WWP69AFN.txt

1 SANDPOINT, IDAHO, WEDNESDAY, JUNE 9, 1999, 1:30 P. M.

2

3

4 COMMISSIONER SMITH: All right, welcome

5 back, everyone.

6 Mr. Woodbury, I think we're ready for your

7 witnesses now.

8 MR. WOODBURY: Thank you, Madam Chair.

9 Staff's first witness would be Randy Lobb.

10

11 RANDY LOBB,

12 produced as a witness at the instance of the Staff,

13 having been first duly sworn, was examined and testified

14 as follows:

15

16 DIRECT EXAMINATION

17

18 BY MR. WOODBURY:

19 Q Mr. Lobb, will you please state your full

20 name?

21 A It's Randy Lobb.

22 Q And for whom do you work and in what

23 capacity?

24 A I work for the Idaho Public Utilities

25 Commission as the engineering supervisor.

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CSB REPORTING LOBB (Di)
Wilder, Idaho 83676 Staff

1 Q And in that capacity, did you have occasion

2 to prepare prefiled testimony in this case consisting of

3 21 pages and Exhibits 101 through 106?

4 A Yes.

5 Q Have you had the opportunity to review that

6 prior to this hearing?

7 A Yes, I have.

8 Q And is it necessary to make any corrections

9 or changes to your testimony?

10 A Yes, I have one correction. On page 13,

11 line 21, the "1996" should be "1997."

12 Q And are there any other corrections or

13 changes necessary?

14 A No, there is not.

15 Q If I were to ask you the questions put

16 forth in your testimony, then, would your answers be

17 otherwise the same?

18 A Yes, they would.

19 MR. WOODBURY: Madam Chair, I'd ask that

20 the testimony be spread on the record and I have a couple

21 of additional questions of Mr. Lobb with respect to the

22 balancing account proposed by Mr. Falkner in his rebuttal

23 testimony.

24 COMMISSIONER SMITH: If there's no

25 objection, we'll spread the prefiled testimony of

914

CSB REPORTING LOBB (Di)
Wilder, Idaho 83676 Staff

1 Mr. Lobb upon the record as if read.

2 (The following prefiled testimony of

3 Mr. Randy Lobb is spread upon the record.)

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CSB REPORTING LOBB (Di)
Wilder, Idaho 83676 Staff

1 Q. Please state your name and business address

2 for the record.

3 A. My name is Randy Lobb and my business

4 address is 472 West Washington Street, Boise, Idaho.

5 Q. By whom are you employed?

6 A. I am employed by the Idaho Public Utilities

7 Commission as Engineering Supervisor.

8 Q. What is your educational and professional

9 background?

10 A. I received a Bachelor of Science Degree in

11 Agricultural Engineering from the University of Idaho in

12 1980 and worked for the Idaho Department of Water

13 Resources from June of 1980 to November of 1987. I

14 received my Idaho license as a registered professional

15 Civil Engineer in 1985 and began work at the Idaho Public

16 Utilities Commission in December of 1987. My duties at

17 the Commission include analysis of utility rate

18 applications, rate design, tariff analysis and customer

19 petitions. I have testified in numerous proceedings

20 before the Commission including cases dealing with rate

21 structure, cost of service, line extensions, developer

22 complaints and facility acquisitions.

23 Q. What is the purpose of your testimony today?

24 A. The purpose of my testimony is to detail the

25 test year power supply adjustments proposed by Avista

916

WWP-E-98-11 LOBB, R (Di) 1
4/23/99 Staff

1 Corporation dba Avista Utilities - Washington Water Power

2 Division (Avista; Company; WWP) in this case and describe

3 my investigation of those adjustments. I will also make

4 recommendations with respect to hydro power relicensing

5 cost recovery.

6 Q. Are you sponsoring any exhibits?

7 A. Yes. I am sponsoring Staff Exhibit Nos. 101

8 through 106.

9 Q. Please summarize your testimony.

10 A. The test year power supply adjustments

11 proposed by the Company in this case can generally be

12 broken down into three different categories. They are:

13 contract expiration/initiation, changes in existing

14 contract rates/terms, and normalization of loads and

15 water conditions to determine normalized power supply

16 expenses. As a result of these adjustments, the Company

17 has proposed a net increase in test year expenses of

18 $15.52 million.

19 My investigation of test year power supply

20 adjustments included evaluation of known and measurable

21 changes through December of 1999 and June of 2000 and

22 replication of the Company's dispatch simulation model

23 and evaluation of its inputs and assumptions. I

24 specifically focused on short-term sales and purchases

25 and long-term wholesale sales and purchase contracts.

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WWP-E-98-11 LOBB, R (Di) 2
4/23/99 Staff

1 I found that the power supply pro forma

2 adjustments proposed by the Company adequately reflect

3 known and measurable changes that will occur through June

4 of 2000. I also found that the dispatch simulation model

5 adequately reflects anticipated dispatch of Company

6 resources, the availability and price of regional surplus

7 energy, the availability of hydro resources, and the

8 contractual cost of fuel for Company-owned thermal

9 resources. Therefore, as a result of my investigation, I

10 recommend that the Commission accept the power supply

11 adjustments as proposed by the Company. However, I also

12 recommend that the Company be directed to separately

13 account for short-term speculative and retail load

14 serving transaction revenues and expenses as well as the

15 operational cost of those activities.

16 Finally, I recommend that $860,000 of the

17 $2.018 million hydro power relicensing expenses proposed

18 by the Company be excluded from the pro formed test year.

19 The recommended reduction is due in part to a

20 transposition error and in part to elimination of

21 expenses that are not known and measurable.

22 Power Supply Adjustments

23 Q. Have you reviewed the testimony of Company

24 witness Norwood and the power supply adjustments shown in

25 Exhibit No. 6?

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WWP-E-98-11 LOBB, R (Di) 3
4/23/99 Staff

1 A. Yes. I have reviewed Mr. Norwood's

2 testimony, Exhibit No. 6, Company workpapers that support

3 the exhibit and Company responses to Staff production

4 requests.

5 Q. What did you find with respect to the

6 proposed power supply adjustments?

7 A. I found that the 93 proposed adjustments to

8 the 1997 test year revenue and expenses can generally be

9 divided into three main categories. They are:

10 1) adjustments due to either the expiration of an

11 existing contract or the initiation of a new contract;

12 2) adjustments due to specific, projected or estimated

13 changes in contract rates or charges; and 3) adjustments

14 that result from the dispatch simulation model.

15 Staff Exhibit No. 101, entitled 1997 Test

16 Year Power Supply Adjustments, provides a categorical

17 breakdown of power supply expense and revenue adjustments

18 for total Company and the Idaho jurisdiction. For the

19 Idaho jurisdiction, expenses have been reduced by $47.44

20 million and revenues have been reduced by $62.95 million

21 for a net increase in revenue requirement of $15.516

22 million.

23 Q. Why have you divided the adjustments into

24 the three categories?

25 A. As stated in Mr. Norwood's testimony, the

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WWP-E-98-11 LOBB, R (Di) 4
4/23/99 Staff

1 Company has included pro forma power supply adjustments

2 to reflect power costs for the twelve-month period

3 beginning July 1, 1999 and ending June 30, 2000. In my

4 review of the Company workpapers for each adjustment, I

5 found that many of the adjustments were the result of

6 changes in wholesale power contracts from 1997 through

7 June of 2000. Moreover, many more of the adjustments

8 reflected contractual rate and cost changes for services

9 purchased, services rendered and acquisition of fuel

10 supplies over the same period. In evaluating whether or

11 not an adjustment was known and measurable, I looked at

12 the method used to determine the change from the test

13 year and I established groupings accordingly. I

14 essentially came up with specific contractual changes,

15 contractual changes using historic estimates or averages,

16 and weather normalization through the dispatch model.

17 This simple separation also provides a way to show the

18 general nature and magnitude of the power supply

19 adjustments.

20 Q. Are the power supply adjustments proposed

21 by the Company and presented by Mr. Norwood reasonable?

22 A. I have reviewed the workpapers provided by

23 the Company for each of the proposed power supply

24 adjustments presented by Mr. Norwood and recommend that

25 they be approved as proposed. It is undisputed that the

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WWP-E-98-11 LOBB, R (Di) 5
4/23/99 Staff

1 specific changes such as new contracts, expired

2 contracts, and contract-specific changes in rates or

3 charges occur at a date certain and are known and

4 measurable. When expense and revenue adjustments shown

5 on line 4 of Staff Exhibit No. 101 are combined, this

6 category of adjustments represents approximately $8.04

7 million or 52% of the increased power supply revenue

8 requirement (note that a negative revenue change is the

9 same as a positive expense increase).

10 When the expense and revenue adjustments

11 shown on line 8 that represent estimated, projected and

12 miscellaneous contract changes are combined they total to

13 only $2.21 million or 14% of the increased power supply

14 revenue requirement. Although these changes are not all

15 specifically stated within a contract, I believe they

16 represent reasonable estimates based on historic

17 averages, projected third party budgets or historic

18 service costs or revenues under existing contracts.

19 The final category of expense and revenue

20 adjustments is from the dispatch simulation model and is

21 shown on lines 10 and 11 of Exhibit No. 101. After

22 extensive analysis of the simulation model, examination

23 of Company workpapers and review of production request

24 responses, I find that the adjustments for normalized

25 weather conditions, speculative sales and purchases, and

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WWP-E-98-11 LOBB, R (Di) 6
4/23/99 Staff

1 fuel price changes for thermal resources are reasonable.

2 When added together, this category of adjustments

3 represents $5.27 million or 34% of the increased power

4 supply revenue requirement. I will discuss the dispatch

5 simulation model and the associated adjustments in more

6 detail later in my testimony.

7 Q. Is it appropriate for the Company to pro

8 form the 1997 test year to reflect power supply costs for

9 the period July 1, 1999 through June 30, 2000?

10 A. I believe that it is reasonable to allow

11 adjustments that reflect power supply cost during the

12 period proposed. In reaching my conclusion, I evaluated

13 several different factors including the known and

14 measurable nature of the adjustments which I have already

15 discussed, the freshness of the test year which will be

16 two years old by the time this case is completed and

17 whether or not the adjustments are independent of future

18 retail load conditions. I also evaluated when these

19 changes actually occur and whether a more current period

20 would be appropriate.

21 I found that the pro forma adjustments

22 proposed by the Company represent power supply cost

23 changes that have or will occur between 1997 and June of

24 2000. The Company resources with the adjusted costs are

25 then used to determine the cost of meeting test year

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WWP-E-98-11 LOBB, R (Di) 7
4/23/99 Staff

1 load. Moreover, based on the Company's response to Staff

2 Production Request No. 7 regarding adjustment through

3 December of 1999 and an itemized review of each proposed

4 adjustment, I find that the power supply cost changes

5 primarily occur before the end of 1999. Therefore, net

6 power supply costs do not change significantly with the

7 later pro forma period.

8 Dispatch Simulation Model

9 Q. You stated that the power supply

10 adjustments proposed by Mr. Norwood were reasonable. How

11 did you evaluate the adjustments that result from running

12 the dispatch simulation model?

13 A. The first step in evaluating the expense

14 adjustments that result from normalizing resource

15 dispatch was to replicate the Company's dispatch

16 simulation model. By replicating the model, I was able

17 to better understand the relationships between energy

18 demand, supply energy and market conditions in the

19 northwest. I then evaluated the hydro generation and

20 market conditions input data provided by third parties,

21 the long-term contract demand obligations and resources

22 as adjusted in the pro forma test year, and the monthly

23 energy as calculated by the model for short-term

24 purchases/sales and for each Company-owned thermal

25 resource. The final step was to evaluate the adjusted

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WWP-E-98-11 LOBB, R (Di) 8
4/23/99 Staff

1 fuel price for each thermal resource that was applied

2 within the model to determine annual fuel cost.

3 Q. What did you find out about the dispatch

4 model and the relationships mentioned above?

5 A. I found that according to the model, the

6 availability of spot market energy and therefore the spot

7 market price establish the thermal fuel expense

8 regardless of the Company's retail load or long-term

9 contract obligations. For example, Staff Exhibit No. 102

10 compares dispatch simulation model results when load

11 conditions change. The results demonstrate that there is

12 no change in annual thermal fuel expense when firm

13 wholesale obligations are excluded from load. This occurs

14 because model logic dictates that resources never run

15 when spot prices are below the incremental cost of

16 operating the resource and they always run when the spot

17 price is above the incremental cost of operating the

18 resource. The only things that change are the spot

19 market purchases and the spot market sales.

20 Q. Are the regional energy surplus and the spot

21 market prices used in the model appropriately determined?

22 A. Yes, I believe that they are. As indicated

23 in Mr. Norwood's testimony, the regional energy surplus

24 used in the model is determined by a hydro

25 regulation/headwater benefits model ran by the Northwest

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WWP-E-98-11 LOBB, R (Di) 9
4/23/99 Staff

1 Power Pool (NWPP). My review of workpapers and

2 production request responses regarding the NWPP model

3 convinces me that the model provides an adequate estimate

4 of surplus energy conditions in the northwest. Moreover,

5 the NWPP model results used in WWP's dispatch model were

6 developed independently for use by many northwest

7 utilities and do not appear to have been influenced by

8 WWP for this case.

9 The spot market energy prices established

10 by WWP for use in the dispatch model have been logically

11 derived using the regional surplus established by the

12 NWPP model and the incremental cost of resources likely

13 to operate under a range of regional surplus conditions.

14 I have verified from the dispatch model that the average

15 weighted cost of energy purchased or sold over the 60

16 years of flow records is $18.81 per Megawatt Hour (Mwh).

17 This compares to the 1998 weighted rate of about $22 per

18 Mwh as calculated from WWP's 1998 Power Cost Adjustment

19 (PCA). The lower average rate results in a conservative

20 estimate of net secondary transaction costs calculated by

21 the model

22 Q. Are the short-term purchase and short-term

23 sales adjustments shown on Norwood's Exhibit No. 6

24 appropriate?

25 A. Yes. Although the purchase expense and

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WWP-E-98-11 LOBB, R (Di) 10
4/23/99 Staff

1 sales revenue adjustments shown are quite large

2 ($174.9 and $182.7 million respectively), these accounts

3 include both excess short-term transactions that occurred

4 as a result of very good test year water conditions and

5 speculative purchases and sales transactions undertaken

6 by WWP that were unrelated to meeting retail/wholesale

7 load or selling excess generation. The first category of

8 sales and purchase transactions consists of economy

9 purchases to meet load or sales of excess Company

10 resources over and above the level that the dispatch

11 simulation model estimates would occur under normal water

12 conditions. Profits from this category of transactions

13 are shared by the Company's retail customers through the

14 PCA.

15 The second category is speculative market

16 transactions that have nothing to do with meeting retail

17 load or selling excess Company resources and neither

18 profit nor loss are shared with the Company's retail

19 customers. Therefore, the test year sales revenues and

20 purchase expenses should be adjusted to reflect only

21 those purchases and sales that occur under normal water

22 conditions as determined by the dispatch simulation

23 model.

24 Q. Shouldn't the Company's retail customers

25 share in the benefits derived from the speculative

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WWP-E-98-11 LOBB, R (Di) 11
4/23/99 Staff

1 transactions when undertaken by the regulated Company?

2 A. No. Staff believes that the speculative

3 transactions are a discretionary activity of the

4 regulated Company that are risky and not always

5 profitable. If ratepayers are allowed to share in the

6 profits they would also be subject to the losses should

7 they occur. Staff believes that the Company's retail

8 customers should not be subject to such risks.

9 Q. If the Company's retail customers are

10 insulated from the profits and losses of speculative

11 transactions, shouldn't the operational expenses incurred

12 by the Company for these activities also be excluded?

13 A. Yes, they should be excluded and it was

14 Staff's understanding that they were excluded within the

15 cost allocation process. However, Staff has been unable

16 to identify all of the direct and overhead costs

17 associated with the marketing functions, determine how a

18 portion of these costs could have been excluded or

19 develop an appropriate method to allocate the costs

20 intra-company. A large part of the problem lies in

21 identifying the actual breakdown of speculative and load

22 serving transactions that occurred in 1997 and

23 determining whether such a breakdown is relevant to

24 subsequent years. Staff continues to believe that the

25 incremental operational cost of the speculative

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WWP-E-98-11 LOBB, R (Di) 12
4/23/99 Staff

1 activities is relatively small on an Idaho jurisdictional

2 basis.

3 Nonetheless, Staff recommends that the

4 Company be directed to establish separate accounting that

5 distinguishes between speculative and retail load

6 transaction revenues and expenses as well as the

7 operational costs of those activities.

8 Q. What other issues did you investigate using

9 the dispatch simulation model?

10 A. I investigated fuel price changes associated

11 with Company-owned thermal resources, and the effect of

12 firm wholesale sales and purchase contracts on annual

13 expenses.

14 Q. What effect did the changes in fuel prices

15 at Company-owned thermal resources have on net expenses?

16 A. The dispatch simulation model was used by

17 the Company to make a single thermal fuel adjustment for

18 each resource even though each adjustment was made up of

19 two parts. The first part is for increased operation of

20 the thermal plants that would occur in a normal water

21 year. The 1997 test year was wetter than normal so hydro

22 generation was greater than normal and thermal generation

23 was generally less than normal. The second part of the

24 adjustment is for the change in thermal fuel cost at each

25 resource from actual test year prices to prices expected

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WWP-E-98-11 LOBB, R (Di) 13
4/23/99 Staff

1 during the proposed pro forma period. Staff Exhibit

2 No. 103, labeled Thermal Fuel Expense Adjustments, shows

3 the change in generation at each resource from test year

4 to normal water conditions, the proposed change in fuel

5 expense for each resource and the resulting percentage

6 change in fuel price that is required to justify the

7 overall change in fuel expense.

8 Q. Do you recommend any changes in the thermal

9 fuel adjustments proposed by the Company?

10 A. No. I believe that the dispatch simulation

11 model adequately estimates the amount of energy that will

12 be generated at each resource under normal water

13 conditions. I also believe that the fuel price changes

14 proposed by the Company are reasonable based on my review

15 of Company workpapers. However, I also believe it is

16 important to display both the changes due to

17 normalization and the changes due to fuel price changes

18 to better understand the reasons for the adjustments.

19 Q. How did you evaluate the economic effect of

20 the Company's wholesale purchase and sales contracts and

21 what did you find?

22 A. Over the years the Company has made many

23 discretionary long-term firm contracts to both sell and

24 purchase on the wholesale market. The dispatch

25 simulation model includes firm off system sales of 406

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WWP-E-98-11 LOBB, R (Di) 14
4/23/99 Staff

1 average megawatts (aMw) and firm off system purchases of

2 374 aMw. By removing these contracts from the dispatch

3 simulation model and comparing the lost sales revenues

4 with the cost of the purchase contracts and power supply

5 expense changes, I was able to evaluate the overall

6 economic effect of the transactions.

7 If all wholesale transactions except

8 purchases made under the 1978 Public Utility Regulatory

9 Policies Act (PURPA) of 59 aMw are removed from the

10 dispatch simulation model, annual power supply expenses

11 increase by approximately $4.6 million. At the same

12 time, annual power supply costs decrease by approximately

13 $77 million due to elimination of the wholesale purchase

14 contracts. The resulting net change in power supply

15 expenses would be a decrease of approximately $72.4

16 million per year. This expense reduction must then be

17 compared to $78 million in annual revenues lost due to

18 elimination of wholesale sales contracts. Therefore, the

19 overall net benefit of all long-term wholesale

20 transactions is approximately $5.6 million per year.

21 Q. Do you recommend any changes to the

22 adjustments made by the Company for wholesale

23 transactions?

24 A. No. As previously mentioned, these

25 contracts contain specific terms that are undisputed. My

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WWP-E-98-11 LOBB, R (Di) 15
4/23/99 Staff

1 analysis simply shows that the discretionary long-term

2 wholesale transactions of the Company are economically

3 beneficial overall.

4 Q. Did you analyze any individual contracts in

5 this manner to determine contract specific economic

6 impacts?

7 A. Yes. I looked at the two-year Cinergy

8 purchase contract that began January 1, 1999 providing 14

9 aMw each month and I looked at the two-year Enron

10 purchase contract that begins July 1, 1999 providing 50

11 aMw each month. Removal of the Cinergy contract from the

12 resource stack results in a modeled expense increase of

13 approximately $2.6 million and a contract purchase

14 reduction of approximately $2.1 million. Therefore, the

15 net benefit of the contract according to the dispatch

16 model under normalized conditions is approximately

17 $500,000 per year.

18 Removal of the Enron contract from the

19 resource stack results in a modeled expense increase of

20 approximately $9.3 million and a contract purchase

21 reduction of approximately $10.8 million. According to

22 the dispatch model, this contract will lose approximately

23 $1.5 million annually on a normalized basis.

24 Q. Is it reasonable to include the Enron

25 contract in the resource stack given the potential cost

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WWP-E-98-11 LOBB, R (Di) 16
4/23/99 Staff

1 as estimated by the dispatch simulation model?

2 A. It appears that in the Company's judgement

3 it was riskier to rely on the spot energy market over the

4 next two years to meet firm load obligations than it was

5 to obtain a firm purchase contract from Enron. I believe

6 it is reasonable to accept the Company's judgement in

7 this instance. Without the Enron contract, the dispatch

8 model estimates on a normalized basis that spot energy

9 purchases will increase by approximately 300,000 Mwh per

10 year with 27% of those purchases occurring in the highest

11 price band. If regional spot prices escalate through

12 load growth or poor water conditions over the next two

13 years then the Enron contract becomes increasingly more

14 economical.

15 Hydro-electric Relicensing Adjustments

16 Q. Have you reviewed the testimony of Company

17 witness Falkner regarding recovery of costs associated

18 with relicensing of hydro electric facilities on the

19 Clark Fork River?

20 A. Yes. I have reviewed Mr. Falkner's

21 testimony. I have also reviewed the Company's response

22 to Staff Production Request Nos. 24 through 28 dealing

23 with relicensing and the Settlement Agreement, Volume III

24 of the Company's Federal Energy Regulatory Commission

25 (FERC) Application for a new license for Cabinet Gorge

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WWP-E-98-11 LOBB, R (Di) 17
4/23/99 Staff

1 and Noxon Rapids Hydroelectric projects.

2 Q. What is your recommendation with respect to

3 the hydro relicensing expense adjustments requested by

4 Mr. Falkner?

5 A. I recommend that the proposed O&M expense

6 adjustment of $2.018 million be reduced by $180,000 to

7 reflect a transposition error in totaling budget expenses

8 for Protection, Mitigation and Enhancement (PM&E)

9 measures provided in response to Staff Production Request

10 No. 27. I also recommend that the Company's adjustment

11 be further reduced by $680,000 to reflect hydro

12 relicensing expenses that are either one time expenses or

13 are not known and measurable. Staff Exhibit No. 104

14 shows the itemized hydro relicensing expense adjustments

15 as submitted by the Company and the summation error.

16 Staff Exhibit No. 105 shows the expense adjustment

17 proposed by the Company for each PM&E measure, the

18 adjustment recommended by Staff and the difference

19 between the two proposals.

20 Q. On what basis did you determine that some

21 expenses were not known and measurable?

22 A. A description of all PM&E measures

23 associated with the Clark Fork Settlement Agreement are

24 shown in Appendices to Volume III of the new license

25 application for the Cabinet Gorge and Noxon Rapids hydro

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WWP-E-98-11 LOBB, R (Di) 18
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1 electric projects as submitted to FERC. I have attached

2 the Funding Summary Table from Appendix U of that same

3 document labeled as Staff Exhibit No. 106 showing the

4 agreed to PM&E measures and the funding levels

5 categorized as Funds, Estimated, Budgeted and Periodic.

6 This table and the "PROPOSED OR ESTIMATED FUNDING"

7 section of each appendix provided the basis for

8 distinguishing between recurring annual expenses that are

9 known and measurable and those that are not.

10 In addition, Mr. Falkner states in

11 testimony on page 29 lines 16 through 18 that:

12 The actual costs in any year over the
course of the license will vary depending
13 upon the level of treatment of the issues
and the impact of new issues.
14

15 And the Company's response to Staff Production Request

16 No. 27 states:

17 The specific projects to be funded by
Avista Corporation are to be determined
18 by the Management Committee and
two technical committees representing
19 signatories to the Settlement Agreement.
The Committees' designation of
20 projects and studies will ultimately
determine the level of capital and O&M
21 funding.

22 Q. Would you briefly describe the rationale

23 behind each of your recommended changes to the Company's

24 proposed pro forma relicensing adjustments.

25 A. Yes. I will briefly describe my rationale

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WWP-E-98-11 LOBB, R (Di) 19
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1 for each recommended change by expense item number as

2 shown on Staff Exhibit No. 105:

3 Item No. 1 -- Change reflects actual amount shown in

4 Settlement Agreement.

5 Item No. 2 -- Company amount is a cap. Actual annual

6 expenditure is unknown.

7 Item No. 3 -- Company amount is a cap. Change reflects

8 $56,000 over two years.

9 Item No. 4 -- Company amount is initial startup only.

10 Actual annual expense is $10,000.

11 Item No. 5 -- Company amount is a one time expense not

12 to exceed $45,000

13 Item No. 6 -- Future cost unknown. Change reflects

14 actual historic annual expense of

15 $100-$200 thousand.

16 Item No. 8 -- Company amount is a one time expense.

17 Item No. 9 -- Company amount reflects estimated

18 amortization of unknown cost incurred once

19 every five years.

20 Item No. 11 --Change reflects actual two year

21 expenditures in Settlement Agreement.

22 Item No. 13 --Change reflects average of two year

23 expenditures.

24 Item No. 15 --Implementation time frame and annual

25 expenses are unknown.

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WWP-E-98-11 LOBB, R (Di) 20
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1 Item No. 17 --Annual expense from Settlement Agreement.

2 Q. Does that conclude your testimony?

3 A. Yes it does.

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WWP-E-98-11 LOBB, R (Di) 21
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1 (The following proceedings were had in

2 open hearing.)

3

4 DIRECT EXAMINATION

5

6 BY MR. WOODBURY: (Continued)

7 Q Mr. Lobb, on page 7 of his rebuttal

8 testimony, Mr. Falkner proposes a balancing account to

9 capture the difference between hydro relicensing and O&M

10 expenses included in rates and those actually expended in

11 any given year. He also proposes that the deferred

12 relicensing expense balance be consolidated with the PCA

13 deferral account subject to refund or surcharge based

14 upon the currently authorized $2.2 million PCA trigger

15 mechanism. What is your response to Mr. Falkner's

16 proposal?

17 A Well, first of all, I understand the

18 problems associated with having a flexible license and

19 the difficulty in specifically identifying expenditures

20 that might occur on an annual basis, so I'm not opposed

21 to the concept of a balancing account; however, I am

22 opposed to combining the balancing account with the PCA

23 for two reasons: First of all, the PCA has a

24 $2.2 million trigger that I believe the Company could

25 delay or manipulate or otherwise change when that might

937

CSB REPORTING LOBB (Di)
Wilder, Idaho 83676 Staff

1 occur simply by altering the expenditures for the

2 relicensing account.

3 Secondly, the PCA was intended to adjust

4 for power supply expenses, expense variations that occur

5 due to changing water conditions, and I think including

6 another adjustment of unknown magnitude would diminish

7 that intent and I believe would be inappropriate.

8 Q You've indicated that a balancing account

9 would be appropriate. What do you propose as an

10 alternative to that structure proposed by Mr. Falkner?

11 A I propose that the Commission approve the

12 relicensing expense in base rates as proposed by Staff

13 with modifications for the Bull Trout adjustment and I

14 also recommend that FERC Account 253 be used and that was

15 the proposal of Mr. Falkner, that subaccounts be used to

16 identify the specific expenses associated with

17 relicensing that are above those costs that are included

18 in base rates, and I recommend that rather than every

19 year, or in conjunction with the PCA, we look at those

20 costs every two to three years so they have a chance to

21 balance out, so any one year it wouldn't be offset by a

22 succeeding shortfall in the second year, and then the

23 Company would come in and either request recovery or

24 disbursement of that account at no longer than three

25 years, and then at that time the Commission Staff would

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1 review and make recommendations to the Commission on

2 whether that could be rolled in with the PCA or it could

3 be recovered in some other manner, amortized or recovered

4 separately.

5 MR. WOODBURY: Madam Chair, I have no

6 further questions and I'd present Mr. Lobb for

7 cross-examination.

8 COMMISSIONER SMITH: What do you want to do

9 with these exhibits?

10 MR. WOODBURY: Spread them. I'd just

11 identify them, Exhibits 101 through 106.

12 COMMISSIONER SMITH: Okay, Exhibits 101

13 through 106 will be identified.

14 Mr. Ward, do you have questions for

15 Mr. Lobb?

16 MR. WARD: Yes, I do.

17

18 CROSS-EXAMINATION

19

20 BY MR. WARD:

21 Q Mr. Lobb, all my questions deal with the

22 power supply area. Would you agree with me that as a

23 general rule in ratemaking that this Commission requires

24 the use of an historical test year?

25 A Yes, as a general rule.

939

CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff

1 Q And that historical test year sometimes is

2 partially projected with true-ups as the year closes;

3 isn't that also true, if you know?

4 A Well, projecting, I guess, my experience

5 has been that they have to be -- they can't be projected

6 inflation rates or projected fuel escalators, they have

7 to be something that's very known and measurable.

8 Q Okay, and regardless of whether they use an

9 historical year or partially historical and partially

10 projected, typically, we allow known and measurable

11 changes outside the test year; for example, something

12 like a labor increase that's known and measurable because

13 it's contractually committed.

14 A Yes.

15 Q But would you also agree that even known

16 and measurable changes are limited primarily because of

17 concerns about introducing a mismatch of revenues and

18 expenses?

19 A I suppose that could be true, yes.

20 Q And to the best of your knowledge, has the

21 Commission ever authorized the use of a fully projected

22 test year?

23 A I'm not aware of any instance.

24 Q Now we come to this case. Here we have a

25 1997 test year with a few important exceptions and the

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CSB REPORTING LOBB (X)
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1 most important of those exceptions is the power supply

2 adjustment which in fact is projected to a period roughly

3 two-and-a-half years after the close of the test year; is

4 that correct?

5 A That's correct.

6 Q And is this unprecedented in your

7 experience?

8 A The period is somewhat longer than I have

9 experienced, that I have knowledge about.

10 Q Okay. Now, I want to ask you about -- and

11 clearly, you gave some thought as to whether you thought

12 that's appropriate because your testimony has a question

13 and answer asking whether it's appropriate to reflect

14 power supply costs for July 1999 through June 30th,

15 2000. Do you recall that?

16 A Yes.

17 Q And that's on page 7 of your testimony, and

18 there would it be fair to say that you conclude that, on

19 balance, after examining the factors you list there that

20 it is appropriate to use that pro forma adjustment in

21 this case?

22 A Yes.

23 Q Now, I want you to skip back to the

24 previous page and ask you about the specific components

25 of the power supply adjustment. Starting on page 6,

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CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff

1 line 4, there you deal with the expense and revenue

2 adjustments in this case and note that they amount to

3 approximately 52 percent of increased power supply

4 revenue requirement and those expense and revenue

5 adjustments are contract specific as you lingual it.

6 Maybe just to be sure that's clear, could you explain a

7 little more what you mean by "contract specific"?

8 A Those are purchases, long-term firm

9 purchases, and sales contracts. Some of them are energy,

10 some of them are capacity, some of them are transmission,

11 some of them are service contracts to either provide or

12 take service and they specifically -- they expire on a

13 specific date or they have a specific -- let's see, I

14 believe that includes the -- yeah, the specific change in

15 rates that are spelled out in the contracts, so the date

16 is certain, the amount is known and measurable and those

17 are included in that category.

18 Q And I take it you examined those contracts

19 to determine whether they are in fact known and

20 measurable as you just said?

21 A I examined the workpapers provided by the

22 Company regarding those specific adjustments in the

23 contracts. I did not examine the contracts themselves

24 other than the excerpts from the contracts that were

25 provided in the workpapers.

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CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff

1 Q Can I take it, then, that they provided you

2 excerpts from the contracts that showed the expiration

3 date, the term of the contract, perhaps, or, in the case

4 of rate changes, the rate schedule incorporated in the

5 contract, is that the type of thing you were looking at?

6 A Yes.

7 Q All right. Now, the second category of

8 power supply adjustments you mention in lines 10 through

9 18 and here you say they represent estimated, projected

10 and miscellaneous contract changes and these constitute

11 2.21 million or 14 percent of the power supply increase.

12 A Yes.

13 Q Now, Mr. Lobb, I've worked with you enough

14 to have a lot of confidence in your judgment on the

15 reasonableness of estimations, let me ask you how they

16 demonstrated the validity or reasonableness of their

17 estimates to you.

18 A Well, there was a variety of ways that they

19 did that. In some instances they used actual

20 expenditures for the last five years and took an average

21 of those to estimate the amounts that could be expected

22 going forward. In some of the Columbia River contracts

23 with the PUDs, the PUDs provided them with budgets and

24 based on past expenditures. It is basically a

25 third-party estimate of what the PUDs would charge them

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CSB REPORTING LOBB (X)
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1 on an annual basis for expenses associated with that

2 contract, so it's what I believe to be reputable, known

3 and measurable, historical types of estimates and I

4 accepted them as being reasonably known and measurable.

5 Q Okay. Now, the third component of the

6 power supply adjustments is the power supply model or

7 dispatch simulation model itself and we have some

8 disagreements about that and I'm not going to cross you

9 on that, but you state that constitutes 34 percent of the

10 adjustment.

11 A Yes.

12 Q Now, what I really want to ask you with all

13 that as background, if you'll turn to your exhibit, your

14 first exhibit is No. 101, what I want to ask you about

15 really, and I tried to figure out some way to articulate

16 this in a short version, what I really want to ask you

17 about is the unknown and immeasurable changes in this

18 situation and I specifically want to look at the specific

19 contract changes that appear on line 1 and 4, 1 through

20 4, of that exhibit. Do you see those changes?

21 A Right.

22 Q Now, I want to make sure I understand

23 exactly what we have here. On line No. 2, the entry is

24 new and expired contracts and under (b), column (b) is

25 total company and you have a figure of 17,547,000;

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CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff

1 correct?

2 A Could you point that out again?

3 Q Line 2, column (b) --

4 A Right.

5 Q -- 17,547,000.

6 A Okay.

7 Q Now, these columns, that is, (a) through

8 (c) -- well, I guess you have a (d) as well, (a) through

9 (d) are expenses; correct?

10 A Right.

11 Q And columns (e) through (g) are revenues;

12 correct?

13 A Yes.

14 Q Now, I take that $17 million entry to mean

15 that with new and -- because of contractual changes, and

16 we're talking now about terms or the entry into new

17 contracts, that there was an increase in power supply

18 expenses of $17,547,000 on a system basis.

19 A Yes, that's the effect on a going-forward

20 basis of the expired and changed contracts.

21 Q For the '99 through 2000 time frame we've

22 been talking about?

23 A Yes.

24 Q Okay, and looking down below that I see the

25 figure of 2,336,000 for contract specific rate and I take

945

CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff

1 it -- would I be correct in assuming that what we're

2 referring to there is not that the contract in fact has

3 expired, but that the rate has escalated in most cases?

4 A Right, and it is specified within the

5 contract.

6 Q Okay. Now, if I go over -- and 1 through

7 4, as we mentioned earlier, constitutes 52 percent of the

8 power supply adjustment in your original computation.

9 A All of the columns.

10 Q Yeah. Now, I want to go over to the

11 revenue side, same thing there. On line 2, I see new and

12 expired contracts and here we have a minus figure of

13 22 million and change. Do you see that?

14 A Right.

15 Q And down below that we have the contract

16 specific rate of 17,673,000 and change and I assume that

17 those are the revenue flip side of the expense

18 adjustments; that is, these are -- what happened in the

19 new and expired contracts is $22 million net worth of

20 contracts expired during this period.

21 A Right. They would be sales contracts that

22 would no longer be in place.

23 Q Now, on your $22 million figure, in the

24 power supply model, as I understand it, all other things

25 being equal, if a contract expires, the power supply

946

CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff

1 model will drop it into short-term sales.

2 A Sometimes if it's an energy contract it

3 will, but if it's capacity or some other type of

4 contract, it's not included at all in the power supply

5 model.

6 Q Okay. If in fact it is a contract that

7 would drop down to the short-term sales category, did you

8 net that short-term sale from the new and expired

9 contract figure you have there? I didn't say that very

10 well. Do you understand?

11 A Did I make an adjustment in the power

12 supply model to reflect the expiration of a sale?

13 Q Let me ask it this way: The power supply

14 model shows an average short-term price of 18 and some

15 mills, I've forgotten the exact number, but, of course,

16 that average is comprised of many data points, correct,

17 in the actual model?

18 A That's correct.

19 Q What I'm trying to get at is did the actual

20 contract, expiring contract, figure look like, let us

21 say, $50 million and then I deducted $28 million for

22 short term?

23 A No, it's not included in that category.

24 Those would be power supply effects and they would be

25 shown in the power supply model adjustments.

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CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff

1 Q Okay; so we would expect if the expiration

2 of that contract allowed an increase in short-term sales,

3 that would appear down in lines 9 through 10 of this

4 analysis?

5 A Right, it would tend to reduce the power

6 supply expenses if you no longer had an obligation to

7 sell.

8 Q Now, what I want to ask about here is a

9 couple of things. Going back to the expense side of the

10 ledger on line 2, it's not too difficult to imagine that

11 through this period that we're looking at, this pro forma

12 period, that we would have a $17 million plus increase in

13 expenses as a result of expiring contracts and that's so

14 because, of course, as longer-term contracts with

15 presumably lower rates expire in today's escalating

16 prices in the market you have to renew at a higher price;

17 correct?

18 A That could be the case, yes.

19 Q What happens in the cases -- well, strike

20 that. And, again, the contract specific rate increases

21 on line 3 are similarly easy to understand; that is, with

22 prices going up over the last year, it's understandable

23 we have a $2.3 million increase in rates, in contract

24 rates, that's what that represents?

25 A Yes.

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CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff

1 Q Now, if I go over on the right-hand side

2 for line 3, again the contract specific rate, again, it's

3 easy to understand the revenue going up 17,673,000 as a

4 result of bracketed escalators in contracts and things

5 like that and that's again what that refers to; correct?

6 A Yes, that's correct.

7 Q What I don't understand, Mr. Lobb, is why

8 would new and expired contracts revenue not also

9 increase?

10 A It might.

11 Q Well, and that's my point. At this point

12 as we sit here before the '99-2000 period in question

13 even starts, what we know is we have 22 million less

14 revenue from expiring contracts, but do we know -- how

15 can we know that we won't have new contracts entered into

16 when that period actually occurs that will like all the

17 other figures here contain higher rates, presumably, and

18 even greater revenues than we started with?

19 A Well, the Company has quite a few long-term

20 contracts and they continually add those contracts and

21 those contracts expire from time to time. I can take the

22 ones that we know are going to be added, they have signed

23 and ones that are going to expire and I believe those are

24 known and measurable. Will the Company make, at their

25 discretion make, new contracts for the long term? Will

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Wilder, Idaho 83676 Staff

1 they serve load with it? I don't know what the Company

2 plans to do, I don't know what they will do, I don't know

3 what the prices are going to be when they make the

4 decision to do that, so I simply don't have the

5 information, the known and measurable information, to

6 include in the power supply model to identify what

7 they're going to do on a discretionary basis or what the

8 value of those decisions will be.

9 Q And I think you stated that very well,

10 Mr. Lobb. I'm not going to pursue it but just a tiny bit

11 further. When we first talked about the use of a test

12 year and known and measurable changes, one of the things

13 I asked you about was the limitations on even known and

14 measurable changes because of the -- because of the

15 concerns about mismatching revenues and expenses. Is it

16 possible here that, as you just stated, we have known

17 expense increases, known revenue decreases, but what we

18 don't know is what potential revenue increases lie in the

19 future, is it possible that we've introduced a serious

20 mismatch of revenues and expenses here?

21 A I don't believe that we have. I believe

22 what I've tried to do is to incorporate and reflect in

23 expenses and in revenues what will occur over the next

24 two years. Now, to the extent the Company will go out or

25 could go out or might go out and make decisions that are

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CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff

1 going to change those expenses in the future, I don't

2 have any information about that.

3 I mean, it could be that it could increase

4 revenues, it could be that it could decrease revenues, it

5 could increase expenses. I hope they make decisions that

6 decrease costs and to that extent, I hope they sign

7 contracts that result in cost decreases. I don't know

8 what those might be, I'm not going to try to pro form

9 those in. I know what's actually going to happen with

10 their contracts and that's what I have tried to

11 incorporate.

12 Q Let me just follow up on one item there.

13 You said, of course, they could decrease costs. With

14 respect at least to the revenue entry for the new and

15 expired contracts, it's not likely they're going to

16 decrease those below the model's short-term sales figure,

17 is it? I mean, that's the bottom.

18 A Well, it depends on the type of contracts

19 and when they occur and it's not just selling and

20 purchasing at the market price. It's deferring

21 resources, it's a timing situation, so there's a lot of

22 different factors that go into that calculation.

23 Q That was poorly phrased. I shouldn't have

24 said it's impossible, but it's not likely, is it?

25 A That they're going to do what?

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CSB REPORTING LOBB (X)
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1 Q That they would enter into a new contract

2 below non-firm sales rates.

3 A Probably not an energy contract.

4 Q One last thing. While you mentioned, of

5 course, that 1 through 4 was 52 percent of the total, it

6 looks like to me if I add line 2 which is, from the

7 customer's point of view, a negative $17 million swing,

8 line 2, column (b) and line 2, column (f), which also is

9 a negative swing of 22 million, that I get as a result of

10 the new and expired contract changes a swing of $39

11 million of the $46 million total in those items alone.

12 A That's correct, they total 39 million.

13 MR. WARD: That's all I have.

14 COMMISSIONER SMITH: Thank you, Mr. Ward.

15 Mr. Shurtliff.

16

17 CROSS-EXAMINATION

18

19 BY MR. SHURTLIFF:

20 Q Mr. Lobb, looking at the adjustments for

21 the power supply, is that an unusual number of

22 adjustments required?

23 A Well, I haven't really reviewed the last

24 case of the Company, so I don't know what's usual in

25 terms of number of adjustments. There were a large

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CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff

1 number of adjustments and I really can't say if that's

2 unusual or not.

3 Q Well, indeed, I think I saw a reference to

4 93 adjustments.

5 A There were a lot of them.

6 Q You've been around the track a time or two,

7 have you ever worked on a case where there were 93 of

8 them?

9 A I haven't worked on a case where there were

10 93 pro forma power supply adjustments, no.

11 Q Does that cause you to pause and consider

12 whether the model itself might be out of date or

13 insufficient because of the number of adjustments

14 necessary to make it work?

15 A No, I don't think it has anything to do

16 with the model. The model really only makes a few

17 adjustments. The other adjustments are simply the

18 contractual changes and the differences that occur under

19 the time period, the pro forma time period, as compared

20 to what actually happened in the test year, so there were

21 quite a few of them. I looked at each one on its own

22 merit.

23 Q But the sheer volume of the adjustments

24 necessarily doesn't cause you any concern as to the

25 validity of the process?

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CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff

1 A Yeah, I look more at -- you know, whether

2 there was two or 1,000, I looked at each one of them and

3 tried to determine if they were reasonable.

4 MR. SHURTLIFF: Thank you. I have no

5 further questions, Madam Chairman.

6 COMMISSIONER SMITH: Thank you,

7 Mr. Shurtliff.

8 Mr. Woodbury? I'm sorry, Mr. Meyer.

9

10 CROSS-EXAMINATION

11

12 BY MR. MEYER:

13 Q Just a bit of a follow-up to some of the

14 examination. Let's step back for a moment from the

15 detail and let me ask you this: Was there anything

16 unorthodox or unusual about the pro forming process to

17 capture these known and measurable changes in power

18 supply or was this a fairly orthodox treatment, at least

19 in concept, of those type of adjustments?

20 A Well, the pro forma adjustments that I've

21 seen in past cases are simply to come up with a test year

22 that is representative of what you can expect going

23 forward with the rates that are established by the

24 Commission.

25 Q And that's what we're trying to do in this

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CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff

1 instance, isn't it, with this adjustment?

2 A Yes. The only thing, I would only add that

3 the only thing that is a little unusual about it is the

4 length of time that those adjustments are made past the

5 end of the test period. You know, a year is pretty

6 standard. Anything longer than a year is somewhat

7 unusual in my experience.

8 Q But you did notwithstanding that spend a

9 fair amount of time with the workpapers and with the

10 analysis and came away satisfied that these adjustments

11 were known and measurable, in fact, your words, I think,

12 were very known and measurable; is that correct?

13 A Well, they were contracts specific.

14 Q And in fact, by the time the rates go into

15 effect in this proceeding, say, in July or soon

16 thereafter, we'll be in the last 12 -- the next 12

17 months, really, leading up to July of the year 2000 which

18 represents the end point for that pro forming exercise;

19 correct?

20 A Yes, and in fact, I think in my testimony I

21 indicated that most of the significant pro forma

22 adjustments were by the end of 1999, so the last six

23 months were not really very meaningful in terms of

24 pro forma adjustments that occurred during that period.

25 Q Exactly. Now, Mr. Ward in his examination

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CSB REPORTING LOBB (X)
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1 referring you to your Exhibit 101 attempted to raise the

2 specter of some sort of serious mismatch for revenues and

3 expense given the pro forma you've done. Do you recall

4 that exchange?

5 A Yes.

6 Q Now, isn't it true that, generally

7 speaking, the Company is in load/resource balance as we

8 speak?

9 A Yes, I believe that is pretty close to the

10 case.

11 Q Okay, and so with that, is the premise in

12 any material sense, does the Company have long-term

13 surplus to sell?

14 A Not generally on an annual basis. From

15 time to time they do.

16 Q Okay; so this notion of some sort of

17 serious mismatch between revenues and expense is a

18 misplaced notion, isn't it?

19 A Based upon the analysis of dispatchable

20 resources and the load that's required to be met, I'd say

21 that's probably true.

22 Q Thanks. Let's turn now to an issue where

23 you spent some time with and it goes to the A&G costs

24 associated with short-term commercial or speculative

25 trading. At page 12 of your testimony, let's turn to

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CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff

1 that, at the bottom of page 12 -- let me get to it

2 myself -- and continuing through to the top of page 13,

3 I'll read from the bottom of 12, line 24, "Staff

4 continues to believe that the incremental operational

5 cost of the speculative activities is relatively small on

6 an Idaho jurisdictional basis." Have I correctly read

7 your testimony?

8 A Yes.

9 Q And do you still believe that statement to

10 be true?

11 A Yes, I think so.

12 Q And that is after an examination of the

13 rebuttal testimony and the work done by Mr. Norwood?

14 A Yes. I am somewhat concerned about the

15 fact that we don't have expenses prior to the large

16 increase in the secondary commercial transactions. For

17 example, 1996, we don't really have any numbers for what

18 the cost of providing those types of services for the

19 system benefit were prior to the huge increase in the

20 speculative commercial transactions and so we're left to

21 rely on the presentation of Mr. Norwood that these are

22 the amounts of time, there's no documents really to

23 support that.

24 Q We'll get to that latter point in just a

25 minute, but you understand, just to refresh our memory,

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CSB REPORTING LOBB (X)
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1 that the Idaho share of A&G costs associated with that

2 short-term trading approximated $157,000?

3 A According to Mr. Norwood, that's correct.

4 Q Okay. Now, at the top of page 19 of

5 Mr. Norwood's testimony -- do you have a copy of that

6 before you?

7 A Direct or rebuttal?

8 Q That would be his rebuttal, and if not, I

9 can provide you with a copy.

10 A I have that. Page 19?

11 Q Yes, please, and I'd like to spend a little

12 bit of time on this particular page. Mr. Norwood

13 identified a number of positions that are necessary to

14 manage the Company's generating system to serve retail

15 load, did he not?

16 A Yes.

17 Q Now, these positions, and I'll take each of

18 them in turn, include, oh, pre-schedulers, real-time

19 schedulers, hydro engineers, fuel purchasers, et cetera.

20 A Yes.

21 Q Okay, those are among the positions that

22 are included; correct?

23 A (The witness nodded his head up and down.)

24 Q Okay. Would you agree that these types of

25 positions really are endemic to the basic operation of

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CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff

1 the Company's existing generating system in order to

2 serve its customers?

3 A Yeah, I believe so. You know, one of the

4 reasons that I think the Staff and I agreed that the

5 costs are relatively small is because these are the types

6 of expenses and activities we felt were being

7 undertaken. We didn't really see a large run-up in these

8 types of positions with the speculative transactions, at

9 least on its face, so, yeah, I think these are the types

10 of things that we expected that the Company would be

11 doing on a regular basis and would be the lion's share of

12 the expenses associated with that activity.

13 Q And in fact, aren't you saying that these

14 are the sort of positions that would have to be

15 maintained irrespective of whether the Company ever

16 engaged in short-term commercial trading?

17 A Right. I think yesterday, I believe, there

18 was some discussion about the incremental cost of

19 undertaking the speculative commercial transactions and

20 how much that is and the fact that it's inappropriate for

21 customers of the regulated company to foot that bill. If

22 you didn't do any speculative commercial transactions or

23 if all of those incremental costs were excluded, the

24 ratepayers would generally be indifferent.

25 Now, from a competitive standpoint, if this

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CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff

1 is a competitive activity, the speculative commercial

2 transactions, then you may get into whether or not there

3 should be a fully allocated cost to the speculative

4 commercial transactions so that the Company doesn't have

5 some advantage over the competition in undertaking these

6 types of activities, so we don't want to have a negative

7 impact on the ratepayers of the Company and we shouldn't

8 allow the speculative business, speculative commercial

9 business, to ride on the backs of the regulated business.

10 Q Understood, but you do understand that

11 Mr. Norwood's analysis that resulted in 157,000 of

12 allocated A&G cost to this function did include such

13 things, in addition to payroll, as square footage, floor

14 rental, janitorial service, building maintenance, those

15 types of things?

16 A Right, and those allocations -- and I agree

17 that he has step by step allocated portions of all of

18 those based upon his presentation that this is the amount

19 of time that each one of these employees work in that

20 area.

21 Q Now, I believe Mr. Norwood -- we've been

22 through the type of, let's say, built-in labor structure

23 necessary to maintain the ongoing operations in the

24 resource optimization department, but Mr. Norwood talked

25 in terms of maybe three or four individuals at most who

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CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff

1 would have any involvement in speculative trading; is

2 that your understanding?

3 A That's what he indicated.

4 Q And you don't have any reason to disagree

5 with that assessment?

6 A I don't have any information to dispute it.

7 Q Now, even though it's a relatively few

8 number of individuals, isn't it possible that given the

9 nature of what's euphemistically known as speculative or

10 short-term commercial trading that the volumes of the

11 transactions can be high because it's on a trading basis,

12 it's not tied to marketing specific resources; correct?

13 A Yes, and that's another reason why the

14 Staff believed that it was relatively small on an Idaho

15 jurisdictional basis because you can rack up some really

16 huge volumes in a very short time.

17 Q Even though only a few individuals are

18 involved in that exercise; correct?

19 A Yes.

20 MR. MEYER: That's all I have. Thank you.

21 COMMISSIONER SMITH: Do we have questions

22 from the Commission?

23 MR. WARD: Madam Chair?

24 COMMISSIONER SMITH: Mr. Ward.

25 MR. WARD: Before redirect, I do have to

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1 follow up on one question Mr. Meyer asked, which was

2 answered correctly but I think left a mistaken

3 impression.

4

5 CROSS-EXAMINATION

6

7 BY MR. WARD:

8 Q Mr. Lobb, Mr. Meyer asked you about whether

9 the Company was roughly in load balance and whether it

10 had large surpluses to sell on the open market and you

11 correctly answered it is in balance and, no, it doesn't.

12 Do you recall that?

13 A Yes.

14 Q But in fact, with regard to my

15 cross-examination on the model results, the model has

16 already normalized loads and resources, has it not?

17 A Yes.

18 Q And so what we're really talking about is

19 when we have a normalized amount of power to sell, we

20 know that we've got $17 million of increased expenses

21 here, but we've got $22 million of decreased revenues

22 over there and is there a possibility that in the future

23 those prices might rise on the sales side, that's all

24 we're talking about, isn't it?

25 A It's always possible that the sales, that

962

CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff

1 the prices might rise and the sales revenue will

2 increase.

3 MR. WARD: That's all I have.

4 COMMISSIONER SMITH: Thank you, Mr. Ward.

5 MR. MEYER: One follow-up?

6 COMMISSIONER SMITH: No, Mr. Meyer, I think

7 we're done.

8 MR. MEYER: Okay.

9 COMMISSIONER SMITH: Mr. Woodbury, do you

10 have redirect?

11 MR. WOODBURY: No, I don't.

12 COMMISSIONER SMITH: Thank you, Mr. Lobb.

13 (The witness left the stand.)

14 MR. WOODBURY: Staff's next witness is Rick

15 Sterling.

16

17

18

19

20

21

22

23

24

25

963

CSB REPORTING LOBB (X)
Wilder, Idaho 83676 Staff

1 RICK STERLING,

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. Sterling, will you please state your

10 full name?

11 A Rick Sterling.

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 a Staff engineer.

16 Q And in that capacity, did you have occasion

17 to prepare prefiled testimony in this case consisting of

18 26 pages and Exhibits 107 through 114?

19 A Yes, I did.

20 Q And have you had the opportunity to review

21 that testimony and those exhibits before this hearing?

22 A Yes, I have.

23 Q And is it necessary to make any

24 corrections?

25 A No, it's not.

964

CSB REPORTING STERLING (Di)
Wilder, Idaho 83676 Staff

1 Q If I were to ask you the questions set

2 forth in the testimony, then would your answers be the

3 same?

4 A Yes, they would.

5 MR. WOODBURY: Madam Chair, I'd ask that

6 the testimony be spread and the exhibits identified.

7 COMMISSIONER SMITH: If there's no

8 objection, it is so ordered.

9 (The following prefiled testimony of

10 Mr. Rick Sterling is spread upon the record.)

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

965

CSB REPORTING STERLING (Di)
Wilder, Idaho 83676 Staff

1 Q. Please state your name and business address

2 for the record.

3 A. My name is Rick Sterling. My business

4 address is 472 West Washington Street, Boise, Idaho.

5 Q. By whom are you employed and in what

6 capacity?

7 A. I am employed by the Idaho Public Utilities

8 Commission as a Staff engineer.

9 Q. What is your educational and professional

10 background?

11 A. I received a Bachelor of Science Degree in

12 Civil Engineering from the University of Idaho in 1981

13 and a Master of Science Degree in Civil Engineering in

14 1983. I worked for the Idaho Department of Water

15 Resources from 1983 to 1994. In 1988, I received my

16 Idaho license as a registered professional Civil

17 Engineer. I began working at the Idaho Public Utilities

18 Commission in 1994. During my employment at the IPUC, I

19 have attended the 1995 Annual Regulatory Studies Program

20 sponsored by the National Association of Regulatory

21 Commissioners (NARUC) at Michigan State University, the

22 1995 Lawrence Berkeley Laboratory Advanced Integrated

23 Resources Planning (IRP) Seminar, an advanced IRP course

24 sponsored by EPRI entitled "Resource Planning in a

25 Competitive Environment", and a 1988 workshop on Pricing

966

WWP-E-98-11 STERLING, R (Di) 1
04/23/99 Staff

1 and Restructuring Alternatives in a Changing Electric

2 Industry sponsored by New Mexico State University Center

3 for Public Utilities. My duties at the Commission

4 include analysis of utility rate applications, rate

5 design, tariff analysis and customer petitions.

6 Q. What is the purpose of your testimony in

7 this proceeding?

8 A. One purpose of my testimony is to evaluate

9 one of the reasons put forth by Avista Corporation dba

10 Avista Utilities - Washington Water Power Division

11 (Avista; Company) justifying the need for a general rate

12 increase, namely, that customer growth and the addition

13 of new distribution plant has contributed to the need for

14 a rate increase.

15 The second purpose of my testimony is to

16 summarize the results of my analysis of the Company's

17 weather normalization in the case.

18 Q. Please summarize your testimony.

19 A. I am recommending that a total of $1,178,835

20 be imputed as contributions in aid of construction

21 because new distribution plant has been added at Company

22 expense which should have been paid for by customers in

23 the form of contributions in aid of construction. I

24 believe the neglect and/or failure of the Company to keep

25 line extension costs in its Schedule 51 tariff up to date

967

WWP-E-98-11 STERLING, R (Di) 2
04/23/99 Staff

1 as ordered by the Commission in 1989 in Order No. 23071,

2 has caused the Company's annual revenue requirement to be

3 higher than it otherwise should be. I also contend that

4 most of the increase in investment in distribution plant

5 made necessary by customer growth should not be paid for

6 through higher rates for all customers, but should have

7 more appropriately been paid through higher line

8 extension charges for those new customers on whose behalf

9 the new line extensions were made. I recommend a new

10 line extension case be opened once this general rate case

11 has been concluded in order to more closely examine the

12 Company's line extension tariff (Schedule 51) to insure

13 that upward pressure on rates due to growth and new

14 distribution plant additions is minimized. Finally, I

15 review the weather normalization adjustments made by the

16 Company in this case and recommend that the results be

17 accepted with no further adjustment.

18 IMPUTED CONTRIBUTIONS IN AID OF CONSTRUCTION

19 Q. What reasons does the Company give for

20 needing a rate increase?

21 A. In its Application, the Company cites the

22 significant growth in number of customers and the

23 associated increase in distribution plant and expenses.

24 In addition, the Company points to changes in net power

25 supply costs, updated depreciation rates, and costs

968

WWP-E-98-11 STERLING, R (Di) 3
04/23/99 Staff

1 associated with relicensing certain hydro electric

2 generating facilities as contributing to the need for a

3 general rate increase. [Application, pg.4, lines 3-11]

4 Company witness Dukich explains in more

5 detail the reasons for seeking a rate increase:

6 Because the Company has not
requested general rate relief
7 for over twelve years, the
pressure for rate relief has
8 increased, prompted by identifiable
customer growth, growth in rate base
9 (notably distribution plant),
increasing power supply costs and the
10 need to revise depreciation rates.
[Dukich, Di., pg. 3, lines 3-8,
11 emphasis added]

12 Over the past twelve years, the
number of Idaho electric customers
13 increased from approximately 68,000
to over 99,000 -- representing
14 a 46% increase. General business
revenues per customer, however, have
15 not kept pace, and have declined by
almost 6% on a normalized basis. This
16 decline in revenue per customer is
largely due to decreasing energy usage
17 per customer. With customer growth,
we have witnessed an increase in
18 distribution plant per customer;
distribution plant has risen from $1,283
19 to $2,052 on a per customer basis
from 1985 to the date of this filing --
20 representing a 60% increase. Moreover,
given the recent growth in number of
21 customers, this has resulted in a higher
percentage of total distribution plant
22 being comprised of newer, higher cost
plant. [Dukich, Di., pg. 3, lines 11-19,
23 emphasis added]

24 In addition, Company witness Falkner, in

25 response to a question in his testimony about whether

969

WWP-E-98-11 STERLING, R (Di) 4
04/23/99 Staff

1 there is one main issue that has contributed to the need

2 for a rate increase states the following:

3 There is no one single item
contributing to the magnitude
4 of the requested increase.
Obviously, not having had a
5 general rate case for over 12
years has contributed to the rate
6 pressure. Readily identifiable
items are customer growth, rate
7 base growth (especially in
distribution plant), power supply
8 costs and updated depreciation
rates. Also, a recent agreement
9 in principle that settles the
long-term negotiations related to
10 relicensing of two of the Company's
hydro generating facilities resulted
11 in added costs. [Falkner, Di, pg. 5,
lines 1-6, emphasis added]
12

13 Falkner goes on to discuss in more detail

14 the rate pressures associated with customer growth:

15 The physical plant known as
Distribution plant has increased
16 by over 130%. Using the proforma
information for Idaho electric
17 operations in 1985 and now in this
filing, on a per customer basis,
18 Distribution plant has risen from
$1283 to $2052, or a 60% increase.
19 With the recent economic growth
in the Company's north Idaho service
20 territory, customer growth has been
higher in recent years than in past
21 years. This results in a higher
percentage of total distribution plant
22 comprised of newer, higher cost plant.
[Falkner, Di, pg. 5, line 23 through
23 pg. 6, line 6, emphasis added]

24 Q. It appears from the Company's Application

25 and from the testimony of its witnesses that customer

970

WWP-E-98-11 STERLING, R (Di) 5
04/23/99 Staff

1 growth and the significant increase in distribution plant

2 investment is one of the primary reasons for requesting a

3 rate increase.

4 Q. Has the Company been able to determine how

5 much of their requested $14,223,000 increase in annual

6 revenue requirement can be attributed to customer growth

7 and increases in distribution plant investment?

8 A. Yes, based on estimates, the Company has

9 broken down the $14,223,000 increase in revenue

10 requirement as follows:

11 Group Percentage Rev. Req. ($ millions)
Power Supply 44% $6.290
12 Distribution 21% 3.044
Depreciation 14% 1.944
13 A&G and Other 21% 2.945
Total 100% $14.223
14

15 Q. Do you believe customer growth and

16 increases in distribution plant investment are valid

17 reasons for seeking a general rate increase?

18 A. Undoubtedly, these factors do cause upward

19 pressure on rates. The critical issue however, is

20 whether a general rate increase for all customers is the

21 appropriate way of relieving that pressure. I do not

22 believe all customers should be burdened with higher

23 rates when much of the cause of the upward rate pressure

24 can be attributed to only a few customers. The Company

25 admits that the higher cost of distribution plant needed

971

WWP-E-98-11 STERLING, R (Di) 6
04/23/99 Staff

1 to serve new customers is one of the primary reasons for

2 needing a rate increase, yet it proposes to recover this

3 cost by increasing rates for all its customers. This

4 proposed means of relieving upward rate pressure would

5 certainly result in subsidization of new customers by

6 existing customers.

7 Q. Why shouldn't all customers pay for the

8 higher costs of new distribution plant, just as they do

9 for new transmission and generation plant?

10 A. All customers should not be burdened with

11 the higher costs of new distribution plant used

12 exclusively to serve only new customers. Unlike new

13 transmission and generation plant which is used to serve

14 all customers, both new and old, new distribution plant

15 can be associated with a small group of very specific

16 customers. When costs can be so directly attributed to

17 specific customers on whose behalf those costs were

18 incurred, then only those specific customers should be

19 responsible for bearing the costs, otherwise,

20 subsidization occurs.

21 Q. Should there be some increase in

22 distribution plant investment over time that should

23 properly be allowed to be added to rate base, and thus

24 paid for by all customers?

25 A. Yes. New distribution plant must not only

972

WWP-E-98-11 STERLING, R (Di) 7
04/23/99 Staff

1 be added to serve new customers, but distribution plant

2 must continuously be replaced in order to continue to

3 serve existing customers. The costs of replacement plant

4 used to serve existing customers have always been

5 historically recovered from all customers through

6 inclusion in rate base, and never recovered only from

7 those customers who use the replacement plant. Since in

8 general, new distribution plant is more expensive over

9 time, and since more customers, in turn, eventually

10 require more replacement distribution plant, there will

11 be some upward pressure on rates even if new customers

12 fully bear their rightful share of new distribution

13 costs.

14 Q. If you object to the Company seeking higher

15 rates from all customers to pay for the costs of growth

16 and higher cost distribution plant, then what do you

17 believe is the appropriate way for the Company to recover

18 these costs?

19 A. A significant portion of higher distribution

20 plant costs should be recovered through higher line

21 extension charges assessed against the new customers when

22 new service is requested. These charges are assessed in

23 accordance with Schedule 51, the Company's line extension

24 tariff. As the cost of providing new distribution plant

25 increases over time because of inflation, the charges

973

WWP-E-98-11 STERLING, R (Di) 8
04/23/99 Staff

1 specified in the line extension tariff should also keep

2 pace. If line extension tariffs are not kept updated,

3 upward pressure on rates will occur.

4 The Company clearly recognizes that this

5 will occur, because the reason cited for needing to

6 revise their line extension tariff in Case No.

7 WWP-E-89-4, the Company's last major line extension case

8 in 1989, was to avoid upward pressure on rates. The

9 following excerpts are from the Company's Application in

10 that case:

11 In the past several years, the
Company has striven to reduce upward
12 pressure on rates by reducing costs
and increasing secondary revenues.
13 The proposed revisions contained in
revised Schedule 51 will help to keep
14 existing rates stable by reducing the
current upward pressure caused by
15 existing line extension policies. The
revised line extension policy is also
16 designed to reduce cross-subsidization
between new and existing customers.
17 [Case No. WWP-E-89-4, WWP Application
for Revised Electric Tariffs, pg. 3]
18

19 Under revised Schedule 51, the existing
construction allowance for a residential
20 customer drops from a maximum of $3450;
to a maximum of $1000. The Company
21 believes that the proposed $1000 allowance
is necessary to reduce cross-subsidization
22 and to reduce upward pressure on rates.
[Case No. WWP-E-89-4, WWP Application for
23 Revised Electric Tariffs, pg. 4]

24 The following testimony of Company witnesses

25 in that case further demonstrates how keenly aware the

974

WWP-E-98-11 STERLING, R (Di) 9
04/23/99 Staff

1 Company was of the close relationship between line

2 extension costs and upward pressure on rates, of the

3 inequity of existing customers subsidizing new customers,

4 and of the Company's desire to eliminate the need for

5 general rate increases:

6 Q. Why is the Company proposing
revisions to its electric line
7 extension tariff?

8 A. The Company's existing electric
policy puts upward pressure on rates
9 and causes cross-subsidization between
new and existing customers. ...[Case No.
10 WWP-E-89-4, Direct Testimony of John
Buergel for WWP, pg. 2]
11

12 Q. Would you explain why the existing
electric extension allowance amounts
13 are too high?

14 A. ... The Company believes that the
existing allowances are too high
15 because the revenue resulting from
added load is not sufficient to
16 offset the revenue requirement of
the added investment ... The proposed
17 allowances will reduce upward pressure
on existing rates and reduce cross-
18 subsidization between new and existing
customers. [Case No. WWP-E-89-4, Direct
19 Testimony of John Buergel for WWP, pg. 4]

20 Q. Is management of the Company
committed to reduce upward pressure on
21 rates?

22 A. ... The Company's proposed
line extension policies are
23 consistent with the Company's
commitment to reduce upward
24 pressure on rates and eliminate
the need for general rate increases.
25 [Case No. WWP-E-89-4, Direct Testimony
of John Buergel for WWP, pg. 5]
975

WWP-E-98-11 STERLING, R (Di) 10
04/23/99 Staff

1 Q. At the time of this line extension case in

2 1989, was it apparent that the Company intended to keep

3 their line extension tariff updated?

4 A. Yes, it appears to be very apparent from

5 the following excerpt from the Company's Application in

6 that case:

7 The Company is proposing that
extension costs be estimated based
8 on average costs of construction for
the Company. The average costs are
9 contained in Schedule 51 and will be
reviewed periodically. [Case No.
10 WWP-E-89-4, WWP Application for Revised
Electric Tariffs, pg. 3]
11

12 Q. Was it also apparent that the Commission

13 intended for the line extension charges listed in the

14 line extension tariff to be regularly updated?

15 A. Absolutely. The Commission's Final Order

16 in that case clearly orders the Company to file annual

17 updated average unit costs:

18 As reflected in the Company's
amended filing, the proposed
19 revised Schedule 51 for Electric
Line Extensions, Conversions and
20 Relocations is purportedly designed
to reduce cross-subsidization between
21 new and existing customers and to
assist in keeping existing energy rates
22 stable as the system approaches
load/resource balance. The Company
23 contends the existing line extension
allowances are too high because the
24 revenue resulting from added load is not
sufficient to offset the revenue requirement
25 of the added distribution investment.
[Case No. WWP-E-89-4, O.N. 23071, pg. 2]
976

WWP-E-98-11 STERLING, R (Di) 11
04/23/99 Staff

1
...
2 CONSTRUCTION-AVERAGE UNIT COSTS

3 Staff suggests that the Company's
average unit costs for construction
4 be carefully reviewed and updated
and filed with the Commission on an
5 annual basis. Proposed schedule changes
related to average unit costs should be
6 requested as necessary.

7 Water Power's Response:
The Company agrees with the Staff
8 suggestion. It intends to provide
updated work sheets and average unit
9 costs to the Commission annually.
Tariff changes will be filed as
10 necessary to keep the costs current.

11 The Commission concurs in this policy.
[Case No. WWP-E-89-4, O.N. 23071, pg. 13]
12
O R D E R
13 After reviewing the Company's
Application and filings of record in
14 Case No. WWP-E-89-4 and in consideration
of the foregoing, IT IS HEREBY ORDERED
15 that the proposed revisions to Washington
Water Power's Schedule 51 electric line
16 extension tariff, as set out in the
November 6, 1989 filing (copy attached),
17 be approved with the following stipulated
and Commission-ordered changes, as more
18 particularly described above:

19 ...

20 6. Construction -- average unit costs:

21 The Company is to provide the Commission
annually with updated worksheets and
22 average unit costs for Schedule 51
construction and is to update its tariff
23 as necessary to keep the costs current.
[Case No. WWP-E-89-4, O.N. 23071, pg. 15,
24 emphasis added]

25

977

WWP-E-98-11 STERLING, R (Di) 12
04/23/99 Staff

1 A full copy of Order No. 23071 is included

2 as Exhibit No. 107.

3 Q. Did the Company ever file updated average

4 unit costs as ordered by the Commission in Order No.

5 23071, Case No. WWP-E-89-4?

6 A. No. The average unit costs specified in

7 the current Schedule 51 tariff are exactly the same as

8 the costs in the version of Schedule 51 approved in 1989.

9 Staff was able to locate only one report filed in

10 compliance with the Order. The report, prepared by Tom

11 Dukich, Manager of Rates and Tariff Administration, was

12 filed approximately nine months after the Commission

13 Order. The main body of that one page report consists of

14 a single paragraph which is repeated below:

15 Regarding updated line extension
construction costs, the Company
16 will be updating the costs using
actual jobs. The Company plans on
17 submitting the updated costs sometime
in the third quarter of 1991. At the
18 time the updated costs are submitted,
the Company will decide whether or not
19 to propose changes to the line extension
tariff. [Case No. WWP-E-89-4, Report
20 Pursuant to IPUC Order No. 23071,
January 25, 1991]
21

22 A copy of the full report is included as Exhibit

23 No. 108.

24 I would also note that the line extension costs

25 specified in Schedule 51 in Idaho are the same as the

978

WWP-E-98-11 STERLING, R (Di) 13
04/23/99 Staff

1 costs in the Company's comparable tariff in Washington,

2 which is also called Schedule 51. As in Idaho, no

3 changes have been made to update these costs in the

4 Company's Washington tariff since they were first

5 implemented in 1989.

6 Q. What are the consequences of not keeping

7 the line extension tariff costs up to date?

8 A. The consequences are higher distribution

9 plant investment, increased pressure on rates if that

10 plant is added to rate base, and ultimately, the need to

11 file for a general rate increase -- exactly the things

12 the Company stated they were trying to avoid, yet exactly

13 some of the direct causes of the present request for a

14 rate increase.

15 Q. Why are you recommending that an amount be

16 imputed as customer contributions in aid of construction?

17 A. I am recommending that $1,178,835 worth of

18 distribution plant added since 1988 be imputed as

19 customer contributions in aid of construction because I

20 believe this portion of distribution plant has been added

21 through investment by the Company to serve new customers

22 when it more appropriately should have been paid for by

23 new customers through higher line extension fees.

24 Q. Would the increase in distribution plant

25 rate base have been as great if the Company had kept the

979

WWP-E-98-11 STERLING, R (Di) 14
04/23/99 Staff

1 average unit costs in its line extension tariff properly

2 updated?

3 A. No, as I explained previously, some increase

4 in distribution plant rate base is justifiable because

5 distribution plant must be periodically replaced for all

6 customers; however, the increase in rate base would be

7 considerably less if new customers had contributed more

8 appropriate amounts toward line extension costs.

9 Q. Please explain how the costs of line

10 extensions are shared between customers and the Company.

11 A. Line extension costs are normally paid

12 through a combination of two parts: an allowance and a

13 contribution in aid of construction. A line extension

14 allowance is the portion of an extension cost that does

15 not have to be directly paid for by the customer

16 requesting the line extension. Line extension allowances

17 are paid by the utility and are accounted for as

18 investment in utility property. If the extension cost

19 exceeds the allowance amount, the customer is required to

20 pay the difference. The difference that is paid by the

21 customer is accounted for as a contribution in aid of

22 construction. The extension cost minus the contribution

23 in aid of construction should equal the extension

24 allowance.

25

980

WWP-E-98-11 STERLING, R (Di) 15
04/23/99 Staff

1 The general rationale used to establish the

2 line extension allowance amounts is that revenue

3 requirements associated with an allowance should be

4 recovered through expected revenues from sales to the

5 customer.

6 Q. If the allowance paid by the Company does

7 not change and the customer's contribution in aid of

8 construction does not change, but the actual costs of

9 line extension work increase, who pays the increased

10 costs and how are they booked?

11 A. Any increase in the cost of line extensions

12 is paid by the Company. The Company books the value of

13 the new plant as plant in service; the customer's payment

14 is booked as a contribution in aid of construction.

15 Since contributions in aid of construction are subtracted

16 from plant in service in computing rate base, any

17 increased cost of a line extension is captured in rate

18 base.

19 I have prepared Exhibit No. 109 to

20 illustrate what happens when line extension costs

21 increase, and how those costs are broken down into the

22 Company's allowance, the customer's contribution in aid

23 of construction, and the remaining costs which are paid

24 by the Company and ultimately reflected in rate base.

25 Q. How did you separate the portion of

981

WWP-E-98-11 STERLING, R (Di) 16
04/23/99 Staff

1 distribution plant investment which you believe should

2 rightfully be allowed in rate base from that portion

3 which you believe should be imputed as contributions in

4 aid of construction?

5 A. Since no customer contributions are

6 received for replacement plant, it is not considered in

7 my analysis. By focusing only on contributions in aid of

8 construction, only that portion of new distribution plant

9 used to serve new customers is captured.

10 Q. Please explain what is included in the

11 average costs for line extensions in Schedule 51.

12 A. Each average cost includes the material,

13 labor and overhead costs required to install the

14 identified facility. The costs are divided into overhead

15 and underground services, transformers and primary line

16 to identify the differences in cost. In addition,

17 services and primary line costs are separated into fixed

18 and variable costs.

19 Q. What is the basis for the costs listed in

20 the Company's current Schedule 51 tariff?

21 A. As stated by a Company witness during the

22 case in which the costs in the tariff were first

23 implemented:

24 Material costs are the average
prices paid by the Company for
25 that material in 1988 and includes
shipping, sales tax, and overheads
982

WWP-E-98-11 STERLING, R (Di) 17
04/23/99 Staff

1 for storing and handling the material.
Labor costs are the average 1988 direct
2 costs per man-hour for a 4-man Company
crew. The overheads for benefits,
3 travel time, tools and equipment are
added to the basic labor cost to get
4 a total effective cost per man-hour
at the work site. The fixed costs are
5 the installed costs that do not vary
with the length of service or primary
6 line. They are the materials and labor
required to terminate the wire at the
7 source and load ends of the conductor.
The variable costs are the installed
8 costs that vary directly with the length
of service or primary line. On an
9 underground primary line they would be
the costs of trench, conduit and cable.
10 [Case No. WWP-E-89-4, Direct Testimony of
Timothy Rahman for WWP, pps. 2-3]
11

12 Q. Please explain how you determined the

13 amount you are recommending be imputed as contributions

14 in aid of construction.

15 A. Exhibit No. 110 shows both graphically and

16 in tabular form the approach I used. I began with the

17 assumption that the full cost of line extensions in 1988

18 was being paid by the combination of the Company's

19 allowance (Company share) and the charges paid by the

20 customer as specified in Schedule 51 (customer share).

21 The charges paid by the customer were booked as customer

22 contributions in aid of construction in 1988. Next, I

23 assumed that the cost of line extensions has increased

24 over time, and that all of the increase in cost has been

25 paid by the Company. I assumed that the level of

983

WWP-E-98-11 STERLING, R (Di) 18
04/23/99 Staff

1 customer contributions should have increased at the same

2 rate as line extension costs have increased. In order to

3 estimate how these costs have increased, I used

4 historical annual implicit price deflators for public

5 utility structures as published by Standard and Poors DRI

6 (The U.S. Economy, March 1998). Since customers have not

7 been charged higher costs, and since line allowances have

8 not changed, it is reasonable to assume that the Company

9 has been bearing all of the increased costs of line

10 extensions. The difference between the actual

11 contributions in aid of construction and what I believe

12 the contributions in aid of construction should have been

13 is the amount I believe should be imputed.

14 Q. Do you believe the method you used

15 accurately determines the amount of distribution plant

16 added at Company expense that should have been

17 contributed instead?

18 A. I believe it is a reasonable approximation,

19 although it certainly is not exact.

20 Q. How could the amount be determined more

21 accurately?

22 A. The amount could be determined more

23 accurately if the costs that should have been charged in

24 the tariff were known for each year since 1988, and all

25 line extensions since 1988 charged at those rates.

984

WWP-E-98-11 STERLING, R (Di) 19
04/23/99 Staff

1 Q. If the average unit costs now in Schedule 51

2 are based on 1988 costs, what should the average unit

3 costs be if 1997 (test year) costs were used instead?

4 A. I have prepared Exhibit No. 111 to

5 illustrate the difference between the line extension

6 costs currently in Schedule 51, and 1997 costs for the

7 same items. The 1997 costs have been provided by the

8 Company in response to Staff production requests.

9 The exhibit shows that the costs of all line

10 extension items except for the fixed costs of underground

11 primary service are higher than the costs currently in

12 the tariff. Some costs have increased over 150 percent,

13 while others have increased less than 20 percent. The

14 unweighted average increase of all of the items is

15 approximately 55 percent.

16 Exhibit No. 112 shows the difference in cost

17 between 1989 and 1997. Note that in this exhibit, the

18 differences in cost between 1989 and 1997 are less than

19 the differences between costs in the current tariff and

20 1997 costs. The average difference between 1989 and 1997

21 costs for all items is approximately 25 percent. This is

22 very close to the same percentage increase reported by

23 Standard and Poors DRI as the implicit price deflator for

24 public utility structures, which I used to calculate my

25 recommended imputed contributions in aid of construction.

985

WWP-E-98-11 STERLING, R (Di) 20
04/23/99 Staff

1 Q. Exhibits Nos. 111 and 112 show that the

2 costs in developments (subdivisions) are nearly the same

3 today as is being charged in the tariff. Given that most

4 new line extension work is associated with new

5 subdivisions, do you believe this is significant?

6 A. Yes, it could be. The Company reports that

7 approximately 75 percent of the annual new electric

8 customers come from residential subdivisions. If the

9 costs of line extensions in new subdivisions truly has

10 not significantly increased since 1988, then the need to

11 update the Company's line extension tariff for

12 subdivision costs would indeed be minimized. In any

13 event, non-subdivision costs still clearly should be

14 updated.

15 However, despite claims that costs in

16 subdivisions have not increased since 1988, the Company

17 has not provided any cost data for the interim period

18 between 1988 and 1997. To better analyze cost trends, I

19 have examined the average unit costs for Idaho Power

20 Company, since it also used a similar average unit cost

21 methodology for pricing line extensions during most of

22 the same time period. As shown in Exhibit Nos. 113 and

23 114, Idaho Power's average unit costs for line extension

24 work associated with subdivisions have varied

25 significantly from year to year, sometimes increasing and

986

WWP-E-98-11 STERLING, R (Di) 21
04/23/99 Staff

1 sometimes decreasing, but over the seven-year period

2 examined, have unquestionably increased overall. For

3 single phase underground work inside subdivisions, costs

4 increased approximately 34 percent during the seven years

5 the method was in place. For work associated with

6 bringing underground single phase service from overhead

7 lines to the outer edge of the subdivision, costs have

8 increased an average of nearly 100 percent.

9 In addition, one item not included in Water

10 Power's cost per lot in subdivisions is the cost of the

11 service circuit from the point of connection with the

12 secondary circuit to the point of delivery. This piece

13 of the cost in subdivisions is separate from the $910 per

14 lot cost in the tariff, which the Company claims has not

15 increased. The service circuit is installed when service

16 is required, and no additional cost is charged to the

17 subdivision developer. According to the Company's cost

18 data, however, the cost for installing underground

19 service circuits has increased. Fixed costs are 153

20 percent higher in 1997 than in 1988, and variable costs

21 have gone up about 12 percent.

22 In summary, I believe a more detailed cost

23 analysis would need to be done in order to determine

24 whether costs have, in fact, changed in subdivisions.

25 Comparing only two years of cost data can give misleading

987

WWP-E-98-11 STERLING, R (Di) 22
04/23/99 Staff

1 results as indicated by Idaho Power's annual cost data.

2 The validity of the Company's cost comparison may also be

3 questionable when nearly all other line extension cost

4 items not associated with subdivisions have been shown to

5 have increased during the same time period.

6 Q. What would be the effect on the Company's

7 annual revenue requirement of your recommended

8 disallowance from rate base?

9 A. The effect of imputing $1,178,835 as

10 additional contributions in aid of construction would be

11 a $100,000 reduction in the Company's annual revenue

12 requirement. Staff witness Lansing discusses in his

13 testimony how this adjustment in the annual revenue

14 requirement has been made. In turn, the effect on rates

15 of this reduction in the annual revenue requirement is

16 discussed in the testimony of Staff witness Keith

17 Hessing.

18 Q. How can the problem of upward pressure on

19 rates as a result of customer growth and the addition of

20 new distribution plant be avoided or mitigated in the

21 future?

22 A. If the Company wishes to continue to use

23 average unit costs, then these costs must be kept up to

24 date. If average unit costs are kept up to date, then

25 the Company's share of investment in distribution plant

988

WWP-E-98-11 STERLING, R (Di) 23
04/23/99 Staff

1 needed to serve new customers will not change and will be

2 limited only to the allowances specified in the tariff.

3 Since the allowance amounts are set, at least in theory,

4 to be recovered from customers over time through energy

5 sales at tariffed rates, additions to rate base for

6 distribution plant needed to serve new customers will not

7 cause upward pressure on rates. There will, however, be

8 some new distribution plant added to serve existing

9 customers which will be added to rate base, and because

10 new plant is more expensive, some upward pressure on

11 rates will still occur. In addition, growth will, over

12 time, simply require more distribution plant to be added,

13 which in turn, will eventually cause more distribution

14 plant to need to be replaced.

15 I recommend that a new line extension case

16 be initiated after this general rate case has been

17 concluded in order to more closely examine the Company's

18 line extension tariff. Line extension costs need to be

19 updated, and allowances may need to be revised as well.

20 The Company may also wish to change other line extension

21 rules. Revising the line extension tariff will greatly

22 help to minimize future upward pressure on rates, and

23 will prevent subsidization of new customers by existing

24 customers.

25 Q. How frequently do you believe average unit

989

WWP-E-98-11 STERLING, R (Di) 24
04/23/99 Staff

1 costs should be updated?

2 A. If the Company desires to continue to use

3 average unit costs for pricing line extension work, then

4 I believe they should be updated annually.

5 WEATHER NORMALIZATION

6 Q. Have you reviewed the weather normalization

7 performed by the Company in this case?

8 A. Yes, I reviewed it in detail. I replicated

9 the method used by the Company in order to verify the

10 accuracy of the Company's results. I also varied the

11 analysis by using weather and customer usage data for

12 different periods of record than used by the Company. I

13 also examined different weather variables. In addition,

14 I performed weather normalization analysis for each of

15 the Company's customer classes to determine which classes

16 are sensitive to weather conditions.

17 Q. What is your opinion of the Company's

18 weather normalization?

19 A. I believe the Company's weather

20 normalization fairly and accurately adjusts test year

21 energy consumption and that no further adjustment to the

22 weather normalization proposed by the Company is

23 necessary.

24 Q. Does this conclude your testimony in this

25 proceeding?

990

WWP-E-98-11 STERLING, R (Di) 25
04/23/99 Staff

1 A. Yes, it does.

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3

4

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7

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23

24

25

991

WWP-E-98-11 STERLING, R (Di) 26
04/23/99 Staff

1 (The following proceedings were had in

2 open hearing.)

3 MR. WOODBURY: And I have one additional

4 question by way of clarification from where we wound up

5 at right before noon with Mr. Hirschkorn.

6

7 DIRECT EXAMINATION

8

9 BY MR. WOODBURY: (Continued)

10 Q Mr. Sterling, you were present when

11 Mr. Hirschkorn testified earlier?

12 A Yes, I was.

13 Q And did you feel that there was an

14 impression or a representation by Mr. Hirschkorn that

15 Exhibit 112 of yours was used for calculation purposes in

16 determining the amounts you recommended be imputed as

17 CIAC?

18 A Yes, I believe Mr. Hirschkorn did give that

19 impression.

20 Q And was that a correct impression?

21 A No. All of the numbers on Exhibit 112,

22 none of those numbers were actually used in my

23 calculation of the amount I believe should be imputed as

24 contributions in aid of construction. All of the numbers

25 that I used in my calculations are shown on Exhibit 110.

992

CSB REPORTING STERLING (Di)
Wilder, Idaho 83676 Staff

1 MR. WOODBURY: Madam Chair, I have no

2 further questions. I'd present Mr. Sterling for

3 cross-examination.

4 COMMISSIONER SMITH: Thank you,

5 Mr. Woodbury.

6 Mr. Ward?

7 MR. WARD: No questions. Thank you.

8 COMMISSIONER SMITH: Mr. Shurtliff.

9 MR. SHURTLIFF: Yes.

10

11 CROSS-EXAMINATION

12

13 BY MR. SHURTLIFF:

14 Q Mr. Sterling, at page 6 of your direct

15 testimony, you talk about the proposal of the Company,

16 I'm paraphrasing, and you have a statement at lines 21,

17 "I do not believe all customers should be burdened with

18 higher rates when much of the cause of the upper rate

19 pressure can be attributed to only a few customers." Do

20 you have that in mind?

21 A Yes, I do.

22 Q Do you continue to adhere today to that

23 position?

24 A Yes, I do, although I might qualify it

25 slightly by rather than saying few customers, simply

993

CSB REPORTING STERLING (X)
Wilder, Idaho 83676 Staff

1 saying new customers.

2 Q In that regard, line 12 of that page, you

3 indicate that the increase in revenue requirement, and

4 that's the previous number and I know it's changed, but

5 for purposes of my question it remains the same, is that

6 a significant portion of the revenue requirement is

7 caused by the distribution aspect; is that not correct?

8 A That's true.

9 Q Is any of that caused by Hecla, Bunker or

10 Silver Valley Resources?

11 A I don't know.

12 Q Have they added anything?

13 A Not to my knowledge.

14 Q In your view from your statement, you

15 believe that the new customers have caused this impact,

16 this pressure; is that my understanding?

17 A New customers since 1988.

18 Q You talked about -- you talked this morning

19 with the Company about your recommendation which is found

20 at page 2 of your testimony, you talked about the

21 contributions in aid of construction because of the

22 distribution plant, what I would characterize and you

23 don't need to, undercollection?

24 A Yes.

25 Q Do you continue to adhere to that view that

994

CSB REPORTING STERLING (X)
Wilder, Idaho 83676 Staff

1 there was some undercollection in that regard?

2 A Yes, I do.

3 Q And you heard the testimony this morning

4 that even if correct it's insignificant?

5 A Yes, I was here for that testimony.

6 Q Do you agree with that testimony?

7 A No, I do not.

8 Q In regard to -- and Mr. Ward characterized,

9 I think, correctly, we're all guided by selfish motives,

10 but I know less than anybody else, but in regard to the

11 three mining companies that are participants here, would

12 you agree or disagree with my notion that if they paid

13 their distribution costs when they got hooked up and then

14 over the course of time there was an undercollection of

15 new distribution costs to a new class of customers and

16 that's going to be put into the forward revenue

17 requirements of the Company to provide service, that in

18 effect those three mining companies would pay not only

19 for their own, but they would pay for those persons who

20 caused that undercollection if it's recaptured in the

21 future?

22 A Yes, I believe that's true.

23 Q So would you agree with me that while it

24 may be insignificant to some people, it might be

25 significant to other people?

995

CSB REPORTING STERLING (X)
Wilder, Idaho 83676 Staff

1 A Certainly.

2 Q Especially if -- I'll leave that.

3 I think I have nothing further. Thank you.

4 COMMISSIONER SMITH: Thank you,

5 Mr. Shurtliff.

6 Mr. Meyer.

7 MR. MEYER: Yes, I do.

8

9 CROSS-EXAMINATION

10

11 BY MR. MEYER:

12 Q Mr. Sterling, my cross-examination will

13 focus on your adjustment for contributions in aid of

14 construction and you did provide just a bit of

15 supplemental testimony when you took the stand, but let's

16 make sure we've set the issue in our minds before I get

17 too deeply into this. Essentially, you're proposing as

18 Staff to impute approximately 1.2 million in additional

19 monies for contribution in aid of construction; am I

20 correct?

21 A Yes.

22 Q And the effect of that would be to reduce

23 Idaho net rate base by approximately $639,000; do I have

24 that about right?

25 A I don't recall the exact figure.

996

CSB REPORTING STERLING (X)
Wilder, Idaho 83676 Staff

1 Q Well, let's not get tangled in that. I'm

2 more interested at this point in your concept, and what

3 you've done is you've compared, haven't you, average line

4 extension costs at two discrete points in time, first in

5 1988 and then again in 1997, haven't you?

6 A Yes, but that particular comparison is not

7 really the basis for the adjustment. The basis for the

8 adjustment is simply an inflation of the actual

9 contributions starting from 1988 to 1997.

10 Q And that's really the point I'm trying to

11 drive at is the assumption that gets you from 1988 to

12 1997 by way of inflation. Haven't you assumed to get

13 from the first point to the second point nearly 10 years

14 later that for each and every intervening year that line

15 extension costs have escalated at the same rate as the

16 S&P DRI price index?

17 A Yes, we have because that was the only

18 information we had available to us. In fact, we had

19 considerable difficulty in simply getting 1997 data from

20 the Company, so we used the best information we had.

21 Q Would you turn to your own Exhibit 114?

22 Let me know when you're ready.

23 A I'm ready.

24 Q Even if we were to make use of your own

25 exhibit, doesn't this show that costs in fact do not

997

CSB REPORTING STERLING (X)
Wilder, Idaho 83676 Staff

1 escalate uniformly over time?

2 A They show for Idaho Power Company that they

3 don't and I pointed that out in my testimony as well, and

4 I would say today I don't believe that they do escalate

5 uniformly even for Avista.

6 Q Now, you've -- incidentally, this is not an

7 issue about prudency of any expenditures, is it?

8 A Not to me it's not.

9 Q You were here earlier when Mr. Hirschkorn

10 testified in response to cross-examination, your

11 Exhibit 112, would you turn to that, please? Are you

12 ready?

13 A Uh-huh.

14 Q Okay, thank you. The column entitled,

15 Percentage Change Over 1989 Cost which is the second to

16 the last column, do you have that?

17 A Yes.

18 Q At the bottom it shows a percentage figure

19 of 25.18 percent; is that correct?

20 A Yes.

21 Q Did you arrive at that percentage figure by

22 simply averaging, not weighting but simply averaging, the

23 above figures, the above percentages?

24 A Yes, I did.

25 Q So there was no attempt to weight any

998

CSB REPORTING STERLING (X)
Wilder, Idaho 83676 Staff

1 particular percentage figure by the relative weight of

2 the dollars involved; correct?

3 A We had no information on the basis to make

4 that weighting.

5 Q Do you have any reason to disagree with

6 Mr. Hirschkorn's earlier testimony today that if those

7 numbers were in fact so weighted that the resulting

8 percentage would not be 25.18 percent but 3.87 percent?

9 A I believe Mr. Hirschkorn may be weighting

10 those based on 1997 weighting and ignoring the interim

11 period which you just referred to as inappropriate.

12 You'd need to -- to properly do it, you'd need to make a

13 correct weighting in each year since 1988 through 1997.

14 If we had that information, I certainly would have done

15 that, but I would point out again that numbers in this

16 exhibit are simply there for illustrative purposes only.

17 They were not used in any calculations.

18 Q But the net effect of what Mr. Hirschkorn

19 did even when comparing the '89 to '97 was still a

20 resulting figure of something below 4 percent, wouldn't

21 you agree with that calculation?

22 A That was Mr. Hirschkorn's testimony.

23 Q Have you had a chance since that testimony

24 was given earlier today to otherwise recalculate that

25 figure and offer up a different number?

999

CSB REPORTING STERLING (X)
Wilder, Idaho 83676 Staff

1 A No.

2 Q Okay. Now, you keep saying, well, you

3 didn't use that figure, you didn't use the 25.18 figure.

4 In fact, didn't you use a somewhat higher figure,

5 approximately 29 percent?

6 A No, I used the DRI index numbers for each

7 year between 1988 and 1997. What those numbers would

8 come out to be over a 10-year period, I didn't make that

9 calculation. I did it on a year-to-year basis.

10 Q Well, your own counsel earlier referred

11 everyone to Exhibit 110, your Exhibit 110?

12 A Yes.

13 Q Essentially, the message, if not the -- the

14 statement was your percentage was derived in fact from

15 that Exhibit 110 or your adjustment was derived from that

16 Exhibit 110; correct?

17 A That's true.

18 Q And if we turn to that and simply do the

19 division, Exhibit 110 shows for each of those years a

20 number of items and then it totals up to just over

21 $6 million for reported construction work in progress for

22 Idaho and then it adjusts upward by about a million, two

23 with a net difference which is the basis for your

24 adjustment of about 1.2 million; isn't that what that

25 exhibit shows?

1000

CSB REPORTING STERLING (X)
Wilder, Idaho 83676 Staff

1 A Yes, it does.

2 Q And just in terms of mathematical

3 percentages, that final figure of a million, two when

4 compared with the first figure of 6 million is about a

5 29 percent, that's about 29 percent of that figure; isn't

6 that about right?

7 A Subject to check, I would accept that.

8 Q Okay, and that essentially is what's going

9 on here, you've used a 29 percent figure for the

10 escalation?

11 A If that's the result of these numbers,

12 yes. Again, that's the information we had available to

13 us. I would have readily used information that the

14 Company provided had they chosen to provide it. They had

15 ample opportunity to provide it and have stated that much

16 of the information isn't available, so we went with the

17 best information we had.

18 Q Had you asked in any of your discovery in

19 this case for information for the intervening years?

20 A No, because -- we asked first for 1997

21 updated numbers for the costs that appear in the Schedule

22 51 tariff. The Company's initial response was something

23 to the effect that we don't have those numbers and can't

24 provide them. In a subsequent production request, we

25 asked for exactly the same information. The Company did

1001

CSB REPORTING STERLING (X)
Wilder, Idaho 83676 Staff

1 provide it at that time. We also asked the Company to

2 provide contributions in aid of construction for each

3 year since 19 -- between 1988 and 1997.

4 Eventually, that information was provided,

5 but it was, as I recall, approximately six weeks after

6 the date we had requested it be submitted to us, so we

7 didn't really think that -- the first time was a factor.

8 Given the difficulty that the Company had in providing

9 that information, we thought if they can't provide one

10 year's worth of information for 1997 that it was unlikely

11 that they would provide 10 years of information.

12 Q So there wasn't a follow-up request, then?

13 A No, there wasn't.

14 MR. MEYER: That's all I have. Thanks.

15 COMMISSIONER SMITH: Thank you, Mr. Meyer.

16 Do we have questions from the Commission?

17 Any redirect?

18 MR. WOODBURY: No, no redirect.

19 COMMISSIONER SMITH: Thank you,

20 Mr. Sterling.

21 (The witness left the stand.)

22 MR. WOODBURY: Staff's next witness is Lynn

23 Anderson.

24

25

1002

CSB REPORTING STERLING (X)
Wilder, Idaho 83676 Staff

1 LYNN ANDERSON,

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. Anderson, will you please state your

10 full name?

11 A I'm Lynn Anderson, A-n-d-e-r-s-o-n.

12 Q And for whom do you work and in what

13 capacity?

14 A The Idaho Public Utilities Commission as a

15 Staff economist.

16 Q And in that capacity, did you have occasion

17 to prepare and prefile actually revised May 12th

18 testimony consisting of 15 pages and Exhibits 129 through

19 132?

20 A Yes.

21 Q And have you had the opportunity to review

22 that testimony and exhibits prior to this hearing?

23 A Yes, I have.

24 Q And is it necessary to make any additional

25 changes?

1003

CSB REPORTING ANDERSON (Di)
Wilder, Idaho 83676 Staff

1 A Yes. In response to --

2 Q Do you have a revised exhibit that you'd

3 like to present?

4 A Yes, I have a revised Exhibit 131.

5 Q Which I believe has been passed out to

6 everyone. Could you explain the reason for this

7 revision?

8 A Don Falkner filed some rebuttal testimony

9 in his exhibit, I don't remember the number, anyway it

10 provided what I thought was a better estimate of the

11 calculated interest for the DSM balance, so I

12 incorporated that into my Exhibit 131.

13 Q Okay, and do the changes occur throughout

14 the exhibit?

15 A Yes, there are -- throughout the exhibit?

16 Q Yes, the revised exhibit.

17 A Yes, they are throughout that exhibit and

18 those do, unfortunately, result in a few corrections I

19 need to make in my testimony as well.

20 Q All right, and if we could walk through the

21 changes to your testimony, the first being on page 8, I

22 believe.

23 A Yes, page 8, line 9, the "$240,000" figure

24 should be "189,000." On line 11, the "$1.1 million"

25 figure should be "1.06." On line 13, the word "revised"

1004

CSB REPORTING ANDERSON (Di)
Wilder, Idaho 83676 Staff

1 should be inserted before "Exhibit No. 131." On that

2 same line 13, the "$55,000" figure should be "$60,000."

3 On line 23, the "$3.3 million" should be "$3.2 million."

4 On the next page, that's page 9, line 4,

5 the "$553,000" figure should be "$528,000," and finally,

6 on page 15, line 5, the "$240,000" figure should be

7 "$189,000."

8 Q And with those changes to your testimony

9 and revised Exhibit No. 131, if I were to ask you the

10 questions set forth in your testimony, would your answers

11 otherwise be the same?

12 A Yes.

13 MR. WOODBURY: Madam Chair, I'd ask that

14 the testimony with revisions be spread on the record and

15 Exhibits 129 through 132, including revised Exhibit 131,

16 be identified.

17 COMMISSIONER SMITH: If there is no

18 objection, it is so ordered.

19 (The following prefiled revised

20 testimony of Mr. Lynn Anderson is spread upon the

21 record.)

22

23

24

25

1005

CSB REPORTING ANDERSON (Di)
Wilder, Idaho 83676 Staff

1 Q. Please state your name and business

2 address for the record.

3 A. My name is Lynn Anderson and my business

4 address is 472 West Washington Street, Boise, Idaho.

5 Q. By whom are you employed and in what

6 capacity?

7 A. I am employed by the Idaho Public Utilities

8 Commission as a Staff economist.

9 Q. What are your duties with the Commission?

10 A. My duties include evaluating electricity,

11 natural gas, water and telephone utility applications and

12 customer petitions, as well as conducting generic

13 investigations, the results of which are used to make

14 recommendations to the Commission.

15 Q. Would you please outline your academic and

16 professional background?

17 A. I have a Bachelor of Science degree in

18 government and a Bachelor of Arts degree in sociology,

19 both from Idaho State University where I also studied

20 economics and architecture. I studied engineering at

21 Northwestern University and Brigham Young University and

22 public administration and quantitative analysis at Boise

23 State University. In addition, I have attended many

24 training seminars and conferences regarding utility

25 regulation, operations, forecasting, and marketing.

1006

WWP-E-98-11 ANDERSON (Rev) 1
5/12/99 Staff

1 I began my employment with the Commission in

2 1980 as a utility rate analyst. In 1983 I was appointed

3 to the position of telecommunications section supervisor

4 and in 1992 I was appointed to my present position as an

5 economist. In that capacity I have been the Staff's

6 representative to the Northwest Energy Efficiency

7 Alliance and Avista Corporation's External Energy

8 Efficiency Board.

9 From 1975 to 1980 I was employed by the

10 Idaho Transportation Department where I performed

11 benefit/cost analyses of highway safety improvements and

12 other statistical analyses.

13 Q. What is the purpose of your testimony?

14 A. The purpose of my testimony is to describe

15 my review of the demand side management (DSM; efficiency;

16 conservation) programs of Avista Corporation dba Avista

17 Utilities - Washington Water Power Division's (Avista;

18 Company). The DSM programs available to Avista's Idaho

19 customers are described in its Electric Tariff Schedule

20 90 and are financed by a 1.5% surcharge described as a

21 tariff rider in Schedule 91. Avista's estimated energy

22 savings and costs for these programs are shown in Company

23 witness Don Falkner's Exhibit Nos. 12 and 13.

24 I discuss general justifications for

25 conservation programs, whether or not Avista's customers

1007

WWP-E-98-11 ANDERSON (Rev) 2
5/12/99 Staff

1 approve of the DSM surcharges they are paying, and the

2 fact that Avista has not been annually notifying

3 customers of the surcharges. I quantify the balance of

4 DSM revenues beyond expenses incurred by Avista and

5 recommend that 10% annual interest be imputed on past DSM

6 account balances as specified in the Company's 1994

7 Application to implement its DSM tariff rider and that

8 the rider surcharges be reduced by one- third, that is to

9 1.0% from their current 1.5% level. I recommend that the

10 Commission find that the Company's DSM expenditures

11 through December 1998, have been prudently incurred.

12 However, I recommend a change in how Avista evaluates the

13 cost-effectiveness of its programs.

14 Q. What is the general justification for

15 allowing a utility to charge all customers for its

16 expenditures in promoting energy efficiency?

17 A. The concept was initiated when electricity

18 demand was growing rapidly and the costs of generating

19 additional electricity were higher than retail rates, let

20 alone just the energy portion of those rates. The

21 justification for DSM was that all customers benefitted

22 if some could reduce their electricity usage. While

23 demand is still growing, improved technologies and lower

24 natural gas prices have caused dramatic reductions in the

25 costs of generating additional electricity. Because of

1008

WWP-E-98-11 ANDERSON (Rev) 3
5/12/99 Staff

1 these cost decreases, DSM efforts are now more narrowly

2 focused. Customers, as a whole, still benefit from cost-

3 effective programs, albeit with program participants

4 receiving most of the benefits. The Company and Staff

5 also recognize that there are often non-energy, societal

6 benefits, such as greater productivity, cleaner air and

7 reduced need for damming rivers, associated with reduced,

8 or at least more efficient, energy usage.

9 Q. Do Avista customers generally approve of

10 the 1.5% surcharges that they pay to fund Avista's DSM

11 programs?

12 A. I don't know. Customers were notified of

13 the surcharges when they were implemented in 1995, but

14 only one customer has suggested to the Commission that

15 the surcharges might not be appropriate. Given the time

16 that has elapsed since the rider began and the growth

17 that has occurred since, it is questionable whether most

18 customers remember or ever knew of these surcharges.

19 The Company discovered from a 1994 survey

20 that while 81% of its customers knew that it offered DSM

21 programs, of those, only 15% were aware that all

22 customers were helping to pay for the programs through

23 their energy rates. Although this survey was conducted

24 prior to the tariff rider's implementation, there is no

25 evidence to suggest that if the survey had been repeated

1009

WWP-E-98-11 ANDERSON (Rev) 4
5/12/99 Staff

1 this year the results would not have been similar.

2 Q. Isn't the Company required to notify

3 customers of these surcharges once a year?

4 A. Yes, it is required, but the Company has

5 not been doing this. Paragraph 8) of the Stipulation

6 signed by the Company and Staff, which was accepted by

7 the Commission in Order No. 25917, states: "Each year the

8 rider will be shown in the annual How to Calculate Your

9 Bill brochure." (Case No. WWP-E-94-10) Exhibit No. 129

10 contains this Stipulation. Avista admits that it has not

11 been identifying the surcharges in its brochure because a

12 predecessor to its External Energy Efficiency Board had

13 decided it did not want the DSM surcharges identified.

14 Regardless, the Company is aware that it should adhere to

15 Commission decisions.

16 Q. Given that Avista collects funds from its

17 customers through the surcharges in advance of performing

18 its DSM activities, how does the Commission ensure that

19 these funds are used prudently?

20 A. Paragraph 5) of the Stipulation states that

21 the various conservation and efficiency activities

22 undertaken by the Company will not be presupposed to be

23 prudent and, in fact, can be argued to be imprudent in

24 future rate cases without the Company objecting to the

25 legal basis for such a scenario by invoking a retroactive

1010

WWP-E-98-11 ANDERSON (Rev) 5
5/12/99 Staff

1 rate making argument.

2 Q. Avista witness Don Falkner has requested

3 "that the Commission issue a finding that the energy

4 efficiency revenues collected under Schedule 91 have been

5 prudently expended through the energy efficiency programs

6 offered under Schedule 90." (Page 14, lines 15-17,

7 Prefiled Testimony) Can the Commission find, as Mr.

8 Falkner requests, "that the revenues collected have been

9 prudently expended?"

10 A. Not exactly. The Commission may find that

11 expenditures have been prudent, but it cannot find that

12 revenues in excess of actual costs have been prudently

13 expended until after they are, in fact, spent.

14 Q. What costs and over what time period is the

15 Company requesting that its DSM programs be found

16 prudent?

17 A. Mr. Falkner's revised Exhibit No. 12 shows a

18 total of $4,461,775 in DSM costs incurred by the Company

19 for its Idaho customers from March 1995 through December

20 1998.

21 Q. How does this amount of DSM expenditures

22 compare to the amount collected by the Company from its

23 customers through the 1.5% tariff rider?

24 A. Avista has collected $5,330,274 from its

25 Idaho customers through its DSM surcharges. This is

1011

WWP-E-98-11 ANDERSON (Rev) 6
5/12/99 Staff

1 $868,449, or 20%, more than it has spent for its

2 conservation and efficiency efforts in Idaho.

3 Q. What is the Company's justification for

4 carrying this positive balance?

5 A. Avista employees have told me that the

6 positive balance is necessary to enable them to prudently

7 manage their DSM program contract commitments.

8 Q. Did the Company's Application in Case No.

9 WWP-E-94-10/WWP-G-94-5 contemplate carrying such a large

10 balance?

11 A. No. In fact, in Attachment D to the

12 Company's Application in that case, paragraph 4 under

13 Rider Implementation reads as follows:

14 As the DSM programs on Schedule 91 and 191
are modified over time, the DSM Tariff Rate
15 would also be adjusted, up or down, to match
funding with DSM program costs and to keep
16 the deferred balance as close to zero as
possible.
17

18 Q. Should the Company be required to add

19 interest to the DSM balance?

20 A. Yes. As shown on Exhibit No. 130, within

21 the Company's proposed Accounting Guidelines filed as

22 Attachment E to its Application in Case No.

23 WWP-E-94-10/WWP-G-94-5, the fourth guideline states that

24 10% annual interest will be added to the balance of the

25 one month lagged differences between revenue and

1012

WWP-E-98-11 ANDERSON (Rev) 7
5/12/99 Staff

1 expenses. This 10% interest rate is also stated in

2 Attachment D to that Application on page 2 of the Summary

3 of DSM Tariff Rider. The Stipulation does not address

4 the issue of interest on balances, therefore the interest

5 provision proposed by the Company was approved by Order

6 No. 25917 as an unmodified portion of the Application.

7 Q. What is the amount of interest that should

8 be added to the DSM balance?

9 A. I have estimated that $189,000 in interest

10 should be added to the end-of-year 1998 DSM balance of

11 $868,498, bringing it up to about $1.06 million. The

12 calculation of this estimate is shown in the upper third

13 of Revised Exhibit No. 131. I estimate an additional

14 $60,000 of interest will have accrued by June 30, 1999.

15 Q. Please describe what is shown in the bottom

16 two-thirds of Exhibit No. 131.

17 A. The middle box of Exhibit No. 131 shows

18 projections of the DSM tariff rider balances that will

19 exist at the end of June and at end-of-year this year and

20 for the next four years. These projections are based on

21 past average revenues, expenditures and interest rate.

22 Assuming an extension of these conditions, at the end of

23 2003 there would be a positive balance of $3.2 million in

24 the DSM tariff rider account.

25 The bottom box of that exhibit shows similar

1013

WWP-E-98-11 ANDERSON (Rev) 8
5/12/99 Staff

1 projections of the DSM balances that would exist if the

2 tariff rider surcharges were reduced to 1.0% from the

3 current 1.5% level. Under this scenario, at the end of

4 2003, there would be a positive balance of $528,000 in

5 the DSM tariff rider account.

6 If, instead, the DSM tariff rider surcharges

7 were reduced by two-thirds, or to 0.5% of base rates, the

8 DSM balance would be reduced to zero by mid-year of 2001,

9 assuming DSM activity continues at its past average pace.

10 Q. What is your recommendation regarding the

11 1.5% level of the tariff rider surcharges?

12 A. I recommend that the DSM tariff rider energy

13 surcharges as shown in Exhibit No. 132 be reduced by

14 one-third, that is, to 1.0% of current base rates or a

15 smaller percent if base rates are increased. That level

16 should provide Avista with ample funds for managing its

17 DSM activity at its current pace for several years. Of

18 course, the Company would not be precluded from seeking

19 different DSM rates at any time in the future.

20 Q. Please describe the processes that should

21 be evident in utility DSM programs in order for the

22 Commission Staff to determine that such programs are

23 reasonable and prudent, thereby enabling it to recommend

24 to the Commission that utility customers pay for them.

25 A. In general, utilities should pre-evaluate

1014

WWP-E-98-11 ANDERSON (Rev) 9
5/12/99 Staff

1 DSM programs for probable cost-effectiveness and should

2 have implementation plans completed before full-scale

3 implementation begins. Utilities should closely monitor

4 these programs while they are operational with process

5 and program evaluations being conducted periodically, the

6 results of which should be used to modify programs as

7 necessary to obtain optimal results. Program evaluations

8 should reasonably estimate baseline customer activity

9 that would have occurred absent the program, which is

10 usually difficult but is essential for reliable

11 evaluations.

12 Q. Does the Company's DSM program design,

13 implementation and evaluation generally meet the

14 conditions you just described?

15 A. Avista meets my expectations in all areas

16 except that it does not explicitly estimate baseline

17 activity that would have occurred absent each of its

18 programs. Jon Powell, an Avista program evaluator, is

19 well aware that the DSM cost-effectiveness calculations

20 of its programs are overstated to the extent that some

21 program participants would have improved the efficiency

22 of their energy usage even without the various programs.

23 The Company apparently does not believe it would be a

24 prudent allocation of resources to produce reliable

25 estimates of such. Instead of hazarding guesses,

1015

WWP-E-98-11 ANDERSON (Rev) 10
5/12/99 Staff

1 Avista's program evaluators carefully monitor programs

2 and suggest modifying or dropping those that show only

3 marginal benefit/cost ratios. Nevertheless, Avista

4 should begin efforts to estimate the baseline activity of

5 customers regarding energy efficiency improvements that

6 would be undertaken in the absence of utility DSM

7 programs. Doing so would be consistent with how the

8 Northwest Energy Efficiency Alliance will evaluate its

9 programs that are funded, in part, from the tariff rider

10 surcharges Avista collects from its customers.

11 Q. Did you recently testify in Case No.

12 IPC-E-98-16 before this Commission to the effect that

13 Idaho Power's Commercial Lighting Program was not

14 prudently managed at least partly because its

15 cost-effectiveness calculations did not include estimates

16 of how many program participants would have installed

17 similar lighting improvements even without the program?

18 A. Yes, I testified that Idaho Power's program

19 was not prudently managed, but the fact that the cost-

20 effectiveness calculations did not include estimates of

21 what customers would have done absent the program played

22 only a small part in reaching this conclusion. In that

23 case, I recommended that the Commission find that Idaho

24 Power's costs were not prudently incurred for

25 continuation of its Commercial Lighting Program beyond a

1016

WWP-E-98-11 ANDERSON (Rev) 11
5/12/99 Staff

1 third year without performing any process or impact

2 evaluations for that program. My recommendation was also

3 based on the fact that Idaho Power did not perform most

4 of the evaluations that it specifically said it would do

5 in its application to initiate the program.

6 Q. Overall, was Avista's planning,

7 implementation and evaluation of its DSM programs prudent

8 from March 1995 through December 1998?

9 A. Yes. The Company created internal and

10 external organizations in its efforts to optimally

11 design, implement, coordinate, verify and evaluate its

12 DSM programs and these are not static processes.

13 Avista's internal DSM structure is such that its program

14 evaluators are organizationally separated from its

15 program managers and implementors, thus allowing more

16 objective verification of energy savings and program

17 evaluation. Avista continually monitors its programs and

18 processes and makes changes when it thinks it is

19 appropriate, but usually only after consulting with its

20 External Energy Efficiency Board. (This Triple E Board,

21 as it is sometimes called, is comprised of customers,

22 community representatives, recognized energy experts and

23 commissions staff.) For example, the Company is in the

24 process of refocussing its DSM efforts to "customer

25 segments" (i.e. agricultural, educational, food service,

1017

WWP-E-98-11 ANDERSON (Rev) 12
5/12/99 Staff

1 health care, hospitality, manufacturing, office, retail,

2 residential and low income) instead of continuing to

3 focus on individual programs. The Company recognizes

4 that some programs are not good "stand alone" programs

5 and that customers would be more efficiently served by a

6 package of programs tailored to their segment and managed

7 by Company employees who are well-versed in all aspects

8 of that segment.

9 Q. How much of the Company's DSM expenditures

10 from 1995 through 1998 were for its participation in the

11 Northwest Energy Efficiency Alliance (NEEA)?

12 A. Avista's obligations to NEEA for its Idaho

13 service area were about $155,000 for 1997 and $310,000

14 for 1998, or $465,000 total. Due to billing lags the

15 Company has deposited only $277,000 into its Idaho

16 account available to NEEA and this account has earned

17 about $3,000 interest. Because many of NEEA's project

18 contracts are not yet payable, NEEA has withdrawn only

19 $155,000 from the account, leaving a balance of $125,000

20 in the account plus $185,000 additional Avista obligation

21 for 1998. All of the amounts listed above are based on a

22 30% Idaho allocation of Avista totals.

23 Q. Have Avista's expenditures for NEEA been

24 reasonable and prudent?

25 A. Yes, I believe they have been.

1018

WWP-E-98-11 ANDERSON (Rev) 13
5/12/99 Staff

1 Q. What was the Commission's decision regarding

2 Idaho Power Company's October 1998 request in Case No.

3 IPC-E-98-12 for recovery of its 1997 and 1998 NEEA

4 expenditures?

5 A. In Order No. 27877 dated January 21, 1999,

6 the Commission authorized Idaho Power's recovery of its

7 1997 NEEA costs, but deferred recovery of its 1998 costs,

8 saying that it needed additional information to make a

9 determination for that year.

10 Q. What additional information is available

11 that enables you to say that Avista's participation in

12 NEEA through 1998 was prudent?

13 A. Order No. 27877 specifically mentioned that

14 a forthcoming PricewaterhouseCoopers (PWC) operational

15 audit report should be available before it could make a

16 decision regarding 1998 NEEA costs. This report is now

17 available and the conclusion therein is that while there

18 are areas in which NEEA should try to improve, its

19 fiduciary processes are sound and it is generally

20 effective and efficient in carrying out its stated

21 purposes and objectives.

22 In addition to the PWC report, Avista has

23 provided a report to me detailing how it leverages NEEA

24 projects and resources within its own service territory

25 and in conjunction with its own DSM programs.

1019

WWP-E-98-11 ANDERSON (Rev) 14
5/12/99 Staff

1 Q. Would you please summarize your

2 recommendations?

3 A. I have recommended that the Tariff Schedule

4 91 balance of revenues collected above expenses through

5 1998 be increased by an estimated $189,000 for the

6 accrual of interest and that the surcharges in that

7 schedule be reduced by one-third. I have recommended

8 that the Commission find that Avista's actual

9 expenditures through December 1998 for conservation and

10 efficiency efforts as described in Tariff Schedule 90,

11 including NEEA, be found reasonable and prudent.

12 Finally, I have recommended that in the future the

13 Company's cost effectiveness evaluations be explicitly

14 adjusted for DSM program participants that would have

15 made similar efficiency improvements on their own absent

16 Avista's programs.

17 Q. Does this conclude your revised testimony in

18 this proceeding?

19 A. Yes, it does.

20

21

22

23

24

25

1020

WWP-E-98-11 ANDERSON (Rev) 15
5/12/99 Staff

1 (The following proceedings were had in

2 open hearing.)

3 MR. WOODBURY: And I'd present Mr. Anderson

4 for cross-examination.

5 COMMISSIONER SMITH: Mr. Meyer, do you have

6 questions for Mr. Anderson?

7 MR. MEYER: I do and, again, I'll try and

8 just focus on an area or two and then be done with it.

9

10 CROSS-EXAMINATION

11

12 BY MR. MEYER:

13 Q At issue still in this case is the level of

14 funding resulting from the continued use of a

15 percent-and-a-half as opposed to what I understand to be

16 your recommendation for a one percent rider. Does that

17 correctly frame that issue?

18 A Yes.

19 Q Okay, and I think, if I understand your

20 testimony correctly, that you argue that a one percent

21 rider is sufficient to provide ongoing balances to fund

22 DSM projects; is that essentially what you're suggesting?

23 A Yes, not indefinitely, but for a number of

24 years.

25 Q Okay, and I know you've provided some

1021

CSB REPORTING ANDERSON (X)
Wilder, Idaho 83676 Staff

1 information in your testimony about cumulative balances

2 that might accumulate in that account over time given the

3 percent-and-a-half continuation; am I correct?

4 A Yes.

5 Q Okay. Have you undertaken -- now that I

6 understand the theory of what you're recommending, have

7 you examined the specific projects that as we go forward

8 may be in the works and may require funding under this

9 DSM?

10 A No, I haven't done that.

11 Q So you're not here to testify as to whether

12 or not as we proceed forward that there is or isn't the

13 need for maintaining those kind of balances for specific

14 projects?

15 A No.

16 Q Okay, but is it possible that there may be

17 projects in the works that require or that involve a

18 substantial lead time given the engineering of the

19 project?

20 A I would imagine, but I would have a hard

21 time imagining that any of those projects will require

22 several million dollars' worth of balance which will

23 happen if the revenues and expenses continue on the same

24 path.

25 Q That several million that you're referring

1022

CSB REPORTING ANDERSON (X)
Wilder, Idaho 83676 Staff

1 to projects out to the year 2003, doesn't it?

2 A Yes.

3 Q And a lot can happen between now and 2003?

4 A Certainly.

5 Q In fact, if program activity continues to

6 ramp up, who knows, it's just as likely that the

7 2-$3 million balance might be used up conceivably?

8 A Sure.

9 Q So there may in fact be no running balance

10 as we get out that far?

11 A Sure.

12 Q Would you agree with me that at least at

13 some level the Company needs to commit on its books a

14 certain level of funding for particular projects with

15 long lead times?

16 A I accept that, yes.

17 Q Okay. In fact, it would surprise you if we

18 didn't, wouldn't it?

19 A Probably, yes.

20 Q Does the Staff participate in what's been

21 described as the triple E board?

22 A Yes.

23 Q And so you have a seat at the table, so to

24 speak?

25 A Yes.

1023

CSB REPORTING ANDERSON (X)
Wilder, Idaho 83676 Staff

1 Q And does the triple E board analyze, among

2 other issues, funding levels?

3 A I don't know if analyze is the right word.

4 It's discussed now and then.

5 Q But it is a topic of discussion?

6 A Yes.

7 Q And it generates some interest?

8 A Yes.

9 Q Okay. Has the triple E board, to the best

10 of your knowledge, weighed in on your proposal to reduce

11 the funding level from a percent-and-a-half to a percent?

12 A Not to my knowledge.

13 Q Don't you think it would be appropriate for

14 them to have an opportunity to address this issue before

15 changes are made?

16 A No, I think this is really a Commission

17 decision on what the Commission thinks is an appropriate

18 balance should customers be required to continue to

19 contribute at the current level in accumulated additional

20 balances.

21 Q I'm sorry, I got distracted, what did you

22 just say?

23 A Good question. I had several thoughts

24 there, but the last was that I think this is a Commission

25 decision on what the appropriate customer contribution

1024

CSB REPORTING ANDERSON (X)
Wilder, Idaho 83676 Staff

1 should be vis-a-vis a steady or increasing balance of the

2 DSM funds.

3 Q Do you have in front of you this

4 Commission's Order issuing November 6, 1998?

5 A I believe I do have that.

6 Q Okay. If not, I can provide you one.

7 A Yes, I have that.

8 Q Turn to page 5 of that Order, please.

9 A Okay.

10 Q And this is under a heading called

11 "Commission Findings," is it not?

12 A Yes.

13 Q Now, in the second paragraph, I'll read

14 that out loud because I understand the Commissioners

15 probably don't have it in front of them, it reads as

16 follows: "The Commission finds that the Company's

17 proposal and rationale for removing the December 31,

18 1999, termination date of Water Power's energy efficiency

19 programs (Schedule 90) and 1.5 percent tariff rider

20 funding mechanism (Schedule 91) are reasonable," and it

21 goes on to say, "The Commission finds that the proposed

22 external energy efficiency board (triple E board) is a

23 reasonable means for stakeholders to review and recommend

24 changes to programs and funding levels."

25 Have I correctly read that?

1025

CSB REPORTING ANDERSON (X)
Wilder, Idaho 83676 Staff

1 A Yes.

2 MR. MEYER: That will be all. Thank you.

3 COMMISSIONER SMITH: Mr. Ward?

4 MR. WARD: No questions. Thank you.

5 COMMISSIONER SMITH: Mr. Shurtliff?

6 MR. SHURTLIFF: Yes, thank you.

7

8 CROSS-EXAMINATION

9

10 BY MR. SHURTLIFF:

11 Q Mr. Anderson, at page 4 of your direct

12 testimony, you indicate in the first paragraph commencing

13 at line 1, the second clause of the sentence that started

14 on the previous page, "DSM efforts are now more narrowly

15 focused. Customers, as a whole, still benefit from

16 cost-effective programs, albeit with program participants

17 receiving most of the benefits."

18 Does that remain your conclusion as you sit

19 here today?

20 A Yes.

21 Q And in that regard, have you reviewed the

22 testimony of Dr. Peseau in regard to his discussion about

23 the DSM programs?

24 A Yes, I believe I did read that.

25 Q And at page 41 of Dr. Peseau's testimony,

1026

CSB REPORTING ANDERSON (X)
Wilder, Idaho 83676 Staff

1 he indicates that in his opinion the DSM expenses ought

2 to be allocated to those classes that receive the benefit

3 in his words. Do you recall reading that?

4 A Yes, I recall that.

5 Q Do you agree or disagree with his

6 proposition in that regard?

7 A I disagree with that and let me explain.

8 Q Surely.

9 A Over time the various classes that have

10 received the most benefit, so to speak, from DSM

11 programs, it changes. Early on it was residential

12 classes and now it's focused more on industrial and

13 commercial and if we were to allocate DSM costs in that

14 fashion, then we would be essentially changing the

15 allocation every year or more frequently, for that

16 matter.

17 Q Well, you would change the allocation each

18 time the number changed as to where the money was flowing

19 to for the program, would you not?

20 A Yes, but then I would add that overall DSM

21 is still only undertaken or at least theoretically only

22 undertaken if it's cost effective for the utility

23 ratepayers in general, so it's still cost effective for

24 the general body of ratepayers.

25 MR. SHURTLIFF: I have nothing further.

1027

CSB REPORTING ANDERSON (X)
Wilder, Idaho 83676 Staff

1 Thank you.

2 COMMISSIONER SMITH: Thank you,

3 Mr. Shurtliff.

4 Do we have questions from the Commission?

5 I just had one, Mr. Anderson.

6

7 EXAMINATION

8

9 BY COMMISSIONER SMITH:

10 Q You discussed with Mr. Meyer an Order of

11 the Commission where we agreed that the triple E board is

12 a good thing to discuss certain issues.

13 A Yes.

14 Q Do you think that the Commission intended

15 with those positive comments to relinquish its

16 decision-making authority in matters involving

17 surcharges?

18 A No, I do not and probably I should have

19 followed up in my answer to Mr. Meyer. Quoting right

20 from the Order, it says that the triple E board is a

21 reasonable means for stakeholders to review and recommend

22 changes to programs and funding levels and that in no way

23 talks about DSM balances and only says that it's a

24 reasonable means to review and recommend changes, not to

25 make decisions.

1028

CSB REPORTING ANDERSON (Com)
Wilder, Idaho 83676 Staff

1 COMMISSIONER SMITH: Okay, thank you.

2 Do you have redirect, Mr. Woodbury?

3 MR. WOODBURY: Just one question along that

4 same line.

5

6 REDIRECT EXAMINATION

7

8 BY MR. WOODBURY:

9 Q Mr. Anderson, would you agree that there's

10 a difference between the nature of review of the triple E

11 board with respect to program funding levels, which I'm

12 assuming is individual DSM programs, and the tariff rider

13 surcharge percentage authorized by Schedule 91?

14 A Yes, they are separate animals.

15 MR. WOODBURY: Okay, thank you. I have no

16 further questions.

17 COMMISSIONER SMITH: Thank you, and thank

18 you for your help, Mr. Anderson.

19 (The witness left the stand.)

20 COMMISSIONER SMITH: Let's take a

21 ten-minute break.

22 (Recess.)

23 COMMISSIONER SMITH: We'll go back on the

24 record. Mr. Woodbury.

25 MR. WOODBURY: Syd Lansing is Staff's next

1029

CSB REPORTING ANDERSON (Di)
Wilder, Idaho 83676 Staff

1 witness.

2

3 SYDNEY LANSING,

4 produced as a witness at the instance of the Staff,

5 having been first duly sworn, was examined and testified

6 as follows:

7

8 DIRECT EXAMINATION

9

10 BY MR. WOODBURY:

11 Q Mr. Lansing, please state your full name.

12 A Sydney Lansing.

13 Q And for whom do you work and in what

14 capacity?

15 A I work for the Idaho Public Utilities

16 Commission. I'm a Staff auditor.

17 Q In that capacity, did you have occasion to

18 prepare and prefile testimony in this proceeding

19 consisting of 17 pages and Exhibits 115 through 117?

20 A Yes, I did.

21 Q And did you have the opportunity to review

22 those exhibits and testimony before today?

23 A Yes, sir, I did.

24 Q And is it necessary to make any changes?

25 A No.

1030

CSB REPORTING LANSING (Di)
Wilder, Idaho 83676 Staff

1 Q If I were to ask you the questions set

2 forth in the testimony, would your answers be the same?

3 A Yes, they would.

4 MR. WOODBURY: Madam Chair, I'd ask that

5 the testimony be spread on the record and Exhibits 115

6 through 117 be identified.

7 COMMISSIONER SMITH: If there is no

8 objection, it is so ordered.

9 (The following prefiled testimony of

10 Mr. Sydney Lansing is spread upon the record.)

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

1031

CSB REPORTING LANSING (Di)
Wilder, Idaho 83676 Staff

1 Q. Please state your name and business address

2 for the record.

3 A. My name is Sydney Lansing. My business

4 address is 472 W. Washington Street, Boise, Idaho.

5 Q. By whom are you employed and in what

6 capacity?

7 A. I am employed by the Idaho Public Utilities

8 Commission as a Staff Auditor in the Accounting Section.

9 Q. Give a brief description of your educational

10 background and experience.

11 A. I graduated from San Jose State College,

12 California in 1958 with a B.A. degree in Business

13 Emphasis in Accounting. I was licensed to practice as a

14 Certified Public Accountant in 1960. I was employed as

15 an Auditor by Arthur Young and Company in San Francisco

16 and by Roland Crabtree, CPA in Riverside, California. I

17 was the partner in charge of audits in the firm of Purl

18 and Lansing in Riverside, California. I have been hired

19 several times to install accounting systems and I have

20 been the Controller of two different organizations. I

21 have attended many seminars, classes and courses

22 involving auditing, accounting and tax issues.

23 Q. What is the purpose of your testimony?

24 A. My testimony involves three issues:

25 depreciation, allocations, and income taxes.

1032

WWP-E-98-11 LANSING (Di) 1
04/23/99 Staff

1 Q. Are you sponsoring any exhibits?

2 A. I am sponsoring three exhibits: (1) Exhibit

3 No. 115 showing a comparison of existing depreciation

4 rates with proposed depreciation rates at the total

5 electric system level; (2) Exhibit No. 116 showing a

6 comparison of depreciation factors, average service lives

7 and future net salvage percentages, and (3) Exhibit No.

8 117 showing the calculation of the adjustments to federal

9 and state income tax expense as well as a comparison of

10 the calculation of the revenue conversion factor.

11 DEPRECIATION

12 Q. What did Avista Corporation dba Avista

13 Utilities - Washington Water Power Division (Avista;

14 Company) request with respect to depreciation in this

15 case?

16 A. Avista is asking for approval of new

17 depreciation rates as well as the resulting depreciation

18 expense amount. Mr. Don Falkner's direct testimony,

19 pages 22 through 26, explains the depreciation requested

20 by the Company. There are three factors that influence

21 the calculation of a depreciation rate: (1) the projected

22 life of the asset usually expressed in years; (2) the

23 projected cost of removing the asset at the end of its

24 useful life net of any salvage value; and (3) the

25 projected length of time between the demise and removal

1033

WWP-E-98-11 LANSING (Di) 2
04/23/99 Staff

1 of the first asset of the group and the demise and

2 removal of the last asset of the group, i.e., the Iowa

3 curve appropriate for the group. The requested increase

4 in depreciation rates in this case is largely caused by

5 projected increases in removal costs.

6 Q. What is the dollar impact of the requested

7 depreciation changes?

8 A. Avista has asked for an increase in

9 depreciation from about $38 million to about $45 million

10 at the total electrical system level. That $7 million

11 increase at the total system would be about $2.4 million

12 for the electric system, Idaho jurisdiction.

13 Additionally, the Company indicates a request of about

14 $0.8 million decrease in rate base to reflect a change in

15 both accumulated depreciation and deferred income tax.

16 Q. Do you accept the Company's proposed changes

17 in the calculation of its depreciation?

18 A. Not in total. I agree with the Company's

19 requested increases related to the following classes of

20 assets: Steam Production Plant, Hydraulic Production

21 Plant, Other Production Plant, and General Plant. I do

22 not agree with the proposed changes related to

23 Transmission Plant and Distribution Plant.

24 Q. What adjustments do you recommend to the

25 Company's requested increase in depreciation?

1034

WWP-E-98-11 LANSING (Di) 3
04/23/99 Staff

1 A. Review of the accounts related to

2 depreciation revealed two main issues. First, there was

3 an error in applying the depreciation rate to the correct

4 depreciable amount, and second, there were judgmental

5 decisions related to costs of removal and future net

6 salvage that should be adjusted. I recommend the

7 following adjustments to the Company's depreciation

8 request:

9 1. Error in applying
the rate of depreciation $182,000
10 2. Transmission net salvage
adjustment $258,000
11 3. Distribution net salvage
adjustment $283,000
12 Total $723,000

13 Also, I recommend related adjustments to accumulated

14 depreciation ($383,000) and to deferred income tax

15 ($268,000).

16 Q. What is the nature of the error in applying

17 the rate of depreciation?

18 A. In several of the accounts, mostly

19 production accounts, the depreciation rate was applied to

20 the year end balance in the account. The depreciation

21 rate should have been applied to the average balance.

22 This is purely a mechanical calculation that should be

23 adjusted, and does not have anything to do with a

24 difference in theory.

25 Q. What is the nature of the adjustments

1035

WWP-E-98-11 LANSING (Di) 4
04/23/99 Staff

1 related to net salvage in Transmission and Distribution

2 Plant?

3 A. I have prepared Exhibit No. 116 showing the

4 old depreciation parameters (established in 1990), the

5 Company proposed parameters (proposed in this case), and

6 the parameters that I propose for this case. Examination

7 and comparison of the "Future Net Salvage" columns shows

8 that the Company proposes a large increase in removal

9 costs. Future net salvage is a projected amount based on

10 past removals with their related costs increased by

11 anticipated inflation and other anticipated costs.

12 Obviously the projection is an art form, not a specific

13 science. There are always areas of judgement that fall

14 within a range of reasonableness in making these

15 projections. I believe that the midpoint in the range of

16 reasonableness is a better assumption to use in setting

17 future net salvage. Therefore, the accounts with large

18 proposed changes in future net salvage were adjusted to

19 approximately that midpoint.

20 Q. What level of depreciation expense do you

21 propose for this case?

22 A. I have prepared Exhibit No. 115 to show the

23 proposed depreciation expense at the total electric

24 system level so the actual depreciation increase included

25 in this case can be evaluated. Page 5 of Exhibit No. 115

1036

WWP-E-98-11 LANSING (Di) 5
04/23/99 Staff

1 shows the overall composite depreciation rate increases

2 from 2.46% to 2.85% and the depreciation expense

3 increases from $38,123,964 to $44,113,014, i.e., an

4 increase of almost $6 million on a total system basis, or

5 about 15.7%. For comparison, the Company requests an

6 increase in overall composite depreciation rates from

7 2.46% to 2.98%, an increase of about $7 million at the

8 total system level, or about 19% (see Falkner, Di,

9 page 24).

10 Q. When was the last time this Commission

11 established general tariff rates as part of a full rate

12 case and when was the last time depreciation rates were

13 established for Avista's (formerly Washington Water

14 Power) electric system?

15 A. The last time this Commission set general

16 tariff rates as part of a full rate case was in Case

17 No. U-1008-256 concluded by Order No. 20905, signed

18 December 4, 1986. In that case, depreciation was not a

19 material issue; however, in 1990 the Company requested

20 new depreciation rates be approved starting January 1,

21 1990. The Commission approved the 1990 depreciation

22 rates subject to justification in a rate case.

23 Therefore, the depreciation rates shown in Exhibit No.

24 115 as "Existing Rates" are from that 1990 tentative

25 depreciation approval, and this case should set the

1037

WWP-E-98-11 LANSING (Di) 6
04/23/99 Staff

1 depreciation rates on a going forward basis.

2 Accordingly, the comparisons of depreciation factors

3 presented in Exhibit No. 116 show the starting position

4 for the depreciation factors to be the 1990 tentative

5 approval.

6 Q. Are there any adjustments made to the

7 depreciation expense other than those mentioned above?

8 A. Yes, Staff engineer Rick Sterling recommends

9 a line extension adjustment of $1,178,000 which includes

10 $26,000 for depreciation expense. The adjustment to

11 plant in service ($1,152,000) reduces the base on which

12 depreciation should be calculated (see Exhibit No. 118,

13 lines 13 and 38, Column F "line extension").

14 Additionally, I have adjusted accumulated depreciation by

15 $110,000 and deferred income tax by $403,000 as a result

16 of that adjustment to plant in service (see Exhibit No.

17 118, Column F "line extension", lines 41 and 45.)

18 ALLOCATIONS

19 Q. What is the allocation method used by

20 Avista?

21 A. The Company first attempts to directly

22 assign any cost to a specific jurisdiction and account.

23 After the direct assignment has been completed, the

24 Company uses a four-factor formula to allocate other

25 costs. The four factors are: (1) direct operations and

1038

WWP-E-98-11 LANSING (Di) 7
04/23/99 Staff

1 maintenance expense; (2) direct labor expense; (3) number

2 of customers, and (4) net direct plant. Direct

3 assignment may result in a charge to an account that is

4 later allocated by the four factor formula. For example,

5 a cost directly assigned to the electric system in

6 general will be allocated between the Washington and

7 Idaho jurisdictions.

8 Q. Were there any specific concerns that you

9 investigated?

10 A. There were concerns that allocations of top

11 management salaries and director fees using the four

12 factor allocation formula utilized by Avista would result

13 in a disproportionate share of those costs being

14 allocated to subsidiaries that have a large investment in

15 fixed assets, i.e., the regulated utility company. The

16 idea is that unregulated subsidiaries with a small

17 investment in fixed assets, like Avista Energy, would not

18 be allocated a fair amount of the costs by utilizing the

19 four factor formula. The salaries of the board of

20 directors as reported on their respective W-2 forms for

21 1997 was allocated at 56% to non-utility operations and

22 44% to Utility Operations Expense. After that allocation

23 76% of the amount allocated to utility operations was

24 allocated to Electric Utility Expense (the balance was

25 allocated to Gas Utility Expense). Then 37% of the

1039

WWP-E-98-11 LANSING (Di) 8
04/23/99 Staff

1 electric utility amount was allocated to the Idaho

2 jurisdiction for electricity. Therefore, 12% of the

3 total salaries was allocated to electric utility - Idaho

4 jurisdiction. This combination of allocations appears

5 reasonable.

6 Q. As part of the additional concerns that you

7 investigated, did you review the utility's transactions

8 with affiliated companies?

9 A. Yes, there are two levels of affiliate

10 transactions: (1) Transactions between affiliates that

11 are both regulated utility companies, and (2)

12 transactions between a regulated utility company and an

13 affiliate that is not regulated. The various regulated

14 sections of Avista Utilities are: Washington Water Power

15 - Gas (operating in Washington and Idaho); Washington

16 Water Power - Electric (operating in Washington and

17 Idaho), and Water Power Natural Gas (WPNG) - Gas

18 (operating in Oregon and California). Transactions

19 between regulated affiliates are as close as possibly

20 recorded the same way costs are allocated, i.e., direct

21 assignment and then the four-factor formula (see Exhibit

22 No. 10 sponsored by Mr. Falkner). Transactions between a

23 non-regulated affiliate and a regulated utility are small

24 in both number of transactions and amount of dollars

25 involved. However, when a transaction occurs the attempt

1040

WWP-E-98-11 LANSING (Di) 9
04/23/99 Staff

1 is made to keep it at arms length. Services are priced

2 at fully distributed cost, e.g., consolidation of the

3 financial statements for income tax preparation are

4 costed at the allocation factor level.

5 Q. How are the direct assignment and allocation

6 accounts identified?

7 A. Avista accounting personnel make these

8 judgements, working from the overall to the most minute

9 level of accountability as to what parts of the Company

10 benefit from each cost: (a) total company, each part of

11 the Company benefits including regulated and non-

12 regulated affiliates; (b) any specific affiliate; (c) all

13 gas operations; (d) specific jurisdiction of gas

14 operations; (e) all electric operations; (f) specific

15 jurisdiction of electric operations, and (g) specific

16 account within the previous designations. Examples of

17 these postings can be seen on page 5 of Exhibit No. 115.

18 See "General Plant Utility 0" - the 0" means Avista

19 Utilities - Washington Water Power Electric. See

20 "General Plant Utility 7" - the 7" means common to

21 Avista Utilities - Washington Water Power Electric,

22 Washington Water Power Gas, and Water Power Natural Gas.

23 See "General Plant Utility 9" - the 9" means common to

24 Avista Utilities - Washington Water Power Electric and

25 Washington Water Power Gas. All of these accounts and

1041

WWP-E-98-11 LANSING (Di) 10
04/23/99 Staff

1 their related expense accounts are then allocated to the

2 various jurisdictions by use of the four factor formula.

3 Q. Do you agree with the allocation process

4 utilized by Avista?

5 A. I think, generally speaking, it is a

6 reasonable process.

7 INCOME TAXES

8 Q. Are there any unusual income tax items in

9 this case?

10 A. There are two items of interest in

11 calculating income taxes in this case. First,

12 accumulated unamortized federal investment tax credits

13 are almost entirely gone because they were written off in

14 1987. Second, Idaho state income taxes need to be

15 calculated using the normalization method, the same way

16 the federal income taxes are normalized.

17 Q. Why were the accumulated unamortized

18 federal investment tax credits written off?

19 A. Washington Water Power requested in Case No.

20 U-1008-270 that the Commission allow the Company to pass

21 the unamortized investment tax credits to its

22 stockholders. This Commission issued two orders allowing

23 Washington Water Power to pass the accumulated

24 unamortized federal investment tax credits to its

25 stockholders, Order Nos. 21416 and 21579.

1042

WWP-E-98-11 LANSING (Di) 11
04/23/99 Staff

1 Q. Do any of the federal investment tax

2 credits still exist?

3 A. Yes, the amount amortized against income

4 tax expense is $23,000, Exhibit No. 118, line 31.

5 Q. Why is normalizing Idaho income tax expense

6 an issue?

7 A. This Commission issued several orders in

8 years past indicating that Washington Water Power, as

9 well as other companies, must record Idaho income taxes

10 using a flow through method (see Order No. 17782). The

11 Idaho legislature changed the income tax law in 1996 to

12 conform in this area to the federal income tax law which

13 does not allow flow through. Because of the legislative

14 change, it is necessary to normalize state income tax

15 expense.

16 Q. How are the federal and state income taxes

17 presented in this case?

18 A. Both federal and state income taxes are

19 calculated and presented using the normalization method.

20 Additionally, because there is a difference in the

21 allocation methodology between state income tax and

22 regulatory requirements, state income taxes are

23 calculated using an effective tax rate as required by

24 this Commission (see Order No. 22369).

25 Q. What adjustments to Company proposed Idaho

1043

WWP-E-98-11 LANSING (Di) 12
04/23/99 Staff

1 state income tax expense do you recommend?

2 A. I recommend four adjustments to Avista's

3 proposed Idaho state income tax expense: (1) reduce state

4 income tax expense because the amount posted in the

5 Company books was in excess of the actual cost; (2)

6 increase state income tax expense because state

7 investment tax credits were deducted in a flow through

8 methodology instead of normalization; (3) decrease state

9 income tax by the proper normalization amount of the

10 state investment tax credits, and (4) reduce the state

11 income tax effective tax rate in calculating a Revenue

12 Conversion Factor.

13 Q. Please explain the adjustment to state

14 income tax expense because the amount posted in the

15 Company's books is not the actual cost.

16 A. The Company estimates the amount of state

17 income tax expense prior to the start of the tax year.

18 Therefore, these proposed postings can be posted starting

19 in January of the tax year. The monthly postings are

20 made based on information available for the month

21 including estimates. Updates can be made as additional

22 information is available. After the close of the tax

23 year, about September of the next year, the tax return is

24 filed and the amount of the actual tax for the year is

25 known. The books, of course, are adjusted to reflect the

1044

WWP-E-98-11 LANSING (Di) 13
04/23/99 Staff

1 proper amount of tax payable, but the expense accounts

2 for the year in question have been closed. The Company

3 filed this case from the closed books. The difference

4 between the amount posted in the books and the actual tax

5 paid from the 1997 income tax return is $878,178 (see

6 calculation in Exhibit No. 117, item 1).

7 Q. Please explain the increase in state income

8 tax expense because state investment tax credits were

9 deducted in a flow through methodology instead of

10 normalization.

11 A. Avista filed a normal Idaho state income tax

12 form for its Idaho operations which includes electric,

13 gas and subsidiaries. On that tax return, the Company

14 reduced tax by applying the available investment tax

15 credits. The Company books its state tax expense on the

16 flow through system; therefore, all of the investment tax

17 credits used on the tax return reduced income tax

18 expense. This practice must be changed to fit the

19 normalization rules. I have calculated that in order to

20 remove the investment tax credits related to flow through

21 booking for the electric portion of the Idaho business,

22 tax expense must increase $533,298 (see Exhibit No. 117,

23 item 2, for the calculation).

24 Q. What is the net change in tax expense

25 because of the first two items on Exhibit No. 117?

1045

WWP-E-98-11 LANSING (Di) 14
04/23/99 Staff

1 A. The net decrease in state income tax expense

2 is $344,880. See Exhibit No. 117 for the calculation and

3 Exhibit No. 118, line 25, for the application to revenue

4 requirement.

5 Q. You have removed all of the state investment

6 tax credits from income tax expense. How does the

7 customer get the benefit of the reduced tax caused by the

8 investment tax credits?

9 A. The investment tax credit should be

10 amortized as a reduction of state income tax expense

11 rateably over the life of the asset that created the

12 credit (see the calculation at Exhibit No. 117, item 3

13 ($153,914)). I have reduced state income tax expense by

14 the amortization of the investment tax credits, rounded

15 to $154,000 (see Exhibit No. 118, line 26).

16 Q. How did you calculate the amortization of

17 the investment tax credit?

18 A. I reviewed the Investment Tax Credits

19 recorded on Idaho tax returns since 1982. I then

20 reviewed the depreciation schedule to determine a proper

21 amortization period. There are assets with a

22 depreciation life in excess of 30 years and assets with a

23 depreciation life shorter than 30 years. I determined

24 that a 30-year amortization period would properly reflect

25 the depreciation life of the assets related to the ITC.

1046

WWP-E-98-11 LANSING (Di) 15
04/23/99 Staff

1 Using a 30-year amortization of the credits, I calculated

2 a total amortization of $243,000. Both gas and electric

3 assets are included in the total ITC, so I allocated part

4 of the ITC to gas using the ratio of plant in service for

5 gas (36.661%). The remaining amount ($153,914) is

6 presented to reduce electric state income tax expense as

7 is proper for normalization. See Exhibit No. 117, item

8 4, the calculation and Exhibit No. 118, line 26, for

9 application to the calculation of the revenue

10 requirement.

11 Q. What adjustments to Company proposed

12 federal income tax expense do you recommend?

13 A. I recommend a reduction of federal income

14 tax expense of $173,866. Because the same posting

15 process is used for the federal income tax expense as is

16 explained above for the state income tax expense, there

17 was an over posting of federal income tax expense. I

18 recommend that over posting be corrected by reducing

19 federal income tax expense. See Exhibit No. 117, item 4,

20 for the calculation and Exhibit No. 118, line 28, for

21 application to the revenue requirement.

22 Q. What is the difference between the way you

23 calculate the Revenue Conversion Factor and the way the

24 Company calculates it?

25 A. I have prepared a comparison of the

1047

WWP-E-98-11 LANSING (Di) 16
04/23/99 Staff

1 calculations (Exhibit No. 117, item 5) showing the

2 individual items that make up the calculation. The only

3 difference is the Idaho state income tax factor. The

4 Company calculated its factor using a 1996 Idaho income

5 tax return and I calculate the Idaho state income tax

6 factor using a 1997 tax year, the test year in this case.

7 The difference in the two methods is about $20,000 when

8 dealing with a $6.3 million conversion.

9 Q. Does this conclude your direct testimony in

10 this proceeding?

11 A. Yes, it does.

12

13

14

15

16

17

18

19

20

21

22

23

24

25

1048

WWP-E-98-11 LANSING (Di) 17
04/23/99 Staff

1 (The following proceedings were had in

2 open hearing.)

3 MR. WOODBURY: And I'd present Mr. Lansing

4 for cross-examination at this time.

5 COMMISSIONER SMITH: Mr. Meyer, do you have

6 questions for Mr. Lansing?

7 MR. MEYER: We do not. Thank you.

8 COMMISSIONER SMITH: Mr. Shurtliff?

9 MR. SHURTLIFF: None.

10 COMMISSIONER SMITH: Mr. Ward?

11 MR. WARD: None.

12 COMMISSIONER SMITH: Any from the

13 Commission?

14 COMMISSIONER KJELLANDER: None.

15 COMMISSIONER HANSEN: I have a few here.

16 COMMISSIONER SMITH: That being the case,

17 there is no redirect and we thank Mr. Lansing.

18 (The witness left the stand.)

19 COMMISSIONER SMITH: Mr. Woodbury, we're

20 ready for your next witness.

21 MR. WOODBURY: Yes, Kathy Stockton.

22

23

24

25

1049

CSB REPORTING LANSING
Wilder, Idaho 83676 Staff

1 KATHLEEN L. STOCKTON,

2 produced as a witness at the instance of the Staff,

3 having been first duly sworn, was examined and testified

4 as follows:

5

6 DIRECT EXAMINATION

7

8 BY MR. WOODBURY:

9 Q Ms. Stockton, will you please state your

10 full name?

11 A Kathleen Stockton.

12 Q And for whom do you work and in what

13 capacity?

14 A Staff auditor, Idaho Public Utilities

15 Commission.

16 Q In that capacity, did you have occasion to

17 prepare and prefile testimony in this proceeding

18 consisting of 20 pages and Exhibits 118 and 119?

19 A Yes.

20 Q Have you had the opportunity to review that

21 testimony and those exhibits for this hearing?

22 A Yes, I have.

23 Q Is it necessary to make any changes or

24 corrections?

25 A No, it's not.

1050

CSB REPORTING STOCKTON (Di)
Wilder, Idaho 83676 Staff

1 Q If I were to ask you the questions set

2 forth in your testimony, then would your answers be the

3 same?

4 A Yes, they would.

5 MR. WOODBURY: Madam Chair, I'd ask that

6 the testimony be spread on the record and the exhibits be

7 identified.

8 COMMISSIONER SMITH: If there is no

9 objection, that is so ordered.

10 (The following prefiled testimony of

11 Ms. Kathleen Stockton is spread upon the record.)

12

13

14

15

16

17

18

19

20

21

22

23

24

25

1051

CSB REPORTING STOCKTON (Di)
Wilder, Idaho 83676 Staff

1 Q. Please state your name and business address?

2 A. My name is Kathleen L. Stockton. My

3 business address is 472 West Washington Street, Boise,

4 Idaho.

5 Q. By whom are you employed and in what

6 capacity?

7 A. I am employed as a Senior Auditor by the

8 Idaho Public Utilities Commission.

9 Q. Please describe your educational background

10 and professional experience.

11 A. I received my B.B.A. degree majoring in

12 Accounting from Boise State University in December 1992.

13 Following graduation I was employed by the Idaho State

14 Tax Commission as a Tax Enforcement Technician. In my

15 capacity as a Tax Enforcement Technician, I performed

16 desk audits on individual state income tax returns. I

17 was promoted to Tax Auditor, and after meeting the

18 underfill requirements, was promoted to Senior Tax

19 Auditor. In my capacity as an auditor, I performed

20 audits on Special Fuel and Motor Fuel Tax returns,

21 International Fuels Tax Agreement Returns and Special

22 Fuel User tax returns. I accepted employment with the

23 Idaho Public Utilities Commission (IPUC; Staff) in July

24 of 1995. I attended the National Association of

25 Regulated Utility Commissioners Annual Regulatory Studies

1052

WWP-E-98-11 STOCKTON, K (Di) 1
04/23/99 Staff

1 program at Michigan State University in the summer of

2 1996. I have testified previously in Capital Water's

3 rate case, Case No. CAP-W-95-1 and in the U S WEST rate

4 case, Case No. USW-S-96-5.

5 Q. What is the purpose of your testimony?

6 A. The purpose of my testimony is to present

7 Staff's calculated revenue requirement. I will discuss

8 the Staff adjustments to the revenue requirement proposed

9 by Avista Corporation dba Avista Utilities - Washington

10 Water Power Division (Avista; Company) in witness

11 Falkner's testimony. Commission Staff has adjustments to

12 both net operating income and rate base.

13 Q. Please summarize your testimony.

14 A. The Company is proposing a revenue

15 requirement of $192,029,000, and a rate base of

16 $360,534,000. Staff is proposing a revenue requirement

17 of $188,040,000, and a rate base of $360,546,000. The

18 Company's existing revenue is deficient by $10,234,000.

19 This revenue requirement, after expenses and income taxes

20 results in a net operating income of $32,712,000. Staff

21 Exhibit No. 118, page 3, summarizes the Company and

22 Staff's cases, with a comparison between the two and

23 calculation of the differences between the two proposals.

24 Q. What return is used in calculating the Staff

25 revenue requirement?

1053

WWP-E-98-11 STOCKTON, K (Di) 2
04/23/99 Staff

1 A. The overall rate of return I used in my

2 calculations of the revenue requirement is 9.073%. This

3 is the overall rate of return on rate base proposed by

4 Staff witness Terri Carlock. In her testimony, Staff

5 witness Carlock recommends an 11% return on equity. The

6 Company is recommending a 12% return on equity and a

7 9.446% overall rate of return.

8 Q. Do you have any exhibits that support your

9 testimony?

10 A. Yes. I am sponsoring two exhibits. I am

11 sponsoring Exhibit No. 118, which is the presentation of

12 the Commission Staff's net operating income and rate base

13 calculations. I am also sponsoring Exhibit No. 119,

14 which is a reconciliation between the Company proposed

15 revenue requirement and rate base, and the Staff proposed

16 revenue requirement and rate base.

17 Q. Please explain Exhibit No. 118.

18 A. This exhibit presents the calculation of the

19 Staff recommended revenue requirement. Exhibit No. 118

20 has virtually the same format as Avista's Exhibit No. 11,

21 sponsored by Company witness Falkner. Exhibit No. 118,

22 page 1, Column A shows the actual dollar amounts from the

23 Company `Per Results Reports' and Column B shows the

24 Company Pro Forma Total With Present Rates. The Company

25 includes Idaho state income taxes in the Taxes Other Than

1054

WWP-E-98-11 STOCKTON, K (Di) 3
04/23/99 Staff

1 Income Taxes line, line 14 in the Distribution Expenses.

2 Column C separates out Idaho state income taxes. Column

3 D shows the Company Pro Forma Total With Present Rates

4 with the Idaho state income tax separately stated. This

5 is the starting point for the Commission Staff revenue

6 requirement calculation. Page 1 of Exhibit No. 118 also

7 shows the summary Staff adjustment columns: Commission

8 Staff Total Adjustments (Column L), Commission Staff

9 State and Federal Tax on Adjustments (Column M),

10 Commission Staff Pro Forma at Present Rates (Column N),

11 Commission Staff Increase in Revenues and Related

12 Expenses (Column O), and finally, Commission Staff Pro

13 Forma at Proposed Rates (Column P).

14 Q. Please describe page two of Exhibit No. 118

15 and indicate which Staff member sponsors which

16 adjustments.

17 A. Page 2, Exhibit No. 118 was prepared by me

18 to summarize the Staff adjustments to net operating

19 income and rate base. Workpapers are attached for each

20 of the adjustments. My testimony will address the

21 specifics of the Injuries and Damages adjustment, the

22 Tree Trimming adjustment, and the Miscellaneous General

23 Expenses adjustment. Staff witness Randy Lobb sponsors

24 the Hydro Relicensing adjustment. Staff witness Rick

25 Sterling sponsors the Line Extension adjustment. Staff

1055

WWP-E-98-11 STOCKTON, K (Di) 4
04/23/99 Staff

1 witness Lansing sponsors the Depreciation adjustment and

2 the Total Income Tax adjustments. These adjustments are

3 reflected in Total Staff Adjustments (Column L) on page 1

4 of Exhibit No. 118.

5 Q. Please describe the Company's revenue

6 requirement increase.

7 A. Avista calculates a revenue deficiency

8 totaling $14.223 million (Company Exhibit No. 11).

9 Avista's case is based upon actual costs using an

10 historic test year ending December 31, 1997. Staff

11 agrees with the use of a 1997 test year. The Company

12 filed financial information based on the Results of

13 Operations Reports for Idaho Electric, as adjusted by

14 Company witness Falkner.

15 Q. Would you please enumerate the various

16 adjustments to Results of Operations proposed by Avista?

17 A. The Company adjustments as detailed in

18 Company Exhibit No. 11, by column letter designation are:

19 b. Per Results Report

20 c. Deferred FIT Rate Base

21 d. Deferred Gain on Office Building

22 e. Colstrip 3 AFUDC Elimination

23 f. Colstrip Common AFUDC

24 g. Kettle Falls Disallowance

25 h. Weatherization & DSM Investment

1056

WWP-E-98-11 STOCKTON, K (Di) 5
04/23/99 Staff

1 i. Customer Advances

2 j. Settlement Exchange Power

3 k. Eliminate B & O Taxes

4 l. Property Tax

5 m. Uncollectible Expense

6 n. Regulatory Expense

7 o. Injuries and Damages

8 p. Federal Income Tax

9 q. Idaho PCA

10 Pro Forma Adjustments

11 PF1. Power Supply

12 PF2. Potlatch

13 PF3. Revenue Adjustment

14 PF4. Miscellaneous Adjustments

15 PF5. Labor/benefit Adjustment

16 PF6. Depreciation Adjustment

17 PF7. Hydro Relicensing Adjustment

18 PF8. Debt Interest Adjustment

19 The Company adjustments begin with the

20 Column b Results of Operations Reports. The amounts in

21 the reports are for the twelve months ended December 31,

22 1997. The dollar amounts tie to the Company's general

23 ledger. The Company computes rate base using the average

24 of monthly averages method. Staff accepts this method

25 and agrees with the beginning results of operations.

1057

WWP-E-98-11 STOCKTON, K (Di) 6
04/23/99 Staff

1 Q. Did Staff perform an audit in preparing its

2 case?

3 A. Yes. In assessing the Company's

4 Application, Staff reviewed and audited the Company's

5 books and records.

6 Q. Did you have an opportunity to examine any

7 transactions that Avista had with affiliates?

8 A. Yes. The were very few transactions between

9 Avista and its affiliates. I examined the 1997

10 transactions between the Company and Avista Energy, and

11 found the transactions to be acceptable. The affiliate

12 transactions were both small in dollar amount and very

13 few in number.

14 Q. Does the Commission Staff accept the

15 adjustments and pro forma adjustments of the Company as

16 filed?

17 A. With three exceptions, the Injuries and

18 Damages adjustment, Pro Forma Depreciation adjustment,

19 and the Pro Forma Hydro Relicensing adjustment, Staff

20 accepts the Company-proposed adjustments as filed. Staff

21 also proposes four additional adjustments to the Company

22 Pro Forma Results of Operations.

23 Q. Are you proposing any adjustments to net

24 operating income and rate base?

25 A. Yes. Staff has seven adjustments to net

1058

WWP-E-98-11 STOCKTON, K (Di) 7
04/23/99 Staff

1 operating income and rate base. They are found in

2 Columns E through K on page 2 of Staff Exhibit No. 118.

3 The state and federal income tax on the Staff adjustments

4 are combined in Column L. Column M shows the Total Staff

5 Adjustments, including income taxes.

6 Q. Please explain the Staff adjustment found

7 in Column E, on page 2 of Staff Exhibit No. 118.

8 A. This Staff adjustment is referred to as the

9 Hydro Relicensing adjustment. Staff witness Randy Lobb

10 is sponsoring this adjustment. The Company's Pro Forma

11 Adjustment 7, Column PF7, Company Exhibit No. 11 - Hydro

12 Relicensing adjustment includes in the test year the

13 annual operating expense portions of costs associated

14 with relicensing of certain of the Company's hydro

15 electric facilities on the Clark Fork River. Staff does

16 not accept this adjustment as presented. The Staff

17 adjustment removes certain expenses associated with the

18 hydro relicensing process, and corrects an addition error

19 in the Company filing. This Staff adjustment removes

20 $285,376 in production and transmission expenses from the

21 test year, with a corresponding increase in state income

22 tax expense of $4,191, and an increase in federal income

23 tax expense of $98,415. The increase to net operating

24 income after taxes is $182,770.

25 Q. Please explain the Staff adjustment found in

1059

WWP-E-98-11 STOCKTON, K (Di) 8
04/23/99 Staff

1 Column F, on page 2 of Staff Exhibit No. 118.

2 A. This Staff adjustment is referred to as the

3 Line Extension adjustment. Staff witness Sterling is

4 sponsoring this adjustment. Staff witness Lansing

5 discusses the income tax effects of removing the plant in

6 service, as well as the impact to depreciation,

7 accumulated depreciation, and deferred income taxes. The

8 Line Extension adjustment impacts both the net operating

9 income and the rate base. This Staff adjustment removes

10 $26,435 in distribution depreciation expenses from the

11 test year with a corresponding increase in state income

12 tax expense of $388; and an increase in federal income

13 tax expense of $9,116. The increase to net operating

14 income after taxes is $16,960. This adjustment reduces

15 distribution plant in service, reduces accumulated

16 depreciation, and increases deferred taxes. The

17 cumulative effect on total rate base for this adjustment

18 is to decrease rate base by $639,075.

19 Q. Please explain the Staff adjustment found

20 in Column G, on page 2 of Staff Exhibit No. 118.

21 A. This Staff adjustment is referred to as the

22 Depreciation adjustment. Staff witness Lansing is

23 sponsoring this adjustment. The Company's Pro Forma

24 Adjustment 6, Column PF6, Company Exhibit No. 11 -

25 Depreciation adjustment, includes the effects of new

1060

WWP-E-98-11 STOCKTON, K (Di) 9
04/23/99 Staff

1 depreciation rates as a result of a study performed by

2 Deloitte and Touche, LLP. Staff does not accept this

3 adjustment as presented. The Staff Depreciation

4 adjustment impacts both net operating income and rate

5 base. It removes $440,000 in production and transmission

6 depreciation expenses, and $283,000 in distribution

7 depreciation expenses from the test year. There is a

8 corresponding increase in state income tax expense of

9 $10,618 and an increase in federal income tax expense of

10 $249,334. The net operating income after taxes is

11 $463,048. The rate base is increased by a reduction of

12 accumulated depreciation, and by an increase in deferred

13 income taxes, for an overall increase in rate base of

14 $651,000.

15 Q. Please explain the Staff adjustment found

16 in Column H, on page 2 of Staff Exhibit No. 118.

17 A. This Staff adjustment is referred to as the

18 Total Income Tax adjustment. This adjustment is

19 sponsored by Staff witness Lansing. It increases Idaho

20 state income tax expense by $344,880, and decreases Idaho

21 state income tax expenses through the amortization of

22 investment tax credits of $153,914, for a net increase in

23 state income tax expense of $190,966. This adjustment

24 also decreases federal income tax expense by $173,866.

25 The overall effect of this adjustment is to decrease net

1061

WWP-E-98-11 STOCKTON, K (Di) 10
04/23/99 Staff

1 operating income by $17,100.

2 Q. Please explain the Staff adjustment found in

3 Column I, on page 2 of Staff Exhibit No. 118.

4 A. I am sponsoring this Staff adjustment

5 referred to as the Injuries and Damages adjustment. In

6 the Company's filing, Column o of Company Exhibit No. 11

7 adjusts the administrative and general expenses. This

8 adjustment replaces the current accrual for injuries and

9 damages with a six-year rolling average of injuries and

10 damages payments that are not covered by insurance. As

11 filed, this adjustment increases expenses by $125,260,

12 with tax consequences of a reduction of $2,086 in state

13 income tax expense, and a reduction of $43,100 in federal

14 income tax expense, for an overall decrease in net

15 operating income of $80,044. The Company, subsequent to

16 their filing, gave Staff revised numbers for this

17 adjustment to correct a payment that had been allocated

18 to Idaho Electric when it should have been directly

19 assigned to Washington Electric. This correction removed

20 the allocated portion of the accrual per results, and

21 directly assigned the entire amount to Washington. This

22 revised adjustment has the effect of increasing expenses

23 by $565,162, with the tax consequences being a reduction

24 of Idaho state income tax expense of $9,415, and a

25 reduction of federal income tax expense of $194,511; for

1062

WWP-E-98-11 STOCKTON, K (Di) 11
04/23/99 Staff

1 an overall decrease to net operating income of $361,236.

2 The Company proposes to amortize the amount

3 of injuries and damages expense in excess of insurance

4 payments due to the "Ice Storm of 1996" over a six-year

5 period. The Staff adjustment removes the additional

6 amount of the Company adjustment that is associated with

7 the "Ice Storm of 1996", and reflects the correction from

8 allocated to direct expense. The adjustment removes

9 $67,001 in Administrative and General Operating expenses,

10 with a corresponding increase in state income tax expense

11 of $984, and an increase in federal income tax expense of

12 $23,106. The increase to net operating income after

13 taxes is $42,911. The Staff adjustment reflects the

14 Company's correction (the direct assignment of expenses

15 to Washington Electric) and also reduces the injuries and

16 damages expenses to the six-year rolling average without

17 the expenses from the "Ice Storm of 1996".

18 Q. Why should the expenses from the ice storm

19 be eliminated from the test year?

20 A. The "Ice Storm of 1996" was an

21 extraordinary, non-recurring item, and does not reflect

22 on-going expenses. It is unlikely that a storm of such

23 magnitude will occur in the near future. In the

24 January 28, 1997 publication by Washington Water Power,

25 "Ice Storm '96 Overview: Two Months Later" it states in

1063

WWP-E-98-11 STOCKTON, K (Di) 12
04/23/99 Staff

1 Section 2.1 "Storm Conditions": "Accumulation of

2 freezing rain on above-ground objects to any extent is

3 extremely rare in the Spokane area. The National Weather

4 Service categorized "Ice Storm 96" as the only event of

5 its kind in 115 years of record. No comparable ice storm

6 has occurred since the recording of weather statistics.

7 One major storm has stressed Washington Water Power's

8 system in the last twenty years. The Siberian Express in

9 1989 caused extreme low temperatures and high loads on

10 WWP's generation and transmission lines. Other notable

11 events include volcanic fallout from the Mount St. Helens

12 eruption in 1981 and close to four feet of snow during a

13 several-day period in November 1992. No significant

14 outages occurred at these times."

15 It is appropriate to remove expenses that

16 are non-recurring in nature. The six-year average is

17 already higher than the amount accrued in 1997. Staff

18 accepts the six-year average, sans ice storm expenses, as

19 being reasonable for ratemaking purposes. The ice storm

20 was an extraordinary, non-recurring event. Also, it is

21 an out-of-test year expense. The Company's Pro Forma

22 Power Supply adjustment uses the year of July 1999

23 through 2000, yet the ice storm was in 1996. To avoid

24 distortion of test year expenses, Staff removes $67,001

25 to bring the Injuries and Damages expenses back to the

1064

WWP-E-98-11 STOCKTON, K (Di) 13
04/23/99 Staff

1 six-year average, without including the effects of the

2 1996 ice storm. It is not reasonable for the Idaho

3 electric customers to pay, through future rates, for such

4 an extraordinary, and past event. Moreover, by the time

5 rates can be expected to be in place, the ice storm will

6 be more than two years in the past, and two years of the

7 six-year amortization will already have taken place. It

8 has been over a decade since the last Idaho electric rate

9 case, and if the next rate case is not filed for another

10 decade, then there will be at least six years of over

11 collection of the amortization of the injuries and

12 damages expense due to the ice storm if the amortized

13 amount is built into rates.

14 Q. Please explain the Staff adjustment found

15 in Column J, on page 2 of Staff Exhibit No. 118.

16 A. The Staff adjustment found in Column J,

17 page 2, of Staff Exhibit No. 118 removes the variance

18 from the five-year average for tree trimming costs

19 directly assigned to Idaho. Production Request No. 8

20 supplied the Commission Staff with the actual amounts

21 booked for tree trimming costs for the years 1994 through

22 1998. The amount booked in 1997, the test year, for tree

23 trimming (vegetation management) was $1,709,397. The

24 average of all five years is $1,205,893. The 1997 total

25 tree trimming costs were the highest of the total costs

1065

WWP-E-98-11 STOCKTON, K (Di) 14
04/23/99 Staff

1 supplied for all five years. This adjustment removes the

2 variance from the five-year average from the test year.

3 The amount of $503,504 is removed from the expense

4 account 593, Maintenance of Overhead Lines. This expense

5 adjustment is directly assigned to Idaho. This

6 adjustment reduces distribution expenses and increases

7 net income by $503,504. The tax consequences of the

8 increase in net income result in an increase in state

9 income tax expense of $7,394 and an increase in federal

10 income tax expense of $173,638. The increase to net

11 operating income after taxes is $322,471.

12 Q. Please explain the Staff adjustment found

13 in Column K, on page 2 of Staff Exhibit No. 118.

14 A. This adjustment removes $259,344 in

15 Miscellaneous General Expenses, Account 930, FERC chart

16 of accounts. This account has 12 FERC sub-accounts. They

17 are:

18 Labor:

19 1. Miscellaneous labor not elsewhere provided for.

20 Expenses:

21 2. Industry association dues for company memberships.

22 3. Contributions for conventions and meetings of the

23 industry.

24 4. Research, development, and demonstration expenses

25 not charged to other O & M expense accounts of a

1066

WWP-E-98-11 STOCKTON, K (Di) 15
04/23/99 Staff

1 functional basis.

2 5. Communication service not chargeable to other

3 accounts.

4 6. Trustee, registrar, and transfer agent fees and

5 expenses.

6 7. Stockholders meeting expenses.

7 8. Dividend and other financial notices.

8 9. Printing and mailing dividend checks.

9 10. Directors' fees and expenses.

10 11. Publishing and distributing annual reports to

11 stockholders.

12 12. Public notices of financial, operating and other

13 data required by regulatory statutes, not including,

14 however, notices required in connection with

15 security issues or acquisitions of property.

16 Staff removes 20% of this account at the Idaho

17 electric jurisdictional level to remove expenses that are

18 not beneficial to customers and reflect them as a below-

19 the-line expense. Included in this account are expenses

20 related to corporate image advertising, membership dues,

21 and meals at such functions as the Rotary Club and the

22 Chamber of Commerce. Staff is not implying that these

23 organizations do not provide benefit to the community,

24 rather that they do not provide a direct benefit to the

25 customer and should be recorded as a below-the-line

1067

WWP-E-98-11 STOCKTON, K (Di) 16
04/23/99 Staff

1 expense. These type of activities are similar to

2 lobbying activities, in that it `gets the name out

3 there'. Expenses associated with lobbying activities are

4 below-the-line activities. Efforts that are aimed at

5 enhancing the image of Avista in the community, and

6 efforts to maximize shareholder value, should be below-

7 the-line expenses ultimately borne by the shareholders.

8 This adjustment removes $259,344 of expenses, with an

9 increase in state income tax of $3,809, and an increase

10 in federal income tax of $89,437, for an overall increase

11 in net operating income after taxes of $166,098.

12 Q. Please explain Column L, on page 2 of Staff

13 Exhibit No. 118.

14 A. This adjustment is the income tax expense

15 (cumulative) for all the Staff adjustments. The Idaho

16 state income tax is calculated at the effective tax rate

17 of 1.4686%, and the federal income tax is calculated at

18 35%. Staff witness Lansing discusses the Idaho state

19 effective tax rate calculation and derivation in his

20 testimony.

21 Q. Did you use an effective Idaho income tax

22 rate for inclusion in calculating the gross-up factor for

23 income taxes?

24 A. Yes, I did. Staff witness Lansing

25 calculates the effective tax rate for Idaho state income

1068

WWP-E-98-11 STOCKTON, K (Di) 17
04/23/99 Staff

1 tax. The effective tax rate used in the calculation of

2 the gross-up factor (Exhibit No. 117, item 5), and

3 applied to the Commission Staff adjustments is 1.4686%.

4 The Company uses an effective tax rate of 1.6659%. The

5 gross-up or conversion factor of 0.63652, Exhibit No.

6 117, is also shown on Staff Exhibit No. 118, page 3.

7 Q. What is the purpose of the gross-up factor?

8 A. The gross-up factor calculates what the

9 gross revenue must be in order for the utility to collect

10 and keep its authorized return after paying income taxes.

11 When revenues increase, the amount of uncollectible

12 expense and the amount of the regulatory fees go up in

13 proportionate amounts. Uncollectible expense is the

14 amount of revenues that the Company is not able to

15 collect. This bad debt expense is an offset of revenues.

16 The Commission Staff gross-up factor also includes a

17 calculation for the increase in uncollectible expense and

18 the increase in regulatory fee expenses associated with

19 the increase in revenues.

20 Q. Why is the Commission Staff gross-up factor

21 different from Avista's gross-up factor?

22 A. The Commission Staff uses 0.3705% as the

23 uncollectible factor, 0.2348% as the regulatory fee

24 expense factor, and 35% as the federal income tax

25 percentage, as does the Company. However, the Company

1069

WWP-E-98-11 STOCKTON, K (Di) 18
04/23/99 Staff

1 uses a different effective Idaho income tax rate. That

2 difference in effective Idaho income tax rates creates

3 the difference in the gross-up or conversion factors.

4 Q. Did you reconcile the Staff revenue

5 requirement with that of the Company?

6 A. Yes. Exhibit No. 119, pages one and two,

7 show the difference in each category, and how those

8 differences can be reconciled.

9 Q. The Company recently hired a new Chief

10 Operating Officer at a higher salary than that of the

11 previous CEO, Paul Redmond. Is any of this increased

12 salary in the test year expenses?

13 A. No. The Company hired Mr. T. M. `Tom'

14 Matthews as new chairman and CEO effective July 1, 1998.

15 The test year does not include any of the salary

16 increase.

17 Q. As of January 1, 1999, the Company changed

18 its name from The Washington Water Power Company to

19 Avista Corporation dba Avista Utilities - Washington

20 Water Power Division. Are any of the costs associated

21 with the name change included in the Company's test year?

22 A. No. The Company did not include any of the

23 costs it incurred to change its name in the test year

24 expenses.

25 Q. Does this conclude your testimony?

1070

WWP-E-98-11 STOCKTON, K (Di) 19
04/23/99 Staff

1 A. Yes, it does.

2

3

4

5

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8

9

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11

12

13

14

15

16

17

18

19

20

21

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1071

WWP-E-98-11 STOCKTON, K (Di) 20
04/23/99 Staff

1 (The following proceedings were had in

2 open hearing.)

3 MR. WOODBURY: And I'd present Ms. Stockton

4 for cross-examination.

5 COMMISSIONER SMITH: Mr. Shurtliff, do you

6 have questions for Ms. Stockton?

7 MR. SHURTLIFF: None.

8 COMMISSIONER SMITH: Mr. Ward.

9 MR. WARD: No. Thank you.

10 COMMISSIONER SMITH: Mr. Meyer.

11 MR. MEYER: Just a few. Nice thing about

12 having a break it allows you to eliminate more and more

13 cross.

14

15 CROSS-EXAMINATION

16

17 BY MR. MEYER:

18 Q Okay, really two issues and I won't dwell

19 on either for very long. First is injuries and damages,

20 the Staff is comfortable with a six-year averaging

21 technique, isn't it?

22 A Yeah, pretty comfortable.

23 Q Okay, and in this case, what you're taking

24 exception to is one item consisting of ice storm damages?

25 A That's correct.

1072

CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff

1 Q But you're not testifying that any of those

2 expenditures were otherwise imprudent or unnecessary;

3 correct?

4 A Oh, no.

5 Q Okay. Well if those aren't rolled into a

6 six-year averaging account, if you will, how will the

7 Company ever recover those necessary and prudent

8 expenses?

9 A Well, in a test year, it's not that I

10 object to them being in a six-year average, but their

11 inclusion in the test year presents a very large spike.

12 Q So you do not --

13 A I don't object to them being put in in a

14 six-year average for recovery. What I object to is

15 including them in the test year.

16 Q Okay; so you're in fact not objecting to

17 including ice storm damages in the six-year injuries and

18 damages adjustment; is that your position?

19 A Well, now you've got me confused. If

20 that's the way they're accrued every year for booking

21 purposes, you accrue a six-year average, that's fine and

22 include them that way, that's fine, but when you have a

23 test year, the ice storm is such an extraordinary and

24 non-recurring event that it ought to be removed from the

25 test year expenses.

1073

CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff

1 Q I'm sorry, the confusion may be just mine,

2 but I thought I understood you in your prefiled testimony

3 to recommend that the ice storm damages not be included

4 in the rolling six-year average on injuries and damages.

5 A The reason being because it was a test year

6 for setting rates on a going-forward basis, not that on

7 general day-to-day operations you couldn't put them in a

8 six-year average.

9 Q I'm still struggling a little bit. We have

10 pro formed the test period, haven't we, for an item

11 consisting of injuries and damages; is that correct?

12 A Yes.

13 Q Okay, and in the process of making that

14 single pro forma adjustment, the Company has proposed a

15 six-year average of injuries and damages to get that

16 pro forma adjustment to the test period; is that correct?

17 A Yes.

18 Q Okay, and the Company has proposed in that

19 pro forming adjustment for injuries and damages the

20 inclusion of ice storm costs?

21 A In a six-year rolling average, they would

22 be included anyway and I'd just take them out of the

23 six-year average, the ice storm costs.

24 Q Okay; so you have not included those in

25 your recommended pro forma adjustment for injuries and

1074

CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff

1 damages; is that what you're saying?

2 A Yeah, I guess. Well, yeah.

3 Q Okay, let me try just a different way. If

4 the ice storm costs are not included in the revenue

5 requirement to be established in this proceeding, how

6 will the Company ever recover these necessary and prudent

7 costs?

8 A If there were to be an ice storm like this

9 that occurred in the future after rates were set, I would

10 assume that an extraordinary event like that the Company

11 could come in and ask for rate relief.

12 Q But as to these ice storm costs that

13 apparently are at issue in this case, the costs have

14 already been incurred, if not recovered in this revenue

15 requirement proceeding, how will the Company recover

16 them, if at all?

17 A I don't know.

18 Q In fact, isn't it true that if not here the

19 Company won't recover them at all?

20 A If they're not built into rates, then they

21 wouldn't be recovered by the ratepayers.

22 Q Okay, thank you. Let's move on to just the

23 second area, if we could, in your testimony. Again, I'll

24 be brief. You make an adjustment to Account 930,

25 miscellaneous general expense, don't you?

1075

CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff

1 A Yes.

2 Q And you essentially removed 20 percent of

3 expenses in that account?

4 A Yes.

5 Q Okay, and have you distinguished within --

6 well, first of all, what does Account 930 purport to do?

7 What kind of expenses does it group together?

8 A It's a FERC account, miscellaneous general

9 expenses. It provides for labor expenses that aren't

10 provided for elsewhere, miscellaneous labor, and then on

11 the expense side, there's 11 items, industry association

12 dues for company memberships, contributions for

13 conventions and meetings of the industry. Do you want me

14 to read them all?

15 Q No, that's fine.

16 A It goes on and on.

17 Q Yeah, sure, and so you familiarized

18 yourself at least generally with the type of items

19 covered?

20 A Yes.

21 Q Do you agree that Account 930 by FERC's

22 definition -- and these are FERC accounts?

23 A Yes.

24 Q -- and by FERC's definition includes cost

25 of labor and expenses incurred in connection with the

1076

CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff

1 general management of the utility?

2 A That's FERC's definition, yes.

3 Q And is this account, generally speaking,

4 deemed to be an above-the-line operating account?

5 A I believe so, yes.

6 Q But you've gone into this account and, if I

7 understand your testimony, you've identified perhaps

8 certain areas of expenditure where you have some

9 misgivings about whether ratepayers benefit; is that your

10 testimony?

11 A Yes, in part.

12 Q Okay, but what you've done is to make an

13 adjustment, you've just taken 20 percent of the entire

14 account balance and removed it as an adjustment; is that

15 correct?

16 A Yeah, 20 percent of the entire account

17 balance.

18 Q So essentially one out of every $5.00 for

19 every entry in this account you've disallowed?

20 A I would say one out of every $5.00 would be

21 an expense that doesn't benefit the ratepayers and they

22 therefore shouldn't have to pay that, that perhaps the

23 shareholders could pay that.

24 Q I don't want to belabor this, but would you

25 agree that a substantial or perhaps most of the expenses

1077

CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff

1 reflected in this account concern themselves with

2 shareholder services and capital management issues,

3 financing issues? I'm not asking for any pinpoint

4 estimate, but would you say probably, oh, two-thirds to

5 three-quarters, somewhere in that ball park?

6 A I didn't calculate it that way, but, yeah,

7 there's definitely money in those types of accounts.

8 Q And in about that range of magnitude;

9 right?

10 A At the electric level, it looks like

11 there's about, and this is before it splits

12 Idaho/Washington, about $3.6 million. Of that, I took

13 into question not those financial communications,

14 corporate fees, not those accounts, but there's about

15 1.4 million in four other subaccounts that I was more

16 concerned with what would be charged to those accounts.

17 Q Would you accept, subject to check, that in

18 approximate terms about 70 percent of the expenses in

19 that account concern themselves with shareholder services

20 and capital management investment services, that sort of

21 thing?

22 A Probably.

23 Q Okay, and you do cite in finishing that

24 some of your concerns are prompted, what, by the

25 activities of area managers in their locales?

1078

CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff

1 A I was prompted just by the actual invoices

2 that I did look at.

3 Q And you're not suggesting that all of the

4 costs associated with maintaining area managers and what

5 they do are somehow improper, not a ratepayer expense,

6 are you?

7 A No.

8 Q But that's a primary focus of what concerns

9 you is the activities, some of the activities, of area

10 managers?

11 A Well, yeah, and just based on the invoices

12 that I did look at.

13 Q And again, of this total amount reflected

14 in 930, would you agree, subject to check, again in

15 approximate terms, that perhaps only 15 percent of all

16 dollars in that account relate to the activities of area

17 managers?

18 A That could certainly be true.

19 Q Okay, but in closing, you're not

20 recommending that we simply take 20 percent of that

21 15 percent and disallow, are you?

22 A Is this at the Idaho level or the all

23 electric level?

24 Q Either, actually either.

25 A Some number, I guess.

1079

CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff

1 MR. MEYER: I think that completes my

2 cross. Thank you.

3 COMMISSIONER SMITH: Thank you, Mr. Meyer.

4 Did I already ask you?

5 MR. WARD: If you did, I don't.

6 COMMISSIONER SMITH: Mr. Shurtliff, do you

7 have questions of Ms. Stockton or did I already ask you?

8 MR. SHURTLIFF: You already asked, but I'll

9 change my mind. No, I don't have any questions.

10 COMMISSIONER SMITH: How about the

11 Commissioners?

12 Redirect, Mr. Woodbury?

13 MR. WOODBURY: No redirect.

14 COMMISSIONER SMITH: Okay.

15 (The witness left the stand.)

16 MR. WOODBURY: Staff's next witness would

17 be Marj Maxwell.

18

19

20

21

22

23

24

25

1080

CSB REPORTING STOCKTON (X)
Wilder, Idaho 83676 Staff

1 MARJORIE MAXWELL,

2 produced as a witness at the instance of the Staff,

3 having been first duly sworn, was examined and testified

4 as follows:

5

6 DIRECT EXAMINATION

7

8 BY MR. WOODBURY:

9 Q Ms. Maxwell, please state your full name.

10 A Marjorie Maxwell.

11 Q And for whom do you work and in what

12 capacity?

13 A I work for the Idaho Public Utilities

14 Commission as a utilities compliance investigator.

15 Q And in that capacity, did you have occasion

16 to prefile testimony in this case consisting of 18 pages

17 and Exhibits 120 and 121?

18 A I did.

19 Q And have you had the opportunity to review

20 that prefiled testimony before this hearing?

21 A I did.

22 Q And is it necessary to make any changes or

23 corrections?

24 A It's not.

25 Q And if I were to ask you the questions set

1081

CSB REPORTING MAXWELL (Di)
Wilder, Idaho 83676 Staff

1 forth in your testimony, would your answers be otherwise

2 the same?

3 A They would.

4 MR. WOODBURY: Madam Chair, I'd ask that

5 the testimony be spread on the record and the exhibits

6 identified.

7 COMMISSIONER SMITH: If there's no

8 objection, that is so ordered.

9 (The following prefiled testimony of

10 Ms. Marjorie Maxwell is spread upon the record.)

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

1082

CSB REPORTING MAXWELL (Di)
Wilder, Idaho 83676 Staff

1 Q. Please state your name and business address

2 for the record.

3 A. My name is Marjorie Maxwell. My business

4 address is 472 West Washington Street, Boise, Idaho.

5 Q. By whom are you employed and in what

6 capacity?

7 A. I am employed by the Idaho Public Utilities

8 Commission as a Utilities Compliance Investigator.

9 Q. What is your educational background and

10 relevant employment history?

11 A. I received a Bachelor of Arts Degree in

12 Secondary Education from the College of Idaho [Albertson

13 College of Idaho] in 1980. I have taken continuing

14 education classes and professional courses including the

15 New Mexico State University's Public Utilities Course,

16 October 1992. I have been employed by the Commission

17 since January 1984, and have been in my present position

18 since June 1992.

19 Q. What issues will you discuss in your

20 testimony?

21 A. I will discuss my findings from a review of

22 Avista Corporation dba Avista Utilities - Washington

23 Water Power Division's (Avista; Company) billings,

24 notices, and other forms and address Avista's compliance

25 with the Idaho Public Utilities Commission's (Commission)

1083

WWP-E-98-11 MAXWELL (Di) 1
4/23/99 Staff

1 Utility Customer Relations Rules [UCRR], IDAPA

2 31.21.01000, et seq., and Utility Customer Information

3 Rules [UCIR], IDAPA 31.21.02000, et seq. I will discuss

4 the Company's proposed rate design changes for

5 residential customers, including its request to eliminate

6 the minimum charge, institute a $5.50 basic charge, and

7 collapse the current three-block inverted rate schedule

8 into two blocks. I will summarize the written comments

9 filed with the Commission by customers after Avista

10 announced its request for a rate increase. I will

11 mention the telephone calls generated by the letter to

12 the editor of the Moscow Pullman Daily News telling of

13 Avista's new CEO salary and signing bonus. Additionally,

14 I will offer an assessment of Avista's general customer

15 relations as reflected by consumer complaints filed with

16 the Commission.

17 Q. Are you sponsoring any exhibits?

18 A. I am sponsoring Staff Exhibit Nos. 120 and

19 121.

20 Q. What did you find when you reviewed the

21 Company's bills, disconnection notices, and other

22 information?

23 A. Avista's bills and disconnection notices

24 provide excellent information meeting all Commission

25 requirements. I found two minor problems in my review of

1084

WWP-E-98-11 MAXWELL (Di) 2
4/23/99 Staff

1 Avista's other forms and notices, both of which were

2 promptly remedied by the Company.

3 Q. Did you find any area where the Company did

4 not comply with the Utility Customer Relations Rules?

5 A. I found one area. Avista applies deposit

6 refunds to a customer's account rather than issuing a

7 refund directly to the customer as UCRR 107.02 requires.

8 The Company states it promptly issues a refund when the

9 customer requests one. I discussed the issue of non-

10 compliance with the Company and determined that customers

11 were not being adversely impacted by Avista's practice of

12 crediting refunds to customer accounts. I recommended

13 that Avista request an exemption to UCRR 107.02, which

14 the Company filed March 24, 1999. The Commission

15 approved the Company's request April 20, 1999, thereby

16 removing its compliance problem.

17 Q. Did you question any other policy of the

18 Company?

19 A. Yes, I did. Avista provided its letter of

20 transfer which requested payment for an amount the

21 customer had guaranteed as a deposit for another

22 customer. I asked how the assessed amount is tracked

23 after being applied to the customer's account. UCRR

24 310.03 prohibits disconnection of service to the

25 guarantor if the reason cited for the disconnection is

1085

WWP-E-98-11 MAXWELL (Di) 3
4/23/99 Staff

1 the failure to pay a guaranteed deposit for another

2 customer. The rule does not prohibit the Company's

3 collection attempt when the guaranteed deposit amount is

4 added to the customers account. The Company complies

5 with Rule 310.03 by adding a special obligation code to

6 the amount guaranteed so that it does not become a part

7 of a collectible balance subject to disconnection. This

8 procedure is acceptable.

9 Q. Has the Company complied with Utility

10 Customer Information Rules [UCIR]?

11 A. With one exception, Avista does comply with

12 Utility Customer Information Rules. Avista acknowledges

13 that it has not provided individual customer notice to

14 announce rate adjustments due to the Power Cost

15 Adjustment (PCA) mechanism instituted in 1988. The

16 Company states it has historically provided notice of

17 rate changes due to surcharges and rebates through press

18 releases sent to all local media sources. The Company

19 commits on a going-forward basis to provide individual

20 customer notice for trackers, surcharges and rebates in

21 accordance with UCIR 102.02.

22 In addition to the notice of when a rate

23 adjustment begins, I suggest that a message be added to

24 bills when a 12-month rebate or surcharge ends. Several

25 customers who filed comments in this case were under the

1086

WWP-E-98-11 MAXWELL (Di) 4
4/23/99 Staff

1 mistaken impression that rates had increased as recently

2 as last September 1998, the time at which a rebate ended.

3 Information at the time of any rate change would help

4 customers better understand the reason for, and duration

5 of, an increase or decrease in rates.

6 Q. What is your position regarding Avista's

7 proposal to drop its minimum charge for customers using

8 less than 203 kWh and implement a basic charge?

9 A. Under Avista's existing rates, an $8.50

10 minimum charge applies only to accounts using less than

11 203 kWh in a month. Approximately eight percent of

12 residential accounts are assessed the minimum charge,

13 according to the Company. The proposed "basic charge"

14 will apply to all residential accounts regardless of

15 energy use. All customers will pay equally toward the

16 Company's fixed expenses, particularly the costs of

17 metering, meter reading, and billing.

18 I support recovery of at least a portion of

19 the Company's fixed expense through a basic charge.

20 However, customers typically object to a charge that

21 includes no commodity and has no perceived value.

22 Utilities that have had a fixed, basic, or customer

23 charge in place for a number of years continue to receive

24 complaints about it. Customers object to being asked to

25 pay to be a customer, especially when they have no choice

1087

WWP-E-98-11 MAXWELL (Di) 5
4/23/99 Staff

1 of providers. Customers accustomed to seeing all costs

2 included in the energy rate often see the charge as a

3 source of additional revenue for the Company.

4 Q. Do you have a recommendation to help offset

5 the likely objections to a basic charge?

6 A. I recommend that the Company provide

7 customers an explanation of its rate design changes

8 through a billing stuffer. This explanation should be

9 easily understood and emphasize that the basic charge is

10 a part of the total revenue needed, as determined in this

11 rate case, and is not in addition to it. I am willing to

12 work with the utility in developing the language.

13 Given the on-going discussions of possible

14 electric utility restructuring, I hope the consumer today

15 has a better understanding that certain costs associated

16 with the meter, meter reading and billing will be

17 identified separately from costs associated with the

18 production and delivery of energy.

19 Q. What is your position regarding the $5.50

20 basic charge proposed by the Company in this rate case?

21 A. The proposed $5.50 basic charge falls within

22 the range of fixed charges previously authorized by this

23 Commission for other utilities, and it is considerably

24 less than the amount Avista's cost of service study

25 supports, i.e., $13.04 for residential class.

1088

WWP-E-98-11 MAXWELL (Di) 6
4/23/99 Staff

1 However, as the Company recognizes cost of

2 service should not be a sole determinant in rate design.

3 There exist legitimate reasons for the Commission in this

4 case to set the basic charge at $4.00.

5 Q. What justification is there for establishing

6 a $4.00 basic charge?

7 A. While $4.00 allows the Company to introduce

8 residential customers to a new type of charge and recover

9 a reasonable portion of its costs through a fixed fee,

10 $4.00 reduces the high percentage increase on low

11 consumption customers that a $5.50 basic charge places.

12 A $4.00 charge is also consistent with other basic

13 charges found in Avista's tariffs.

14 Avista's MOPS II experimental two-year

15 program which began July 1, 1998 and ends June 30, 2000,

16 set its basic charge at $4.00 for small commercial

17 customers, Schedule 11 and 12, and sets a basic charge of

18 $4.30 for residential customers, Schedule 1.

19 Additionally the Commission determined that

20 $4.00 was a reasonable charge for seasonal customers who

21 opted to close an account and use no electricity during a

22 billing cycle (Case No. WWP-E-97-2, Order No. 27376). In

23 this rate case, I note that the Company did not propose a

24 change to the $4.00 per month optional seasonal charge.

25 Q. Is there another supporting argument for a

1089

WWP-E-98-11 MAXWELL (Di) 7
4/23/99 Staff

1 $4.00 basic charge?

2 A. Yes. In response to Idaho State Legislature

3 House Bill No. 399, which required cost information to be

4 separated among the utility functions, the Commission

5 requested utilities to provide unbundling information.

6 In its response, Avista identified its costs for

7 metering, meter reading and billing for small customers.

8 Staff engineer Keith Hessing using information provided

9 by Avista, calculated the following costs:

10 Metering .41 cents per customer per month
Meter Reading .81 cents per customer per month
11 Billing $2.65 per customer per month
Total $3.87 per month per customer
12

13 Q. Please explain what an inverted block rate

14 means.

15 A. An inverted block rate is one in which each

16 succeeding block of kilowatt hours is priced higher than

17 the preceding block.

18 Q. Do you support Avista's proposal to collapse

19 its current three block inverted rate into two?

20 A. Yes. Staff witness Keith Hessing will also

21 discuss specific recommendations regarding Avista's rate

22 design. I offer the following comments. I reviewed the

23 Company's proposal and find its logic to be sound.

24 However, it must be recognized that any change in a rate

25 design necessarily creates winners and losers.

1090

WWP-E-98-11 MAXWELL (Di) 8
4/23/99 Staff

1 The historical reason for implementing an

2 inverted rate block was to send a price signal to

3 customers that reflected the higher incremental cost of

4 building new generating resources, as well as to send a

5 price signal encouraging conservation. Because Idaho

6 utilities are not constructing new plants to serve native

7 load and because the higher energy block no longer

8 represents the incremental cost of energy, Staff supports

9 Avista's proposal. The Company's two-block inverted rate

10 will encourage conservation in a more muted fashion.

11 Q. Have you considered the impact of the new

12 rate design on the low income customer?

13 A. Yes. A substantial increase in rates will

14 be difficult, especially for low income customers.

15 Under the Company's proposed rate design,

16 customers whose main heat source is electricity will

17 experience a smaller percentage increase than will low

18 use residential customers. Staff witness Keith Hessing's

19 Exhibit No. 128 demonstrates the resulting percentage

20 increase and dollar increase for each level of

21 consumption as a result of the implementation of a basic

22 charge, whether it be $4.00, $4.50, $5.00, or $5.50.

23 The third block rate began at 1300 kWh and

24 is eliminated in the Company's proposal; usage over 1300

25 kWh now falls in the second block and will temper a high

1091

WWP-E-98-11 MAXWELL (Di) 9
4/23/99 Staff

1 dollar increase for that customer. Customers with

2 electricity as their primary heat source typically use

3 more than 1300 kWh during the winter months. Average

4 winter usage during the test year of 1997 for low income

5 customers with electric heat was 1968 kWh for January,

6 1732 kWh for February, 1554 kWh for March, and 1802 kWh

7 for December. A low income customer would pay a total of

8 $377 during the winter heating season at the above

9 consumption levels under Staff's proposed rates using a

10 $4.00 basic charge.

11 Q. Do you know how many customers Avista

12 considers low income?

13 A. The Company's testimony and documentation

14 shows that 11,100 of its Idaho customers are in

15 households whose annual income falls below $15,000. The

16 number of those customers whose primary heat source is

17 electricity is 5,198. Of those, 3,500 customers received

18 energy assistance during 1998.

19 Low Income Energy Assistance Program

20 guidelines set the poverty level for a family of four at

21 $21,876, and a family of two at $14,436. I cannot

22 determine the number of households whose annual income is

23 above $15,000 and yet may be below the poverty level,

24 according to LIEAP guidelines.

25 Depending upon the actual family

1092

WWP-E-98-11 MAXWELL (Di) 10
4/23/99 Staff

1 composition, and income, an Avista customer could qualify

2 for a LIEAP benefit ranging from $212 to $395 to be

3 applied towards the winter heating bill.

4 Q. Is it likely that energy assistance benefits

5 will increase to help offset the additional costs for

6 electricity due to an increase in electric rates?

7 A. I contacted the Low Income Energy Assistance

8 Program (LIEAP) grants officer at the Department of

9 Health & Welfare (H&W) to determine if energy assistance

10 benefits will automatically increase in relation to an

11 increase in electric rates. The grants officer said that

12 an increase in benefits is not automatic nor is it

13 necessarily a reasonable expectation. Until H&W learns

14 the amount of federal dollars available for next year's

15 heating season, next year's benefit amount cannot be

16 established. H&W will not know until summers end the

17 amount of federal dollars available. The benefit amount

18 is dependent on decisions and dollars coming from the

19 federal government next Fall.

20 Q. Do you have any comment regarding the

21 change in rates for customers from Sandpoint, Clark Fork,

22 Hope, East Hope, Oldtown, and Priest River?

23 A. Yes. In 1995, when Avista (then known as

24 Washington Water Power Company) bought Pacific Power and

25 Light Company's service territory, rates were not

1093

WWP-E-98-11 MAXWELL (Di) 11
4/23/99 Staff

1 immediately lowered to Avista's existing rates. Instead,

2 transition rates, which were slightly less than Pacific

3 Power & Lights rates, but more than Avista's were put

4 into effect for a transition period of four years. At

5 the end of the four years, all customers of similar

6 classes were to be placed on Avista's (WWP) comparable

7 rate schedules. This four-year rate transition period

8 ended January 1999 and rates were lowered, as promised,

9 to the appropriate rate schedule. Had Avista's proposed

10 rate increase been in effect January 1, 1999, those

11 customers would have seen a slight net decrease and

12 likely would have been pleased with the new rate. Having

13 received a rate reduction in January 1999, I expect that

14 even if the net result is lower than their rate prior to

15 January, these same customers will be less happy with any

16 rate increase granted as a result of this case. Even so,

17 these customers financially benefitted during the 1999

18 winter heating season because the higher rates were not

19 in effect.

20 Q. Did you find evidence or cause for concern

21 regarding the reliability of Avista's distribution

22 system?

23 A. With the possibility of a future

24 restructured electric industry, there is a general

25 concern about the integrity and reliability of utility

1094

WWP-E-98-11 MAXWELL (Di) 12
4/23/99 Staff

1 systems. Staff has no specific information to indicate

2 that Avista has a system reliability problem. Avista did

3 provide me with its Vegetation Management Schedule which

4 indicates the Company continues to trim trees and remove

5 vegetation on a regular basis. If the Commission wishes

6 to set reliability standards or have the utilities supply

7 certain information on its construction, maintenance and

8 operation practices, I recommend that such standards

9 and/or required information be determined outside this

10 rate case and be applied to all Idaho electric utilities.

11 Q. You've read the written comments submitted

12 by customers after they learned of Avista's proposed rate

13 increase. What concerns are evident as expressed by

14 customers?

15 A. The fact that more than 200 customers

16 submitted written comments to the Commission protesting

17 the rate increase, or some aspect of it, shows

18 significant consumer concern. Nearly all customers who

19 submitted comments expressed a concern about the large

20 proposed increase and its impact on customers. There is

21 also a perception that the rate request was prompted by

22 costs associated with Avista's name change or Avista's

23 "purchase" of Washington Water Power. (Some customers

24 are not aware that WWP changed its name to Avista, and

25 that no purchase or merger was involved.) Even customers

1095

WWP-E-98-11 MAXWELL (Di) 13
4/23/99 Staff

1 who acknowledge the Company may be entitled to some

2 increase in rates oppose the implementation of a large

3 increase all at once. Many said they are attempting to

4 get by on limited and/or fixed incomes. Customers often

5 compared Avista's request for an 11% overall increase to

6 the customers 1999 Social Security benefit increase of

7 1.3%, or a salary increase of less than 3%. Others claim

8 that because northern Idaho is a depressed area not

9 enjoying the economic financial gains that other parts of

10 the country are seeing, consumers simply cannot afford an

11 additional increase for a necessity.

12 I did find it significant that very few of

13 the more than 200 letters mention a specific problem that

14 the customer had experienced in his or her interaction

15 with the Company. Generally, when customers write

16 letters they use the opportunity to point out a prior

17 problem they experienced with the utility as additional

18 support for why the Company should not be granted a rate

19 increase. I interpret this lack of complaints in

20 Avista's case as an indicator of good customer relations.

21 A more detailed description of customer

22 comments, under broad categories, is found in Exhibit

23 No. 120.

24 Q. How would you respond to those who submitted

25 comments?

1096

WWP-E-98-11 MAXWELL (Di) 14
4/23/99 Staff

1 A. I understand why customers perceive that the

2 request for a rate increase is directly related to the

3 Company's name change because both occurred at

4 approximately the same point in time. The request for an

5 increase in rates was filed December 18, 1998 and the

6 Company announced its name change January 1, 1999. With

7 the benefit of hindsight, the Company could have made a

8 better timing decision to announce its name change.

9 However, this rate increase request is based on a 1997

10 test year and does not include costs associated with

11 Avista's name change.

12 Q. Did Paul N. Valanoff's letter to the editor

13 of the Moscow Pullman Daily News, discussing the signing

14 bonus and the salary of Avista's new CEO, generate much

15 response?

16 A. Indeed it did. Thirty calls objecting to

17 the rate increase came to the Commission from April 15,

18 1999 to April 21, 1999. In general, callers objected to

19 a rate increase for a utility that can give its CEO a

20 signing bonus and a $750,000 salary. Consumer Staff

21 advised callers that the costs associated with these two

22 issues are not a part of this rate increase request.

23 Q. How have others rated Avista's performance

24 with respect to its customer relations?

25 A. The Company provided a list of studies by

1097

WWP-E-98-11 MAXWELL (Di) 15
4/23/99 Staff

1 independent entities ranking the Company toward the top

2 of the industry in management efficiency and innovations.

3 Theodore Barry and Associates ranked the Company first in

4 overall customer service performance based on its having

5 the lowest annual customer service expense while

6 receiving one of the highest customer satisfaction

7 ratings in the survey group. After the Company filed its

8 rate case, Avista's Call Center was awarded the "Call

9 Center of the Year" award by Call Center Magazine, a

10 respected and nationally recognized magazine.

11 Q. What is your assessment regarding Avista's

12 customer relations?

13 A. Based on my personal experience working with

14 Avista in resolving consumer complaints and my analysis

15 of complaints from Avista's customers filed with this

16 Commission over the past few years, customer relations

17 appear to be good. As identified in its testimony, the

18 Company has a number of helpful programs in place for its

19 customers, including multiple payment options. Its

20 Customer Assistance Referral and Evaluation Service,

21 (CARES) program is especially helpful to customers in

22 crisis.

23 The Company's commitment to customer service

24 is reflected in the low number of complaints the

25 Commission receives. According to our records, since

1098

WWP-E-98-11 MAXWELL (Di) 16
4/23/99 Staff

1 1995 complaints have slightly decreased each year (see

2 Exhibit No. 121). The decrease is more significant when

3 one considers that the number of customers increased each

4 year.

5 Exhibit No. 121 also provides a comparison

6 based on complaints per thousand customers for Avista,

7 Idaho Power and Utah Power over the past four years. The

8 same comparison is made based on all consumer contacts

9 with the Commission regarding these three companies.

10 Avista's performance compares favorably with

11 that of the two other major electric utilities serving

12 Idaho.

13 I agree with the Company when it claims that

14 most of the Commission complaints concern the customer's

15 inability to pay. However, the Company appears to be

16 even-handed in its attempts to collect amounts owed to

17 it. Avista's complaints do not point to any one specific

18 category or area of concern outside customers seeking

19 additional assistance with a payment arrangement or a

20 delay in a disconnection date.

21 Effective February 15, 1999, the Company

22 discontinued accepting cash payments and closed certain

23 local offices. Additional pay stations, often open

24 during extended hours, were arranged. The Company is

25 educating its customers about other bill paying options

1099

WWP-E-98-11 MAXWELL (Di) 17
4/23/99 Staff

1 as well, including U.S. Mail, automatic payment

2 deductions from checking accounts, or payment over the

3 Internet.

4 My general assessment is that Avista's

5 customer relations are very good to excellent. With the

6 recent Avista local office closures, Staff will monitor

7 to insure that this good trend is not reversed.

8 Q. Does this conclude your direct testimony in

9 this proceeding?

10 A. Yes, it does.

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

1100

WWP-E-98-11 MAXWELL (Di) 18
4/23/99 Staff

1 (The following proceedings were had in

2 open hearing.)

3 MR. WOODBURY: And I'd present Ms. Maxwell

4 for cross-examination at this time.

5 COMMISSIONER SMITH: Mr. Shurtliff.

6 MR. SHURTLIFF: None.

7 COMMISSIONER SMITH: Mr. Ward.

8 MR. WARD: Oh, I should ask one or two for

9 old times' sake, but no.

10 THE WITNESS: Thank you.

11 COMMISSIONER SMITH: Mr. Meyer.

12 MR. MEYER: Just a few.

13

14 CROSS-EXAMINATION

15

16 BY MR. MEYER:

17 Q I'm not sure why I do this with

18 trepidation, just a few. Basic charge is an issue, the

19 Staff position is a $4.00 basic charge?

20 A That's correct.

21 Q The Company position is a $5.50 basic

22 charge?

23 A That's correct.

24 Q And the primary difference that explains

25 away $4.00 versus $5.50 is whether or not one also

1101

CSB REPORTING MAXWELL (X)
Wilder, Idaho 83676 Staff

1 includes the cost of the service line; is that correct?

2 A I would disagree with that. The service

3 line was not excluded. It wasn't specifically looked at

4 when we were making our recommendations, but had we

5 intentionally excluded it, we would have recommended

6 somewhat less than $3.85.

7 Q Does your $4.00 minimum charge include the

8 following, basic charge include the following: meters;

9 secondly, meter reading; thirdly, billing?

10 A Those were the specific items that we

11 looked at just because historically those three items

12 have gone in to make up a basic or a customer charge.

13 Q Have you then taken the fourth and final

14 step of also capturing the cost of the service line in

15 your $4.00 figure?

16 A We never alleged that $4.00 recovered all

17 of the Company's fixed costs, just that this would allow

18 the Company to introduce this charge and recover a

19 reasonable portion of fixed costs.

20 Q In fact, you don't disagree with the

21 Company's cost allocation, do you, that shows a basic

22 charge in excess of $13.00 would be justified?

23 A It's clear that the Company made a good

24 case for that $13.04.

25 Q So really, what you're introducing into the

1102

CSB REPORTING MAXWELL (X)
Wilder, Idaho 83676 Staff

1 discussion are concerns other than strictly costing

2 concerns?

3 A Just because of the major change in rate

4 design will affect customers.

5 MR. MEYER: Thank you.

6 COMMISSIONER SMITH: Do we have questions

7 from the Commissioners?

8 I just had one.

9

10 EXAMINATION

11

12 BY COMMISSIONER SMITH:

13 Q When you agreed with Mr. Meyer that the

14 Staff had concerns other than strictly cost for making a

15 recommended rate, is it your impression that the

16 Commission nearly always has concerns other than cost

17 when it considers which rates are appropriate?

18 A That's my sense, I mean, how rates are

19 going to impact individual consumers at all levels.

20 COMMISSIONER SMITH: Thank you.

21 Do you have redirect, Mr. Woodbury?

22 MR. WOODBURY: No, I don't.

23 COMMISSIONER SMITH: Thank you for your

24 help.

25 (The witness left the stand.)

1103

CSB REPORTING MAXWELL (Com)
Wilder, Idaho 83676 Staff

1 MR. WOODBURY: Staff's next witness is

2 Terri Carlock.

3

4 TERRI CARLOCK,

5 produced as a witness at the instance of the Staff,

6 having been first duly sworn, was examined and testified

7 as follows:

8

9 DIRECT EXAMINATION

10

11 BY MR. WOODBURY:

12 Q Ms. Carlock, please state your full name.

13 A Terri Carlock.

14 Q And for whom do you work and in what

15 capacity?

16 A The Idaho Public Utilities Commission as

17 the accounting section supervisor.

18 Q And in that capacity, did you have occasion

19 to prepare and prefile testimony in this case consisting

20 of 25 pages and Exhibit 122?

21 A I did.

22 Q And is it necessary to make any changes or

23 corrections to that testimony?

24 A It is not.

25 Q If I were to ask you the questions set

1104

CSB REPORTING CARLOCK (Di)
Wilder, Idaho 83676 Staff

1 forth in your testimony, would your answers otherwise be

2 the same?

3 A Yes, they would.

4 MR. WOODBURY: Madam Chair, I'd ask that

5 the testimony be spread on the record and the exhibit be

6 identified.

7 COMMISSIONER SMITH: If there's no

8 objection, that is so ordered.

9 (The following prefiled testimony of

10 Ms. Terri Carlock is spread upon the record.)

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

1105

CSB REPORTING CARLOCK (Di)
Wilder, Idaho 83676 Staff

1 Q. Please state your name and address for the

2 record.

3 A. My name is Terri Carlock. My business

4 address is 472 West Washington Street, Boise, Idaho.

5 Q. By whom are you employed and in what

6 capacity?

7 A. I am employed by the Idaho Public Utilities

8 Commission as the Accounting Section Supervisor.

9 Q. Please outline your educational background

10 and experience.

11 A. I graduated from Boise State University in

12 May 1980, with a B.B.A. Degree in Accounting and in

13 Finance. I have attended the annual regulatory studies

14 program sponsored by the National Association of

15 Regulatory Utility Commissioners (NARUC) at Michigan

16 State University. I chaired the NARUC Staff Subcommittee

17 on Economics and Finance for over 3 years. Under this

18 subcommittee, I also chaired the Ad Hoc Committee on

19 Diversification. I have also attended various finance

20 conferences, including the Public Utilities

21 Finance/Advance Regulation Course at the University of

22 Texas at Dallas, National Society of Rate of Return

23 Analysts' Financial Forums, Regulatory Economics and Cost

24 of Capital Conference, and Standard & Poor's Corporation

25 Telecommunications Ratings Seminar. Since joining the

1106

WWP-E-98-11 CARLOCK (Di) 1
4/23/99 Staff

1 Commission Staff in May 1980, I have participated in

2 several audits, performed financial analysis on various

3 companies and have presented testimony before this

4 Commission on numerous occasions.

5 Q. What is the purpose of your testimony in

6 this proceeding?

7 A. The purpose of my testimony is to present

8 Staff's recommendation related to the overall cost of

9 capital for Avista Corporation dba Avista Utilities -

10 Washington Water Power Division, (Avista) to be used in

11 the revenue requirement in this case, WWP-E-98-11. I

12 will address the appropriate capital structure, cost

13 rates and the overall rate of return. I will also

14 address the recommended equity adder.

15 Q. Please summarize your recommendations.

16 A. I am recommending a return on common equity

17 in the range of 10.25% - 11.25% with a point estimate of

18 11.0%. The recommended overall weighted cost of capital

19 is i n the range of 8.792% - 9.166% with a point estimate

20 of 9.073% to be applied to the rate base for the test

21 year. The point estimate includes an adder above the

22 midpoint.

23 Q. Are you sponsoring any exhibits to

24 accompany your testimony?

25 A. Yes, I am sponsoring Exhibit No. 122

1107

WWP-E-98-11 CARLOCK (Di) 2
4/23/99 Staff

1 consisting of 14 schedules.

2 COST OF CAPITAL

3 Q. What legal standards have been established

4 for determining a fair and reasonable rate of return?

5 A. The legal test of a fair rate of return for

6 a utility company was established in the Bluefield Water

7 Works decision of the United States Supreme Court and is

8 repeated specifically in Hope Natural Gas.

9 In Bluefield Water Works and Improvement Co.

10 v. West Virginia Public Service Commission, 262 U. S.

11 679, 692, 43 S.Ct. 675, 67 L.Ed. 1176 (1923), the Supreme

12 Court stated:

13 A public utility is entitled to such
rates as will permit it to earn a return
14 on the value of the property which it
employs for the convenience of the public
15 equal to that generally being made at the
same time and in the same general part of
16 the country on investments in other
business undertakings which are attended
17 by corresponding risks and uncertainties;
but it has no constitutional right to
18 profits such as are realized or
anticipated in highly profitable
19 enterprises or speculative ventures. The
return should be reasonably sufficient to
20 assure confidence in the financial
soundness of the utility and should be
21 adequate, under efficient and economical
management, to maintain and support its
22 credit and enable it to raise the money
necessary for the proper discharge of its
23 public duties. A rate of return may be
reasonable at one time and become too
24 high or too low by changes affecting
opportunities for investment, the money
25 market and business conditions generally.

1108

WWP-E-98-11 CARLOCK (Di) 3
4/23/99 Staff

1 The Court stated in FPC v. Hope Natural Gas Company, 320

2 U. S. 591, 603, 64 S.Ct. 281, 88 L.Ed. 333 (1944):

3 From the investor or company point of
view it is important that there be enough
4 revenue not only for operating expenses
but also for the capital costs of the
5 business. These include service on the
debt and dividends on the stock.
6
... By that standard the return to the
7 equity owner should be commensurate with
returns on investments in other
8 enterprises having corresponding risks.
That return, moreover, should be
9 sufficient to assure confidence in the
financial integrity of the enterprise, so
10 as to maintain its credit and to attract
capital. (Citations omitted.)
11

12 As a result of these Supreme Court

13 decisions, three standards have evolved for determining a

14 fair and reasonable rate of return: (1) the Financial

15 Integrity or Credit Maintenance Standard; (2) the Capital

16 Attraction Standard, and (3) the Comparable Earnings

17 Standard. If the Comparable Earnings Standard is met,

18 the Financial Integrity or Credit Maintenance Standard

19 and the Capital Attraction Standard will also be met, as

20 they are an integral part of the Comparable Earnings

21 Standard.

22 Q. Have you considered these standards in your

23 recommendation?

24 A. Yes. These criteria have been seriously

25 considered in the analysis upon which my recommendations

1109

WWP-E-98-11 CARLOCK (Di) 4
4/23/99 Staff

1 are based. It is also important to recognize that the

2 fair rate of return that allows the utility company to

3 maintain its financial integrity and to attract capital

4 is established assuming efficient and economic

5 management, as specified by the Supreme Court in

6 Bluefield Water Works.

7 Q. What approach have you used to determine

8 the cost of equity for Avista specifically?

9 A. I have presented two methods: the Discounted

10 Cash Flow (DCF) method and the Comparable Earnings method

11 for industrial companies and utilities.

12 Q. Please explain the Comparable Earnings

13 method and how the cost of equity is determined using

14 this approach.

15 A. The Comparable Earnings method for

16 determining the cost of equity is based upon the premise

17 that a given investment should earn its opportunity

18 costs. In competitive markets, if the return earned by a

19 firm is not equal to the return being earned on other

20 investments of similar risk, the flow of funds will be

21 toward those investments earning the higher returns.

22 Therefore, for a utility to be competitive in the

23 financial markets, it should be allowed to earn a return

24 on equity equal to the average return earned by other

25 firms of similar risk. The Comparable Earnings approach

1110

WWP-E-98-11 CARLOCK (Di) 5
4/23/99 Staff

1 is supported by the Bluefield Water Works and Hope

2 Natural Gas decisions as a basis for determining those

3 average returns.

4 I have analyzed the returns for utilities

5 and industrial companies in order to determine a fair

6 return for Avista. When determining the comparable

7 earnings rate, it is important that a cross-section of

8 various companies and industries be utilized in the

9 sample so that any possible effects of unusual

10 occurrences or monopoly powers are limited. It is also

11 important that any risk differentials between the

12 comparable earnings sample and Avista be resolved.

13 In my comparable earnings analysis, the

14 rates of return on common equity historically earned by

15 industrial firms were examined. The historical returns

16 earned by electric and gas utilities were also studied.

17 Then, based upon current economic conditions, the current

18 cost of equity capital for industrial firms on the

19 average was estimated. Taking into consideration the

20 risk differentials between industrial companies and

21 utilities and those differentials as they specifically

22 relate to Avista, I estimated the current cost of equity

23 range utilizing the Comparable Earnings approach.

24 Q. Please explain your schedules reflecting the

25 historical rate of return earned for industrial firms.

1111

WWP-E-98-11 CARLOCK (Di) 6
4/23/99 Staff

1 A. Schedules 1 through 4 of Exhibit No. 122

2 show the returns on common equity for the Business Week

3 Corporate Scoreboard over the last 11 years. Schedule 1

4 reflects the returns earned for periods ending the First

5 Quarter of each year; Schedule 2 reflects the returns for

6 periods ending the Second Quarter; Schedule 3 reflects

7 the returns for periods ending the Third Quarter; and

8 Schedule 4 reflects the returns for periods ending the

9 Fourth Quarter of each year.

10 Industrial returns tend to fluctuate with

11 business cycles, increasing as the economy improves and

12 decreasing as the economy declines. I have utilized a

13 three-year moving average to smooth the business cycle

14 effects and yearly fluctuations in the industrial rate of

15 return. Utility returns are not as sensitive to

16 fluctuations in the business cycle because the demand for

17 utility services generally tends to be more stable and

18 predictable.

19 For years ending the First Quarter

20 (Schedule 1 of Exhibit No. 122), the five-year average

21 return from 1994 through 1998 was 16.0%. The three-year

22 average from 1996 through 1998 was 16.8%, the same as the

23 all industry composite in 1998 and similar to the 1997

24 three-year moving average. The five-year moving average

25 for 1997 of 14.9% is substantially less than the

1112

WWP-E-98-11 CARLOCK (Di) 7
4/23/99 Staff

1 five-year moving average of 16.0% in 1998.

2 For years ending the Second Quarter

3 (Schedule 2 of Exhibit No. 122), the five-year average of

4 16.0% for 1998 is greater than the five-year average of

5 15.0% for 1997. The three-year moving average decreases

6 from 16.7% in 1997 to 16.4% in 1998.

7 For years ending the Third Quarter

8 (Schedule 3 of Exhibit No. 122), the five-year average

9 from 1994 through 1998 was 15.9%, increasing from 15.3%

10 in 1997. The three-year moving average from 1996 through

11 1998 was 16.1%, reflecting a decrease from 16.6% in 1997.

12 The all industry average of 15.5% is lower than the

13 three-year moving averages reflecting somewhat slower

14 conditions in 1998 than in 1995 through 1997.

15 For years ending the Fourth Quarter

16 (Schedule 4 of Exhibit No. 122), the five-year average

17 and the three-year average returns are 16.2% for 1998.

18 This is a slight decrease from the three-year average of

19 16.5% in 1997. The all industry average of 15.3% is

20 lower than the five-year average and again lower than the

21 three-year moving averages.

22 Schedule 5 of Exhibit No. 122 depicts the

23 returns for the years ending each quarter from 1988

24 through the 1998 for the Corporate Scoreboard composite

25 return, the three-year moving average industrial return

1113

WWP-E-98-11 CARLOCK (Di) 8
4/23/99 Staff

1 and the utilities return as reflected in Schedules 1

2 through 4. This graph shows the increase and decrease of

3 industrial returns through good and slower economic times

4 of business cycles.

5 Q. What is your estimate of the current and

6 near-future equity returns for industrial companies?

7 A. Based upon the three-year moving average

8 trend in industrial earnings and actual earnings since

9 1995 (Schedules 1 through 5, Exhibit No. 122) along with

10 current economic conditions, I believe industrial returns

11 will decrease through 2000.

12 The 1998 inflation rate is 1.6% for the

13 consumer price index and -.1% for the producer price

14 index. The change in the inflation rate can be seen by

15 looking at the consumer and producer price indexes as

16 shown in Schedule 6 of Exhibit No. 122. The change in

17 bond rates is illustrated in Schedule 7 of Exhibit No.

18 122, Moody's Average for Public Utility Bond Yields. The

19 yields are shown for "Aa", "A" and "Baa" bonds from 1977

20 through January 1999. Prime interest rates as shown in

21 Schedule 8 of Exhibit No. 122 decreased from 9.0% in 1995

22 to 7.75%, effective 11/17/98, where they currently

23 remain.

24 The Dow Jones Industrial Average Index

25 (DJIA) has fluctuated widely since the 1982 low of 776.92

1114

WWP-E-98-11 CARLOCK (Di) 9
4/23/99 Staff

1 on August 12, but the long-run rising trend has

2 continued. The DJIA closed at a record high of 10,581.42

3 on April 21, 1999. The DJIA was between 7500 and 8200

4 August 27 through October 15, 1998. The Dow Jones

5 Utility Average (DJUA) reached a high of 320 on October

6 8, 1998 and closed at 302.35 on April 21, 1999.

7 I made a review of the actual earned returns

8 on equity for industrial companies, the decline and start

9 of improvement in the economy, changing inflation

10 and stock market conditions. Based upon these

11 considerations my estimate of the near future earned

12 equity capital returns for industrial companies is in the

13 range of 15.0% - 16.0%. The Value Line Data Base of 1798

14 stocks as of March 3, 1999 reflects the following

15 statistics: Percent Earned Common Equity 15.52%, Total

16 Return 3-year 12.21%, Total Return 5-year 12.30%,

17 Dividend Yield 2.36%, Dividend Growth 5-year 6.75% and

18 Projected Dividend Growth 8.12%.

19 Q. How does the trend in utility returns

20 compare with the trend in industrial returns?

21 A. Schedule 9 of Exhibit No. 122 shows the

22 returns for the Moody's Electric Utilities since 1970.

23 The returns in individual years may increase or decrease

24 from the prior year, but the three-year moving averages

25 show general movements in earned returns. The three-year

1115

WWP-E-98-11 CARLOCK (Di) 10
4/23/99 Staff

1 moving average return was 12.0% for 1996, the highest

2 since 1987. In 1998 the 8.8% three-year moving average

3 return is the lowest for any period shown on this

4 schedule. The area of 10.7% and 10.9% reflects the mode

5 range of earned return.

6 The return on common equity for the Moody's

7 Gas Distribution Companies is shown in Schedule 10 of

8 Exhibit No. 122. The three-year average return in 1998

9 is 12.8%. The annual returns and the three-year average

10 returns for the gas utilities reflect decreases since

11 1996.

12 A review of electric and gas utility returns

13 provides a record of actual utility returns earned in the

14 past. The required return for electric utilities, and

15 Avista specifically, can then be estimated by reviewing

16 current market changes and considering any risk

17 differentials between the different types of utilities.

18 Q. Please explain the risk differentials

19 between industrial companies and utilities.

20 A. Risk is a degree of uncertainty relative to

21 a company. The lower risk level associated with

22 utilities is attributable to many factors even though the

23 difference is not as great as it used to be. The

24 competitive risks for gas and electric utilities have

25 changed with the increase in non-utility generation and

1116

WWP-E-98-11 CARLOCK (Di) 11
4/23/99 Staff

1 open transmission access.

2 Competitive risks are less for Avista than

3 for most other electric companies primarily because of

4 the low cost source of power and the low retail rates.

5 The investment risk for Avista is less than the level

6 reflected before the Power Cost Adjustment mechanism

7 (PCA) was implemented. The risk differential between

8 Avista and other electric utilities is based on the

9 resource mix and the cost of those resources. All

10 resource mixes have risks specific to resources chosen.

11 The demand for electric utility services of Avista is

12 relatively stable compared to that of unregulated firms

13 and even other electric utilities. This low demand risk

14 is partially due to the low cost power and the customer

15 mix of the power users.

16 Under regulation, utilities are generally

17 allowed to recover, through rates, reasonable, prudent

18 and justifiable cost expenditures. Unregulated firms

19 have no such assurance. Utilities in general are

20 sheltered from risk by regulation allowing reasonable

21 cost recovery thus making the average utility less risky

22 than the average unregulated industrial firm. Avista's

23 regulatory risk is low compared to many other regulated

24 utilities. The Idaho Public Utilities Commission has

25 shown overall support for Avista during drought years by

1117

WWP-E-98-11 CARLOCK (Di) 12
4/23/99 Staff

1 providing for surcharges and approving the PCA. Avista

2 does not have substantial plant investment or expenses

3 that are at risk in this case. This makes the regulatory

4 risk in Idaho low for Avista.

5 Q. Have you compared Avista directly with

6 other utility companies?

7 A. Yes. Schedule 9 of Exhibit No. 122 shows

8 the returns for Moody's electric utility companies of

9 10.0% for the three-year average return in 1997 and 8.8%

10 for the three-year average return in 1998. I have

11 compared Avista with this electric utility average and

12 financial statistics for other companies that meet the

13 following Value Line Investment Survey criteria:

14 1. Beta of .50 - .70 where the market

15 equals 1.00 (Avista's Beta is .60);

16 2. Safety of 2 - 3 on a scale of 1 - 5

17 where 1 is the highest rating and 3 is average

18 (Avista's safety rating is 2); and

19 3. Timeliness of 2 - 4 on a scale of 1 - 5

20 where 1 is the highest rating and 3 is average

21 (Avista's safety rating is 4).

22 There are 180 companies meeting these

23 criteria but only 13 Electric Utilities - West meeting

24 the criteria. The Electric Utilities - West are shown on

25 Schedule 11 of Exhibit No. 122. The financial statistics

1118

WWP-E-98-11 CARLOCK (Di) 13
4/23/99 Staff

1 shown on Schedule 11 of Exhibit No. 122 include annual

2 statistics for average annual price/earnings ratio,

3 average annual dividend yield, common equity ratio,

4 percent earned on common equity, percent payout ratio and

5 market to book ratio. The financial statistics shown on

6 Schedule 12 of Exhibit No. 122 show the group average

7 compared to Avista.

8 Q. Based upon your analysis of industrial

9 returns, utility returns, and current economic

10 conditions, what is your estimate of the cost of equity

11 capital for Avista Company based upon the Comparable

12 Earnings method?

13 A. When utilizing the Comparable Earnings

14 method, the risk differentials between industrial

15 companies and utilities, particularly Avista, must be

16 considered. Utility returns, in comparison to industrial

17 returns, may be ranked by classifying the utility

18 services according to risk levels. Utility groups are

19 less risky than industrial companies. Because an average

20 utility company is less risky than an average industrial

21 company, its cost of equity capital range would be less.

22 I believe Avista is less risky than an

23 average utility company due to lower competitive risks

24 and regulatory risks as discussed previously. These

25 lower risks produce a lower business risk for Avista than

1119

WWP-E-98-11 CARLOCK (Di) 14
4/23/99 Staff

1 for other companies. Therefore, the cost of equity

2 capital would be less for Avista than that of both an

3 average utility and that of an industrial company. When

4 considering the risk differentials between Avista and

5 other companies, the lower risk for Avista due to

6 implementing the PCA compared to its risks before the PCA

7 must be considered along with the current competitive

8 position related to low cost resources and low rates.

9 The comparable group of Value Line Electric

10 Utilities - West shows an average earned return on equity

11 of 11.4%. The average earned return on equity for 1998

12 was 11.6% for the comparable group of Value Line Electric

13 Utilities - Central and 10.9% for the Electric Utilities

14 - East. The projected 3-5 year average returns for the

15 comparable group of Value Line Electric Utilities are

16 7.5% West and 8.33% for both Central and East.

17 Using the Comparable Earnings approach, my

18 estimate of the current cost of equity capital for Avista

19 is in the range of 10.5% - 11.5%. This range is

20 developed by reviewing the most recent and projected

21 utility returns shown for the Value Line comparable

22 electrics above; electric returns as shown in the

23 Corporate Scoreboard of 10.1% for the First Quarter of

24 1998, 9.5% for the Second Quarter of 1998, 9.4% for the

25 Third Quarter of 1998 and, 10.1% for the Fourth Quarter

1120

WWP-E-98-11 CARLOCK (Di) 15
4/23/99 Staff

1 of 1998 (Ex. 122, Sch. 1-4, respectively); three-year

2 average return of 8.8% ending 1998 and a 10.7% annual

3 return in 1998 for the Moody's Electric Utilities

4 (Ex. 122, Sch. 9); and three-year average return of 12.8%

5 ending 1998 and a 10.0% annual return in 1998 for the

6 Moody's Gas Distribution Utilities (Ex. 122, Sch. 10).

7 These returns were then analyzed along with the

8 comparable earnings shown on Schedule 11, the market

9 indicators (Schedules 6 - 8 of Ex. 122) and the

10 industrial returns (Schedules 1 - 5 of Ex. 122) to

11 predict a reasonable required return.

12 Q. You indicated that the Discounted Cash Flow

13 method is utilized in your analysis. Please explain this

14 method.

15 A. The Discounted Cash Flow (DCF) method is

16 based upon the theory that (1) stocks are bought for the

17 income they provide (i.e., both dividends and/or gains

18 from the sale of the stock), and (2) the market price of

19 stocks equals the discounted value of all future incomes.

20 The discount rate, or cost of equity, equates the present

21 value of the stream of income to the current market price

22 of the stock. The formula to accomplish this goal is:

23

24

25

1121

WWP-E-98-11 CARLOCK (Di) 16
4/23/99 Staff

1 D1 D2 DN PN
Po = PV = ------- + ------- +...+ ------ + ------
2 (1+ks)1 (l+ks)2 (1+ks)N (1+ks)N

3 Po= Current Price

4 D= Dividend

5 ks= Capitalization Rate, Discount Rate, or
Required Rate of Return
6
N= Latest Year Considered
7

8 The pattern of the future income stream is

9 the key factor that must be estimated in this approach.

10 Historically some simplifying assumptions for ratesetting

11 purposes can be made without sacrificing the validity of

12 the results. Two such assumptions are: (1) dividends per

13 share grow at a constant rate in perpetuity; and, (2)

14 prices track earnings. These assumptions lead to the

15 simplified DCF formula, where the required return is the

16 dividend yield plus the growth rate (g):

17 D

18 ks = -- + g

19 Po

20 Q. Please summarize your understanding of

21 Avista witness Avera's argument against the constant

22 growth DCF method?

23 A. Avista witness Avera states that the constant

24 growth DCF method produces unreasonable results. He

25 argues that deregulation trends in the electric industry

1122

WWP-E-98-11 CARLOCK (Di) 17
4/23/99 Staff

1 dictate that even a two-stage DCF method should not be

2 used because of the transition of electric utilities to a

3 competitive industry. Witness Avera uses projected

4 annual revenue streams for his group of comparables.

5 Q. Do you agree with Avista witness Avera's

6 evaluation on the feasibility of using the DCF method?

7 A. I agree that the constant growth DCF method

8 is not reasonable to use for Avista. The primary reasons

9 include: (1) the dividend change for Avista minimizes the

10 benefit of historical trends, and (2) growth projections

11 for the next three years are not representative of

12 ongoing growth due to the Common Stock Exchange Offer

13 where Return-Enhanced Convertible Securities (RECONS)

14 will be converted to common shares within three years

15 (Dec. 2001).

16 I do not agree that the two-stage DCF method

17 should not be used. While it may not be appropriate for

18 particular companies, I believe it can reasonably be used

19 for the industry. The combination of growth estimates

20 with the two-stage DCF method can be just as accurate as

21 the projection of revenue streams and stock prices

22 significantly into the future for use in the non-constant

23 DCF method. It is the possible variability of these

24 projections used by Avista witness Avera that causes

25 concern.

1123

WWP-E-98-11 CARLOCK (Di) 18
4/23/99 Staff

1 Q. What DCF method have you utilized?

2 A. I have used the two-stage DCF method with

3 the growth with the two stages averaged for the groups of

4 electric utility comparables. I have not relied on the

5 DCF calculation for Avista, although it is calculated,

6 due to the instability of current market prices and

7 growth estimated immediately following a dividend cut. I

8 also compare these DCF variables with those used by Mr.

9 Avera to establish his comparable DCF spectrum of 11.1% -

10 11.8% with an average of 11.5%.

11 Q. What is your estimate of the current cost

12 of capital for comparable electric utilities of Avista

13 Company using the Discounted Cash Flow method?

14 A. The current cost of equity capital for Avista

15 comparables using the Discounted Cash Flow method is

16 between 8.5% - 10.1% with projected growth in dividends

17 and projected growth in earnings averaged to use for the

18 growth rate. The cost of equity capital using the

19 average annual dividend yield for the electric comparable

20 groups produces a range of 10.1% - 11.2%. I believe a

21 10.0% to 11.0% range as the most appropriate estimate

22 under the Discounted Cash Flow method for use in this

23 case.

24 Q. You have utilized an adjusted dividend yield

25 to determine the required return with the DCF method.

1124

WWP-E-98-11 CARLOCK (Di) 19
4/23/99 Staff

1 Please explain.

2 A. The adjustment I have made to arrive at the

3 adjusted dividend yield for the DCF method recognizes

4 direct issuance or flotation costs for stock issuances.

5 Market pressure should not be reflected in the flotation

6 cost adjustment. I have used a 4% flotation cost rate

7 based on the range of 3%-5% as a reasonable flotation

8 cost over time to be included in the DCF analysis. This

9 3%-5% range for flotation costs is the same range used by

10 Mr. Avera.

11 Q. Please explain the adjustment to reflect a 4%

12 issuance expense or flotation cost factor to calculate

13 the dividend yield in the DCF calculation?

14 A. The 4% is based on the issuance expenses

15 based on an acceptable range of 3%-5% incurred for

16 issuances. Issuance costs are relevant expenditures to

17 consider in the cost of equity determination for new

18 issuances. Direct issuance or flotation costs impact the

19 actual price received by the Company for stock sold. The

20 funds received amount to the stock price less the

21 issuance costs. To reflect these costs, the dividend

22 yield is adjusted in the DCF method.

23 A specific allowance for market pressure is

24 not appropriate. Investors determine the price they are

25 willing to pay for stock at the time of issuance. I do

1125

WWP-E-98-11 CARLOCK (Di) 20
4/23/99 Staff

1 not believe it is appropriate to make an allowance

2 for price fluctuations as a result of this competitive

3 process. I have used the 4% allowance as reasonable over

4 time.

5 Q. What is the capital structure you have used

6 for Avista Company to determine the overall cost of

7 capital?

8 A. I have utilized a capital structure

9 consisting of 51.988% debt, 10.588% preferred securities

10 and 37.424% common equity as shown on Schedule 14 of

11 Exhibit No. 122. This capital structure is appropriate

12 to use for ratemaking purposes in this case and is the

13 same capital structure presented by Avista witness Avera.

14 Q. What are the costs related to the capital

15 structure for debt and the preferred securities?

16 A. The embedded cost long-term debt is 8.011%,

17 the embedded cost of short-term debt is 6.255%, the

18 embedded cost of preferred trust securities is 8.113%,

19 the embedded cost of preferred stock is 8.151%. I have

20 accepted the methodology and cost rates used by Avista

21 witness Avera in his exhibits to calculate the cost of

22 debt and preferred.

23 Q. You indicated the cost of common equity range

24 for Avista is 10.5% - 11.5% under the Comparable Earnings

25 method and 10.0% - 11.0% under the Discounted Cash Flow

1126

WWP-E-98-11 CARLOCK (Di) 21
4/23/99 Staff

1 method. What is the cost of common equity capital you

2 are recommending?

3 A. The fair and reasonable cost of common equity

4 capital I am recommending for Avista is in the range of

5 10.25% - 11.25%. Although any point within this range is

6 reasonable, the return on equity granted would not

7 normally be at either extreme of the fair and reasonable

8 range. The mid-point is 10.75%. This is a reasonable

9 return of equity for Avista based on a review of the

10 market data and comparables shown on the schedules in

11 Exhibit No. 122.

12 EQUITY ADDER

13 Q. Avista witness Dukich discusses and

14 recommends that an equity adder of 25 basis points be

15 added to the equity return of Avista to recognize and

16 reward Avista for its innovative management and strategic

17 initiatives. Please discuss the rationale for this

18 incentive.

19 A. Staff has recommended equity adders in other

20 cases and the Commission has awarded equity adders and

21 imposed equity penalties in the past. In the Idaho Power

22 Company case (Case No. IPC-E-94-5, Order No. 25880) the

23 Commission did not specifically decide on an equity adder

24 but took the circumstances into account when deciding the

25 return on equity point authorized.

1127

WWP-E-98-11 CARLOCK (Di) 22
4/23/99 Staff

1 The equity adder is not necessarily a reward

2 for past exemplary performance but is an incentive to

3 continue programs and processes that lead to the noted

4 qualities and initiatives. Continued betterment of

5 performance is an ongoing goal.

6 Q. Do you agree with the proposed method of

7 quantifying and structuring a bonus incentive?

8 A. Yes. I believe the best way to recognize

9 improvement in management policies or programs through

10 innovative management and strategic initiatives is

11 through the rate of return. In cases where exemplary

12 performance was recognized by the Commission, a bonus of

13 up to 25 basis points has been added to the authorized

14 return on equity. Avista is making improvements, and

15 deserves recognition for those improvements.

16 Q. Avista witness Dukich lists numerous reasons

17 why Avista should be awarded an equity adder. Do you

18 agree with his characterizations?

19 A. Overall I agree that these accomplishments

20 are outstanding, placing Avista ahead of many if not most

21 other utilities. The studies and facts supporting

22 management efficiency and innovation are consistent with

23 Staff's findings for these areas in this case.

24 There are areas of Staff concern explained

25 in the testimony of Staff witnesses Sterling, Maxwell,

1128

WWP-E-98-11 CARLOCK (Di) 23
4/23/99 Staff

1 and Anderson that the Commission must weigh when determining

2 if an equity adder should be allowed and if so, by how

3 much. These concerns revolve around Avista not following

4 Commission Orders or requesting an exclusion or change in

5 the ordering directive. They include: (1) Line Extension

6 practices where the average cost has not been updated

7 since 1988 even though Mr. Dukich in a letter to the

8 Commission acknowledged that provision of the order and

9 stated Washington Water Power would be providing these

10 updates; and (2) No notices sent to customers related to

11 PCA surcharges, PCA rebates, DSM rider rate change or the

12 amount of the DSM rider included in rates.

13 I will let the Commission weigh these factors

14 to see if they should offset partially or completely the

15 exemplary performance of Avista management in the areas

16 referenced by Mr. Dukich. For purposes of calculating

17 the overall rate of return for use in the revenue

18 requirement, I have included an equity adder of 25 basis

19 points. The return on equity point is increased above

20 the mid-point of 10.75% to 11.0%.

21 Q. What is the overall weighted cost of capital

22 you are recommending for Avista?

23 A. I am recommending an overall weighted cost of

24 capital in the range of 8.792% - 9.166% as shown on

25 Schedule 14, Exhibit No. 122. For use in calculating the

1129

WWP-E-98-11 CARLOCK (Di) 24
4/23/99 Staff

1 revenue requirement, a point estimate consisting of a

2 return on equity of 11.0% and a resulting overall rate of

3 return of 9.073% was utilized.

4 Q. Does this conclude your direct testimony in

5 this proceeding?

6 A. Yes, it does.

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

1130

WWP-E-98-11 CARLOCK (Di) 25
4/23/99 Staff

1 (The following proceedings were had in

2 open hearing.)

3 MR. WOODBURY: And I'd present Ms. Carlock

4 for cross-examination.

5 COMMISSIONER SMITH: Mr. Ward, do you have

6 questions for Ms. Carlock?

7 MR. WARD: Just a couple.

8

9 CROSS-EXAMINATION

10

11 BY MR. WARD:

12 Q Ms. Carlock, I want to ask you briefly

13 about the 25 basis point equity kicker. Do you

14 understand what I mean about that?

15 A Yes, the equity adder.

16 Q More elegant term, but the same thing, is

17 it not?

18 A Yes.

19 Q As I understand it, in the last -- was it

20 the last Idaho Power rate case where Idaho Power was

21 awarded a 25 basis point adder?

22 A Actually, they were not awarded an adder.

23 The factors that were looked at relative to the adder

24 were taken into consideration when the Commission set its

25 return and they did not explicitly have an adder

1131

CSB REPORTING CARLOCK (X)
Wilder, Idaho 83676 Staff

1 reflected even though they recognized some of those

2 points.

3 Q Okay, and that leads me to my next

4 question. In general, the Commission's charge, is it

5 not, is to set just and reasonable rates?

6 A Yes.

7 Q And that, of course, requires a just and

8 reasonable calculation of the cost of capital?

9 A That's correct.

10 Q Are we in danger of creating a situation

11 here in which even if not awarded at least in every case

12 the companies are asking for just and reasonable cost of

13 equity plus 25 basis points?

14 A There's a possibility that companies would

15 ask for that and I know as a Staff witness I would look

16 at the reasonable cost separate from any adder and then

17 the Commission would have to take that into

18 consideration, also, and as long as the return was in the

19 reasonable range, it would provide reasonable and just

20 rates.

21 MR. WARD: That's all I have.

22 COMMISSIONER SMITH: Thank you, Mr. Ward.

23 Mr. Shurtliff.

24

25

1132

CSB REPORTING CARLOCK (X)
Wilder, Idaho 83676 Staff

1 CROSS-EXAMINATION

2

3 BY MR. SHURTLIFF:

4 Q So I take it from that response that if the

5 Commission picked an equity point based on the

6 calculation at the top end that if you added on it would

7 go beyond the pale of reasonableness?

8 A Generally, when you pick a point within a

9 reasonable range, you take into consideration

10 extraordinary events if you're going to go towards the

11 top end or, for that matter, to the lower end; otherwise,

12 the point generally is somewhere close to the middle of

13 that range unless there is something that needs to be

14 taken into consideration.

15 Q Something extraordinary one way or the

16 other?

17 A Exactly.

18 Q So when you calculate a fair and reasonable

19 cost of common equity at the range of 10.25 to 11.25 at

20 page 22 of your direct testimony, the midpoint being

21 10.75, anything above that would be an adder?

22 A Not necessarily. Anything at either

23 extreme would probably take into consideration the

24 positive aspects if it's at the upper end of the range or

25 negative aspects if it's at the lower end of the range,

1133

CSB REPORTING CARLOCK (X)
Wilder, Idaho 83676 Staff

1 but just because it's not 10.75, maybe the Commission

2 went with 10.8 or 10.9, that's not at the extreme, so it

3 doesn't necessarily mean that they've put an adder or

4 penalty in there. It's just their interpretation of what

5 the witnesses' testimony may portray.

6 Q The notion of an adder discussed from

7 yesterday and with you, and we don't need to go over it

8 at great length, but you make reference to a couple of

9 reasons why the Company hasn't been exemplary, do you

10 not?

11 A I do. Yes, there are a couple of reasons

12 that I took into consideration that were offsets in my

13 mind as to somewhat the perception of perfection that

14 people would like to achieve.

15 Q And so not to suggest they had clay feet,

16 but they were less than perfect on some occasions?

17 A That's true. There were a couple of areas

18 that I had some concern relative to Commission orders,

19 particularly, and customer notice. At this point I would

20 like to add that the Company has corrected potential

21 problems, I understand, with the customer notice

22 situation.

23 Q Would a Commission order less than the

24 midpoint of your recommended 10.25 to 11.25, less than

25 the midpoint, would that be beyond the range of

1134

CSB REPORTING CARLOCK (X)
Wilder, Idaho 83676 Staff

1 reasonable?

2 A The Commission has to take into

3 consideration all testimonies. I have a range that I

4 recommended. Mr. Avera has a range that he recommended

5 and Dr. Peseau recommended a couple of points in his

6 testimony. All of that has to be taken into

7 consideration by the Commission and just because it's

8 outside of my range doesn't mean that it's not within a

9 reasonable range the Commission may decide. I may not

10 personally agree with that, but that's not what the

11 Commission has to take into consideration.

12 Q Indeed, one of the reasons you have ranges

13 personally yourself, your own testimony, is because you

14 don't know with empiric soundness what the point is, do

15 you?

16 A You are estimating investor requirements

17 and since there is a group of investors, that there is no

18 way of polling all of them, you don't know exactly. You

19 have to use the tools that are available to you in order

20 to try to determine that.

21 Q And you use those tools and then you come

22 up with a range, not a number?

23 A That's correct, and then within that range,

24 you have to pick a number to calculate the revenue

25 requirement.

1135

CSB REPORTING CARLOCK (X)
Wilder, Idaho 83676 Staff

1 Q And that's a matter of judgment, that range

2 that you arrived at?

3 A It is a matter of judgment as far as the

4 point within that range and somewhat the range, also.

5 Usually the different ranges in a case have some

6 overlapping areas no matter which witness you're talking

7 about.

8 Q Was there an overlap in this case?

9 A I believe that some of the upper ends of my

10 numbers do overlap the lower ends of Mr. Avera's numbers.

11 Q Is that unusual?

12 A No.

13 MR. SHURTLIFF: I have no further

14 questions. Thank you.

15 COMMISSIONER SMITH: Thank you,

16 Mr. Shurtliff.

17 Mr. Meyer.

18

19 CROSS-EXAMINATION

20

21 BY MR. MEYER:

22 Q Yes, good afternoon.

23 A Good afternoon.

24 Q You really conduct a couple of analyses to

25 get to your recommended cost of capital; the first being

1136

CSB REPORTING CARLOCK (X)
Wilder, Idaho 83676 Staff

1 a comparable earnings approach and the second being a DCF

2 method; correct?

3 A That's correct.

4 Q Let's turn to your DCF method. Let's start

5 with areas where you and the Company agree. Both Staff

6 and the Company agree to reject the constant growth

7 method for the analysis?

8 A For this particular case for Avista, that's

9 true. There are various things that are going on in the

10 market with Avista stock that make it not reasonable to

11 use that methodology at this point in time.

12 Q So instead of the constant growth method,

13 you've recommended, as has the Company, a two-stage

14 method or model; is that correct?

15 A Yes. What I have used is looking at growth

16 at two different points in time for use in the DCF.

17 Q And what were those points in time?

18 A Basically, current levels and levels five

19 to ten years out.

20 Q And in your testimony or exhibit material,

21 will you show me where you've incorporated or identified

22 the second stage, five to ten years out?

23 A If you look at Exhibit 122, schedule 13,

24 the growth factors shown in that exhibit are a composite

25 of those two stages for each of the different utility

1137

CSB REPORTING CARLOCK (X)
Wilder, Idaho 83676 Staff

1 groups for the West, Central and East.

2 Q Are you talking about schedule 13?

3 A Schedule 13, yes.

4 Q So without getting into the -- there's a

5 fair amount of detail on this exhibit, but you don't

6 show, and maybe it's implicit in what you've done, but I

7 don't see, I guess, on the face of this exhibit where

8 you've incorporated a two-stage model that projects out

9 essentially ten years. Does that show here?

10 A That is not shown here. Underneath the

11 Electric Utility West, the 4.18 percent is the

12 combination of those two stages and I discuss that in my

13 testimony, and in my workpapers the individual numbers

14 are shown.

15 Q Okay. Now, your capital structure -- well,

16 let's put it this way: In arriving at your overall rate

17 of return recommendation, and that's in your schedule 14,

18 that's your summary sheet, if you will --

19 A That's correct.

20 Q -- what equity percentage for the Idaho

21 electric jurisdiction did you employ? Was it 37.424

22 percent?

23 A That's correct.

24 Q Now, on your schedule 12 of the same

25 exhibit, do you have that in front of you?

1138

CSB REPORTING CARLOCK (X)
Wilder, Idaho 83676 Staff

1 A I do.

2 Q Okay, you present equity ratios for your

3 comparable utility groups as well as for Avista, don't

4 you?

5 A I do.

6 Q Okay, and how does the 37.4 percent in

7 round terms, 37.4 percent equity for Avista that you

8 recommend, compare with the common equity ratios for

9 these others, other groups, Utility Electric West,

10 Utility Electric Central and Utility Electric East?

11 A It is lower than all of those, as well as

12 for the Avista group. The difference is that you're

13 looking at a regulatory capital structure versus a

14 reported capital structure.

15 Q So what we're doing here, though, under the

16 Hope and Bluefield decisions is trying to establish

17 reasonable and compensatory cost recovery so we can

18 attract and maintain capital and investor confidence, are

19 we not?

20 A Yes.

21 Q And its confidence in the utility as the

22 utility?

23 A Avista is not only a utility, so investors

24 look at the total corporation for Avista in making their

25 decisions. There is the utility aspect and then there

1139

CSB REPORTING CARLOCK (X)
Wilder, Idaho 83676 Staff

1 are also the nonregulated aspects that go into the

2 composite review that an investor would look at.

3 Q If one were to look at rate setting for

4 this utility's operations, your cost of equity

5 recommendation is as a cap structure goes about

6 37 percent; correct?

7 A That's correct, for the regulated

8 operations of the utility.

9 Q And what we're all about in this proceeding

10 is in part to establish an appropriate cost of capital

11 for Idaho electric utility operations?

12 A That is correct, but the cost of capital is

13 determined based on the stock of the Company. There is

14 not Idaho electric stock available to analyze, so you

15 have to look at the Company and the market as a whole.

16 Q Now, does Idaho Power, if you know, have a

17 higher bond rating than Avista?

18 A I believe it might be just slightly

19 higher. I'd have to look at that to see. There's been a

20 credit watch and I'm not sure whether there was a change,

21 but they're fairly close.

22 Q Would you accept, subject to check, that

23 for Idaho Power their Moody's rating is A2 as opposed to

24 an A3 for Avista?

25 A I would.

1140

CSB REPORTING CARLOCK (X)
Wilder, Idaho 83676 Staff

1 Q And likewise, with Standard and Poor's that

2 it's a double A minus for Idaho Power versus a single A

3 for Avista?

4 A That's true.

5 Q If you had used hypothetically Idaho

6 Power's 45 percent capital structure instead of Avista's,

7 in round terms instead of Avista's, 37 percent capital

8 structure, all else being equal, would your rate of

9 return have been higher?

10 A The rate of return would have been higher,

11 but I do not believe that that would be appropriate in

12 this case. There are valid reasons why the capital

13 structures are different and one of those is the

14 nonregulated operations and because of that, the

15 nonregulated operations should be bearing the cost of

16 that difference between the capital structure, not the

17 regulated operations.

18 Q Okay, but if we were to just isolate, try

19 and isolate, the impact of a different capital structure,

20 comparing, say, an Idaho Power with an Avista, holding

21 all else constant so we can zero in on that effect, you

22 don't disagree, do you, that given Avista's lower 37

23 percent equity component of its capital structure that

24 its rate of return would have been higher?

25 A If you change the capital structure and put

1141

CSB REPORTING CARLOCK (X)
Wilder, Idaho 83676 Staff

1 in a greater common equity ratio, the overall rate of

2 return would be higher, yes.

3 Q Almost by definition?

4 A Just by the mathematics of it. You would

5 then have to look at the return on equity and see if

6 there was a change that was required there, also.

7 Q In terms of interest rates, on page 9 of

8 your testimony, you refer to interest rate trends, don't

9 you?

10 A Okay. Yes, I do refer to interest rates.

11 Q Thank you, and what has been, if you know,

12 the general trend in interest rates over the last several

13 months?

14 A The actual changes have not, you know,

15 there has not been a change. There have been indications

16 for potential increases, but those have not occurred.

17 For instance, the prime rate has been consistent since

18 November 17th, 1998, and it's still at that same rate.

19 Q Would you agree with me, subject to check,

20 that the U.S. Treasury bond yield at the close as of

21 yesterday was 5.99 percent?

22 A That is entirely possible. The bond yields

23 fluctuate up and down weekly.

24 Q And I'll be happy to show you something to

25 verify that. You're prepared to accept that subject to

1142

CSB REPORTING CARLOCK (X)
Wilder, Idaho 83676 Staff

1 check?

2 A I will accept it subject to check, yes,

3 because they do fluctuate.

4 Q Now, do you recall that the Company

5 referenced, Dr. Avera referenced, a 5.21 percent yield on

6 page 32 of his direct testimony when he filed it last

7 year in 1998?

8 A In his direct testimony?

9 Q Yes, page 32.

10 A Okay, on page 32, he referenced for

11 October, '98 5.21 for the long-term U.S. Treasury; is

12 that what you're referring to?

13 Q Yes.

14 A Yes.

15 Q Thank you, and if we were to take a point

16 in time as of yesterday as we've discussed, it's nearly

17 6 percent; is that correct?

18 A That's correct.

19 Q Okay. Is it your recollection that a

20 Potlatch witness, Peseau, referenced a 5.5 percent

21 long-term Treasury rate in his testimony, would you

22 accept that subject to check?

23 A I would accept that.

24 Q Okay. Exhibit 122, schedule 11, please, of

25 your testimony.

1143

CSB REPORTING CARLOCK (X)
Wilder, Idaho 83676 Staff

1 A Okay.

2 Q There you show, don't you, equity returns

3 for the 12-month period for a variety of companies for

4 the period ending December 31 of 1998?

5 A Yes, I do.

6 Q Now, in terms of the outliers in this group

7 or, to state it differently, out of the 14 companies

8 identified here, there are four that show single digit

9 common equity returns, aren't there?

10 A Okay.

11 Q And those would be, get my lines right

12 here, Nevada Power, PG&E Corp., Public Service of New

13 Mexico and Puget Sound Energy?

14 A That's correct.

15 Q All of those which range anywhere from

16 6.8 percent to 9.78 percent are well below the average of

17 11.43 percent?

18 A That's true, just like Avista at 14.6 and

19 Black Hills at 15.75 are well above it.

20 Q Now, have you examined for each of the four

21 that fall well below that average what conditions in 1998

22 may have adversely impacted their returns?

23 A No, I didn't investigate the returns for

24 any of the individuals, whether it was below the average

25 or above the average.

1144

CSB REPORTING CARLOCK (X)
Wilder, Idaho 83676 Staff

1 Q Okay; so no -- very well. Does your

2 recommended return on equity imply a pre-tax interest

3 coverage ratio of 2.63 percent?

4 A According to, let's see, schedule 10 of

5 Mr. Avera's --

6 Q Not percent, I'm sorry, it was just 2.63.

7 A 2.63 times, yes, that is how he's

8 calculating it and I have no reason to take exception to

9 that, that's the mathematical calculation.

10 Q Okay. Now, compare that with the interest

11 coverage ratios for other single A rated electrics as

12 reported by Standard & Poor's, if you know, and I can

13 give you a number subject to check.

14 A It's lower than some and it's also higher

15 than others for --

16 Q Go ahead.

17 A This is not so far outside of the range

18 that there would be a particular question for this one

19 item. There would have to be other things that were

20 looked at in order to question the overall validity of

21 the rating for the Company.

22 Q In terms of Standard & Poor's reported

23 benchmarks required to support a single A bond rating, do

24 you have the brackets, the ranges, the benchmarks, if you

25 will?

1145

CSB REPORTING CARLOCK (X)
Wilder, Idaho 83676 Staff

1 A I don't have those in front of me, but I do

2 know them. If you have them, I can verify that that's

3 correct.

4 Q Okay, the brackets or the ranges being on

5 the low end 2.75 times; on the high end 4.5 times?

6 A I would accept that, yes.

7 Q And again, you established earlier that, I

8 guess you accepted our witness' calculation that your ROE

9 implies only an interest coverage ratio for Avista of

10 2.63 times; correct?

11 A Yes, and again, we're looking at the

12 operations in this calculation for the 2.63 of just the

13 regulated operations. The total operations for the

14 utility is looking at the total operations for all of

15 those entities and not just this regulated operation. In

16 order to impact the bond rating, you would have to look

17 at Avista's coverage in total.

18 Q Just one other area, bear with me a

19 moment. Would you agree with me that as a general matter

20 that the investment community, the marketplace, if you

21 will, does not like uncertainty?

22 A That's true.

23 Q It's almost an article of faith, it seems

24 to be, doesn't it?

25 A Yes, they look at uncertainty as a level of

1146

CSB REPORTING CARLOCK (X)
Wilder, Idaho 83676 Staff

1 risk and then they would have to determine how much

2 uncertainty they're willing to bear.

3 Q And to the extent that there is any

4 uncertainty concerning either the timing or the extent of

5 requested rate relief, would that be viewed as a

6 negative?

7 A In partial, yes.

8 MR. MEYER: Thank you. That's all I have.

9 COMMISSIONER SMITH: Thank you, Mr. Meyer.

10 Do we have questions from the Commission?

11 Any redirect, Mr. Woodbury?

12 MR. WOODBURY: No, Madam Chair.

13 COMMISSIONER SMITH: Thank you.

14 (The witness left the stand.)

15 MR. WOODBURY: Staff's last witness is

16 Keith Hessing.

17

18

19

20

21

22

23

24

25

1147

CSB REPORTING CARLOCK (X)
Wilder, Idaho 83676 Staff

1 KEITH.D HESSING,

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. Hessing, will you please state your

10 full name?

11 A My name is Keith D. Hessing.

12 Q And for whom do you work and in what

13 capacity?

14 A I work for the Idaho Public Utilities

15 Commission Staff as a Staff engineer.

16 Q And in that capacity, did you have occasion

17 to prepare and prefile in this case 10 pages of testimony

18 and Exhibits 123 through 128?

19 A Yes, I did.

20 Q And have you had the opportunity to review

21 that prior to this hearing?

22 A Yes.

23 Q And is it necessary to make any changes or

24 corrections to the testimony or exhibits?

25 A No.

1148

CSB REPORTING HESSING (Di)
Wilder, Idaho 83676 Staff

1 Q If I were to ask you the questions set

2 forth in your testimony, would your answers be the same?

3 A Yes, they would.

4 MR. WOODBURY: Madam Chair, I'd ask that

5 the testimony be spread on the record and the exhibits

6 identified.

7 COMMISSIONER SMITH: If there's no

8 objection, that is so ordered.

9 (The following prefiled testimony of

10 Mr. Keith Hessing is spread upon the record.)

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

1149

CSB REPORTING HESSING (Di)
Wilder, Idaho 83676 Staff

1 Q. Please state your name and business address

2 for the record.

3 A. My name is Keith D. Hessing and my business

4 address is 472 West Washington Street, Boise, Idaho.

5 Q. By whom are you employed and in what

6 capacity?

7 A. I am employed by the Idaho Public Utilities

8 Commission as a Public Utilities Engineer.

9 Q. What is your educational and experience

10 background?

11 A. I am a Registered Professional Engineer in

12 the State of Idaho. I received a Bachelor of Science

13 Degree in Civil Engineering from the University of Idaho

14 in 1974. Since then, I have worked six years with the

15 Idaho Department of Water Resources, and two years with

16 Morrison-Knudsen. I came to work for the Commission in

17 August 1983.

18 As a member of the Commission Staff, my

19 primary areas of responsibility have been electric

20 utility power supply, revenue allocation and rate design.

21 Q. What is the purpose of your testimony in

22 this proceeding?

23 A. I will discuss class cost-of-service,

24 allocation of revenue requirement to the classes and rate

25 design.

1150

WWP-E-98-11 HESSING, K (Di) 1
04/23/99 Staff

1 Q. Please summarize your testimony.

2 A. I accept the Company's proposed cost-of

3 service methodology and calculate an overall rate of

4 return of 7.27% under current rates with Staff's pro

5 forma adjustments. Staff witness Carlock proposes an

6 overall rate of return of 9.073% which requires an

7 increase in the Company's revenue requirement of

8 $10,234,000. I incorporate the additional revenue

9 requirement along with a proposed one-third move toward

10 cost-of-service which produces the following increases by

11 customer class:

12 Customer Class Rate Increase

13 Residential Service 12.7%

14 General Service 3.2%

15 Large General Service 6.2%

16 Extra Large General Service 13.0%

17 Pumping Service 5.4%

18 Street and Area Lighting 7.2%

19 Potlatch Special Contract 0.0%

20 Average 8.3%

21 I accept the Company's non-energy rate design components

22 and balance each class's revenue requirement on the

23 energy rate except for the lighting schedules where I

24 propose a uniform percentage increase to all components.

25

1151

WWP-E-98-11 HESSING, K (Di) 2
04/23/99 Staff

1 Class Cost-of-Service

2 Q. What class cost-of-service methodology do

3 you prefer and why?

4 A. Cost-of-service methodology is often a hotly

5 debated item in a general rate case. There is no such

6 thing as one and only one correct methodology. Instead

7 there are an infinite number of possible methods with

8 advantages and disadvantages. The reality of what is an

9 advantage and what is a disadvantage changes depending

10 upon the view from each individual customer class.

11 When rates are adjusted in relation to any

12 particular cost-of-service study, those rates change as a

13 direct result of changes in one or both of the following

14 two items:

15 First, rates change because the physical

16 characteristics of the individual rate classes change

17 relative to one another. Class energy use and peak

18 demands change. Rates also change when rate base and

19 expense account amounts change as a result of the

20 Company's daily business operations over time. As a rule

21 I believe that rate changes caused by changes in customer

22 usage characteristics and account totals are appropriate.

23 Second, rates change because of changes in

24 cost-of-service methodology. I believe that changes

25 caused by changes in cost-of-service methodology should

1152

WWP-E-98-11 HESSING, K (Di) 3
04/23/99 Staff

1 be infrequent and need to be justified.

2 Q. Washington Water Power proposes some

3 methodological changes between this case and its last

4 case in its cost-of-service study. Are these changes

5 acceptable?

6 A. It has been 12 years since the Company last

7 had a general rate case in Idaho. It has been even

8 longer than that since the Company's cost-of-service

9 method has been substantially changed. The Company, in

10 this case, does not propose a change to the major

11 allocation method, the Peak Credit method. However, the

12 Company does propose two significant changes. First, it

13 proposes that distribution costs be classified to demand

14 and energy based on the Basic Customer Method instead of

15 the Minimum Distribution System Method. Second, it

16 proposes that administrative and general costs be

17 directly assigned to functions where possible and that

18 the remaining costs be included with the distribution

19 function and classified 40% to energy and 60% to

20 customer. Company witness Knox describes these changes

21 and their justification in more detail in pages 5 through

22 7 of her testimony. These changes are substantial and

23 materially affect the results. The effects are softened

24 by the Company's proposal to only move one-third of the

25 way toward cost-of-service. I am willing to accept the

1153

WWP-E-98-11 HESSING, K (Di) 4
04/23/99 Staff

1 methodology changes that the Company proposes in this

2 case based on the justification provided by the Company.

3 Q. What differences do changes in

4 cost-of-service methodology make in this case?

5 A. Company witness Knox has provided Exhibit

6 No. 17 which demonstrates the results of alternate

7 cost-of-service methodologies applied to the same base

8 data. Alternate No. 1 is the methodology used in the

9 Company's last general rate case. A comparison of "Base

10 Case Cost of Service" with "Alternative Scenario No. 1"

11 reveals that the proposed change in methodology is

12 detrimental to Residential, General Service and Pumping

13 Classes while it benefits Large General Service, Extra

14 Large General Service and Lighting Classes. Even with a

15 full move to cost-of-service the methodology changes

16 affect no class by more than one percentage point on rate

17 of return, except for street lighting which benefits by

18 almost a two percentage point increase.

19 Q. Have you performed a cost-of-service study

20 incorporating Staff's proposed changes?

21 A. Yes I have performed a cost-of-service

22 study incorporating Staff's proforma adjustments. Exhibit

23 No. 123, Parts 1, 2 and 3 show the process and the

24 results. I used the Company's model with Staff inputs to

25 produce this exhibit. Company witness Knox's testimony

1154

WWP-E-98-11 HESSING, K (Di) 5
04/23/99 Staff

1 contains a discussion of how the model operates. Part 3,

2 page 1 shows the results including class rates of return

3 under current rates for the 1997 test year.

4 Revenue Allocation

5 Q. The Company proposes a one-third move toward

6 cost-of-service for all rate classes except the special

7 contract class. What is Staff's proposal?

8 A. Staff agrees with the Company that it is

9 appropriate to move one-third of the way toward

10 cost-of-service in this proceeding. A more aggressive

11 move toward cost-of-service would produce overwhelmingly

12 large increases which are unacceptable.

13 Q. Why is the special contract class not being

14 included in moves toward cost-of-service?

15 A. Potlatch is the Company's only "special

16 contract" customer. Potlatch has a contract that

17 establishes its rates until its contract expires at the

18 end of the year 2001.

19 Q. What would class rate increases be under

20 your proposal?

21 A. Staff Exhibit No. 124, page 3 shows Staff's

22 proposed increases. As you can see Residential -

23 Schedule 1 and Extra Large General Service - Schedule 25

24 require 12.7% and 13.0% increases respectively even with

25 a modest one-third move toward cost-of-service. Pages 1

1155

WWP-E-98-11 HESSING, K (Di) 6
04/23/99 Staff

1 and 2 of Exhibit No. 124 show the calculations used to

2 determine the revenue requirement associated with a

3 one-third move toward cost-of-service.

4 Q. Have you calculated what class increases

5 would be under more aggressive moves toward

6 cost-of-service?

7 A. Yes I have. Staff Exhibit No. 125, pages 1

8 through 3 show the results of making a one-half move

9 toward full cost-of-service and Staff Exhibit No. 126,

10 pages 1 through 3 shows the results of moving all

11 adjustable classes to an equal rate of return. Special

12 contract class revenues are not adjusted in any of these

13 analysis.

14 Rate Design

15 Q. What structural changes does the Company

16 propose to class rates?

17 A. In its testimony the Company proposes three

18 structural changes to class rates, two in the residential

19 class and one in the pumping class. For the residential

20 class it proposes to change from a three block inverted

21 energy rate structure to a two block inverted energy rate

22 structure and to move from a customer minimum, which

23 includes 203 kWhs of energy, to a basic charge, which

24 includes no energy. For the pumping class it proposes to

25 add a basic charge where there currently is none.

1156

WWP-E-98-11 HESSING, K (Di) 7
04/23/99 Staff

1 Q. What structural changes does Staff propose?

2 A. Staff accepts the changes proposed by the

3 Company. Staff witness Maxwell discusses residential

4 rate design in her testimony.

5 Q. What justification is there for adding a

6 customer charge to pumping class rates?

7 A. The same justification that exists for a

8 fixed charge in other classes. That is that there are

9 costs associated with meter reading and billing that the

10 Company incurs whether or not the customer uses any

11 energy. Without a fixed customer charge, these costs

12 must be recovered in the energy rate which causes cost

13 subsidies among customers within the class.

14 Q. Have you prepared an exhibit showing the

15 results of Staff's rate design recommendations?

16 A. Yes I have. Staff Exhibit No. 127 compares

17 present rates to Staff's proposed rates. Page 3 of

18 Company Exhibit No. 21 includes the same information for

19 the Company's case.

20 Q. What rate design philosophy did the Staff

21 employ in determining the proposed rates shown on Exhibit

22 No. 127?

23 A. The Company provided substantial detailed

24 unbundled cost information supporting its proposed

25 increases in non-energy rate design components. I

1157

WWP-E-98-11 HESSING, K (Di) 8
04/23/99 Staff

1 accepted those moves toward full cost recovery and

2 balanced my calculations by determining the energy rate

3 for each class that recovered the remaining revenue

4 requirement. For the residential and pumping classes,

5 which have multiple energy rate blocks, I balanced my

6 calculations on the block that brought energy rates

7 between the blocks closer together.

8 Q. Staff Exhibit No. 127 does not provide any

9 information concerning the design of Street and Area

10 Lighting Rates - Schedules 41-49. How do you propose the

11 increase be spread to this customer class?

12 A. I propose that the increase be spread on a

13 uniform percentage basis to all rate components of these

14 schedules.

15 Q. Did you calculate some alternative rate

16 designs for the residential customer class?

17 A. Yes I did. Staff Exhibit No. 128 provides

18 some alternatives. Page 1 is an analysis of the

19 potential effects of Staff's proposed residential rate

20 design. Pages 2, 3 and 4 provide the same information

21 for Basic Charges of $4.50, $5.00 and $5.50 with their

22 associated energy rates. Staff witness Maxwells

23 testimony includes further discussion of residential

24 basic charges.

25 Q. Does this conclude your direct testimony in

1158

WWP-E-98-11 HESSING, K (Di) 9
04/23/99 Staff

1 this proceeding?

2 A. Yes, it does.

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

1159

WWP-E-98-11 HESSING, K (Di) 10
04/23/99 Staff

1 (The following proceedings were had in

2 open hearing.)

3 MR. WOODBURY: And I'd present Mr. Hessing

4 for cross-examination.

5 COMMISSIONER SMITH: Mr. Ward, do you have

6 questions for Mr. Hessing?

7 MR. WARD: No questions. Thank you.

8 COMMISSIONER SMITH: Mr. Shurtliff?

9 MR. SHURTLIFF: Yes, Madam Chairman.

10

11 CROSS-EXAMINATION

12

13 BY MR. SHURTLIFF:

14 Q Mr. Hessing, at pages 3 and 4 of your

15 direct testimony, you're talking about the cost of

16 service study performed in this case by Washington Water

17 Power, Avista. Starting at page 3 at line 24 you

18 indicate, "I believe that changes caused by changes in

19 cost of service methodology should be infrequent and need

20 to be justified." Is that another way of saying if it

21 ain't broke, don't fix it?

22 A Yes.

23 Q Now, what was broke in the cost of service

24 methodology used by Washington Water Power in the last

25 rate case?

1160

CSB REPORTING HESSING (X)
Wilder, Idaho 83676 Staff

1 A Well, I guess even if something isn't

2 broken, it may well be able to be improved and the

3 changes that are proposed by the Company in this case,

4 the two changes that Company witness Knox has already

5 discussed, appeared to me to be improvements in the way

6 that they did their cost of service study.

7 Q So you believe that the two major changes

8 that you've identified also on page 4 are justified and

9 are necessary to make a cost of service study in this

10 case appropriate?

11 A I believe that they're justified. I

12 believe that they improve the cost of service results.

13 Q In that regard, the two changes that you

14 indicated and you've identified them, you believe from

15 your professional expertise that it improves the cost of

16 service study to take into account the distribution --

17 well, the second change, the proposed change, is that

18 administrative and general costs be directly assigned to

19 functions where possible and that the remaining costs be

20 included with the distribution function and classified

21 40 percent to energy and 60 percent to customer, you

22 believe that reallocation to energy and customer is

23 justified and necessary?

24 A I do, especially the portion where the

25 costs that could be directly assigned were directly

1161

CSB REPORTING HESSING (X)
Wilder, Idaho 83676 Staff

1 assigned. Any time that that circumstance can be

2 identified, that's an improvement.

3 Q Well, in this case, what portion of the

4 allocation was identified and what portion is just

5 classified 40 percent to energy and 60 percent to

6 customer, do you know?

7 A I don't have those numbers right off the

8 top of my head, but I know that in the past methodology,

9 at least to the best of my recollection, it was all

10 allocated by another allocation factor and so to be able

11 to directly assign is an improvement.

12 Q The first change that you've indicated was

13 proposed is that distribution costs be classified to

14 demand and energy based on the basic customer method

15 instead of the minimum distribution system method, the

16 result of which is to increase the allocation to demand,

17 is it not, or to energy, I'm sorry?

18 A I believe it does increase the distribution

19 to energy.

20 Q And you believe that that's a necessary

21 improvement in a cost of service?

22 A I believe that it was an improvement in

23 this cost of service study. I believe that more of those

24 costs were energy related.

25 Q More than --

1162

CSB REPORTING HESSING (X)
Wilder, Idaho 83676 Staff

1 A More than the previous method, the minimum

2 distribution system method.

3 Q You indicate at line 22 on page 4, "These

4 changes," the two we've just talked about, "are

5 substantial and materially affect the results." What

6 results do they affect?

7 A They affect the results of the cost of

8 service methodology and the returns that the individual

9 classes have been shown to earn under that methodology.

10 They affect those percentage rates of return.

11 Q And you say that the changes were

12 substantial.

13 A They were and Ms. Knox has an exhibit in

14 her testimony that compares those changes to the

15 methodology that was used in the last case.

16 Q Would your characterization of substantial

17 apply to Schedule 25 results?

18 A As I recall, and I don't recall the exact

19 numbers right now, but the two changes that she has

20 proposed taken together are beneficial to Schedule 25

21 customers compared to the methodology of the last rate

22 case.

23 Q Which changes are substantial, then, that

24 affect any class negatively?

25 A I guess I would have to look at her exhibit

1163

CSB REPORTING HESSING (X)
Wilder, Idaho 83676 Staff

1 in order to tell you which classes that it affects

2 negatively, but it certainly does affect classes

3 negatively. I mean, you can't increase or decrease a

4 rate of return for one class without affecting and having

5 an offsetting increase or decrease to the other classes,

6 it just doesn't happen.

7 Q Finally, you indicate that one of the

8 reasons that you are willing to accept, I think, the

9 methodology changes is because the effects thereof are

10 ameliorated somewhat by only a partial move to what you

11 call cost of service and I think the Company called it

12 unity?

13 A Yes.

14 Q And in that regard, you said at page 6 at

15 lines 10 and 12, "A more aggressive move toward cost of

16 service would produce overwhelmingly large increases

17 which are unacceptable."

18 A Yes.

19 Q When do we get to an unacceptably,

20 overwhelmingly large move?

21 A Well, certainly, that's a judgment call. I

22 mean, you have to balance that against the cost of

23 service results. You have to balance that against the

24 positions of the different classes and how they're

25 affected. You're looking here mostly at those who have

1164

CSB REPORTING HESSING (X)
Wilder, Idaho 83676 Staff

1 increases as opposed to those who have decreases, but you

2 also have to consider the fact that -- well, I guess we

3 don't have any decreases, who have much smaller increases

4 than if they were moved to full cost of service, but you

5 do have to consider those, too, because there is a

6 subsidy on a cost of service basis when you do that.

7 Q Would you agree or disagree with the

8 proposition that what is an overwhelmingly large increase

9 which is acceptable is somewhat in the eye of the

10 beholder?

11 A Yes.

12 Q And there is nothing -- again, there's no

13 benchmark of what is an acceptably large increase?

14 A In my mind, there's no absolute number.

15 Q And so for the residential customer who is

16 on a fixed income, an increase might be less or more

17 overwhelmingly large and unacceptable than it would be to

18 someone who is not on a fixed income who just won the

19 lottery? The Power Ball, I think I saw it at 50 million

20 yesterday.

21 A Yes, I think what we saw in the comments

22 that were filed by many of the customers is that for

23 those who filed the comments, many of them felt that the

24 increase proposed by the Company, which was the one that

25 they mostly saw, they felt that it was a large increase

1165

CSB REPORTING HESSING (X)
Wilder, Idaho 83676 Staff

1 and it shouldn't be implemented.

2 Q So the circumstances of the beholder or the

3 payer of this increase, whatever it is, do those

4 circumstances play a part in what is a reasonable

5 allocation?

6 A I think they play a part.

7 Q And in your analysis and in your work, did

8 you factor in those considerations?

9 A Yes, I believe I did.

10 Q And you're satisfied that the proposal that

11 you came up with was fair and reasonable to all classes

12 of customers, I take it?

13 A Yes, and I really did believe that a full

14 move to cost of service would have been more difficult

15 for more people.

16 MR. SHURTLIFF: Thank you. I have nothing

17 further.

18 COMMISSIONER SMITH: Mr. Meyer.

19 MR. MEYER: I have no questions.

20 COMMISSIONER SMITH: How about from the

21 Commission?

22 Any redirect, Mr. Woodbury?

23 MR. WOODBURY: No redirect, no further

24 witnesses.

25 COMMISSIONER SMITH: Thank you very much

1166

CSB REPORTING HESSING (X)
Wilder, Idaho 83676 Staff

1 for your help, Mr. Hessing.

2 THE WITNESS: Thank you.

3 (The witness left the stand.)

4 COMMISSIONER SMITH: Mr. Ward, we're now

5 ready for your witness.

6 MR. WARD: We call Dr. Peseau to the

7 stand.

8

9 DENNIS E. PESEAU,

10 produced as a witness at the instance of Potlatch

11 Corporation, having been first duly sworn, was examined

12 and testified as follows:

13

14 DIRECT EXAMINATION

15

16 BY MR. WARD:

17 Q Would you please state your name and

18 address for the record?

19 A My name is Dennis E. Peseau, spelled

20 P-e-s-e-a-u.

21 Q And your business address?

22 A It's 1500 Liberty Street, S.E., Salem,

23 Oregon, 97302.

24 Q By whom are you employed and in what

25 capacity?

1167

CSB REPORTING PESEAU (Di)
Wilder, Idaho 83676 Potlatch

1 A I'm president of Utility Resources, Inc.

2 Q Thank you. Dr. Peseau, in preparation for

3 the proceeding -- well, let me do it this way: Did you

4 prepare testimony for this proceeding today?

5 A Yes, I did.

6 Q And before I ask you to adopt that, let me

7 ask you if you have any changes or corrections.

8 A Yes, I do. On page 14, line 17 --

9 Q Okay.

10 A -- the word "most" in that sentence has

11 caused some confusion. Apparently, some have taken it to

12 read that I'm recommending this as a result. If we

13 change the word "most" to "a" --

14 Q How about change "the most" to "a"?

15 A That's better yet.

16 Q Okay, the next change, please?

17 A Page 25, line 21, I've inadvertently

18 created a new acronym, there's a "DWIP," it should be

19 "CWIP."

20 Q Okay.

21 A I believe that concludes my corrections.

22 Q All right, if I asked you the questions

23 that are in your prepared testimony today, would your

24 answers be as given?

25 A Yes.

1168

CSB REPORTING PESEAU (Di)
Wilder, Idaho 83676 Potlatch

1 Q And did you also cause to be prepared a

2 number of exhibits consisting of Exhibits 201 through

3 209?

4 A That's correct.

5 MR. WARD: And with that, Madam Chair, I

6 request that the testimony be spread on the record as if

7 read and the exhibits be marked for identification. I'll

8 move them later.

9 COMMISSIONER SMITH: If there's no

10 objection, it is so ordered.

11 (The following prefiled testimony of

12 Dr. Dennis E. Peseau is spread upon the record.)

13

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1169

CSB REPORTING PESEAU (Di)
Wilder, Idaho 83676 Potlatch

1 Q PLEASE STATE YOUR NAME AND BUSINESS

2 ADDRESS.

3 A My name is Dennis E. Peseau. My business

4 address is 1500 Liberty Street, S.E., Suite 250, Salem,

5 Oregon 97302.

6 Q BY WHOM ARE YOU EMPLOYED AND IN WHAT

7 CAPACITY.

8 A I am the President of Utility Resources,

9 Inc., ("URI").

10 Q PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND

11 AND WORK EXPERIENCE.

12 A My resume is attached as Exhibit No. 201.

13 In addition, I have testified before the Idaho Public

14 Utilities Commission on various revenue requirement and

15 cost of service issues on numerous occasions since the

16 early 1980s.

17 Q FOR WHOM ARE YOU APPEARING IN THIS CASE?

18 A I am appearing on behalf of Potlatch

19 Corporation.

20 Q WHAT IS POTLATCH'S INTEREST IN THIS CASE?

21 A Potlatch's largest facility in terms of

22 energy consumption is the mill at Lewiston. This

23 facility is not affected by the present case because it

24 is served by Avista pursuant to a ten year contract.

25 However, Potlatch also has three other facilities in

1170

D. PESEAU Di 2
Potlatch Corporation

1 northern Idaho that are Schedule 25 Avista customers.

2 Q WHAT IS THE PURPOSE OF YOUR TESTIMONY?

3 A My testimony can be divided into three

4 general topics:

5 1. A discussion of the problems posed by

6 Avista's power marketing efforts and

7 the shortcomings of the Company's

8 attempt to allocate the costs and benefits

9 of secondary transactions.

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1171

D. PESEAU Di 2A
Potlatch Corporation

1 2. An examination of the revenue requirement

2 issues of depreciation, net power supply

3 costs, hydro relicensing costs,

4 amortization of ice storm costs, and

5 allowed rate of return.

6 3. Correction of Avista's cost of service

7 classification and allocation of

8 distribution costs, its demand allocators

9 for both generation and distribution costs,

10 the classification of transmission costs

11 and the allocation of conservation costs.

12 Q WHAT CONCLUSIONS HAVE YOU REACHED?

13 A I conclude that:

14 1. Avista's proposed treatment of secondary

15 transactions is unacceptable, and it raises

16 policy issues that the Commission should

17 address in some type of rulemaking

18 proceeding.

19 2. Avista's $14.2 million Idaho rate increase

20 request is overstated by approximately

21 $11.5 million.

22 3. Avista's cost of service analysis is flawed

23 and departs from previous Commission

24 positions. Correction of these flaws

25 demonstrates that Avista's Schedule 25

1172

D. PESEAU Di 3
Potlatch Corporation

1 customers are currently paying rates that

2 cover their cost of service.

3 REVENUE REQUIREMENT ISSUES

4 Off System Sales

5 Q LET'S BEGIN WITH THE OFF-SYSTEM SALES

6 ISSUE. WOULD YOU PLEASE EXPLAIN THIS ISSUE?

7 A In order to do so, I must begin with a

8 brief review of recent developments in the electric

9 utility industry. As the Commission is

10

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1173

D. PESEAU Di 3A
Potlatch Corporation

1 well aware, the latter half of the 1990s has been a

2 period of unprecedented change. On the federal level,

3 wholesale electric sales have been largely deregulated

4 and opened to competition. On the state level, electric

5 utility restructuring and retail competition have been

6 studied and debated in virtually every state, and adopted

7 in many. In the West, California, Nevada, and Montana

8 have enacted restructuring legislation and are in the

9 process of transitioning some portions of the old

10 electric utility monopolies to competitive markets.

11 Although restructuring legislation has not been adopted

12 in Idaho, the state's utilities, ratepayers and the Idaho

13 Public Utilities Commission have all been significantly

14 affected by this general transformation of the electric

15 utility industry.

16 Q HOW HAS IDAHO BEEN IMPACTED BY THESE

17 CHANGES IN THE ELECTRIC UTILITY INDUSTRY?

18 A In many ways, but one overriding impact is

19 crucially important here. Federal deregulation and the

20 development of competitive electricity markets in a

21 number of states has created entrepenurial opportunities

22 that were virtually non-existent only a few years ago.

23 Perhaps the most visible symbol of this new era is the

24 growing importance of energy traders and power marketers.

25 Some of these power marketers are utility affiliates, but

1174

D. PESEAU Di 4
Potlatch Corporation

1 others have neither retail customers nor energy

2 production resources of their own. The common

3 denominator is that all seek to earn a profit from the

4 buying and selling of energy or

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1175

D. PESEAU Di 4A
Potlatch Corporation

1 energy contracts in much the same way that similar

2 traders are employed in the more familiar commodities

3 markets.

4 Avista has chosen to enter this market with a

5 vengeance. In Exhibit No. 202, I have reproduced a table

6 entitled "Financial and Operating Highlights" from page 2

7 of Avista's 1998 Annual Report. There are a number of

8 interesting facts in this exhibit, but for the moment I

9 would like to concentrate on Avista's growth in revenues

10 and sales over the last three years. Line 1 of the

11 exhibit shows that total operating revenues have nearly

12 quadrupled from $944 million in 1996 to $3.68 billion in

13 1998, while operating expenses have also grown by roughly

14 commensurate amounts from $758 million in 1996 to $3.51

15 billion in 1998. But, as the exhibit's Operating Results

16 show, only the tiniest fraction of this growth was

17 attributable to increased retail sales of electricity and

18 natural gas, which amounted to $216 million and $193

19 million respectively in 1998.

20 Q IF RETAIL SALES INCREASES WERE

21 INSIGNIFICANT, WHAT CAUSED THIS REMARKABLE GROWTH IN

22 OPERATING REVENUES?

23 A Avista's increased operating revenues and

24 expenses are almost entirely attributable to its power

25 marketing endeavors. The majority of these transactions

1176

D. PESEAU Di 5
Potlatch Corporation

1 occur under the auspices of Avista Corp's National Energy

2 Trading and Marketing line of business, which is in turn

3 comprised of subsidiaries Avista Energy, Avista Advantage

4 and Avista Power.

5

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1177

D. PESEAU Di 5A
Potlatch Corporation

1 Revenues from this unregulated endeavor have grown in

2 spectacular fashion, from $116 million in 1996 to $2.4

3 billion in 1998.

4 But the Company's power marketing

5 activities are not confined to unregulated affiliates.

6 Avista Corp's Generation and Resources line of business

7 manages Avista's utilities resources portfolio for both

8 retail and wholesale sales. It also engages in both

9 short term and long term electric and natural gas trading

10 and marketing, primarily to other utilities and power

11 brokers within the Western Systems Coordinating Council.

12 From 1996 through 1998, Generation and Resources'

13 revenues increased by more than 50%, from $418 million to

14 $639 million.

15 Q WHAT CONCLUSIONS DO YOU DRAW FROM THIS

16 DATA?

17 A The most obvious is that Avista is

18 transforming itself into a very different company than it

19 was in the early years of this decade. This point can be

20 illustrated by comparing the relative sales from the

21 Company's different divisions over the last three years.

22 In 1996, Generation and Resources was already the largest

23 contributor to total sales, but retail electricity and

24 natural gas sales still ranked second and third among the

25 Company's business lines:

1178

D. PESEAU Di 6
Potlatch Corporation

1 1996

2 Revenues (000s) KWH(millions)

3 Generation & Resources $418,566 11,175

4 Retail Electric $209,117 7,771

5 Retail Gas $171,311 ----

6 Non-energy $145,857 ----

7 National Trading $116 N/A

8 By 1998, this relative ranking changed

9 dramatically, with National Trading and Generation and

10 Resources accounting for roughly 9 times as many kwhs

11 sold as the retail division:

12 1998

13 Revenues (000s) KWH(millions)

14 National Trading $2,409,920 54,430

15 Generation & Resources $639,529 19,215

16 Non-energy $232,292 ----

17 Retail Electric $216,545 7,944

18 Retail Gas $193,138 ----

19 Q ARE YOU SUGGESTING THAT NATIONAL TRADING IS

20 NOW THE MOST IMPORTANT SEGMENT OF AVISTA'S BUSINESS?

21 A No. In any business, the first

22 consideration is profitability. In terms of relative

23 contribution to the bottom line, retail sales are still

24 the most important segment of the Company's business. On

25 page 19 of Appendix A to Avista's 1998 Annual Report,

1179

D. PESEAU Di 7
Potlatch Corporation

1 pre-tax profits are broken out by business line as

2 follows:

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1180

D. PESEAU Di 7A
Potlatch Corporation

1 1998 1997 1996

2 Energy Delivery $116,944 $113,745 $89,447

3 Generation & Resources $26,209 $64,613 $84,211

4 National Trading $19,922 $2,191 ($1,801)

5 Non-energy $9,745 $8,984 $15,064

6 Total $172,820 $189,464 $186,921

7 There is no readily identifiable trend in this

8 data, other than the continued importance of retail

9 sales.

10 Q THIS IS ALL VERY INTERESTING, BUT WHAT DOES

11 IT HAVE TO DO WITH THIS RATE CASE?

12 A Avista is obviously evolving from a

13 traditional fully regulated utility to a business with

14 one foot in the regulated world and the other in the

15 competitive marketplace. From the regulatory viewpoint,

16 this trend has to be viewed with some apprehension

17 because of the unique challenges it poses for rate of

18 return ratemaking. Among other things, this type of

19 transition introduces a whole new set of financial and

20 business risks for the utility. But the most important

21 of these challenges is the difficult problem of how to

22 deal with the increased revenues and expenses generated

23 by power marketing efforts.

24 Q WHY IS THIS SUCH A DIFFICULT ISSUE?

25 A In order to answer that question I must

1181

D. PESEAU Di 8
Potlatch Corporation

1 provide one more piece of background information.

2 Wholesale electricity sales are not a new phenomenon.

3 Utilities have always bought and sold on the secondary

4 market to balance loads and resources and to take

5 advantage of

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1182

D. PESEAU Di 8A
Potlatch Corporation

1 attractive market conditions. Secondary purchases are

2 typically designed either to supplement a company's

3 existing resources until load growth is sufficient to

4 justify the addition of a new large baseload plant, or to

5 take advantage of prices that are below the variable

6 operating costs of its own generating plants.

7 Conversely, secondary sales are made primarily to

8 minimize resource surpluses immediately following the

9 construction of new plants or, in the Northwest in

10 particular, to take advantage of surplus hydroelectric

11 generation.

12 Ordinarily, the costs and benefits of these

13 secondary purchases and sales are passed through to

14 retail ratepayers as an adjustment to jurisdictional

15 revenues and expenses. The rationale is that, in the

16 case of secondary sales, the ratepayers paid for the

17 plants that make the sales possible, while in the case of

18 purchases it is retail demand that made the purchases

19 necessary.

20 Of course, nothing in regulation is ever as

21 simple as this brief explanation implies, and this maxim

22 holds true for the treatment of secondary sales as well.

23 Actual test year secondary transactions are typically

24 adjusted for pro forma changes in contract terms and

25 prices and to normalize for weather and hydroelectric

1183

D. PESEAU Di 9
Potlatch Corporation

1 conditions. This normalization process is generally

2 accomplished using a Power Supply Model. The model uses

3 multiple years of recorded weather and hydro conditions

4 to predict loads and resources and, ultimately, the

5 revenues and expenses associated with serving both retail

6 and secondary loads under normal conditions.

7

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1184

D. PESEAU Di 9A
Potlatch Corporation

1 Q WITH THIS BACKGROUND IN PLACE, LET ME ASK

2 YOU AGAIN; WHAT DOES THIS HAVE TO DO WITH THE PRESENT

3 CASE?

4 A In the present case, Avista is obviously

5 buying and selling quantities of power that are many

6 times as large as the capacity of its own resources and

7 its retail load. A significant portion of these

8 transactions during the test year were conducted by the

9 National Energy Trading and Marketing division, which is

10 now a separate subsidiary. These sales present possible

11 cost allocation problems, but they are not insurmountable

12 if the books are properly kept and the trades are not

13 dependent on use of utility resources.

14 The difficult question is how to deal with

15 the massive off system purchases and sales by the utility

16 itself. As Mr. Norwood notes in his testimony, the

17 utility's 1997 test year sales were nearly 1.5 times the

18 size of its retail load. If we followed traditional

19 ratemaking principles, the benefits of all these off

20 system transactions would flow solely to the ratepayers.

21 But in this case Avista takes the position that short

22 term purchases and sales should be excluded from 1997 pro

23 forma results because, "The majority of these short-term

24 purchase and sale transactions were for speculative

25 purposes," and the risks and benefits associated with

1185

D. PESEAU Di 10
Potlatch Corporation

1 these transactions should therefore reside with the

2 shareholders and "be excluded from the retail ratemaking

3 process." Norwood Testimony at 17 and 19.

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1186

D. PESEAU Di 10A
Potlatch Corporation

1 Q WOULDN'T YOU AGREE THAT THE COMPANY SHOULD

2 BE ENTITLED TO REAP THE REWARDS OF THESE SALES IF IT BORE

3 THE RISKS?

4 A The argument has some validity, but let me

5 point out the problems with it. First, short term sales

6 are not inherently speculative, as the Company's

7 testimony suggests. Secondary purchases and sales have

8 almost always included short term transactions that were

9 nevertheless credited to ratepayers. Secondly, the

10 question of who bears the gain or loss on a transaction

11 is not the whole story. The other questions are who was

12 entitled to seize this opportunity and who facilitated

13 the transaction? Arguably the trading opportunity

14 belonged to the ratepayers in the first instance, and it

15 seems irrefutably true that if a particular transaction

16 relied either in whole or in part on the utility's

17 resources, then the ratepayers have a legitimate claim to

18 at least a portion of the proceeds.

19 These considerations are important, but the

20 insurmountable objection to Avista's argument is its

21 tardy nature. At this late date, it is virtually

22 impossible to tell in retrospect which secondary

23 transactions were actually associated with retail loads

24 and which were purely speculative. In 1997, Avista knew

25 full well that a utility's secondary transactions

1187

D. PESEAU Di 11
Potlatch Corporation

1 ordinarily belong to the ratepayers. If it wanted to

2 change this rule, it was incumbent upon the Company to

3 make that proposal in a timely fashion so that the

4 Commission could establish proper safeguards to insure

5 protection of the ratepayers.

6

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1188

D. PESEAU Di 11A
Potlatch Corporation

1 It is very difficult to accept at face value the

2 utility's claim that it shouldered the full risk and is

3 therefore entitled to the profits of these transaction

4 when that claim is made after the fact. It is as if a

5 stockbroker traded on a customer's account and then at

6 the end of the year claimed that 90% of the transactions

7 were for the broker's benefit. This subsequent reckoning

8 at the end of the year might be conducted with rigorous

9 honesty, but the potential for self dealing and other

10 mischief would be sufficient to persuade most of us to

11 take our business elsewhere.

12 Q ARE THERE ALSO PRACTICAL PROBLEMS WITH

13 MR. NORWOOD'S PROPOSED ADJUSTMENT?

14 A Yes. As I just pointed out, it is

15 virtually impossible to separate speculative short term

16 transactions from system short term transactions after

17 the fact. Even if we could somehow unscramble the

18 omelette, we could never be sure that the utility didn't

19 advantage itself by claiming the most profitable

20 opportunities for its shareholders at the ratepayers'

21 expense. Mr. Norwood's proposed solution to this problem

22 is to simply substitute the power supply models predicted

23 short term transaction for actual figures. The implicit

24 suggestion is that ratepayers cannot be harmed if they

25 are simply paying the "normal" cost of these

1189

D. PESEAU Di 12
Potlatch Corporation

1 transactions.

2 Q IS THIS A SATISFACTORY SOLUTION?

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1190

D. PESEAU Di 12A
Potlatch Corporation

1 A No, it is not. In the first place, it puts

2 the model to a use that was not intended and it forces it

3 to accommodate a huge adjustment that was not

4 contemplated by the designers.

5 Q WHAT DO YOU MEAN BY A HUGE ADJUSTMENT?

6 A Referring to Avista Exhibit No. 6, actual

7 1997 short-term purchases of $191.1 million are adjusted

8 to a test year pro forma figure of $16.3 million and

9 actual 1997 short-term sales of $192.4 million are

10 reduced to $9.7 million. These two adjustments turn a

11 modest actual profit into a pro forma loss of $6.6

12 million. In each instance, the adjustment necessary to

13 reduce actual expenses and sales to the test year

14 proposed levels is 10-20 times the pro forma figures.

15 Adjustments of this magnitude are inherently suspect, and

16 this is doubly true when they greatly exceed the

17 parameters the model was built to handle. Under the very

18 best hydro and other conditions in the power supply

19 model, it can never predict more than $18 million in

20 resale sales and $39.7 million in short-term purchases.

21 Therefore, we cannot simply assume that the power supply

22 model is adequate to make adjustments of the size

23 proposed.

24 There is also a more fundamental flaw with

25 Avista's suggestion that the power supply model can

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1 adequately predict normalized revenues and expenses in

2 this situation. The model was built to estimate

3 financial results under very different conditions than

4 those existing today. It is predicated on the old world

5 of regulated wholesale and retail transactions, and it is

6 therefore not a reliable indicator of

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1 today's situation of wide open markets with many players.

2 Consequently, a model that replicated a bygone era can't

3 answer the question of how we deal with the unprecedented

4 issue raised by Avista's filing. For all we know, 1997's

5 new market opportunities might have generated wildly

6 different results from those predicted by the model, even

7 in the absence of speculative trading by the utility.

8 Q DO YOU HAVE A PROPOSED SOLUTION AT THIS

9 POINT?

10 A In my view, Avista has not met its burden

11 of proof in justifying the exclusion of short-term

12 purchases and sales. At this point, there is truly no

13 exact means to allocate these transactions between

14 ratepayers and shareholders or even determine what

15 portion of the huge amounts of these purchases and sales

16 was due to excellent hydro conditions and what portion

17 represented new market opportunities.

18 The best estimate we can come up with is

19 that approximately 10% of these transactions are due to

20 hydro and 90% to market opportunities. If the Commission

21 decides to reverse the entirety of Avista's adjustment, a

22 reasonable procedure would be to adjust the test year pro

23 forma to include 90% of actual 1997 short-term sales and

24 purchases.

25 Q IS IT POSSIBLE THAT IN SOME PERIODS THIS

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1 ADJUSTMENT WOULD BE NEGATIVE, THAT IS, RAISE CUSTOMER

2 RATES?

3 A Yes, this is possible, although not in this

4 test year.

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1 Q IS THERE ANY OTHER APPROPRIATE ADJUSTMENT

2 TO AT LEAST COMPENSATE RATEPAYERS FOR PARTIALLY

3 UNDERWRITING THESE MARKET TRANSACTIONS?

4 A Yes. The root of the concern here is that

5 the Generation and Resources department has been able to

6 develop short-term sales and transactions that now

7 exceeds 1.5 times Avista's retail loads. This has been

8 possible because the Generation and Resources department

9 has been underwritten by retail customers, because the

10 Water Power and now Avista name and logo have been used,

11 and because the entire corporate structure and overhead

12 has been used. An interim and reasonable adjustment

13 would be to allocate an additional portion of the

14 corporate overhead and A & G expenses as well as general

15 plant rate base to the speculative transactions. These

16 costs are contained in the exhibit of Tara Knox. As she

17 explains, 40% of these costs are energy related, 60% are

18 customer related.

19 Q HOW CAN THESE OVERHEAD EXPENSES BE FAIRLY

20 APPORTIONED TO THE REGULATED AND MARKETING ACTIVITIES?

21 A Ms. Knox currently proposes to charge all

22 of the energy-related expenses only to ratepayers. The

23 common sense adjustment here would be to simply include

24 both regulated sales (with a weight of 1) and

25 nonregulated sales (with a weight of 1.5) in which to

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1 allocate these energy-related overhead costs. My Exhibit

2 203 makes these

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1 allocations. The net result is to lower the requested

2 regulated revenue requirement by $3.9 million.

3 Q DO YOU HAVE ANY OTHER RECOMMENDATIONS ON

4 THIS ISSUE?

5 A We must also consider the need for a long

6 term resolution of this problem. In other jurisdictions

7 where such activities are undertaken by the utility, the

8 utility is either required to divest itself of all its

9 generating assets, or it is required to establish

10 affiliates that are structurally separated from

11 potentially anti-competitive associations. Divestiture

12 hardly seems like a good idea for Avista's low cost

13 system. Therefore, I recommend that this Commission

14 immediately consider a formal rulemaking or similar

15 process whereby parties may work this problem out.

16 Depreciation Issues

17 Q WHAT CHANGES IS AVISTA REQUESTING WITH

18 RESPECT TO DEPRECIATION?

19 A As explained on pages 22-24 of

20 Mr. Falkner's testimony, and elsewhere, Avista is seeking

21 approval of new, higher depreciation rates on its plant

22 in service, thereby increasing its annual noncash

23 expenses by approximately $2.4 million.

24 Q DO YOU AGREE WITH AVISTA'S PROPOSAL TO

25 INCREASE ITS DEPRECIATION RATE?

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1 A No. We must keep in mind that the request

2 is merely to change accounting to increase Avista's cash

3 flow. None of the categories of

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1 plant in service listed on Page 23 of Mr. Falkner's

2 testimony has in any way had their performance, economic

3 value or other attributes changed. Avista has not, and

4 will not, incur any different real cash expense

5 obligations as a result of its depreciation study. The

6 Company simply wants to raise rates to recover its

7 original plant investment sooner to increase today's

8 shareholders' profit.

9 Q ARE THERE FACTUAL REASONS WHY YOU RECOMMEND

10 THAT AVISTA'S PLANT DEPRECIATION RATES NOT BE RAISED AT

11 THIS TIME?

12 A Yes, there are at least two reasons.

13 First, there is ample evidence that electric utilities

14 throughout the U.S. have had excessively high

15 depreciation rates over the past several years. This is

16 evidenced by the fact that virtually all sales of utility

17 assets in preparation for open markets are being made at

18 significant multiples of the regulated book value of

19 these assets. The only possible conclusion is that

20 depreciation on these assets has been excessive, leaving

21 a book value far below market value.

22 Second, a comparison of Avista's present

23 depreciation rates with other utilities shows Avista's

24 rates to be comparable, or on the high end of comparable,

25 for all major accounts except distribution plant.

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1 Q PLEASE EXPAND ON YOUR POSITION THAT

2 ELECTRIC UTILITY DEPRECIATION RATES HAVE BEEN TOO HIGH.

3 A My firm has been active in various utility

4 merger proceedings and in major electric market

5 restructuring efforts in the West. These

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1 proceedings often involve voluntary or involuntary

2 divestiture of generation and other assets. A good test

3 of proper depreciation rates and levels is to compare the

4 market value of these assets, as measured by sale price,

5 to the depreciated book value of these assets.

6 To pick but one of several examples, a merger

7 proceeding in the state of Nevada has been concluded

8 recently between Sierra Pacific Resources and Nevada

9 Power Company. The utilities voluntarily agreed to

10 divest themselves of all generation resources and certain

11 other assets as part of merger. In doing so, the merging

12 utilities retained financial institutions to conduct

13 studies of the valuation of their plants and other

14 utilities' generating assets. My Exhibit 204 is a copy

15 of an exhibit, sponsored by Nevada Power and Sierra

16 Pacific, in that recent merger filing. This exhibit was

17 used to support the companies' claim that their expected

18 proceeds from the sale of generating units would be

19 approximately two times book value. With market values

20 so far above the book values of these assets, it is

21 wholly unjustified to seek even higher depreciation

22 rates, as Avista is doing.

23 Q HAVE OTHERS ALSO RECOGNIZED THE FACT THAT

24 UTILITIES' DEPRECIATION RATES HAVE BEEN TOO HIGH?

25 A Yes, at least for generation or production

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1 plant. For example, an article by J.G. Campbell and

2 M.J. Majores in Public Utilities Fortnightly, April 1,

3 1999 examines this issue in detail. I attach the article

4 as my Exhibit 205.

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1 Q HOW DO AVISTA'S PRESENT DEPRECIATION RATES

2 COMPARE WITH OTHER UTILITIES?

3 A In general, they are as high or higher than

4 other regional utilities. My firm recently participated

5 in such studies for another regional utility. This study

6 included a review of an Edison Electrical Institute

7 survey of U.S. electric utility depreciation rates, dated

8 1996-97. Unfortunately, the EEI study itself is

9 proprietary to nonmembers.

10 With the exception of distribution plant,

11 Avista's present depreciation rates are as high or higher

12 than most other western utilities. Avista's request to

13 increase its already very high general plant depreciation

14 rates of 6.00% to 12.24% is entirely excessive.

15 Q FROM YOUR ANALYSIS, WHAT DO YOU RECOMMEND

16 WITH RESPECT TO AVISTA'S REQUEST TO RAISE ITS

17 DEPRECIATION RATES?

18 A I recommend that all of Avista's requested

19 depreciation rate increases be denied, with the exception

20 of that for distribution plant. The financial effects of

21 Avista's requests are shown on Avista Exhibit No. 11,

22 Page 8 of 8.

23 Q WHAT IMPACT ON REVENUE REQUIREMENT DOES

24 YOUR RECOMMENDATION HAVE?

25 A The Company's request results in an

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1 approximate $2.4 million revenue increase. By approving

2 only the increase in the proposed depreciation rate for

3 distribution plant, the revenue increase is reduced to

4 approximately $300,00.

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1 Normalized Net Power Supply Costs

2 Q WHAT ISSUES DO YOU HAVE RESPECTING AVISTA'S

3 CALCULATION OF NORMALIZED NET POWER SUPPLY COSTS?

4 A In order to normalize net power supply

5 costs for hydro conditions, it is common to run a power

6 supply model over a number of historically experienced

7 hydro conditions, compute power costs under each, and

8 average them to come up with so-called normal conditions.

9 Presumably, this averaging process provides the best

10 prediction as to a test year level of power costs that

11 should be experienced.

12 I take exception to the means by which Avista

13 computes this simple average of annual power costs, as it

14 happens to produce the highest possible figure for test

15 year net power supply expenses.

16 Q BUT ISN'T AN AVERAGE JUST THAT, A SIMPLE

17 AVERAGE?

18 A No, not in this case. The purpose of the

19 whole power cost modeling exercise is to predict likely

20 power costs under normal conditions. The average

21 computed within the power cost model is sensitive to the

22 time period chosen and the number of years included in

23 the average. By selectively choosing these time periods

24 and number of years in the average, one can raise or

25 lower test year power cost estimates.

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1 Q WHY IS THIS?

2 A As we know, water conditions can vary

3 significantly from year to year. By selecting periods of

4 prolonged drought or precipitation, a bias in the average

5 can occur. Additionally, a considerable body of

6 literature in the Pacific Northwest has concluded that

7 there are distinct weather

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1 cycles that are important to take into account in

2 predicting future hydro conditions. Each of these

3 factors make power supply modeling more than a simple

4 process of computing an average.

5 Q WHY DO YOU TAKE EXCEPTION TO AVISTA'S

6 METHOD OF AVERAGING ANNUAL POWER COSTS?

7 A As explained in Mr. Norwood's testimony and

8 workpapers, Avista's test year net power supply expense

9 estimate is an average of sixty years of power costs from

10 the water years 1927-28 through 1987-88. The problem I

11 have is that in reviewing all the power cost data, it

12 appears that Avista's choice of the sixty year period

13 ending in 1988 produces a higher test year power cost

14 estimate than any recent subperiod within the sixty years

15 of data. That is, fifty year, forty year, thirty year

16 and twenty year averages all produce lower test year net

17 power supply expense estimates than Avista's sixty year

18 average.

19 Q PLEASE EXPLAIN THE RELATIONSHIP BETWEEN

20 THESE AVERAGES AND THEIR CORRESPONDING POWER COST

21 ESTIMATE.

22 A The following are the net power supply

23 expense estimates for different averages ending in water

24 year 1987-88 as compared to Avista's. Details of these

25 calculations are provided in my Exhibit 206.

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1 No. Of Years Difference from Avista's Request

2 (Million $)

3 60 -

4 50 (2.5)

5 40 (5.5)

6 30 (4.9)

7 20 (2.2)

8 As is readily apparent, estimates for test year net power

9 supply expenses drop dramatically as recent shorter

10 period averages are computed. The table above indicates

11 that, had Avista used any of the more recent time period

12 averages, its requested net power supply expenses would

13 have been lower by $2.2 million to $5.5 million per year.

14 Avista's proposed 60 year average is likewise

15 inconsistent with longer periods. While Avista's data

16 goes back only sixty years, we were able to estimate net

17 power supply expenses based on the longest available

18 record, 1880-1998. As shown on my Exhibit 206, this

19 longer water record still produces an average net power

20 supply estimate of test year expenses that is $3.4

21 million below that requested by Avista.

22 Q IT SEEMS OBVIOUS THAT LONGER PERIODS WOULD

23 PROVIDE MORE DATA POINTS AND THEREFORE MORE RELIABLE

24 RESULTS. HOW DO YOU EXPLAIN THIS INCONGRUITY?

25 A Recent studies have identified significant

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1 cycles in precipitation in the Pacific Northwest. These

2 cycles appear to occur roughly every thirty

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1 years. In fact, a study conducted by Alan Hamlet, which

2 I attach as Exhibit 207 concludes that the 1990s may be

3 the start of another wet cycle.

4 If no cycles exist in weather or precipitation,

5 then an argument can be made for using the longest of

6 periods in the power cost averages. But the existence of

7 shorter-term weather cycles argues for use of

8 shorter-term averages that appear to be more

9 representative of normal conditions.

10 Q HAS THIS COMMISSION PREVIOUSLY RECOGNIZED

11 THE EXISTENCE OF SHORTER-TERM CYCLES IN DETERMINING THE

12 NUMBER OF YEARS TO INCLUDE IN AVERAGES USED TO PREDICT

13 POWER COSTS?

14 A Yes. In the Idaho Power general rate case

15 No. 265 this same issue was analyzed in great detail.

16 After considerable debate, often based on very technical

17 statistical analysis, the Commission determined 20-25

18 year averages were best for estimating test year net

19 power supply expenses.

20 Q WHAT PERIODS DO OTHER AGENCIES USE?

21 A Bonneville Power Administration, in making

22 comparisons of present water conditions to "average,"

23 uses a thirty year most recent period.

24 Q DO BOTH AVISTA AND IDAHO POWER COMPANY HAVE

25 POWER COST ADJUSTMENT MECHANISMS IN PLACE?
A Yes.
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1 Q GIVEN THIS, WHY IS IT IMPORTANT TO USE SO

2 MUCH CARE IN SETTING NET POWER SUPPLY EXPENSES?

3 A First, test years established in general

4 rate cases should, as a matter of course, always be based

5 on the most accurate data possible. Additionally, for

6 Avista as well as Idaho Power, 100% of power cost

7 expenses are not collected or passed through. This

8 circumstance provides a systematic reward or loss to

9 shareholders or customers if a consistent bias in the

10 base power cost estimates exists. Finally, we must keep

11 in mind that the PCA may someday be eliminated, in which

12 case the choice of an appropriate number of water years

13 would become even more important than it is now.

14 Q AFTER REVIEWING THE VARIOUS TEST YEAR

15 ESTIMATES IN YOUR EXHIBIT 206, WHAT LEVEL OF TEST YEAR

16 NET POWER SUPPLY EXPENSES DO YOU PROPOSE THAT THE

17 COMMISSION ADOPT IN THIS PROCEEDING?

18 A I recommend the adoption of net power

19 supply expenses of $37,088,000 as opposed to Avista's

20 proposed $42 million. My recommendation is based on the

21 use of a 30 year average. My recommendation results in a

22 reduction of Avista's revenues of $1.6 million per year

23 for the Idaho jurisdiction.

24 Clark Fork Relicensing Costs

25 Q WHAT IS THE ISSUE WITH RESPECT TO AVISTA'S
REQUEST TO INCREASE REVENUES TO COLLECT APPROXIMATELY $2
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1 MILLION PER YEAR FOR EXPENSES AND RETURN INCURRED IN THE

2 EFFORT TO RELICENSE THE CLARK FORK PROJECTS?

3 A Mr. Falkner, at pages 26-30 of his

4 testimony, gives a detailed discussion of the processes

5 that Avista went through to date in this relicensing

6 effort. As I understand Mr. Falkner's testimony, the

7 relicensing effort to date may streamline the process at

8 FERC, hopefully reducing total costs of this effort if

9 the license is granted. The issue I raise now is not one

10 of prudency.

11 The problem I have is that Avista's proposal

12 causes a mismatch of costs and benefits between present

13 and future ratepayers. Ratepayers are now paying for the

14 current costs of operating and maintaining the Clark Fork

15 projects. Avista is asking present ratepayers to pay

16 additionally for something they may never benefit from.

17 There are no assurances that a present ratepayer will

18 still be a customer after 2001 when the benefits of this

19 low cost hydro are distributed.

20 A related problem is that Avista is in a very real

21 sense asking this Commission to approve putting the

22 equivalent of construction work in progress into rate

23 base. That is, it wants to collect today and put into

24 rate base today something that FERC may or may not do

25 (relicense) in 2001. My understanding is that the

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1 inclusion of CWIP in rate base is forbidden by Idaho

2 statutes.

3 Q WHAT DO YOU RECOMMEND?

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1 A Avista should of course continue the

2 relicensing process. The costs and, presumably, AFUDC

3 could continue to be accounted for. If and when the

4 license goes into effect in 2001, the expenses and rate

5 base can be properly recovered.

6 Ice Storm Costs

7 Q PLEASE EXPLAIN THE "ICE STORM" ISSUE?

8 A In 1996, Avista's Washington and Idaho

9 system experienced an ice storm of unusual severity. The

10 result was that Avista incurred costs over and above its

11 insurance recovery. Avista now requests a six year

12 amortization of these unrecovered costs, arguing that

13 this amortization is essentially a surrogate for similar

14 extraordinary costs that can be expected to occur every

15 six years. Avista's proposed adjustment adds

16 approximately $125,000 to its test year revenue

17 requirement.

18 Q IS THIS ADJUSTMENT REASONABLE?

19 A No. One of the bedrock principles of

20 regulation is that retroactive ratemaking is absolutely

21 forbidden. The regulator's task is to establish rates

22 that will give the utility a fair opportunity to earn a

23 reasonable return on its investment. But this

24 opportunity is not a guarantee. Regulation also

25 recognizes that a utility is ultimately a business,

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1 subject to most of the risks that all businesses face.

2 Thus, skill or chance may produce a greater or lesser

3 return than the ratemaker's target.

4 It is unfortunate that the ice storm hurt both

5 Avista and its customers in 1996. But that does not

6 justify a regulatory attempt to

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1 make Avista whole for an event that occurred in the past.

2 Even if it did, what justification is there for Avista's

3 proposed six year amortization of its uninsured losses?

4 This is clearly a completely arbitrary time period. If

5 Avista really knew that such an event would occur every

6 six years on average, it would simply insure against this

7 eventuality.

8 Perhaps the best way to drive this point home is

9 to look at Avista's actual results in the 1997 test year.

10 The Commission will perhaps be astonished to learn that

11 Avista actually earned a 15% return on total company

12 equity in the year in which it is claiming a revenue

13 deficiency. Why? In part because Avista booked to

14 income an income tax recovery that increased earnings

15 $.49 per share. Avista quite properly excluded this

16 unusual event from its normalized test year just as the

17 ice storm damage should be excluded. But, if Avista is

18 allowed to recover for extraordinary storm damage that

19 occurred prior to the test year, how can we justify the

20 exclusion of a similarly extraordinary revenue incident

21 that at least occurred in the test year?

22 The whole point here is that the ice storm was

23 either bad luck or bad insurance risk management,

24 probably the former. But it is not the regulator's job

25 to repair the vagaries of fate. If it were otherwise, we

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1 would simply dispense with pretense and guarantee the

2 utility a rate of return regardless of luck, business

3 conditions and the capabilities or ineptness of

4 management. This is not what the law envisions, and it

5 would be a poor public policy choice.

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1 Rate of Return

2 Q WHAT ISSUES DO YOU ADDRESS WITH RESPECT TO

3 AVISTA'S REQUESTED ALLOWED RATE OF RETURN OF 9.446%?

4 A My testimony on this issue is limited

5 primarily to the Company's request for a 12.0% return on

6 equity. In this regard, my analysis is confined to

7 noting the equity return allowed WWP in the 1986 rate

8 case compared to debt costs at that time. The debt to

9 equity cost relationships at that time are then compared

10 to present debt costs and interest rates today in an

11 effort to identify a range of reasonable equity returns

12 that the Commission might grant to Avista in the

13 proceeding.

14 Q ARE YOU AWARE THIS COMMISSION HAS IN THE

15 PAST CONSIDERED EQUITY RETURN METHODS SUCH AS THE

16 DISCOUNTED CASH FLOW ("DCF"), RISK-PREMIUM, CAPITAL ASSET

17 PRICING AND COMPARABLE EARNINGS METHODS?

18 A Yes, and I expect Staff to present an

19 analysis using some or all of these techniques. The

20 purpose of my analysis is simply to note the dramatic

21 drop in the cost of both equity and debt since 1986 and

22 to suggest a range of equity returns that are reasonable.

23 Q DURING THE MONTHS LEADING UP TO SEPTEMBER

24 1986, WHAT WERE THE PREVAILING LEVELS OF INTEREST RATES?

25 A To answer this question, I referred to

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1 interest rates on 30 year Treasury Bonds as reported by

2 the Federal Reserve Board. In the twelve months prior to

3 September 1986, interest rates ranged from a high of

4 10.5% in October, 1985 to a low of 7.27% in July, 1986.

5 In the

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1 eight months ending September 1986, the monthly measures

2 of interest rates were all below 9%. In my opinion, a

3 fair estimate of prevailing interest rates at that time

4 is 7.5% to 8.0%. This compares to an allowed rate of

5 return on equity of approximately 12.9%.

6 Q WHAT IS THE LEVEL OF COMPARABLE INTEREST

7 RATES TODAY?

8 A From both the Federal Reserve Board data

9 and the Wall Street Journal, comparable interest rates

10 today are 5.5%, or 200 to 250 basis points below the

11 September 1986 levels.

12 Q WHAT IMPLICATIONS FROM THE REDUCTION IN

13 INTEREST RATES DO YOU DRAW FOR A REASONABLE RETURN ON

14 EQUITY FOR AVISTA?

15 A While I am aware that the spreads between

16 interest rates and equity returns need not be exactly

17 constant over time, I nonetheless suggest that the

18 200-250 basis point change in interest rates from

19 September 1986 to the present should provide a reasonable

20 estimate of the possible change in required equity

21 returns over the same period.

22 Q PLEASE EXPLAIN.

23 A The point is simple: costs or returns on

24 debt and equity tend to move together unless the risk

25 attendant with either changes dramatically. Since this

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1 is not the case for Avista, I propose to deduct 200-250

2 basis points from the 12.9% rate of return on equity

3 previously allowed. This results in a range of allowed

4 equity returns of 10.4-10.9%. My Exhibit 208 shows that

5 the revenue change from the 10.4% to 10.9%

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1 return compared to Avista's requested equity return of

2 12%, is a reduction of $2.368 million to $3.383 million.

3 Q PLEASE SUMMARIZE YOUR PROPOSED REVENUE

4 REQUIREMENT ADJUSTMENTS.

5 A The revenue requirement adjustments I

6 recommend are:

7 Millions $

8 Short-term Sales/Purchases (3.9)

9 Depreciation Rates (2.1)

10 No. Water Years in Average (1.6)

11 Clark Fork Relicense (1.4)

12 Ice Storm (.125)

13 Rate of Return (2.4)

14 COST OF SERVICE AND RATE DESIGN ISSUES

15 Q WHAT IS THE GENERAL OBJECTIVE OF COST OF

16 SERVICE STUDIES?

17 A The process of cost of service studies is

18 to first break utilities' total costs (revenue

19 requirement) into functions -- production, transmission

20 and distribution. Within each of these functions, the

21 costs are further classified into demand, energy and

22 customer components. Finally, the costs are allocated to

23 various customer classes. The ultimate goal, in my

24 opinion, is to charge various customers -- residential,

25 commercial and industrial -- rates that reflect the cost

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1 each imposes on Avista.

2 Q ARE COST OF SERVICE STUDIES AN EXACT

3 SCIENCE?

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1 A Not really. There is, of course, a natural

2 friction among different rate classes because each wants

3 to pay the lowest possible power bills. This can lead to

4 "subsidies" where some classes are paying above their

5 respective cost of services while some are paying below.

6 Unfortunately, there is some "art" as well as economic

7 principles in cost of service studies. My fear is that

8 Avista has offered us a study that leans too far toward

9 the "art" that has evolved in the State of Washington.

10 Q WHAT GENERAL CONCERNS DO YOU HAVE WITH THE

11 COST OF SERVICE STUDY PROPOSED BY AVISTA IN THIS

12 PROCEEDING?

13 A In general, Avista's cost of service study

14 introduces a number of procedures for classifying and

15 allocating costs to customer classes that promote

16 subsidies between rate classes. In particular, Avista

17 proposes to classify and allocate distribution,

18 transmission and generation costs in such a way as to

19 penalize high load factor customers. For example, Avista

20 witness Ms. Tara Knox concludes (Page 4, Line 14) that

21 the Extra Large General Service Schedule 25 customers

22 presently pay rates that result in their contributing a

23 rate of return of 4.47% compared to the system average

24 return of 6.94%. This conclusion in turn leads

25 Mr. Dukich to recommend raising Schedule 25 rates by a

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1 whopping 16.4%.

2 A further problem with Avista's study is that its

3 means for classifying and allocating costs of all

4 functions - distribution, transmission and generation -

5 are counter to generally accepted cost of

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1 service principles. They are also contrary to Avista's

2 filings before the FERC and previous Idaho Commission

3 filings. Correcting these errors or shortcomings changes

4 the return found for Schedule 25 customers to an

5 approximate average system rate of return.

6 Basic Customer vs. Minimum Distribution System

7 Q PLEASE EXPLAIN THE ISSUE WITH RESPECT TO

8 AVISTA'S CLASSIFICATION AND ALLOCATION OF DISTRIBUTION

9 COSTS?

10 A The general issue here is that Avista,

11 through its witness Ms. Knox, proposes a cost study that

12 ends up allocating huge amounts of distribution costs to

13 large customers who by definition, use little of the

14 distribution system. This so-called "Basic Customer"

15 classification is directly contradictory to all new,

16 emerging methods of estimating marginal distribution

17 costs. While Ms. Knox is correct that the Basic Customer

18 Method ("BCM") has been adopted in the Washington

19 jurisdiction, she is absolutely wrong in contending there

20 is a theoretically sound basis for doing so.

21 Q PLEASE ELABORATE.

22 A Since the beginning of the big push in

23 regulation in the mid 1970s to base customer rates on the

24 basis of cost of service, emphasis in terms of

25 sophistication of cost studies has been given primarily

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1 to generation and transmission functions. At that time

2 and continuing to today, distribution cost studies have

3 relied more on simplifying assumptions due to the

4 complicated and shorter-term nature of distribution

5 system planning. The "Minimum Distribution System"

6 ("MDS") method was

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1 and remains the primary distribution cost method here in

2 Idaho and elsewhere. The reason, in my opinion, that the

3 MDS remains a good method - despite its simplifying

4 assumptions - is that it fairly classifies distribution

5 costs between customer and demand components. The Basic

6 Customer Method does not.

7 Q WHY DO YOU STATE THAT THE MDS METHOD

8 PRODUCES A FAIR CLASSIFICATION OF DISTRIBUTION COSTS?

9 A The evolving and much more elaborate and

10 accurate distribution cost studies, generally referred to

11 as "Facilities Approach," have proven to classify costs

12 similarly to the classification resulting from the MDS.

13 I have found this generally to be true in the

14 distribution planning and costing for Portland General

15 Electric, Nevada Power and Sierra Pacific Power Company.

16 My problem with Ms. Knox's suggestion that this

17 Commission now ought to change to the BCM is that this

18 method goes in the wrong direction by greatly

19 underestimating the customer cost component and greatly

20 overestimating the demand component of distribution

21 costs. This inherent bias greatly exaggerates the costs

22 to high load factor customers.

23 Q PLEASE EXPLAIN.

24 A The problem with both the BCM and MDS

25 methods is that they are ambiguous about any definition

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1 of demand. Typically, there are four measures of

2 "demand" on a system like Avista's:

3 1. coincident peak demand

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1 2. rate class non-coincident peak demand

2 3. individual customer non-coincident peak

3 demand

4 4. customer design demand

5 When we conduct distribution system planning and cost

6 studies we have only in the last 8-10 years begun to

7 correctly focus on "customer design demand" as the

8 appropriate analytical basis for the classification and

9 allocation of distribution costs.

10 Q WHAT IS "CUSTOMER DESIGN DEMAND"?

11 A Customer design demand is the basis upon

12 which distribution facilities are sized and designed.

13 The sizing of these facilities and therefore the costs

14 incurred to build distribution facilities is a function

15 of design demand instead of, say, a utility's generation

16 peak demand.

17 For example, distribution facilities are planned

18 and built for specific geographic areas of the service

19 territory, as for a subdivision. The facilities are not

20 in any way based on system demand of the utility, but

21 rather upon maximum subdivision design demand. This is

22 done by initially sizing substations, feeders,

23 transformers, etc. to meet all eventual growth within the

24 limited area. Once the subdivision is sized and

25 constructed these costs are essentially fixed and do not

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1 vary with what we typically consider demand allocators.

2 The facilities approach takes all these considerations

3 into account. The BCM and MDS cannot.

4 Q IF NEITHER THE BCM NOR THE MDS CAN ACCOUNT

5 FOR CUSTOMER DESIGN DEMAND, WHY DO YOU ARGUE THAT THE

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1 MDS METHOD USED BY THE IDAHO COMMISSION IS TECHNICALLY

2 AND THEORETICALLY SUPERIOR TO THE BCM PROPOSED BY

3 MS. KNOX?

4 A Because the minimum distribution system

5 method correctly classifies a significant amount of

6 distribution costs as design demand or customer related,

7 it does not bias the classification as does Ms. Knox's

8 BCM. Recall that the BCM contains the assumption that

9 all distribution facilities costs except the customer

10 service drops and meter vary with usage. I have yet to

11 see a power pole shrink or expand with changes in daily

12 demand.

13 Q WHAT IS YOUR RECOMMENDATION WITH RESPECT TO

14 THE MDS?

15 A I recommend that this Commission continue

16 its prudent policy of using the MDS to classify

17 distribution costs. The fact that the BCM is used in

18 Washington is no reason to change.

19 I modify Avista's cost of service study to change

20 from the BCM to the MDS. These and other recommended

21 changes are summarized in my Exhibit 209.

22 Demand Allocators

23 Q WHAT ARE THE ISSUES WITH REGARD TO THE

24 DEMAND ALLOCATORS USED BY MS. KNOX FOR AVISTA?

25 A I have two issues here. First, Ms. Knox

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1 uses an "average for the twelve monthly system coincident

2 peak loads" (Knox, page 11, lines 7-8) to allocate

3 production and transmission demand related costs. I

4 strongly

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1 disagree with this allocator. Second, Ms. Knox allocates

2 distribution demand related costs with an allocator that

3 is "...the average of the twelve monthly non-coincident

4 peaks for each class." I also take exception to this

5 allocator.

6 Q WHAT IS THE BASIS FOR YOUR CRITICISM OF

7 MS. KNOX'S USE OF THE AVERAGE 12 CP ALLOCATOR FOR

8 PRODUCTION AND TRANSMISSION COSTS?

9 A Both production and transmission demand

10 costs are incurred to meet the highest, or peak demands.

11 In order to provide a proper price signal to customers,

12 and to allocate costs to customers most responsible for

13 creating this peak demand, these demand costs need to be

14 allocated to customer classes on a basis that reflects

15 customer demand at system peak.

16 Q BUT DOESN'T MS. KNOX DO THIS BY ALLOCATING

17 COSTS BASED ON THE AVERAGE 12 CP BASIS?

18 A No. Utilities incur demand costs to meet

19 system peaks. As discussed in the section on

20 transmission cost classification, once production and

21 transmission costs are incurred to meet peak demands,

22 other times such as the monthly peak demands of lower

23 load months of the year do not cause capacity to be built

24 and, therefore, cause no demand costs to be incurred. No

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1 those in which the annual system peak occurs.

2 Q HAS THE IDAHO COMMISSION RECOGNIZED THIS IN

3 THE PAST?

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1 A Yes. The Idaho Commission has adopted

2 demand allocators that reflect the importance of system

3 peaks in all Idaho Power rate cases. In those cases,

4 Idaho Power and, as I recall, all other parties supported

5 a "weighted twelve month" coincident peak allocator which

6 essentially gives the predominant weight to Idaho Power's

7 maximum peak loads.

8 Q WHAT DO YOU RECOMMEND TO THIS COMMISSION IN

9 REGARD TO THE PROPER METHOD TO ALLOCATE PRODUCTION AND

10 TRANSMISSION COSTS IN THIS PROCEEDING?

11 A I recommend that the Commission require

12 Avista to allocate these demand costs on the basis of the

13 customer class contribution to the system peak demand,

14 which occurs in January. I have reallocated both

15 production and transmission demand related costs on this

16 basis in my Exhibit 209.

17 Q PLEASE ADDRESS YOUR SECOND ISSUE PERTAINING

18 TO AVISTA'S DISTRIBUTION DEMAND ALLOCATOR.

19 A As explained by Ms. Knox on page 11, lines

20 12-14 of her testimony, distribution demand related costs

21 are allocated with "...the average of the twelve monthly

22 non-coincident peaks for each class." My criticism here

23 is very much related to my discussion of distribution

24 system design characteristics. There is no reasonable

25 basis to use the average 12 NCP demands. A single annual

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1 NCP allocator is appropriate. Again, the distribution

2 system is sized according to maximum customer design

3 demand which occurs only once. I recommend that

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1 the Commission require Avista to modify its distribution

2 demand related cost allocator to reflect the single NCP

3 load. My Exhibit 209 reflects this change.

4 Classification of Transmission Costs

5 Q WHAT IS THE COST OF SERVICE ISSUE WITH

6 RESPECT TO THE MANNER IN WHICH AVISTA CLASSIFIES

7 TRANSMISSION COSTS?

8 A On page 7 of her testimony, Ms. Knox

9 justifies her classifying of transmission costs to both

10 demand and energy on the basis of a Peak Credit method.

11 Her method results in 28.82% of transmission costs being

12 classified to demand and 71.18% to energy. The issue

13 here is that the Peak Credit method is valid only for

14 classifying production costs, and only under certain

15 circumstances. The Peak Credit method should never be

16 applied to transmission costs, only to production costs.

17 Q DOES MS. KNOX EXPLAIN WHY SHE APPLIED THE

18 PEAK CREDIT METHOD TO TRANSMISSION COSTS?

19 A The only explanation provided is that

20 "...likewise the transmission system is built not only

21 for peak use but everyday delivery of energy..."

22 Q IS THIS TRUE?

23 A No. She is correct that the transmission

24 system is, of course, used not only for peak use but also

25 for every day delivery of energy. But this does not

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1 justify the Peak Credit which classifies some

2 transmission costs to energy. Transmission facilities

3 are designed and built to serve a maximum peak demand and

4 are therefore 100% demand related.

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1 Q HAS THIS COMMISSION IN THE PAST RECOGNIZED

2 THAT TRANSMISSION COSTS ARE 100% DEMAND RELATED?

3 A Yes. Transmission costs have been

4 classified 100% to demand in previous Idaho Power rate

5 cases.

6 Q DOES AVISTA CLASSIFY TRANSMISSION COSTS

7 100% TO DEMAND IN ALL ITS FILINGS AND PROCEEDINGS BEFORE

8 THE FERC?

9 A Yes.

10 Q ARE OTHER UTILITIES AND OTHER USERS OF

11 AVISTA'S TRANSMISSION SYSTEM CHARGED TRANSMISSION RATES

12 BASED ON CLASSIFYING 100% OF TRANSMISSION COSTS TO

13 DEMAND?

14 A Yes.

15 Q BUT DOESN'T THE FACT THAT AVISTA'S

16 TRANSMISSION SYSTEM IS USED OFF PEAK TO DELIVER ENERGY A

17 REASON TO CLASSIFY SOME OF THESE COSTS TO ENERGY?

18 A No.

19 Q WHY NOT?

20 A Properly designed rates are intended to

21 reflect cost causation and cost of service. In designing

22 and building transmission systems, all costs are "caused"

23 by the paramount objective of meeting peak demands. All

24 electric system stability and reliability considerations

25 depend on meeting these peak power demands. The

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1 economist describes this peak requirement as causing the

2 incremental or marginal cost of

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1 transmission. Once the costs of building the

2 transmission system have been incurred to meet peak

3 demand, the incremental costs of using these facilities

4 to carry energy are virtually zero. And, as a result, no

5 costs are allocated to energy.

6 Q ARE YOU AWARE OF OTHER JURISDICTIONS THAT

7 USE A PEAK CREDIT BASIS FOR CLASSIFYING TRANSMISSION

8 COSTS?

9 A No, none outside of Washington.

10 Q HOW DO YOU PROPOSE THAT THIS COMMISSION

11 CLASSIFY TRANSMISSION COSTS?

12 A I recommend that the Commission require

13 Avista to modify its cost of service study to classify

14 100% of its transmission costs to demand. This will

15 realign its rates for retail customers with those of

16 wholesale customers and will prevent customers inside

17 Idaho from having to subsidize purchases made by

18 customers outside Idaho. My Exhibit 209 makes this and

19 other corrections to Avista's cost of service study.

20 Allocation of Conservation Costs to Rate Classes

21 Q HOW DOES AVISTA ALLOCATE ITS PROPOSED

22 RECOVERY OF CONSERVATION COSTS TO RATE CLASSES IN ITS

23 COST OF SERVICE STUDY?

24 A On pages 8-9 of her testimony, Ms. Knox

25 explains that she proposes to allocate pre-1995 DSM costs

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1 on the basis of plant in service. More recent DSM costs

2 are allocated on the basis of the Schedule 91 Tariff

3 Rider Revenue.

4 Q DO YOU AGREE WITH THESE ALLOCATIONS?

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1 A No. In my opinion these allocations are

2 unfair and unreasonable. The reason they are unfair is

3 because they cause a large disparity between the customer

4 classes receiving benefits from DSM programs and those

5 paying for them.

6 For example, in response to Potlatch data request

7 No. 21, Avista explains that of the $4,124,158 of total

8 expenditures on the energy efficiency programs, only

9 $136,375, or 3.3% of these expenditures were for Schedule

10 25. Yet Avista's proposal allocates between 11.3% and

11 13.9% of the post and pre-1995 programs' expenditures to

12 Schedule 25.

13 Q WHY DO CLASSES THAT RECEIVE DSM

14 EXPENDITURES BENEFIT MOST?

15 A Energy conservation measures reduce power

16 bills to the class receiving the benefits of the DSM

17 programs. In a period of relative resource surplus,

18 other customer classes receive little or no benefit from

19 such programs.

20 Q HOW DO YOU PROPOSE THAT THE COSTS OF THESE

21 DSM PROGRAMS BE ALLOCATED AMONG CUSTOMER CLASSES?

22 A A fair and equitable manner would be to

23 allocate these costs in direct proportion to the

24 expenditures made on each class. For example, since 3.3%

25 of DSM expenditures were made for Schedule 25, Schedule

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1 25 would be allocated 3.3% of the costs.

2 Q WHAT IS YOUR PROPOSAL ON RATE CLASS

3 INCREASES IN THIS PROCEEDING?

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1 A As I have pointed out, it is the Schedule

2 25 class that has had its rate of return most distorted

3 by Avista's cost of service study. After reviewing the

4 sum of my corrections and proposed adjustments, my rate

5 change recommendation for Schedule 25 is very simple. My

6 Exhibit 209, line 58 shows that Schedule 25 is

7 approximately at the average rate of return.

8 I request that the Commission give Schedule 25

9 customers no more than an average overall increase. In

10 my study, as in Avista's, the Commission is still left

11 with a decision as to how much to change the rates for

12 commercial customers who are paying too much, and

13 residential customers who are paying too little.

14 Q DOES THIS CONCLUDE YOUR TESTIMONY?

15 A Yes, it does.

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1 (The following proceedings were had in

2 open hearing.)

3 MR. WARD: And Dr. Peseau is available for

4 cross.

5 COMMISSIONER SMITH: Mr. Shurtliff, do you

6 have questions?

7 MR. SHURTLIFF: The conclusions that you

8 reached on page 3 --

9 MR. WARD: Oh.

10 COMMISSIONER SMITH: Mr. Ward seems to have

11 forgotten something.

12 MR. WARD: Yes, I did, Madam Chair. I

13 needed to ask just a couple of questions in response to

14 answers that came up today.

15 COMMISSIONER SMITH: Let's do that.

16

17 DIRECT EXAMINATION

18

19 BY MR. WARD: (Continued)

20 Q One that we just heard just a few minutes

21 ago, it's a minor thing, Dr. Peseau, but I believe

22 Mr. Hessing said that the basic customer method

23 classifies increasing distribution costs to energy; is

24 that correct?

25 A I believe that's what he said.

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1 Q Is that a correct statement?

2 A It can be a correct statement because, I

3 mean, one can choose to classify distribution costs to

4 energy, but typically, the dispute between the minimum

5 distribution system and the basic customer is a dispute

6 about classifying costs into a customer category versus a

7 demand category. The basic customer method minimizes the

8 allocation to or the classification to customer related

9 and thereby maximizes the allocation to demand and that's

10 the dispute that I had with Ms. Knox's procedure.

11 Q Okay, and I did want to -- there were a

12 couple of things in Ms. Knox's testimony that there was

13 no way to get to through cross-examination that I'd like

14 you to clear up. One is -- do you have a copy of her

15 rebuttal testimony?

16 A Yes, if I may have a moment.

17 Yes, I do.

18 Q If you'd turn to page 4 of that testimony,

19 lines 5 through 12, there Ms. Knox is replying to your

20 statements about Idaho Power's classification of

21 transmission to demand and she makes a number of

22 statements about how she perceives that Idaho Power's

23 classification is done. Are those statements correct?

24 A Her statements are not correct.

25 Q And will you please explain?

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1 A I explained in my testimony that Idaho

2 Power classifies 100 percent of its transmission costs to

3 demand, that's true. Apparently, what Ms. Knox did was

4 to look at a summary sheet in the 1994 Idaho Power study

5 and note correctly that transmission costs were broken

6 into two categories, one called other transmission and

7 one called power supply.

8 She incorrectly then inferred that because

9 generation power expenses are classified using a system

10 load factor that Idaho Power did the same with

11 transmission expenses. That's not true. I brought the

12 1994 study and it's quite clear that the demand

13 allocator -- excuse me, that the allocator for the

14 transmission costs is 100 percent demand allocator.

15 Just to be sure, I called Mr. Rick Gale and

16 Phil Obenchain at Idaho Power Monday morning to confirm

17 that for not only the 1994 study but subsequent studies

18 as well.

19 Q Okay, thank you. One other thing, in

20 discussing the dispute about the basic customer method,

21 Ms. Knox seems to have assumed that the Utah Power &

22 Light PacifiCorp system uses the basic customer method.

23 Did you hear that testimony this morning, this afternoon?

24 A Yes, what I heard her say this morning was

25 that in talking with Mr. Taylor of PacifiCorp, he

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1 indicated that in the 20 years he had been conducting

2 cost of service studies that he was aware of none that

3 PacifiCorp had done using the minimum distribution system

4 approach which is true.

5 Q But what do they really do? Does that mean

6 that they use the basic customer method?

7 A No. The basic customer method is comprised

8 of looking up a few FERC accounts for distribution

9 numbers and multiplying it times a non-coincident

10 factor. It's very simple and straightforward.

11 PacifiCorp goes the other way towards the method I

12 describe more fully in my testimony, one which is

13 considered a facilities approach, an engineering

14 approach, looking forward at what distribution facilities

15 are planned and what causes those to be planned.

16 In fact, PacifiCorp has for many years

17 designed basically three different distribution symptoms,

18 one tailored after a residential subdivision, another

19 from the substation all the way to the -- through the

20 feeders, transmission, poles, conduits, transformers, all

21 the way to the customer house. The second system they

22 use is a mixed residential/commercial, and finally,

23 there's a third for the commercial, and these are

24 designed according to a distribution engineer's

25 specifications and then they're allocated to customer and

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1 demand. The point I want to make is that it comes out

2 more heavily customer and less demand than the basic

3 system does.

4 Q Okay, and finally, anyone whose

5 observations on cost of capital were characterized as

6 simpleminded certainly gets a chance to answer. What's

7 your response to that?

8 A Who said that?

9 MR. MEYER: You know --

10 COMMISSIONER SMITH: Mr. Meyer.

11 MR. MEYER: At this point, if you'll give

12 me a minute just to fully explain myself. What we're

13 hearing, of course, is surrebuttal. A few weeks ago I

14 spoke with Mr. Ward, I spoke with Scott Woodbury about

15 whether or not Potlatch should be allowed to introduce

16 surrebuttal and by agreement of counsel, Mr. Ward

17 acknowledged that he would file an appropriate motion

18 prior to the start of the hearing in the event that they

19 wished to essentially engage in surrebuttal. He didn't,

20 he passed on the opportunity.

21 Essentially, what's being done at this late

22 juncture is to wedge into the record surrebuttal on a

23 number of issues. I don't mean to get in between the

24 Commission and its fact finding, but I think certain

25 sensible limits need to be set, so I object.

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1 COMMISSIONER SMITH: Mr. Ward.

2 MR. WARD: Counsel's characterization of my

3 agreement is correct, but I understood that agreement to

4 be with regard to the rebuttal testimony itself, as I

5 understand it. I can't think of an instance in which any

6 party was denied a chance to respond to those items that

7 came up in the proceeding. Now, I will admit that with

8 the one exception of the use of the Idaho Power

9 transmission system which is in Ms. Knox's rebuttal

10 testimony and which I did ask Dr. Peseau on because I

11 cannot figure a way to say that in cross, the others are

12 in response to items that have come up in the proceeding

13 and I'd add that this is my last question.

14 COMMISSIONER SMITH: Mr. Meyer.

15 MR. MEYER: Then I would note that the last

16 question made reference to a characterization of certain

17 testimony as simpleminded. That appears in the prefiled

18 rebuttal testimony, hence making his question

19 surrebuttal.

20 COMMISSIONER SMITH: Mr. Meyer, I

21 understand what you're saying. I think the Commission

22 has been historically fairly relaxed in allowing parties

23 the opportunity to respond and I assume that's why you

24 still have your witnesses here and have the opportunity

25 and have reserved the opportunity to recall them if

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1 something came up in the course of the hearing, so I'm

2 going to overrule your objection and allow Mr. Ward to

3 ask this final question of Dr. Peseau.

4 Q BY MR. WARD: Doctor, what is your response

5 to that characterization of your cost of service

6 analysis?

7 A Cost of capital?

8 Q I mean cost of capital.

9 A The procedure I summarize in my testimony I

10 certainly think can be viewed as being simple; however,

11 it's certainly not simpleminded. It's premised upon a

12 one-to-one relationship between the changes in risk free

13 rates, that is, Treasury bonds, and the cost of equity.

14 That happens to be the underlying premise to the most

15 sophisticated method of estimating cost of equity that

16 exists in modern financial literature. That's the

17 capital asset pricing model.

18 Mr. Avera is simply wrong in saying that

19 you take my number, which he says is too simple, divide

20 by two and now it's appropriate. The capital asset

21 pricing model says that there's a one-to-one relationship

22 between the risk free rate, the interest rate, and the

23 cost of equity if underlying risk has not significantly

24 changed.

25 If Mr. Avera would have reviewed the

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1 financial literature for risk measures on Avista, he

2 would have found out that indeed, Avista's risk measures

3 measured by beta have changed, they've gotten lower, so I

4 think that the simple analysis that I performed is

5 certainly a good indication of the magnitude of the

6 movement in today's cost of equity.

7 MR. WARD: Thank you, and with that,

8 Dr. Peseau is available for cross-examination.

9 COMMISSIONER SMITH: Thank you, Mr. Ward.

10 Now, Mr. Shurtliff.

11 MR. SHURTLIFF: Thank you.

12 COMMISSIONER SMITH: You're sure you have

13 questions?

14 MR. SHURTLIFF: I'm sure.

15

16 CROSS-EXAMINATION

17

18 BY MR. SHURTLIFF:

19 Q Dr. Peseau, your conclusions stated at

20 page 3 of your testimony, conclusions number two and

21 three, do they stand alone?

22 A I guess I don't understand the question.

23 Q I mean, could you be wrong as to conclusion

24 number two and correct as to conclusion number three or

25 do you need to accept both conclusions in order to accept

1254

CSB REPORTING PESEAU (X)
Wilder, Idaho 83676 Potlatch

1 either one of them?

2 A The analyses underlying conclusions two and

3 three are largely independent.

4 Q You talk about hydro and those sorts of

5 things, I wanted to ask you just simply, were you here

6 yesterday when the witness testified that information is

7 available for the 1990s, but was not included in the

8 hydro study conducted by the Company?

9 A Is this Mr. Norwood?

10 Q I believe it was.

11 A I heard Mr. Norwood testify that the water

12 record he was referring to was updated every,

13 approximately every, 10 years, if that's what you're

14 referring to. I thought with respect to that water

15 record he had indicated that while 10 years has elapsed,

16 that is, it's now past 1998, it still takes a couple of

17 more years for the water record he wants to rely upon to

18 be updated.

19 Now, there may have been other testimony.

20 I know Idaho Power uses water records including 1998, and

21 streamflows, natural streamflows, for the Dalles are

22 available up through 1998, but I did not -- if that's

23 responsive. I didn't hear Mr. Norwood say that, if he

24 was the witness, he had a water record that he wanted to

25 rely upon that was current, but he didn't use it.

1255

CSB REPORTING PESEAU (X)
Wilder, Idaho 83676 Potlatch

1 Q Well, he didn't have one that he wanted to

2 rely on. Would you agree, however, that the use of the

3 hydro cycle that's used in any case is a matter of

4 judgment that can be the subject of different opinions?

5 A I think that's true, although if you read

6 the hydrological literature, most of that judgment is

7 pretty well informed.

8 Q In regard to the cost of equity

9 proposition, I wanted to ask you in your professional

10 opinion, Dr. Peseau, if a commission were to select at

11 the midpoint of the equity figure, isn't that in and of

12 itself a sufficient bonus or a kicker or an adder for a

13 good job done?

14 A I don't agree with the concept of an adder

15 or a kicker above the market-determined rate of return.

16 I think the market rate of return does compensate

17 adequately. Most analyses that use a range and a

18 midpoint, I think, use a midpoint because it's assumed to

19 be somewhat of a symmetric outcome and that is, there's,

20 if there's an error, it's equally likely to go on either

21 side of the midpoint and the midpoint is, therefore, the

22 best estimate, so in most cases, I would recommend using

23 a midpoint if that's the case.

24 Q Would you expand a little bit on why you

25 don't believe in the notion of adders?

1256

CSB REPORTING PESEAU (X)
Wilder, Idaho 83676 Potlatch

1 A Well, I think the charge of regulation is

2 to simulate competition and competitors' actions cause

3 management employees to do a good job. If they don't,

4 they're no longer a competitor, so I think a

5 market-determined fair rate of return is adequate.

6 MR. SHURTLIFF: I have no further

7 questions. Thank you.

8 COMMISSIONER SMITH: Thank you,

9 Mr. Shurtliff.

10 Mr. Woodbury.

11 MR. WOODBURY: Madam Chair, Staff has no

12 questions of Dr. Peseau.

13 COMMISSIONER SMITH: Okay, thank you. I'd

14 like to take about a five-minute break right now.

15 (Recess.)

16 COMMISSIONER SMITH: Mr. Meyer.

17 MR. MEYER: Thank you. We've put together

18 what we believe is extensive and effective rebuttal, so

19 we have no cross.

20 COMMISSIONER SMITH: I think that's very

21 effective.

22 Questions from the Commission?

23 Any redirect?

24 MR. WARD: No redirect.

25 COMMISSIONER SMITH: Thank you,

1257

CSB REPORTING PESEAU (X)
Wilder, Idaho 83676 Potlatch

1 Dr. Peseau.

2 THE WITNESS: Thank you.

3 (The witness left the stand.)

4 COMMISSIONER SMITH: All right, this brings

5 us to Mr. Shurtliff's witnesses.

6 MR. SHURTLIFF: Madam Chair, we have three

7 persons. We'll call first George Johnson.

8

9 GEORGE R. JOHNSON,

10 produced as a witness at the instance of the Hecla Mining

11 Company, having been first duly sworn, was examined and

12 testified as follows:

13

14 DIRECT EXAMINATION

15

16 BY MR. SHURTLIFF:

17 Q Would you state your full name, please, and

18 spell your last name?

19 A George R. Johnson, J-o-h-n-s-o-n.

20 Q By whom are you employed, Mr. Johnson?

21 A Hecla Mining Company.

22 Q And where are you located?

23 A In Coeur d'Alene, Idaho, based.

24 Q You prepared comments which we've

25 characterized as testimony herein, have you not?

1258

CSB REPORTING JOHNSON (Di)
Wilder, Idaho 83676 Hecla Mining

1 A Yes.

2 Q And you drafted that yourself?

3 A Yes.

4 MR. SHURTLIFF: And, Madam Chair, I don't

5 know, it's three pages, single-spaced, we could read it

6 or we could spread it on the record. I have no

7 preference.

8 COMMISSIONER SMITH: It would be my

9 preference to spread it unless there's an objection by

10 the other parties who would like it read.

11 MR. SHURTLIFF: In that case, I would move

12 that it be spread upon the record as if read.

13 COMMISSIONER SMITH: If there's no

14 objection, then we'll spread it on the record as if read.

15 MR. MEYER: Excuse me.

16 COMMISSIONER SMITH: Mr. Meyer.

17 MR. MEYER: Thank you. This and the

18 following two witnesses, other than noting for the record

19 that their testimony was filed well beyond the

20 established deadlines for filing testimony, we won't

21 object and I'll save you the suspense, we won't object to

22 the next two either.

23 COMMISSIONER SMITH: Thank you, Mr. Meyer.

24 (The following prefiled testimony of

25 Mr. George Johnson is spread upon the record.)

1259

1 My name is George Johnson. I am employed by Hecla

2 Mining Company as the Vice President of Metal Mining and

3 directly responsible for the performance of the Lucky

4 Friday Mine located at Mullan, Idaho.

5 I am here today to comment on the electric power

6 rate increase proposed by Avista. But first, I would

7 like to give you a brief description of the Lucky Friday

8 Mine.

9 The Lucky Friday Mine is located just east of

10 Mullan, Idaho, in the famous Coeur d'Alene Mining

11 District of northern Idaho.

12 The Lucky Friday claims were located in 1889

13 around a modest quartz vein outcrop. Early exploration

14 work was not promising. The property changed ownership

15 several times in the next 50 years as various individuals

16 attempted to find improved mineral grade at depth. At

17 one point, the property was let go for back taxes.

18 The first commercial ore was found in 1941 on the

19 300 level as a 25-foot long section of the vein. In

20 1958, Hecla Mining Company purchased a 38% interest in

21 the Lucky Friday. In 1964, the Lucky Friday Silver-Lead

22 Mines company was merged into Hecla. The mine operated

23 continuously until excessive losses forced a suspension

24 of operations in April 1986. Production resumed in June

25 1987 after the employees agreed to a 30% reduction in

1260

1

1 wages and benefits, and continues today. In conjunction

2 with the wage reduction, the company agreed to split a

3 portion of any cash generated by the mine in the future

4 with the employees.

5 The Lucky Friday Mine produces silver, lead and

6 zinc as primary products. Since the first commercial ore

7 shipment in 1942, more than 6,900,000 tons of ore have

8 been mined, yielding over 106,200,000 ounces of silver,

9 732,000 tons of lead, and 94,000 tons of zinc.

10 Cut and fill mining is used in the Lucky Friday

11 ore body. A "cut" is taken along the length of the vein

12 approximately 10 feet in height. When the cut is

13 completed, the void created by ore extraction is filled

14 with tailings from the concentrator, and then the next

15 cut is taken either above or below the filled area.

16 Access to the next cut is through a series of ramps mined

17 outside the ore body.

18 Mine ore is processed in a concentrator or mill.

19 The course ore is first crushed to -3/4" size. The fine

20 ore is then ground in a ball mill to a sand consistency

21 and introduced to flotation cells for processing. The

22 product produced from the mill is called a flotation

23 concentrate.

24 /

25 /

1261

1A

1 The lead and zinc concentrates are shipped by

2 truck either directly to the smelters or to a rail head

3 in Superior, Montana, for transloading. The lead

4 concentrate is sold to smelters in the U.S., Mexico,

5 Canada and the Pacific Rim. The zinc concentrate is

6 shipped to Cominco's smelter in Trail, British Columbia.

7 Since 1987, Hecla has invested over $30 million at

8 the Lucky Friday for new equipment and mine

9 infrastructure to improve productivity and lower

10 operating costs by approximately 40%.

11 During 1998, the Lucky Friday produced 4.1 million

12 ounces of silver, 28,000 tons of lead and 2,600 tons of

13 zinc. Silver is used for photography, jewelry and

14 sophisticated electrical circuits. Lead is used

15 primarily in car batteries and zinc is used primarily in

16 the manufacturing of automobiles to prevent corrosion.

17 The mine currently employs 198 men and women and

18 payroll in 1998 was about $8,000,000. In addition, there

19 are hundreds of service jobs created in the Inland Empire

20 due to the mine.

21 More specific to the proposed rate increase, I am

22 not an expert in the costs of power transmission, but I

23 have about 28 years of experience in the mining business

24 with 18 years of that in mine management. I don't know

25 exactly what the purpose of the commission is, but it is

1262

2

1 my basic understanding that you oversee the activities of

2 power companies and approve rate increases sought by the

3 companies or co-ops if appropriate. In addition, it is

4 my understanding there are laws or regulations within the

5 State of Idaho that provide a profit margin or rate of

6 return for the power companies based on revenues minus

7 their costs of providing power. I would imagine the

8 types of costs that are appropriate to include in the

9 calculation are critical and there must be some

10 obligation of the power provider to calculate them

11 properly, have an impeccable cost tracking system and

12 keep the costs down.

13 As I said, I do not have a technical background on

14 how power rates are to be calculated so I can't quibble

15 over how the calculations were done. However, I have

16 read the testimony of Mr. Dennis Peseau on behalf of

17 Potlatch Corporation. I agree with the conclusions on

18 page three of his testimony and the logic he has based

19 those conclusions on.

20 I would like to add to Mr. Peseau's comments. The

21 proposed rate increase will be material and detrimental

22 to the Lucky Friday business and its employees.

23 First, let me give you a little more background

24 about the business. As I said, the Lucky Friday is a

25 mine. Ore is extracted from the underground and

1263

2A

1 processed, and the products are sold. By definition, ore

2 is material that can be extracted from the ground,

3 processed and sold at a profit. You are probably aware

4 that there have been several mine closures over the past

5 20 years in the Silver Valley. Some have closed

6 permanently and some have reopened. In fact, the three

7 major mines currently operating in the valley were

8

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1264

2B

1 closed down at some time during the last 20 years because

2 they were not making money, not because the silver-rich

3 veins were mind out.

4 The Lucky Friday Mine has a demand of just over

5 8.5 megawatts. The annual energy consumption is just

6 under 100,000 megawatts resulting in annual energy costs

7 of approximately $1,300,000 to $1,500,000.

8 The mine is over a mile deep and approximately 50%

9 of the electrical energy used at Lucky Friday is for mine

10 ventilation and cooling. Conditions for the miners would

11 be unbearable with temperatures underground exceeding 115

12 degrees F without the current ventilation and cooling

13 system.

14 At current metals prices, the mine makes very

15 little money. If you include the capital invested, the

16 net amount is negative. The prices received for the

17 metals produced at the mine are established by

18 international markets; costs cannot be passed on to our

19 customers, however, our suppliers can and do pass along

20 their cost increases to us. In 1987, labor rates

21 including benefits were reduced by over 30%, which along

22 with some other things, allowed the mine to reopen. I

23 think all of mines operating today significantly reduced

24 labor rates to stay alive. It was a big deal in the

25 valley.

1265

3

1 The proposed rate change of 16% will increase

2 costs at the Lucky Friday by $250,000 to $300,000 per

3 year. This would be material to the cost structure and

4 future of the mine. To compensate for the increase, it

5 would be necessary to eliminate six jobs (3% of the

6 workforce) or reduce wages by 3% across the board. While

7 it is horribly distasteful to me, if the increase comes

8 through, I will have to take action to make up for the

9 loss and ultimately to avoid closing the mine. Avista

10 should consider the viability of the mines in its

11 proposed rate hikes. When the Lucky Friday was closed in

12 the 1980s, Avista lost well over one $1,000,000 in

13 revenue from the mine. Maybe I'm wrong, I guess they may

14 have been able to sell the power out of state at a higher

15 margin, which would have made the closure beneficial to

16 them.

17 To summarize, I object to the proposed rate

18 increase. It will materially impact our ability to keep

19 the Lucky Friday business going. I do not see a good

20 basis for increasing the power rates as much as what is

21 requested, if at all. I absolutely don't see a

22 justification for the large users to have more of an

23 increase than other classes of users. In the Silver

24 Valley, I am not aware of any special installations or

25 facilities upgraded recently due to commercial users. If

1266

3A

1 you find a rate increase is warranted, please consider it

2 to be the same percentage across the board for all

3 classes of users.

4 On behalf of Hecla Mining Company and the 198 men

5 and women at the Lucky Friday, please carefully consider

6 this requested increase and the effect it will have.

7

8 /

9

10 /

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1267

3B

1 (The following proceedings were had in

2 open hearing.)

3 MR. SHURTLIFF: I would tender Mr. Johnson.

4 COMMISSIONER SMITH: Mr. Ward, do you have

5 questions for Mr. Johnson?

6 MR. WARD: I do not. Thank you.

7 COMMISSIONER SMITH: How about

8 Mr. Woodbury?

9 MR. WOODBURY: No. I thank Mr. Johnson for

10 his comments, but I have no questions.

11 COMMISSIONER SMITH: Mr. Meyer?

12 MR. MEYER: None.

13 COMMISSIONER SMITH: How about from the

14 Commission, questions?

15 There being no questions, there can be no

16 redirect.

17 Thank you, Mr. Johnson.

18 (The witness left the stand.)

19 MR. SHURTLIFF: Thank you. Call Robert

20 Peterson.

21

22

23

24

25

1268

CSB REPORTING JOHNSON
Wilder, Idaho 83676 Hecla Mining

1 ROBERT H. PETERSON,

2 produced as a witness at the instance of the Sunshine

3 Mining and Refining Company, having been first duly

4 sworn, was examined and testified as follows:

5

6 DIRECT EXAMINATION

7

8 BY MR. SHURTLIFF:

9 Q Would you state your full name, please, and

10 spell your last name?

11 A Robert H. Peterson, P-e-t-e-r-s-o-n.

12 Q And where do you reside, Mr. Peterson?

13 A In Boise, Idaho.

14 Q And by whom are you employed?

15 A Sunshine Mining and Refining Company.

16 Q Where are they located?

17 A The headquarters offices are in Boise.

18 Q Where are their principal operations?

19 A Principal operations in Kellogg, Idaho.

20 Q And, Mr. Peterson, you've prepared what has

21 been characterized as direct testimony herein, have you

22 not?

23 A Yes, I have.

24 MR. SHURTLIFF: And, Madam Chair, I would

25 just move that it be spread upon of the record and tender

1269

CSB REPORTING PETERSON (Di)
Wilder, Idaho 83676 Sunshine Mining

1 the witness.

2 COMMISSIONER SMITH: If there is no

3 objection, we will spread the direct testimony of Robert

4 H. Peterson upon the record as if read.

5 (The following prefiled testimony of

6 Mr. Robert Peterson is spread upon the record.)

7

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1270

CSB REPORTING PETERSON (Di)
Wilder, Idaho 83676 Sunshine Mining

1 Sunshine Mining and Refining Company operates a

2 large Silver Mining Complex near Kellogg, Idaho. We

3 currently employ 305 people at the facility, with an

4 annual silver production of approximately 5-1/2 million

5 troy ounces per year. Sunshine also produces copper,

6 lead, and antimony money as "by-products" to the primary

7 function of silver production. The prices for all these

8 metal products are severely depressed. The company has

9 already installed cost reduction programs in every area

10 of the operation in an attempt to survive this depressed

11 period. The underground mining procedures have been

12 mechanized, the size of the work force has been reduced

13 more than 30%, the silver refinery has been closed, wage

14 rates have been reduced approximately 20% and costs

15 associated with outside smelting services have been

16 reduced. All these cost savings achievements have been

17 critical. However, our survival depends on continued

18 cost control and the prices we receive for our products.

19 We have no

20

21 /

22

23 /

24

25 /

1271

1

1 control over the prices we receive. Our products must

2 complete in international markets!!!

3 ADDITIONAL COSTS CAN NOT BE PASSED ON TO OUR CUSTOMERS.

4

5 Sunshine Mining and Refining Company is very

6 concerned about the cost impact of the proposed Avista

7 Electric Power Rate Increase request. Sunshine is a

8 large North Idaho customer subject to Avista's Schedule

9 25 rate structure. The proposed Avista rate increase

10 will increase Sunshine's electric power costs by about

11 $218,000 per year, which is 16% above current charges.

12 Sunshine believes this Avista increase request is unduly

13 excessive, and cannot be justified. This increased rate

14 (if granted) would jeopardize Sunshine's North Idaho

15 operation.

16

17 Sunshine believes Mr. Dennis E. Peseau presented

18 excellent testimony opposing the Avista rate increase

19 request, and the following opinions primarily support

20 Mr. Peseau.

21

22 1. Mr. Peseau correctly points out how electric power

23 transmission systems are sized, designed, and

24 installed to meet "peak power demands". After

25 the system has been installed, any costs

1272

2

1 associated with carrying energy are negligible.

2 The Avista power transmission systems in North

3 Idaho that services large Schedule 25 ratepayers

4 was installed many years

5

6 /

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8 /

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1273

2A

1 ago. There are few, if any recent Avista

2 expenditures in this area. In Sunshine's case the

3 demand for electric power has decreased more than

4 20% in the last 5 years.

5

6 Any recent Avista Costs associated with supplying

7 "peak power demand" for North Idaho Schedule 25

8 ratepayers are insignificant, and in Sunshine's

9 case nonexistent.

10

11 Mr. Peseau recommends Avista change its cost of

12 service allocation so that 100% of transaction

13 costs are classified to demand. This will mean

14 Idaho customers will not be required to subsidize

15 customers outside Idaho. Accordingly, any

16 approved rate change increase will be distributed

17 equally, with Schedule 25 customers paying no more

18 than the average amount.

19

20 2. As I understand, Avista's requested increase

21 includes an allowed rate of return of 9.446%.

22 Mr. Peseau points out the reasons why this should

23 be reduced. I believe Mr. Peseau has been

24 generous enough.

25

1274

3

1 3. Avista is asking for approval to increase their

2 depreciation rate from 6% to 12.24% even though it

3 is

4

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1275

3A

1 already comparable to or higher than other

2 utilities. Mr. Peseau's testimony states that

3 Avista, as well as the other utilities, are

4 already depreciating their assets at a higher rate

5 than should be allowed. This has been evidenced

6 by the large differences between sales prices for

7 utility assets (at market values) and their

8 respective book values. To illustrate, book value

9 is the difference between acquisition cost of the

10 asset (less any salvage values) and what has

11 already been depreciated. Low book values would

12 lead to the conclusion that the asset is nearing

13 the end of its useful life, or that it will soon

14 become obsolete, and require replacement. This is

15 in direct contrast to the high market values for

16 these assets. (Who would pay a high price for any

17 asset that doesn't have a useful life? )

18

19 Accordingly, Avista wants to have the best of both

20 worlds by:

21 a. Requesting a rate increase to increase their

22 cash income.

23 b. Justifying the rate increase with additional

24 (non-cash) depreciation charges.

25 This request should be totally denied.

1276

4

1 4. Mr. Peseau makes a strong argument that customers

2 should at least share in short term sales and

3 transactions. Avista wants to exclude short-term

4 purchases and sales from the retail rate-making

5 process. Mr. Peseau believes these benefits

6 should be allowed on the ratio of 1.5:1. This is

7 because Avista bought and sold quantities of power

8 in 1997 that were 1.5 times the size of their

9 retail load. The ratepayers paid for the

10 facilities that made these transactions possible;

11 and therefore, they should at least get credit for

12 their "fair share".

13

14 Mr. Peseau's suggested allocation is a fair and

15 reasonable way to divide these activities.

16

17 5. I have attached an article published in the Idaho

18 Statesman on May 15, 1999. Idaho Power has

19 requested lower rates because snow-pack was higher

20 than normal and it will therefore be a good year

21 for hydroelectric generation facilities. The

22 requested reduction for "large power users" is

23 12.6%

24

25 As I understand, both Idaho Power and Avista

1277

5

1 Utilize hydroelectric sources for approximately

2 60% of their

3

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1278

5A

1 overall power generation. A "good water year" for

2 Idaho Power probably means a "good water year" for

3 Avista. If Idaho Power reduces the rate for

4 "large power users" by 12.6%, while Avista

5 increases the rate for "large power users" by 16%,

6 the differential would be 28.6%. With very

7 similar facilities and conditions, the Avista

8 requested increase seems unnecessary and totally

9 self-serving.

10

11 I strongly suggest that the Idaho Public Utilities

12 Commission take this under advisement as this concept

13 indicates there should be no Avista rate increase at

14 all.

15

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1279

6

1 (The following proceedings were had in

2 open hearing.)

3 COMMISSIONER SMITH: Mr. Ward, do you have

4 questions?

5 MR. WARD: No questions. Thank you.

6 COMMISSIONER SMITH: Mr. Woodbury?

7 MR. WOODBURY: Again, I appreciate the

8 comments of Mr. Peterson. I really like those

9 commemorative coins Sunshine puts out. I have nothing.

10 COMMISSIONER SMITH: Mr. Meyer.

11 MR. MEYER: And we have no questions.

12 COMMISSIONER SMITH: How about from the

13 Commission?

14 You're off the hook. Thank you.

15 MR. SHURTLIFF: Thank you, Mr. Peterson.

16 THE WITNESS: Thank you.

17 (The witness left the stand.)

18 MR. SHURTLIFF: Arthur Iverson.

19

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1280

CSB REPORTING PETERSON
Wilder, Idaho 83676 Sunshine Mining

1 ARTHUR D. IVERSON,

2 produced as a witness at the instance of Silver Valley

3 Resources, having been first duly sworn, was examined and

4 testified as follows:

5

6 DIRECT EXAMINATION

7

8 BY MR. SHURTLIFF:

9 Q Mr. Iverson, would you state your full

10 name, please, and spell your last name for the record?

11 A Arthur D. Iverson, I-v-e-r-s-o-n.

12 Q And where do you reside, Mr. Iverson?

13 A Pinehurst, Idaho.

14 Q And by whom are you employed?

15 A Silver Valley Resources.

16 Q In what capacity are you employed?

17 A Purchasing agent.

18 Q And you've prepared what's been

19 characterized as direct testimony for the proceeding

20 herein?

21 A Yes.

22 MR. SHURTLIFF: I would ask, Madam Chair,

23 that it be spread upon the record as if read and tender

24 the witness.

25 COMMISSIONER SMITH: Thank you,

1281

CSB REPORTING IVERSON (Di)
Wilder, Idaho 83676 Silver Valley Resources

1 Mr. Shurtliff. If there is no objection, we will spread

2 this direct testimony of Mr. Iverson upon the record as

3 if read.

4 (The following prefiled testimony of

5 Mr. Arthur Iverson is spread upon the record.)

6

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1282

CSB REPORTING IVERSON (Di)
Wilder, Idaho 83676 Silver Valley Resources

1 My name is Arthur Iverson; I am the Purchasing

2 Agent and representative for Silver Valley Resources or

3 SVR. Thank you for the opportunity to testify in

4 opposition to Avista's rate increase request. SVR is a

5 privately held corporation which owns and operates two

6 underground silver/copper mines, the Galena and Coeur

7 Mines which are located outside of Wallace, Idaho. The

8 Galena Mine is in full production and the Coeur Mine is

9 in a care and maintenance status. SVR employees 200

10 people. SVR purchases all of its electricity from Avista

11 under Schedule 25. The proposed rate increase of 16.4%

12 would have a substantial impact to SVR's cost of doing

13 business. SVR's electrical power costs in 1998 were

14 approximately one $1.4 million dollars. Based on this

15 number an increase of 16.4% would equate to an additional

16 $229,000.

17 I have reviewed the volumes of testimony and

18 exhibits concerning the proposed rate increase. I am not

19 testifying as an expert on utilities, or power rates. I

20 am testifying as an employee of SVR whose job

21 responsibilities include purchasing products and services

22 at the best cost. Concerning the purchase of

23 electricity, I do not have the opportunity to bid or

24 negotiate the rates, which SVR must pay. SVR has taken

25 an aggressive approach to lowering costs through cost

1283

1

1 controls, competitive bidding, and best operating

2 practices. In the instance of the proposed rate

3 increase, SVR has no options but to accept the rate

4 increase if approved.

5 The testimony of Mr. Peseau does ask questions

6 which I would like to have answered. In particular:

7 a. Is Avista's $14.2 million rate increase

8 overstated by approximately $11.5 million?

9 b. Is Avista's cost of service analysis flawed?

10 c. Are Schedule 25 customers currently paying

11 rates that cover their cost of service?

12 d. Should Schedule 25 customers be allocated

13 between 11.3% and 13.9% for energy efficient programs

14 which 3.3% of expenditures are for Schedule 25

15 customers?

16 I attended a meeting on September 29, 1998

17 sponsored by, at that time, WWP. During this meeting,

18 Thomas Matthews, Chairman of the Board and Chief

19 Executive Officer for WWP spoke about the need for WWP to

20 increase its value to insure the company is not purchased

21 by a competitor and to allow the company to be

22 competitive moving forward. Although this is a concern

23 for many companies, is the propose rate increase

24 financing the increase in value and what is this cost and

25 what are the benefits to the customers?

1284

1A

1 As I stated earlier, the proposed 16.4% rate

2 increase equates to approximately $229,000 in increased

3 costs to SVR. To put this into perspective, $229,000 is

4 equal to:

5 a. 45,800 oz. of silver @ $5.00 oz. silver price

6 or;

7 b. 352,308 lbs. of copper @ $.65 lb. copper or;

8 c. Over 1,000 ft. of underground tunnel

9 development or;

10 d. 25% of SVR's capital expenditures for 1999.

11 In closing, if a rate increase is warranted, I

12 request that the increase be justified and not create

13 substantial financial impacts on the customers. I would

14 also ask that the increase be equally divided between all

15 customers of Avista.

16 Thank you again for allowing me to testify in this

17 proceeding.

18

19

20

21

22

23

24

25

1285

2

1 (The following proceedings were had in

2 open hearing.)

3 COMMISSIONER SMITH: Mr. Ward, do you have

4 questions?

5 MR. WARD: No, thank you.

6 COMMISSIONER SMITH: Mr. Woodbury.

7 MR. WOODBURY: No. Staff again appreciates

8 the comments of Mr. Iverson, but has no questions.

9 COMMISSIONER SMITH: Mr. Meyer.

10 MR. MEYER: No.

11 COMMISSIONER SMITH: And from the

12 Commission?

13 Thank you, Mr. Iverson. I guess we should

14 have asked him about the fluctuating price of silver.

15 THE WITNESS: Yeah.

16 (The witness left the stand.)

17 MR. SHURTLIFF: That would complete our

18 case in chief.

19 COMMISSIONER SMITH: Thank you,

20 Mr. Shurtliff. It appears that all the persons that I

21 have on my list who should appear as witnesses have

22 appeared. Are there other matters that need to come

23 before the Commission now?

24 Mr. Meyer.

25 MR. MEYER: I know that I inquired at the

1286

CSB REPORTING IVERSON
Wilder, Idaho 83676 Silver Valley Resources

1 time of the motion as to whether or not after two days of

2 evidentiary hearings whether the Commission would be

3 prepared to rule on the motion and you indicated at that

4 time, appropriately so, that you didn't know, so I'll ask

5 again if the Commission intends to rule at this time.

6 COMMISSIONER SMITH: It's my understanding,

7 and the Commissioners can correct me if I'm wrong, that

8 we are not yet prepared to rule on that motion.

9 MR. MEYER: Okay, thank you.

10 COMMISSIONER SMITH: Does anyone feel the

11 need for closing arguments or remarks, briefs or any

12 other process in this matter? That's good for us.

13 That being the case, all exhibits which

14 have not previously been admitted into the record will

15 now be admitted if there's no objection.

16 (All exhibits previously marked for

17 identification were admitted into evidence.)

18 COMMISSIONER SMITH: I think that concludes

19 everything we came here to accomplish, and, therefore, we

20 are adjourned and the Commission will do its best to get

21 its order out as quickly as possible and certainly by our

22 deadline which I have calculated to be July 21st.

23 Thank you for your time and cooperation.

24 (The Hearing adjourned at 4:50 p.m.)

25

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CSB REPORTING COLLOQUY
Wilder, Idaho 83676

1 AUTHENTICATION

2

3

4 This is to certify that the foregoing

5 proceedings held in the matter of the application of The

6 Washington Water Power Company (now Avista Corporation

7 dba Avista Utilities - Washington Water Power Division)

8 for an order approving increased rates and charges for

9 electric service in the State of Idaho, commencing at

10 9:30 a.m., on Tuesday, June 8, and continuing through

11 Wednesday, June 9, 1999, at the Edgewater Resort,

12 56 Bridge Street, Sandpoint, Idaho, is a true and correct

13 transcript of said proceedings and the original thereof

14 for the file of the Commission.

15 Accuracy of all prefiled testimony as

16 originally submitted to the Reporter and incorporated

17 herein at the direction of the Commission is the sole

18 responsibility of the submitting parties.

19

20

21

22
CONSTANCE S. BUCY
23 Certified Shorthand Reporter #187

24

25

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CSB REPORTING AUTHENTICATION
Wilder, Idaho 83676