMS:

Q. Good morning, Mr. Bokenkamp.

A. Good morning.

Q. I have a couple of questions that relate to your
testimony as QF contracts get put into your queue, and your
reference to your testimony can be found on page 29 of your
direct testimony. I'll just paraphrase. It says: Upon
receipt of a written request from a QF for contract pricing,
the OF is designated as queued.
And what that means, to me at least, is that that
request goes into the IRP model for calculating avoided costs
at that point. Do I understand that?

A. Yeah. Referring to that direct part of my
testimony, it says: If queued, QFs -- if queued QFs and QFs
with signed contracts are considered to be part of the resource
portfolio, then the calculated avoided cost of energy and
capacity can change.
So, yes, that is the intent is that a queued QF
would be included in the resource portfolio for a calculation
of subsequent avoided cost rates.

Q. Okay. So is it also then included in the
integrated resource plan for planning purposes?

A. I haven't proposed that in my testimony.
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Q. Okay. Should it be?
A. I think the position the Company has taken on
that is that it would not be included in the portfolio for
assessment of the -- of the integrated resource plan for
planning until it had a signed contract.
Q. So for purposes of calculating avoided cost
you're going to assume that that project is going to exist, but
for purposes of resource planning you're going to assume that
it is not going to exist. Is that the distinction?
A. Yes, until it had a signed contract.
Q. Okay. So in the IRP process, you assume that
there will be carbon costs. Correct? That is in the
integrated resource plan?
A. That is correct. We run some analysis with
carbon costs.
Q. And what is -- in the 2011 IRP, what was the
dollar result of assuming -- your assumption as to what carbon
would be costing the Company at some point in the future?
A. I don't recall.
Q. So I want you to -- I'm going to give you a
hypothetical that I am a large industrial customer that is
looking where to locate my industrial facilities and Idaho is
one of those locations, and one of the factors that's going to
help me decide whether to come or not is I want to cogenerate
electricity. So I file a request with Idaho Power to
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1 cogenerate and ask you to purchase let's assume it's 150
megawatts of cogenerated electricity. Does that 150 megawatts
3 influence my avoided cost price or does it only influence the
4 next -- everybody in the queue down below me?

5 A. As the methodology has been presented --

6
Just, if I may, just to make sure I understand
7 your question, you are the QF that's bringing the 150 megawatt

8 project?

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Q. Yes, I'm QF. I just sent you a request for a QF
10 contract pricing, and you are going to put me in your queue.
11 Does my request influence my price or is it everyone after
12 me?

13 A. As proposed, as the methodology is proposed now,

14 it would be those after you.

15
Q. Okay. So let's assume that I locate my
16 industrial plant somewhere other than Idaho and I don't give

17 you the courtesy of saying, "I'm not here," and I don't

18 withdraw my request, but, in fact, I'm not coming. Isn't at
19 that point the avoided cost rate for everyone behind me in the
20 queue, by definition, below the actual avoided cost that they
21 hope to get?

22 A. You know that's -- the actual avoided costs of
23 the Company are really hard to determine, so that estimate of
24 avoided cost that would be calculated under that would be
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25 lower, potentially, than if you were not in the queue.
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Q. Well at 550 megawatts, it, in fact, would be
lower, or does 150 megawatts of QF have no impact on avoided
cost?
A. No. No, I wouldn't necessarily say that.
Q. Probably would?
A. I would suggest that it probably would have an
impact.
Q. Okay. So let's say that I am the next developer
that comes in for 10 megawatts and in the queue is a fictitious
150 megawatts that is depressing my avoided cost price. Isn't,
by definition of federal law, that creating a lower than
avoided cost for everybody down the stream of me?
A. I'm not certain as to what the federal law -- how
that would be addressed there. I would comment that in my
perspective any avoided cost methodology is an estimate, so the
avoided cost can be different.
Q. So if we get the estimate wrong, it's okay?
A. Well, in fact, I believe there's something in the
FERC regulations that says if the cost turns up different than
what it was when the contract was calculated, that is okay.
MR. R. WILLIAMS: Madam, I have no further
questions.
MR. ARKOOSH: I just have one question based on
the last answer, Madam Chairman.
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CROSS-EXAMINATION
BY MR. ARKOOSH:
Q. But it's not okay to -- the cost can be -- actual
cost can be different than the estimate, but there's nothing in
the FERC regulations that say that you can make those estimates
based upon known incorrect information, is there?
A. I don't know of anything in the regulations that
states that.
Q. Okay.
MR. ARKOOSH: Thank you, Madam Chair.
COMMISSIONER SMITH: Thank you.
Ms. Sasser, do you have any questions?
MS. SASSER: I do, Madam Chair. Thank you.
CROSS-EXAMINATION
BY MS. SASSER:
Q. Good morning, Mr. Bokenkamp.
A. Good morning.
Q. Along the lines of what my colleagues in the back
were talking about regarding counting projects in the queue, is
it your understanding that all QFs that enter the queue, all of
the projects come to fruition?
A. No.
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Q. So wouldn't a more reasonable approach be to
consider contracted, signed contracts and QF5 who have signed
contracts, as opposed to QFs that enter the queue?
A. I don't know that it would be more reasonable.
But the point that I was trying to get at by
virtue of including a queued resource in there is the fact that
if we experience a large number of resources that come into the
queue that are seeking contracts and then we have more that
keep seeking contracts, the point is that as resources are
added to our portfolio, it would be my opinion that our avoided
cost changes or could change as a result of the addition of
those resources. And so in the event that a bunch of those
queued resources are developed and not included in rates for
subsequent resources, we may not be providing as good of an
estimate as we could.
Q. Okay. And then I just have a couple of questions
for clarification on the new exhibit that was handed out,
Exhibit No. 16:
At the bottom, there's a notation "Wind and solar
avoided cost of energy includes a $6.50 integration deduction."
Is it your understanding currently that we have a $6.50
integration deduction for solar facilities here in Idaho?
A. I don't think we do for solar, but I'm not
positive on that.
Q. Is the statement then representative of what
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P. 0. BOX 578, BOISE, ID 83701 Idaho Power
1 actually shows in the numbers, or are you not sure?
2 A. The numbers, the energy cost had been reduced by
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6.50, so the energy component of those had been reduced by

4 6.50, that's my understanding.

5
Q. Including on the solar?

6 A. Yes.

7
Q. Okay. Would -- is it fair to represent to you

8
that, to my knowledge, solar in Idaho does not have an
9 integration charge currently?

10 A. Yes.

11
Q. So those rates for solar would be bumped by

12 $6.50?
E1 13 A. If we pulled the integration charge that was

14 applied to it in this exhibit out, yes.

15
Q. Okay. One last question: On page 24 of your
16 direct testimony, in speaking to the IRP methodology and
oirm whether to use combined cycle or simple cycle combustion

18
turbines in the calculation, on line -- beginning at line 13,
19 you state that if a combined cycle combustion turbine is used

20 to set the avoided cost of capacity, customers will not receive

21 the benefits associated with a combined cycle's higher

22 efficiency. Can you explain what you mean by that?

23 A. Yes. Simple cycle is typically a less expensive

24 resource and has a higher heat rate. So it's less efficient,
.

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HEDRICK COURT REPORTING BOKENKAMP (X)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
1 cost. A combined cycle combustion turbine has a higher capital
2 cost, better efficiency, and so, essentially, it would have a
3 lower variable cost of operation. So there's a trade-off
4 between capital cost and variable cost.
5 Typically, if you were going to run a resource
6 more or anticipate at a higher capacity factor, the appropriate
7 resource choice would be a combined cycle, whereas if it was
8 for a more intermittent peaking type of duty, shorter duration
9 capacity factor as a simple cycle with a combustion turbine
10 would be the better choice.
11 MS. SASSER: Okay, thank you. That's all I have,
12 Madam Chair.
13 COMMISSIONER SMITH: Questions from the
14 Commissioners.
15. COMMISSIONER REDFORD: No.
16
17 EXAMINATION
18
19. BY COMMISSIONER SMITH:
20
Q. I just have one, following on the questions that
21 were asked about the queuing. Well, I turned my page, so I
22 don't even know where it was.
23 So you have acknowledged that not every project
24 that comes to you and says, I think I want to contract, give me
.

25 a sample --
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Which by your methodology puts them in the queue.l
Is that correct?
A. Yes.
Q. Not all of them are going to come back later and
say, Let's sign a contract. Is that correct?
A. That's correct.
Q. But once they have requested and gotten in the
queue, what does it take for them to get out of the queue?
A. I think what it would take for them to get out of
the queue would be some sort of formal notification that they
weren't in or perhaps an assessment on our part that the
project just wasn't happening, so it would be something that we
would have to manage to remove projects from the queue as they
appeared to drop off the radar screen.
Q. So what would be your process for managing that
queue?
A. We don't have a process fully outlined right now,
or I didn't reference one in my testimony.
Q. So you don't have in mind waiting a certain
period of time and checking back with them, or -- I mean, I
don't know what your process would be.
A. Well, I haven't addressed it in detail in my
testimony, I left that open. And really it's more conceptual
in my mind that they be added to the queue because they could
happen and they could have an adverse effect on customers,
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especially if we had a large number of resources that came in
in a short period of time, which we have experienced. So I'm
confident we would come up with a reasonable process to assess
that, and it could involve a period of time, it could involve
an inquiry on our part as to a formal inquiry to say, Are you
still pursuing your project or not?
Q. Thank you. That's all I have.
COMMISSIONER SMITH: Mr. Walker, do you have any
redirect?
MR. WALKER: No, Madam Chair.
COMMISSIONER SMITH: Thank you for your help.
MR. WALKER: May Mr. Bokenkamp be excused?
COMMISSIONER SMITH: If there's no objection, we
will excuse Mr. Bokenkamp from the remainder of the
proceedings.
(The witness left the stand.)
COMMISSIONER SMITH: All right, I take it that
concludes your witnesses.
MR. WALKER: That is the end of our witnesses,
Madam Chair.
COMMISSIONER SMITH: All right. We have a
request that Mr. Looper be done today. Is he ready to do it
now?
MR. R. WILLIAMS: Madam Chair, if we could just
have a couple-minute break and then he's here, ready to go.
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COMMISSIONER SMITH: You may have five minutes.
(Recess.)
COMMISSIONER SMITH: I think we're ready. If you
could take your seats, I'd appreciate it.
Mr. Williams.
MR. R. WILLIAMS: Thank you.
ROBERT LOOPER,
produced as a witness at the instance of Dynamis Energy, LLC,
being first duly sworn, was examined and testified as follows:
DIRECT EXAMINATION
BY MR. R. WILLIAMS:
Q. Mr. Looper, could you state your name and
business address for the purposes of the record?
A. Name is Robert Looper. Last name is L-O-O-P-E-R.
Business address is 1015 West Hayes, Boise, Idaho, 83702.
Q. And are you the same Mr. Looper that caused to be
filed direct testimony on behalf of Dynamis Energy consisting
of nine pages, along with Exhibit 1001?
A. lam.
Q. And if I were to ask you today the same questions
contained in this testimony, would your answers today be the
same?
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A. They would.
MR. R. WILLIAMS: Now, Madam Chair, I would ask
your permission to engage in a couple of questions of
surrebuttal that have come about with respect to the
cross-examination of Ms. Park.
COMMISSIONER SMITH: Well, we will certainly try
it. And Ms. Park has not been excused, so I think if she needs
to be recalled, the Company has that option.
MR. R. WILLIAMS: Thank you very much.
Q. BY MR. R. WILLIAMS: Mr. Looper, you had the
opportunity to listen to Ms. Park's testimony yesterday and
today, did you not?
A. I did.
Q. And review her rebuttal testimony?
A. I did.
Q. And on page of her rebuttal testimony, she
testifies that -- this is page 4, line 18 -- that Dynamis has
an incentive to make as many deliveries to Idaho Power and make
as much money as it can, regardless of Idaho Power's need for
the generation or the cost of other available resources on its
system. Do you agree or disagree with that statement?
A. I disagree with that statement.
Q. And why?
A. Well, I think even her own testimony and she read
the effects of delivering in light load hours and delivering in
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heavy load hours beyond whatever is scheduled in the contract.
In fact, if we intend and do deliver in light load hours,
there's a severe penalty; and if we deliver in heavy load hours
outside of 10 percent of the capacity, there's a penalty. So
there's absolutely no incentive in the contract for us to
deliver anything other than what is scheduled during heavy
load, and of course not doing any delivery in light load hours.
That was the intent of the contract.
Q. And the requirement that you not deliver during
light load hours, did that have any influence in the AURORA
modeling of the price for the delivery during heavy load
hours?
A. It did. In fact, the AURORA model is very
effective at looking at light load hours and determining
increased value to power purchase rates from actually not
scheduling and delivering those light load hours. So if one
were to put two schedules in front of us from AURORA, one in
which a contract had no curtailment and one in which a contract
had effectively, like the Dynamis contract, no delivery within
the light load hours, you would, in fact, see a higher rate
being paid to the generator for the contract in which he agreed
not to deliver during light load hours. So, I mean, we've been
talking about this, you know, around.
The issue, of course, goes ultimately to Schedule
74 and the random curtailment that we've discussed here and
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what the effective yield with that would be. If that had been
modeled in AURORA, in fact, you would have a higher rate
effectively being paid to the generator for that curtailment.
Q. Now, did you also listen to Ms. Park's testimony
with respect to curtailment in Dynamis and how, in her opinion,
that could be justified as a force majeure event?
A. I did.
Q. Okay.
MR. R. WILLIAMS: And may I approach the witness?
COMMISSIONER SMITH: You may.
MR. R. WILLIAMS: What's being handed out is the
force majeure provision from the Dynamis contract.
Q. BY MR. R. WILLIAMS: And are you familiar with
this provision?
A. lam.
Q. And are you familiar with the provisions in
Schedule 74 that allow interruption?
A. lam.
Q. And do you agree or disagree with Ms. Park's
characterization that Schedule 74 fits within the definition of
force majeure in the Dynamis contract?
A. I disagree with that.
Q. And why?
A. It's firmly stated in the contract under Force
Majeure that no regulatory events that occur after the signing
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HEDRICK COURT REPORTING LOOPER (Di)
P. 0. BOX 578, BOISE, ID 83701 Dynami S

1 of the contract can constitute a change in the pricing, and so

2
there's no means in the force majeure for interpretation of --

3
that Schedule 74 could be a force majeure event.

4
And more importantly to my interpretation will be
5 the interpretation of the lender and the person overseeing the
6 project from a financing perspective and looking at what the
7 effect of Schedule 74 would be under the current force majeure

8
in the contract. The effect would be suffocating from a

9
financing standpoint. You would be asked, in fact, to put
10 together some sort of working capital, additional capital
11 against your loan and debt, to cover the events that could come
12 from such an undefined force majeure without compensation on
.
13 Schedule 74.

14 Q. And

15 A. So I disagree.

16
Q. So, Mr. Looper, I'd have to stop you there

17 because I just made a major mistake.

18 MR. R. WILLIAMS: I handed out the wrong exhibit,
19 and for some reason I mixed up my exhibits and I did not get

20
here with the force majeure provision, and so I apologize to
21 the Commission that this is not this is not the exhibit that

22 contains the force majeure. I have that marked as 1003.

23 So I can -- we can take official notice of the

24 Dynamis contract that is on the -- can't do that? Okay. Well,
[I1
25 let's just move on then.
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HEDRICK COURT REPORTING LOOPER (Di)
P. 0. BOX 578, BOISE, ID 83701 Dynami 5
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Q. BY MR. R. WILLIAMS: Yesterday, you heard
2 Ms. Park testify with respect to thermal operations.

3
COMMISSIONER SMITH: So just a moment. So will

4
it be your intent maybe right after lunch to have the correct
5 exhibit so that we can mark it and have some reference in the
6 record for the testimony that just occurred?

7
MR. R. WILLIAMS: Madam Chair, thank you for that

8
life saver. I will have that, this exhibit, right after lunch.

9
It can be marked as Exhibit 1003. And I think Mr. Looper's
10 testimony as to what that language says will show up on that

11 exhibit.

12
COMMISSIONER SMITH: And what happened to 1002?
.
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MR. R. WILLIAMS: I thought Exhibit -- Exhibit

14
1002 is what I just handed out, and it was introduced yesterday

15
in cross-examination of Ms. Park.

16
COMMISSIONER SMITH: So we have a 1002 and I

17 failed to mark it down?

18 MR. R. WILLIAMS: Yes. So the force majeure
19 provision for the Dynamis contract will be 1003, and I

20 apologize again.

21
COMMISSIONER SMITH: All right. Thank you.

22 Q. BY MR. R. WILLIAMS: Mr. Looper, yesterday --

23 COMMISSIONER SMITH: So --

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MR. R. WILLIAMS: Oh, I'm sorry.
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COMMISSIONER SMITH: So give Wendy a minute. So
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did we get that straight?
THE COURT REPORTER: Yes.
COMMISSIONER SMITH: All right.
MR. R. WILLIAMS: Fine. Thank you.
Q. BY MR. R. WILLIAMS: Yesterday, you heard
Ms. Park testify regarding the operation of the Company's gas
fire units centered around Langley Gulch, but also included
Bennett Mountain and Evander Andrews. Correct?
A. Correct.
Q. And do you have any experience in building or
operating a gas-fired power plant?
A. Ido.
Q. Could you briefly --
MR. WALKER: Madam Chair, I object to this. This
is highly improper. Mr. Williams and Mr. Looper had their
opportunity to submit prefiled testimony and rebuttal just like
everyone else in this proceeding, and to now go into matters
in-depth that maybe they feel they should have done more
properly in their written I don't think is proper nor fair to
all the other parties, and we're getting somewhat afield of the
scope of Ms. Park's testimony and expertise. Neither Ms. Park
or Mr. Looper are attorneys to be interpreting force majeure
clauses. And the particular operation or Mr. Looper's
expertise with Bennett Mountain or some other plant is
tangentially relevant to the limited issues of their testimony
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HEDRICK COURT REPORTING LOOPER (Di)
P. 0. BOX 578, BOISE, ID 83701 Dynamis
• 1 1 in the first place. And I think this is improper and object to

2 it continuing.

3 COMMISSIONER SMITH: Mr. Williams.

4 MR. R. WILLIAMS: Madam Chair, yesterday Ms. Park
5 testified that she did not know the ramp rates of any of the
6 thermal plants. That, in fact, is a very important factor, as
7 it relates to the ability to integrate and respond to changes

8 in wind. And if she had been able to answer those questions,
9 Mr. Looper wouldn't have to testify to this, but she said
10 specifically she did not know that and she did not know how
11 much wind Langley Gulch could integrate. So it's just simply
12 responding to a very critical part of the case in her testimony
.
13 yesterday and this morning.

14 COMMISSIONER SMITH: Mr. Walker.

15 MR. WALKER: I continue my objection on the
16 relevance of that. Mr. Williams and his client had every
17 opportunity to ask discovery and to find out ramp rates of the

18 appropriate people at Idaho Power, and I take exception to
his -- I don't think he's shown how this is critical to the
20 limited issue present- -- issues presented by Dynamis and their
21 contract and their effects. And I maintain my objection and

22 don't think this is a proper procedure, nor area of

23 exploration, by Mr. Williams.
COMMISSIONER SMITH: Your continuing objection is
.

25 noted, Mr. Walker.
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HEDRICK COURT REPORTING LOOPER (Di)
P. 0. BOX 578, BOISE, ID 83701 Dynamis
Mr. Williams, please proceed.
Q. BY MR. R. WILLIAMS: Mr. Looper, why don't we,
unless there's objection to it, why don't we skip the questions
of your qualifications and go directly to the harder question.
A. Yeah. When a combustion turbine is online, much
like Bennett Mountain and/or the combustion turbine at Langley
Gulch, you're at about 25 megawatts per minute of ramping
capability within the limits and the air emission limits and
the unit limits between P min and P max of that unit, which is
normally defined by temperature.
So, the two key things that we need to note here
is that Idaho Power, which does a very good job of balancing
the load as we see, has something between 140, 170 megawatts at
Langley Gulch in simple cycle mode, and another 440 in CTs
between Bennett Mountain and Evander Andrews, the Danskin
Projects. So when those projects are online, they have a
significant ramping capability on a real-time basis.
The issue here that was addressed was, you know,
the challenge of integrating wind on a day-ahead and hourly
basis and intrahourly basis, and we get down to what happens oni
a ten-minute basis and within ten minutes. And it's important
have the capability to integrate hundreds and hundreds of
megawatts of wind on the order of Langley Gulch, two to three
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times the capacity of the Langley Gulch.
So, when we discuss and no one answers the
question about how wind can be integrated, there's some
system-wide studies we can look at: The brand new WECC study
that was done using PLEXOS that looked at wind integration
across the West that talked about how much combustion turbine
capacity would be required to integrate the amount of renewable
coming online. We can talk about the California ISO study with
25,000 megawatts of renewable calling for 5,000 megawatts of
combustion turbines coming online to balance and integrate
wind. There's lots of things we can point to.
Idaho Power's system is unique. It has some
hydro, they have their own unique limitations and
characteristics. But they have a significant capacity to
integrate and balance wind with the combustion turbines.
MR. WALKER: Madam Chair, I move to strike
Mr. Looper's monologue as unresponsive to the question and
irrelevant to his testimony on behalf of a nonwind QF.
COMMISSIONER SMITH: Mr. Williams.
MR. R. WILLIAMS: The answer was directly
responsive to the question. And more importantly, it answered
the questions that Ms. Park either couldn't or wouldn't answer
yesterday.
COMMISSIONER SMITH: Well, I would note that I
think the Company has the opportunity for rebuttal if it so
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HEDRICK COURT REPORTING LOOPER (Di)
P. 0. BOX 578, BOISE, ID 83701 Dynamis
• 1 desires because this is definitely new stuff, but I'm not going

2 to strike it.

3
Q. BY MR. R. WILLIAMS: And just one last question,

4 Mr. Looper --

5 MR. ANDREA: Excuse me, Mr. Williams, but if I
6 could interrupt for just a moment. 1 apologize.

7 I am happy to indulge the Commission has made a

8 ruling, but I just want to note for the record that Avista also
9 objects on the grounds that this is improper surrebuttal and

10
I'm just concerned about it setting a precedent for the

11 Intervenors following. We do not have the same opportunity

12 with our witnesses to provide surrebuttal, so --
.
13 COMMISSIONER SMITH: So noted.

14 Q. BY MR. R. WILLIAMS: And the last question,

15 Mr. Looper, is that Ms. Park testified that -- and it was
16 discussed this morning -- that Schedule 74 curtailments could
17 approximate about five percent of the time period, but that

18 that could be escalating if additional revenues are -- excuse
19 me -- if additional intermittent resources are brought on. Do
20 you have a response to what five percent of revenue, it would
21 mean to a developer?

22 A. It would be crushing to a developer. A five
23 percent revenue obviously has a multiple impact on your bottom

24 line because of debt coverage ratios from financing your
.

25 project. To have in a retrospect in a contract that's been
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negotiated, signed, a plant that's been built, that is in
operation, to have somebody come back and suggest that they
could curtail five percent of your revenue would trigger lender
audit on the contract and restructuring of the agreement. It
would be -- I can't tell you the complications.
I've financed over 3,000 megawatts of renewables
and gas fired power plants in the Western United States, and
I've never heard of such a thing. So it would be very
difficult to absorb.
MR. R. WILLIAMS: With that, Madam Chair,
Mr. Looper is ready for cross-examination.
COMMISSIONER SMITH: Thank you, Mr. Williams.
Mr. Uda.
MR. UDA: No questions.
COMMISSIONER SMITH: Mr. Miller.
MR. MILLER: No, thank you, Madam.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Just one, Madam Chair.
CROSS-EXAMINATION
BY MR. RICHARDSON:
Q. Mr. Looper, you were just asked about the five
percent and the impact on financing. Are you aware of any
financial institutions looking at that number and calculating
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that it's way understated what Idaho Power would actually
curtail?
A. I know that lenders employ independent engineers
to obtain opinions since it's beyond their expertise.
Independent engineers are going to look with the clarity to
which Idaho Power defines the five percent curtailment, which I
think we've heard there is a lack of clarity, and that
therefore you're going to get a huge estimate from the
independent engineer as to what the potential is for
curtailment on your contract, which would be a multiple of the
five percent.
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MR. RICHARDSON: Thank you.
COMMISSIONER SMITH: Ms. Nelson.
MS. NELSON: No questions. Thank you,
Madam Chair.
COMMISSIONER SMITH: Mr. Otto.
MR. OTTO: No questions, Madam Chair.
COMMISSIONER SMITH: Mr. Solander.
MR. SOLANDER: No questions, Madam Chair.
COMMISSIONER SMITH: Ms. Sasser.
MS. SASSER: I have a couple, thank you,
Madam Chair.
MR. WALKER: Excuse me. I'm sorry for the
interruption, Madam Chair, but I haven't been paying attention
to what's been going on, and maybe I'm out of line, but correct
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HEDRICK COURT REPORTING LOOPER (X)
P. 0. BOX 578, BOISE, ID 83701 Dynami s
1 me if I'm wrong but I don't believe that Mr. Looper presently
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for his monologues on wide examination.
COMMISSIONER SMITH: Did we neglect to do that,
Wendy?

6 THE COURT REPORTER: I believe so.

7 COMMISSIONER SMITH: Oh, boy, I am tired today.

8 MR. R. WILLIAMS: I thought I had too.

9 apologize.

10 COMMISSIONER SMITH: Do you want to do that now,

11 Mr. Williams?

12 MR. R. WILLIAMS: Madam Chair, I would ask that
.
13 Mr. Looper's testimony be spread upon the record.

14 COMMISSIONER SMITH: If there's no objection, we
15 will spread the testimony upon the record as if read, and admit

16 Exhibit 1001.

17 I apologize, Mr. Walker. Thank you for bringing

18 that to my attention.

19 MR. WALKER: Thank you, Madam Chair.

20 (The following prefiled direct testimony

21 of Mr. Looper is spread upon the record.)
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HEDRICK COURT REPORTING LOOPER (X)
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I Q. Please state your name and business address.

S 2 A. My name is Robert D. Looper my business address is 1015 W. Hays

3 Street, Boise Idaho.

4 Q. By whom are you employed and in what capacity?

5 A. I am employed by and am the owner of Summit Energy, LLC. I am
6 appearing in this proceeding as a consultant to Dynamis Energy, LLC.

7 Q. What is your educational background?

8 A. I received a Bachelor of Science in Civil Engineering, 1978, from
9 Colorado State University. I am a registered Professional Engineer in the states of Idaho
10 (19 years) and Colorado (30 years).

11 Q. Please describe your professional and work experience.

12 A. For the past thirty-four years, I have been involved in the engineering,
13 development, financing, construction and operation of power plants. I have constructed
14 power plants using various technologies including natural gas fired turbines, landfill gas,
15 biomass, photovoltaic solar power, wind turbines and hydroelectric power. I was
16 President of Mountain View Power when it was awarded the bid and built the Bennett
17 Mountain Power Plant in Mountain Home for Idaho Power Company. Bennett Mountain
18 was a 162 MW large frame simple cycle gas fired combustion turbine operational in
19 March, 2005. I also led the effort for Summit Energy, as President of Lake Side Power,
20 LLC, in winning the bid and building the 535 MW two-on-one Lake Side combined cycle
21 natural gas fired power plant for PacifiCorp, south of Salt Lake City. I am an owner of
22 US Solar, a solar power developer with primary operations in Arizona and California. I
23 am also a principal in Idaho Energy Ventures, which has also unsuccessfully bid into
24 recent Idaho Power and PacifiCorp RFPs for gas fired or all-source generating resources.
25 I have advised Dynamis Energy in negotiating a VVA with Idaho Power and in planning
LOOPER, Di 1
Dynamis Energy, LLC
I the development and operation of its Ada County landfill waste-to-energy power plant.
2 Attached as Exhibit No. 1001 is a more detailed summary of the power plants and power
3 projects I have been involved in.
4 Q. What is the purpose of your testimony in this proceeding?
5 A. The purpose of my testimony is to respond to Idaho Power witness Tessia
6 Park and Idaho Power's proposal to implement a new Schedule 74, to dispatch, or curtail,
7 generation from PURPA qualifying facilities, when the Company is experiencing certain
8 load conditions. In particular, I will address this proposal as it relates to the Dynamis
9 Energy Project for the Ada County landfill.
10 Q. In summary, what are the points you intend to address in your testimony?
11 A. The proposed Schedule 74 will severely damage the ability of IPP
12 Generators to develop and build QF power plants in Idaho. First, I disagree with the
is 13 assertion that Idaho Power has little or limited information available as to how much
14 renewable generation will be available on its system. Second, I disagree with the
15 characterization of Idaho Power's coal units and Langley Gulch as being "must run"
16 resources. I also believe Idaho Power has better alternatives than Schedule 74 for
17 managing the integration of renewable resources into their system. Finally, I will discuss
18 the inability for a developer to finance and build a new PURPA project, if Schedule 74
19 were to be approved by this Commission.
20 Q. How does Schedule 74 specifically impact the proposed Dynamis Energy
21 Project?
22 A. As a QF project, the Dynamis Project would be subject to an unknown
23 level of curtailment under conditions described in the Idaho Power filing. This
24 curtailment would reduce operating income for the Project. The PPA with Idaho Power
25 has been fully negotiated, executed and approved? l? the IPUC. The Project has moved
LOOPER, Di 2
Dynamis Energy, LLC
I forward on this basis and is currently sourcing financing based on this PPA.
.
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2 Q. During PPA discussions with Idaho Power, did Dynamis Energy make any
3 proposals to Idaho Power specifically regarding scheduling of generation for the
4 Dynamis Ada County landfill project?
5 A. Yes, in initial contract negotiations, Dynamis offered to allow Idaho
6 Power to schedule and dispatch generation from the Ada County waste fueled thermal
7 facility. A significant effort was made to define and guarantee operating parameters for
8 the Project, such as start-up and shut-down times, Pmin (minimum generation), Pmax
9 (maximum generation), and ramp rates which really define dispatchability for a power
10 plant. The Project was configured to allow Idaho Power to dispatch the plant during
11 periods of heavy loads, and ramp off the plant during lightly loaded hours. While some
12 good discussions were held on the ability and parameters of scheduling and
13 dispatchability, in the end, the Company declined this opportunity to have what I believe
14 would have been the first dispatchable QF on its system. In my opinion, the AURORA
15 model was unable to properly evaluate the value of a fully dispatchable unit and provide
16 additional value in the PPA to Dynamis for this service.
17 Q. Is the Dynamis facility an intermittent generating facility?
18 A. No, the generation is scheduled and considered a firm energy resource by
19 established industry standards. The PPA with Idaho Power has the energy delivery
20 scheduled for heavy load hours, with penalties if it operates during light load hours and
21 penalties applied if it does not generate within its available capacity during the scheduled
22 hours.
23 Q. If the unit is on during heavy load hours, and off during lightly loaded
24 hours, doesn't this achieve the goal of a dispatchable resource as far as Idaho Power is
25 concerned? 778
LOOPER, Di 3
Dynamis Energy, LLC
I A. Only on a limited basis. The plant is block loaded during heavy load
2 hours, and completely off during light load hours. This does not allow Idaho Power the
3 ability to ramp the generation up and down 24 hours a day, to meet the requirements due
4 to other intermittent generation and loads. One of the concerns expressed by Idaho
5 Power in support of Schedule 74, appears to be just that, the ability to ramp on and off
6 generation to better meet Idaho Power's load profile. If Idaho Power is seeking relief via

7 Schedule 74, it should first strive to value dispatchability providing incentives to QF
8 projects who can meet dispatchable goals.

9 Q. What is the status of the generation interconnection of the Dynamis Project?

10 A. Idaho Power has supplied Dynamis with a proposed generation
11 interconnection agreement, or GIA, that requires Dynamis to install generator output
12 limiting controls, or GOLCs. It is my understanding of proposed Schedule 74, that using
13 the GOLCs, the Company could interrupt or limit Dynamis' generation any day of the
14 year, at any time.

15 Q. Ms. Park makes the statement that the Company has only a limited amount
16 of information available to it, as to when or how much intermittent QF generation it
17 might receive on a given day. Do you agree with this statement?

18 A. No. The output from the Dynamis Project is on a set schedule, delivering a
19 firm 20 MW per day from the hours of 6 am until 10 pm every day of the year.
20 Renewable resources such as the Dynamis Project and other MSW biomass projects can
21 be made to be fully dispatchable. As far as other renewable generators such as wind and
22 solar, forecasting tools have become more sophisticated and on site weather data
23 combined with regional weather stations are being used to monitor real time conditions.
24 Monitoring changes in wind currents and cloud conditions allow dispatchers to bring on

25 additional fast starting resources or ramp down larger facilities to anticipate the changes
LOOPER, Di 4
Dynamis Energy, LLC

1 in generation. In addition, improving technology for control of power factor at each
2 inverter combined with advanced technology will reduce the volatility of generation from
3 wind and solar farms. Other renewable resources such as run-of-river or run-of-canal
4 Hydroelectric, and Geothermal are inherently less volatile in their generation patterns and
5 although not considered dispatchable, can be mostly accommodated through day ahead

6 scheduling.

7 Q. Idaho Power suggests that Schedule 74 is required because they have
8 "must run" facilities and therefore must curtail QF generation. Do you agree with this
9 statement?

10 A. No. Although Idaho Power does have what would traditionally be

11 considered "must run" coal facilities, circumstances in gas pricing and technology have
12 changed and a designation of "must run" must be looked at in a new light.
0 13 Q. Ms. Park states that the Company must keep at least 300 MW of its
14 thermal units - the three coal plants and Langley Gulch - running and able to ramp up to
15 600 MW to serve load during heavy load hours. Do you agree that Langley Gulch should
16 be considered "base load" and that it is cannot be cycled on and off, on a short term

17 basis?

18 A. Langley Gulch is a 300 MW lvi (one combustion turbine, one steam
19 turbine) natural gas fired power plant, with additional duct fired capacity. Langley Gulch
20 is a dispatchable resource, and would not be considered a "must run" unit. From the
21 Idaho Power Corporate website:

22 "In addition to providing electricity for Idaho Power's customers, Langley

23 Gulch will also help to integrate the large amount of wind and other

24 renewable resources Idaho Power expects to have on its system in the

25 near term.

26 The new plant will be able to increase or decrease generation quickly to
27 respond to the variable and intermittent nzIte of renewable resources."
LOOPER, Di 5
Dynamis Energy, LLC
1 The 300 MW Langley Gulch was always intended to provide capability for multiple
2 starts and stops, certainly on a seasonal schedule, but also on a weekly schedule. This is
3 not the characteristics of a "must run" resource.
4 Q. Ms. Park also seems to testify that some of the Company's coal plants
5 must remain on-line and available at all times, because once taken off line, they cannot,
6 for several or more days, be brought back on. In such instances, Ms. Park testifies that the
7 Company would need to start its higher cost, less efficient natural gas peaking units. Do
8 you agree?
9 A. I agree with the statement that coal plants cannot quickly be cycled up or
10 down, but disagree with the premise that this operational constraint means the Company
11 must, at virtually all times, have the ability to ramp-up all or most of its coal units. I also
12 disagree with the assertion that the Company's coal fleet is "must run" twelve months of
13 the year.
14 Using cost data provided by Idaho Power to dispatch and operate coal plants,
15 it is clear that as natural gas prices have declined, the cost of starting and stopping gas
16 fired peaking plants is becoming more economical and lower risk than operating the coal
17 plants. It is apparent that Idaho Power has not used current pricing of natural gas in their
18 analysis, and has not incorporated the risk of carbon adders to the cost of coal generation.
19 Q. What do you mean by Lower Risk?
20 A. Idaho Power has not included the potential cost of green house gas
21 emissions in their estimates for dispatching their coal and natural gas generating
22 resources. Idaho Power, in their Response to Request No. 12, has provided a 20 year
23 levelized avoided cost of energy for the four sample QF Projects including Baseload,
24 Canal, Solar PV and Wind should a carbon cost adder be utilized in accordance with the
25 2011 IRP. The results increased the levelized avo&1d cost of power in a range from
LOOPER, Di 6
Dynamis Energy, LLC

1 $18.70-25.44/MWh.

2 Using a heat rate of 10,000MMBtu's/kWh that might represent a gas fired
3 peaking plant, and using the current average price of natural gas for the next five years of
4 approximately $3.1 O/MMBtu of natural gas as published on NYMEX, the fuel cost of
5 dispatching a gas fired peaker would be approximately $31 /MWh. The incremental cost
6 of CO2 emissions when operating coal as opposed to natural gas units, range from $5-
7 15/MWh, should greenhouse gas regulations be implemented. Using the middle of this
8 range of $1 0/MWh for coal, the fuel cost of dispatching a coal unit as owned by Idaho
9 Power would be over $40IMWh. The cost of dispatching gas fired peakers can be more
10 economical than dispatching Idaho Power coal fired resources. This is a significant
11 conclusion in driving future decisions on how Idaho Power is to economically dispatch
12 their generating resources. For Idaho Power to conclude that the coal is "must run"

•
13 because it is the most economical to do so for ratepayers, is not a valid conclusion when
14 incorporating reasonable expectations for CO2 emission cost adders.

15 Q. How does this factor into the proposed Schedule 74?

16 A. Idaho Power's future of generation mix should be focused on use of
17 existing, and construction of new flexible fast start gas fired peaking generation, to better
18 integrate renewable resources while looking at turning off some of the "must run" coal
19 units which may carry higher cost for rate payers (certainly higher rate risk) and are less
20 desirable from a renewable perspective. There would be no need for a proposed

21 Schedule 74 following this policy on future generation.

22 To further illustrate, Rocky Mountain Power, in its testimony before the
23 Wyoming Public Service Commission, has recommended converting the Naughton Coal
24 Plant Unit #3 to natural gas, as opposed to expending dollars to clean up the coal plant
25 emissions. PacifiCorp (Rocky Mountain Power) 1ing a "Base Case" of $1 6/MMBtu
LOOPER, Di 7
Dynamis Energy, LLC
I and a high case of $34/mmBtu for CO2 emission costs. For the 2010 Request for Offer,
2 PacifiCorp used a $9/MWh adder for CO2 emissions in their evaluation of generation
3 resources when comparing to natural gas fired resources. This is how our neighboring
4 utility views "risk" associated with future of coal fired resources.
5 Q. If Schedule 74 were to be adopted, what impact do you believe it would
6 have on the ability to finance new PURPA projects in Idaho?
7 A. A rate schedule or tariff, as open ended as such proposed schedule 74,
8 would impose a huge burden for any PURPA project to be developed, if that
9 development needs to rely on debt financing. It would be foolish for a pure equity
10 investor to develop a QF plant, knowing that the revenue stream for such a project could
11 be interrupted at any time by the utility, with limitation. Schedule 74 makes it virtually
12 impossible for a project to develop reasonably accurate pro forma revenue projections,
13 for the reason that no one can predict to what level, and how often, the Company would
14 implement a Schedule 74 interruption. Without assurance of a steady revenue stream,
15 debt financing and loan prepayment become virtually impossible.
16 If the Company's goal is not to purchase some amount or level of QF
17 generation during light load hours, in light load seasons, there are other, much less
18 dramatic ways for the Idaho Power to achieve this result. For example, the Dynamis PPA
19 contains a provision where it does not generate during light load hours. As I mentioned
20 earlier, Dynamis offered, but the Company rejected, the ability to dispatch the Dynamis
21 power deliveries. Dispatching would have provided additional value to Idaho Power, as
22 discussed by Ms. Park. But, Idaho Power should have to negotiate for and compensate
23 Dynamis for this right, and this benefit to the Idaho Power system. Instead, the Company
24 is asking for a tariff based dispatch ability, without having to pay any compensation to
25 Dynamis for this right. Idaho Power should not MN the right, through a tariff, to
LOOPER, Di 8
Dynamis Energy, LLC
I indiscriminately interrupt or dispatch all existing and future QFs, without any limitations
2 on the use of this interruption right, and without there being compensation paid.

3 The proposed Schedule 74 sends a message to the Finance Community that
4 the State of Idaho is no place for IPP generation. If Idaho is willing to curtail generation
5 retro-active to existing PPA contracts, what further changes may be in store for a PPA
6 holder from Idaho Power? What is the true value of a long term bilateral PPA contract if
7 the IPP cannot rely on guarantee of the underlying utility to buy its energy?

8 Q. Do you know if other Utilities have had to address this oversupply issue
9 identified by Idaho Power?

10 A. In March 2012, Bonneville Power Administration (BPA) filed its own
11 version of Schedule 74 with the Federal Energy Regulatory Commission. BPA identified
12 the same issue as Idaho Power, oversupply of renewable energy (predominantly wind)
13 during periods of abundant hydroelectric generation and minimum loads. In their filing
14 with the FERC, BPA proposes to curtail the generation but compensate the generation
15 owners for lost revenue. Quoting from the BPA Journal, April 2012 edition;

16 "Under the protocol, BPA would cover the costs of compensating

17 generators this spring from its transmission reserve account until a

18 rate can be established to recover the cost. BPA will initiate a new

19 rate case in which it will propose dividing compensation costs roughly

20 equally between users of BPS 'sfederal base system and generators

21 eligible for compensation from BPA."
22
23 This approach leaves the generator and its PPA contract whole, while addressing the
24 scheduling needs of the Utility.

25 Q. Would you support Idaho Power's proposed Schedule 74 if it included full
26 compensation for lost revenue to generators in accordance with their PPAs?

27 A. Yes

28 Q. Does this conclude your testimony?
784
LOOPER, Di 9
Dynamis Energy, LLC
A. Yes.
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LOOPER, Di 10
Dynamis Energy, LLC
(The following proceedings were had in
open hearing.)
3
(Dynamis Exhibit No. 1001, having been
premarked for identification, was admitted into evidence.)
5 COMMISSIONER SMITH: Ms. Sasser.
6 MS. SASSER: Thank you, Madam Chair.
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CROSS-EXAMINATION
BY MS. SASSER:
Q. Good morning, Mr. Looper.
A. Good morning.
Q. Despite your extensive testimony this morning
regarding Schedule 72 and curtailment, you were originally
retained as a witness for Dynamis Energy. Is that correct?
A. That's correct.
Q. And regarding the Dynamis Energy contract, have
you estimated the impact that curtailment would have on
expected revenues for your project?
A. It's really -- like I said, it's hard to do.
It's probably going to be greater than five percent because
the -- there's no limit to whether it's light load or heavy
load hours, and as we heard in the testimony here, it's very
possible that when you declare a base load must-run facility
for a period of time, that those curtailments could come during
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HEDRICK COURT REPORTING LOOPER (X)
P. 0. BOX 578, BOISE, ID 83701 Dynamis
heavy load hours, despite their statements to the contrary that
it would only be during light load hours. So it's very
difficult to calculate revenue losses for Dynamis, but it would
be -- it would certainly be in that order of magnitude.
Q. Can you explain how it is that curtailment of
your facility would occur during heavy load hours when the
curtailment issue that's being discussed is surrounded on light
load?
A. That's a good question. It's because our heavy
load period really has shoulder hours in it and the light load
period really hasn't been defined, and so it's very possible
that with the period of time, the 16-hour duration there at the
beginning, at the end of the hours if you look at the data,
that we could actually be curtailed as part of the light
loading that's going on in the shoulder hours.
Q. Did you negotiate your contract with Idaho Power
with those types of things in mind?
A. No.
Q. Okay, that's all I have. Thank you.
COMMISSIONER SMITH: Mr. Andrea.
MR. ANDREA: No questions, Madam Chair.
COMMISSIONER SMITH: Mr. Walker.
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HEDRICK COURT REPORTING LOOPER (X)
P. 0. BOX 578, BOISE, ID 83701 Dynamis
CROSS-EXAMINATION
BY MR. WALKER:
Q. So let me understand this. Does Dynamis, do they
have a published rate standard contract or do they have a
negotiated rate and negotiated contract as a large QF?
A. We have a negotiated rate and a negotiated
contract.
Q. And is the mode of force of Dynamis' project, is
that wind?
A. No.
Q. And is the Dynamis output, is that a scheduled
delivery with Idaho Power?
A. It is.
Q. How is it a scheduled delivery with Idaho Power?
A. I'm glad you asked that question.
Q. Excuse me. Strike that. Do you preschedule
deliveries with Idaho Power?
A. We submit a day-ahead schedule to Idaho Power
for -- to schedule in accordance with the contract.
Q. But it's not scheduled deliveries as operator
Idaho Power's system, it's not a firm delivery?
A. Well since we haven't defined "scheduled" here in
this proceeding, I would tell you that the operators of the
Dynamis facility most certainly are scheduling to the minute
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HEDRICK COURT REPORTING LOOPER (X)
P. 0. BOX 578, BOISE, ID 83701 Dynamis
1 and the hour the time that the plant goes on and the plant goes
2 off. Submitting that schedule to Idaho Power and being paid in
3 accordance with that penalties if they don't meet that

4 schedule, that's about as scheduled as you can get.
5
Q. Does Idaho Power dispatch the deliveries from
6 your projects?

7 A. Idaho Power has the ability to curtail

8 dispatchment.
9
Q. That's not what I asked, sir. Does Idaho Power

10 dispatch, does it ramp up and start your project --

11 A. No.

12
Q. -- and dispatch deliveries?

13 A. It does not.
.

14
Q. And you did negotiate an expected amount of

15 curtailment. Does Idaho Power have to curtail those deliveries

16 under the contract?

17 A. No.

18
Q. Tell me, sir, does -- if Idaho Power were to

19 choose not to contract with Dynamis, did it have that choice?

20 A. I don't know. That's a good question. I'm

21 not -- that's a good question. I don't know. I'm not a

22 regulatory guy, you know that.

23
Q. You're not aware of whether a Utility is required

24 to contract with a qualifying facility under PURPA?

25 A. Yes, they are.
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HEDRICK COURT REPORTING LOOPER (X)
P. 0. BOX 578, BOISE, ID 83701 Dynamis

1
Q. So let me ask you again: Could Idaho Power have
I
2 refused to contract with Dynamis?
3 A. I don't -- I don't think so.

4 MR. WALKER: No further questions, Madam Chair.
5 COMMISSIONER SMITH: Thank you.
6 Do we have questions from the Commission?

7 COMMISSIONER REDFORD: No.

8 COMMISSIONER KJELLANDER: Just one.
9 COMMISSIONER SMITH: Commissioner Kjellander.
10

11 EXAMINATION
12
13 BY COMMISSIONER KJELLANDER:
S
14 Q. Mr. Looper, when you were talking about

15 scheduling for Dynamis, you made it sound as if that's the

16 certainty of how it's happening, and I just wanted for

17 clarification to make sure that that would be as it would be

18 proposed since that plant is not built and online.

19 A. Right, that's correct.

20 COMMISSIONER KJELLANDER: Thank you.

21 MR. ARKOOSH: Madam Chairman, I got skipped.

22 COMMISSIONER SMITH: You certainly did. I'm

23 going to blame it on a seating malfunction.

24 MR. ARKOOSH: That's my seatmate here, is it?

25 COMMISSIONER SMITH: No, no. I'm sorry.
.

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HEDRICK COURT REPORTING LOOPER (Com)
P. 0. BOX 578, BOISE, ID 83701 Dynamis
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MR. ARKOOSH: I do have a couple questions.
COMMISSIONER SMITH: Mr. Arkoosh, please.
CROSS-EXAMINATION
BY MR. ARKOOSH:
Q. You testified in your surrebuttal how much energy
you financed. How much was that?
A. About 3,000 megawatts.
Q. Okay. What would the effect of a five-year
contract have on the ability to finance?
MR. WALKER: Objection. That's beyond the scope
of the surrebuttal. Are we at sur-sur?
COMMISSIONER SMITH: Mr. Orndorff -- or, I mean,
Arkoosh.
MR. ARKOOSH: Thank you, Madam Chairman. Madam
Chairman, he testified about the effects of financing, so this
is a witness that knows about the effects of financing. That
was, in part, what the surrebuttal was about, and it's an issue
in the case.
MR. WALKER: But it was offered as surrebuttal on
Ms. Park's testimony, which is beyond her scope.
COMMISSIONER SMITH: I understand that,
Mr. Walker, but I think that five year is an issue in the case
and I am going to allow Mr. Arkoosh to ask this question. So
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HEDRICK COURT REPORTING LOOPER (X)
P. 0. BOX 578, BOISE, ID 83701 Dynamis

1 your objection is noted.

2 MR. WALKER: Thank you.
3 MR. ARKOOSH: Thank you, Madam Chair.

4 THE WITNESS: It's inconceivable that you could
5 finance a project on a five-year power purchase agreement
6 contract.

7
Q. BY MR. ARKOOSH: Regarding Ms. Park's testimony,

8 I wrote this down as well as I could in quotes, and I think
9 it's accurate. She said that if Langley was needed for energy,

10 we wouldn't be in a 74 light load condition.

11 Did you hear that testimony?

12 A. I did.

13
Q. Does that mean that Langley is not a must-run

14 base load resource?

15 A. Yes, it is. Yes, it does mean that, sorry.

16
Q. Secondly, she indicated in her testimony on cross

17 that wind resources, if taken off -- that the inability to

18 incorporate wind resources would cause the generating complexes
19 to be taken off from five to six days to accommodate the wind

20 power. Then she later testified up to seven days.

21 Did you hear that testimony?

22 A. I did.

23
Q. Is that disadvantageous to ratepayers?

24 A. May not be.

25 Q. Why?
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HEDRICK COURT REPORTING LOOPER (X)
P. 0. BOX 578, BOISE, ID 83701 Dynamis

1 A. Because of what's happening in the gas and the

2 coal markets, and of course in the future. This proceeding
3 here is to look at how we should move forward. And coal
markets are carrying a risk of CO2 adders and gas is cheap, and

5 so it may be a good thing to lay off your coal plant for a

6 week.

7 Q. Thank you.

8 MR. ARKOOSH: Thank you, Madam Chairman, for the
9 accommodation.

10 COMMISSIONER SMITH: Certainly, and I apologize

11 once more for neglecting you initially.

12 MR. ARKOOSH: Thank you, Madam Chair.
.
13 MR. WALKER: Madam Chair.

14 COMMISSIONER SMITH: Mr. Walker.

15 MR. WALKER: May I have one last question on

16 sur-sur or --

17 COMMISSIONER SMITH: Absolutely.
18

19 CROSS-EXAMINATION
20

21 BY MR. WALKER:

22
Q. And I know lawyers say this all the time but I

23 really do just have one question, and that is do you operate

24 Idaho Power's system?
.
25 A. No. Thank God.
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HEDRICK COURT REPORTING LOOPER (X)
P. 0. BOX 578, BOISE, ID 83701 Dynamis
COMMISSIONER SMITH: Mr. Williams, I assume you
have no more questions.
MR. R. WILLIAMS: I have nothing.
COMMISSIONER SMITH: That's a good choice.
MR. R. WILLIAMS: May Mr. Looper be excused?
COMMISSIONER SMITH: Is there any objection to
excusing Mr. Looper? Seeing none, he's excused.
THE WITNESS: Thank you for taking me early. I
appreciate it.
I.
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(The witness left the stand.)
COMMISSIONER SMITH: So, according to a list I
was given, I am led to believe that perhaps Mr. Zamora would
like to go now.
MR. ARKOOSH: That's correct, ma'am. I call
Mr. Zamora.
COMMISSIONER SMITH: Mr. Arkoosh.
18 LOUIS ZAMORA,
19 produced as a witness at the instance of Twin Falls Canal
20 Company, et al, being first duly sworn, was examined and
21 testified as follows:
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HEDRICK COURT REPORTING ZAMORA (Di)
P. 0. BOX 578, BOISE, ID 83701 TFCC, et al
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DIRECT EXAMINATION
BY MR. ARKOOSH:
Q. Good morning, Mr. Zamora.
A. Good morning.
COMMISSIONER KJELLANDER: Microphone, please.
MR. ARKOOSH: Thank you, Mr. Commissioner.
Q. BY MR. ARKOOSH: Would you state your name
please, sir?
A. Louis Zamora.
Q. And how are you employed?
A. By the Twin Falls Canal Company.
Q. And what is your job there?
A. Engineering technician and assistant secretary to
Twin Falls Energy.
Q. Did you prefile testimony in this case on behalf
of Twin Falls Canal Company, North Side Canal Company, and then
ultimately it became on behalf of American Falls Reservoir
District No. 2 and Big Wood Canal Company?
A. I did.
Q. Have you reviewed that testimony?
A. Yes.
Q. Would you look at page 5 of seven, line 23, last
line on the page?
A. Yes.
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HEDRICK COURT REPORTING ZAMORA (Di)
P. 0. BOX 578, BOISE, ID 83701 TFCC, et al
Q. Does it reference an attached graph?
A. It does.
Q. Was the graph attached?
A. It was not.
MR. ARKOOSH: May I approach?
COMMISSIONER SMITH: You may.
MR. ARKOOSH: We'd ask this be marked as 1102,
Madam Chairman.
(Twin Falls Canal Company, et al., Exhibit
No. 1102 was marked for identification.)
Q. BY MR. ARKOOSH: Other than the absence of 1102,
would your answers to the questions be the same as in your
prefiled testimony?
A. They are.
MR. ARKOOSH: I would ask this testimony be
spread on the record and 1102 be admitted, Madam Chair.
COMMISSIONER SMITH: If there's no objection, it
is so ordered.
(The following prefiled direct testimony
of Mr. Zamora is spread upon the record.)
I 796 1
HEDRICK COURT REPORTING ZAMORA (Di)
P. 0. BOX 578, BOISE, ID 83701 TFCC, et al
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1 Q. PLEASE STATE YOUR NAME.
2 A. Louis Zamora
3 Q. WHAT IS YOUR BUSINESS ADDRESS?
4 A. Twin Falls Canal Company, P.O. Box 326, Twin Falls, Idaho, 83303.
5 Q. HOW ARE YOU EMPLOYED?
6 A. I am an Engineering Technician and Field Supervisor for Twin Falls Canal
7 Company ("TFCC"), and Assistant Secretary to Twin Falls Energy, Inc., a
8 subsidiary of TFCC. I oversee operation at the Midway Power Plant.
9 Q. WHAT IS YOUR EDUCATIONAL BACKGROUND?
10 A. I received an Associate of Applied Science Degree in 1993 from College of
11 Southern Idaho.
12 Q. WHAT IS YOUR WORK EXPERIENCE?
13 A. For five years after graduation, I worked in the construction trades. Since then, I
14 have worked at TFCC.
15 Q. PLEASE DESCRIBE YOUR DUTIES IN YOUR PRESENT
16 EMPLOYMENT.
17 A. I do surveying and water measurement. I am responsible for maintaining the
18 automation of the facilities on our canal system. Concerning energy matters, I
19 am the company's liaison with third parties.
20 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY HERE?
21 A. The purpose of my testimony here is to describe our canal project; the energy
22 production aspects of our project; how and for whom the energy aspects of our
Case No. GNR-E-ll-03 Zamora, Di
May 2, 2012 797 Twin Falls Canal Company
North Side Canal Company
Page 1 of
I project enhance the economic welfare of our shareholders and our local
2 communities; how PURPA made this possible; and how some of the proposals
3 made in this case will stymie potential future benefits from PURPA to our
4 projects and shareholders without the need to do so.
5 Q. PLEASE DESCRIBE YOUR PROJECT.
6 A. TFCC is an Idaho nonprofit corporation formed under the Carey Act and owned
7 by individual shareholders who pay annual assessments for the operation,
8 maintenance, and management of TFCC. Some of the costs of operating TFCC
9 are offset by income received through power generation. TFCC delivers water to
10 over 200,000 acres of farm ground through over 1,100 miles of canals. TFCC
11 also has two wholly owned subsidiaries, Twin Falls Energy Company ("TFEC")
12 and Midway Power, LLC.
13 Q. PLEASE DESCRIBE THE PLANTS OWNED BY YOUR PROJECT.
14 A. TFEC is a fifty-fifty partner with Ida-West on the eight megawatt South Forks
15 Plant, and sole owner of the 2.5 megawatt Lowline Midway Hydro, and has an
16 interest in Lowline #2.
17 Q. PLEASE CATALOGUE THE FUTURE POTENTIAL ENERGY
18 ASPECTS OF YOUR PROJECT.
19 A. The future potential energy production from our project is difficult to pinpoint
20 without a feasibility study. While we contemplated a feasibility study, we
21 cancelled it due to the current unsettled nature of PURPA project development in
22 Idaho. We have identified at least two potential one megawatt sites. More
23 importantly to us, however, is that fact that we have 1,100 miles of canals. We
Is Case No. GNR-E-1 1-03 Zamora, Di
May 2, 2012 798 Twin Falls Canal Company
North Side Canal Company
Page 2 of 7

I contemplate that as technology improves, and that improvement of technology

2 escalates, what would not now be a practical site may be a practical site in the

3 future. Future upward avoided cost price changes would also influence when we

4 would begin our feasibility study and contemplate development of more canal

5 based hydroelectric projects.
6 Q. WHAT DOES YOUR COMPANY DO WITH THE PROCEEDS IT

7 RECEIVES FROM ENERGY?

S A. Revenues from electric sales from our hydro plants are used as an offset to

9 assessments made against our shareholders for water delivery and use. This

10 revenue stream reduces the variable cost of production for irrigated agricultural

11 products in the Magic Valley, provides a boost to the economy of our service

12 area, and positively affects our statewide agricultural economy. The redirection

13 of the revenues we receive for electric sales to Idaho Power is a very important

14 boost to the agricultural economy in southern Idaho, all the while leaving the

15 Company's rate payers indifferent as to where the power came from.
16 Q. WOULD THE DEVELOPMENT OF YOUR SMALL HYDRO PROJECTS

17 HAVE BEEN POSSIBLE WITHOUT PURPA?

18 A. No. We understand the purpose of PURPA is to encourage the development of

19 local, independent and/or renewable resources, while keeping the ratepayers of

20 the utility indifferent, as to where the power comes from. That renewable energy

21 may otherwise have been forfeited and lost due to traditional utility reluctance to

22 purchase alternative energy. We understand that the encouragement of PURPA

23 resource development comes by excusing cogeneration and small power
Case No. GNR-E-1 1-03 Zarnora, Di
May 2, 2012 799 Twin Falls Canal Company
North Side Canal Company
Page 3 of 7

I production from traditional utility styled ratemaking and regulation, and the

2 establishment of a power purchase price that is supposed to be equal the cost to

3 Idaho Power of otherwise generating the electricity itself.

4 These incentives have been successful for our canal company and others,

5 resulting in the development of plants on our canals would not have been

6 developed. In fact, PURPA has resulted in some partnerships between the canal

7 companies and utilities, providing mutual benefits through net wins for both the

8 utility and the canal company.
9 Q. DO YOU HAVE CONCERN REGARDING IDAHO POWER'S

10 PROPOSAL WOULD ALLOW THE UTILITY TO CURTAIL ENERGY

11 FROM QUALIFIYING FACILITIES?

12 A. Yes. For our existing generating facilities, we simply did not contract for this,

13 nor does it appear necessary given the predictability of the energy we deliver.

14 For future generation projects, it would severely limit our ability to debt finance

15 them, where the revenue stream was subject to such an unpredictable

16 interruption. Without the ability to finance such a large capital expenditure, it is

17 doubtful we would be, able to proceed.
18 Q. WHAT EFFECT WOULD THE PROPOSAL THAT PURPA

19 CONTRACTS BE LIMITED TO FIVE YEARS HAVE UPON THE

20 FUTURE POTENTIAL ENERGY DEVELOPMENT ON YOUR

21 PROJECT?

22 A. Although I will defer to the technical expertise of our expert, Don Schoenbeck,

23 some of the proposals will be fatal to future development of small hydro on our
Case No. GNR-E-1 1-03 Zamora, Di
May 2, 2012 800 Twin Falls Canal Company
North Side Canal Company
Page 4 of 7

I system. The reduction of the term of a power purchase agreement from twenty

2 years to five years will kill our ability to finance either new plants or rebuilds on

3 existing plants. While short term PURPA contracts may lead to more accurate

4 avoided cost pricing, limiting power purchase agreement terms to periods too

5 short to finance fails to serve the purpose of PURPA, which is to encourage the

6 development of alternate energy. There must be some balance. We believe that,

7 at least for small hydros providing reliable, predictable power, the previous

8 twenty-year term provided that balance.
9 Q. DO YOU HAVE A RECOMMENDATION CONCERNING AN

10 ELGIBILITY CAP TO STANDARD PURPA RATES, FOR SMALL

11 HYDRO PROJECTS?

12 A. Yes. Reducing the eligibility cap for published rates from ten megawatts to 100

13 kilowatts, at least in the circumstance of small hydro, is unnecessary and

14 unnecessarily dampening to the encouragement we expect to be offered to

15 PURPA projects. Following the current line of cases, we understand the

16 Commission's purpose is to prevent large projects from "disaggregating" into a

17 group of smaller projects solely to qualify for a published rate. This concern is

18 not applicable to small hydro. We cannot build two diversion structures where

19 one would do. Further, insofar as the reduction of the eligibility cap seeks to

20 control and modulate the mix of resources that come on line such that a

21 purchasing utility's operations not be overborn by variable power, again the

22 reduction does not address any aspect of small hydro. Our power is steady and

23 predictable. As the graph illustrates, small hydro is steady and predictable.
Case No. GNR-E-l1-03 Zamora, Di
May 2, 2012 801 Twin Falls Canal Company
North Side Canal Company
Page 5 of

1 Q. DO YOU HAVE AN OPINION ON THE OWNERSHIP OF
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2 RENEWABLE ENERGY CREDITS FROM YOUR SMALL HYDRO

3 FACILTIES?

4 A. We cannot understand any of the reasoning for an arbitrary award of a

5 small power producer's Renewable Energy Credits ("REC' s") to the purchasing

6 utility. Right now, our energy and capacity are priced at avoided cost, which is

7 what we get paid when we deliver the energy and provide the capacity, and the

8 utility receives the energy and has access to the capacity. If we understand the

9 current proposal, without changing any compensation formula or making other

10 adjustments, the REC 's would be gratuitously transferred to the utility. Right

11 now, we can, and do, sell those REC's for added compensation because we own

12 and control them. The current explanations provided for changing how our
.

13 property is handled, and what we are compensated for our property, and the

14 proposal to transfer the REC's, simply makes no sense.
15 Q. DO YOU BELIEVE THAT THE UTILITY PROPOSALS IN THIS CASE

16 ARE NECESSARY TO PROTECT IDAHO POWER RATEPAYERS,

17 WHICH INCLUDES ALL OF YOUR SHAREHOLDERS?
I.
18 A. No, not with small hydro in any event. So long as the mechanism to calculate
19 avoided cost rates reasonably determines the utility's actual avoided cost, the
20 ratepayer remains indifferent whether the energy comes from a utility or a small
21 hydro. Our power is sufficiently reliable so that no gas or carbon spikes are
22 needed to balance unanticipated power swings. Our conclusion is that all the
Case No. GNR-E-1 1-03 Zamora, Di
May 2, 2012 802 Twin Falls Canal Company
North Side Canal Company
Page 6 of 7
I reasons given in this case for adoption of a 100 kilowatt cap and a fatally short
2 term power purchase agreement have no application to small hydro.
3 Q. WHAT WOULD YOU PROPOSE CONCERNING THE OUTCOME OF
4 THESE ISSUES?
5 A. The power purchase agreements for small hydro should be for a twenty-year term
6 to afford reasonable certainty, which in turn offers us encouragement to develop
7 our small hydra facilities on our project. The eligibility cap for standard
8 published avoided cost rates for small hydra should be ten megawatts of
9 nameplate capacity. There exists no disaggregation issue with small hydro
10 driving the imposition of an impossibly low eligibility cap. To the extent the
11 Commission desires to address the REC's, those should be confirmed as being
12 the private property of the present owner, the power producer.
13 Q. ARE YOUFAMILIAR WITH THE TESTIMONY OF DON
14 SCHOENBECK?
15 A. Yes.
16 Q. DO YOU CONCUR WITH AND ADOPT THE POSITIONS CONTAINED
17 WITHIN THAT TESTIMONY?
18 A. Yes.
19 Q. DOES THAT CONCLUDE YOUR TESTIMONY?
20 A. Yes.
is Case No. GNR-E-1 1-03 Zamora, Di
May 2, 2012 803 Twin Falls Canal Company
North Side Canal Company
Page 7 of 7
(The following proceedings were had in
open hearing.)
(Twin Falls Canal Company, et al, Exhibit
No. 1102 was admitted into evidence.)
MR. ARKOOSH: I would tender him for cross-
examination, ma'am.
COMMISSIONER SMITH: All right.
Mr. Uda, do you have questions?
MR. UDA: No, Madam Chair.
COMMISSIONER SMITH: Mr. Miller.
MR. MILLER: No, Madam.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: No questions, Madam Chair.
COMMISSIONER SMITH: Ms. Nelson.
MS. NELSON: No questions, Madam Chair.
COMMISSIONER SMITH: Mr. Otto.
MR. OTTO: No questions.
COMMISSIONER SMITH: Okay. Mr. Solander.
MR. SOLANDER: No questions, Madam Chair.
COMMISSIONER SMITH: Ms. Sasser.
MS. SASSER: I have a couple. Thank you,
Madam Chair.
I.
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I 804 I
HEDRICK COURT REPORTING ZAMORA (X)
P. 0. BOX 578, BOISE, ID 83701 TFCC, et al

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CROSS-EXAMINATION
2

3 BY MS. SASSER:

4
Q. Hello, Mr. Zamora.

5 A. Good morning.

6
Q. Do any of your projects have the generator output

7 control limiters on them?

8 A. Yes.

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Q. How many projects?

10 A. Just the new one, Midway Power.

11
Q. And is that project or are any of your other

12 projects over ten megawatts?

13 A. They are not over ten, no.

14 Q. So even the project that has the control limiter
15 on it is below the ten megawatt threshold?

16 A. Correct.

17
Q. So how is it that curtailment and Schedule 74

18 would affect your projects?

19 A. Somewhere I had read that -- my understanding was

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ten megawatts or projects with the limiting control.

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Q. Okay.

22 A. I may be mistaken.

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Q. Are you aware that -- well, can I represent to

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you that FERC's given authority to the states to determine

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25 ownership of renewable energy credits?
805
HEDRICK COURT REPORTING ZAMORA (X)
P. 0. BOX 578, BOISE, ID 83701 TFCC, et al
A. Yes.
Q. Thank you. So at page 6, beginning line 10 in
your testimony when you talk about "our property" in relation
to the RECs that are generated from your projects, your
position is premised on the theory that you do, indeed, own
those renewable energy credits?
A. Yes.
Q. Is that pursuant to some language in a contract?
A. It is in our contract that we -- Idaho Power does
not own them, they stayed with the project.
Q. Okay. That is all.
A. And we have sold them in the past.
Q. Okay. Thank you.
MS. 5AS5ER: That's all I have. Thank you.
COMMISSIONER SMITH: Thank you.
Mr. Andrea.
MR. ANDREA: Thank you, Madam Chair. I actually
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20 CROSS-EXAMINATION
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22 BY MR. ANDREA:
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Q. Mr. Zamora, looking at the same portion of your
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testimony, page 6, starting at line 6, this doesn't take a
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25 position on RECs. I'm not asking about that. I'm asking about
806
HEDRICK COURT REPORTING ZAMORA (X)
P. 0. BOX 578, BOISE, ID 83701 TFCC, et al
your avoided cost testimony. And the sentence starts "Right
now." It states:
Right now, our energy and capacity are priced at
avoided cost, which is what we get paid when we deliver the
energy and provide the capacity, and the Utility receives the
energy and has access to the capacity.
Is it fair to take from that that it's your view
that if a project doesn't provide capacity, the avoided cost
rate would be lower because it wouldn't include that component?
A. Yes.
MR. ANDREA: Thank you. That's all I had.
MR. J. WILLIAMS: Yes, Madam Chair.
COMMISSIONER SMITH: Mr. Williams.
CROSS-EXAMINATION
BY MR. J. WILLIAMS:
Q. Good morning, Mr. Zamora.
A. Good morning.
Q. On page 4 of your testimony, looking at line 9
through 17, there's a Q and A there that says: Do you have
concern regarding Idaho Power's proposal would allow the
Utility to curtail energy from QF5?
Do you see that?
A. On what page was that?
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HEDRICK COURT REPORTING ZAMORA (X)
P. 0. BOX 578, BOISE, ID 83701 TFCC, et al
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Q. I'm sorry. Page 4, beginning at line 9.
A. Okay.
Q. And your response there -- why don't you just go
ahead, could you read your response to that question, beginning
at line 12 through 17?
A. Yes: For our existing generating facilities, we
simply did not contract for this, nor does it appear necessary
to give (sic) the predictability of the energy we deliver. For
future generation projects, it would severely limit our ability
to debt finance them, where the revenue stream was subject to
such an unpredictable interruption. Without the ability to
finance such a large capital expenditure, it is doubtful that
we would be able to proceed.
Q. Okay. Are you aware that Idaho Power currently
has the ability to curtail generation from QF5 in emergency
situation under Schedule 72?
A. Yes.
Q. And has that ability and has that curtailment
right inhibited your ability to debt finance and proceed with
large capital expenditures in your projects?
A. We have not built another project since and we
have not been curtailed by Schedule 72 since that plant was
built.
Q. I'm sorry, which plant?
A. The Midway Power Plant.
HEDRICK COURT REPORTING ZAMORA (X)
P. 0. BOX 578, BOISE, ID 83701 TFCC, et al
MR. J. WILLIAMS: Thank you. No further

3 COMMISSIONER SMITH: From the Commission.

4 COMMISSIONER KJELLANDER: No.

5 COMMISSIONER REDFORD: No.

6 COMMISSIONER SMITH: Nor I.

7 Any redirect

8 MR. ARKOOSH: I have no redirect. Thank you,

9 Mr. Zamora.

10 COMMISSIONER SMITH: Thank you for being here.

11 (The witness left the stand.)

12 COMMISSIONER SMITH: Do you want to also do

13 Mr. Schoenbeck while we're with you?

14 MR. ARKOOSH: We can. What we agreed to on the

15 schedule --

16 COMMISSIONER SMITH: Well, it got altered,

17 because Mr. Sorenson and Mr. Hansten want to go tomorrow.

18 So next would be Mr. Richard Guy, which was

19 Ms. Nelson's witness.

20 MS. NELSON: I'd be happy to proceed if

21 Mr. Arkoosh would like that.

22 COMMISSIONER SMITH: Sure.

23 MS. NELSON: Call Mr. Richard Guy to the stand.
01 E COMMISSIONER SMITH: We need to plug in your mic.

25 Thank you.
:DJ
HEDRICK COURT REPORTING ZAMORA (X)
P. 0. BOX 578, BOISE, ID 83701 TFCC, et al
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I know that Mr. Zamora is probably so excited
about this process that he doesn't want to leave, but I am
willing to excuse him in the unlikely event he doesn't want to
be here until the clear end.
MR. ARKOOSH: Thank you, Madam. It has affected
his sleep pattern.
COMMISSIONER SMITH: Yeah, okay. Thank you.
RICHARD GUY,
produced as a witness on behalf of Idaho Wind Partners I, LLC,
being first duly sworn, was examined and testified as follows:
COMMISSIONER SMITH: So, Ms. Nelson.
MS. NELSON: Thank you, Madam Chair.
15
16 DIRECT EXAMINATION
17
18 BY MS. NELSON:
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Q. Good morning, Mr. Guy.
20 A. Good morning.
21
Q. Would you please state your name for the record?
22 A. Richard Guy.
23 ME And by whom are you employed and in what
24 capacity?
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25 A. I'm employed by Reunion Power, LLC. I'm the
810
HEDRICK COURT REPORTING GUY (Di)
P. 0. BOX 578, BOISE, ID 83701 IWP
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general manager. Reunion Power, LLC, is the managing partner
of Idaho Wind Partners I, LLC.
Q. And are you the same individual who filed written
prefiled testimony on behalf of Idaho Wind Partners?
A. lam.
Q. If I asked you today the same questions that were
in that prefiled testimony, would your answers be the same?
A. Yes.
Q. And are those answers true and correct, to the
best of your knowledge?
A. They are.
Q. Did any exhibits accompany your testimony?
A. Yes.
MS. NELSON: Madam Chair, I would move that the
direct prefiled testimony of the witness be read into the
record as if read here today -- be spread into the record as if
read here today, and that Exhibit 2101 through 2120 be marked.
COMMISSIONER SMITH: If there is no objection, we
will spread the written prefiled testimony upon the record as
if read --
MS. NELSON: Thank you, Madam Chair.
COMMISSIONER SMITH: -- and mark for
identification the exhibits.
(The following prefiled direct testimony
of Mr. Guy is spread upon the record.)
811
HEDRICK COURT REPORTING GUY (Di)
P. 0. BOX 578, BOISE, ID 83701 IWP
id
I Q. Please state your name and business address for the record.
2 A. Richard Guy, 450 Alan Drive, Jerome, ID 83338.
3 Q. Who is your employer and what is your position?
4 A. I am the General Manager of Reunion Power, LLC, which is the Managing Member of
5 Idaho Wind Partners 1, LLC.
6 Q. What is your educational and professional background?
7 A. I have been working in the energy field for 35 years. I have provided my Curriculum
8 Vitae.1
9 Q. What is the purpose of your testimony in this proceeding?
10 A. The purpose of my testimony is to provide comments on Idaho Power Company's
11 proposal to apply a new economic curtailment tariff (Schedule 74) against existing fixed-rate QF
12 contracts.
13 Q. Does IWP have facilities that would be affected by the proposed curtailment tariff?
14 A. Yes. IWP owns and operates eleven wind projects in Idaho with a combined capacity of
15 183 MW ("IWP Projects"). The IWP Projects are Qualifying Facilities ("QFs") pursuant to the
16 Public Utility Regulatory Policies Act of 1978 ("PURPA"). Eight of the IV-1P Projects—Burley
17 Butte, Golden Valley, Milner Dam, Oregon Trail, Pilgrim Stage Station, Salmon Falls, Thousand
18 Springs, and Tuana Gulch—have year 2005 Firm Energy Sales Agreements ("FESAs")2 with
19 Idaho Power, approved by the Idaho Public Utilities Commission ("Commission").3 Three of the
20 1WP Projects—Camp Reed, Payne's Ferry and Yahoo Creek—have year 2009 FESAS 4 with
21 Idaho Power, approved by the Commission. 5 Each of the IWP Projects agreed, in its Generator
'See Exhibit 2101.
2 The 2005 FESAs are attached as Exhibits 2102 (Burley Butte), 2103 (Golden Valley), 2104 (Milner Dam), 2105
(Oregon Trail), 2106 (Pilgrim Stage Station), 2107 (Salmon Falls), 2108 (Thousand Springs), and 2109 (Tuana
Gulch).
3 Order Nos. 29813 (Burley Butte), 29814 (Golden Valley), 29948 (Milner Dam), 29772 (Oregon Trail), 29771
(Pilgrim Stage Station), 29951 (Salmon Falls), 29770 (Thousand Springs), and 29773 (Tuana Gulch).
4 The 2009 FESAs are attached as Exhibits 2110 (Camp Reed), 2111 (Payne's Ferry), and 2112 (Yahoo Creek).
'Order Nos. 30924 (Camp Reed), 30926 (Payne's Ferry), and 30925 (Yahoo Creek).
Guy DI -2
Idaho Wind Partners I, LLC
812
I Interconnection Agreement ("GIA") with Idaho Power, to be subject to Generator Output
2 Limiting Control ("GOLC")6 pursuant to Commission Order No. 30414 in docket IPC-E-6-21.

3 Q. How much money has been invested in development of the IWP Projects to date?

4 A. Approximately $450 million.

5 Q. Do the IWP Projects provide economic benefits in Idaho?

6 A. Yes. The operating IWP Projects contribute approximately $2.4 million annually in
7 wages and locally-purchased goods and services; approximately $860,000 annually in various
8 state and local taxes; and approximately $820,000 annually in landowner payments. The IWP
9 Projects provide 18 high-wage permanent full-time jobs with medical and other benefits.

10 Q. Did IWP build the IWP Projects and secure financing based on certain

ii expectations?

12 A. Yes. The Projects secured both debt and equity financing based on revenue projections,
13 which in turn were based on the fixed energy prices set forth in the FESAs, the known power
14 generation characteristics of the turbines, and a forecast of the available wind resource. Our IS
15 revenue projections included no allowances for economic curtailment since that right is not
16 provided to Idaho Power by any of the IWP Projects' FESAs.

17 Q. What is your understanding of the IWP Projects' agreement to be subject to
18 GOLC?

19 A. Each of the Projects elected in its GIA to be subject to GOLC pursuant to the
20 Commission's Order No. 30414 (August 29, 2007) in docket IPC-E-6-21. This Order approved

21 a Settlement Stipulation between Idaho Power and certain QFs that called for the installation of
22 GOLC technology to facilitate a specific curtailment called "Cassia Redispatch."7
See Attachments 4 and 5 of the GIAs. The GIAs are attached as Exhibits 2113 (Burley Butte), 2114 (Pilgrim Stage
Station), 2115 (Camp Reed, Oregon Trail, Payne's Ferry, Thousand Springs, Tuana Gulch, Yahoo Creek), 2116
(Golden Valley), 2117 (Milner Dam), and 2118 (Salmon Falls).
The Settlement Stipulation was attached to the Joint Motion to Approve Settlement and to Dismiss Complaint,
' attached as Exhibit 2119.
Guy DI-3
813 Idaho Wind Partners I, LLC

I Q. What Is your understanding of when Cassia Redispatch could occur?

2 A. OOLC could only be used in limited circumstances. The Commission explains in Order
3 No. 30414 at page 4: "Idaho Power will call for a Cassia Redispatch only when necessary to
4 respond to system emergencies or when identified transmission lines are out of service."

5 Q. Are there any other circumstances under which you understand the Projects may be
6 curtailed?

7 A. The IWP Projects' FESAs set forth very narrow circumstances for curtailment: (1) an
8 event of Force Majeure, Forced Outage or temporary disconnection of the Facility in accordance
9 with Schedule 72; or (2) if Idaho Power reasonably determines our operation is unsafe or may
10 otherwise adversely affect Idaho Power's equipment, personnel or service to its customers
11 (Sections 14.2.1 and 14.2.2, 2005 FESAs; Sections 12.2.1 and 12.2.2, 2009 FESAs).

12 Q. Based on the direct testimony of Idaho Power witness Tessia Park and the proposed
13 Schedule 74, can you determine the extent of economic curtailment that IWP may
14 experience?

15 A. No. The proposal lacks the necessary specificity to determine the specific circumstances
16 in which Idaho Power could cease purchases under the IWP Projects' FESAs.

17 Q. Are you familiar with the FERC Rule 304(1) that Idaho Power witness Tessia Park
18 states is the basis for the proposed Schedule 74?

19 A. Yes. Like witness Park, I am not a lawyer, but Iam familiar with Rule 304(f) and
20 associated FERC orders, and I do not believe this rule applies to QFs with fixed-rate contracts
21 like the IWP Projects' FESAs.

22 Q. What is your understanding of when Rule 304(1) is intended to apply?

23 A. FERC explains in its Order adopting the rule (FERC Order No. 69)8 that section 304(1)
24 applies to those QF contracts where the rate is determined based on the avoided costs at the time
25 of delivery (i.e. in "real time"), as opposed to being fixed in the initial contract. FERC explains
26 that 304(1) was intended to deal with a certain condition that can occur during light loading
27 periods: if a utility operating only base load units during these periods was forced to cut back
'The excerpt from FERC Order No. 69 (February 19, 1980) containing relevant pages 75-77 is attached as Exhibit
2120.
- Guy DI-4
Idaho Wind Partners I, LLC
814
I output to accommodate purchases from QFs, then the base load units might not be able to
2 increase output rapidly when the system demand later increased. As a result, the utility would be

3 required to use less efficient, higher cost units with faster startup to meet the demand.. FERC
4 was worried that this situation, when applied to a QF contract whose avoided cost rate is
5 determined at the time of delivery, could actually force the QF to have to pay the utility to take
6 its power. To avoid this situation, FERC proposed a rule to require the utility to identify periods
7 during which this would occur so the QF could cease delivery during those periods.
8 Q. What is the basis for your understanding that Rule 304(1) does not apply to fixed-
9 rate QF contracts?

10 A. FERC specifically explains in Order 69, at page 77, that Rule 304(f) does not apply to

11 contracts where the avoided cost rate was pre-determined and fixed in the contract:

12 The Commission does not intend that this paragraph [304(f)]

13 override contractual or other legally enforceable obligations

14 incurred by the electric utility to purchase from a qualifying

15 facility. In such arrangements, the established rate is based on the

16 recognition that the value of the purchase will vary with the

.
17 changes in the utility's operating costs. These variations ordinarily

18 are taken into account, and the resulting rate represents the average

19 value of the purchase over the duration of the obligation. The

20 occurrence of such periods may similarly be taken into account in

21 determining rates for purchases.

22 FERC confirmed this distinction between real-time and fixed-rate contracts again just a
23 few months ago in the Entergy Order that was cited in Tessia Park's testimony as demonstrating

24 a utility's ability to curtail QF purchases.9 What witness Park did not add was that, in that Order,
25 where FERC actually rejected a proposed curtailment, FERC explained that fixed-rate contracts
26 already take into account the anticipated average or composite avoided costs for the life of the
27 contract, including the potential times for negative avoided costs. On the other hand, the Entergy
28 Order noted, for contracts where the avoided cost rate is determined "in real time" and could
29 potentially be negative, the rule applies to allow the QF to cease deliveries. FERC concluded:

30 "In neither case is the utility authorized to curtail the QF purchase unilaterally."
. 9 Order on Compliance Filing, 137 FERC J 61,199 (December 15, 2011).
Guy DI - 5
815 Idaho Wind Partners I, LLC
I Q. Based on FERC's statements, do you agree with witness Park's assertion that Rule
2 304(f) applies to existing fixed-rate contracts such as the IWP Projects?
3 No. The fixed rates set forth in IWP Projects' FESAs reflect the parties' and the
4 Commission's determination, at that time, of the anticipated avoided costs for the twenty-year
5 term of the FESAs. This necessarily means that during some operational circumstances, Idaho
6 Power's real-time avoided costs may be below the rates, at other times, the real-time avoided
7 costs may be above the rates. As FERC explained, Rule 304(t) cannot be used to avoid
8 purchases under fixed-rate contracts in these circumstances.
9 Q. What operational and economic impacts might IWP experience if the proposed
10 economic curtailment is implemented?
11 A. Curtailment has a direct impact on our revenues. Revenues are based directly on hours of
12 operation. IWP is not otherwise compensated for fixed costs that will continue during
13 curtailment. This could affect the IWP Projects' ability to comply with existing credit terms with
14 the IWP Projects' lenders, the effect of which could lead to various penalties and, ultimately,
15 default of the debt financing.
16 Curtailment also has a direct impact on our sale of Renewable Energy Credits ("RECs").
17 Under the IWP Projects' FESAs, IWP owns the RECs, and we can and do sell them. We
18 produce RECs only if we produce energy, so if curtailment causes us to produce less energy then
19 we produce fewer RECs and suffer a further reduction in revenue.
20 At the same time curtailment causes revenues to go down, it causes operating expenses to
21 go up. When a wind project is shut down, especially if it is done on short notice, it causes
22 mechanical difficulties. In addition to the additional wear and tear this places on the turbines and
23 other equipment, specific items may fail with a shutdown. For example, there are fuses (ranging
24 from approximately $10 to $1 0,000/per fuse) that may blow at any given time with a shutdown.
25 IWP would incur the hard and soft costs to physically replace these parts. Further, the IWP
26 Projects do not uniformly come back online with a simple remote switch but rather frequently
27 require on-site crews and manual adjustments to get the system fully operational again, all
28 causing further lost delivery hours and lost revenues beyond the actual period of curtailment.
29 And, low loading load periods typically occur in the middle of the night, which is of course an
30 expensive and challenging time to mobilize crews and to safely make the necessary repairs.
GuyDI-6
Idaho Wind Partners I, LLC
816
191 Q. What impacts on others do you believe may occur if the proposed economic
2 curtailment is implemented?
3 A. To the extent IWP has lower revenues, then its landowners also receive less money,
4 causing indirect impacts in their communities. Also, the production taxes the IWP Projects pay
5 in lieu of property tax (3% of gross revenue) will decline as revenues decline. Most importantly,
6 investment in all regulated industries will be discouraged if contracts are perceived to be so
7 easily undone.
8 Q. What does IWP request the Commission to do in this docket?
9 A. IWP requests the Commission not to apply the proposed Schedule 74 to existing fixed-
10 rate QF contracts.
11 Q. Does this conclude your testimony in this proceeding?
12 A. Yes, it does.
S Guy DI-7
817 Idaho Wind Partners I, LLC
(The following proceedings were had in
open hearing.)
(Idaho Wind Partners I, LLC, Exhibit Nos.
2101-2120 were premarked for identification.)
MS. NELSON: The witness is available for
cross-examination.
COMMISSIONER SMITH: Mr. Otto, do you have any
questions?
MR. OTTO: I do not, Madam Chairwoman.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: No questions, Madam Chair.
COMMISSIONER SMITH: Miller. Uda.
MR. R. WILLIAMS: No questions, Commissioner.
COMMISSIONER SMITH: Ms. Sasser, do you have
questions?
MS. SASSER: I do. Thank you, Madam Chair.
CROSS-EXAMINATION
BY MS. SASSER:
Q. Welcome --
A. Thank you.
Q. -- Mr. Guy. If you refer to page 5 of your
direct testimony, line 25, in discussing curtailment under the
FERC regulations, at line 25, you say: FERC explained that
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HEDRICK COURT REPORTING GUY (X)
P. 0. BOX 578, BOISE, ID 83701 IWP

1 fixed rate contracts already take into account the anticipated

2 average or composite avoided costs for the life of the
3 contract, including the potential times for negative avoided

4 costs.

5 Do you see that?

6 A. Yes.

7
Q. Can you explain how Idaho's SAR methodology takes

8 that into account?

9 A. I could not explain that. I'm not familiar with

10 the SAR methodology.

11
Q. Each of your exhibits is substantially similar in

12 the fact that they are standard QF contracts in Idaho. Is that

13 correct?

14 A. Well, if they're substantially similar, I would

15 agree with that.

16 Q. Okay. If you turn to the exhibits, Item 7.5,

17 which looks to be page 12, if you look at -- will look at

18 Exhibit 2102, page 12, Paragraph 7.5.

19 A. 2102?

20
Q. Sure. Yes.

21 A. Page 12?

22
Q. Yes.

23 A. And paragraph what?

24 Q. 7.5 on the page.
.
25 A. Okay.
I 819 I
HEDRICK COURT REPORTING GUY (X)
P. 0. BOX 578, BOISE, ID 83701 IWP
Q. Would you, if I represent to you that each of
your contracts that you've submitted has this standard language
in it --
A. I believe they do.
Q. Okay. If you read that language -- or, I can
read the language for you. Sometimes it's condescending to
have the witness read:
This agreement is a special contract and, as
such, the rates, terms and conditions contained in this
agreement will be construed in accordance with -- and then
there's a list.
At the bottom of that list is 18 CFR Section
292.303 through 308. Do you see where that is noted?
A. Yes, I do.
Q. And the curtailment language that you testify to
as to whether it applies is part of that section, is it not,
292.304(f)?
A. I am not aware of that.
Q. Okay. Well, if you will refer back to page 5 in
your direct testimony, you testify to the fact of whether the
curtailment provision should apply.
A. Okay, yeah, I stand corrected.
Q. Okay. So just then confirmation that in
Paragraph 7.5 of each of your exhibits that's been submitted as
an exhibit, there is a citation that continuing jurisdiction of
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the Commission includes that all items within the agreement
will be construed in accordance with the provisions of the FERC
regulations, and that the curtailment provisions are part of
that citation?
A. Right.
Q. That's all I
MS. SASSER:
COMMISSIONER
Mr. Andrea.
MR. ANDREA:
COMMISSIONER
have. Thank you.
Thank you, Madam Chair.
SMITH: Certainly.
No questions, Madam Chair.
SMITH: So, Mr. Williams or
Mr. Walker.
CROSS-EXAMINATION
BY MR. WALKER:
Q. Good morning -- I guess it's still morning --
Mr. Guy.
A. Good morning.
Q. Now, I'd like to follow up with a couple of the
questions Ms. Sasser was asking you, if that's all right.
Now, is it your testimony that a proposed Section
304(f) curtailment such as Schedule 74 does not apply to the
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HEDRICK COURT REPORTING GUY (X)
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contracts that your projects hold?
A. Yes.
Q. And, now, if there was a specific reference in
your contracts to those provisions being applicable to those
contracts, do you think that would apply?
MS. NELSON: Objection: That calls for a legal
opinion.
COMMISSIONER SMITH: Mr. Walker.
MR. WALKER: It's simply asking what's in his
contract and whether he thinks that applies to his contract or
not, Madam Chairman. I don't think it's a legal opinion.
COMMISSIONER SMITH: I'm going to allow the
witness to respond to the best of his ability.
THE WITNESS: To the best of my ability, I
believe that that is in our contract right now.
Q. BY MR. WALKER: Paragraph 7.5 you confirmed is
present in each of your contracts that are attached here as
exhibits. You accepted Ms. Sasser's and you'd accept my
representation that that language is exactly the same in each
one of the exhibits that you submitted?
A. I would.
Q. And it does specifically say that the agreement
is a special contract and, as such, the rates, terms and
conditions contained in this agreement will be construed in
accordance with 18 CFR Section 292.303 to 308.
I 822 I
HEDRICK COURT REPORTING GUY (X)
P. 0. BOX 578, BOISE, ID 83701 IWP
1 That's an express provision of each of your
2 contracts, is it not, sir?
3 A. It is.
4 Q. And, as such, there is an express provision that
5 says Section 304(f) is applicable to the rates, terms, and
6 conditions contained in those agreements. Is that not correct?
7 MS. NELSON: Objection: The language speaks for
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itself. Whether it is applicable is dependent upon the
9 language of that regulation, and this witness is not being put
10 forth to interpret that regulation for a legal opinion or the
11 effect of this provision on the applicability of that
12 provision.
.
13 COMMISSIONER SMITH: Mr. Walker.
14 MR. WALKER: Well, Madam Chair, I do take
15 exception to the representation that he has not been put forth
16 to interpret 304(f), as much of his testimony does purport to
Norm do exactly that. However, I have no further questions.
t:i COMMISSIONER SMITH: I think you made your point.
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Thank you.
Any questions from the Commission?
COMMISSIONER REDFORD: No.
COMMISSIONER SMITH: Nor I.
Any redirect?
MS. NELSON: No, thank you, Madam Chair.
COMMISSIONER SMITH: Thank you for your help,
I 823 I
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Mr. Guy.
THE WITNESS: Thank you.
MS. NELSON: Madam Chair, may Mr. Guy be excused
from the proceedings?
COMMISSIONER SMITH: If there is no objection,
Mr. Guy is excused.
(The witness left the stand.)
COMMISSIONER SMITH: Next, Mr. Schoenbeck.
MR. OTTO: Madam Chairman -- Chairwoman, if I
may.
COMMISSIONER SMITH: Mr. Otto.
MR. OTTO: Over here. I know Mr. Schoenbeck
covers quite a bit of ground in his testimony. My witness,
Mr. Hayes, is here and available. We might be able to fit that
in before we break for lunch at the assigned hour, just for
continuity.
COMMISSIONER SMITH: I'd be happy for Mr. Hayes,
if there is no objection.
MR. OTTO: With that, I'll call ICL's witness,
Mr. Justin Hayes.
COMMISSIONER SMITH: Thank you, Mr. Otto.
I 824 I
HEDRICK COURT REPORTING GUY (X)
P. 0. BOX 578, BOISE, ID 83701 IWP
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JUSTIN HAYES,
produced as a witness at the instance of Idaho Conservation
League, being first duly sworn, was examined and testified as
follows:
DIRECT EXAMINATION
BY MR. OTTO:
Q. Good morning, Mr. Hayes.
A. Good morning, Mr. Otto.
Q. Would you please state your name and spell your
last name for the record?
A. I am Justin Hayes. Hayes is H-A-Y-E--S.
Q. And with whom are you employed and what is your
position?
A. I am employed by the Idaho Conservation League.
There I serve as the program director.
Q. And did you file prefiled direct testimony in
this case?
A. I did.
Q. And if I asked you those questions today, would
your answers remain the same?
A. They would.
MR. OTTO: And with that, I'd ask that
Mr. Hayes's direct testimony be spread upon the record as if
825
HEDRICK COURT REPORTING HAYES (Di)
P. 0. BOX 578, BOISE, ID 83701 ICL
1 read, including Exhibits 1701 through 1705. I will note that I
2 asked Ms. Park about the Exhibit 1704 previously.
3 COMMISSIONER SMITH: Okay.
4 MR. OTTO: Just for completeness sake.
5 COMMISSIONER SMITH: If there's no objection, we
6 will spread the prefiled written testimony of Mr. Hayes upon
7 the record as if read, and admit Exhibits 1701 through 1705.
8 (The following prefiled direct testimony
9 of Mr. Hayes is spread upon the record.)
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I 826 I
HEDRICK COURT REPORTING HAYES (Di)
P. 0. BOX 578, BOISE, ID 83701 ICL
Q. Please state your name, affiliation, and qualifications.
A. My name is Justin Hayes. I am the Program Director for the Idaho Conservation League. In
this role, I supervise all of ICL's programmatic work particularly issues involving water quality
standards, permitting, and enforcement. Before this, I worked for American Rivers on water
quality and hydropower issues. I hold a Bachelors of Arts in Human Biology, a Bachelor of
Science in Earth Systems, and a Masters of Science in Earth Sciences from Stanford University.
For more than a decade, I have provided substantive comments to the Environmental Protection
Agency (EPA) and Idaho Department of Environmental Quality (DEQ) on numerous permits,
certifications, state and federal regulations, guidelines and standards related to water quality.
Q. Please describe the scope of your testimony in this matter.
A. I address Idaho Power's assertion that, pursuant to Federal Energy Regulatory Commission
(FERC) licenses, the Company's "run-of-river" hydroelectric projects provide approximately 450
MW of "must run" resources. Idaho Power witness Tessia Park testifies on page 20: "Pursuant to
the FERC licenses Idaho Power has for its run-of-river hydroelectric projects, the Company is
obligated to take whatever generation flows through them; it does not have the ability to decrease
or increase the generation." Based on my review, these "run-of-river" FERC licenses do require
water to move downriver, but they allow Idaho Power to accomplish this movement by balancing
generation and releasing water from the dams within certain parameters. Also, I explain that
releasing water within certain parameters improves water quality, fish habitat, and aesthetics,
which are the primary public benefits the FERC licenses, seek to balance with hydropower
generation. I take no position on what the appropriate balance between generation and release
may be. Rather my testimony explains that pursuant to FERC licenses at certain dams Idaho
Power can, within certain parameters, balance generation with releasing water all the while
maintaining run-of-river operations. 827
Hayes, Di 2
Idaho Conservation League
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101 Q. Please describe how FERC licenses and the Idaho DEQ water quality certifications interact.
2 A. FERC is empowered to regulate the construction and operation of hydroelectric facilities
3 through the issuance and conditioning of licenses. When exercising this power FERC must
4 ensure their actions comply with other federal laws including the Clean Water Act (CWA).
5 Under the CWA, Idaho establishes, and the EPA approves, standards to protect water quality.'
6 Further, the CWA requires any applicant for a federal license to provide a certification from the
7 state the project will comply with all applicable water quality standards - known as a 401
8 certification! The state can impose conditions on the FERC license to ensure compliance with
9 the water quality standards? Through this approach, FERC balances the operation of the
10 hydroelectric project with the protection of other public benefits including aesthetics, water
11 quality, and fish habitat.
0 13 Q. Please name the specific hydroelectric projects you will discuss.
14 A. My testimony covers only four projects located along the Mid-Snake River identified as "must
15 run" resources in Exhibit 1701, Idaho Power's Response to Exergy Development Group's Production
16 Request No 19: Milner, Twin Falls, Bliss, and Lower Salmon Falls. These are the four largest of the
17 "run-of-river" projects and combined provide 257.28 MW of capacity.
18
19 Q. Idaho Power alleges they do not have the ability to increase or decrease generation at the
20 Milner project pursuant to FERC license. Do you agree?
21 A. No. A complete reading of the Milner project license, sets a target flow level, but allows for
22 greater flows in order to benefit water quality and fish habitat. The Milner project diverts water
'42 U.S.C. 1313.
2 42 U.S.C. § 1341.
S.D. Warren Co. v. Maine Board of Environmental Protection, 547 U.S. 370 (2006).
828
Hayes, Di 3
Idaho Conservation League

9 1 from Milner reservoir, sending it along an irrigation canal, and returns a portion of the diversion
2 through the powerhouse 1.6 miles downstream." This creates a "bypass" reach of river 1.6 miles

3 long where the river level is controlled only by releasing water from the dam. Idaho waived their

4 water quality certification authority by failing to submit within their one-year timeline.' The

5 FERC license describes the negative impacts to water quality, specifically reduced dissolved
6 oxygen and increased temperatures, caused by reduced flows in the bypass reach." To avoid these

7 negative impacts, the license establishes a "target" flow of water released from Milner into the
8 bypass reach of 200 cubic feet per second (cfs).7 Since the primary reason for the Milner dam is

9 to divert irrigation water, this "target" is primarily applicable during the irrigation season. FERC
10 also imposes a limit on the "ramping rate" in the bypass reach to one foot per hour to protect fish

11 and recreationalists.8 Logically, and scientifically, decreasing generation and releasing more water
*12 from Milner dam beyond this "target" flow, but within the ramping rate, further benefits water

13 quality and provides more flexibility for Idaho Power to integrate wind.

14 Maintaining an appropriate level of dissolved oxygen is an important water quality
15 standard for fish habitat. The growth and decay of aquatic plants reduces dissolved oxygen below
16 these levels. Reduced water velocity and warmer waters encourage aquatic plant growth. To
17 maintain adequate water velocity to prohibit plant growth and limit water warming thereby

18 maintaining an appropriate level of dissolved oxygen, FERC established, in Article 407, a target
19 flow in the bypass reach of 200 cfs.9 Importantly in terms of meeting dissolved oxygen standards,
20 this is a minimum level, not a maximum. FERC explains the "DEIS, "the environmental review
21 supporting the license, recommended flows in the bypass reach between 720 to 2190 cfs in order
See Exhibit 1702 at 1, Milner FERC License Project # 2899.
Id., at 3.
6 Id., at 4.
Id.; See Article 407 at p. 19.
8 Id., at 7 - 8; See Article 410 at 20. .
9 1d.,at6- 7; See Article 4o7atp. 19. 829
Hayes, Di 4
Idaho Conservation League

I to protect the fishery resource in the bypass reach.'° This recommendation reveals that water
2 quality and fish habitat will benefit if Idaho Power increases flows beyond the "target" in the
3 bypass reach by reducing generation.

4 The FERC license explains that low flows in the bypass reach harms the trout fishery by
5 increasing water temperature and sedimentation." Further, reduced flows prevent fish from
6 moving downstream, which "is probably the primary mechanism by which trout populate the
7 bypassed reach."" In setting a "target" flow of 200 cfs, FERC balanced fish protection with the

8 need to maintain irrigation flows in the canal, as well as generate electricity." Maintaining
9 irrigation levels is beyond the scope of my testimony. But I do want to make clear that decreasing
10 generation and releasing more than the "target" of 200 cfs will benefit the trout resource FERC

11 was concerned with. Doing so will increase water velocity in the bypassed reach, help maintain
12 cold water, reduce sedimentation, and increase trout recruitment from the reservoir into the
0 13 downstream fishery.

14 A complete reading of the Milner FERC license reveals that Idaho Power has the flexibility
15 to maintain a run-of-river operation by balancing generation and release from Milner dam
16 within certain parameters. The Company must maintain at least 200 cfs in the bypass reach, but

17 increasing this flow, within the one-foot per hour ramping rate, will benefit the water quality
18 standards that underlay this target while allowing Idaho Power to integrate variable energy

19 resources.
I 20
21 Q. Idaho Power alleges they do not have the ability to increase or decrease generation at the
22 Twin Falls project pursuant to FERC license. Do you agree?
10 Id.
"Id., at 18.
2 Id at 19.
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830 Hayes, Di 5
Idaho Conservation League
0 1 A. No. Similar to the Milner project, the Twin Falls License establishes imposes license
2 conditions to maintain appropriate dissolved oxygen levels, water temperatures, and protect the
3 aesthetics of allowing water to flow over Twin Falls."' The Twin Falls project diverts water from
4 flowing over the falls and sends it through a powerhouse located near the base." Unlike, the

5 Milner project, at Twin Falls there is no bypass reach into which spill flows; rather spill at Twin
6 Falls means allowing water to cascade over the falls as God intended. This difference in physical
7 layout means that water quality is affected through different mechanisms than Milner. But the

8 result is the same, decreased generation and increased spill will benefit the water quality
9 standards and other benefits that underlie FERC's license conditions.

10 FERC imposes a minimum average of flow 300 cfs over the Twin Falls cataract to protect

11 it's aesthetic value." In doing so FERC recognized that this requirement will reduce generation
12 revenue from the project." Whether this concern holds true for Idaho Power today is beyond the 013 scope of my testimony. However, reducing generation and increasing flows will benefit the

14 aesthetics of Twin Falls while providing the Company additional flexibility to integrate variable
15 energy. While FERC requires a minimum flow over Twin Falls, the license also empowers the
16 Company to increase these levels for operational constrains or by agreement with the Bureau of
17 Land Management, Idaho Department of Parks and Recreation, and the Idaho State Historic

18 Preservation Officer.'8 As agencies concerned with protecting the aesthetics of Twin Falls, I

19 imagine they share my position that more spill over the falls is more aesthetic.

20 Diverting water around Twin Falls and through the powerhouse reduces aeration and

21 thus the level of dissolved oxygen in the Snake River." These water quality concerns and license
' Exhibit 1703, Twin Falls License FERC Project # 18.
15 Id., at 1.
16 Id., at 3; See Article 410 at p. 11.
" Id. • '8 1d., See Article 4lOatp. 11.
'91d.,at2. 831
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Idaho Conservation League

I conditions arose from the Idaho water quality certification issued before the FERC license." To
2 avoid violating water quality standards Article 404 of the license requires Idaho Power to monitor
3 dissolved oxygen levels and either reinject air at the powerhouse or "release water over the falls

4 rather than through the project turbines" to maintain water quality."
5
6 Q. Idaho Power alleges they have no ability to increase or decrease generation at the Bliss or
Lower Salmon projects. Do you agree?
8 A. Not completely. While the current FERC licenses do impose run-of-river operations, Idaho
9 Power has a request currently pending before FERC to operate both projects as load following
10 resources.22 These projects had traditionally been operated as load following resources.23 When

11 Idaho Power applied for a relicense, state and federal agencies sought to limit these operations to
12 protect a variety of Snake River snails listed under the Endangered Species Act (ESA)."' A six-
13 year study of the impacts on the snails appears to show that resuming load following operations,
14 within sideboards, is "not likely to jeopardize the continued existence of the species" - the term
15 of art that triggers ESA based restrictions." The US Fish and Wildlife Service, Idaho Department
16 of Fish and Game and Idaho DEQ support this request."' Further Idaho DEQ indicates that

17 changing to load following operations complies with their existing water quality certifications.27
18 While I await the final outcome of the consultation process under the ESA and FERC's decision
20
21 Id., See Article 404 at pp.9 - 10.
22 Exhibit 1704, FERC Notice of IPC's Application to Amend the Bliss and Lower Salmon Falls
Licenses and Exhibit B from IPC's FERC Application Containing Support Letters from U.S. Fish
and Wildlife Service, and Idaho Department of Fish and Game, and IPC's FERC Submittal of
Idaho Department of Environmental Quality's Support Letter.
23 Id., at 6.
24 Id.
25 Exhibit 1705 at 17, Biological Assessment for the Snake River Physa Submitted by IPC to FERC
for the Bliss and Lower Salmon Falls License Amendments.
26 Exhibit 1704 at 12.
27 1d.
832 Hayes, Di 7
Idaho Conservation League

1 on Idaho Power's request, but it appears the Company is on a path towards greater flexibility to
2 operate these dams than they have represented to this Commission so far.
3
4 Q. Please summarize your testimony.
5 A. Idaho Power alleges they cannot increase or decrease generation in their run-of-river hydro

6 projects due to environmental constraints to protect water quality, fisheries, and endangered
7 species. This simply is not true. A complete and fair reading of the FERC documents for the four

8 projects described above reveal Idaho Power has far more flexibility while still protecting these
9 other environmental values.
10
11 Q. Does this conclude your testimony as of May 4, 2012?

12 A. Yes.
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Hayes, Di 8
Idaho Conservation League
(The following proceedings were had in
open hearing.)
(Idaho Conservation League Exhibit Nos.
1701-1705, having been premarked for identification, were
admitted into evidence.)
MR. OTTO: And, with that, Mr. Hayes is available
for cross-examination.
COMMISSIONER SMITH: Thank you.
Ms. Nelson, do you have questions?
MS. NELSON: No, thank you.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: No questions, Madam Chairman.
COMMISSIONER SMITH: Miller. Uda. Williams?
MR. R. WILLIAMS: No questions.
MR. ARKOOSH: No questions, Madam Chair.
COMMISSIONER SMITH: Mr. Solander.
MR. SOLANDER: No questions, Madam Chair.
COMMISSIONER SMITH: Ms. Sasser.
MS. SASSER: No questions, Madam Chair.
MR. ANDREA: No questions.
MR. J. WILLIAMS: No questions, Madam Chair.
COMMISSIONER SMITH: Come on, Paul, don't let us
down.
COMMISSIONER KJELLANDER: Give me about ten
minutes: I'll come up with one.
834
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HEDRICK COURT REPORTING HAYES (Di)
P. 0. BOX 578, BOISE, ID 83701 ICL
COMMISSIONER SMITH: Well, thank you for being
here.
THE WITNESS: It was a pleasure. Thank you for
having me.
MR. OTTO: May Mr. Hayes be excused from the
hearing?
COMMISSIONER SMITH: Seeing no objection,
Mr. Hayes is excused.
THE WITNESS: Thank you.
(The witness left the stand.)
COMMISSIONER SMITH: How about Mr. Schoenbeck.
835
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HEDRICK COURT REPORTING HAYES (Di)
P. 0. BOX 578, BOISE, ID 83701 ICL
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DONALD SCHOENBECK,
produced as a witness at the instance of Twin Falls Canal
Company, et al, being first duly sworn, was examined and
testified as follows:
DIRECT EXAMINATION
BY MR. ARKOOSH:
Q. Will you state your name, please, sir?
A. My name is Donald W. Schoenbeck. That's
S-C-H-O-E-N-B-E-C-K.
Q. And, Mr. Schoenbeck, did you previously file
direct testimony and rebuttal testimony in this case, and
sponsor Exhibit 1101?
A. Yes, I did.
Q. And Exhibit 1101 are your qualifications?
A. Yes, they are.
Q. If you were asked those questions, would you give
the same answers as you did in your direct and your rebuttal
testimony?
A. Yes, I would.
MR. ARKOOSH: With those answers, Madam Chairman,
I would ask his testimony be spread, and his exhibit be
admitted.
COMMISSIONER SMITH: If there is no objection, we
836
HEDRICK COURT REPORTING SCHOENBECK (Di)
P. 0. BOX 578, BOISE, ID 83701 TFCC, et al
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will spread the prefiled written testimony of Mr. Schoenbeck
upon the record as if read, and admit Exhibit 1101.
(The following prefiled direct and
rebuttal testimony of Mr. Schoenbeck is spread upon the
record.)
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I 837 I
HEDRICK COURT REPORTING SCHOENBECK (Di)
P. 0. BOX 578, BOISE, ID 83701 TFCC, et al

1 PREFILED DIRECT TESTIMONY OF

2 DONALD W. SCHOENBECK

3 I. INTRODUCTION AND SUMMARY
4 ' I Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

5 A. My name is Donald W. Schoenbeck. I am a member of Regulatory &
6 '
Cogeneration Services, Inc. ("RCS"), a utility rate and economic consulting firm.

7 My business address is 900 Washington Street, Suite 780, Vancouver, WA 98660.
I Q. PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE.

9 A. I've been involved in the electric and gas utility industries for over 40 years. For

10 the majority of this time, I have provided consulting services for large industrial

11 customers addressing regulatory and contractual matters. A significant portion of

12 my work has included testifying on avoided cost pricing and the negotiation of
S
13 contracts for Qualifying Facilities ("QFs"). A further description of my

14 educational background and work experience can be found in Exhibit No. 1101

15 filed with this testimony.
16 Q. ON WHOSE BEHALF ARE YOU SUBMITTING THIS TESTIMONY?

17 A. This testimony is on behalf of Northside Canal Company, Twin Falls Canal

18 Company and Renewable Energy Coalition (collectively, "QF Companies").
19 Q. WHAT TOPICS WILL YOUR TESTIMONY ADDRESS?

20 A. I will discuss various aspects of the utility proposals to modify the manner in

21 which avoided cost prices are determined pursuant to the Public Utilities
.
Case No. GNR-E-1 1-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
838 Page lof45
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Regulatory Policies Act of 1978 ("PURPA") as implemented by the Idaho Public
Utilities Commission ("Commission") and certain power purchase agreement
("PPA") provisions. While most of my testimony will address the testimony filed
on behalf of the Idaho Power Company ("Idaho Power"), my recommendations
should apply to Avista Corporation ("Avista") and PacifiCorp/dba Rocky
Mountain Power ("PacifiCorp") as well.
Q. PLEASE BRIEFLY SUMMARIZE YOUR FINDINGS AND
RECOMMENDATIONS ADDRESSED IN THIS TESTIMONY.
A. On behalf of the QF Companies I recommend the following:
Establish an eligibility cap of ten megawatts (10 MW) of nameplate
capacity for published avoided cost prices.
Maintain a maximum contract term of twenty (20) years for published
fixed prices under PPAs for QFs at or below the eligibility cap.
Allow all avoided energy costs to be determined using a third party
production simulation model such as AURORA ':t
Two computer simulations are performed ("QF-
in/QF-out")and there are no "post processing"
adjustments such as proposed by Idaho Power.
Between integrated resource plan periods the only
avoided energy cost updates can be for gas price
changes (once per year and from a third party
source) and additional executed QF PPAs.
Carbon costs are included in the avoided cost
energy simulations.
All environmental attributes (such as renewable
energy certificates) are retained by the seller.
Avoided capacity costs should be determined based upon the particular
needs of each utility. At this time, a single cycle combustion turbine
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
839 Page 2of45
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("SCCT") should be used to derive capacity prices for just Idaho Power
while a combined cycle combustion turbine ("CCCT") would be used to
derive PacifiCorp' s avoided capacity prices.
In calculating avoided capacity prices for a new QF, no capacity value
should be included for periods when a utility has excess capacity based on
a one day in ten year loss of load analysis. However, the PPA capacity
price should be paid over each and every year of the PPA.
Full capacity value should be included and paid in each and every year to
a QF with a follow-on PPA.
The PPA capacity prices should only be paid during the peak months and
on-peak hours of each utility.
The Commission should order that workshops be held at the conclusion of
this phase of this proceeding to develop a standard tariff for PPA
negotiations and standard PPAs for each utility.
If non-pricing contractual issues are to be addressed and decided now, the
Commission should order that the QFs with standard PPAs: (i) will not be
subject to operational curtailment (i.e., reject Idaho Power's proposed
Schedule 74), (ii) can be executed up to five years prior to commercial
operation with "locked-in" fixed pricing, and (iii) contain liquidated
damage provision options including both a fixed dollars per kilowatt price
and a mark-to-market method.
II. ELIGIBILITY CAP AND CONTRACT TERM
Q. PLEASE EXPLAIN THE IMPORTANCE OF THE ELIGIBILITY CAP
WITH REGARD TO AVOIDED COST PRICING IN IDAHO.
A. The megawatt cap determines if a QF is eligible for standard published prices as
compared to having to negotiate prices with the utility. If the QF facility is less
than the eligibility cap, the QF can avail itself of published avoided cost rates
based on a surrogate avoided resource ("SAR") methodology. The current
surrogate avoided resource for all three utilities is a CCCT. If the QF facility is
larger than the eligibility cap, the QF avoided cost prices are determined under
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
840 Renewable Energy Coalition
Page 3 of 45
what is termed the integrated resource plan ("IRP") methodology. Under the IRP
method, avoided energy costs are determined by performing two production cost
3 computer simulations. The first computer simulation derives the company's
4 production costs over the planning horizon under a base case set of assumptions
5 consistent with the utility's integrated resource plan and the second simulation
6 determines the production costs with the QF included in the utility's resource mix.
The difference in costs between these "QF-in/QF-out" simulations is used in
deriving the avoided energy costs paid to the QF. As capacity costs are not
included in the production simulations, the fixed costs associated with a surrogate
resource are used—currently a CCCT—for deriving the avoided capacity costs
paid to the QF. Finally, for intermittent resources such as solar and wind, there is
an integration adjustment to the prices paid to the QF.
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Q. WHAT HAS THE ELIGIBILITY CAP BEEN IN IDAHO?
A. Until Order No. 32176, the cap had been 10 MW since July 2002 for all QF types.
This cap figure was originally applied as being 10 MW of capacity but in
November 2004, the cap was clarified to be 10 average megawatts ("aMW") in
any month. (Order No. 29632, page 14). With the issuance of Order 32176, the
Commission reduced the cap from 10 aMW to 100 kilowatts ("kW") for wind and
solar QFs, effective December 14, 2010, while maintaining the cap at 10 aMW for
all other technologies. With the issuance of Order No. 32498 on March 22, 2012,
the Commission directed that all contracts executed by Idaho Power in excess for
100 kW must be presented to the Commission for approval until such time that
the Commission modifies this determination.
.
Case No. GNR-E-1 1-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
841 Page 4of45
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Q. WHAT IS IDAHO POWER'S PROPOSAL IN THIS PROCEEDING FOR
AN ELIGIBILITY CAP VALUE?
A. Idaho Power is proposing that the cap be set at 100 kW for all QF technologies.
Q. WHAT IS THE MAXIMUM TERM FOR WHICH IDAHO POWER IS
WILLING TO OFFER FIXED PRICE CONTRACTS TO QFS?
A. Idaho Power is proposing that fixed-price contracts be limited to a maximum term
of only five years. This is a substantial reduction from the existing authorized
maximum term of 20 years.
Q. WHY IS IDAHO POWER PROPOSING SUCH RADICAL CHANGES TO
THE ELIGIBILITY CAP SIZE AND CONTRACT TERM?
A. It would appear that most of Idaho Power's testimony on these matters has to do
with a concern or fear that the avoided costs prices will not be properly
established when the contracts are executed or the contract prices may not be
correct based on an after-the-fact analysis. Other than these concerns, which I
will address later in this testimony, Idaho Power has offered little else in support
of these two very substantial and adverse changes.
With regard to the extremely low cap value, Idaho Power argues having
fixed prices in place for as long as two years could expose customers to high
avoided cost payments due to "unforeseen circumstances or risks". It asserts
these conditions could be taken into account in negotiating a contract with an
updated IRP method determination. Regarding the five year maximum contract
term, Idaho Power asserts that "locking in" fixed prices "shifts market price risk
0
Case No. GNR-E-11-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
842 Page 5of45
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from the project developer/owner entirely onto Idaho Power's customers". (See
Stokes 43-46).
Q. DO YOU AGREE WITH IDAHO POWER'S PROPOSAL WITH REGARD
TO ELIGIBILITY SIZE AND CONTRACT TERM?
A. No. The proposed eligibility size is far too small and contract term is far too
short. At a cap level of just 100 kW, virtually every QF contract would be a non-
standard PPA requiring the QF to negotiate the prices, terms and conditions of the
agreement. State commissions have discretion under PURPA to determine the
level of QF capacity that is eligible for standard rates above 100 kW. For most of
the years since PURPA was enacted, this Commission has had in place a 10 MW
cap (From 1997 to 2002, the eligibility cap was 1 MW or 5 MW). In 2005, the
Oregon commission ordered an eligibility cap of 10 MW that is still in effect
today. More recently, in December 2010, as part of the settlement on avoided
cost matters the California commission approved an eligibility cap of 20 MW.
Q. WHY HAVE COMMISSIONS APPROVED ELIGIBLITY CAPS IN THE
10 TO 20 MW RANGE?
A. I believe there are several significant reasons which have to do with transaction
costs, economies of scale, lack of alternative markets and FERC's regulations for
implementing PURPA in response to the Energy Policy Act of 2005 ("EP Act
2005").
Forcing virtually every QF to negotiate a non-standard contract adds to the
upfront transactional costs by extending the period over which the QF could
ascertain if the project was commercially viable based upon a complete review of
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
Page 6 of 45
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the prices, terms and conditions offered by the utility. In addition, it would only
be prudent for the QF to retain the necessary expertise to assist in the evaluation
and negotiation of the contract. It has been my experience that negotiating a non-
standard QF PPA with a utility can take a great deal of time. In some instances,
the slowness in which a utility will negotiate a PPA can cause a project to not be
built as the developer may not have the time or money for an extended negotiation
process. These additional transactional costs could well make a smaller project
uneconomical.
Setting a low cap may also impact project viability due the economies of
scale that are inherent in the utility industry. Typically, utility-owned resources
benefit from being sized large enough such that the dollar-per-kilowatt investment
required to build the plant is less than for a much smaller sized QF of the same
basic technology. Establishing a reasonable size cap, in the 10 to 20 MW range
will allow some scaling benefits for the QF.
The typical short-term power sale trades in the Pacific Northwest
electricity market are for blocks of 25 MW for each and every hour of the "on-
peak" period, Monday through Saturday, 6:00 a.m. to 10 p.m., or "off-peak
period",all other hours plus holidays. Only in California is there an organized
market run by an independent administrator, California Independent System
Operator ("CAISO"), for day-ahead or real-time products in the Western United
States. Consequently, QFs in the Pacific Northwest cannot provide the product
.
Case No. GNR-E-1 1-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
844 Page 7of45
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most traded nor do they have access to competitive organized markets for their
products.
Finally, the EP Act 2005 established a new section within PURPA that
relieves a utility of the obligation to purchase QF power if the utility has sought
and received a waiver of the obligation from FERC by showing the QF has
wholesale market access under certain standards. However, in implementing EP
Act 2005, FERC ruled that even where QFs have market access, the utility is
only relieved of the must purchase obligation for QFs larger than 20 MW. In
other words, utilities must still purchase QF power from "smaller" facilities if the
facility is less than 20 MW. All these factors suggest an eligibility cap much
greater than Idaho Power's 100 kW value.
Idaho Power has not addressed the reasons why state commissions have
imposed much greater values in recognition of the hurdles facing the development
of smaller QF facilities. Idaho Power's reasoning for proposing a cap of 100 kW,
so it can apply the latest available information as part of the IRP method,is really
a pricing issue. This can be more appropriately addressed by modifying the
manner in which the fixed prices are determined.
Q. WHY DO YOU DISAGREE WITH A CONTRACT TERM OF JUST EWE
YEARS?
A. There are three reasons: fairness, equity and insufficient cost recovery period.
Q. WHAT IS UNFAIR ABOUT THE COMPANY'S PROPOSED FIVE YEAR
TERM?
.
Case No. GNR-E-1 1-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
845 Page 8of45
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A. The five-year term is unfair and inappropriate because it creates such a mismatch
between the maximum contract term allowed a QF versus the economic life used
or assumed for a comparable utility-owned resource. In Idaho Power's 2011
Integrated Resource Plan, a thirty (30) year plant life is used for all the resource
types illustrated in Idaho Power's Exhibit No. 8. As deliveries from QFs are in
part in lieu of building company-owned resources, a contract life comparable to
the utility-owned resource life is only fair and equitable. I am sure Idaho Power
would be unwilling to invest in a resource if it was only assured of some cost
recovery for just five years and had no assurance of a follow-on contract at the
end of this five year period.
Q. WHY ARE YOU EMPHASIZING THE WORD "SOME" COST
RECOVERY?
A. As I will explain later in this testimony, Idaho Power's avoided capacity pricing
proposal will only include a capacity value in the avoided cost contract prices if
there is a need for capacity. As such, the capacity provided by any QF under a
five-year extension agreement or a follow-on PPA could well be bumped or
displaced by any utility-owned or contracted-for resource that has been executed
subsequent to the initial QF PPA. For resources such as those owned by the QF
companies that have been providing reliable capacity for a number of years, the
Idaho Power proposal is patently inequitable.
Q. WHY WON'T A FIVE-YEAR TERM ALLOW FOR REASONABLE COST
RECOVERY?
Case No. GNR-E-1 1-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
846 Page 9of45

1 A. A contract term of just five years is simply an insufficient time period to provide
any prospect for the recovery of the investment in the facility in today's markets.

3 For all but the spring period, the California market tends to dominate western

4 market prices due to its resource mix. Every year in its annual market report, the

5 CAISO publishes the results of an analysis it conducts to see if a new market

6 entrant would generate sufficient market revenue to cover its costs. For the last

7 several years, this analysis has shown that the net market revenue (total market

8 revenue less variable operating costs) generated from sales in the CAISO markets

9 are inadequate to allow a new combined cycle facility to recover its fixed costs as

10 shown by the following table.
11
.
Case No. GNR-E-1 1-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
847 Page lOof4S
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CAISO Annual Fixed Cost versus Net Market
Revenue in Excess of Variable Costs
($IkW-year)
NP15 Net SP15 Net
CCCT Fixed Market Market
Year Cost Revenue Revenue
2009 $190.70 $40.14 $38.48
2010 $190.70 $30.60 $35.52
2011 $190.70 $23.30 $22.99
From this analysis, the CAISO appropriately concluded:
These findings continue to underscore the critical
importance of long term contracting as the primary
means for facilitating new generation investment.
Local requirements for new generation investment
should be addressed through long-term bilateral
contracting under the CPUC resource adequacy
and long-term procurement framework. (CAISO
Annual Report on Market Issues and Performance,
April 2012, page 47)
A similar type of analysis and result can be done using Idaho Power's
estimated capital costs and projected avoided cost payments under its pricing
proposals in this proceeding. The following table compares the estimated capital
cost of select resources with the revenue recovery under Idaho Power's proposed
five-year maximum contract term and proposed QF prices. The capital cost
estimates (dollars per kilowatt-"$/kW") were taken directly from Idaho Power's
2011 Integrated Resource Plan ("2011 Plan") Appendix C, page 82. The values
in the other columns represent 100% of the revenue received over five years using
the monthly avoided cost prices Idaho Power provided in response to Staff
Case No. GNR-E- 11-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
848 Page llof4S

I Production Request No. 15 along with the estimated monthly deliveries for each
resource type used in compiling Idaho Power's Exhibit No. 8. The revenue value

3 was converted to the $/kW value shown in the table using the associated capacity

4 of each resource. The column in the table labeled "Revenue Recovery 2013-

5 2017" uses the prices of both capacity and energy, from every month of the Idaho

6 Power data response times the associated monthly energy to calculate the total

7 expected revenue for a five-year period for each resource type. The column

8 labeled "2017 Revenue Recovery for 5 Years" is a five-year revenue amount

9 based solely on the 2017 revenue (2017 revenue multiplied by 5 years). This

10 single year was chosen as the monthly avoided cost prices include full capacity

11 value for the entire year.
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Capital Cost versus Revenue Recovery for a 5 Year Period
($/kW)
Idaho Revenue 2017
Power IRP Recovery Revenue
Capital Years Recovery for
Resource Type Cost 2013-2017 5 Years
Baseload
(Geothermal) $6,250 $1,573 $2,003
Hydro/Canal Drop $4,000 $665 $960
Wind $1,450 $426 $474
Solar $2,115 $377 $554
It is important to emphasize that the revenue recovery values in the table have not
been reduced to reflect any annual costs that would be incurred by the facility
such as operations and maintenance expense for running the facility, property
taxes or insurance. Even based upon the 2017 prices, with full capacity payments
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
849 Page l2of4S
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each and every year, a condition that may never materialize under Idaho Power's
"sufficiency proposal", Idaho Power's maximum contract term of just five years
is woefully inadequate for the QF to recover its capital investment. In my view,
the above table demonstrates the unreasonableness of Idaho Power's proposals in
this proceeding. It could well eliminate the development of QF facilities in this
state if the Commission were to adopt the proposals.
Q. WHAT IS YOUR RESPONSE TO IDAHO POWER'S ASSERTION THAT
LOCKING IN A LONGER TERM SHIFTS RISK TO RATE PAYERS?
I A. The implication of Idaho Power's testimony is that Idaho Power customers will
be harmed from locking in fixed prices for a long period of time. This, of course,
may not necessarily be the case. In this current period of low gas prices, locking
into longer term contracts may in fact provide a substantial benefit if gas prices
were to rise above current projections. In actuality, locking into fixed price
arrangements reduces Idaho Power's exposure to market price movements. More
importantly, however, the Idaho Power witnesses really appear to be arguing that
a different standard of prudency and reasonableness should be used for judging
QF contracts as compared to utility owned resources. For QF resources, Idaho
Power seems to imply there should be an ongoing review as to the
appropriateness of the QF payments. However, for utility-owned resources or
inter-utility PPAs, Idaho Power, like all other utilities, will argue just one
reasonableness review should be conducted based on the standard of what was
known at the time the decision to acquire the resource or execute the PPA was
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition 850 Page l3of4S
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made. This approach is consistent with the PURPA standards. FERC's
regulations provide QFs the right to receive energy and capacity payments based
on a forecast of "the avoided costs calculated at the time the obligation is
incurred." 18 CFR Section 292.304 (d)(2)(ii). This should be the exact same
standard for judging the reasonableness of QF contracts employed by this
Commission.
Q. WHAT ARE YOUR RECOMMENDATIONS WITH REGARD TO THE
ELIGIBILITY CAP AND MAXIMUM CONTRACT TERM IN THIS
PROCEEDING?
A. For all the reasons I have presented in this testimony, I recommend the eligibility
cap be set at the low end of a reasonable range, that being 10 MW of nameplate
capacity for all technologies, along with a maximum contract term of 20 years.
These values will reduce the administrative costs on Idaho Power and the
Commission in having to carefully review and approve virtually every single QF
contract under Idaho Power's proposal. It will also lower the contracting costs for
the QF. The longer contract term will also provide a realistic time frame for a QF
to recover its development costs, including its debt financing costs. The
reasonableness of these specific recommendations should be considered in total,
including the avoided cost pricing methodology I recommend for deriving the
published fixed prices.
III. AVOIDED COST PRICING
Q. DO YOU BELIEVE AVOIDED COSTS CAN BE PROPERLY
ESTABLISHED USING EITHER A SAR OR IRP METHOD?
Case No. GNR-E- 11-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
851 Page l4of45
I A. Yes. As long as consistent assumptions are used in both methods (such as fuel
costs and market price forecasts), all the same costs categories are included in

3 both methods and the expected QF generation pattern is taken into account, I

4 believe employing either method would essentially result in similar avoided cost

5 streams. There are trade-offs between using either one of the two methods. A

6 surrogate resource method is generally easier to explain, implement and

7 understand the resulting prices because the calculus is more straightforward and

8 transparent. The surrogate resource calculations can be done using Microsoft's

9 Excel spreadsheet software which most QF owners or developers would already

10 have on their computers. On the other hand, an integrated resource plan method

11 will generally rely on a much more complex "black box" production simulation

12 model that uses thousands of inputs and forecast assumptions in order to derive
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the avoided cost prices. While most QF owners or developers are likely to
understand the workings of an Excel spreadsheet, it is highly unlikely that they
are knowledgeable with respect to all the inputs required in a production
simulation model such as AURORA and the impact the representation of a
particular resource could have on the simulation result. Further, the licensing of a
third party production model can be very expensive adding to the QF's transaction
cost. For example, the AURORA annual licensing fees range from $39,500 to
$150,000 for the basic regional modeling capability. While the integrated
resource method may not be as transparent as the surrogate resource method, it
can do a better job of taking into account a utility's needs by incorporating all the
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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expected loads and resources over the contracting planning horizon. This gives
the appearance of a more precisely determined, and therefore more accurate,
avoided cost prices but the result is driven by all the numerous forecast
assumptions and resource representations, many of which will likely be wrong
based on a "20-20" hindsight review. For these reasons, in my view either
method can be used to determine reasonable avoided cost prices.
Q. WHY IS IDAHO POWER PROPOSING TO DISCONTINUE USING THE
SAR PRICING METHOD FOR ALL QF CONTRACTS?
A. Idaho Power provides four reasons: 1) the use of a high SAR capacity factor does
not recognize the economic dispatch that is likely to occur with the resource, 2)
the SAR method does not value energy at the time it is delivered or valued by the
utility, 3) the SAR method does not recognize the characteristics of different QF
resource types, and 4) the SAR method is too static. (See Stokes 40-41).
manner in which the SAR method is implemented. It does not necessarily follow
that the method itself should be abandoned; it could simply be modified. For
example, the SAR method could employ an exogenously determined market
price, either hourly or monthly by on and off peak period, to incorporate
economic displacement of the resource. The resulting energy costs would then
reflect the lower of the operating cost of the surrogate resource or the market
value. This resulting hourly cost stream would inherently reflect the value of
Q. ARE IDAHO POWER'S CRITICISMS VALID?
A. Not really, in that every one of these criticisms can be addressed by modifying the
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May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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energy by time period, thereby addressing the Company's second concern.
Determining four different sets of published prices based on the four different QF
delivery patterns applied to the cost stream would recognize the delivery
characteristics of each resource type just as Idaho Power is proposing under their
IRP method. Finally, the most critical component or input under a gas-fired
surrogate resource method or computer-generated production simulation results of
an integrated resource method is the gas price(s) used in the analysis. By requiring
annual updates to the gas prices and the corresponding market prices, the SAR
method will not be static between integrated resource plan publications.
The only item that cannot be directly addressed by these modifications is
how additional QFs that commence delivering generation to Idaho Power might
impact Idaho's published avoided costs, if at all. To the extent Idaho Power
believes it will have requests for numerous additional QF PPAs seeking published
fixed prices, the much more costly and work intensive IRP method could be
considered to establish all avoided cost prices for both standard and non-standard
contracts if it were done in a proper manner.
Q. HOW DOES IDAHO POWER DETERMINE AVOIDED ENERGY COSTS
UNDER THE CURRENT IRE METHOD?
A. Idaho Power uses the AURORA simulation model developed and marketed by
EPIS to perform the QF-in/QF--out computer simulations. The difference in costs
between the two computer simulations is used to derive the base energy cost. I
am not opposed to using an integrated third party model such as AURORA for
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
854 Page l7of45

I deriving avoided energy prices under an IRP method. I am opposed however, to
allowing a utility to use an internally developed model such as PacifiCorp's GRID

3 model. It requires far too many exogenous inputs, including internally developed

4 projected hourly market prices for each trading hub, that can influence the

5 resulting cost projection.
6 Q. IS IDAHO POWER PROPOSING ANY CHANGES TO ITS METHOD OF

7 DETERMINING IRP DERIVED ENERGY COSTS IN THIS

8 PROCEEDING?
9 A. Yes, Idaho Power is proposing several changes to the manner in which it will

10 calculate avoided energy prices under it proposed IRP method. Idaho Power is

11 proposing 1) to use just one AURORA computer simulation instead of two

12 simulations, 2) make post processing adjustments to the AURORA results to

13 remove market sales revenue impacts and assign the QF power an avoided energy
O 14 cost of $0/MWh during minimum load conditions, and 3) proposing ongoing

15 updates to many AURORA inputs between IRPs, including changes in resource

16 costs, load forecasts, and including all newly signed QF and "queued" QF PPAs.
17 Q. DO YOU SUPPORT ANY OF THESE CHANGES?

18 I A. No. Avoided costs are defined at 18CFR, Section 292.101 as:

19 (6) Avoided costs mean the incremental cost to an electric

20 utility of electric energy or capacity or both which, but for

21 the purchase from the qualifying facility or qualifying

22 facilities, such utility would generate itself or purchase

23 from another source.
241 In other words, an appropriate method for establishing the rates for energy and
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May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
855 Page l8of45
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capacity payments must reflect the cost that is avoided by purchasing the power
from the QFs. The best manner to implement this fundamental avoided cost "but
for" pricing principle is through employing two production cost simulations
With one simulation having the QF excluded from the resource mix and a second
simulation with the QF in the utility resource mix, the difference in cost
represents the costs that would have been incurred "but for" the QF. The costs
avoided due to the presence of the QF cannot be quantified under Idaho Power's
single "QF-in" computer simulation. To correct for this 'one-model-run' bias,
Idaho Power proposes a series of inappropriate post processing adjustments.
Q. PLEASE EXPLAIN THE POST PROCESSING CALCULATIONS IDAHO
POWER IS PROPOSING IN ORDER TO DETERMINE AVOIDED
ENERGY COSTS UNDER ITS PROPOSAL.
A. Idaho Power uses the AURORA-generated hourly dispatch of its resources and
market purchases to determine its highest cost displaceable resource in any hour
to determine the incremental cost for that hour. If there are no displaceable
resources due to the thermal resources operating at the minimum generation levels
set by Idaho Power, including a substantial minimum value for Langley Gulch,
Idaho Power's method assigns a $0/MWh incremental cost value for those hours.
The resulting stream of hourly incremental costs is then used along with the
estimated delivery patterns to derive the avoided cost prices for each QF type
shown in Idaho Power's Exhibit 8. Significantly, as noted in the testimony of
Idaho Power, under this proposed IRP method, no credit to the QF for opportunity
sales that arise from the availability of the QF power is recognized. The
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Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
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following table compares the avoided energy prices under Idaho Power current
IRP method with the proposed method.
Comparison of 20-Year Levelized Energy Costs
($IMWh)
'PC
Current IPC
IRP Proposed
Resource Type Method IRP Method Difference
Baseload $49.96 $43.82 -$6.14
Canal Drop $47.27 $45.45 -$1.82
Solar $48.33 $40.99 -$7.34
Wind $41.60 $35.86 -$5.74
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The source of the avoided cost energy values under the column labeled "IPC
Current IRP Method" are from Idaho Power's Exhibit 8. The values under the
column labeled "IPC Proposed IRP Method" are from Idaho Power's response to
Staff Production Request No. 13. The energy values in both columns include the
integration cost adjustment.
Q. DO YOU BELIEVE IDAHO POWER'S PROPOSED IRP ENERGY
PRICING PROPOSAL IS CONSISTENT WITH PURPA AND HOW
AVOIDED ENERGY PRICES SHOULD BE DETERMINED?
A. No. PURPA imposes a must take obligation on the utility and provides only very
limited circumstances under which a utility can curtail purchases from a QF. In
deriving avoided energy prices under an IRP like methodology, the complete
change in the incremental cost incurred by the utility, including additional short-
term sales opportunities, are the costs incurred "but for" the QF. Idaho Power is
alleging that "the absence of any reference to sales in determination of avoided
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May 2, 2012 Twin Falls Canal Company
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Renewable Energy Coalition
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costs" is a "significant aspect of the definition" with reference to Section
292.101(b)(6). (See Bokenkamp page 9). In my view, the absence of any
reference to sales is not significant and cannot be harmonized with the utility must
take obligation. The two AURORA production simulations will determine the
appropriate hourly value of the QF power including under what Idaho Power has
claimed are minimum load conditions. Idaho Power's proposals to ignore
opportunity sales and replace minimum load hours with a zero value are
inappropriate.
The potential for gaming that can occur under Idaho Power's proposal is
also of concern. Idaho Power has included Langley Gulch in its analysis as a
must run resource with a substantial minimum load level. If the Commission
were to adopt Idaho Power's proposal, including this type of resource in the
analysis as must run would be inappropriate. I will address this further in
discussing Idaho Power's proposed Schedule 74 later in this testimony.
Q. WHY DO YOU OBJECT TO IDAHO POWER'S PROPOSAL TO ALLOW
VIRTUALLY CONTINUOUS UPDATING OF THE INPUTS UNDER THE
IRP METHOD?
A. I have three concerns with allowing unconstrained updating to the AURORA
inputs, in-between publication of IRPs. First of all, it could create a substantial
burden on the QF to have to analyze and evaluate the reasonableness of any
change made by the utility subsequent to the integrated resource planning process.
Second, it could allow for game playing by the utility, as there are many
modifications that could be made simply to produce lower prices for the QF.
Case No. GNR-E- 11-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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Third, Idaho Power is proposing that any QF that has made a written inquiry
seeking avoided cost prices would be included as a contract or resource in the
proposed IRP method calculations. Undoubtedly, some of these inquiries would
not result in executed PPAs, and yet avoided cost prices would have been
calculated for other QFs based upon this faulty assumption. Yet, none of these
"inquiry-only" QFs will be used by Idaho Power in the preparation of its
subsequent IRP. All of these concerns are likely to result in numerous complaint
proceedings requiring Commission resolution under Idaho Power's proposed IRP
implementation method.
Q. WOULD LIMITED AVOIDED COST UPDATES BE ACCEPTABLE
BETWEEN TWO-YEAR IRPS?
A. Yes, updates should be allowed for two, and only two, factors. As I noted earlier,
a critical input in determining incremental costs in an AURORA simulation is
natural gas prices. Forward gas prices for up to 10 to 12 years can be tracked and
are readily obtainable from third-party providers such as NYMEX or ICE.
Accordingly, having a mandatory annual update to the published avoided energy
cost prices based on forecasts from one of these independent third party sources
would be acceptable. The annual gas price update should occur every twelve
months from the date Idaho Power's integrated resource plan is completed and be
based on the average forward prices from the prior month's trading days. For the
plan years that extend beyond the third-party forward period, the absolute change
in the monthly prices from the last reported year should be used for all subsequent
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Case No. GNR-E-1 1-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
859 Page 22of45

1 years to adjust the plan's value. As an example, if the most recent plan was

2 completed in June 2013, the utility would be required to provide revised avoided

3 cost prices by July 1, 2014 based upon the average forward prices from all trading

4 days occurring in May 2014. Assume the third party's forward price stream

5 ended as of December 2026. The updated plan values for 2027 and beyond would

6 be derived from taking the difference between the plan's monthly prices for 2026

7 and the third party's forward prices and applying this differential to the same

8 month for all subsequent plan years.

9 The second type of update to avoided cost prices that should be allowed is

10 for new QF PPAs. The very important distinction from Idaho Power's proposal is

11 that for the new QF to be considered as a change to the utility's IRP, it must have

12 executed a PPA with its associated obligations, as compared to the uncommitted

13 "queued" status Idaho Power has proposed. For published avoided costs, the QF

14 PPA update would be concurrent with the gas price update and would include all

15 QF PPAs that had been executed, and not included in, the most recently

16 completed integrated resource plan. For non-standard QF PPA price

17 development, all newly executed QF PPAs could be included in each successive

18 QF PPA simulation. Allowing these two very significant-- but also very limited

19 updates, should resolve a great deal of Idaho Power's pricing and contractual

20 commitment concerns.
21 Q. ARE THERE ANY ELEMENTS WHICH YOU BELIEVE HAVE BEEN

22 IMPROPERLY OMITTED FROM IDAHO POWER'S PROPOSED IRP

23 AVOIDED ENERGY PRICING METHOD?
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
860 Page 23of4S
A. Yes. I believe carbon costs should be included in the avoided energy prices and it
must be clearly stated that under the IRP method any and all environmental
attributes ("EAs") are retained by the seller.
Q. WHAT ARE IDAHO POWER'S STATED REASONS FOR EXCLUDING
CARBON COSTS FROM THE AVOIDED ENERGY PRICE
CALCULATIONS?
A. Idaho Power claims there is uncertainty in what this future cost may be and that
the cost does not exist today.
Q. WHY DO YOU DISAGREE WITH THIS REASONING?
A. There are several reasons. First, in the 2011 Plan, Idaho Power has included its
best estimate of carbon costs. The 2011 Plan assumptions are that carbon costs
could exist in 2015 and be $20 per ton escalating at 5% per year. Idaho Power
explains the basis of the inclusion as follows:
The purpose of the carbon adder is to account for all of the
costs in the price of energy produced by carbon-emitting
resources. (2011 IIRP, page 73)
Avoided costs prices should include all cost elements as well. While I
acknowledge that there is greater uncertainty regarding the exact year for national,
state or region wide, carbon legislation, all utility resource plans I have seen
assume it will occur. As Idaho Power has included this cost in its resource
selection process as well, it should do the same for deriving avoided energy prices
using the carbon cost assumptions from the utility's latest resource plan.
Second, it is patently unfair for a utility such as Idaho Power to exclude
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
861 Page 24of4S
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significant cost elements simply because it claims there is uncertainty about the
cost level and the expected date of implementation. The uncertainty regarding
exact price level knowledge exists in other major avoided cost elements such as
projected coal and gas prices. It is unlikely that Idaho Power can say with virtual
certainty what its exact fuel cost for the Bridger coal plant will be in 2015 but it
has assumed a value in its proposed IRP avoided cost pricing method based upon
its best available estimate. This same best estimate approach should be used to
include carbon costs in the avoided energy prices.
Third, under either the current or proposed Idaho Power IRP pricing
methods, carbon resources are on the margin the vast majority of the time. To
ignore carbon costs would have a significant impact on the resulting avoided
energy prices. The following table illustrates this impact under Idaho Power's
current and proposed IRP methods.
Comparison of 20-Year Levelized Energy Costs
($/MWh)
IPC Current IPC
Current IRP
IRP w/Carbon
Resource Type Method Costs Difference
Baseload $49.96 $63.57 $13.61
Canal Drop $47.27 $60.90 $13.63
Solar $48.33 $62.00 $13.67
Wind $41.60 $56.16 $14.56
The source for the values under the column entitled "IPC Current IRP Method" is
Idaho Power's Exhibit 8 while the source for the values under the column labeled
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Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
862 Page 25of4S
I "Current IPC JRP w/Carbon Costs" come from Idaho Power's response to Staff
production request no. 12. The energy values in both columns include the
3 integration cost adjustment. As would be expected, the inclusion of carbon costs
4 increases the avoided energy costs by 27 to 35%, a substantial amount.
5 Q. PACIFICORP WITNESS PAUL CLEMENTS RECOMMENDS THAT
6 WHEN A QF SELLS RENEWABLE POWER TO A UTILITY, THE
7 ENVIRONMENTAL ATTRIBUTES, INCLUDING RENEWABLE
8 ENERGY CREDITS, SHOULD TRANSFER TO THE UTILITY, ALONG
9 WITH THE POWER. DO YOU AGREE?
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A. Absolutely not. There are two critical reasons why the EAs should stay with the
developer. First, as was just discussed, the IRP pricing method is based upon the
incremental cost of a host of resources the vast majority of which are carbon
emitters being either gas or coal fired resources. None of the utilities in this case
are proposing to determine avoided costs based on the full cost of surrogate
renewable resources with EAs. As such, consistency and equity requires any
environmental attribute rights that are not being paid for should stay with the QF.
Second, FERC has been very clear that avoided cost rates are not intended to
compensate the QF for more than capacity and energy. In FERC Docket No.
EL03 -133 FERC stated the following with regard to renewable energy credits or
similar tradeable certificates ("RECs"):
21 23......What is relevant here is that the RECs are
22 created by the States. They exist outside the
23 confines of PURPA. PURPA thus does not address
24 the ownership of RECs. And the contracts for sales
25 of QF capacity and energy, entered into pursuant to
26 PURPA, likewise do not control the ownerships of
27 RECs (absent an express provision in the contract).
L--]
Case No. GNR-E-1 1-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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States, in creating RECs, have the power to
determine who owns the REC in the initial instance,
and how they may be sold or traded; it is not an
issue controlled by PURPA.
24. We thus grant Petitioner' petition for a
declaratory order, to the extent that they ask the
Commission to declare that contracts for the sale of
QF capacity and energy entered pursuant to
PURPA do not convey RECs to the purchasing
utility (absent an express provision in a contract to
the contrary). While a state may decide that a sale
of power at wholesale automatically transfers
ownership of the state-created RECs, that
requirement must find its authority in state law, not
PURPA. (see EL03-133, Order issued October 1,
2003, paragraphs 23 and 24)
As Idaho does not have a state renewable portfolio standard and FERC has stated
that PURPA pricing does not include a value for EAs, this Commission should
clearly state that the published standard prices do not compensate the seller for
any EAs and that the rights to the EA remain the QF's.
Q. PLEASE SUMMARIZE YOUR RECOMMENDATIONS WITH RESPECT
TO DETERMINING AVOIDED ENERGY PRICES.
A. Properly implemented, published avoided energy costs could be determined using
either a surrogate resource or an integrated resource plan method. However, if an
IRP method is to be used, it should be done: 1) using a third-party production
simulation model such as AURORA, but not an in-house model such as
PacifiCorp's GRID, 2) the energy cost should be based on the difference between
the two computer simulations ("QF-in/QF-out"), 3) no "post processing"
calculations such as proposed by Idaho Power should be allowed, 4) between
integrated resource plan periods mandatory annual scheduled updates should be
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
864 Page 27of4S
done to incorporate current forward gas prices from a third party source and
additional executed QF PPAs but no other changes should be allowed, 5) carbon
costs should be included in the computer simulations consistent with the latest
utility integrated resource plan assumptions, and 6) based on the IRP method and
consistent with FERC rulings, all EAs, such as renewable energy certificates, are
retained with the QF.
Q. HAVE YOU PREPARED A COMPARISON SHOWING THE IMPACT OF
YOUR AVOIDED ENERGY COST RECOMMENDATIONS AS
COMPARED TO THE COMPANY'S IRP PROPOSAL?
A. No, but I believe a reasonable approximation can be made using Idaho Power's
responses to Staff Production Request Nos. 12 and 13. These responses compare
Idaho Power's existing IRP method, including carbon costs, with the proposed
method. This table shows a substantial difference of 34-57% in the resulting
avoided energy costs. What cannot be shown in the table is the updating process
which would incorporate the latest gas price information and the impact of
additional executed QF PPAs as the method is implemented over time.
Comparison of 20-Year Levelized Energy Costs
($IMWh)
Current IPC
IPC IRP
Proposed w/Carbon
Resource Type IRP Method Costs Difference
Baseload $43.82 $63.57 $19.75
Canal Drop $45.45 $60.90 $15.45
Solar $40.99 $62.00 $21.01
Wind $35.86 $56.16 $20.30
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Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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Q. HAVE YOU REVIEWED IDAHO POWER'S PROPOSALS FOR
CALCULATING AVOIDED CAPACITY COSTS?
II A. Yes. Idaho Power is proposing to continue to use its load resource balance
position based on existing and committed resources as a trigger for including the
cost of capacity in the avoided cost payments. Based on this approach, Idaho
Power is not reflecting capacity costs until July 2016 in its illustrative examples in
this proceeding. However, Idaho Power is proposing to use a different resource to
determine the capacity value. While Idaho Power has been using a CCCT, it is
now proposing to use a SCCT for the capacity cost. The difference is significant
as Idaho Power states its integrated plan shows a CCCT capital cost of $1,380/kW
and a SCCT cost of only $790/kW. As shown by Idaho Power's Exhibit 8 and the
below table, this resource change reduces the capacity related payments by 44-
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45% for each of the illustrative technologies.
Comparison of 20-Year Levelized Capacity Payments
($/MWh)
Resource Current Proposed
Type CCCT SCCT Delta Reduction
Baseload $15.04 $8.27 -$6.77 -45%
Canal $33.04 $18.18 -$14.86 -45%
Solar $27.27 $15.16 -$12.11 -44%
Wind $1.48 $0.82 -$0.66 -45%
Q. DO YOU AGREE WITH IDAHO POWER'S PROPOSAL TO USE A SCCT
TO DETERMINE AVOIDED CAPACITY COSTS?
A. Yes. The appropriate avoided resource is dependent upon the particular needs of
the utility including the existing resource mix and load shape. The peak hour
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
866 Page 29 of 45
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monthly load and resource balance tables in Idaho Power's 2011 Plan show
substantial monthly surpluses in the non-summer months (October through May)
in each year of the planning horizon. The historical monthly peak loads from
2006 - 2010 of Idaho Power also indicate the relative sharp four-month seasonal
load shape. Further evidence is provided by the loss of energy study conducted
by the utility which indicates a non-zero probability of unserved energy occurring
only during the four summer months. These factors, coupled with the need to
integrate variable resources into the system on a real time basis, make a SCCT the
correct avoided resource at this time for Idaho Power. (It is important to note that
I am not recommending changes to Avista's or PacifiCorp's avoided capacity
resource.)
Q. DO YOU AGREE WITH IDAHO POWER'S PROPOSAL TO NOT
INCLUDE AVOIDED CAPACITY COSTS IN DERIVING AVOIDED
COST PRICES UNTIL THERE IS A SYSTEM NEED?
A. I agree with the concept for a new QF but I disagree in how it should be
determined. As previously noted, Idaho Power relies on a negative July deficit
from its latest integrated resource plan to trigger the inclusion of capacity costs.
Based on the 2011 Plan, Idaho Power started including capacity costs in its
avoided cost rate calculations in July 2016. In my view, this is a far too restrictive
test and is readily subject to gaming. To illustrate my concerns, the 2011 Plan
shows July peak deficits in years 2014 and 2015. In the case of 2014, the deficit
is only 1 MW while in 2015, the July deficit is 80 MW. The 2011 Plan shows a
2015 eastside purchase of 83 MWs just for the month of July in order to eliminate
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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the apparent capacity deficit. The possibility for Idaho Power to insert a one
month purchase to prevent a triggering of capacity costs and payments to QF is
troubling.
Idaho Power's loss of load analysis included in the 2011 Plan is much
more illustrative and a better benchmark or measuring tool with regard to capacity
needs. Idaho Power correctly notes that the industry standard for these types of
analysis is to plan for no more than a one day in ten year loss of load. Idaho
Power equates this metric to being "roughly equivalent to 0.5 to 1.0 hours per
year." (See 2011 Plan, page 119). The Idaho Power loss of load expectation
study ("LOLE Study") shows the following expected loss of load hours:
LOLE Study
(Preferred Portfolio)
Year Hours
2012 0.62
2013 1.54
2014 1.65
2015 1.92
This analysis indicates or suggests additional capacity is needed well before July
2016 in order to meet the industry reliability standard. It also demonstrates the
game that can be played, in assuming a one-month contract purchase during a
peak summer month, and its effect of deferring into the following year a QF
capacity purchase obligation.
Utility resource additions are recognized as having a certain "lumpiness"
that does not allow for a precise matching of resource size to need. This can be
illustrated with the planned 450 MW capacity addition from the Boardman to
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition

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Hemingway transmission addition. After this sizable addition, Idaho Power's
peak load resource balance studies show a July surplus for the next four years.
Under Idaho Power's proposed short contract term, a new QF that executed a 5
year contract for deliveries in 2013 - 2017 would receive capacity payments for
just the last eighteen months of the contract (2016 and 2017). Now due to the
lumpiness of the resource addition, the QF' s follow-on 5 year contract for 2018 -
2022 would only reflect capacity payments in the last eighteen months once again
due to the July surplus caused by the transmission addition. It is highly likely that
a new QF would ever receive five years of capacity value over each and every
successor contract under Idaho Power's capacity triggering proposal. The
capacity provided by the QF would continually be displaced or "bumped out" of
the resource need stack by any other resource addition subsequent to the PPA
execution date.
A QF with an expiring PPA has this exact same issue and concern. For
example, there are several QF PPAs that expire in 2017 and 2018 that had initial
contract terms of 35 years. These resources have not caused the projected short-
term surplus and should not be penalized in the form of reduced capacity value
payments in a subsequent follow-on PPA. Existing QFs entering into follow-on
PPAs or contract extensions should be provided full avoided cost capacity value
each and every year. To not provide capacity payments to these resources in
follow-on contracts would be inequitable as compared to the treatment afforded
utility-owned resources.
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Q. HOW CAN THIS SITUATION BE PREVENTED?
A. The best solution is to offer 20 year QF contract terms as I have recommended so
that after a relatively short surplus period, the new QF will receive capacity value
for all remaining contract years. If the Commission instead approves Idaho
Power's five-year maximum contract term, the Commission should provide full
capacity payments to all QFs in follow-on PPAs and need cannot be used as a
reason to deny a follow-on PPA.
Q. WHAT IS YOUR RECOMMENDATION FOR A REASONABLE
CAPACITY PAYMENT TRIGGER?
A. I recommend that instead of using a one-hour July peak trigger, the results from
the Idaho Power LOLE Study should be used. Specifically, avoided capacity
costs should be included in the avoided cost prices to QFs in the first year the
LOLE Study produces a probability equal to or greater than 0.75 hours.
Q. WHY ARE YOU RECOMMENDING THE LOLE STUDY RESULTS BE
USED FOR TRIGGERING CAPACITY PAYMENTS?
A. It is a more complete analysis by taking into account all hours of the year and in
particular all peak summer months. Idaho Power's approach places far too much
weight on a single peak hour.
Q. WHY ARE YOU RECOMMENDING A VALUE OF 0.75 HOURS?
A. It is the mid-point under Idaho Power's analysis that equates to the industry
standard of having sufficient capacity such that there will not be a loss of load
exceeding a one-day-in-ten-year probability.
Q. HOW IS IDAHO POWER PROPOSING TO REFLECT THE AVOIDED
Case No. GNR-E-1 1-03 Schoenbeck, Di
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Renewable Energy Coalition
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I CAPACITY COSTS IN THE PUBLISHED PRICES?

A. Idaho Power is proposing to include avoided capacity costs beginning with the

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first month where the integrated resource plan shows a monthly deficit. Idaho

4 Power is proposing that avoided capacity costs be paid over each and every hour

5 (on-peak and off-peak periods) of every month. This can be seen by reviewing

6 Idaho Power's response to Staff production request no. 15. The attachment shows

7 the step-up in the heavy (on-peak) and light (off-peak) load prices occurring in

8 July 2016.
9 Q. DO YOU AGREE WITH THIS APPROACH?

10 A. No. First, while capacity value may not be provided in each and every year of a

11 PPA due to Idaho Power having sufficient capacity in the early years, the capacity

12 value should be levelized over all years of the PPA. This levelization will hold
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rate payers harmless over the contract term but allow the QF larger upfront
payments when its investment is at its highest level. This is essentially no
different than the rate base treatment afforded a utility owned resource whereby
the revenue requirement associated with the return on the investment is at its
highest level at the start of commercial operation. Second, providing the same
capacity value in every month and every hour makes little sense for Idaho
Power's system. This is readily apparent from reviewing the monthly peak load
and resource balance tables in the 2011 Plan. Other than the summer months,
Idaho Power has substantial amounts of excess capacity. For Idaho Power, the
avoided capacity costs should be assigned and paid over the heavy load hours of
Case No. GNR-E-1 1-03 Schoenbeck, Di
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Renewable Energy Coalition
871 Page 34of4S
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1 the summer season when the capacity is needed. This should be done by
calculating a $fkWh amount for each QF type based on the expected heavy load
3 hour deliveries during the four summer months or through the establishment of a
4 separate $/kW value as is being proposed by Avista.
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IV. OTHER IDAHO POWER TERMS AND CONDITIONS
Q. HAS IDAHO POWER MADE ANY OTHER PROPOSALS THAT WOULD
IMPACT QFS IN THIS PROCEEDING?
A. Yes. First, Idaho Power has proposed that a standard negotiating and contracting
process be established by the Commission. Second, the Company asks that it be
given the authority to curtail deliveries from QFs under proposed Schedule 74
(Idaho Power Exhibit No. 5) for operational reasons.
Q. WHAT IS IDAHO POWER'S PROPOSAL FOR STANDARDIZING THE
NEGOTIATING PROCESS?
A. Idaho Power has not provided a specific proposal on the structure of the process
or all the issues it might address. In response to Staff production request no. 3
regarding the proposal, Idaho Power noted that PacifiCorp's proposed Schedule
38 may be a good starting point but that adjustments to it will likely be required
based on the Commission decisions in this phase of the proceeding. The response
further states that Idaho Power will be submit a proposed tariff later in this
proceeding.
Q. DO YOU AGREE THAT STANDARD CONTRACTING TERMS AND
PROCEDURES SHOULD BE DEVELOPED TO FACILIATE THE QF
CONTRACTING PROCESS WITH IDAHO POWER?
Case No. GNR-E-1 1-03
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1 A. Yes. As I previously noted, transaction costs for small QFs can act as a barrier for
project development. Transaction costs can be minimized by having standard

3 prices, term and conditions for deliveries along with a clear stated time table for

4 the QF contracting process.
5 Q. HOW WOULD YOU RECOMMEND THIS BE ACCOMPLISHED?

6 A. I recommend the Commission order a collaborative workshop process for the

7 utilities and interested parties to develop the necessary contracts and any needed

8 tariffs after the Commission's ruling in this phase of the proceeding. The process

9 should attempt to resolve as many issues brought by the participants as possible.

10 Any issues that cannot be resolved among the parties could then be brought

11 before the Commission or an agreed upon decision maker for resolution.
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Q. PLEASE SUMMARIZE IDAHO POWER'S PROPOSAL TO CURTAIL
QFS UNDER SCHEDULE 74.
A. Idaho Power is seeking Commission approval to impose curtailments on QFs that
have a nameplate capacity greater than or equal to 10 MW or more and also have
generator output limiting controls ("GOLCs") when it is experiencing "must run
periods." Idaho Power is proposing to define must run periods as:
Those periods when the Company's system load
demand in the upcoming hours and days requires
that sufficient Base Load Resources will be on-line
and available to serve system load. (See proposed
Schedule 74)
Idaho Power is proposing to define "Base Load Resources" as:
Company-owned hydroelectric resources, including
all run-of-river generators and the Hells Canyon
Complex, coal-fired generating resources (Jim
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
873 Page 36of45
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I Bridger generating plant, Valmy generating plant,
. 2 and the Boardman generating plant), and the

3 Langley Gulch power plant. (See proposed

4 Schedule 74)

5 Idaho Power describes the possible need to curtail as follows:

6 The Company may curtail the generation of an

7 applicable QF during Must Run Periods if, due to

8 operational circumstances, purchases from the

9 applicable QF would require the Company to

10 dispatch higher cost, less efficient resources to

11 serve system load or to make Base Load Resources

12 unavailable for serving the next anticipated load.

13 (See proposed Schedule 74)
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Q. SHOULD THE COMMISSION APPPROVE IDAHO POWER'S
PROPOSED SCHEDULE 74?
A. No. There are several reasons why the proposed schedule should not be
approved. First, it unilaterally modifies otherwise negotiated and existing
contractual rights. Second, Idaho Power presents a very misleading picture of
FERC's rulings regarding operational curtailment rights. Finally, Idaho Power
mischaracterizes Langley Gulch as a must-run base load resource, which it is not.
Schedule 74 would give Idaho Power the unilateral right to curtail QFs
under existing contracts where no such provision has been included in the
contract. It seems patently unfair for Idaho Power to seek to impose a tariff that
is, in effect, a significant and adverse contractual modification. While many of the
QF generation interconnection agreements ("GIAs") require the QF to install
generator output limit controls (GOLCs) at their facilities, the same GIAs restrict
Idaho Power's ability to actually limit a QFs generation through GOLCs to
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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contingency and reliability events. Schedule 74 would now expand the
Company's use of GOLCs to also include interruptions for essentially economic
dispatch reasons. If Idaho Power wants the right to dispatch QFs, it should have to
negotiate PPAs that contain these rights, and compensate the QFs for this
dispatch.
The Idaho Power testimony also asserts there have been two state
commissions that have implemented the FERC "rule"—Florida and Nevada. In
the case evolving the Nevada commission, Idaho Power asserts the
implementation was due to the "direct result of the authority given to the Nevada
PSC by the FERC rule." (See Park, page 17). Idaho Power Exhibit No. 4 is the
resulting procedure for curtailing three QFs: Saguaro Power Company, Nevada
Cogeneration Associates 1 ("NCA 1") and Nevada Cogeneration Associates 2
("NCA 2") (collectively, "Nevada QFs"). I am familiar with the contract terms of
NCA 1 and NCA 2 as RCS was asked to provide an opinion report on the possible
purchase of these facilities by Texaco, now Chevron, from Bonneville Nevada
Corporation in 1990. Our analysis included a review of the two long-term power
purchase agreements for NCA 1 and NCA 2 with Nevada Power Company.
These contracts contain a specific provision that allows for curtailment based on
operational circumstances up to a specified number of hours. Exhibit No. 4
should be viewed for what it truly is. At the time it was issued by the Nevada
commission, it established the conditions and procedure by which Nevada Power
.
Case No. GNR-E-1 1-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
875 Page 38of45
would implement the curtailment rights for all the Nevada QFs in an equitable
manner. It was issued in response to complaint proceedings brought by the
Nevada QFs due to disputes arising over utility requests for curtailment made
during 1993. The disputes continued for several years even after the initial
complaint proceedings.
Idaho Power's brief reference to the Florida commission ruling does not
provide a complete picture of that decision. A critical Idaho Power omission is
the fact the utility's actions prior to seeking QF curtailments must include
"maximizing economic off-system sales" and that the utility had negotiated
curtailment provisions with "many of the QFs." Consequently, when it is
necessary to curtail QFs, the curtailments are to be sequenced from three groups.
The first QF group consists of QFs having PPAs with curtailment provisions. The
second QF group consists of "as-available" QFs and finally, the third group, if
needed, are firm QFs. Finally, the utility must still pay the QF the avoided
capacity rate during the curtailment periods. None of these provisions are
elements contained within Idaho Power's Schedule 74 proposal.
The existing Idaho Power QF PPAs I have reviewed do not contain
operational or economic curtailment provisions. Accordingly, Idaho Power's
request to unilaterally change the contractual terms by implementing Schedule 74
should not be approved by the Commission.
Q. HOW HAS IDAHO POWER NOT PRESENTED A COMPLETE
EXPLANATION OF FERC'S CURTAILMENT POSITION?
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
876 Page 39of45
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A. The Idaho Power testimony provides a very brief paraphrased comment on
FERC's recent December 15, 2011 ruling in Docket Nos. ER05-1065-01 1 and
0A07-32-008 ("Entergy Order"). The complete pertinent paragraphs from the
ruling state:
53.Exemptions to the statutory QFpurchase obligation
are limited. First, a utility can be relieved of its QF
purchase obligation under section 201(m) of PURPA, 16
U.S. C § 824a-3(m) (2006). This provision is not at issue
here, as Entergy has not claimed relief under section
210(m), nor filed a petition seeking relief.
54.Second, section 304(f)(1) of the Commission's
PURPA regulations, 18 C.F.R § 292.304(f)(1) provides,
with certain limitations, that a utility is not required to
purchase unscheduled QF energy "during any period
during which, due to operational circumstances, purchases
from qualifying facilities will result in costs greater than
those which the utility would incur if it did not make such
purchases, but instead generated an equivalent amount of
energy itself" Entergy argues that this provision entitles it
to curtail unscheduled QF energy purchases whenever
Entergy has exhausted the cost-neutral redispatch options
available to accommodate the purchase. However, section
292.304(f) provides for afar more limited exception to the
P URPA purchase obligation than Entergy claims.
55.In Order No. 69, which implemented section 304(f),
the Commission stated that that section was intended to
deal with a certain condition which can occur during light
loading periods, in which a utility operating only base load
units would be forced to cut back output from the units in
order to accommodate the unscheduled QF energy
purchases. The Commission stated that such base load
units might not be able to later increase their output levels
rapidly when the system demand later increased, resulting
in the utility needing to rely upon less efficient, higher cost
units. Section 304(f), when read in conjunction with the
relevant explanation in Order No. 69, applies only to such
.
Case No. GNR-E-1 1-03
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1 low loading scenarios, and cannot be relied upon to curtail

2 purchases of unscheduled QF energy for general economic

3 reasons.

4 56 Many avoided cost rates are calculated on an

5 average or composite basis, and already reflect the

6 variations in the value of the purchase in the lower overall

7 rate. In such circumstances, the utility is already

8 compensated, through the lower rate it generally pays for

9 unscheduled QF energy, for any periods during which it

10 purchases unscheduled QF energy even though that

11 energy's value is lower than the true avoided cost. On the

12 other hand, for avoided cost rates that are determined in

13 real-time, such avoided costs adjust to reflect the low (or

14 zero or negative) value of the unscheduled QF energy,

15 allowing the QF to make its own curtailment decisions. In

16 neither case is the utility authorized to curtail the QF

17 purchase unilaterally. (Footnotes omitted)
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A review of all the above paragraphs provides a different perspective on FERC' s
view on curtailing QF deliveries from that asserted by Idaho Power. Paragraphs
55 and 56 are particularly important. Paragraph 55 states that the utility must be
operating only base load units and that they would be "forced to cut back output."
Paragraph 56 notes that avoided costs are generally determined taking into
account the time value of purchases. By employing production simulation models
such as AURORA, the economic dispatch of the system, including during light
load hours, has already been taken into account in deriving the avoided cost
prices. In this circumstance, FERC states the utility has already been
compensated through the lower avoided cost payment for these periods.
An even handed reading of these FERC statements shows Idaho Power
Schedule 74 is not consistent with FBRC's view on QF curtailment. First,
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
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Renewable Energy Coalition
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Langley Gulch would not be a base load resource as FERC is using that term.
FERC is referring to thermal resource that may not be able "to increase their
output levels rapidly." Langley Gulch can go from 0 to 150 MW in ten minutes.
This is certainly not the ramp rate FERC was assuming in terms of a base load
resource. In fact, the manufacture, Siemens, markets the Langley Gulch "flex
plant" configuration as the "best solution for peaking to intermediate duty
dispatch." Second, Idaho Power has not shown that it would be forced to cut back
its base load resources under Schedule 74. While Idaho Power may be in a
legitimate minimum load condition, surrounding service territories or balancing
areas may not be. Idaho Power may be able to execute a sale to another entity
instead of curtailing a legitimate base load resource. Finally, under Idaho Power
proposed IRP method, it has already included a zero price for QF deliveries
during minimum load conditions. To now also curtail the QF is the precisely the
double penalty FERC pointed out in paragraph 56 of the Entergy Order as being
inappropriate. For all these reasons, Idaho Power's Schedule 74 should be
rejected by the Commission. It is a poorly disguised effort to impose economic
curtailment on QF deliveries.
V. AVISTA AND PACIFICORP CONTRACTING MATTERS
Q. HAVE AVISTA OR PACIFICORP RAISED ISSUES YOU WOULD LIKE
TO ADDRESS?
A. Yes. Avista is proposing several issues that need to be addressed regarding
standard contract terms if they are to be decided in this contested proceeding as
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
879 Page 42of45
0

1 opposed to a collaborative workshop process. These issues are: 1) how soon
before commercial operation can a QF execute a PPA, 2) when will the PPA

3 prices be set, 3) liquidated damage provisions and 4) utility termination rights.
4 Q. WHAT IS AVISTA'S PROPOSAL FOR HOW SOON A PPA CAN BE

5 EXECUTED PRIOR TO COMMERCIAL OPERATION?
6 A. Avista is proposing that once a QF has executed a PPA, it must be commercially

7 operable within five years. This is a reasonable amount of time subject to the

8 occurrence of a force majeure event. Force majeure events that are beyond the

9 control of either party should allow for an extension beyond the five year window.

10 With this understanding, the QF Companies would support Avista's

11 recommendation.
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Q. WHAT IS AVISTA'S PROPOSAL REGARDING WHEN THE PPA
PRICES WOULD BE SET?
A. Avista is proposing that the PPA prices would not be locked-in until just two
years prior to commercial operation.
Q. IS THIS AN ACCEPTABLE PROPOSAL?
A. Absolutely not. This proposal is totally impractical. As the CAISO analysis
noted, California, and by extension the west coast, market prices cannot sustain
the development of new generating resources. A long-term contract is required in
order to ensure reasonable cost recovery. The PPA prices must be known and
"bankable" at the time of PPA execution. No new QF developer or owner would
be willing to invest the time and money to permit and construct a new facility if
the contract prices have not been locked-in. The Commission should reject
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
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Renewable Energy Coalition
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Avista' s proposal to only lock in the prices just two years before commercial
delivery.
Q. WHAT IS AVISTA'S LIQUIDATED DAMAGE PROPOSAL?
A. Avista is proposing that all QF PPAs have liquidated damage deposit provisions
set at $45 per kilowatt of installed capacity when the PPA is executed.
Q. WHAT ARE YOUR VIEWS ON THIS PROPOSAL?
A. If the Commission is going to decide this issue now, instead of it being discussed
later in a workshop format, then I would offer another option for a more accurate
tie between liquidated damages and a particular type of QF or generating profile,
instead of the proposed flat $/kW assessment.
The crux of the issue, as correctly noted by Avista, is non-performance by
the QF thereby requiring the utility to procure replacement energy at perhaps a
higher price than the QF PPA. This issue can be readily and fairly dealt with
through a mark-to-market liquidated damage option. At the time of PPA
execution, the QF could elect to post a fixed $/kW amount or an amount based
upon the difference between the contract revenue payments and forward power
prices for a period of three years starting at the expected commercial operation
date. Under this mark-to-market option, updates would also have to occur to
capture forward price movements. I recommend these updates be required once
every three months (every calendar quarter) to ensure adequate security has been
posted by the QF throughout the licensing and construction period. With this
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1 additional liquidated damage option, the QF Companies would support the
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2 inclusion of liquidated damage provisions in all QF PPAs.
3 Q. WHAT UTILITY TERMINATION RIGHT IS AVISTA PROPOSING?
4 A. Avista is proposing that a utility may terminate a QF PPA if it has missed its
5 schedule commercial operation date by 180 days.
6: Q. IS THIS A REASONABLE CONDITION?
7 A. Yes, as long as the delay is not due to a force majeure event. With this
8 understanding, the QF Companies would support Avista's termination
9 recommendation.
10 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
11 A. Yes.
S
Case No. GNR-E-1 1-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
882 Page 45of45
A
1 PREFILED REBUTTAL TESTIMONY OF
2 DONALD W. SCHOENBECK
3 I. INTRODUCTION AND SUMMARY
4 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
5 A. My name is Donald W. Schoenbeck. I am a member of Regulatory &
6 Cogeneration Services, Inc. ("RCS"), a utility rate and economic consulting firm.
7 My business address is 900 Washington Street, Suite 780, Vancouver, WA 98660.
8 Q. HAVE YOU PREVIOUSLY SUBMITTED TESTIMONY IN THIS
9 PROCEEDING?
10 A. Yes. I provided direct testimony in this proceeding on behalf of Northside Canal
11 Company, Twin Falls Canal Company and Renewable Energy Coalition
12 (collectively, "QF Companies"). This rebuttal testimony is being submitted on
13 behalf of these same companies.
14 Q. WHAT TOPICS WILL YOUR TESTIMONY ADDRESS?
15 A. Following this introduction and summary, my rebuttal testimony is organized in
16 three sections. First, I will address matters where I have altered or modified the
17 recommendations set forth in my direct testimony from having reviewed the
18 prefiled direct testimony and subsequent discussions with other parties in this
19 proceeding. These issues have to do with the source of gas prices for use under
20 the SAR and IRP methods, allowable updates under the IRP method and avoided
21 capacity cost. The next section of this testimony will address issues where my
22 position has not changed even after reviewing other party's thoughts on certain
23 matters. These issues have to do with contract term, REC ownership, the
24 eligibility cap for fixed price contracts and Idaho Power's proposed Schedule 74.
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Finally, in the last section, I discuss an issue raised by another party that I had not
addressed in my direct testimony. Specifically, Dr. Reading's proposal with
regard to transmission network upgrades.
Q. PLEASE BRIEFLY SUMMARIZE YOUR RECOMMENDATIONS
ADDRESSED IN THIS TESTIMONY.
A. First, regarding modifications to my prior direct testimony, I recommend the
following:
The Energy Information Administration's Annual Energy Outlook ("ETA
AEO") forecast should be used as the source of gas prices under the SAR
method and for any updates under the IRP method.
In addition to gas prices and QF contracts, updates to the IRP method can
include newly executed non-QF contracts with a term of at least five years
and known customer specific load changes that in aggregate are at least 25
MWs.
Avoided capacity cost recognition and pricing can be done as set forth in
Staffs revised updated avoided cost EXCEL spreadsheet model
("Updated Avoided Cost Model version 2.0").
Second, I disagree with Staffs direct testimony where Staff advocates the
following policy changes: (a) that the Commission authorize a maximum QF
contract term of just five years under the IRP method, (b) that the seller is
compensated for RECs under the IRP method, (c) that the eligibility cap for fixed
published rates be maintained at just 100 kWs for wind and solar projects, and (d)
Idaho Power's proposed QF curtailment tariff, Schedule 74, should be approved.
For the reasons set forth in my direct testimony, and as further explained in this
rebuttal testimony, the Commission should not adopt any of these proposals. I re-
affirm my direct testimony in advocating that contracts should be offered for up to
twenty years under either pricing method, REC ownership should be retained by
884
Donald W. Schoenbeck Page 2 of 14
I the seller, the eligibility cap for fixed published prices should be 10 MW for all
2 resource types and Schedule 74 should not be approved by the Commission.
3 Finally, Dr. Reading's testimony recommends that a QF be entitled to full
4 recovery of construction contributions paid by the QF for network transmission
5 upgrades. The QF Companies fully support Dr. Reading's recommendation on
6 this issue.
7 II. MODIFIED RECOMMENDATIONS
8 Q. HAVE YOU REVIEWED THE DIRECT TESTIMONY OF THE NON-
9 UTILITY PARTIES FILED IN THIS PROCEEDING IN MAY 2012?
10 A. Yes, Ihave.
11 Q. HAS THIS REVIEW ALTERED OR CHANGED ANY OF THE
12 RECOMMNEDATIONS SET FORTH IN YOUR DIRECT TESTIMONY?
13 A. Yes. From having reviewed and considered the prefiled direct testimony of Staff
14 and Dr. Reading and from having additional discussions with parties, I believe it
15 is appropriate to modify three recommendations I made in direct testimony
16 regarding the source of gas prices, what updates or changes should be allowed
17 under the IRP method and how avoided capacity costs should be determined and
18 priced.
19 Q. HOW DID THE PARTIES TESTIMONY INFLUENCE YOUR THINKING
20 WITH REGARD TO GAS SOURCE?
21 A. Both Staff witnesses and Dr. Reading proposed using prices from the EIA AEO as
22 had also been recommended by Avista under the SAR method, including any
23 updates. (See Dr. McHugh pages 3-5, Mr. Sterling page 8, Dr. Reading page 19
24 and Mr. Kalich page 34) Based upon my further discussions, I believe all these
25 parties are now in agreement that the specific price series to use would be the
885 Donald W. Schoenbeck Page 3 of 14
Mountain division series for electric power ("EIA Forecast") as detailed by Dr.
McHugh under the SAR method. (See Dr. McHugh page 5, lines 7-10). Given
this consensus and my review of this source, I agree that the ETA Forecast
achieves most of the objectives I was seeking in an independent third party source
and can be used to determine avoided cost rates.
Q. ARE THESE PARTIES IN AGREEMENT THAT THE EIA AEO SHOULD
BE USED FOR IRP UPDATES AS WELL?
A. No, I do not believe this is the case. Staff advocates that the utilities do not have
to use the ETA AEO (see Mr. Sterling page 23, lines 1-6) while Dr. Reading
appears to advocate that it could be used in the IRP update (see Dr. Reading page
26, line 15 to page 27, line 5). The Avista testimony did not specifically address
IRP gas price updates.
Q. WHAT IS YOUR RECOMMENDED SOURCE OR METHOD FOR AN
IRP GAS PRICE UPDATE?
A. I recommend the EIA AEO be used for IRP updates as well. I fully understand
and expect that the utility will use its preferred method for deriving gas prices for
its initial IRP filing. During the IRP development process, parties are generally
provided the opportunity to examine and comment on many inputs including the
gas price forecast. However, an IRP update does not allow for this opportunity.
Consequently, I believe the Commission should require that any TRP update
should use precisely the same gas price source as under the SAR update. Given
that any IRP update will be in place for only one or two years, use of an
independent third party source should not result in any rate payer harm while on
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the other hand it would eliminate any potential game playing by the utility
regarding this most critical input variable.
Q. WHAT DID YOUR DIRECT TESTIMONY RECOMMEND WITH
RESPECT TO ALLOWABLE IRP UPDATES?
A. My direct testimony recommended that only two items may be updated: the gas
price forecast and the inclusion of any newly executed QF PPAs.
Q. HAVE PARTIES PROPOSED INCLUDING OTHER ITEMS FOR
ALLOWABLE IRP UPDATES?
A. Yes. Staff is proposing that fuel price forecasts, load forecasts and any new long-
term purchase or sale contract obligation can be updated (see Mr. Sterling pages
22-25). More specifically, Staff is proposing that fuel prices and load forecasts
should be updated once per year and any new purchase or sale contract
commitments made at least one year in advance and at least one year's duration
should be included in an IRP update, whenever the commitment is made.
Q. WHAT ARE YOUR THOUGHTS REGARDING THE STAFF'S
ALLOWABLE UPDATE ITEMS?
A. I previously addressed my concern about allowing the utility to make updates
based on internally generated forecasts for items that have no impact other than to
greatly complicate the QF PPA negotiation process and allow for potential game
playing of the avoided cost determination. Under the Staff proposal, this could
readily happen by a utility lowering an internally generated coal price forecast or
load forecast in an IRP update. With regard to allowing non-QF purchase or sale
contract commitments in the update, I believe Staffs proposed inclusion of utility
wholesale purchase contracts with terms of such short duration does not allow a
utility to actually avoid capacity. For these reasons, I disagree with these aspects
Donald W. Schoenbeck 887 Page of 14
of Staffs update proposal. However, I am willing to recommend additional IRP
update items addressing both these areas as long as they can be readily verified
and not subject to any possible manipulation.
Q. WHAT ADDITIONAL ITEMS WOULD YOU RECOMMEND COULD BE
INCLUDED IN AN IRP UPDATE?
A. I recommend that customer specific known load changes of at least 25 MWs (up
or down) be included as well as any executed non-QF purchase or sale contract
commitments of at least 5 or more years in duration.
Q. WHY DID YOU SELECT 25 MWS AS THE VALUE FOR LOAD
CHANGES?
A. There were three reasons. First, it is the size of the standard market energy
trading amount. As such, this is at least one measure for considering it to be a
meaningful amount. The second reason has to do with the granularity with which
production simulation models can produce meaningfully different results. Very
modest load changes simply do not have a material impact on the result. Finally,
load changes of this magnitude could well be reported and widely known even
prior to the IRP update. This will facilitate the verification of the load change I
believe is critical to minimizing disputes over the IRP update.
Q. MUST THE KNOWN LOAD CHANGE BE JUST A SINGLE
CUSTOMER?
A. No. The 25 MW value can be an aggregated value from the departure, addition or
expansion of several customers but it must be known and measurable. It cannot
be a projection of load changes for a given customer class or sub-class from
updating typical load forecast input assumptions.
Donald W. Schoenbeck 888 Page 6ofl4
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Q. WHY DO YOU DISAGREE WITH THE STAFF PROPOSAL TO ALLOW
UTILITY WHOLESALE PURCHASES WITH A TERM OF JUST ONE
YEAR TO BE INCLUDED IN IRP UPDATES?
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A. Allowing such market-based wholesale purchases with short terms in the IRP
process does not eliminate the utility's need for capacity. PPAs with terms of just
one, two, three or even four years are shorter than the typical time it takes to plan
for and build a resource to meet a capacity deficit position. Consequently, the
only effect of including PPAs with this short of duration in the IRP update would
be to artificially lower the avoided capacity costs included in a QF PPA. This is
inappropriate. However, I must emphasize that the non-QF PPAs I am
recommending be allowed in the IRP update must be fully executed and have
received Commission approval.
Q. BASED ON THIS REASONING, WOULD YOU AGREE THAT QF PPAS
WITH TERMS LESS THAN FIVE YEARS DO NOT AVOID CAPACITY
EITHER?
A. Yes, I would, provided that the Commission elects a reasonable QF PPA contract
term in this proceeding. If non-QF power purchase contracts less than five years
duration are not included in the IRP calculation of avoided costs, and the
Commission requires utilities to sign QF contracts with terms up to 20 years, then
I agree that QF PPAs with terms less than five years should not receive any
avoided capacity payment or credit. On the other hand, if the Commission adopts
the Idaho Power and Staff proposals to limit the maximum contract term to just
five years, than avoided capacity costs should be included in the contractual
prices because the QF and the utility are limited to this restrictive term.
Q. HOW HAVE YOUR RECOMMNEDATIONS CHANGED WITH REGARD
TO AVOIDED CAPACITY COST ALLOCATION AND PRICING?
Donald W. Schoenbeck 889 Page 7 of 14
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A. I believe that my recommendations to determine capacity need, allocation and
pricing based on the results of a loss of load or unserved energy analysis is
analytically superior to the existing methods employed by the utilities and Staff.
However, I am readily aware that the results from such a probabilistic "black box"
simulation can be subject to and sensitive to certain critical assumptions used in
the analysis including inter-balancing area market availability. In addition, from
discussions with Staff, including the examination of Staffs revised avoided cost
EXCEL spreadsheet model ("Updated Avoided Cost Model version 2.0"), my
primary concern with Staff's avoided capacity need determination has been
addressed. Accordingly, I find Staffs revised model a simple, transparent and
straightforward approach to determine capacity need, allocation and pricing.
III. NO CHANGES TO PRIOR RECOMMENDATIONS
13 Q. HAS YOUR REVIEW OF SOME OF THE PARTIES' TESTIMONY
14 IDENTIFIED AREAS OF SIGNIFICANT DISAGREEMENT WITH YOUR
15 DIRECT TESTIMONY?
16 A. Yes. Staff has accepted four utility proposals which I continue to oppose. These
17 are: (i) that IRP priced contracts be limited to a maximum term of just five years,
18 (ii) that RECs are deemed transferred to the purchasing utility under the IRP
19 method,(iii) that a fixed price eligibility cap of just 100 kW apply to wind and
20 solar resources, and (iv) that Idaho Power's proposed Schedule 74 for curtailment
21 of QF generation be adopted. In large part, I have addressed the reasons why
22 each of these proposals is inequitable, inappropriate and unfair in my direct
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testimony. I will limit my rebuttal testimony to specific points raised by Staff that
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I did not previously address.
Donald W. Schoenbeck
BOB
Page 8 of 14
I Q. WHAT COMMENTS DO YOU HAVE WITH REGARD TO STAFF'S
S 2 MAXIMUM FIVE YEAR CONTRACT TERM FOR IRP BASED
3 CONTRACTS?
4 A. I find Staff's proposal to allow a maximum 20 year contract term under the SAR
5 based method but only a maximum five year term under the IRP based method
6 quite troubling. As stated in my direct testimony, a 20 year term is fair and
7 appropriate. A five year term is not. It appears the crux of Staff's proposal is that
8 the IRP contract term should be used "to control the pace ofPURPA
9 development" as set forth on page 29 of Mr. Sterling's testimony. Staff claims
10 this control is needed because the power "is not needed to serve customers" and
11 the depressed economy "strain customers' ability to pay." Of course, we are all
12 sympathetic to the economic woes the Pacific Northwest has been experiencing
13 for some time. However, Staff must acknowledge that avoided costs are set such
5 14 that the ratepayer is indifferent as to whether the power came from a QF PPA or
15 the alternative resource.
16 Staff's testimony does state that when the Commission had previously
17 imposed a maximum contract term of just five years from September 1996 to May
18 2002, QF development all but ceased as only one contract was executed during
19 this period. (See Mr. Sterling, pages 27-28) While Staff asserts this was
20 attributable to many factors, one of the significant factors was low natural gas
21 prices, a condition that is present today as well. The ability to finance and recover
22 capital costs based on the avoided costs proposed in this proceeding with today's
23 gas prices is impossible over a five year period. Just has had occurred in 1996 to
24 2002, adoption of a maximum five year contract term will not "control the pace"
S
Donald W. Schoenbeck 891 Page 9ofl4
I of QF development above the fixed price eligibility cap but, rather, it will end it.
2 Q. IS THERE ANOTHER FACTOR THAT WILL BE CONTROLING THE
3 PACE OF QF DEVELOPMENT?
4 A. Yes. Most parties to this proceeding are advocating no avoided capacity costs
5 should be paid during periods of sufficiency. If this is adopted by the
6 Commission, this feature will naturally control the pace of QF development
7 without having to put in place a totally unreasonable five year contract term.
8 Q. WHAT IS STAFF'S POSITION WITH REGARD TO ENVIRONMENTAL
9 ATTRIBUTES INCLUDING RECS?
10 A. The Staff believes the Commission should decide the question of REC ownership.
11 For contracts under the JRP method, Staff asserts the cost is included in
12 computing the avoided cost rates and therefore the utility should be entitled to the
13 RECs. (See Mr. Sterling, page 46, lines 6-20) Under the SAR method, Staffs
14 "if testimony states the utility should pay an additional amount it wished to own
15 the RECs." (See Mr. Sterling, page 46, line 21 through page 47, line 8)
16 Q. DO YOU AGREE WITH STAFF'S ASSERTION THAT THE COSTS OF
17 RECS ARE INCLUDED IN THE AVOIDED COST RATES DERIVED
18 UNDER THE IRP METHOD?
19 A. No. Staffs logic is dependent upon the assertion that renewal resources are
20 reflected in the utility resource plans and therefore are implicitly within the
21 resulting avoided costs under the IRP method. This assertion is simply not
22 correct. Earlier in the testimony, Staff acknowledges that under the utility IRP
23 proposals "capacity and energy values are calculated independently" of each
24 other. (See Mr. Sterling, page 17, lines 13-19). Under both the Idaho Power and
25 Staff proposals, the capacity value is based on a SCCT and not the costs of the
892 Donald W. Schoenbeck Page 10 of 14
I renewable resources in the utility's preferred portfolio. Under both the Staff and
2 Idaho Power proposals, energy costs are derived from the incremental cost or
3 market price of short-term energy. The resources supplying this energy are gas-
4 fired or coal fired resources. These resources do not generate any RECs. As the
5 resources used to derive the avoided costs under the IRP method do not produce
6 RECs and Staff has proposed no incremental adjustment to the resulting IRP
7 avoided costs, the REC ownership right should stay with the seller under the IRP
8 method.
9 Q. DO YOU AGREE WITH THE STAFF POSITION THAT UTILITIES
10 SHOULD HAVE TO PAY FOR REC OWNERSHIP UNDER THE SAR
11 METHOD?
12 A. Yes, I do. If the REC market was liquid and transparent, it would make sense to
13 provide a REC purchase option under the published fixed rates for QFs choosing
S 14 to transfer (sell) RECs to the utility. However, it has been my experience that the
15 REC market is illiquid and not transparent. Because of this market situation, I
16 believe the fairest approach for all parties (QF, utility and ratepayers) is to simply
17 allow the seller to retain the ownership of any associated RECs and all other
18 environmental attributes. As noted in my direct testimony, this is my
19 recommendation under both JRP and SAR methods.
20 Q. DO YOU HAVE ANY COMMENTS REGARDING STAFF'S SUPPORT
21 FOR CONTINUING THE 100 KW PUBLISHED RATE ELIGIBILITY
22 CAP FOR WIND AND SOLAR RESOURCES?
23 A. Yes. Staff's reasoning is based on the continuing existence of a financial
24 incentive to game play through the disaggregation of resource capability. No
25 party to this proceeding has objected to requiring annual gas price updates under
Donald W. Schoenbeck 893 Page 11 of 14
both the SAR and IRP methods. If these updates are done simultaneously, I
believe any financial incentive to disaggregate will be eliminated as the avoided
energy costs should be very close under either method. Under these
circumstances, a uniform eligibility cap across all technologies should be re-
instated by the Commission. As explained in my direct testimony, I recommend
this cap be 10 MW. I would also not that this is a significant reduction from the
previous 10 average MW cap and a substantial reduction in size, moving from
average to nameplate capacity.
Q. DO YOU HAVE ANY COMMENTS REGARDING STAFF'S SUPPORT
OF IDAHO POWER'S PROPOSED SCHEDULE 74?
A. No. Staff has not provided any additional arguments that I need to address. For
all the reasons stated in my direct testimony, the Commission should not approve
the Idaho Power proposed schedule.
IV. ISSUES RAISED BY OTHER PARTIES
Q. DID YOUR REVIEW OF THE PARTY TESTIMONY RAISE ANY NEW
ISSUES YOU HAD NOT ADDRESSED?
A. Yes. Dr. Reading's testimony recommended certain transmission and
interconnection policy matters which I had not previously addressed. (See Dr.
Reading pages 66 and 67). The essence of one of Dr. Reading's
recommendations is that the Commission should mirror the FERC pricing
standards for customer contributions in aid of construction for interconnection
costs. The FERC policy calls for the payment of all costs up to the point of
interconnection to be borne by the project developer. The cost of facilities
beyond this point ("network upgrades") however are initially funded by the
Donald W. Schoenbeck 894 Page 12 of 14
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project developer but are eventually refunded by the transmission provider. On
the other hand, Idaho Power's Schedule 72 ("Interconnection to Non-Utility
Generation") provides for only a limited upgrade refund based upon another
generator using the same network upgrade facilities and this "vested interest"
refund right expires after just five years.
Q. IS THERE A BASIS FOR THE DIFFERENCE IN POLICIES BETWEEN A
FERC REGULATED INTERCONNECTION AND A QF
INTERCONNECTED DIRECTLY TO ITS BUYER?
A. Yes, there can be. In cases where a FERC interconnection is required, the
interconnected QF (or possibly the purchaser) must pay for wheeling the power
across the local transmission provider's system. In the case where the QF is
directly connected to the purchasing utility (who is also the transmission
provider), no such ongoing wheeling payments are required. Differences in
policy can also arise simply from having differing views on who benefits from the
system upgrade. FERC generally views network upgrades as providing a system
benefit for all users of the network. From this perspective, then, it is equitable for
all users to pay for the upgrade. Other parties have the prospective that the
network upgrade is not providing any system benefit and that it would not be
needed but for the QF. These parties argue that the QF should be responsible for
paying for all network upgrades.
Q. WHICH PERSPECTIVE DO YOU AGREE WITH?
A. I agree with FERC's perspective. Network upgrades that allow power to be
delivered to loads should be paid for by the loads and not the QF. In my view,
this "levels the playing field" with utility owned generation. Certainly, Idaho
Donald W. Schoenbeck 895 Page 13 of 14
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Power's customers are paying the network transmission costs to deliver power
from Bridger to Boise and all other Idaho Power owned resources. These

3 customers are even paying all the interconnection costs associated with these

4 utility-owned assets as well (costs up to the interconnection point with the

5 transmission network). The FERC prospective should be used to determine the

6 costs that should be borne by QFs in Idaho as well. The QF Companies fully

7 support Dr. Reading's recommendation and ask the Commission to adopt and

8 employ the FERC interconnection policy in Idaho whereby network upgrades

9 should be paid for by the users of the transmission system.
10 Q. DOES THIS CONCLUDE YOUR TESTIMONY?

11 A. Yes.
.
Donald W. Schoenbeck Page 14 of 14
(The following proceedings were had in
open hearing.)
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COMMISSIONER SMITH: Thank you.
Any questions, Mr. Williams?
MR. R. WILLIAMS: No questions.
COMMISSIONER SMITH: Uda. Miller. Richardson.
MR. RICHARDSON: No questions, Madam Chair.
MS. NELSON: No questions.
COMMISSIONER SMITH: Mr. Otto.
MR. OTTO: No questions, Madam Chair.
COMMISSIONER SMITH: Mr. Solander.
MR. SOLANDER: Yes, please.
CROSS-EXAMINATION
BY MR. SOLANDER:
Q. Good afternoon, Mr. Schoenbeck.
A. Good morning.
Q. Good morning.
COMMISSIONER SMITH: Don't forget your mic.
:iy I
(Twin Falls Canal Company, et al, Exhibit
No. 1101, having been premarked for identification, was
admitted into evidence.)
MR. ARKOOSH: We tender him for cross-
examination.
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MR. SOLANDER: Oh, thank you.
COMMISSIONER SMITH: Thank you.
Q. BY MR. SOLANDER: Are you aware that PacifiCorp
trades natural gas at locations throughout Western North
America, and that the use of a single Rocky Mountain Power!
PacifiCorp natural gas price as developed by the EIA would not
properly capture PacifiCorp's rates at those market hubs?
A. Yes, I do. That's why at least with respect to
the IRP methodology I said a Utility such as PacifiCorp or
Avista that trades gas at several different hubs can use those
hubs as part of the IRP process like they always have. It was
only with respect to using any IRP update, the gas price
updates, the IRP, that you then go to the single gas price
forecast.
Q. And you agree that PacifiCorp doesn't currently
use the EIA forecast in its IRP?
A. PacifiCorp generally uses internally-generated
forward price curves for both gas and electricity.
Q. And isn't it true that the GRID model has been
reviewed and approved by the Commission for use in rate making
proceedings since 2002?
A. I'm not sure of the exact date, but certainly the
GRID model has been used in PacifiCorp's jurisdictions for a
number of years.
MR. SOLANDER: I have no further questions.
I 898 I
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COMMISSIONER SMITH: Ms. Sasser.

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MS. SASSER: Yes. Thank you, Madam Chair.
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CROSS-EXAMINATION
5

6 BY MS. SASSER:

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Q. Hello.

8 A. Good morning.

9
Q. Have you negotiated any QF contracts in Idaho?

10 A. I have reviewed a QF contract for the potential

11 sale of a QF facility in Idaho, but I never negotiated the

12 original contract.
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Q. Okay. So on page 7 of your direct testimony, at

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line 3 and going on to line 4 to finish the sentence, you

15 state: It has been my experience --

16 A. Excuse me. Could you give me the cite again?

17 Q. Oh, I'm sorry.

18 A. It was the direct testimony?
Wom Q. Page 7 of your direct testimony.

20 A. Okay, I'm on page 7.

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Q. Line 3 and 4. You state: It has been my

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experience that negotiating a nonstandard QF PPA with a Utility

23 can take a great deal of time.

24 A. Yes, that's correct.
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Q. So that's not necessarily the case in Idaho. You
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don't have a basis for which to make that statement regarding
negotiating contracts in Idaho?
A. I personally have not negotiated a nonstandard
contract in Idaho. I have negotiated QF contracts in the
states of Washington, Oregon, California, Virginia -- these are
the ones that are off the top of my head -- and in almost every
single instance, it took months to negotiate the contract. In
the state of California, it literally has taken years to
negotiate QF contracts.
Q. Along the lines of experience that you've had in
other states, you discuss at page 6 of your testimony
generally -- I'm not going to cite to a specific sentence
there -- eligibility size and contract length and standards
that seem to be working in California and Oregon. Are you
aware of whether these states have seen the influx of QF
development that Idaho has seen?
A. Well, certainly the state of California has
approximately 10,000 megawatts of QF development, so it has
been a substantial portion of their power for -- portfolio for
a number of years. Oregon, not quite as much, but with respect
to California, it's a significant amount.
Q. But would you be willing to admit that the
circumstances in Idaho are quite different from those,
especially of California, even just with regard to number of
customers and demand?
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A. No, I would not.
Q. Okay. In your prefiled direct testimony on
page 4, beginning at line 11, you mention that contracts for
solar --
Are you there? I'm sorry.
A. You said page 4, line 11, in regard to solar?
Q. "For intermittent resources such as solar and
wind, there is an integration adjustment to the prices paid."
Would you be willing to accept the fact that
Idaho does not, in fact, have an adjustment for solar
resources?
A. I will accept that, subject to check.
Q. On page 9 of your direct testimony, you discuss
generally the difference in treatment for Utility-owned
resources versus QF-owned resources, and you talk about what is
fair and equitable.
Wouldn't you agree though that sometimes it's
actually in the QF's best interest that they're not treated
like a Utility-owned resource?
A. If you could give me a precise example, I would
consider that question, certainly.
Q. Not subject to the regulations of the Federal
Power Act. Not --
A. Well --
Q. Well that --
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A. Certainly they are not, but to the extent is that
better or worse than a Utility, it is -- I don't have an
opinion on that particular issue.
Q. So you don't think that qualifying facilities --
A. -- being exempt from 205 or 206 of the Federal
Power Act is much of an advantage? No, I don't.
Q. On page -- let me make sure that's yours.
On page 37 of your direct testimony, you discuss
Idaho Power's proposed Schedule 74. And beginning at line 22,
you state that there is currently no provision in Idaho Power's
existing QF contracts to curtail. Is that correct?
A. That's correct.
Q. And I'm assuming you were sitting in the hearing
room with witness Guy, Mr. Guy, where it was noted in those
power purchase agreements that there, in fact, is a provision
that includes regulation for FERC REC5 between 292-303 and
308?
A. Yes, I did hear that question and answer.
Q. So would you stand by your testimony then that no
contracts in Idaho contain a provision that would allow for
curtailment?
A. What my testimony said was with the existing
contracts that I had reviewed, I did not see the typical
procedures I've seen for implementing the Section 304 of the
PURPA regulations. And, basically, the Idaho witnesses
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testified that there are three jurisdictions that they have

2 relied on that have interpreted these regulations within the

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contracts. They are with respect to the states of California,

4 Nevada, and Florida.

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I'm familiar with every one of those

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jurisdictions, and in those standard contracts there are

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specific provisions for implementing that's part of the PURPA

8 Statute, and including one of the significant differences that
9 are in every one of those states that are not in the proposal

10 under Idaho Power's Schedule 34 is the fact that the Utility

11 must first exercise all due diligence to make off-system sales.

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Provisions such as that are not in the Idaho contracts that I

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13 have seen.
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Q. Is that a provision that is required by FERC?
A. It's a provision that every Utility I'm familiar
with has done in implementing PURPA.
MS. NELSON: Madam --
Q. BY MS. SASSER: Is that a provision required by
FERC?
MS. NELSON: Madam Chair, I apologize. I didn't
want to interrupt the answer to the question, but I object to
the question that was asked that attempted to construe the
testimony by Mr. Guy to say that the provision in 7.5 allowed
for curtailment, as I understood Ms. Sasser to say. That is
not what the testimony was, and I object to that
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COMMISSIONER SMITH: Ms. Sasser.

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MS. SASSER: Let me attempt to restate. I

4 apologize, I did not intend to misconstrue Mr. Guy's testimony.

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Q. BY MS. SA5SER: An admission that the contracts
6 that were entered into evidence by Mr. Guy reflect a provision
7 under ongoing jurisdiction of this Commission that the terms of

8
the contract be construed pursuant to the Regulations of FERC

9 of which includes 292.304(f). Is that an adequate --

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let the contract language speak for itself. I don't believe

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language does speak for itself, and the point was made that

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that language is in the contract.

16 MS. NELSON: The citation to the Federal range of
Norm Regulations, yes.

18
COMMISSIONER SMITH: Yes. And this witness was
19 only asked I think whether he was here when he heard that.

20
MS. NELSON: Yes, I know. I appreciate that.

21 Thank you for letting me state my objection.

22
COMMISSIONER SMITH: We've got the records here.

23 Thank you.

24 Q. BY MS. SASSER: So my question to you was:
25 Regarding all of those additional provisions that you just gave
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2 apart --
MR. ARKOOSH: I have an objection to that: It
was asked and answered, that exact same question.
MS. SA55ER: It wasn't answered. He answered
that every state that he has worked in, negotiated contracts
in, has included that provision. He did not, in fact, answer
whether the FERC Regulations require those provisions.
MR. ARKOOSH: Well, and I have a further
objection if she's going to ask him about the Regs. Clearly,
it's asking him for a legal opinion; I'm not going to object on
that ground. But show him the Reg you're talking about and let
him read the Reg and say whether it allows it or doesn't allow,
but just asking generally I don't think is fair. So that's the
objection.
COMMISSIONER SMITH: Ms. Sasser.
MS. SASSER: I can provide him with the CFR if he
would like to read it and then state to me whether -- it's his
testimony that they have been included in other contracts. I'm
simply asking --
Q. BY MS. SASSER: I mean, would you like me to
provide you with 292.304(f) of the Federal Regulations?
A. I don't believe that's necessary.
MS. SASSER: Then could the witness be directed
to answer the question as to whether those provisions are
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COMMISSIONER SMITH: I know that the question was
asked.
MR. ARKOOSH: And it was answered, but I'll let
him answer it again. Withdraw my objection, Madam Chair.
COMMISSIONER SMITH: Thank you.
THE WITNESS: I think to clarify the discussion
we've been having, if you go to page 40 of my testimony --
Q. BY MS. SASSER: I'm sorry, page 40?
A. Of my direct testimony. I have included an
extensive quote from a FERC Order on how Section 304(f) should
be implemented, what the circumstances are whether or not it
can be implemented, and I believe based on the fixed price
contracts I have seen in Idaho --
MS. SASSER: Madam Chair, I would ask that the
witness be directed to answer. It's a "yes" or "no" question.
THE WITNESS: But, well, the answer is the
contracts cannot be -- I believe the Idaho Power contracts,
fixed price contracts, cannot be curtailed based on 304(f).
MS. 5ASSER: I'd like the record to reflect that
it was a nonresponsive answer to the question, but I'll move
on.
COMMISSIONER SMITH: I think he did answer the
24 question.
25
MR. ARKOOSH: Madam Chairman, he said no. she
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wanted "yes" or "no," he said no.
Q. BY MS. SASSER: Thank you. I'll move on.
On page 9 of your rebuttal testimony --
COMMISSIONER SMITH: Did -- this brings up a
question for me: Did we spread his rebuttal testimony?
MR. ARKOOSH: I think so, but I can sure do it
again, if I may, Madam Chairman, to be sure the record is
correct.
COMMISSIONER SMITH: You may have and I'm not
sure.
But, Wendy, so I intended to spread both, so if
you could correct that if I didn't, I would appreciate it.
Thank you.
MR. ARKOOSH: I recall doing it, Madam Chairman,
but just for the record, Mr. Schoenbeck, if you were asked the
questions in your direct and your rebuttal --
COMMISSIONER SMITH: No, we -- I know we did
direct.
MR. ARKOOSH: Well, I'll just do them both
together.
COMMISSIONER SMITH: All right.
MR. ARKOOSH: -- direct and rebuttal, would your
answers to those questions be the same?
THE WITNESS: Yes, they would.
MR. ARKOOSH: And 1101 is your qualifications.
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Is that correct?
THE WITNESS: That's correct.
MR. ARKOOSH: And your only exhibit?
THE WITNESS: Yes, that's correct.
MR. ARKQO5H: I would ask that direct and
rebuttal be spread on the record, and 1101 be admitted, Madam
Chair.
COMMISSIONER SMITH: So to the extent that we may
not have done rebuttal earlier, if we didn't, we will do it
now, but hopefully we did it right the first time.
MR. ARKOOSH: Thank you, Madam Chair.
COMMISSIONER SMITH: Sorry. All right, rebuttal
questions.
Q. BY MS. SASSER: I will reduce it to one final
question, and go to page 11. Are you there?
A. Yes, I am.
Q. On page 11 of your rebuttal testimony, you oppose
Staff's position that wind and solar resources continue to be
capped at 100 kilowatts for eligibility to a published rate
contract. If you look at line -- moving to the next page,
line 2 and 3, you state that annual gas price updates will
eliminate any financial incentive to disaggregate, and then at
line 2 and 3 you say: The avoided energy costs should be very
close under either method.
If this is the case, then what's the harm in
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leaving the 100 kilowatt threshold for wind and solar?
A. I'm sorry, did you say what's the harm in
removing it or leaving it?
Q. What's the harm in leaving the cap at 100
kilowatt?
A. It again goes to not just the price of what the
contract, what the QF would ultimately be paid, but it also
goes to the issue of having to negotiate basically a contract.
There's an administrative cost there, particularly with respect
to the potential of having to review any update to the IRP --
initial IRP model determination. That administrative cost
particularly for a project that's 101 kilowatts, it just does
not make it a cost effective size to choose.
Q. Okay.
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couple.
MS. SASSER: Thank you. That's all I have.
COMMISSIONER SMITH: Okay. Mr. Andrea.
MR. ANDREA: Thank you, Madam Chair. Just a
CROSS-EXAMINATION
21
22 BY MR. ANDREA:
23
Q. Good morning, Mr. Schoenbeck.
24 A. Good morning, Mr. Andrea.
25 Q. Can I direct you to the series of questions and
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1 answers starting on page 33, the bottom of page 33 of your

2
direct testimony, and running through the top of page 35 of

3 your testimony. Let me know when you're there.
A. Yes, I've given those pages a quick scan.

5 Q. Okay. And in that series of Q and As, you're
6 responding to Idaho Power's proposal with regard to how to

7
include capacity costs in the published rates, is that correct,

8 the published avoided cost rates?

9 A. That's correct. Since this was my direct

10
testimony, I did offer some changes on determining and

11 allocating capacity costs in my rebuttal testimony.

12 Q. Thank you, Mr. Schoenbeck, I appreciate that.

n 13
don't think the changes are material to my questions, but I

14 appreciate that clarification.

15 Generally, you don't agree with Idaho Power's
16 approach, and I see that in Q and A starting in the middle of

17 page 34. But is it fair to say that you do agree that

18 resources should not be provided or compensated for capacity

19 that a Utility does not need?

20 A. Yes. Both in my direct testimony and in my

21 rebuttal, I discuss the notion that to the extent a Utility is

22 surplus, there should not be a capacity payment during that
23 period. However, I caveated it based on whether and what that

24 corresponding contract term is.

25 To the extent the contract term ends up being the
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Idaho Power proposal of just a five-year contract term, then I

2 stated very specifically that the capacity should be paid every

3 year of that five-year contract because there's no other option

4 on any additional follow-up contract, but if it's a reasonable

5
20-year term, yes, then in the surplus year there should be no

6 capacity payment in the first years of that surplus for that

7 contract.

8 Q. Thank you. Would it also be your position that

9
if a resource provides no capacity, let's assume a 20-year

10 contract term but a resource that provides no capacity to the

11
Utility, that that resource should not be compensated for

12 the capacity?
.
13 A. That naturally follows; but again, generally,

14 every resource has at least some capacity contribution, even in

15 the case of a wind project.

16 MR. ANDREA: Thank you very much.

17 COMMISSIONER SMITH: Mr. Williams.

18 MR. J. WILLIAMS: Madam Chair, given the
19 admonition from the Commission that we would need to be

20
dismissed at 11:55 today, I would -- I probably have more than

21
five minutes of questions for Mr. Schoenbeck, so --

22 COMMISSIONER SMITH: So we'll go to lunch, and we

23 will be back at 1:30.

24 MR. J. WILLIAMS: Thank you.

25 (Noon recess.)
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COMMISSIONER SMITH: Welcome back, ladies and
gentlemen. We're about ready to start in the afternoon.
Mr. Williams, is this from you?
MR. R. WILLIAMS: Yes, Madam Chair. That is the
exhibit that I thought I was handing out this morning, but it
now is excerpts from Dynagy -- Dynamis's, excuse me --
Dynamis's power purchase agreement with Idaho Power. And then
on the second and the third pages, or page 22 and 23 of the
contract, are the force majeure provisions from that agreement
that Mr. Looper spoke to.
COMMISSIONER SMITH: And this is Exhibit one
thousand and --
MR. R. WILLIAMS: Three.
COMMISSIONER SMITH: Three. And all parties have
been provided a copy?
MR. R. WILLIAMS: Yes, they have.
COMMISSIONER SMITH: Okay. So Exhibit 1003 is
18 now with us.
19 (Dynamis Exhibit No. 1003 was marked for
20 identification.)
21 COMMISSIONER SMITH: Mr. Williams.
22 MR. J. WILLIAMS: Thank you, Madam Chair.
23
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DONALD SCHOENBECK,
produced as a witness at the instance of Twin Falls Canal
Company, et al, having been previously duly sworn, resumed the
stand and was further examined and testified as follows:
CROSS-EXAMINATION
BY MR. J. WILLIAMS:
Q. Good afternoon, Mr. Schoenbeck.
A. Good afternoon, Mr. Williams.
Q. I would like to begin by following up with you on
some questions related to Schedule 74. Could you please go to
your testimony, page 39 -- your direct testimony, page 39. In
that sentence -- I'll give you a second if you're not there.
A. I am, I'm sorry.
Q. Okay, that's fine. On page 39, beginning at
line 17, there's a sentence there that reads: The existing
Idaho Power QF PPAs I have reviewed do not contain operational
or economic curtailment provisions.
Do you see that sentence?
A. Yes, I do.
Q. And I just wanted to be clear --
Well, first of all, which Idaho Power QF PPAs did
you review?
A. Those were the PPAs associated with the North
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Side Canal Company, the Twin Falls Canal Company.

2 Q. Okay. And how many -- was that just two PPAs

3 then?

4 A. Yes, two or three.

5 COMMISSIONER SMITH: So --

6 THE WITNESS: Because I think --

7 COMMISSIONER SMITH: Mr. Schoenbeck, apparently

8
there have -- apparently there have been complaints from the
9 back of the room that they can't hear you, so if you could

10 speak into the mic, your chance to be a rock star.

11 THE WITNESS: I don't think so, but okay.

12
Q. BY MR. J. WILLIAMS: I'm sorry, Mr. Schoenbeck,
.
13 did you say the two or three QF PPAs that Idaho Power has with

14
the North Side and then Twin Falls Canal Companies?

15 A. Yes, that's correct.

16
Q. Are you aware of how many QF PPAs Idaho Power has
lorm with QF5?

18 A. I'm sure they have several. I did, going through

19 some of the other dockets, I did note some of the PPAs, but

20 again, that was the focus of my testimony.

21 Q. So -- okay, fair enough. So the North Side Canal
22 Company and the Twin Falls Canal Company, those are QF

23 projects. Is that your understanding?

24 A. Yes, that's correct. Well, the contracts such as
.
25 I think the Midway contract, for example, is one of the
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contracts I have reviewed.
Q. So -- but I guess what I'm getting at is are the
Canal Companies themselves, those legal -- or, those entities,
are those actual QFs?
A. The purchase power contracts that those entities
have are drop canal projects, so they are QFs under PURPA.
Q. Okay.
A. Are you distinguishing the projects from the
Companies?
Q. That's my question. Is it your understanding
that the Canal Companies --
A. The projects are the qualifying facilities with
the PPAs.
Q. Okay. So is it your understanding that the Canal
Companies then own the individual projects, and it's the
projects themselves that are the QF5? Is that your
testimony?
A. I guess I'm missing -- again, sorry, I'm missing
the distinction, but the projects are the QFs --
Q. Okay.
A. -- associated with the legal entities.
Q. Okay. So does Idaho Power have power purchase
agreements with the North Side Canal Company and the Twin Falls
Canal Company, do you know?
A. There's a list and it was listed in discovery of
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the I believe it's nine or ten total projects the Companies

2
have. It's -- I did not bring that Data Response with me

3 today.

4
Q. Do you know if the projects, if they were to
5 breach their PPAs with Idaho Power, would the North Side Canal
6 Company or the Twin Falls Canal Company be liable to Idaho

7 Power for those breaches?

8 A. Sitting here today --

9 MR. ARKOOSH: Your Honor, I object: That's a

10
legal conclusion. I think that maybe after six or seven years

11 of litigation, we can probably figure that out.

12 COMMISSIONER SMITH: Mr. Williams.
.
13 MR. J. WILLIAMS: Madam Chair, it's a simple

14 question. I'm just trying to figure out exactly who owns the
15 projects and what recourse the Canal Companies have. I mean,

16 if these are, indeed, the entities that have financed the
17 projects and that have contracted with Idaho Power, whether or

18 not they're liable to Idaho Power if a breach should occur.

19 MR. ARKOOSH: I can't -- you know, I just can't

20 see the relevance. The projects are owned by wholly-owned

21 subsidiaries, so --
MR. J. WILLIAMS: Madam Chair, I'm going to

23 object to that. Mr. Arkoosh is testifying now.

24 MR. ARKOOSH: I'm not testifying. He wants this.

25 COMMISSIONER SMITH: It seems, to me, that this
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1 witness probably isn't going to get the answers or have answers

0m,
that you want answered, which do appear to be legal in nature.

3
MR. J. WILLIAMS: Fair enough, Madam Chair. I'll

4 move on.

5
Q. BY MR. J. WILLIAMS: Mr. Schoenbeck, it's your

6 testimony, is it not, that it is patently unfair for Idaho

7 Power to be excluding hypothetical carbon costs from its

8 avoided cost calculation for PURPA? Is that a fair

9 characterization of your testimony?

10 A. What my testimony is saying was based on the IRP
11 method, I believe it should include carbon cost as an avoided

12 cost.

13
Q. And is it your testimony in fact though that it's

14 patently unfair if Idaho Power does not count those carbon

15 costs?

16 A. You can give me a specific reference, but I'm

17 recommending that they be included, yes.

18 Q. Sure. Page 24 of your testimony, the very last

19
line, line 23, there's a whole discussion here on carbon costs.

20 And does line 23 say: It is patently unfair for a Utility?

21 A. Yes, it does.

22
Q. Okay. Do you think it's appropriate for Idaho

23 Power to be assessing a hypothetical carbon tax against its

24 customers?
.
25 A. Well, what my testimony explains and it actually
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1 goes to Mr. Bokenkamp's characterization of when you're doing

2 avoided cost, it is, particularly over a reasonable contract
3 period such as 20 years, it is your best estimate based on your

4 best available information.

5 In the Idaho Power IRP process, your best
6 information when they did the IRP, that carbon costs would be

7 imposed as of 2015. But my testimony is stating if that's your

8 best estimate, that's what your IRP is based on, your IRP
9 method should include that cost in your avoided cost

10 determination under that approach.

11
Q. But isn't it true that we could -- if we did

12 that, we could sign PPA5 with customers -- I'm sorry, with QF
13 projects where we would be assessing this hypothetical carbon

14 tax against our customers, our retail customers?

15 A. You would not be assessing a hypothetical tax
16 against your customers. You would have included in the avoided

17 cost calculation precisely the same assumption you used when

18 you performed and evaluated your IRP. It's, again, no

19 different than Mr. Bokenkamp stated. It is based on the best

20 available information at the time. The best available

21 information that you employed is that carbon tax would be

22 imposed as of 2015.

23 MR. J. WILLIAMS: No more questions, Madam Chair.

24 Thanks.

25 COMMISSIONER SMITH: I think that brings us to
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the Commissioners.
COMMISSIONER REDFORD: No questions.
COMMISSIONER SMITH: Nor I.
Redirect?
MR. ARKOOSH: No redirect, thank you.
COMMISSIONER SMITH: Thank you for your help.
THE WITNESS: Thank you.
(The witness left the stand.)
(Whereupon, Volume V of this transcript is
completed.)
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