20210527Van Engelenhoven Direct-Redacted.pdf

BEFORE TIIE IDAHO PUBLIC UTILITIES COMMISSION
IN TIIE MATTER OF THE )
APPLTCATTON OF ROCKY )
MOUNTATN POWERFOR )
AUTHORITY TO INCREASE ITS )
RATES AI\ID CHARGES IN IDAIIO )
AI\ID APPROVAL OF PROPOSED )
ELECTRTC SERVTCE SCmDULES )
AI\D REGTILATIONS )
ROCKY MOT]NTAIN PO}VER
CASE NO. PAC.E,-2L.07
Direct Testimony of Robert Van Engelenhoven
REDACTED
CASE NO. PAC.EAIo7
I&'[ay 2021
TABLE OF CONTET{TS
L TNTRODUCTTONAND QUALTFTCATIONS....
II. PURPOSE OF TESTIMONY..........
Itr. PRYOR MOUNTAIN WIND PROJECT.
ry. NAUGHTON UNIT 3 GAS CO}.IVERSION.........
V. LAKE SIDE 2 NATURAL GAS PLANT
YI. 2O2O DECOMMISSIONING STUDIES..
VII. CONCLUSION AND RECOMMENDATION.......
ATIACHED EXHIBITS
Exhibit No. 32-Site Plan Pryor Mountain
Confidential Exhibit No. 33-Demolition Estimate (Jan 15, 2020)
Confrdential Exhibit No. 34-Demolition Estimate (Mar 13, 2020)
Confidential Exhibit No. 3}-Demolition $rrmmary
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I. INTRODUCTIONAI\DQUALIFICATIONS
Please state your name, business address, and present position with PaciliCorp
d/b/a Rocky Mountain Power ("Rocky Mountain Power" or the "Company").
My name is Robert Van Engelenhoven and my business address is 1407 West North
Temple, Suite 310, Salt Lake City, Utah 84116. I am currently employed as Resource
Development Director. I am testifliing on behalf of the Company.
Please describe your education and professional experience.
I have a Bachelor of Science in Civil Engineering from Iowa State University and am
a licensed sffuctural engineer in Utah and a licensed professional engineer in Wyoming.
I have managed major capital projects for the Company for over 20 years.
II. PT]RPOSE OF TESTIMONY
What is the purpose of your direct testimony in this case?
The purpose of my testimony is four-fold: (1) discuss the Pryor Mountain Wind Project,
(2) provide an overview of the natural gas conversion of Naughton Unit 3, (3) discuss
the Lake Side 2 natural gas plant; and (a) discuss the confidential decommissioning
and site reclamation studies attached to my testimony.
First, I explain and support the Company's development and implementation of
the Pryor Mountain Wind Project and show that the costs are reasonable. The Pryor
Mountain Wind Project, located in Carbon Counry Montana, was identified as an
opportunity to acquire and implement a late-stage renewables development project to
capture 100 percent production tax credits ("PTC") if acted on expeditiously to deliver
the project by year-end 2021. In addition to providing PTCs and net power cost
benefits, the project also allows the Company to meet a customer need for incremental
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renewable energy credits ("RECs"), the purchase of which under the Company's
Oregon Schedule 272 - Renewable Energy Rider Optional Bulk Purchase Option
("Schedule 272"), further improves the project's economics and associated customer
benefits. Mr. Rick T. Link provides the economic analysis demonstrating the net
benefits associated with the acquisition of the Pryor Mountain Wind Project.
Second, I give a sunmary of the natural gas conversion of Naughton Unit 3,
which was removed from operation as a coal-fired unit on January 30,2019,to maintain
compliance with certain environmental regulations. Conversion of Naughton Unit 3 to
a natural gas fueled resource was facilitated by the design of the unit, which already
incorporates natural gas fueling infrastructure for start-up. This underlying
infrastructure was readily and economically modified to facilitate generation up to
247 megawatts ("MW") of capacity from the unit within applicable environmental
permit limits for periods of peak loads across the Company's system to benefit our
customers.
Third, I explain and support the Company's development and construction of
the Lake Side 2 natural gas plant and show the costs are reasonable. Placed in service
in June 2014, Lake Side 2, which is located just North of Provo in Vineyard, Utah, is a
natural gas-fued elecric generation facility with a total capacity of 637 MW.
Finally, I provide background regarding the confidential decommissioning and
site reclamation studies dated January 15, 2020, and March 13, 2020, (the
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"Decommissioning Studies").1 I discuss the scope of the Decommissioning Studies and
the differences from previous plant decommissioning estimates, and summarize the
costs estimated in the Decommissioning Studies.
Please summarize your direct testimony.
My testimony demonstrates that:
. The acquisition and construction of the Pryor Mountain Wind Project is prudent
and in the public interest. The Pryor Mountain Wind Project was acquired and
developed in 2019, constructed in2020 and achieved commercial operation on
April l, 202I, delivering significant net power cost and PTC benefits, as well
as incremental customer benefits derived from the associated REC sale.
. Completion of the natural gas conversion of Naughton Unit 3 is prudent and in
the public interest. The natural gas conversion project is de minimis in scope
and facilitates operation ofa significant generation resource during periods of
peak loads across the Company's system for the benefit of customers.
. The development and construction of Lake Side 2 was prudent and in the public
interest. The addition of Lake Side 2 to the Company's gas fleet has generated
significant customer benefits and continues to be an important part of the
generation fleet.
. The updated decommissioning and remediation costs in the Decommissioning
Studies are a reasonable estimate to be included in the revenue requirement.
I The Decommissioning Studies were frled in the Company's proceeding to change depreciation rates. See In the
Matter of the Application of Roclqt Mountain Power for Authorizalion to Change Depreciation Rotes Applicable
to Electric Pruperty, Case No. PAC-E-I8-08.
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The estimates were developed by an independent engineering consultant, with
review and input by other independent contractors and were prepared and filed
consistent with the 2020 Protocol.
[I. PRYOR MOTINTAIN WIND PROJECT
Please provide an overview of the Pryor Mountain Wind Project.
The Pryor Mountain Wind Project has a nameplate capacity of 240 MW and is located
in Carbon County, Montana, approximately 60 miles south of Billings, Montana. The
project consists of 57 Vestas Model Vl 10-2.0 MW safe harbor, 16 Vestas Model Vl10-
2.2 MW safe harbor, four General Electric Model 116-2.3 MW safe harboq and
37 Vestas model Vll0-2.2 MW follow-on wind turbine generators ("WTGs"). [n
addition to the wind turbines, there will be a 34.5 kilovolt ("k\f') collector system, a
collector substation with two 34.5 kV to 23O kV step-up transformers, an operations
and maintenance ("O&M") building, and site access roads. A new point of
interconnection substation located on the project site in Montana was also constructed.
Based on current regulatory practice, the project has been assessed using a depreciable
life of 30 years.
Please provide background on the Company's development of the Pryor
Mountain Wind Project.
The opportunity to capture customer benefits resulting from the acquisition,
development, and implementation of the Pryor Mountain Wind Project was identified
and evolved over a compressed timeline beginning in October 2018 and ending with
final terms on all material agreements (i.e., the engineer, procure, and construct contract
and WTG supply agreements) completed by September 30, 2019. In parallel,
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negotiation of an Oregon Schedule 272 REC purchase agreement for the sale of all
RECs associated with the output of the Pryor Mountain Wind Project to Vitesse, LLC
began in December 2018 and final terms were reached in late June 2019. The process
from initial discussions to negotiation of final terms ofthe Schedule 272REC purchase
agreement occurred in under six months. The updated cost forecast of the Pryor
Mountain Wind Project is
Has the COyID-f9 pandemic had a material impact on the Company's
construction schedule or costs for the Pryor Mountain Wind Project?
As a result of the COVID-l9 pandemic, the Company received notices from the turbine
supply and balance of plant contractors, in which they generally claim delays due to
disruption to the global supply chain caused by the COVID-I9 pandemic. The
Company has and continues to work with these contractors to resolve these claims
strictly according to the terms and conditions of their respective contracts. However,
this affected both construction schedule and costs of the project.
With respect to construction, final wind turbine equipment deliveries were
made the week of November 9,2020. This allowed erection of all I 14 wind turbines to
be completed the week of November 16, 2020, prior to high-wind and severe winter
conditions that could have shut down the project for the winter and further delayed
construction until Spring 2021. Completing wind turbine erection ahead of the high
wind season also reduced project cost risk. The Company energized both the Bowler
Flats (point of interconnection) substation and the Pryor Mountain (collector)
substation the week of November 16, 2020. With the Pryor Mountain substation
energized, collector circuits 1 through 4 were energized and proving back feed power
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to the first 40 wind turbines (80 MW) in December 2020, allowing commissioning of
the wind turbines to commence. The remaining collector circuits (5 through 12) were
energized in the first quarter 202l.Theproject achieved commercial operation onApril
1,2021,90 days later than the originally scheduled December 2020 completion date.
Further, the overall cost ofthe project increased from an original forecasted cost
ofI,totheupdatedforecastedcostoff.Theincreaseincosts
resulted from delays experienced in consffuction, which were due to a disruption in the
worldwide supply chain caused by the COVID-19 pandemic. Specifically, the increase
in costs were caused by delayed delivery of the wind turbine components, requiring a
shift from rail delivery to the more expensive truck delivery. The delayed component
delivery from the turbine supplier delayed the erection of the wind turbines increasing
the labor and equipment costs. The delivery and erection delays were compounded by
the higher wind speeds experienced during the winter months further delaying
construction and increasing costs. During November 2020 there was an onsite COVID-
l9 outbreak which delayed erection of the wind turbines and the start of commissioning
and placing wind turbines in service.
Please describe the time-sensitive nature of the federal PTCs as it pertains to the
Pryor Mountain Wind Project.
The time sensitive nature of the federal PTCs for the Pryor Mountain Wind Project is
similar to the new wind facilities included in the Energy Vision 2O2O Projects, which
is discussed by Mr. Timothy J. Hemstreet. The time-sensitive nature of the Pryor
Mountain Wind Project is primarily driven by the pending phase-out of the federal
PTCs for new wind resources. Originally, under prior Internal Revenue Service ("IRS")
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guidance, PacifiCorp would have captured the full rate (100 percent) of the PTCs if the
project's in-service date was before the end of 2020. However due to the COVID-I9
pandemic, in May 2020, the Continuity Safe Harbor was extended to five calendar
years for projects that began construction in 201 6 or 2Ol7 .2 Pryor Mountain has a 201 6
start of construction date. Accordingly, the continuity requirement will be met if the
project is placed in service by December 31, 2021. With an in-service date of April l,
202I, the Pryor Mountain Wind Project will capture the full rate (100 percent) of the
PTCs. The Pryor Mountain Wind Project deployed safe harbor WTG equipment to
achieve PTC eligibiliry The Company's acquisition and implementation plan for the
Pryor Mountain Wind Project allowed the Company to meet the year-end 2021 in-
service schedule and provide customers the full economic benefit of the project.
Does the Pryor Mountain Wind Project meet the IRS start-of-construction
criteria?
Yes. The Pryor Mountain Wind Project will utilize WTG equipment acquired before
December 31, 2016. The WTG equipment acquisition satisfies the safe-harbor
requirements under the PTC guidance issued by the IRS.
What approach was taken to secure late-stage development safe harbor WTG
equipment and follow-on WTG equipment for the Pryor Mountain Wind Project?
The Vestas safe harbor WTG equipment identified above was sourced, acquired, and
transferred under an affiliate transaction with Berkshire Hathaway Energy Renewables
("BHER"). The fotr General Electric safe harborWTGs described above were directly
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procured by the Company in 2016. The Company completed a competitive market
solicitation for the follow-on WTG equipment required to complete the nominal
240 MW Pryor Mountain Wind Project. By combining the use of safe harbor
equipment, the transfened BHER safe harbor equipment, and competitive market
engagement for follow-on WTG equipment, the Company addressed a couple of key
risk points for the project. Specifically, through this combination of procurement
strategies the Company limited its exposure to competitive market constraints and
pricing volatility for 2O2O delivery of 100 percent PTC projects with the safe harbor
equipment already manufactured and awaiting delivery.
a. What is the current construction status of the Pryor Mountain Wind Project?
A. The Pryor Mountain Wind Project was primarily constructed in 2020, although site
activities began in 2019 with completion of geotechnical borings and surveys, other
site surveys and detailed engineering, consffuction of a material laydown area, and
installation of approximately five percent of the site access roads before winter weather
halted construction. The consffuction contractor re-mobilized in March 2020 and
completed construction in December 2O2O with commissioning completed by March
31,2021. The project was placed in commercial operation onApril l, 2021.
a. Did the Company perform preliminary evaluations of the wind potential at the
Pryor Mountain Wind Project site?
A. Yes. A wind potential study for the Pryor Mountain Wind Project was completed by a
third-party wind resource evaluation firm. The wind potential assessments for Pryor
Mountain indicate that the site has a favorable wind regime suitable for high
performance wind energy generation. The expected capacity factor for the project is
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I p"r""rt and aligns with the assumptions made in support of the economic
evaluation of the project.
a. Did the Company collaborate with the U.S. Fish and Wildlife Service in developing
and implementing the Pryor Mountain Wind Project?
A. Yes. The Company engaged the U.S. Fish and Wildlife Service regarding developing
and implementing the Pryor Mountain Wind Project. The Company and the project's
previous owner and developers began pre-construction usage surveys for various avian,
bat, and wildlife species utilizing recommendations from applicable state and federal
guideline documents, including the 2Ol2 Land Based Wind Energy Guidelines. The
Company will continue to coordinate with county, state, and federal agencies that have
jurisdiction over development, permitting, and operations to ensure appropriate
environmental and safety measures are implemented throughout the life of the Pryor
Mountain Wind Project. The Company is committed to maintaining development and
implementation schedules and protocols that recognize potential environmental
impacts and strive to mitigate them.
a. How did the Company assess the customer benefits provided by the Pryor
Mountain Wind Project?
A. Mr. Link provides a detailed description of the Company's customer benefits
assessment in his testimony. In general terms, the methodology used to perform the
economic analysis of the Pryor Mountain Wind Project is consistent with the
methodology used to perform the economic analysis of the Energy Vision 2020
Projects. The Company's economic analysis also reflects the significant benefits from
the sale of RECs associated with the Pryor Mountain Wind Project.
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How did the Company generate the cost information for construction, operation,
and maintenance of the Pryor Mountain Wind Project through its useful life?
The Company assessed life cycle costs for the Pryor Mountain Wind Project using
information from a variety of sources. For example, initial installation costs and run
rate O&M cost projections were developed through competitive market engagements
for project construction and WTG supply and long-term O&M contracts. Transmission
interconnection costs were confirmed against the Pryor Mountain Wind Project's
transmission interconnection studies. The Company's internal project management and
administrative costs were estimated based on the Company's experience with
construction of past and current wind facilities and other recent generation resource
additions. The Company also applied limited frrnds to the Pryor Mountain Wind Project
to account for project uncertainties. O&M cost estimates were developed based on the
Company's experience with currently operating wind facility O&M budgets and third-
party contracts for the Company's existing wind facilities. Ongoing capital costs were
estimated based upon the Company's experience and indicative costs provided by WTG
suppliers for critical capital components.
Please describe the exhibit for the 240 MW Pryor Mountain Wind Project.
The site plan for the 240 MW Pryor Mountain Wind Project is provided in
Exhibit No. 32 which accompanies my testimony.
IV. NAUGHTON TINIT 3 GAS COIIVERSION
Please describe why Naughton Unit 3 was converted to natural gas fueling.
The Company was required to cease coal-fired operations in Naughton Unit 3 on
January 30, 2019, to maintain compliance with certain environmental regulations.
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Completion of the natural gas conversion of Naughton Unit 3 increases the unit's
generating capacity when fueled by natural gas from 35 MW (utilizing existing start-
up fuel infrastructure) to 247 MW.
Please describe the permitting process for Naughton Unit 3.
On July 5, 2013, the Wyoming Deparfrnent of Environmental Quality (*WDEQ")
issued Air Permit MD 14506, which establishes natural gas emission and heat input
limits for Naughton Unit 3 which would "become effective upon conversion" of Unit 3
to natural gas firing. On November 28, 2017, the WDEQ submitted to the
Environmental ProtectionAgency ("EPA") a Regional Haze State Implementation Plan
("SIP") revision which required Naughton Unit 3 to cease burning coal no later than
January 30,2019, the SlPproposes federally enforceable emission limits for Naughton
Unit 3 to fire on natural gas. The EPA issued its proposed approval of WDEQ's SIP
revision on November 7,2018, seeking public comments on the proposal.
On February 4,2019, the Company filed a notification to the WDEQ that
Naughton Unit 3 had ceased coal combustion; the Company designated Naughton Unit
3 as "temporarily 'mothballed' while awaiting final federal action" from the EPA on
approval of the WDEQ SIP The Company clarified in its notification that Naughton
Unit 3 remained capable of generating 35 MW when fueled on natural gas, and that the
unit could be considered effectively converted following EPA approval of the Wyoming
SIP
On March 21,2019, the EPApublished its approval of the Naughton Unit 3
conversion to natural gas and incorporated by reference the natural gas emission limits
from Wyoming state air permits. The Company submitted a notification to WDEQ on
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May 24,2019,for initial startup ofNaughton Unit 3 on natural gas and commencement
of construction for additional upgrades supporting the full conversion to247 MW. The
Company removed Naughton Unit 3 from designation as 'temporarily mothballed'and
committed to completion of all consffuction relating to natural gas conversion by
June24,202l.
The Company filed a notification with WDEQ on July 3,2019, that Naughton
Unit 3 was first fired (initial start-up after being temporarily mothballed) on natural gas
on July 1,2019.
The Naughton Unit 3 conversion project was complete and placed into service
on July 29,2020.
What is the cost to complete the full conversion of Naughton Unit 3 to a 247 NNy
nafural gas fired generation resource?
The cost of the Naughton Unit 3 gas conversion to 247 MW included in this proceeding
irl million on a total-company basis.
Does the Naughton Unit 3 gas conversion to a 247 MW natural gas lired
generation resource provide customer benefits?
Yes. As discussed in the testimony of Mr. Link, full conversion of Naughton Unit 3 to
a247 MW gas fueled resource is projected to provide $62 million to $121 million in
present-value revenue requirement differential ("PVRR(d)") benefit for customers as
analyzed in the 2019 lntegrated Resource Plan ("IRP") against early retirement of the
unit. As such, the 2019 IRP Preferred Portfolio included Naughton Unit 3 gas
conversion as a generation resource available to serve customers going forward.
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V. LAKE SIDE 2 NATTIRAL GAS PLANT
Please describe the Lake Side 2 Power Plant ("Lake Side 2") and its integration
into PacifiCorp's System.
Lake Side 2 is a natural gas-fired electric generation faciliry consisting of a 2xl
configuration, with two Siemens SGT6-5000F combustion turbine generators and a
single 55T6-5000 steam turbine generator. It is a 548 MW base load with 89 MW of
duct firing for a total capacity of 637 MW at average ambient conditions for the site.
Each combustion turbine exhausts into its own heat recovery steam generator and,
together, they supply a single steam turbine generator. Lake Side 2 is located on a 63.6-
acre site in Vineyard, Utah, next to Lake Side 1. The electrical energy generated by
Lake Side 2 is delivered to a 345 kV point of interconnection substation where it ties
into the PacifiCorp's transmission system.
Please explain why the Company decided to build Lake Side 2.
The Company decided to acquire Lake Side 2 based on three IRPs and a competitive
request for proposals ("RFP") process. The need for a resource such as Lake Side 2
was recognizedas apart of the Commission's acknowledgment of the Company's 2007
and 2009 IRPs.3 These are the two IRPs that immediatety preceded the Company's
execution of the Lake Side 2 acquisition agreement in December 2010. Item2 in the
2011 IRP Revised Action Plan indicated that the Company would: "[a]cquire a
combined cycle combustion turbine resource at the Lake Side site in Utah by the
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3 PacifiCorp 's 2007 Integrated Resource Plan, Case No- PAC-E-O7- I I , Acceptance of Filing (Oct. I 5, 2007);
PacifiCorpb 2009 Integrated Resource Plan,Case No. PAC-E-09-06, Acceptance of Filing (Sept. 15, 2017).
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suilrmer of 2014.-4 Lake Side 2 was the 2014 combined cycle combustion turbine
("CCCT") proxy resource included in the 2011 IRP preferred portfolio.5 Further, the
Engineer, Procure and Consffuct ("EPC") contract for Lake Side 2 was awarded to
CH2M Hill E&C, Inc. based on a competitive solicitation in the Company's 2010 All
Source RFP, which was open to all bidders.6 The EPC contract provided specific terms
and conditions to protect customers and required the 637 MW CCCT resource to be
placed in service by June 2014.
Please describe the characteristics of Lake Side 2.
Lake Side 2 is located in the Company's control area. Energy from Lake Side 2 is
dispatched on a forward, day-ahead basis, with real-time optimization of the plant's
usage. Dispatch flexibility gives the Company an additional system resource with the
ability to provide operating reserves, load-following reserves, and automatic generation
control. This system flexibility provides increased benefit to PacifiCorp as: (1) load
grows; (2) PacifiCorp's existing flexible contracts expire; and (3) new wind and solar
resources are added to the System.
Is Lake Side 2 in-service providing energy to the Company's customers?
Yes. Lake Side 2 was placed in-service in June 2014.
What was the total capital cost of Lake Side 2?
The total capital cost for Lake Side Z was! million on a total-Company basis.
a PacifiCorpb 20ll Integrated Resource Plan,Case No. PAC-E-ll-10, 20ll IRP at l4
5 Id.
6 Id. at 44.
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What do you recommend concerning Lake Side 2?
The RFP, along with the analysis of the Company and independent evaluators
conducted prior to building Lake Side 2, demonstrated that it was in the public interest
because it was identified as the best resource to fulfill the need established in the RFP
Lake Side 2 also filled part of the capacity deficit in the Company's system in2014,
identified in the 2008 IRP Update. Lake Side 2 is a valuable part of PacifiCorp's
generation resource portfolio. It is used and useful and provides significant benefig to
Idaho customers. Therefore, I recommend that the Commission find that the decision
to construct Lake Side 2 was prudent and in the public interest and its cost should be
included in rate base as a part of this general rate case.
VI. 2O2O DECOMMISSIONING STTIDIES
\ilhat is the purpose of this section of your direct testimony?
I provide background regarding the Decommissioning Studies provided in Confidential
Exhibit Nos. 33 and 34 that accompany my testimony. I also discuss the scope of the
Decommissioning Studies and the differences between previous plant
decommissioning estimates, and summarize the costs estimated in the
Decommissioning Studies.
\ilhy did PacifiCorp conduct the Decommissioning Studies?
Through PacifiCorp's Multi-State Process negotiations, the signatories to tbe 2O20
PacifiCorp Inter-Jurisdictional Allocation Protocol (*2020 Protocol") agreed that the
Company should conduct a thorough study of decommissioning and site reclamation
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I costs for certain coal-fueled generation resources.T
Please describe the scope of the Decommissioning Studies.
The scope of work for the Decommissioning Studies included the following
requirements:
. Provide an owner-informed, overall decommissioning design basis to be used
for all generating facilities in the study. The design basis established the
fundamental assumptions for the cost estimates provided in the final
Decommissioning Studies.
. Provide a Class 3 cost estimate to identifu all costs for the decommissioning,
demolition, reclamation, and remediation of the Hunter, Huntington, Dave
Johnston, Jim Bridger, Naughton, Wyodak, Hayden, and Colstrip generating
facilities.
. Provide a narrative report describing the entities involved, process used to
prepare the report, and assumptions.
. Provide a spreadsheet report incorporating the Association for the Advancement
of Cost Engineering (*A,r{CE")8 Class 3 cost estimates inclusive of certain
owner provided Asset Retirement Obligation ("ARO") cost estimates as
verified by the third-party study provider
. Provide cost estimates based on fourth quarter 2019 dollars.
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1 In the Matter of Roclry 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).8AACE 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.
Van Engelenhoven, Di - 16
Rocky Mountain Power
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Why were PacifiCorp's other coal-fueled generation facilities not included in the
Decommissioning Studies?
PacifiCorp's owned, but did not operate, Cholla Unit 4 and Craig Units I and2, and so
these generating units were not included in the Decommissioning Studies. Those units
had common depreciable lives proposed for all states in the most recent depreciation
study and common retirement dates in the 2019 IRP.e
Who conducted the Decommissioning Studies for the Company?
The Decommissioning Snrdies were performed by independent engineering consultant
Kiewit Engineering Group lnc., with input from independent contractors with direct
experience decommissioning coal-fueled facilities and site reclamation. The studies
included review and input from an independent demolition contractor NorthAmerican
Dismantling Corporation and independent hazardous materials abatement contractors
Winter Environmental and ARC Abatement. Two additional independent demolition
conffactors, Bierlein Companies, Inc. and Brandenburg Industrial Service Company
also reviewed the Decommissioning Studies results.
Are you planning to conduct separate decommissioning studies for Cholla Unit 4
and Craig Units I and 2?
Yes. Arizona Public Service Company, the operator of the Cholla generation facility,
retained APTIM Corporation and has completed a study of 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
e PactfiCorpb Integrated Resource Plan (IRP)for 2019, Case No- PAC-E-19-16 (Oct. 18, 2019).
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Rocky Mountain Power
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later than 2024 in accordance with the 2020 Protocol.
Please describe the difference between the Decommissioning Studies and previous
decommissioning estimates prepared by the Company?
The Decommissioning Studies provide an AACE Class 3 estimate for demolition,
salvage, and scrap costs for the facilities studied. An AACE Class 3 cost estimate is
based on a definition of the scope of work between l0-40 percent and has an expected
accuracy of minus 20 percent to plus 30 percent. The typical purpose of a Class 3
estimate is for budget authorization or control.
Previous decommissioning cost estimates 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. The typical purpose of a Class 5 estimate is for concept screening. [t
should also be noted that the underlying scope and desigu basis for the previous
decommissioning cost estimates was refined and expanded in response to scoping
feedback from stakeholders during the Multi-State Process negotiations.
Please describe the major differences between the previous estimates and the
current Decommissioning Studies.
The differences between the previous estimates and the current Decommissioning
Studies are primarily from the definition of the scope of worlq the method, estimate
class, assumptions for ARO and environmental liabilities, site reclamation, owner's
costs and contractor indirect costs applied in the current Decommissioning Studies.
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Roclcy Mountain Power
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What is the change to the method of estimating decommissioning costs used in the
Decommissioning Studies?
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.l0 The
current Decommissioning Studies estimate the cost and salvage values for each
generating facility individually.
Were there other changes in the scope of the estimate in the Decommissioning
Studies compared to the previous sfudy?
Yes. The previous estimates were based on 0-2 percent of the scope of the work defined
and was focused on three facilities from which the individual generating unit estimates
were extrapolated. The previous estimates did not include infrastructure, utilities, or
any facilities outside the plant perimeter. The current studies are based on a scope of
work defined at 10-40 percent and focused on individual units as well as all common
plant facilities, both inside and outside the facility perimeter.
How were ARO addressed in the Decommissioning Studies?
During the time between the previous estimates and the current studies, the scope and
cost of AROs changed as existing obligations were completed and new obligations
were incurred. ln addition, the scope of the current studies included reviewing the cost
Van Engelenhoven, Di - 19
Rocky Mountain Power
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to See also, Case No. PAC-E-I8-08, Direct Testimony of Chad A. Teply
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of the Company's ARO estimates. Where the consultant found that 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 Decommissioning Studies. The
net result was a total increase of approximately $15 million.
Did the Decommissioning Studies address site reclamation?
Yes. Unlike previous estimates, the current 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 topsoil, and seeding for
native plants. Topsoil installation and seeding was not estimated for Wyodak, due to its
co-location with non-PacifiCorp generation resources in an energy hub.
How did the Decommissioning Studies address owner's costs and contractor
indirect costs?
The current 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. The
previous estimates did not include owner's project development and oversight costs or
itemized competitive market contractor indirect costs.
Please summarize the results of the Decommissioning Studies.
Exhibit No. 35 contains a table showing the results of the Decommissioning Studies
excluding certain closure-related costs that may be considered outside of
decommissioning costs or require additional steps to refine their accuracy.
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Rocky Mountain Power
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What costs were included in the total base decommissioning and demolition costs
for each facility?
In general terms, the base decommissioning costs include the costs for: (1) developing
the decommissioning project including the site investigation; (2) decommissioning the
facility, decontaminating activities, and preparing the facility for the demolition
contractor; (3) dismantling and demolition of the facility less the offset value of salvage
and scrap; (4) completing ARO, site remediation, and site reclamation; and (5) the
estimates of competitive market contractor margin and indirect costs.ll The costs and
offsets were adjusted to PacifiCorp ownership values for each facility studied.
Were there any offsets to the estimated base decommissioning and demolition
costs?
Yes. 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 sold. Estimated scrap value is based on the estimated then-current market
prices of steel, titanium, copper-based metals, and other valuable metals.12
Do the Decommissioning Studies incorporate other costs in relation to
decommissioning?
Yes. Other costs incorporated in the 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,
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rr See Confidential Exhibit No. 33 and Confidential Exhibit No. 34
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Rocky Mountain Power
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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 (a) material and supply inventory and rolling
stock dispensation.13 As discussed by Mr. Steven R. McDougal, these other costs were
not reflected in the revenue requirement request in the proceeding.
Are these the Company's final estimates for decommissioning costs?
No. The 2020 Protocol contemplates an update of the Decommissioning Studies in
2024to address the Craig, Hunter, Huntington, andWyodak coal-fueled resources. That
study will update the estimated decommissioning costs so that depreciation rates for
Craigla and the longer-lived resources (i.e. Hunter, Huntington, and Wyodak) can be
updated to reflect more accurate and contemporaneous decommissioning estimates.
Further, as I discussed previously, the operator of Cholla Unit 4 has separately
estimated decommissioning and site reclamation costs for that unit.
YII. CONCLUSIONANDRECOMMENDATION
Please summarize your testimony.
The Company requests the costs for the Pryor Mountain wind facility be included in
the approved revenue requirement because it is prudent and benefits Idaho customers.
Cost recovery is also appropriate for the Naughton Unit 3 natural gas conversion, which
has been prudently analyzed and implemented. The natural gas conversion project is
de minimis in scope and facilihtes operation of a siguificant (247 MW, post-
conversion) generation resource during periods of peak loads across the Company's
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ta PacifiCorp's ownership share is l9 percent of Craig Unit I and l9 percent of Craig Unit 2.
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Rocky Mountain Power
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system for the benefit of customers. The Company requests that the costs for Lake Side
2 be included in its revenue requirement because it is prudent and benefits customers.
Lake Side 2 was built to meet customer needs as identified and filed in the Company's
2008 IRP process. Lake Side 2 resulted from a competitive solicitation in an All Source
RFP process as the least-cost adjusted for risk resource. Based on these conclusions, I
recommend that the Commission approve these projects for inclusion in rates.
Finally, I recommend that the Commission approve the incremental
decommissioning costs as determined by an independent third-party contactor,
presented in my testimony, and included in the revenue requirement calculation
performed by Mr. McDougal.
Does this conclude your direct testimony?
Yes.
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Rocky Mountain Power
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