20190610Thackston Exhibit 6.pdf

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DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O.BOX3727
I41 I EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220 -3727
TELEPHONE: [phone]
FACSIMILE: (509) 495-885 I
[e-mail]
l0t9 JUH I
li]
TILIT
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC SERVICE
TO ELECTRIC CUSTOMERS IN THE
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CASE NO. AVU-E-I9-04
EXHIBIT NO. 6
JASON R. THACKSTON
OF
FOR AVISTA CORPORATION
(ELECTRIC)
REC E IVED
&lt l0:08
C
SSION
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Exhibit No. 6, Schedule I
Capital Investment Business Case Justification Nanatives Index
Business Case Name Page Number
Ge ne ration and Environme ntal
Coyote Sprinp 2 Caprtal Improvements
Nine Mile Redevelopment
Base Hydro
Regulating Hydro
Base Load Thermal
Peaking Generation
Little Falls Powerhome Redevelopnrent
Long Lake Plant Upgrades
Generation Direct Current Sryplied System Upgrade
Post Falls Redevelopment
Cabinet Gorge FIED - Gantry Crane Replacenrent
Automation Replacement
Cabinet Gorge FIED Station Service Replacement
Cabinet Gorge HED - Replace Headgates
Noxon Rapids HED Spillgate Refi.rbishment
Long Lake HED Stabilily Enhancement
Resource Metering Telenretry, and Controls Upgrade
Hurnan Machine lnterhce Control Sotware
Kettle Falls Boiler Tube Maintenance (Economizer section)
Kettle Falls Fuel Yard Equipment Replacement
Cabinet Gorge Unit 3 Protection & Control Upgrade
Environmental C ompliance Blanket
Hydro Generation Minor Blanket
Clark Fork License Implementation
Spokane River Licerse Implementation
Colstrip
Colstrip Capital Additiors
2
4
8
13
18
22
25
30
5t
42
5l
59
62
67
72
79
83
81
9l
98
105
r08
tt2
I l5
118
75
Exhibir No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page I of 120
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Coyote Springs 2 - Failed Plant
1 GENERAL INFORMATION
Requested Spend Amount
Req uesting Organ izationlDepartment c06
Business Case Owner Thomas C Dempsey
Business Case Sponsor Andy Vickers
Sponsor Organization/Department c06
Category Program
1onver Failed Plant & Operations
1.1 Steering Committee or Advisory Group lnformation
This Business Case is set up to handle emergency projects for Coyote Springs 2
Funding Requests will generally go directly to the Capital Planning Group.
2 BUSINESS PROBLEM
Aging assets will have replacement need at end of life or early failure. This business
case supports replacement of failed plant equipment at Coyote Springs 2.
. Upon failure, the failed equipment must be replaced immediately or else plant
operations will likely be curtailed or suspended indefinitely.
. The most significant cost of deferring this work upon failure is the market
price of energy to replace the lost production at this plant.
. Past plant failures include faults on the last three generation step-up
transformers, and this issue illustrates an ongoing need for this business
case.
3 PROPOSAL AND RECOMMENDED SOLUTION
Start
Do nothing
Entergency Actions as Needed MM YYYY MM YYYY
IAlternatrve #1]MAI YYYY MM YYYY
Replace the failed equipment as the situation requires. A specialized business case
will be made for each event.
Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l,Page2ofl20
$0
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$0
$M
$M
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Cost
Business Case Justification Narrative Page 1 ol 2
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Coyote Springs 2 - Failed Plant
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Coyote Sprzrgs 2 - Failecl
Plant and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role.
Signature.
Print Name:
Title:
Role:
5 VERSION HISTORY
Version i lmplemented
Thomq C Dempsey
Mgr. Th-ermal Ops & I\Iaint
Business Case Owner
Andy Vickers
Director GPSS
Business Case Sponsor
Steering/Advisory Comnrittee Review
Date:
Date
Date
By ___
Revision
Date
Approved
By_
Approval
Date
Reason
1.0 Mike Nlechartt 09/27/2018 <name>mm/dc[/yy lnitial version
Tem plate Version: O3lO7 120'17
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Business Case Justification Narralive Page 2 of 2
Exhibit No. 6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 3 of 120
zl-,/r*
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{Ii-1--r
Ni ne Mile Rehabi I itation
o1 GENERAL INFORMATION
Requested Spend Amount $ 116,720,931
Req uesti n g Organ ization/Department Generation Production and Substation Support
Business Case Owner Jacob Reidt
Business Case Sponsor Andy Vickers
Sponsor Organ ization/De partment Generation Production and Substation Support
Category Project
Driver Failed Plant & Operations
1.1 Steering Gommittee or Advisory Group lnformation
The Steering Committee for the Nine Mile Rehabilitation governs the scope,
schedule, and budget requests made by the stakeholder group when creating the
deliverables and requirements for any sub projects. Each project may have the
same, partial, ordifferent members as selected bythe Program Steering Committee.
ln general, Power Supply is represented by its Direction, Generation is represented
by its Director, and Hydro Licensing & Environmental is represented by its Director.
2 BUSINESS PROBLEM
Both Units 1 and 2 at Nine Mile have mechanically failed, and are no longer able to
generate electricity per our FERC license. These issues are a result of aging
equipment, reservoir sedimentation, and damage to submerged equipment from the
sediment. A FERC license amendment has been received to replace these units. ln
addition to the loss of generation for customers, failure to return the units to service
may put the existing Spokane River License at risk. Requirements for Renewable
Energy Credits (RECs) as part of Avista's Resource portfolio make this an opportune
time increase REC availability, restore the powerhouse to full capacity and
rehabilitate the surround ing facility.
3 PROPOSAL AND RECOMMENDED SOLUTION
Following the failure of Unit 1, Unit 2, and the subsequent turbine failure in Unit 4,
an assessment of the Spokane River Plants was performed to establish the
prudency of work within the Spokane River, prior to commencing work at Nine Mile.
Many alternatives were generated, including:
. Rehabilitation or new construction of powerhouse at Post Falls. Construction of new powerhouse at Upper Fall. Construction of new powerhouse or spillway modification at lvlonroe Street. Rehabilitation or new construction of powerhouse at Nine Mile. Rehabilitation or new construction of powerhouse at Long Lake
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Business Case Justification Narrative
Schedule I,Page 4 of 120
Page 1 of4Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Nine Mile Rehabilitation
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A Likert Scale was developed by the team to evaluate each alterative against the
following criteria.
. Alternative Development. Financial. Energy. Regulatory lnfluences. Operation and Maintenance. Transmission System lmpact. Stakeholders. Risk ldentification. Customer and Community lmpact
Following the group evaluation of all proposed alternatives, the Project Team
determined the only plant that warranted further evaluation at that time was Nine
Mile due to the failed equipment, and ongoing operational and maintenance issues
at the 100 year old facilfty. Focusing on the Nine tVlile plant allowed for further
evaluation of and reduced the number of fully evaluated alternatives to two:
Based on the criteria used by the Project Team to evaluate the Nine Mile
Alternatives, Replacement of Units 1 and 2, rehabilitation of Units 3 and 4, and
modify the Sediment Bypass System received the best score primarily due to project
economics and likelihood of regulatory agency approval. Do nothing was eliminated
due to the risk to our licenses.
The recommended alternative consists of a series of steps or phases, beginning in
November 2012 and continuing through 2021. The key elements are:
Unit 1 and 2 Upgrade to Seagull Turbines:. Units, including Turbines, Bulkheads, Generators, Switchgear. Control and Protection Package including Excitation and Governors. Powerhouse including Station Service, Ventilation, lntakes. Substation and Communications work. Site Work including cottages and warehouse. Rehabilitate Intake Gates and Trash Rack
rrrJlllPl
Do nothing $0
Replace Units 1 and 2, rehabilitate Units 3 and 4, and modify the
Sediment Bypass System $ 70.8 2012 2019
A new five-unit 60 MW powerhouse located on the same footprint
as the existing powerhouse, which would be demolished.$ 192.7 2012 2027
Business Case Justification Narrative Exhibit No. 6
Case No. AVU-E-I9-04
J. Thackston, Avista
Schedule l, Page 5 of 120
Page 2 ol 4
t:
N i ne Mile Rehabilitation
Unit3and4Overhaul:. Overhaul including Runners, Thrust Bearings, Switchgear. Control and Protection Package including Excitation and Governors. Rehabilitate lntake Gates and Trash Rack
Plant Rehab
. Sediment Bypass and Debris Handling System. Rehabilitation of the existing 100 year old Powerhouse Building
At completion, the powerhouse production capacity will be increased, units will
experience less outages and reduced damaged from the sediment, and the failing
control components will be replaced. Spending is expected to occur between 2012
and2021.
A complete evaluation of this alternative's review, the analysis process, and the risks
associated with the each is available in the aftached material. Construction of a new
powerhouse was eliminated due to lengthy permitting efforts, and increased risk
surrounding unknown construction efforts.
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Business Case Justification Narrative Page 3 of 4Exhibit No. 6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 6 of 120
Ni ne M i le Rehabilitation
o 4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Nine Mile Rehabilitation
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Date: ?/f fA7Z8
b
Mgr Contract & Project Mgmt
Business Case Owner
Signature:
Print Name:
Title:
Role:
Date:
Andy Vickers
Dir Gen Prod Sub Support
Business Case Sponsor
o 5 VERSION HISTORY
Template Version: A2f2412017
Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l,PageT of120
Version lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Nathan Fletcher 03128117 Steve Wenke 04to712017 lnitial version
1.1 Nathan Fletcher 6t27117 Jacob Reidt 06t2712017 Align with 2018+
Budqet
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Business Case Justification Narrative Page 4 of4
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Base Load Hydro
o1 GENERAL INFORMATION
Requested Spend Amount $1,149,000
Requesti n g Organ ization/Department Generation Production and Substation Support
Business Case Owner Mike Magruder
Business Gase Sponsor Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Category Program
Driver Asset Condition
1.1 Steering Committee or Advisory Group Information
Most projects are proposed through Operations and Engineering. The projects are vetted
holistically by Operations and Engineering to evaluate the issue, determine available
options, confirm prudency, and bring the potential solutions forward for discussion with the
Advisory Group consisting ofthe Plant Managers and the Manager of Hydro Operations. A
similar vetting process is followed for funding emergency projects with the impacted
stakeholders included.
Over the course of the year, the program funding is actively managed by the Manager of
Hydro Operations through monthly analysis and reporting for end of year expected spend.
2 BUSINESS PROBLEM
Avista's Base Load Hydro (or Base Hydro) program includes the Post F-alls, Upper Falls,
Monroe Street, and Nine Mile Hydroelectric Developments. These are all located on the
upper Spokane River and are "run of river" plants which require them to have a constant
water level in their forebay. It also includes minor capital projects at the Generation Control
Center and on the Generation Control Network. It can also include some projects at the Post
Street 115kV Substation where the two downtown hydro plants are tied into the grid.
The purpose of this progriln is provide funding for these plants to accomplish the objectives
of keeping operating expenses as low as possible and maintain a level of reliability as
indicated by the Equivalent Availability Factor (EAF) in the graph below. This program
covers the smaller capital expenditures and upgrades required to safely and reliably operate
the Upper Spokane River plants and continue their low cost. Projects completed under this
program include replacement of failed equipment and small capital upgrades to plant
facilities. The business driver for this pro$am is a combination of Asset Condition, Failed
(or Failing) Plant, and addressing operations deficiencies.. Most of these projects are short
in duration, typically well within the budget year, and many are reactionary to plant
operations issues.
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Business Case Justification Narrative Exhibit No. 6 page 1 of S
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 8 of I 20
Base Load Hydro
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Base Hydro Plant KPls
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- a E$,t6lor Ar.i.Urr, f.ctor lt^fL rollbt U oG. r{.
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Ease losd Hydro planti ore lhe run-of-rher pl.nt5 - NM, MS, UF and 9F
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Potelltlel for lmprovemcnt
s900,r00
sm0,100
5r00,100
s600,100
s500,100
s(00.100
s300.100
5200,100
3100.100
Above Bt.trctrttr.rt k (i
aaooaoarrt
3100
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"s"**!+'"o.tirt"r".r+S""o*".r.t*l'i".t!"r'*.t!"{+*t.".{o$.*$'$f,d*r$Jtr\tr$Month
Examples of projects completed in20l6 or in progress under this business case include:
o Monroe St. - Water Drain and Diversion Installation. This project captured high
flows on the site that were washing away some of the visitor amenities.
o Nine Mile - Replace Failed Spillway Gate Controls. This project will replace failed
controls that allow the spillway to automatically adjust to maintain a forebay level.
. Upper Falls - Upgrade Headgate Camera. This replaced a non-functioning camera
used for some area surveillance and to observe the trash rake operation on the intake.
o Post Falls - Replace Switch Building Drain Field. This project is to move ponding of
water away from the foundation structure to maintain the integrity of the building.
o Nine Mile - Install Roof Safety Handrail. This addresses a personnel safety item.
o Post Falls - Install N. Channel Downstream Warning System. This is a system that
wams the public in the event of a start of a spill or a significant increase in spill at the
site.
The Program funding requests are submitted to the Capital Planning Group (CPG) through
the business case review process. The business case expenditures over the last 5 years are
shown below.o
Business Case Justifi cation Nanative Page 2 of 5Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 9 of 120
oa.i+a +to
Base Load Hydro
oBase Load Hydro Expenditures
Previous Five Years
s1,000,000
s9oo,o0o
s800,000
s700,000
s600,000
sso0,oo0
S4oo,ooo
s300,000
s200,000
s100,ooo
SO
)-o12 2013 2014
3 PROPOSAL AND RECOMMENDED SOLUTION
These base load hydro plants are among the oldest plants in Avista's generating fleet. The
option to "Do Nothing" is impractical in that existing machinery and systems periodically
fail and are required to be replaced. Having no costs allocated to address those concems is
impractical.
The second proposal is to continue with the Base Hydro program business case as it is
intended for asset condition, failed plant and operations. The program is actively managed
and the vetting process considers all options for projects including doing the project under
maintenance, the Base Hydro program, or a specific project business case.
The last proposal to eliminate funding for this program introduces greater risk to the ongoing
operation of the plants by reducing the efficiency of operations and administration to set up
and execute the required projects, especially for failed plant and operations. 'fhe program
gives us the flexibility to respond quickly and prudently.
The recommended option to pursue is the second proposal to continue with the Base Hydro
program business case as it is intended for asset condition, failed plant and operations. The
program is actively managed and the vetting process considers all options for projects
including doing the project under maintenance, the Base Hydro program, or a specific project
I
2016
I
2015
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2012 2013 2014 2015 20t6
$631,961 $905,557 $664,783 $342,194 $394,849
Optlon Gapltal Cost Start Complete
Do nothing $o
Maintain Existing Base Hydro Program Busrness Case $350k - $1.15M Annual Annual
Make all small projecfs as sfandalone projects $s.1M - $5.9M Annual Annual
Business Case Justification Narrative Page 3 of 5Exhibit No. 6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule I, Page l0 of 120
Base Load Hydro
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business case. The program offers greater efficiency to manage "drop-in" or emergency
projects allowing for better response time.
The annual requested budget amount is conservative to cover potential large expenditures
that do not require a new project business case to be developed. The annual amount is
reasonable, especially given that the program is actively managed and there is a means to
release or request funds through the CPG.
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Business Case Justification Narrative Page 4 of 5Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page I I of 120
Base Load Hydro
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Base Load Hydro Business
Case and agree with the approach it presents and that it has been approved by the
steering committee or other governance body identified in Section 1.1. The
undersigned also acknowledge that significant changes to this will be coordinated
wlth and approved by the undersigned or their designated representatives.
o
o
Signature:
Print Name
Title:
Role:
Signature:
Print Name:
Title:
Role:
-ll*,,L^06)r4^ee Date:fl n /ro,t
Date:
Tem plate Version; 03107 12017
(\
Mar. t{zfuq Ops i /-la-)n*cnn**-('/
Business cas6 owner
O;rec{.r GPSs
Business Case Sponsor
5 VERSION HISTORY
o
Verslon lmplemented
By
Revlslon
Dats
Approved
By
Approval
Date
Reason
1.0 Mike Magruder 03117117 Jacob Reidt 04t19t2017 lnitialversion
Business Case Justification Narrative Page 5.of 5Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 12 of 120
,/t -
Regulating Hydro
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1 GENERAL INFORMATION
Requested Spend Amount $3,533,000
Requesting Organ izationlDepartment Generation Production and Substation Support
Business Case Owner Mike Magruder
Business Case Sponsor Andy Vickers
Sponso r Organization/Department Generation Production and Substation Support
Category Program
Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
Most projects are proposed through Operations and Engineering. The projects are vetted
holistically by Operations and Engineering to evaluate the issue, determine available
options, confirm prudency, and bring the potential solutions forward for discussion with the
Advisory Group consisting of the Plant Managers and the Manager of Hydro Operations. A
similar vetting process is followed for funding emergency projects with the impacted
stakeholders included.
Over the course of the year, the program funding is actively managed by the Manager of
Hydro Operations through monthly analysis and reporting for end of year expected spend.
2 BUSINESS PROBLEM
Avista's Regulating Hydro program includes the Cabinet Gorge (Idaho) and Noxon Rapids
(Montana) Hydroelectric Developments on the Clark Fork River and the Long Lake (WA)
and Little Falls (WA) Hydroelectric Developments on the lower Spokane River. Because
ofthe storage available in their reservoirs, these plants are operated to support energy supply,
peaking power, provide continuous and automatic adjustment of output to match the
changing system loads, and other types ofservices necessary to provide a stable electric grid
and to maximize value to Avista and its customers. These plants are the four largest hydro
plants on Avista's system representing more than 950 MW of power.
Because these plants are used to provide a wide variety of grid services, energy and power
supply, and other types of electric grid support services, the availability for the generating
units in these plants is pararnount. The purpose of this program is to provide funding to
achieve availability targets (Equivalent Availability Factor or EAF) of 85Yo or higher.
o
Business Case Justification Narrative Exhibit No. 6 page 1 of S
Case No. AVU-E- I 9-04
J. Thackston, Avista
Schedule l, Page 13 of 120
Regulating Hydro Plant KPls
s900,100
s800,1@
$700,100
$600,100
s500,r00
s100,l(E
9300,r00
s200,r00
slm,r00
s100
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+ a Equied.naAvrl{.lilityf.dor{CAR .ollirB12ne.y!.
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Rqulating Hydro Plants ere plarts wherethe output of the plant can be shaped throughout the day - lF,
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This program covers the smaller capital expenditures and upgrades required to safely and
reliably operate four largest hydro plants and to achieve the EAF target. Maintaining these
plants safely and reliably provides our customers with low cost, reliable power while
ensuring the region has the resources it needs for the Bulk Electric System. Projects
completed under this program include replacement of failed equipment and small capital
upgrades to plant facilities. The business driver for this program is a combination of Asset
Condition, Failed (or Failing) Plant, and addressing operations deficiencies. Most of these
projects are short in duration, typically well within the budget year, and many are reactionary
to plant operations issues.
Examples of projects completed in20l6 or in progress under this business case include:
o Cabinet Gorge - Tunnel Access Improvement; this work removed loose rock along the
access road and installed protective metal netting to address the hazard of falling rocks
on personnel and equipment. (Rock Scaling/Netting)
o Noxon - Install Dam Pressure Monitoring System; this work provided specialized
instrumentation so that operators and engineers can monitor the structural stability of the
dam.
o Long Lake - Spillway Improvements; this project replaced and enhanced some areas of
the Long Lake spillway section by removing and replacing areas of the decaying 100
year old concrete. (Rebuild Parapet Wall/Extend Spillway Walkway)
Business Case Justification Narrative Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 14 of 120
Page 2 of 5
Regulating Hydro
ol I
Regulating Hydro
o
o I
Regulating Hydro Expenditures
Previous Five Years
$6,000,000
s5,o@,ooo
94ooo,ooo
$r,ooopoo
s2,o0o,000
$1,ooo,ooo
so
2012 201s 2 016
3 PROPOSAL AND RECOMMENDED SOLUTION
The plants that make up the Regulating Hydro group provide the most flexibility of any of
the generating assets owned by Avista. As such, they provide a wide variety of critical and
economical services that allows Avista to optimize the entire energy portfolio.
Consequently, the option of doing nothing to maintain these units is a poor economic choice
on behalf of Avista's customers and shareholders.
Exhibit No. 6
CaseNo. AVU-E-I9-04
J. Thackston, Avista
Schedule l, Page 15 of 120
Sf.ZnA Five year Avera6e
II
20L3 2014
2012 2013 2014 2015 2016
$1,514,577 $2,517,815 $2,519,775 $4,073,698 $5,558,100
Optlon Capltal Gost Start Complete
Do nothing - not a viable option.$0
Maintain Existing Regulating Hydro Program Business Case $1.5M - $5.5M Annual Annual
Make all small projecfs as standalone projects $3.1M - $5.9M Annual Annual
o
Business Case Justification Narrative Page 3 of 5
o Little Falls - Replace Spillway Log Boom; this is a plant safety system that diverts
floating debris from the generating units and can provide a boundary to keep the public
away from the hazardous intake area of the dam.
o Noxon - Replace Unit 5 Turbine Bearing Cooling System
. Long Lake - Install Redundant Spillgate Hoist System; this work added a FERC required
secondary system so that in the event of a failure of one system, the spillgates could still
be operated with a second power source to assure ability to manage river flows at the
project and provide safe operation of the spillway.
The Program funding requests are submitted to the Capital Planning Group (CPG) through
the business case review process. The business case expenditurcs over the last 5 years are
shown below.
Hydro
The second option is to continue with the Regulating Hydro program business case as it is
intended for asset condition, failed plant and operations. The program is actively managed
and the vetting process considers all options for projects including doing the project under
maintenance, the Regulating Hydro program, or a specific project business case.
The last option to eliminate funding for this program introduces greater risk to the ongoing
operation of the plants by reducing the efficiency of operations and administration to set up
and execute the required projeots, especially for failed plant and operations. The program
gives us the flexibility to respond quickly and prudently.
The recommended option to pursue is the second proposal to continue with the Regulating
Hydro program business case as it is intended for asset condition, failed plant and operations.
The program is actively managed and the vetting process considers all options for projects
including doing the project under maintenance, the Regulating Hydro program, or a specific
project business case. The program offers greater efficiency to manage "drop-in" or
emergency projects allowing for better response time.
The annual requested budget amount is conservative to cover potential large expenditures
that do not require a new project business case to be developed. The annual amount is
reasonable, especially given that the program is actively managed and there is a means to
release or request funds through the CPG.
o
o
o
Business Case Justification Narrative Page 4 of 5Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 1 6 of 1 20
Hydro
o 4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Regulating Hydro Business
Case and agree with the approach it presents and that it has been approved by the
steering committee or other governance body identified in Section 1.1. The
undersigned also acknowledge that significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Signature:
Print Name:
Title:
Role:
)u";2.,^/a\.t -*-d Date: (/r1/-n
4 C
Case Owner
Signature:
Print Name:
Title:
Role:
Date:
tt/er5
{);re"f,, f, P Sj
Business Case Sponsor
o 5 VERSION HISTORY
Template Version: 03107 12017
Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 17 of 120
Vereion lmplemented
By
Revlolon
Date
Approved
By
Approval
Date
Reason
1.0 Mike Magruder 03117117 Jacob Reidt 04t19t2017 lnitial version
o
Business Case Justification Narrative Page 5 of 5
tt "
Baseload Thermal Program
1 GENERAL INFORMATION
Requested Spend Amount $3,100,000 per year
Requestin g Organ ization/Department Generation Production and Substation Support
Business Case Owner Thomas Dempsey
Business Gase Sponsor Andy Mckers
Sponsor Organ izationlDepartment Generation Production and Substation Support
Gategory Program
Driver Failed Plant & Operations
1.1 Steering Committee or Advisory Group lnformation
This business case request is for Avista's base load thermal plants, Kettle Falls and
Coyote Springs 2. The purpose of this program is for these plants to keep their
operating expenses as low as possible by providing funding for specific efforts to
allow the plants to accomplish that objective.
Smaller and emergent projects planned for Kettle Falls are identified and prioritized
through their plant Budget Committee. The plant Budget Committee utilizes an in-
house Maintenance Project Review scoring matrix.
Projects planned specifically for Coyote Springs 2 are identified and prioritized
during the Annual Budgeting process, with emergent projects discussed during the
Monthly Owners committee meetings between Avista management and Coyote
Springs management. Some of the projects that fall within this business case are
joint projects between Portland General Electric (PGE) and Avista. Those
"common" projects are also reviewed in an ownercommittee setting during meetings
at the plant that take place on a monthly basis.
lndividual projects are identified and approved by the Manager of Thermal
Operations and Maintenance, specific plant managers and/or GPSS management.
Some specific jobs under this program may require additional financial analysis if
they are sufliciently large or there are several options that can be chosen to meet
the objective. These projects are reviewed with finance personnelto make sure that
they are in the best interest of our customers.
2 BUSINESS PROBLEM
Various projects for Coyote Springs 2 and Keftle Falls Generating Station are
necessary to ensure continued safe, low cost, reliable and compliant electrical
generation for Avista's electric customers. Work includes replacement of items
identified through asset management decisions and programs necessary to
maintain reliable and low operating costs of these plants. The projects that are
opened under this business case are not known in advance. Most of the individual
projects are small in nature and are required due to regulatory or environmental
o
o
Business Case Justification Narrative Page 1 of4
o
Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 18 of 120
Baseload Thermal Program
o requirements, emergent safety items, orfor continued reliable operation. Examples
of recent expenditures under this Program include:
o Kettle Falls - Replace the Furnace Grate Drive System, part of the system
that moves the burned fuel from the boiler to the ash disposal system
(Reliability)
o Kettle Falls - Replace Furnace Forced Draft Fan motor, the fan that blows
the wood waste fuel into the boiler where it is burned (Reliability)
. Kettle Falls - Diesel Fueling System, providing additional containment and
system to improve the onsite diesel fuel handling system (Regulatory or
Environmental)
o Kettle Falls - Replace the Turbine/Generator fire system (Safety)
. Coyote Springs 2 - Replace the Reheat Steam Attemperator, the system
used to controlthe steam temperature in the boiler (Reliability)
. Coyote Springs 2 - Upgrade the Medium Pressure steam control valves
(Safety and Reliability)
. Coyote Springs 2 - Upgrade the NOx analyzer, part of the plant emission
monitoring system that monitors the Nitrous Oxide emissions (Regulatory or
Environmental)
. Coyote Springs 2 - lmprove physical site security, addition of key card
access door locks on criticalfacility doors. (Regulatory, Safety)
3 PROPOSAL AND RECOMMENDED SOLUTION
The Capital Retirement Unit Catalog for Kettle Falls and "Other" became effective
January 1 ,2017 . Due to this Retirement Unit Catalog update, $900,000 in additional
funds are necessary for 2017, in order to cover capital projects that were previously
identified as Operation and Maintenance. The Base Load Thermal Business case
is reassessed for adjustments on a 5 year cycle.
A 5 year historical graph of expenditures is attached to help assess future capital
funding for the Base Thermal Plant. This spending pattern indicates the diligence
that is applied to capital requests as managed by the Kettle Falls plant Budget
Committee and the joint owners of Coyote Springs during their monthly meetings.
As mentioned above, there is opportunity to adjust this amount every five years if
needed.
o
o
Option Capital
Cost
Start Complete Risk
Mitigation
As proposed $3,100,000 Ongoing, required for operation
Unfunded Program
Business Case Justification Nanative Exhibit No. u Page 2 0f 4
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page I 9 of 120
Baseload Thermal Program
Baseload Thermal Capital Program
52,244,s4O s2,083,1S4
o
s2,s00,000
s2,000,000
s1,500,000
s1,000,000
s500,000
So
st,970,337
s1,s90,60s
51,162,L97
2012 2013 20L4 2015 2016
o
Exhibit No. 6 Page 3 of 4
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1 , Page 20 of I 20
Business Case Justification Narrative
o
Baseload Thermal Program
o 4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Baseload Thermal Program
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name:
Title:
Role:
Thomas Dem
(4*. The,c*nau O* & fl*,oferri;;a;;offi"'
Andy Vickers
Drtea'.oa, G P65
Business Case Sponsor
Date:
Date:
Template Version : 0212412017
o 5 VERSION HISTORY
o
Vension lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Mike Mecham 04105t2017 Jacob Reidt 04t14t2017 lnitial version
2.O Thomas Dempsey 07t16t2018
3.0 Thomas Dempsev 05t31t20't9
Business Case Justification Narrative Page 4 of 4Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule I, Page 2l of 120
4i,
o1 GENERAL INFORMATION
Requested Spend Amount $500,000 per year
Requesting Organ ization/Department Generation Production and Substation Support
Business Case Owner Thomas Dempsey
Business Case Sponsor Andy Vickers
Sponsor Organization/Department
Category Program
Driver Failed Plant & Operations
1.1 Steering Gommittee or Advisory Group lnformation
This business case request is for Avista's Peaking Generation thermal plants,
Boulder Park Generating Station, Northeast Combustion Turbine and Rathdrum
Combustion Turbines. The purpose of this program is for these plants to keep their
operating expenses as low as possible and to ensure start and operating reliability
is achieved by providing funding for specific efforts to allow the plants to accomplish
that objective.
Smaller and emergent projects planned for these facilities are identified and
prioritized during monthly maintenance meetings, and approved by the Manager of
Thermal Operations and Maintenance.o
o
Peaking Generation Business Case
Business Case Justification Narrative Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule I , Page 22 of 120
Page 1 of3
Generation Production and Substation Support
2 BUSINESS PROBLEM
Various projects for Boulder Park Generating Station, Northeast Combustion
Turbine and Rathdrum Combustion Turbines are necessary to ensure continued
safe, low cost, reliable and compliant electrical generation for Avista's electric
customers. Work includes replacement of items identified through asset
management decisions and programs necessary to maintain reliable and low
operating costs of these plants. Attimes these plants are needed byAvista's Power
Supply and System Operations group to start and operate in an emergency
situation, where the electrical output is needed in a short amount of time. There
have been times that have been identified by plant operations and tracked by
Avista's asset management metrics reports, where start reliability and forced
outages occur on a higher than acceptable occurrance. Some projects under this
business case are completed to improve the start reliability of these facilities.
The projects that are opened under this business case are not known in advance.
Most of the individualprojects are small in nature and are required due to regulatory
or environmental requirements, emergent safety items, or for continued reliable
operation. Examples of recent expenditures under this program include:
. Boulder Park - Emission Programmable Logic Controller replacement -
allows remote monitoring of air emission to remain compliant with permit.
(reg ulatory or environmental)
Peaking Generation Buslness Case
. Boulder Park - Replace the start air compressors - air used for start up of
the engines (reliable operation)
o Northeast Combustion Turbine - Replace start system air compressors - air
used for start up of the turbine (reliable operation)
o Northeast Combustion Turbine - Add sewage holding tank - replace
antiquated sewage management system (regulatory or environmental)
. Rathdrum Combustion Turbines - Replace the Carbon Dioxide fire
extinguishing system controllers - system utilized in case of an emergency
in the combustion turbine area (safety)
. Rathdrum Combustion Turbines - Continuous Emission Monitoring System
replacement - used to monitor and record air emission when the combustion
turbines are on line (regulatory or environmental)
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capita!
Cost
Start Gomplete Risk
Mitigation
As proposed $500,000 Ongoing, required for operation
Unfunded Program
This program is necessary to sustain or improve the existing operating costs for
Boulder Park Generating Station, Northeast Combustion Turbine and Rathdrum
Combustion Turbines. Work includes replacement of items identified through asset
management decisions and programs necessary to maintain reliable and low
operating costs of these plants. The Peaking Generation Business Case is
reassessed for adjustments on a 5 year cycle.
A 5 year historical graph of expenditures is attached to help assess future capital
funding for the Peaking Generation plants. This spending pattern indicates the
diligence that is applied to capital request as managed by the Peaking Generation
management team. As mentioned above, there is opportunity to adjust this amount
every five years.
Peaking Generation Capital Progra m
s1,000,000
ss00,000
So
5s20,891
2016
ss92,863
;i*#;..-"
ffi
2013
$3s8,049
2072
582,773
III
2014
s488,646
2015
o
Business Case Justifi cation Narrative Exhibit No. u Page 2 0f 3
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l,Page 23 of 120
Peaking Generation Busrness Case
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Peaking Generation
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Date:
o
o
Signature:
Print Name:
Title:
Role:
Signature:
Print Name:
Title:
Role:
lr
Thomas Dempsey
ltvt*,onrr*tt^ //l,q,r..t
Business Case Owner
Andy Vickers
D,Re.-rr4 C lss
Business Case Sponsor
Date: Otf t,fiq s
5 VERSION HISTORY
Tem plate Version : 0?24 f2O17
Version !mplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Mike Mecham 04107t2017 Jacob Reidt 0/.117t2017 lnitialversion
2.0 Thomas Dempsev 05t31t2019
Business Case Justification Narrative
o
Exhibit No. 6 Page 3 of 3
Case No. AVU-E-I9-04
J. Thackston, Avista
Schedule l,Page 24 of 120
Little Falls Plant Upgrade
o
o
1 GENERAL INFORMATION
Requested Spend Amount $56,100,000
Requesting Organ ization/Department Generation Production and Substation Support
Business Case Owner Jacob Reidt
Business Case Sponsor Andy Vickers
Sponsor Organ ization/Department Generation Production and Substation Support
Gategory Project
Asset Condition
{.1 Steering Committee or Advisory Group Information
This program is comprised of two layers of Steering Committee Oversight. One
layer of oversight is at the program level and the other layer is at the project level.
The Program Steering Committee is responsible for vetting and approving the
objective, scope and priority of the program. The deliverables for the program are
then reviewed with the Program Steering Committee on a semi-annual basis. Any
significant changes to the program's scope, budget or schedule will be approved
by the Program Steering Committee. The Program Steering Commiftee is
composed of the Director of GPSS and the Director of Power Supply. This
committee meets semi-annually or as major events create a change order request.
The Project Steering Committee oversees the deliverables of the individual
projects. Each member of the steering committee represents a major stakeholder
in the project. The members are dependent on the respective project but will
include representatives from hydro operations, central shops and engineering. The
Project Steering Committee will approve and changes to the schedule, scope and
budget of the individual project. They also are responsible for approving the
necessary personnel for the completion of the project. This group is engaged on a
quarterly basis.
2 BUSINESS PROBLEM
The existing Little Falls equipment ranges in age from 60 to more than 100 years
old. Little Falls experienced an increase in forced outages over the past six years,
increasing from about 20 hours in 2004 to several hundred hours in the past
several years, due to equipment failures on a number of different pieces of
equipment.
The major drivers for the Little Falls Plant Upgrade are available and reliability. See
the graph below that illustrates the trend line for availability at Little Falls.
o
Page 1 of5 Exhibit No- 6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 25 of 120
Driver
Trend Line
oPlant Availability
2001 2@2 2003 20[,4 200s 2006 20A7 2m8 2@9 2010
Once the business case is complete, a study of forced outages at the plant over a
5 year period could be taken and measured against the pre-construction outage
numbers to determine if plant availability has increased and the business case
objective met.
3 PROPOSAL AND RECOMMENDED SOLUTION
Below is a breakdown of the capital construction cost associated with each
alternative and any ongoing maintenance costs associated with each alternative.
Capital Cost O&M Cost
Status Quo $0 $150,000/yr +
Alternative 1 $5,000,000 $20,000/yr +
Alternative 2 $83,000,000 $0
Proposed Alternative $56,100,000 $0
Summarv of alternatives:
Status Quo: Forced outages and emergency repairs would continue to increase,
reducing the reliability of the plant. Each time a generator goes down for an
emergency repair, Avista is forced to replace this energy from the open market
which leads to higher energy costs.
It is expected that the O&M costs would continue to climb as more failures
occurred. This may also require personnel to be placed back in the plant to man
the plant 2417 in order to respond to failures. Again, increasing expenses for the
project with no benefit in performance.
1
0.95
0.9
0.85
0.8
o
a
Little Falls Plant Upgrade
Page 2 of 5 Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1 , Page 26 of 120
Little Falls Plant Upgrade
o
o
o
Alternative 1: Replace Switchgear and Exciter: This would replace the two items
that are currently responsible for the majority of the forced outages, and then
continue to use the remaining equipment.
This alternative is a temporary fix. One of the generators has a splice and is
expected to fail in the next few years. lf this generator fails before a new generator
is ordered, this generator will be out of service for 2 years. The control system is a
vintage system and is on the verge of a total failure and spare parts are not
available (a few minor system failures occurred in the past 2 years). lf a total
system failure is encountered, it is expected the plant to be down for a year as the
control system is designed, procured and installed.
Alternative 2: Replace all generating units with larger, vertical units capable of
additional output. Avista's Power Supply group evaluated the present value of
larger, vertical units at Little Falls. The increase in present value from larger units
was $20M over a 30 year analysis. The capital construction cost increase from in-
kind replacement to vertical units was $27M.
This present value calculation of benefit did not include risk. lnstalling new vertical
units would require modification of the powerhouse foundation and presents
serious construction risk. Due to the high construction costs, high risk, and low
payoff NPV, this alternative was abandoned.
Alternative 3 and Proposed Alternative: Replace nearly all of the older and less
reliable equipment with new equipment. This includes replacing two of the
turbines, all four generators, all generator breakers, three of the four governors, all
of the AVR's, removing all four generator exciters, replacing the unit controls,
replacing the unit protection system, and replacing and modernizing the station
service. All major equipment would be procured through a competitive bid process
to help keep construction costs low. Equipment would also be purchased for all
four units at once to help keep costs down.
Add itional J ustif ication for Proposed Alternative :
Because of the age and condition of all of the equipment at the plant, all of the
equipment has been qualified as obsolete in accordance with the obsolescence
criteria tool. The Asset Management tool has been applied to Little Falls and also
supports this project. The Asset Management studies that have been done to date
are still subject to further refinements, but the general conclusions support this
project. There are many items in this 100 year old facility which do not meet
modern design standards, codes, and expectations. This project will bring Little
Falls to a place where it can be relied on for another 50 to 100 years. Finally, this
project will need to be worked in coordination with our lndian Relations group as
the Little Falls project is part of a settlement agreement with the Spokane Tribe.
Milestone Schedule:
January 2010
March 2012
January 2014
January 2014
Program Begins
Exciter & Generator Breaker Replacement Complete
Warehouse Construction Complete
Bridge Crane Overhaul Complete
Page 3 of 5 Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1 , Page 27 of 120
February 2015 Station Service Replacement Complete
February 2016 Unit 3 Modernization Complete
April2017 Unit 1 Modernization Complete
October 2017 Backup Generator lnstall Complete
May 2018 Unit 2 Modernization Complete
May 2019 Unit 4 Modernization Complete
October 2019 Headgate Replacement Complete
Yearly Transfer to Plant:
2013 $3,100,000
2014 $2,000,000
2015 $4,000,000
2016 $16,300,000
2017 $10,400,000
2018 $9,000,000
2019 $13.000.000
Total $57,800,000
Strateqic Aliqnment:
The Little Falls Plant Upgrade aligns with the Safe and Reliable lnfrastructure
company strategy. The program will address safety and reliability issues while
looking for innovative, economical ways to deliver the projects.
Customers and Stakeholders:
Mike Magruder Manager, Hydro Operations and Maintenance
Alexis Alexander Manager, Spokane River Hydro Operations
Kevin Powell Chief Operator, Long Lake and Little Falls HED
o
o
o
Little Falls Plant Upgrade
Page 4 of 5 Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule I , Page 28 of 1 20
o
o
Little Falls Plant
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Little Falls Plant Upgrade
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Mgr Contract & Project Mgmt
Business Case Owner
Date: bffi)flV
Date:
Template Vension: 0A2412017
Signature:
Print Name:
Title:
Role:
Andy Vickers
Dir Gen Prod Sub Support
Business Case Sponsor
5 VERSION HISTORY
o
Verslon lmplemented
By
Revlslon
Date
Approved
BY
Approval
Date
Reason
1.0 Brian
Vandenburq
o2l'14120't7 Steve
Wenke
0411012017 lnitialCreation
Page 5 of 5 Exhibit No. 6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule I , Page 29 of 120
1?
Long Lake Plant Upgrade
1 GENERAL INFORMATION
Requested Spend Amount $46,000,000
Req uesting O rgan ization/Department Generation Production and Substation Support
Business Case Owner Jacob Reidt
Business Gase Sponsor Andy Vickers
Sponsor Organization/Depa rtment Generation Production and Substation Support
Gategory Project
Driver Asset Condition
1.1 Steering Committee or Advisory Group Information
This program is comprised of two layers of Steering Committee Oversight. One Iayer
of oversight is at the program level and the other layer is at the project level.
The Program Steering Committee is responsible for vetting and approving the
objective, scope and priority of the program. The deliverables for the program are
then reviewed with the Program Steering Committee on a semi-annual basis. Any
significant changes to the program's scope, budget or schedule will be approved by
the Program Steering Committee. The Program Steering Committee is composed of
the Director of GPSS, Director of Environmental Affairs, and the Director of Power
Supply. This committee meets semi-annually or as major events create a change
order request.
The Project Steering Committee oversees the deliverables of the individuallrojects.
Each member of the steering committee represents a major stakeholder in the
project. The members are dependent on the respective project but will include
representatives from hydro operations, central shops and engineering. The Project
Steering Committee will approve and changes to the schedule, scope and budget of
the individual project. They also are responsible for approving the necessary
personnel for the completion of the project. This group is engaged on a quarterly
basis.
2 BUSINESS PROBLEM
The existing Long Lake equipment ranges in age from 20 to more than 100 years
old. We have experienced an increase in forced outages at Long Lake overthe past
six years, almost zero in 2011 and increasing every year since then. This is caused
by equipment failures on a number of different pieces of equipment. Specifically, the
turbines are thrusting too much (a sign of significant wear), including a failure in
2015. The 1990 vintage control system is failing and only secondary markets can
support this equipment.
The original generators consist of a stator frame, stator core, stator winding, and
rotor field poles. They were originally rated at 12 MW's. ln the late 1940's, the
height of the dam was raised 16 feet which resulted in more operating head for the
o
o
Exhibit No. 6
Case No. AVU-E- I 9-04
J. Thackston, Avista
Schedule l, Page 30 of 120
Business Case Justification Narrative PaOe 1 of[
o
Long Lake Plant Upgrade
o generating units. A forced air cooling system for the generators was added to the
plant at that time to accommodate the increase in output from 12to 17 MW's due to
the increased head. ln the 1960's, the stator windings on all of the units were
replaced and the rating of the generators, along with the forced air system allowed
for the units to operate at the higher 17 MW output.
ln the 1990's, the original turbine runners were replaced and upgraded. The
improvement in turbine runner efficiency resulted in still another increase in unit
output. Since the mid-1990's, the generators have been operating with a maximum
output of 22 to 24 MWs. The generators are currently operated at their maximum
temperature which stresses the life cycle of the already s0+-year'old winding.
Inspections of other components of the generator show the stator core is "wavy".
The core lamination steel should be in straight. The "wave" pattern is a strong
indication of higher than expected losses are occurring in the generator. Finally,
maintenance reports have identified that the field poles on the rotor have shifted
from their designed position very slightly over the years. While there can be several
causes of this movement, it is speculated that it is due to the high operating
temperatures of the generator. This highlights the first driver for the program,
reliability.
With the increase in generator output, the output of the generator step up
transformer (GSU) has also increased to its rating. These GSU's are now running
at the high 65C temperature which is a concern. As these GSU's are more than 30
years old and operating at the high end of their design temperature, these are now
approaching their end of useful life and need to be replaced proactively rather than
wait for a failure.
The other major driver for the program is safety. The switching procedure for moving
station service from one generator to the other resulted in a lost time accident and a
near miss in the past 5 years. ln addition, the station service disconnects represent
the greatest arc-flash potentia! in the company. This area is roped off and substantial
safety equipment is required to operate the disconnects. This project will reconfigure
this system to eliminate requiring personnelto perform this operation and avoid the
arc-flash potentia! area.
Below is a graph of Forced Outage Factor for Long Lake HED from Avista's Asset
Management Plan.
o
o
Business Case Justification Narrative Page 2 of 7Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 31 of 120
Long Lake Plant Upgrade
Long Lake HED Forced Outage Factor o
o
-)(-Long Lake HED Unit 1
Long Lake HED Unit 3
+Long Lake HED Unit 2
Long take HED Unit 4
25%
20%
t5%
10%
5%
o%
2009 2010 20tt 20t2 2013 20L4 2015
The below graph shows the O&M cost at Long Lake for the past 11 years. The
trendline is increasing due to increasing repairs to aging equipment.
O&M Cost at Long Lake
1,000,000
900,000
800,000
700,000
600,000
500,000
400,000
300,000
200,000
100,000
0 lll II
2005 2006 2007 2008 2009 2010 2011 2072 2013 2014 2015
The above graph shows the O&M cost at Long Lake for the past 11 years. The trendline is
increasing due to inoreasing repairs to aging equipment.
& smaller
Business Case Justification Narrative Page 3 of 7
o
Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 32 of 120
Lon Lake Plant
o 3 PROPOSAL AND RECOMMENDED SOLUTION
Optlon Capltal
Cost
Requeeted
Start
Requested
Gomplete
Do nothing $0 N/A
Recommended: Replace Units ln-Kind $46M 05t2018 06t2024
Alternative 1: lnstall four new 60MW vertical units $173M 05/2018 04t2023
Alternative 2: Construct one unit powerhouse $144M 0512018 07t2021
Alternative 3: Construct two unit powerhouse $276M 05t2018 1112021
Alternative 4: Replace Units ln-Kind $46M 05t2018 06t2024
o
Do Nothing: Continue to run plant and repair as necessary
The Long Lake powerhouse would continue to operate as it has for the past 10
years. O&M costs would continue to rise. ln an additional 10 years, if the trend
continues, average O&M costs will rise from $285k in 2005 to $590 in 2014 and
projected to be $900kin 2024. Due to the condition of the generators, it is likely that
one of the generators or another piece of major equipment will fail and permanently
disable equipment, increasing forced outage numbers.
Altemative 1: lnstall four new 30MW vertical units
This alternative would be to replace the four existing units in the powerhouse with
four new 30 MW Kaplin units. Significant civil, electricaland mechanicalwork would
be required, in addition to powerhouse access.
The increased yearly generation would be 114,000MWh. Using $30/MWh
(extremely conservative number) the rough yearly benefit to Avista is $3.4M. The
payoff period is greaterthan 30 years and therefore this alternative was abandoned.
Alternative 2: Construct one unit powerhouse
lnstead of upgrading the current powerhouse, this alternative is to construct a new
powerhouse with a single, 68MW next to the existing powerhouse, using the saddle
dam (also referred to as the "arch dam") as an intake. This alternative would only
use the old powerhouse during high flows, when flows exceeded the new unit's
capacity. Additional funds would be required to upgrade, even at a minimum level,
to address some of the failing components.
The increased yearly generation would be 170,000MWh. Again, using $30/MWh the
rough yearly benefit to Avista is $5.1M. The payoff for this is 30 years. Again, since
this cost does not include the additional work required in the plant and the cost of
the risk associated with modifying the saddle dam, this alternative was abandoned.
Alternative 3: Construct two unit powerttouse
Another option to build a new powerhouse is to construct a new powerhouse with
two, 76MW units next to the existing powerhouse. This alternative would also use
the saddle dam as an intake. This alternative would only use the old powerhouse
Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 33 of 120
o
Business Case Justification Narrative Page 4 of 7
during extreme high flows, minimizing the need to perform any upgrades to the old
plant.
The increased yearly generation would be 258,000MWh. Using $30MWh, the rough
yearly benefit to Avista is $7.7M. The payoff would be greater than 30 years and
therefore the alternative was abandoned.
Alternative 4 and Recommended Altemative: Replace units in-kind
This alternative would replace the existing major unit equipment (generator, field
poles, governors, exciters, generator breakers) with new equipment.
Over the past 11 years, the average O&M spend at Long Lake was $470k, with the
low being $262k and the high year being $944k. ln addition, the O&M cost is trending
upward. After the upgrade, the expected O&M cost is $200k/year, an average
reduction of $270Uyear.
Milestone Schedule:
May 2017 Project Kickoff
Sept 2018 Vertical Elevator Replacement Complete
Dec 2018 Bridge Crane Replacement Complete
Nov 2018 Sewer System Overhaul
Oct 2019 Access Road Overhaut
Dec 20'19 Facility Upgrades
Oct 2019 Station Service Replacement
Apr 2021 Unit 1 Overhaul
Oct 2020 Air System Overhaul
Apr 2022 Unit 2 Overhaul
Apr 2023 Unit 3 Overhaul
Sep2022 Sump System Overhaul
Sep 2022 Spillway Controls Replacement
Apr 2024 Unit 4 Modernization
Aug2024 Control Room Remodel
Yearlv Transfer to Plant:
2018 $3,750,000
2019 $5,500,000
2020 $250,000
2021 $21,100,000
2022 $8,050,000
2023 $7,600,000
2024 $8.300.000
Total $45,750,000
Strategic Aliqnment:
Business Case Justification Narrative Page 5 of 7
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 34 of I 20
o
o
o
Long Lake Plant Upgrade
Long Lake Plant Upgrade
o The Long Lake Plant Upgrade aligns with the Safe and Reliable lnfrastructure
company strategy. The program will address safety and reliability issues while
looking for innovative, economicalways to deliver the projects.
Customers and Stakeholders:
Manager, Hydro Operations and Maintenance
Manager, Spokane River Hydro Operations
Chief Operator, Long Lake and Little Falls HED
o
o
Business Case Justification Narrative Page 6 of 7Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 35 of 120
Long Lake Plant Upgrade
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Long Lake Plant Upgrade
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
o
Signature:
Print Name:
Title:
Role:
Date: 7n0y tr
Mgr Contract & Project Mgmt
Business Case Owner
Signature:
Print Name:
Title:
Role:
Date e
Andy Vickers
Dir Gen Prod Sub Support
Business Case Sponsor
5 VERSION HISTORY o
Template Version: OZl24l2O17
o
Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 36 of 120
Verslon lmplemented
By
Revhlon
Date
Apprcved
By
Approval
Date
Reason
Brian
Vandenburo
03t22t2017 Steve
Wenke
04t1012017 lnitialCreation
Business Case Justification Narrative Page 7 of 7
'1.0
Generation DC Supplied Sysfem Update
o
o
1 GENERAL INFORMATION
Requested Spend Amount $1,315,000
Req uesting O rga n ization/Depa rtment Generation Production and Substation Support
Business Case Owner Glen Farmer
Business Case Sponsor Andy Vickers
Sponsor Organ ization/Department Generation Production and Substation Support
Category Program
Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
The Steering Committee for this project consists of members from the Generation
Production and Substation Support Department including the Hydro Operations &
Maintenance Manager, the Thermal Operations & Maintenance Manager, and the
Generation Electrical Engineering Manager. Steering committee members receive project
status updates when there are proposed changes to the program plan and are convened only
in the event of a decision point.
The project stakeholder teams meet on a regular basis to work on the project scope and
planning the project. The stakeholder teams are comprised of the representatives from
Project Management, Engineering (Electrical, Controls, Mechanical & Civil), Operations,
Maintenance and Compliance.
2 BUSINESS PROBLEM
This program supersedes a previous program that was identifiedfor Battery Bank replacements only.
Traditionally, the Direct Current @C) system, (aka Battery System) at each generation plant
is used for protection and monitoring of the plant. All the protection relays, breaker control
circuits and monitoring circuits are fed from this source. The source is assumed to always
be on-line and able to supply the critical load for a predetermined length of time.
As technology has evolved, other standalone DC systems that were installed at difflerent
times, Typical plants now have standalone DC Systems for: general station, Uninterruptible
Power Supplies (UPS), govemors (electronic turbine speed controllers), communications
and control systems. Each of these systems have a battery bank, battery charger, converters
to supply different voltages, and distribution panels and circuits. As things have changed on
the generating units or in the balance of plant systems, the DC load requirement has
significantly increased and the time duration for the systems to supply this critical load has
increased. Our current practice is to replace the battery banks per manufactures life cycle
recommendations. This practice is not addressing the additional load added to the systems.
Some of the other issues we have had on the DC systems are the failing of battery cells due
to inconsistent temperature and environmental control needed to maintain these present
battery systems. The system life cycle is 20 years at its normal operating temperature of 77
degrees F. For temperatures fifteen degrees F over the normal operating temperature the life
Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 37 of 120
o
Business Case Justification Narrative Page 1 of5
Generation DC Sup plied Sysfem Update
cycle is decreased by 50 percent. Component failure, utilization from multiple extended
outages and manufactures quality are other problems we have experienced on these systems.
Finally there are compliance requirements from the North American Electric Reliability
Corporation (NERC) for inspections, maintenance and testing of the battery banks to make
sure they are in good working order and will perform when called upon. In order to perform
these inspections and maintenance, and testing needs, it requires either unit or plant outages
to comply with the requirements for multiple DC systems that are now present in our
stations.
To address these multiple issues, a new Generation Plant DC Standard was developed by the
engineering group. The new Generation Plant DC Standard System provides for layers of
back up and redundancy to address current and future capacity needs as well as addressing
maintenance and testing requirements. This Program will replace existing DC systems at
Avista's owned and operated generation plants with a system that meets this new design
standard. The Generation Plant DC Standard will be used as a guide for defining the base
scope ofthe project.
The activity objectives is to order the plant replacements in a time line that will allow for
stages ofaproject to happen and use our engineering and construction staffing. At each plant
the DC System will be updated to meet the current Generation Plant DC System Standard
and the following:
l. Comply with NERC requirements for inspection and testing.
2. Address battery room environmental conditions to optimize battery life.
3. Replace any legacy UPS systems with an invertor system.
4. Address auxiliary equipment based on life cycle.
5. Hydrogen sensing and fire alarm, eyewash station and lighting.
6. Wall separation of batteries and auxiliary equipment.
7. Install Programmable logic controller monitoring and new operating screens to provide
visibility for operations and maintenance purposes.
8. Provide new distribution panels, disconnect switches, voltage conversion devices for
communications equipment that operate at different voltages.
9. Establish current drawings, construction documents, VO list, plans, schedules, manuals
and as-builts.
o
o
Option CapltalGost Start Complete
1. Do nothing - no action $o
2. Address the DC system standards as we
are doing other system or unit upgrades.
$1,315,000/yr 01t2017 12t2030
3. Replace parts as they fail with the goal
of making it like our standard over time.
$200,000/yr o'U2017 1212037
Business Case Justification Narrative Page 2 of 5
o
Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule I , Page 38 of 1 20
3 PROPOSAL AND RECOMMENDED SOLUTION
Generation DC Supplied System Update
o
o
The "no action" alternative fails to address the issues associated with our culrent DC system.
It allows for the scope of any maintenance work to balloon into a large project so if a problem
arises there is not defined plan to address it. This can extend outages and leave the plant
exposed for extended time frames for repairs and/or replacement parts. Upon failure we
would temporarily restore the system back to working condition with the knowledge that we
have to address it later. It places plant equipment at risk if a key element of the DC system
were to fail, particularly the battery system. It also does not provide a means to perform
required NERC testing and does not provide a means to plan for replacements costly. AIso,
critical AC loads served from the UPS have increased to the point where we can no longer
get a UPS that is of necessary size. We would have to install more UPS systems, creating
more maintenance work and increasing the NERC testing requirements. It also does not
address any other issues that our design standard is intending to address. While it is a much
higher life cycle cost and operationally impactful option.
Alternative 2 is to address the DC system as part of another capital project. In this case the
scope of the DC system upgrade project is often a lower level effort and is subordinated to
the primary project. The table below shows the current upgrade plans. While planning and
scoping management can manage the concerns about making sure the DC Supplied Systems
can be fully addressed, we do not have plans to work through all of the plants. This would
leave the program incomplete.
Alternative 3 to replace parts as they fail doesn't address any of the requirements for
Standards, NERC inspection and testing, or the room itself. The parts fail at different time
and we are subject to more outages. This also requires reaction to a critical system failure.
Clearly replacing failed parts and components is a more costly item than performing planned
work and without a planned effort, deployment of that new Generation Plant DC Standard
would likely take decades. Replacing as components fail and gradually build out to our
standard has the benefit of minimizing the costs of this program. However, it would be
unpredictable would make labor planning impossible. This would also place the plant at a
higher likelihood of forced outages and equipment damages if we wait for failure.
Business Case Justification Narrative Exhibit No. 6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 39 of I 20
Page 3 of 5
o
4. Establish an independent DC system
replacement program to bring plants to a
standard as quickly as possible.
1,315,000/yr 1t20t2017 12t20t26
Year Plant Comments Cost
2014 Little Falls DC system was built to our standard, example to follow.$700k
201s Nine Mile Being addressed by Units l&2 project $650k
201s GCC Just battery bank replacement.$250k
2016 Monroe Street Doing design in 2015. Basis of design done. Install in 2016.$700k
2017 Cabinet Gorge Address existing problems with UPS system.s700k
201 8 Long Lake Do design in conjunction with Unit Upgrades.$700k
2019 Post l'alls Do design with plant rebuild.$700k
2420 Kettle Falls Steam Turbine & Gas Turbine DC System.s700k
Generation DC Supplied Sysfem Update
o
Altemative 4 is to construct new systems as part of a programmatic effort. This would allow
for prioritized and planned series of projects to upgrade the existing station DC systems to
the Generation Plant DC Standard. This will save time and expense over the life cycle of the
station with the flexibility it provides to address future capacity and maintenance needs, and
the ability to perform NERC required testing. It also has the benefit allowing a schedule to
be established for both the engineering and the installation. Both of these resources are
constrained and it would allow options of contracting or in-house consideration. A typical
schedule to execute is given below. Each planned project would take approximately 16 to
18 months. Added complexity, cost, and time may be needed if extensive work is required
to address the temperature and other environmental issues with the location of the new
battery system.
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Alternative 4 is the recommended approach. This program aligns with Avista's Safe and
Reliable Infrastructure goal through investment to achieve optimum life-cycle performance
and operational safety. In addition, it helps Avista meet its corporate compliance goals.
Exhibit No. 6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule 1 , Page 40 of I 20
Business Case Justification Narrative Page 4 of 5
o
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Generation DC Supplied Sysfem Update
o 4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Generation DC Supplied
System Update Business Case and agree with the approach it presents and that it
has been approved by the steering committee or other governance body identified
in Section 1.1. The undersigned also acknowledge that significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Date 7
Business Case Owner
Signature:
Print Name:
Title:
Role:
Date:
I
a ire c
Business Case Sponsor
5 VERSION HISTORY
Tem plate Version: O3lO7 12017
(r^
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o
Verslon lmplemented
By
Revlelon
Date
Approved
By
Approval
Date
Reason
1.0 Glen Farmer 4nt2a17 Steve Wenke 411012017 lnitialVersion
o
Business Case Justification Narrative Page 5 of 5Exhibit No. 6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule I, Page 41 of 120
/,2 -
Posf Falls HED Redevelopment Program
o1 GENERAL INFORMATION
Requested Spend Amount $89,500,000 - +l- 30o/o
Req uesting Organ ization/Department Generation Production and Substation Support
Business Case Owner Jacob Reidt
Business Case Sponsor Andy Vickers
Sponsor Organ ization/Department
Category Project
Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
The Post Falls HED Redevelopment program is monitored by a steering committee
consisting of the Director of Environmental Affairs, the Director of Generation
Production and Substation Support, the Director of Power Supply, and the Director
Electrica! Engineering, with sponsorship from the Vice President of Energy
Resources. This group is provided quarterly updates on project cost and schedule
status. This group is also included in decisions on significant changes in scope.
The program is actively overseen by a stakeholder group that consists of
representatives from Power Supply, Asset Management, Licensing and
Environmental, and Generation & Production. This group meets at least monthly to
receive progress reports, cost and schedule updates, and is presented with project
risks and proposed mitigations to those risks. This group is also consulted on
decisions of significant and modest changes in scope.
The plant redevelopment project is led by a Project Manager. The Project Manager
(PM) has a team of subject matter experts (SME) in a variety of areas to help them
execute the project plan. Under the management of the PM and SME's, weekly and
daily decisions are made to determine the most prudent course of action and to
actively monitor progress of the project.
The substation project will be led by an engineer, with oversight by the Engineering
Roundtable who meets Monthly. The engineer will coordinate the daily and weekly
decisions, implement Substation, Distribution, and Transmission standards as
necessary, and coordinate with the plant PM for plant integration.
The Enterprise Technology or Communications project will be led by an Enterprise
Technology (ET) Project Manager. The Project Manager (PM) will lead a team of
Network Engineers that will design a solution to accommodate network
requirements set forth by the lntegration and Protection plans and provide network
connectivity through all phases of construction. The network solution wil! be
approved by the ET Steering Committee consisting of the Director of lT and
Security, Sr Manager of Network Engineering and Manager of lT Operations.
o
Business Case Justification Narrative
o
Exhibit No. 6 page 1 of 9
Case No. AVU-E- I 9-04
J. Thackston, Avista
Schedule l, Page 42 of 120
Generation Production and Substation Support
Posf Falls HED Redevelopment Program
o
o
2 BUSINESS PROBLEM
The Post Falls HED started operation in 1906 and has been operating continually
since that time. The generators, turbines, and governors (turbine speed controller)
are original equipment and are still in service. The brick powerhouse with riveted
steel superstructure is has not changed since the plant was constructed. Over
time, it has been re-roofed and the intake area has had some major work
performed, but the appearance of the project remains largely the same as when it
started operation more than 110 years ago.
Photo showing interior of present Powerhouse
While the plant is still producing, the generating equipment, protective relaying, unit
controls, and many other components of the operating equipment are mechanically
and functionally failing. The turbines are estimated to be 50% efficient contrasted to
modern turbines which can exceed 90% efficient. The existing governors have had
patchwork repairs due to lack of replacement parts and while they do allow for unit
control, they are ineffective in their response to system disturbances. Generator
voltage controllers, protective relays, and unit monitoring systems all have a similar
condition of marginal functionality.
The units are exhibiting signs of failure. Attached are recent reports for Unit 1, Unit
4 and Unit 6 that describe some of the problems encountered during the last
maintenance on Unit 1, and the current operational directive to de-rate Unit 4 and
Unit 6 due to their mechanical condition.
Because of the age of the plant, it presents some safety issues that have evolved
over time. The access port for crews to access and maintain the turbine runners is
too small to allow for any type of backboard or stretcher to exit the turbine area in
the event a worker would be injured. The castings used to create the turbine watero
Business Case Justification Nanative Page 2 of 9Exhibit No. 6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule l,Page 43 of 120
I trtI
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Post Falls HED Redevelopment Program
case do not allow the opening to be increased without risk of permanently damaging
the water case and leaking. For this reason, crews can no longer access the
turbines to maintain the runners. This has been the case for nearly a decade.
Photo showing safety issue due to restricted access to turbine area.
The opening will not allow a backboard or stretcher to the area for emergency
evacuation.
Additionally, control modifications done in the late 1940's place the primary
generator breakers inside the contro! room. This presents and unacceptable arc
flash hazard to operating and maintenance personnel. While either the operation
desk or the switchgear can be relocated to address this issue, this work would cost
several million dollars and would not address some of the other issues associated
with the plant.
Photo showing proximity of switchgear to Operators Station
(Operator Chair is indicated by arrow)
Finally, the Post Falls project has a number of critical operational requirements that
support key recreationalfacilities, fishery, and other FERC license requirements.
Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 44 of 120
o
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Business Case Justification Narrative Page 3 of 9
7
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The Post Falls dam must provide minimum flows during summer months to support
fishery habitat downstream. lt is also subject to restrictions on how fast the flows
through the project can change in order to meet downstream flow requirements.
The present plant controls marginally provide the precision needed for this control.
To address water quality issues during high river flow seasons, unit and spillway
controls must follow certain procedures to minimize Total Dissolved Gas creation in
the river system. ln addition, flows through the project provide water at the
recreational site known as Trailer Park Wave. Upstream of the dam is the Spokane
River and Lake Coeur d'Alene which are significant regional recreational resources
that rely on the water control at Post Falls to maintain the water levels during the
summer months.
Finally, there is a City Park and boat launch that is integralwith the immediate
upstream reservoir. Safety requirements have been implemented that require all
spillgates at the project be closed before boaters are allowed to use the boat launch
and recreate in the reservoir immediately upstream. Flows that would normally go
through the plant need to be passed through the spillgates instead because of the
unreliability of the generating units, extended maintenance outages, unit de-rates,
and forced outages. This requires the boat launch opening to be delayed or in some
cases closed on an emergency basis until flows subside or the generating unit can
be returned to service.
Post Falls Substation is a wood station and is in poor condition due to proximity to
the river. Two of the three breakers at the station are Westinghouse GMSA, 1957
vintage, some of the oldest in the system and a type of vintage that we have been
anxious to replace across the system. One failed in 1993 and was replaced with an
SFG breaker. The Voltage Regulators are over 40 years old and the distribution
reclosers are oil filled, both of which are driving factors for redevelopment of the
substation within the near future. Work has not been done on the station historically
due to difficulty of obtaining outages, which could be mitigated by working in
conjunction with a plant rebuild.
o
Business Case Justification Narrative Exhibit No. 6 Page 4 of 9
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule I , Page 45 of 1 20
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Post Falls HED Redevelopment Program
Aftachments
1. Plant Operating Record and Restrictions
2. FERC License Conditions
3. Post Falls Assessment Study
4. Post Falls Feasibility Workshop Report
5. Post Falls Final Presentation
6. Post Falls Redevelopment Approval Summary
7. Post Falls Substation Asset Condition - (New)
8. Post Falls Redevelopment Substation Project Request - (New)
3 PROPOSAL AND RECOMMENDED SOLUTION
The estimates in the above table for capital costs should be construed to be +/- 307o for each of the options.
ln an effort to determine a prudent course of action to address the Post Falls project,
a significant Assessment Study was performed. This assessment considered a
number of different options that might address the issues described above. The
report of this assessment is attached to this document. This assessment concluded
that the most prudent course of action was to redevelop the site by keeping the
existing powerhouse and location.
Subsequently, a Feasibility Study was undertaken to evaluate dffierent alternatives
that could be done to redevelop the existing powerhouse. These include
replacement of the present units with some new parts and pieces and modernizing
the plant to the extent possible. lt also considered a full redevelopment which would
effectively remove all of the existing equipment and replace it with new and still
retaining the existing powerhouse structure. This Feasibility Study recommended
that the project be redeveloped by shutting down the plant, removing the old
equipment, and replacing it with new. This report on the Feasibility Workshop is
attached to this document.
o
o
o
Option - Plant CapitalCost Start Gomplete
Remove the existing six generating units and
equipment and replace them with new units, control
and monitoring equipment, and balance of plant
equipment. This is to be done within the present
building structure, and includes plant specific lT
project costs.
S zs.g NI 12 2017 6 2023
Perform minimum life extension activities, and begin
unit overhauls and upgrades as units fail over the
next decade +
s 98.5 M 12 2018 TBD
Business Case Justification Narative Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l,Page 46 of 120
Page 5 of 9
Post Falls HED Redevelopment Program
o
o
o
Finally, a team of Avista made up of personnel from the GPSS department,
Licensing and Environmental, Power Supply, Asset Management, and
Procurement convened a series of meetings to analyze the results of the Feasibility
Study recommendation and explore its conclusions and assess how the
recommended solution addressed the issues such as equipment reliability,
personnel safety, and risks associated with potential disruption of fishery and
recreational needs. Significant financial analysis was performed by the Power
Supply group in support of this effort to ascertain the most attractive alternative that
addressed the issues. This analysis was summarized and presented to the steering
committee identified above in April of 2016. That presentation is attached to this
document.
The final conclusion of all of this effort recommended that a full replacement of the
existing units and other powerhouse equipment be replaced in their entirety with
new equipment. lt was estimated that the project would cost $58,100,000 (+/- 30%),
not including AFUDC, management, or substation costs. lt was also demonstrated
that due to a shorter construction period, it is more beneficialto shut down the plant
during this reconstruction. lt was estimated the entire project would take five years
once it was initiated. This decision was recorded in a summary message to a group
of stakeholders and is attached to this document.
This work will replace the existing six 110 year old generating units with six new
variable blade turbine generator units. Work will also include needed ancillary
replacements and powerhouse remediation to attain a 50 year life project. ln
addition, the efficiency of the new generating equipment will result in an
improvement in output capacity and energy. This project will result in an estimated
40% increase in capacity and 15% increase in energy and reduce future major
maintenance costs.
To support the above executed work, substantial modifications to the substation are
required specifically relocation of the GSU, and integration of new protection at a
minimum.
The estimates in the above table for capital costs should be construed to be +/- 30% for each of the options,
Option - Substation GapitalCost Start Complete
Relocate and construct a new substation on the
island prior to construction work on the powerhouse.
This includes substation specific lT project costs.
s10.6 M 1 2019 1 2021
Relocate Plant GSU, and integrate into existing
substation, with full substation rebuild within in the
next 10 years.
s2.sM+$10.6M 1 2019 1 2031
Rebuild substation in place. This includes substation
specific lT project costs.
S11.7s M 1 2019 I 2021
Relocate and construct a new substation off the
island prior to construction work on the powerhouse.
This includes substation specific lT project costs.
S13 M 1 2019 I 2023
Business Case Justification Narrative Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l,Page 47 of 120
Page 6 of 9
Posf Falls HED Redevelopment Program
o
At the request of Generation Production and Substation Support, the Engineering
Roundtable (ERT) formed a sub-team to evaluate the current condition of the
Substation, develop options, and propose a solution. Attached is a Post Falls
Substation Asset Condition report demonstrating several key asset condition issues
with the substation. The substation team developed and evaluated four options,
identified potentia! risks, and developed Rough Order of Magnitude Costs for each.
Relocating the Substation off the island and rebuilding the substation in place were
eliminated due to the risks of schedule delays for permitting, working around
energized lines, and high probable costs were not offset by value.
The minimum viable option of relocating the GSU, and performing minimum
upgrades would cost approximately $2.5 Million, with an expected additional spend
of $10 Million in the near future. By coordinating a relocation of the substation with
the plant redevelopment, the ERT and GPSS identified substantial risk reduction by
minimizing exposure to high voltage lines during construction.
The sub team recommended, and the ERT approved, the further development of
relocating and rebuilding the substation on the island due to considerations of asset
condition issues, risks to the plant construction project, and best use of budget and
resources based on a long-term view. This would require the use of contract
resources (Commonwealth for design, contractor for construction) to minimize
impact to existing ERT plan.o
Business Case Justification Narrative
o
Exhibit No. 6 Page 7 of 9
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1 , Page 48 of I 20
Posf Falls HED Redevelopment Program
o
o
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Post Falls HED
Redevelopment Business Case and agree with the approach it presents and that it
has been approved by the steering committee or other governance body identified
in Section 1.1. The undersigned also acknowledge that significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
'qf*r
Project Delivery
Business Case Owner
Vickers
Director of GPSS
Business Case Sponsor
Steering Committee Review
ruce Howard
Senior Director of Environrnental Affairs
Steering Committee Review
Scott Kinney
Director of Power Supply
Steering Committee Review
'l ,fru/
Josh DiLuciano
Director of Electrical Engineering
Steering Committee Review
Date: ?gtu l tt
Date:
il'tIt{
Signature:
Print Name
Title:
Role:
Signature:
Print Name:
Title:
Role:
Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
Date:
Date:
Date:Ur/r Y
o
Business Case Justification Nanative Exhibit No. 6 Page 8 of 9
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule l,Page 49 of 120
&*1^:*-
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Posf Falls HED Rede
5 VERSION HISTORY o
Tem plate Version: 0212412017
o
o
Version lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Steve Wenke 0411912017 Jacob Reidt 04t19t2017 lnitialversion
2.0 Nathan Fletcher 07t1112018 Jacob Reidt 07t11t2018 Update for Material
Change during 5 Year
Budqet Cvcle
Business Case Justification Narrative Page 9 of 9Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule I, Page 50 of 120
o
Cabinet Gan Crane cement
1 GENERAL INFORMATION
1.1 Steering Committee or Advisory Group lnformation
Steering Committee members are comprised of: Director - GPSS, Manager,
Hydro Operations & Maintenance and Manager - Project Delivery. Steering
Committee members are provided a monthly project status report but, meet only in
the event a decision point is needed.
Other key stakeholders include: Manager, Clark Fork River Hydro; Manager,
Mechanica! Engineering. Additional Cabinet Gorge Hydro Electrical Development
mechanical staff that more directly represent the interests of the plant itself are
consulted regularly.
2 BUSINESS PROBLEM
The gantry crane at Cabinet Gorge Hydro Electrical Development was used in the
originalconstruction of the plant in 1952-53. The crane is rated at275 tons but can
perform lifts as heavy as 330 tons on an occasional basis given that a certified test
has been performed. As the asset has aged, various upgrades and updates have
been made to prolong the crane's usefulness. However, it has become apparent
that the crane is unable to perform the duties required of it in a dependable
manner.
The gantry crane is of the only means of moving the large machinery found at
Cabinet Gorge Hydro Electric Development such as moving/placing transformers,
tailgates and generators. lt is also the only way other equipment can be moved
into and out of the plant. lts inability to function reliably impacts the work that is
able to be performed at the plant and presents a safety risk to personne! if the
crane fails to controlthe load. There is also a risk of not being able to accomplish
repairs in the event of an emergency related to any one of the four generating
units. !n essence, the gantry crane is a bottle neck preventing both annual
maintenance work and capital improvements alike.
The crane has a long history of breakdowns and operational problems. Most
recently, during the Cabinet Gorge Unit #1 rehabilitation project spanning from
2014 to 2016, problems with the crane caused significant delays. Some examples
include:
Relay/Contactor control problem - approx. 6 days
Business Case Justification Narrative Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 5l of 120
Page 1 ofB
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Requested Spend Amount $3,530,000
Req uestin g Organ izationlDepartment Generation Production and Substation Support
Business Gase Owner Jacob Reidt
Business Case Sponsors Andy Vickers
Sponsor Organ ization/Department Generation Production and Substation Support
Category Project
lnvestment Driver Asset Condition
Gear/bearing problem - approx. 3 weeks
Brake problem - approx. 2 days
Additional problems experienced with the crane during the Unit #1 rehabilitation
are documented in a memo by Ryan Bean, dated November 13,2015, attached as
Appendix A below.
lnspections performed by Professiona! Crane lnspections in the years 2010,2012,
2015 and 2016 each give the crane an overall condition level 3 indicating that
"Minor to moderate performance issues exist. PCI recommends repair or
adjustment as soon as practical.' Copies of these inspection reports can be made
available upon request. A summarized list of foreman reports dating back to 1966
can be found in Appendix B below.
The successful outcome of this project would be to deliver a state-of-the-art crane
capable of safely and reliably providing rated lifting capabilities for the likes of draft
tube bulkheads, Generation Step-Up transformers and any one of the four
generators.
A properly functioning crane at Cabinet Gorge Hydro Electric Development
enables Avista to tend to the aging assets and maintenance needs of plant
machinery to ensure that they run safely and reliably.
Customers benefit in the ability to adequately and safely maintain this equipment
to continue to provide low cost and reliable energy.
3 PROPOSAL AND RECOMMENDED SOLUTION
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Optlon Estlmated
Capltal Cost
Stad Complete
Do nothing $o
Alternative 1: Full Replacement $5,308,449 03t2017 12t2018
Alternative 2: Replacement w/extended
reach
$7,272,000 03t2017 1212018
Alternative 3: Refurbishment $3,894,173 03t2017 12t2018
Cabinet Gorge Gantry Crane Replacement
Do Nothinq: doing nothing is an option however, given the criticality of this asset,
doing nothing would leave the plant at risk should an emergency arise
necessitating the crane's use
Alternative #1: Full Replacement. Advantages of this option include new structure
designed and rated for 330T from conception, modernized controls utilizing current
technology, reduced maintenance costs, elimination of as-building the existing
crane structure, full archived drawing and product data set and removal of any
lead-based paint and asbestos contamination risks.
Alternative #2: Replacement MExtended Reach. This alternative expands on
alternative #1 by utilizing extended reach to enable reach to the transformers and
leg pass-through design enabling access to the draft tube bulkheads.
Replacement with extended reach represents a modest increase (comparatively)
Business Case Justification Nanative
case No. ^t#,itili}:;l
Pase 2 of 8
J. Thackston, Avista
Schedule l, Page 52 of 120
Cabinet Gorge Gantry Crane Replacement
o in price but will provide savings in terms of usability for the foreseeable future in
terms of lifting capability. The estimated capital cost of $7,272,000 represents a
very high level estimate at this point.
Alternative #3: Refurbishment. Advantages of refurbishment included lower up-
front costs resulting from retaining the majority of the steel structure and a reduced
level of demolition and installation work. However, this alternative would require
lead-based paint and asbestos abatement and without X-ray examination of each
rivet, it would be impossible to accurately and definitively assess the true condition
of the structure.
A final decision has yet been made with regard to selection of Alternatives 1,2, or
3. However, with any option we anticipate construction willtake upwards of four
months, following dismantling of the existing crane. Due to weather conditions
inherent in north ldaho, it would be optimal to construct the new crane during the
months of June to September. Given the long lead time expected in the
manufacturing of a new crane (upwards of twelve months), we anticipate that all
construction will be completed and the project placed in service no later than
December 31,2018.
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Business Case Justification Narrative o.
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 53 of 120
Page 3 of I
Cabinet Gorge Crane Replacement
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Cabinet Gorge Gantry Crane
Replacement Business Case and agree with the approach it presents and that it has
been approved by the steering commiftee or other governance body identified in
Section 1.1. The undersigned also acknowledge that significant changes to this will
be coordinated with and approved by the undersigned or their designated
representatives.
o
Signature:
Print Name:
Title:
Role:
Signature:
Print Name:
Title:
Role:
Business Case Owner
Date: bl|ty17
Date:
MeB & pfl\
e/ert
[);recbr GP s9
Business Case Sponsor
VERSION HISTORY
Template Version : O3lO7 f20'17
CaseNo.OUr-"-rrfffi
J. Thackston, Avista
Schedule l, Page 54 of 120
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Verclon lmplemented
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Revlslon
Date
Apprcved
By
Approval
Date
Reason
1.0 Terri Echegoyen 4t14t2017 Steve Wenke 411412017 lnitial version
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Cabinet Gorge Gan Crane Replacement
APPENDIX A
DATE: NOVEMBER 13TH, 2015
TO: FILE, JACOB REIDT, RANDY PEIRCE, BOB WEISBECK, MIKE SHOFF
FROM: RYAN BEAN
SUBJECT: CABINET GORGE UNIT 1 . GANTRY CRANE ROTOR PICK
PROBLEIVIS
Backqround
The scope of work during the Unit I rehabilitation included two picks of the generator rotor
complete with field poles installed. The first pick removed the rotor from the stator and placed it
in the shop for field pole removal. The rotor was then moved to the rotor storage building until
the field poles were returned after being refurbished by RPR Hydro (subcontractor to GE). The
field poles were reinstalled in the rotor storage building and the rotor was then placed back in the
stator.
An Engineered Pick Plan was produced in accordance with ASME Code Section 830.2-3.1 .7 that
allows for occasional picks for loads exceeding rated limits up to l25Yo of the nameplate rating.
The crane nameplate is275 tons with an occasional pick of up to 343.8 tons. The rotor with lifting
device weighs approx 330 tons. The cranes ability to lift this load was confirmed by Bedford
Crane during the initial installation. The code allows an occasional pick not to exceed two
occunences in a 12 month period provided the crane manufacturer or other qualified person has
reviewed the crane design to handle the load.
Inconsistencies During Oneration
During the initial removal of the rotor from the stator, the micro drive and main hoist motor were
used. The micro drive operated as expected, however the main hoist motor appeared to struggle
when initially engaged. While retuming the rotor to the stator on September 22'd,z}l1,an issue
was experienced where the main hoist did not operate as expected during raising. This was a
repeatability issue with the main hoist where the hoist may raise, stall, or lower the rotor when the
control lever was taken back into the same notch repeatedly. The lift was stopped and an
investi gation followed.
Investisation and Troubleshooting
With assistance from PCI and K&N Electric, an investigation and houbleshooting of the power
and control systems followed. Components checked included the control lever, overloads,
contactors, resistors, motor currents, brakes, and micro-drive operation. Everything appeared to
be operating correctly, albeit in an overloaded condition due to the above nameplate load. The
micro-drive operated reliably throughout testing. This lead us to believe the problem resides
downstream of the control system, potentially with either the motor output or mechanical drive
system. The gear train was visually inspected via available access ports and appeared to be in
good shape and operated smoothly.
Original records of the hoist motor test data indicate the existing hoist motor reaches its nameplate
current of 160 amps at a load of approximately 205 tons. This limits the service cycle at 240 amps
with a load of approx. 320 amps to approximately one to two minutes without overheating resistor
banks. This would require several lifting and cooling off periods to complete the lift. This reflects
Business case Justification Narrative Exhibit No' 6 Page 5 of 8
Case No. AVU-E- l9-04
J. Thackston, Avista
Schedule l, Page 55 of 120
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Cabinet Gorge Crane Replacement
what we experienced in the field with tripping of the overload relays during sustained lifting at
approx. 250 amps.
The crane micro-drive arrangement was also inspected, which consists of an additional motor and
speed reducer that can be clutched in or out as necessary. 'the arrangement utilizes the same main
hoist drivetrain and brakes (with an additional motor brake) without using the main hoist motor.
Per Mark Oney's crane evaluation dated May 10, 1994 and design drawings, the micro-drive is
rated for continuous duty without overheating. Hoisting speed is reduced during operation to
slightly less than 0.5 feet per minute.
Conclusion
This has historically been a difficult pick for this crane and the system appears to have reached an
impasse where the main hoist is no longer capable of producing the power to function at l00Yo.
We suspect the issue lies in either the motor output, which has been operatcd above its nameplate
current a number of times in the past, or due to an increase in mechanical drag in the gear train.
Per the results of our initial investigation and a stakeholder meeting on October 5th, 2015, (Ryan
Bean, Andy Vickers, Mike Gonnella, Bob Weisbeck, Brand McNamara, Rob Selby, and Jeremy
Winkle in attendance) and in agreement with the project Foreman Mike Shofll the rotor pick was
completed using the installed micro-drive system, without the use of the main hoist motor.
References
1. CG 1 Rotor Pick Plan Oct 2015 Revl
2. ASME Crane code for CG1
3. Crane Report by Mark Oney, May 10 9944. D-15701s00Lc1952 - Gantry Clearance Diagram with notes
5. 304E-25-040-01-01, 02, 03,04, 05, 08 - Micro Drive Arrangement Drawings
6. 1952 Load Test Data
7. 1993 Load Test Data
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Business Case Juslification Narrative Page 6 of IExhibit No. 6
Case No. AVU-E- l 9-04
J. Thackston, Avista
Schedule 1, Page 56 of 120
Cabinet Crane
o APPENDIX B: SUMMARIZED FOREMAN REPORTS
o
Job Title Begin
date End date Description
Gantry Crane -
Mechanical
Maintenance
5t23t1966 7t1t1966
Replaced sheaves and greased bearings
on large hook. Applied oilto bearings on
trolley. Drained and cleaned gear cases.
Checked brakes.
Repair Gantry Crane 3/31/1969 4t9t1969
Large bevel gear was removed. New
bushing was installed and the drive
reassembled. Wheel guards were
repaired and installed.
Re-reeve Gantry
Crane Main Hook -
Cabinet Gorge
Station
12t2t1976 12t14t1976 Old cable was removed and new cable
added to the drums.
Crane Maintenance 11t14t1988 11t14t1988 Main hoist gear box inspected. Friction
brake assembly was seized together.
Redo Crane Track
Splices 4t511993 5/1 3/1 993 Weld holding rails together were
repaired.
Gantry Crane -
Bridge Drive Motor 1t23t1997 2t11t1997
The bridge drive motor on the Gantry
Crane was removed and sent in for
repair. Report includes repair details.
Crane Maintenance 6/28/1 999 7t2911999
The bridge motor, brake and gearbox
were inspected. Trolley motor removed
and sent to K&N for maintenance.
Annual Safety
lnspection for Gantry
Crane
7t12t2000 7t12t2000 Mechanical and Electrical inspection of
crane components.
Crane Maintenance 5t1t2000 7t13t2000
Crane was pressure washed. Full
structural inspection completed. Rusting
areas noted. The main and auxiliary
hoists were load tested.
Gantry Crane
Maintenance "03"6t16t2003 8t26t2003
Replaced all races and several bearings,
and repaired sheaves of the main hoist
block. Replumbed bridge brake system
and repairecUreplaced several brake
components. Maintained the trolley
controller (electricians), main and
auxiliary hoist cables, and openo
Business Case Justification Narrative Page 7 of 8Exhibit No. 6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule l,Page 57 of 120
Cabinet Gorge Gantry Crane Replacement
Job Title Begin
date End date Description
275Ton Gantry
Crane Load Test 6i5t2006 6t8t2006
Components of the main hoist had been
modified necessitating a load test
(Report from load test on the 275 ton
gantry cane).
Crane Maintenance
2010 9t15t2010 9t15t2010 Abbreviated maintenance on the gantry
crane. See report for details.
Gantry Crane Oil
Analysis 4t19t2011 4119t2011 OilAnalysis results for Gantry Crane
components.
Gantry Crane
Maintenance 2O11 4t11t2011 4t20t2011
Report includes details on maintenance
of the gantry crane, checklist included.
Report state the crane in in dire need of
a paint iob.
Annual Maintenance
Gantry Crane 41912012 513t2012 Crane condition regarding many items is
not satisfactory, see report for details
detailed Foreman reports can be found here > c01m1 l4lGtlForemanrepofis.accdb
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Business Case Justifi cation Narative Page 8 of IExhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 58 of I 20
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A utom atio n Rep I ace ment
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1 GENERAL INFORMATION
Requested Spend Amount $650,000.00
Req uesting Organ izationlDepartment Generation Production and Substation Support
Business Case Owner Kristina Newhouse
Business Gase Sponsor Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Category Program
Driver Customer Service Quality & Reliability
1.1 Steering Committee or Advisory Group lnformation
The controls engineering team identified the need to address the risk of aging and
failing control equipment. The Distributed Control Systems (DCS) and
Programmable Logic Controllers (PLC) are aging and are introducing an increase in
hardware and software failures. Discussions with the Director of GPSS, the Manager
of Operations Analytics, the Electrical Engineering Manager, and the Protection
Control Meter Technician Foreman concluded that a planned replacement program
was needed.
The controls engineering manager will provide ongoing oversight and monthly
tracking of the ongoing work within the program. The advisory group for ongoing
vetting includes the Director of GPSS, the Controls Engineering Manager, the
Protection Control Meter Technician Foreman, the Manager of Hydro Operations
and Maintenan@, and the Manager of Thermal Operations and Maintenance.
2 BUSINESS PROBLEM
The major driver for the Automation Replacement business case is Reliability. This
program aligns with Avista's Safe & Reliable lnfrastructure strategy. Upgrading our
control systems within our generating facilities allows us to provide reliable energy.
The Distributed Controls Systems (DCS) and Prograrnmable Logic Controllers
(PLC) are used to control and monitor Avista's generating units as well as each
generating facility. For many facilities the operation of the generating units is
performed remotely with the use of the DCSs and the PLCs. These aging devices
use unsupported operating systems and modules that are no longer available.
Failing software and hardware introduces risk and limits Avista's ability to operate
generating facilities reliably.
The DCS and PLC work is needed now to reduce the higher risk of failure due to the
aging equipment. The DCSs are no longer supported and spare modules are limited.
The modules in service have a high risk of failure as they are over 20 years old. The
computer drivers that are needed to communicate to the DCSs will not fit in new
computers with Windows 10 operating systems. This creates a Cyber Security issue.
Exhibit No. 6
case No. AVU-E- 19-04 Page 1 0f 3
J. Thackston, Avista
Schedule l, Page 59 of 120
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Business Case Justification Narrative
Auto matio n Re p I ace ment
The software needed to view and modify the logic programs only runs on Windows
95. Avista has a very limited supply of Windows 95 laptops and they also continue
to fail.
Replacing aging DCSs and PLCs will reduce unexpected plant outages that require
emergency repair with like equipment. A planned approach will allow engineers and
technicians to update logic programs more effectively and replace hardware with
current standards.
3 PROPOSAL AND RECOMMENDED SOLUTION
Option 1 is to replace all aging DCSs and PLCs proactively on a schedule that takes
into account resources and outage availability. This option addresses aging
hardware and software concerns as well as the cyber security vulnerabilities.
Additional resources are required in order to maintain a schedule and consistently
meet the objectives. Engineering will require a designer to develop new logic
programs and designs for installations. The Protection Control Meter Shop will need
a resource to installand commission the PLC programs.
Option 2 is to maintain exlsting Bailey DCSs and Modicon PLCs as we currently do
today. This includes replacing modules as they fail with old spare parts or refurbish
third party parts. Maintaining spare parts allows us to continue using existing
infrastructure and logic programs but it does not resolve the long term issue which
is aging equipment that will eventually no longer be available. The risk of outages at
undesirable times to replace failed parts becomes more likely the longer the aging
hardware is in service. This alternative also does not resolve the issue with
computers that have unsupported operating systems and are considered a cyber-
security risk.
Option 3 is to upgrade software on the DCSs and PLCs. This would include replacing
each system's software that runs on Windows 95 and Windows XP with a separate
software for each platform that runs on Windows 7. This will mitigate the software
and cyber security issue but not the aging hardware issue. Outages would be
required and the new logic programs would need to be rewritten and fully
commissioned. Upgrading the Bailey software and the Modicon software do not align
with our standard PLC platform that our engineers and technicians are trained on.
This would introduce two new software applications. Efficiency to troubleshoot and
resolve issues in a timely manner could be impacted.
Option 1 is the proposed option because it addresses the issues with aging hardware
and software and it resolves the cyber security vulnerabilities. This option addresses
the identified issues in a more controlled and planned manner where designs can
be wellthought out and plant outages for construction can be scheduled and ideally
Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule I , Page 60 of 1 20
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Optlon CapitalCost Start Complete
Option 1 - Upgrade DCS and PLCs 1t2017 1212025
Option 2 - Spare Parts Refurbishment / Do nothing $1 00k/year 1t2017 NA
Option 3 - Software Upgrade $2.5M 1t2017 '1212025
Business Case Justification Narrative Page 2 of 3
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$6.5M
Autom atio n Repl acement
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limited. The requested spend amount is based on Option 1 and takes into account
resources needed to perform designs and installations. ls also takes into
consideration feasibility of plant outages as projects are spread out over time.
See attached timeline titled Irmeline Estimate - Automation Replacement Busrness
Case.pdf
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Automation Replacement
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name:
Title:
Role:
Date:
Date
Template Version: AAOT PO17
&ififutt fuiinry'$ hr e,.Business Case Owner
ndre- h'cke, s
l) ire c'fdr G P 93
Business Case Sponsor
5 VERSION HISTORY
Verslon lmplemented
By
Revlslon
Date
Approved
By
Approval
Date
Reason
1.0 Kristina Newhouse 04t05t2017 Andy Vickers 04t11t2017 lnitial version
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Business Case Justification Narrative Page 3 of 3Exhibit No. 6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule I, Page 6l of 120
{nlwn
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Cabinet Gorge Station Selvice
1 GENERAL INFORMATION
Requested Spend Amount $4,275,000
Requesting Organ ization/Department Generation Production and Substation Support
Business Case Owner Jacob Reidt
Business Gase Sponsors Andy Vickers
Sponsor Org an ization/Department Generation Production and Substation Support
Category Project
lnvestment Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
The advisory group for this project consists of members from the Generation
Production and Substation support department including: Director - GPSS,
Manager Hydro Operations & Maintenance and Manager Electrical Engineering.
Steering committee members receive monthly project status update reports but are
convened only in the event of a decision point.
The projecUstakeholder team meets on a more regular basis (at least monthly) to
work on the project's scope and planning. The projecUstakeholder team is
comprised of representatives from the various engineering groups (electrical,
controls, mechanical) and operations.
2 BUSINESS PROBLEM
All generation facilities require Station Service to provide electric power to the plant.
Station Service components include Transformers, Power Centers, Motor Control
Centers, Load Centers, Emergency Load Centers and various breakers. Station
Service is an elaborate system with multiple built-in redundancies designed to
protect the plant's electrical operation.
The Cabinet Gorge Station Service equipment is originalfrom 1951. The station
service is a typical redundant Main-Tie-Main Service with some components added
over time to accommodate changes to the Units and Balance of Plant needs. The
Main-Tie-Main has multiple power sources which provides various switching
alternative to bypass systems so that power is never lost. Station Service
transformers no longer have the capacity to provide the needed load and could be
subject to overload. The current Motor Control Centers (MCC) Iack monitoring and
indication. Replacement of these MCCs would create operational efficiencies by
providing visibility into how station service is pefforming. The cables require
evaluation due to age of insulation and the wet conditions they have been subject to
over the years. The weight due to the number of cables in the tray cause concern
for potentialfailure (see photo below). Due to control and other additions that have
occurred over time, the existing 26 year old Emergency Generator no longer meets
the load critical requirements for the plant. The only components of Station Service
E hibit No. 6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 62 of 120
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Business Case Justification Narrative Page 1 of5
Cabinet Gorge Station Seryice
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that have been recently replaced are the lntake Motor Control Center in 2010 and
the single high voltage circuit breaker serving the plant in 2015.
lf no action is taken, there is a risk of individual component failure that could force
load shedding under certain operational scenarios. Should a catastrophic failure
occur with switchgear and/or power cables, it could result in generator unit andlor
plant wide forced outages potentially lasting as long as eight months. This is due to
the long manufacturing lead time for some types of specialized equipment.
3 PROPOSAL AND RECOMMENDED SOLUTION
Do Nothing: doing nothing is an option. However, if components do fail, due their
age, replacements are not available. Addressing such failures in an emergency/ad
hoc situation would increase the cost and extend the outage time. This option does
not provide any capacity for future loads.
Alternative #1 would replace the following components:
o Station Service Transformers 1 & 2
o Power Center A & B.
o Load Center 1,2 & 4 would be replaced with Motor Control Centers with
provisions for future capacity.
o Power cables
o Emergency Generator and controls to accommodate additional emergency
load.
. Address arc flash rating and improve load flow analysis and coordination.
o Add metering to each Station Service Power Center and Emergency
Generator.
Alternative #2: Add a second emergency generator with appropriate
transformation to add capacity in the event of a failed Station Service transformer.
This alternative would require the addition of another Power Center that when tied
in with the others would significantly increase the complexity of the system. The
additional environmental risk in the form of containment and risk of release of the
Emergency Generator fuel would need to be addressed. This alternative does not
address the risks associated with the overloaded cable trays and Motor Control
Centers. When the costs of procuring a new generator, power center and
associated cables are factored in, alternative#2 exceeds the cost of alternative #1
by $490k.
Business Case Justification Narrative Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1 , Page 63 of 1 20
Page 2 of 5
Optlon Gapltal Cost Start Complete
Do nothing $o
Alternative #1 - Replace identified
components
$4,275,000 0212017 02t2020
Alternate #2 - New external source $4,765,381 02t2017 02t2020
Cabinet Gorge Station Senrice
o
The recommended approach is alternative#1. This project aligns with both Avista's
Safe and Reliable lnfrastructure goalthrough investment to achieve optimum life-
cycle performance and operational safety and Reliable Resources goal to control a
portfolio of resources that responsibly meet our long term energy needs.
Additionally, alternative #1 provides an avenue for prudent procurement of capital
components by engaging in the competitive bid process.
This project impacts our external customers by ensuring they have predictable,
affordable power. When units go offline unscheduled, we are forced to purchase
power on the open market and/or produce power with our less cost effective
generating facilities. These alternatives come at the risk of higher and/or
unpredictable power costs per MWH for both our customers and shareholders.
Finally, unscheduled outages force hydro plants to spillwater which represents a
FERC license violation.
Overloaded Cable Trays
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J. Thackston, Avista
Schedule I , Page 64 of 120
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Cabinet Gorge Station Seryfce
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Cabinet Gorge Station
Service Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
o
Signature:
Print Name:
Title:
Role:
Date: Al
Contract & Project Mgmt
Business Case Owner
Signature:
Print Name:
Title:
Role:
Date
Andy Vickers
Director, GPSS
Business Case Sponsor
o5 VERSION HISTORY
Template Version: 03107 12017
O
EihibiaNor
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 66 of 120
Verslon lmplemented
By
Revblon
Date
Approved
By
Apprcval
Date
Reason
1.0 Terri Echegoyen 4l't4t17 Steve Wenke 4t14117 lnitialversion
Business Case Justification Narrative Page 5 of 5
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Cabinet Gorge - Replace Headgafes
o
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1 GENERAL INFORMATION
Requested Spend Amount $4,400,000
Requesting Orga n izationlDepartment Generation Production and Substation Support
Business Case Owner Mike Magruder
Business Case Sponsor Andy Vickers
Sponsor O rganization/Department Generation Production and Substation Support
Category Project
Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
Cabinet Gorge Operations and Engineering have evaluated the headgate issues, determined
potential solutions, confirmed prudency, and brought the solutions forward for vetting with
the Plant Manager, Manager of Hydro Operations, and Director of GPSS. This group will
follow the project to completion.
2 BUSINESS PROBLEM
The four intake headgates at Cabinet Gorge Dam are 62+ years old and are the original
headgates installed. See photos. Headgates are critical equipment required to completely
block water flow through the penstock and turbine for equipment safety (runaway unit) and
for maintenance, repair, or replacement of the generating unit assembly.
These gates were last maintained 10 years ago. Because of their curent condition the
headgates requires a complete overhaul. An overhaul includes maintaining (lubing,
bearings), repairing (re-machining), or replacing all the wheels (l4lgate), replacing wom
seals around the edges of the gates, inspecting gate rivet integrity throughout, high pressure
and manual paint scraping (lead paint abatement required), and re-coating the entire structure
and wheels for long-term water submersion.
Operations has found wheel friction increasing on most of wheels during manual
inspections. This is concerning for operation of the gate during an emergency when the
pressure on the gate (to stop river flow) is at its greatest. The existing seals no longer provide
intended functionality and are in need of complete replacement, which requires manual
preparation of the seal/gate surface interfaces.
These headgate issues need to be resolved now for the safety and reliability of plant
equipment and the safety and efficiency of craft and operations personnel required to work
behind these gates.
o
Business Case Justification Narrative Page 1 of5Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 67 of 120
Cabinet Gorge - Replace Headgafes
Photo 1
Condition of gate wheels showing corrosion and problems with bearing area.
(Note: condition has worsened in the succeeding ten years)
o
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Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1 , Page 68 of I 20
Business Case Justification Narrative Page 2 of 5
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Photo 2
Condition of Upstream side of gate showing corrosion and generally poor condition of the
gate. This illustrates the need to at a minimum sandblast to white metal and recoat.
(Note: condition has worsened in succeeding ten years)
3 PROPOSAL AND RECOMMENDED SOLUTION
The condition of the gates have reached a point where some action must occur to assure they
remain reliable for operation and safe for workers to work behind during annual maintenance
and other plant and penstock work. The Do Nothing option is no longer tenable.
Optlon Capltal Gost Malnt Cost Start Complete
Do nothing $0 $0
Replace 4 Headgates, llyear $4,400,000 $0 01t2017 10t2020
o
Business Case Justification Narrative ffi
case No. AVU-E-19-04 Page 3 0f 5
J. Thackston, Avista
Schedule l,Page 69 of 120
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Plans had been developed to replace one gate per year at an estimated cost of $1,100,000 for
each gate. Planning for this efforts is anticipated to take one year with installation of one
gate per year to follow.
New gates will include a welded design rather than the existing riveted construction.
Inspection of the integrity of welds versus rivets will be much easier and more accurate over
the long term. New wheel design will provide us with a better baseline measures for
operation and much better confidence for emergency use. New seals designed and installed
with the new gate and analyzed for a more accurate fit in the gate slot will provide assurance
for a better seal when the gates are down and employees are working in the penstock or on
a generating unit behind the gate.
The decision to replace the headgates also considered power supply and overall system
reliability. For complete overhaul.maintenance, the headgate will be completely out of the
water and above the deck for work access. The gate and corresponding unit will be out of
service for the duration of the work.
Replacing the headgates allows for less generating unit outage time. We will have the gates
manufactured offsite and delivered for installation. This allows power supply and operations
more time with unit availability as we will only need to be down long enough for removal
and installation. Engineer's estimate is a project reduction time from 16 weeks (overhaul) to
1 0 weeks (replacement).
After gaining experience with the first replacement, we may have an opportunity, depending
on river operations, power supply, and other external factors to accelerate the project and do
2 gates in one year.
The proposed solution is to retire the existing headgates and replace them over a 4 year
project timeframe as described in the preceding five paragraphs.
o
o
o
Case No. AVU-E- 19-04
J. Thackston, Avista
Schedule 1, Page 70 of 120
Cabinet Gorge -Replace Headgates
o
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Cabinet Gorge Replace
Headgates Business Case and agree with the approach it presents and that it has
been approved by the steering committee or other governance body identified in
Section 1.1. The undersigned also acknowledge that significant changes to this will
be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name:
Title:
Role:
Mil<el\,lArCP
14/*/"^0aU,tu&Z-
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Date:
Date 2-.t7
Template Version: O3lO7 12017
Case Owner
Andy Vickers
o Business Case Sponsor
5 VERSION HISTORY
Verslon lmplemented
By
Revlslon
Date
Approved
By
Approval
Date
Reason
1.0 Mike Magruder 03t14t17 Jacob Reidt 0411912017 lnitialversion
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Business Case Justification Narrative Page 5 of 5Exhibit No. 6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 7l of 120
'f f n l?-.n
Noxon Rapfds te Remediation
o1 General information
Requested Spend Amount $ 24,900,000
Requesting Organization/Department LO7IGPSS
Business Case Owner Bob Weisbeck
Business Case Sponsor Andy Vickers
Sponsor Organization/Department AO7/GPSS
Category Project
Driver Asset Condition
1.1 Steering Committee or Advisory Group Information
A project manager and a steering committee will be selected by the GPSS'
Leadership Team for this project
2 Business problem
The eight Spillgates at Noxon Rapids HED are over 60 years old and are the
original gates. The Spillgates are critical equipment which control the flow of water
over the dam during spill conditions when the water flowing in the river exceeds that
which passes through the turbines in the plant. They are also protection for the
dam during high flow periods or in the event that the plant or units trip to prevent
overtopping or flooding of the dam. The gates have been periodically maintained
but corrosion and use have caused the gates to degrade to the point where they
need to removed and completely rebuilt or replaced. Structural analysis has also
revealed that the current gates may not be designed to meet the loading
requirements during operation and due to seismic conditions. The spillgate issues
must be resolved in the near future for the safety and reliability of the plant
personnel and equipment. Fully functioning spillgates is a FERC requirement and
part of the Dam Safety program.
3 Proposal and recommended solution
Option CapitalCost Start Complete
Do nothing $0
Alternative 1: Refurbishment or replacement of the
Spillgates
$24,900,000 03/2018 12t2022
Alternative 2: Continued Repair of the gates
Do Nothing: The condition of the gates has reached a point where some action must
occur to assure they remain reliable for operation and provide a safety mechanism to
prevent flooding and overtopping of the dam. The Do Nothing option puts the plant at risk
of an uncontrolled release of water, overtopping and flooding of the dam or a FERC
Exhibit No. 6
case No. AVU-E-I9-04 Page 1 0f 3
J. Thackston, Avista
Schedule l,Page72 of 120
o
Business Case Justification Nanative
o
Noxon Rapids Spillgate Remediation
o
o
o
mandated reservoir elevation reduction. The existing gates are made of riveted steel
design which has degraded over time. The lifting mechanisms have are approaching the
end of their useful life. lncrease friction of the bearings is increasing the load on the gate
structure.
Alternative 1: The recommended alternative is to completely refurbish or replace the
spillgates. New gates will include an updated structural design including welded
construction which has proven to be superior to the riveted structural design of the 1950's.
A new wheel and seal design will provide a more accurate fit and operation of the gate.
New controls and operating mechanisms will provide more granular operation and handle
the increased frequency of gate operation due to market and power conditions. The new
gate design will reduce the amount of maintenance required and insure reliability.
Alternative 2: Components such as the wheels and seals could be replaced but would
require the gates to be removed and refurbished. The lifting mechanisms have served
their useful life and were designed for less frequent use than current demands. The
existing gates are made of riveted steel design which has degraded over time. The
structural integrity of the gates will come into question without steel replacement. The
maintenance costs will be extensive and increase over time.
4 Approval and authorization
The undersigned acknowledge they have reviewed the Noxon Rapids Spillgate
Remidiation Project and agree with the approach it presents. Significant changes to
this will be coordinated with and approved by the undersigned or their designated
representatives.,l
Date{) #)t*J y/t,f ,7Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
Signature.
Print Name
Title:
Role:
Bob Weisbeck
Business Case Owner
Date
Andy Vickers
Business Case Sponsor
Date
Steering/Advisory Com mittee Review
Business Case Justification Narrative Exhibit No. 6 Page 2 ol 3
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule I , Page 73 of 120
*b*
Noxon Rapids s te Remediation
5 version history
Template Version : O3lO7 l2O1 7
o
o
Version lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Bob Weisbeck 07t07t17 Andy
Vickers
07110117 lnitialversion
Business Case Justification Narrative
o
Exhibit No. 6
case No. AVU-E-19-04 Page 3 0f 3
J. Thackston, Avista
Schedule l,Page 74 of 120
I I
Long Lake Stability Enhancemento
o
1 GENERAL INFORMATION
Requested Spend Amount $19,200,000
Requestin g Organ ization/Department GPSS
Business Case Owner Jacob Reidt
Business Case Sponsor Andy Vickers
Sponsor Organization/Department GPSS
Category Project
Driver Mandatory & Compliance
1.1 Steering Commiftee or Advisory Group lnformation
The directors of GPSS and EnvironmentalAffairs will be the primary members of the
steering committee for the program. This project is a top priority for both groups due
to the mandatory requirement. This project has been place on GPSS 5 year priority
board with construction preliminary slotted for 2019.
2 BUSINESS PROBLEM
lnternaldam stability has been a concem around the region afterthe 2014Wanapum
Dam spillway crack incident. This business case is to address stability concerns at
the Long Lake dam.
During a recent FERC inspection, the inspector noticed a seeping joint and
requested that Avista evaluate the internal plane stability of the intake and spillway
dams. The stability analysis evaluates all conditions the dam may experience
including full pool operations, probable maximum flood (PMF), and post-earthquake
loading conditions.
The stability study revealed that Long Lake dam does not meet the minimum safety
factor during a PMF event. Avista already submitted a preliminary study to FERC
and is waiting for final design before sending FERC the full scope of the project and
timeline to address mitigation.
FERC expects Avista to develop a mitigation plan to address the stability issues and
therefore this project is mandatory. lf this project does not move through, Avista's
relationship with FERC will be heavily damaged and fines will likely result.
The initial design's executive summary is included as an attachment detailing the
exact requirements to address the stability issues.
3 PROPOSAL AND RECOMMENDED SOLUTION
o
Mitigate for PMF stability deficiency $19,200,000 111t2017 12t30t2020
Business Case Justiflcation Narrative Page 1 of 3
Exhibit No. 6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 7 5 of 120
Long Lake Stabilifrl En hancement
The study proposed some high level mitigation solutions; including adding additional
anchoring to the bedrock and concrete mass to the dam structure itself. Both of
these would stabilize the dam in a PMF event. No other solutions exist for stabilizing
the dam.
Construction wil! require barges in the forebay with cranes and drilling equipment.
Unit and spillgate outages will be required to perform the work. Coordination with
hydro operations and power supply is required.
A high level construction feasibility study was conducted at the 2Oo/o design
complete. lt was estimated that the construction could be done in one year but more
realistically should be done over two years. The construction cost of one year was
roughly $17M. This costdoes not includeAvista time ordesign cost. ltalso does
not account for the additional cost to mobilize a second year. A copy of this draft
construction report is attached.
The design is ongoing and 607o completion will be done by the end of 2017. At this
point, contracting approach will be decided and final design will continue through
2018. Construction would then be in 2019 and 2020, beginning after high flows.
The stakeholders in this project is Avista's dam safety team, hydro operations and
FERC. Alden Engineering firm is working on the design and a contractor will be
retained to perform the construction work. Constant communication with FERC will
be necessary on this project.
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Long Lake Stability
Mitigation project and agree with the approach it presents. Significant changes to
this will be coordinated with and approved by the undersigned or their designated
representatives.
o
o
Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
Reidt
Mgr Project Delivery
Date Jor 7071-Y
Date
Business Case Owner
Andy Vickers
7
Director, GPSS
Business Case Justification Nanative
Business Case Sponsor
Page 2 of 3
o
ExhibitNo.6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule l,Page76 of 120
o Long Lake Stability Enhancement
5 VERSION HISTORY
Tem plate Vercion: 03107 12017
o
o
07/07/20171.0 Brian
Vandenbure
06/22/2017 Jacob Reidt lnitial version
Business Case Justiflcation Narrative Page 3 of 3
Exhibit No. 6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule I , Page 77 of 120
Version lmplemented
Bv
Approved
BY
Approval
Date
Reason
ALDEN December 2016 o
Executive Summary
This report presents the initial design of stability measures to achieve compliance with Federal
Energy Regulatory Commission (FERC) stability criteria for Long Lake Dam. The initial design
was developed in response to recent dam safety inspections and associated recommendations.
ln addition, this report updates the stability analysis of record to account for changes in the
spillway geometry resulting from modifications to reduce totaldissolved gas (TDG) downstream
of Long Lake Dam. This report presents the loading and design parameters used in the initial
design and supporting analyses, and provides the rationale for the selected values.
The global stability of the spillway with the TDG modifications meets FERC stability criteria for
all loading conditions. The global stability analysis presented in this report yields conservative
results because the stabilizing influence of the foundation embedment, uplift reduction from the
foundation and apron drain systems, and stabilizing effects of the abutments were not
considered. The spillway and intake internal planes meet FERC stability criteria for the Normal
High Water condition. The internal plane stability analyses yield conservative results because
they do not account for the uplift reduction provided by the drain system at the upstream face.
All design and analyses documented in this report were performed assuming zero cohesion.
Stabilization measures are proposed to address rotational and sliding stability for internal planes
in the spillway and the unanchored computational "blocks"1 of the intake (Blocks 1 , 2 and 5) for
the Probable Maximum Flood (PMF) condition and Post Earthquake load conditions. The initial
design proposes the following stabilization measures:
. Twelve multi-strand post-tension anchors (2,190 kips/anchor) to stabilize the spillway
internal planes.. Five multi-strand post-tension anchors (1,600 kips/anchor) to stabilize intake Blocks 1
and 2.. Two multi-strand post-tension anchors (1,125 kips/anchor) to stabilize intake Block 5.
The initial design is subject to change.
Table ES-1 through Table ES-6 demonstrate the improvement that would be achieved by the
proposed stabilization measures, and document that the proposed design would achieve FERC
criteria for dam stability.
' The intake is physically a monolith construction; however, for computational purposes it has been
divided into seven "blocks".
Exhibit No. 6
CaseNo. AVU-E-I9-04
J. Thackston, Avista
Schedule 1, Page 78 of 120
o
Report: Long Lake Dam Stability Measures lnitial Design o
Resource Metering, Telemetry and Controls Upgrade
o
o
1 GENERAL INFORMATION
1.1 Steering Committee or Advisory Group lnformation
ln January af 20L7 Scott Kinney, Director of Power Supply, sponsored a small cross
departmental team to evaluate the status of our generation plant metering, generation
controls and associated telemetry to ensure Avista will be compliant with metering
requirements in the California lndependent System Operator (CAISO) Energy lmbalance
Market (ElM) if and when Avista decides to join the CAISO EIM market structure. The
team was tasked to develop a multiyear capital budget business plan by the end of June
201-7 and an associated schedule to prioritize and perform any necessary metering,
controls and telemetry upgrades over a three year period to satisfy these goals. lf the
proposed project receives funding from the Capital Planning Group an Advisory Group
consisting of personnelfrom GPSS and Power Supply with be created to provide project
guidance.
Z BUSINESS PROBLEM
The CAISO EIM is an in-hour economic based regional resource dispatch program that
allows participants to lower energy costs by either dispatching less expensive resources to
meet load obligations or increase revenue through the bidding of excess energy into the
market. The EIM dispatches the most economic resource across its entire market footprint
based on bid prices to balance in-hour load and generation resulting in lower overall
dispatch cost for each individual participant. The EIM also lowers the amount of on-line
regulation that each utility holds in excess every hour to make up the error between the
forecasted load and resource plans, and what actually occurs during the operating hour.
The reduced regulation can then be monetized creating additional revenue.
Joining the CAISO ElM, or any other sub hourly dispatch market, requires adherence to the
market operator metering and controls standards. The CAISO EIM dispatches resources in
5 minute intervals and an EIM member will economically settle any generation imbalance
to dispatch request on a 5 minute basis. The EIM member entity is required to and
advantaged by having accurate reliable meter data, control equipment and telemetry to
accurately account for the generation output in each of these 5 minute dispatch
Exhibit No. 6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule I , Page 79 of 1 20
Requested Spend Amount s3,33s,000
Requesti ng Organization/Department Power Supply and Generation Production
Business Case Owner Kristina Newhouse - Mgr. Controls Engineering
Business Case Sponsor Andy Vickers - Dir. Generation Production and
Substation Support
Sponsor Organization/Department GPSS
Category Project
Driver Performance & Capacity
o
Business Case Justification Narrative Page 1 of4
Resource Metering, Telemetry and Controls Upgrade
increments. The metering required to satisfy the accurate accounting are posted on the
CAISO EIM Metering and Telemetry Business Practice Manual and the CAISO Tariff section
L0, as well as various additional resources on the CAISO EIM website. Avista does not
currently meet all of the required metering device types.
Avista is currently transacting in the California market on a bilateral basis and appropriate
resource metering is required to account for these current market initiatives. This plan
places emphasis to first upgrade resource metering on those resources that are currently
being sourced to provide these transaction enabling Avista to continue capitalizing on these
lucrative transactions.
lf Avista waits until a decision is made to join the CAISO EIM to perform these metering and
controls upgrades, there is risk of not being able to complete the upgrades before an EIM
go live date. Accurate quality metering in an EIM allows the participant to maximize the
benefits of participating in the ElM.
Avista is currently undertaking a long term program to update all generation metering to
the SEL-735 lntermediate meter, which is an approved CAISO meter. This metering
upgrade plan accelerates the upgrading and replacement of metering to ensure Avista is
prepared for organized market entry in the near future.
There is a possibility that another market could form in the region as the Mountain West
Transmission Group (MWTG) is making progress in their organized market initiative. lf that
market does form and Avista decides to forgo the CAISO EIM entry for the MWTG that
market will still require metering and settlements in 5 minute increments. The metering
upgrade plan we undertake in this plan will be adequate for either market
There are several factors that impact the timing for when Avista will join the CAISO ElM.
Avista will continuously monitor these factors throughout this year and plans to make a
formal decision on when to join the market by the end of 2017.
3 PROPOSAL AND RECOMMENDED SOLUTION
The following recommendations are for a multiyear capital budget plan to upgrade all of
the Avista generation metering for organized market compliance.
1. Retain the services of a metering engineer (internal or consultant) for the first 6
months of 2018 to perform a full engineering review and report of the following:
a. Specifications for each meter associated with each Avista Generator.
b. Specifications for each PT and CT associated with each meter.
o
o
o
Option CapitalCost Start Complete
Do nothing $0 N/A N/A
California lndependent System Operator Energy
lmbalance Market Metering Upgrade
$s.34 M 01 2018 12 2020
Business Case Justification Narrative Exhibit No. u Page 2 ot 4
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule I , Page 80 of I 20
Resource Metering, Telemetry and Controls Upgrade
o c. Telemetry quality and paths associated with each plant.
d. Current controlsystems at each plant.
e. All engineering drawings associated with each meter.
Make a final report laying out actual costs to make the Avista generation fleet
metering, controls and telemetry in compliance with CAISO standards. Estimated
cost for the full Engineering Review S125,000.
2. Continue the current metering upgrade schedule already in the capital budget
schedule at Little Falls, Cabinet Gorge and Rathdrum CTs changing out metering to
the SEL-735. lnclude the review ofthe associated PTs and CTs and perform upgrades
as necessary.
3. Prioritize the metering upgrade at generating plants based on plants that are
currently being used to fulfil merchant positions in California and those plants that
could be used to supply potential non EIM market services in the near future. The
prioritization list is attached. An estimate of 575,000 per meter upgrade is used. This
cost includes the meter, engineering work, crew time for the actual meter change
out and any potential additional work needed to make to the telemetry and controls
compliant with CAISO metering standards. See Attachment A.
4. Upgrade the MV-90 system to be CAISO meter data compliant in year 3. Estimated
cost 560,000. This cost includes ltron support, licensing fees and virtual servers.
o
o
Business Case Justification Narrative Page 3 of 4Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 8l of 120
Resource Metering,Telemetry and Controls Upgrade
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the EIM project and agree with the
approach it presents. Significant changes to this will be coordinated with and approved by
the undersigned or their designated representatives.
Date:
o
o
Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
na Newhouse
Date: t lrc lzotl
Manager Generation Controls
Business Case Owner
Andy Vickers
Business Case Sponsor
tft'f2.,1
Director GPSS
Mike Magruder
Director T&D System Operations
Date:
Template Version: O3lO7 12017
Steering/Advisory Committee Review
5 VERSION HISTORY
o
Version Implemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Robert Follini 07/05/2017 Andy
Vickers
7 t10t2017 lnitial version
2.0 Kristina
Newhouse
7 t10t2017 Andy
Vickers
7t10t2017 Modified initial revision
(Aftachment separated)
Business Case Justification Narrative Exhibit No. u Page 4 of 4
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 82 of 120
Il^*w//t,tttl^,*
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HMI Control Software
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1 GENERAL INFORMATION
Requested Spend Amount $1,200,000
Requesting Organization/Department GPSS
Business Case Owner Kristina Newhouse - Controls Engineering Mgr
Business Case Sponsor Andy Vickers - Director of Generation Production
and Substation Support
Sponsor Organization/Department GPSS
Category Pro.lect
Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
The need to address the risk of aging control software and outdated control screens
has been vetted through the Generation Production and Substation Support (GPSS)
planning process.
The Controls Engineering Manager will provide oversight and monthly tracking of
the ongoing work within the project. The advisory group for ongoing vetting includes
the Director of GPSS, the Controls Engineering Manager, the Protection Control
Meter Technician Foreman, the Spokane River Operations Manager, the Clark Fork
River Operations Manager, and the Thermal Plant Operations Manager.
2 BUSINESS PROBLEM
The existing Human Machine lnterface (HMl) software, Wondenarare sold by
Schneider Electric, will not be supported after 2017. New control screens will need
to be developed using a new software platform. The major driver for the HMI Control
Software business case is the Asset Condition. This project aligns with Avista's Safe
& Reliable lnfrastructure strategy. The existing HMI control software has reached
end of life. HMI control Software is used to develop control screens are used to
control generating systems within Avista Hydroelectric Developments and Thermal
Generating facilities. They allow an operator to run the station from a computer in a
control room rather than from the equipment on the generating floor.
New HMI control software is needed now to prevent limitations going forward that
will introduce security risks. The existing HMI software runs on Windows 7. Microsoft
will not be supporting Windows 7 after the year 2020.lf we do not stay current with
supported operating systems then cyber security risks increase. Replacing
unsupported HMI software will allow upgrading control computers to supported
operating systems such as Windows 10.
ln addition, developing new controls screens on a new software platform will
modernize control screens and allow operators to carry out their responsibilities
more effectively. Control Screens will need to be developed for each generatingo
Business Case Justification Narrative Exhibit No. 6 page 1 of 4
Case No. AW-E-19-04
J. Thackston, Avista
Schedule 1, Page 83 of 120
HMI Control Software
facility, therefore, a planned approach will allow engineers and technicians to
develop screens over time to coordinate with control upgrades.
3 PROPOSAL AND RECOMMENDED SOLUTION
The preferred alternative is to purchase new HMI control software that better meets
the needs of operators, protection control and meter (PCM) technicians, and
engineers. Most HMI control software provides the same functionality but engineers
and PCM technicians are interested in software that provides user friendly
installations, interfaces with existing equipment with ease, such as PLCs, and allows
for control screen modifications and troubleshooting with efficiency.
This alternative addresses concerns with unsupported software, such as cyber
security vulnerabilities. There is a risk that upgrading HMI software and developing
new screens will take longer than expected. The duration of the project could take
longer due to complexity, limited outage availability, or a shortage of resources. To
mitigate risk a project manger is needed to maintain schedule and provide ongoing
coordination. An engineer is also needed to consistently upgrade control screens
at each generating facility, preferably before the year 2020 when Microsoft will no
longer be supporting Windows 7. Engineering will assist with developing a new
seryer based architecture and developing and commissioning HMI control screens.
The PCM Shop will need a resource to develop, installand commission the new HMI
control screens. A contractor will be necessary, at least in the beginning, to help
establish a new control screen standard template. Support from the Enterprise
Technology (ET) will also be necessary to install new servers at each plant and
provide ongoing support.
Tohle I
o
Table 1 is an estimate of how progress will be made
over the course of 4 years. lt shows what percentage
of sites (12 total) will have new controlscreens by the
end of 2021
Another alternative is to remain with the current HMI
Control Software vendor (Wonderware) and upgrade
to a new version that has already been purchased
(System Platform). This option will still require the
development of new control screens from scratch and
has the same risks as the preferred alternative. This
alternative only saves the cost in software as a new
Year Percentage of
sites with new
control screens
2018 10%
2019 33%
2020 66%
2021 lOOo/o o
Option CapitalCost Start Complete
Do nothing $0
Purchase new software platform and
new control screens
develop $1,200,000 01/2018 09/2021
Upgrade existing software (Wonderware) and
develop new control screens
$1,000,000 01/ 201 I 09/2021
Business Case Justification Narrative
Schedule 1,84 of 120
Page 2 of 4Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
C
HMI Control Software
O
o
server based architecture and controls screens are still necessary.
o
Business Case Justification Narrative Page 3 of 4Exhibit No. 6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 85 of 120
HMI Control Software
It is expected that a server based architecture will reduce O&M costs as it will allow
for modifications to be made to HMI control screens from one central location and
eliminate the need to drive to each facility when changes are needed. However, the
servers will require ongoing support, therefore, increasing O&M costs.
o
Stakeholders that interface with the HMI Control Screen Software business case
include Controls Engineering, Project Management, Hydro Operations, Thermal
Operations, PCM shop, and Central Systems.
4 APPROVAL AND AUTHORIZATION tlfif (cntr./ gaffe-'c*Ye
Theundersignedacknowledgetheyhavereviewedthe@
and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Date: 1 Ilol-lat1
Newhouse
Controls Engineering Manager
Business Case Owner
Signature:
Print Name:
Title:
Role:
Date a-oAndy Vickers
Director of GPSS
Business Case Sponsor
Signature:
Print Name:
Title.
Role:
Date
SteeringiAdvisory Committee Review
5 VERSION HISTORY
Template Version: 03107 12017 o
Exhibit No. u Page 4 of 4
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 86 of I 20
Vercion lmplemented
By
Revision
Date
Approved
By
Approva!
Date
Reason
1.0 Kristina
Newhouse
7/7/2017 Andy
Vickers
7n0/2017 lnitial version
Business Case Justification Narrative
KFGS Boiler Tube Maintenance - Economizer Secfion
o
o
1 GENERAL INFORMATION
Requested Spend Amount $2,000,000.00
Requesting Organ ization/Department Generation Production and Substation Support
Business Case Owner Thomas C Dempsey
Business Case Sponsor Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Category Project
Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
The plant Budget Committee evaluates, prioritizes, and oversees project work at the
generating station. This group consists of the Plant Manager, General Foreman,
Plant Mechanic and a Plant Technician.
This project was identified after the unit experienced a tube leak near the inlet header
of the economizer. The inspection report indicated significant wear on the U bends
of the economizer tubes. After repairing the leaking tubes and any accessible tubes
that were below the allowable tube thickness, a Project Request was submitted to
the plant Budget Committee to perform any remaining maintenance in the
economizer section during a scheduled outage.
The plant Budget Committee utilizes an in-house Maintenance Project Review
scoring matrix. The review process focuses around Personnel and Public Safety,
Environmental Concerns, Regulatory/lnsurance lvlandates, Ongoing Maintenance
lssues, Decreasing Future Operating Costs, lncreasing Efficiency, Managing
Obsolete Equipment and Assessing the Risk of Equipment Failure.
The Maintenance Project Review scoring matrix revealed risks around Safety,
Ongoing Maintenance, and Equipment Failure.
The project request and detailed estimate were brought fonruard to Corporate
Finance and Planning Analyst for further analysis. The project was then
presented to the Thermal Operations and Maintenance Manager for plant budget
approval.
Approved projects are assigned a project Lead from the plant staff depending on
discipline. Large, complex projects may be assigned Engineering staff and/or a
Project Manager from Generation Production and Substation Support Department
to oversee. Project status and updates are discussed at the weekly plant
maintenance meetings.
2 BUSINESS PROBLEM
The Kettle Falls Generating Station thermal plant is a wood fired natural circulation
boiler. The wood is burned on a traveling grate system and the heat from the fire iso
Business Case Justification Narrative Exhibit No. 6 Page 1 of 4
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 87 of 120
KFGS Boiler Tube Maintenance - Economizer Secfion
i
transferred into the boiler which consists of water walls, a superheater section, a
generation section, an economizer section and the air heater. The process begins
with pumping water through a series of heat
a
oT.{''
exchangers to add heat and pressure to the boiler water. There are five external
heat exchangers in the condensate and feedwater systems. Pressure and
temperature is increased from 175 psi and 130 F to 1 ,900 psi and 450 F as the water
is pumped through the heaters. The feedwater is then pumped into the economizer
which is internal to the boiler flue gas. The water enters the economizer at 450F
and exits at 575F. After exiting the economizer, the boiler water is then pumped into
the steam drum. The water is then heated to steam, which produces 415,000 lbs/hr
of steam flow at 950F superheated steam and 1,550 psi operating pressure to drive
the steam turbine generator. The steam is then condensed back into water and it is
pumped back through the heating system again.
An annual outage inspection utilizing Non-Destructive Testing (NDT) is performed
on all areas of the boiler that can be accessed with scaffolding. The NDT results
are used to make repairs on the boiler.
During the combustion process, ash and sand is carried off the grate and into the
flue gas stream. The ash and sand is removed from the flue gas mechanically
through a series of aggressive flow changes, cyclone separation and electrostatic
precipitation. The economizer is positioned upstream of all the collection equipment.
The abrasive nature of the sand and ash has caused significant wear to the outside
Exlribit No. u Page 2 o'f 4
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 88 of I 20
Business Case Justifi cation Narrative
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KFGS Boiler Tube Maintenance - Economizer Secfion
o of the economizer tubes, resulting in tube thinning and leading to ruptures
3 PROPOSAL AND RECOMMENDED SOLUTION
There are no inspections or testing that can be performed to determine when or
where the next failure will occur. The unit will be subject to more forced outages and
employees will be at risk of being around the unit when the next rupture arises. lt is
not a matter of ffthe unit will experience another tube rupture it's when.
Phase 1 to perform needed U-Bend repairs during the annual maintenance outage.
Phase 2 to repair and replace the economizer section with the same configuration
and size would address both the U-Bend wear and the tube length failure.
CH Murphy has provided a high level approach to the project and budgetary estimate
(see attached 2017-670 Re{ube Economizer Budget Estimate.pdf). The project
could be completed within the scheduled 20'19 annual outage, as quickly as 17 days,
without any impacts to schedule or additional resources.
Performing boiler tube maintenance on regular intervals minimizes employee
exposure to hazards resulting from a tube rupture. This project should reduce
potential safety risks and increase plant reliability.
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the KFGS Boiler Tube
Maintenance and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.
o
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Thomas C Dempsey
Date
Date:/Z
Business Case Owner
Andy
Option CapitalCost Start Complete
Do nothing $0
1. Partial U-Bend repair $325,000 06/2418 06/2018
2. Repair economizer section $2M 03/2018 06t2019
o
Business Case Justification Narrative
rS
Page 3 of 4Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 89 of 120
KFGS Boiler Tube Maintenance - Economizer Section
Role Business Case Sponsor
Steering/Advisory Committee Review
Date:
Template Version : 03107 12017
o
5 VERSION HISTORY
o
Version lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Greg Wiggins 12/22/2017 12/222017 lnitial version
2.0 Thomas
Dempsey
3.0 Darrell Soyars 2t5t2018 Environmental review
Business Case Justification Narrative
o
Exhibit No. u Page 4 0f 4
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 90 of I 20
Signature:
Print Name.
Title:
Role:
I
KF_Fuel Yard Equipment Replacement
o
o
1 GENERAL INFORMATION
Requested Spend Amount $ 22,000,000
Requesting Organization/Department Generation Production and Substation Support
Business Case Owner Greg Wiggins
Business Case Sponsor Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Category Project
Driver Asset Condition
2 EXECUTIVE SUMMARY
. The existing system does not allow us to operate consistently with safe best
practices due to it being designed for truck sizes smaller than subsequently
updated trucking regulations allow for.
. The existing system does not meet environmental regulations for visibility
and particulate matter (PM) emissions for intermittent periods.
o All of the equipment operates at or near its absolute limit- we expect
additional output in the coming years which will require a more robust fuel
supply system.
. All of the equipment is 35+ years old and has reached the end of its useful
life- most will have to be replaced in order to stay reliable.
r Although the primary drivers for the project are safety, environmental, and
reliability, we do expect a decrease in O&M. Using an unloaded cost of
$16.6 million the project has a calculated IRR of -2.73 if the benefits of
improved safety, improved environmental characteristics and plant
reliability are excluded. With all benefits included, Financial Planning and
Analysis has concluded that this is a prudent project.
o The project will proceed over a two year period with $12 million in201g and
$10 million in2020 (fully loaded).
3 STEERING COMMITTEE OR ADVISORY GROUP INFORMATION
The plant uses a plant Budget Committee to evaluate, prioritize, and oversee project
work at the station. This group consists of the Plant Manager, General Foreman,
Plant Mechanic and a Plant Technician.
The plant Budget Committee utilizes an in-house Maintenance Project Review
scoring matrix. The review process focuses around Personnel and Public Safety,
Environnrental Concerns, Regulatory/lnsurance Mandates, Ongoing Maintenance
lssues, Decreasing Future Operating Costs, lncreasing Efficiency, Managing
Obsolete Equipment and Assessing the Risk of Equipment Failure.o
Business Case Justification Narrative Exhibit No. u Page 1 0f 8
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 91 of 120
KF Fuel Yard Equipment Replacement
This project was first identified by plant mechanics and equipment operators due to
asset condition and environmental exposure. The project was then elevated due to
a fatality from a contracted employee. Using past maintenance logs in Maximo along
with known environmental and safety risks a Project Request was submitted to the
plant Budget Committee for a replacement of major fuel handling equipment.
The Maintenance Project Review scoring matrix revealed risks around Safety,
Ongoirrg f\/aintenance, Environmental, Decreasing Future Operating Costs and
Equipment Failure.
A project team was assembled including the GPSS Thermal Operations and
Maintenance Manager, Kettle Falls Plant Manager, GPSS Thermal Engineer, Solid
Fuel Manager, Plant General Forman, Electrician, Maintenance and Operations
staff. The project team met with a number of outside engineering firms to begin a
feasibility study to help define the scope of the project and high level estimates. The
project team visited two new biomass facilities to learn about process equipment.
After working closely with outside engineering further internal analysis was done with
the Energy Resources group and a project plan estimate was brought forward to
Corporate Finance and Planning Analyst for further analysis. The project was then
presented to the Thermal Operations and Maintenance Manager for plant budget
approval.
Approved projects are assigned a project Lead from the plant staff depending on
disciplirre. Large complex projects may be assigned Engineering staff and/or a
Project lVlanager from Generation Production and Substation Support Department
to oversee. Project status and updates are discussed at the weekly plant
maintenance meetings.
3.I INTRODUCTION
The major fuel yard equipment being considered for replacement includes the truck
dumpers, fuel hog, truck scale, and conveyance systems.
Truck Scale- The truck scale is used to account for the quantity of fuel received
from each truck delivery. The truck drivers scale in upon arrival to the site and the
scale out after completing the unloading process.
Truck Dumpers- The truck dumper receives the delivered fuel by elevating the
trailers. Fuel exits the rear of the trailer into a receiving housing.
Fuel Conveyors- Fuel conveyers move the fuelfrom the truck dumpers to a metal
detection system, then to the fuel hog system and finally out to the fuel yard.
Hog- The fuel hog is a device that clarifies and conditions the fuel so that it is the
proper size required for optimum combustion.
Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 92 of 120
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Business Case Justification Narrative Page 2 of 8
KF_Fuel Yard Equipment Replacement
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4 BUSINESS PROBLEM
There are three key components that comprise the business problem presented by the
current fuel yard.
1. Safety
2. Environmental
3. Reliability
These three components are summarized as follows:
The Kettle Falls Generating Station is a biomass fueled power plant that processes on
average 500,000 green tons of waste wood from area sawmills. The wood delivered to
the facility is trucked in by contractors utilizing semi-trucks and chip trailer. On average
the plant received 65-80 loads of fuel each day with surges to 100 deliveries in a 24 hour
period.
Business Case Justification Narrative Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 93 of 120
Page 3 of 8
i.r
,1:
The plant's original design was just prior to Washington State increasing the legal haul
lengths and weights. All the equipment was designed for 48' trailers and the new law
change in 1985 allowed drivers to haul with 53' trailers. When the drivers enter the facility
the load is weighed on a State certified scale to determine amount of fuel being delivered.
The longer trailers do not completely fit on the scale without the drivers lifting the tag axle
on the trailer. The plant's delivery tracking system captures the gross weight of the truck
and trailer into the 3log financial interface application. Through this system vendors and
suppliers are paid for their services. Due to the longer trailers and short scale drives can
"cheat" the system by not positioning the load correctly on the scale. Each load is
reviewed through the 3log (TWA) Truck Weight Analyzer. When an infraction is found
the surveillance video is reviewed and sent to the hauling company for reconciliation.
Manual adjustments are made in the system to ensure proper payment to the supplier.
ir-n r'|n. !'.a ry affiffi
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Truck was intentionally positioned short on the scale. TWA show drivers manipulating the scale due to being overloaded.
The fuel is offloaded truck trailers into the receiving hoppers via a truck dumpers. The
wood is then conveyed, screened and sized prior to being transferred out to the fuel
inventory pile. The Fuel Equipment Operators then manage the fuel inventory utilizing
D10 Cat dozers to stack out incoming fuel and stage inventory to be processed in the
plant.
Due to the higher legal hauling limits in Washington the longer truck/trailer configurations
require the truck drivers to unhitch the trailer from their trucks. This unhitching process
not only increases truck turnaround time and increases hauling costs to plant, it adds a
difficult step. Although not the primary factor, a contractor fatality in 2013 occurred while
going through this step in the process. One driver was attempting to unhitch his trailer
from the truck and was working with another driver to get the hitch pin released when the
accident occurred.
After the load is raised into the air and the fuel is discharged out of the back of the haul
trailer into the truck receiving hopper a large plume of dust often launched into the air and
then carried in the wind off the plant site.
KF_Fuel Yard Equipment Replacement
Business Case Justification Narrative Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1 , Page 94 of I 20
Page 4 of 8
I
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KF_Fuel Yard Equipment Replacement
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After the wood discharges out of the truck receiving hopper it is transferred via conveyor
belt to a disc screen and hammer hog to be properly sized and then discharged onto the
hog storage area.
Both Safety and Environmental
regulations require that PM be
reasonably controlled for worker
safety, air quality and visibility. All
emissions should be managed on-
site.
The fuel yard is subject to a very
corrosive environment due to the
wet wood being in contact with the
equipment. The years of rusting has
caused failure to metal conduit and
structural steel. The metal support
structure of the truck receiving hoppers has rusted through to the point of being
completely cracked through. Welded plates have been installed to affected areas on the
truck receiving dumpers, Many of the electrical conduits are rusted through and need
replacement.
The system is currently running at maximum capacity with fuel spilling over the edges of
the conveyance system, the disc screen is not operating at the proper throughput as a
significant amount of proper sized fuel is carried over the disc screen into the hammer
hog. The over feeding of material into the hog creates excessive wear on the hammer
hog grates and hammers.
With an average of 80 semi loads delivered each day and over 25 sawmills depending on
the fuelyard at Kettle Falls to be in full operation there is tremendous pressure in keeping
the system running. Area mills store the fuel purchased by Avista in storage bins and can
only hold the waste wood for a few days and sometimes only hours before the backup of
wood begins to cause production issues at the mill. When product flow out of the mill is
not managed well suppliers may begin to look for other options to move their waste to
more reliable markets. Another important detriment to not keeping fuel moving efficiently
is that as more fuel inventory builds at the supplying mill, the resulting Moisture Content
increases as well as the opportunity for contamination from rock and other "non-spec"o
Business Case Justification Narrative Page 5 of 8
\
1,
Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 95 of 120
KF_Fuel Yard Equipment Replacement
materials. lt is important to keep the KFGS fuel yard operating with minimal downtime
to provide good service and quality controlto the supplier's milling operations. lt is critical
to the reliability of both the KFGS plant and its supply chain.
ln 2017 a team was assembled including the Thermal Operations and Maintenance
fvlanager, Fuel l\Ianager, Plant lvlanager, Thermal Engineering and plant staff. The team
worked with outside engineering firm WSP to evaluate the fuel yard equipment and
explore options. The team also traveled to two new biomass plants to gain knowledge of
new equipment and process. This information along with the support of WSP allowed the
team to evaluate a number of options.
5 PROPOSAL AND RECOMMENDED SOLUTION
Option CapitalCost Start Complete
Do nothing $0
1. Rebuild critical components of the fuel yard $4,225,000 05 2019 06 2020
2. Replace critical components of the fuel yard
and install new conveyors.
$22,000,000 05 2019 06 2020
3. Replace critical components of the fuel yard
including fuvo radial stacker reclaimers
$30,000,00a 06 201 I 06 2020
The four options were discussed and doing nothing has been the approach for a
number of years. Maintenance costs have increased with equipment failure to the live
bottom gear boxes, dumper cylinders and lifting deck. Modifications are being made to
equipment due to obsolete equipment is no longer available. This approach will see
continued breakdown maintenance, reduction in fuel yard reliability and continued risks
around safety and environmental litigation.
Option 1 includes major rebuild of the existing equipment. The truck dumpers would
have mechanical and support rebuilt, some conveyors would be sped up to the
maximum allowed throughput, hog and disc screen would be rebuilt, the power
distribution, motor control centers and PLC's replaced, all the electrical hardware in the
yard would be replaced. This option would not change the operations of the fuel
handling system. Safety and environmental concerns would remain unchanged. The
truck scaling issue would still remain. The work would create major disruptions to our
suppliers as the work and repairs could not be done without interrupting delivery
schedules for days and weeks at a time. Fuel would have to be diverted to other
consumers with the risk of losing the contracts in the future.
Recommendation is to pursue Option 2 that includes relocating new equipment to a
different location in the fuel yard. This approach would allow the current system to
operate while the new system is constructed and commissioned. The layout would
reduce crossing traffic issues with the semitrucks. A new longer inbound and separate
outbound scales would eliminate the scaling issue as sensors would not allow a driver
to scale in unless the truck was positioned correctly on the scale. The two new truck
dumpers would be larger in size which would allow the lifting of both the truck and the
trailer. This would reduce truck turnaround time and eliminate the hazard identified in
o
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Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 96 of 120
Business Case Justification Narrative Page 6 of 8
o
KF Yard Equ ipment Replacement
the driver fatality. The new dumpers would incorporate a dust containments systems to
reduce fugitive dust during the offload. New conveyors would be larger to
accommodate higher throughput. The higher capacity belt system would reduce
laborious shoveling of spilled fuel. The incline of the new belts would reduce winter
frozen fuelfrom sliding on the conveyor belts. The disc screen would be larger in size
for better screening efficiency and reduce hog operation to only oversized material. The
upgraded stack out fuel conveyor system would strategically move the fuel to three
locations reducing Caterpillar dozer fuel consumption and yearly time base
maintenance. A new controltower and power supply would eliminate the electrical
deficiencies with the cunent system.
Option 3 is the same as option 2 with the addition of an automatic stacker reclaimer
conveyor systems. This would eliminate the need to operate and maintain the 2
Caterpillar dozers. Fuel would be moved into and out of the fuel yard using conveyor
systems. One dozer would be retired while the other would be used very little during
emergency situations. Dieselfuelconsumption would be reduced 95% along with the
time based maintenance. Using the stacker reclaimer requires the plant to operate and
maintain very low inventory volume of a maximum of three week on one stacker
reclaimer. After studying past operations and pricing Power Supply would need to
install 2 stacker reclaimers to optimize price and inventory. Power Supply's analysis
indicated that while operations and maintenan@ costs would be reduced, Power Supply
costs to our customers would offset the gains in a single stacker reclaimer and to
mitigate Power Supply expense, to stacker reclaimers would be required. The price of
two stacker reclaimers make this option unattractive.
6 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Certified Rebuild D10R CAT
Dozer Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name:
Title:
Role:
W,
wiggtns
Kettle Falls Plant Manager
Date,6-lv- aoq
Date:
,r\^ra
Business Case Owner
Vickers
Director of GPSSo
Business Case Justifi cation Nanative
Business Case Sponsor
Page 7 of 8
Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule I, Page 97 of 120
Cahinet Gorge Unit 3 Protection & Control Upgrade
1 GENERAL INFORMATION
Requested Spend Amount $2,786,000
Requesting Organization/Department Generation Production and Substation Support
Business Case Owner Jacob Reidt
Business Case Sponsors Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Category Project
lnvestment Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
As generating plants are managed by the Generation, Production, and Substation
support group, they provide energy and other services used by Power Supply. The
steering committee for this project includes members from both groups: Director
Power Supply; Director GPSS; Manager Hydro Ops and Manager Project Delivery.
This team receives monthly project status updates but meets only in the event that
a decision is needed.
The projecUstakeholder team meets on a more regular basis (at least monthly) to
work on the project's scope and planning. The projecUstakeholder team is
comprised of representatives from the various engineering groups (electrical,
controls, mechanical) and plant operations.
2 BUSINESS PROBLEM
This plant was designed for base load operation. Today, Cabinet Gorge is called on
to not only provide load, but to quickly change output in response to the variability of
wind generation, to adjust to changing customer loads, and other regulating
services needed to balance the system load requirements and assure transmission
system reliability. The controls necessary to respond to these new demands
include speed controllers (governors), voltage controls (automatic voltage regulator
a.k.a. AVR), primary unit control system (i.e. PLC), and the protective relay system.
ln addition to reducing unplanned outages, these systems will provide the ability for
o
o
Business Case Justification Narrative
o
Exhibit No. 6 page 1 of 7
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 98 of 120
I
Cabinet Gorge Unit 3 Protection & Control Upgrade
o
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Avista to maximize these services from within the pool of its own assets on behalf of
its customers rather than having to procure them from other providers.
As part of the designated "Regulating Hydro" class of assets. The key metric for
these plants is their Equivalent Availability Factor or EAF.
Chart 1 - Equivalent Availability Factor
Equivalent Availability Factor (EAF) measures the amount of time that the Unit is able
to produce electricity in a certain period, divided by the amount of time in that period.
In this case, Cabinet Gorge has averaged below 85% EAF forthe twelve month rolling
period ending February of 2018. The internal company target for this measure is
8s%
Some of the outages that cause the EAF to fall below the target include forced and
maintenance outages associated with the control and protection systems described.
Some recent events captured are attached to this document for referencel.
An additional problem with the existing governor (speed) control is the lack of
response to a system frequency event. The graph below compares the response of
Cabinet Gorge Unit 3 (CG3) to Noxon Rapids Unit 2 (NR2) for one minute after a
significant frequency excursion event. NR2 was recently modified to provide
I See - 18 Ma-rimo Work Orders related trr C(i Controls."
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Business Case Justification Narralive Page 2 af 7Exhibit No. 6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule I , Page 99 of 120
a ,,
Cahinet Gorge Unit 3 Protection & Control Upgrade
adequate response to frequency excursions. During this event NR2 increased output
by 2.53 MW and CG3 decreased output by 0.03 MW. CG3's response negatively
impacted the Avista's response to this event. Given the outdated unit control and
governor technology, modifications cannot be made to programs and settings to
reliably improve the frequency response of CG3. Upgrading the unit to Avista's
standard hydro unit control package will immediately correct frequency response.
Chart 2 - Lack of Frequency Response
RtquENcY EX(UR5r()tl RE5pO
CG UTJIT ] VS N8 UilIT 2
ll2
CG Unit 3 (TSMWMarOutputl
NR Urir ! (1fi6 MW Max Ourpuri
i{l t}
fo,o
=c)
ec
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c!
intl
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98
96
9il
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0.91
'.,
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A similar chart showing voltage control issues at Cabinet Gorge can be found in
Appendix A.
There are several NERC Reliability standards against which the existing equipment
performs at a sub-standard level. One of these standards involves frequency
response as describe above. The related NERC standards are attached to this
document along with some technical explanation if more information is needed.
Last, there have been several unit outages that were specifically taken to address
problems associated with the existing control and protection equipment. This
equipment is at the end of its intended life and there is an increased likelihood of
forced outages and subsequent loss of revenue and reliability. More details of these
events can be found in Maximo Work Orders related to CG Controls.
Exhibit No. 6 page 3 of 7
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 100 of 120
Business Case Justification Narralive
):
Cabinet Gorge Unit 3 Protection & Control Upgrade
o
o
3 PROPOSAL AND RECOMMENDED SOLUTION
Avista's Safe & Reliable lnfrastructure strategic initiative seeks to leverage
technology and innovative products and services offered to existing and new
customers. The work proposed for Cabinet Gorge will include equipment and
component replacement geared at increasing reliability and unit control/monitoring.
Customers benefit in that it will allow Avista to economically optimize an existing
asset to provide energy and other energy related products.
To accomplish prolect objectives to improve unit response, operating flexibility, and
reliability, the following components will be considered: governor and governor
controls, generator excitation system and AVR, protective relays, and unit controls.
The extended outage will provide an opportunity to address other issues including,
insulating the generator housing roof, cooling water upgrade, unit flow meter and
other items to improve overall reliability. The objective is to ensure system
compatibility with current standards and improve system reliability.
Do Nothing / Continue to Repair: While the generator is capable of producing
energy with existing systems, the present equipment does not provide the system
support abilities needed to meet today's requirements (see graph above). This
solution requires maintenance of old systems that are no longer supported by the
original manufacturer and there is some question on parts availability, Additionally,
trained personnel available to work on these older systems are becoming scarce
and formal training is no longer available. For reasons of obsolescence, inadequate
system performance, and increasing maintenance demands, this option is not the
preferred option.
Replace Unit Control. Monitorino. and Protection Systems: ln addition to addressing
issues of obsolescence and increased likelihood of unplanned outages,
replacement of these key systems addresses the performance needs to work with
the new dynamics of the systems today. This includes integration of intermittent
resources, reseryes, frequency and voltage response, and the ability to adapt these
controls and protection devices as the larger grid continues to evolve.
lnstallation of new controls and protection will also provide increased visibility into
the systems allowing better remote monitoring and troubleshooting. New systems
Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page l0l of 120
Option CapitalCost Start Complete
Do nothing / Continue to Repair $0
$1,850,000
ongoing ongoing
Replace Unit Control, Monitoring, and
Protection Systems
Q1 2019 Q2 2020
Mechanical, Controls, Electrical upgrades
and Stator Re-wedging
$2,786,000 Q1 2019
o
Business Case Justification Narrative Page 4 of 7
Q2 2020 i
Cabinet Gorge Unit 3 Protection & Control Upgrade
are also configured so compliance with NERC standards is much easier to achieve.
As this option addresses the primary issues, this is considered the minimal preferred
option.
Mechanical. Controls. Electrical upqrades and Stator Re-wedqing: This solution is
the same as the Replace Unit Controls, Monitoing, and Protection Sysfems
described above except it also includes addressing additional items related to the
reliability of the generating unit. This may include replacing the insulation system
on the generator rotor, re-wedging the generator stator, replacing and updating
auxiliary system motor controls, and other items identified as necessary to both
extend the life of the asset and improve the reliability. This solution would allow for
work that would be necessary in the near future to be performed now therefore
avoiding future outages and improving the near and long term reliability of the Unit.
Program Cash Flows for recommended solution
Scenario 1 Scenario 2
201 I $ 500,000
2019 $2,000,000 $2,286,000
2020 $ 286,000 $ 500,000
o
o
o
Business Case Justification Narrative Page 5 of 7Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 102 of 120
Cabinet Gorge Unit 3 Protection & Control Upgrade
o 4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Cabinet Gorge Automation
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
rttSignature:
Print Name:
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Role:
Signature:
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Date
Template Version: 03107 12017
o 5 VERSION HISTORY
Version lmplemented
By
Revision
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Approved
By
Approval
Date
Reason
1.0 Terri Echeqoven 6t8t18 Glen Farmer 6/8/18 lnitialversion
Jeremy Winkle 7t11t18 Glen Farmer 7111t2018 Finalto submit.
o
Business Case Justification Narrative Page 6 of 7Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 103 of 120
I
I
1.1
Cabinet Gorge Unit 3 Protection & Control Upgrade
APPENDIX A
frwstr Page 1 of I
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Acrpr*mg Unts CsnfEdad
tJt'ts 3 1ld4 .1 IGSU 1 GSU
t*tnnber o{ Flouo ',o*tags Erce€d€d lribr Lm63:
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Business Case Justification Narrative
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Exhibit No. 6 paoe 7 of 7
Case No. AW-E-t9-04
J. Thackston, Avista
Schedule 1, Page 104 of 120
lo.
frrlsleslslPerio<, Corared,l ti 140161
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Env i ro n mental Com pl i ance
o
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1 GENERAL INFORMATION
Requested Spend Amount $400,000
Requesting Organ ization/Department Environmental Compliance
Business Case Owner DanellSoyars
Business Case Sponsor Bruce Howard
S ponsor Organization/Department Legal
Gategory Mandatory
Driver Mandatory & Compliance
1.1 Steering Committee or Advisory Group lnformation
Avista is subject to multiple Federal, State and Local environmental regulatory requirements.
Environmental Compliance is tasked with managing and maintaining compliance with the applicable
requirements from these programs, some of which require capital projects from time to time.
The Environmental Compliance group maintains a risk-based ranking of potential compliance issues
that includes our current approach, accompanied documentation and a target date for resolution. This
ranking is typically dynamic as smaller issues rise and fall or as larger issues are addressed through
various process changes, audits or projects.
2 BUSINESS PROBLEM
Regulatory programs and standards have been established to control the handling, emission,
discharge, and disposal of harmfulsubstances. These programs are implemented directly by Federal
agencies or delegated to the State or local authority. ln many cases, they are applied to sources
through permit programs which control the release of pollutants into the environment.
Two efforts currently require capital funding under this business case:
1. The proper handling and disposal of hazardous waste, specifically oil-filled electrical
equipment governed by Resource Conservation and Recovery Act (RCRA), Toxic
Substances Control Act (TSCA) and related State regulations. This funding covers all
activities associated with the proper handling and disposal of hazardous waste, specifically
oil-filled electrical equipment as part of the asset decommissioning process. This includes
labor and equipment from when the equipment is removed from service, transported back to
the Spokane Waste and Asset Recovery Facility where they are identified, investigated,
inventoried, sampled, sorted, stored and/or shipped to the proper waste vendor for proper
disposal. These activities are accomplished by numerous field personnel including two
hazardous waste technicians. The handling of these materials is mandated by state and
federalrules
2. Specific site mitigation required by our U.S. Forest Service Special Use Permit (SUP) which
allows right-of-way and access to our transmission and distribution assets on public land.o
Business Case Justiflcation Narrative Exhibit No. 6 page 1 of 3
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 105 of 120
Envi ron mental Com plian ce
The SUP outlined specific mitigation projects when it was renewed in 2009 for a period of 30
years'. Approximately 60% of these have been completed to date. The specific mitigation or
restoration projects were an agreed upon remedy from past impacts from our activities
related to our transmission and distribution assets. New mitigation requests do result from
on-going activities to maintain our assets. Some of these arise from security issues related
to managing public access while others are weather related or considered acts of god.
3 PROPOSAL AND RECOMMENDED SOLUTION
Hazardous llYaste Disposal
Funding allows Avista to maintain compliance with Federal, State requirements. Our compliance
approach is the most cost effective method to support how construction and operational work is
currently being accomplished at Avista Corp. We have explored other methods such as utilizing
alternative support or contractors but these result in higher cost and increased liability.
Non-Funding would create significant environmental risk and potential liability which may prove
detrimental to our customers, the company, and the communities we serve. There are no
practicable alternatives to environmental compliance as stated in our Environmental Policy which
describes our commitment to protect human health and the environment We comply with all
applicable environmental laws, regulations, and company procedures.
US Forest Seryice Special Use Permit (SUP)
Funding the SUP mitigation is essential to remaining in compliance with the conditions of the SUP.
This allows for continued permission to occupy and operate our facilities on US Forest Service Land.
Alternatives to crossing US Forest Service land were likely considered prior to the construction of
these Transmission and Distribution lines; we are not aware of a cost effective alternative that could
be employed allowing the removal of our assets and the surrender of our SUP.
Non-Funding of mitigation efforts would pose potential risk of cancellation of our SUP, which would
undermine the ability to keep and maintain these facilities on Forest Service lands. We would also
be subject to direct enforcement by the Forest Service via penalties or orders. This could cause
interruption in service and increase in rates to our customers.
o
o
Optlon Gapltal
Coat
Start Gomplete
Do nothing $0 N/A
Fund the Hazardous Waste Disposal $250,000 01 2017 12 2017
Fund the USFS SUP mitigation activities $'t50,000 01 2017 12 2017
Business Case Justification Narrative Page 2 of 3
o
Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 106 of 120
o
Environmental
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Environmental Compliance
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name:
Title:
Role:
\A**.-."-
Date:
Date:
Template Version: 0212412017
9-+..-0-I
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Business Case Owner
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Revision
Date
Approved
BY
Approval
Date
Reason
1.0 Heide Evans 03t29t17 DarrellSoyars 04110117 lnitialversion
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Business Case Justification Narrative Page 3 of 3Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 107 of 120
t-.-
,{ry1,r
Hydro Safety Minor Blanket
1 GENERAL INFORMATION
Requested Spend Amount $350,000.00
Req uesting Organ ization/Department Hydro Compliance
Business Case Owner Michele Drake
Business Case Sponsor Bruce Howard
S ponsor O rganizationlDepartment Legal
Category Mandatory
Driver Mandatory & Compliance
1.1 Steering Committree or Advisory Group lnformation
Funded projects are identified in several ways. During periodic site inspections,
FERC staff may identify a new specific concern or point out an existing item that is
deficient or in need of repair. ln other cases, Avista has assessed the condition of
safety items at our dams, and proactively plans replacement or addition of a new
safety measure. Replacement can be driven by physical condition/agelfunction,
changing standards in FERC guidance, industry practice, or emergent public safety
needs. All projects are subject to the conceptual approval of the Chief Dam Safety
Engineer and to additional internal review and oversight.
2 BUSINESS PROBLEM
Section 10(c) of the Federal Power Act authorizes the Federal Energy Regulatory
Commission (FERC) to establish regulations requiring owners of hydro projec'ts
under its jurisdiction to operate and properly maintain such projects forthe protection
of life, health, and property. FERC's Division of Dam Safety and lnspections
establishes national guidance and policy, and Regional Offices implement this
responsibility. 18 CFR Parl12 delegates to the Regional Engineer the authority to
require safety devices, where necessary. Section 12.42 of the Regulations states
that, "To the satisfaction of, and within a time specified by the Regional Engineer,
an applicant or licensee must install, operate, and maintain any signs, lights, sirens,
barriers, or other safety devices that may reasonably be necessary or desirable to
warn the public of fluctuations in flow from the project or otherwise, to protect the
public in the use of the project lands and waters."
ln addition to the broad regulatory discretion given to FERC, Avista is subject to
liability should we not maintain safety-related equipment at our hydro facilities. This
work is aimed at reducing both regulatory and liability risks. Some of the projects
under this budget are planned, but others are opportunistic. We take advantage of
other planned work to coordinate dam safety actions, and at times, we have to
replace equipment that has been damaged due to flow conditions. I
Projects identified for 2017 include replacement of the boater safety cable at Noxon
Rapids and replacement of a boater safety sign at Post Falls.
o
o
o
Business Case Justification Narrative Page 1 of3Exhibit No. 6
Case No. AVU-E-I9-04
J. Thackston, Avista
Schedule I, Page 108 ofl20
o
o
Sa Minor Blanket
1. The boater safety cable at Noxon Rapids is more than 30 years old, and has
begun to show visual signs of failure, including listing, rusted floats and
deteriorating concrete. Operators and hydro safety staff identified the item
as in need of repair or replacement.
2. The boater safety sign at Post Falls was installed in 1994 and utilizes neon,
molded bulb lighting. A FERC inspector identified that the sign was becoming
difficult to read, and informally suggested replacement. Upon investigation,
some of the individual letters fail to illuminate.
ln both cases, repair of the existing item was considered. However the age and
condition of the items and improvements in technology have made repair moot.
1. "Guidelines for Public Safety at Hydropower Project" httosJArww.ferc.gov/industries/hvdrooower/sahtv/ouidelines/oublic-
safetv.pdf
2. Avista's Hydro Public Safety Plans for each of it hydro facilities.
3 PROPOSAL AND RECOMMENDED SOLUTION
Funding of these activities protect employees, contractors, and the general public,
and reduces financial risk to Avista.
Non-Funding activity would ultimately result in total failure of safety equipment,
subjecting Avista to additional liabilities due to possible regulatory penalties, injuries
or loss of life, and is therefore not a recommended option.
Optlon Capital Cost Start Complete
Do nothing 0
Fund annual request $350,000 01 2017 't22017
o
Business Case Justification Nanative Page 2 of 3Exhibit No. 6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 109 of 120
Hydro Safety Minor Blanket
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Hydro Safety Minor Blanket
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
o
Signature:
Print Name:
Title:
Role:
Date:
Business Case Owner
.?
Signature:
Print Name:
Title:
Role:
Date:
(? tutce ? +$q*na
D tna.Tot, Fwv. t4, Ffa&g
Business Case Sponsor
5 VERSION HISTORY o
Template Version : O3lO7 12017
Exlibit No. 6 Page 3 of 3
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page I l0 of 120
Vereion lmplemented
By
Revlelon
Date
Approved
By
Approval
Date
Reason
1.0 Heide Evans 03117117 Bruce Howard 04t03t17 lnitial version
Business Case Justification Narrative
o
qililF
o
Hydro Safety Minor Blanket
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Hydro Safety Minor Blanket
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other govemance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name:
Title:
Role:
Date: 4
Business Owner
f=rut<4 f tlocu*t-D
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Template Version: 03107/201 7
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o 5 VERSION HISTORY
Exhibit No. 6
CaseNo. AVU-E-19-04
J. Thackston, Avista
Schedule l,Page lll ofl20
Version lmplemented
By
Revision
Date
Approved
By
Approval
Ilab
1.0 Heide Evans ou17t17 Bruce Howard ut03t17 lnitial version
o
Suoinese Case Page 3 ot 3
tu
Reason
1 GENERAL INFORMATION
Requested Spend Amount $6,832,275
Requesting Organization/Department Clark Fork License lmplementation
Business Case Owner Nate Hall
Business Case Sponsor Bruce Howard
Sponsor Organization/Department Legal
Category Mandatory
Driver Mandatory & Compliance
1.1 Steering Committee or Advisory Group lnformation
ln mid-1996, stakeholders were invited to meet with a neutral facilitator to develop
a process for participating in the relicensing of these projects. There evolved a Clark
Fork Relicensing Team, which included representatives from nearly 40
organizations, including representatives from federal, state, and local government
agencies, five lndian tribes, special interest groups, conservation groups, property
owners, and Avista Corporation. The Relicensing Team established five technical
working groups, covering: 1) fisheries; 2) water resources; 3) wildlife, botanical, and
wetlands; 4) land use, recreation, and aesthetics; and 5) cultural resources
management. The team developed protection, mitigation, and enhancement
(PM&E) measures that were the basis for the comprehensive Settlement
Agreement filed with Avista's license application. The Settlement Agreement
establishes processes and includes 26 PM&E measures to resolve a wide range of
complex and conflicting natural resource interests. Avista led this collaborative
effort and signed the Agreement, making commitments for the 4S-year term of the
license. FERC incorporated the Settlement Agreement into the new license. Under
the Settlement Agreement and license, the licensee works through a Management
Committee (MC), comprised of one representative of each of the 27 parties to the
Agreement, to implement the PM&E measures. ln addition, the Clark Fork
Settlement Agreement (CFSA) and license require Avista to provide funding for
PM&E implementation over the course of the term.
All proposed PM&E activities and associated budgets are developed through one
of the three technical working groups identified in the settlement agreement and
approved by the MC, which strives to make all decisions, including approval of
planned activities and expenditures, by consensus. FERC reviews and approves
annualwork plans to implement license requirements.
2 BUSINESS PROBLEM
Avista owns and operates the Noxon Rapids and Cabinet Gorge hydroelectric
developments (Clark Fork Project No.2058). The operation of the Clark Fork Project
Business Case Justification Narrative Page 1 of3
Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 1 12 of 120
Clark Fork License lmplementation
o Clark Fork License lmplementation
is conditioned bythe Clark Fork SettlementAgreement, signed in 1999, and FERC
License No. 2058, effective date of March 1, 2001. Avista evaluated whether to
proceed with a traditional licensing process in the 1990s, which typically led to
conflict and Iitigation, or pursue a different strategy. The Company elected to pursue
an agreement through a collaborative effort. During the negotiations, Officers and
Directors of the company were informed and engaged, and officer approval was
required for the Settlement. This business case represents the ongoing resolution
of these issues and the means bywhich Avista fulfills its obligations underthe CFSA
and the FERC License.
The License was issued to Avista Corporation for a period of 45 years to operate
and maintain the Clark Fork Project No. 2058. The License, and associated Code
of Federal Regulation, includes hundreds of specific legal requirements, many of
which are reflected in License Articles 404430. These Articles derived from a
comprehensive settlement agreement between Avista and over 20 other parties,
including the States of ldaho and Montana, various federal agencies, five Native
American tribes, and numerous Non-Governmental Organizations. We are requiredto develop, in consultation with the Management Committee, an annual
implementation plan and report, addressing all PM&E measures of the License. ln
addition, implementation of these measures is intended to address ongoing
compliance with Montana and ldaho Clean Water Act requirements, the
Endangered Species Act (fish passage), and state, federal and tribal water quality
standards as applicable. License articles also describe our operational
requirements for items such as minimum flows, and reservoir levels, as wellas dam
safety and public safety requirements.
3 PROPOSAL AND RECOMMENDED SOLUTION
Funding of the Clark Fork License lmplementation is essential to remain in
compliance with the FERC license and CFSA for permission to continue to own and
operate the hydro-electric facilities. This commitment was made in 2001, and is
ongoing. At that time, Avista determined that the Settlement was in the best interest
of Avista, our customers, our shareholders, and the communities we serve. These
decisions were documented throughout the process at that time.
lf the PM&Es and license articles are not implemented and/or funded, we would
be in breach of an agreement and in violation of our License. There would be high
risk for penalties and fines, new license requirements, higher mitigation costs, and
loss of operational flexibility of the Cabinet Gorge and Noxon Rapids Hydro
Electric Facilities. Ultimately, FERC has the authority to revoke our operating
license and we could risk a competing license or even losing the facility. Loss of
o
o
Option
Do nothing $o
Fund the annual request $6,832,275 01 2018 12 2018
Business Case Justification Narrative Page 2 of 3
Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page I l3 ofl20
I
Clark Fork License lmplementation
operational flexibility, or, in the extreme, of these generation assets, would create
substantial new costs, to the detriment of our customers and the company.
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Clark Fork Settlement
Agreement Business Case and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.
Signature.Date:
Print Name
Title:
Role:Business Case Owner
o
Signature:
Print Name
Title:
Role:
Signature:
Print Name:
Title.
Role:
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Business Case Sponsor
Steering/Advisory Committee Review
Date:5, ltr1
Date
Tem plate Version: 03107 12017
o
5 VERSION HISTORY
Version lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Heide Evans 03t29t17 Bruce Howard 03t29t17 lnitial version
2.0 Heide Evans 7tl1t18 Bruce Howard 7t11t18 Changed BC Owner
Business Case Justification Narrative
,
Page 3 of 3
Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 1 14 of 120
I
Spokane River License lmplementation
o
o
o
GENERAL INFORMATION
Requested Spend Amount $2,033,063
Requesting Organ ization/Department Spokane River License lmplementation
Business Case Owner Speed Fitzhugh
Business Case Sponsor Bruce Howard
Sponsor OrganizationlDepartment Legal
Category Mandatory
Driver Mandatory & Compliance
1.1 Steering Committee or Advisory Group lnformation
Decisions related to annual implementation activities are reviewed and approved by
technical working groups (i.e., fish, aquatic weeds, water quality, recreation, land
use, and cultural) comprised of Avista, Tribal, local, state (ldaho and Washington),
and federal agency staff. The activities are specific to the Federal Energy Regulatory
Commisslon (FERC)-approved resource and operational plans that were developed
to address Spokane River Project License conditions. Capital projects ate
undertaken only to meet the requirements of the Spokane River License.
II. BUSINESS PROBLEM
Avista must have a license from FERC to operate the Spokane River Project. The
Spokane River Project consists of the Post Falls Hydroelectric Development (HED),
Upper Falls HED, Monroe Street HED, Nine Mile HED and Long Lake HED. Avista's
prior license expired in 2007;Avista undertook a relicensing effort beginning formally
in 20A2 to secure a new license, consisting of a collaborative process with over 200
stakeholders. The process ultimately resulted in FERC's issuance of a SO-year
license to Avista to operate and maintain the Spokane River Project, No 2545,
effective June 18, 2009. This License defines how Avista shall operate the Spokane
River Project and includes several hundred requirements, through license
conditions, that we must meet.
The License was issued pursuant to the Federal Power Act (FPA) and embodies
requirements of a wide range of other laws (The Clean Water Act, The Endangered
Species Act, The National Historic Preservation Act, etc.). These requirements are
also expressed through specific license articles (known as Protection Mitigation and
Enhancement Measures (PME)), relating to fish, terrestrial, water quality, recreation,
land use, education, culturaland aesthetic resources.
Avista also entered into additional two-party agreements with loca! state, and federal
agencies and the Spokane Tribe. Avista's FERC license and agreements include
mandatory conditions issued by the ldaho Department of Environmental Quality
(401 Water Quality Certification, issued June 5, 2008), the Washington Department
of Ecology (401 Certification, issued May 8, 2009), the U.S. Forest Service (Federal
Power Act 4(e), issued May 4, 20071, U.S. Bureau of Land Management, as well as
Business Case Justification Narrative Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page I I 5 of 120
Page 1 of3
commitments joined in with the ldaho Department of Fish and Game, ldaho
Department of Parks and Recreation, City of Coeur d'Alene, and the City of Post
Falls, Kootenai County Parks and Waterways, Washington Parks and Recreation
Commission, the Washington Department of Natural Resources, and articles set
forth in Form L-1 (entitled "Terms and Conditions of License for Constructed Major
project Affecting Lands of the United States"). During the seven-year relicensing
process, we engaged stakeholders in direct negotiations and we also engaged in
litigation to challenge some proposed conditions. Avista's officers and Board were
updated regularly during these efforts, and officers were engaged at key decision
points. Ultimately, FERC retains oversight jurisdiction for license compliance;
however, other entities, such as state agencies, assert their authority to
independently enforce license terms. The FERC license ensured Avista's ability to
operate the Spokane River project on behalf of our customers for another 50 years.
III. PROPOSAL AND RECOMMENDED SOLUTION
Complying with our license is mandatory to continued permission to operate the
Spokane River Project. Funding the implementation activities for the Spokane River
Project License is essentialto remain in compliance with the FERC license. There
are no practicable alternatives to meet compliance. Avista evaluated the potential
of surrendering the Spokane River license at the beginning of the relicensing
process, determining that this option would be detrimental to our customers, the
company, and the communities we serve.
lf the PM&Es, license afticles and settlement agreements are not implemented
and/or funded, we would be out of compliance with and/or in violation of our
License. This would lead to penalties and fines, new license requirements, court
costs, higher mitigation costs, and loss of operational flexibility. Ultimately, FERC
has the authority to revoke our License if we do not comply with the terms and
conditions required by it. Loss of operationalflexibility, or in the extreme, loss of our
generation assets, would create substantial new costs to our customers and no
benefits.
o
o
o
Optlon GapltalCost Start Complete
Do nothing $0
Fund the annual request $2,033,063 0'12017 12 2017
Spokane River Lrcense lmplementation
Business Case Justification Narrative Page 2 of 3Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page I 16 of 120
Spokane River Lfcense lmplementation
o IV. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Spokane River License
lmplementation Business Case and agree with the approach it presents and that it
has been approved by the steering committee or other governance body identified
in Section 1.'t. The undersigned also acknowledge that significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Date:
Business Case Owner
Signature:
Print Name:
Title:
Role:
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V. VERSION HISTORY
Tem plate Version : O3lO7 12017
Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page I 17 of 120
Venslon lmplemented
By
Revlslon
Date
Approved
By
Approval
Date
Reason
1.0 Heide Evans 03t15t17 Bruce Howard 3t30t17 lnitialversion
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Business Case Justificalion Nanative
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Page 3 of 3
1 GENERAL INFORMATION
Requested Spend Amount $10-$20 Million per year
Requesting Organization/Department Generation Production and Substation Support
Business Case Owner Thomas C Dempsey
Business Case Sponsor Andy Vickers
S ponsor O rgan izationlDepartment Generation Production and Substation Support
Category Program
Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
This Business Case request is for Colstrip 3&4 capital projects. Avista does not operate the
facility nor does it prepare the annual capital budget plan. The current operator provides the
annual business plan and capital budgets to the owner group every September. They also
provide individual project summaries which characterize the work using categories similar
in concept the Avista business case drivers. Avista reviews these individual projects. Some
of them are reclassified to O&M if the work does not conform to our own capitalization
policy. Avista does not have a "line item veto" capability for individual projects but it can
present concerns during the September owners' meeting. Ultimately, the business plan is
approved in accordance with the Ownership and Operation Agreement for units 3&4 that six
companies are party too. This Business case rcpresents the final approved budget after
subtracting items that we will expense instead of charging to capital.
2 BUSINESS PROBLEM
This Business Case represents the entire body of capital work performed in a calendar year
at Colstrip. This includes a variety of types of projects that Talen (current operator)
characterizes using the following categories:
o ENVMD- Environmental Must Do
o Sustenance
o Regulatory
o Reliability Must Do
3 PROPOSAL AND RECOMMENDED SOLUTION
o
o
o
Optlon Capitel
Cost
Start Complete Riek
Mltigatlon
Ongoing Operations (Yes/No Vote)$10-$20M NIA
Colstrip 3&4 Capital Projects
Business Case Justification Narralive Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule 1, Page 1 18 of 120
Page 1 of3
Colstrip 3&4 Capital Projects
o
Colstrip Capital is required as part of ongoing operations of the facility.
. The operator (Talon) reviews each proposed project. Discretionary items are
reviewed in a hurdle rate analysis.
. The operator reviews the risk mitigation for each altemative using the
busrness risk worksheef as well as descibe the nature of the risks for each
altemative.
o Those that meet the criteia are submifted as part of an overall budget to the
owner committee,
. This process is repeated annually
. The annualbusiness plan is available on request.
c Although altematives are not available for consideration at this level,
individual projects are rcviewed and considered by all the joint owners.
Projects may be delayed and changed per committee rccommendation to the
operator of the facility.
o
o
Business Case Justification Narrative Page 2 of 3Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 1 19 of 120
Colstrip 3&4 Capital Projects
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Colstrip 3&4 Capital Projects
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Date
Business Case Owner
o
Signature:
Print Name:
Title:
Role:
Date:
Template Version: OZl24l2O17
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Business Case Sponsor
o5 VERSION HISTORY
o
Verslon lmplemented
By
Revlslon
Dats
Approved
By
Approval
Date
Reason
1.0 Mike Mecham 04117t2017 Steve Wenke 0411712017 lnitial version
Business Case Justification Narrative Page 3 of 3Exhibit No. 6
Case No. AVU-E-19-04
J. Thackston, Avista
Schedule l, Page 120 ofl20
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