20020507Preston Hearing.pdf

1 PRESTON, IDAHO, TUESDAY, MAY 7, 2002, 1:00 P. M.

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4 COMMISSIONER SMITH: Good afternoon, ladies

5 and gentlemen. This is the time and place set for a

6 hearing before the Idaho Public Utilities Commission in

7 Case No. PAC-E-02-1, further identified as in the matter

8 of the application of PacifiCorp dba Utah Power & Light

9 Company for approval of changes to its electric service

10 schedules.

11 We'll start this afternoon with the

12 appearances of the parties. For the Applicant.

13 MR. FELL: My name is James Fell. I'm with

14 the firm of Stoel Rives. I'm counsel for --

15 COMMISSIONER SMITH: Mr. Fell, just one

16 minute. We ask, please, that all cell phones be turned

17 off. We don't have our official sign that we have at the

18 Hearing Room where we put it outside to turn off your

19 cell phones here, but it is disruptive and we'd

20 appreciate it if they were all turned off.

21 Okay, Mr. Fell.

22 MR. FELL: James Fell of the law firm of

23 Stoel Rives for PacifiCorp.

24 COMMISSIONER SMITH: Thank you.

25 Mr. Shurtz.

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1 MR. SHURTZ: Tim Shurtz, pro se with Alva

2 Harris as my legal advisor.

3 COMMISSIONER SMITH: Mr. Harris, you're an

4 attorney?

5 MR. HARRIS: Yes, ma'am.

6 COMMISSIONER SMITH: And you're licensed to

7 practice in Idaho?

8 MR. HARRIS: Yes, in Idaho.

9 COMMISSIONER SMITH: That's good.

10 Mr. Ward.

11 MR. WARD: Conley Ward of the firm Givens

12 Pursley for Nu-West Industries, Inc.

13 COMMISSIONER SMITH: Mr. Budge.

14 MR. BUDGE: Randy Budge, Racine, Olson,

15 Nye, Budge & Bailey, Pocatello, Idaho, for Monsanto

16 Company.

17 COMMISSIONER SMITH: And is Mr. Olsen

18 here?

19 MR. BUDGE: I expect that he's on his way

20 and he got detained in the same construction I did for

21 about a half an hour, so I suspect he'll be late.

22 COMMISSIONER SMITH: All right, we'll await

23 his arrival. For the Staff.

24 MR. WOODBURY: Scott Woodbury, Deputy

25 Attorney General, for Commission Staff.

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1 COMMISSIONER SMITH: Are there any

2 preliminary matters that need to come before the

3 Commission before we begin taking the testimony of the

4 Applicant?

5 MR. WOODBURY: Yes, Madam Chair.

6 COMMISSIONER SMITH: Mr. Ward.

7 MR. WARD: Madam Chair, at an appropriate

8 time I'd like to -- well, first of all, I'd like to note

9 that Nu-West was a late-filed intervenor and so I'm

10 hoping you will grant that intervention today.

11 COMMISSIONER SMITH: Mr. Ward, we can do

12 that right now. If there's no objection, we will grant

13 the intervention of Nu-West in this proceeding, so

14 ordered.

15 MR. WARD: At an appropriate time, I would

16 like to make a brief oral argument basically following

17 the comments that we filed for Nu-West. Hopefully, the

18 Commission received those comments in time to get a look

19 at them.

20 COMMISSIONER SMITH: We have, Mr. Ward, and

21 they're in our files. I think it would be better to have

22 that come after the Company's case if you don't object to

23 that.

24 MR. WARD: That would be fine.

25 COMMISSIONER SMITH: Mr. Woodbury.

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1 MR. WOODBURY: Madam Chair, the other

2 matters to take up, we have a motion from the intervenor

3 Tim Shurtz, a motion for a continuance and although

4 Mr. Shurtz was a party to this case and participated in

5 stipulations and knew of scheduling, he did not make the

6 prefiled deadline and he filed this motion for

7 continuance instead and then subsequently filed pages of

8 comments, I guess, and so it's how the Commission wishes

9 to handle his request for a continuance.

10 COMMISSIONER SMITH: Well, I think

11 Mr. Shurtz is here represented by counsel, so I don't

12 think you need to make his argument, but if your question

13 is are we accepting late-filed comments of Mr. Shurtz,

14 the answer is yes, because he's here today to appear and

15 be cross-examined, so that's how we'll handle it.

16 MR. WOODBURY: Well, I thought your

17 question was are there any other preliminary matters and

18 so I was just bringing that to your attention.

19 COMMISSIONER SMITH: Yes, thank you.

20 MR. WOODBURY: You're welcome.

21 COMMISSIONER SMITH: It appears you have

22 two attorneys, Mr. Shurtz.

23 Are there any other matters? Mr. Fell.

24 MR. FELL: PacifiCorp would propose that we

25 spread on the record the original prefiled testimony and

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1 exhibits filed with the application in support of the

2 relief requested. We think it's important because it

3 provides the background for the stipulation and provides

4 the original request, it relates to the original request

5 for the $38 million recovery.

6 The stipulation is a compromise in that

7 number and to fully understand the stipulation, I think

8 the record is best to contain the original filing, and so

9 what I would do, it's probably best to make a motion, I

10 would move that the Commission spread on the record the

11 direct testimony of Douglas Larson, he did not sponsor

12 exhibits; Stan Watters who sponsors Exhibits 1, 2 and 3;

13 Mark Widmer who sponsors Exhibit 4, 5, 6 and 7; Barry

14 Cunningham who sponsors Exhibits 8 through 13, and I'd

15 like to add for the record that Mr. Cunningham is not

16 here today because he's on business in Toronto, Ontario,

17 Canada, but Joe Goodrich is here and able to answer any

18 questions about that testimony. He's familiar with the

19 testimony and with the people who assisted Mr. Cunningham

20 in preparing it. He's also familiar with the

21 circumstances of the Hunter outage which that testimony

22 addresses.

23 The next is Brian Hedman and he does not

24 have any exhibits; Dave Taylor who sponsors Exhibits 14,

25 15 and 16; and James Zhang, that's Z-h-a-n-g, who

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1 sponsors Exhibits 17, 18 and 19; and then I'll defer

2 until later the testimony of Robert Lively who sponsors

3 the stipulation, but with that, I would move the

4 admission of that testimony and exhibits.

5 COMMISSIONER SMITH: Is there any objection

6 to spreading the prefiled testimony of the witnesses

7 identified by Mr. Fell upon the record as if read in

8 full?

9 MR. WOODBURY: Madam Chairman, I'd like to

10 speak to that motion, if I could.

11 COMMISSIONER SMITH: Mr. Woodbury.

12 MR. WOODBURY: I've had a conversation with

13 Mr. Fell with respect to his proposal to spread that

14 earlier filed testimony and we indicated in our

15 discussion that the purpose of this hearing was one to

16 consider the stipulation that was filed and essentially

17 in going into the stipulation, there was quite a bit of

18 preparation that had we been preparing for a full hearing

19 the Staff would have done and we didn't do, so Staff

20 considers it appropriate perhaps to admit that for the

21 limited purpose of providing the background and the

22 starting point for the Company, but certainly not for the

23 purpose of the truth of the statements contained therein,

24 because Staff has no intention at this point to

25 cross-examine on that earlier filed testimony.

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1 COMMISSIONER SMITH: Any other comments on

2 the motion?

3 MR. BUDGE: I would on behalf of Monsanto

4 join in with Staff. We would certainly have no objection

5 with the understanding, as Mr. Fell has indicated, that

6 the testimony is being presented for the sole purpose of

7 providing background on the case and underlying support

8 for the settlement and as a signatory party to the

9 settlement stipulation, Monsanto also would not

10 contemplate cross-examining any of the witnesses and we

11 would do so based upon the understanding that I think is

12 set forth in paragraph 14 of the stipulation that none of

13 the parties are acknowledging or accepting anything in

14 this case, nor would they be bound upon anything

15 presented in this case in the form of testimony or

16 exhibits or otherwise for purposes of any other

17 proceeding, including the upcoming 16 case that involves

18 Monsanto's specific rate.

19 COMMISSIONER SMITH: Any other comments?

20 (Pause in proceedings.)

21 COMMISSIONER SMITH: All right, I'm going

22 to grant the motion to spread the prefiled testimony upon

23 the record and we will consider it as background for the

24 stipulation. We recognize that the hearing in the

25 proceeding today is to explore the settlement that has

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1 been filed and that agreement in the event the Commission

2 does not adopt the settlement, there would be a further

3 proceeding at which time other parties would prefile

4 their testimony, so that is the understanding that we'll

5 spread this testimony on the record.

6 MR. FELL: Thank you.

7 (The following prefiled testimony of

8 Mr. D. Douglas Larson is spread upon the record.)

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1 Q Please state your name and business

2 address.

3 A My name is D. Douglas Larson. My business

4 address is One Utah Center, Suite 2300, 201 South Main

5 Street, Salt Lake City, Utah, 84140-2300.

6 Qualifications

7 Q What is your current position at PacifiCorp

8 (the Company) and your previous employment history with

9 the Company?

10 A I am Vice President of Regulation. I joined

11 the Company in 1981 in the Financial Accounting

12 Department and have held various accounting and

13 regulatory related positions prior to assuming my current

14 position.

15 Q What are your responsibilities as Vice

16 President of Regulation?

17 A My responsibilities include management of

18 regulatory proceedings for the Company. This would

19 include revenue requirement, cost of service, rate design

20 and all other proposed changes to the Company's retail

21 tariffs. In addition, I have the responsibility for

22 developing regulatory policy on issues that the

23 Commissions must address and making recommendations to

24 management on policy direction.

25 Q What is your educational background?

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1 A I graduated from Brigham Young University

2 in 1982 with a Bachelor of Science Degree in Accounting.

3 In addition to formal education, I have also attended

4 various educational, professional and electric industry

5 related seminars during my career at the Company. I am

6 currently a member of the board of directors of the

7 Intermountain Electric Association, and I am a licensed

8 CPA in the State of Utah.

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PacifiCorp

1 Q What is the purpose of your testimony?

2 A My testimony provides an overview of the

3 Company's proposal to implement the increased Bonneville

4 Power Administration credit for residential and small

5 farm customers, to adjust rates on a revenue neutral

6 basis to bring customer classes closer to their full cost

7 of service and to recover the excess power costs that

8 were deferred from November 1, 2000 through October 31,

9 2001. I also introduce the Company witnesses in this

10 case and briefly discuss the issues they address.

11 Overview of the Company's Proposal

12 Q Please describe the Company's proposal.

13 A Under PacifiCorp's proposal, a surcharge

14 would be added to the customer's bills to recover the

15 $38 million in excess power costs incurred by the Company

16 during the deferral period. This surcharge would last

17 over a two-year period, with the level of the surcharge

18 decreasing for the second year. In addition, the

19 proposal includes adjusting rates by class to bring them

20 closer to the actual cost to serve each class. This

21 aspect of the proposal is necessary since the Company has

22 not adjusted rates to reflect the actual cost of service

23 since the Company's 1990 case (Case No. UPL-E-90-1). The

24 adjustment is a reapportionment of the existing revenues

25 and will not result in an increase in the revenues

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PacifiCorp

1 collected in total. The third aspect of the proposal is

2 an increase in the Bonneville Power Administration credit

3 to the recently settled amount. Finally, the Company is

4 proposing a Rate Mitigation Adjustment. When combined,

5 the result of these four elements of the proposal is that

6 no customer class will receive an increase during the two

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1 amortization period for the power costs and customers

2 that qualify for the BPA credit will see significant

3 decreases.

4 Q Please explain the Rate Mitigation

5 Adjustment.

6 A The Rate Mitigation Adjustment is a pricing

7 mechanism that the Company proposes on a policy basis.

8 This filing consists of several elements that will each

9 have the effect to increase or decrease individual

10 customer's rates. The Rate Mitigation Adjustment assures

11 that when summed together no customer class will receive

12 a rate increase during the two year power cost

13 amortization period and those that qualify for the BPA

14 credit will see a significant decrease.

15 Q Are you saying that rates are frozen for

16 this two-year period?

17 A Not necessarily. The Company continually

18 monitors its earnings level in all jurisdictions. If

19 earnings fall below what the Company believes to be an

20 acceptable level the Company may propose a general rate

21 case to reset base rates.

22 Q Does this proposal increase the Company's

23 base revenue requirement?

24 A No. The Company's base revenue requirement

25 was set during the case in 1990, which implemented a

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PacifiCorp

1 revenue requirement reduction through stipulation. Since

2 then base revenue requirement has been unchanged. This

3 filing recovers extraordinary costs that occurred due to

4 the volatility in the power cost markets over a

5 twelve-month period with a short duration sur-charge.

6 Q The deferral period was only for 12 months.

7 Were there costs outside of the deferral period as well?

8 A Yes. The Company incurred approximately

9 $1 billion of excess power costs over the past 18 months.

10 Of that, $300 million is outside of the deferral period.

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PacifiCorp

1 Q Does the Company plan to recover the

2 $300 million that you mention from customers?

3 A No. Those costs will be borne by the

4 shareholders.

5 Q Are you saying that shareholders have paid

6 for approximately 1/3 of the excess power costs and this

7 proposal is to recover the remaining 2/3 from customers?

8 A Yes.

9 Q On a relative basis, how has PacifiCorp

10 weathered the volatile wholesale power market?

11 A PacifiCorp and its customers have certainly

12 fared better than many other utilities. Mr. Watters'

13 testimony describes PacifiCorp's power supply strategy.

14 This strategy is based upon a broad diversification of

15 markets, supply resources and contract terms. The

16 Company's diversification is designed to both increase

17 opportunities and mitigate risks. The strategy has

18 resulted in solid fundamentals with which to meet future

19 market challenges, including relatively low wholesale

20 market exposure and future benefits to customers based on

21 a reliable, stable resource portfolio.

22 Introduction of Witnesses

23 Q Please list the other Company witnesses and

24 provide a brief description of the subject matter of

25 their testimony.

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PacifiCorp

1 A The Company witnesses in this proceeding

2 will be the following:

3 Stan Watters, who discusses PacifiCorp's power

4 supply strategy.

5 Mark Widmer, who addresses the calculation of the

6 Company's deferred excess net power costs.

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PacifiCorp

1 Barry Cunningham, who will describe the specifics

2 of the Hunter Unit No. 1 outage.

3 Brian Hedman, who will describe the settlement of

4 exchange rights with the Bonneville Power administration

5 and the subsequent determination of the BPA credit.

6 Dave Taylor, who sponsors testimony supporting the

7 rates to reflect the current cost of service study.

8 James Zhang, who sponsors testimony regarding the

9 calculation of the proposed surcharge, the allocation of

10 the surcharge among customer classes, the application of

11 the BPA credit and the calculation of the rate mitigation

12 adjustment.

13 Q Does this conclude your testimony?

14 A Yes.

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16 (The following prefiled testimony of

17 Mr. Stanley Watters is spread upon the record.)

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PacifiCorp

1 Q Please state your name, business address

2 and position with PacifiCorp (the Company).

3 A My name is Stan K. Watters. My business

4 address is 825 NE Multnomah, Portland, Oregon, 97232. My

5 present position is Vice President of Wholesale Energy

6 Services.

7 Qualifications

8 Q Please describe your education and business

9 experience.

10 A I joined the Company in 1982 and I have

11 held various positions in engineering, finance, and

12 wholesale prior to my current position. In my position

13 as Vice President of Wholesale Energy Services, I am

14 responsible for the Company's wholesale sales and trading

15 functions including the economic dispatch of PacifiCorp's

16 system resources. I graduated from Oregon State

17 University in 1981 with a Bachelor of Science in Civil

18 Engineering.

19 Purpose of Testimony

20 Q What is the purpose of your testimony?

21 A My testimony addresses the Company's

22 overall power supply strategy during the deferral period,

23 focusing in particular on the cause of the significantly

24 higher net power costs incurred above the level included

25 in rates and the actions that the Company took to keep

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PacifiCorp

1 net power costs as low as possible.

2 The Company's 2000-2001 Power Supply Strategy

3 Q Would you describe the Company's overall

4 approach in securing the necessary power supply to serve

5 its retail customers?

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PacifiCorp

1 A Yes. During the 2000-2001 period, the

2 Company generally relied upon the market for balancing

3 the system portfolio and supplying incremental

4 requirements. As part of this strategy, PacifiCorp,

5 similar to any load serving utility, uses a complex

6 process that evaluates its load and resource balances

7 well in advance of the scheduled delivery of energy, so

8 that the Company can meet its objectives of reducing

9 risks associated with market price and supply while

10 serving customers safely and efficiently. This process

11 is continually revisited because load and resource

12 balances can and do change frequently due to a variety of

13 factors. Those factors include higher or lower than

14 expected retail loads, changes in market prices, thermal

15 unit outages, weather and hydro conditions.

16 Q Please explain the major causes of the

17 significant increase in net power costs the Company

18 incurred during the deferral period.

19 A The significantly higher net power costs

20 experienced by the Company during the deferral period are

21 primarily attributable to the extraordinary increase in

22 wholesale prices beginning in late spring 2000. This

23 situation was exacerbated by other, unrelated

24 circumstances including (1) the impact of the sale of

25 Centralia, (2) the Hunter 1 failure, (3) abnormally poor

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PacifiCorp

1 hydro conditions, and (4) retail load growth. The

2 Company's losses were further compounded by the impact of

3 FERC's unanticipated rule changes adopted June 19, 2001,

4 and the resulting price decreases in market prices after

5 those FERC rule changes. I will discuss each of these

6 circumstances in my testimony.

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PacifiCorp

1 Extraordinary Increase in Wholesale Prices

2 Q Please describe the extraordinary and

3 volatile price conditions that existed in the wholesale

4 market during the deferral period.

5 A Beginning in late spring 2000, wholesale

6 energy markets changed unexpectedly. Prices and price

7 volatility surged dramatically to unprecedented levels,

8 and the supply became more constrained. For example, the

9 daily on-peak wholesale market price for January 2000 at

10 COB averaged $31.62 per MWh compared to $180.82 per MWh

11 in June 2000, $129.96 per MWh in July 2000 and $213.73

12 per MWh in August 2000. The significant increase in

13 price volatility was evident in the changes in market

14 spreads between peak and off-peak prices. For example,

15 the COB average market spread between peak and off-peak

16 prices changed from $6.62 per MWh in January 2000 at COB

17 to $117.94 per MWh in August 2000.

18 Q Did market price forecasts vary by a large

19 amount from May 2000 through the deferral period?

20 A Yes. As shown on Exhibit No. 1, the

21 variation in market prices was at unprecedented levels,

22 and the prices were substantially higher than our

23 historical experience. Using August 2001 as an example,

24 in late May 2000 the forecasted price for this particular

25 month was $80 per MWh, in April 2001 the forecast price

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PacifiCorp

1 increased to $598 per MWh, and then unexpectedly declined

2 dramatically to $67 per MWh in July 2001.

3 Q How did market prices compare to the level

4 included in rates for short-term purchases?

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PacifiCorp

1 A The average market price of short-term

2 purchased power included in the Company's rates was

3 approximately $21.50 per MWh compared to an average price

4 of approximately $139 per MWh during the deferral period,

5 or approximately 6.5 times the level included in rates.

6 In this environment, the Company's strategy of relying on

7 the market to fill in during the "peaks" of a generally

8 balanced load and resource situation became very costly.

9 The market purchases used to fill in the occasional

10 short-term deficiency in supply were no longer priced at

11 $20-$30 per MWh, but at prices dramatically higher, as I

12 discussed above.

13 Q What were the Company's options for meeting

14 load requirements with the near term implications of

15 these unforeseen price levels and volatility?

16 A Based upon forward price projections

17 available at the time, it appeared likely that market

18 prices would stay higher than historical averages for the

19 foreseeable future. We had two options for meeting near

20 term resource requirements: the Company could buy forward

21 to cover the bulk of resource requirements or leave most

22 of the balancing to the extremely volatile day-ahead and

23 real-time markets.

24 Q How did the Company respond?

25 A The Company rejected reliance on the

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PacifiCorp

1 day-ahead and real-time markets to balance its system,

2 and determined that the inclusion of some forward

3 purchases provided a better balance to meeting load

4 requirements. As the Commission is aware, the failed

5 California deregulation attempt featured reliance on

6 these markets. This approach resulted in the bankruptcy

7 of one major utility, a second major utility teetering on

8 the brink of bankruptcy, and the state of California with

9 an additional

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PacifiCorp

1 $9.0 billion of debt related to energy purchases that it

2 did not expect. The Company did not adopt the California

3 approach, but rather chose to prudently buy resources

4 forward, in support of the load requirements during the

5 deferral period to hedge risk.

6 Q When did the Company begin buying energy to

7 meet load requirements for the deferral period?

8 A The Company began purchasing energy during

9 June 2000 to meet expected energy requirements during the

10 deferral period. At that time the purchases were

11 predominately for the 2001 summer season because the loss

12 of Hunter 1 and the upcoming poor hydro conditions were

13 not known. Provided, as Exhibit No. 2, is a summary of

14 forward purchases executed for June 2001, July 2001 and

15 August 2001 prior to June 18, 2001.

16 Q Does the Company employ a specific process

17 when balancing its system forward?

18 A Yes. The Company continually evaluates its

19 position and requirements so that it buys and sells

20 energy in the most advantageous locations to optimize the

21 Company's system and keep costs as low as possible given

22 the various constraints present in the Company's system

23 and the market at that time. Sales and purchases are

24 entered on a gradual basis because large transactions can

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PacifiCorp

1 significantly higher or lower. In addition, a gradual

2 process utilizes the concept of price averaging, which is

3 beneficial.

4 Q Did the Company undertake additional

5 activities to handle the high price volatility and reduce

6 its exposure to the wholesale market?

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Watters, Di 5a
PacifiCorp

1 A Yes. The Company undertook a series of

2 non-traditional transactions to deal with the unexpected

3 risks the Company was experiencing under the

4 unprecedented conditions occurring in the wholesale

5 energy market. In addition to buying energy forward, the

6 Company entered the following transactions to reduce

7 reliance on the wholesale market.

8 * Purchase of Incremental Generation - the purchase of

9 generation output via bilateral contracts from

10 entities owning generation that was previously

11 off-line.

12 * Purchase of Displaced Generation - the purchase of

13 generation output from entities that either had

14 invoked, or intended to invoke, their option to

15 displace operating generation and take retail

16 service at tariff prices.

17 * Purchase of Operating Reserves - the purchase of

18 load reduction options that qualify as a

19 supplemental reserve pursuant to North American

20 Reliability Council criteria, thus, freeing up

21 additional PacifiCorp generation to serve load.

22 * 10/10 and 20/20 Challenge Programs - the

23 implementation of two customer buyback programs

24 under which residential customers that reduced

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PacifiCorp

1 summer peak levels were rewarded with a 10 percent

2 or 20 percent price reduction on their remaining

3 energy consumption.

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PacifiCorp

1 * Advertising - the implementation of advertising

2 programs in conjunction with the 20/20 and 10/10

3 programs to make customers aware of the high cost

4 of resources and to encourage voluntary

5 conservation.

6 * Gadsby Peakers - the lease of 100 MW of gas

7 peakers at the Company's Gadsby Power Plant from

8 May 15, 2001 through November 15, 2001. The

9 additional generation provided intermediate

10 peaking capacity and reduced the Company's

11 exposure to the forecast high market prices during

12 super peak hours.

13 * Demand Exchange Program - the implementation of a

14 daily demand exchange program whereby qualified

15 retail customers are able to bid in verifiable

16 load reductions.

17 * Continued Conservation - the continuation and

18 expansion of existing conservation programs, such

19 as the Compact Fluorescent Light Program whereby

20 customers are given compact fluorescent lights and

21 educated as to their use.

22 * Load Reduction - securing bilateral agreements

23 with retail customers to curtail load for various

24 time periods.

25 * Incremental Transmission - the acquisition of

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1 incremental transmission rights to improve the

2 Company's ability to delivery power to our

3 customers.

4 Q Did the Company's customers benefit from

5 these transactions?

6 A Yes. Customers benefited from the fact

7 that these programs helped insure supply to meet load

8 requirements. In addition, some customers benefited

9 monetarily

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1 from customer buy-back programs where the savings were

2 shared with customers. For example, customers that had

3 generation were paid the cost of generation plus an

4 amount of the difference between the day-ahead power

5 market and the cost of generation. The cost of

6 generation was based on the heat rate of their unit(s)

7 multiplied by an appropriate gas index used to reflect

8 their fuel cost plus variable O & M on their generation.

9 The Company then shared the difference between this cost

10 of generation and the index price of electricity at an

11 appropriate delivery point into the Company's system.

12 This structure insured that the customer recovered their

13 cost of generation and received a profit on the

14 difference between the day-ahead power market index and

15 the generation cost. All of PacifiCorp's customers

16 received a benefit of power purchases at prices below the

17 day-ahead power market prices.

18 Q Was the Company also facing a supply risk

19 during the deferral period?

20 A Yes. As shown on Exhibit No. 3, there were

21 a significant number of power emergencies declared in

22 California. During 2000 and through the first few months

23 of 2001 parts of California experienced rolling

24 blackouts, which affected hundreds of thousands of

25 customers. Further, there were forecasts that the 2001

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1 summer season would be even worse and that the problem

2 could spread to other parts of the WSCC.

3 Q What did the Company do to reduce the risk

4 that supplies would be inadequate?

5 A The Company's strategy of buying forward

6 and the other innovative transactions the Company entered

7 ensured that customers had adequate power supplies. As a

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1 result, our customers had none of the supply interruption

2 problems encountered by the California utilities.

3 Impact of Other Factors

4 Q Apart from these conditions in the

5 wholesale markets, what other factors contributed to the

6 high power costs during the deferral period?

7 A As I mentioned above, the extraordinary

8 circumstances in the wholesale market were exacerbated by

9 other, unrelated factors including (1) the impact of the

10 sale of Centralia, (2) the Hunter 1 failure, (3)

11 abnormally poor hydro conditions, and (4) retail load

12 growth.

13 Q What was the impact of the Centralia sale?

14 A The Company sold the Centralia plant to

15 TransAlta prior to the run up in wholesale market prices

16 that began in May 2000. The Centralia transaction was

17 approved by this Commission (in Order No. 28296) as well

18 as the other state commissions that regulate the Company.

19 This sale, net of the associated replacement power

20 contract with TransAlta, eliminated approximately

21 1.2 million and 1.4 million MWhs from the Company's

22 long-term resource portfolio in 2000 and 2001,

23 respectively.

24 Q Did the Company indicate in the Centralia

25 proceeding that it would be relying on market purchases

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1 to replace the Centralia output?

2 A Yes. As described in Order No. 28296, the

3 Company indicated that without Centralia, it intended to

4 balance its loads and resources with market purchases.

5 (Under the Company's medium market price forecasts,

6 customers were shown to

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1 be better off if the plant were sold.) This is the

2 strategy the Company pursued, as a majority of the

3 replacement power was purchased from TransAlta, with the

4 balance of the requirement obtained from the general

5 market. There was a recognition at the time of the

6 Centralia sale that the economic analysis associated with

7 the Centralia transaction was sensitive to small changes

8 in critical assumptions. The Commission recognized as

9 well "the vagaries inherent in long-term forecasting,"

10 and agreed with Staffs characterization of the Company's

11 decision to sell "as an exercise of business judgment."

12 (Order No. 28296)

13 Q What was the Hunter 1 failure, and how did

14 that affect the level of power cost deferrals?

15 A On November 24, 2000, the Company

16 experienced a catastrophic outage at its Hunter 1 unit, a

17 430-MW baseload generating station. This outage, which

18 lasted through May 8, 2001, contributed approximately

19 another .3 million and 1.1 million MWh's of short-term

20 purchase requirements in 2000 and 2001, respectively.

21 Q How did hydro conditions affect the level

22 of power cost deferrals?

23 A The 2000-2001 water year, commencing on

24 October 1, 2000, was second worst water year on record.

25 These poor hydro conditions added another .5 million and

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1 2.3 million MWh's of short-term purchase requirements in

2 2000 and 2001, respectively.

3 Q What was the impact of load growth?

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1 A The Company's retail load growth in 2000

2 and 2001 added additional short-term purchasing

3 requirements above the level included in rates. The

4 Company's strategy has always been designed to match

5 loads and resources, thereby minimizing the extent of the

6 Company's exposure to purchases from the wholesale

7 market. As a result of load growth, the Company's

8 resources were needed earlier than expected. Of course,

9 without the significant increase in wholesale market

10 prices, the slight mismatch between projected and

11 realized loads and resources would not have been

12 expensive. Combined with the conditions in the wholesale

13 markets, however, the failure to achieve a precise

14 matching of loads and resources -- an impossible feat

15 under the best of circumstances -- had exaggerated

16 consequences.

17 Q Given these circumstances, how much has the

18 Company relied on the wholesale market to balance its

19 system load requirements?

20 A As Table 1 below shows, the Company

21 generally matched its short-term sales and purchases

22 fairly well prior to 2000. The circumstances described

23 above caused the Company to increase slightly its

24 reliance on short-term purchases in 2000 and 2001. Had

25 these circumstances not occurred, net market purchases

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1 would have been 4.1% in 2000 and the Company would have

2 had a net short-term sales surplus during the first 10

3 months of 2001 of approximately 1.1 percent. Even with

4 all of these impacts, net short-term purchase

5 requirements in 2000 and 2001 represented a fairly

6 small amount about - 6.6 percent and 7.1 percent

7 respectively - of the Company's system requirements.

8 This means that the

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1 Company was not being overly aggressive in the wholesale

2 market and exposing customers to unreasonable market

3 price risk.

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5 Table 1
PacifiCorp 1996-2001
6 Net Short-Term Purchases as a Percentage of System
Requirements
7

8 Year Total System Net Short Term % of System
Load Purchases Requirements
9 (Million MWH) (Million MWH)

10 1996 62.9 0.9 1.4
1997 66.1 1.8 2.7
11 1998 68.3 2.3 3.4
1999 67.5 1.7 2.5
12 2000 68.1 4.5 6.6
20011 52.3 3.7 7.1
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1Through October 2001
14

15 The Impact of FERC's Price Mitigation Measures

16 Q Although you claim that PacifiCorp's

17 customers benefited from purchasing power below the

18 day-ahead power market, wasn't there a risk associated

19 with buying forward?

20 A There is always some risk in

21 forward-looking transactions, because variables can and

22 do change, as I explained above. That is why the Company

23 continually evaluates the options for minimizing risk.

24 In this case, the Company decided that the risk of

25 balancing the system forward coupled with the risk of

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1 falling prices due to various factors was less than the

2 potentially unlimited risk of balancing the system in the

3 extremely volatile day ahead and real time markets.

4 Q Was the Company successful at reducing its

5 exposure to the wholesale market?

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1 A Yes. Based on the Company's load and

2 resource position and the average cost of that position

3 on March 6, 2001, the Company had a mark-to-market value

4 of approximately $700 million associated with its forward

5 purchases for the ensuing year. In other words, had the

6 Company been able to close all of its forward purchases

7 on that date, at the then current forward price curve

8 prices, net power costs would have been approximately

9 $700 million lower than they would have been had the

10 Company not previously engaged in forward purchases.

11 Therefore, the Company had prudently met its objective of

12 reducing market price risk. (Actually closing the

13 Company's position at that time was not an acceptable

14 alternative, however, as it would have defeated the

15 purpose of the forward purchases: the Company would have

16 been exposed to unlimited risk for the energy still

17 expected to be necessary to meet load requirements.)

18 Q Wasn't the risk associated with forward

19 purchases increased by the fact that the Company and

20 numerous other parties had urged FERC to impose wholesale

21 price caps?

22 A It is true that various interested parties

23 and individuals including senators, governors, public

24 utilities and municipalities had requested price caps.

25 Given that the Bush Administration and FERC repeatedly

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PacifiCorp

1 stated that price caps would not be implemented, however,

2 the Company had no reason to believe price caps or other

3 measures would be implemented that would effectively

4 lower prices. For these reasons, the Company prudently

5 acquired resources to limit risk. As a matter of fact,

6 the Company's opinion was only reinforced when the FERC

7 implemented "Soft Caps" in January 2001.

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1 Q Please explain.

2 A When the Soft Caps were implemented they

3 tended to do more damage than good. The price caps did

4 not have a firm dollar limit and were limited to the

5 state of California. Power marketers soon realized that

6 power could be acquired in California under the price

7 caps, moved outside the state, mixed with other power and

8 resold back to California at prices well above the price

9 caps. The failure of the soft caps only reinforced the

10 Company's view that "hard" price caps would not be

11 implemented by FERC.

12 Q Without these price caps, did the Company

13 expect that wholesale market prices would fall in the

14 near future?

15 A No. The Company believed that extremely

16 high wholesale prices would continue until new gas fired

17 resources came on-line to provide adequate supply. With

18 construction lead times in the range of two and three

19 years, depending upon the type of plant built, the

20 Company expected that wholesale prices would not start to

21 decline until at least late spring or summer of 2002.

22 Q Did the Company monitor actions at FERC and

23 other agencies to remain informed about potential changes

24 that could affect prices in the wholesale markets?

25 A Yes. The Company monitored formal

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1 proceeding as well as statements by individual FERC

2 Commissioners in various public forums. The Company's

3 senior management attended a special FERC Western states

4 forum in Boise at which then-FERC Chairman Curt Hebert

5 forcefully reiterated the Commission position against

6 price caps. Company officials met with other key federal

7 energy policy makers throughout the period to gain

8 insight. Based on the information the

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1 Company obtained, we believed there would be no changes

2 forthcoming from the FERC that would materially affect

3 the price of energy in the wholesale market. As a matter

4 of fact, as late as May 26, 2001, Vice President Dick

5 Cheney expressed his strong opposition to any price caps.

6 He stated price caps

7 "are a mistake. Its not a solution; it's adding
to the problem. There isn't anything that can be
8 done short-term to produce more kilowatts this
summer."
9

10 With statements like these, the Company had no

11 expectations that measures would be implemented that

12 would lower prices.

13 Q How did circumstances change when FERC

14 implemented its price mitigation measures?

15 A FERC unexpectedly implemented a new price

16 cap Order effective June 19, 2001. The FERC Order not

17 only placed a cap on market prices, but also

18 fundamentally changed the market place with two other

19 rules that were contained in the Order. First, FERC

20 required generators in California to exclude emission

21 costs from their incremental generation costs. This

22 lowered the fundamental dispatch curve in the WSCC by the

23 level of these emission costs, which at times were

24 approximately $130 per MWh. Second, FERC required each

25 generator in California to offer their power into the

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1 market unless their units were legitimately down for

2 maintenance. Generators could no longer withhold

3 generation from the market in order to keep prices high.

4 These two unexpected changes significantly lowered the

5 price of power in the WSCC.

6 Q Did the Company anticipate the FERC Order?

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1 A No. As I explained earlier, there was no

2 reason to expect the implementation of measures that

3 would materially lower prices. And the market did not

4 anticipate the change in market fundamentals. Prior to

5 the FERC rule changes and the fundamental changes in the

6 market, the Company continued to believe that FERC would

7 not implement changes that would significantly alter the

8 market price of energy. Accordingly, the 2001 summer was

9 expected to be robust from an energy use perspective. As

10 shown on Exhibit No. 1, at the end of May 2001 the market

11 forecast August 2001 prices to be $391 per MWh.

12 Q Please explain the causes of the

13 significant increase in net power costs during the period

14 following the FERC Order.

15 A The primary cause was the sudden and

16 unforeseen drop in wholesale market prices which was

17 precipitated by lower than expected retail loads, lower

18 gas prices and the unexpected rule changes adopted in

19 concert with the FERC Order that was implemented on

20 June 19, 2001. Unfortunately, the Company had hedged

21 against potential market price risk at prices much higher

22 than the historical norm, but less than the then current

23 forward price curve, to cover the usually high resource

24 requirements of the summer peak period, plus the impact

25 of the second worst water year on record. To make

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PacifiCorp

1 matters worse, loads were less than expected because of a

2 cooler summer, customer conservation and a slowing

3 economy. Market prices were driven still lower in part

4 because of lower than expected gas prices. As a result,

5 the once extremely valuable long shoulder period

6 position, which had previously been created through the

7 Company's forward purchases, was now a liability, because

8 the average price of the long

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1 shoulder period position was now substantially above then

2 existing wholesale market prices.

3 Q What do you mean by "shoulder position"?

4 A Sometimes we enter into near-term contracts

5 knowing that some of the power that will be delivered

6 under them is surplus to our needs. There are "standard"

7 products in the market, for example a "Heavy Load Hour"

8 product that provides a "6 x 16" block of deliveries

9 (16 hours per day for six days). To the extent we do not

10 purchase "standard" forward products, we are forced to

11 rely more on hourly purchases at unpredictable prices.

12 Therefore we may purchase a "Heavy Load Hour" product as

13 the most economical and lowest-risk means of meeting our

14 "super-peak" needs during eight hours each day of an

15 upcoming six-day period, with the expectation that we

16 will sell surplus energy in hourly markets for the eight

17 "shoulder" hours of each of those days. At other times,

18 we enter into term contracts and expected load does not

19 materialize, requiring us to sell surplus energy into

20 near-term markets.

21 Q Why didn't the Company close some of its

22 surplus shoulder positions prior to the FERC rule

23 changes?

24 A There are two primary reasons. First, as I

25 previously mentioned, the Company had no reason to

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PacifiCorp

1 believe FERC would implement effective measures that

2 would materially lower the market price of energy.

3 Second, the Company could not have closed any of the long

4 shoulder period positions before market prices dropped

5 without increasing market price and supply risk during

6 the extremely volatile super-peak period, because the

7 forward market only trades standard

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1 products such as 6x16, 5x16 and 7x24 products. Trading

2 standard products to reduce the long shoulder position

3 would have resulted in the Company being further short

4 during the super-peak period and therefore exposed to

5 more risk.

6 Q Did other parties buy forward at prices

7 that are now significantly above market?

8 A Yes. The State of California for one,

9 through the California Department of Water Resources,

10 bought a significant amount of energy many years into the

11 future at prices that are now quite a bit above market.

12 In addition, several other utilities have requests before

13 various commissions seeking recovery of significantly

14 higher net power costs. The Company's request is thus

15 not an isolated request that should be viewed with

16 skepticism; rather, it is a somewhat common, yet

17 unfortunate, problem that faces many utilities in the

18 WSCC.

19 Q Why is it appropriate for the Company to

20 recover the costs of these forward purchases under such

21 circumstances?

22 A Utilities were generally encouraged during

23 the period prior to the June 19 FERC Order to engage in

24 such forward purchases to reduce reliance on spot or

25 short-term markets and instead increase reliance on term

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PacifiCorp

1 products. Having engaged in these actions, the Company

2 should have an opportunity to recover the costs we

3 incurred. The Washington Utilities and Transportation

4 Commission ("WUTC"), for its part, has commented to FERC

5 that it would be unfair to penalize utilities, such as

6 PacifiCorp, that prudently purchased in the forward

7 market prior to the FERC Order. In comments filed with

8 FERC on August 17, 2001, the WUTC stated:

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1 It is fundamentally unfair to preclude
load-serving entities from the opportunity to
2 recover in wholesale markets the cost of term
products they purchased pursuant to load-service
3 obligations incurred in those markets prior to the
Commission's action to implement price mitigation.
4 Load-serving utilities are fundamentally different
from marketers because they do not have the choice
5 to enter the market they must obtain the power to
serve their statutory obligations. Between
6 December 15, [2000] and June 19, 2001, the
Commission admonished purchasers in the wholesale
7 power market to reduce reliance on spot or
short-term markets and increase reliance on term
8 products. To ignore now the consequences of costs
incurred by utilities that followed that advice
9 would be to punish those that heeded the
Commission's directives and, perversely, would
10 benefit those that did not.

11 (WUTC Comments, p. 12) For the same reasons, we believe

12 we should be provided an opportunity to recover the costs

13 of these forward purchases.

14 Conclusion

15 Q Please summarize why the Company's deferred

16 power costs should be recovered in rates.

17 A The Company reasonably responded to the

18 extraordinary and volatile conditions in the wholesale

19 electricity markets in the western United States since

20 May 2000 by engaging in forward purchases to minimize

21 availability and price risks to customers. As described

22 in my testimony above, the level of deferral in this

23 proceeding arises from a number of factors beyond the

24 Company's control, including the impact of extraordinary

25 and unprecedented high prices and volatility in the

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PacifiCorp

1 wholesale markets, the Hunter 1 outage, the second worst

2 water year on record and the consequences of actions

3 outside the Company's control - such as the FERC Order

4 and rule changes - on the Company's forward power

5 purchases. Moreover, it would be punitive and unfair to

6 penalize the Company for events beyond the Company's

7 control - primarily FERC's June 19, 2001 Order imposing

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1 price caps and new rules - when the strategy followed by

2 the Company to balance its system was prudent based on

3 then-existing circumstances and expected future

4 conditions at the time. Had these unusual and unexpected

5 events not occurred, net power costs would have been

6 substantially lower than the level incurred.

7 Q Does this conclude your direct testimony?

8 A Yes.

9

10 (The following prefiled testimony of

11 Mr. Mark Widmer is spread upon the record.)

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Watters, Di 20
PacifiCorp

1 Q Please state your name, business address

2 and present position with PacifiCorp (the Company).

3 A My name is Mark Widmer, my business address

4 is 825 N.E. Multnomah, Suite 800, Portland, Oregon 97232,

5 and my present position is Manager, Regulation.

6 Qualifications

7 Q Briefly describe your education and

8 business experience.

9 A I received an undergraduate degree in

10 Business Administration from Oregon State University. I

11 have worked for PacifiCorp since 1980 and have held

12 various positions in the power supply and regulatory

13 areas. I was promoted to my present position March 2001.

14 Q Please describe your current duties.

15 A I am responsible for the coordination and

16 preparation of net power cost and related analyses used

17 in retail price filings. In addition, I represent the

18 Company on power resource and other various issues with

19 intervenor and regulatory groups associated with the six

20 state regulatory commissions to whose jurisdiction we are

21 subject.

22 Purpose of Testimony

23 Q What is the purpose of your testimony?

24 A I will describe the Company's Power Cost

25 Adjustment (PCA) and present the results of the

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Widmer, Di 1
PacifiCorp

1 adjustment from November 1, 2000 through October 31,

2 2001, that the Company seeks to recover from customers

3 through this filing.

4 Power Cost Adjustment Mechanism

5 Q Please describe the Power Cost Adjustment.

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Widmer, Di 1a
PacifiCorp

1 A The Power Cost Adjustment (PCA) is

2 determined on a monthly basis and is equal to the Actual

3 Net Power Cost in dollars per MWh (ANPC) less the Base

4 Net Power Cost in dollars per MWh (BNPC) multiplied by

5 the Idaho load deemed in rates.

6 Q Please explain how the BNPC is determined.

7 A BNPC is intended to represent the level of

8 power costs currently reflected in rates, which is

9 somewhat difficult to determine inasmuch as the last rate

10 case in Idaho in which the Company's net power costs were

11 addressed was prior to the Utah Power/Pacific Power

12 merger. For this reason and based on conversations with

13 the Idaho Staff, it was decided that the last audited net

14 power cost study for a semi-annual filing would be

15 appropriate for use in the deferral calculations. The

16 last audited net power cost study is for the 12-months

17 ended December 31, 1998, and included a Type III study,

18 which incorporated known and measurable changes through

19 December 31, 1999. The BNPC is equal to the monthly net

20 power cost, which consists of purchased power, wheeling

21 and fuel expenses less special sales revenue, divided by

22 the monthly net system load in rates. Exhibit No. 4

23 shows the components and calculation of the BNPC.

24 Q How is the monthly ANPC calculated?

25 A The ANPC is calculated based on the

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PacifiCorp

1 Company's actual monthly net power cost adjusted to

2 exclude energy exchange contracts that only have nominal

3 dollar values for accounting purposes. The resulting

4 adjusted actual monthly net power cost is then divided by

5 the actual monthly net system load to arrive at the ANPC.

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Widmer, Di 2a
PacifiCorp

1 Q Have you prepared exhibits that detail the

2 calculation of ANPC for the deferral period?

3 A Yes. Exhibits No. 5 and 6 show the actual

4 monthly net power costs for November 2000 to December

5 2000, and the first 10 months of 2001, respectively.

6 Q Please explain Exhibit No. 7.

7 A Exhibit No. 7 shows the determination of

8 the monthly power cost adjustment for the period of

9 November 1, 2000 through October 31, 2001. The amount of

10 the power cost adjustment is calculated as the product of

11 Idaho load deemed in rates multiplied by the difference

12 between ANPC and BNPC. The cumulative balance of the

13 power cost adjustment for the period is $37,381,713,

14 prior to inclusion of carrying charges.

15 Q How is the Company accounting for the costs

16 referenced in your testimony and in Exhibit No. 7?

17 A Pursuant to the Idaho Commission's approval

18 of the Company's deferred accounting request, the monthly

19 values of the PCA are credited to Account 557, thereby

20 decreasing the recorded power supply expenses, and

21 debiting Account 182.3. Deferred income taxes are

22 recorded by debiting Account 410.10, and crediting

23 Account 283. The amortization of the balance in Account

24 182.3 would be accomplished by crediting Account 182.3

25 and debiting Account 557. Deferred income taxes would be

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PacifiCorp

1 amortized by debiting Account 283 and crediting Account

2 411.10.

3 Q Is the Company proposing to accrue carrying

4 charges on its accrued excess net power costs?

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PacifiCorp

1 A Yes. The Commission order granting the

2 Company's request to defer excess net power costs allowed

3 the Company to request carrying charges "in a future

4 case." The Company is therefore requesting as part of

5 this filing that it be allowed to accrue carrying charges

6 on its deferred net power costs at the 6.0 percent

7 interest rate it pays for customer deposits. The Company

8 believes this request is reasonable because it prudently

9 acquired resources for the benefit of its customers at a

10 significant cost, which to this time have been borne by

11 the Company's shareholders. This proposed treatment is

12 consistent with the Commission's actions for both Idaho

13 Power and Avista, which have deferral accounts on which

14 they are allowed to collect interest at the same rate

15 paid by the utility on customer deposits (6 percent).

16

17 PCA Deferrals November 30, 2000 through October 31, 2001

18 Q What is the amount of PCA deferrals for

19 which the Company is seeking recovery in this proceeding?

20 A As shown on Row 70 of Exhibit No. 7, the

21 Company's cumulative deferral balance, including carrying

22 charges, is $38,279,851. This covers the period November

23 30, 2000 through October 31, 2001.

24 Q Does this conclude your direct testimony?

25 A Yes.

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PacifiCorp

1 (The following prefiled testimony of

2 Mr. Barry Cunningham is spread upon the record.)

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CSB REPORTING COLLOQUY
Wilder, Idaho 83676

1 Q Please state your name, occupation, and

2 business address.

3 A My name is Barry G. Cunningham. My

4 business address is 201 South Main, Suite 2300, One Utah

5 Center, Salt Lake City, Utah. My position is Vice

6 President of Generation for PacifiCorp.

7 Qualifications

8 Q Please describe your education and business

9 experience.

10 A I have a Bachelor of Arts degree in

11 Physical Science. During my career with PacifiCorp, I

12 have served as a Trainer, Training Manager, Assistant

13 Operations Superintendent, a Maintenance Superintendent,

14 a Plant Manager and the Director of Technical Support

15 with responsibility for all the small plants. I became

16 Assistant VP of Generation in 1998 and VP of Generation

17 in 1999 with responsibility for all thermal and hydro

18 generation assets.

19 Purpose of Testimony

20 Q What is the purpose of your testimony?

21 A I will describe the Hunter Unit Number 1

22 ("Unit 1") generator outage that occurred on November 24,

23 2000 and the circumstances leading up to the outage. In

24 addition, I will describe what PacifiCorp has been able

25 to determine about the cause of the generator outage.

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Cunningham, Di 1
PacifiCorp

1 Description of Unit and Generator

2 Q Please describe Unit 1.

3 A Hunter Plant is a three-unit coal fired

4 steam-electric plant located three miles south of Castle

5 Dale, Utah. Construction of Unit 1 began in March 1975,

6 and commercial operation began June 1, 1978.

7 Stearns-Roger, an engineering

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1 company that was located in Denver, Colorado, designed

2 Unit 1. Jelco, a Utah based construction company,

3 constructed the unit. The official net output rating for

4 Unit 1 is 430 megawatts.

5 Q Please describe the ownership of Unit 1.

6 A PacifiCorp operates the Hunter plant.

7 PacifiCorp and Utah Municipal Power Agency jointly own

8 Unit 1 with ownership interests of 93.75 percent and 6.25

9 percent respectively.

10 Q Please describe the operation of Unit 1.

11 A The owners use Hunter Unit 1 for base load.

12 Q Please describe the Unit 1 electric

13 generator.

14 A The generator was manufactured by

15 Westinghouse Electric Corporation ("Westinghouse"), now

16 part of Siemens Westinghouse Power Corporation ("Siemens

17 Westinghouse"). The generator is a two pole, hydrogen

18 inner-cooled machine rated at 496 megavolt-amperes

19 ("MVA"). The output voltage of the generator is 24,000

20 Volts. The frame size is 2-104 x 225. Westinghouse has

21 manufactured generators of the same basic design and

22 construction for over 30 years. Twenty-eight generators

23 of this same frame size were built and are in service in

24 the United States and Spain.

25 Q Please describe the general arrangement and

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1 construction of the generator.

2 A Exhibit No. 8 shows the arrangement of the

3 generator equipment. The generator, exciter, and

4 permanent magnet generator ("PMG") are each a rotating

5 electrical machine with their shafts coupled end to end.

6 The steam turbine drives the generator, the exciter, and

7 the PMG.

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1 The generator consists of the following major components:

2 * Frame and bearing brackets

3 * Stator with armature winding

4 * Rotor with field winding

5 * Cooling system

6 * Exciter, PMG and voltage regulator.

7 Exhibit No. 9 illustrates the major components of

8 the generator. The frame is fabricated from welded steel

9 plate and forms the shell of the generator. The frame is

10 designed as a pressure vessel that contains the hydrogen

11 gas that is used to cool the generator. Two heat

12 exchangers called hydrogen coolers are mounted inside the

13 generator frame on the turbine end. These heat

14 exchangers cool the hydrogen that is circulated through

15 the generator when it is in operation. Bearing brackets

16 enclose each end of the generator. These brackets carry

17 the generator bearings and their associated hydrogen

18 seals. The hydrogen seals prevent hydrogen gas from

19 leaking out around the shaft. The generator frame weighs

20 approximately 100 tons.

21 The stator core is constructed inside the

22 generator frame. The core has the shape of a large

23 hollow cylinder that is 104 inches in diameter and is 225

24 inches long. A cylindrical cage made from building bolts

25 and bore rings is installed inside the stator frame. The

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1 stator core is fitted inside this cage of building bolts.

2 The core consists of many layers or laminations of sheet

3 steel. Each lamination of steel is 0.018 inch thick and

4 is coated on each side with a thin layer of varnish-like

5 insulating material. Each layer or lamination consists

6 of nine segments that

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1 each clip on to the building bolts. Exhibit No. 10 shows

2 the Unit 1 core being constructed. The laminations are

3 arranged in 3-inch thick packs. Exhibit No. 11 shows the

4 arrangement of the stator laminations and winding

5 installation. In between each pack is a ventilation

6 space 0.125 inches wide through which hydrogen cooling

7 gas flows. Each end of the core is finished with a system

8 of finger plates, end plate and core support plates.

9 Through bolts are inserted through the laminations,

10 finger plates, end plate and core support plates. The

11 through bolts and building bolts clamp the core together

12 axially. The bore rings that surround the core are also

13 tightened to clamp the core radially. A small ring of

14 laminations called a flux shield is installed on each end

15 of the core to help direct the magnetic fields in the

16 generator. The stator windings (coils), in which

17 electricity flows, are installed in slots in the bore of

18 the stacked stator body. Each winding is held securely

19 in its stator slot with a system of filler strips, ripple

20 springs and wedges.

21 The generator rotor, which is a long solid

22 cylindrical steel forging, contains the field winding.

23 It rotates inside the bore of the stator. Exhibit No. 12

24 shows a typical generator rotor. The rotor weighs

25 approximately 60 tons and is supported by the bearings on

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1 each end of the generator. The bearing on the turbine

2 end is No. 5 bearing and the bearing on the exciter end

3 is No. 6 bearing. The field winding is contained in slots

4 that are machined into the rotor. The rotor has a

5 multi-stage blower mounted on the turbine end that

6 circulates the hydrogen cooling gas through the generator

7 and the hydrogen coolers. Hydrogen cooling gas flows in

8 parallel through the windings, the stator core, and the

9 rotor. The

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1 hydrogen carries heat away from these components and

2 passes through the rotor blower to the hydrogen coolers

3 where it is cooled again.

4 The purpose of the exciter is to provide electric

5 energy to the field winding of the generator rotor.

6 Exhibit No. 8 illustrates how the PMG, exciter, generator

7 and voltage regulator are interconnected. The PMG

8 produces electrical energy that supplies the voltage

9 regulator. The voltage regulator output energizes the

10 field winding of the exciter. The exciter output then

11 energizes the field winding of the generator. The

12 voltage regulator controls the main generator voltage

13 level by regulating the input to the exciter field

14 winding.

15 Description of Incident

16 Q Please describe the condition of the plant

17 at the time of the incident.

18 A The incident occurred during the day shift

19 of Friday, November 24, 2 000, the day following the

20 Thanksgiving holiday. All three Hunter generating units

21 were operating near full load. Operating conditions in

22 the plant were normal. Transmission system conditions

23 were also normal. The Unit 1 generator net output was

24 approximately 415 megawatts.

25 Q Please describe the incident.

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1 A The first indication of abnormal conditions

2 was at 12:38:53 when the Number 5 bearing alarmed with a

3 temperature indication of -262.6F, which is impossibly

4 low. Exhibit No. 8 shows a diagram of the bearing

5 arrangement. This alarm continued to clear and re-occur

6 during the event. The alarm would clear and indicate a

7 normal bearing temperature. The alarm would then

8 re-occur and indicate bearing temperature at -262.6F.

9 About 40 seconds after the first

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1 temperature alarm, the Number 6 bearing vibration alarm

2 annunciated at a value of 5.29 mils displacement. The

3 bearing alarms when vibration exceeds 5.0 mils. The

4 Control Room Operator ("CRO") sent the Plant Operator

5 ("PO") out to visually inspect the generator for any

6 problems. The CRO verified that bearing drain

7 temperatures were normal. In parallel with the PO's

8 inspection, the shift supervisor and CRO began reviewing

9 potential causes of high vibration. They checked the

10 "Water Induction" displays and the "Bearing Oil Drain

11 Temperature" display. During this period of time, a

12 generator winding cooling gas differential temperature

13 alarm annunciated and then returned to normal. The PO

14 returned to report that vibration was perceptibly more

15 than normal and that sparks could be seen at the joints

16 of the generator frame and cowling and that heavy arcing

17 was occurring around the ground straps near Number 5

18 bearing. During this exchange of information, the unit

19 tripped automatically due to operation of the Loss of

20 Field relay. The elapsed time of the event from first

21 alarm until trip was about 5 minutes. The turbine

22 generator then coasted down to turning gear speed in

23 approximately 45 minutes.

24 Immediate Response and Damage to the Generator

25 Q Please describe the immediate response

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1 taken by PacifiCorp personnel.

2 A Plant personnel immediately initiated

3 emergency procedures, and began damage control and then

4 proceeded with an initial inspection and event

5 assessment. Arcing had created a hole in an exciter

6 bearing oil pipe allowing oil to leak. The oil was

7 running down into the voltage regulator cabinets on the

8 level below the generator exciter. Immediate action was

9 taken to control the oil leak and to

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1 protect the voltage regulator controls from the oil.

2 Plant management personnel were contacted and traveled

3 immediately to the site. The PacifiCorp staff engineer

4 responsible for generators was contacted and arrived on

5 site Saturday, November 25, 2000. Siemens Westinghouse

6 was contacted on Friday, November 24, 2000. Saturday

7 morning, a Siemens Westinghouse service engineer made

8 arrangements for a tool trailer to be delivered to the

9 site and then traveled to the site to assist in the

10 inspection and disassembly of the generator. I was

11 contacted on Friday afternoon and again Saturday morning.

12 I traveled to the site on Saturday to participate in the

13 initial inspections.

14 Q Please describe the initial assessment of

15 the damage.

16 A First indications of failure were in the

17 exciter housing where it could be observed that the PMG

18 that supplies energy to the voltage regulator was

19 damaged. Bearing vibration sensor wiring was burned off

20 the number 7 exciter bearing. Areas of sparking/arcing

21 were noted on many external locations on the generator.

22 After the initial inspections, it was determined

23 that an internal inspection of the generator was

24 necessary. The generator was purged of hydrogen late on

25 Friday, November 24th and into the morning of the 25th.

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1 PacifiCorp personnel removed inspection covers to begin

2 inspection while the turbine-generator was on turning

3 gear. A solidified mass of previously molten metal was

4 observed in the exciter end of the generator.

5 Arrangements were made for Fluor to provide millwrights

6 to continue disassembly work on Sunday morning. Fluor is

7 a maintenance company that has a contract to supply

8 supervision and maintenance workforce to the Hunter

9 Plant. Hydrogen coolers and bearing brackets were

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1 removed on Sunday. Around the clock teardown began with

2 Sunday dayshift. Electrical insulation testing by

3 Siemens Westinghouse and PacifiCorp showed no problems in

4 the field winding or stator windings. The upper half of

5 the bearing brackets on both ends of the machine was

6 removed. At this point, it was clear that major damage

7 had occurred in the generator. Initial inspections noted

8 solidified masses of molten metal hanging off winding end

9 turns on each end of the core. Based on these

10 observations work continued to remove the rotor. Arcing

11 damage was noted in several areas as parts were removed

12 from the generator. The PMG sustained major damage due

13 to arcing across the air gap between the PMG rotor and

14 the PMG stator magnets. The number 4 turbine bearing and

15 journal sustained damage due to sparking/arcing within

16 the bearing. The carbon brush and copper braid used to

17 ground the turbine generator shaft between the

18 low-pressure turbine and generator were burned off.

19 Q When was the decision made to completely

20 rebuild the core?

21 A The molten iron in each end of the

22 generator indicated damage to the core. The outside

23 circumference of the core visible through inspection

24 covers showed no visible damage. Since the windings had

25 not failed, our initial belief was that core damage could

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1 be limited to the ends of the generator and repair might

2 be possible by restacking only the ends of the core with

3 the generator on its foundation. Siemens Westinghouse

4 winders, specialists in rebuilding generators, began

5 arriving on site on Monday, November 27. The rotor was

6 removed by late the next day. Removal of the windings

7 began on November 29. As the windings were removed from

8 the core, it became obvious that the damage to the core

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1 extended the entire length of the generator stator core

2 (225 inches) and consequently, the total stator core

3 would need to be completely rebuilt. The winding removal

4 was completed on December 7, 2000. Fluor millwrights and

5 Siemens Westinghouse winders working under the

6 supervision of Siemens Westinghouse service engineers

7 worked around the clock to remove stator core iron. The

8 old core iron was removed from the frame by December 20,

9 2000.

10 Q Please describe the overall damage

11 sustained by the turbine-generator.

12 A The stator windings and core sustained the

13 majority of the damage. The initial insulation test of

14 the windings, performed with a low voltage, did not

15 indicate a problem. However, the windings did fail when

16 a direct current high potential test placed the windings

17 under more electrical stress. The insulation had most

18 likely been weakened by heat where it was in contact with

19 the molten iron. The winding insulation was visibly

20 discolored and damaged in the areas where it was in

21 contact with the molten iron. The core melted in three

22 separate areas. Exhibit No. 13 shows the areas of

23 damage:

24 * Below stator slot 21, a tunnel like hole was melted

25 through the core iron from one end of the generator to

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1 the other end. The hole was like a small cavern that

2 varied in size from 1 inches to 5 inches in diameter.

3 The total length was about 225 inches. Molten iron

4 from this cavern spilled out each end of the core and

5 flowed down across the windings into the end of the

6 generator. The cavern enveloped a portion of the

7 through bolt hole. Approximately 4 feet of the

8 high-strength, core clamping through bolt was melted

9 away below

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1 slot 21, close to the exciter end of the

2 generator. The cavern also enveloped a corner of slot

3 21 for part of the length of the generator.

4 * Below stator slot 10, approximately 4 feet of the

5 exciter end of the through bolt was melted. The core

6 surrounding the melted portion of the through bolt

7 also began to melt. The melted core was concentric

8 with the through bolt hole.

9 * A tunnel like hole enveloping the corner of slot 27 on

10 the exciter end was melted for a length of

11 approximately 2 feet.

12 In addition to this major damage to the core iron, the

13 exciter end flux shield showed signs of heating damage.

14 Some melting had also occurred on the turbine end flux

15 shield at through bolt number 10. Other core components

16 such as core support plates, finger plates, and end

17 plates were damaged by the molten core iron.

18 In addition to the stator core, damage was sustained in

19 the following areas:

20 * Damage to the turbine was limited to the number 4

21 bearing and journal. The bearing was damaged by

22 extremely high shaft current that flowed from the

23 generator rotor through the bearing as the generator

24 failed. The steam turbine was inspected using fiber

25 optic equipment that was inserted into the turbine

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1 through quick look inspection ports that were

2 installed during the 1999 overhaul. No damage was

3 observed during the inspection.

4 * Damage to the voltage regulator was limited to that

5 caused by lubricating oil from the exciter bearing oil

6 leak. A number of components required disassembly and

7 clean up.

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1 * The PMG that supplies electric energy to the voltage

2 regulator sustained significant damage. Stray

3 currents arcing across the air gap in the PMG damaged

4 the permanent magnets and destroyed the stator iron.

5 * The vibration sensor and associated electrical wiring

6 were burned off the exciter bearing. A hole was

7 burned in the lube oil piping to the exciter.

8 * As the core failed, the hydrogen cooling gas that is

9 circulated at high velocities through the generator

10 scattered small pellets of molten core iron throughout

11 the generator. Both hydrogen coolers had a

12 significant amount of core iron material imbedded

13 between cooling fins.

14 Repair Options

15 Q Describe what action was taken to initiate

16 repairs.

17 A Repair program project teams were assigned

18 on Tuesday, November 28. A technical lead person was

19 assigned to oversee and coordinate the on-site

20 disassembly of the generator. Another technical lead

21 person was assigned to oversee off-site work. This person

22 was dispatched to the Siemens Westinghouse Orlando,

23 Florida, office to work with Siemens Westinghouse staff

24 on repair options, material availability, and possible

25 full stator replacements. This effort continued through

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1 the weekend and into the week of December 4. Alstom and

2 GE, both major manufacturers of large utility generators,

3 were also contacted to solicit proposals for repairs.

4 Q Please describe the actions taken to

5 consider alternative options.

6 A A search for possible replacement units was

7 conducted in parallel with the generator repair planning.

8 PacifiCorp identified generators within the U.S. that

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1 potentially matched the Hunter Unit 1 generator and that

2 could possibly be brokered for a swap. Siemens

3 Westinghouse reviewed the interchangeability of the

4 identified units with Hunter Unit 1. PacifiCorp

5 contacted the owners. Three possibilities emerged:

6 * On December 4, PacifiCorp management contacted Reliant

7 Energy about the feasibility of using the generator

8 from Green Bayou Unit Number 5.

9 * On December 4, PacifiCorp management contacted Excelon

10 about the feasibility of using a generator from one of

11 the Eddystone Station units.

12 * PacifiCorp management also contacted City of San

13 Antonio to discuss the feasibility of acquiring a

14 spare stator that had been manufactured by Alstom to

15 fit a matching Westinghouse generator at the JT Deely

16 Station in San Antonio, Texas. The JT Deely unit was

17 scheduled to continue operating in a derated output

18 mode until Spring 2001 when the new Alstom stator core

19 and winding would be installed.

20 The Eddystone and JT Deely options were explored in

21 detail. Reliant Energy management did not want to

22 consider participating in a swap. A team of PacifiCorp

23 personnel were dispatched to San Antonio and then to

24 Philadelphia to negotiate the potential options.

25 Q Please describe the details of the San

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1 Antonio option.

2 A The San Antonio option consisted of

3 acquiring a new stator that was built for the Deely

4 Station. The general elements of this option are as

5 follows:

6 * PacifiCorp would buy the Alstom generator stator

7 from San Antonio.

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1 * PacifiCorp would pay the city for replacement

2 energy during the period of construction of the

3 replacement Alstom stator, a period estimated to

4 be 14 months. This payment would cover the derate

5 of the operating Deely unit.

6 * PacifiCorp would purchase a replacement stator

7 from Alstom for the JT Deely station.

8 * PacifiCorp would pay Alstom to ship the Deely

9 generator stator to the Hunter Plant and to

10 install the stator on Unit 1.

11 * PacifiCorp would also pay for replacement energy

12 if the JT Deely unit's existing stator failed

13 during the period required to construct the

14 replacement stator.

15 Q Please describe the details of the Excelon

16 Eddystone option.

17 A The Eddystone option consisted of acquiring

18 an existing operating generator from Excelon Eddystone

19 Station, Philadelphia, Pennsylvania.

20 * PacifiCorp would purchase the Eddystone Station

21 Unit 3 generator stator.

22 * Westinghouse would remove the Eddystone generator

23 stator, ship the stator to the Hunter Plant and

24 install in Unit 1.

25 * Westinghouse would ship the Unit 1 generator

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1 stator frame to the Eddystone station, install new

2 core and windings, and install the rebuilt

3 generator stator on Eddystone Unit 3.

4 * For each day that Eddystone Unit 3 was not

5 available after April 15, PacifiCorp would buy, at

6 market prices, the quantity of energy that the

7 unit historically had produced and would sell that

8 energy to Excelon at the cost of producing the

9 energy at Eddystone.

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1 This option required transporting the generator stator

2 with windings approximately 3,700 miles by water and

3 rail. The stator weighs approximately 235 tons. The

4 physical size and weight of the stator prohibited moving

5 the stator along rail corridors in the eastern U.S. The

6 transportation plan for moving the Eddystone stator to

7 the Hunter Plant consisted of transport by barge from

8 Philadelphia to Houston and by rail from Houston to Price

9 and by truck from Price to Hunter Plant. The stator was

10 four years older than the stator that failed at Hunter

11 Plant. Also, the stator winding end turn support system

12 did not have the upgrades that had been installed

13 previously on Hunter Unit 1 generator. The Eddystone

14 unit had been used in a peaking mode with over one

15 hundred and fifty start-ups per year giving rise to

16 concerns about its reliability. The plan was to test the

17 stator to insure it was in good condition before

18 disassembly of the Eddystone generator and then to retest

19 after delivery to the Hunter Plant. No plans were made

20 to rebuild or upgrade the stator.

21 Q What was considered to be the best option?

22 A During the time the generator was being

23 disassembled, PacifiCorp considered its options and

24 decided that the best available option was to rebuild the

25 damaged generator. The San Antonio Deely option was

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1 ultimately not selected because the San Antonio

2 management wanted to increase substantially the

3 negotiated premium and the city negotiators could not get

4 approval to proceed. In addition, PacifiCorp would bear

5 the risk of purchasing replacement energy for San

6 Antonio, if the Deely unit stator failed between Spring

7 2001 and Spring 2002. The Eddystone option was not

8 selected because of the risks associated with

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1 shipping the stator and the risks associated with

2 installing a used stator that was older with fewer

3 upgrades than the stator that had failed in Unit 1.

4 Rebuild/Repair Process

5 Q Describe the project organization for the

6 generator rebuild.

7 A PacifiCorp established a project manager

8 for the generator rebuild project. At the Hunter Plant

9 site, a lead technical person had responsibility for

10 coordinating all PacifiCorp activities with Siemens

11 Westinghouse activities and responsibility to clear any

12 road blocks to the generator repair activities. A second

13 lead technical person had the responsibility to

14 facilitate and expedite the off-site manufacture and

15 repair of the components required. This person worked

16 closely with the Siemens Westinghouse team to ensure that

17 materials were delivered as necessary. Siemens

18 Westinghouse also established a project manager and team

19 in Orlando for the generator rebuild. A lead engineer in

20 Orlando for the project was also assigned. At the Hunter

21 site, Siemens Westinghouse had a site project manager who

22 managed and coordinated all activities on site. The

23 total Siemens Westinghouse workforce on site averaged

24 approximately 45 persons. A conference call was

25 conducted every weekday and most weekends to coordinate

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1 activities. The Siemens Westinghouse site project

2 manager updated the project schedule and forecast

3 completion dates daily. Status reports of repair

4 progress were prepared daily for Siemens Westinghouse

5 management and PacifiCorp management. These reports

6 included progress against schedule, explanations for

7 delays in schedule, and forecasts of completion dates.

8 It should be noted that this

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1 was the largest generator stator core that Siemens

2 Westinghouse had rebuilt in the field in the United

3 States.

4 Q Why was it decided that the generator

5 should be rebuilt at the plant site?

6 A The critical issue was to return the unit

7 to service as quickly as possible with confidence in its

8 reliability. The rebuilding of the stator was the

9 critical path of the generator repair. The rotor,

10 exciter, and other components could be refurbished in

11 parallel with the generator stator and could be completed

12 in less time. The physical size of the stator required

13 that it be transported by rail. The repair facility was

14 located in Charlotte, North Carolina. It was estimated

15 that transportation would add an additional four weeks to

16 the repair schedule if no difficulties were encountered.

17 Therefore the decision was made to rebuild the stator on

18 the plant site.

19 Q Please describe briefly the magnitude of

20 the repairs.

21 A The generator stator core and windings were

22 replaced. The old windings and core were removed from

23 the generator frame. Manufacture of new windings was not

24 a critical path item because PacifiCorp had previously

25 procured a set of windings. A special foundation fitted

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1 with a building plate supplied by Siemens Westinghouse

2 was constructed on the ground floor of the plant. The

3 generator frame that weighs 105 tons was removed from its

4 foundation and turned up on end on the building plate.

5 New building bolts, new through bolts, and new stator

6 core iron were installed in the stator frame. Over

7 100,000 new pieces of core iron and fittings were

8 installed in the stator frame. The generator frame

9 complete with new core weighed approximately 235 tons.

10 The complete assembly was lifted

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1 back on to the generator foundation using a crane that

2 was specially built and erected in the plant for that

3 purpose. The new core was consolidated and tested. New

4 windings were installed and tested.

5 The rotor was refurbished in parallel with the

6 stator rebuild. The rebuild of the rotor was

7 competitively bid and Alstom offered the lowest price and

8 fastest rebuild schedule. The 60-ton rotor was shipped

9 to Altsom's Richmond, Virginia shop by truck on December

10 14, 2000. The generator rotor was completely

11 disassembled and inspected to ensure that there was no

12 damage and that there were no pellets of core iron in the

13 rotor cooling passages or under the retaining rings that

14 could ultimately result in a shorted or grounded field

15 (rotor winding). The rotor was rewound with the original

16 copper winding. A new coupling was manufactured and

17 installed. This particular type of rotor has a tendency

18 to develop cracks near the tooth tops of the rotor

19 forging. While being rebuilt, a modification was made to

20 eliminate the potential for cracking. New field

21 retaining rings were manufactured from an improved 18-18

22 alloy and installed to eliminate the risk of stress

23 corrosion failure associated with the original 18-5 alloy

24 rings. The rotor was high speed balanced, electrically

25 tested, and trucked back to the plant on March 28, 2001.

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1 New rotating blower blades were fitted on the rotor at

2 the plant site. New stationary blower blades were

3 manufactured and fitted into the generator during

4 reassembly.

5 The exciter and PMG were trucked to the Siemens

6 Westinghouse facility in Charlotte, North Carolina. The

7 exciter was disassembled, inspected and refurbished to

8 ensure that no damage was sustained from stray currents

9 and arcing

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1 that occurred in the exciter cubicle. The PMG was

2 completely rebuilt with new stator iron and a new

3 winding. New permanent magnets were also installed. The

4 refurbished exciter-PMG assembly was balanced, tested,

5 and shipped back to the plant on March 30, 2001.

6 Hydrogen coolers were shipped to Harris Tube

7 Service in Salt Lake City and fitted with new tubes.

8 Harris Tube Service is a Salt Lake City company that

9 specializes in the repair and maintenance of heat

10 exchangers and tube replacement.

11 The voltage regulator was inspected, cleaned and

12 tested. Components were disassembled as necessary to

13 clean-up oil residue from exciter lube oil leak.

14 Q Please provide an overview of the repair

15 schedule.

16 A The following is a chronology of the major

17 milestones:

18 November 24, 1999 Generator Failed

19 November 25, 2000 Disassembly commenced

20 November 29, 2000 Rotor removed, damage assessed

21 November 30, 2000 Decision made to replace complete

22 stator core

23 December 18, 2000 Option to rebuild was selected

24 December 20, 2000 All damaged components are removed

25 December 29, 2000 Stator frame was upended on building

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1 plate

2 February 20, 2001 Completed core installation

3 February 22, 2001 Rebuilt stator frame and core back on

4 foundation

5 March 7, 2001 Completed core consolidation and core

6 testing

7 March 8, 2001 Began installing winding coils

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1 April 19, 2001 Complete high potential test of

2 windings

3 April 19, 2001 Reassembly of generator commenced

4 April 26, 2001 Unit on turning gear, air test

5 complete

6 April 28, 2001 Initial synchronization

7 May 1, 2001 Generator in service and commenced

8 generator testing

9 May 2, 2001 Identified winding cooling problem

10 May 6, 2001 Unit removed from service, inspection

11 covers removed, repairs completed on

12 winding cooling problem

13 May 7, 2001 Generator in service and testing

14 resumed

15 May 8, 2001 Generator was released for normal

16 operation.

17 Q When was Hunter Unit 1 returned to service?

18 A The first synchronization occurred on

19 April 28, 2001. Final tests were completed on May 8,

20 2001.

21 Cause of Failure

22 Q Has a cause of the failure been determined?

23 A No. The generator failure resulted from a

24 shorting of laminations within the generator stator core.

25 The location of the initial failure has been determined

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1 to be 5-6 feet from the exciter end of the stator between

2 the through bolt and the bottom of Slot 21 as illustrated

3 in Exhibit No. 13. The root cause of the shorting has

4 not been determined. Evidence of the root cause was most

5 likely destroyed in the process of the generator failure.

6 Q Describe your investigation process for

7 this generator incident.

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1 A Plant personnel began preparing for an

2 internal investigation of the generator failure in

3 parallel with the initial generator inspection. Plant

4 personnel gathered all plant records associated with the

5 operation of the generator and the November 24 generator

6 outage. Power Supply Technical Services immediately

7 engaged the services of Bob Ward, a retired Westinghouse

8 generator engineer whom now consults. At the

9 recommendation of Hartford Steam Boiler Company, the

10 company insurance provider, Ron Halpern was engaged to

11 also help in the initial review of the incident.

12 Subsequently, PacifiCorp hired two additional

13 consultants, Clyde Maughan and Dean Harrington, to

14 participate in the review. Three of the four consultants

15 visited the site to inspect the generator during the

16 disassembly period. Plant personnel and Siemens

17 Westinghouse personnel took many photographs of the

18 generator components as the machine was disassembled.

19 Following disassembly of the generator and removal of the

20 core iron, PacifiCorp personnel convened a 3-day meeting

21 in late January with Siemens Westinghouse personnel and

22 the four consultants to review and discuss data.

23 Q What have you determined regarding the

24 cause of the failure?

25 A We have not been able to determine a

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1 specific root cause of the failure. All persons that

2 have examined the data are in general agreement that the

3 failure occurred at a point in the core between the

4 through bolt and the bottom of Slot 21 approximately 5-6

5 feet from the exciter end. This conclusion is based on

6 the magnitude of the melting in this location relative to

7 other locations. Also, the experts involved in the

8 examination of the evidence agree that damage in other

9 locations of the generator is consequential to the

10 initial point of failure. All

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1 experts agree that the damage resulted from a break down

2 of insulation between the laminations of the core that

3 resulted in overheating caused by eddy currents within

4 the area where the lamination insulation failed. The

5 cause of the failure of lamination insulation has not

6 been determined. Potential causes of overheating were

7 identified. Some causes have been eliminated by the

8 evidence that is available. A number of potential causes

9 remain, but no hard evidence exists to identify one

10 specific cause. The evidence of the cause was most

11 likely destroyed in the failure.

12 Q Is there any reason to believe that

13 maintenance practices contributed to the failure of the

14 generator?

15 A No. The generator was overhauled by

16 Siemens Westinghouse in June 1999. A complete inspection

17 of the generator was performed. Siemens Westinghouse's

18 1999 overhaul report concluded, "All tests showed this

19 machine to be in good operating condition. The

20 modifications made to this machine have put it into the

21 high reliability range...."

22 Q Were protective relays and automatic trip

23 circuits working properly?

24 A Yes. Protective relays had been calibrated

25 during the 1999 overhaul and were in service. All

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1 automatic trip circuits were in service.

2 Q Is there any evidence that the generator

3 was operated improperly?

4 A No. The generator is always operated

5 within the design capability when synchronized to the

6 system.

7 Q Did any operator action cause or contribute

8 to the failure?

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1 A The unit was operating at full load and the

2 control room operator was monitoring his equipment at the

3 time of the incident. There were no abnormal operating

4 conditions or events on the morning of the generator

5 failure. The control room operator, shift supervisor,

6 and plant operator responded appropriately to the initial

7 generator alarms and reacted correctly to the occurring

8 events.

9 Q Who insures the generator?

10 A The generator is insured by a consortium of

11 insurance companies. Hartford Steam Boiler Insurance

12 Company is acting as the lead insurance company for this

13 claim. Hartford Steam Boiler Insurance Company is

14 investigating and adjusting the claim.

15 Q What is the amount of the claim?

16 A Invoices have been received from Alstom and

17 Siemens Westinghouse. However, the exact amount of the

18 claim remains to be determined because the Company has

19 not yet completed the final review of the repair costs

20 with the insurance company at this time. The estimated

21 amount of the claim in US$ is:

22 Total Project Cost $17,558,000

23 Insured Portion 16,991,000
Deductible (2,250,000)
24 Claim $14,741,000

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1 Q What position has Hartford Steam Boiler

2 taken on this claim?

3 A Hartford Steam Boiler has agreed to payment

4 of the claim for the generator repair cost.

5 Q Does this conclude your testimony?

6 A Yes.

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13 (The following prefiled testimony of

14 Mr. Brian Hedman is spread upon the record.)

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PacifiCorp

1 Q Please state your name, position, and

2 address.

3 A My name is Brian Hedman. I am Manager,

4 Regulation at PacifiCorp. My address is 825 NE

5 Multnomah, Portland, Oregon.

6 Q Please describe your education and business

7 experience.

8 A I have a bachelor's degree in business

9 administration from the University of Washington and a

10 masters degree in economics from Portland State

11 University. I have been employed by PacifiCorp since

12 1980 and have held several positions. I have held my

13 current position for the last 5 years.

14 Q Have you previously testified?

15 A Yes. I have represented the Company before

16 this Commission on many regulatory issues over the years

17 and have testified or submitted testimony before the Utah

18 Public Service Commission, the Washington Utilities and

19 Transportation Commission, the Oregon Public Utilities

20 Commission and the Federal Energy Regulatory Commission.

21 Q What is the purpose of your testimony?

22 A The purpose of my testimony is to describe

23 the benefits that PacifiCorp's customers in Idaho will

24 receive from the Bonneville Power Administration through

25 its residential and small farm exchange credit.

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1 Q What is the Bonneville Power Administration

2 (BPA) Residential and Irrigation Exchange Credit?

3 A The BPA credit is a mechanism to provide

4 benefits to qualifying customers of investor owned

5 utilities (like Utah Power) from the Federal Columbia

6 River Hydroelectric System in satisfaction of BPA's

7 obligations under the Northwest

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1 Power Act of 1980. The credit is available only to

2 residential and small farm customers and is provided to

3 the Company's customers in Idaho through Electric Service

4 Schedule No. 34.

5 Q Please give a brief history of the BPA

6 credit in Idaho.

7 A Prior to 1997 the amount of credit received

8 from BPA was based on the actual energy used by the

9 customer, the average system cost of Utah Power and BPA's

10 seasonally adjusted Priority Firm Exchange rate. In 1996

11 this methodology changed. A settlement with BPA in 1996

12 resulted in a fixed monetary benefit being provided to

13 the Company to pass-on to qualifying customers. In

14 advice filing 98-002, the Company proposed an allocation

15 of 43 percent of the 1996 settlement amount to

16 residential customers and 57 percent to irrigation

17 customers. These proportions were based on a calculation

18 of what the respective classes would have expected to

19 receive had that settlement not been reached. In Order

20 No. 27709 the Commission accepted the Company's proposal.

21 The exchange agreement with BPA expired in 2001, and a

22 new agreement (the "2001 settlement") was entered into to

23 provide a continuation of exchange benefits.

24 Q Please describe the 2001 settlement.

25 A In its 2001 rate case, BPA proposed an

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1 alternative to the traditional exchange. The alternative

2 was to provide investor owned utilities the option to

3 purchase actual power or rights to power through a

4 subscription process. The amount that the IOU's could

5 subscribe to was based on their qualifying residential

6 and small farm load in consultation with the regulatory

7 commissions of Idaho, Washington, Montana and Oregon.

8 IOU's that chose subscription did so as a settlement of

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1 their exchange rights for this period. The subscription

2 was further split between actual power and a monetary

3 portion that was calculated as the difference between

4 BPA's price and BPA's forecasted market price. Finally,

5 BPA expected to need to purchase additional resources in

6 order to serve that portion of the subscription that was

7 delivered as actual power. Faced with the potential of

8 very high costs for these additional resources,

9 PacifiCorp agreed to forgo its right to actual power for

10 an overall financial settlement of its exchange benefits.

11 The resulting financial settlement provides $34 million

12 in benefits to qualifying Idaho customers for the first

13 year in benefits and $35.2 million in the second year.

14 Q How does this level compare with historical

15 levels?

16 A It is substantially higher. From 1990-1996

17 BPA provided to PacifiCorp, for its Idaho customers,

18 between $16 and $22 million in exchange benefits

19 annually. The actual amount varied with energy use. As

20 a result of a 1996 settlement with BPA for the period

21 1997-2001, BPA provided a fixed amount of $47 million for

22 that 5-year period. Annual payments declined from $14

23 million in 1997 to $8.5 million in 2001, including an

24 additional $5.5 million to cover the period between

25 June 30, 2001 when the previous contract ended and

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PacifiCorp

1 October 1, 2001 when the new contract period started.

2 Q How are these benefits distributed among

3 the qualifying customers?

4 A As explained above, in recent years the

5 benefits have been allocated 43 percent to residential

6 customers and 57 percent to irrigation customers. In

7 this case, the Company proposes to continue to allocate

8 the settlement amounts between the residential and

9 irrigation customers based on that same approach.

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PacifiCorp

1 Q Why is the Company requesting that the BPA

2 credit be implemented immediately, even if the other

3 aspects of the filing are suspended?

4 A BPA increased its credit effective October

5 1, 2001. The Company has a contractual obligation to

6 pass the credit through to its customers in a timely

7 manner. Consequently, the Company is proposing that

8 Schedule 34, the BPA credit, be approved immediately.

9 Q What happens to the increased credit for

10 the period from October 1 until the new credit level is

11 implemented in rates?

12 A The Company proposes to add the anticipated

13 four month's worth of credit for residential customers to

14 the first year's credit rate. In other words, the rate

15 for the first year will be set to distribute 16 months

16 worth of a normal year's amount for residential

17 customers. At the end of the first year the rate will be

18 reset to match a normal 12 month's worth of credit.

19 Q Why is only the residential credit adjusted

20 for the four-month lag?

21 A Irrigation usage is largely completed by

22 October 1. Irrigation payments fluctuate significantly

23 year to year due to differences in irrigation usage

24 during the irrigation season. The Company believes that

25 it is most important to make an explicit adjustment to

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PacifiCorp

1 the residential customers in order to reflect the winter

2 heating months and to assure that the credit is

3 ultimately distributed according to the 43 percent

4 residential/57 percent irrigation proportion mentioned

5 earlier.

6 Q Does this conclude your testimony?

7 A Yes.

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14 (The following prefiled testimony of

15 Mr. David Taylor is spread upon the record.)

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PacifiCorp

1 Q Please state your name, business address

2 and position with PacifiCorp dba Utah Power & Light

3 Company (the Company).

4 A My name is David L. Taylor. My business

5 address is 825 N. E. Multnomah, Suite 800, Portland,

6 Oregon, where I am employed as the Cost of Service

7 Manager.

8 Qualifications

9 Q Please briefly describe your education and

10 business experience.

11 A I received a Bachelor of Science in

12 Accounting from Weber State College in 1979 and an MBA

13 from Brigham Young University in 1986. I have been

14 employed by PacifiCorp since the merger with Utah Power

15 in 1989. Prior to the merger I was employed by Utah

16 Power, beginning in 1979. At the Company I have worked

17 in the Accounting, Budgeting, and Pricing and Regulatory

18 areas. From 1987 to the present I have held several

19 supervision and management positions in Pricing and

20 Regulation.

21 Q Have you appeared as a witness in previous

22 regulatory proceedings?

23 A Yes. I have testified on numerous occasions

24 in California, Idaho, Montana, Oregon, Utah, Washington

25 and Wyoming.

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PacifiCorp

1 Purpose of Testimony

2 Q What is the purpose of your testimony?

3 A I will present PacifiCorp's year-end March

4 2001 functionalized Class Cost of Service Study.

5 Q Please identify Exhibit No. 14 and explain

6 what it shows.

7 A Exhibit No. 14 is the summary table from

8 PacifiCorp's year-end March 2001 Class Cost of Service

9 Study for the State of Idaho. It summarizes, both by

10 customer group and by function, the results of the

11 year-end March 2001 cost study. Columns A and B

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PacifiCorp

1 identify the rate schedules, or classes of customers,

2 currently served in Idaho. Column C lists the test

3 period revenue for each customer class. Column D lists

4 the earned rate of return for each class and the Rate of

5 Return Index, shown in column E, is the ratio of each

6 class's rate of return to the overall normalized

7 jurisdictional rate of return. Column F shows the total

8 cost of service for each rate schedule or the revenues

9 necessary for each customer class to produce the

10 jurisdictional normalized rate of return. Columns G

11 through K list the cost of service by function. Columns

12 L shows the revenue increase or decrease necessary to

13 bring each class of service to full cost of service and

14 column M shows the associated percent change.

15 Q Please identify Exhibit No. 15 and explain

16 what it shows.

17 A Exhibit No. 15 shows the cost of service

18 results in more detail by class and by function. Table 1

19 summarizes the total cost of service summary by class and

20 tables 2 through 6 contain a summary by class for each

21 major function.

22 Q Please explain how the Cost of Service

23 Study was developed.

24 A The Class COS Study is based on

25 PacifiCorp's year end March 2001 normalized results of

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PacifiCorp

1 operations for the State of Idaho. The study employs a

2 three-step process generally referred to as

3 functionalization, classification, and allocation. These

4 three steps recognize the way a utility provides

5 electrical service and assigns cost responsibility to the

6 groups of customers for whom those costs were incurred.

7 Q Please describe functionalization and how

8 it is employed in the Cost of Service Study.

9 A Functionalization is the process of

10 separating expenses and rate base items according to

11 utility function. The production function consists of

12 the costs associated with power generation, including

13 coal mining, and wholesale purchases. The transmission

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1 function includes the costs associated with the high

2 voltage system utilized for the bulk transmission of

3 power from the generation source and interconnected

4 utilities to the load centers. The distribution function

5 includes the costs associated with all the facilities

6 that are necessary to connect individual customers to the

7 transmission system. This includes distribution

8 substations, poles and wires, line transformers, service

9 drops and meters. The retail services function includes

10 the costs of meter reading, billing, collections and

11 customer service. The miscellaneous function includes

12 costs associated with Demand Side Management, franchise

13 taxes, regulatory expenses, and other miscellaneous

14 expenses.

15 Q Describe classification and explain how

16 PacifiCorp uses it in the cost of service study.

17 A Classification identifies the component of

18 utility service being provided. The Company provides,

19 and customers purchase, service that includes at least

20 three different components; demand-related,

21 energy-related, and customer-related.

22 Demand-related costs are incurred by the

23 Company to meet the maximum demand imposed on generating

24 units, transmission lines, and distribution facilities.

25 Energy-related costs vary with the output of a kWh of

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PacifiCorp

1 electricity. Customer-related costs are driven by the

2 number of customers served.

3 Q How does PacifiCorp determine cost

4 responsibility between customer groups?

5 A After the costs have been functionalized

6 and classified, the next step is to allocate them among

7 the customer classes. This is achieved by the use of

8 allocation factors which specify each class' share of a

9 particular cost driver such as system peak demand, energy

10 consumed, or number of customers. The appropriate

11 allocation factor is then applied to the respective cost

12 element to determine each class' share of cost.

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1 A detailed description of PacifiCorp's functionalization,

2 classification and allocation procedures and the

3 supporting calculations for the allocation factors are

4 contained in my workpapers.

5 Q How are generation and transmission costs

6 apportioned among customer classes?

7 A Production and transmission plant and

8 non-fuel related expenses are classified as 75% demand

9 related and 25% energy-related. The demand-related

10 portion is allocated using 12 monthly peaks coincident

11 with the PacifiCorp system firm peak. The energy portion

12 is allocated using class MWhs adjusted for losses to

13 generation level.

14 Q Are distribution costs determined using the

15 same methodology?

16 A No. Distribution costs are classified as

17 either demand related or customer related. In this study

18 only meters and services are considered as customer

19 related with all other costs considered demand related.

20 Distribution substations and primary lines are allocated

21 using the weighted monthly coincident distribution peaks.

22 Distribution line transformers and secondary lines are

23 allocated using the weighted NCP method. Services costs

24 are allocated to secondary voltage delivery customers

25 only. The allocation factor is developed using the

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1 installed cost of new services for different types of

2 customers. Meter costs are allocated to all customers.

3 The meter allocation factor is developed using the

4 installed costs of new metering equipment for different

5 types of customers.

6 Q Please explain how customer accounting,

7 customer service, and sales expenses are allocated.

8 A Customer accounting expenses are allocated

9 to classes using weighted customer factors. The

10 weightings reflect the resources required to perform such

11 activities as

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PacifiCorp

1 meter reading, billing, and collections for different

2 types of customers. Customer service expenses are split

3 between Demand Side Management (DSM) expenditures and

4 other customer service expenses. The DSM expenditures

5 are allocated on the number of customers in each class.

6 Sales expenses are allocated to rate schedules according

7 to revenue.

8 Q How are administrative & general expenses,

9 general plant and intangible plant allocated by

10 PacifiCorp?

11 A Most General plant, intangible plant, and

12 administrative and general expenses are functionalized

13 and allocated to classes based on generation,

14 transmission, and distribution plant. Employee Pensions

15 and Benefits have been assigned to functions and classes

16 on the basis of labor. Costs that have been identified as

17 supporting customer systems are considered part of the

18 retail services function and have been allocated using

19 customer factors. Coal Mine plant is allocated on the

20 energy factor.

21 Q Are costs and revenues associated with

22 wholesale contracts included in the cost of service

23 study?

24 A No costs are assigned to wholesale sales

25 contracts. The revenues from these transactions are

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1 treated as revenue credits and are allocated to customer

2 groups using appropriate allocation factors. Other

3 electric revenues are also treated as revenue credits.

4 Revenue credits reduce the revenue requirement that is to

5 be collected from firm retail customers.

6 Q Are there any differences in this study

7 from those filed previously with the Idaho Commission?

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PacifiCorp

1 A This class COS Study and the supporting

2 jurisdictional results of operations were prepared using

3 the same general methodology as previously filed studies

4 with a few modifications. In previous studies,

5 interruptible customers were removed from jurisdictional

6 results. No costs were assigned to these customers and

7 their revenues were treated as revenue credits which were

8 allocated to all states. In the interjurisdictional

9 allocation supporting this cost study, all special

10 contract customers have been assigned to their home

11 states as firm, situs customers.

12 Q What are the reasons for changing the

13 status of interruptible and other large special contract

14 customers from system allocation to state situs

15 customers?

16 A There are several reasons that system-wide

17 revenue requirement treatment is no longer appropriate.

18 First, this approach has not proved acceptable to all

19 states. Under the current approach, every state needs to

20 become comfortable with the terms and prices of every

21 contract in every state. In the last few rate cases

22 there have been proposals from intervenors and regulators

23 in the various states to either impute revenue for the

24 existing contracts in other states or to shift to situs

25 assignment of costs for those contracts. Second, market

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1 prices and the Company's avoided costs now make the

2 contribution to fixed cost standard much harder to meet.

3 In nearly every case prices under the contribution fixed

4 cost standard would be higher than full embedded costs.

5 Third, including a price discount for interruptibility in

6 an electric service agreement assigns a fixed value to

7 the interruptibility over the term of the agreement.

8 However, the drastic changes in the wholesale market over

9 the last couple of years have shown us that

10 interruptibility can have very different values at

11 different points in time. Recognition of those different

12 values can best be dealt with in

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1 separate, shorter-term interruptibility agreements.

2 Also, under the Company's Structural Realignment

3 Proposal, there will be no interjurisdictional allocation

4 of costs to which system-wide revenue credits can be

5 applied. Each state electric company will have the

6 obligation to serve all the retail load in its service

7 territory. If the current interruptible loads are

8 removed from the apportionment of the existing generation

9 and transmission resources, the state electric company

10 will be left without the resources to meet that

11 obligation.

12 Because of these reasons it is more

13 appropriate to treat the sales of electricity from

14 PacifiCorp to large contract customers under one

15 agreement and to treat any interruptibility provisions a

16 customer is able to provide under a separate agreement as

17 a power purchase by PacifiCorp from that customer. The

18 Company intends that sales of electricity to customers

19 such as Monsanto will be full firm service at embedded

20 cost equivalent prices. The loads associated with firm

21 service to these customers will be included as part of

22 the jurisdictional allocation and included in the revenue

23 requirement for the state where they are served. Any

24 interruptible provisions will be treated as a purchase by

25 the Company's power supply organization and included as a

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1 purchased power cost allocated among all states.

2 Q How are the Idaho special contract

3 customers treated in the class cost of service study?

4 A Because the prices for the two non-tariff

5 customers are being determined in separate proceedings,

6 they have been treated in this cost of service study as

7 state specific revenue credits. The cost and revenues

8 for these two customers have been included in the Idaho

9 results of operations, but no costs have been assigned to

10 them in the class

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1 cost of service study. The revenues from the two

2 customers have been allocated to each of the tariff

3 classes of customers to offset its allocated share of

4 revenue requirement responsibility.

5 Q What revenue assumptions did you use for

6 Monsanto and Nu-West?

7 A The present revenues for these two

8 customers have been estimated at the rate PacifiCorp has

9 proposed for their contract renewals. These rates are

10 based on the embedded cost of service for the two

11 customers. (Monsanto, 31.4 mills; Nu-West, 34.82 mills)

12 Q How have you treated the interruptibility

13 provisions of the irrigation load control program in your

14 cost of service study?

15 A The study is being used to determine the

16 cost of firm service to irrigation customers and will be

17 used to set the firm tariff price. As such, no

18 adjustment to loads was made. Similar to the treatment

19 for contract customers, any interruptibility provisions

20 for irrigation customers will be treated as a power

21 purchase by PacifiCorp under a separate agreement. The

22 Company is developing an optional load control credit for

23 irrigation customers that will replace the load control

24 program. We have been engaged in discussions with

25 customers and Commission staff, and plan to file a

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1 program later this year.

2 Q Have you included your workpapers?

3 A Yes. Work papers showing the complete

4 functionalized results of operations and class cost of

5 service detail are included as Exhibit No. 16. Also

6 included in the workpapers is a detailed narrative

7 describing the Company's functionalization,

8 classification and allocation procedures.

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1 Q Does this conclude your testimony?

2 A Yes it does.

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4 (The following prefiled testimony of

5 Mr. James Zhang is spread upon the record.)

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1 Q Please state your name.

2 A My name is James Z. Zhang.

3 Q What is your business address and by whom

4 are you employed?

5 A My business address is 825 NE Multnomah

6 Avenue, Portland, Oregon. I am employed by PacifiCorp

7 (the Company).

8 Qualifications

9 Q What is your current position with

10 PacifiCorp?

11 A My current position is Pricing Consultant

12 in the Regulation Department.

13 Q What is your educational and professional

14 background?

15 A I earned a Bachelor of Science degree in

16 Mechanical Engineering from Beijing University of

17 Chemical Technology in 1982, a Master of Science degree

18 in Engineering Management from Tsinghua University in

19 1985 and a Ph.D. in Economics from Oregon State

20 University in 1994. I joined the Company in the

21 Regulation Department in August 1997.

22 Q Have you appeared as a witness in previous

23 regulatory proceedings?

24 A No. Since 1997, with levels of increasing

25 responsibility, I have developed and implemented a number

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1 of rate spread and rate design proposals throughout the

2 Company's six state service territory.

3 Purpose of Testimony

4 Q What is the purpose of your testimony?

5 A The purpose of my testimony is to address

6 the Company's proposed rate spread in this case and to

7 propose price changes for the affected rate schedules.

8 Q Please describe PacifiCorp's pricing

9 objectives in this case.

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PacifiCorp

1 A The Company's pricing objectives in this

2 case are to implement, over two years, a cost of

3 service-based redesign of the Company's prices along with

4 the proposed power cost adjustment, while also

5 implementing the revised BPA credit. The Company's

6 overall goal is to implement these three elements in such

7 a way that no customer class will see a price increase.

8 Q How does the Company propose to redesign

9 rates based on cost of service?

10 A Based on the cost of service (COS) study

11 introduced by Mr. Taylor, the Company proposes to

12 redesign its rates so that all customer classes fall

13 within five percent of their cost of service.

14 Specifically, for rate schedules that are currently

15 paying more than 105% of COS, the Company proposes to

16 reduce their rates to 105% of COS. Similarly, for rate

17 schedules that are currently paying less than 95% of COS,

18 the Company proposes to increase their rates to 95% of

19 COS. For rate schedules that currently fall between 95%

20 and 105% of COS, the Company proposes no change to

21 present base rates. The COS redesign will be fully

22 implemented in the first year and has been designed to be

23 revenue neutral; that is, the Company's total revenues

24 will be unchanged as a result of this rate redesign.

25 Q Why did the Company choose to bring all

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PacifiCorp

1 rate schedules within five percent of cost of service

2 rather than proposing that all rate schedules be at 100%

3 of cost of service?

4 A Due to the changing makeup of customer

5 classes, variations in usage and other factors, cost of

6 service results can vary from year to year. A customer

7 class that was at 100 percent of cost of service in one

8 year can be higher or lower than that in the following

9 year. The Company chose the five percent cost of service

10 threshold as a way to balance cost of service precision

11 and appropriate cost responsibility for

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1 customer classes. We believe it makes reasonable

2 movement toward bringing each customer class closer to

3 cost of service, while recognizing the inherent

4 variability from year to year.

5 Q Please describe the Company's proposed

6 power cost adjustment (PCA).

7 A Mr. Widmer provides testimony regarding the

8 Company's need to recover approximately $38 million in

9 excess power costs. The Company proposes to recover

10 these costs over a two-year period in which 70 percent,

11 or $27 million, is recovered in the first year and the

12 remaining 30 percent, or $11 million, is recovered in the

13 second year. This 70/30 split is designed in conjunction

14 with a rate mitigation adjustment (discussed below) to

15 achieve the goal of customer classes not seeing any price

16 increases as a result of these changes in either year.

17 Q On what basis does the Company propose to

18 collect the PCA from customers?

19 A Because the excess power costs are energy

20 related, the Company proposes to collect them through a

21 cents per kilowatt-hour adjustment (PCA) based on

22 customers' service voltage levels. The PCA rates are

23 obtained by dividing the total excess power costs by the

24 total kilowatt-hours at the generator and then adding an

25 adjustment for voltage losses. The PCA will be applied

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PacifiCorp

1 to all customer classes and to all energy usage.

2 Q Please describe the Company's proposed

3 distribution of the credit from the Bonneville Power

4 Administration (BPA).

5 A In year one, the Company proposes to

6 distribute the $34 million of Idaho BPA credit based on

7 historic allocations, with 57 percent going to irrigation

8 customers and 43 percent going to other qualifying

9 (residential and qualifying small commercial)

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1 customers. Moreover, residential and qualifying small

2 commercial customers receive an additional credit benefit

3 in year one equal to four months of their year-one BPA

4 credit. This additional amount is being applied in order

5 to distribute funds accumulated since implementation of

6 increases in the BPA benefit in September 2001 and will

7 be spread evenly over the twelve months of year one. In

8 addition, $1.6 million of previously collected BPA

9 exchange benefit is to be distributed in year one with

10 the historic 57/43 percent split. The total amount of

11 BPA credit the Company proposes to distribute to

12 qualifying customers in year one is $40.6 million.

13 In year two, the Company proposes to adjust

14 the BPA credit to distribute the $35.1 million of allowed

15 benefits using the same historic 57/43 percent split

16 between irrigation and other qualifying (residential and

17 qualifying small commercial) customers.

18 Q What is the purpose of the rate mitigation

19 adjustment (RMA)?

20 A The combination of the COS redesign, the

21 PCA and the BPA credit as described above results in

22 changes to most customer prices and in some cases

23 increases occur. The RMA is designed to offset those

24 changes and to balance revenues so that no customer class

25 will see a price increase in the first two years. The

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PacifiCorp

1 RMA is also designed to maintain greater price stability

2 by minimizing price fluctuations from year to year.

3 Q How does the RMA work?

4 A The RMA is a surcharge or surcredit applied

5 on a cents per kilowatt-hour basis to each rate schedule.

6 It has been designed to mitigate and moderate price

7 impacts that may occur and to achieve the goal that no

8 customer class receives a price increase for

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1 the next two years. In fact, most customers will see

2 significant price decreases in both year one and year

3 two.

4 Q Has the Company implemented an RMA in any

5 of its other jurisdictions?

6 A Yes. The Company implemented an RMA in

7 Oregon in late 2001 in order to minimize price

8 fluctuations across customer classes.

9 Q Please describe Exhibit No. 17.

10 A Exhibit No. 17 details the Company's

11 proposed changes and the development of the RMA, based on

12 the 12 month test period ending March 2001, to be

13 implemented over a two year period. Table 1 shows the

14 changes in year one; Table 2 shows the changes in year

15 two. On an overall basis in year one, these revisions

16 produce a 4.2 percent net price decrease. In year two,

17 an overall net price decrease of 7.2 percent is achieved.

18 Tables 3 to 18 contain monthly billing comparisons for

19 each of the affected rate schedules showing the net

20 impact of the proposed prices at various usage levels.

21 Q Please describe Exhibit No. 18.

22 A Exhibit No. 18 contains the Company's

23 proposed revised tariffs in this case.

24 Q Please describe the overall change that

25 customers will see in their prices in year one of the

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1 Company's proposal.

2 A In year one, residential customers will see

3 an average price decrease of eight percent. Irrigation

4 customers on average will also see a price decrease of

5 eight percent while, overall, commercial and industrial

6 customers will see a decrease of three percent. Lighting

7 customers will see an overall decrease of nine percent.

8 Q Please describe the change customers will

9 see in year two of the Company's proposal.

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PacifiCorp

1 A In year two, the residential customer class

2 will see a decrease of 15 percent from prices at the end

3 of year one. Irrigation customers will also see an

4 average decrease of 15 percent, while commercial and

5 industrial customers overall will see a decrease of four

6 percent from prices in effect at the end of year one.

7 Lighting customers overall will see a decrease of another

8 15 percent.

9 Q What happens to these customers' bills when

10 the PCA and the RMA go away at the end of two years?

11 A In the third year, prices will continue to

12 decline. Residential prices will decrease by 19 percent.

13 Irrigators will see a decrease of 21 percent while

14 commercial and industrial customers will see, overall, a

15 decrease of six percent. Lighting customers will see,

16 overall, a decrease of 17 percent. It should be noted

17 that this discussion about the decreases that will be

18 seen by customer classes reflects the effective price

19 paid by customers, taking all adjustments into account.

20 Q Please summarize these changes over the

21 course of three years for the major rate schedules.

22 A The following table summarizes these

23 percentages:

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PacifiCorp

1 Customer Class Year One Year Two Year Three

2 Residential -7.8% -14.6% -18.8%

3 General Service
Schedule 6 0.0% 0.0% 0.0%
4 Schedule 9 0.0% 0.0% 0.0%
Schedule 23 -7.1% -6.2% -5.0%
5 Irrigation
Schedule 10 -7.8% -14.6% -21.2%
6 Commercial &
Industrial Total -2.8% -4.4% -5.7%
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Lighting -8.5% -14.9% -17.3%
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1 Residential Prices

2 Q Please describe the Company's proposed

3 residential price design changes.

4 A For residential customers, the Company

5 proposes to implement the COS redesign decrease by

6 reducing the energy charges, while keeping the current

7 ratio between summer/winter energy charges and

8 on-peak/off-peak energy charges for the optional time of

9 day schedule. The Company proposes no changes to the

10 minimum charge, service charge or seasonal service charge

11 minimums in the residential schedules.

12 Q How does the Company propose to implement

13 the PCA and the RMA?

14 A Proposed Schedule 93 contains the PCA, a

15 cents per kilowatt-hour adjustment based on the customers

16 voltage level. (All residential customers are served at

17 the secondary level.) Proposed Schedule 94 contains the

18 RMA, a cents per kilowatt-hour adjustment based on rate

19 schedule. Both schedules have columns indicating

20 different prices for year one and year two and are

21 proposed to expire 24 months after these tariffs go into

22 effect. These tariffs are included in Exhibit No. 18.

23 General Service & Irrigation Prices

24 Q Please describe the Company's proposed

25 price design changes for commercial and industrial

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PacifiCorp

1 customers.

2 A To implement the COS changes, for Schedules

3 19 and 23, the Company proposes to decrease the energy

4 charges while keeping the same summer/winter ratio. To

5 implement the COS changes for Schedule 8, the Company

6 proposes to increase the demand charges as well as the

7 energy charges, again while keeping the same seasonal

8 ratios.

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Zhang, Di 7a
PacifiCorp

1 Q Why does the Company propose to change the

2 demand charges for Schedule 8?

3 A An increase in the demand charge as well as

4 the energy charge for Schedule 8 will bring Schedule 8's

5 prices more closely in line with the cost of service

6 results.

7 Q What are the Company's proposed price

8 design changes for irrigation customers.

9 A The Company proposes to consolidate the

10 three rates currently contained in irrigation Schedule 10

11 into one firm service rate. The proposed service charges

12 and demand charge are the average of the three current

13 rates, proportioned for the amount of usage under each of

14 the three rate options.

15 Q What does the Company propose for the

16 energy charge in Schedule 10?

17 A The Company proposes to recover the COS

18 redesign increase through the energy charge while keeping

19 the same relationship between the current average

20 on-season and off-season revenues. The charge for

21 off-season energy has consequently been increased to

22 5.2459 cents per kWh. Also, the two-block current

23 on-season energy charge has been revised to a three-block

24 energy charge. The three-block energy charge will more

25 closely track cost of service while giving more uniform

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1 price signals to large irrigation customers. The first

2 block covers the first 25,000 kilowatt-hours, the same as

3 the current design. The second block covers the next

4 225,000 kilowatt-hours, and the third block covers all

5 kilowatt-hours over 250,000. The proposed rates for

6 on-season kilowatt-hours are 5.9485 cents per kWh for the

7 first tier, 4.7588 cents per kWh for the second tier and

8 2.5000 cents per kWh for the last tier.

9 Q How are the PCA and the RMA applied to

10 general service and irrigation customers?

11 A As with residential customers, for general

12 service and irrigation customers the PCA is applied as a

13 cents per kilowatt-hour adjustment based on the

14 customer's voltage level.

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PacifiCorp

1 The RMA is applied as a cents per kilowatt-hour

2 adjustment by rate schedule. The PCA and RMA adjustments

3 are contained in Schedules 93 and 94, respectively.

4 Q If Schedule 10 is proposed to be a firm

5 service rate, what does the Company propose for the

6 current load control program?

7 A The Company is developing an optional load

8 control credit for irrigation customers that will replace

9 the load control program. We have been engaged in

10 discussions with customers and Commission staff, and plan

11 to file a program later this year.

12 Other Changes

13 Q What price changes does the Company propose

14 for lighting customers?

15 A The appropriate COS redesign percentage

16 change has been applied to the current per lamp charges

17 in each of the lighting schedules. The PCA and RMA for

18 lighting schedules are contained in Schedules 93 and 94

19 as cents per kilowatt-hour charges and credits.

20 Q Please explain Exhibit No. 19.

21 A In Exhibit No. 19, Table 1 details the

22 billing determinants used in preparing the pricing

23 proposals in this case. It shows billing quantities and

24 prices at present rates and proposed rates. Table 2 and

25 Table 3 show the development of Company's proposed BPA

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1 credit and PCA surcharge, respectively.

2 Q Does this conclude your testimony?

3 A Yes, it does.

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1 (The following proceedings were had in

2 open hearing.)

3 COMMISSIONER SMITH: Mr. Fell.

4 MR. FELL: The next question is whether the

5 Commissioners have any questions or any other, I guess

6 it's Mr. Shurtz, frankly, have any questions of any of

7 those witnesses, whether you want to conduct any

8 cross-examination of any of the witnesses. The

9 stipulating parties have waived cross-examination.

10 COMMISSIONER SMITH: Do you have

11 questions?

12 COMMISSIONER HANSEN: I do of a couple of

13 the witnesses.

14 COMMISSIONER SMITH: Do you want to tell us

15 who they are so we can get them up here?

16 COMMISSIONER HANSEN: Mr. Watters and

17 I have Mr. Cunningham who isn't here.

18 COMMISSIONER SMITH: But we have

19 Mr. Goodrich for him.

20 COMMISSIONER HANSEN: Those two. I think

21 that was the only two.

22 COMMISSIONER SMITH: And Mr. Harris or

23 Mr. Shurtz, did you have questions of any of these

24 witnesses?

25 MR. SHURTZ: Other than the prefiled

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CSB REPORTING COLLOQUY
Wilder, Idaho 83676

1 testimony of Mr. Lively and Randy Lobb, not at this time.

2 COMMISSIONER SMITH: All right, thank you,

3 then we need Mr. Watters and Mr. Goodrich.

4 MR. FELL: Let me call Mr. Watters to the

5 stand first.

6

7 STANLEY K. WATTERS,

8 produced as a witness at the instance of PacifiCorp,

9 having been first duly sworn, was examined and testified

10 as follows:

11

12 DIRECT EXAMINATION

13

14 BY MR. FELL:

15 Q Mr. Watters, would you please state for the

16 record your name and your position with PacifiCorp?

17 A Stanley K. Watters, vice president of

18 wholesale energy services.

19 MR. FELL: Mr. Watters is available for

20 questions. His testimony has been spread on the record.

21 COMMISSIONER SMITH: Yes, and it further

22 identifies him and his credentials, I assume.

23 MR. FELL: Yes, it does.

24 COMMISSIONER SMITH: Okay, Commissioner

25 Hansen.

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CSB REPORTING WATTERS (Di)
Wilder, Idaho 83676 PacifiCorp

1 EXAMINATION

2

3 BY COMMISSIONER HANSEN:

4 Q Good afternoon.

5 A Good afternoon.

6 Q I did have a couple of questions on your

7 original testimony you filed and probably mainly just to

8 clarify a couple of things. On page 2, starting with

9 line 13, you say that the higher net power costs

10 experienced by the Company during the deferral period are

11 primarily attributed to the extraordinary increases in

12 wholesale prices, and then going on to line 15 through

13 18, you mention four unrelated circumstances which

14 further compounded the power costs. Have you found that?

15 A Yes.

16 Q And I guess my question is concerning your

17 No. 3 where you say abnormally poor power conditions and,

18 I guess, are you referring to hydropower conditions

19 within the Company or hydropower conditions in the

20 Northwest?

21 A Specifically within my testimony here and

22 in another location, I specifically refer to our own

23 hydro condition; however, both are just as poor in the

24 Northwest as what we experienced.

25 Q I guess a question I'd have is how much

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Wilder, Idaho 83676 PacifiCorp

1 hydro is normally or in a normal water year, how much

2 hydropower is generated or assigned to the Idaho load, do

3 you know?

4 A I would not be -- that's probably not an

5 area that I would be best to answer that question. It

6 may be better to have that answered by Mark Widmer or Bob

7 Lively, but I can take a little stab at it. I believe

8 that hydro would be allocated based on the allocated

9 share of Idaho and so we -- typically, these numbers may

10 be a little off, but I think we were about 2.6 million

11 megawatt-hours off in our hydro for the year from normal

12 conditions, so whatever the allocated share that Idaho

13 would receive would be a portion of that.

14 Q On page 10 and line 18, I think you

15 probably identify, you go on and you say, "These poor

16 hydro conditions added another .5 million and 2.3 million

17 megawatts of short-term purchase requirements in 2000 and

18 2001"; so are you literally saying that because of the

19 poor water year and the decrease in hydro conditions and

20 generation that you had to go out and purchase .5 million

21 megawatts in 2000 and in 2001 you had to purchase 2.3 as

22 a result of lack of hydro?

23 A Yeah, maybe the best way to answer that is

24 on how we plan for our system and when we do our

25 planning, we look at our portfolio and our position and

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Wilder, Idaho 83676 PacifiCorp

1 we obviously have to take into account our thermal

2 resources and what we expect to receive from them, loads,

3 load forecasts, what kind of growth we've seen and what

4 kind of hydro we would anticipate and well in advance of

5 our planning stages, we don't know what the weather is

6 going to be, we don't know what kind of water is going to

7 be available to us, so we basically look at our planning

8 from what is average, so our first step is to look at

9 average water and use that within our physical position.

10 Then, as time goes on, we adjust that and

11 our position is adjusted every day based on the more

12 knowledge we have, so as snowpack starts to accumulate or

13 doesn't accumulate, we start to reforecast what kind of

14 hydro we think we will receive from our facilities, so as

15 time went on, it just kept continuing to get worse and

16 there were early bird forecasts from Bonneville and we do

17 our own snow surveys in our water sheds that are

18 associated with our facilities and as time went on, you

19 just keep forecasting and you never know what's going to

20 happen the next day, but based on what you know today,

21 what does it look like you're going to get for hydro

22 output for that year, so it was continually being

23 adjusted through this period and in the end it ended up

24 being, as I've indicated here, our second worst water

25 year on record which couldn't happen at a worse time.

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1 Q I see. Is most of the hydro that is

2 assigned to the Idaho load, does that come from

3 generation on the Bear River?

4 A We have some generation on the Bear River,

5 but the predominance of our hydro conditions are or our

6 hydro facilities are in Oregon and Washington and I'm not

7 sure how that gets -- I'm not a --

8 Q But that ties into the Idaho load, that

9 hydro in Washington, the State of Washington?

10 A That I would have to defer to Mr. Widmer.

11 I'm not sure how we allocate resources amongst the

12 different states. From my position, I look at all the

13 resources of the Company and optimize them to meet all

14 the needs of our customers. How that gets determined in

15 rates is best asked by someone with more expert knowledge

16 in that area.

17 Q So the 2.3 million megawatts for 2001 may

18 be more associated with the hydropower facilities in the

19 State of Washington than in the State of Idaho; is that

20 correct?

21 A The predominance of our hydro is in Oregon

22 and Washington and so the predominance of this would be

23 there; however, the Bear system has been struggling for a

24 number of years and it is way off and it's way off again

25 this year.

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Wilder, Idaho 83676 PacifiCorp

1 Q Okay, I guess I'd move back to the four

2 unrelated circumstances that we were talking about and

3 now to Item No. 4, you mentioned retail load growth and I

4 guess I'm kind of curious, what was Idaho's load growth

5 during this deferral period? Did it increase drastically

6 or quite a bit?

7 A The preponderance of -- I don't have

8 specific numbers with me here today, but the excessive

9 load growth that we've been experiencing has mainly been

10 in our eastern control area which Idaho is part of and

11 the predominant growth has been in that control area.

12 Our western control area, I'm trying to reflect back on

13 some of my prior testimony in other states, has been

14 averaging about somewhere in the 2.5 range percent. Over

15 in our eastern control area, the last few years it's been

16 upwards of five to seven. How that breaks out to Idaho,

17 I don't want to -- I don't know right now today.

18 Q So really, there may not have been any load

19 growth in Idaho associated with this?

20 A I'm just talking about our eastern control

21 area there and a lot of that would come from Utah,

22 obviously. I don't know how much would be attributable

23 to Idaho.

24 Q So does the Company -- you forecast for

25 load growth, so do you have any idea of -- did you have a

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Wilder, Idaho 83676 PacifiCorp

1 surprise or something you didn't calculate that caused

2 this load growth in your, I guess it's your, system, not

3 Idaho?

4 A I look at the entire system, both control

5 areas, and manage to balance the loads and resources to

6 serve our customers in both areas. I look at the system

7 as an aggregated system and don't specifically make

8 decisions for Idaho or for Oregon. I make decisions on

9 an aggregated basis to minimize our total net power costs

10 for the system and then that gets allocated out to the

11 states, as I understand it, through our ratemaking

12 process.

13 As far as the load growth, yes, we were

14 surprised as far as the eastern control area. We had

15 never experienced load growth like that previously. In

16 our planning for load growth in the area had never been

17 as high as that. To be more specific, even Nevada and

18 even Arizona was experiencing some of the same type of

19 load growth that was pretty much at unprecedented levels

20 on the east side of the system.

21 Q So I'm just kind of curious and maybe

22 you're not the person to ask, but what would you say the

23 dollar impact of load growth would be a part of the

24 38 million? And if you don't know a number, is it major,

25 minor or what would you say?

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Wilder, Idaho 83676 PacifiCorp

1 A Well, take three percent of our total

2 energy needs, I'm trying to kind of come up what that

3 might be about, and three percent growth on average over

4 the whole system would be -- we grow about 150 megawatts

5 a year, something like that, 150 to 200 megawatts a year,

6 that would be about 1.6 million megawatt-hours times

7 about, I believe this case during this period, I think

8 the average price was $139 a megawatt-hour, so that's

9 about $200 million.

10 Q That is associated with load growth?

11 A And Idaho would be, I think I heard last

12 night is four percent, something like that. Now, those

13 are very rough and I'm taking them off the top of my

14 head, so please understand. It was a lot of money,

15 though.

16 Q Well, I guess that brings me to a question

17 I'm kind of confused on, maybe you could help clarify, if

18 you would turn to page 16, lines 18 through 23, and there

19 you say, "To make matters worse, loads were less than

20 expected...," so early on, I guess at page 2 when you

21 talk about load growth, you're saying that load growth

22 was a problem, it cost a lot of money, now you're saying

23 that -- I mean, I'm just trying to compare the two --

24 you're saying that load growths were less than expected,

25 so is there really a dollar impact if it didn't

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Wilder, Idaho 83676 PacifiCorp

1 materialize what you expected?

2 A Yeah, I think you need to look at the

3 context of my testimony, which is really kind of a time

4 horizon as you think about it. We have to plan well in

5 advance of what our obligations are. It's changing all

6 the time. I don't know what loads are going to be four

7 months from now. I have a good idea based on historical

8 information that I have and we do a lot of studies and we

9 can try and forecast that. I don't know how my thermal

10 is going to operate. I don't know what kind of hydro

11 resources I'm going to have; so as we're planning through

12 time, we're making decisions.

13 The way this market was and the high

14 volatility it was, there is an exhibit I have, I think

15 it's an exhibit that I might call your attention to,

16 Exhibit 1, you can see how prices changed through this

17 period of time that we're trying to make decisions on

18 buying resources to meet customer needs, so what happened

19 when -- the testimony, I believe it was on page 18 or 16

20 that you just indicated, what I'm talking about there is

21 after the FERC order and after the FERC order, what

22 happened was we had a precipitous drop, so if we look at

23 June 2001 when the FERC order came out on the left column

24 and if you go over to, let's say, August and July of that

25 summer, you can see that in May 2001, the market prices

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1 for July deliveries were $359 a megawatt-hour. Right

2 after the FERC order came out in June 2001, deliveries

3 for July went to $77 and so here we are planning, trying

4 to meet our customers' needs and we're having to buy in

5 these high prices that were back before this time period

6 and then, all of a sudden, with the precipitous drop, my

7 testimony is referring to what happened to the Company at

8 that point in time.

9 What happened to the Company at that point

10 in time is in order for us to meet our customers' needs

11 on peak, we have to buy certain products that are

12 available in the market to meet that peak demand and meet

13 it reliably. Those products in my testimony I refer to

14 as 6x16 product, which is six days a week, 16 hours a day

15 and obviously with our load shape the way it is during

16 the day, we have shoulder periods where we know we're

17 going to have to sell some of that power back to the

18 market.

19 Well, that worked fairly well to help

20 manage some of the risks the corporation had earlier on,

21 but as soon as you bought power that may have been $200

22 to meet a July need and your opportunity to sell your

23 shoulders because you can't sell those in advance, you

24 sell them in either day-ahead or real-time markets, their

25 value went to 77. I couldn't make up -- I mean, there

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1 was a huge loss taken into account there.

2 Then when loads went away because it was a

3 mild year, I had $354 power, whatever, I mean, there's a

4 whole bunch that were there of different values, but then

5 I didn't need the peak resources, so I had the load,

6 actually I was selling it at even lower prices, so that's

7 what I'm referring to here is that the load didn't

8 materialize like I thought it would and then I had to

9 sell those resources back to a market that was far less

10 than the market that we purchased the power in. Did that

11 help explain it?

12 Q It did. Let me just kind of ask you a

13 question now. You actually, did you not, have to

14 purchase on the market for wholesale contracts you had?

15 A Well, if I could --

16 Q I guess what I'm asking, let me just kind

17 of follow through, I guess my question that I'm leading

18 to is on your purchasing, you purchased both long term or

19 forward and then you also had the short term, probably

20 daily purchases; is that correct?

21 A It was a combination, yes.

22 Q And so to cover the load in Idaho, was that

23 with your long-term purchases or your short term?

24 A Both.

25 Q Both?

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1 A Both.

2 Q Like can you give me a percentage or

3 approximately how much short-term buying you did for the

4 Idaho load and how much long term and with your long-term

5 wholesale contracts, how much of it was long term and how

6 much of it was short term?

7 A I'm going to do my best to answer all those

8 questions.

9 Q I'm sorry, I can go back and ask them one

10 at a time.

11 A If I could call your attention to page --

12 Q I guess my concern is, I'd like to know how

13 much of your purchases for the Idaho load was on a

14 long-term or forward basis and how much of it was short

15 term, because in reading some, I think there's been some

16 points made that maybe the long-term purchases were for

17 the wholesale customers and the Idaho load got hit more

18 with the short term and that was more costly. That's

19 what I'm trying to find out.

20 A I'm going to answer that question in

21 several -- I think I need to give some context first.

22 When we look at our obligations, our wholesale

23 obligations or firm obligations, just like we have firm

24 obligations to our retail customers, our short-term

25 wholesale sales are not -- I mean, they may be sold as

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1 firm, but they're very short term and those decisions are

2 made on a short-term basis, so I'm going to characterize

3 this only to our long-term firm obligations to our

4 customers, both retail and wholesale.

5 On page 12, there is a table, Table 1, and

6 what this shows is that of our total system load, and

7 this is long-term wholesale commitments and retail load,

8 our net short-term purchase requirement, which means we

9 do a lot of short-term sales, too, so I have netted our

10 short-term sales with our short-term purchases and

11 matched them up, each year you can see that by -- in the

12 time period we're talking about here, I had about 3.7

13 million megawatt-hours of short-term, net short-term,

14 purchases required to meet those firm obligations, which,

15 as you can see, was about 7.1 percent of our total system

16 requirements, so everything else, all the thermal, all

17 the hydro, everything else represented about 93 percent;

18 so on the short-term markets, it was about 7.1 percent.

19 On page 11, I describe that taking into

20 account the fact that we sold Centralia and couldn't

21 replace it all with our long-term TransAlta purchase that

22 we purchased back on that facility, the poor hydro

23 conditions and the loss of the Hunter plant that you can

24 see in 2001, if it wasn't for those events, we would have

25 had an approximate surplus of short-term sales of 1.1

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1 percent, and the reason for that was, and it's not in my

2 testimony here because we only had direct testimony, but

3 it probably would have been in my rebuttal testimony, is

4 that there was about eight long-term sales contracts

5 entered into in '96 to '98 that have been an issue in

6 other cases. Those were timed to end when we thought

7 resources would be needed to serve retail customers, and

8 my point of this testimony is most of those contracts are

9 all gone today. In fact, I think November is -- the last

10 one drops off in November, but during this time, some of

11 them were still there.

12 My point being is that as we planned to

13 meet our customers' needs long term, trying to match

14 exactly your resources and requirements is a very

15 difficult task, but they were designed to drop off those

16 contracts and other long-term contracts as our load

17 growth grows in to requiring our resources. My point

18 here is that these were starting to drop off during this

19 time and my short term -- I actually would have had

20 short-term sales surpluses of about 1.1 percent during

21 2001 if I would have had the resources that I thought I

22 was going to have when we made the decisions to enter

23 into those sales contracts; so for instance, when we

24 entered into the sales contracts in '96 to '98, I didn't

25 know we were going to sell Centralia, so my point being

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1 to try and answer your question is I look at our firm

2 obligations and our wholesale obligations are just as

3 important to meet those commitments as it is to retail

4 customers because the FERC has told us that those are

5 firm commitments and they need to be met.

6 It would be like if I bought firm power

7 from some other entity thinking I was going to use it to

8 serve load and it wasn't there, so pretty much the same

9 requirements are on me, the same obligation, so with

10 that, in our planning, we had thought that we were going

11 to ease right into our retail load and resources would

12 come back available. The problem here is we lost a bunch

13 of resource during this period and I was also in a very

14 extraordinary market condition.

15 Absent the extraordinary market condition,

16 those contracts under the conditions that they were

17 entered into provided a benefit to retail customers and

18 they did when they entered into them and if prices would

19 have stayed roughly the same, that would not be an issue

20 here, but I did want to get that out because I know that

21 has been an issue in some of the discussions that I heard

22 last night.

23 Q Just a couple more questions. When the

24 market price dropped back pretty much to normal in July

25 of 2001, I'm just kind of curious, although your deferral

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1 goes through October --

2 A Correct.

3 Q -- so it would be July, August, September,

4 and October, how much additional cost is in this deferral

5 to cover power that you had committed to at a higher

6 price, that you still had committed to buy at a higher

7 rate than what market might have been in those months, do

8 you know?

9 A I may be confused on your question. Are

10 you asking me how much more power that we bought that has

11 yet gone to delivery or back during last summer?

12 Q I'm asking you what the additional cost the

13 Company incurred by the commitments of contract purchases

14 you had for the last four months of this deferral period

15 when the prices had dropped back to normal or I guess I'm

16 asking you, were the customers in Idaho able to benefit

17 from the market prices that dropped back in July, August

18 and September or were they still committed to a

19 higher-priced power that you had committed to earlier?

20 A We were committed at that point to those

21 contracts.

22 Q So they didn't benefit to the market price

23 of power over the last four months of the deferral

24 period?

25 A I'm sure in some cases they did on some of

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1 our daily and real-time purchases and sales. One of the

2 things we do every day and even out through the period is

3 because of our system in that we do touch all markets, we

4 feel it's our job to optimize that system the best we

5 can, so even during times where we may not have

6 obligations, we feel it's our obligation to fill our

7 transmission lines and take the value differences out of

8 markets that may be in the Northwest compared to the

9 desert, so there's a lot of that activity that takes

10 place and it's very low risk business, because you're

11 just matching a purchase with a sale and using your

12 system to monetize that value for our customers.

13 In the case of last summer, we were

14 committed to, and I turn you to Exhibit 2 which may help

15 with this question, you can see the contracts that we

16 entered into and the month we entered into them, so in

17 the far left column, that was the year, the month and you

18 see above that it says "Done Date," the done date was the

19 date that we entered into that transaction, and then you

20 can see what the prices were. If you follow that on

21 down, the top graph is the dollars, the next section is

22 megawatt-hours and the next section shows you the dollars

23 per megawatt-hour for all of those purchases, so in that

24 case, you can see these were the costs that were incurred

25 for us in purchasing power to meet our customers' needs

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1 during that time period, and so when the prices dropped

2 after the FERC order and we were only able to sell some

3 of the excesses at a lot lower prices, that's what hurt

4 the Company during that time period and the Company did

5 make a financial statement to the extent of the losses

6 that we incurred during that quarter.

7 Q That's fine. My last, and this is my last,

8 question, you talk about the Company, you refer to as

9 shoulder position, do you recall that in your testimony?

10 A Uh-huh.

11 Q What was the purpose of the Company going

12 with this concept?

13 A Well, the purpose of the Company going with

14 this concept is we had lost a bunch of resources. Summer

15 is our peak requirement on the east side of our system.

16 We are required to buy power to meet some of that peak

17 obligation. The problem is our market isn't real great

18 for product design. It would be nice if we had a market

19 like England that you can buy power in four-hour blocks,

20 but we're pretty much blocked into a 6x16 product in our

21 market and a 6x8 plus 24 on Sunday, the light load hour

22 product. We don't have a lot of flexibility.

23 Once in awhile you can find some super peak

24 product, but it's usually not until you get closer to the

25 time of delivery and during this time period the risks

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1 were so great of taking any type of position into very

2 near-term markets that we were very concerned about

3 reliability and service to customers. California, I have

4 another exhibit that shows you the number of declarations

5 they had as Exhibit 3 and these are things that we

6 factored in and as we knew what was happening, the summer

7 of 2001 was even supposed to be worse than the summer of

8 2000, so we didn't want to be caught short, we didn't

9 want to be in the high volatility markets, we made our

10 decisions in advance because we believed that was the

11 best way to minimize those risks. Absolutely every day I

12 worked was unprecedented during that time period.

13 COMMISSIONER HANSEN: Well, thank you very

14 much for your answers.

15

16 EXAMINATION

17

18 BY COMMISSIONER SMITH:

19 Q I guess I just had two and you just touched

20 on one of the areas. In your years of planning, is it

21 ever acceptable to not cover?

22 A Load?

23 Q Load.

24 A We do have some interruptible contracts and

25 interruptible customers. Most of those interruptible

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1 customers are solely for system integrity. If I can buy

2 power from the market under most of those contracts, I

3 have to. If I can't find the power and power is still

4 needed, then I have a right to trip the loads of some of

5 our larger customers, but the instructions that I have,

6 that I'm aware of, is economics is not just justification

7 to curtail customers' requirements or load and so we will

8 buy to meet customers' requirements.

9 To be quite honest, Commissioner, I would

10 love nothing more than to have someone in the rules say

11 if markets get to 800, you can do something different or

12 some level to cap the risk of this market, because I'm

13 sure you're aware, most people are saying that the

14 electricity market is the most volatile market in the

15 world and will be because we can't store it very

16 effectively and as such, we will have times where we may

17 see this again.

18 I never thought we'd see this to begin

19 with, especially in the Northwest or in the West at all,

20 but once we have, we have a requirement to serve and

21 that's what we go by, and if we can't find the power,

22 then that's what California did, they could not get the

23 power, they finally had to have their curtailments, but

24 there is no economic test that I know of.

25 Q Well, I once suggested one and it was made

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1 very plain to me by customer letters to the governor's

2 office that that was a very dangerous suggestion, that if

3 the price went to $1,000 a megawatt-hour, you just don't

4 buy it.

5 A I think in some respects that can be a very

6 effective policy because you can roll through your load,

7 you can roll through it and only disrupt people for about

8 an hour.

9 Q But customers expect that when they want

10 power, it's there.

11 A And that's what our marching orders are.

12 Q Commissioner Hansen had mentioned a couple

13 of times now that prices are back to normal, is this

14 normal and what's summer look like, because I've heard

15 that the resources that California thought they were

16 going to get, a lot of them didn't materialize, that the

17 load is growing again because we're out of the economic

18 slump and we may be back in the summer of 2000 mode?

19 A Normal to me, I think normal has changed

20 for the West. I think most of us that have been around

21 the industry for a long time know that we pretty much saw

22 prices maybe go up into the low 30s. They mainly

23 fluctuated in the 20s to middle 30s. Gas is now on the

24 increment. It's becoming more of a driver in incremental

25 resources, so as gas prices move, you will see

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1 electricity markets follow.

2 Recently we have seen markets return more

3 to normal. I mean, the one sheet I showed you, they

4 still weren't quite normal last summer, I mean $70. I

5 use to get phone calls when it was $100 for one hour.

6 I'd get a phone call to tell me that markets had went to

7 that, but $70 is quite high. For this summer right now,

8 Palo Verde prices this morning were at $48 for the full

9 summer season. Normal to me would have been about 42, I

10 would have expected about that. Mid Columbia is about

11 $40.00. That's the highest three months of the year, so

12 to me things at least out forward look more normal, but

13 normal by any means should not be compared to five years

14 ago.

15 You need to take into context what the gas

16 market is doing and it has fundamentally changed the

17 Western market, so it has moved it up a little bit.

18 We're no longer a coal-based and hydro-based system and

19 so normal to me, you've ratcheted it up a few more

20 mills. We are still seeing -- some of the plants were

21 far long enough that were being built that they are still

22 continuing on their course. Some have been canceled.

23 The economy has definitely slowed down

24 loads since 9/11. We have seen it in our own system that

25 loads are a lot lower than they were prior to 9/11. I

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1 don't expect too many surprises this summer. Maybe a

2 week or two of hot weather we may see some, but I don't

3 expect any big surprises.

4 California has done a lot to fix their

5 problem. They have bought a lot of long-term forward

6 power which will tend to alleviate some of the issues

7 that we all faced before.

8 COMMISSIONER SMITH: Thank you.

9 Commissioner Kjellander.

10 COMMISSIONER KJELLANDER: Just one.

11

12 EXAMINATION

13

14 BY COMMISSIONER KJELLANDER:

15 Q Kind of to piggyback off of the word you

16 used, "surprises," just a moment ago when you said that

17 you didn't expect any this year, but last year as you

18 looked at your load projections, you were somewhat

19 surprised at what you saw in the late summer with regard

20 to load reductions; was that a fairly correct

21 characterization?

22 A Well --

23 Q Yes or no?

24 A Yes.

25 Q Okay. With that in play, then, how typical

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1 or atypical was this surprise as far as the load

2 reduction was concerned? Could you put that in a brief

3 historical context? Had you seen anything like that in

4 your estimations over the last decade?

5 A Yes. I mean, I think summer of 2000 was

6 extremely hot, so that's kind of on the other side of the

7 coin and loads are moving all along. It kind of goes

8 back to I was talking about hydro and how you plan for

9 resources, you can only look out and plan on what you

10 think you're going to see and then weather throws you

11 kind of a curve, and I believe last summer was out on the

12 end of probability tails as far as mild summers are

13 concerned and so yeah, you plan within a range, but you

14 do get those exogenous events and we saw a lot of those

15 during this time period.

16 COMMISSIONER KJELLANDER: Thank you.

17 COMMISSIONER SMITH: Any redirect,

18 Mr. Fell?

19 MR. FELL: Just one question.

20

21 REDIRECT EXAMINATION

22

23 BY MR. FELL:

24 Q You testified about your need to buy power

25 at high prices and then being stuck with selling excess

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1 power at low prices, was PacifiCorp unusual as a load

2 serving utility in facing that problem?

3 A No, just about every utility in the West

4 faced the same problem. We've seen Avista, Idaho Power,

5 Portland General, Puget, Seattle City Light, EWEB,

6 municipal-owned, investor-owned, bankrupt companies in

7 California and now who knows with Sierra and Nevada Power

8 what's going to happen to those companies.

9 COMMISSIONER SMITH: Could you identify

10 "EWEB" for the record?

11 THE WITNESS: Oh, Eugene Water and Electric

12 Board.

13 MR. FELL: Thank you. I have no other

14 questions.

15 COMMISSIONER SMITH: Thank you for your

16 testimony, Mr. Watters.

17 (The witness left the stand.)

18 MR. FELL: And were there any follow-up

19 questions from the Commissioners for Mr. Widmer, anything

20 that might have been referred by Mr. Watters to

21 Mr. Widmer that you'd like to follow up on?

22 Commissioner Hansen asked some.

23 COMMISSIONER SMITH: We'll be at ease for a

24 moment.

25 (Pause in proceedings.)

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1 MR. FELL: The next witness will be Mr. Joe

2 Goodrich, please, and as I mentioned earlier,

3 Mr. Goodrich will respond to issues contained in the

4 prefiled testimony of Mr. Cunningham.

5

6 HOWARD JOE GOODRICH,

7 produced as a witness at the instance of PacifiCorp,

8 having been first duly sworn, was examined and testified

9 as follows:

10

11 DIRECT EXAMINATION

12

13 BY MR. FELL:

14 Q Mr. Goodrich, would you please state your

15 name and spell your last name for the record?

16 A Howard Joe Goodrich, G-o-o-d-r-i-c-h.

17 Q Mr. Goodrich, what is your position with

18 PacifiCorp?

19 A Managing director in generation department.

20 Q Would you explain what background you have

21 in generation facilities?

22 A I've worked my career in the power plants,

23 from engineering plant manager at the Carbon plant, plant

24 manager at the Hunter plant, at the Dave Johnston plant

25 and just recently working in the generation office at One

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1 Utah Center in implementing the transition plan.

2 MR. FELL: Thank you. With that, I offer

3 Mr. Goodrich for questioning.

4 COMMISSIONER SMITH: Thank you, Mr. Fell.

5 Commissioner Hansen.

6 COMMISSIONER HANSEN: Thank you.

7

8 EXAMINATION

9

10 BY COMMISSIONER HANSEN:

11 Q Mr. Goodrich, on page 20 of

12 Mr. Cunningham's testimony, line 17, he says the Company

13 has not been able to determine the cause of the failure

14 of the Hunter unit. Have you found that?

15 A Yes.

16 Q And I guess I have a hard time

17 understanding in this day and age that we live in that in

18 one-and-a-half years since the failure, completely taking

19 the unit apart and rebuilding it that the Company is not

20 able to determine the failure and what caused it and I

21 guess my question is, isn't this very unusual that the

22 Company cannot determine the cause? And a second

23 question, is this the case in most of the failures the

24 Company has in their generation units that they never can

25 determine the cause of the failure?

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1 A Specifically what this means is we know

2 what happened, we know where it happened, we know how it

3 happened, what we don't know is why it happened. We do

4 know that there was a lamination short in the iron deep

5 within the core of the generator and that it resulted in

6 high temperatures that melted through the core. We know

7 that it was five to six feet in from the exciter end of

8 the generator, but the reason we don't know the why is

9 because it was burned up.

10 The initiation site was destroyed through

11 the high heat and melted away and so that's the reason

12 that Mr. Cunningham stated it in this manner is that we

13 can't determine exactly what happened because the

14 evidence is gone.

15 Q I see. On line 6 you say a number of

16 potential causes remain, do you see that or

17 Mr. Cunningham said that?

18 A On line 6?

19 Q I believe that's the same --

20 A On the next page, 21?

21 Q Right, on the next page, and I guess why

22 didn't Mr. Cunningham identify the potential causes that

23 remain? I think that would be very beneficial if we knew

24 what those were.

25 A I don't know why he didn't identify those.

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1 Q Is the Company the only one that knows or

2 other parties, has it been made available to other

3 people?

4 A We had a number of experts do the

5 evaluation, consultants. We had the OEM, the original

6 manufacturer, Westinghouse. We hired a company that

7 specializes in failure analysis out of Palo Alto,

8 California and my understanding is that there are some

9 speculative things that might have happened in that area,

10 but to specify exactly why Mr. Cunningham didn't

11 elaborate on this, I don't know that.

12 Q Is it possible that some of the potential

13 causes could be attributed to the Company's maintenance

14 practices?

15 A No.

16 Q Have you changed some of the maintenance

17 and operating practices since the merger?

18 A No, not to my knowledge.

19 Q So you haven't made any changes since the

20 merger to how you maintain or operate generation plants?

21 A With generators, is that what you're asking

22 specifically?

23 Q Yeah.

24 A Not to my knowledge as to how we were

25 operating this generator at that time, no.

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1 Q That's kind of interesting to me because I

2 guess I thought back in the merger case, in my mind,

3 there was some testimony saying that under the merger

4 that plant operations could be more efficient and run

5 different and so I'm just curious, but you're saying to

6 your knowledge, they haven't made any changes in how they

7 maintain and how they operate?

8 A Excuse me, I thought you were asking

9 specifically about the generator and how the generator

10 was operated and maintained.

11 Q Right.

12 A If you're asking general, we're doing a

13 number of things to try and improve productivity, just

14 continuous improvement in how we both maintain and

15 operate, that's correct, but those are just general in

16 all aspects of doing business.

17 Q So it could have affected the Hunter plant,

18 you don't know; is that right?

19 A I'm not sure whether -- if you're asking

20 have we changed our maintenance practices with regards to

21 how we operate and maintain the generator, I'd have to

22 say no, I don't know of any specific issues as to how we

23 operate and maintain the generator itself that's

24 changed. How we manage work, plan work, how we organize

25 ourselves, we've had continuous improvements in those

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1 areas, yes.

2 Q So there has been some changes made, then,

3 in how the Company maintains and operates the generators

4 since the merger? I guess I need a yes or no.

5 A Well, I'm not sure I can answer

6 specifically maintains the generator as to how -- what we

7 have been focusing on is general operation practices of

8 running a power plant, how we are organized within our

9 power plants. Those types of changes have taken place,

10 but for me to address specifically that we have changed

11 the maintenance practices of our generators or the

12 operations practice of our generators, I am not

13 personally aware of that.

14 Q So, for example, you're not aware that you

15 may have changed from inspecting or maintaining a

16 generator, say, on a three-year cycle to a five-year

17 cycle, to your knowledge, you haven't done anything like

18 that?

19 A We have not changed that decision process

20 that we go through at any of our generators that I'm

21 aware of. We follow the same decision process to

22 determine the length between overhauls as was previously

23 being followed.

24 COMMISSIONER HANSEN: Thank you very much.

25 That's all the questions I have.

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1 COMMISSIONER SMITH: Redirect, Mr. Fell?

2 MR. FELL: Yes, just a little bit.

3

4 REDIRECT EXAMINATION

5

6 BY MR. FELL:

7 Q Mr. Goodrich, there was -- the Company

8 hired more than one consultant, did they not? I refer

9 you to page 20 where it identifies two other consultants

10 on line 9.

11 A That's correct, I believe there were four

12 consultants, plus a failure analysis group.

13 Q And the insurance company for the --

14 A And the insurance company was separate,

15 that's correct.

16 Q And none of them have identified any

17 failures on PacifiCorp's part that would have caused the

18 generator failure?

19 A That is correct, there was nothing

20 identified.

21 Q And this generator, I refer you to page 21,

22 line 11, was overhauled in 1999?

23 A That is correct.

24 Q So you would not expect a failure -- well,

25 it would be unusual to have a failure so soon after an

246

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Wilder, Idaho 83676 PacifiCorp

1 overhaul, I assume; is that correct?

2 A That would have been unusual. In fact, we

3 got -- the OEM made statements that it was in highly

4 reliable condition when returned to service.

5 COMMISSIONER SMITH: Mr. Goodrich, can you

6 tell us what OEM is?

7 THE WITNESS: Original equipment

8 manufacturer.

9 MR. FELL: No further questions.

10 COMMISSIONER SMITH: Thank you for your

11 testimony. Oh, Mr. Shurtz?

12 MR. SHURTZ: May I?

13 COMMISSIONER SMITH: Yes.

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15 CROSS-EXAMINATION

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17 BY MR. SHURTZ:

18 Q Has Scottish Power since taking over

19 management instituted -- what changes have they

20 instituted?

21 A I'm not quite sure how to answer that, but

22 let me elaborate on --

23 Q As far as the operation of your plants.

24 A We are always in a continuous improvement

25 mode and we did go through a transition plan that I

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Wilder, Idaho 83676 PacifiCorp

1 believe you're aware of that we looked at in great detail

2 as to where we might have improved productivity and from

3 that there was an early out, early retirement where a

4 number of people eligible chose to accept that early

5 retirement, so that came, I think, maybe in direct answer

6 to your question, from Scottish Power and following the

7 merger, but I have to say that we are part of that

8 philosophy in continually looking for opportunities for

9 improvement and so I'm reluctant, frankly, to say that we

10 are being directed to do any of these from Scottish

11 Power.

12 Scottish Power is constantly encouraging us

13 to look for opportunities for improvement, but there's

14 not been any mandate this is how you're going to operate

15 your power plants that's come down from Scottish Power.

16 Q Okay, you mentioned that some experienced

17 or long-term employees took an early out, would you have

18 a rough guesstimate of what the percentage of those

19 senior employees were in the generation area?

20 A Within the thermal plants, there were --

21 you asked for a rough estimate, so let me -- 12 percent.

22 Q Okay, and again, these were some of your

23 most senior individuals?

24 A The requirements for the early out was 55

25 years old and 20 years' experience.

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Wilder, Idaho 83676 PacifiCorp

1 Q Since this happened, I know Commissioner

2 Hansen asked sort of the same question, have you done any

3 preventive protocols or done anything to examine what

4 happened and say can we prevent this from happening in

5 the future?

6 A In this particular case?

7 Q Such as the Hunter 1.

8 A As I explained earlier, there have been

9 numerous experts, consultants hired to evaluate and to

10 look for opportunities and what came from all of that was

11 that this was a very unusual failure that happened deep

12 within the generator core itself and that there was

13 nothing learned, to my knowledge, that stated we need to

14 change our operation practices, nor our maintenance

15 practices with how we operate or maintain generators.

16 Q You also mentioned that your insurance

17 looked at it. How much insurance was collected if you

18 don't mind me -- I guess I can ask that. One, was it

19 insured and how much was it?

20 A In the testimony, let me see if I can find

21 exactly where it is --

22 MR. FELL: Page 22.

23 THE WITNESS: -- page 22 and these are

24 projected costs because all of the costs at this time

25 when the testimony was issued had not been in and I'm not

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Wilder, Idaho 83676 PacifiCorp

1 aware of any changes to this, but the total cost of the

2 project was approximately $17.5 million. Of that, the

3 insured portion was 16, almost $17 million, 16.99

4 million. There was a deductible of $2.25 million, so

5 that left the Hartford Insurance group with the

6 responsibility of paying $14.74 million.

7 Q BY MR. SHURTZ: Okay, also when the Hunter

8 plant went down, it went down on November 28th of 2000?

9 A Actually, November 24th, the day after

10 Thanksgiving.

11 Q Okay, I saw the 28th was on something I

12 looked at, I'm sorry, on the 24th, in and around

13 Thanksgiving weekend, as the operators, did you have a

14 pretty good idea once you saw that everything was melted

15 down and all you had was molten steel laying all over the

16 place, did you have an idea of how long -- project how

17 long it would take before the Hunter plant would be back

18 up in operation? Did you have a rough idea of -- you

19 know, I see it went back up in operation May 8th, 2001,

20 did you have that type of time frame in mind?

21 A What I heard at that time is this is going

22 to be a long outage, so there was an investigation

23 process that had to take place there, but we knew that it

24 would be down for months, but at that very early date, I

25 don't remember hearing right within -- like, I think

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1 you're asking the first few days as to the extent of the

2 outage and we didn't get those projections for quite

3 awhile.

4 Q No, I'm looking at -- we're talking

5 December, January, so I'm just wondering if at some point

6 that you had a pretty good idea of what your lag time

7 would be in bringing that plant back into operation.

8 A By that time we were projecting late April,

9 early May.

10 Q You're aware of the Oregon case, UM-855 --

11 COMMISSIONER SMITH: Is this within the

12 scope of the testimony?

13 MR. FELL: The testimony, Madam Chair, does

14 not discuss the Oregon case.

15 COMMISSIONER SMITH: I think that's beyond

16 the scope of this witness' testimony, Mr. Shurtz.

17 MR. SHURTZ: Okay, sorry. I have no more

18 questions, thank you.

19 COMMISSIONER SMITH: Thank you. Any other

20 redirect?

21 MR. FELL: Perhaps it would be more

22 efficient for me to just state that the request in this

23 case does not include any of those capital costs that

24 were subject to insurance or the deductible.

25 COMMISSIONER SMITH: Thank you.

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Wilder, Idaho 83676 PacifiCorp

1 MR. FELL: No further questions.

2 COMMISSIONER SMITH: Thank you,

3 Mr. Goodrich.

4 THE WITNESS: Thank you.

5 (The witness left the stand.)

6 MR. FELL: Madam Chair, may we then excuse

7 the witnesses whose testimony has already been

8 presented?

9 COMMISSIONER SMITH: Without objection, all

10 of the witnesses whose testimony has been previously

11 spread upon the record are excused from this proceeding.

12 MR. FELL: Thank you. Could we take a

13 minute and let them leave the room?

14 COMMISSIONER SMITH: We'll be at ease for

15 about ten minutes.

16 (Recess.)

17 COMMISSIONER SMITH: All right, we'll be

18 back on the record. Mr. Fell.

19 MR. FELL: Yes, the Company's next witness

20 is Robert Lively.

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1 ROBERT C. LIVELY,

2 produced as a witness at the instance of PacifiCorp,

3 having been first duly sworn, was examined and testified

4 as follows:

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6 DIRECT EXAMINATION

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8 BY MR. FELL:

9 Q Mr. Lively, would you please state your

10 name and business address?

11 A My name is Robert C. Lively. My business

12 address is One Utah Center, Suite 2300, 201 South Main

13 Street, Salt Lake City, Utah.

14 Q And are you sponsoring testimony in this

15 proceeding?

16 A I am.

17 Q And are you also sponsoring exhibits

18 numbered 20 and 21, I believe they are; is that correct?

19 A I am, yes.

20 Q If I were to ask you today the questions

21 that are contained in your prefiled testimony, would your

22 answers be the same?

23 A Yes.

24 MR. FELL: I move that the testimony of

25 Mr. Lively be spread on the record as if read.

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1 COMMISSIONER SMITH: If there's no

2 objection, the prefiled testimony of Mr. Lively will be

3 spread upon the record as if read and Exhibits 20 and 21

4 will be admitted.

5 (PacifiCorp Exhibit Nos. 20 & 21 were

6 admitted into evidence.)

7 (The following prefiled testimony of

8 Mr. Robert Lively is spread upon the record.)

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1 Q Please state you name and business address.

2 A My name is Robert C. Lively. My business

3 address is One Utah Center, Suite 2300, 201 South Main

4 Street, Salt Lake City, Utah 84140-2300

5 Qualifications

6 Q Please describe your employment history

7 with PacifiCorp (or the"Company").

8 A I joined the Company in 1983 in the

9 accounting department and have held various accounting,

10 regulatory, and customer account management positions

11 prior to assuming my current position in 1997.

12 Q What is your current position at the

13 Company? I am Manager, Regulation at PacifiCorp.

14 Q What are your responsibilities as Manager,

15 Regulation?

16 A My responsibilities include management of

17 regulatory proceedings principally in Idaho and Utah.

18 This includes management of rate cases, stipulations,

19 contract negotiations, and other regulatory proceedings.

20 I also assist and advise in the development of the

21 Company's regulatory policy.

22 Q What is your educational background?

23 A I graduated from the University of Utah in

24 1980 with a Bachelor of Arts Degree in Accounting. I am

25 a licensed CPA in the State of Utah and I have served on

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1 the board of Directors of the Intermountain Electrical

2 Association. I have also attended various educational,

3 professional and electric industry related seminars

4 during my career at the Company.

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1 Purpose of Testimony

2 Q Are you familiar with the terms and

3 conditions of the Stipulation before the Commission?

4 A Yes.

5 Q What is the purpose of your testimony.

6 A The purpose of my testimony is twofold:

7 First, I will describe and support the Stipulation among

8 Staff of the IPUC ("Staff"), the Company, the Idaho

9 Irrigation Pumpers Association ("IIPA") and Monsanto

10 Company ("Monsanto") (collectively referred to as

11 the "Parties") in Case No. PAC-E-02-1 (the

12 "Stipulation"). The Stipulation, which was filed with

13 the Commission on April 11, 2002, is identified as

14 Exhibit No. 20. Second, I will address the matters

15 identified as "at issue" in the Commission's Notice of

16 Issue Identification and Scheduling.

17 Background

18 Q Please describe the events precipitating

19 the Company's application for deferral of its excess net

20 power costs.

21 A Beginning in May 2000, electric utilities

22 began to experience an unanticipated and extraordinary

23 increase in wholesale power prices. Between May 2000 and

24 November 2000 alone, PacifiCorp incurred approximately

25 $228 million in excess net purchased power costs on a

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1 total Company basis (approximately $11 million on a Idaho

2 jurisdictional basis). PacifiCorp's situation became

3 even worse in November when the Company was forced to

4 purchase additional replacement

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1 power as a result of the forced outage of one of its

2 major generating facilities, Hunter Unit Number 1.

3 Faced with an increasing disparity between the

4 purchased power costs it was recovering in its prices and

5 the costs it was incurring, on November 1, 2000,

6 PacifiCorp filed an Application in Case No. PAC-E-00-5

7 for approval to defer excess net power costs incurred

8 from November 1, 2000 through October 31, 2001. In

9 Commission Order No. 28630, the Commission approved the

10 Company's request for deferred accounting of those excess

11 power costs. That order also permitted the Company to

12 request recovery of carrying charges when it applied for

13 ratemaking treatment of the amounts deferred. Pursuant

14 to the Commission's order, the Company deferred $37

15 million in excess power costs, including replacement

16 power costs related to the outage of the Hunter Unit

17 Number 1 generator.

18 Q Please describe Exhibit No. 21.

19 A Exhibit No. 21 shows a timeline quantifying

20 the excess purchased net power costs incurred between May

21 2000 and October 31, 2001. The timeline breaks out the

22 total Idaho-related excess net power costs of $49 million

23 into two parts. The first part being $11 million

24 incurred from May 2000 through October 2000. This amount

25 was borne by the Company's shareholders and is not being

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PacifiCorp

1 requested from Idaho customers. The second amount, for

2 which the Company seeks recovery in this proceeding, is

3 the $38 million of excess net power costs (including

4 $1 million of carrying charges) incurred from November 1,

5 2000 through October 31, 2001.

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PacifiCorp

1 The Company's excess power costs were deferred under

2 terms of the Commission's order previously described.

3 The Stipulation, if approved by the Commission, allows

4 the Company to recover $25 million (or approximately

5 51%), of the total Idaho-related excess net power costs.

6 Q Please describe the background of the

7 Stipulation.

8 A On January 7, 2002, PacifiCorp filed the

9 Application in this case seeking to recover over a two

10 year period its deferred excess net power costs, plus

11 carrying charges, amounting to approximately $38. The

12 Company further proposed electric service schedules that

13 would adjust rates to bring customer classes closer to

14 the cost of serving the respective classes. In addition,

15 the Company proposed a Rate Mitigation Adjustment

16 designed in such a way that no customer class would

17 receive a price increase during the two-year period of

18 the surcharge for recovery of the deferred excess net

19 power costs. Finally, the Company also proposed an

20 increase to the Electric Service Schedule No. 34-BPA

21 Exchange Credit to reflect the increased benefit from

22 settlement with the Bonneville Power Administration

23 regarding residential exchange benefits.

24 On January 31, 2002, in its Order No. 28946, the

25 Commission approved Electric Tariff Schedule 34-BPA

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PacifiCorp

1 Exchange Credit using Modified Procedure, i.e., by

2 written submission rather than by hearing. The remainder

3 of the Company's filing was processed separately as

4 specified herein.

5 On February 19, 2002, a prehearing conference was

6 held in Boise, Idaho. At that conference, the parties

7 and the Commission identified a nonexclusive list

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PacifiCorp

1 of matters to be "at issue" in this proceeding and the

2 Commission adopted a procedural schedule.

3 Settlement discussions were held among the parties

4 on March 5, 20 and 28, 2002. As a result of those

5 settlement conferences, the Parties to the Stipulation

6 reached an agreement detailed in the Stipulation and

7 described in the testimony below.

8 Terms of Stipulation

9 Q Please summarize the Stipulation.

10 A Simply stated, the Stipulation allows the

11 Company to recover approximately 65% of its deferred

12 excess purchased power costs (plus carrying charges), or

13 51% of the total excess purchased power costs it incurred

14 to serve Idaho customers between May 2000 and October 31,

15 2001. The Parties have agreed to support the Company's

16 recovery, through a surcharge and the acceleration of the

17 "Merger Credit," as described below, of $25 million of

18 its $37 million in deferred excess power costs through a

19 Power Cost Surcharge. The Parties have also agreed 1) to

20 the manner in which the revenue obligations will be

21 spread among the classes as reflected in Attachment B to

22 the Stipulation, 2) to redesign Electric Service Schedule

23 10 in accordance with Attachment C to the Stipulation,

24 and 3) to implement a modified Rate Mitigation Adjustment

25 as a line item charge on customers' bills through

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PacifiCorp

1 Electric Service Schedule 94, Attachment D to the

2 Stipulation. The Parties agree that the Stipulation

3 produces an overall just and reasonable result that is in

4 the public interest.

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1 Q Please describe how the Company will

2 recover the $25 million of deferred excess power costs

3 agreed to in the Stipulation.

4 A As a result of the Commission's order

5 ("Merger Order") in the Scottish Power merger case

6 (Case No. PAC-E-99-1), customers have received since

7 January 2000 a credit of approximately $1.6 million per

8 year from PacifiCorp that has been reflected as a line

9 item on customers' bills pursuant to Electric Service

10 Schedule No. 99 (the"Merger Credit"). If PacifiCorp were

11 to continue the Merger Credit for the full four-year

12 period reflected in the Merger Order, there would be

13 approximately $2.3 million, on a present value basis,

14 remaining to be credited to customers. Accordingly, the

15 Parties have agreed that to offset PacifiCorp's excess

16 power costs, the Merger Credit and Electric Service

17 Schedule No. 99 should be accelerated and credited to

18 reduce the Company's excess power cost recovery from

19 $25 million to $22.7 million.

20 The Parties also have agreed that PacifiCorp

21 should be allowed to implement a Power Cost Surcharge

22 designed to recover $22.7 million over a 24-month period

23 beginning May 15, 2002 and ending May 14, 2004. The

24 Power Cost Surcharge will be implemented as a line item

25 charge on customers' bills through Electric Service

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PacifiCorp

1 Schedule No. 93, Attachment A to the Stipulation. As

2 reflected in Attachment A, the Parties have agreed that

3 the Power Cost Surcharge should be tracked and that a

4 true-up surcharge or surcredit may be implemented over a

5 12-month period immediately following the 24-month Power

6 Cost Surcharge recovery period to reflect any under- or

7 over-collection of the total

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1 authorized Power Cost Surcharge amount.

2 Q Including the offsets, how much of its

3 excess net power costs will the Company recovery under

4 the Stipulation?

5 A As described in PacifiCorp Exhibit No. 21,

6 the Company will recover approximately $25 million

7 including offsets, representing approximately 65% of

8 deferred excess power costs attributable to Idaho plus

9 carrying charges.

10 Q Please describe Attachment B of the

11 Stipulation.

12 A Attachment B reflects the Parties'

13 agreement regarding the manner in which the revenue

14 obligations of the various customer classes should be

15 spread among the classes.

16 Q Please describe the modified Rate

17 Mitigation Adjustment agreed to in the Stipulation.

18 A The Parties were unable to reach agreement

19 regarding the cost of service study and Rate Mitigation

20 Adjustment originally proposed by the Company. Instead,

21 the Stipulation contains an agreed upon "modified" Rate

22 Mitigation Adjustment, which assures that no customer

23 class will see a price increase of more than 4% over the

24 two-year period of the Power Cost Surcharge. The Company

25 supports the modified Rate Mitigation Adjustment included

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1 in the Stipulation because it is directionally consistent

2 with the Cost of Service study originally filed in the

3 Company's proposal. Additionally, the modified Rate

4 Mitigation Adjustment included in the Stipulation serves

5 the purpose of moderating the impact on customer classes

6 of rate increases related to the excess net power cost

7 recovery.

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PacifiCorp

1 The modified Rate Mitigation Adjustment is

2 proposed as a surcharge or surcredit applied on a cents

3 per kilowatt-hour basis to each rate schedule and will be

4 shown as a separate line item charge on customers' bills

5 through Electric Service Schedule No. 94. In year one,

6 the modified Rate Mitigation Adjustment applies only to

7 commercial, industrial and lighting customers. In year

8 two, the modified Rate Mitigation Adjustment continues

9 and will apply to all customer classes. No customer

10 class will receive a price increase in year two. In year

11 three and subsequent years, the modified Rate Mitigation

12 Adjustment may continue, subject to termination

13 provisions contained in the Stipulation. The Parties

14 have agreed that upon the earlier of 1) the expiration of

15 the current Electric Service Schedule No. 34-BPA Exchange

16 Credit or 2) the adoption by the Commission of a cost of

17 service study for PacifiCorp and the subsequent

18 implementation for all customers of the approved cost of

19 service study by any lawful method by the Commission or

20 PacifiCorp, Electric Service Schedule No. 94 will be

21 terminated.

22 Q In comparison to rates in effect during

23 2001, please describe the overall change that customers

24 will see in their prices in year one after all of the

25 revenue components are added.

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1 A In year one, residential customers will see

2 an average price decrease of 28%. Irrigation customers

3 on average will also see a price decrease of

4 approximately 19% while, overall, commercial and

5 industrial customers will see a decrease of approximately

6 8%. Lighting customers will see an overall increase of

7 approximately 2%. This is shown in Attachment B to the

8 Stipulation, Table B1.

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1 Q Please describe the overall change that

2 customers will see in their prices in year two after all

3 of the revenue components are added.

4 A In year two, no customer class will see a

5 change from prices at the end of year one except

6 irrigation customers. Irrigation customers will see an

7 average decrease of 11%. This is shown in Attachment B to

8 the Stipulation, Table B2.

9 Q Please describe the changes to Irrigation

10 Schedule 10 agreed to in the Stipulation.

11 A The proposed Irrigation Schedule 10 agreed

12 to in the Stipulation consolidates the three rates

13 currently contained in Irrigation Schedule 10 into one

14 firm service rate. Customers previously under the three

15 load-control options have been combined and will now be

16 under one, revenue-neutral, firm service rate. In order

17 to minimize impacts on individual Schedule 10 customers,

18 the proposed service charges and demand charge are

19 calculated as the average of the three current rate

20 options, proportioned for the amount of usage under each

21 of the three rate options.

22 In addition, the two-block current on-season

23 energy charge has been revised to a three-block energy

24 charge. The three-block energy charge is designed to

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1 uniform price signals to all irrigation customers.

2 Q Please describe other essential terms of

3 the Stipulation.

4 A In response to concerns raised by the IIPA

5 concerning the loss of the Schedule 10, Irrigation Season

6 Rate C and its associated load control benefits,

7 PacifiCorp has agreed to discuss individual

8 interruptibility or load control contracts for the 2002

9 irrigation season with not more than 15 large irrigators

10 (defined as irrigators

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1 having an individual meter registering greater than 500

2 kW demand during the last 12 months) on a first-come,

3 first-served basis. Pacificorp has also agreed that it

4 will work with the IIPA and the irrigators as a class to

5 develop an optional load control program for the 2003

6 irrigation season and thereafter that would allow an

7 irrigator to participate in such program on an annual

8 basis. The Company has agreed to file its proposed

9 optional load control program with the Commission no

10 later than January 31, 2003.

11 Matters "At Issue" in this Proceeding

12 Q In its Notice of Issue Identification and

13 Scheduling in this case, the Commission identified

14 several matters as continuing to be "at issue" in this

15 proceeding. Please address the Company's position with

16 respect to the first issue identified: the Company's cost

17 of service study with related adjustments to rate design.

18 A Mr. Dave Taylor and Mr. James Zhang

19 provided a detailed cost of service study and price

20 design proposal as part of the Company's Application in

21 this proceeding. As discussed above, the parties were

22 unable to agree that the Company's proposed cost of

23 service study and related price design were appropriate

24 for implementation at this time. Although the Company

25 continues to support the original proposals as filed, the

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1 Parties to the Stipulation (including the Company) agreed

2 to a modified Rate Mitigation Adjustment in lieu of the

3 Company's proposed cost of service study and price

4 design.

5 Q Please address the Company's position with

6 respect to the second issue identified: the revenue

7 ramifications of the Company's filing.

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1 A As stated above, the Company supports the

2 modified Rate Mitigation Adjustment included in the

3 Stipulation in part because of the moderating impact it

4 has on customer classes impacted by the excess power cost

5 recovery. Under the Stipulation, some customer classes

6 would face double-digit increases absent the modified

7 Rate Mitigation Adjustment. Instead, with the modified

8 Rate Mitigation Adjustment, increases are limited to 4%

9 over the two year period of the Power Cost Surcharge.

10 Q Please address the Company's position with

11 respect to the third issue identified: the power costs

12 PacifiCorp is seeking to recover.

13 A As discussed above, the Company has

14 incurred approximately $49 million total of excess net

15 purchased power costs, attributable to Idaho between May

16 2000 and October 31, 2001. $37 million of this amount

17 was deferred by authorization of the Commission and an

18 additional $1 million would accrue as carrying charges,

19 if approved. Under terms of the Stipulation, the Company

20 agreed to recovery of $25 million of the $38 million

21 total. The recovery amount agreed to in the Stipulation

22 represents approximately 51% of the total amount of

23 excess net power costs attributable to Idaho between May

24 2000 and October 31, 2001, and approximately 65% of the

25 amount deferred between November 1, 2000 and October 31,

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1 2001 plus carrying charges.

2 Q Please address the Company's position with

3 respect to the fourth issue identified: the Rate

4 Mitigation Adjustment originally proposed by the Company.

5 A As discussed above, the Parties were unable

6 to reach agreement in settlement

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1 discussions regarding the Rate Mitigation Adjustment

2 originally proposed by the Company. For purposes of the

3 Stipulation the Company supports the modified Rate

4 Mitigation Adjustment as directionally consistent with

5 the original proposal and also because it moderates the

6 impact of the excess power cost recovery.

7 Q Please address the Company's position with

8 respect to the fifth issue identified: whether the

9 Company's attempted recovery of excess power costs

10 incurred in 2000/2001 violates Merger Approval Condition

11 No. 2. Reference Case No. PAC-E-99-1, Order No. 28213.

12 A The Company agrees with the findings of the

13 Commission in its Order Nos. 28630 (Case No. PAC-E-00-5)

14 and 28998 (Case No. PAC-E-02-1). In Order 28630, the

15 Commission found that authorization of PacifiCorp's

16 application for deferred accounting only preserved the

17 amounts deferred for future consideration. Accordingly,

18 the Commission found that "approval of PacifiCorp's

19 Application [for deferral] Will not result in a rate

20 increase at this time and thus does not violate the

21 condition that it will not seek a general rate increase

22 effective prior to January 1, 2001." Subsequently, in

23 Order 28998, the Commission clarified its Merger Order

24 and stated that the language of Condition 2 prohibited

25 PacifiCorp from seeking a general rate increase effective

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1 prior to January 1, 2002. Because PacifiCorp did not

2 seek any increase in rates to be effective before that

3 date, the Commission explained, the Company has fulfilled

4 that Condition. The Commission's clarification of its

5 Condition 2 resolved this issue.

6 Q Please address the Company's position with

7 respect to the sixth issue identified:

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1 whether it was appropriate (and perhaps prudent) for

2 PacifiCorp to enact economic curtailments of usage as

3 opposed to the alternative purchase of high cost power.

4 A In addition to purchasing power to serve

5 its customers' needs during the deferral period (November

6 30, 2000 through October 31, 2001), the Company also

7 implemented Idaho Schedule 72, a load curtailment program

8 pursuant to which irrigation customers were paid to

9 curtail their irrigation systems - either fully or

10 partially - for the entire 2001 irrigation season (June

11 15 to September 15, 2001). In addition, the Company

12 implemented two other load curtailment programs in Idaho:

13 the Customer Energy Challenge and the Energy Exchange

14 Program. As a result of these load curtailment programs,

15 requirements for wholesale purchases were decreased.

16 Q Please address the Company's position with

17 respect to the seventh issue identified: the presence of

18 interruptible load, and the Company's treatment of the

19 same.

20 A Interruptibility is present in PacifiCorp's

21 Idaho jurisdiction only with respect to irrigation

22 customers and Monsanto. The Company's treatment of

23 Monsanto as an interruptible customer is the subject of a

24 separate proceeding (PAC-E-01-16) the PacifiCorp/Monsanto

25 Service Contract proceeding and, therefore, was not

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1 discussed during the course of settlement discussions in

2 this proceeding. The Company's treatment of irrigation

3 customers as interruptible, however, was discussed

4 extensively during the settlement discussions. As

5 reflected in the

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1 Stipulation, the Parties agreed to terminate the

2 interruptible-options tariff in the current Schedule

3 No. 10. Instead, the Company has committed to work with

4 the IIPA and customers in the irrigation class to develop

5 a non-tariff based interruptibility option that will be

6 offered to customers in the future. The Company believes

7 this approach to irrigation interruptibility is

8 appropriate because it will allow the interruptibility

9 option to be more closely aligned with the value of the

10 resource acquired through interruption.

11 Q Please address the Company's position with

12 respect to the eighth issue identified: the Company's

13 sales contracts executed in 2000/2001.

14 A No new long-term firm wholesale contracts

15 were executed by the Company in 2000/2001. The Company's

16 overall power supply strategy is discussed in detail by

17 Mr. Stan Watters in his testimony filed with the

18 Company's Application in this proceeding.

19 Q Please address the Company's position with

20 respect to the ninth issue identified: the timing of the

21 loss of the Company's Hunter coal generation plant in

22 2000-2001 and related cause(s) therefore.

23 A The circumstances leading up to the Hunter

24 Unit Number 1 generator outage and what PacifiCorp has

25 been able to determine about the cause of the outage are

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1 described in the testimony of Mr. Barry Cunningham, filed

2 with the Company's Application in this proceeding. While

3 the outage of the Hunter Unit Number 1 generating unit

4 from November 28, 2000 through May 8, 2001 occurred at a

5 very inopportune time with respect to purchase power

6 prices during that time period,

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1 there is no evidence to suggest that the Company's

2 operating or maintenance practices contributed to the

3 outage.

4 Q Please address the Company's position with

5 respect to the tenth issue identified: the treatment of

6 irrigators as firm, as opposed to iterruptible customers.

7 A As discussed above, following extensive

8 discussion during settlement negotiation, the Parties

9 agreed to eliminate the existing interruptibilty options

10 in Schedule No. 10. Further the Company agreed to work

11 with irrigators to develop a non-tariff interruptibility

12 option for irrigators. The Company believes this

13 approach will permit a more appropriate valuation of the

14 benefit of interruptibility.

15 Q Please address the Company's position with

16 respect to the eleventh and final issue identified: the

17 treatment of special contract customers as situs

18 customers, as opposed to system customers.

19 A The treatment of special contract customers

20 as situs customers as opposed to system customers is the

21 subject of a separate proceeding before this Commission

22 (Case No. PAC-E-01-16, the PacifiCorp/Monsanto Service

23 Contract proceeding). Accordingly the issue was not

24 addressed by the parties during settlement. The Company

25 will make its recommendation to the Commission regarding

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1 that issue in conjunction with Case No. PAC-E-01-16.

2 Q Does the Stipulation resolve all of the

3 issues presented above?

4 A The parties were unable to reach specific

5 agreement regarding some of the issues. Nevertheless, the

6 Stipulation represents an overall compromise of the

7 Parties' positions regarding all issues. The Parties

8 agree that the Stipulation overall

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1 represents a fair, just and reasonable compromise of the

2 issues raised in this proceeding and that this

3 Stipulation is in the public interest.

4 Q Are there any other issues upon which you

5 would like to comment?

6 A Yes. I would like to add that the

7 underlying market conditions and high purchased power

8 prices that resulted in the Company's applications for

9 deferral and recovery of its excess power costs are the

10 same as those that resulted in the significant BPA credit

11 received by Idaho customers. As such, it would be unfair

12 for customers to enjoy the favorable BPA benefits

13 obtained as a result of those high cost market

14 conditions, on the one hand, and not share the burden

15 that those conditions imposed by allowing PacifiCorp to

16 recover in rates a portion of the excess power costs it

17 incurred.

18 Parties' Recommendation

19 Q Why do the Parties agree that the terms of

20 the Stipulation in this proceeding produce an overall

21 just and reasonable outcome?

22 A The Parties believe that the 65% recovery

23 of deferred excess power costs allowed under the

24 Stipulation represents a reasonable compromise level of

25 excess power cost recovery for the Company. In addition,

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1 the Parties believe that the modified Rate Mitigation

2 Adjustment effectively reduces the impact of the Power

3 Cost Surcharge by equitably distributing responsibility

4 for excess power cost recovery among customer classes and

5 by limiting the change in annual revenue requirement for

6 any given class to a maximum 4% increase during the first

7 two years the Rate Mitigation Adjustment is in place.

8 Finally, the Parties also believe that

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1 modification of the rate structure in the irrigation

2 class to establish a single firm rate, together with

3 PacifiCorp's commitment to developing an interruptibility

4 option for irrigators on a non-tariff basis, represent an

5 appropriate and reasonable compromise by 1) allowing the

6 Company pricing flexibility that will better reflect

7 market conditions and 2) affording irrigators the benefit

8 of firm service at prices comparable to existing

9 interruptible service.

10 Q What do the Parties recommend regarding the

11 Stipulation?

12 A The Parties recommend that the Commission

13 admit the Stipulation into the PAC-E-02-1 record and

14 adopt the Stipulation in its entirety to resolve all of

15 the outstanding issues in this proceeding.

16 Q Does this conclude your testimony?

17 A Yes.

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1 (The following proceedings were had in

2 open hearing.)

3 MR. FELL: Thank you. Mr. Lively is

4 available for cross-examination.

5 COMMISSIONER SMITH: Okay, thank you.

6 Mr. Ward.

7 MR. WARD: No questions. Thank you.

8 COMMISSIONER SMITH: I'd like to note long

9 ago Mr. Olsen joined us. Any questions, Mr. Olsen?

10 MR. OLSEN: No.

11 COMMISSIONER SMITH: Mr. Budge.

12 MR. BUDGE: No questions.

13 COMMISSIONER SMITH: Mr. Woodbury.

14 MR. WOODBURY: No questions.

15 COMMISSIONER SMITH: Mr. Shurtz.

16 MR. SHURTZ: Yes.

17

18 CROSS-EXAMINATION

19

20 BY MR. SHURTZ:

21 Q Mr. Lively, we participated or I

22 participated in a teleconference, forgive me, I can't

23 remember the date, it was our fourth session that we met

24 and at that time I had a rate spreadsheet that you guys

25 had been kind enough to send me, then when the final

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1 stipulation arrived, the business rate in Class 23 and

2 23A had switched from 2.6 percent increase over two years

3 to a four percent increase, could you explain what the

4 change in that was?

5 A Well, I guess I can't respond to the sheet

6 that you were looking at. I don't recall what sheet we

7 would have provided to you. As you're aware, as a

8 participant in the process of the stipulation, there were

9 a number of various rate spread options.

10 COMMISSIONER SMITH: Mr. Lively, can you

11 get your microphone closer or maybe it's not turned on.

12 We're having difficulty hearing.

13 THE WITNESS: I'll start again. As you're

14 aware, Mr. Shurtz, there were various rate spread options

15 that we looked at during the course of the settlement

16 discussions. I'm not specifically aware of the sheet

17 that you're referring to; however, I will make comment

18 that in the final stipulation that was agreed to, one of

19 the principles of the stipulation was that we limit rate

20 increases to any customer class to four percent, so

21 that's why the final stipulation rate spreadsheet has a

22 four percent for some customer classes.

23 Q BY MR. SHURTZ: Okay, in our last

24 discussion that had taken place, and forgive me, I'm not

25 as learned as the rest of you, what prompted that change

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1 from 2.6 percent, as we were talking, as I participated,

2 to the four percent?

3 A Well, I can only speak in general terms as

4 to the increase and, again, referring back to the

5 principle of the stipulation that we would limit rate

6 increases to any rate, to any customer class to four

7 percent, so I'm not sure that I'm aware of a specific

8 discussion as to that particular customer class that

9 you're referring to.

10 Q Okay, I was just kind of surprised because

11 original sheets that I'd seen during my participation in

12 the negotiation before the stipulation was a 2.6 percent

13 and then when the stipulation came out, it increased

14 1.4 percent, I was just wondering what basically prompted

15 the change and I guess you've kind of answered that, that

16 you kept it to four percent, but I still have a question

17 in my mind. I just kind of felt at that point that I

18 was --

19 COMMISSIONER SMITH: Mr. Shurtz?

20 Q BY MR. SHURTZ: -- out somewhere on this.

21 COMMISSIONER SMITH: Mr. Shurtz, the

22 opportunity now is to ask questions of Mr. Lively. If

23 you have a statement or position you'd like to make, you

24 can do that later when you're there.

25 Q BY MR. SHURTZ: Also, you may not be the

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1 expert on this to ask, in Idaho what hydro projects does

2 PacifiCorp operate?

3 A I'm clearly not the witness to ask that

4 question to.

5 Q Okay, can I -- could that information be

6 later forwarded or provided?

7 A I'm not sure I understand the question.

8 Q The question is I would like to know what

9 actually the hydro projects in Idaho actually do produce

10 for the Pacific system, PacifiCorp system.

11 COMMISSIONER SMITH: Mr. Fell?

12 MR. FELL: We can provide that information,

13 yes, and we will do that.

14 MR. SHURTZ: Okay, that's all I have.

15 COMMISSIONER SMITH: Do we have questions

16 from the Commissioners?

17 COMMISSIONER HANSEN: I do.

18 COMMISSIONER SMITH: Commissioner Hansen.

19

20 EXAMINATION

21

22 BY COMMISSIONER HANSEN:

23 Q Mr. Lively, go to page 13 of your

24 testimony, lines 17 through 20, where there you're

25 talking about -- we're talking about the interruptibility

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1 and you're talking about the treatment of Monsanto as an

2 interruptible customer and then on line 19 you say,

3 "...was not discussed during the course of settlement

4 discussions in this proceeding," and I guess I'd ask the

5 question, why shouldn't the Company's treatment of

6 Monsanto as an interruptible customer be part of this

7 proceedings?

8 A Well, it was not an issue that was raised

9 or discussed as part of the settlement discussions and in

10 my own mind, I reconciled that fact to the -- that we

11 knew that Monsanto had a separate proceeding before the

12 Commission and in my own mind, it seemed reasonable that

13 we would address the issue of interruptibility for

14 Monsanto in that proceeding.

15 Q Is it true that you did have the right to

16 interrupt Monsanto's load during this deferral period?

17 A As I understand it, yes.

18 Q I guess I'm -- I'd like to go another step

19 forward, are you aware that Monsanto offered to curtail

20 or reduce its load during the period of high prices in

21 the winter of 2000-2001?

22 A I'm not, I'm sorry.

23 Q You're not aware of that?

24 A No.

25 COMMISSIONER HANSEN: I would ask the

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1 Chairman if I could give Mr. Lively a letter that he may

2 look at that I received from Monsanto addressing this

3 issue.

4 COMMISSIONER SMITH: Certainly.

5 (Documents being distributed.)

6 Q BY COMMISSIONER HANSEN: I'll give you just

7 a moment to look at that. Mr. Lively, have you seen that

8 letter before?

9 A No, I have not.

10 Q Are you familiar or had you ever heard that

11 that letter had been sent to PacifiCorp or that Monsanto

12 had ever offered those types of interruptibility to

13 PacifiCorp before?

14 A Only peripherally, not in any detail that

15 was involving my responsibility at PacifiCorp or in the

16 accomplishment of my job, I mean, but only through

17 peripheral discussions.

18 Q Would -- and here again, if -- would you

19 know why the Company might not have been interested in

20 pursuing this with Monsanto at this time, because, as

21 pointed out, the electricity prices were very high at

22 this time, would you have any reason to know why the

23 Company might not have pursued this?

24 A No. I mean, it's not part of my job

25 function to be involved in these kinds of arrangements.

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1 As I stated earlier, I only knew peripherally and

2 generally of the issue, but in no great detail at all.

3 COMMISSIONER HANSEN: Thank you.

4 Madam Chairman, later I may like to come back to this

5 letter and consider introducing it as part of the record,

6 but at a later time I may ask that request.

7 COMMISSIONER SMITH: Okay.

8 Q BY COMMISSIONER HANSEN: I have another

9 question, Mr. Lively. On page 15, lines 1 and 2 of your

10 testimony, you say, "...there is no evidence to suggest

11 that the Company's operating or maintenance practices

12 contributed to the outage." We're referring to Hunter;

13 is that correct?

14 A That's what this statement refers to, yes.

15 Q Are you aware that in the Wyoming hearings

16 that there were expert witnesses that suggested that

17 there was evidence that caused the failure of the

18 Company's operating and maintenance practices?

19 A No.

20 Q On page 8 of Mr. Lobb's testimony, lines 15

21 and 16 or, excuse me, lines 15 through 19, if you have

22 that there, does it surprise you that the Staff believed

23 that the Company had some responsibility in the failure

24 and should share the responsibility?

25 A That was an issue discussed during our

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1 settlement discussions. It was a statement that the

2 Staff made. There were some discussion and exchange of

3 information and ideas during the course of the settlement

4 discussions and so at the end of the settlement

5 discussions, certainly, the Company did not concur with

6 this statement of the Staff, but we understood it was a

7 view that they had discussed among themselves and so is

8 it surprising to me to see it in Mr. Lobb's testimony,

9 no, because I understand that it was something that they

10 had discussed and also something we discussed in the

11 course of the settlement discussions.

12 Q So based on your answer, are you saying,

13 then, that of the $25 million of the settlement agreement

14 that none of that is attributed to the Hunter failure?

15 A No, I'm not saying that at all. I'm saying

16 simply that the issue of the Hunter failure was a topic

17 of discussion during the settlement discussions and I

18 think each party came to their own conclusion of what was

19 a reasonable settlement and that the $25 million

20 represented a reasonable settlement and in their own

21 judgment had some view of what constituted or what made

22 the 25 million appropriate.

23 Q So how much of the 25 million is attributed

24 to the Hunter failure? Are you saying you don't know?

25 A I'm saying that the 25 million -- well, I

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1 can only speak from the Company's perspective as to why

2 the 25 million is an appropriate number. After we

3 through the course of the stipulation heard the comments

4 and thoughts of the other parties to those stipulation

5 discussions, we took their figures and their analysis and

6 in our own minds made a judgment about what -- not in any

7 sense, you know, specifically issue by issue, but

8 generally given the scope of the topics, the scope of the

9 issues, we made a judgment that 25 million was indeed an

10 appropriate and reasonable adjustment to settle at or

11 figure to settle at.

12 Q Well, did you think at any time the

13 Commission may want to know what makes up that 25

14 million, that it just isn't a number pulled out of the

15 sky? Excuse me, in our rules 274, 275 and 276, it states

16 that in a settlement, the Commission is entitled to know

17 that and I guess I'm just wondering, how would you

18 suggest as a Commissioner that I could get these numbers

19 or find out what it is that totals 25 million?

20 A Well, again, I can only speak from the

21 Company's perspective and I think each of the parties who

22 signed the stipulation have in their own judgment what

23 makes up the 25 million and so you may -- I mean, I can

24 only say from the Company's perspective there is no

25 specific delineation of costs that makes up the 25

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1 million; however, in my own mind, I would believe that,

2 going back to our earlier discussion about Hunter 1, that

3 there should reasonably be some recovery of Hunter 1 in

4 that $25 million.

5 Q But you're not aware of how much?

6 A No. I mean, I can't say that there's an

7 analysis, that there's an evaluation, you know, that

8 we've come to any conclusion from a financial perspective

9 or a quantification perspective of the elements of the

10 discussions or the elements of the issues that make up

11 the 25 million.

12 Q And that would be the same if I was trying

13 to get a number of how much was in it for the hydropower,

14 the reduction in hydropower or any of the issues that

15 have been brought up, I really couldn't get an exact

16 number; is that true, then?

17 A I'm saying that the Company does not have

18 an exact break-out in our minds of what makes up the 25

19 million.

20 Q So you're really not aware of how the

21 Company came up with the 25 million?

22 A No, I am aware. I think we evaluated the

23 discussion that occurred among the parties. We

24 evaluated, you know, our initial filing, the 38 million

25 through the process of four separate sessions among the

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1 various parties and in hearing the concerns and issues of

2 the Staff and Irrigators and Monsanto, Mr. Shurtz, you

3 know, as we evaluated the entirety of the discussions,

4 the entirety of the package of issues that were

5 addressed, in our mind, 25 million seemed to be a

6 reasonable amount or figure to settle at.

7 COMMISSIONER HANSEN: Thank you very much.

8 That's all I have.

9 COMMISSIONER SMITH: Do you have redirect,

10 Mr. Fell?

11 MR. FELL: Yes, I do.

12

13 REDIRECT EXAMINATION

14

15 BY MR. FELL:

16 Q Mr. Lively, let me maybe just ask you about

17 a couple of or some of the issues that might have been

18 addressed in the settlement discussions. Did the

19 settlement discussions address responsibility for the

20 Hunter outage and the amount that perhaps might be

21 disallowed due to the Hunter, not necessarily

22 specifically, but that some disallowance is appropriate

23 for the Hunter situation?

24 A There was some discussion, yes, about

25 responsibility for Hunter and what might be disallowed

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1 relative to Hunter.

2 Q So as PacifiCorp discussed this settlement,

3 they evaluated whether there was some exposure of loss

4 attributable to the Hunter outage?

5 A Yes.

6 Q And then was there a discussion regarding

7 the power purchases that PacifiCorp made?

8 A Yes.

9 Q And the wholesale power contracts that

10 PacifiCorp had to serve?

11 A Yes.

12 Q And PacifiCorp's strategies in serving its

13 load during this period?

14 A Yes.

15 Q And was there a risk that some of that

16 would be challenged as having been imprudent and

17 therefore disallowed by the Commission?

18 A Certainly.

19 Q And did the Company consider that in

20 deciding to reduce its level of recovery?

21 A Well, certainly, and as I discussed with

22 Commissioner Hansen, you know, those were parts of the

23 discussion or those were parts of the decision making

24 process that the Company engaged in in determining that

25 the $25 million was appropriate, but, again, not arriving

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1 at specific amounts.

2 Q And did the Company also consider the issue

3 of the level of load that would be taken into account,

4 current load versus load from several years back? I

5 recall the Staff talking about that.

6 A About load growth?

7 Q Yes.

8 A The issue that load growth, Staff raised

9 the concern that the Company should not be allowed to

10 recover a portion of excess power costs that related to

11 load growth.

12 Q And did the Company still consider that its

13 total of 37 to $38 million was prudently incurred and

14 should be recoverable?

15 A Yes.

16 Q So then did the Company consider

17 essentially in arriving at the stipulation, was it a

18 balancing of its own sense of fairness and these various

19 positions?

20 A Well, certainly, fairness, a sense that

21 there was some exposure on those issues and that the risk

22 existed that we wouldn't recover all of those costs even

23 though we considered them to be prudently-incurred costs,

24 that we might not be able to recover them through a rate

25 case proceeding and so all of those issues went into the

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1 Company's decision making.

2 Q Was it possible at that time to quantify

3 the risks that the Company faced on these disallowances?

4 A No. I mean, we could gain a general sense,

5 but certainly no quantification.

6 MR. FELL: I have no other questions.

7 COMMISSIONER SMITH: Okay, thank you,

8 Mr. Lively.

9 (The witness left the stand.)

10 COMMISSIONER SMITH: Do you have further

11 witnesses, Mr. Fell?

12 MR. FELL: We have no further witnesses.

13 COMMISSIONER SMITH: I would now give to

14 Mr. Ward the opportunity to go now or following the Staff

15 witnesses.

16 MR. WARD: It's at your pleasure, probably

17 put the Staff up first.

18 COMMISSIONER SMITH: Mr. Woodbury.

19 MR. WOODBURY: Thank you, Madam Chair.

20 Staff would call Randy Lobb.

21

22

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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 and spell your last name for the record?

11 A My name is Randy Lobb, L-o-b-b.

12 Q And for whom do you work and in what

13 capacity?

14 A I work for the Idaho Public Utilities

15 Commission as utility division administrator.

16 Q And in that capacity, did you have occasion

17 to participate in settlement discussions and negotiations

18 in this case?

19 A Yes, I did.

20 Q And did you also have occasion to prepare

21 prefiled testimony consisting of 17 pages and four

22 exhibits, Exhibits 101 through 104?

23 A Yes.

24 Q And have you had the opportunity to review

25 that testimony and those exhibits prior to this hearing?

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1 A Yes.

2 Q And is it necessary to make any changes?

3 A No, not to my knowledge.

4 Q If I were to ask you the questions set

5 forth in your testimony, then, would your answers be the

6 same?

7 A Yes, they would.

8 Q And do you offer this testimony in support

9 of the stipulation and proposed settlement previously

10 filed in this case?

11 A Yes, I do.

12 MR. WOODBURY: Madam Chair, I'd ask that

13 the testimony be spread on the record and the exhibits

14 identified and I'd present Mr. Lobb for

15 cross-examination.

16 COMMISSIONER SMITH: If there's no

17 objection, we will spread the prefiled testimony of

18 Mr. Lobb upon the record as if read and Exhibits 101

19 through 104 will be admitted.

20 (Staff Exhibit Nos. 101 - 104 were

21 admitted into evidence.)

22 (The following prefiled testimony of

23 Mr. Randy Lobb is spread upon the record.)

24

25

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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 Utilities Division Administrator.

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 currently include case management and

18 oversight of all technical staff assigned to Commission

19 filings. I have conducted analysis of utility rate

20 applications, rate design, tariff analysis and customer

21 petitions. I have testified in numerous proceedings

22 before the Commission including cases dealing with rate

23 structure, cost of service, power supply, line extensions

24 and facility acquisitions.

25 Q. What is the purpose of your testimony in

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1 this case?

2 A. The purpose of my testimony is to describe

3 the provisions of the Stipulated Settlement presented to

4 the Commission in this case and attached as Staff Exhibit

5 No. 101. I will also discuss the issues considered in

6 negotiating and developing the agreement and support

7 Staff's recommendation for Settlement approval.

8 Q. Would you please summarize your testimony?

9 A. Yes. The tendered Stipulation is the end

10 result of comprehensive negotiations by the parties to

11 this case. The Stipulation incorporates implementation

12 of the BPA credit, reasonable recovery of extraordinary

13 power supply costs with mitigation, modified revenue

14 requirement across customer classes and changes in

15 irrigation rate design. The Settlement package

16 incorporates an extraordinary BPA credit agreement and

17 allows reasonable recovery of extraordinary power supply

18 costs. The Settlement utilizes a modified irrigation

19 class revenue requirement that more accurately reflects

20 cost of service to significantly reduce rate increases in

21 other classes that would otherwise occur due to power

22 supply cost recovery.

23 The Settlement negotiations focused on

24 three main areas: 1) power supply cost recovery amount, 2)

25 customer class revenue requirement, and 3) rate design.

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1 The primary issues addressed by the parties in the cost

2 recovery negotiations centered around those issues

3 identified by the Commission including the Idaho

4 jurisdictional revenue requirement, the merger condition

5 prohibiting a rate increase for two years, the Hunter

6 generating plant outage and the effect of wholesale sales

7 contracts and load growth on power supply costs. After

8 evaluation of these issues and numerous discussions with

9 all parties, Staff believes that a 65% recovery of the

10 deferred power supply costs is appropriate and fair to

11 both the Company and its Idaho customers.

12 The second phase of the negotiations dealt

13 with the determination of the appropriate annual revenue

14 requirement for each customer class. Staff believes that

15 the Settlement properly incorporates the previously

16 approved BPA credit and reasonably adjusts the irrigation

17 revenue requirement to better reflect cost of service.

18 More importantly, the Settlement effectively reduces the

19 impact of power supply cost recovery by applying a

20 revenue (rate) mitigation adjustment to various customer

21 classes and spreading recovery over two years. The net

22 change in annual revenue requirement (as compared to

23 2001) ranges between a 34% decrease in one customer class

24 to a maximum 4% increase in other classes.

25 Finally, Staff supports adjusting the energy

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1 component of rates in each class (where appropriate) to

2 reflect a combination of BPA credit, a power supply

3 surcharge and a rate mitigation adjustment. Staff

4 further supports modification of the rate structure in

5 the irrigation class to establish a single low cost firm

6 rate and a declining block energy rate for large

7 irrigators.

8 POWER SUPPLY COSTS

9 Q. What issues did Staff consider in

10 evaluating the Company's request to recover deferred

11 extraordinary power supply costs?

12 A. Staff focused on four main issues in its

13 evaluation of the Company's request. They included: 1)

14 a determination of the appropriate Idaho jurisdictional

15 power supply costs on a normalized basis; 2) an

16 evaluation and audit of Idaho jurisdictional power supply

17 costs during the deferral period; 3) the economic impact

18 and propriety of wholesale power sales contracts, and 4)

19 the economic impact and circumstances surrounding the

20 failure of the Hunter coal fire generating station.

21 Q. How did Staff determine what issues to

22 address?

23 A. Staff issues were identified during its

24 case review and audit and established by the Commission

25 in its Notice of Issues and Scheduling in this case. The

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1 nature of the extraordinary system power supply costs

2 that the

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1 Company is seeking to recover and the methodology used to

2 allocate those costs to Idaho were main factors

3 considered when framing the issues. For example, higher

4 than normal power purchase costs and lower than normal

5 surplus sales comprised the vast majority of the

6 extraordinary system costs. Therefore, Staff focused on

7 resource availability and load obligations.

8 Resource availability was diminished by

9 abnormally low water conditions and the loss of the

10 Hunter generating plant. Replacement resources were

11 essentially limited to energy purchases from the market

12 at extraordinarily high prices. Load obligations

13 included normalized native load, growth in native load

14 and long-term firm wholesale sales contracts. Hunter

15 operation and the magnitude of wholesale sales are under

16 the direct control of the Company. During the audit,

17 these areas were identified as the main focus of Staff's

18 investigation. Once the level of system costs was

19 established, methods used to allocate those costs to

20 Idaho were reviewed and compared to past practices to

21 assure consistency.

22 Q. Why didn't Staff oppose recovery based on

23 Scottish Power/PacifiCorp Merger Approval Condition No. 2

24 that prohibited rate increases for two years?

25 A. Staff believed that the merger language was

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1 clear. It stated: "As a minimum, Scottish Power shall

2 not seek a general rate increase for its Idaho service

3 territory effective prior to January 1, 2002."

4 Based on this language, Staff believed that

5 rates could increase after January 1, 2002. Staff

6 further understood as part of its participation in the

7 merger negotiations that rate stability through 2001 was

8 the objective of the condition and the use of costs

9 incurred during 2001 to establish rates after January 1,

10 2002, was not prohibited. Staff also considered the

11 extraordinary market conditions and the fact that

12 PacifiCorp does not control the market as a legitimate

13 reason for power cost deferral and recovery.

14 The Commission has subsequently issued

15 Order No. 28998 establishing that the merger condition

16 does not prohibit recovery of deferred power supply costs

17 after January 2, 2002.

18 Q. Based on its review of the main issues

19 cited above, what cost recovery adjustment did Staff

20 believe was justified prior to Settlement negotiations?

21 A. As a starting point to the negotiations,

22 Staff originally proposed that approximately $21 million

23 in deferred power supply costs be recovered from the

24 Idaho jurisdiction. This represents a reduction of about

25 $17 million in the amount requested for recovery by the

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1 Company.

2 Q. What adjustments were specifically identified?

3 A. As shown on Staff Exhibit No. 102, Staff

4 adjustments specifically included a reduction in the base

5 jurisdictional allocation to Idaho of $3.2 million in

6 1998 net power costs consistent with previous Staff

7 recommendations in Case No. PAC-E-00-5. Staff also

8 maintained that interest of about $900,000 on the

9 deferral balance should be removed in addition to removal

10 of $600,000 to reflect the additional costs of normal

11 load growth included by the Company as an extraordinary

12 power supply cost.

13 Staff proposed that $1.5 million for two

14 wholesale power contracts be remove from the total

15 deferred power costs based on contract charges. Nine

16 other wholesale sales contracts signed after 1994 were

17 considered under priced. Consistent with prior audit

18 adjustments, one contract has 100% of the revenue imputed

19 for an adjustment of $400,000. Imputation of revenue for

20 the remaining contracts at the 1998 marginal cost of

21 service resulted in an adjustment of approximately $15.2

22 million. Staff believed that a 50% sharing of the

23 imputed revenue reflected a reasonable sharing of costs

24 and risk associated with the contracts. A 50% sharing of

25 the $1 million costs and risks associated with wheeling

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1 for non-native load contracts was also believed to be a

2 reasonable sharing of cost risk associated with

3 discretionary transactions.

4 Q. Did Staff propose any adjustment in cost

5 recovery associated with the outage at the Hunter coal

6 fired generating station?

7 A. Yes. Staff determined that the cost associated

8 with the Hunter outage represented approximately $11.9

9 million of the total $38.3 million in extraordinary power

10 supply costs requested for recovery by the Company.

11 Based on a review of expert testimony filed in other

12 jurisdictions regarding this issue, it is unclear exactly

13 what role, if any, maintenance schedules, monitoring

14 equipment and operating protocols had in the failure of

15 the Hunter generator. Based on its review, Staff

16 believed that the Company had some responsibility in the

17 failure and should share responsibility for a portion of

18 the extraordinary costs. Therefore, Staff proposed that

19 the Hunter cost recovery be reduced by 25% or $3 million.

20 Q. What costs were included in the Hunter

21 outage total?

22 A. The costs included were essentially the net

23 costs above and beyond what would have occurred had

24 Hunter operated normally. While fuel costs to operate

25 Hunter were obviously eliminated, the Company was forced

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1 to buy replacement energy from the market at a time when

2 prices were extraordinarily high. The costs do not

3 include the costs to repair the plant.

4 Q. What amount of extraordinary power supply

5 expense did the parties ultimately agree to?

6 A. The parties ultimately agreed to allow

7 recovery of $25 million in extraordinary power supply

8 costs or approximately 65% of the original request.

9 Q. How did Staff determine what adjustments to

10 propose and what level constituted a reasonable

11 settlement?

12 A. Staff reviewed filed testimony and orders

13 issued in other jurisdictions that dealt with wholesale

14 contracts and the Hunter outage. Staff also carefully

15 reviewed past Company filings and Staff recommendations

16 to establish a reasonable level of normalized power

17 supply costs allocated to Idaho. Staff then evaluated

18 the components of the deferred power supply costs to

19 identify what costs were extraordinary, to determine what

20 events caused the extraordinary costs and to establish

21 responsibility for cost recovery.

22 The determination of what constituted a

23 reasonable adjustment for each power supply issue and

24 what constituted a reasonable overall settlement was made

25 based primarily upon Staff's evaluation of how successful

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1 it would be in presenting and defending its positions at

2 hearing. Discussing the merits of the various issues

3 with other parties to the negotiation and evaluating the

4 resources required to litigate in Idaho the same issues

5 already addressed in other jurisdiction also shaped

6 Staff's position. Finally, Staff saw an opportunity to

7 significantly reduce the impact of power supply cost

8 recovery for customers by packaging the recovery with the

9 BPA credit and movement in irrigator revenue requirement

10 to more closely reflect cost of service.

11 Q. Does the Settlement specifically establish

12 the exact adjustment required for each issue?

13 A. No. The Settlement establishes an overall

14 adjustment to the Company's request. The cost

15 responsibility for the Hunter outage or any of the other

16 issues was not specifically identified as part of the

17 Stipulation.

18 Q. Why were the remaining two years of the

19 merger credit accelerated and included in the Stipulated

20 Settlement?

21 A. The remaining two years of the merger

22 credit, valued at $2.3 million, was included to further

23 reduce the impact of power supply cost recovery and

24 eliminate the need for a rate increase when the merger

25 credit expires at the end of 2003.

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1 CLASS REVENUE REQUIREMENT

2 Q. Once an agreement was reached on a reasonable

3 level of power supply cost recovery, how did Staff and

4 the other parties establish an equitable spreading of

5 revenue requirement among the customer classes?

6 A. Staff's objective was to create a package

7 that appropriately applied the BPA credit, equitably

8 distributed the power supply cost recovery responsibility

9 and ultimately moved the irrigation class closer to cost

10 of service. Most importantly, Staff's objective was to

11 achieve this result with the smallest possible increase

12 in customer rates.

13 Q. Was Staff able to achieve its desired result?

14 A. Yes, we believe that we have. All of the

15 objectives were reasonably achieved and no customer class

16 received a rate increase greater than 4% over the two-

17 year period. While Staff does not wish to minimize the

18 impact of a 4% increase, we also recognize that rate

19 increases due to recent extraordinary events have been

20 much higher for many other electric customers throughout

21 the region. In addition, without the class rate

22 mitigation provided by the Stipulation, the rate impact

23 resulting from what we believe is reasonable power supply

24 cost recovery could have exceeded 17% for some customers

25 over a two-year period.

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CASE NO. PAC-E-02-1 R. LOBB (Di) 11
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1 Q. What do you mean by rate mitigation and how

2 was it achieved?

3 A. Rate mitigation is simply a credit used to

4 reduce the energy rate of a given customer class that

5 would otherwise experience a larger rate increase.

6 Increasing the revenue requirement assigned to the

7 irrigation class and distributing the savings to classes

8 that experience an increase during the power supply cost

9 recovery period provided rate mitigation. Rate

10 mitigation was also provided in year two to assure that

11 no customer class experiences any rate increase as

12 compared to the prior year.

13 Q. Why did you increase the revenue

14 requirement assigned to the irrigation class?

15 A. Based on the last cost of service study

16 approved by the Commission in 1990 and several cost of

17 service studies submitted since then including the one

18 submitted by the Company in this case, the irrigation

19 class has generated revenues significantly below that

20 required to cover cost of service. The result is a

21 subsidy of the irrigation class by other customer

22 classes. The extraordinarily large BPA credit provided a

23 valuable opportunity to modify the irrigation class

24 revenue requirement without increasing average irrigation

25 rates. Modifying the revenue requirement at this time

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CASE NO. PAC-E-02-1 R. LOBB (Di) 12
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1 reduces the subsidy, reduces the effect on irrigation

2 rates that would have occurred without the BPA credit and

3 provides an opportunity to provide rate mitigation to

4 reduce the effects on other classes of extraordinary

5 power supply cost recovery.

6 Because movement in class revenue

7 requirement must be revenue neutral outside of a general

8 rate case, the level of mitigation had to exactly equal

9 the $4 million increase in irrigation revenue

10 requirement. After power supply costs are recovered in

11 full, rate mitigation will continue to reflect a

12 continuation of class revenue requirement that more

13 closely reflects costs of service.

14 Q. Does Staff agree with the cost of service

15 study submitted by the Company in this case?

16 A. No. Staff did not accept the specific

17 details of the cost of service study submitted by the

18 Company and required that the position be so stated in

19 the Stipulation. Staff did agree that an increase in

20 irrigation revenue requirement at this time represents a

21 reasonable step toward what will ultimately be accepted

22 as cost of service. Staff will evaluate specific cost of

23 service issues and make its recommendations to the

24 Commission in conjunction with Case No. PAC-E-01-19 (The

25 Monsanto/PacifiCorp Service Contract Case). The cost of

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CASE NO. PAC-E-02-1 R. LOBB (Di) 13
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1 service study ultimately approved by the Commission may

2 result in an irrigation class revenue requirement that is

3 different than that established in this case. The

4 Commission will decide at that time whether it is

5 necessary or appropriate to further modify irrigation

6 class revenue requirement.

7 Q. Why didn't Staff support using the BPA

8 credits or an alternative spread of power supply cost

9 recovery among the classes to fully mitigate the rate

10 increase?

11 A. BPA credits, as required by BPA rules, must

12 go only to qualifying customers. Therefore, the credit

13 may not be used to offset rate increases in other

14 customer classes. With respect to recovery of

15 extraordinary power supply costs, Staff believed that

16 these costs were incurred based on energy consumption and

17 should be recovered based on energy consumption. Any

18 shifting of responsibility for cost recovery from one

19 class to another would be inappropriate.

20 Q. After all of the revenue components are

21 added, what is the revenue requirement for each customer

22 class and how does it compare to the revenue requirement

23 in 2001?

24 A. Staff Exhibit No. 103 shows the various

25 revenue components for each class and compares the

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1 revenue requirement agreed to under the stipulation to

2 last

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1 year's revenue requirement.

2 RATE DESIGN

3 Q. What rate structure is recommended for the

4 various customer classes under the Stipulation?

5 A. The parties to the Stipulation agreed that

6 rate structure should remain unchanged for all classes

7 except the irrigation class. The proposal is to reflect

8 the change in revenue requirement for each class by

9 modifying the energy component of the rate either up or

10 down as necessary. Increasing the energy component was

11 determined by the parties to be most appropriate given

12 the nature of the extraordinary power supply costs

13 subject to recovery. These variable costs were incurred

14 based on energy consumption and are equitably recovered

15 based on energy consumption. BPA credits are already

16 provided on the basis of energy consumption and the rate

17 mitigation component had to be applied based on energy

18 consumption to be effective. Staff Exhibit No. 104 shows

19 the new energy rates recommended for the Residential,

20 General service and irrigation classes and a provides a

21 comparison to rates in 2001.

22 Q. What is recommended for the irrigation class?

23 A. The parties agreed to eliminate the separate

24 A, B and C firm and interruptible schedules in favor of a

25 single firm rate. The parties also agreed to modify the

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CASE NO. PAC-E-02-1 R. LOBB (Di) 15
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1 energy rate component from a two block, declining rate to

2 a three block, declining rate.

3 Q. Why was the interruptible rate eliminated

4 for irrigators?

5 A. Most of the irrigation customers currently

6 take service under Schedule C because it is the lowest

7 price of the three service schedules available.

8 Therefore these customers generate most of the revenue in

9 the class. However, irrigators indicated that

10 significant economic hardship was suffered in 2001 due to

11 the numerous interruptions that occurred. Consequently,

12 the Company and the parties agreed that a single

13 non-interruptible rate at a price previously offered for

14 interruptible service should be provided.

15 Q. Will irrigators be able to obtain further

16 rate discounts for interruptible service?

17 A. Some of the larger irrigation customers on

18 a case-by-case basis may be able to take interruptible

19 service for a discounted rate. The Company agreed to

20 discuss this type of service with irrigators that use

21 energy at levels not subject to the BPA credit.

22 Q. Why was the energy rate changed from a two-

23 tiered structure to a three-tiered structure?

24 A. The rate structure was modified to recognize

25 that the BPA credit is applied to a limited amount of

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1 energy consumed during a given month. Establishing a

2 third block at a lower price will help to mitigate rate

3 impacts that will occur for usage not eligible for a BPA

4 credit.

5 Q. Does that conclude your direct testimony in

6 this proceeding?

7 A. Yes, it does.

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1 (The following proceedings were had in

2 open hearing.)

3 COMMISSIONER SMITH: Questions, Mr. Budge?

4 MR. BUDGE: Nothing, thank you.

5 COMMISSIONER SMITH: Mr. Olsen.

6 MR. OLSEN: Nothing, Madam Chair.

7 COMMISSIONER SMITH: Mr. Ward?

8 MR. WARD: No questions, thank you.

9 COMMISSIONER SMITH: Mr. Fell?

10 MR. FELL: No questions.

11 COMMISSIONER SMITH: Mr. Shurtz.

12

13 CROSS-EXAMINATION

14

15 BY MR. SHURTZ:

16 Q Randy, what is your, as Commission Staff,

17 what is your role in this stipulation?

18 A I basically represent the Staff's

19 position. I oversee all of the technical Staff, the

20 accountants, the engineers, the Staff that was assigned

21 to this case.

22 Q Okay, does the Staff represent the people

23 of Idaho?

24 A Absolutely.

25 Q Okay. In your negotiations with Utah

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Wilder, Idaho 83676 Staff

1 Power, how many times have you negotiated with Utah Power

2 in the past? I know you negotiated in this stipulation,

3 is there any others that you've negotiated with Utah

4 Power?

5 A Not personally, no.

6 Q Have you ever -- in your Staff, what

7 percentage of, or just rough guesstimate, Randy, these

8 cases do you settle by stipulation?

9 A Very few, really. Most of them go to

10 technical hearing. Most of the cases overall go to

11 hearing. Once in awhile cases are settled, issues are

12 settled sometimes. Some issues are settled in some

13 cases, some issues go to hearing.

14 Q What percentage of the time does the Staff

15 tend to, I guess we are in a hearing now, tend to settle

16 with the applicant in that? Did I miss the --

17 A A small percentage. I don't know

18 numerically what that number would be. Once in awhile.

19 Q So this agreement that we have now is an

20 exception to the rule?

21 A I would say it's unusual for me

22 personally. I think it's happened over the years. This

23 is the first one with PacifiCorp. The conditions are

24 really extraordinary.

25 MR. SHURTZ: I have no further questions.

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1 COMMISSIONER SMITH: Are there questions

2 from the Commission? Commissioner Kjellander.

3

4 EXAMINATION

5

6 BY COMMISSIONER KJELLANDER:

7 Q Mr. Lobb, on page 7 of your direct

8 testimony, it would be lines 13 through 15, that one

9 sentence, you talk about the 1.5 million for two

10 wholesale power contracts that would be removed from the

11 total deferred power costs based on contract charges.

12 Could you just elaborate a little bit more for my

13 clarification on some of the specifics surrounding the

14 contract charges?

15 A Yes. This was the Staff's original

16 position as we began the negotiations. There were two

17 contracts and I think they are shown on exhibit -- I have

18 some notes on this particular issue in my briefcase if I

19 could get that from you. I think those contracts are

20 shown on Staff Exhibit 102, thank you, and they are the

21 Cheyenne Contract, No. 1 and No. 2 shown about mid page

22 on the left-hand side, Cheyenne contract and the WAPA II

23 buy-out.

24 Generally, the Cheyenne contract was a

25 contract that the Staff took a position on some time ago

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CSB REPORTING LOBB (Com)
Wilder, Idaho 83676 Staff

1 and as a matter of consistency, the Cheyenne contract was

2 determined to have been served longer than was actually

3 needed or required under the contract and so the costs,

4 the excess costs, were eliminated from that particular

5 contract. That was a Staff position on the Cheyenne

6 piece.

7 The WAPA buy-out was basically a buy-out of

8 a -- the Company basically --

9 COMMISSIONER SMITH: Could we please

10 identify WAPA? Western Area Power Administration.

11 THE WITNESS: Okay, Western Area Power

12 Administration, thank you. In any case, the WAPA

13 contract essentially from the Staff's position required a

14 buy-out to be paid for the contract and it was -- the

15 Staff determined that it was already intended to expire,

16 so in fact, the Staff believed that payment was made for

17 a buy-out of a contract that was expiring, so that was

18 the adjustment made on the WAPA. The Cheyenne

19 essentially served longer than needed, the Company

20 incurred costs that we believed were improper, we removed

21 those.

22 COMMISSIONER KJELLANDER: Thank you.

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Wilder, Idaho 83676 Staff

1 EXAMINATION

2

3 BY COMMISSIONER SMITH:

4 Q Mr. Lobb, is this the only case where the

5 Commission has considered utility expenses incurred for

6 power supply costs during the years 2000-2001?

7 A No. In fact, we've already considered

8 these extraordinary costs for both Idaho Power Company

9 and Avista Corporation.

10 Q Would it be acceptable to the Staff, do you

11 think, for a utility not to cover its projected load?

12 A Yes, I believe that it would be improper.

13 There's been some discussion about the economics of

14 meeting all your load and whether it's reasonable to

15 curtail based on economics, but as it stands today, we

16 believe that the Company has an obligation to serve firm

17 load and it's their responsibility to acquire the

18 resources necessary to do that.

19 Q Do you think it would be appropriate to use

20 a spot market or day ahead to cover your purchased power

21 needs?

22 A I think you need a balanced portfolio of

23 purchases, a little bit of long term, a little bit of day

24 ahead and a piece of real time. Real time you use to

25 balance. I think it's prudent to do that. There's risks

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1 associated with relying too heavily on any one of those

2 purchases.

3 COMMISSIONER SMITH: Thank you.

4 Any redirect, Mr. Woodbury?

5 MR. WOODBURY: No redirect.

6 COMMISSIONER SMITH: Thank you, Mr. Lobb.

7 (The witness left the stand.)

8 MR. WOODBURY: Staff has no further

9 witnesses.

10 COMMISSIONER SMITH: Thank you.

11 Mr. Ward.

12 MR. WARD: Thank you, Madam Chair.

13 Madam Chairman, as the Commission knows, I filed a late

14 petition to intervene for Nu-West which the Commission

15 has courteously granted. The reason for that and the

16 sole reason is the question of whether Nu-West should be

17 subject to any surcharge granted pursuant to this

18 stipulation and settlement or, in fact, in any manner in

19 this proceeding and I have to give you a little

20 background about how I got involved because it will

21 explain why I'm going to have to go into a little

22 detail.

23 Nu-West didn't realize its position in this

24 proceeding until sometime after April 22nd and on either

25 the afternoon of the 25th or the morning of the 26th,

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CSB REPORTING LOBB (Com)
Wilder, Idaho 83676 Staff

1 they contacted me and asked me to review the case and see

2 if there was anything I could do for them. I did review

3 it on the 26th, which was a Friday, and called them back

4 and told them that afternoon or the end of the day that I

5 would take the case and then had Monday and Tuesday to

6 collect the documentation, do the research and submit

7 comments which were due at the close of business on

8 Tuesday.

9 In the course of preparing those comments,

10 we spent some considerable period of time trying to

11 determine how it was that the 1998 contract, as I've

12 referred to it in my comments, didn't appear to have been

13 approved by the Commission and we finally tracked that

14 down, so as a result of all of that, those comments were,

15 I'm sorry to say, whipped together rather quickly and

16 that's why I'd like to elaborate on them just a bit.

17 Basically, there are only three

18 possibilities here with regard to Nu-West being subject

19 to the surcharge in question here. One possibility is

20 that the 1998 agreement governs and if that's the case,

21 the answer is very straightforward. The 1998 agreement

22 was a fixed price contract that lasted through the end of

23 2000, terminated at the end of the year or 2001, excuse

24 me. All of the costs incurred in this proceeding that

25 are subject to consideration in this proceeding were

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CSB REPORTING COLLOQUY
Wilder, Idaho 83676

1 incurred between November of 2000 and October of 2001.

2 That's the period during which the 1998 contract was in

3 effect.

4 I would contend that that contract is very

5 straightforward, it had a fixed price for the energy

6 consumed during the period of the contract and there's no

7 question that for the energy consumed during the period

8 of the contract coincides with the period in which these

9 surcharges were incurred, so I don't believe there's any

10 case that can be made -- well, I believe the most

11 straightforward case is that the 1998 agreement governed,

12 it specified a fixed price. The fact that PacifiCorp's

13 costs increased during that period of time is

14 unfortunate, but it is -- it has nothing to do with

15 Nu-West.

16 Certainly, if the shoe had been on the

17 other foot and PacifiCorp had received a windfall in

18 terms of lower costs, I don't think Nu-West would have

19 even considered applying for any credit on its contract

20 and I don't think the Commission would have considered

21 for a second allowing it, so the fact that these costs

22 may have been deferred for tariff customers really has no

23 bearing on Nu-West. Nu-West had a fixed price for the

24 energy it consumed during the given period and that price

25 should be honored.

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Wilder, Idaho 83676

1 The other possibility, of course, is -- and

2 I would point out, I mentioned briefly in my comments,

3 that I think the Agricultural Products rule governs in

4 this case, notwithstanding the Commission is now looking

5 at spreading a surcharge after the termination of the

6 1998 agreement and the reason why I say that is

7 two-fold. First, as I pointed out, the agreement

8 governed consumption during a period by a customer and I

9 think that's very straightforward, but secondly, if the

10 Commission could defer costs during the pendency of an

11 agreement and then load up the customer with those

12 deferred costs after the agreement terminated, obviously,

13 Agricultural Products would not be worth the paper it's

14 written on. The Commission could get around it any time

15 it pleased, so I think, first of all, recovery is barred

16 by the Ag Products doctrine.

17 Secondly, even if one can somehow get past

18 that argument, there's only two possibilities

19 thereafter. One is that Nu-West is a tariff customer or

20 pursuant to the contract now in effect is to be treated

21 as a tariff customer and subject to the same rate

22 disposition as all other customers or two, if it is not a

23 tariff customer, then to the extent there's an agreement

24 between the parties, in effect what distinctions are

25 drawn in that agreement between the existing contract and

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1 a tariff customer, and here's where in my haste to get

2 comments in, I think I did the Commission a disservice by

3 providing a less than complete analysis of that

4 contract. That contract I will start off by saying is to

5 me a muddled mess of the first order and I cite the

6 Commission's Order approving it --

7 COMMISSIONER SMITH: That's a technical

8 term?

9 MR. WARD: That is a technical term. It's

10 a technical term for what happens when marketing people

11 and plant managers write contracts and don't submit them

12 to people with a regulatory background to look at it, but

13 I want to walk through that, if I may, and try and

14 explain it. I could not for the life of me in the day or

15 so that I was dealing with that try to make the various

16 terms in that contract rhyme with the Commission's order

17 and the representations made to the Commission when the

18 contract was approved, but I now think I can, so if you

19 would follow me briefly through that contract, and I'm

20 now referring to the 2001 agreement that's still in

21 effect. It's Exhibit C in our filing.

22 COMMISSIONER SMITH: Well, let's fix that,

23 Mr. Ward. The next range of exhibit numbers will be 501,

24 so could we start with 501?

25 MR. WARD: Yes, if we give these exhibit

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1 numbers as if they were evidentiary exhibits, what I

2 attached as Exhibit A to my comments is what I

3 characterize as the 1998 agreement and it would be 501.

4 Exhibit B following that is the Commission's Order

5 June 13, 2000 approving the '98 agreement and it would be

6 502, so that's the agreement that I contend governed the

7 period in question when the power was consumed and

8 Exhibit 502 is the Commission Order approving that

9 agreement.

10 Both the agreement and the Commission Order

11 are unexceptional in every way. It's a fixed price

12 contract with a straightforward approval. Exhibit C,

13 which I think got to you late, not until the next day

14 after April 30th, is the 2001 service agreement and it is

15 some 12 pages, so that would be 503. That agreement by

16 its terms is still in effect.

17 COMMISSIONER SMITH: Could we just go at

18 ease for a moment while we find these?

19 MR. WARD: As I say, 503 may not have made

20 it attached to your comments because it was filed the

21 next day.

22 COMMISSIONER SMITH: We have it.

23 MR. WARD: Exhibit D would be 504. That is

24 the Commission's Order of March 27, 2002 approving the

25 2001 agreement.

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1 (Nu-West Industries, Inc. Exhibit

2 Nos. 501 - 504 were marked for identification.)

3 MR. WARD: Now, the best way to approach

4 this is to pull 503 apart from 504 and put them together

5 and I want to deal with some of the provisions. It will

6 take five minutes, I think. If you look at -- let's

7 start with the 2001 agreement, that's 503. In the

8 agreement itself, if you turn to page 4, you'll see a

9 section entitled "4.2" and this deals with the annual

10 adjustment to the basic rates established by the

11 agreement and if you just look at the last paragraph

12 above the formula on page 4, you'll see the interesting

13 sentence that says, "This shall be the sole and exclusive

14 means of annual adjustment to the unit charges contained

15 herein."

16 That looks very much like a fixed price

17 contract with a fixed provision for an adder, but turn to

18 section 8.2. In 8.2, you have what looks very much like

19 what is known as a Memphis clause. That is a savings

20 clause that provides for continuing Commission

21 jurisdiction notwithstanding the contract,

22 notwithstanding that a contract has been entered and I

23 think as the Commission is probably painfully aware,

24 under the mobile Sierra doctrine which is incorporated in

25 Idaho under the Agricultural Products case, a contract

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1 that states a rate cannot be changed by the Commission

2 except upon extraordinary circumstances, which aren't at

3 issue here, unless there's a Memphis clause and that

4 clause, of course, typically looks much like this.

5 Excuse me, I said 8.2, I meant 8.3. "The

6 parties agree that the Commission has the authority to

7 modify the rates for service under this agreement under

8 the same standard that applies to tariff customers

9 generally. Accordingly, surcharges or credits," and take

10 particular note of the words surcharges or credits, "that

11 apply to service to tariff customers generally will also

12 apply to service under this agreement." Now, how can

13 that make any sense when we have an annual adjustment,

14 when we have a fixed price contract to start with stating

15 an annual adjustment factor.

16 Well, in the Commission's Order approving

17 the contract, and I did not represent -- as far as I

18 know, Nu-West was not represented at all when this

19 contract was approved, but apparently, Staff picked up

20 the discrepancy between those provisions and raised some

21 questions about it, so if you will turn to 504, on page 3

22 over to the top of 4 there's some discussion, including

23 some discussion of what the Commission's jurisdiction

24 over the rates under this contract is and the Staff

25 points out the discrepancy between 4.2 and 8.3.

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1 On page 4, it appears, then, the Company,

2 PacifiCorp, was asked to explain how these provisions

3 held together and you'll see under Company reply, the

4 Commission's paraphrase of the Company's reply, which is

5 that, as I understand it -- well, I'll give you a second

6 to read it and then I'll tell you what I think it means.

7 What I take that section to mean is when

8 the Company says "If the Commission were to find that

9 some particular rate is the just and reasonable rate,"

10 then that would apply to Nu-West, but if a general rate

11 increase, for instance, were spread by stipulation, it

12 would not. Now, what I take that to mean is that if in

13 fact there were a general rate case or some other

14 proceeding that put Nu-West's costs at issue and the

15 Commission made a specific finding that no, it will not

16 be a 34 mill rate, it will be a 37 mill rate based on

17 cost of service or some other factor, then the Commission

18 could change the rates, but otherwise, it could not

19 except that rates could change under the provisions of

20 the contract, but why did the contract leave in the

21 general rate jurisdiction language? This took me forever

22 to figure out and by the way, the Commission then goes on

23 to say we approve the contract terms as clarified.

24 Now, if you go back to the agreement for a

25 moment, go back to 4.2 and there, again, that's on

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1 page 4, there you see the formula that applies to rate

2 revisions and if you work this through, you can finally

3 make sense of all the contract provisions and all the

4 representations made and here's the only way it makes

5 sense: The key element in the formula is defined on the

6 first page of the contract and it is the adjustment

7 percentage. That is "AP" as it appears under the

8 formula.

9 The adjustment percentage is none too

10 clearly written, but what it says is, "The adjustment

11 percentage for the following calendar year is the overall

12 annual percentage change in PacifiCorp's Idaho base rates

13 for all non-special contract classes of customers, as

14 approved by the Commission to be effective for the period

15 from July 1st of the previous year to June 30th of the

16 current year," the current year meaning the year in which

17 the change is first authorized by the contract and each

18 succeeding year thereafter.

19 Now, take you back to 4.2, 4.2 says that

20 the demand and energy charges shall be annually adjusted

21 effective January 1, 2003 and each January 1 thereafter.

22 Here's what they were trying to do and it takes a long

23 time to get this figured out or it took me a long time.

24 Quicker people will get it quicker. They entered into a

25 contract at the end of 2001 to begin January 1, 2002.

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1 What it did is it guaranteed Nu-West a fixed price

2 through 2002 at full cost of service at the rates that

3 were then in effect. The Commission Order, by the way,

4 notes that PacifiCorp represents it's at cost of

5 service.

6 Beginning in 2003, there could be an

7 adjustment made and that adjustment would track the

8 overall percentage of annual increases approved for the

9 Idaho jurisdiction, but there would be a lag. If you

10 approved by July 1 of the preceding year, let us say, a

11 five percent overall Idaho increase, the way this formula

12 works out is on the succeeding January 1st, Nu-West

13 becomes subject to that increase.

14 Now, the question is, of course, is it any

15 and all increases and if you go back to 1.1 and look at

16 the adjustment percentage it says, "only to Idaho base

17 rates," but fortunately, that's not going to be an issue

18 here, although, arguably, that in itself would exclude a

19 surcharge, but if you work it out, if in fact the rates

20 in effect here go into place on May 15th as the

21 stipulation intends, then they will not be available to

22 increase the rates on January 1 of 2003 under the

23 percentage. The earliest possible increase that Nu-West

24 could face would be January 1 of 2004, because the

25 contract provides that it's the rate increase on and

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1 after July 1st of the preceding year is what it amounts

2 to when you boil all the language down, so that's a

3 long-winded way of saying, to my mind, the first contract

4 governs, the '98 agreement governs no matter what, but

5 even if you thought the 2001 agreement governs, if you

6 work it through, you can kind of make sense of what

7 they -- of what the contract intended and that is Nu-West

8 would be subject to general rate increases, but it would

9 get a year 2002 reprieve and there would be a lag

10 thereafter in terms of the Commission might approve a

11 general rate increase, it wouldn't go into effect for

12 Nu-West until the following year, the anniversary of the

13 contract; in other words, a series of one-year agreements

14 based on the prior year's general rate levels.

15 That when you get all said and done is what

16 they intended to do, unless the Commission specifically

17 intervened and ordered a new rate for Nu-West based on

18 some cost of service or full proceeding, evidentiary

19 proceeding, not a stipulation or settlement as we have

20 today, so I would argue that it's very conclusive that

21 Nu-West should not be subject to the $159,000 a year

22 increase that is proposed for it for each of the next two

23 years, and I would add one more factor to that.

24 Mr. Woodbury pointed out to me today that

25 in my comments on page 3 in the second paragraph, I state

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1 that it was not until the Commission issued its Notice of

2 Stipulation and Settlement on April 22nd that Nu-West

3 knew its rates were at issue. As Mr. Woodbury correctly

4 points out, all Commission orders noticing up a rate

5 proceeding always contain standard language saying all

6 customers' rates are at issue and the Commission may

7 determine them in any fashion it sees fits, essentially,

8 but what I'm pointing out here is I meant to make a

9 different point.

10 I will recognize that in terms of strict

11 legal notice, yes, like every other customer, they had

12 legal notice, but in fact, PacifiCorp filed this case

13 proposing no increase for Nu-West and that leads me to

14 make two points: First, that's powerful evidence that

15 PacifiCorp knew that by either of these contracts,

16 Nu-West was contractually excluded from this rate

17 adjustment. Secondly, because of the curious

18 circumstances of the case, I think PacifiCorp and

19 arguably the Commission Staff is estopped to take a

20 contrary position because here's what happened.

21 While the last contract was awaiting

22 approval pending before the Commission, shortly after

23 that was submitted, PacifiCorp made its filing in this

24 case showing Nu-West not subject to the increase, so

25 Nu-West, of course, makes no dispute about either this

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1 filing or any interpretation of the contract that's now

2 in effect. Had there been a contrary filing by

3 PacifiCorp, had it filed and said Nu-West is subject to

4 this increase, then Nu-West would have had an opportunity

5 before the Commission approved its contract which

6 occurred well after the filing of this case to come to

7 the Commission and say, wait a minute, that's not our

8 understanding of our deal, we have to go back and

9 straighten that out, but because of the way the -- and

10 I'm not saying there's anything villainous about it, but

11 the fact of the matter is Nu-West was in a position where

12 it reasonably relied on what it thought was a filing that

13 concurred with its understanding of the contract and in

14 fact did concur with the intent of the contract I

15 maintain, but at any rate, it lost its opportunity to

16 make its case to the contrary by the way the filings came

17 down, so I think in justice, quite apart from the pure

18 language of the contract, Nu-West ought to be omitted

19 from this surcharge proceeding and on the basis of what

20 I've just said, I would so move.

21 COMMISSIONER SMITH: Mr. Ward, we'll now

22 ask if any of the other parties wish to comment on this

23 issue. Mr. Budge.

24 MR. BUDGE: No comments.

25 COMMISSIONER SMITH: Mr. Olsen.

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1 MR. OLSEN: No.

2 COMMISSIONER SMITH: Mr. Shurtz.

3 MR. SHURTZ: No.

4 COMMISSIONER SMITH: Mr. Woodbury.

5 MR. WOODBURY: Well, I do have some

6 comments and it's just regarding, I guess, which

7 agreement is the effective agreement for -- which is the

8 agreement that we should look at in determining whether

9 Nu-West should share some of the power cost surcharge.

10 You know, is it the 2001 agreement which was recently

11 submitted or the 1998 agreement? Clearly, the 2001

12 agreement, I mean, I don't know that you can say it's

13 clear on anything, but it purports to be a tariff, a

14 tariff standard agreement.

15 The 1998 agreement, it's difficult to say

16 what that is. It does have a rate in it, but it has some

17 language which is, I think, ambiguous and it merely, with

18 respect to Commission jurisdiction, seems to give the

19 Commission the right to change the contract and it

20 absolves PacifiCorp from any damages, and it was my

21 understanding that the contract that preceded 1998 was a

22 tariff standard.

23 Staff entered into the settlement

24 negotiations in this case with PacifiCorp a party to the

25 Nu-West agreements and we relied on them to some extent

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1 to characterize the 1998 agreement, whether it was a

2 tariff standard or a contract standard agreement, and so

3 now we have Nu-West's argument that they shouldn't be,

4 shouldn't receive any share of the power costs based on,

5 I'm not sure whether it's the '98 or the 2001 agreement.

6 Mr. Ward seems to be arguing both agreements, but I think

7 this is -- I wasn't a party to the underlying contract.

8 I think in the Commission's language approving the 2001

9 agreement, we took the Company's clarification to say

10 this is a tariff standard agreement and this contract can

11 be modified by the Commission, the contract rates.

12 With respect to the 1998 agreement, again,

13 that contract was submitted to the Commission for

14 approval two years after it was executed. Arguably for

15 some administrative oversight, it sat in some drawer on

16 some desk, but that agreement had one-and-a-half years

17 left to run and we were -- we felt a little laid out at

18 the gate, I guess, in trying to determine what is this

19 contract, what is this contract and so we approved it as

20 it was submitted and authorized the Company to -- we

21 approved it from its effective date, so I would say with

22 respect to Staff's participation in the negotiations,

23 there was no -- Staff should not be precluded, I guess,

24 from treating Nu-West in such a manner that the Company

25 contended that it should be treated, you know, as a

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1 tariff customer and subject to a spread of the power cost

2 surcharge.

3 COMMISSIONER SMITH: Thank you,

4 Mr. Woodbury.

5 Mr. Fell.

6 MR. FELL: Yes, thank you. Taking it a

7 step at a time, first I'll address the due process

8 issue. The original filing made by PacifiCorp actually

9 in Exhibit 19, page 6 of 6, which is the rate spread

10 table --

11 COMMISSIONER KJELLANDER: Could you give us

12 a second to get there?

13 MR. FELL: Yes. It's Mr. Zhang's exhibit.

14 There is a line item there, Special Contracts - Nu-West,

15 which is just above the Total Commercial and Industrial

16 line. Going up from Total Commercial and Industrial,

17 there's Special Contracts - Solutia, Special Contracts -

18 Nu-West. It shows -- I'll wait for all the Commissioners

19 to locate that.

20 MR. SHURTZ: Jim, what tab?

21 MR. FELL: I'm not sure what tab. It's

22 Exhibit 19, page 6 of 6, and it should be almost the last

23 page in this binder.

24 MR. SHURTZ: It's not in this binder.

25 MR. FELL: My point about this is that the

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1 Company's original proposal was that there would be no

2 increase to any customer class. This particular exhibit

3 shows that Nu-West was included in the rate spread

4 analysis, but was given a zero increase. Then the

5 Commission issued its notice of the proceeding and in

6 that notice stated that the rates and charges of all

7 customers of PacifiCorp in the State of Idaho, including

8 those governed by special contract, are at issue and

9 subject to change in this proceeding, so I think on the

10 due process issue it was covered.

11 Then the negotiations began and it was

12 through negotiations that the limit of no increase was

13 changed to no more than a four percent increase for any

14 customer class, so as a result of the negotiations,

15 Nu-West became, in a sense, vulnerable to an increase and

16 was one that ended up getting a four percent increase

17 under the negotiated resolution. Now, Nu-West was not

18 there and I can understand some reasons why. I don't

19 believe there was an estoppel on our part, but I do

20 understand the circumstances.

21 The second point, getting to the contracts,

22 PacifiCorp's tariff for industrial customers has a limit

23 of, I think it's, 15 megawatts and Nu-West exceeds that,

24 so there is no regular tariff schedule that covers

25 Nu-West's service. As a result of that, contracts have

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1 to be signed with Nu-West. We have regarded those

2 contracts as tariffs and intended to file them as

3 tariffs. One was filed late, but the intention was that

4 these were similar to tariff schedules.

5 The contract prior to the 1998 contract,

6 the one that was in effect before that, was treated as a

7 tariff contract. The 1998 contract is ambiguous, I will

8 admit, on that subject and after Mr. Ward's remarks, I'm

9 pleased that I didn't draft any of these, but it does

10 have a provision in section 7 that says that

11 PacifiCorp -- that if the Commission alters the contract

12 that PacifiCorp won't be liable to Nu-West for any of

13 those changes in the contract terms, which suggests to me

14 anyway that even the 1998 contract as a successor to the

15 one that had been in place contemplated that it was a

16 tariff contract subject to Commission change.

17 Then taking us to the construction of the

18 2001 contract, frankly, I guess I disagree with

19 Mr. Ward's construction of the agreement, but really,

20 you'd have to write it all out and study it more

21 carefully probably to be more certain, but to me, the

22 section 4 formula provisions he referred to are the

23 standard contractual pricing terms and the prices would

24 change on a normal contractual basis as part of this

25 tariff contract based upon changes that were made in

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1 general rate cases, but in the section 8.3, the parties

2 specifically agreed with regard to the Commission

3 jurisdiction that the Commission has jurisdiction in the

4 2001 agreement to change the contract in the same way

5 that it changes tariffs.

6 If we go to the Order, the Order is

7 ambiguous, too and the clause -- and this may be

8 PacifiCorp's responsibility, but the sentence that says

9 if, however, there were not a specific Commission

10 determination of the rates for Nu-West (for instance, if

11 a general rate increase were spread by stipulation), the

12 Company contends that section 4.2 would apply.

13 Well, what does that parenthetical mean,

14 for instance, if a general rate increase were spread by

15 stipulation. Here we have a stipulation. It's not a

16 general rate increase because it doesn't contemplate a

17 full review of costs, but it also is very specific as to

18 Nu-West. It is not a situation where there's a

19 stipulation that a general rate increase will be spread

20 on a cents per kilowatt-hour basis, for example. It

21 specifically identifies Nu-West and says this is how much

22 will be charged to Nu-West, so if the Commission were to

23 adopt that, it is a specific finding as to Nu-West and I

24 think it doesn't fall within this exception that Mr. Ward

25 cites.

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1 All that said, his next point is this isn't

2 just or fair and we have some sympathy with that point.

3 We signed the agreement and have an obligation to support

4 the stipulation and also believe the stipulation is a

5 fair outcome, but it isn't the only fair outcome and

6 PacifiCorp notes that the amount involved is not huge.

7 The net effect is $159,000 per year for two years and we

8 would be satisfied and we've discussed this with others

9 if that $159,000 per year that's assigned to Nu-West were

10 pushed out and included in the true-up mechanism after

11 the two years, if it turns out PacifiCorp over-collects

12 during the two-year period or under-collects, then that's

13 all part of the true-up mechanism that goes on after the

14 two-year period and that Nu-West would just get no

15 increase and that amount would then get spread back to

16 the other customer classes like true-up adjustments would

17 be.

18 Now, PacifiCorp is not the one that would

19 bear that cost, the other customer classes would and so

20 they should speak for themselves, but that's something

21 that we thought if you're looking for an alternative to

22 deal with the fairness issue and believe that Nu-West

23 should not have an increase here, we would suggest that

24 solution.

25 We also frankly request that the Commission

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1 determine that the 2001 agreement is a tariff form of

2 contract. With the exception that I've mentioned about a

3 rate increase that would be spread on a flat

4 kilowatt-hour basis, the Commission would actually have

5 to make a finding as to Nu-West to include them in a rate

6 change, but in that respect would be subject to the

7 tariff standard, not the Agricultural Products standard.

8 Thank you.

9 COMMISSIONER SMITH: We'll take a

10 ten-minute break.

11 (Recess.)

12 COMMISSIONER SMITH: Okay, we're back on

13 the record. Mr. Ward.

14 MR. WARD: I do want to respond, and I'll

15 try to keep it relatively brief, to the arguments made by

16 both Mr. Woodbury and Mr. Fell. First of all, point

17 No. 1, to the extent I wasn't clear as to which agreement

18 I think applies, let me be perfectly clear, I think it's

19 the '98 agreement without question. I recall very

20 clearly the Commission stating not so long ago that a

21 company's consumption and charges were governed by the

22 four corners of their contract and I would submit that's

23 exactly the case here.

24 Secondly, there's no way you can

25 realistically characterize the '98 agreement as anything

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1 other than a fixed price contract. There is not anything

2 that remotely resembles a Memphis clause in here.

3 Section 7 cited by both Mr. Woodbury and Mr. Fell reads

4 as follows: "Nu-West acknowledges that it is familiar

5 with the electric service schedule and electric service

6 regulations and agrees to abide by them and all

7 amendments and changes thereto so approved by the

8 Commission."

9 That is clearly not the unambiguous Memphis

10 clause language that all of us in this room know how to

11 draft and typically all contracts, even ones at a fixed

12 price, have an acknowledgment that the Commission has

13 jurisdiction insofar as service non-rate items go.

14 Secondly, it goes on to say, "In the event that the

15 Commission or any other state, federal or municipal

16 authority issues any rules, regulations or orders which

17 require PacifiCorp to alter or amend any of the

18 provisions of this agreement or to terminate or curtail

19 the delivery of firm power and energy to Nu-West,

20 PacifiCorp shall not be liable to Nu-West for damages or

21 losses of any kind whatsoever which Nu-West may sustain,"

22 et cetera, et cetera. There is no way to interpret that

23 as a saving clause for Commission jurisdiction over

24 rates.

25 All that says is if you or any other

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1 competent body with jurisdiction over PacifiCorp orders

2 them to change their manner of delivery or fulfillment of

3 the contract, then PacifiCorp is not liable to Nu-West.

4 It doesn't even say that the agreement terminates. It's

5 a fixed price contract. There's no other way to

6 characterize it.

7 Now, as to the 2001 agreement, there is --

8 again, you cannot say that a particular agreement is

9 subject to the tariff standard or the contract standard,

10 as Mr. Woodbury does, as if there were only black or

11 white and it's one or the other. Contracts mean what

12 contracts say. Yes, there are contracts that have an

13 unmistakable Memphis clause that one could say is subject

14 to the tariff standard. In that case, the contracting

15 party becomes essentially a tariff customer class of

16 one. That's exactly what that does, but there are whole

17 gradations of meaning in between the fixed price contract

18 which says I'll serve you for X number of years at Y

19 dollars per kilowatt-hour and that's it.

20 This contract, the 2001 agreement, is

21 clearly something in between. There's no way you can

22 say, you can look at that language that survived in 8.3

23 and say that it really is a Memphis clause, because if it

24 was, they wouldn't have all of the language in there on

25 how the prices could be changed, language that says in

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1 fact it is the sole available means for changing prices.

2 None of that makes any sense. If you say 8.3 simply

3 provided that Nu-West would be treated like a tariff

4 customer, then why did they draft all of that other

5 language?

6 Now, there's a judicial rule as the

7 Chairman well knows that you have to try in construing

8 documents to give meaning to all provisions that the

9 parties include in a contract. Both Mr. Fell and

10 Mr. Woodbury's argument falls to that doctrine. If in

11 fact 8.3 reserved Commission jurisdiction to just change

12 Nu-West's prices when everybody else's change on exactly

13 the same standard, then all of that other language,

14 clause after clause of it, makes no sense whatsoever and

15 has no reason for being in the agreement.

16 That's clearly not what the parties

17 intended and I think it's quite clear, I walked you

18 through the contract, it's quite clear in my own mind

19 what the deal was. Nu-West when it signed the agreement

20 would get the prices set in the agreement for a year and

21 thereafter, January 1st of each year, they could be

22 subject to any general rate increase granted in the prior

23 year by July 1 of the year and by the way, they point out

24 not only just by July 1, by July 1 and in effect through

25 June 30th.

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1 Now, what does that tell you? The

2 January 1st adjustment is averaging any adjustment the

3 Commission makes to general rates that's in effect

4 between July 1 and June 30th. Why did they add the

5 June 30th? Because January 1, the adjustment date, is an

6 average of that entire period, so it's remarkably clear

7 if you just take the time to work through all the strings

8 of the spaghetti what the deal really was and it

9 certainly was not a tariff rate. That much is

10 indisputably clear.

11 Finally, as to -- not finally, two more

12 points. One, Mr. Fell produced an exhibit that showed

13 Nu-West with an allocation on, I assume on, a straight

14 spread of the PCA, but I would also like to refer the

15 Commission to Exhibit No. 17, page 1 of 18, this is

16 witness Zhang, and on that exhibit, if you look across in

17 the same Nu-West column, you will see that Nu-West is not

18 proposed for any rate increase. Their base rate is

19 $4 million. All the way across it reads $4 million and

20 all the way across the proposed increase reads zero. It

21 seems to me that's unmistakable and it's not unreasonable

22 for a customer to rely on that as the Company's position.

23 Last point I'd make is simply this: In the

24 dozen years or so or more, unfortunately, that I've been

25 representing industrial customers, I have always

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1 discouraged any attempt to talk about the customer's

2 economic, individual economic, situation as part of a

3 plea before the Commission. As long as there are single

4 mothers working at poorly paying jobs and seniors working

5 at McDonald's, it's hard to make a plea of poverty for a

6 corporation, but I would point out that over the past few

7 years, the industrial base in this state and elsewhere in

8 this country has been decimated and not the least of it

9 is Nu-West which just laid off 40 people within the week

10 before we got here, 10 days, I guess, before we got here

11 and I want to leave you with a final thought.

12 To the extent there is any lingering

13 suspicion among the Commission or others that we can

14 simply look to industrial customers as a source of

15 revenue that will relieve the pain of other parties and

16 not hurt them, I want to leave you with this last fact.

17 In this week's issue of Barons, I read something that

18 shocked me to my toes. Industrial or manufacturing

19 employment in this country now stands at the same level

20 as in 1955, not percentage of people employed, number of

21 people employed in manufacturing is the same as when I

22 was eight years old, so it, too, is a sector that needs

23 some attention and some consideration.

24 Thank you. That's all I have.

25 COMMISSIONER SMITH: Thank you, Mr. Ward.

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1 I don't believe any of the Commissioners have questions,

2 but I guess I do have one comment based on your last

3 remark and that is that I believe that the Idaho Public

4 Utilities Commission has a long history of not unfairly

5 burdening its industrial class customers in order to

6 favorably treat other classes and I think that was a

7 legacy left to us by past commissions in the gas industry

8 with the transportation rate, in the electricity industry

9 with cost of service that tried to accurately reflect

10 those costs through rates and I think all of Idaho has

11 benefitted from that policy and I don't think that this

12 Commission has ever engaged in a policy like that.

13 MR. WARD: Madam Chairman, I'm sorry if you

14 took that as a jab at the Commission. I meant that as an

15 observation for all parties and the reason why I think

16 it's pertinent here is because of the way this settlement

17 and stipulation came down. It wasn't meant for the

18 Commission. The fact, however, the 1955 fact, is a fact

19 for all of us to ponder.

20 COMMISSIONER SMITH: Thank you very much.

21 Mr. Shurtz.

22

23

24

25

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1 TIMOTHY J. SHURTZ,

2 produced as a witness at the instance of Timothy J.

3 Shurtz, having been first duly sworn, was examined and

4 testified as follows:

5

6 COMMISSIONER SMITH: So is Mr. Harris going

7 to get you on the record or do you want Mr. Woodbury to

8 do that?

9 THE WITNESS: We're new to this proceeding.

10 COMMISSIONER SMITH: Okay, Mr. Woodbury,

11 would you get Mr. Shurtz started, please?

12 MR. WOODBURY: Thank you.

13

14 EXAMINATION

15

16 BY MR. WOODBURY:

17 Q Mr. Shurtz, please state your full name and

18 spell your last name for the record.

19 A Timothy J. Shurtz, S-h-u-r-t-z.

20 Q And where do you reside, sir?

21 A I reside at 411 South Main, Firth, Idaho.

22 Q And you've been given intervenor status in

23 this case?

24 A Yes, I have.

25 Q And pursuant to your status, have you

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1 prepared four pages of comments?

2 A Yes, I have.

3 Q And is it your desire that those comments

4 be entered into the record in this proceeding?

5 A Yes, I do.

6 COMMISSIONER SMITH: If there's no

7 objection, we will spread the prefiled comments of

8 Mr. Shurtz upon the record as if read in full.

9 Mr. Fell.

10 MR. FELL: For clarification,

11 Madam Chairman, are these the May 1, 2002 comments in

12 opposition of the settlement proposal?

13 MR. WOODBURY: Yes.

14 COMMISSIONER SMITH: Yes.

15 MR. FELL: Thank you.

16 COMMISSIONER SMITH: Hearing no objection,

17 the comments of Mr. Shurtz will be spread upon the record

18 as if read.

19 (The following prefiled comments of

20 Mr. Timothy Shurtz is spread upon the record.)

21

22

23

24

25

357

CSB REPORTING SHURTZ (Di)
Wilder, Idaho 83676 Timothy J. Shurtz

1 Written Testimony of Timothy J. Shurtz

2 411 S. Main

3 Firth, ID 83236

4

5 May 1, 2002

6

7 In the Case #PAC-E-02-1

8

9 In opposition to the proposed settlement:

10 1. Cost of Service Study. I feel that without a cost

11 of service study in a general rate case that we have not

12 had since 1988 PacifiCorp is engaging in piece mil rate

13 making. In order to make a fair settlement all the

14 related Net Power Cost and associated expenses should be

15 examined. We should be looking at the big picture, not a

16 small segment of that picture. That is why, I feel

17 before any moneys are paid to PacifiCorp, the company

18 should be required to engage in a general rate case

19 filing.

20

21 2. The Revenue Ramifications of the Company's Filing.

22 I feel that it is important for us to have a sound

23 electric utility provider. I feel at this time, the

24 recovery of cost that the company is seeking in its

25 filing do not truly reflect the needs of the company. I

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Wilder, Idaho 83676 Intervenor Pro Se

1 also feel that while the company is entitled to a fair

2 return of its money as stated in Idaho law, a 10.7%

3 return based on the existing conditions is excessive.

4 One only has to look at the much lower interest rates

5 that exist in the general markets at this time, as well

6 as the general earnings based on the stock market, lead

7 me to believe that PacifiCorp is entitled to a fair

8 return on their money, but something much lower than

9 10.7% and again without a general rate case we are still

10 engaging in nothing more that piece mil rate making. I

11 would ask the commission to carefully look at the revenue

12 ramifications in the Company's filing and ask the

13 question, what is the need verses profit taking.

14

15 3. Power Costs PacifiCorp is seeking to recover. Are

16 these costs that PacifiCorp is seeking to recover

17 management mistakes or are they truly valid costs? Much

18 of these power cost that PacifiCorp is seeking to recover

19 was due to there inability to judge and manage there

20 power needs. PacifiCorp engaged in speculative and risky

21 contracts and also locked in any surplus power supplies

22 in those contracts that would have kept them from having

23 to buy power on the spot market. In the first two years

24 that Scottish Power has owned PacifiCorp, they have

25 misread the energy situation and have made mistakes in

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CSB REPORTING SHURTZ (Di) 2
Wilder, Idaho 83676 Intervenor Pro Se

1 management by engaging in these and other speculative

2 contracts. I believe that much of the loss that

3 PacifiCorp has suffered in excess power cost can be

4 blamed on Scottish Power's inexperience in managing their

5 American utilities. Also their relative inexperience in

6 dealing with the wholesale energy market in the United

7 States. I believe that much of the losses incurred by

8 Scottish Power/PacifiCorp is reflective of a new

9 management company coming into a market in which they had

10 not operated in before. With this in mind I believe and

11 would ask the commissioners not to penalize the people of

12 Eastern Idaho for the growing pains and lag time for

13 learning in the new management at PacifiCorp I feel the

14 commission should look closely at all these costs.

15

16 4. Rate Mitigation Adjustment. Again I must point out

17 that rate mitigation is only fair and equitable when a

18 general cost of service study as part of a general rate

19 case has been performed. I again look at the problem of

20 piece mil rate making without a general rate case and

21 accompanying cost of service study, the rate mitigation

22 adjustment is an arbitrary and unequal way of mitigating

23 cost to all classes of consumers. Again, before the

24 commission approves any RMA, in the rate structure it

25 should be based upon a general rate case and not this

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CSB REPORTING SHURTZ (Di) 3
Wilder, Idaho 83676 Intervenor Pro Se

1 piece mil rate making as proposed by PacifiCorp.

2

3 5. Whether the Company's attempted recovery of excess

4 power costs incurred in 2000/2002 violates Merger

5 Approval Condition No. 2, Reference Case No. PAC-E-99-1,

6 Order No. 28213, page 31 issued November 15, 1999, i.e.,

7 "following the merger, PacifiCorp shall not seek a

8 general rate increase effective prior to January 1,

9 2002"; see also Order No. 28213, page 31, fn. 22 "our

10 Order imposes the additional condition of a rate

11 moratorium for approximately two years. PacifiCorp is

12 entitled to seek a rate increase to be effective in year

13 three if it can prove that its revenue requirement is

14 deficient." When condition #2 the rate moritorium was

15 made as an additional protection to insure that there

16 would be no rate increases in the first two years of

17 Scottish Power's ownership, almost to an individual the

18 utility customers in Idaho took the rate moritorium to

19 protect us from unforeseen management problems that the

20 new management might experience in the first two years of

21 its ownership of PacifiCorp. I felt that it was a

22 tangible benefit given to us by the owners of Scottish

23 Power, to assure us of the high standards and expertise

24 in management that they said they were going to bring to

25 Utah Power. I also feel that had we been told that the

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CSB REPORTING SHURTZ (Di) 4
Wilder, Idaho 83676 Intervenor Pro Se

1 rate moritorium would be nothing more than a deferral of

2 cost that would lead to a retroactive rate increase the

3 vast majority of leaders who change their position would

4 not have change their positions. To quote Senator Lee,

5 the last time I spoke with him he called the rate

6 moritorium "a sham moritorium". Whether written or

7 verbally implied, the Utah Power customers then as well

8 as now believe that the rate moritorium implies that no

9 deferred cost or retroactive rate increase can be

10 collected or enacted based on events during this rate

11 moritorium. And again, I would also refer you to

12 Commissioner Hansen's descenting opinion in my petition

13 for clarification. I also feel that the majority opinion

14 of the commissioners did not invalidate the rate

15 moritorium. In their opinion the rate moritorium was to

16 protect the rate merger credit so that the Idaho/Utah

17 power customers would receive the full benefit of the

18 rate merger credit, which due to the recovery of cost in

19 this agreement the Idaho/Utah power customers will not

20 receive its intended long term benefits. I also believe

21 that another issue or reason for the rate moritorium was

22 the protection against management mistakes that we as

23 state and community leaders saw as a potential for costly

24 management mistakes while training on the job by the

25 Scottish Power managers of PacifiCorp. I would encourage

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1 the commissioners to re-examine merger condition #2 from

2 the point of view of the 50,000+ power customers of Utah

3 Power on what we believed the rate moritorium is and what

4 the company says it is, and enact the terms that we feel

5 the rate moritorium means and throw out this recovery of

6 cost.

7

8 6. Whether it was appropriate (and perhaps prudent) for

9 PacifiCorp to enact economic curtailments of usage

10 (Company imposed interruptions of power) as opposed to

11 the alternative purchase of high cost power. I would

12 point out on this issue that again that it was a lack of

13 experience by Scottish Power in managing such a diverse

14 company as PacifiCorp, and that their decisions to buy

15 power at high cost verses to impose interruptions of

16 power was again a lack of management experience by a

17 foreign company in an American Market.

18

19 7. A review of Company sales contracts executed in

20 2000/2001. I believe that a review of PacifiCorp's sales

21 contracts shows a lack of experience by the new

22 management in dealing in the electric markets in the

23 United States, and that these excess power costs might

24 not have happened in the absence of the merger or buy out

25 of PacifiCorp by Scottish Power. Before Scottish Power

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CSB REPORTING SHURTZ (Di) 6
Wilder, Idaho 83676 Intervenor Pro Se

1 bought PacifiCorp, PacifiCorp engaged in sales contracts

2 without the disastrous losses suffered by PacifiCorp,

3 since the Scottish Power buy out. Again I believe that

4 part or most of the losses incurred in this area can be

5 traced to the changes in management caused by

6 PacifiCorp's being bought out by Scottish Power.

7 Scottish Power's inexperience in the American energy

8 market. I would ask the commissioners to carefully

9 review these contracts to see what part of inexperienced

10 and the new management of Scottish Power played in their

11 losses in this area.

12

13 8. The timing of the loss of the Company's Hunter coal

14 generation plant in 2000/2001 and related cause(s)

15 therefore. As to the question of the Hunter coal

16 generation plant. I would encourage the commissioners to

17 hold off on any decision of customer responsibility for

18 the failure of the Hunter Plant until case UM855 now

19 before the Oregon Commission is fully litigated. Also

20 review the Wyoming Utility Commission's findings in this

21 case as well. I also believe that if PacifiCorp cannot

22 tell us why the Hunter generation plant failed, it shows

23 a lack of management of that facility on their part. And

24 the fact that they had to buy on the open market more

25 expensive power is again another indication of management

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CSB REPORTING SHURTZ (Di) 7
Wilder, Idaho 83676 Intervenor Pro Se

1 problems caused by the Scottish power merger. I would

2 also ask was there any insurance or other renumeration

3 collected on the losses suffered for the Hunter Plant.

4 Finally, I feel as I have previously stated that it is in

5 the best interest of the people of Idaho for the

6 commissioners to wait and see what the findings of the

7 Oregon commission in relationship to the Hunter outage

8 and what they feel is the rate payers responsibility for

9 this outage and its related causes.

10

11 In concluding my testimony, I feel that much of this

12 agreement was done in haste without the benefit of a cost

13 of service study and should have been done in a general

14 rate case not this piece mil rate making that this

15 stipulation and proposed settlement is nothing more than

16 piece mil rate making. I also believe that condition #2

17 of the merger agreement, should be invoked and this whole

18 case of cost recovery should be thrown out. And in a

19 general rate case look at only the conditions that exist

20 for January 1, 2002, should Utah power seek any

21 additional income from its customers. I believe that the

22 commission should carefully look at the losses incurred

23 by the new management of PacifiCorp and ask the questions

24 are these losses because of on the job training by the

25 new management of Scottish Power and their inexperience

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CSB REPORTING SHURTZ (Di) 8
Wilder, Idaho 83676 Intervenor Pro Se

1 in the American market. I would request that should the

2 commissioners decide that merger condition #2 has no

3 effect on this recovery of cost that they review other

4 agreements that have been made and will be made in other

5 PacifiCorp states to make sure that if Utah Power is to

6 be allowed a recovery of cost that it be equal and fair

7 as reflected by what percentage of our cost should be as

8 compared to other states.

9

10 Respectively,

11

12 Timothy J. Shurtz

13

14

15

16

17

18

19

20

21

22

23

24

25

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Wilder, Idaho 83676 Intervenor Pro Se

1 (The following proceedings were had in

2 open hearing.)

3 COMMISSIONER SMITH: Okay, I guess if

4 there's no further questions, we are ready for

5 cross-examination.

6 Mr. Ward.

7 MR. WARD: No questions.

8 COMMISSIONER SMITH: Mr. Olsen.

9 MR. OLSEN: No questions.

10 COMMISSIONER SMITH: Mr. Budge.

11 MR. BUDGE: No questions.

12 COMMISSIONER SMITH: Mr. Woodbury.

13 MR. WOODBURY: I have no questions. Thank

14 you.

15 COMMISSIONER SMITH: Mr. Fell.

16 MR. FELL: Yes, thank you.

17

18 CROSS-EXAMINATION

19

20 BY MR. FELL:

21 Q Mr. Shurtz, I'd like to have you turn to

22 paragraph 3 in your comments. You comment in the middle

23 of that paragraph about the blame that should be laid on

24 Scottish Power's inexperience in managing their American

25 utilities and in dealing with wholesale energy markets in

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CSB REPORTING SHURTZ (X)
Wilder, Idaho 83676 Timothy J. Shurtz

1 the United States. Do you see that?

2 A Yes, I do.

3 Q Are you aware of whether it is Americans or

4 Scots who are actually managing the power supply business

5 at PacifiCorp?

6 A No, I'm not, but I'm also aware there was a

7 change in management and whether it is the Scots or the

8 Americans that are managing PacifiCorp, there still is

9 some change in direction of management at the top in

10 regards to style with any change of management.

11 Q Do you have any specific facts that you

12 could give us that would support these claims?

13 A During this energy -- this unpleasantness

14 that we went through, it seems in my -- as far as facts,

15 this is my perception, excuse me, that PacifiCorp is

16 always being caught a little bit behind the curve.

17 Q Did you hear Mr. Watters' testimony about

18 the other utilities that suffered losses?

19 A Yes, I did.

20 Q And are you familiar with the bankruptcy of

21 Pacific Gas & Electric Company?

22 A Yes, I was familiar with that.

23 Q And that's a more extreme situation than

24 PacifiCorp is in, isn't it?

25 A Not knowing the case in their bankruptcy

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CSB REPORTING SHURTZ (X)
Wilder, Idaho 83676 Timothy J. Shurtz

1 totally, other than what I've heard, I really am not in a

2 position to comment on it.

3 Q Isn't it the case that you also aren't in a

4 position to comment on how much the Scottish ownership

5 influenced any of these power transactions?

6 A I am commenting from what my perception is

7 as a ratepayer and as a customer and in the reading that

8 I have done in the case, so in one case, yes, I may not

9 because I do not know what the inner workings of Scottish

10 Power is, but I do know that it appears to me that we had

11 a utility here that was very responsive at one time and

12 now it seems to have had some problems cutting in the new

13 management. That's my perception.

14 Q Wouldn't it be more accurate to say that

15 those are your opinions about those matters?

16 A Well, perception and opinion are probably

17 about the same thing.

18 Q Now, in paragraph 5, about a third of the

19 way down, you talk about the rate moratorium and you seem

20 to suggest that the rate moratorium was an agreement

21 offered by Scottish Power. Do I read you correct on

22 that?

23 A Yes, but I also stand corrected on that.

24 As mentioned in the hearings last night, that was

25 something that was imposed on Scottish Power by the

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Wilder, Idaho 83676 Timothy J. Shurtz

1 Commission, but Scottish Power still signed the

2 agreement. Whether it was imposed on Scottish Power or

3 whether you agreed to it, your signature still is on the

4 agreement on that merger, so that rate moratorium held

5 you to that standard depending on what the Commission

6 decides.

7 Q I understand. Now, you also state that the

8 rate moratorium should be inflexible in terms of any rate

9 adjustments at all during the period or relating to costs

10 in the period. Do I read you correctly on that?

11 A Yes. I've felt all along, and I think

12 Nu-West's attorney referred to it as well, had the price

13 market changed in favor of the utility and,

14 unfortunately, it did not, we would probably not have

15 seen PacifiCorp willing to give us a price reduction

16 during that two years because it was under that

17 moratorium.

18 Q Now, in previous years PacifiCorp sold

19 property. In one case, for example, they sold the

20 service territory up in Sandpoint. Once that transaction

21 was closed, the property was sold, PacifiCorp got the

22 gain on that sale, that was a past event as well, should

23 PacifiCorp have been allowed to keep all of that gain

24 from that sale?

25 A I'm not aware of that sale and I'm not able

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Wilder, Idaho 83676 Timothy J. Shurtz

1 to comment on the conditions under which that sale was

2 made under. Again, that might be looked at, should be

3 looked at, in a general rate case which we haven't had

4 since 1988.

5 Q Well, if that event had occurred in the

6 moratorium period, would customers have been entitled to

7 any of that gain from that sale?

8 A I think a deal is a deal as was told early

9 in the negotiations, no, because we made -- I felt in my

10 mind, and this is my perception or opinion, I felt that

11 that rate moratorium was a fixed thing. When we went

12 into it and the Commission put that rate moratorium and

13 the contract was signed, we as customers accepted the

14 Commission's Order and what happened during that two-year

15 period was a -- what's the word I'm looking for here -- I

16 would almost want to say a cooling off-period so that the

17 new management at PacifiCorp could get a handle of what's

18 going on and two, that we would not be -- we'd be

19 protected against the inflexibilities or the

20 flexibilities that happen in this market and, of course,

21 as has been pointed out, nobody could see, no one had a

22 crystal ball to see what the future was going to be and

23 it came as a surprise.

24 Q So it's your position, then, that the

25 Commission would not have had the flexibility to take

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Wilder, Idaho 83676 Timothy J. Shurtz

1 into account some kind of windfall profits that

2 PacifiCorp might earn during that period? That would

3 just be lost to customers?

4 A It's not my position to decide what the

5 Commission would decide. It's within their realm of what

6 they decide.

7 Q Fair enough, thank you. In paragraph 6,

8 you talk about the Company's decision to buy power at

9 high cost versus to impose interruptions of power. Just

10 to clarify, are you talking about involuntary

11 interruptions of power, that the Company could have

12 involuntarily interrupted customers, that is, against the

13 customer's wish, rather than buy power?

14 A No, I think if you look at, and forgive me,

15 I'm not an expert here, Mr. Fell --

16 Q That's okay.

17 A -- if you look at Monsanto's effort to help

18 alleviate the situation, it looks like a clear case of

19 the Company not looking at all the options and Monsanto

20 offered an interruption and to work with them and I also

21 believe that other employers, industrials, I work for

22 one, that -- let's take an example in a natural gas

23 situation. We'll take a curtailment when it's necessary

24 to deliver power to essential things. I think with

25 curtailment in mind, it could have been looked at to work

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Wilder, Idaho 83676 Timothy J. Shurtz

1 with the community as you did work with the irrigators

2 and other aspects. The program probably could have been

3 pushed a little further.

4 Q Let me ask you something because I don't

5 want to put company names on this, let's just take a

6 hypothetical company that has a business cycle that is

7 very busy through the year and through the Christmas

8 season, for example, and they just customarily take

9 January off. Now, let's say that company came to Utah

10 Power in December and said we've got a deal for you. If

11 you pay us $100,000, we will shut down in the month of

12 January, is that a deal the Company should take?

13 A If you need that power and it's within the

14 guidelines that are for wheeling, I guess the word is

15 wheeling, in electricity.

16 Q I was positing, though, a situation where

17 they were not going to be consuming any electricity in

18 January.

19 A Well, they're still making an offer. I

20 don't know what -- I know with specific companies that

21 I've worked with or been involved in, we do -- we can

22 plan our downtime and if I didn't get a deal -- if I were

23 making that offer to you, if I didn't get a deal in

24 January, I'd say, well, okay, I'd walk away and maybe you

25 might not want that power in January and instead have me

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Wilder, Idaho 83676 Timothy J. Shurtz

1 take that power, then take February off, so it depends on

2 the situation.

3 Q That's fine. I will agree that it depends

4 on the situation. That's what I was trying to get to.

5 You also have testimony here about the insurance proceeds

6 and I think we have already addressed that, haven't we?

7 A Yes.

8 MR. FELL: No further questions.

9 COMMISSIONER SMITH: Are there questions

10 from the Commissioners?

11 COMMISSIONER KJELLANDER: Yes.

12 COMMISSIONER SMITH: Commissioner

13 Kjellander.

14

15 EXAMINATION

16

17 BY COMMISSIONER KJELLANDER:

18 Q Mr. Shurtz, good afternoon.

19 A Good afternoon.

20 Q I had a couple of questions and they're

21 primarily focusing on paragraph 5 of the testimony that

22 you recently filed, and in that, it deals primarily with

23 condition No. 2 and I know you've been asked a couple of

24 questions already on it, so I apologize for beating a

25 dead horse, but what the heck. As you look at condition

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Wilder, Idaho 83676 Timothy J. Shurtz

1 No. 2, it's obviously been something that you've been

2 concerned about from the beginning of your intervention

3 status. Is it fair to say that you believed that the

4 Company had the right to file a rate case after

5 January 1, 2002 as you looked at that merger condition?

6 A It would be fair to say that they could

7 file a rate case based on conditions on January 1st,

8 2002, but I would believe that the current thing that is

9 happening now is nothing more than a retroactive rate

10 increase that they could not file during that two-year

11 period, which they did obey the Commission's ruling on

12 that merger, but we, again, as part of this stipulation,

13 we're going to be required to pay interest, a carrying

14 charge on the money.

15 Q But back to my question, and I don't mean

16 to interrupt, but as you see that, then the Company could

17 under the terms of that condition file a rate case on

18 January 1, 2002?

19 A Based on the conditions on January 1, 2002,

20 and what we are in.

21 Q Then as a follow-up, then, what you're

22 actually saying is they could file a case on January 1,

23 2002, but they couldn't include any expenses it incurred

24 during the moratorium period?

25 A Yes, that's correct.

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Wilder, Idaho 83676 Timothy J. Shurtz

1 Q Are you aware of a concept referred to as a

2 test year that is almost always a piece of any rate case

3 that's filed? Is that a concept you're familiar with?

4 A Like a normalized or --

5 Q A test year essentially is you'll look at

6 the latest 12-month period and you have the complete data

7 in that 12 months and then what you're really looking at,

8 then, is a way to essentially create a basis for

9 estimating future revenue requirements by looking at past

10 experience and by past experience, you're looking at

11 expenses, revenues and other conditions that exist, but

12 you always have a -- usually it's a 12-month period just

13 prior to the time in which you file for a rate case, so

14 with that in mind, would you say that under your logic

15 that it would be impossible for the Company to file a

16 rate case on January 1, 2002, based on your

17 interpretation of not being able to include any expenses

18 that occurred during the moratorium?

19 A Yes, I guess you're correct there, but I've

20 got to be honest with you, I'm totally lost in this. It

21 wasn't until recently that I even understood what an RMA

22 was. What I'm saying ultimately in paragraph 5, if I may

23 go on --

24 Q No, that's okay.

25 A -- the ratepayers of Idaho felt that the

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1 Commission had stepped in and done a very good job of

2 guaranteeing price stability for this two years and that

3 we had received a real benefit and maybe us generally as

4 ratepayers not understanding the intricacies of how these

5 things are looked at on a professional level in the

6 electricity market, we in our minds and in my mind today

7 perceived that as a real benefit and as Senator Lee

8 commented in his statement, his letter last night, that

9 it was a real benefit given to us and that's how we

10 perceived it and that's how I will perceive it until told

11 differently, I guess.

12 Q Well, I don't want to tell you what to

13 think and I appreciate the fact that you're not as

14 involved in regulatory processes and wouldn't expect you

15 to be, but could you see from the perspective of, let's

16 say, the utility and people who are involved in the

17 regulatory process, when you look at that condition and

18 recognize that the only way you could file a rate case

19 under the terms of that condition, which would be not

20 until January 1, 2002, that the only way you could file

21 that is to have a test year that actually was isolated

22 within the confines of that moratorium period, so if you

23 were familiar with regulatory processes and you see that

24 condition, you would not conclude that you were precluded

25 from trying to recover expenses because you would have to

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1 establish a test year during that moratorium period that

2 actually looked at expenses.

3 A I felt that -- I can see -- they've got a

4 business to run, just as I have a household to run and a

5 business that I work for that stands to have some

6 negative effective from this, but I could see the

7 Commission's reasoning for allowing this accounting of

8 costs, because just to slam the door on somebody and say,

9 well, we have this, you know, the facts need to come out

10 and everything needs to be heard and it is good that

11 PacifiCorp has presented their thing because at least we

12 know and in public hearings we know what PacifiCorp is

13 saying and we can again look at our opinions and either

14 modify them or change them or be as stubborn as what I

15 am.

16 COMMISSIONER KJELLANDER: I appreciate your

17 comments and thanks also for subjecting yourself to

18 intervention in a regulatory process. We appreciate your

19 presence.

20 COMMISSIONER SMITH: I guess I'll just make

21 one comment based on Commission Kjellander's questions

22 which were pointed around when a rate case could be filed

23 and note that the condition says that they shall not seek

24 a general rate increase for its Idaho service territory

25 effective prior to January 1, 2002, and I think you have

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1 very correctly characterized what the Commission was

2 trying to do, which was to give price stability for two

3 years, so what that means to me is that a rate case could

4 have been filed in 2001, but rates could not have been

5 changed or been made effective prior to January 1, 2002,

6 and I think by doing that the Commission gave the

7 customers what we sought to give them, which was price

8 stability for two years and I believe Commissioner Hansen

9 has a question.

10 COMMISSIONER HANSEN: Just a comment. You

11 reference Senator Lee in No. 5 in your comment and I

12 guess just a comment I'd like to make is that last night

13 at the hearing there were some comments made about

14 Senator Lee had had conversations with certain parties of

15 PacifiCorp and that they had guaranteed this or

16 guaranteed that, but I'd just like to say that when the

17 Commission Order came out and was signed, that's what

18 real. It isn't an individual from a company making a

19 commitment, they can't, and at that time if Senator Lee

20 or any other party thought there was a three- or a

21 five-year freeze as was mentioned last night or they

22 think the moratorium is different than it was, when that

23 Order came out from the Commission, they had the right to

24 ask the Commission to reconsider.

25 They could have come before the Commission

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1 and said hey, this isn't the understanding the Company

2 has made. I guess what I'd like to say to you is they

3 had their day in court. They could have come before the

4 Commission and said hey, we understand it differently.

5 We've been told differently, but I just wanted to make a

6 statement here that when the Order was published, all

7 parties that gave testimony in that case was mailed a

8 copy of that Order. I mean, we sent out probably

9 literally hundreds --

10 THE WITNESS: Yeah, I received one.

11 COMMISSIONER HANSEN: -- and so if anyone

12 looked at that Order and said oh, it's two years, but

13 hey, up at my cabin the CEO said it was going to be three

14 to five or some lobbyist said it was going to be five

15 years or so, that wasn't so. They should have questioned

16 it at that time. I just wanted to make that comment and

17 that's all I've got to say.

18 COMMISSIONER SMITH: Did you have a

19 response?

20 THE WITNESS: Yes. In my -- I think in

21 everything I've said, I've pretty much stuck to the

22 two-year period and I've not tried to introduce all the

23 three- and five-year because, again, that's not in the

24 Commission Order. I've kind of tried to stay within the

25 Commission Order, but I'd also like to thank the

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Wilder, Idaho 83676 Timothy J. Shurtz

1 Commission and the Staff for treating me kindly as I've

2 gone through this. I've learned quite a bit and, you

3 know, I feel that can changes be made down the road, yes,

4 but also last week I was in a radio talk show and they

5 wanted me to beat up on the Commission and the Staff and

6 I didn't give them the satisfaction. My response was

7 that this Commission, the Staff is governed by the law

8 that exists right now and if you don't like the law, talk

9 to your legislators, talk to your elected officials and

10 have them change it, but until then, don't beat up on the

11 people that are charged with enforcing that law. Thank

12 you.

13 COMMISSIONER SMITH: And, Mr. Shurtz, I

14 guess I just want to thank you and I think all the

15 Commission and the Staff, probably every other party who

16 has experience in these matters, has a great deal of

17 admiration and sympathy for someone wading into what is a

18 very technical, very arcane process and law and procedure

19 and succeeding in it as you have, so we do appreciate

20 your participation.

21 COMMISSIONER KJELLANDER: I just want to

22 say that the nicest thing that had been said about the

23 Commission publicly up until your comments there were in

24 the Senate State Affairs Committee this last session when

25 a lobbyist referred to us as stingy and I really grasped

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Wilder, Idaho 83676 Timothy J. Shurtz

1 on to that because it made me feel good, but I will say

2 that your comments made me feel a whole lot better and I

3 appreciate that and thanks for recognizing that and,

4 again, we appreciate your comments.

5 THE WITNESS: Thank you.

6 (The witness left the stand.)

7 COMMISSIONER SMITH: All right, is there

8 any other matter to come before the Commission during the

9 technical portion of the hearing?

10 MR. FELL: Madam Chairman?

11 COMMISSIONER SMITH: Mr. Fell.

12 MR. FELL: One item and that is that if the

13 letter from Monsanto is admitted into the record, I

14 believe PacifiCorp sent the Commission a response to this

15 letter and I'd like to have an opportunity to submit that

16 into the record as well.

17 COMMISSIONER SMITH: All right, would there

18 be any objection to marking the letter that was

19 previously handed out by Commissioner Hansen as Exhibit

20 No. 601 and if Mr. Fell would provide PacifiCorp's

21 response, we could label that your next number.

22 MR. FELL: Which would be 22.

23 COMMISSIONER SMITH: Exhibit No. 22?

24 MR. FELL: Yes.

25 COMMISSIONER SMITH: Would there be any

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1 objection to admitting those two letters into the record

2 as Exhibit 601 and 22?

3 Mr. Budge.

4 MR. BUDGE: We certainly have no objection

5 to 601, but I think in fairness, we should have an

6 opportunity to look at whatever that reply letter is. I

7 doubt that we will an objection. Having not seen it, I

8 think we'd like to have that opportunity to reserve the

9 right to object. I have no clue what that is.

10 COMMISSIONER SMITH: Okay, what I'm going

11 to do, Mr. Budge, is mark it, PacifiCorp will provide it,

12 you may discover you've already seen it and it just

13 refreshes your memory. If you do have an objection,

14 would you please file one in writing --

15 MR. BUDGE: Certainly.

16 COMMISSIONER SMITH: -- within three days

17 of receiving it?

18 MR. BUDGE: Fine, thank you.

19 COMMISSIONER SMITH: When can you provide

20 that, Mr. Fell?

21 MR. FELL: By Friday.

22 COMMISSIONER SMITH: Okay; so by Friday

23 Mr. Fell will have provided it to the Commission and to

24 the parties. That means by --

25 MR. FELL: We would have to fax it, I

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1 suppose, to make sure they have it or do an overnight

2 delivery, something like that.

3 COMMISSIONER SMITH: I believe the

4 Commission may even an original, maybe we could rustle

5 one up and so by next Wednesday.

6 MR. BUDGE: That's fine. I just was not

7 aware of it and apparently we haven't seen it and I'm a

8 little hesitant to stipulate to something you don't know.

9 COMMISSIONER SMITH: Very good lawyering,

10 Mr. Budge.

11 (Commission Exhibit No. 601 was

12 admitted into evidence.)

13 (PacifiCorp Exhibit No. 22 was marked

14 for identification.)

15 Any other matters?

16 MR. FELL: None, thank you.

17 COMMISSIONER SMITH: Then we will conclude

18 the technical portion of the hearing and there is a

19 workshop in this location commencing at 6:00 p.m. tonight

20 to be followed by another public hearing of the

21 Commission at 7:30. Mr. Olsen.

22 MR. OLSEN: Yes, Madam Chairman, with

23 respect to filing a request for intervenor funding, I

24 would like to request an extension of time or a deadline

25 to file that on behalf of the Idaho Irrigation Pumpers

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1 Association.

2 COMMISSIONER SMITH: And when might your

3 filing be ready to be filed?

4 MR. OLSEN: Well, basically, at the

5 conclusion of these hearings, I think our work will be

6 finished, so we can get that request together.

7 COMMISSIONER SMITH: Today will be the

8 conclusion of the proceedings, so how about next Friday?

9 MR. OLSEN: That would be fine.

10 COMMISSIONER SMITH: Mr. Shurtz?

11 MR. SHURTZ: I would like to on behalf of

12 myself and my attorney and those who did the research,

13 I'd like to ask the same.

14 COMMISSIONER SMITH: Well, if we establish

15 a date for filing intervenor funding petitions, that will

16 apply to all intervenors.

17 MR. SHURTZ: Okay, thank you.

18 COMMISSIONER SMITH: I'm trying to

19 recollect what the date will be a week from Friday and

20 it's not coming to me. The 17th? So petitions for

21 intervenor funding should be received at the Commission

22 no later than May 17.

23 Any other items? So we will be in recess

24 until 7:30 p.m. Thank you all for your participation.

25 (The Hearing recessed at 4:20 p.m.)

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