20200828Phase II Comments-Redacted.pdf

1407 West North Temple, Suite 330
Salt Lake City, Utah 84116

August 28, 2020

VIA ELECTRONIC DELIVERY

Jan Noriyuki
Commission Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd.
Building 8 Suite 201A
Boise, ID 83714

Re: CASE NO. PAC-E-18-08
IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER
FOR AUTHORIZATION TO CHANGE DERECIATION RATES APPLICABLE
TO ELECTRIC PROPERTY

Attention: Ms. Noriyuki

Pursuant to Order No. 34754, please find Rocky Mountain Power’s Phase II comments in the
above referenced matter.

Informal inquiries may be directed to Ted Weston, Idaho Regulatory Manager at (801) 220-
2963.

Very truly yours,

Joelle Steward
Vice President, Regulation

RECEIVED
2020 August 28 PM 4:09
IDAHO PUBLIC
UTILITIES COMMISSION

1
Emily Wegener
Rocky Mountain Power
1407 West North Temple, Suite 320
Salt Lake City, Utah 84116
Telephone No. [phone]
[e-mail]

Attorney for Rocky Mountain Power

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER FOR
AUTHORIZATION TO CHANGE
DERECIATION RATES APPLICABLE TO
ELECTRIC PROPERTY

)
)
)
)
)

CASE NO. PAC-E-18-08

PHASE II - INCREMENTAL
DECOMMISSIONING COSTS

Rocky Mountain Power, a division of PacifiCorp (the “Company”) pursuant to the
Idaho Public Utilities Commission (“Commission”) Order No. 34754, which approved
changes to depreciation rates and authorized Phase II to evaluate decommissioning costs and
determine the appropriate ratemaking treatment for them. Phase II is to evaluate the
decommissioning costs in the 2018 Depreciation Study, filed on September 11, 2018,
compared to the costs in the 2020 decommissioning studies (“Incremental Decommissioning
costs”) filed on January 17, 2020, and March 16, 2020, (collectively “2020 Decommissioning
Studies”). The Company respectfully submits the following proposal for ratemaking treatment
of the Incremental Decommissioning costs.
1. Rocky Mountain Power is an electrical corporation and public utility operating
in the state of Idaho and is subject to the jurisdiction of the Commission with regard to its

2
public utility operations. PacifiCorp has two retail electric service divisions, Rocky Mountain
Power and Pacific Power. Rocky Mountain Power provides retail electric service in Idaho,
Utah, and Wyoming, and Pacific Power provides retail electric service in California, Oregon,
and Washington.
2. Communications regarding this Application should be addressed to:

Ted Weston
Emily Wegener
Rocky Mountain Power
1407 West North Temple, Suite 320
Salt Lake City, Utah 84116
E-mail: [e-mail]
E-mail: [e-mail]

In addition, Rocky Mountain Power requests that all data requests regarding this
Application be addressed to:
By email (preferred) [e-mail]

By regular mail Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR 97232
Informal inquiries related to this Application may be directed to Ted Weston, at
[phone].
3. Through PacifiCorp’s Multi-State Process negotiations, the signatories to the
2020 PacifiCorp Inter-Jurisdictional Allocation Protocol (“2020 Protocol”) agreed that the
Company should conduct a thorough study of decommissioning and site reclamation costs for

3
certain coal-fueled generation resources.1 On January 17, 2020, and March 16, 2020, the
Company filed copies of the 2020 Decommissioning Studies with the Commission.
4. The 2020 Decommissioning Studies were performed by independent
engineering consultant Kiewit Engineering Group Inc., with input from the Company and
independent contractors with direct experience decommissioning coal-fueled facilities and site
reclamation. The studies included review and input from an independent demolition contractor
North American Dismantling Corporation and independent hazardous materials abatement
contractors Winter Environmental and ARC Abatement. Two additional independent
demolition contractors, Bierlein Companies, Inc. and Brandenburg Industrial Service
Company, also reviewed the 2020 Decommissioning Studies results.
5. The scope of work for the 2020 Decommissioning Studies included the
following requirements: (1) provide an owner-informed, overall decommissioning design basis
to be used for all of the generating facilities in the study. The design basis established the
fundamental assumptions for the cost estimates provided in the final 2020 Decommissioning
Studies; (2) provide a Class 3 cost estimate to identify all of the costs for the decommissioning,
demolition, reclamation, and remediation of the Hunter, Huntington, Dave Johnston, Jim
Bridger, Naughton, Wyodak, and Hayden, and Colstrip generating facilities; (3) provide a
narrative report describing the entities involved, process used to prepare the report, and
assumptions; (4) provide a spreadsheet report incorporating the Association for the
Advancement of Cost Engineering (“AACE”)2 Class 3 cost estimates inclusive of certain

1In the Matter of Rocky Mountain Power's Application for Approval of the 2020 PacifiCorp Inter-Jurisdictional
Allocation Protocol, Case No. PAC-E-19-20, Order No. 34649 (Apr. 22, 2020) (2020 Protocol Sections 4.3.1.1-
4.3.1.2).
2 AACE is a 501(c)(3) non-profit professional association founded in 1956 that offers publications, practice
guides, education, certification and recommended practices for cost estimating.

4
owner provided Asset Retirement Obligation (“ARO”) cost estimates as verified by the third-
party study provider; and (5) provide cost estimates based on fourth quarter 2019 dollars.
6. PacifiCorp’s owned, but not operated, Cholla Unit 4 and Craig Units 1 and 2
were not included in the 2020 Decommissioning Studies because those units had common
depreciable lives proposed for all states in the most recent depreciation study and common
retirement dates in the 2019 Integrated Resource Plan.3
7. Arizona Public Service Company, the operator of the Cholla generation facility,
has retained APTIM Corporation to study the decommissioning and demolition costs for the
entire Cholla generation facility, including Cholla Unit 4. A decommissioning and demolition
study for the Craig facility will be completed by no later than 2024 in accordance with the
2020 Protocol.
8. The 2020 Decommissioning Studies provide an AACE Class 3 estimate for
demolition, salvage, and scrap costs for the facilities studied. An AACE Class 3 cost estimate
has an expected accuracy of minus 20 percent to plus 30 percent.
9. The decommissioning cost estimates included in the 2018 Depreciation Study
were extrapolated from AACE Class 5 estimates for demolition of a limited subset of
PacifiCorp’s owned and operated coal-fueled facilities. A Class 5 study has an expected
accuracy of minus 50 percent to plus 100 percent. It should also be noted that the underlying
scope and design basis for the previous decommissioning cost estimates was refined and
expanded in response to scoping feedback from stakeholders during the Multi-State Process
negotiations.

3 PacifiCorp’s Integrated Resource Plan (IRP) for 2019, Case No. PAC-E-19-16 (Oct. 18, 2019).

5
10. The differences between the previous estimates and the current 2020
Decommissioning Studies are primarily in the method, estimate class, scope, assumptions for
ARO and environmental liabilities, site reclamation, owner’s costs and contractor indirect
costs.
11. The previous estimates developed demolition costs and salvage values for three
coal-fueled generating facilities that were intended to be generally representative of the broader
coal-fueled generating fleet. The cost of demolition and salvage for the generating facilities
that were not directly studied were extrapolated to establish estimates using generally
comparable generating facilities that had been studied. The 2020 Decommissioning Studies
estimate the cost and salvage values for each generating facility individually.
12. The scope of the previous estimates was focused primarily at a facility level and
limited to individual generating units. The previous estimates did not include infrastructure
and utilities outside the plant perimeter. The 2020 Decommissioning Studies focused on
individual units as well as all common plant facilities, both inside and outside the facility
perimeter.
13. During the time between the previous estimates and the 2020 Decommissioning
Studies, the scope and cost of AROs changed as existing obligations were completed and new
obligations were incurred. In addition, the scope of the current studies included reviewing the
cost of the Company’s ARO estimates. Where the consultant’s estimate for an ARO was
significantly different than the Company’s estimate, the consultant included their estimate for
the ARO in the 2020 Decommissioning Studies. The net result was a total increase of
approximately $15 million.

6
14. Previous estimates did not include site reclamation. The 2020
Decommissioning Studies include site reclamation at an estimated average cost of $9.8 million
per generating facility. Reclamation scope assumptions include grading to meet permit
conditions and match existing terrain as much as reasonably possible, installing top soil, and
seeding for native plants. Top soil installation and seeding was not estimated for Wyodak, due
to its co-location with non-PacifiCorp generation resources in an energy hub.
15. The previous estimates did not include owner’s project development and
oversight costs or itemized competitive market contractor indirect costs. The 2020
Decommissioning Studies includes owner’s project development and oversight costs. Owner’s
costs include the cost of preparing the facility for the work, project management, long-lead
permitting, and site demolition management.
16. Attachment No. 1 summarizes the results of the 2020 Decommissioning Studies
by major category by plant excluding certain closure-related costs that may be considered
outside of decommissioning costs or require additional steps to refine their accuracy.
17. The decommissioning costs include the costs to: (1) develop the
decommissioning project including the site investigation; (2) decommission the facility,
including decontaminating and preparing the facility for the demolition contractor; (3)
dismantle and demolition of the facility less the offset value of salvage and scrap; (4) complete
ARO, site remediation, and site reclamation; and (5) estimate competitive market contractor
margin and indirect costs. The costs and offsets were adjusted to PacifiCorp’s ownership values
for each facility studied.
18. Demolition costs are offset by the value of salvage and scrap. Estimated salvage
value is based on the projected value of equipment, materials, and commodities that could be

7
sold. Estimated scrap value is based on the estimated then-current market prices of steel,
titanium, copper based metals, and other valuable metals.
19. Other costs incorporated in the 2020 Decommissioning Studies that may be
considered outside of decommissioning costs include: (1) assets for which cost recovery is
accounted for through mechanisms other than depreciation; (2) assets that do not present an
immediate hazard, nuisance, or need to decommission and remediate, including asbestos
coated piping; (3) coal pile subsurface excavation and remediation and above-ground asbestos
remediation costs that have been estimated, but will be further evaluated in the next steps; and
(4) material and supply inventory and rolling stock dispensation.
20. The Company proposal does not seek recovery of the Other Decommissioning
costs at this time; they are not part of the costs summarized in Attachment 1 and 2. The
Company continues to evaluate these other costs, recovery will be addressed in future
proceedings.
21. The 2020 Decommissioning Studies also assumed removal of 10 feet of coal-
laden soil under the current coal piles at each facility. The Company plans to conduct a coal
pile boring study to improve the coal pile subsurface excavation, remediation, and haul off cost
estimate for each facility studied. The Company also plans to conduct an asbestos study for
each facility studied to improve asbestos abatement costs.
22. The Company contemplates an update of the 2020 Decommissioning Studies
in 2024 to address the Craig, Hunter, Huntington, and Wyodak coal-fueled resources. That
study will update the estimated decommissioning costs so that depreciation rates for Craig4
and the longer-lived resources (i.e. Hunter, Huntington, and Wyodak) can be updated to reflect

4 PacifiCorp’s ownership share is 19 percent of Craig Unit 1 and 19 percent of Craig Unit 2.

8
more accurate and contemporaneous decommissioning estimates. Further, the operator of
Cholla Unit 4 is separately estimating decommissioning and site reclamation costs for that unit.
23. The 2020 Decommissioning Studies also identified other plant closure costs
that are necessary for the Company to fully recover all costs associated with closing a plant.
For example, each generation plant has a certain level of materials and supplies inventory that
is required to operate the plant. In the event of a plant closure, those material and supplies will
no longer be required and often cannot be absorbed for use at a different generation facility.
Given those circumstances, the Company would seek recovery of the unusable material and
supplies inventory in addition to all of the other incurred or expected plant closure costs. As
identified in the 2020 Decommissioning Studies, there are a significant amount of other plant
closure costs that will need to be addressed in a future proceeding.
24. Attachment 2 summarizes the Incremental Decommissioning costs by plant
with the annual amount on a total Company and Idaho allocated basis. The Incremental
Decommissioning costs for the plants included in the study are approximately $454 million.
The annual cost was calculated by dividing the Incremental Decommissioning costs by the
remaining life of the last retired unit of the plant, based on the lives assumed in the 2018
Depreciation study.
25. Idaho’s allocation of the Incremental Decommissioning costs based on the 2020
Decommissioning Studies is approximately $2.3 million per year. The decommissioning costs
collected in rates would be deferred to a regulatory liability account that would be reduced by
actual decommissioning costs as incurred by the Company.
26. On June 15, 2020, the Company filed a Stipulation between parties in this case
for new depreciation rates from the 2018 depreciation study. To enable the Company to delay

9
filing a rate case in 2019 with rates effective January 1, 2021, the Stipulating Parties agreed
that the Company could defer incremental depreciation expense for one year during calendar
year 2021.
27. The Company strives for consistent treatment among its states on system
allocated assets, therefore it requests that amortization of the Incremental Decommissioning
costs begin January 1, 2021, aligned with the new depreciation rates authorized by Order No.
34754.5
28. Consistent with the Commission-approved treatment of the incremental
depreciation expense, the Company proposes that Idaho’s allocation of Incremental
Decommissioning costs of $2,291,178 also be deferred during calendar year 2021 to be
collected in customers’ rates beginning with the rate effective date of the Company’s next
general rate case. The amortization period to recover the deferral would be determined in that
case.
III. REQUEST FOR RELIEF
Rocky Mountain Power respectfully requests that the Commission approve the
Incremental Decommissioning costs reflected in the 2020 Decommissioning Studies and
authorize the Company to create a regulatory asset to defer Idaho’s allocated share of annual
amortization expense of $2,291,178 of the Incremental Decommissioning costs during
calendar year 2021.

5 In the Matter of the Application of Rocky Mountain Power for Authorization to Change Depreciation Rates
Applicable to Electric Property, Case No. PAC-E-18-08.

10
DATED this 28th day of August, 2020.
Respectfully submitted,
ROCKY MOUNTAIN POWER

______________________________
Emily L. Wegener
1407 West North Temple, Suite 320
Salt Lake City, Utah 84111
Telephone No. [phone]
[e-mail]

Attorney for Rocky Mountain Power

CONFIDENTIAL
Attachment 1
2020 Decommissioning Summary

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REDACTED

Attachment 2
Incremental Decommissioning Costs

Rocky Mountain Powe ttachment No. 2
Incremental Decommissioning Costs
2018 Depreciation Stud - Phase II
SG Allocation Facto
5.911%
Plant Plant Closure Date Remaining Life (Years)
2018 Depreciation Study
Estimated Total Plant
Decommissioning
2020 Engineering
Decommissioning Study
Incremental
Decommissioning Costs
Total Company Annual
Amount
Idaho Allocated Annual
Amount
Hunte 2042 22 50,022,000 109,400,262 59,378,262 2,699,012 159,542
Huntin ton 2036 16 40,256,000 111,919,004 71,663,004 4,478,938 264,756
Dave Johnston 2027 7 26,095,000 101,989,356 75,894,356 10,842,051 640,887
Jim Brid er 2037 17 52,662,000 156,984,308 104,322,308 6,136,606 362,742
Nau hton 2029 9 62,267,000 158,991,849 96,724,849 10,747,205 635,281
W odak 2039 19 7,138,000 30,690,185 23,552,185 1,239,589 73,274
Ha den 2030 10 352,000 14,093,486 13,741,486 1,374,149 81,228
Colstrip 2027 7 12,685,000 21,385,311 8,700,311 1,242,902 73,469
Total 251,477,000 705,453,761 453,976,761 38,760,451 2,291,178
Generating Unit Plant
2018 Depreciation 
Study ‐ Depreciable 
Life 2016 $/kW
Net 
Dependable 
Capacity
Estimated Unit 
Decommissioning
Estimated
Total Plant
Decommissioning
Cholla 4 Cholla 2025 51.46 395.0            20,328,000            
Cholla Cholla 20,328,000             
Dave Johnston 1 Dave Johnston 2027 34.25 106.0            3,630,000                
Dave Johnston 2 Dave Johnston 2027 34.25 106.0            3,630,000                
Dave Johnston 3 Dave Johnston 2027 34.25 220.0            7,534,000                
Dave Johnston 4 Dave Johnston 2027 34.25 330.0            11,301,000            
Dave Johnston Dave Johnston 26,095,000             
Hunter 1 Hunter 2042 43.19 418.1            18,060,000            
Hunter 2 Hunter 2042 43.19 269.0            11,618,000            
Hunter 3 Hunter 2042 43.19 471.0            20,344,000            
Hunter Hunter 50,022,000             
Huntington 1 Huntington 2036 44.29 459.0            20,327,000            
Huntington 2 Huntington 2036 44.29 450.0            19,929,000            
Huntington Huntington 40,256,000             
Jim Bridger 1 Jim Bridger 2028 37.21 354.0            13,172,000            
Jim Bridger 2 Jim Bridger 2032 37.21 359.3            13,370,000            
Jim Bridger 3 Jim Bridger 2037 37.21 348.7            12,973,000            
Jim Bridger 4 Jim Bridger 2037 37.21 353.3            13,147,000            
Jim Bridger Jim Bridger 52,662,000             
Naughton 1 Naughton 2029 97.75 156.0            15,249,000            
Naughton 2 Naughton 2029 97.75 201.0            19,648,000            
Naughton 3 Naughton 2029 97.75 280.0            27,370,000            
Naughton Naughton 62,267,000             
Wyodak Wyodak 2039 26.63 268.0            7,138,000                
Wyodak Wyodak 7,138,000               
Colstrip 3 Colstrip 3/4 2046 85.71 74.0              6,342,500                
Colstrip 4 Colstrip 3/4 2046 85.71 74.0              6,342,500                
Colstrip 3/4 Colstrip 3/4 12,685,000             
Craig 1 Craig 2025 12.37 82.33            1,018,000                
Craig 2 Craig 2026 12.37 82.52            1,021,000                
Craig Craig 2,039,000               
Hayden 1 Hayden 2030 4.50 45.1              203,000                   
Hayden 2 Hayden 2030 4.51 33.01            149,000                   
Hayden Hayden 352,000                  
Gadsby 1 Gadsby 2032 39.11 64.0              2,503,000                
Gadsby 2 Gadsby 2032 39.12 69.0              2,699,000                
Gadsby 3 Gadsby 2032 39.12 104.5            4,088,000                
Gadsby Gadsby 9,290,000               
Blundell 1 Blundell 2037 139.39 23.00            3,206,000                
Blundell 2 Blundell 2037 139.30 10.00            1,393,000                
Blundell Field Blundell 2037 2,140,000                
Blundell Blundell 6,739,000               
Fleet 46.7              6,205.9        289,873,000           289,873,000          
Page 1 of 3
CERTIFICATE OF SERVICE
I hereby certify that on this 28th of August, 2020, I caused to be served, via electronic mail a true and correct copy of Rocky Mountain Power’s Phase II Comments in Case No. PAC-E-18-08 to the following:

Service List

IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.
Eric L. Olsen (C)
ECHO HAWK & OLSEN, PLLC
505 Pershing Ave., Ste. 100
P.O. Box 6119
Pocatello, Idaho 83205
[e-mail]

Dr. Lance D. Kaufman (C)
4801 W. Yale Ave.
Denver, CO 80219
[e-mail]

Anthony Yankel (C)
12700 Lake Avenue, Unit 2505
Lakewood, Ohio 44107
[e-mail]

MONSANTO COMPANY
Randall C. Budge (C)
Racine, Olson, Nye & Budge, Chartered
P.O. Box 1391
201 E. Center
Pocatello, Idaho 83204-1391
[e-mail]

Thomas J. Budge (C)
Racine, Olson, Nye & Budge, Chartered
P.O. Box 1391
201 E. Center
Pocatello, Idaho 83204-1391
[e-mail]

BAI Maurice Brubaker (C)
16690 Swingley Ridge Rd. #140
Chesterfield, MO 63017
[e-mail]

Brian Collins
16690 Swingley Ridge Rd. #140
Chesterfield, MO 63017
[e-mail]

PIIC
Ronald L. Williams (C)
Williams Bradbury, P.C.
P.O. Box 388
Boise ID, 83701
[e-mail]

Jim Duke
Idahoan Foods
[e-mail]

Kyle Williams
BYU Idaho
[e-mail]

Val Steiner
Nu-West Industries, Inc.
[e-mail]

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IDAHO CONSERVATION LEAGUE
Benjamin J. Otto (C)
710 N 6th Street
Boise, ID 83702
[e-mail]

SIERRA CLUB
Matthew Gerhart (CO Bar #50908)
Sierra Club
1536 Wynkoop St., Ste. 200
Denver, CO 80202
[e-mail]

Ana Boyd
Sierra Club
2101 Webster St., Ste. 1300
Oakland, CA 94612
[e-mail]

COMMISSION STAFF
Edward Jewell (C)
Deputy Attorney General
Idaho Public Utilities Commission
472 W. Washington (83702)
PO Box 83720
Boise, ID 83720-0074
[e-mail]

ROCKY MOUNTAIN POWER
Ted Weston
Rocky Mountain Power
1407 West North Temple, Suite 320
Salt Lake City, Utah 84116
[e-mail]

Emily Wegene
Rocky Mountain Power
1407 West North Temple, Suite 320
Salt Lake City, Utah 84116
[e-mail]

D. Matthew Moscon (#6947) Stoel Rives, LLP 201 South State Street, Suite 1100 Salt Lake City, Utah 84111 [e-mail]
Lauren Shurman (#11243) Stoel Rives, LLP 201 South State Street, Suite 1100 Salt Lake City, Utah 84111 [e-mail]
Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR 97232
[e-mail]

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Dated this 28th day of August, 2020.

__________________________________
Katie Savarin
Coordinator, Regulatory Operations