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1 BOISE, IDAHO, TUESDAY, JANUARY 11, 1994, 1:30 P. M.
2
3
4 COMMISSIONER MILLER: We'll go back on the
5 record. Commissioner Smith will join us in a few moments.
6 Mr. Woodbury, I think we're still with you.
7 MR. WOODBURY: Thank you, Mr. Chairman.
8
9 JAN B. PACKWOOD,
10 produced as a witness at the instance of the Idaho Power
11 Company, having been previously duly sworn, resumed the
12 stand and was further examined and testified as follows:
13
14 CROSS-EXAMINATION
15
16 BY MR. WOODBURY: (Continued)
17 Q Mr. Packwood, just to clarify a matter, when
18 we were discussing the December 10th correspondence from
19 Idaho Power to Rosebud which correspondence seemed to
20 precipitate the complaint filing in this case, I asked you
21 whether the Company had sent similar notice to any other QFs
22 and you indicated not to your knowledge. Have you had the
23 opportunity to review a piece of correspondence that I gave
24 you just prior to reconvening?
25 A Yes, I did.
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1 Q And is that piece of correspondence dated
2 December 7th related to the Hot Sulfur Springs Project in
3 Nevada which is being developed by Earth Power?
4 A Yes, it was to the Earth Power Project.
5 Q And is it wrong to characterize the substance
6 of the two letters as being similar?
7 A Very similar wording.
8 Q And do you know what the result of the
9 December 7th letter to Earth Power was?
10 A I could not remember, but you suggested that
11 that was the letter that prompted their complaint as well.
12 Q Yes, their complaint was filed on
13 December 9th. You state on Page 12, Line 23 of your
14 testimony, that the use of the integrated resource plan
15 process to evaluate resources will also ensure that the
16 evaluation criteria will be open to public scrutiny and
17 discussion, and following up on the next page, you state
18 that resource decisions, and I'm assuming that you mean
19 including QF acquisitions, should be made in a forum in
20 which all interested parties, not just utilities and QF
21 developers, are encouraged to participate, and you state
22 that the IRP process is such a forum. The IRP process, is
23 there a public hearing, was there a public hearing in March
24 or after the March presentation of the '93 integrated
25 resource plan?
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1 A As best I recall, the hearings conducted by
2 the Commission are public hearings, but I guess I don't
3 exactly know that. I would assume that to be the case.
4 Q Was there a hearing, to your knowledge?
5 A To my knowledge.
6 Q And is that the type of public input,
7 opportunity for public input, that you're referring to or
8 are you referring to the opportunity for public
9 participation during the formulation of the integrated
10 resource plan during the prior two years?
11 A On the '93 plan or the plan we filed in March
12 of '93, the public process had really three pieces. It had
13 a technical advisory panel that helped us with the
14 development of the plan. We then held a series of meetings
15 on our motion in our service area and then it culminated
16 with a hearing before this Commission.
17 Q And it's within that type of forum that you
18 believe we should be assessing the reasonableness of QF
19 purchases?
20 A As that forum evolves and as it's determined
21 that the application of IRP to how
22 administratively-determined avoided costs might be set, if
23 that was going to be the outcome, then I would suspect that
24 there would have to be some action on the part of this
25 Commission in doing more than acknowledging the report, but
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1 to this point in time, the way we're trying to use it is to
2 come up with the best available actual data we know how to
3 get to apply to projects over 10 megawatts to adjust the
4 rates that we offer and really nothing more beyond that.
5 Q And you were already well into that IRP
6 process in December of '92 when you sent the letters to
7 Earth Power and to Rosebud?
8 A We were halfway through the second iteration.
9 Q And when you indicate in your letter to Earth
10 Power that Idaho Power's analysis show that future
11 generation acquisitions should not be take-and-pay
12 non-dispatchable purchase contracts like the contract you
13 are requesting, that is a, was a conclusion that you drew
14 from your IRP process?
15 A Yes, that was a determination as to deficit
16 year based on our planning process, not based on Appendix A
17 of avoided costs. The problem with Earth Power was that
18 they're a Nevada utility and it was not clear to us at that
19 point in time what they qualified by the way of avoided
20 cost.
21 Q But that statement would be equally applicable
22 to any QF offering power to the Company, wouldn't it?
23 A To those over 10 in which we are negotiating
24 with to try to determine a basis for a contract, it was the
25 only tool we had, yes, sir.
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1 Q So based on that conclusion, then it would be
2 the Company's intent to defer any project coming in above
3 10 megawatts?
4 A A deferral is something we can ask for which
5 is part and parcel to negotiation with knowledgeable,
6 sophisticated developers. They can agree to it or not.
7 Again, it is no effort to suspend PURPA. It's a negotiating
8 position that seeks to obtain for Idaho Power Company some
9 of the interests we need in negotiating with projects
10 greater than 10 megawatts.
11 Q And so a suggestion that discussions related
12 to a project be deferred until '97 or '98 is just that, it's
13 a suggestion of the Company?
14 A Suggestion and request of the other party to
15 the negotiation.
16 Q You indicate that the IRP process is an
17 appropriate forum. Is the avoided cost case process also an
18 appropriate forum?
19 A Avoided cost case? The one that we filed and
20 that is pending?
21 Q Yes.
22 A Yes, it certainly would be an appropriate
23 forum.
24 Q And have you presented your integrated
25 resource plan in that particular case?
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1 A Yes, we have. We suggested that it should be
2 the basis for negotiating with projects greater than one
3 megawatt.
4 Q And do you anticipate that there will be
5 in-depth analysis of the plan as to appropriateness in that
6 case?
7 A I think this proceeding guarantees it.
8 Q In speaking of the risks associated with
9 acquisition of large supply side resources prior to need,
10 cannot that risk be addressed in the contract terms and
11 rates?
12 A Yes, it can.
13 Q Referring to your rebuttal testimony, Page 1,
14 starting about Line 20, you state that Mr. Faull recommends
15 that the Commission adopt a new policy entitling developers
16 of proposed QF projects greater than 10 megawatts to the
17 same rates, terms and conditions contained in prior
18 Commission approved contracts for QF projects greater than
19 10 megawatts. Can you direct me to a testimony reference in
20 Mr. Faull's revised testimony where he reaches that
21 conclusion or makes that suggestion?
22 A I can't cite a line, you know, page or line
23 number, but I sat there and heard repetitively those
24 assertions this morning.
25 Q You did?
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1 A Yes.
2 Q So if I were to present you with the two pages
3 or three pages of revised testimony, you would not be able
4 to point to where he said that because in fact it's not
5 there?
6 A I'd be happy to look.
7 Q Okay. Your rebuttal testimony only was
8 addressed to his revised testimony, wasn't it?
9 A Do you have Exhibit 109?
10 Q Pardon?
11 A Exhibit 109 was part of the revised --
12 Q Exhibit 109 was the correspondence.
13 A Okay.
14 Q There was no correspondence from Mr. Faull in
15 that exhibit.
16 A We can do one of two things. I can read the
17 three pages and I suppose by the fact that you're offering
18 them that you don't believe the statement is there. What I
19 was responding to was either oral testimony that I heard as
20 we sat here the previous time where the Meridian Generating
21 contract was suggested by Mr. Faull to be an appropriate
22 proxy for determining the rates for Rosebud, and if I've
23 misconstrued it or if it doesn't appear, I apologize.
24 Q Do you further believe as you state that this
25 entitlement would apparently exist regardless of any
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1 difference in operating characteristics between QF
2 projects? Do you believe that Mr. Faull would say that, let
3 alone did say that?
4 A You'll have to repeat the question. I was
5 busy returning those to you.
6 Q Your testimony indicates that Mr. Faull's
7 proposed policy of entitlement would apparently exist
8 regardless of any difference in operating characteristics
9 between QF projects.
10 A That's what I believe and that's what I
11 thought I heard, yes, sir.
12 Q Are you still of that opinion today?
13 A Even more so today, yes.
14 Q Okay. On Page 2, Line 9, you state that Faull
15 finds that the transmittal of the May 25th letter,
16 Exhibit 109, perfected Rosebud's right to a contract. Isn't
17 that where Mr. Faull's testimony stops and then you go on,
18 "...for the Mountain Home Project at the rates, terms and
19 conditions contained in the Firm Energy Sales Agreement for
20 the Meridian Generating Project," don't you add that last
21 part yourself?
22 A I guess I don't understand the question
23 again. It seems like the one we just spoke to.
24 Q The problem is that you're reaching some
25 conclusions that basically you're following -- you're
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1 reading into Mr. Faull's testimony a conclusion that he does
2 not in fact reach himself. He indicates that it provides
3 entitlement to a contract. Entitlement to a contract, would
4 you agree and in your review of Commission orders, is a
5 little, has been sort of a term of art and it's a time that
6 we fix the party's obligation to provide power to the
7 utility and say that his obligation is specific enough and
8 firm enough that he's entitled to a contract and to a set of
9 avoided cost rates?
10 MR. KLINE: Mr. Chairman, I'm going to object
11 to the question. There may have been multiple questions in
12 there.
13 COMMISSIONER MILLER: It was a compound
14 question, plus I think it verges on argumentative; so I'll
15 sustain the objection.
16 MR. WOODBURY: It verges on what?
17 COMMISSIONER MILLER: The witness is not
18 required to answer.
19 Q BY MR. WOODBURY: Well, your statement is,
20 "Faull finds that the transmittal of the 5-25-93 letter,
21 Exhibit 109, perfected Rosebud's right to a contract for the
22 Mountain Home Project at the rates, terms and conditions
23 contained in the Firm Energy Sales Agreement for the
24 Meridian Generating Project." Please direct me to a
25 testimony reference where Mr. Faull makes that statement.
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1 A We go right back to where we were on the next
2 question or the last question.
3 Q Did you have in mind Mr. Faull's rebuttal
4 testimony in front of you when you prepared your rebuttal
5 testimony, Mr. Faull's revised testimony?
6 A We had the revised testimony. We had a
7 discussion as to what we heard in the Hearing Room and I
8 guess somehow I left under the mistaken impression that he
9 was suggesting the Meridian Generating contract was a proxy
10 that Rosebud was entitled to. Again, if I've misconstrued
11 it, I apologize.
12 Q In answer to a question that you posed to
13 yourself, "In your view, has Rosebud provided evidence that
14 it is ready, willing and able to enter into a Power Purchase
15 contract," you answer no and for reason that Rosebud has not
16 engaged in good faith negotiation. Are there any other
17 reasons to support your conclusion?
18 A Only those we've spent the morning on and
19 that's the litany that goes back to March 26th of letters
20 exchanged, rates offered and what constitutes good faith
21 negotiation, and I guess in my mind, I look for good faith
22 negotiation, particularly for projects greater than 40
23 megawatts, is that when the Company says here's what we
24 need, here's what it costs, that we would expect the
25 developer or whoever we're negotiating with to apply an
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1 equal level of sophistication to try to see if there's a
2 match there, not simply take a contract that was clearly a
3 settlement of another issue and suggest that, well, we'll
4 take this one. To me, that doesn't seem like they perfected
5 any right and that's where Mr. Faull and I disagree.
6 Q Do you believe that a QF has the resources
7 available to it to calculate an avoided cost rate which
8 would be acceptable to this Commission?
9 A I certainly do.
10 Q Do you believe that it is the QF that should
11 be calculating avoided cost rates and not the Company?
12 A We have to again define what avoided cost
13 rates we're talking about. The administratively-determined
14 and published avoided cost rates are determined in theory,
15 at least my understanding of the theory, for the smaller
16 projects that lack the resources or capability or
17 sophistication to do this. I would certainly expect a
18 developer who is proposing a $72 million project to have the
19 ability to negotiate and look out for its interests with
20 Idaho Power or any other utility. They have no obligation
21 to determine the administratively-set avoided costs for the
22 under 10 megawatts, but they certainly have an obligation to
23 suggest rates in a negotiation for a project greater than
24 10 megawatts.
25 Q Are the rates for projects larger than
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1 10 megawatts as opposed to smaller than 10 megawatts, is the
2 standard that it be the full avoided costs of the utility
3 any different?
4 A The standard is that the full avoided costs
5 beginning with the published avoided costs are then adjusted
6 for real and actual conditions that are site specific and
7 it's not our obligation to understand all of the real and
8 actual considerations that the developer has that is site
9 specific. His costs, his fuel arrangements, his siting
10 conditions are all known to him and are proprietary to him
11 and it's based on that that he sees if he can find a price
12 that both parties can agree to where he can go forward and
13 develop and earn his return and where we have met at least
14 some of our interests as well. If that's not what's
15 intended through negotiations, then let's drop the charade
16 that there should be negotiations.
17 MR. WOODBURY: Mr. Chairman, I have -- thank
18 you, Mr. Packwood. Mr. Chairman, I have no further
19 questions.
20 COMMISSIONER MILLER: Mr. Orndorff.
21 MR. ORNDORFF: Thank you, Mr. Chairman. I
22 will try to minimize the coverage and if I pause as I go
23 through these questions, I hope the Commission is
24 understanding. I'll try to make it as brief as possible.
25 I'd like to start off by pointing out that the
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1 December 10th letter is included as Exhibit C to Rosebud's
2 Complaint; so it is in the record and I'd like not to
3 introduce it into the record again if that would be the
4 Commission's pleasure. Further, the correspondence leading
5 to the Complaint is attached as Exhibit A to the Rosebud
6 Complaint, and generally, I think Mr. Woodbury has covered
7 it and I don't want to again repeat that exercise, but it is
8 in the record already.
9
10 CROSS-EXAMINATION
11
12 BY MR. ORNDORFF:
13 Q Mr. Packwood, could you explain to me the
14 difference between deferral and suspension?
15 A I use deferral to mean to delay, to set off
16 until some later date discussions or agreement. Suspension
17 means that everything comes to an absolute standstill.
18 Q In looking at the December 10th letter, '92
19 letter, that Mr. Woodbury and you discussed extensively, is
20 your second paragraph a suspension of the avoided cost as of
21 December 10th, 1992, as far as what Rosebud could get?
22 A No.
23 Q I'd like to again read you, then, the second
24 paragraph which says --
25 MR. KLINE: Do you have a copy of it, Jan?
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1 THE WITNESS: I'm looking for it now. He said
2 it's in Appendix C of the Complaint. I'll get there
3 eventually. I have it.
4 Q BY MR. ORNDORFF: Now, Mr. Packwood, the
5 letter says in the second paragraph, "Because Idaho Power
6 does not need to add any new resources for such a long
7 period of time, it would be imprudent for Idaho Power to
8 contractually commit at this time to a 40 megawatt 35-year
9 purchase beginning in either 1998 or year 2000." Now, is
10 that a suspension of the avoided costs, an indefinite
11 suspension?
12 A No.
13 Q Could you explain to me why?
14 A All it is is a statement of a position of need
15 and interest on the part of the Company. I go on in the
16 same letter to say, "For all these reasons, Idaho Power
17 Company requests that future discussions regarding the
18 proposed Mountain Home project be deferred until after the
19 Commission has completed the review of Idaho Power's avoided
20 cost and resource acquisition program."
21 Q Is that deferral the same as a suspension,
22 until Idaho Power and the Commission have finished the new
23 case?
24 A It's, again, a bilateral negotiation where you
25 as the other party have the right to agree or disagree. It
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1 was a request. In fact, the fifth line says, "Idaho Power
2 requests...."
3 Q And you only made the request with a view
4 towards, as an option that Rosebud had?
5 A How else could it be construed?
6 Q Even though it would be imprudent for you to
7 contract?
8 MR. KLINE: I'm going to object,
9 Mr. Chairman. I think it's asked and answered and
10 argumentative.
11 MR. ORNDORFF: Mr. Chairman, I don't think
12 it's argumentative at all because I'm getting to the issue
13 of whether the Company would do anything that was imprudent,
14 as the letter suggests, and I believe if the Company is
15 going to tell Rosebud it would be imprudent for them to
16 negotiate that we ought to find out if the Company would do
17 anything imprudent.
18 COMMISSIONER MILLER: I'll overrule the
19 objection.
20 THE WITNESS: You'll have to restate the
21 question.
22 Q BY MR. ORNDORFF: Mr. Packwood, the letter
23 says very clearly that it would be imprudent to contract
24 with Rosebud. Do you see that in the second paragraph?
25 A Sure.
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1 Q Now, given that statement, is it conceivable
2 that the Company would do something in the future that would
3 be imprudent?
4 A We would never knowingly do something that
5 would be judged imprudent where prudency is actually
6 determined and that's before this Commission.
7 Q Mr. Packwood, is it possible that a project
8 larger than 40 megawatts would offer unique benefits to the
9 Company that it would be worth more than the posted avoided
10 cost rates?
11 A I don't know the answer to that.
12 Q Have you ever told a qualified facility that
13 was considering locating in eastern Idaho that the
14 transmission system in eastern Idaho was inadequate and that
15 the avoided costs for a plant there would be less than
16 locating in the western part of Idaho?
17 A We tell everyone, independent and utility
18 alike, about the transmission constraints west of our Borah
19 substation.
20 Q Do you recall if the Company has ever raised
21 those issues in the U-150-1700 [sic] case?
22 A I'm not familiar with the 150-1700 case.
23 Q Oh, 1500-170.
24 A I don't recall if that was, our transmission
25 constraints were part of that proceeding or not.
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1 Q Mr. Packwood, if Idaho Power purchases four
2 9.9 megawatt projects totaling roughly 40 megawatts versus
3 one project from Rosebud at rates that are less than the
4 avoided cost, is there any difference to the ratepayers?
5 A There certainly can be, yes.
6 Q Do the rates for a 9.9 megawatt project, are
7 they being subsidized by the ratepayer?
8 A They're being paid by the ratepayer.
9 Q Is the ratepayer overpaying for those
10 9.9 megawatt projects?
11 A I don't actually know. That's a determination
12 that was made in the 170 case whereby
13 administratively-determined avoided costs would be offered
14 to the small projects and that's what we do.
15 Q Well, if I look at -- if a 40 megawatt project
16 receives substantially less than avoided cost than four
17 9.9 megawatt projects, surely there must be some
18 justification for that other than a Commission arbitrary or
19 determination of 9.9 megawatts being the limit. Can you
20 offer some explanation why four 9.9 megawatt projects are
21 different than one?
22 A I guess the only basis I would have on which
23 to attempt to answer that is in every instance where we've
24 negotiated an avoided cost rate with a project greater than
25 10 megawatts, it has been demonstrably and measurably lower
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1 than the published avoided cost and I'd have to attribute
2 that to economies of scale of a larger project, but
3 certainly with those economies of scale come economies of
4 impact as well.
5 Q Well, Mr. Packwood, how much lower was the
6 Auger Falls contract rate than the avoided cost?
7 A Fourteen percent, 14 to 16 percent.
8 Q How much lower was the Meridian contract
9 price?
10 A Same neighborhood.
11 Q Did you ever offer Rosebud 14 to 16 percent?
12 A No, because the need went away with the
13 previous large projects.
14 Q Based on a determination in the rates in
15 effect at the time?
16 A No, based on our efforts to justify or to
17 adjust for the impacts of a project on our load/resource
18 balance. It only stands to reason that as you add resource,
19 need will change.
20 Q Did you specifically tell Dr. Willmorth in
21 calculating the avoided costs for Rosebud to use as the
22 basis of those rates the IRP?
23 A I may have. I don't recall what specific
24 instructions I may have given Dr. Willmorth.
25 Q Who made the determination of what the
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1 starting point and the ending point was?
2 A The planning process that we've described
3 earlier of determining what the adjustment as to actual
4 circumstances from the public's cost should be was done
5 collectively, but ultimately the responsibility falls on
6 Dr. Willmorth's department because that's where our analysts
7 are, that's where the model is and there's where those
8 people who actually prepare the tables work.
9 Q But you don't recall whether you told
10 Dr. Willmorth as a matter of fact just to use the IRP to
11 calculate the Rosebud rate?
12 A I have no idea what I told him. I just know
13 what the decision was and what we've done.
14 Q On Page 2, Line 20 of your direct, you refer
15 to the cost of Mountain Home being three-quarters of a
16 billion dollars for a 25-year contract based on Meridian
17 Energy rates. Do you recall the size of the Meridian Energy
18 project?
19 A Yes.
20 Q What was that size?
21 A Fifty-four megawatts.
22 Q Would the cost of the Meridian Energy contract
23 be larger than the Mountain Home project?
24 A Well, yeah, if you have 54 megawatts as
25 opposed to 40 and the same rate, it would be about
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1 28 percent larger.
2 Q On Page 4, Lines 16 to 23 and on to Page 5,
3 you indicate that Idaho Power used the published avoided
4 rates as a starting point for computing Rosebud's rates. Do
5 you recall the rates Idaho Power offered Rosebud for its
6 base-loaded plant and I think that's Exhibit 208 to
7 Dr. Willmorth's testimony?
8 A Yeah, I've looked at four rate schedules that
9 we offered to Rosebud.
10 Q These are the base-loaded rates. I believe,
11 subject to check, that between year 1998 and 2005 you
12 offered 21.8 mills strictly for energy. Does that sound
13 correct or would you like to look at Exhibit 208?
14 A I'd defer that to Dr. Willmorth.
15 Q Do you know what the published avoided cost
16 rates unlevelized for a project coming on line January 1,
17 '98, would be based on the Commission's Order of July 2nd,
18 1993? That's Order No. 24971.
19 A I know how to get that answer. I don't have
20 them memorized, no.
21 Q Would you accept, subject to check, that such
22 rate is 52.89 mills?
23 A Sure.
24 Q Hypothetically, if I were to ask you if you
25 were troubled by the difference between an offer of 21.8
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1 mills versus an avoided cost rate of 52.89 mills, whether
2 you would find that troubling, I'm asking you
3 hypothetically, that difference, would you find that
4 troubling?
5 A That would suggest that the project is
6 premature and probably shouldn't be built.
7 Q Do you recall if the offer of 21.8 mills was a
8 firm offer for energy?
9 A Again, I'd have to defer the details of that
10 to Dr. Willmorth.
11 Q Do you recall when the Meridian Energy
12 contract was signed?
13 A January of '93.
14 Q Did the Commission approve the rates and allow
15 recovery from ratepayers on the Meridian Energy contract?
16 A There is an order that approved that contract,
17 yes.
18 Q Were the rates in the Meridian contract
19 developed with the published rates as the starting point for
20 negotiations?
21 A The rates in the Meridian contract were
22 negotiated rates based on a litany of litigation with which
23 you're very familiar.
24 Q Do you recall what the Commission said on
25 Page 8 of the Exhibit 216 to your rebuttal testimony as the
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1 avoided costs have as a starting point the administrative
2 costs?
3 A Vaguely. We can refer to it if you want to
4 refer me to a page and line.
5 Q Sure. If we go to your Exhibit 216 and we
6 look at Page 8 underneath the heading "MGC Contract," one
7 two, three, four lines down, there's a reference to, and
8 I'll read the sentence, "Administratively-determined rates
9 are, however, the basis or starting point for negotiation
10 for projects greater than 10 megawatts."
11 A I think as I recall this and as I verify by
12 looking at Page 7, this is what Commission Staff testified
13 and there's a different outcome in the discussion and
14 findings which I believe represents what the Commission
15 actually found.
16 Q Okay, let's skip ahead to your rebuttal
17 testimony. I believe you offer us a quote from --
18 A Where are we now?
19 Q In your rebuttal testimony.
20 A Page?
21 Q I think it's Page 4 of your rebuttal,
22 Mr. Packwood, Line 1.
23 A Yes.
24 Q After the word "implications," did you
25 intentionally delete the sentence?
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1 A Yes, that's what the three dots indicate is
2 that there's a sentence missing.
3 Q Let me see if you really intended to delete
4 this sentence. I would be interested if it was
5 inadvertent. Turning to the Order, after the word
6 "implications," the next sentence is, which is missing,
7 "Analysis indicates that the power purchase rates under the
8 MGC agreement are less than Idaho Power's unlevelized
9 avoided cost." Did you intend to leave that sentence out?
10 A Yes, we did.
11 Q Do you think that leaving that sentence out
12 significantly changes the meaning of that paragraph?
13 A Since I was arguing at the non-precedential
14 nature of the rates, I didn't think that affected it.
15 Q I see, and down below where you picked up
16 starting with, "As a stand-alone rate, it is reasonable,"
17 you don't believe that then stand-alone refers to the
18 unlevelized avoided cost in the sentence that you deleted?
19 A I didn't really try to determine that. Again,
20 I was supporting my contention that this rate is not a
21 precedential rate and was selecting that language which
22 supports my argument.
23 Q Is the Auger Falls rate a precedential rate?
24 A Not as far as I know.
25 Q So in looking at the Mountain Home contract
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1 and its rates that were to be negotiated with the
2 administrative rates being the starting point, you used a
3 different process in administratively determining those
4 rates for Mountain Home than you used for Auger Falls and
5 for Meridian Energy?
6 A I think that's a true characterization since
7 these three projects covered a fairly large span in time.
8 Q And the basis of that discrimination is --
9 MR. KLINE: Object.
10 COMMISSIONER MILLER: Sustained.
11 Q BY MR. ORNDORFF: Is the basis of the
12 discrimination --
13 MR. KLINE: Object again. That's a legal
14 characterization. It's argumentative.
15 COMMISSIONER MILLER: I do think,
16 Mr. Orndorff, it's kind of a loaded word. Perhaps
17 differentiation would be better.
18 MR. ORNDORFF: I think I can use a different
19 word. I appreciate the Chair's indulgence.
20 Q BY MR. ORNDORFF: The difference in the
21 starting point between Auger Falls, Meridian Energy and
22 Mountain Home is the existence of the IRP analysis?
23 A They correspond with a parallel path in which
24 the IRP analysis was developed. They correspond with the
25 acquisition in sequence of large projects for the first time
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CSB REPORTING PACKWOOD (X)
Wilder, Idaho 83676 Idaho Power
1 since the passage of PURPA and they developed in the same
2 time frame where we were trying to come up with a method to
3 use best available information to adjust from
4 administratively-determined avoided costs to the costs we
5 actually offered. That, again, comes back to how we define
6 negotiations and that's the ability to identify our
7 interests and attempt to meet our interests.
8 Q When you say "our," could you be specific as
9 to who you are referring to?
10 A I actually could argue I was referring to the
11 ratepayer, but I view it as a Company obligation to protect
12 that interest.
13 Q Is it your position, then, that Idaho Power
14 has a duty to protect the ratepayer different than the
15 Commission's?
16 A No, I think our interest and duty there is the
17 same one.
18 Q So when the Commission issues an Order setting
19 the avoided costs in July of 1993, it's your duty -- is it
20 your understanding it's your duty to comply with that Order?
21 A And I think you'll find we diligently have for
22 projects under 10 megawatts in size.
23 Q I forgot to ask, can you explain to me, then,
24 Mr. Woodbury's introduction of the Earth Power letter and
25 how you diligently complied?
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CSB REPORTING PACKWOOD (X)
Wilder, Idaho 83676 Idaho Power
1 A I don't understand why Mr. Woodbury introduced
2 it either, because, again, that was more a jurisdictional
3 issue for where published avoided costs did not exist,
4 absent any published avoided costs in that jurisdiction, I
5 think we determined that the best we could do is attempt to
6 negotiate a contract.
7 Q Questions that I have about Exhibit 208 I
8 should refer to Dr. Willmorth?
9 A If they determine the genesis and the
10 mechanics of developing those rates, I would appreciate it
11 if you could.
12 Q Okay. On Page 6, Line 13 --
13 MR. KLINE: Direct?
14 Q BY MR. ORNDORFF: -- of your direct, you state
15 "Idaho Power offered rates based on full dispatchability."
16 Do you see that?
17 A I don't see it at Line 10, no.
18 Q Line 13.
19 A Oh, excuse me. I don't see it at Line 13
20 either. What was the page again?
21 Q It should be on Page 6.
22 MR. KLINE: This is your direct testimony.
23 THE WITNESS: Excuse me, I was on Page 5.
24 Q BY MR. ORNDORFF: Line 13?
25 A I'm in the whole wrong chapter here, excuse
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CSB REPORTING PACKWOOD (X)
Wilder, Idaho 83676 Idaho Power
1 me.
2 Q I think it's the last two words in Line 13,
3 Mr. Packwood.
4 A I have that.
5 Q Okay, you do have it.
6 A Yes.
7 Q In just cursory looking at Exhibit 208, is it
8 your understanding that there is a rate for full
9 dispatchability in that offer?
10 A That's my understanding, yeah.
11 Q I see; so when I talk to Dr. Willmorth and if
12 he tells me that it's not for full dispatchability, we
13 should rely on his testimony?
14 A I would stand corrected.
15 Q Now, turning to Exhibit A of your direct
16 testimony, I believe it's Exhibit 201, I'd like you to turn
17 to the attachment to the letter of May 28th, and at the
18 bottom of that page, read me the three lines. It's the page
19 with the rates that are set out starting in year 1998.
20 A If I'm on the right page, 5 of 5 of my
21 Exhibit 201 and we're talking about variable costs?
22 Q Yes, read me the last three lines there on the
23 page.
24 A "Variable costs will be escalated consistent
25 with existing Commission Orders the most recent of which is
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CSB REPORTING PACKWOOD (X)
Wilder, Idaho 83676 Idaho Power
1 Commission Order 24911."
2 Q Do you recall in the Meridian contract what
3 the variable rate was that started off?
4 A I don't remember.
5 Q Would you accept, subject to check, that it
6 was different than the rate in Commission Order 24911?
7 A I would refer it to Dr. Willmorth and direct
8 my question to him.
9 Q If in fact the rate, variable rate, in the
10 Rosebud offer of May 25th was less than the Meridian
11 variable rate, would it be your view, then, that the Rosebud
12 rate was in the variable energy component less?
13 A I didn't follow the question. I'm sorry.
14 Q Well, what I'm trying to get to, Mr. Packwood,
15 is if in fact we determine that in talking with
16 Dr. Willmorth that the variable energy rate as set forth in
17 Exhibit 201 is less than the variable energy rate in the
18 Meridian contract, if that were in fact true, then the
19 Meridian contract offer that Rosebud made you is less than
20 the Meridian contract total rate that Idaho Power otherwise
21 is going to pay for the Meridian project.
22 A There's ways to check that and I can't decide
23 that here.
24 Q Mr. Packwood, since December 10th, 1992, has
25 Rosebud ever refused to negotiate or discuss the contract
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CSB REPORTING PACKWOOD (X)
Wilder, Idaho 83676 Idaho Power
1 with Idaho Power at any time in any form that Idaho Power
2 has wanted to talk about the contract?
3 A Again, it would come back to what we would
4 define as "negotiations." There's been no hesitance to
5 exchange letters. There's been one face-to-face meeting.
6 Most of the proposals prior to May of '93 came from us.
7 Q Mr. Packwood, on Page 13, Lines 20 through 23
8 and on to Page 14, you discuss retail access. Can you
9 explain to me what retail access has to do with whether
10 Rosebud is entitled to a contract at avoided costs?
11 A In this portion of my testimony, I was
12 discussing the risk to ratepayers of too much energy at too
13 high a price and what ultimately would be the outcome of
14 that.
15 Q Well, I think that confuses me. Is it the
16 Company's position that if the Company determines there's a
17 risk it suspends the avoided costs?
18 MR. KLINE: Objection.
19 THE WITNESS: Again, we've been over that. We
20 haven't suspended anything.
21 Q BY MR. ORNDORFF: Well, your testimony you
22 said was designed to focus on the risk of buying too much
23 power at too high of a price, retail wheeling.
24 A The portion that you've asked me about is a
25 discussion of what risk does retail wheeling constitute for
619
CSB REPORTING PACKWOOD (X)
Wilder, Idaho 83676 Idaho Power
1 Idaho Power Company and, again, Dr. Parkinson who will
2 follow me goes to great lengths to try to explain the
3 concerns and why we should look very prudently at how we
4 acquire large projects that represent tremendous revenue
5 requirements for our Company and for our ratepayers.
6 Q Well, to go back one more time, why is that
7 relevant in a qualified facility's request for a contract?
8 A It's not relevant other than it speaks to need
9 and it speaks to the issue of timing and that's what this
10 portion of my testimony does.
11 Q Okay, I'm now on your rebuttal testimony,
12 Mr. Packwood. On lines -- on Page 3, Lines 2 and 3, you
13 discuss the Commission specifically rejected approving the
14 Meridian project agreement.
15 MR. KLINE: Where are you, Owen?
16 MR. ORNDORFF: I'm on Page 3 where the Q and A
17 goes over from Page 2. The question is, "Is it your
18 understanding that by approving the Meridian Project
19 Agreement, the Commission intended to make the Meridian
20 Project Agreement a pattern for subsequent contracts for
21 large QF projects?"
22 And the answer is, "No. In fact, the
23 Commission specifically rejected that position when it
24 reviewed and approved the Meridian Project Agreement."
25 Now, is it your understanding that the
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CSB REPORTING PACKWOOD (X)
Wilder, Idaho 83676 Idaho Power
1 Commission approved the Meridian project agreement?
2 A I guess I can't make the distinction. I have
3 an Order 24805 in which we applied for approval of a
4 replacement firm energy sales agreement and termination of a
5 power sales agreement and the Commission ruled favorably on
6 that; so if the answer to your question is yes, it's yes.
7 Q Do you know of any contract form that this
8 Commission has specifically approved?
9 A I'm lost as to what distinction you're trying
10 to make. I know of no contract this Commission hasn't
11 approved.
12 Q Has the Commission -- it may be a distinction
13 without a difference for lots of folks, but the Commission
14 did in Meridian approve rates for ratepayer recovery. Now,
15 in your testimony when you say "and approved," are you
16 referring to the rates approved for recovery or are you
17 really saying that the Commission approved the contract
18 form?
19 A I don't know the distinction.
20 Q Now, Mr. Packwood, you were in the Hearing
21 Room, I believe, when we had a discussion about Rosebud's
22 Exhibit 13 and the interconnect diagram?
23 A Yes.
24 Q Do you recall when that was sent to Idaho
25 Power?
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CSB REPORTING PACKWOOD (X)
Wilder, Idaho 83676 Idaho Power
1 A I would assume if it was sent, it was in the
2 transmittal of October 7th, but I don't know that.
3 Q Do you know if Rosebud filled out the
4 interconnect form that Idaho Power provided?
5 A That was included in the transmittal of
6 October 7th.
7 Q Since October of '92, has the Company ever
8 asked Rosebud, to your knowledge, any questions about the
9 interconnect schematic provided in Exhibit 13?
10 A I'm not aware.
11 Q On Page 6, Line 18 of your direct testimony,
12 you indicate that Rosebud terminated negotiations.
13 A Page 6, Line --
14 Q -- 18 of your direct.
15 A That's how I characterize the short meeting on
16 the -- that's how I characterized the filing of the
17 complaint concurrent with your December 14th letter, I
18 guess.
19 Q But in fact, the negotiations have been going
20 on since the complaint?
21 A I understand discussions resumed again
22 following the prehearing conferences previously discussed
23 and there has been discussion from time to time right up
24 until November.
25 MR. ORNDORFF: Thank you, Mr. Chairman. I
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Wilder, Idaho 83676 Idaho Power
1 have no other questions.
2 COMMISSIONER MILLER: Thank you, Mr. Orndorff.
3 Commissioner Nelson.
4 COMMISSIONER NELSON: Thank you.
5
6 EXAMINATION
7
8 BY COMMISSIONER NELSON:
9 Q One question just as a matter of curiosity,
10 when we reviewed that Meridian contract, why, we looked at
11 the terms and conditions. I'm wondering if in looking at
12 Rosebud you made any analysis or if there is any difference
13 in the advantage or disadvantage to the Company from having
14 a project sited in Meridian or sited in Mountain Home.
15 A The project in this proceeding when it was
16 originally made or disclosed to us was a waste coal facility
17 in Wyoming, and following our disclosure that there were
18 transmission problems coming from Wyoming, about a six-month
19 period elapsed between April and September of '92 and when
20 the next letter came, the project was then a waste coke
21 facility in Mountain Home in an attempt to alleviate the
22 transmission constraint as an issue, and generally, as a
23 general rule, generation sited next to the load is
24 beneficial in that you don't incur transmission losses and
25 it supports essentially where it's being consumed; so, yes,
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CSB REPORTING PACKWOOD (Com)
Wilder, Idaho 83676 Idaho Power
1 facilities close to Boise have advantage to them.
2 Q So you're saying, then, that the Meridian
3 project would seem to have some advantage in site location
4 over the Mountain Home location?
5 A In a perfect world, when you need resources,
6 you like the resources as close to the load as you can get
7 them, but the key issue underlying all of the disagreement
8 we have is the timing.
9 COMMISSIONER NELSON: Okay, thank you. That
10 was my question.
11 COMMISSIONER MILLER: I think we'll let you go
12 since you've had a long road. Let's see if we have redirect
13 first.
14 MR. KLINE: We do not.
15 COMMISSIONER MILLER: Thank you, Mr. Packwood.
16 (The witness left the stand.)
17 MR. KLINE: Mr. Chairman, would there be an
18 objection if Mr. Packwood could be excused if he needed to
19 go?
20 COMMISSIONER MILLER: Any objection to
21 Mr. Packwood being excused?
22 MR. ORNDORFF: I don't think so,
23 Mr. Chairman. It's a long day.
24 COMMISSIONER MILLER: Mr. Packwood, you're
25 free to come and go as you wish.
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CSB REPORTING PACKWOOD (Com)
Wilder, Idaho 83676 Idaho Power
1 MR. PACKWOOD: Appreciate it.
2
3 THOMAS W. PARKINSON,
4 produced as a witness at the instance of the Idaho Power
5 Company, having been first duly sworn, was examined and
6 testified as follows:
7
8 DIRECT EXAMINATION
9
10 BY MR. KLINE:
11 Q Dr. Parkinson, could you please state your
12 name and business address, please?
13 A My name is Thomas W. Parkinson, 950 Winter
14 Street, Waltham, Massachusetts 02154.
15 Q And by whom are you employed, Mr. Parkinson?
16 A By the NorthBridge Group, that's NorthBridge
17 one word, capital "N", capital "B".
18 Q And, Dr. Parkinson, have you previously filed
19 direct testimony in this case?
20 A Yes, I have.
21 Q And have you also prefiled exhibits in this
22 case, specifically Exhibits 202, 203 and 204?
23 A Yes, I have.
24 Q And are there any additions or corrections
25 that you need to make either to your prefiled testimony or
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CSB REPORTING PARKINSON (Di)
Wilder, Idaho 83676 Idaho Power
1 to those three exhibits?
2 A No, there are not.
3 Q And if I were to ask you the questions today
4 that are contained in your prefiled testimony, would your
5 answers be any different?
6 A No.
7 MR. KLINE: With that, Mr. Chairman, I would
8 request that Dr. Parkinson's testimony be spread on the
9 record.
10 COMMISSIONER MILLER: In the absence of
11 objection, it will be so ordered and Exhibits 202, 203 and
12 204 will be marked.
13 (The following prefiled testimony of
14 Dr. Thomas Parkinson is spread upon the record.)
15
16
17
18
19
20
21
22
23
24
25
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CSB REPORTING PARKINSON (Di)
Wilder, Idaho 83676 Idaho Power
1 QUALIFICATIONS
2 Q Please state your name and address for the
3 record.
4 A My name is Thomas W. Parkinson. My business
5 address is 950 Winter Street, Waltham, Massachusetts. I am
6 a Principal in The NorthBridge Group, a consulting firm
7 providing economic and strategic advice to clients on
8 matters primarily related to regulated industries.
9 Q What is your educational background?
10 A I graduated in 1974 from Massachusetts
11 Institute of Technology with a Bachelor of Science Degree
12 (B.S.) in management with a concentration in management
13 science. I was awarded a Master of Science Degree (M.S.) in
14 1975 and a Doctorate (Ph.D.) in 1982 by Stanford University
15 from the Department of Engineering-Economic Systems.
16 Q Please outline your business experience.
17 A Prior to joining The NorthBridge Group in
18 1992, I was Principal with the firm of Putnam, Hayes and
19 Bartlett, Inc. an economic and management consulting firm
20 based in Cambridge, Massachusetts. Since 1986, I have
21 focused my practice almost exclusively on consulting on
22 matters relating to regulated industries and their
23 deregulation. A more detailed statement of qualifications
24 is attached as Appendix A to my testimony.
25
627
Parkinson, Di
Idaho Power Company
1 Q Please describe some of your domestic
2 consulting clients and assignments.
3 A I have been engaged on domestic projects for
4 independent power producers (including U.S. Windpower, Oxbow
5 Corporation and Enron Cogeneration), electric and gas
6 utilities (such as San Diego Gas & Electric and New England
7 Electric System), and industry groups (such as EPRI). I
8 have consulted on a broad range of issues including market
9 pricing, risk analysis, options theory and capital
10 investment decision making.
11 Q Have you testified before any state regulatory
12 bodies?
13 A In 1991, I testified before the Oklahoma
14 Public Utilities Commission on behalf of Oklahoma Gas &
15 Electric Co. on several issues, including the calculation of
16 appropriate avoided costs for purchases by the utility from
17 a qualifying facility under PURPA.
18 Q Do you have any international experience?
19 A Internationally, I have advised public
20 commissions, crown corporations, and government ministries
21 on the restructuring of power markets. In 1989, I advised
22 Scottish Power on the energy trading impacts of the
23 deregulation of the England and Wales power pool. In 1991,
24 I was retained by the Electricity Corporation of New Zealand
25 on a project to institute transmission pricing
628
Parkinson, Di
Idaho Power Company
1 reform based on marginal cost principles. During 1991 and
2 1992, I worked with the Electricity Commission and the
3 Office of Energy in New South Wales (Australia) to structure
4 a competitive generation market. Finally, in 1992, I
5 advised the Energy Ministry of the Ukraine (formerly in the
6 U.S.S.R.) on creating a market structure as a replacement
7 for the centrally-planned electricity system.
8 Q Do you have experience in unregulated,
9 capital-intensive, commodity industries?
10 A Yes. I consulted to the oil and gas industry
11 and the steel industry on a full-time basis for a number of
12 years and have also consulted on specific projects in the
13 petrochemical and mining industries.
14 PURPOSE OF TESTIMONY
15 Q What is the purpose of your testimony in this
16 proceeding?
17 A The purpose of my testimony is twofold:
18 . To support the testimony of Mr. Jan Packwood of
19 Idaho Power regarding the policy of negotiating
20 contracts over 10 MW with cogenerators and small
21 power producers (CSPPs);
22 . To respond to testimony offered by Staff witness
23 Faull regarding the public interest effects of QF
24 acquisition
25
629
Parkinson, Di
Idaho Power Company
1 policies, specifically as they relate to the
2 risks to utilities and their customers arising
3 from long-term fixed commitments.
4 Q Please summarize your first point.
5 A Idaho Power's process for acquiring resources
6 in excess of a threshold size, through negotiation in
7 conjunction with the Integrated Resource Plan (IRP), is in
8 the public interest because:
9 . Acquiring larger resources to match an explicit
10 need is superior to acquiring all resources
11 available at a given administratively determined
12 price that is adjusted via a trigger price mechanism;
13 The IRP process adequately and explicitly defines the
14 need for new resources;
15 . Avoided costs derived in conjunction with the IRP
16 represent a reasonable basis for negotiation and
17 acquisition of needed resources in excess of a
18 threshold size.
19 Q Please summarize your second point.
20 A Long-term resource acquisition commitments at
21 predetermined prices restrict purchasing flexibility and
22 expose utility shareholders and customers to significant
23 risks. This conclusion follows from the observations that:
24
25
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Parkinson, Di
Idaho Power Company
1 . Wholesale competition in electricity generation exists
2 today;
3 . In the short to medium term, wholesale competition is
4 likely to extend to competition among generators for
5 sales to retail customers;
6 . Retail competition will expose the shareholders
7 of utilities with above-market generation costs
8 to capital losses and cause their customers with
9 limited access to alternative generation sources
10 (core customers) to suffer from higher rates and
11 potentially lower service quality;
12 . Long-term resource acquisition commitments create
13 potential above-market exposure.
14 RESOURCE ACQUISITION PROCESS IS IN PUBLIC INTEREST
15 Q Please elaborate on your conclusions regarding
16 Idaho Power's negotiation policy regarding acquisition of
17 new large resources such as Rosebud.
18 A I conclude that the process is workable and is
19 in the public interest.
20 Need-Based System is Preferable
21 Q On what basis do you reach this conclusion?
22
23
24
25
631
Parkinson, Di
Idaho Power Company
1 A In order to benefit ratepayers, the Commission
2 is faced with the question of how best to induce Idaho Power
3 and other utilities to acquire needed resources at a fair
4 price. A policy of acquiring resources to match an explicit
5 determination of need is preferable to a policy of acquiring
6 all resources available at a given administratively
7 determined price.
8 To explain this point, I will assume for simplification
9 that all capacity that would be freely offered for sale to
10 Idaho Power is similar, differing only in price. While this
11 assumption is approximately true for baseload capacity, for
12 cycling and peaking capacity the consideration of differing
13 attributes complicates the argument. This does not,
14 however, change my fundamental conclusion.
15 Q What would be the outcome of an ideal resource
16 acquisition process?
17 A The ideal process would result in the
18 acquisition of the optimal quantity of capacity at the
19 optimal price, as shown in Exhibit 202. The underlying need
20 for system reliability defines the capacity need of a
21 utility system. There exists a tradeoff between desired
22 reliability and resource cost that defines the demand curve
23 for capacity. The costs of various potential capacity
24 alternatives define the supply curve for capacity.
25
632
Parkinson, Di
Idaho Power Company
1 The intersection of these supply and demand curves
2 define the optimal quantity and price of new capacity. The
3 demand curve is relatively observable, based on reliability
4 analysis. However, the supply curve is not directly
5 observable, because it reflects the collective actions of
6 all suppliers in the market.
7 Q What is the policy problem facing regulators?
8 A As indicated by the intersection of the two
9 curves, the policy problem facing regulators is how best to
10 induce a utility to acquire needed resources at a fair
11 price. Different Commissions have taken two distinctly
12 different approaches to this problem:
13 . Define an explicit capacity need in each year and
14 direct the utility to acquire the associated capacity
15 via bidding or negotiation;
16 . Define an administratively determined price and direct
17 the utility to acquire all capacity offered at this
18 price.
19 Q How does this relate to the supply and demand
20 curves?
21 A As shown in Exhibit 203, the capacity
22 need-based approach matches resource acquisition to actual
23 needs quite closely, resulting in small differences in
24 reliability or cost relative to the optimal outcome. This
25 is true because the demand curve for capacity is quite
inelastic. That is, the quantity of desired
633
Parkinson, Di
Idaho Power Company
1 incremental capacity changes little as the price of capacity
2 changes. This argument can be shown rigorously, through
3 analysis of system reliability and the customer value of
4 unserved energy, but that level of proof is not necessary to
5 make the argument here. The underlying rationale is that
6 incremental capacity has a rapidly diminishing effect on
7 system reliability. In other words, the 1st MW added will
8 have a far greater incremental effect on system reliability
9 than the 100th MW added. Moreover, in practice, most
10 utilities treat the demand curve as strictly inelastic by
11 identifying capacity needs in conjunction with a desired
12 reserve margin.
13 Q What is the consequence of this inelasticity
14 of demand for the need-based mechanism?
15 A Because of this inelasticity, acquiring a
16 fixed quantity of capacity will yield a close-to-optimal
17 solution, even with a fairly large misestimation of the
18 supply curve. For example, Exhibit 203 posits a situation
19 in which the actual supply curve is substantially below the
20 estimated supply curve (in other words, capacity is
21 unexpectedly inexpensive). The intersection of this
22 estimated supply curve with the demand curve defines the
23 estimated capacity need, which the utility proceeds to
24 acquire.
25
634
Parkinson, Di
Idaho Power Company
1 Based on the actual supply curve, incremental capacity
2 would be less expensive than expected. If the utility were
3 free to adjust the quantity acquired, it would logically
4 choose to add slightly more capacity so as to offer its
5 customers even greater reliability. Therefore, acquisition
6 of the estimated capacity need, as opposed to the optimal
7 need, will forego the incremental net benefits of this
8 marginal reliability increase in the short run. By
9 adjusting its capacity need in the following year, however,
10 the utility can reap the incremental benefit in succeeding
11 years.
12 Underestimating the cost of new capacity would yield the
13 opposite result. In this case, the utility would purchase
14 incrementally too much capacity, resulting in slightly
15 higher costs to ratepayers. Again, the utility could
16 correct this slight deviation from the optimal purchase
17 quantity in the following year.
18 Q How does this compare to a price-based system?
19 A By comparison, the price-based system will
20 lead to dramatically higher ratepayer costs and risks to
21 shareholders. Unlike the demand curve, the supply curve for
22 capacity is very elastic. Exhibit 204 shows an actual
23 supply curve developed from the eight lowest offers in the
24 recent Clark Public Utility District (PUD) request for
25 proposals. As can be seen from the graph in Exhibit
635
Parkinson, Di
Idaho Power Company
1 204, small errors in setting the administrative price can
2 create major swings in the resulting capacity offered.
3 The Clark PUD sought 150 MW of new capacity. Based on
4 the supply curve in Exhibit 204, the required price to
5 obtain 150 MW would be 26.6 mills per kWh on a real
6 levelized basis (in 1993 dollars).
7 If Clark PUD acquired resources based on a fixed price
8 rather than a fixed quantity, then the effect of
9 overestimating the required price by only 10 percent would
10 be to attract a much larger offer quantity because of the
11 price elasticity of the supply curve. For example, if Clark
12 PUD offered to purchase all capacity offered at a real
13 levelized price of 29.3 mills per kWh, instead of the market
14 clearing price of 26.6 mills per kWh, it would have been
15 forced to contract for capacity in excess of 1300 MW, based
16 on the supply curve in Exhibit 204.
17 Q Under a system in which the price is set and
18 all quantities are accepted at that price, what is the
19 result of setting a price other than the market clearing
20 price?
21 A If price is set too low, the cost is not
22 onerous. Too little (or no) capacity acquisition would
23 result, and the administrative price adjustment mechanism
24 would need to raise the price in following
25
636
Parkinson, Di
Idaho Power Company
1 year. The only cost would be the cost of deficit
2 reliability until the price rises high enough to attract the
3 needed capacity.
4 However, this result is not symmetric. If price is set
5 too high, then too much capacity would result and the excess
6 costs would be enormous. In the Clark PUD example in
7 Exhibit 204, the capacity actually acquired would be nearly
8 ten times the capacity needed.
9 Q What would be the effect on ratepayers of
10 adopting a price-based system and acquiring too much
11 capacity?
12 A The burden on ratepayers would be the cost of
13 large amounts of excess capacity persisting over a long
14 period, perhaps as long as a decade. As discussed in the
15 second part of my testimony, acquiring excess capacity in
16 advance of need further limits purchasing flexibility and
17 exacerbates fixed commitment problems.
18 Q Is there any real-world example of the problem
19 with setting a price above the market-clearing price and
20 taking all the supply offered at that price?
21 A Yes. Past experience in other states confirms
22 this economic analysis. In California, the imposition of
23 Standard Offer 4 led to the acquisition by Pacific Gas &
24 Electric and Southern California Edison of more than 9300 MW
25 of non-utility generation most of
637
Parkinson, Di
Idaho Power Company
1 which was in excess of current need. The estimated excess
2 cost to the ratepayers of these two utilities totaled 3.5
3 billion dollars. In New York, the mandated six-cent law led
4 to the acquisition of over 1000 MW by Niagara Mohawk alone.
5 As a result, Niagara Mohawk and other New York utilities are
6 now engaged in a concerted effort to buy out the excess
7 supply effected by the six-cent law.
8 Q What lessons have other states learned from
9 this experience with price-based purchase mechanisms?
10 A Having observed the experiences of California
11 and New York, all the neighboring western states with any
12 significant qualifying facility (QF) activity have adopted
13 need-based approaches in conjunction with integrated
14 resource plans for all resource acquisition above a given
15 threshold size. These states include California, Oregon,
16 Washington, Montana, Nevada and Colorado.
17 IRP Explicitly Defines Need
18 Q In view of the problems you identify with
19 price-based mechanisms, how is need to be determined?
20 A As discussed by Dr. Willmorth, the IRP
21 adequately defines the need for new resources. I will
22 summarize the key points.
23 The IRP sets forth future need for resources and the
24 selection and type of resources the Company expects to
25 acquire;
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Parkinson, Di
Idaho Power Company
1 in particular, the IRP defines magnitude, timing, and type
2 of needed resources. This satisfies the requirement for an
3 explicit and measurable determination of need.
4 The IRP process itself acts to ensure that this
5 determination is in the public interest. In fact, the IRP
6 process was developed in conformance with the requirements
7 of Order No. 22299 of the Idaho Public Utilities Commission
8 (PUC) and Order 89-507 of the Oregon Public Utility
9 Commission. In conjunction with those requirements, the IRP
10 process explicitly incorporates treatment of uncertainty,
11 risk, and environmental externalities in the evaluation of
12 resources. Through the required public participation
13 process, the IRP incorporates the disparate positions of
14 various parties with respect to differences in future
15 expectations and tradeoffs among desired attributes such as
16 cost and reliability.
17 IRP Provides Reasonable Basis for Negotiation
18 Q On what basis should Idaho Power undertake
19 negotiations for the acquisition of QF resources in excess
20 of 10 MW?
21 A Avoided costs derived in conjunction with the
22 IRP represent a reasonable basis for negotiation and
23 acquisition of needed resources. The IRP can serve as the
24 basis for calculation of
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1 avoided costs for any given resource alternative by means of
2 the following procedure (as discussed by Dr. Willmorth):
3 . The IRP defines least cost resources selected from the
4 identified portfolio of alternatives;
5 . The IRP is amended and reoptimized, consistent with the
6 decision criteria used to optimize the baseline IRP, to
7 include purchase or acquisition of a proposed resource
8 alternative.
9 . Avoided costs equal the payment stream that equates the
10 total cost to ratepayers in each year of the amended
11 IRP with that of the baseline IRP.
12 Q Are these calculations consistent with the
13 language and intent of PURPA?
14 A Yes, the avoided costs so calculated meet the
15 requirements of PURPA:
16 . Under PURPA, avoided costs (as interpreted by the Idaho
17 PUC in Order No. 15746) are "savings in total utility
18 power costs made possible when a utility purchases
19 power from a qualifying facility rather than producing
20 or purchasing the power itself;"
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1 . The baseline IRP defines the total utility power costs
2 anticipated without consideration of the proposed
3 resource alternative;
4 . The amended IRP defines the anticipated total costs
5 made possible by the purchase from the proposed
6 resource;
7 . The difference between the costs for the baseline IRP
8 and the amended IRP directly measures the savings
9 and thereby represents avoided costs as defined in
10 PURPA.
11 Q Does this procedure provide a workable
12 acquisition process?
13 A Yes, the avoided costs so calculated would
14 successfully result in the acquisition of resources
15 consistent with need as determined by the IRP and thereby
16 form the basis for a workable resource acquisition process.
17 If these avoided costs are sufficiently attractive to
18 the party proposing the alternative resource, then Idaho
19 Power would consider other alternatives as available or
20 acquire or purchase the specific resource additions
21 indicated in the IRP. In either case, Idaho Power would
22 fulfill its resource needs as indicated in
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1 the IRP at a cost to ratepayers no higher than that
2 projected within the IRP.
3 LONG-TERM FIXED COMMITMENTS ARE RISKY
4 Q What response do you have to Mr. Faull's
5 testimony regarding the public interest effects of QF
6 acquisition policies?
7 A Mr. Faull asserts that the current Commission
8 policies are in the public interest because they result in
9 the acquisition of "optimal cost" resources. However, in
10 his assessment of what constitutes "optimal cost," Mr. Faull
11 has failed to properly account for the risk associated with
12 long-term fixed commitments.
13 Q What conclusions do you reach concerning this
14 risk?
15 A I conclude that, given the current state of
16 the electricity industry and the likely future course of
17 deregulation, long-term resource acquisition commitments at
18 predetermined prices restrict a utility's purchasing
19 flexibility and expose its shareholders and core customers
20 to significant risks and that these risks must be considered
21 in assessing the public interest effects of QF acquisition
22 policies.
23 Wholesale Competition Exists Today
24 Q What is the current state of the electricity
25 industry with respect to generation sales at the wholesale
level?
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1 A Generation at the wholesale level is a
2 workably competitive market. Numerous sellers can compete
3 for any purchase, and numerous buyers can compete for any
4 sale.
5 Sales in this market include both long-term firm
6 contracts (bundled sales of energy and capacity for terms of
7 one year or more) and short-term sales of energy and
8 capacity. I will focus now on the long-term firm market and
9 later discuss the role of the short-term market.
10 Q Who are the sellers of generation?
11 A Sellers include QFs and cogenerators, the
12 vertically integrated utilities and nonqualifying
13 independent power producers (IPPs). A new category, exempt
14 wholesale generators (EWGs), is just beginning to gain in
15 importance.
16 Q What is the role of QFs and cogenerators?
17 A The passage of the Public Utilities Regulatory
18 Policy Act of 1978 (PURPA) required public utilities to
19 purchase power from QFs and cogenerators at rates equal to
20 the utilities' full avoided costs. In so doing, PURPA set
21 in motion the process of deregulation of the generation
22 sector and, in effect, created the modern market for
23 non-utility generation.
24 Q Has PURPA changed the character of the
25 electric utility industry?
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1 A Yes, very much so. The vertically integrated
2 utility structure that existed prior to 1978 has given way
3 to significant utility purchases from QFs and other
4 non-utility generators. From 1987 to 1992 non-utility
5 generators captured over 50 percent of the market for new
6 capacity in the United States.
7 Q To what extent do QFs and cogenerators compete
8 for sales?
9 A There has always been a form of indirect
10 competition because of the effect of current purchases by
11 any utility on its subsequent avoided costs. In recent
12 years, however, state commissions have increasingly embraced
13 direct competition among QFs by means of bidding
14 solicitations.
15 Q Have the vertically integrated utilities
16 contributed to the development of this competitive
17 generation market?
18 A Yes, overestimation of load growth by
19 utilities during the 1970s and 1980s, coupled with the
20 implementation of PURPA by certain states, left many
21 utilities with excess capacity. Their attempts to market
22 this capacity at market-based, rather than cost-based,
23 prices led the Federal Energy Regulatory Commission (FERC)
24 to impose certain transmission access provisions as a
25 condition of orders permitting market-based rates.
Q Why was this important?
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1 A FERC recognized that a workably competitive
2 generation market was unlikely as long as the utilities
3 owning transmission facilities could use this control to
4 exercise market power over generation sales. Until the
5 passage of the National Energy Policy Act (NEPA) in 1992,
6 however, FERC did not have the requisite authority to
7 directly effect wholesale transmission access. NEPA gives
8 FERC the explicit authority to order wholesale wheeling.
9 NEPA also declares EWGs to be exempt from the requirements
10 of the Public Utilities Holding Company Act, thereby
11 removing certain institutional hurdles to wholesale
12 competition.
13 Q What does this mean for wholesale customers
14 seeking long-term power?
15 A Wholesale customers can purchase generation
16 from a wide variety of QFs, cogenerators, IPPs, utilities
17 and EWGs at market-based prices. If necessary to effect the
18 transaction, the wholesale customer can request that FERC
19 order wheeling access.
20 Retail Competition is Coming
21 Q What does NEPA offer to retail customers?
22 A Today, nothing. As enacted, NEPA specifically
23 precludes FERC from ordering retail wheeling. Nonetheless,
24 in the short to
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1 medium term, wholesale competition is likely to extend to
2 competition among generators for sales to retail customers.
3 Q Given this provision of NEPA, why do you think
4 retail competition is likely in the short to medium term?
5 A This provision does not in any way preclude
6 retail wheeling. In fact, Section 722 of NEPA provides that
7 "Nothing in this subsection shall affect any authority of
8 State or local government under State law concerning the
9 transmission of electric energy directly to an ultimate
10 customer." Thus, NEPA serves mainly to help clarify the
11 respective Federal and State jurisdiction roles with respect
12 to retail wheeling.
13 This jurisdiction controversy merely highlights the
14 intense interest that certain retail customers (most notably
15 large industrials) have in gaining access to electricity at
16 wholesale prices. The gap between wholesale prices at two
17 cents per kWh and retail rates at four cents per kWh, six
18 cents per kWh and higher creates a powerful economic
19 incentive to effect institutional change.
20 Q Is there any clear precedent suggesting what
21 might happen to institutional barriers to retail wheeling in
22 the face of this economic incentive?
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1 A Yes. A similar economic incentive arose about
2 1983 when spot gas supplies became available at prices far
3 below the weighted average cost of gas (WACOG) of the
4 interstate pipelines. Over the ensuing decade, the efforts
5 by industrial customers and local distribution companies
6 (LDCs) to gain access to these supplies resulted in a
7 fundamental restructuring of the role of interstate gas
8 pipelines. This institutional restructuring, culminating in
9 1992 with Order 636, effected the unbundling of the
10 commodity, transport and storage services offered by gas
11 pipelines.
12 The experience of the natural gas industry suggests that
13 the path of institutional change is a slippery slope; once
14 started, change builds its own momentum.
15 Q Have there been any State or local initiatives
16 in retail wheeling that might indicate movement down this
17 slippery slope?
18 A Yes, there has been activity in at least eight
19 states: New York, Nevada, New Mexico, Pennsylvania,
20 California, Michigan, Rhode Island and Texas.
21 Q Has this activity originated in the state
22 legislatures or at the state public utility commissions?
23 A Both. In New York, existing state law allows
24 industrial customers that can demonstrate "serious,
25 long-term distress that is not primarily caused by normal
short-term changes in the business
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1 cycle" to qualify for an "economic development power
2 allocation" that permits them to secure wheeling service and
3 allows them to obtain power from another utility.
4 In June 1993, the Nevada legislature enacted retail
5 wheeling legislation directed at encouraging economic
6 development. Retail access is limited to new industrial
7 load possessing certain recycling and capital investment
8 requirements.
9 Also in 1993, retail wheeling bills were introduced into
10 the New Mexico and Pennsylvania legislatures. The New
11 Mexico legislation has been tabled pending the results of a
12 subcommittee study and the Pennsylvania legislation is
13 pending.
14 Finally, during 1992 and 1993 State commissions in
15 California, Michigan, Rhode Island and Texas studied various
16 types of retail wheeling proposals.
17 High Cost Utilities Will Suffer
18 Q What would be the effect of retail competition
19 on electric utilities?
20 A Retail competition will affect electric
21 utilities in much the same fashion as open access affected
22 natural gas pipelines. Those pipelines having take-or-pay
23 contracts with gas producers at prices far above market
24 could not pass the excess costs through to their previously
25 core customers. Many suffered, some went bankrupt.
Similarly, retail competition will cause shareholders
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1 and core customers of utilities with above-market generation
2 costs to suffer.
3 Q How will retail access affect the nature of
4 competition for retail customers?
5 A Utilities currently compete for customer loads
6 in limited ways, in terms of self-generation, cogeneration,
7 municipalization and end-use substitution. As the retail
8 franchise erodes, existing players in the wholesale
9 generation market will compete to serve selected retail
10 customers. Utilities will find themselves competing with
11 QFs, cogenerators, IPPs, other utilities and EWGs for
12 customers whose access was previously limited.
13 Q What effect will this competition have on
14 pricing?
15 A If there exists excess capacity, competition
16 for attractive retail loads will be intense. In order to
17 profit from an incremental sale, a generator need only cover
18 its variable costs of production. Accordingly, retail
19 generation prices will be bid down to short-term spot market
20 levels, which closely approximate the variable costs of
21 incremental generation for the market as a whole. If there
22 is no excess capacity, then retail prices could include an
23 additional premium reflecting the carrying costs of a
24 combustion turbine (as a backstop source of capacity).
25 Q How will competition affect ratepayers and
shareholders?
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1 A Ratepayers without market alternatives, like
2 similarly situated gas buyers in the 1980s, will be at risk
3 of paying higher rates. As market competition for the
4 attractive large industrial and commercial loads expands,
5 customers with market alternatives will seek significant
6 reductions in their rates as the quid pro quo for remaining
7 on the system. If the utility responds to competition and
8 reduces rates to these customers, the utility must seek to
9 recover the associated lost revenue requirement on these
10 sales by raising rates to other customer classes.
11 Alternatively, if the utility chooses not to reduce
12 rates, or is not permitted to reduce rates by its
13 regulators, and the customer leaves the system, then the
14 remaining customers must bear the full burden of the lost
15 revenue requirement. Rate increases triggered by the above
16 cycle could lead to another round of potential customer
17 defections, and thus to another round of rate increases for
18 the remaining core customers. As well, system reliability
19 may suffer as the utility attempts to reduce costs to
20 mitigate the need for additional rate increases.
21 Regulators are unlikely to let the entire burden fall on
22 the core customers. Both utility shareholders and core
23 ratepayers will share the burden of above-market generation
24 commitments in some proportion.
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1 Long-Term Fixed Commitments Create Exposure
2 Q Given the potential for future retail access,
3 how should utilities view long-term fixed commitments?
4 A Long-term resource acquisition commitments at
5 predetermined prices restrict purchasing flexibility and
6 expose core customers and shareholders to significant risks.
7 Purchasing flexibility is restricted because fixed
8 commitments by their nature are largely irreversible and
9 sunk costs are not recoverable. Therefore, these fixed
10 commitments effectively preclude other potentially
11 attractive options that might have been exercised thereafter
12 but for the prior commitment.
13 Q Can fixed commitments be avoided?
14 A Fixed commitments, or their close substitutes,
15 can be often be delayed, thereby allowing new information to
16 be gathered before making a decision to commit capital to
17 building or acquiring a resource with those.
18 Q What new information are you referring to?
19 A The most significant pieces of new information
20 would be the future prices of alternative resources, the
21 need for resources to assure system reliability and the
22 operating cost of these resources. It is trite to say that
23 hindsight is always 20/20, but
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Idaho Power Company
1 deferral of fixed commitments gives you the ability to
2 exercise hindsight in the future.
3 Q Are you saying that utilities should never
4 enter into long-term commitments?
5 A No, but I am saying that they should
6 explicitly account for the cost of this foregone flexibility
7 when comparing long-term and short-term alternatives.
8 Short-term contracts or obligations are significantly more
9 flexible than long-term fixed commitments. Short-term
10 obligations keep other options open and allow for
11 information gathering before a long-term commitment is made.
12 Finance theory shows that this loss of flexibility has
13 an explicit cost. Professor Robert S. Pindyck of MIT in his
14 article "Irreversibility, Uncertainty, and Investment,"
15 Journal of Economic Literature, Sept. 1991, 29, pp.
16 1110-1148, (attached as Appendix B) writes at p. 1112:
17 When a firm makes an irreversible investment
18 expenditure, it exercises, or "kills," its option to
19 invest. It gives up the possibility of waiting for new
20 information to arrive that might affect the desirability
21 or timing of the expenditure; it cannot disinvest should
22 market conditions change adversely. This lost option
23 value is an opportunity cost that must be included as
24 part of the
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1 cost of the investment. As a result, the NPV rule
2 "Invest when the value of a unit of capital is at least
3 as large as its purchase and installation cost" must be
4 modified. The value of the unit must exceed that
5 purchase and installation cost, by an amount equal to
6 the value of keeping the investment option alive.
7 Accordingly, long-term contracts must offer explicit
8 benefits to offset this inflexibility cost.
9 Q What risks do customers and shareholders face
10 from long-term fixed commitments?
11 A This cost of inflexibility is a risk to both
12 customers and shareholders. Over the 20 year life of a
13 typical long-term commitment, market power prices can vary
14 significantly. The predetermined contract prices, even if
15 consistent with market prices at the start of the contract,
16 can rise substantially above market prices after only a few
17 years. As utilities and ratepayers in New York and Maine
18 have learned, fixed commitments can be very expensive. In
19 those states, it is now economic for utilities to pay
20 certain QFs not to operate, because of drastic declines in
21 the real cost of power production -- declines that were not
22 imaginable only a decade earlier.
23 Q What conclusions do you draw from these
24 examples?
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1 A First, that ratepayers may pay more for their
2 power because of the alleged "security" of long-term fixed
3 commitments. However, we should not conclude that power
4 production costs are now a one-way street downward. Rather,
5 we need to know the cost of giving up flexibility and factor
6 that into any decision to incur fixed commitments. Second,
7 the excess of any contract price over market price will be
8 at risk in the event of retail competition, endangering both
9 core customers and shareholders. Third, the risks of
10 inflexibility are aggravated by contracts signed at
11 above-market prices or in advance of need. In such cases,
12 market prices need not drop in order to create financial
13 exposure for shareholders and core customers. Instead, the
14 burden of the opportunity cost of lost flexibility compounds
15 the detriment of contracting at an above-market price or in
16 advance of need.
17 Summary
18 Q Please summarize your testimony.
19 A My testimony can be summarized as follows:
20 . Idaho Power's process for acquiring resources in
21 excess of a threshold size, through negotiation in
22 conjunction with the Integrated Resource Plan, is in the
23 public interest;
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1 . Given the current state of the electricity industry and
2 the likely future course of deregulation, long-term
3 resource acquisition commitments at predetermined
4 prices restrict a utility's purchasing flexibility and
5 expose its captive ratepayers and shareholders to
6 significant risks.
7 Q Does this conclude your testimony?
8 A Yes it does.
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1 (The following proceedings were had in open
2 hearing.)
3 MR. KLINE: With that, Mr. Chairman,
4 Dr. Parkinson is available for cross-examination.
5 COMMISSIONER MILLER: Mr. Fell.
6 MR. FELL: No questions.
7 COMMISSIONER MILLER: Mr. Woodbury.
8 MR. WOODBURY: Thank you, Mr. Chairman.
9
10 CROSS-EXAMINATION
11
12 BY MR. WOODBURY:
13 Q Mr. Parkinson, you indicate on Page 12 of your
14 testimony that western states with any significant QF
15 activity have adopted need-based approaches in conjunction
16 with integrated resource plans for all resource acquisitions
17 above a given threshold size, and you cite as examples
18 California, Oregon, Washington, Montana, Nevada and
19 Colorado. Are you familiar with all of the avoided cost
20 procurement methodologies in those states?
21 A I'm not familiar with all of the specifics in
22 all those states.
23 Q When you speak of "above a given threshold
24 size," is there a single threshold size that the states use?
25 A My understanding is that the threshold size
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1 used in those states varies from one to three megawatts.
2 Q And how did you reach your understanding?
3 A I think it was through discussions with Idaho
4 Power personnel.
5 Q Are you familiar with the relative sizes of
6 the utilities in those states?
7 A Roughly.
8 Q And does the size of the utility have, is that
9 a relevant factor in determining which approach to take for
10 QF acquisition?
11 A No, I don't think it really is. I don't think
12 it's all that important. May I give just one caveat?
13 Q Is the nature of the resources being offered
14 of any relevance?
15 A Yes.
16 Q And if we were in a state where the primary
17 development was small hydro projects, would you believe that
18 regardless of that a bidding mechanism is a superior
19 mechanism for QF acquisition?
20 A For small hydro projects? Define "small."
21 Q Let's just say less than -- let's say if
22 you've got 60 projects, half of them are less than five
23 megawatts.
24 A For less than five megawatts, I don't see that
25 a bidding would necessarily make sense, particularly for
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1 hydro projects that have differing flow conditions.
2 Q What value do you see in the one to three
3 megawatt threshold size?
4 A What value?
5 Q Yeah.
6 A It differentiates projects that are fairly
7 small and can be dealt with through a standard
8 administrative process without significant possibility of
9 harm to the ratepayers and yet provide benefits because they
10 reduce the transaction cost to the developers.
11 Q Did you have the opportunity to review the
12 P-300-12, the U-1500-170, the orders that flowed from those
13 cases and how this Commission determined its methodology?
14 A I've reviewed a lot of those orders. I will
15 tell you I'm not going to be familiar with the case numbers
16 by themselves. You'll have to help me beyond that.
17 A You say on Page 4 of your testimony that
18 long-term resource acquisition commitments at predetermined
19 prices restrict purchasing flexibility and expose utility
20 shareholders and customers to significant risks, and when
21 you're saying "long-term resource acquisition," are you
22 speaking of contracts longer than how many years?
23 A Well, certainly 20-year contracts would
24 qualify. I think any contract in excess of one year would
25 certainly trigger the point at which you'd begin starting to
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1 look at the risks of inflexibility.
2 Q Do you know if rating agencies look at the, I
3 guess, percentage of QF purchases within a utility's
4 resource portfolio in determining whether there's some added
5 risk there?
6 A It's my understanding that they look both at
7 the quantity and at the price of those contracts.
8 Q And is it your understanding that rating
9 agencies have downrated Idaho Power for its QF resources?
10 A As far as I know, and I'm not specifically
11 familiar with what the agencies have said about Idaho Power,
12 I have not heard that they've downgraded Idaho Power yet.
13 Q Did you participate with Idaho Power at all in
14 formulating its integrated resource plan?
15 A No, I did not.
16 Q The demand curve and supply curves that you
17 talk about as a method to define optimal quantity and price
18 of new capacity, has this been employed by Idaho Power in
19 determining the optimal price for the Rosebud facility?
20 A No, it's merely an example.
21 Q To your knowledge, do any of the cited states,
22 do the utilities in those states use such a procedure for
23 determining price and resource?
24 A They certainly don't use a procedure that
25 matches exactly the drawing of a supply curve and a demand
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1 curve; however, the planning processes that they use and
2 implicit in a bidding procedure or even in a negotiation
3 procedure is an economic process quite similar to the
4 crossing of a supply and demand curve.
5 Q But you haven't attempted to perform such an
6 analysis with respect to the matter that we're considering
7 today?
8 A In effect, the discussions surrounding the
9 calculation of an avoided cost implicitly makes such a
10 calculation and that has been discussed at quite a length.
11 Q Did you participate in that calculation?
12 A No. I've had some discussions, but I did not
13 participate in the calculation, per se.
14 Q The capacity need-based approach that you
15 advocate, can that be satisfied by anything other than a
16 bidding mechanism?
17 A Yes.
18 Q And is Idaho Power's proposal to use its
19 integrated resource plan, I guess, also a method of
20 following this approach?
21 A Yes, it could be.
22 Q You state that the demand curve for capacity
23 is quite inelastic and that the quantity of desired
24 incremental capacity changes little as the price of capacity
25 changes, and then you conclude argument can be shown
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1 rigorously, but the level of proof is not necessary.
2 A Could you give me a page cite?
3 Q Yes, starting on Page 7, Line 18, following
4 that, your discussion of Exhibit 203.
5 A Okay, the idea there is that capacity as
6 distinct from energy has a value that's derived from what
7 customers are willing to pay in terms of its effect on
8 reliability; so the value of capacity arises because it --
9 basically, because if you don't have the capacity, the
10 customer is going to be unserved from an energy standpoint.
11 The value the customer places on that marginal energy then
12 works through the reliability calculations to determine a
13 marginal value of capacity.
14 Q You're essentially saying that this
15 demand-supply mechanism that you propose is a preferable way
16 to acquire and determine the need for future resources to
17 what we presently use for calculating the need for resources
18 in our present methodology?
19 A Let me understand the question specifically.
20 If what you're referring to in the present methodology is a
21 criterion based on a reserve margin from a capacity
22 standpoint, I think understanding what customers are willing
23 to pay for reliability and tying a criterion explicitly to
24 that would not be a bad idea. It could well be an
25 improvement.
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1 Q The need-based approach is in fact a part of
2 the existing methodology where we've determined a year for
3 first deficit is and we calculate that there should be no,
4 at least for a non-levelized rate, that there would be no
5 capacity payments made for that period, is that not a
6 need-based approach?
7 A Not strictly. The inductive leap you make is
8 that if there is a need, for example, in the year 2000 that
9 committing today but simply not paying a capacity payment
10 until the year 2000 is equivalent and in fact, it's not. My
11 testimony shows that entering into a fixed commitment today
12 reduces the flexibility of the utility. That loss of
13 flexibility has an explicit cost which can be quantified and
14 is in fact part of the avoided cost calculation, or should
15 be in my opinion, that should be used as the basis for
16 negotiation for projects over 10 megawatts.
17 Q And do you know whether that factored into
18 Dr. Willmorth's calculation of the rates that were offered
19 to Rosebud?
20 A As far as I know, it did not enter into it in
21 an explicit way. Certainly, the discussions from the
22 Company concerning the risks of entering into contracts
23 prior to need are an informal way of getting at the same
24 issue.
25 Q The two systems, two approaches, that you
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1 distinguish are the need-based approach and the price-based
2 approach?
3 A I'm sorry, what is the question?
4 Q Need-based and price-based?
5 A Those are the two I mentioned.
6 Q And you characterize the existing methodology
7 as being a price-based?
8 A If the existing methodology presumes that all
9 comers seeking contracts can get it at a stipulated
10 administrative price, then it is essentially a price-based
11 approach.
12 Q Regardless of -- how would you characterize
13 the trigger mechanism which is part of the existing
14 methodology?
15 A I would characterize the trigger mechanism as
16 a mechanism to adjust for one of the many factors that can
17 change between the time of setting the
18 administratively-determined avoided cost rates and the time
19 of negotiation of any given contract; so in a sense, it's a
20 partial adjustment. It by no means is a complete adjustment
21 for changes that occur between the setting of the
22 administratively-determined avoided cost rates and any
23 contract entered into at a later date.
24 Q When you say on Page 16, starting about
25 Line 3, that long-term fixed commitments are risky, are you
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1 saying that a utility that would enter into such contracts
2 would be imprudent?
3 A No. It would depend on the nature of the
4 contract and the nature of the alternatives.
5 Q If the nature of the contract is a contract
6 which the Company is required to sign as a result of federal
7 law, how does that play into your free market?
8 A I would hope if the nature of the contract,
9 all the contract terms and the price are required by federal
10 law, if that were the case, I would hope, at least from the
11 standpoint of determining what costs can be passed on to
12 ratepayers, it would not be deemed imprudent.
13 Q You state that the long-term fixed commitments
14 create exposure and you are talking about exposure to the
15 Company and to its ratepayers. Can that exposure be
16 addressed in contract terms?
17 A You could certainly offset that exposure
18 through a suitable reduction in the price. I mean, there's
19 certainly a risk-reward trade-off inherent in these
20 contracts the same way there are in many financial
21 instruments; so a suitable reduction in price could offset
22 the inherent risk and make such as contract attractive to
23 the utility.
24 Q The appendix to your testimony, Appendix B,
25 which is an article --
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1 A Yes.
2 Q -- Irreversibility, Uncertainty, and
3 Investment, does that have uniform applicability to both
4 unregulated entities and regulated utilities?
5 A It certainly doesn't make any distinguishment
6 from the standpoint of the nature of the asset. What would
7 be different is who bears the resulting costs.
8 Q It would not be your belief that Idaho Power
9 operates in a truly competitive market at this time?
10 A It is my belief they do not at this time.
11 Q And to the extent that they do not operate in
12 such a market, can it be expected that they may not have the
13 flexibility which would otherwise be desired?
14 A I think the question of whether the market is
15 perfectly competitive is distinct from whether they have and
16 should have purchasing flexibility.
17 Q When I speak of "competitive market," I guess
18 the way I'm saying it's not competitive is that there are
19 some resources which the Company is required to purchase.
20 A At some price, yes.
21 Q At some price, yes.
22 COMMISSIONER MILLER: Mr. Woodbury, I think
23 it's time for our afternoon recess. If you have just one or
24 two questions left, we could finish them up; otherwise,
25 we'll take our recess now.
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CSB REPORTING PARKINSON (X)
Wilder, Idaho 83676 Idaho Power
1 MR. WOODBURY: Actually, I don't think I have
2 any further questions.
3 COMMISSIONER MILLER: All right, thank you,
4 Mr. Woodbury. With that, we will take a 15-minute recess
5 and resume at 3:15 promptly.
6 (Recess.)
7 COMMISSIONER MILLER: All right, we'll resume
8 our hearing with Dr. Parkinson on the stand and,
9 Mr. Orndorff, I think we're ready for you.
10 MR. ORNDORFF: I have no questions,
11 Mr. Chairman.
12 COMMISSIONER MILLER: Questions from the
13 Commission. Commissioner Nelson.
14 COMMISSIONER NELSON: I have none. Thank you.
15 COMMISSIONER MILLER: Commissioner Smith.
16 COMMISSIONER SMITH: Nor I.
17 COMMISSIONER MILLER: Nor I, Doctor. Thank
18 you for your help, though.
19 THE WITNESS: You're welcome.
20 COMMISSIONER MILLER: We'll see you again,
21 perhaps.
22 THE WITNESS: Quite possibly.
23 (The witness left the stand.)
24 MR. KLINE: I'd like to call John Church as
25 Idaho Power's next witness.
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CSB REPORTING PARKINSON (X)
Wilder, Idaho 83676 Idaho Power
1 JOHN S. CHURCH,
2 produced as a witness at the instance of the Idaho Power
3 Company, having been first duly sworn, was examined and
4 testified as follows:
5
6 DIRECT EXAMINATION
7
8 BY MR. KLINE:
9 Q Mr. Church, could you please state your name,
10 business address and present position with Idaho Power
11 Company?
12 A My name is John Church. My business address
13 is 1221 West Idaho. I am corporate economist with Idaho
14 Power Company.
15 Q And have you previously filed testimony in
16 this case, Mr. Church?
17 A Yes, I have.
18 Q And along with that prefiled testimony, did
19 you also file Exhibits 210, 211, 212 and 213?
20 A Yes, I did.
21 Q Mr. Church, do you have any additions or
22 corrections that you need to make to either your prefiled
23 direct testimony or the four exhibits I just mentioned?
24 A No, I do not.
25 Q If I were today to ask you the same questions
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CSB REPORTING CHURCH (Di)
Wilder, Idaho 83676 Idaho Power
1 that are contained in your prefiled direct testimony, would
2 your answers be the same?
3 A Yes.
4 MR. KLINE: With that, Mr. Chairman, I would
5 request that Mr. Church's testimony be spread on the record.
6 COMMISSIONER MILLER: So ordered, and
7 Exhibits 210 through 213 will be marked.
8 MR. KLINE: Thank you.
9 (The following prefiled testimony of Mr. John
10 Church is spread upon the record.)
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CSB REPORTING CHURCH (Di)
Wilder, Idaho 83676 Idaho Power
1 Q Please state your name, business address and
2 present position with Idaho Power Company (Idaho Power).
3 A My name is John S. Church and my business is
4 1221 W. Idaho Street, Boise, Idaho. I am Corporate
5 Economist for Idaho Power Company.
6 Q What is the purpose of your testimony in this
7 proceeding?
8 A The purpose of my testimony in this proceeding
9 is to address Mr. Slaughter's criticisms of the Company's
10 load and economic forecasts. While I cannot specifically
11 determine from Mr. Slaughter's direct testimony, the exact
12 documents which contain the forecasts he criticizes, I
13 believe that he is referencing Idaho Power Company's
14 Integrated Resource Plan of January 1993, (IRP). The IRP
15 has been provided in this case as Dr. Willmorth's Exhibit
16 No. 205.
17 Q What is your general opinion of Mr.
18 Slaughter's testimony with regard to its accuracy and
19 completeness in characterizing Idaho Power's load forecast?
20 A Mr. Slaughter paints a picture which is both
21 inaccurate and misleading. He has chosen only those parts
22 of the IRP's load and economic forecasts which are suitable
23 to the premise that he wants to put forth.... "the Company's
24 projection may (be) low."
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CHURCH, Di
Idaho Power Company
1 (Mr. Slaughter's testimony, page 5, line 11 and continued on
2 line 12.) He then goes on to defend his premise using
3 innuendo and inaccurate statements which are not based on
4 all of the facts available to him.
5 Q Please provide an example.
6 A On page 3, line 30 to 31, and continuing on to
7 lines 1 through 3 of page 4, the following question is
8 asked:
9 "The Idaho Power load forecast in the 1993 Integrated
10 Resource Plan shows long-term load growth averaging
11 1.4% per year, 2.1% between 1992 and 1998, while the
12 Commission has adopted a load growth assumption of
13 3.25%. How would you evaluate these forecasts?"
14 Idaho Power's load forecast, with off system firm surplus
15 sales, does show a long-term (1992 to 2014) rate of growth
16 of 1.4%, and during the years 1992 to 1998, again with off
17 system firm surplus sales included, the load forecast does
18 show 2.1%. However, Mr. Slaughter does not acknowledge the
19 fact that excluding the firm off-system surplus sales which
20 automatically expire and can be terminated by the Company
21 when the resource is needed, the true underlying rate of
22 growth is 1.9% per year over the 1992 to 2014 period or 2.3%
23 per year in the 1992 to
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CHURCH, Di
Idaho Power Company
1 1998 period. The forecasted 2.3% per year is a faster rate
2 of increase than that which has actually occurred in the
3 previous five years, despite the fact that the previous five
4 years are some of the highest economic growth years that
5 have occurred in the Idaho Power service area. Exhibit No.
6 210 visually depicts this aspect of Idaho Power's forecast.
7 Q Please address Mr. Slaughter's reference to
8 the load growth assumption of 3.25%.
9 A This assumption, while used as a premise in
10 the surrogate avoided cost methodology established in 1990
11 may not have a good foundation in reality today. Again,
12 during the years 1988 to 1992, five of the fastest years of
13 growth in Idaho's economy and in the Idaho Power service
14 area, native load growth (without firm off-system sales) has
15 grown at a rate of 2.25% per year. This is the equivalent
16 of an increase of annual sales of 1,279,000 MWH. In the
17 IRP, during forecast period of 1992 to 1998, the Company is
18 expecting an increase in sales of 1,717,000 MWH.
19 This is the forecast that is in the IRP and it says that
20 load growth will grow faster in absolute numbers in the next
21 five years than it has in the previous five years.
22 Mr. Slaughter is inappropriately using the numbers to fit
23 the erroneous picture that
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CHURCH, Di
Idaho Power Company
1 he is attempting to paint.
2 Q What would the long-term outlook be like if
3 the 3.25% per year figure that Mr. Slaughter referred to
4 were the actual outcome.
5 A If Idaho Power's forecast of electricity sales
6 (without firm off-system sales) were increased at a 3.25%
7 per year rate to the year 2014 it would result in an average
8 annual load of 660 MW (5,761,600,000 kWh) higher than in the
9 Company's base scenario load forecast.
10 To put this another way, if a growth of 3.25% per year
11 is assumed in forecasted loads, and Idaho Power's historical
12 use per residential customer remains at nearly 14,000 kWh
13 per year, as it has for the last twelve years, and given the
14 historical proportion that residential sales have been to
15 total sales (nearly 32%), then the Idaho Power Service area
16 would have a higher household number of nearly 132,00
17 households, and an additional population of nearly 318,000
18 in the year 2014. In addition, the total service area
19 population would be nearly 1,236,000 with a state population
20 of 1,680,000. That would correspond to a rate of population
21 growth of 3.7% per year over the 1992 to 2014 period, nearly
22 four times the national rate. Even in the 1970s, with the
23 rapid expansion of Idaho's economy, it only grew at an
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CHURCH, Di
Idaho Power Company
1 annual average compound rate of 2.8% (that is on a much
2 smaller base). The Pacific Northwest Power Planning
3 Council's high scenario (which they gave a low probability
4 of occurrence) is for an Idaho population of 1,474,000 in
5 2010. Mr. Slaughter infers that we should acquire resources
6 now on the speculation and low probability that Idaho's
7 population would be higher than the highest published
8 scenario for the state.
9 Arguably, Mr. Slaughter could also speculate that use
10 per customer will increase to meet his desired 3.25% rate of
11 growth in electric loads rather than additional population
12 growth. If so, the average for the last twelve years
13 (nearly 14,000 kWh per residential customer) would have to
14 increase to 18,000 annual kWh per residential customer by
15 the year 2014.
16 Q Does Mr. Slaughter make any further inferences
17 about the Company's load forecast?
18 A Yes, on page 4 line 19 of his direct
19 testimony, he refers to the 6.4% Company total sales growth
20 in 1991 and infers that this is inconsistent with the long
21 term rate of 1.7%. In this particular case he fails to
22 mention that the 1991 sales figures that he cites includes a
23 59% increase in firm off-system sales. If just the
24 incremental increase in the firm off-system sales is removed
25 from
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CHURCH, Di
Idaho Power Company
1 the total sales, the 1991 percentage increase drops to 1.5%.
2 This is shown in Exhibit No. 211, page 1, and visually
3 depicted on page 2 of Exhibit No. 211.
4 In addition, he consistently implies that because the
5 growth rate in sales, or population, or households, falls
6 over time the Company is biasing the forecast. Mr.
7 Slaughter's testimony on this is a smokescreen and an
8 obvious deception. Most anyone could tell you that 2.5% of
9 23,000 is 575 and that 1.7% of 35,000 is 595. A smaller
10 percentage on a larger number is not an absolute decrease.
11 I should point out that the numbers 23,000 and 35,000 are
12 approximately the Company's projected 1993 and 2014 firm
13 sales figures in millions of kWh. By drawing these
14 inferences in his testimony, Mr. Slaughter is being
15 extremely misleading.
16 Q Does Mr. Slaughter present any testimony
17 relating to the underlying population and employment
18 projections that went into the IRP load forecast?
19 A Yes, he does, and his presentation of these
20 points is also done in such a way as to present a very
21 misleading conclusion. For example, Mr. Slaughter cites the
22 Idaho Department of Financial Management's (DFM's) forecast
23 and an unidentified Bonneville
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CHURCH, Di
Idaho Power Company
1 Power Administration forecast of Idaho population and
2 nonagricultural employment, as being higher than Idaho
3 Power's. But, he fails to mention the fact that both of
4 these forecasts were made in April and July of 1993. As the
5 former Chief Economist for the Idaho Department of Financial
6 Management, I am sure Mr. Slaughter knows that a forecast is
7 predicated on a view of the world and it's prospects based
8 on knowledge at a particular point in time. He has failed
9 to point out that the forecast comparisons to the Idaho
10 Power forecast he presents are based on different time
11 frames. He is comparing apples and oranges in a way he must
12 know is misleading.
13 Q Would a comparison of the Idaho Power forecast
14 to an Idaho Department of Financial Management forecast made
15 at nearly the same time create a different picture than the
16 one offered by Mr. Slaughter?
17 A Yes, Exhibit No. 212, page 1, reviews some of
18 the past DFM forecasts. The economic forecast of the
19 Company's which is dated December 1992, and due to the lead
20 time necessary to fully integrate all of the items necessary
21 for the Resource Management Report, was actually completed
22 in August 1992, and the January 1993 DFM forecast, are the
23 closest in time, when based on
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CHURCH, Di
Idaho Power Company
1 publication date. Page 2 of Exhibit No. 212 visually
2 depicts the comparison of nonagricultural employment. The
3 Company's forecast for 1995 was very close to the DFM
4 forecast, a difference of 14,400 lower in population (1.3%),
5 and 1,290 higher (0.3%) in nonagricultural employment. The
6 Bonneville Power Administration did have a forecast with a
7 more comparable origination date. BPA's June 1992 forecast
8 is consistently lower than the Company's. This is also
9 shown in Exhibit No. 212, page 1 and visually for
10 nonagriculture employment on page 3 of the Exhibit. The
11 Pacific Northwest Power Planning Council's economic
12 forecasts for the Northwest states provided another
13 comparison that Mr. Slaughter overlooked. The Company's
14 economic outlook for the two key summary measures fell above
15 the Council's medium high scenario and just below their high
16 scenario. This is also shown in Exhibit No. 212 at lines 13
17 through 17 for population and lines 33 through 37 for
18 nonagricultural employment, and for nonagricultural
19 employment is visually depicted on page 4 of the Exhibit.
20 Q Does Mr. Slaughter leave anything else out of
21 his comparison to the other economic forecasts?
22 A Yes he does. While he does mention the newer
23 (July 1993) BPA
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CHURCH, Di
Idaho Power Company
1 forecast as being higher than the Company's in the
2 short-term (planting the rather obvious inference that the
3 Company's forecast is bias downward) he fails to mention
4 that at the end of the forecast period the Company outlook
5 is consistently higher in terms of Idaho population and
6 nonagricultural employment. It is also higher in its
7 outlook for employment in manufacturing, food processing,
8 lumber, machinery, and electronics. The Company's forecast
9 also is higher for Wholesale and Retail Trade employment,
10 for employment in Services, for Government employment, and
11 for per capita and total personal income. Mr. Slaughter
12 fails to mention any of these facts in presenting his
13 deliberately abbreviated numbers. I say deliberately
14 abbreviated numbers because upon discovery the Company found
15 that Mr. Slaughter had the time series information available
16 to him to the year 2015. Exhibit No. 212, page 5, which is
17 the table found on page 1 of the Exhibit, has been changed
18 so as to depict the forecasted figures which are lower than
19 the Company's forecast. The shaded areas represent those
20 forecasted figures which are lower than the Company's
21 forecast for the state or service area.
22 Q You mentioned in response to a previous
23 question the growth in Idaho and Idaho Power's service
24 territory. Is there a distinction
25
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CHURCH, Di
Idaho Power Company
1 between the two?
2 A Yes, there is a definite distinction between
3 the State of Idaho and the Company's service area that Mr.
4 Slaughter ignores throughout his testimony. As most are
5 aware, Idaho Power Company does not serve all of the state.
6 Exhibit No. 213 provides a visual representation of the
7 Company's service area.
8 Q Does an overall view of Mr. Slaughter's
9 analysis of the forecast provide any sense of confidence as
10 to the degree of analysis of the materials that were
11 available to Rosebud?
12 A No it does not. In many instance Mr.
13 Slaughter has merely thrown out statements that are
14 inaccurate and that he can easily step aside from when they
15 are questioned.
16 For example: On page 8, lines 15 through 17 in
17 referring to the IRP, he states; "The economic forecast
18 shows five scenarios, but the load forecast is done only
19 with the base case of 1.4%." This is not true and even with
20 a cursory reading of the IRP load forecast it would be
21 readily evident that the load forecast documentation states
22 throughout, in numerous tables, that five scenarios were
23 performed.
24 Also on page 18, lines 11 through 13 he states; "In the
25 1980's, even with years of contraction and rising relative
electric
678
CHURCH, Di
Idaho Power Company
1 prices, the compound rate was 1.9%." This statement is
2 overly simplistic and inaccurate. He does not refer to the
3 fact that many "special" occurrences in the 1980s caused a
4 low growth in electricity sales. First, the 1980-1982
5 recession should not be overlooked, but, to add to that, the
6 ending of the sales contract to CP National (which is
7 included in the time series that Mr. Slaughter used to
8 calculate the 1.9% he references), and the 1986 turndown in
9 the electronics industry, all had significant impacts on
10 Idaho Power's load growth.
11 Furthermore, while real electric prices have fallen
12 during most of the 1980s a comparison to the overall price
13 level is not an adequate comparison. What Mr. Slaughter
14 fails to mention is that while electricity became relatively
15 cheaper in coted, but also any questions we feel
6 are essential and it wouldn't just state the points but
7 argue the points as well?
8 COMMISSIONER MILLER: Yes, but recognizing
9 that we have listened to this case very attentively so
10 there's not a need for long recaps of the evidence.
11 MR. FELL: Yes, I would try not to lose your
12 attention.
13 COMMISSIONER MILLER: All right, let's admit
14 all the exhibits that have been previously marked and not
15 admitted.
16 (All exhibits previously marked for
17 identification were admitted into evidence.)
18 COMMISSIONER MILLER: Mr. Woodbury, would you
19 mind informally notifying the other parties to the case who
20 aren't here this afternoon of the briefing or comment
21 schedule that we've established in case they want to do
22 anything?
23 MR. WOODBURY: Yes, I will do it.
24 COMMISSIONER MILLER: With that, if there's
25 nothing else, thank you for all your hard work. We'll try
745
CSB REPORTING COLLOQUY
Wilder, Idaho 83676
1 and do as good a job as you've done. We'll adjourn this
2 hearing and hold the record open for the receipt of
3 posthearing submissions and decide as promptly as we can
4 after that. We're adjourned.
5 (The Hearing concluded at 4:45 p.m.)
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CSB REPORTING COLLOQUY
Wilder, Idaho 83676
1 AUTHENTICATION
2
3
4 This is to certify that the foregoing proceedings
5 held in the matter of Rosebud Enterprises, Inc.,
6 Complainant, versus Idaho Power Company, Respondent,
7 continuing at 9:00 a.m., on Tuesday, January 11, 1994, at
8 the Commission Hearing Room, 472 West Washington, Boise,
9 Idaho, is a true and correct transcript of said proceedings
10 and the original thereof for the file of the Commission.
11 Accuracy of all prefiled testimony as
12 originally submitted to the Reporter and incorporated herein
13 at the direction of the Commission is the sole
14 responsibility of the submitting parties.
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18 CONSTANCE S. BUCY
Certified Shorthand Reporter.
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Wilder, Idaho 83676