20130122DIRECT H.Lay.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF ROCKY )
MOUNTAIN POWER'S )
APPLICATION FOR AN ORDER )
AUTHORIZING CHANGES IN )
DEPRECIATION RATES )
APPLICABLE TO ELECTRIC )
PROPERTY )
CASE NO. PAC-E-13-02
Direct Testimony of Henry E. Lay
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-13-02
January 2013
I Q. Please state your name, business address and position with PacifiCorp dlb/a
2 Rocky Mountain Power (the "Company").
3 A. My name is Henry E. Lay. My business address is 825 NE Multnomah Street,
4 Suite 1900, Portland, Oregon, 97232. I am employed by the Company as
5 corporate controller.
6 Qualifications
7 Q. Please briefly describe your education and professional experience.
8 A. I have a Bachelor of Science degree in Accounting from the University of Utah. I
9 have worked for the Company for over 37 years, primarily in corporate
10 accounting management roles. The areas for which I have been responsible
11 include asset\plant accounting, corporate\general accounting, regulatory
12 accounting, and customer accounting. In the past, I have personally prepared
13 depreciation studies for the Company. I have also supervised the independent
14 experts the Company has retained to conduct the current and past depreciation
15 studies.
16 Purpose of Testimony
17 Q. What is the purpose of your testimony?
18 A. The purpose of my testimony is as follows:
19 • I summarize the Company's proposal for new depreciation rates and the effect
20 on annual depreciation expense from applying the proposed depreciation rates
21 to depreciable plant balances. The proposed rates are contained in the
22 depreciation study based on projected December 31, 2013 balances performed
23 on behalf of the Company by Mr. John J. Spanos of Gannett Fleming, Inc.
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I ("Depreciation Study"). The Depreciation Study is provided as Exhibit No. 3.

2 • I provide background information describing the development of the

3 Depreciation Study and explain why I believe the depreciation rates resulting

4 from the Depreciation Study are accurate and reasonable.

5 • I explain the impact of the Depreciation Study on Idaho as a result of previous

6 regulatory actions.

7 • I identify and discuss the significant issues considered during the preparation

8 of the Depreciation Study. The disposition of these issues was reflected in the

9 data provided to Mr. Spanos and, in turn, this data formed the basis for the

10 Depreciation Study and the recommended changes in depreciation rates.

11 • I introduce the other Company witnesses who will testify in this proceeding

12 and provide a brief description of the subject matter on which they are

13 testifying.

14 • I briefly summarize the Company's recommendations to the Idaho Public

15 Utilities Commission ("Commission").
16 Results of the Depreciation Study

17 Q. Please explain the depreciation rates for which the Company is seeking

18 Commission approval in this proceeding.

19 A. With this Application the Company seeks Commission approval of the

20 depreciation rates contained in the Depreciation Study based on December 31,

21 2013 projected plant balances. Based on the Depreciation Study prepared by Mr.

22 Spanos the Company proposes a system-wide increase of 0.37 percent (or 0.70

23 percent including the accelerated depreciation associated with early retirement of
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I the Carbon plant) to the current composite depreciation rate of 2.54 percent for

2 the Company's electric utility plant, resulting in a new composite depreciation

3 rate of 2.91 percent (or 3.24 percent including the Carbon plant). The specific

4 depreciation rate changes recommended for the components of the composite

5 depreciation rate are summarized in Mr. Spanos' testimony and set forth in

6 account detail in the Appendix to the Depreciation Study.

7 Q. Please explain how the depreciation rates were developed.

8 A. The Company instructed Mr. Spanos to use December 31, 2011, historical data as

9 the basis for his depreciation life study analysis, which was then used to develop

10 depreciation rates based on projected December 31, 2013 plant balances. This

11 process is further described in Mr. Spanos' testimony.

12 Q. What is the effect on annual depreciation expense if the depreciation rates

13 recommended by Mr. Spanos are adopted?

14 A. The effect of applying the recommended depreciation rates to the projected

15 December 31, 2013 depreciable plant balances is an increase in total Company

16 annual depreciation expense of approximately $83.9 million (or $160.8 million

17 including Carbon plant), compared with the level of annual depreciation expense

18 developed by application of the currently authorized depreciation rates to the

19 same plant balances. Annual depreciation expense by functional plant

20 classification is summarized in the Appendix to the Depreciation Study.

21 Adoption of the depreciation rates proposed in the Depreciation Study

22 results in an increase of approximately $4.5 million (or $8.9 million including the

23 Carbon Plant) in annual Idaho jurisdiction depreciation expense, based on
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I projected December 31, 2013 depreciable plant balances. The calculation of the

2 Idaho jurisdictional amount under the 2010 Protocol methodology is described in

3 Exhibit No. 1.

4 Q. What does the Company propose as the effective date for implementing the

5 new depreciation rates?

6 A. The Company's accounting system maintains depreciation rates on a calendar

7 year basis. Therefore, the Company proposes that the new depreciation rates be

8 made effective January 1, 2014, which is the beginning of the next calendar year

9 following the anticipated approval of the study.

10 Q. Please describe the treatment of the Carbon Plant related depreciation

11 expense in the depreciation study and how the changes will be treated for

12 ratemaking.

13 A. In the Depreciation Study, the Carbon Plant depreciation rate is increased to 67

14 percent to recover the entire remaining plant balance and estimated removal costs

15 prior to the projected plant closure in 2015. To eliminate the rate shock associated

16 with the decommissioning of the Carbon plant the Company filed for a deferred

17 accounting order authorizing creation of a regulatory asset associated with the

18 plant closure, (Case No. PAC-E-12-08). The Commission's final Order 32701

19 approved the Company's request to create a regulatory asset for these costs.

20 For Carbon the regulatory asset will consist of the difference between the

21 new depreciation rate effective in 2014 from the Depreciation Study and the

22 depreciation rate based on the prior decommissioning date of 2020. The Company

23 will continue to include depreciation expense in rates at the currently approved
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I depreciation rate of 444305 percent as set in the 2007 depreciation study and
2 used for setting rates in the last general rate case. Any difference between the
3 current rate of 4443.05 percent and the new rate used by the Company for
4 depreciation expense (currently estimated at 67 percent) will be recorded as a
5 regulatory asset with recovery through 2020
6 The Carbon removal costs will also be excluded from the depreciation rate
7 and recorded as part of the regulatory asset. The removal costs will be included in
8 the next general rate case and the estimate will be updated based on the best
9 available removal cost projections at that time. The Company will request
10 recovery of the removal costs through 2020 in the next general rate case
11 consistent with the depreciation
12 Depreciation Study Background
13 Q. Please explain the concept of depreciation.
14 A There are many definitions of depreciation The following definition was put
15 forth by the American Institute of Certified Public Accountants in its Accounting
16 Research Bulletin #43
17 Depreciation accounting is a system of accounting which aims to
18 distribute the cost or other basic value of tangible capital assets,
19 less salvage (if any), over the estimated useful life of the unit
20 (which may be a group of assets) in a systematic and rational
21 manner. It is a process of allocation, not of valuation.
22 The actual payment for an electric utility plant asset occurs in the period in
23 which it is acquired through purchase or construction Depreciation accounting
24 spreads this cost over the useful life of the property. The fundamental reason for
25 recording depreciation is to provide for accurate measurement of a utility's results
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Rocky Mountain Power
I of operations. Capital investments in the buildings, plant, and equipment
2 necessary to provide electric service are essentially a prepaid expense, and annual
3 depreciation is the part of that expense applicable to each successive accounting
4 period over the service life of the property. Annual depreciation is an important
5 and essential factor in informing investors and others of a company's periodic
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9 A.
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income. If it is omitted or distorted, a company's periodic income statement is
distorted and would not meet required accounting and reporting standards.
Why is depreciation important to an electric utility?
An electric utility is very capital intensive; that is, it requires a tremendous
investment in generation, transmission, and distribution equipment with long lives
in order to provide electric service to customers. Thus, the annual depreciation of
this equipment is a major item of expense to the utility. Regulated electric prices
are expected to allow the utility to fully recover its operating costs, earn a fair
return on its investment and equitably distribute the cost of the assets to the
customers using these facilities. If depreciation rates are established at an
unreasonably low or high level for ratemaking purposes, the utility will not
recover its operating costs in the appropriate period, which will shift either costs
or benefits from current customers to future customers.
19 Q. Why was it necessary for the Company to conduct the Depreciation Study?
20 A. It is sound accounting practice to periodically update depreciation rates to
21 recognize additions to investment in plant assets and to reflect changes in asset
22 characteristics, technology, salvage, removal costs, life span estimates, and other
23 factors that impact depreciation rate calculations. The Company conducts
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Rocky Mountain Power

1 depreciation studies as it deems appropriate or as mandated by the Commission.

2 The Company's last Depreciation Study was conducted approximately five years

3 ago. The Company's current depreciation rates in Idaho were effective on January

4 1, 2008, based on a 2007 Depreciation Study.

5 Q. Was the Depreciation Study prepared under your direction?

6 A Yes As corporate controller, .I have responsibility for the Company's corporate

7 accounting departments and for ensuring compliance with Company accounting

8 policies and procedures This includes periodic review and study of depreciation

9 rates.

10 Q. Do you believe that the estimated plant depreciable lives and depreciation

11 rates developed in the Depreciation Study result in a fair level of depreciation

12 expense for customers to reimburse the Company for its investment in

13 electric utility plant and equipment?

14 A. Yes, I believe that the Depreciation Study is well supported by the underlying

15 engineering and accounting data and that the resulting depreciation rates produce

16 an annual depreciation expense that is fair and reasonable for both financial

17 reporting and ratemaking purposes.

18 Q. What is the basis for your conclusions about the Depreciation Study?

19 A. I believe that a good depreciation study is the product of sound analytical

20 procedures applied to accurate, reliable accounting and engineering data. I have

21 reviewed Mr. Spanos' work in preparing the Depreciation Study and I concur

22 with his choice and application of analytical procedures as described in his

23 testimony. With respect to data inputs, the estimated generation plant economic
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1 lives used in the study are those provided by the Company as explained in
2 Company Witness Mr. K. Ian Andrews' testimony. Depreciable life estimates for
3 other types of plant and equipment are based on Mr. Spanos' actuarial analysis of
4 the data and reviewed for reasonableness by the Company. The accounting data
5 has also been carefully and consistently prepared. I recommend approval of the
6 rates contained in the Depreciation Study.
7 Significant Issues
8 Q. Please summarize the significant issues you considered in your supervision of
9 the Depreciation Study.
10 A. The most significant issue considered in the current study relates to the impact of
11 incremental capital additions on the Company's steam generation facilities. These
12 capital additions are the most significant factor creating the increase in
13 depreciation expense. Further explanation of this issue is included in Company
14 Witness Mr. Andrews' testimony.
15 Q. Is this a new issue in relationship to the steam generation facilities?
16 A. No, this issue was identified in the last depreciation study where the Company
17 proposed to include projected capital additions into depreciation rates to help
18 mitigate potential future depreciation step increases. The depreciation rates arising
19 out of that study did not allow any recognition of additions occurring after the
20 implementation of those rates.
21 Q. Did the Company consider extending the depreciation lives of the steam
22 generation facilities to mitigate the increase in depreciation expense?
23 A. Yes, but recognizing the uncertainty regarding the period in which steam
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I generation facilities will be allowed to continue to operate, the Company is
2 continuing to recommend retaining 61 years, as previously approved by the
3 Commission, as the depreciable terminal life of steam generating facilities where
the Company is not a minority owner.
What is the significant issue related to hydroelectric facilities you considered
in the Depreciation Study?
The 2007 Depreciation Study based hydroelectric plant terminal lives primarily
on Federal Energy Regulatory Commission ("FERC") hydroelectric plant license
termination dates. For this study, the Company has continued to use the FERC
hydroelectric plant license termination dates and have updated those lives where
new licenses have been issued.
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12 Q. What are the other issues related to hydroelectric facilities you considered in
13 this study?
14 A. The 2007 Depreciation Study included removal cost for hydroelectric facilities
15 where the Company has entered into negotiations or settlements to remove those
16 facilities, as well as a decommissioning reserve for minor hydroelectric facilities
17 that may be removed within the next 10 years. The Company has updated the
18 Depreciation Study to reflect the current projection for small plants where the
19 Company has estimated some probability of them being decommissioned in the
20 next 10-year period. This reserve is not intended to cover the decommissioning or
21 removal of any large facility.
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I Q. What is the significant issue related to wind generation facilities in the
2 Depreciation Study?
3 A. Since preparation of the 2007 depreciation study the Company has added more
4 renewable resources to its generation portfolio, with the expansion of the
5 Company's wind generation fleet, the Company has gained more experience
6 related to the operation and maintenance of wind generation facilities. As part of
7 the Depreciation Study, the Company is recommending extending the terminal
8 lives of wind generation facilities by five years. This issue is discussed further in
9 Mr. Andrews' testimony.
10 Q. What is the significant issue related to gas generation facilities in the
11 Depreciation Study?
12 A. - Since the 2007 Depreciation Study, the Company has experienced a number of
13 required overhauls on its gas generation facilities. This information has been
14 provided to Mr. Spanos and has been included in the Depreciation Study. This
15 experience has resulted in a significant increase in interim retirements, which
16 produced an increase in depreciation rates.
17 Q. Were there any significant changes in the Depreciation Study related to
18 transmission and distribution plant assets?
19 A. No. Mr. Spanos was provided the historical data for both transmission and
20 distribution assets including removal costs, salvage, and third party
21 accommodation payments related to removal cost to use in determining the
22 proposed depreciation lives and rates. There were no significant changes outside
23 of those which would normally result from updating the study.
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Rocky Mountain Power

I Q. What is the significant issue related to general plant facilities in this study?

2 A. The Company has opted to apply FERC accounting release 15 to the remainder of

3 communication equipment not previously included. In accordance with this

4 accounting standard, the Company will apply a 24-year life, which is the

5 composite of the lives approved in the last study.

6 Q. What is the significant issue related to mining facilities in this study?

7 A. Since the last study, significant changes in underground mining safety

8 requirements coupled with additional geologic analysis have resulted in reduced

9 levels of economically recoverable reserves at the Company's Deer Creek mine.

10 The Company has updated the life of the mine based on its most current

11 information.
12 Introduction of Witnesses

13 Q. Who will be testifying on behalf of the Company in support of the

14 Company's petition?

15 A. Two other witnesses will testify on behalf of the Company: Mr. John J. Spanos,

16 Senior Vice President of Gannett Fleming, Inc. and Mr. K. Ian Andrews, Manager

17 of Resource Development for PacifiCorp.

18 Mr. Spanos presents the Depreciation Study and the depreciation rates for

19 which the Company is seeking Commission approval. He describes how the

20 Depreciation Study was prepared and discusses the basis for the recommended

21 changes in depreciation rates.

22 Mr. Andrews describes the process used by Company engineers to

23 evaluate the current approved plant depreciable lives for steam generation plants.
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I He describes the procedure used to estimate the retirement date for the

2 Company's gas, wind and hydroelectric generation resources. He demonstrates

3 that the estimated retirement dates proposed by the Company for generation

4 plants are reasonable and prudent and are appropriate inputs for Mr. Spanos'

5 depreciation analysis. Jvfr. Andrews also explains why the rates the Company

6 proposes to include as terminal net salvage, or "decommissioning costs," in the

7 calculation of deprciation rates for generation plants are reasonable and prudent.
8 Summary of Recommendations

9 Q. Please summarize your recommendations to the Commission.

10 A. I recommend that the Commission find that the depreciation rates sponsored by

11 Mr. Spanos in the Depreciation Study based on projected December 31, 2013

12 balances are proper and adequate depreciation rates for the Company and will

13 result in fair and reasonable rates that accurately reflect costs on those customers

14 for whom such costs are incurred. I further recommend that the Commission order

15 the Company to implement these depreciation rates in its accounts and records

16 effective January 1, 2014.

17 Q. Does this conclude your direct testimony?

18 A. Yes.
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Case No. PAC-E-13-02
Exhibit No. 1
Witness: Henry E. Lay
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Henry E. Lay
Calculation of the Idaho Jurisdictional
Amount Under the 2010 Protocol Methodology
January 2013
Allocation Factor Table
ID
CA 0.0000%
CN 3.8582%
ID 100.0000%
OR 0.0000%
SE 6.2744%
SG 5.6449%
SO 5.5148%
SSGCH 5.6449%
SSGCT 5.9326%
UT 0.0000%
WA 0.0000%
WY 0.0000%
Source: Factors from
December 2011 Semi-Annual
Report -2010 Protocol and 13
Month Average
PACIFICORP
Depreciation Rate Comparison - Plant Balances as of December, 2013
Depreciation Rate Total Company Depreciation ALLOCATED
Description AF Plant-in-Service EXISTING I PROPOSED EXISTING PROPOSED I DIFFERENCE ID
Production Plant
Steam Production SG 6,108,552,080 2.26% 3.58% 137,945,075 218,930,804 80,985,729 4,571,547
Steam Production - Cholla SSGCFI 536,902,995 1.51% 2.88% 8,121,741 15,449,657 7,327,916 413,652
Steam Production - Carbon SG 120,084,309 3.05% 67.13% 3,662,198 80,614,396 76,952,198 4,343,859
Steam Production - Water Rights 36,503,523
Hydro Production SG 938,122,143 2 91% J%
_______
27,268 605 J48,744 6,680,139 377 086
Other Production SG 3,230,056,230 3.50% 3.27% 113,080,152 105,596,499 (7,483,653) (422,443)
Other Production - Gadsby Peakers SSGCT 83,587,219 3.32% 3.99% 2,774,825 3,332,766 557,941 33,100
Other Production - Water Rights 17,420,186
Total Production Plant 11,071.228,687
Distribution Plant
Distribution CA 231,412,734 2.91% 2.67% 6,724,725 6,171,346 (553,379) -
Distribution OR 1,800,233,098 2.86% 2.54% 51,408,119 45,706,796 (5,701,323) -
Distribution WA 414,312,516 3.13% 12,981,304 4 (1,335,043)
Distribution WY 635,669,345 2.87% 2.84% 18,246,611 18,062,124 (184,487) -
Distribution UT 2,524,656,040 2.52% 2.46% 63,524,102 62,029,227 (1,494,875) -
Distribution ID 297,471,473 2.59% 2.27% 7,694,643 6,759,630 (935,013 (935,013)
General Plant - Vehicles *
General Plant - Vehicles 392.1 CA CA 668,807 7.89% 3.48% 52,773 23,274 (29,499) -
General Plant - Vehicles 392.1 CA SG 159,467 7.89% 3.48% 12,583 5,549 (7,034) (397)
General Plant - Vehicles 392.1 ID ID 1,685,882 6.66% 7.11% 112,265 119,866 7,601 7,601
General Plant - Vehicles 392.1 ID SG 552,076 6.66% 7.11% 36,764 39,253 2,489 141
General Plant - Vehicles 392.1 OR OR 9,772,343 7.63% 7.27% 745,154 710,449 (34,704) -
General Plant - Vehicles 392.1 OR SG 682,209 7.636/. 7.27% 52,019 49,597 (2,423) (137)
General Plant - Vehicles 392.1 OR 50 470,991 7.63% 7.27% 35,914 34,241 (1,673) (92)
General Plant - Vehicles 392.1 OT SG 459,186 6.42% 2.53% 29,462 11,598 (17,864) (1,008)
General Plant - Vehicles 392.1 UT SE 128,866 7.07% 6.93% 9,111 8,930 (181) (11)
General Plant - Vehicles 392.1 UT SG 2,446,693 7.07% 6.93% 172,985 169,556 (3,429) (194)
General Plant - Vehicles 392.1 UT SO 1,613,206 7.07% 6.93% 114,056 111,795 (2,261) (125)
General Plant - Vehicles 392.1 UT UT 9,673,376 7.07% 6.93% 683,922 670,365 (13,557) -
General Plant - Vehicles 392.1 WA SG 713,985 7.91% 5.60% 56,451 39,983 (16,468) (930)
General Plant - Vehicles 392.1 WA WA 1,683,994 7.91% 5.60% 133,145 94,304 (38,841) -
General Plant - Vehicles 392.1 WY SG 1,853,905 7.34% 7.01% 136,112 129,959 (6,154) (347)
General Plant - Vehicles 392.1 WY WY 2,834,019 7.34% 7.01% 208,072 198,665 (9,407) -
General Plant - Vehides 392.3 UT SO 3,076,269 3.59% 3.42% 110,313 105,208 (5,105) (282)
General Plant - Vehicles 392.5 CA CA 797,625 5.63% 4.49% 44,885 35,813 (9,072) -
General Plant - Vehicles 392.5 CA SG 164,303 5.63% 4.49% 9,246 7,377 (1,869) (105)
General Plant - Vehicles 392.5 ID ID 2,443,129 5.22% 5.73% 127,632 139,991 12,360 12,360
General Plant - Vehicles 392.5 ID SG 382,200 5.22% 5.73% 19,967 21,900 1,934 109
General Plant - Vehicles 392.5 OR OR 9,616,255 5.05% 5.67% 485,727 545,242 59,515 -
General Plant - Vehicles 392.5 OR SG 992,358 5.05% 5.67% 50,125 56,267 6,142 347
General Plant - Vehicles 392.5 OT SG 255,349 2.96% 2.10% 7,567 5,368 (2,199) (124)
General Plant - Vehicles 392.5 UT SE 199,475 5.41% 5.59% 10,797 11,151 353 22
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Description AF Plant-in-Service
Depreciation Rate Total Company Depreciation ALLOCATED
EXISTING PROPOSED EXISTING PROPOSED I DIFFERENCE ID
General Plant - Vehicles 392.5 UT SG 4,143,374 5.41% 5.59% 224,276 231,615 7,338 414
General Plant - Vehicles 392.5 UT SO 776,182 5.41% 5.59% 42,014 43,389 1,375 76
General Plant - Vehicles 392.5 UT UT 15,396,189 5.41% 5.59% 833,379 860,647 27,268 -
General Plant - Vehicles 392.5 WA SG 1,424,088 6.66% 5.07% 94,781 72,201 (22,580) (1,275)
General Plant - Vehicles 392.5 WA WA 2,643,534 6.66% 5.07% 175,942 134,027 (41,915) -
General Plant - Vehicles 392.5 WY SG 1,873,720 6.80% 6.38% 127,386 119,543 (7,843) (443)
General Plant - Vehicles 392.5 WY WY 4,305,701 6.80% 6.38% 292,726 274,704 (18,022) -
General Plant - Vehicles 392.9 CA CA 437,317 2.69% 2.32% 11,752 10,146 (1,606) -
General Plant - Vehicles 392.9 CA SG 13,876 2.69% 2.32% 373 322 (51) (3)
General Plant - Vehicles 392.9 ID SG 893,408 2.50% 2.73% 22,369 24,390 2,021 114
General Plant - Vehicles 392.9 ID ID 49,887 2.50% 2.73% 1,249 1,362 113 113
General Plant - Vehicles 392.9 OR OR 3,191,788 2.45% 2.56% 78,277 81,710 3,433 -
General Plant - Vehicles 392.9 OR SG 132,522 2.45% 2.56% 3,250 3,393 143 8
General Plant - Vehicles 392.9 OR SO 3,421 2.45% 2.56% 84 88 4 0
General Plant - Vehicles 392.9 UT SE 45,180 2.57% 2.60% 1,159 1,175 15 1
General Plant - Vehicles 392.9 UT SG 1,198,511 2.57% 2.60% 30,754 31,161 407 23
General Plant - Vehicles 392.9 UT SO 474,168 2.57% 2.60% 12,167 12,328 161 9
General Plant - Vehicles 392.9 UT UT 4,880,292 2.57% 2.60% 125,229 126,888 1,658 -
General Plant - Vehicles 392.9 WA SG 83,653 2.65% 2.38% 2,214 1,991 (223) (13)
General Plant - Vehicles 392.9 WA WA 685,566 2.65% 2.38% 18,143 16,316 (1,826) -
General Plant - Vehicles 392.9 WY SG 569,316 3.37% 3.40% 19,177 19,357 180 10
General Plant - Vehicles 392.9 WY WY 2,303,712 3.37% 3.40% 77,597 78,326 729 -
General Plant - Vehicles 392.9 OT SG 7,844 2.18% 2.18% 171 171 (0) (0)
General Plant - Vehicles 396.3 CA CA 918,154 10.34% 7.20% 94,923 66,107 (28,816) -
General Plant - Vehicles 396.3 ID SG 1,567,172 9.15% 12.04% 143,461 188,688 45,226 2,553
General Plant - Vehicles 396.3 ID ID 66,834 9.15% 12.04% 6,118 8,047 1,929 1,929
General Plant - Vehicles 396.3 OR OR 6,104,847 9.71% 8.84% 592,583 539,668 (52,915) -
General Plant - Vehicles 396.3 OR SG 60,453 9.71% 8.84% 5,868 5,344 (524) (30)
General Plant - Vehicles 396.3 UT SG. 51,662 10.07% 9.86% 5,201 5,094 (107) (6)
General Plant - Vehicles 396.3 UT UT 5,429,736 10.07% 9.86% 546,602 535,372 (11,230) -
General Plant - Vehicles 396.3 WA SG 58,134 9.69% 5.66% 5,634 3,290 (2,344) (132)
General Plant - Vehicles 396.3 WA WA 1,370,946 9.69% 5.66% 132,871 77,596 (55,276) -
General Plant - Vehicles 396.3 WY SG 61,879 10.37% 9.64% 6,419 5,965 (454) (26)
General Plant - Vehicles 396.3 WY WY 2,569,556 10.37% 9.64% 266,551 247,705 (18,846) -
General Plant - Vehicles 396.7 CA CA 3,051,020 5.60% 4.98% 170,993 151,941 (19,052) -
General Plant - Vehicles 396.7 ID ID 6,468,406 3.87% 3.90% 250,428 252,268 1,839 1,839
General Plant - Vehicles 396.7 ID SG 879,645 3.87% 3.90% 34,056 34,306 250 14
General Plant - Vehicles 396.7 OR OR 24,441,728 5.39% 5.24% 1,317,716 1,280,747 (36,970) -
General Plant - Vehicles 396.7 OR SG 1,513,765 5.39% 5.24% 81,611 79,321 (2,290) (129)
General Plant - Vehicles 396.7 OT SG 2,250,062 2.71% 1.86% 60,947 41,933 (19,014) (1,073)
General Plant - Vehicles 396.7 UT SE 45,854 6.84% 6.10% 3,135 2,797 (338) (21)
General Plant - Vehicles 396.7 UT SG 13,051,444 6.84% 6.10% 892,419 796,138 (96,281) (5,435)
General Plant - Vehicles 396.7 UT SO 1,046,883 6.84% 6.10% 71,583 63,860 (7,723) (426)
General Plant - Vehicles 396.7 UT UT 37,298,792 6.84% 6.10% 2,550,381 2,275,226 (275,155) -
General Plant - Vehicles 396.7 WA SG 415,484 6.81% 6.03% 28,282 25,054 (3,228) (182)
General Plant - Vehicles 396.7 WA WA 5,630,534 6.81% 6.03% 383,268 339,521 (43,747) -
General Plant - Vehicles 396.7 WY SG 19,993,847 5.19% 4.94% 1,038,116 987,696 (50,420) (2,846)
General Plant - Vehicles 396.7 WY WY 12,635,403 5.19% 4.94% 656,053 624,189 (31,864) -
Total General Plant - Vehicles* 245,841,456 6.10% 5.75% 14,996,739 14,128,823 (867,916) 11,891
rocation Factor Table
ID
. 0) 0 C) CD z z'< (npp
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I1
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Depreciation Rate Total Company Depreciation ALLOCATED
EXISTING I PROPOSED EXISTING PROPOSED DIFFERENCE ID Description AF Plant-in-Service
General Plant - All Other
General Plant - All Other 389.2 ID ID 4,733 2.01% 1.71% 95 81 (14) (14)
General Plant - All Other 389.2 UT SG 1,171 2.32% 2.15% 27 25 (2) (0)
General Plant - All Other 389.2 UT UT 32,503 2.32% 2.15% 754 699 (55) -
General Plant - All Other 389.2 WY WY 74,342 2.01% 2.01% 1,491 1,494 3 -
General Plant - All Other 390 CA CA 2,936,056 2.38% 1.71% 69,829 50,083 (19,746) -
General Plant - All Other 390 ID ID 10,530,869 2.12% 1.86% 222,839 195,936 (26,903) (26,903)
General Plant - All Other 390 ID SG 1,326,754 2.12% 1.86% 28,075 24,678 (3,397) (192)
General Plant - All Other 390 ID SO 712,206 2.12% 1.86% 15,071 13,247 (1,824) (101)
General Plant - All Other 390 OR OR 32,159,408 2.21% 1.98% 711,644 634,943 (76,700) -
General Plant - All Other 390 OR SG 2,897,547 2.21% 1.98% 64,119 57,371 (6,747) (381)
General Plant - All Other 390 OR SO 39,342,704 2.21% 1.98% 870,601 778,986 (91,615) (5,052)
General Plant - All Other 390 OT SG 374,091 2.06% 1.51% 7,721 5,647 (2,074) (117)
General Plant - All Other 390 UT CN 7,839,508 2.18% 2.06% 171,280 161,494 (9,786) (378)
General Plant - All Other 390 UT SG 2,093,476 2.18% 2.06% 45,739 43,126 (2,613) (148)
General Plant - All Other 390 UT SO 39,519,198 2.18% 2.06% 863,426 814,095 (49,331) (2,720)
General Plant - All Other 390 UT UT 38,830,771 2.18% 2.06% 848,385 802,717 (45,668) -
General Plant - All Other 390 WA SG 75,535 3.80% 2.52% 2,869 1,903 (965) (54)
General Plant - All Other 390 WA WA 10,894,083 3.80% 2.52% 413,748 274,627 (139,121) -
General Plant - All Other 390 WY SG 914,264 3.03% 2.61% 27,694 23,862 (3,831) (216)
General Plant - All Other 390 WY WY 13,172,144 3.03% 2.61% 398,991 345,013 (53,978) -
Total General Plant - All Other 203,731,364 2.34% 2.08% 4,764,396 4,230,028 (534,368) (36,276)
Total Company - Depreciable Plant 22,869,363,406 2.54°Io 1%1 582,443,595 743,256,789 160,813,194 8,851,849
Steam Production - Carbon SG 120,084,309 3.05% 67.13% 3,662,198 80,614,396 76,952,198 4,343,859
Total Company - Less Carbon I I 22,749,279,097 I 2.54% 2.910/o I 578,781,397 I 662,642,393 I 83,860,996 I 4,507,989 I
* For regulatory purposes, vehicle depreciation is re-classified as O&M.
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Allocation Factor Table
ID