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J f i;JDAVID J. MEYER ..
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VICE PRESIDENT AND CHIEF COUNSEL FOR U Tit Ii IES.
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tt'~1-~ IONGOVERNMENTAL AND REGULATORY AFF AIRS
VISTA CORPORATION
O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: (509) 495-4316
FACSIMILE: (509) 495-4361
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF A VISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC AND
NATURAL GAS CUSTOMERS IN THE STATE~ IDmO
CASE NO. A VU-04-
CASE NO. A VU-04-
REBUTTAL TESTIMONY
TARAL.KNOX
FOR A VISTA CORPORATION
(ELECTRIC AND NATURAL GAS)
Please state your name, business address and present position with A vista
Corporation?
My name is Tara L. Knox and my business address is 1411 East Mission
Avenue, Spokane, Washington.I am employed as a Rate Analyst in the Rates and
Regulation Department.
Have you previously submitted direct testimony in this proceeding?
Yes, I sponsored the electric and natural gas cost of service studies.
What is the scope of your rebuttal testimony in this proceeding?
My testimony responds to the cost of service issues discussed in the testimony
of Staff witness Fuss, Potlatch witness Peseau, and Coeur Silver Valley witness Yankel.
Would you please summarize your rebuttal testimony?
With regard to natural gas cost of service, the Company finds Commission
staff recommendation for allocation of underground storage costs and related capacity release
revenues to be reasonable.
Regarding electric cost of service, the Company supports the following: 1) resource
costs should be excluded from the O&M portion of the four-factor allocator used for common
costs in the Company s cost of service study; 2) although 100% demand allocation is an
approach that could be used to classify transmission costs as described by witness Peseau, it
represents a material change from the peak credit methodology the Company has historically
applied and should not be used; and 3) the cost of primary distribution plant Mr. Yankel
proposes to assign to Schedule 25 customers is understated and cannot be reasonably
estimated without considerable additional investigation. The Company recognizes, however
Knox, Di - Reb
A vista Corporation
that the costs for these facilities probably fall between the Company s allocation and Mr.
Yankel ' s estimated assignment. Therefore, the Company proposes an intennediate cost
assignment.
Are you sponsoring any exhibits with your rebuttal testimony?
Yes. I am sponsoring two exhibits. Exhibit No. 28 includes revised Natural
Gas Cost of Service summary infonnation, and Exhibit No. 29 includes revised Electric Cost
of Service summary infonnation.
I. Gas Cost of Service Issues
Please describe the issue regarding Natural Gas underground storage
costs referred to earlier.
In the Company s cost of service study, underground storage costs and
capacity release revenues are spread to customer classes based on annual consumption. Staff
witness Fuss, on pages 11 through 13, recommends allocating underground storage costs by
consumption only during the winter months to better match the benefits received from these
assets. Mr. Fuss also recommends spreading underground storage capacity release revenue
(offset to cost) by another similar allocation factor. This factor is created from a combination
of winter monthly usage and scheduled withdrawals which essentially results in weighted
winter consumption.
What do you recommend in response to Mr. Fuss s proposal regarding
underground storage costs?
I have no philosophical obj ection to using an allocation based on winter
consumption to spread underground storage and related costs. In the Company s last natural
Knox, Di - Reb
A vista Corporation
gas general case in Idaho (Case No. WWP-88-5), the Company originally proposed using
winter thenns to allocate these costs for similar reasons, but at the conclusion of that case the
Commission selected annual throughput as the preferred option.
I am somewhat concerned about the lack of consistency between the allocations used
for underground storage costs versus the capacity release revenues. I see no reason why the
same allocation factor should not be used for both. While the weighted allocation is slightly
more refined, the winter thenn allocator is more straightforward and less complicated. The
resulting ratios are very similar and will produce nearly the same results. Therefore, I
propose using the less complicated winter thenn allocator for both underground storage costs
and capacity release revenues.
Have you prepared an exhibit summarizing the natural gas cost of service
results associated with the Company s proposed changes described above?
Yes. Exhibit No. 28 is a summary of the natural gas cost of service results
incorporating the proposed changes described above, and all non-contested natural gas
adjustments to the pro-forma results discussed in Mr. Falkner s rebuttal testimony.
II. Electric Cost of Service Issues
Moving on to electric cost of service, what issues are you addressing?
Three different cost of service issues were raised by the parties in this case that
I will address. Potlatch witness Peseau recommends two changes to the cost of service study:
a change to the calculation of the common cost allocator, and a change in the allocation
methodology for transmission costs. Coeur Silver Valley witness Yankel recommends direct
assignment of certain distribution costs to Schedule 25 customers.
Knox, Di-Reb
A vista Corporation
Regarding the common cost allocator, can you summarize the issue?
Yes. Dr. Peseau points out that resource costs (purchased power and fuel)
were not removed from the direct O&M expense portion of the four-factor allocator. He
discusses various reasons to support the exclusion of purchased power and fuel expenses
largely stemming from their volatility.
Do you agree that resource costs should be excluded from the direct
O&M expense portion of the four-factor allocator?
Yes.The theory behind moving to the four-factor allocation factor for
common costs was to emulate the four-factor allocation used for the Company s utility and
jurisdictional separation process. Examination of the detail behind the calculation of the
utility four-factor shows that resource costs are excluded from the direct O&M expense factor
calculation. Specifically, FERC Accounts 501 , 547, 555 , 557, & 565 are excluded from the
electric utility allocation factor.These resource costs tend to be high dollar value
transactions that do not require proportionate administrative support. Labor costs are also
excluded from the direct O&M portion of the four-factor to avoid double counting. In light
of this information, I find that the simplified direct O&M factor utilized in the Company Base
Case study should have been refined to exclude accounts 501 , 547, 555 , 557, 565 and labor
dollars. I have revised the Company s electric cost of service study to reflect this change.
What is the effect on the Company s Base Case electric cost of service
study when this one factor has been refined as you describe?
Exhibit No. 29, Page 1 , lines 1 through 8 show the incremental changes to rate
base, net income, rate of return and return ratio due entirely to modification of this one
Knox, Di - Reb
A vista Corporation
allocation factor.As you can see by the return ratio comparison below, while this
modification changes the absolute results, the basic under-earninglover-earning relationships
do not change a great deal.
Table 1
Rate Class Base Case Revised 4-factor Increase
Return Ratio Return Ratio (Decrease)
Residential Schedule 1 .42 .39 (0.03)
General Service Schedule 11-(0.05)
Large General Service Schedule 21-1.72 1.73
Extra Large General Service Schedule 25
Potlatch Lewiston Schedule 25P 1.11 1.19
Pumping Service Schedule 31-1.54 1.53 (0.01)
Street & Area Lights Schedules 41 - 49 (0.10)
Idaho Jurisdictional Total 1.00 1.00
This information is derived from columns K through M on Exhibit 29, Page 1.
Turning to the allocation of transmission costs, what is the issue here?
Dr. Peseau advocates using a 100% demand allocation for all transmission
costs. He cites Idaho Power Company and Avista s FERC transmission tariff utilization of
this approach to justify changing from Avista s traditional peak credit method.
Do you agree with Dr. Peseau s argument that transmission costs
embedded in bundled retail rates should be allocated in accordance with FERC tariffed
wholesale rates?
No.The wholesale transmission tariff cost analysis is independent from
transmission system cost analysis for jurisdictional ratemaking. From the perspective of
Knox, Di-Reb
A vista Corporation
jurisdictional retail ratemaking, the revenues from FERC transmission transactions are simply
an offset to transmission cost. As long as this revenue offset is allocated in the same manner
as the associated costs, customers are receiving a fair share of the benefits of non-retail usage
of the transmission system. State Commissions have jurisdiction over bundled retail rate
issues, and this Commission has consistently accepted Avista s combination of demand and
energy for the allocation of transmission costs.
Mr. Peseau mentions the Idaho Power Company transmission
classification methodology. How does Pacificorp (governed by the Idaho Commission)
allocate transmission costs?
Pacificorp, doing business as Utah Power in Idaho, also uses a combination of
energy and demand for jurisdictional separation and Idaho cost of service purposes. Each
company s system and circumstances should be evaluated on their own merits to determine
the best fit.
Please explain the peak credit classification theory the Company uses for
production and transmission costs?
The peak credit theory acknowledges that baseload production facilities
provide energy throughout the year as well as capacity during system peaks and likewise the
transmission system is required not only for use during peak times but for everyday delivery
of energy. The intent is to reflect how these systems are used by the consumers.
Does the Commission Staff take issue with the Company s peak credit
approach to transmission costs?
Knox, Di - Reb
A vista Corporation
No. Mr. Hessing accepted the Company cost of service methodology and
pointed out the value inherent in maintaining consistent methodology over time.
Do you agree with Dr. Peseau that transmission costs should be classified
1000/0 as demand-related in the Company s cost of service study?
No. Although this an accepted approach, I think the Company s peak credit
approach is equally valid and use of a consistent methodology over time is the overriding
factor.
Regarding Mr. Yankel's distribution plant assignment, what is the issue
involved here?
Mr. Yankel has proposed incorporating a direct assignment of primary
distribution costs in FERC Accounts 364, 365, 366, and 367 to Schedule 25 customers. The
method he used to estimate these costs is a ratio based on the sum of the circuit mileage from
the appropriate substation to each Schedule 25 customer.
Isn direct assignment of costs whenever possible preferred over
allocation in a cost of service study?
Yes, as long as it is a viable assignment. In this case there are a number of
problems with the flat circuit mileage approach to estimating the amounts assigned to these
customers.
What are the problems with Mr. Yankel's direct assignment?
First and foremost, the assignment process he uses does not account for the
relative cost of the conductor and other materials that are necessary to support the capacity
requirements of these extra large usage customers. The flat mileage based allocation implies
Knox, Di-Reb
A vista Corporation
that the major feeder lines necessary to ensure adequate capacity for these customers have the
same cost per mile as simple single-phase circuits serving residential neighborhoods. This is
clearly not the case. Additionally, the line mile measurement used by Mr. Yankel looked
only at the direct route from the closest substation to the customer. Some of these customers
may also receive power from alternative routes or other substations in the case of interruption
in power along the direct route. To the extent that other substations may be found to be
available as back-up resources, Mr. Yankel's assignment of primary distribution cost is
understated, as well as the current substation costs assigned to these customers in the
Company s study.
What would be required to come up with an acceptable direct assignment
of primary plant to these customers?
A thorough engineering cost analysis that incorporates the factors addressed
above would be required. A dollar estimate could then be assigned to Schedule 25 , with the
remaining primary distribution plant allocated by non-coincident peak demand to the other
customer groups.
What does Mr. Yankel's analysis indicate?
There is material difference between a primary demand allocation, used by the
Company, for these fourteen customers and Mr. Y ankel' s unweighted line mile analysis.
Given the limited distances observed between the Schedule 25 customers and the substations
that have been directly assigned to them, the Company believes that the demand allocation
used in its study overstates the relative primary plant costs related to these customers.
Knox, Di - Reb
A vista Corporation
The discussion above indicates that Mr. Yankel's cost study understates
primary distribution costs for Schedule 25 customers and the Company s Base Case
study overstates them. Do you have a proposal in response to this issue?
Yes. I have prepared a cost of service scenario that provides reasonable
movement between the two positions. In this analysis I have taken the plant dollars Schedule
25 customers were assigned for accounts 364, 365, 366, and 367 in Mr. Yankel's proposal
and added to that assignment one-half the difference between the Base Case study demand
allocated amounts and Mr. Yankel' s amounts.
What are the results of this scenario?
Exhibit No. 29, page 2 is the cost of service basic summary from this model
run. The refinement of the four-factor allocator has also been incorporated into this analysis.
On Exhibit No. 29, page 1 , lines 9 through 16 I illustrate the incremental changes in rate base
net income, rate of return, and return ratios compared to the results with only the refined four-
factor.
Knox, Di-Reb
A vista Corporation
Table 2
Rate Class Base Case Rev 4-factor Rev 4- factor &In crease
Return Return Direct Sch 25 (Decrease)
Ratio Ratio Return Ratio vs Base Case
Residential Schedule 1 .42 .36 (0.06)
General Service Sch 11-1.96 (0.10)
Lg General Svc Sch 21-1.72 1.73 1.68 (0.04)
Extra Lg Gen Svc Sch 25
Potlatch Lewiston Sch 25P 1.11 1.19 1.19
Pumping Service Sch 31-1.54 1.53 1.48 (0.06)
St & Area Lts Sch 41 - 49 (0.11)
Idaho Jurisdictional Total 1.00 1.00 1.00
This information is derived from columns K through M on Exhibit 29, Page 1.
How would you interpret the results shown here?
There is a material increase in the rate of return for Schedule 25 customers.
Naturally, in this type of cost study where the system total remains fixed, if one group is
relieved of cost responsibility, all other groups then absorb a portion of those costs. As can
be observed from Table 2 above, the negative impact on the other customer groups is not
nearly as dramatic as the positive impact on Schedule 25.
spread?
Have you shared this analysis with Mr. Hirschkorn for his work on rate
Yes. He was provided with a copy of the information on Exhibit No. 29, Page
2 for incorporation into his rebuttal testimony.
Does this conclude your pre-filed rebuttal testimony?
Yes.
Knox, Di - Reb
A vista Corporation
DA VID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
GOVERNMENT AL AND REGULA TORY AFFAIRS
VISTA CORPORATION
O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: (509) 495-4316
FACSIMILE: (509) 495-4361
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF A VISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC AND
NATURAL GAS CUSTOMERS IN THE STATEOF IDAHO
CASE NO. A VU-04-
EXHIBIT NO. 28
TARA L. KNOX
FOR AVIS T A CORPORATION
(NATURAL GAS)
Sumcost AVISTA UTILITIES Natural Gas Utility
Company Rebuttal Case Cost of Service General Summary Idaho Jurisdiction
As Filed Except UG by Winter Therms For The Twelve Months Ended December 31 2002
(b)(c) (d) (e)(f)
(g)
(h)(i)(k)
Residential Small Firm Large Firm Interrupt Transport
System Service Service Service Service Service
Description Total Sch 101 Sch 111 Sch 121 Sch 131 Sch 146Plant In Service
Production Plant
Underground Storage Plant 041 000 825,407 882 095 114 729 30,267 188 503
Distribution Plant 87,598 000 75,115,371 10,131,341 937 240 199,847 214 201Intangible Plant 766,000 652,766 047 694 902 591General Plant 943 000 064 228 706,537 486 762 89,987Total Plant In Service 99,348,000 657,773 11,811 019 128,149 246 778 504 281
Accum Depreciation
Production Plant
Underground Storage Plant (2,294 000)740,822)(401,414)(52,209)(13,773)(85 782)Distribution Plant (26,397 000)(22,793,740)880,654)(299 560)(63 624)(359 421)10 Intangible Plant (626,000)(533,435)(74 422)(7,109)555)(9,479)General Plant (2,076,000)(1,769,029)(246,806)(23,574)(5,157)(31,434)Total Accumulated Depreciation (31,393,000)(26,837 027)(3,603,296)(382 452)(84 110)(486,115)
13 Net Plant 67,955,000 57,820,746 207 723 745,696 162 668 018,16614 Accumlulated Deferred FIT 831 000)377 ,326)168,762)(111 636)(24,420)(148,856)
15 Miscellaneous Rate Base 315,000 708,793 413,156 68,398 16,278 108,376Total Rate Base 60,439 000 152 214 7,452,117 702,458 154,526 977 ,685
17 Revenue From Retail Rates 51,419 000 40,114 000 954 000 522 000 385,000 444 00018 Other Operating Revenues 156,000 923,063 174 952 20,538 163 283Total Revenues 575,000 037,063 128 952 542 538 390,163 476,283
Operating Expenses20 Purchased Gas Costs 35,803,000 300,352 924 182 262,412 312,556 3,497Underground Storage Expenses 134 000 101,687 23,448 050 805 01122 Distribution Expenses 207 000 895 249 222 617 40,382 744 40,00823 Customer Accounting Expenses 064 000 008 196 555 266 315 66824 Customer Information Expenses 260,000 222,668 23,961 925 035 7,41125 Sales Expenses 224,000 221 746 181
26 Admin & General Expenses 666,000 012,554 444 167 75,878 20,644 112 757Total O&M Expenses 358,000 34,762,453 688,111 391,951 345 107 170,378
28 Taxes Other Than Income Taxes 876 000 746,673 104,021 923 168 13,21529 Depreciation Expense
30 Underground Storage Plant Depr 105,000 79,680 373 390 630 926Distribution Plant Depreciation 125,000 841,640 226,067 23,626 013 28,65332 General Plant Depreciation 321,000 273,535 38,162 645 797 86033 Amortization of Intangible Plant 260,000 221 ,555 30,910 952 646 937Total Depr & Amort Expense 811,000 2,416,409 313,513 614 087 41 ,37735 Income Tax 251,000 503 655 511,382 111 21 ,809 157 042Total Operating Expenses 49,296,000 38,429 191 617,027 491 598 376 171 382 013
37 Net Income 279,000 607 873 511,926 50,940 13,992 270
38 Rate of Return 5.43%10%87%25%05%64%
39 Return Ratio
40 Interest Expense 902 000 2,456,092 357 816 33,729 7,420 46,944
Exhibit No. 28
T. Knox
Avista Corporation
Page 1 of 1
DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
GOVERNMENTAL AND REGULATORY AFF AIRS
VISTA CORPORATION
O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: (509) 495-4316
FACSIMILE: (509) 495-4361
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF A VISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC AND
NATURAL GAS CUSTOMERS IN THE STATE
OF IDmO
CASE NO. A VU-04-
EXHIBIT NO. 29
TARA L. KNOX
FOR A VISTA CORPORATION
(ELECTRIC)
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Sumcost AVISTA UTILITIES Idaho Jurisdiction Page 1 of 1Scenario: Rebullal3B Fix S19 & Modified DA Primary Cost of Service Basic Summary Electric Utility 06-3()'O4Last Idaho Method modified For The Twelve Months Ended December 31 , 2002
Common Costs by 4-Factor
(b)(c) (d) (e)(f)
(g)
(h)(i)(k)(I)(m)
Residential General Large Gen Extra Large Potlatch Pumping Street &
System Service Service Service Gen Service Ex Lg Gen Svc Service Area UghtsDescriptionTotalSch 1 Sch11.Sch 21-Sch 25 Sch 25P Sch 31-Sch 41.Plant In Service
Production Plant 300,269,000 103 855,863 23,871 210 64,089,462 28,322 636 527 729 560,417 041 683Transmission Plant 109,001 000 345 154 575 673 23,320 080 10,300,710 407,393 663,998 387 992Distribution Plant 257 643000 127,399,434 593,642 004,590 879 815 125,817 152,270 487 432Intangible Plant 353,000 974 306 112,097 134464 821 049 045,161 171,273 650General Plant 36,524 000 19,370,982 260,122 958 606 868 684 053,191 543,524 468,892Total Plant In Service 714 790 000 292 945,738 70,412 744 164,507202 50,192 894 110 159,291 091 481 14,480,649
Accum Depreciation
Production Plant (91 465,000)(31 590,537)260,043)(19,529,251)629,804)(22,746,584)390 227)(318,554)Transmission Plant (36,394 000)(12,469056)(2,863,304)786 268)(3,439272)150 968)(555,587)(129,546)Distribution Plant (75,640,000)(37 336,907)619 755)(19,099 874)(2,146,430)(546 491)(1,492 853)(5,397 690)Intangible Plant 893,000)(920,776)(203 944)(331 272)(115,953)(272 465)(28,354)(20,236)General Plant (16,434 000)(8,715 987)916,845)681 079)(840,816)823 736)(244 559)(210,978)Total Accumulated Depreciation (221,826,000)(91,033,263)(21 863 891)(49,427 744)(15 172,273)(34,540,244)(3,711 580)(6,077,004)
Net Plant 492 964,000 201,912 475 548,853 115 079,458 35,020,621 75,619,047 379 901 403,646Accumulated Deferred FIT (61 593,000)(25,223,999)(6,070,048)(14 216,118)320,525)457 927)043785)260,598)Miscellaneous Rate Base 836,000 748 569 654 105 005 992 903,580 362,172 136,112 25,470Total Rate Base 440,207 000 179,437 046 43,132 910 102,869 332 603,676 523292 7,472,228 168,517
Revenue From Retail Rates 146,248,000 648,000 16,212000 804,000 10,475 000 696000 549,000 864 000Other Operating Revenues 677,000 589 955 752 962 664,028 005,124 226957 332 591 105 383Total Revenues 167 925,000 237,955 964 962 39,468028 480,124 922 957 881 591 969,383
Operating Expenses
Production Expenses 522 000 179 034 239 677 023454 518 503 20,060,876 215,561 284 895Transmission Expenses 485 000 879,232 431 533 173,481 518,338 379,158 83,733 19,524Distribution Expenses 495,000 929,307 902,478 794858 272,303 378 150,887 377,789Customer Accounting Expenses 296 000 174073 712,481 196,952 870 200 053 370Customer Information Expenses 1,480 000 589,887 129 334 283,641 124 152 326 637 592 756Sales Expenses 421 000 134538 672 568 40,311 115 486 659 767Admin & General Expenses 888,000 093,327 028,086 118,712 973,301 154 072 272 384 248,118Total O&M Expenses 115 587 000 979,397 10,474 262 23,682 665 502 778 199 807 801,870 946,220
Taxes Other Than Income Taxes 438,000 081 908 753,505 782,908 490 405 013,124 130,425 185,726Other Income Related Items
Depreciation Expense
Production Plant Depreciation 933 000 759,593 634,649 690 789 747 420 953,357 120 107 085Transmission Plant Depreciation 532 000 867,496 199,206 541 706 239 277 636,650 653 013Distribution Plant Depreciation 670,000 757 911 712447 1,456,706 174 736 654 111 808 407 738General Plant Depreciation 892,000 064,173 453,959 634 949 199 127 431 908 918 49,965Amortization Expense 367000 134,172 004 216 225 910 5,401 073Total Depreciation Expense 394 000 583,345 031 264 401 366 394 785 154,480 333,887 494 873Income Tax 794 000 556,313 728 569 486,433 169 087 705,286 95,277 53,035Total Operating Expenses 147 213,000 200,963 13,987 600 353,373 557 054 072,697 361,459 679,855
Netlncome 712 000 036,993 977 362 114 655 923 070 850,260 520,132 289 528
Rate of Return 71%69%22%89%92%62%96%04%Return Ratio 1.00 1.96 1.68 1.19 1.48Interest Expense 20,250 000 254299 984 161 732 101 1,453,803 152 146 343 731 329 760
Exhibit No, 29
T. Knox
Avista Corporation
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