AVIS1192.docx

1 BOISE, IDAHO, WEDNESDAY, JANUARY 19, 2000, 1:15 P. M.
2
3
4 COMMISSIONER SMITH: All right, let's go
5 back on the record. I think just before we broke for
6 lunch Mr. Ward had passed out a document that we have
7 neglected to officially mark for the record.
8 MR. WARD: Thank you, Madam Chair. That
9 document is the Avista/Potlatch agreement and I'd ask
10 that it be identified as No. 204.
11 COMMISSIONER SMITH: Okay, we'll mark this
12 multi-page document as Exhibit 204.
13 (Potlatch Corporation Exhibit No. 204
14 was marked for identification.)
15 COMMISSIONER SMITH: Mr. Dahlke.
16 MR. DAHLKE: Just a comment. If I make a
17 mistake and inadvertently refer to Water Power or
18 Washington Water Power, I hope everybody will forgive me,
19 and also that I've heard this mistake, too, and just so
20 everybody knows, it may not be intuitively obvious from
21 the spelling, but the pronunciation is Avista with a
22 short "i."
23 COMMISSIONER SMITH: Mr. Ward is marking
24 that down, and we're all still being retrained on the
25 Water Power change. Okay, we were to Mr. Woodbury.
183
CSB REPORTING COLLOQUY
Wilder, Idaho 83676
1 MR. WOODBURY: Thank you, Madam Chair.
2
3 RONALD L. McKENZIE,
4 produced as a witness at the instance of Avista
5 Corporation, having been previously duly sworn, resumed
6 the stand and was further examined and testified as
7 follows:
8
9 CROSS-EXAMINATION
10
11 BY MR. WOODBURY:
12 Q Mr. McKenzie, as part of -- there was an
13 exchange between you and Mr. Ward regarding Potlatch and
14 Potlatch's options, I guess, at the expiration of the
15 current service agreement with Avista and you had
16 expressed a thought that Potlatch could easily bypass at
17 that time and so I'm guessing, have you had the
18 opportunity to consider your response and is it necessary
19 to make any changes?
20 A Yes. My response was incorrect. I was
21 mistaken. Under the present rules, Potlatch cannot leave
22 the Company's system.
23 Q The company does have the ability or could
24 self-generate if they chose, couldn't they, Potlatch?
25 A Yes.
184
CSB REPORTING McKENZIE (X)
Wilder, Idaho 83676 Avista
1 Q I have a question, maybe you can clarify,
2 with respect to the pricing of the coal inventory. Is it
3 your understanding that we're talking about in place or
4 mined coal?
5 A The coal inventory is mined coal from the
6 mine that's in a stockpile and that portion of the
7 stockpile that exists at the time of the sale will be
8 sold along with the plant.
9 Q Okay, and it was also my understanding from
10 the Company's testimony this morning that most of the
11 fuel requirements for Centralia are satisfied with
12 Centralia mine coal?
13 A Yes.
14 Q And yet, for pricing purposes, it's going
15 to be determined by the cost of the last 100,000 tons of
16 rail coal?
17 A That's correct. That's what the contract
18 specifies in determining a price for the stockpiled coal.
19 Q Is there a contractual commitment to
20 purchase rail coal at Centralia?
21 A I don't know if there's a commitment. I
22 know that they take advantage of rail coal purchases from
23 time to time, but I don't know about a commitment.
24 Q You're unaware whether there might exist a
25 long- or a short-term contract?
185
CSB REPORTING McKENZIE (X)
Wilder, Idaho 83676 Avista
1 A I don't know.
2 Q Referring to your direct testimony on
3 page 4, you speak of the Company's proposed offset to any
4 portion of gain allocated to customers. Apart from the
5 ice storm, the remaining offset items are already being
6 amortized in rates?
7 A Yes, that's correct.
8 Q And you specifically mention that you felt
9 that the amortization period for the Nez Perce lawsuit
10 settlement was 45 years. Are you aware of the
11 amortization periods for the other two or would you
12 accept that the PURPA contract buy-out cost is an
13 eight-year amortization period and the remaining
14 transition obligation for post-retirement benefits is 20
15 years?
16 A I'll accept that, subject to check. What I
17 did was I calculated a remaining amortization at the end
18 of April 2000.
19 Q Do you know the remaining unamortized years
20 for each of those items?
21 A Yes.
22 Q What would that be?
23 A For post-retirement benefits, other than
24 the pension transition costs, approximately 12 2/3
25 years. The Wood contract, PURPA, Wood Power, Inc., PURPA
186
CSB REPORTING McKENZIE (X)
Wilder, Idaho 83676 Avista
1 contract buy-out is approximately 4.95 years at that
2 time, and then I didn't precisely calculate the Nez Perce
3 settlement payment, but it would be somewhere between 44
4 and 45 years.
5 Q Could you please explain the customer
6 benefit in accelerating the amortized recovery of these
7 amounts?
8 A Well, the customer benefit of writing off
9 all or a portion of the unamortized balance would mean
10 that in the future rates would not have to recover
11 amortization of the amounts written off.
12 Q Aren't there benefits that the Company
13 would receive in this proposal by faster recovery of an
14 allowed amortization such that your cash flow would
15 improve and your financing requirements would decrease?
16 A I think cash flow would be the same unless
17 you made rate adjustments and to the extent that you did
18 make rate adjustments, that could affect the cash flow.
19 Q And if the Commission adopted the Company's
20 proposal for offset, it removes some uncertainty related
21 to deregulation and continued recovery of regulatory
22 assets?
23 A Generally, I would accept that, yes.
24 Q Will the gain on the sale be known and
25 measurable once the sale closes?
187
CSB REPORTING McKENZIE (X)
Wilder, Idaho 83676 Avista
1 A Yes. At some point all of the sales price
2 amounts and adjustments will actually be known.
3 Q Within a known time frame?
4 A The contract specifies certain time frames
5 for -- one of the big adjustments is the sale of the coal
6 mine, that's a zero gain situation, so a portion of the
7 sales price will offset the remaining cost of the mine
8 and then the remainder of the sales price will be
9 allocated to the sale of the plant, and there's
10 provisions in the contract for auditing the coal mine
11 sale, for truing-up the plant balances and then after
12 that there would be a true-up of all other costs
13 associated with the sale. We did respond to a Staff data
14 request that kind of laid out those time frames.
15 Q Will the annual costs to replace Centralia
16 generation be known and measurable at the closing of the
17 sale?
18 A I'm sorry, could you repeat that, please?
19 Q Will the annual costs to replace the
20 Centralia generation be known and measurable at the time
21 of closing?
22 A On a long-term basis, I would say no, not
23 precisely. We would have estimates. On a short-term
24 basis, to the extent that we've made replacement power
25 purchases, yes.
188
CSB REPORTING McKENZIE (X)
Wilder, Idaho 83676 Avista
1 Q A short-term basis being how many, what
2 length of time?
3 A Probably the one- to three-year period that
4 was discussed with Mr. Johnson.
5 Q On page 4 of your rebuttal testimony, you
6 speak of inconsistency in Staff's testimony, Staff
7 witnesses Stockton and Lobb. Did you understand
8 Ms. Stockton's testimony to be dealing with the gain and
9 Mr. Lobb's testimony to be dealing with power supply
10 costs?
11 A No, it was my understanding of
12 Ms. Stockton's testimony that she was referring to the
13 offset items and unless rates were adjusted when the
14 unamortized balances were offset against the gain that
15 there would be an overrecovery of costs, not that the
16 gain would cause an overrecovery, but the fact that rates
17 weren't adjusted for the offsets being written down.
18 Q Okay, and would you agree that those items
19 that Ms. Stockton was testifying about are not power
20 supply items?
21 A That's correct, they're not power supply
22 items. The Wood Power, Inc. contract buy-out is a PURPA
23 contract buy-out and that is a power supply cost.
24 Q And you didn't read Mr. Lobb's testimony as
25 indicating that power supply replacement costs are not
189
CSB REPORTING McKENZIE (X)
Wilder, Idaho 83676 Avista
1 known and measurable?
2 A I recall the statement he made that talked
3 about replacement costs being projected to be higher than
4 the current costs of Centralia built into rates. I don't
5 recall if he specifically said they were speculative, but
6 in the short term they are a lot less speculative and we
7 may have even quantified them.
8 Q You would agree that the Company's own
9 witness testifies to the speculative nature of
10 replacement power costs?
11 A In the long term, yes, but the short term,
12 like I said, there may be no speculation.
13 Q Well, at the time the Company filed its
14 testimony in this case you had no replacement resources.
15 A That's correct, yes.
16 MR. WOODBURY: Madam Chair, Staff has no
17 further questions of this witness.
18 COMMISSIONER SMITH: Thank you,
19 Mr. Woodbury.
20 Do we have questions from the
21 Commissioners? I just have a couple. They may seem very
22 simple-minded, but maybe you can help me.
23
24
25
190
CSB REPORTING McKENZIE (X)
Wilder, Idaho 83676 Avista
1 EXAMINATION
2
3 BY COMMISSIONER SMITH:
4 Q In thinking about the contract that the
5 Company has with Potlatch and, you know, it's true, like
6 you say, those rates don't fluctuate like in a rate case,
7 they're set by the contract, when you set the rates,
8 wouldn't you have looked at your current inventory of
9 resources and set a rate that maybe covered those costs
10 so that in effect Potlatch's rates did support recovery
11 of costs for the plants that you were operating?
12 A The rates do recover the incremental costs
13 of resources within a floor and a ceiling and it was what
14 Mr. Ward ran me through in the contract, it's the last
15 incremental resource or the last incremental cost and
16 Potlatch pays the actual cost to the extent they're
17 within the bounds of the floor and the ceiling.
18 Q Well, I guess my thought being that should
19 the Commission decide that a portion of the gain ought to
20 be returned to ratepayers and that Potlatch is one of the
21 ratepayers that helped provide revenue to support this
22 resource, then there ought to be maybe some recognition
23 of that in them getting a portion of the gain.
24 A Well, I would argue that they haven't
25 supported the costs of the Centralia resource, that they
191
CSB REPORTING McKENZIE (Com)
Wilder, Idaho 83676 Avista
1 have been basically paying market-based rates.
2 Q Have those been higher or lower than
3 Centralia?
4 A I don't know. I would guess that they were
5 lower, but that's just a guess. I haven't made an
6 analysis.
7 COMMISSIONER SMITH: That's all.
8 Mr. Dahlke, do you have redirect?
9 MR. DAHLKE: Yes.
10
11 REDIRECT EXAMINATION
12
13 BY MR. DAHLKE:
14 Q Mr. McKenzie, you were asked some questions
15 about Mr. Johnson's Exhibit No. 1 and the year 2000 cost
16 for Centralia of $26.45 shown on that exhibit. Do you
17 recall that?
18 A Yes.
19 Q And do you know whether the costs of
20 Centralia currently built into Avista's rates are based
21 on year 2000 costs or are they based on a different time
22 period?
23 A They're based on a different time period.
24 The test period used in our last general rate case was
25 1997.
192
CSB REPORTING McKENZIE (Di)
Wilder, Idaho 83676 Avista
1 Q And do you know whether the costs of
2 Centralia would likely be, as they're built into rates
3 based on that 1997 test period, are they likely to be
4 different than the $26.45 that's the estimate that
5 Mr. Johnson had on Exhibit No. 1?
6 A Yes, I believe that they're lower than 2000
7 costs.
8 Q And are there other references in the
9 record that we have here for this proceeding to answer
10 that question?
11 A At page 3 of Mr. Lobb's direct testimony,
12 beginning on line 11, he states that, "Finally, my
13 analysis shows that the revenue requirement for Centralia
14 replacement alternatives is projected to be higher in the
15 future than the Centralia revenue requirement currently
16 included in rates."
17 MR. DAHLKE: Thank you. That's all I had.
18 COMMISSIONER SMITH: Thank you,
19 Mr. Dahlke.
20
21
22
23
24
25
193
CSB REPORTING McKENZIE (Di)
Wilder, Idaho 83676 Avista
1 EXAMINATION
2
3 BY COMMISSIONER SMITH:
4 Q Actually, I thought of one more question,
5 so I jotted it down and it was with regard to your
6 comment to Mr. Ward that Potlatch was free to leave after
7 the contract expired and then your subsequent correction
8 to Mr. Woodbury. There is, of course, one way under
9 existing law that Potlatch is free to leave and that's if
10 the Company consents, so do you know whether or not
11 Avista would consent to Potlatch shopping elsewhere at
12 the conclusion of its contract?
13 A I don't know. I can't answer that.
14 COMMISSIONER SMITH: Thank you for your
15 help.
16 (The witness left the stand.)
17 MR. DAHLKE: That concludes the Company's
18 witnesses on direct and rebuttal. There was a question
19 of Mr. Ely which he was unable to answer concerning the
20 FERC order on approval of the sale to TECWA and I would
21 like to distribute the order. We have a copy of that if
22 there's no objection. I don't know that it's necessary
23 that it be placed on the record. This is just
24 informational.
25 COMMISSIONER SMITH: The Commission has
194
CSB REPORTING McKENZIE (Com)
Wilder, Idaho 83676 Avista
1 been empowered by our rules to take official notice of
2 FERC orders, so probably that's the best thing for us to
3 do in this case.
4 (Mr. Dahlke distributing documents.)
5 COMMISSIONER SMITH: All right, now we have
6 witnesses from the Staff and from Potlatch. Have either
7 of you a preference for proceeding purposes?
8 MR. WARD: We're ready.
9 COMMISSIONER SMITH: Okay, Mr. Ward, do you
10 want to call your witness?
11
12 DENNIS E. PESEAU,
13 produced as a witness at the instance of Potlatch
14 Corporation, having been first duly sworn, was examined
15 and testified as follows:
16
17 DIRECT EXAMINATION
18
19 BY MR. WARD:
20 Q Dr. Peseau, would you please state your
21 name and address for the record?
22 A Yes, my name is Dennis E. Peseau, spelled
23 P-e-s-e-a-u, and I work at 1500 Liberty Street Southeast
24 in Salem, Oregon.
25 Q By whom are you employed and in what
195
CSB REPORTING PESEAU (Di)
Wilder, Idaho 83676 Potlatch
1 capacity?
2 A I am president of Utility Resources, Inc.
3 Q In preparation for this proceeding, did you
4 cause to be prepared certain prefiled testimony
5 consisting of some 25 pages?
6 A Yes.
7 Q And did you also prepare Exhibits No. 201
8 through No. 203?
9 A Yes, I did.
10 Q Dr. Peseau, do you have any corrections or
11 changes to your exhibit -- I mean to your testimony?
12 A Just one. It's a simple insert, but I
13 think it will need some explanation given the rebuttal
14 testimony of Mr. McKenzie written in this morning. The
15 change is on page 21 of my testimony, line 7. Between
16 the words "taxes" and "in" should be inserted "estimated
17 to be."
18 Q Okay, and what's the reason for that
19 change?
20 A The cite on page 1 of Exhibit 8 of the
21 Company does indicate that that number is an estimate and
22 I knew that all along. The problem was that whether the
23 estimate was exactly right or not, there was a portion of
24 that which has been flowed through to customers and would
25 be removed in the final disposition of the gain and so
196
CSB REPORTING PESEAU (Di)
Wilder, Idaho 83676 Potlatch
1 that number can't be exactly estimated at the writing of
2 this testimony or now.
3 Q Okay, thank you. With that correction, if
4 I were to ask you the questions contained in your
5 prefiled testimony today, would your answers be the same?
6 A Yes, they would.
7 MR. WARD: With that, Madam Chairman, I'd
8 request that Dr. Peseau's prefiled testimony be spread on
9 the record and Exhibits 201 through 203 be identified.
10 COMMISSIONER SMITH: If there's no
11 objection, it is so ordered.
12 (The following prefiled testimony of
13 Dr. Dennis Peseau is spread upon the record.)
14
15
16
17
18
19
20
21
22
23
24
25
197
CSB REPORTING PESEAU (Di)
Wilder, Idaho 83676 Potlatch
1 Q PLEASE STATE YOUR NAME AND BUSINESS
2 ADDRESS.
3 A My name is Dennis E. Peseau. My business
4 address is 1500 Liberty Street, S.E., Suite 250, Salem,
5 Oregon 97302.
6 Q BY WHOM ARE YOU EMPLOYED AND IN WHAT
7 CAPACITY.
8 A I am the President of Utility Resources,
9 Inc., ("URI").
10 Q PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND
11 AND WORK EXPERIENCE.
12 A My resume is attached as Exhibit No. 201.
13 I have testified before the Idaho Public Utilities
14 Commission on various revenue requirement and cost of
15 service issues on numerous occasions since the early
16 1980s.
17 Q FOR WHOM ARE YOU APPEARING IN THIS CASE?
18 A I am appearing on behalf of Potlatch
19 Corporation.
20 Q WHAT IS POTLATCH'S INTEREST IN THIS CASE?
21 A Potlatch's largest facility in terms of
22 energy consumption is the mill at Lewiston. Potlatch
23 also has three other facilities in northern Idaho that
24 are Schedule 25 customers. All four facilities receive
25 their electricity supplies from Avista.
198
D. PESEAU DI 2
POTLATCH CORPORATION
1 Q WHAT IS THE PURPOSE OF YOUR TESTIMONY?
2 A My testimony deals solely with the proper
3 allocation of the gain or profit from the sale of
4 Avista's 15% interest in the Centralia plant. In the
5 first portion of the testimony I will explain why an
6 allocation is necessary and critique the two allocation
7 methods proposed by Avista. My conclusion is that both
8 Avista proposals are unreasonable and prejudicial to
9 Avista's customers.
10
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
199
D. PESEAU DI 2a
POTLATCH CORPORATION
1 The second section of my testimony describes an
2 alternative method of allocating the gain that is fair to
3 both shareholders and customers and is consistent with
4 prior decisions of this Commission.
5 Q WHAT IS THE CONCEPTUAL BASIS FOR A PROPOSAL
6 TO SHARE THE GAIN ON THE SALE OF CENTRALIA?
7 A The principal concept underlying such a
8 proposal is that the gain from an asset sale should be
9 apportioned between ratepayers and shareholders in
10 accordance with their relative contribution to the
11 investment in the asset and the risks that result
12 therefrom. At the original date of commercial operation
13 of Centralia and its booking into plant in service or
14 rate base, Avista shareholders arguably contributed to,
15 or supported, 100% of the financing of the Centralia
16 plant. I say arguably because the reality of the
17 financial markets is that the regulatory obligation of
18 customers facilitates attractive financing terms, both in
19 terms of the price of debt and the amount of debt
20 leveraging deemed acceptable.
21 Once an asset is placed in rate base, regulation
22 in Idaho provides for both the return on (rate of return)
23 and return of (depreciation) shareholder investment in a
24 plant such as Centralia. Thus Avista's customers have
25 paid electric rates that have reflected not only the
200
D. PESEAU DI 3
POTLATCH CORPORATION
1 operating, maintenance, general and administrative
2 expenses associated with Centralia, but also a rate of
3 return on, and depreciation of, the investment in
4 Centralia. Since rates to customers include
5 depreciation, customers have been returning the
6 shareholders'
7
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
201
D. PESEAU DI 3a
POTLATCH CORPORATION
1 capital investment over time. In this sense, Avista
2 customers have been co-investing in Centralia. As
3 co-investors, customers should proportionally share in
4 any sale proceeds over and above the portion attributable
5 to the shareholders' remaining investment.
6 In legal terms, the ratepayers have acquired an
7 "equitable ownership interest" in Centralia as a result
8 of depreciation. This Commission has routinely
9 recognized that this equitable ownership interest is
10 entitled to participate in the gain on sale of
11 depreciable utility assets. There is no valid reason to
12 depart from the practice established by prior orders.
13 Q DO AVISTA'S PROPOSALS FOLLOW THE
14 ESTABLISHED PRACTICE OF ALLOCATING A PORTION OF THE GAIN
15 TO RATEPAYERS?
16 A No. In essence, both proposals allocate
17 100% of the gain to Avista's shareholders. The first
18 does so directly, the second by subterfuge.
19 Q WHAT IS AVISTA'S RATIONALE FOR THE
20 ALLOCATION OF 100% OF THE GAIN TO SHAREHOLDERS?
21 A The "direct" proposal advanced by
22 Mr. Dukich contains, as best I can determine, three
23 interrelated arguments for awarding the entire gain to
24 shareholders. First, Mr. Dukich contends that Avista has
25 often failed to achieve the rate of return authorized by
202
D. PESEAU DI 4
POTLATCH CORPORATION
1 the Commission, and shareholders are therefore entitled
2 to the Centralia gain to make up this shortfall.
3 Secondly, he argues that Avista's rates are among the
4 nations lowest, and
5
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
203
D. PESEAU DI 4a
POTLATCH CORPORATION
1 shareholders are entitled to the entire gain as a reward
2 for this "efficiency". Finally, he contends that
3 regulation unfairly deprives Avista of the full benefits
4 of its investments, and shareholders should be allowed to
5 keep this gain in order to compensate them for this
6 perceived inequity.
7 Q TURNING TO MR. DUKICH'S FIRST ARGUMENT,
8 THAT AVISTA HAS OFTEN FAILED TO ACHIEVE ITS AUTHORIZED
9 RATE OF RETURN. IS THIS AN ADEQUATE RATIONALE FOR THE
10 COMPANY'S PROPOSAL?
11 A No. In the first place, I do not accept
12 the company's factual assertion at face value.
13 Mr. Dukich's Exhibit No. 3 purports to show that Avista
14 failed to achieve its authorized rate of return in 20 of
15 the last 26 years. But of course, Avista is doing the
16 calculating in this exhibit. The first 17 years compare
17 "actual" results to the authorized rate of return, while
18 the last nine years utilize "Commission basis" results.
19 In the case of "actual" results, it is widely recognized
20 that they will almost always show a failure to achieve
21 the utility's authorized rate of return. This is because
22 booked results ordinarily contain a substantial number of
23 revenue and expense items that commissions adjust for
24 valid reasons. To a lesser degree, the same is true of
25 "Commission basis" results, as the Commission knows from
its experience in the last Avista rate case.
204
D. PESEAU DI 5
POTLATCH CORPORATION
1 Consequently, all Exhibit No. 3 proves is that the
2 Company clearly exceeded its authorized rate of return in
3 6 of the last 26 years. As to the other 20 years, we
4 don't know what the actual rates of return would be if
5 the booked results were subjected to a full regulatory
6 review. Nor do we know what Avista's authorized rate of
7 return should have been.
8 Q PLEASE EXPLAIN WHAT YOU MEAN BY THE
9 REFERENCE TO WHAT THE RATE OF RETURN SHOULD HAVE BEEN?
10 A Exhibit 3 shows that Avista's allowed rate
11 of return has been the same 10.95% from 1986 to 1999.
12 One must ask why Avista did not seek rate relief during
13 this 13 year period when its results were often less than
14 the authorized return? The answer is that the cost of
15 utility capital declined dramatically during this time
16 period, ultimately reaching new all-time post WWII lows.
17 Consequently, Avista's authorized rate of return was much
18 too high during most of this period, and the fact that it
19 was not achieved in many years does not mean that Avista
20 did not achieve a reasonable rate of return. In fact, my
21 own interpretation of Exhibit No. 3 is that Avista
22 probably exceeded a fair and reasonable rate of return in
23 most years since 1986.
24 Q DID YOU CONDUCT AN INDEPENDENT ANALYSIS TO
25 TEST THE VALIDITY OF EXHIBIT NO. 3?
205
D. PESEAU DI 6
POTLATCH CORPORATION
1 A No, for two reasons. In the first place,
2 testing the legitimacy of Avista's 26 years of results
3 would be a Herculean task. It would essentially amount
4 to an investigation equivalent to 26 years of
5
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
206
D. PESEAU DI 6a
POTLATCH CORPORATION
1 rate cases. Even if the information were available
2 twenty six years after the fact, I would not willingly
3 undertake the project, nor would my client or any other
4 reasonable person pay for it. Moreover, the whole
5 exercise would be irrelevant.
6 Q WHY DO YOU SAY IT WOULD BE IRRELEVANT?
7 A Because Avista's actual results are beside
8 the point. I don't want to paraphrase a full treatise on
9 ratemaking on this issue, so I will just cut to the
10 essential points.
11 First, an authorized rate of return is often
12 referred to as a "target rate of return". What this
13 means is that the regulator's charge is to set a rate of
14 return that a utility has a reasonable chance of
15 achieving with efficient management and reasonable luck.
16 But regulators cannot predict or factor in unknown
17 developments, which are more often negative than
18 positive. Moreover, the inexorable effects of inflation
19 eat away at a utility's returns from the first day a rate
20 order is in effect. Consequently, the utility industry
21 as a whole often fails to achieve its authorized rates of
22 return.
23 Regulators are repeatedly urged to, and presumably
24 do, take this factor into account when they establish the
25 authorized rate of return. Thus, bottom line results
207
D. PESEAU DI 7
POTLATCH CORPORATION
1 that are below the authorized rate of return are not ipso
2 facto unreasonable or confiscatory. To make the point
3 another way, a utility that consistently meets or exceeds
4 its
5
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
208
D. PESEAU DI 7a
POTLATCH CORPORATION
1 authorized rate of return should probably be hauled
2 before the Commission on a rate reduction proceeding.
3 Secondly, Mr. Dukich's argument obviously runs
4 afoul of the prohibition against retroactive ratemaking.
5 Even if we accepted Avista's argument that it has
6 experienced unreasonably low rates of return in the past
7 (which I do not), citing this alleged fact as grounds for
8 an extraordinary reward to shareholders in the present is
9 precisely the type of rationale that is prohibited by
10 Idaho law. If the prohibition against retroactive
11 ratemaking did not exist or was not honored, utility
12 shareholder investments would essentially be fully
13 guaranteed by the government, and the utility's rate of
14 return would presumably be limited to an amount roughly
15 equivalent to the interest rate on government bonds.
16 Q WHAT DO YOU MAKE OF MR. DUKICH'S SECOND
17 ARGUMENT THAT AVISTA'S MANAGEMENT AND SHAREHOLDERS SHOULD
18 RETAIN THE GAIN AS A REWARD FOR THE COMPANY'S EFFICIENCY
19 AND LOW RATES?
20 A Let me start by saying I am growing a
21 little weary of Avista's practice of routinely claiming
22 credit for what is primarily the work of the Almighty.
23 It is an admitted fact that Avista's electric rates
24 routinely rank among the three or four lowest in the
25 nation, and this has been the case throughout the nearly
209
D. PESEAU DI 8
POTLATCH CORPORATION
1 three decades that I have practiced in this industry.
2 But if you ask knowledgeable industry observers across
3
4 /
5
6 /
7
8 /
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
210
D. PESEAU DI 8a
POTLATCH CORPORATION
1 the nation what first pops into their mind when they
2 think of Pacific Northwest electric utilities, I
3 guarantee the answer will not be "management efficiency".
4 As everyone knows, low cost hydroelectric
5 generation is the dominant economic characteristic of
6 this region's electric utility industry. This wonderful
7 natural resource is clearly the primary reason for both
8 Avista's and Idaho Power's low rates.
9 Rate levels, in and of themselves, tell us little
10 or nothing about management efficiency. The best that
11 can be said is that in the distant past Avista's prior
12 management exploited this natural resource intelligently,
13 and successive management teams have thus far managed to
14 avoid bungling away this patrimony.
15 Q ARE YOU SUGGESTING THAT AVISTA'S MANAGEMENT
16 IS NOT EFFICIENT?
17 A No. In the absence of evidence to the
18 contrary, I assume they are capable and efficient. But
19 both shareholders and ratepayers are entitled to expect
20 and demand efficiency and capable performance as a
21 minimum. Extra awards for management performance are
22 both unreasonable and unnecessary. Truly extraordinary
23 management will be amply rewarded without imposing
24 unreasonably high rates on captive utility customers.
25 Q WHAT DO YOU MEAN WHEN YOU SAY EXTRAORDINARY
MANAGEMENT IS ALREADY AMPLY REWARDED?
211
D. PESEAU DI 9
POTLATCH CORPORATION
1 A By definition, great business managers
2 produce exceptional bottom line results. There really
3 can be no other test in a capitalist economic system.
4 Outstanding operating results produce increased
5 shareholder value in the form of rising earnings and
6 stock prices, thus rewarding shareholders. Top managers
7 are, in turn, rewarded through the increase in the value
8 of their shares and options plus, in many cases,
9 increased compensation or bonuses awarded by the
10 company's board of directors.
11 This basic economic system governs every publicly
12 traded corporation, including Avista and other members of
13 the utility industry. Consequently, there is no need for
14 the Commission to provide for "extra" management or
15 shareholder rewards. If management does an outstanding
16 job, shareholders will be rewarded by the enhanced value
17 of their investment. As to the managers themselves, it
18 is the function of the company's board of directors and
19 shareholders to determine whether management deserves
20 additional rewards, and the Commission should not
21 intervene in this process unless compensation becomes
22 excessive.
23 Q WHAT IS YOUR RESPONSE TO MR. DUKICH'S THIRD
24 ARGUMENT, THAT AVISTA SHOULD KEEP THE GAIN AS
25 COMPENSATION FOR ITS INVESTMENT RISK?
212
D. PESEAU DI 10
POTLATCH CORPORATION
1 A The Company's argument is premised "on the
2 notion that the benefit of a gain should follow the risk
3 of possible loss." (Dukich Testimony at P. 5, L. 13-14.)
4 This is the proper starting point in analyzing the
5
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
213
D. PESEAU DI 10a
POTLATCH CORPORATION
1 disposition of a gain on sale, but Mr. Dukich conducts no
2 analysis at all. Instead he makes a number of sweeping
3 statements intended to show that regulation consistently
4 denies shareholders the opportunity to benefit from the
5 business and investment risks they have undertaken.
6 These allegations are simply unfounded.
7 The fact is that a utility's status as a regulated
8 monopoly imposes a unique risk-benefit relationship
9 between the utility's shareholders and its ratepayers.
10 In general, regulation places a floor on the
11 shareholders' downside risk and a ceiling on their upside
12 potential. It does so, in part, by shifting some of the
13 investment risks (and benefits) from shareholders to
14 ratepayers.
15 Q HOW DOES THIS SHIFT OCCUR.
16 A As soon as a utility asset is placed in
17 rate base, depreciation begins shifting the risk of loss
18 from shareholders to ratepayers. Perhaps the simplest
19 way to prove this point is with a hypothetical situation.
20 Suppose Centralia was fully depreciated and it thereafter
21 burned to the ground for a total loss. Who would bear
22 the risk of this loss? Clearly, shareholders would not
23 lose a dime as a result of the disaster. This is because
24 they have been paid a return on their capital while it
25 was invested in the unit and they have also received a
214
D. PESEAU DI 11
POTLATCH CORPORATION
1 full return of capital through depreciation. Their
2 investment (and risk of loss) in the fully depreciated
3 unit is precisely zero.
4 The ratepayers, on the other hand, have an
5 equitable capital investment in the plant equal to the
6 prior return of the shareholders'
7
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
215
D. PESEAU DI 11a
POTLATCH CORPORATION
1 capital through depreciation. In the example I am using,
2 this equitable investment is equal to 100% of the plant's
3 original cost. This investment is completely at risk and
4 would be totally lost if the depreciated unit burned
5 down. In addition to losing their equitable investment
6 in the plant, the customers would almost certainly face a
7 rate increase when the utility built a replacement plant
8 and placed it in rate base.
9 This example illustrates a key point that is worth
10 emphasizing. Once the plant is in rate base, utility
11 shareholders are virtually assured of a gradual return of
12 their capital and a return on their investment. This is
13 because ratepayers, by force of law, must buy from the
14 utility at a price that is profitable to its
15 shareholders. In effect, the captive ratepayers stand
16 surety for most (but not all) of the ordinary business
17 and financial risks that a normal firm faces in the
18 competitive world.
19 Q HOW DO THE ASSET WRITE OFFS CITED BY
20 MR. DUKICH FIT INTO THIS ASSESSMENT OF RELATIVE RISKS?
21 A Before I answer that question I can't
22 resist noting that I found Mr. Dukich's litany of write
23 off woes a little amusing, coming as it does on the heels
24 of his arguments about management efficiency. As a
25 general rule, great managers aren't forced to repeatedly
216
D. PESEAU DI 12
POTLATCH CORPORATION
1 write off assets.
2 Nor are these write offs solely
3 attributable to regulatory decisions, as Mr. Dukich seems
4 to imply. It is true that the Idaho Commission
5 eliminated a portion of WNP-3 and the Kettle Falls' plant
6
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
217
D. PESEAU DI 12a
POTLATCH CORPORATION
1 from rate base. In these two cases the Commission's
2 order may have played a role in the write off decision.
3 But the other three cases cannot be attributed to
4 regulatory actions. The Skagit and Creston write offs
5 occurred as the result of failed construction projects,
6 and the Meyers Falls write off was taken for unknown
7 reasons, perhaps related to the plant's sale price.
8 Q WITH THOSE PREFATORY COMMENTS OUT OF THE
9 WAY, LET'S RETURN TO THE PRIOR QUESTION ABOUT THE WRITE
10 OFFS.
11 A As I have just explained, regulation
12 eliminates much, but not all of the risk from a utility
13 shareholder's investment. One of the recognized
14 limitations on the ratepayers' obligations is that they
15 should not be forced to pay for investments that are not
16 prudently acquired or "used and useful". All of the
17 cited write offs, in one way or another, ran afoul of
18 this rule. The fact that they had to be written off is
19 hardly the injustice to Avista that Mr. Dukich implies,
20 nor is it peculiar to the regulatory world. In the
21 competitive world, shareholder investments in failed
22 projects and uneconomic assets are mercilessly destroyed
23 by marketplace pressures, without regard to good
24 intentions, the prudence of the original investment, or
25 its functional usefulness.
218
D. PESEAU DI 13
POTLATCH CORPORATION
1 Q IN RESPONSE TO A QUESTION FROM COUNSEL,
2 MR. DUKICH SAYS HE CANNOT RECALL A SINGLE INSTANCE WHERE
3 SHAREHOLDERS TOOK A RISK IN BUILDING A RESOURCE OR MAKING
4 A PURCHASE AND WERE ALLOWED TO KEEP ALL OR EVEN PART OF
5 AN ULTIMATE GAIN. IS THIS TRUE?
6
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
219
D. PESEAU DI 13a
POTLATCH CORPORATION
1 A I have no idea what Mr. Dukich was thinking
2 when he made that statement, for it is demonstrably
3 false. In fact, the exact contrary is true. I can
4 recall no instance where the Company was not allowed to
5 keep the entire gain attributable solely to its at risk
6 capital.
7 Avista's recent Idaho rate case provides a
8 perfect example of just the type of risk/reward that
9 Mr. Dukich contends is nonexistent. As the Commission
10 will recall, one of the issues in that case was the
11 proper treatment of Avista's energy trading activities.
12 Potlatch agreed that shareholders should reap the rewards
13 of those activities to the extent they bore the risks,
14 but that it was not possible to determine the extent of
15 shareholder risk because the transactions had been
16 commingled with normal system transactions. Avista
17 argued that the commingling was irrelevant because
18 ratemaking costs were based on modeled power supply
19 costs, and ratepayers were therefore held harmless.
20 Ultimately the Commission accepted the Company's argument
21 and allowed the shareholders to retain all of the gains
22 from energy trading. The Commission's sole adjustment
23 was to correct the Company's clear error in failing to
24 allocate any costs to these activities.
25 Mr. Dukich was an active participant in that case
220
D. PESEAU DI 14
POTLATCH CORPORATION
1 that was heard only a scant five months ago.
2 Consequently, I am dumbfounded by the exchange with
3 counsel in which he states he "can't recall a single
4 instance" in which the Commission allowed the Company "to
5 retain all or even part of the `gain' or savings" from a
6 purchase. Dukich Testimony, P. 7, L.1-3. Even more
7 surprising is the later
8
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
221
D. PESEAU DI 14a
POTLATCH CORPORATION
1 statement that shareholders "receive none of the benefits
2 from... opportunity sales that do no harm to the
3 customer" Dukich Testimony, P. 7, L 16-17 (emphasis
4 original). As I have just pointed out, the "hold
5 harmless" rationale described in this statement was
6 precisely the argument Avista advanced, and the
7 Commission ultimately accepted, as the basis for the
8 decision to allow shareholders 100% of the Company's
9 market trading profits.
10 Q CAN YOU PROVIDE OTHER EXAMPLES OF CASES
11 WHERE AVISTA SHAREHOLDERS ASSUMED THE RISK OF AN ASSET
12 INVESTMENT AND WERE ALLOWED TO RETAIN THE SUBSEQUENT GAIN
13 ON SALE?
14 A To the best of my recollection, this the
15 only instance of Avista's sale of a regulatory asset at a
16 profit during my years of involvement with the Company.
17 And in this case I am recommending that the Company keep
18 the entire gain associated with its at risk investment in
19 Centralia. Of course, there are numerous examples where
20 the shareholders made a profitable investment without
21 relying on the ratepayers as captive customers, and in
22 those cases the Company has always been allowed to keep
23 the entire gain.
24 Q DO YOU HAVE AN EXAMPLE?
25 A The most recent Value Line report on
222
D. PESEAU DI 15
POTLATCH CORPORATION
1 Avista, attached as Exhibit No. 202, provides a
2 convenient and recent example. As the report notes,
3 Avista recorded "a gain of around $0.50 a share on an
4 asset sale" by its Penzer subsidiary. To the best of my
5 knowledge no one has argued for
6
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
223
D. PESEAU DI 15a
POTLATCH CORPORATION
1 a ratepayer share of this gain, nor would it be
2 appropriate to do so. The reason for this is very
3 straightforward. By conducting this business through a
4 separate subsidiary, Avista insured that ratepayers were
5 not forced to provide either a return on, or return of,
6 invested capital. Avista's shareholders have therefore
7 borne the entire risk and are entitled to all the profits
8 from the gain.
9 Q BEFORE WE LEAVE MR. DUKICH'S TESTIMONY, DO
10 YOU HAVE ANY RESPONSE TO HIS COMPLAINT ON PAGE 7 THAT
11 SHAREHOLDERS DON'T PARTICIPATE IN THE BENEFITS FROM
12 FAVORABLE CONTRACTS AND OTHER COST SAVING INITIATIVES?
13 A Mr. Dukich is wrong on the facts, and his
14 suggested remedy for this nonexistent problem is
15 completely at odds with the most fundamental ratemaking
16 principles.
17 Q WHY DO YOU SAY THE STATEMENT IS FACTUALLY
18 INACCURATE?
19 A Shareholders routinely participate in the
20 benefits of cost saving initiatives. In fact,
21 shareholders ordinarily receive 100% of any cost savings
22 until such time as a subsequent Commission order
23 establishes a new ratemaking base case. The interim
24 between Avista's 1986 rate case and its next proceeding
25 in 1999 affords a convenient illustration of this
224
D. PESEAU DI 16
POTLATCH CORPORATION
1 process.
2 As I previously noted, throughout the late
3 1980s and early 1990s the cost of utility debt dropped
4 enormously. Utilities across the
5
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
225
D. PESEAU DI 16a
POTLATCH CORPORATION
1 country repeatedly took advantage of these favorable
2 circumstances to refinance debt and otherwise restructure
3 their capital costs. Avista presumably did the same, and
4 those savings flowed straight to the bottom line and into
5 the shareholders pockets until the 1999 case established
6 new rates. Assuming a 1987 refinancing, the shareholders
7 would have retained 100% of these benefits for twelve
8 years.
9 The same thing happens with other contracts for
10 everything from office supplies to gasoline prices.
11 Shareholders recoup the entirety of any savings until a
12 rate case occurs. The sole exception to this general
13 rule concerns power supply contracts, where the adoption
14 of the PCA has largely eliminated the shareholders'
15 ability to benefit from lower costs during the last few
16 years.
17 Q YOU ALSO STATED THAT MR. DUKICH'S
18 CONTENTION IS AT ODDS WITH FUNDAMENTAL RATEMAKING
19 PRINCIPLES. WHAT DID YOU MEAN?
20 A In the first place, shareholders have
21 nothing at risk in the case of contract expenses. They
22 do not furnish any capital upfront, and they are
23 compensated dollar for dollar for all expenses in the
24 ratemaking process. Since they bear no financial burden,
25 there is no reason for them to be compensated with cost
226
D. PESEAU DI 17
POTLATCH CORPORATION
1 plus returns as Mr. Dukich implicitly suggests.
2 Secondly, and perhaps more to the point, utility
3 managers owe both their shareholders and ratepayers an
4 absolute duty to mitigate
5
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
227
D. PESEAU DI 17a
POTLATCH CORPORATION
1 costs whenever doing so would not impair reasonable
2 service. This is part and parcel of the regulatory
3 compact, and it is not in the least unjust to managers or
4 shareholders, as Mr. Dukich implies. Utility managers
5 are expected to seize attractive business opportunities
6 when they are available for the benefit of both
7 shareholders and ratepayers. This, after all, is their
8 job and top managers are presumably hired, and
9 compensated handsomely, because they are good at it.
10 Simply doing this job well is not an occasion for
11 unreasonable rewards to either managers or shareholders.
12 In fact, a utility that did not exert its best efforts,
13 or competent efforts to prudently reduce costs should be
14 penalized by the regulators, and its managers should be
15 fired by the shareholders.
16 Q YOU EARLIER STATED THAT AVISTA PROPOSED TWO
17 ALTERNATIVE DISPOSITIONS OF THE CENTRALIA GAIN. WHAT IS
18 THE SECOND?
19 A Avista's alternative proposal is contained
20 in its Exhibit 8, Page 1 of 2, sponsored by Mr. McKenzie.
21 Q DOES THIS PROPOSAL SATISFACTORILY ALLOCATE
22 THE NET GAIN FROM THE CENTRALIA SALE?
23 A No.
24 Q WHY NOT?
25 A First of all, the Avista proposal
228
D. PESEAU DI 18
POTLATCH CORPORATION
1 summarized in Exhibit 8 purports to allocate the
2 Centralia gain based on the relative investments in the
3 plant by ratepayers and shareholders. It does so by
4 calculating the
5
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
229
D. PESEAU DI 18a
POTLATCH CORPORATION
1 proportion or ratio of gross plant in service to net
2 plant in service. The difference between gross and net
3 plant is, of course, accumulated depreciation. While
4 this ratio correctly reflects the accumulated
5 depreciation already paid by customers over many years,
6 it doesn't include the customers' entire contribution to
7 the investment in the Centralia plant.
8 Q PLEASE EXPLAIN.
9 A Avista's net plant method equates the
10 customers' contribution with accumulated depreciation.
11 This overlooks another important source of customer
12 contributions to the Centralia investment in the form of
13 accumulated deferred income taxes. Avista's proposal
14 needs to be modified to reflect this customer
15 contribution as well.
16 Q WHAT ARE ACCUMULATED DEFERRED INCOME TAXES?
17 A In states such as Idaho, where regulation
18 provides for normalized treatment of utility income
19 taxes, Avista is allowed to set rates in advance of tax
20 expenses that collect more for income taxes than it pays
21 out. This occurs because Avista depreciates plant more
22 rapidly for tax purposes than for ratemaking purposes.
23 The annual excess of customer contributions for income
24 taxes over actual income taxes paid is aggregated as
25 accumulated deferred income taxes. This customer
230
D. PESEAU DI 19
POTLATCH CORPORATION
1 contribution is held as cost-free capital by Avista, and
2 it is treated as such for regulatory purposes. Page 2 of
3 Avista Exhibit 7 estimates this customer contribution to
4 be $4,000,000.
5
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
231
D. PESEAU DI 19a
POTLATCH CORPORATION
1 Q WHY SHOULD THIS CONTRIBUTION BE INCLUDED IN
2 THE CALCULATION OF THE CUSTOMERS' PORTION OF THE GAIN?
3 A Deferred taxes represent money for future
4 tax expense that Avista has collected from customers in
5 rates but has not yet incurred. In effect, Avista has
6 borrowed money from ratepayers in advance of the actual
7 tax payment. In theory at least, this tax expense is
8 only deferred rather than avoided. But when the bill
9 ultimately becomes due, the shareholders bear sole
10 responsibility for payment of the taxes because they have
11 already received the necessary funds from the customers.
12 This is precisely the situation we now face. Upon
13 Avista's sale of the plant, the actual tax expense that
14 customers prepaid will be incurred because the taxable
15 gain on the plant is based on investment less accumulated
16 tax depreciation, not book depreciation. This
17 calculation is shown in Exhibit No. 7, Page 1 of 3, in
18 the section labeled "Estimated Income Tax Calculation"
19 where the book gain is adjusted by adding the net book
20 value of the plant and deducting the net tax value of the
21 plant. Thus the difference between book value and tax
22 value, which is essentially equal to the difference
23 between accumulated tax depreciation and accumulated book
24 depreciation, becomes part of taxable gain and is taxed
25 as income.
232
D. PESEAU DI 20
POTLATCH CORPORATION
1 If customers are given no credit for accumulated
2 deferred taxes, Avista in effect collects deferred taxes
3 twice from ratepayers. It has already collected deferred
4 taxes in rates. If it also keeps a portion of
5
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
233
D. PESEAU DI 20a
POTLATCH CORPORATION
1 the pre-tax gain to cover this now due tax expense, the
2 result is a double recovery.
3 Q WHAT IS THE PROPER METHOD OF TREATING
4 ACCUMULATED DEFERRED INCOME TAXES IN THE ALLOCATION OF
5 THE NET GAIN?
6 A Avista's proposal on Page 1 of Exhibit 8
7 simply needs to be modified at Line 4 to add deferred
8 taxes estimated to be in the amount of $4,000,000 to the
9 accumulated depreciation of $40,196,876. My Exhibit
10 No. 203 makes this modification. The revised customer
11 ratio of investment in gross plant is increased from
12 69.70% to 76.63%. Applied to the estimated net gain from
13 the sale of $29,605,503, the customer share of gain
14 becomes $22,686,697. The Idaho jurisdictional customer
15 share is $7,488,879.
16 Q ARE THERE ANY OTHER PROBLEMS WITH THE
17 MR. MCKENZIE'S PROPOSED ALLOCATION OF THE GAIN?
18 A Yes. It purports to allocate a portion of
19 the gain to ratepayers, but in a manner that provides no
20 actual customer benefits.
21 Q WHAT DO YOU MEAN?
22 A Mr. McKenzie's direct testimony, at Page 3,
23 Line 23 through Page 4, Line 18, proposes to use the
24 customers' (76.63%) share of the gain to write down three
25 items that are currently amortized in rates
234
D. PESEAU DI 21
POTLATCH CORPORATION
1 (post-retirement benefits, a PURPA contract buy-out, and
2 the Nez Perce lawsuit settlement) and to write down ice
3 storm expenses that were specifically disallowed in
4 Avista's recent Idaho general rate case.
5
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
235
D. PESEAU DI 21a
POTLATCH CORPORATION
1 The Company's proposal for the offset of the three
2 test year expense items would put $4.9 million in the
3 pockets of shareholders, but it would not in any way be
4 reflected in lower customer rates. Present rates to
5 customers would remain in effect at present levels unless
6 or until a further general rate case is filed by Avista.
7 Avista shareholders would be collecting 100% of these
8 expenses as a prepayment from the net gain, and then
9 overcollect for these same three items in present rates
10 indefinitely.
11 If Avista's next general rate case is filed
12 at or about the same time as the expiration of the
13 authorized amortization period for these three items,
14 Idaho customers would have paid roughly 200% of these
15 expenses. If Avista's next general filing is not made
16 until a period twice that of the amortization, Avista
17 shareholders will have collected 300% of these expenses.
18 Q COULD AN ADJUSTMENT FOR THIS OBVIOUS
19 OVER-COLLECTION BE MADE IN A SUBSEQUENT GENERAL RATE CASE
20 FILING?
21 A Probably not, as it probably would be
22 considered retroactive ratemaking.
23 Q WHAT IS YOUR RESPONSE TO AVISTA'S PROPOSAL
24 TO USE IDAHO CUSTOMERS' SHARE OF THE NET GAIN TO COLLECT
25 $1.9 MILLION FOR STORM DAMAGE COSTS OCCURRING IN 1996?
236
D. PESEAU DI 22
POTLATCH CORPORATION
1 A The Company argued the merits of charging
2 this unusual, nonrecurring expense to the Commission in
3 the recent general rate case. The Commission rejected
4 the merits of Avista's arguments there and should reject
5 the request here.
6 Q DO YOU AGREE WITH MR. MCKENZIE'S CONCLUSION
7 THAT "... CERTAINLY, THE SALE OF THE CENTRALIA POWER
8 PLANT FALLS INTO THE SAME CATEGORY AS ICE STORM OF BEING
9 AN EXTRAORDINARY AND NON-RECURRING TYPE OF EVENT (PAGE 6,
10 LINES 20-22)?
11 A I find this argument fascinating. Mr.
12 McKenzie is placing the sale of Centralia into the same
13 category as a fluke ice storm. I do not recall that the
14 Commission had the opportunity to determine in advance
15 whether the ice storm and the expenses associated
16 therewith were in the public interest.
17 More to the point, the sale of Centralia means the
18 loss of a valuable asset to Avista's customers that may
19 or may not prove to be economic over time. This risk is
20 in no manner being assumed by shareholders. If
21 replacement power is more expensive than with Centralia,
22 customers lose. The Commission should not change its
23 previous position that Avista should not be compensated
24 for the 1996 Ice Storm.
25 Q ASSUMING THE COMMISSION REJECTS MR.
237
D. PESEAU DI 23
POTLATCH CORPORATION
1 MCKENZIE'S PROPOSALS, HOW SHOULD THE CUSTOMERS SHARE OF
2 THE GAIN BE DISTRIBUTED?
3
4 /
5
6 /
7
8 /
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
238
D. PESEAU DI 23a
POTLATCH CORPORATION
1 A All retail customers have contributed to
2 the accumulated depreciation and deferred taxes
3 associated with the Centralia Power Plant and are
4 therefore deserving of a pro rata share of the customers'
5 net gain. This gain should be distributed to all retail
6 customers on a simple allocation according to usage.
7 Annual energy consumption is the logical allocator.
8 Because the customer share of the gain is, in
9 effect, a return of capital, my suggestion is that the
10 return should be accomplished as rapidly as possible. In
11 the case of large industrial customers and contract
12 customers whose annual consumption is easily calculated,
13 a single billing credit or issuance of a check would be
14 appropriate. For the other customer classes, a credit
15 over the course of at least a year would be more
16 appropriate in order to insure that customers with
17 seasonally variable loads receive their fair share.
18 Q DOES THE COMMISSIONS' DECISION ON THIS
19 ISSUE OF ALLOCATING THE NET GAIN FROM THE SALE OF
20 CENTRALIA HAVE MAJOR POLICY IMPLICATIONS?
21 A Yes. The issue of allocating the net gain
22 from Centralia is just the first of a sequence of
23 important policy decisions to be made by this Commission
24 in regard to utility mergers and acquisitions, the
25 continued restructuring of retail and wholesale markets
239
D. PESEAU DI 24
POTLATCH CORPORATION
1 for electricity, and the quest for shareholder value. In
2 this case, the proposed sale is to TECWA, an unregulated
3 entity and an obvious participant in the restructured
4 wholesale and retail electricity markets. Similar
5
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
240
D. PESEAU DI 24a
POTLATCH CORPORATION
1 generating asset sales continue throughout the western
2 United States. All major sales to date have been, or are
3 expected to be, made at a price in excess of book value.
4 Under such circumstances, where large net gains may be
5 realized, the issues surrounding the allocation of net
6 gains between shareholders and retail customers can be
7 expected to be both contentious and ongoing.
8 In my opinion, the Commission should set a policy
9 in this proceeding that facilitates a "long memory" as to
10 the overall fairness of sharing both gains and losses
11 between customers and shareholders. If neighboring
12 states are any indicator, and I think they are, utilities
13 will continue to dispose of generating assets and request
14 permission to pocket the gains. Once the gains are
15 exhausted and only assets with "stranded costs" remain,
16 utilities will then be in position to request that retail
17 customers pick up 100% of the net losses from such asset
18 sales. The Commission should take whatever steps are
19 necessary to forestall this problem. At a minimum, it
20 should provide in this order for future "netting" of
21 present shareholder gains against any claimed losses in
22 the future.
23 Q DOES THIS CONCLUDE YOUR TESTIMONY?
24 A Yes, it does.
25
241
D. PESEAU DI 25
POTLATCH CORPORATION
1 (The following proceedings were had in
2 open hearing.)
3 MR. WARD: And Dr. Peseau is available for
4 cross-examination.
5 COMMISSIONER SMITH: Mr. Woodbury, do you
6 have any questions?
7 MR. WOODBURY: Staff has no questions of
8 Dr. Peseau.
9 COMMISSIONER SMITH: Mr. Dahlke.
10 MR. DAHLKE: My client attempted to respond
11 in rebuttal to Dr. Peseau and I have no questions on
12 cross.
13 COMMISSIONER SMITH: How about from the
14 Commission?
15 COMMISSIONER KJELLANDER: I did have one
16 question.
17
18 EXAMINATION
19
20 BY COMMISSIONER KJELLANDER:
21 Q Mr. Peseau, I think as I read your
22 testimony, and it's been about a week ago that I went
23 through it a second time, you made reference in there to
24 the PURPA contract, at least as far as the Company's
25 proposal, it not being an acceptable thing to buy out
242
CSB REPORTING PESEAU (Com)
Wilder, Idaho 83676 Potlatch
1 with regards to some of the proceeds from the sale; is
2 that correct? Is that a correct evaluation of what your
3 comments were there?
4 A Yes, there were a number of uses for the
5 customer share of the gain, if any, according to the
6 Company's proposal and I thought given the fact that
7 Centralia has been left in rate base as used and useful
8 and the rates that are being amortized for the PURPA and
9 other amortizations will remain in effect, apparently, I
10 think it would be inappropriate to use customer share of
11 the gain to offset that.
12 Q With regard to PURPA contracts, I know that
13 a lot of electric utilities are trying to buy them down,
14 do you see there as being no benefit to ratepayers by
15 buying down PURPA contracts as a whole? Aren't there
16 situations in which they do benefit ratepayers?
17 A I think there are definitely instances
18 where negotiating those contracts out to make them either
19 dispatchable or to give -- to buy them out and allow
20 those contracts and facilities to be purchased by power
21 marketers who are perhaps more adept at reselling the
22 power and therefore could enhance it, I think there are
23 very much benefits to that, but in this instance, if we
24 allow the Company to buy it down with customer money and
25 then continue to charge rates that still reflect those
243
CSB REPORTING PESEAU (Com)
Wilder, Idaho 83676 Potlatch
1 PURPA contracts, then I think that's in a sense a double
2 recovery on the part of shareholders.
3 COMMISSIONER KJELLANDER: Thank you for
4 clearing that up for me.
5
6 EXAMINATION
7
8 BY COMMISSIONER SMITH:
9 Q I don't even know if I should try and
10 attempt it, I was trying to sort through the taxes and
11 first when I read the testimony that was filed, I thought
12 I understood because growing up in a telephone case where
13 assets transferred and deferred tax amounts did not, it
14 was clear to me those amounts belonged to ratepayers, but
15 it was pointed out to me that this is different because
16 this is a sale and a sale is a taxable event, so taxes
17 will be paid and essentially there won't be any deferred
18 amounts that belong to ratepayers, so do I see it clearly
19 now or is there another piece that's missing?
20 A Well, it was referenced earlier that the
21 accumulated deferred taxes were in a sense a payment made
22 by ratepayers that has not yet been paid out by the
23 Company and if Centralia were not sold, then those
24 balances would shrink to zero so that there would be no
25 net loan from the customer to the shareholder.
244
CSB REPORTING PESEAU (Com)
Wilder, Idaho 83676 Potlatch
1 Now, the sale only ends the repayment by
2 shareholders to customers of that advanced amount, so
3 that amount still needs to be advanced. Now, it's true
4 that the sale will cause a taxable event. The question
5 is, is it fair to ignore the fact that some of those
6 taxes have been paid in advance from customers to
7 shareholders, and another way of looking at my issue is
8 that since the customers have already prepaid, in a
9 sense, those taxes, then the shareholders in effect get a
10 disproportionate share. I mean, that's not the
11 adjustment I made, but an equivalent adjustment would be
12 made in that way. The shareholders have a balance
13 advanced by customers, they're choosing by their means to
14 ignore that in distributing the federal taxable event.
15 Q But that's not the $4 million number?
16 A It's the $4 million number, plus the
17 $900,000 number less, as Mr. McKenzie pointed out,
18 FAS-109 does have some amount. If that $4 million were
19 correct, some of that $4 million would be flowed through
20 and it would not be appropriate to treat that as being
21 normalized. That is advanced by the customers, so the
22 $4 million number is an estimate, it's an estimate, but
23 what I would propose, if the Commission is compelled by
24 our proposed adjustment that when the sale is final,
25 there's no problem in truing up what the actual amount of
245
CSB REPORTING PESEAU (Com)
Wilder, Idaho 83676 Potlatch
1 the $4 million is to begin with and then, secondarily,
2 what additional amount of that $4 million has been flowed
3 through and is not appropriately allocated to customers
4 rather than shareholders, so what I'm proposing is a
5 true-up when we do know the numbers.
6 COMMISSIONER SMITH: All right, thank you.
7 Any redirect, Mr. Ward?
8 MR. WARD: I'm going to take one quick try
9 at a follow-up.
10
11 REDIRECT EXAMINATION
12
13 BY MR. WARD:
14 Q Let me see if this is a fair
15 characterization of the deferred tax issue. A deferred
16 tax balance, as you said, is basically funds advanced by
17 the customers for a tax obligation that in fact is not
18 due under the tax code at that time; correct?
19 A That's correct.
20 Q And whether Centralia is sold or not, at
21 some point that tax obligation does become due; also
22 correct?
23 A It ought to become due, yes.
24 Q And when it does come due, whether
25 Centralia is sold or not, the shareholders should not be
246
CSB REPORTING PESEAU (Di)
Wilder, Idaho 83676 Potlatch
1 allowed to tell the ratepayers once again that you're
2 obligated to compensate us for this tax for which the
3 money was already advanced?
4 A It's over the life of the asset. It's
5 supposed to be a zero sum gain. The reason that
6 accelerated depreciation and the resulting tax
7 advancement or balances were conceived of and were
8 allowed was for investment incentive purposes. Since the
9 Company was being paid more by customers than they were
10 paying out to the IRS, there were real cash consequences
11 that they were holding which would allow them, and
12 nonregulated companies as well, to have money, and
13 similarly with investment tax credits, money that they
14 were booking but not actually spending for investment
15 purposes. That deals with the timing of that, but they
16 were supposed to pay back ultimately either the IRS or
17 the customers advancing that over the life of the
18 project. That's a long yes.
19 MR. WARD: Thank you.
20 COMMISSIONER SMITH: Well, then I have
21 another problem.
22
23
24
25
247
CSB REPORTING PESEAU (Di)
Wilder, Idaho 83676 Potlatch
1 EXAMINATION
2
3 BY COMMISSIONER SMITH:
4 Q But if Centralia is a pre-1981 asset and
5 flow-through continued, how could there be any deferred
6 taxes?
7 A That's the empirical question.
8 Mr. McKenzie said it was 900,000, so we know that 100
9 percent hasn't been. In his testimony, he's very careful
10 to qualify when he disputes my $4 million number that,
11 among other things, FAS-109 has some amount that's flowed
12 through and it's very carefully qualified, so there are
13 portions of investment tax credit, whatever it is, in
14 that account that have not been flowed through. All I'm
15 saying is that if we can true this up at the end, we can
16 probably in an informal proceeding simply make sure that
17 the amount flowed through and the amount normalized are
18 appropriately identified and accounted for.
19 COMMISSIONER SMITH: Thank you.
20 (The witness left the stand.)
21 COMMISSIONER SMITH: All right,
22 Mr. Woodbury, we're ready for your witnesses.
23 MR. WOODBURY: Thank you, Madam Chair.
24 Staff would call as its first witness Kathleen Stockton.
25
248
CSB REPORTING PESEAU (Com)
Wilder, Idaho 83676 Potlatch
1 KATHLEEN L. STOCKTON,
2 produced as a witness at the instance of the Staff,
3 having been first duly sworn, was examined and testified
4 as follows:
5
6 DIRECT EXAMINATION
7
8 BY MR. WOODBURY:
9 Q Ms. Stockton, will you please state your
10 full name for the record?
11 A Kathleen Stockton.
12 Q And for whom are you employed and in what
13 capacity?
14 A I'm employed by the Idaho Public Utilities
15 Commission as a Staff auditor.
16 Q And in that capacity, did you have occasion
17 to prefile testimony in this case consisting of 18 pages
18 and one exhibit, Exhibit 104?
19 A Yes, I did.
20 Q And did you have occasion also to file with
21 the parties replacement pages 16 and 17 and a revised
22 Exhibit 104?
23 A Yes, I did.
24 Q Could you -- is the nature of the changes
25 within those pages a different regulatory treatment of
249
CSB REPORTING STOCKTON (Di)
Wilder, Idaho 83676 Staff
1 the gain?
2 A Yes, it is.
3 Q Could you please explain why Staff is now
4 proposing a different regulatory treatment?
5 A Yes. I used -- I revised the number for
6 the revenue amount that I compare to on Exhibit 104.
7 Originally I used the total revenue requirement when I
8 should have used the general business revenues less
9 special contract and other revenues, so that was one
10 change. Also, in reviewing the reply comments in the
11 related PacifiCorp Centralia sale, it became evident that
12 using accumulated depreciation would have some problems
13 because that accumulated depreciation would not be tied
14 to a specific asset. It could also cause problems with
15 depreciation studies, so I decided to set up a regulatory
16 asset -- excuse me, a regulatory liability and amortize
17 that over eight years. Also, I had incorrectly grossed
18 up the preferred securities. Those are tax deductible;
19 therefore, it's inappropriate to gross them up.
20 Q All right, if I were to ask you the
21 questions set forth in your prefiled testimony as revised
22 and as supported by your revised exhibit, would your
23 answers now be the same?
24 A Yes, they would.
25 Q Is it necessary to make any other changes
250
CSB REPORTING STOCKTON (Di)
Wilder, Idaho 83676 Staff
1 or corrections?
2 A No.
3 MR. WOODBURY: Madam Chair, I'd ask that
4 the testimony be spread and that the exhibit be
5 identified and I'd present Ms. Stockton for
6 cross-examination.
7 COMMISSIONER SMITH: Thank you. If there's
8 no objection, we will spread the prefiled testimony upon
9 the record as if read and identify Revised Exhibit
10 No. 104.
11 (The following prefiled testimony of
12 Ms. Kathleen Stockton is spread upon the record.)
13
14
15
16
17
18
19
20
21
22
23
24
25
251
CSB REPORTING STOCKTON (Di)
Wilder, Idaho 83676 Staff
1 Q. Please state your name and business address?
2 A. My name is Kathleen L. Stockton. My
3 business address is 472 West Washington Street, Boise,
4 Idaho.
5 Q. By whom are you employed and in what
6 capacity?
7 A. I am employed as an Auditor by the Idaho
8 Public Utilities Commission.
9 Q. Please describe your educational background
10 and professional experience.
11 A. I received my B.B.A. degree majoring in
12 Accounting from Boise State University in December 1992.
13 Following graduation I was employed by the Idaho State
14 Tax Commission as a Tax Enforcement Technician. In my
15 capacity as a Tax Enforcement Technician, I performed
16 desk audits on individual state income tax returns. I
17 was promoted to Tax Auditor, and after meeting the
18 underfill requirements, was promoted to Senior Tax
19 Auditor. In my capacity as an auditor, I performed
20 audits on Special Fuel and Motor Fuel Tax returns,
21 International Fuels Tax Agreement Returns and Special
22 Fuel User tax returns. I accepted employment with the
23 Idaho Public Utilities Commission (IPUC; Staff) in July
24 of 1995. I attended the National Association of
25 Regulated Utilities Commissioners Annual Regulatory
252
AVU-E-99-6 STOCKTON (Di) 1
12/02/99 STAFF
1 Studies program at Michigan State University in the
2 summer of 1996.
3 Q. What is the purpose of your testimony?
4 A. My testimony addresses the calculation of
5 the gain associated with the sale of the Centralia Power
6 Plant and Staff's recommendations for the proposed
7 ratemaking treatment of the gain on the sale.
8 Q. What are the accounting rules and
9 regulations for the treatment of the gain on the sale of
10 a utility asset?
11 A. The Federal Energy Regulatory Commission
12 (FERC) Uniform Systems of Accounts Prescribed for Public
13 Utilities and Licensees Subject to the Provisions of the
14 Federal Power Act defines "Property retired," as property
15 which has been removed, sold, abandoned, destroyed, or
16 which for any cause has been withdrawn from service.
17 Section B of Account 108 - Accumulated
18 provision for depreciation of electric utility plant
19 (Major only) states:
20 At the time of retirement of
depreciable electric utility plant,
21 this account shall be charged with
the book cost of the property retired
22 and the cost of removal and shall be
credited with the salvage value and
23 any other amounts recovered, such as
insurance. When retirement, costs of
24 removal and salvage are entered origin-
ally in retirement work orders, the
25 net total of such work orders may be
253
AVU-E-99-6 STOCKTON (Di) 2
12/02/99 STAFF
1 included in a separate subaccount here-
under. Upon completion of the work order,
2 the proper distribution to subdivisions
of this account shall be made...
3
4 Item 5, letter F from the Electric Plant
5 Instructions from the Uniform System of Accounts, states:
6 F. When electric plant constituting
an operating unit or system is sold,
7 conveyed, or transferred to another
by sale, merger, consolidation, or
8 credited to the appropriate utility
plant accounts, including amounts
9 carried in account 1114, Electric
Plant Acquisition Adjustments. The
10 amounts (estimated if not known)
carried with respect thereto in the
11 accounts for accumulated provision
for depreciation and amortization and
12 in account 252, Customer Advances for
Construction, shall be charged to such
13 accounts and contra entries made to
account 102, Electric Plant Purchased
14 or Sold. Unless otherwise ordered by
the Commission, the difference, if any,
15 between (1) the net amount of debits
and credits and (2) the consideration
16 received for the property (less
commissions and other expenses of making
17 the sale) shall be included in account
421.1, Gain on Disposition of Property,
18 or account 421.2, Loss on Disposition of
Property. (See account 102, Electric
19 Plant Purchased or Sold.)
20 The accounting entry for the sale of
21 depreciable property in textbook terms would be to debit
22 the Cash account for the purchase or sale price of the
23 property; credit the Property Asset account for the
24 original cost of the asset; debit the Accumulated
25 Depreciation account for the amount of accumulated
254
AVU-E-99-6 STOCKTON (Di) 3
12/02/99 STAFF
1 depreciation associated with the property; and credit
2 Gain on Disposal of the property. If the sale resulted
3 in a loss, Loss on Disposition of property would be
4 debited. The appropriate regulatory commission would
5 determine the ratemaking treatment of any gain or loss.
6 Q. What are some of the prior Commission-
7 Ordered Treatments of the Gain/Loss on a Sale of Utility
8 Assets?
9 A. This Commission has utilized various
10 treatments for the gain on the sale of Utility assets:
11 Charge to accumulated depreciation, offset expenses,
12 return to ratepayers through a final bill credit, return
13 a portion of the gain to the purchaser for plant
14 investment plus a special contribution to the IUSF, and
15 amortize over a period of years.
16 1. In Case No. U-1025-43, In the matter of the
17 Application of Boise Water Corporation to revise and
18 increase rates charged for water service, the treatment
19 of the gain from the sale of the Company's old downtown
20 headquarters was decided. Order No. 16557 states:
21 The Staff proposed that the complete
after-tax gain from the sale of property
22 be recaptured for the benefit of the
ratepayers. The Company, on the other
23 hand, contended that that portion of
the gain attributable to non-depreciable
24 property (the land) should inure to the
benefit of the Company's shareholders
25 and that portion of the gain attributable
255
AVU-E-99-6 STOCKTON (Di) 4
12/02/99 STAFF
1 to depreciable property should inure to
the benefit of the ratepayers. We agree
2 with the Company...
The next issue presented is how should
3 the gain be apportioned between depreciable
and non-depreciable property. The Staff
4 contended that the gain should be in
proportion to the book value of depreciable
5 and non-depreciable property at the time
of the sale while the Company contended
6 that the gain should be apportioned
according to its appraiser's assessment
7 of the relative values. We agree with
the Staff. We find that book values are
8 the appropriate basis for allocating the
gain between depreciable and non-depreciable
9 asset. Instead, we find it fair and
reasonable to use book values, which are
10 used for determination of rate of return
and depreciation expense, to allocate gain
11 for the sale of property....
The Company proposed to amortize the
12 ratepayers' share of the gain over a five-
year period by reducing the revenue
13 requirement by 1/5th of the gain
attributable to the ratepayers over five
14 years. The Staff proposed to recapture
the gain which the ratepayers are entitled
15 by reducing the Company's rate base
attributable to the new headquarter by
16 the amount of the gain. We agree with the
Staff's approach. We find that rate base
17 adjustment of the gain rather than
relatively quick amortization of the gain
18 over a five-year period is the proper way
to treat this item.
19
20 2. In Case No. IPC-E-93-24, Idaho Power Company
21 requested authority to offset the net gain from the sale
22 of a gas turbine against the recent increase in its
23 income tax rates. The recent increase in taxes was a
24 result of the passage of the Omnibus Budget
25 Reconciliation Act of 1993 (OBRA 93) by the United States
256
AVU-E-99-6 STOCKTON (Di) 5
12/02/99 STAFF
1 Congress. The Staff recommended,
2 that Idaho Power be allowed to offset
its normalized incremental tax expense
3 associated with OBRA 93 on a prospective
basis from the date of the Commission's
4 final Order entered in this case with the
gain from the sale of the Hailey Turbine.
5 Using this method and the calculations
provided by Idaho Power in its filing,
6 Staff would anticipate that if the
Company's general rate case is filed when
7 expected, with new rates in effect by year
end 1994, approximately $1,200,000 of the
8 Hailey Turbine gain will remain for
disposition in the general rate case."
9
10 The Commission, in Order No. 25339 ordered,
11 "that Idaho Power may offset OBRA 93 related tax
12 increases against the gain from the sale of the Hailey
13 Turbine for the entire year of 1993. The decision as to
14 an offset for the 1994 increased tax expense will be made
15 in the future, if presented to the Commission."
16 3. In Order No 25753, Case Nos. PPL-E-94-1 and
17 WWP-E-94-1 (the transfer to Water Power of Pacific
18 Power's Bonner County, Idaho service territory and
19 electrical distribution facilities) the Commission
20 stated:
21 We find that the customers are entitled
to share in any gain attributable to the
22 sale of depreciable property. The
customers have paid rates based on a
23 revenue requirement that included the
assets to be transferred and therefore
24 have an equitable interest. We find
it reasonable to distribute this amount
25 to Sandpoint District customers as a
257
AVU-E-99-6 STOCKTON (Di) 6
12/02/99 STAFF
1 final bill credit. The amount is to be
allocated among customer classes on the
2 basis of the most recent 12 months annual
kilowatt hour usage by class and is to be
3 shared equally by current customers within
each class.
4
5 4. In the Sale of the Exchanges from U S West
6 to the seven purchasers (Albion Telephone Company,
7 Cambridge Telephone Company Inc., Midvale Telephone
8 Exchange, Inc., Fremont Telcom Company, Silver Star
9 Telephone Company, Rockland Telephone Company, Inc., and
10 Project Mutual Telephone Cooperative Association, Inc.),
11 the treatment of the gain was reached through a
12 settlement stipulation and negotiation between the
13 Commission Staff, U S West, and the purchasing companies.
14 Order No. 26280 states:
15 Prior to the consolidated technical hearing
on the sales cases, the Commission Staff and
16 U S WEST entered into a settlement
stipulation "to compromise and resolve the
17 issue of the treatment of U S West's gain
on the sales transaction." Staff Exhibit
18 No. 119. The Stipulation required U S WEST
to make a "special contribution" of
19 approximately $4.35 million to the Idaho
Universal Service Fund (USF). At the
20 hearing, Project Mutual and the other
purchasers suggested a different use for
21 the $4.35 million. Instead of depositing
this amount as a special contribution to the
22 Idaho USF, the purchasers suggested that
this amount be used to fund the replacement
23 of central office switches in the sales
exchanges including the existing remote
24 switch in Oakley.
In its Order approving the Oakley
25 exchange sale, the Commission adopted the
258
AVU-E-99-6 STOCKTON (Di) 7
12/02/99 STAFF
1 purchasers' alternative proposal for the
special contribution. The Commission found
2 that approval of this sale, [should be
conditioned upon the payment of $140,000
3 by U S WEST to Project Mutual to
replace the switch for the Oakley
4 exchange. This amount will be paid at
the time of closing. Because Project
5 Mutual will not have to pay income tax on
this contribution, the full amount may be
6 applied to the switch cost. This affords
ratepayers in the Oakley exchange a portion
7 of the gain through the contribution toward
the switch replacement cost. We believe
8 this is a fair, just, and reasonable
apportionment of the gain in the Oakley
9 exchange sale. Order No. 26198 at 11.]
10 In Order No. 26353, approving the sale of
11 the exchanges to all parties except Project Mutual, which
12 had already been approved in Order No. 26198, the
13 Commission stated:
14 As we did in Order No. 26198, we find
it is fair and reasonable to adopt the
15 Purchasers' proposal, as amended for use
of a special contribution by U S WEST.
16 This resolution affords ratepayers in the
purchased exchanges a portion of the
17 purchase premium through the contribution
toward switch replacement costs. It is
18 also fair and reasonable to return funds
to the Revenue Sharing Plan for Tech II
19 improvements, and for U S WEST to make a
contribution to the Idaho Universal Service
20 Fund. This disposition of the contribution
by U S WEST spreads a benefit from the
21 sales to a significant number of ratepayers
in U S WEST's southern Idaho exchanges,
22 and materially improves the financial
aspects of the sales for the Purchasers.
23
24 A portion of the gain from the sale of the
25 exchanges was used to update the switches in the
259
AVU-E-99-6 STOCKTON (Di) 8
12/02/99 STAFF
1 exchanges that had been sold, and thus returned to the
2 ratepayers. Some was also returned to the revenue
3 sharing funds, and thus returned to the ratepayers, and
4 some was put into the Idaho Universal Service Fund, thus
5 benefiting ratepayers.
6 5. In Case No. IPC-E-93-20, Idaho Power Company
7 filed an Application for authority to sell electric
8 distribution facilities located on Bald Mountain to
9 Sinclair Oil Corporation, d.b.a. Sun Valley Company.
10 This sale resulted in an accounting loss of $124,058.
11 Idaho Power requested that the loss be absorbed in the
12 accumulated reserve for depreciation account. This would
13 be the conventional treatment of a gain or loss. Under
14 this treatment, the reserve balance would be depleted and
15 this in turn would cause an increase in the Company's
16 rate base. The effect of the treatment would be to pass
17 the loss onto the ratepayers. In the future,
18 depreciation rates would also increase due to the loss.
19 The Commission Staff recommended that the loss from the
20 sale be placed "into a regulatory asset account to be
21 amortized over a period of ten years. The unamortized
22 balance of the loss would be excluded from rate base.
23 The annual amortization expense would be included in
24 revenue requirement." The Commission stated:
25 In Order No. 24676, Case No. IPC-E-92-9,
260
AVU-E-99-6 STOCKTON (Di) 9
12/02/99 STAFF
1 Idaho Power agreed to pass the gain from
the sale of its Hailey Turbine to its
2 ratepayers. It would be inconsistent
for us to now refuse to allocate the
3 loss from the sale of the Sun Valley
facilities to ratepayers.
4 We share Staff's concern, however, that
ratepayers should not be required to
5 continue to provide a return on assets no
longer owned by the Company. Staff's
6 proposal to place the loss from the sale
into a regulatory asset account to be
7 amortized over a period of ten years is a
reasonable one. Furthermore, Staff's
8 proposal to exclude the unamortized loss
from rate base and to include the
9 amortization expense in revenue
requirement would accomplish the
10 objectives of allowing the Company to
recover the loss from ratepayers but
11 not requiring ratepayers to continue
providing a return on assets that have
12 been sold. It is therefore ordered
that the net book loss from the sale
13 of the electrical distribution facilities
of $124,058, adjusted for income taxes,
14 will be placed in a regulatory asset
account to be amortized over ten years.
15 Amortization will commence January 1, 1994.
The annual amortization expense will be
16 included in the Company's revenue
requirement determinations.
17
18 Q. Have you examined the Company's calculation
19 of the regulatory gain on the sale of the Centralia
20 facility?
21 A. Yes. The Company has provided Staff with
22 the workpapers and assumptions used in the calculation of
23 the regulatory Gain for the Centralia facility. Staff
24 has reviewed the supplied documents and agrees with the
25 Company's calculation of the gain at this time. Because
261
AVU-E-99-6 STOCKTON (Di) 10
12/02/99 STAFF
1 the sale has not been completed, the numbers are subject
2 to change. At the time of the sale, Staff will audit and
3 review the final sale numbers. The customer portion of
4 the regulatory gain for Idaho, pending final sale, and as
5 calculated by the Company and verified by Staff is
6 $6,811,625.
7 Q. What method does the Company use to
8 determine the customer portion of the gain?
9 A. The Company uses the depreciation approach
10 to determine the customer portion of the gain. This
11 approach uses the ratio of depreciated plant to total
12 plant to determine the customer portion of the gain. The
13 ratio of depreciated plant to total plant is applied to
14 the total gain to determine the customer share of the
15 gain.
16 Q. Mr. Dukich, in his testimony (page 3, line 10)
17 states, "the Company believes there is still a rational
18 and reasonable basis that would support a shareholder
19 retention level above the depreciation based approach
20 proposed by PacifiCorp." Why is the depreciation
21 approach the proper approach for determining the customer
22 portion of the gain on the sale of the Centralia
23 facility?
24 A. The depreciation approach is the proper
25 approach according to the Supreme Court of Idaho. The
262
AVU-E-99-6 STOCKTON (Di) 11
12/02/99 STAFF
1 Supreme court of Idaho, in Boise Water Corporation v.
2 Idaho Public Utilities Commission, 99 Idaho 158, 578 P.2d
3 1089 (1978), found that the ratepayers' payment of
4 depreciation expense (on property other than real
5 property) established a right to the gain on the sale of
6 an asset. Not only was depreciation expense built into
7 rates, but also maintenance expense; therefore the
8 customers have borne the burden of the depreciation and
9 maintenance expenses. Certainly there are risks
10 associated with building a generation facility and
11 initially shareholders bore those risks. However, those
12 risks were lower for the Company and the shareholders,
13 once the depreciation, operation and maintenance expenses
14 were included in the Company's rates. The customers paid
15 for and thus purchased a portion of the plant. Also, the
16 Company was compensated for risk through the rate of
17 return component included in rates.
18 Q. Has the Company proposed ratemaking
19 treatment for the customer portion of the regulatory
20 gain?
21 A. The Company is proposing that all the gain
22 be assigned to shareholders. However, should the
23 Commission allocate a portion of the gain to customers,
24 then the Company proposes that the gain be used to:
25 1. offset costs related to storm damage
263
AVU-E-99-6 STOCKTON (Di) 12
12/02/99 STAFF
1 repair costs in Idaho resulting from the Ice Storm
2 in 1996;
3 2. offset the Idaho electric portion of the
4 remaining transition obligation for post-
5 retirement health care and life insurance
6 benefits;
7 3. offset the costs associated with the buy-
8 out of a PURPA contract; and
9 4. offset a portion of the cost of the
10 initial payment to settle the Nez Perce lawsuit.
11 Q. Does Staff find the Company's proposal for
12 the treatment of the Idaho jurisdictional regulatory
13 customer portion of the gain on the sale of the Centralia
14 facility acceptable?
15 A. No.
16 Q. Is it appropriate to use the gain on the
17 sale of the Centralia facility to offset the unrecovered
18 costs of the Ice Storm of 1996?
19 A. No. In the Company's last general rate
20 case, Avista was denied the opportunity to recover
21 retroactively through rates, the Ice Storm costs. In
22 Order No. 28097, the Commission stated, "When it became
23 aware that the uninsured ice storm costs would be
24 substantial, the Company had the opportunity to request
25 rate relief or deferral of these costs for future
264
AVU-E-99-6 STOCKTON (Di) 13
12/02/99 STAFF
1 recovery. It did neither." It is clear that since the
2 Company, at the time of the Ice Storm, did not request
3 rate relief or deferral of the Ice Storm costs for future
4 recovery, it is not allowed to request recovery of those
5 costs now, as the opportunity for requesting relief is
6 past. It is clear that the Commission did not allow
7 recovery of the Ice Storm costs through present rates,
8 and did not intend for the Company to request relief at
9 an even later time. If it was too late to request
10 recovery at the time of the last general rate case, it is
11 certainly too late now.
12 Q. What about the comparison the Company makes
13 between the Ice Storm and the sale of the Centralia
14 facility as both being unusual?
15 A. While it is true these events don't happen
16 every day for Avista, it is not an unusual occurrence for
17 electric companies to sell generating facilities. It may
18 be prudent for a company to sell a generating facility
19 and it is not unusual for utility companies to spin off
20 their generating assets through a sale, and make a gain
21 on that sale. Avista has control over what and when it
22 will sell in regards to its generating facilities.
23 Selling, building, or buying a generating facility is in
24 the normal course of business for an electric utility,
25 and therefore a usual event. An ice storm of the
265
AVU-E-99-6 STOCKTON (Di) 14
12/02/99 STAFF
1 magnitude that happens only once every 115 years is an
2 unusual event. The sale of Centralia is simply not an
3 extraordinary and non-recurring type of event.
4 Q. Is it appropriate to offset the Idaho
5 electric portion of the remaining transition obligation
6 for post-retirement health care and life insurance
7 benefits?
8 A. No, the proper time for that was established
9 in Order No. 24673, Case Numbers WWP-E-92-5 and
10 WWP-G-92-2. In fact, the customers through current rates
11 are already paying the remaining transition obligation
12 for post-retirement health care and life insurance
13 benefits. The transition amount is being amortized over
14 a 20 year period, and the yearly amortization is already
15 accounted for in current rates, so to offset these costs
16 with the gain from the sale would mean that the customers
17 would then be paying, through rates, what has already
18 been recovered. The customers would, in effect, be
19 paying for the transition obligation for post-retirement
20 health care and life insurance benefits twice.
21 Q. Is it appropriate to offset the gain with a
22 PURPA contract or the Nez Perce lawsuit?
23 A. No. These costs also are being amortized
24 over a period of years, and that amortization is already
25 accounted for in current rates. Therefore, it makes no
266
AVU-E-99-6 STOCKTON (Di) 15
12/02/99 STAFF
1 sense to offset these expenses against the gain from the
2 sale. The customers are already paying these expenses,
3 as the yearly amortization is already built into current
4 rates. Approving an offset for these costs from the gain
5 would allow over-recovery.
6 Q. Does Staff have a proposal for the
7 treatment of the Idaho jurisdictional regulatory customer
8 portion of the gain on the sale of the Centralia
9 facility?
10 A. Yes. Staff proposes that the Idaho
11 jurisdictional regulatory customer portion of the gain be
12 credited to Account 254.XX - Other Regulatory Liabilities
13 - Centralia Sale Gain. The unamortized amount in this
14 account will be deducted from rate base, thereby reducing
15 rate base by the gain amount. Staff also proposes that
16 current rates be reduced to reflect the revenue
17 requirement reduction associated with the lower rate base
18 from the
19 gain. Staff is proposing that Account 254 be amortized
20 over a period of 8 years, and that current rates be
21 reduced to reflect the yearly amortization expense. The
22 calculations for Staff's proposal are provided in Staff
23 Exhibit No. 104 (revised).
24 Q. Why should the gain be used to reduce rate
25 base?
267
AVU-E-99-6 STOCKTON (Di) 16
12/02/99 STAFF
1 A. The gain should be used to reduce rate base
2 because Centralia is rate based. Reducing rate base
3 gives customers the full and immediate benefit of the
4 gain in a simple and efficient manner.
5 Q. Please explain the benefits customers will
6 receive from the gain?
7 A. Customers benefit from the reduced rate base
8
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
268
AVU-E-99-6 STOCKTON (Di) 16a
12/02/99 STAFF
1 and the associated revenue requirement reduction. Staff
2 proposes that the reduced revenue requirement be
3 immediately reflected in current rates. Therefore,
4 customers will see benefits immediately.
5 Q. Have you calculated the reduction to Avista's
6 revenue requirement as a result of reducing the rate base
7 by the amount of the customer portion of the Idaho
8 jurisdictional gain?
9 A. Yes. My calculations are shown in Exhibit 104.
10 The existing revenue requirement, as well as the overall
11 rate of return, the weighted return on equity, debt and
12 preferred securities, are from Avista's last rate case,
13 Case No. WWP-E-98-11.
14 Q. What is the total revenue requirement reduction
15 associated with the rate base reduction from the gain on
16 the sale?
17 A. The Total Revenue Requirement reduction, as
18 shown on Line 16, Exhibit No. 104, is $1,031,784.
19 Q. How was this amount derived?
20 A. This amount is a composite of four pieces as
21 shown on Exhibit No. 104 (revised). The first piece is
22 the net operating income requirement associated with the
23 return on common equity and preferred stock (lines 4-5).
24 Both equity components are grossed up for income taxes
25 (lines 6-7). The second piece is the net operating income
269
AVU-E-99-6 STOCKTON (Di) 17
12/02/99 STAFF
1 requirement associated with debt (lines 8-9). The third
2 piece is the net operating income requirement associated
3 with preferred securities (lines 10-11). The fourth
4 piece is the amortization expense associated with the
5 regulatory liability (line 12). The total revenue
6 requirement reduction is $1,579,131 as shown on line 13.
7 Staff witness Lobb discusses the rate design for the
8 1.318% decrease in revenue requirement as shown on line
9 15 of Exhibit No. 104 (revised).
10 Q. Does this conclude your testimony?
11 A. Yes, it does.
12
13
14
15
16
17
18
19
20
21
22
23
24
25
270
AVU-E-99-6 STOCKTON (Di) 18
12/02/99 STAFF
1 (The following proceedings were had in
2 open hearing.)
3 COMMISSIONER SMITH: Mr. Ward, do you have
4 questions?
5 MR. WARD: Just a few.
6
7 CROSS-EXAMINATION
8
9 BY MR. WARD:
10 Q Ms. Stockton, if I understand what the
11 Company has filed, and the Staff has essentially agreed
12 to correctly, it goes something like this: With regard
13 to the actual ratemaking impact of the sale of Centralia,
14 leaving aside the question of gain for the moment, okay,
15 I read the Company's proposal to say essentially that
16 when you look at the sale and -- strike that. When you
17 look at the operational costs of Centralia, the all-end
18 cost, rate base, expenses, everything, versus the cost of
19 replacement power, the two are roughly equivalent with
20 replacement power according to the Company being a little
21 cheaper; correct so far?
22 A Yes.
23 Q And on the other hand, the Staff comes back
24 with Mr. Lobb's testimony and suggests that maybe the
25 replacement power will actually be a little more
271
CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff
1 expensive than the all-end cost of Centralia; also
2 correct?
3 A I believe the replacement power costs are
4 unknown.
5 Q But it appears to me that what the Company
6 has suggested, and the Staff has essentially agreed to,
7 is because these two items are about a wash, there's no
8 need for a ratemaking adjustment, this is close enough
9 for government work, so to speak; isn't that what it
10 amounts to?
11 A Not entirely. At this time because the
12 replacement costs are not known, the Staff is not
13 proposing that they're a wash, but because they aren't
14 known, at the time they're known and measurable, that
15 would be the time to address ratemaking.
16 Q Right, I understand what you're saying, but
17 that would be in the future at some other ratemaking
18 proceeding. As of the date the Commission enters this
19 order, apparently the Staff is agreeing there's no need
20 for a rate change other than the gain question.
21 A Yes, and my testimony deals with the gain
22 and Randy Lobb's testimony addresses more the ongoing
23 costs of Centralia and replacement power.
24 Q I understand. Now, if you'd turn to page 2
25 of your testimony, beginning at line 20 you have a
272
CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff
1 quotation from the Uniform System of Accounts that
2 carries on over to the next page, page 3. Do you
3 recognize that?
4 A Yes.
5 Q Now, boiling that down, doesn't that
6 provision essentially state that in the case of disposal
7 of a utility plant such as this the proper accounting
8 procedure is essentially to eliminate it from rate base?
9 There are four steps there, but those four steps
10 eliminate the plant from rate base, do they not?
11 A That's what the FERC accounts state, yes,
12 that's true, and those rules, the FERC accounts are
13 adopted, the System of Accounts for Public Utilities is
14 adopted, in IDAPA 31, Title 12, and it states that the
15 accounts adopted by reference are adopted for convenience
16 of establishing uniform systems of accounts only for
17 accounting and reporting and do not bind the Commission
18 in any manner to any particular ratemaking treatment of
19 items in those accounts.
20 Q I understand that, but isn't it the normal
21 course of events in reviewing a utility's request in a
22 proceeding such as this that the Staff and the Company
23 and all parties follow the Uniform System of Accounts
24 with very rare exceptions?
25 A I would say in general that's true.
273
CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff
1 Q And wouldn't you agree with me that rather
2 than saying the cost of replacing Centralia is roughly
3 equivalent to the cost of running it and therefore we
4 don't have to worry about rates, wouldn't you agree with
5 me that the far more accurate way to deal with this issue
6 in regulatory terms would be to do what's normally done,
7 to eliminate the plant from rate base, make other
8 appropriate adjustments and see what the revenue
9 requirement is?
10 A I would say -- could you repeat that
11 question?
12 Q Probably not. Wouldn't you agree with me
13 that the far more accurate means of determining the
14 Company's revenue requirement after the disposition of
15 Centralia would be to follow the normal Uniform System of
16 Accounting procedure of eliminating the plant from rate
17 base, making other appropriate ratemaking adjustments and
18 determining the revenue requirement?
19 A For regulatory purposes, I believe it would
20 be up to the Commission to decide what to do in
21 ratemaking after a sale.
22 Q Okay, that's fine. I don't want to cut you
23 off.
24 A No, I'm finished.
25 Q If in fact the Commission does not
274
CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff
1 eliminate the plant from rate base but simply makes a
2 judgment as to the relative comparability of post and
3 after revenue requirement, do you think there's any
4 violation or implied violation of the general requirement
5 that a plant in rate base must be used and useful and in
6 fact in production?
7 A The Staff isn't recommending that they keep
8 Centralia in rate base indefinitely.
9 Q But you don't think it has to be taken out
10 until sometime in the future?
11 A Well, my testimony deals more with the
12 disposition of the gain and how that's treated, into
13 which accounts.
14 MR. WARD: All right, thank you very much.
15 COMMISSIONER SMITH: Mr. Dahlke.
16
17 CROSS-EXAMINATION
18
19 BY MR. DAHLKE:
20 Q Just to follow up on Mr. Ward's last
21 questions, I almost interposed a question, I didn't
22 understand what was meant by remove from rate base. So I
23 understand the context of your answers, if an item is
24 removed from rate base, would it be fair to say that that
25 only happens for rate purposes during a rate proceeding
275
CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff
1 with an order at the end of a rate proceeding?
2 A An item can be removed from rate base, but
3 it would not be reflected in rates until the next general
4 rate case were filed.
5 Q So the appropriate accounting entries might
6 be made to remove an item from rate base, but that's
7 different from removing it in the sense that the revenue
8 stream associated with that item is removed from an
9 overall rate calculation?
10 A That's correct. It would not be reflected
11 in rates until a rate case.
12 Q I wanted to ask you a question about the
13 Boise Water Corporation matter and the Supreme Court
14 decision in Idaho that is referenced in your testimony.
15 What I'd like to ask is whether Staff believes that the
16 Boise Water Corporation case precludes the Commission
17 from ordering any other sharing of the gain of Centralia
18 than the depreciation method that is discussed in that
19 case or if there were a sufficient factual basis, is it
20 possible that the Commission could consider other
21 allocations than that one allocation?
22 A Not being an attorney, I don't know how
23 binding the Supreme Court decision is on them, but I'm
24 certain, I'm not certain, I'm sure that the Commission
25 takes all of those things into consideration when they
276
CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff
1 make their decision as to how a gain should be treated.
2 Q So your approach was that you believed that
3 that was the fair method, not that it was a method
4 required as a matter of law by the Boise case?
5 A It was a method that they had used after
6 that case, also.
7 Q At page 12 of your testimony, beginning at
8 line 14, you make the statement, "The customers paid for
9 and thus purchased a portion of the plant." Is it your
10 testimony that the customers actually become an owner of
11 the plant by virtue of their having paid for electric
12 service to Avista Corporation?
13 A Not that they have title. They have an
14 equitable ownership of that plant which would entitle
15 them to sharing in the gain.
16 Q So the equitable concept that you're
17 referring to, then, is an overall concept of fairness as
18 applied to what should happen to the gain, any particular
19 gain? It doesn't derive simply because you are or are
20 not a fee title owner?
21 A No.
22 Q So would you accept that if the equities
23 favored allocating the gain to shareholders rather than
24 to ratepayers in a particular case that that type of
25 allocation would be permissible?
277
CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff
1 A I would be assuming that that would be the
2 sale of something that the ratepayers or customers had no
3 equitable ownership in?
4 Q Okay, let's start with that. If they have
5 no equitable ownership, that's one case where the gain
6 would not be allocated to shareholders -- or to
7 customers, I'm sorry; is that right?
8 A If the theory is that if the ratepayers
9 through their payment of depreciation expense built into
10 rates and maintenance of the plant, et cetera, causes
11 them to have an equitable ownership, then they would
12 share in the gain. If they didn't have an equitable
13 ownership, the opposite, if you hold that theory, then
14 the opposite would be true. If they had no equitable
15 ownership when the item is sold, then they would not
16 share in the gain.
17 Q The concept of equity there being tied to
18 payment of depreciation expense, that's the basis for the
19 depreciation method; is that correct?
20 A Yes.
21 Q Wouldn't you acknowledge that there are
22 other equities that the Commission might consider in
23 deciding how to allocate a gain than just that one
24 equitable consideration? Couldn't there be others?
25 A There certainly could.
278
CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff
1 Q I'd like to ask you about your testimony on
2 ice storm which I believe begins on page 13. Is it your
3 understanding that Avista has not requested recovery of
4 ice storm costs through prior rate proceedings?
5 A Could you repeat that?
6 Q Isn't it the case that Avista Corporation
7 has not requested recovery of costs associated with ice
8 storm in prior rate proceedings?
9 A I believe they did request recovery in the
10 last general rate case through the six-year rolling
11 average of injuries and damages that included some ice
12 storm costs in their request.
13 Q And what was the disposition of that
14 request?
15 A In that case, the Commission found that
16 they could not authorize the requested recovery of the
17 ice storm expense in present rates.
18 Q And am I to understand that you believe
19 that that finding precludes the opportunity to use the
20 ice storm costs as an offset to the gain allocation
21 that's made in this proceeding?
22 A Not that they didn't request -- it was the
23 language in the Order that I took to mean where they say
24 when it became aware -- the Order states, "When it became
25 aware that the uninsured ice storm costs would be
279
CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff
1 substantial, the Company had the opportunity to request
2 rate relief or deferral of these costs for future
3 recovery. It did neither. Accordingly, we cannot in
4 this case authorize the requested recovery of this
5 expense."
6 It says further up, "The proscription
7 against retroactive ratemaking means that ice storm costs
8 expended by the Company in the past are not recoverable
9 through future rates unless they are preserved for that
10 purpose by deferral or other regulatory action."
11 I took that to mean since the Company did
12 not take action at the time of the ice storm when it
13 became aware that those would be substantial that they
14 could not recover them.
15 Q Would you agree that the sale of a major
16 utility plant such as Centralia that's been in Avista's
17 rate base is an extraordinary event?
18 A Are you meaning "extraordinary" in terms of
19 accounting terms or --
20 Q No, in terms of how often that type of an
21 event occurs.
22 A If you're defining extraordinary as being
23 not very often, then it would be an extraordinary event.
24 Q And wouldn't you agree that the ice storm
25 costs which were an extraordinary event and the sale of
280
CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff
1 Centralia producing a gain which is an extraordinary
2 event, wouldn't it make sense that those two could be
3 considered by the Commission in connection with each
4 other, notwithstanding that you may not entertain a
5 regular rate case request for recovery two years after
6 the event when there was a rate case in between and the
7 Company passed up an opportunity to request for those
8 costs?
9 A I'm sorry, I'm not understanding the
10 question.
11 Q I understand why. I'm trying to get at the
12 concept of -- I understand you're saying that because the
13 Company did not request the ice storm costs immediately
14 after the ice storm occurred in a rate case or in a
15 special proceeding that your feeling is that that more or
16 less precludes recovery on down the road because the
17 decision has been made, that's what I understood you to
18 say.
19 A That was -- my interpretation of the Order
20 was that a regulatory, some kind of deferral account, a
21 regulatory-approved deferral account or something, needed
22 to be done at the time and that wasn't done.
23 Q And my question was if another
24 extraordinary event comes down the line which creates the
25 potential for a large gain that we weren't expecting, why
281
CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff
1 can't you consider that gain in connection with the
2 earlier extraordinary event that had created the loss?
3 A My interpretation of the Order is that the
4 ice storm reimbursement, that's already been dealt with,
5 that that issue is closed.
6 Q In any event, you don't have any problem in
7 agreeing that the ice storm expenditures that the Company
8 made were prudent and necessary, do you?
9 A No, I'm not saying they weren't prudent and
10 necessary.
11 Q At page 9, beginning at line 6 of your
12 testimony, you discuss an Idaho Power Company case that
13 deals with the loss on sale of distribution facilities;
14 is that correct?
15 A Yes, I do.
16 Q And isn't it true that the Staff proposed
17 and the Commission accepted Staff's proposal there that
18 the unamortized balance of the loss not be included in
19 rate base? I guess to me that means there's no carrying
20 charge on the unamortized balance of that loss.
21 A Yes, that's what the Order said.
22 Q And that was Staff's position as well at
23 that time?
24 A Yes, that was Staff's position at that
25 time.
282
CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff
1 Q In the case of the Centralia gain, am I
2 correct that it is Staff's position that you are to
3 include the unamortized gain in rate base; is that
4 correct?
5 A Yes, the unamortized balance would be a
6 reduction of rate base.
7 Q Do you see any inconsistency in those two
8 positions?
9 A My reason for each case is different. When
10 I included that case in my testimony, my thoughts were
11 that the Commission has consistently shared the gain in
12 an equitable manner with the customers and in that case
13 it was a loss and they shared that loss with the
14 customers. The customers had to bear that loss, but each
15 case is different and the disposition of the gain in each
16 case was also different, with the exception of it being
17 equitably shared with the ratepayers.
18 Q Could you please explain why it is
19 appropriate not to include a return on a loss, but to
20 include a return on a gain, if you can respond to that in
21 a general sense and without having to respond as to the
22 specifics of either of the cases?
23 A I'm confused by the question.
24 Q I think you answered that each of those
25 cases had to be dealt with on their own facts and I
283
CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff
1 understand there may be differences. I was trying to get
2 at whether there is some -- is there any prohibition -- I
3 mean, in the first instance, you would think that if you
4 were going to include a return or a carrying charge on an
5 event that causes a loss you'd do the same on an event
6 that causes a gain for the unamortized balance and I just
7 want to understand what the reason is why it was done
8 differently between those two cases and if it's the
9 specific facts of those cases, if you could help us what
10 those facts were.
11 A I'm not entirely familiar with the specific
12 facts of that Idaho Power case.
13 MR. DAHLKE: That's fine. That's all I
14 have.
15 COMMISSIONER SMITH: Okay, do we have
16 questions from the Commission? Commissioner Kjellander.
17 COMMISSIONER KJELLANDER: I have just one,
18 Ms. Stockton.
19
20 EXAMINATION
21
22 BY COMMISSIONER KJELLANDER:
23 Q You were being asked a few moments ago
24 about whether or not you perceived it as being
25 extraordinary that a generation asset might be sold off
284
CSB REPORTING STOCKTON (Com)
Wilder, Idaho 83676 Staff
1 by Avista. I was sort of wondering if you did any review
2 of the electric industry as a whole. Are you seeing more
3 and more instances where either through specific state
4 regulatory activity or through concerns about electric
5 restructuring that it might be labeled as more
6 commonplace to see generation assets being sold off for
7 electric utilities across the country?
8 A Certainly in the industry right now
9 industry-wide it's not an extraordinary event. It may be
10 for that particular company if that's the only generating
11 asset they ever sell. In accounting terms, that could be
12 an extraordinary event.
13 COMMISSIONER KJELLANDER: Thank you.
14 COMMISSIONER SMITH: I guess I'll just take
15 my stab at the ice storm.
16
17 EXAMINATION
18
19 BY COMMISSIONER SMITH:
20 Q I think you were asked, couldn't the
21 Commission look at, which I thought was a very creative
22 argument, that one extraordinary event in the red ink
23 could be offset by another extraordinary event with black
24 ink and the answer to question is of course.
25 A The Commission can do anything.
285
CSB REPORTING STOCKTON (Com)
Wilder, Idaho 83676 Staff
1 Q The Commission could do that.
2 A Yes.
3 Q Would that be good regulatory policy and
4 would you see that perhaps Idaho Power Company would find
5 some extraordinary event to offset its Pac Hyde clean-up
6 expense of millions of dollars?
7 A I could see that that could be a
8 consequence of that.
9 Q And could it be that no issue would ever be
10 settled until the utility had recaptured every last dime
11 of what it thought it should get?
12 A That's possible.
13 Q On the rate base issue, if all we do is
14 reduce the rate base by the amount of the gain that
15 you've calculated and then have this reduction -- which
16 I'm no longer sure since we replaced Exhibit 104, is it
17 still .551 percent or is it now 1.318 percent?
18 A Let's see. Yes, the percent reduction
19 would be 1.318 percent.
20 Q So if that's the only reduction we do and
21 we don't remove this plant from rate base, then is the
22 rate base overstated?
23 A If you don't remove it from rate base, it
24 would be overstated, but you would true that up at the
25 next general rate case.
286
CSB REPORTING STOCKTON (Com)
Wilder, Idaho 83676 Staff
1 Q Is there any way to true-up the rates that
2 customers will pay between now and whenever this
3 hypothetical next rate case occurs? Is there any way to
4 go back and say, ah, we're truing it up, you now get
5 backs $.50 a month for the past X years, can we do that?
6 A I suppose you could set up a mechanism like
7 the PCA.
8 Q Have you ever heard of retroactive
9 ratemaking? Do you think we might run into some trouble?
10 A Yes.
11 COMMISSIONER SMITH: Mr. Woodbury, do you
12 have any redirect?
13 MR. WOODBURY: Staff has no redirect.
14 COMMISSIONER SMITH: Thank you,
15 Ms. Stockton.
16 (The witness left the stand.)
17 MR. WOODBURY: Staff would call as its next
18 witness Randy Lobb.
19
20
21
22
23
24
25
287
CSB REPORTING STOCKTON (Com)
Wilder, Idaho 83676 Staff
1 RANDY LOBB,
2 produced as a witness at the instance of the Staff,
3 having been first duly sworn, was examined and testified
4 as follows:
5
6 DIRECT EXAMINATION
7
8 BY MR. WOODBURY:
9 Q Mr. Lobb, will you please state your name
10 for the record?
11 A My name is Randy Lobb, L-o-b-b.
12 Q For whom do you work and in what capacity?
13 A I work for the Idaho Public Utilities
14 Commission as the engineering supervisor.
15 Q And in that capacity, did you have occasion
16 to prefile testimony in this case consisting of 14 pages
17 and three exhibits, Exhibits 101, 102 and 103?
18 A Yes, I did.
19 Q And have you had the occasion to review
20 that testimony prior to this hearing?
21 A Yes, I have.
22 Q Is it necessary to make any changes or
23 corrections to that testimony or those exhibits?
24 A Yes, I have a couple of changes. I have a
25 modification on page 12, line 11 and line 20. The number
288
CSB REPORTING LOBB (Di)
Wilder, Idaho 83676 Staff
1 "0.551%" should be changed to "1.318%" as a result in
2 changes in Ms. Stockton's testimony.
3 The second change is replacement of
4 Exhibit 103 with a corrected exhibit to correct an error
5 on the original. The new exhibit should show a firm
6 purchase replacement in columns 2 and 3 of $2,490 to
7 reflect the cost -- actually, it's a number, it's 2,490
8 is the number in columns 2 and 3 -- to reflect the cost
9 of capacity and shaping and so, therefore, the grand
10 total revenue requirement, the last row on that exhibit,
11 would also be changed as a result of the addition of the
12 2,490 in columns 2 and 3.
13 Q What would be the new numbers for your
14 totals?
15 A The column 2 total would be 55,817.
16 Column 3 grand total revenue requirement would be 1,004.
17 Q And, as corrected, if I were to ask you the
18 questions set forth in your testimony and reflected in
19 your exhibits, would your answers be otherwise the same?
20 A Yes, they would.
21 MR. WOODBURY: Madam Chair, I'd ask that
22 the testimony be spread, that the exhibits be identified
23 and I'd present Mr. Lobb for cross-examination.
24 COMMISSIONER SMITH: If we could also
25 correct on page 11, line 9, the spelling of Mr. Ely's
289
CSB REPORTING LOBB (Di)
Wilder, Idaho 83676 Staff
1 name, I would spread the testimony upon the record as if
2 read and identify the exhibits.
3 (The following prefiled testimony of
4 Mr. Randy Lobb is spread upon the record.)
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
290
CSB REPORTING LOBB (Di)
Wilder, Idaho 83676 Staff
1 Q. Please state your name and business address
2 for the record.
3 A. My name is Randy Lobb and my business
4 address is 472 West Washington Street, Boise, Idaho.
5 Q. By whom are you employed?
6 A. I am employed by the Idaho Public Utilities
7 Commission as Engineering Supervisor.
8 Q. What is your educational and professional
9 background?
10 A. I received a Bachelor of Science Degree in
11 Agricultural Engineering from the University of Idaho in
12 1980 and worked for the Idaho Department of Water
13 Resources from June of 1980 to November of 1987. I
14 received my Idaho license as a registered professional
15 Civil Engineer in 1985 and began work at the Idaho Public
16 Utilities Commission in December of 1987. My duties at
17 the Commission include analysis of utility rate
18 applications, rate design, tariff analysis and customer
19 petitions. I have testified in numerous proceedings
20 before the Commission including cases dealing with rate
21 structure, cost of service, power supply, line extensions
22 and facility acquisitions.
23 Q. What is the purpose of your testimony in
24 this case?
25 A. The purpose of my testimony in this case is
291
AVU-E-99-6 LOBB, R (Di) 1
12/02/99 STAFF
1 to evaluate the quantitative and qualitative reasons put
2 forth by Avista Corporation d.b.a. Avista Utilities -
3 Washington Water Power Division (Avista; Company)
4 as justification for sale of the Centralia coal fired
5 power plant (Centralia, the plant). Based on the
6 evaluation, I will then provide a recommendation
7 regarding the sale. I will also address the need to
8 modify revenue recovery through rates should the sale of
9 the plant proceed.
10 SUMMARY
11 Q. Would you please summarize your testimony.
12 A. The long-term economic analysis provided by
13 the Company that compares the future cost of keeping the
14 Centralia plant with selling the plant and purchasing
15 replacement resources neither justifies nor precludes the
16 transaction. Depending upon the escalation rates for
17 coal and market resources and the actual replacement
18 alternative chosen, keeping the plant could be more or
19 less costly than likely generation alternatives over the
20 plant's remaining life.
21 Absent a clear economic reason for the
22 sale, the justification must be based on the elimination
23 of reclamation cost risk, the elimination of uncertainty
24 associated with multiple project owners and on an
25 equitable distribution of the gain. I believe that the
292
AVU-E-99-6 LOBB, R (Di) 2
12/02/99 STAFF
1 Company should be allowed to exercise its business
2 judgement in addressing the qualitative issues associated
3 with Centralia operation. I therefore, recommend that
4 the sale be allowed to proceed. However, I also believe
5 that the only tangible and quantifiable way to
6 demonstrate that customers will not be harmed is to
7 require that the gain be shared. I recommend that the
8 reduction in revenue requirement associated with the gain
9 be spread equally to all customer classes on a uniform
10 percentage basis once the sale closes.
11 Finally, my analysis shows that the revenue
12 requirement for Centralia replacement alternatives is
13 projected to be higher in the future than the Centralia
14 revenue requirement currently included in rates. This is
15 true with or without continued Centralia operation. Mere
16 projections however are not certainties and provide no
17 basis for departing from test-year data. Therefore, I
18 recommend that the revenue requirement not be changed to
19 reflect future changes in power costs.
20 LOADS/RESOURCES
21 Q. Please describe Avista's current
22 load/resource situation.
23 A. According to Avista's 1997 Integrated
24 Resource Plan (IRP), the Company's year 2000 peak
25 obligations, including retail load and wholesale sales,
293
AVU-E-99-6 LOBB, R (Di) 3
12/02/99 STAFF
1 are slightly more than available peak resources.
2 Centralia provides 201 MW or approximately 9% of the peak
3 capacity for a system that according to the IRP has
4 little or no peak reserves until wholesale sales
5 contracts begin to expire in 2001. Based on information
6 provided by Avista, I understand that the Company has
7 acquired an additional 50 - 100 MW of short-term firm
8 power through contracts that are not included in the 1997
9 IRP report.
10 Q. How does the cost of operating Centralia
11 compare to other Company-owned resources and purchase
12 prices?
13 A. Based on information provided in Case No.
14 WWP-E-98-11, the fuel costs for the four dispatchable
15 Avista thermal resources are 1) the Colstrip coal fired
16 plant at $7.59/MWh, 2) the Centralia coal fired plant at
17 $18.24/MWh, 3) the Rathdrum Gas fired turbine at $23/MWh
18 and 4) the Kettle Falls wood fired plant at $9.86/MWh.
19 While these prices represent the lion's share of the
20 variable cost of operating the plants, they do not
21 include operation and maintenance or capital recovery
22 costs.
23 The Company in Case No. WWP-E-98-11
24 calculated the weighted average unit price for secondary
25 purchases and sales to be $18.32/MWh while the average
294
AVU-E-99-6 LOBB, R (Di) 4
12/02/99 STAFF
1 weighted non-firm price at mid-Columbia from August 1,
2 1998 through July 31, 1999 was $20.75/MWh. These prices
3 reflect the cost of non-firm energy without capacity.
4 The average weighted firm price at mid-Columbia for the
5 same period of $26.27/MWh is comparable to the firm
6 market price that is escalated by Avista to predict the
7 cost of replacing Centralia.
8 THE ECONOMIC ANALYSIS
9 Q. Have you reviewed the Company's testimony
10 regarding the economic impact of selling the Centralia
11 power plant?
12 A. Yes, I have reviewed the testimony of all
13 Company witnesses including that of Mr. Johnson, a Power
14 Contracts Analyst for the Company. Mr. Johnson
15 specifically provides an analysis that compares the
16 future costs, on a net present value basis, of operating
17 Centralia to the future cost of selling Centralia and
18 replacing the generation with market purchases.
19 Q. What does Mr. Johnson's analysis show?
20 A. Mr. Johnson's analysis shows that the
21 levelized cost of Centralia over the next 20 years is
22 projected to be $32 per MWh while the levelized
23 replacement cost over the same period is projected to be
24 $31.37 per MWh. This represents a projected difference
25 of 2% in the net present value of the annual revenue
295
AVU-E-99-6 LOBB, R (Di) 5
12/02/99 STAFF
1 requirement with and without Centralia. Based on its
2 analysis showing this reduction, the Company states that
3 the sale will not harm existing customers.
4 Q. Is the 2% cost reduction shown by the
5 analysis sufficient to conclude that no harm will come to
6 customers as a result of the sale?
7 A. No, I don't believe that it is in this case
8 because the small reduction is based on twenty years of
9 projected expenses. Over this period, a small change in
10 a single critical assumption can turn a projected expense
11 reduction into an expense increase.
12 Q. What are the critical assumptions in the
13 economic analysis and what effect do changes have on the
14 results?
15 A. Staff Exhibit No. 101 is a graphical
16 representation of the components that make up the
17 Centralia annual revenue requirement. As the graph
18 shows, just over 60% of the revenue requirement is for
19 coal to fuel the plant. Therefore, the coal escalation
20 rate over the twenty-year period is critical in
21 determining the cost of operating Centralia over its
22 remaining life.
23 Company witness Johnson chose to use a coal
24 escalation rate of 2% per year to ultimately derive the
25 annual net savings of $7.7 million. If the 1999 Standard
296
AVU-E-99-6 LOBB, R (Di) 6
12/02/99 STAFF
1 and Poor's DRI Coal escalation rate of 1.73% for the same
2 period is used, the annual savings are reduced to $1.3
3 million or 0.3% of annual revenue requirement. If the
4 historic, 1989-1998 actual coal escalation rate of 1.53%
5 or the 1.4% base coal escalation rate provided by
6 PacifiCorp in Case No PAC-E-99-2 (the Centralia sale
7 case) are used in the calculation, net annual expenses
8 will actually increase by $3.3 and $6.2 million
9 respectively.
10 Q. Are there other assumptions that are
11 critical to the economic analysis?
12 A. Yes. Mr. Johnson's analysis assumes that
13 replacement power costs purchased from the market over
14 the twenty-year period will essentially escalate at the
15 rate of 2.5% per year. If energy rates escalate at 2.8%
16 per year, the annual expense reduction of $7.7 million is
17 eliminated entirely and a slight increase results. The
18 high market rate projects shown by Mr. Johnson on Exhibit
19 No. 1, page 2 of 2 represent an equivalent energy
20 escalation rate of approximately 4% and result in net
21 increased revenue requirement of nearly $36 million per
22 year. The table provided in Staff Exhibit No. 102 shows
23 how projected savings change with changes in variables.
24 Q. Are there any other reasons that lead you
25 to conclude that benefits demonstrated in the economic
297
AVU-E-99-6 LOBB, R (Di) 7
12/02/99 STAFF
1 analysis are unreliable?
2 A. Yes, the purchase of market resources that
3 escalate at a fixed rate is just one of a number of
4 possible replacement alternatives. Mr. Johnson indicates
5 that a combined cycle combustion turbine (CT) with a cost
6 equivalent to the high market purchase price in 2003 is
7 also being explored. Standard and Poor's DRI projects
8 natural gas escalation rates of nearly 4.3% over the 2001
9 to 2020 period. Gas escalation rates in this range will
10 not only significantly increase the cost of CTs over
11 time, they could likely cause market purchase prices to
12 increase faster than anticipated in the Company's
13 analysis.
14 Mr. Johnson also points out that the
15 Centralia plant is dispatchable and can be shut down when
16 it is not economical to operate. Market purchases are
17 not dispatchable and therefore, are less advantageous
18 from a resource flexibility perspective. Finally, I
19 believe Mr. Johnson correctly points out in testimony on
20 page 3 that: "Since no power replacement options have
21 been finalized, the actual cost is not known."
22 Q. What do you conclude from the net present
23 value analysis conducted by the Company?
24 A. The net present value analysis with and
25 without Centralia provides one estimate of how annual
298
AVU-E-99-6 LOBB, R (Di) 8
12/02/99 STAFF
1 revenue requirement might be affected when certain
2 conditions are projected over the next twenty years. The
3 analysis also shows that the impact can be positive or
4 negative when conditions vary within a reasonable range.
5 Furthermore, the analysis does not compare the future
6 cost of Centralia to the cost of resources actually
7 chosen as a replacement by the Company. Consequently, I
8 do not believe that the Company's estimated 2% reduction
9 in annual revenue requirement alone provides sufficient
10 justification for selling the plant nor does it
11 reasonably or reliably satisfy the no-harm to customers
12 standard.
13 SALE BENEFITS
14 Q. What other benefits are cited by the
15 Company as justification for the sale?
16 A. Company witness Ely states that the Company
17 and its customers will benefit through reduced exposure
18 to mine reclamation costs and by enabling Avista to
19 conduct resource optimization strategies more
20 independently.
21 Q. Are these legitimate benefits that can be
22 quantified?
23 A. They may be legitimate benefits but I do
24 not believe they are readily quantifiable. Clearly,
25 final reclamation of the Centralia coal mine represents a
299
AVU-E-99-6 LOBB, R (Di) 9
12/02/99 STAFF
1 significant cost liability to Avista. PacifiCorp
2 testimony in Case No. PAC-E-99-2 (the Centralia sale)
3 indicates that reclamation costs could vary widely
4 depending upon the reclamation method used but could be
5 as high as $350 million in 1999 dollars with mine
6 shutdown near the year 2020. It should be noted however,
7 that Avista would only bear a share of the reclamation
8 cost and according to the testimony of Mr. Johnson,
9 expenses to fund current estimates of future reclamation
10 costs are included in the net present value economic
11 analysis.
12 With respect to problems associated with
13 multiple plant owners, Company witness Ely indicates in
14 testimony that plant closure with associated plant
15 dismantling costs and mine reclamation costs is possible
16 absent the sale. The Centralia ownership agreement
17 requires that there be unanimous agreement between owners
18 before any capital investment at the plant is undertaken.
19 The owners did not reach unanimous agreement for scrubber
20 investment at Centralia but the agreement provides no
21 recourse in such a situation.
22 Theoretically, the Company and its customers
23 could wind up paying plant closure costs and resource
24 replacement costs if the sale falls through and the plant
25 closes. Although the likelihood of such an event is
300
AVU-E-99-6 LOBB, R (Di) 10
12/02/99 STAFF
1 impossible to predict, Avista seems to believe that the
2 plant would continue to operate should the sale not take
3 place given its willingness and commitment to purchase
4 plant shares owned by other companies.
5 Q. Is the exposure to potentially high mine
6 reclamation costs and the threat of plant closure absent
7 the sale justification for the sale? Is it a sufficient
8 showing that customers will not be harmed?
9 A. Company witness Ely states in testimony that
10 the decision to sell was based on business judgement,
11 qualitative factors surrounding continued ownership,
12 projected replacement power costs and the price offered
13 by the buyer. I believe that the Company's right to
14 exercise its business judgement regarding the qualitative
15 factors surrounding continued operation of Centralia
16 provides sufficient basis for allowing the sale to
17 proceed. However, I also believe that the reasons for
18 allowing the sale to proceed while potentially beneficial
19 to customers are unquantifiable and an insufficient
20 showing that customers will not be harmed.
21 RECOMMENDATION
22 Q. What do you recommend?
23 A. I recommend that the sale be allowed to
24 proceed but that the gain on the sale be shared with
25 ratepayers to sufficiently demonstrate that customers
301
AVU-E-99-6 LOBB, R (Di) 11
12/02/99 STAFF
1 will not be harmed by the transaction. I believe that
2 the purchase price offered by the buyer and the resulting
3 profit from the sale, is an important justification for
4 the sale and should be shared with customers. Moreover,
5 I believe it is the only tangible way to show that
6 customers will not be harmed given the intangible
7 potential qualitative benefits and the unreliability of
8 replacement power cost projections.
9 Q. Staff witness Stockton has determined that
10 the revenue requirement associated with the rate base
11 reduction from the gain represents 1.318% of the total
12 Idaho jurisdictional revenue requirement authorized by
13 the Commission in Case No. WWP-E-98-11, Stockton Exhibit
14 No. 104. How do you propose to return the revenue
15 associated with the gain to Idaho ratepayers?
16 A. I recommend that the revenue requirement
17 for all customer classes, excluding special contracts, be
18 decreased by a uniform percentage once the sale closes.
19 I further recommend that the rate components within each
20 class be reduced by 1.318%.
21 REVENUE REQUIREMENT ADJUSTMENT
22 Q. If the sale is allowed to proceed, should
23 the revenue requirement approved by the Commission in
24 Avista's last general rate case be modified to reflect
25 replacement power costs?
302
AVU-E-99-6 LOBB, R (Di) 12
12/02/99 STAFF
1 A. No, it should not be modified at this time.
2 My analysis using the Company's power supply model and
3 portions of Mr. Johnson's economic analysis show that the
4 authorized revenue requirement for Centralia is lower
5 than the future revenue requirement projected for
6 replacement power. Staff Exhibit No. 103 compares the
7 estimated revenue requirement authorized for Centralia in
8 the last rate case with two power replacement scenarios.
9 The first scenario uses the dispatch simulation model to
10 replace Centralia with secondary power purchases. An
11 additional cost increment is then added for capacity and
12 shaping. The second scenario uses the dispatch
13 simulation model to replace Centralia with the 1999
14 medium market price as shown in Company Exhibit No. 1,
15 page 2 of 2.
16 Exhibit No. 103 shows that when all revenue
17 requirement components are included, both power
18 replacement scenarios have a higher projected revenue
19 requirement than what is currently included in rates for
20 Centralia. After the transaction is complete, the
21 perceived difference in revenue requirement will be the
22 relative difference between the revenue requirement of
23 Centralia if it were not sold and the revenue requirement
24 of replacement resources. These differences to the
25 extent they materialize would be captured in a subsequent
303
AVU-E-99-6 LOBB, R (Di) 13
12/02/99 STAFF
1 rate case.
2 Q. Does that conclude your testimony?
3 A. Yes it does.
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
304
AVU-E-99-6 LOBB, R (Di) 14
12/02/99 STAFF
1 (The following proceedings were had in
2 open hearing.)
3 COMMISSIONER SMITH: Questions, Mr. Ward?
4 MR. WARD: Yes.
5
6 CROSS-EXAMINATION
7
8 BY MR. WARD:
9 Q Mr. Lobb, probably the best place to start
10 is on page 13. Were you in the room when I asked
11 Ms. Stockton questions?
12 A Yes.
13 Q So let me avoid walking all the way through
14 that again but simply ask this: Rather than making an
15 attempt to say that the before and after cost is roughly
16 the same, before and after Centralia, shouldn't this
17 Commission be removing Centralia from rate base, making
18 any appropriate adjustments in revenues and expenses in
19 that regard, including those through the power supply
20 model, and isn't that the accurate way to determine the
21 revenue requirement consequences of this sale?
22 A Well, you could certainly take Centralia
23 out of the revenue requirement, revenue requirement of
24 Centralia out from rates. My position is that we simply
25 don't know what the replacement alternatives will be, so
305
CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff
1 if you adjust one side of the ledger, you would have to
2 adjust the other side of the ledger. You can make
3 assumptions with respect to what type of replacement
4 alternatives there will be and how much they will cost
5 and what type of revenue requirement you should add back
6 into the total, but without knowing that, I just am
7 unable to make a recommendation on that.
8 Q But wouldn't the power supply model
9 determine accurately what the actual replacement costs
10 for output are?
11 A The power supply model, if you take
12 Centralia out of the power supply model, it would simply
13 purchase at the spot price and that's just a non-firm
14 purchase price. It has no capacity. The Company may
15 choose to do that, but they may not choose to do that.
16 They may choose to go out and get a firm purchase at a
17 different price, and I think if you look at my
18 Exhibit 103, that's what I'm attempting to show is that
19 if you assume they make a non-firm spot purchase in the
20 power supply model, you get X revenue requirement. If
21 you assume they make a firm purchase at some rate that is
22 currently unknown, they would have a different revenue
23 requirement. If they built a plant somewhere at X cost,
24 you would get an entirely different revenue requirement,
25 and that's the whole point is I just don't know what that
306
CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff
1 revenue requirement for the replacement resources will
2 be.
3 Q Well, I understand that, Mr. Lobb. It's
4 like the stock market, any market, nobody knows what the
5 market will be tomorrow.
6 A True.
7 Q But for the life of me, I'm having a very
8 difficult time understanding why taking the plant out of
9 rate base in the normal fashion as the System of Accounts
10 provides and then determining the resulting change in
11 power supply wouldn't give you the actual answer, not a
12 hypothesized answer, the actual answer as to what the
13 changes are.
14 A Well, once again, we don't know what the
15 resulting change in power supply expenses will be. Now,
16 we can take Centralia out, the revenue requirement for
17 Centralia out of rates and that's pretty easy, we know
18 what that is. The replacement alternatives may have a
19 higher revenue requirement than Centralia or it may have
20 a lower revenue requirement than Centralia. The question
21 is what do we put back in and we know that there's going
22 to be a replacement alternative of some kind, whether
23 it's spot purchases or firm purchases or a replacement
24 plant. I don't know what that is.
25 Now, I could guess and we could just put in
307
CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff
1 a number. We could try to project what the Company might
2 do or guess what the Company might do. I'm not sure what
3 that would be. I might also add that there are a lot of
4 changes that occur in expenses and investment and costs
5 of the Company between rate cases, and although in this
6 case we're treating the gain on the sale, at the next
7 rate case we will treat the change in rate base that has
8 occurred just like we would any other change in expense
9 that occurs between rate cases.
10 Q I understand that, Mr. Lobb, but let me try
11 one more time and then I'll get off of this. As I
12 understand it, the power supply model as it now exists
13 forecasts under normalized conditions, let's assume
14 completely average, completely normalized conditions, it
15 forecasts a power supply cost net X, whatever it is,
16 $20 million net in costs let's say. Now, we know that's
17 the normalized condition. We also know that the model
18 can model other conditions and, in fact, that's the way
19 we adjust in the PCA, isn't it?
20 A Could you say that again? What was that
21 last part?
22 Q Well, we track PCA adjustments because in
23 fact we have a combination of actuals to measure against
24 normalized results; right?
25 A Sure, with respect to water conditions,
308
CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff
1 that's correct.
2 Q Well, with respect to other conditions,
3 though, too, correct, secondary sales, items like that?
4 A Well, those are an offshoot of the changes
5 in water conditions.
6 Q Okay. Now, why couldn't we take this plant
7 out of rate base and why shouldn't we take this plant out
8 of rate base and simply run the resulting changes through
9 the power supply model?
10 A You could certainly do that, but you're
11 taking 201 megawatts of capacity out of service and
12 you're replacing it with a non-firm spot energy purchase,
13 so I think there's reliability questions, and one of the
14 reasons I added in a capacity and shaping increment in my
15 Exhibit 103 in column 2 was to reflect the fact that you
16 can't just replace a firm 201 megawatt capacity plant
17 with a bunch of non-firm spot purchases and I don't know
18 what that capacity cost would be, so you're going to have
19 to replace it with more than just non-firm energy.
20 You're going to have to have some other instrument, a
21 capacity purchase or some type of firm instrument, to
22 include as a replacement.
23 Q That capacity problem exists regardless of
24 how we treat this adjustment, does it not? I mean, the
25 Centralia plant is physically gone when the sale is
309
CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff
1 completed?
2 A Yes.
3 Q Okay. Do you know if the Commission's
4 failure to remove a sold plant from rate base has any
5 implications in other jurisdictions, in the federal
6 jurisdiction, for instance, if you know?
7 A I guess I don't really know with regard to
8 the federal jurisdiction. I would assume that each state
9 would address the costs at the time of a rate case in
10 those states.
11 Q Last area. Obviously, you and the Company
12 disagree on your projections to some degree regarding the
13 replacement costs. You're suggesting they would be
14 somewhat higher, the Company that they would be somewhat
15 lower than the Centralia revenue requirement. Assume for
16 the moment that the Company is right, that replacement
17 costs are in fact lower. Do you have that hypothesis in
18 mind?
19 A Yes.
20 Q If we simply adopt the -- if the Commission
21 simply in this Order says, well, you know, these are
22 roughly equivalent, the before and after scenario, so
23 we're going to leave rates as is, not worry about rate
24 base adjustments and things like that and the Company
25 turns out to be correct, under the Staff's hypothesis, we
310
CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff
1 leave it to the Company to decide whether it wants to
2 come in and true-up that situation or going forward to
3 change that revenue requirement, don't we?
4 A To the extent they can choose when they
5 want to come in. On the other hand, the Commission can
6 conduct an overearnings investigation and call the
7 Company in.
8 Q On the other hand, if you're right and the
9 Company faces a revenue requirement that's significantly
10 higher if it turns out that way, don't you think the
11 Company will be in, all other things being equal, quite
12 promptly?
13 A Probably so.
14 MR. WARD: That's all I have.
15 COMMISSIONER SMITH: Thank you, Mr. Ward.
16 Let's take a ten-minute break.
17 MR. WARD: Madam Chair, could I have
18 Dr. Peseau excused?
19 COMMISSIONER SMITH: Is there any objection
20 to excusing Dr. Peseau? He may be excused.
21 MR. WARD: Thank you.
22 (Recess.)
23 COMMISSIONER SMITH: All right, let's go
24 back on the record. I believe we were with Mr. Dahlke.
25
311
CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff
1 CROSS-EXAMINATION
2
3 BY MR. DAHLKE:
4 Q Mr. Lobb, I'd like to ask you a couple of
5 questions about Exhibit No. 103, if you have that there.
6 A Yes.
7 Q Just to review, column 1 as shown on that
8 exhibit, this is the current revenue requirement for
9 Centralia in Avista Corporation's rates; is that correct?
10 A It's an accurate, as accurate an estimate
11 as I could make with the information that I had. It
12 includes power supply expenses from the rate case for
13 sure.
14 Q And in column 2 you're comparing the
15 revenue requirement associated with a run of the power
16 supply model and some firming of secondary purchases?
17 A That's correct. I ran the power supply
18 model, I took the Centralia generation out and the model
19 simply replaces it with purchases and there's some sales
20 reduction and you come up with a new number, new power
21 supply cost number.
22 Q And in column 4, you run another
23 comparison, this is a comparison at a fixed price?
24 A Yes.
25 Q What's the price?
312
CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff
1 A I believe it was the '96 estimate with
2 shaping or the '98 estimate with shaping from the
3 estimate that was provided by Mr. Johnson.
4 Q And in each of those two cases the revenue
5 requirement for the replacement of Centralia is higher
6 than what's currently in rates; is that correct?
7 A That's correct.
8 Q So is it fair to say that this analysis
9 forms the basis for your conclusion that we could proceed
10 with the sale of Centralia without having simultaneously
11 a rate case to completely readjust all of Avista's rates?
12 A Well, again, it wasn't because it was
13 higher or lower. It was because it was unknown and that
14 was the primary reason that I didn't want to a make
15 recommendation. Certainly, the actual revenue
16 requirement going forward is dependent upon what the
17 Company actually does.
18 Q As I understand, your general
19 recommendation is to proceed with the sale of Centralia;
20 is that correct?
21 A Yes.
22 Q And in making that recommendation, I take
23 it you considered both the quantifiable and the
24 non-quantifiable reasons for pursuing the sale?
25 A Yes.
313
CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff
1 Q And would you agree that the -- that in
2 terms of the non-quantifiable reasons that there exists
3 the risk that the future costs of Centralia may actually
4 end up being higher than the estimates that have been
5 included in the base case studies here?
6 A They could be higher.
7 Q There could be additional environmental
8 mitigation required at the site potentially?
9 A Potentially, more or less.
10 Q And there could be other taxes that we
11 currently don't have, such as carbon taxes?
12 A I don't know the answer to that.
13 Q I think you make reference in your
14 testimony to the possibility of a plant closure event at
15 pages 10 and 11. Do you have that there?
16 A What line?
17 Q Twenty-two? I'm sorry. Right, beginning
18 at line 22, and you indicate that Avista seems to believe
19 that the plant would continue to operate should the sale
20 not take place. Isn't it true that there is a
21 possibility of a plant closure event whether or not the
22 sale to TECWA is concluded?
23 A To the extent that TECWA would close it?
24 Q No, not TECWA. I think you indicate that
25 by the purchase of the PGE share of Centralia that Avista
314
CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff
1 has removed the possibility of an early plant closure due
2 to disagreement among the owners.
3 A I guess my point was that it seems unlikely
4 that Avista would make an additional investment in a
5 plant that they truly believe is going to be closed and
6 has a large risk of closure costs and reclamation costs.
7 Q Wouldn't it be equally fair to assume that
8 Avista is simply trying to minimize the risk of plant
9 closure by making the purchase that it's made from
10 Portland General?
11 A The Company has indicated that that is the
12 case. I think they probably -- I would assume that the
13 Company tried to balance the risks.
14 Q I just wanted to understand whether you
15 thought there was no risk out there at all or if you
16 would agree that what the Company is trying to do is to
17 minimize the risks.
18 A I'm sorry, what was the question?
19 Q I was trying to understand from your
20 testimony whether you were indicating that you felt there
21 was no risk of early plant closure or whether you would
22 agree that what the Company is trying to do is to
23 minimize the risks, but that some risks still remain.
24 A I think I would agree that risk remains. I
25 think my point was that it was impossible to quantify.
315
CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff
1 MR. DAHLKE: Thank you. That's all I have.
2 COMMISSIONER SMITH: Thank you.
3 Questions from the Commissioners?
4 Commissioner Hansen.
5 COMMISSIONER HANSEN: I believe I have one.
6
7 EXAMINATION
8
9 BY COMMISSIONER HANSEN:
10 Q Have you not indicated, I guess, earlier in
11 your testimony that you feel that the replacement power,
12 then, could be higher than what is being supplied by
13 Centralia right now currently; is that right?
14 A I think it's possible that the replacement
15 revenue requirement could be higher than the revenue
16 requirement that's included in rates as a result of a '97
17 test year.
18 Q Okay, if the replacement power would be
19 higher, who bears that risk of the cost of that?
20 A The Company would bear that risk.
21 Q And if it was great enough, then do you see
22 them coming in for a rate case, then, based on that?
23 A Depending upon the other cost factors, it's
24 possible.
25 Q But it could be a factor?
316
CSB REPORTING LOBB (Com)
Wilder, Idaho 83676 Staff
1 A Sure.
2 COMMISSIONER HANSEN: Thank you. That's
3 all I have.
4
5 EXAMINATION
6
7 BY COMMISSIONER SMITH:
8 Q Well, my question was essentially the same
9 and I think Mr. Ward attempted it as Commissioner Hansen
10 just did, but your recommendation is based essentially on
11 your view of what's equitable; is that correct?
12 A What's equitable with respect to the total
13 case?
14 Q With respect to the total case for the
15 customers and the Company.
16 A Yes.
17 Q If you looked at it in terms of who should
18 bear the risk, do you think you'd come out differently;
19 in other words, if you leave it in the rate base, it
20 seems to me customers bear the risk because they're
21 paying rates and they have to pay those rates and there's
22 no way to go back and retroactively adjust those rates;
23 whereas, if you take it out, then the Company bears the
24 risk and it goes out and exercises its best judgment and
25 does the best job it can and it comes in either lower or
317
CSB REPORTING LOBB (Com)
Wilder, Idaho 83676 Staff
1 higher and if it's significantly higher, I assume it
2 comes to us and says we need more.
3 A Well, depending upon what your assumption
4 is for the replacement revenue requirement, the customers
5 could end up paying more immediately if it's higher than
6 what rates currently include for Centralia, and I suppose
7 that -- I guess there wouldn't be really any risk there,
8 the customers would simply pay more.
9 Q But they're bearing the risk of that. I
10 mean, that's what I'm saying. I don't know what the
11 future costs are. I assume the Company is going to make
12 its best effort to get the most economically priced and
13 most efficient resources it can for its customers. I
14 assume they're going to make all the best decisions, but
15 my question is who should bear the risk --
16 A Well, I think --
17 Q -- the customers or the Company?
18 A And there's two sides to the equation
19 there, I would think. It seems to me that if you -- I
20 would agree that the Company should bear the risk if
21 costs go up as a result of this sale and to the extent
22 that you change the revenue requirement and immediately
23 lower rates, that would certainly lock in and eliminate
24 the risk that the customers might bear in the future.
25 Q So do you now think we should remove
318
CSB REPORTING LOBB (Com)
Wilder, Idaho 83676 Staff
1 Centralia from rate base?
2 A No, I don't believe we should remove
3 Centralia from rate base because we don't know what the
4 costs are.
5 Q It's always the one question too many.
6 Okay, another topic. It just occurred to me that there
7 are three different changes to a customer's rates that
8 are coming up, maybe not simultaneously, but I'm
9 wondering if they ought to be taken care of in the same
10 time frame, and one is this adjustment to deal with the
11 gain, one is the trigger just triggered on the PCA, and
12 the other is the second phase of the rate increase from
13 the Company's rate case. Do you have any opinion on
14 whether we should try and mesh all that together so
15 customers don't go up and down and wonder why?
16 A I'm not sure of the exact timing of all
17 those. I would certainly recommend that you do it all at
18 once if you can. If a decision can be made on this case
19 and that decision is to lower rates to spread the gain,
20 then I think it would be pretty reasonable to incorporate
21 that with a reduction as a result of a PCA trigger and
22 use those to offset, to the extent it's possible, the
23 increase from the second phase of the rate case.
24 COMMISSIONER SMITH: Well, just food for
25 thought. Thank you.
319
CSB REPORTING LOBB (Com)
Wilder, Idaho 83676 Staff
1 Any redirect, Mr. Woodbury?
2 MR. WOODBURY: No redirect. Staff has no
3 further witnesses.
4 COMMISSIONER SMITH: Thank you, Mr. Lobb.
5 (The witness left the stand.)
6 COMMISSIONER SMITH: Any other matters that
7 the parties wish to bring up before the Commission before
8 we close today's hearing? Any need for those stirring
9 closing arguments? How about briefs? Everyone is
10 silent.
11 Then it seems to me the only thing to do is
12 to declare that the record in this case is now closed and
13 the Commission will undertake its deliberations as
14 speedily as it can and render a decision in due course.
15 Thank you all for your appearances today and your help
16 and your courtesy. We're adjourned.
17 (All exhibits previously marked for
18 identification were admitted into evidence.)
19 (The Hearing adjourned at 3:05 p.m.)
20
21
22
23
24
25
320
CSB REPORTING COLLOQUY
Wilder, Idaho 83676
1 AUTHENTICATION
2
3
4 This is to certify that the foregoing
5 proceedings held in the matter of the application of
6 Avista Corporation for authority to sell its interest in
7 the coal-fired Centralia power plant, commencing at
8 9:30 a.m., on Wednesday, January 19, 2000, at the
9 Commission Hearing Room, 472 West Washington, Boise,
10 Idaho, is a true and correct transcript of said
11 proceedings and the original thereof for the file of the
12 Commission.
13 Accuracy of all prefiled testimony as
14 originally submitted to the Reporter and incorporated
15 herein at the direction of the Commission is the sole
16 responsibility of the submitting parties.
17
18
19
20
CONSTANCE S. BUCY
21 Certified Shorthand Reporter #187
22
23
24
25
321
CSB REPORTING AUTHENTICATION
Wilder, Idaho 83676