20190610Rosentrater Exhibit 8 Sechedule 1.pdf

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RECEIV
9DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P .O. BOX 3727
I41 1 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220 -37 27
TELEPHONE: (s09) 495-431 6
FACSIMILE: (509) 49s-885 I
DAVID.M [e-mail]
i0t9 JUH t0 AH t0:
i}AijJ FUBLICTILiTIIS COffMISSI
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
STATE OF IDAHO
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CASE NO. AVU-E-19-04
EXHIBIT NO. 8
HEATHER L. ROSENTRATER
FOR AVISTA CORPORATION
(ELECTRIC)
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Exhibit No. I
Case No. AVU-E-1 9-04
H. Rosentrater, Avista
Schedule 1, Page 'l of 103
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Avista Utilities
Electric Distribution lnfrastructure Plan
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Ausre, AssET M^A.r.IeeeMENT Gnoup
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Tuerlxs & AanNoWLEDGEMENTS
Amber Fowler - Transformer Analysis
Amy Jones - Distribution Wood Pole Management Data Analysis
Angela Moffat - Graphics
Casey Fielder - Graphics and District Maps
Chris Lum - Distribution Research and Analysis
Cody Krogh - PCB Replacement, Underground Cable, Content, ldeas and lmprovements
David Howell - Content and Review, Project Support and Guidance
David James - Distribution Facts, Figures and Photos, Editing and Enhancements
Glenn Madden - Research, Data, Content and Review
Jeff Budke - Distribution Facts and Photos
Jeff Schlect - Content Checking
Jeff Smith - Data Analysis, Content Checking
Jeremiah Webster - Capital Budgeting Numbers
Jill Ham - Reliability and Outage Data
John Gross - Underground Cable Failures
Julie Lee - Financial Data, Distribution Vegetation Management Analysis
Karen Schuh -Transfer to Plant
Kyia Douglas - Charts & Graphs, Editing and Content Support
Laine Lambarth - Grid Modernization, Editing and Content Review
Larry Lee - Distribution Vegetation Management
Landen Grant- LED Street and Area Lights, Distribution Device Management
Mark Gabert - Wood Pole Management, Wood Pole lnspections and Photos
Marty Gulseth - Underground Cable and Downtown Network Data and Photos
Rob Cloward - GIS lnformation and District Analysis
Rob Gray - Report Editing and Content Review
Rodney Pickett - Wood Pole Management, Transformer and Underground Analysis
Rubal Gill - Budget and Actual Data
Shane Pacini- Grid Modernization, Editing and Content Review
Tyler Dornquast - Reliability Data
Valerie Petty - Distribution Research and Analysis
Lisa [a Bolle - Chief Editor, Research, Drafting, Figures and Graphics, Report Production
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Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 2 of 103
District Descriptions
& Photos:
Chris Schlothauer (Coeur d'Alene)
Chris Sands (St. Maries)
Cesar Godinez (Colville)
Jesse Butler (Kellogg)
Steve Aubuchon (Lewiston/Clarkston)
Elizabeth Frederiksen (Palouse)
Kermit Olson (Spokane)
Kelly Donohue (Davenport)
Frank Binder (Deer Park)
Jeff Schwendener (Grangeville)
lan Eccles (Othello)
Jim Kane (Sandpoint)
Chris Sands (St. Maries)
Reuben Arts (Downtown Network)
Ryan Bradeen (Downtown Network)
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T,ASI-E oF CourENTs
Thanks & Acknowledgements.............. ............. i
Executive Summary .........1
Our Service is Reliable and Cost Effective......
I ncreas ing C ap ital Inves tment s fo r I nfr qs truc ture N eeds..........
Clas sification of Infrostructure Need by " Investment Dr ivers " .............
Currently Planned Investments in Electric Distribution 2017 - 2021....
Customer Requested
Customer Service Quality & Reliability
Mandatory & Compliance
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5
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Performance & Capacity..................
Asset Condition
Failed Plant & Operations.
Introduction ............
Conclusion..
Accountable to Our Customers.............
Prudent lnvestment.
Managing Our Costs
Investments in Electric Distribution Since 2005 ......
Currently Planned Distribution Investments (2017 - 2021) .....
Outlookfor Future Utility Investment Needs.
Overview of Avista's Electric Distribution System. .......18
Overview....... 1B
Colville District 2t
Coeur d'Alene District...... 22
Providing Reliable Electric Service
Historic and Industry Patterns of Overall Investment.......
Kellogg District .............
L ew i st o n- C I arks t on Dis tr ict
Sandpoint District.
Deer Park District
Davenport District......
Grangeville District
Palouse District
Othello District..
St. Maries District..................
10
14
15
..... 17
.............. 23
24
.............. 25
..........,.,. 26
.............. 27
28
29
... 30
...31
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 3 of 103
o Spokane District 32
Spokane Downtown Network......
Planned Spending by Investment Driver
Cus t om er Reques t ed Inv e s tment s
New Service Gonnects
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Investments in Customer Service Quality and Reliability ............
Reliability !nvestments
Evaluation of Reliability Results
Setting Actionable Targets
lnvestments to Uphold Customer Service Quality and Reliability
Mandatory and C ompl ianc e Inv e stment s ...............
Electric Replacement / Re1ocation..................
Washington State Department of Transportation (WSDOT) Franchising
Environmental Compliance
Reliability Strategy
33
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41
43
44
50
50
50
51
5tP erformance and Capacity Investmenls ...........................
Dlstribution Segment Reconductor and Feeder Tie Program ................ ......................52
Avista's LED Street and Area Lighting Program
Investments B qsed on As s et Condition .............
Overview of Asset Management ..................
Asset Management at Avista..
Wood Pole Management...
Distribution Grid Modernization
Distribution Device Management Program...
Replacing Transformers Containing PCBs
Underground Cable Replacement
Underground lnspection Pilot Program ................
Worst Feeders......
Failed Plant and Operations Investments .........
Failed Plant
Emergency Storm Response
Operations Capital
Spokane Electric Network
Conclusion .............. ........ 84
Appendix A: Avista Customer Costs ..............86
Appendix B: Customer Satisfaction.......... .....87
Appendix C: Grid Modernization Benefits... ..................88
Appendix D: Automated Equipment .............95
Exhibit No. 8
Case No. AVU-E-I9-04
H. Rosentrater, Avista
Schedule 1, Page 4 of 103
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55
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64
70
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Cost of Service
o Te,eLE oF Freunes
Figure 1. Aviso Electric System Outages 1_
Figure 2. lnfrastructure lnvestment Demonds 2
Figure j. Notional & Avisto Distribution Cost Per Customer 2
Figure 4. Avisto Copital Cost Per Customer
Figure 5. Avisto Total Copitol Expenditures by lnvestment Driver.... ......................... 3
Figure 6. Totol Annual Electric Customer Connections: Actuol & Projected . .............4
Figure 7. The Averoge Number ond Durotion of Electric System Outoges
...3
Figure 8. Avista's Annual Capital Expenditures, L950 to Present, With Lorge Projects Noted
Figure 9. Avista's Aging lnfrastructure Timeline
Figure 10. National & Avista Transmission & Distribution Copitol Spending
Figure 17. Avista Cost Per Customer Trend Over the Last 30 Years
Figure 1.2. Electric Distribution lnvestments 2005 - 20L6
Figure 13. Notional & Avisto Electric Distribution Copitol Cost Per Customer
Figure 22. Outoge Couses 2001 - Present.......
Figure 23. Outages from Foiled Tronsformers & Cutouts
Figure 25. Outoges Required for Planned Work
Figure 26. Outages Resulting from Failed Poles
Figure 29. Forecost of Optimum Replocement ..................
Figure 30. Wood Pole lnspection Cycle Anolysis
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Figure 14. Average Distribution Expenditures by lnvestment Driver for 2017-2021
Figure L5. Averoge lnfrastructure lnvestment by Driver: 2017-202L
Figure L6. Primory Elements of Avisto's Electric Generotion, Tronsmission ond Distribution iystem.........,... 18
Figure 77. Map of Avista's Service Territory in Washington and ldaho.L9
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Figure 18. Avisto District Office Charocteristics: Customer Count ond Miles of Line
Figure 19. Avisto District Office Choracteristics: Ave. Cust/Mile, # of Feeders, Miles of Line
Figure 20. Avista Electric Customer Connection Requests - Actual & Forecast
Figure 27. Avisto Electric Customer Number of Connections & Cost Per
Figure 24. Squirrel Related Outoges
Figure 27. Distribution Vegetotion Monogement Reloted Outoges
Figure 28. Distribution Vegetotion Monogement Budget Cut lmpocts
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 5 of 103
o Figure 3L. Wood Pole Annuol lnspections..
Figure 32. Wood Pole Feeder Miles Completed 60
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oFigure j3. Wood Pole Monogement Assets Replaced
Figure j4. Wood Pole Age Profile
Figure 35. Wood Pole Age Profile as of 2017
Figure j6. Wood Pole Age Distribution - 2017 ond 2024
Figure j7. Projected Electric Distribution lnvestments
Figure j8. Grid Mod Sustoined Outages
Figure 39. Transformer Replocement Stotus ...
Figure 40. Avista Tronsformer lnventory 2016
Figure 41. Transformer Related Outages......
Figure 42. Avista's Distribution Transformer lnventory Age Profile.
Figure 43. Projected Underground Coble Foilures
Figure 44. Actuol Underground Cable Reloted Outoges
Figure 45. Underground Cable Replacement Progrom
Figure 46. Foiled Plant & Operotions Expenditures
Figure 47. Storm Response Costs
Figure 48. Distribution Spending by lnvestment Driver .....o
T,ABI-E oF TagI-Es
To b I e 1. Av i sto D i str i ct Off ic e Stoti sti cs...............1_9
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Table 2. Forecast Electric Customer Connections
Table j. Distribution Vegetation Manogement Actual ond Budget
Table 4. Distribution Vegetation Manogement Budget Needed to Maintoin Program Schedule
Table 5. Washington AMI Planned Annuol lnvestments..
Table 6. Grid Modernization Planned lnvestments
Toble 7. Required Replocement/Relocation Plonned lnvestments
Table 8. Estimated Washington Dept. of Tronsportotion Required lnvestments
Toble 9. Estimated Environmentol Compliance lnvestments
Table 1-0. Estimoted Segment Reconductor & Feeder Tie Program lnvestments..
Toble 11. Actuol LED Change-Out Program Performonce
Toble L2. Estimated LED Chonge-Out Program lnvestments o
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 6 of 't 03
Toble 1"3. Wood Pole Management Program Actuols.
Table 74. Grid Modernization Budgets ond Actuols 69
Toble 1"5. Distribution Automated Devices Mointenance Budget..... .......................7L
Table L6. Tronsformer Replacement Progrom Requested & Actuols..... ..................72
Toble 17. Underground Cable Replocement Progrom Requested & Actuals 77
Table L8. Underground Equipment lnspection Expenditures 79
Table 1"9. Plonned Distribution lnvestments: Wood Pole, Grid Mod, Underground, PCB Replacement.......... 80
Table 20. Plonned Distribution Progrom lnvestments: Storms, Routine Work, Meters, Downtown Network 84
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Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 7 of 103
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ExgcurrvE Sutw*tanY
Avista Utilities serves approximately 340,000 electric customers in Washington and ldaho over an extensive
electric distribution system that is designed, built, operated and maintained by the Company. This
infrastructure system consists of approximately L9,000 miles of distribution lines, including both overhead
wire, underground cable and service lines, and customers' meters, all interconnected with 133 distribution
substations. Avista must continually make new investments in this system in order to continue providing
our customers with safe and reliable electric service, at a reasonable cost, and with service levels that meet
our customer's expectations for quality and satisfaction.
Oun Senvrce rs RELnBLE AND Cosr Errecrryg
Avista is focused on maintaining a high degree of system reliability as an important aspect of the quality of
our service. Providing a reasonable level of reliability for our customers represents a complex balance of
customer expectations, cost, and system performance. We believe our prior and planned investments in
distribution infrastructure enable the Company to effectively strike this balance and deliver a level of
reliability that is satisfactory to our customers and that represents a cost-effective value. This assessment is
evidenced by our high level of customer satisfaction with their overall service from Avista (which includes
aspects such as electric reliability), by the low number of complaints we receive each year that are related
to reliability issues, and our performance being in a reasonable range for the electric utility industry. The
Company's overall system reliability has been fairly stable, with a slight trend toward improvement since
2005, as shown in Figure 1-.
Average Number of Outages
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Figure 1. Avisa Electric System Outages
I NCNTE.SI NG CAPITAL I T{VESTNA ENTS FOR I N TNASTRUCTURE N EEDS
ln recent years, Avista has experienced an increasing demand for new infrastructure investment. The
pattern of investments made by the Company during this period bear a striking resemblance to that of the
industry, though Avista's investments have increased at a slower pace, as shown below in Figure 2. This
similarity should not be a surprise, since we are all responding to the same investment drivers: the demand
to replace an increasing amount of infrastructure that has reached the end of its useful life, and the need
for reliability and technology investments necessary to build the integrated energy services grid of the
future.
Exhibit No. I
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 8 of '103
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distribution investments
also reflects our adoption of
new asset management-
based approaches for
assessing our infrastructure
needs and developing
strategies and programs to
optimize the lifecycle value
of our system.
Transmission & Distribution Capital Spending 1994 - 2015
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line with that of the electric utility industry, as shown in Figure 3
Avista's investments in electric distribution infrastructure were depressed for an early portion of this period
due to the financial effects of the Western Energy Crisis, as reflected in our below average cost per
customer. Our more recent investments (as described later in this report) pushed our annual per customer
Figure 2. Infrastructure Investment Demands
Source of Notionol Doto: FERC Form 7
1994 1996 1998 2000 2002 200/. 2006 2008 2010 20L2
cost to the national
average and slightly
above; however, our
above-average costs are
largely the result of the
significant spending in
repairing and replacing
equipment damaged by
the windstorm of
November 2015.
Excluding these
significant costs, the
Company's per customer
cost would be essentially
equal to the national
Figure 3. National & Avista Distribution Cost Per Customer average'
Source of National Data: FERC Form L When considering all of
the Company's
infrastructure investments measured across the entirety of our business over the past 65 years, Avista's
capital cost per customer has varied, sometimes substantially, based on the intensity of our historic levels
of investment and the number of customers we served at the time, as shown in Figure 4. Though increased
over the prior decade, our current level of capital spending on a per-customer basis is generally in line with
the trend over the last 30 years.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 9 of 103
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Despite the increased
demand for new investment
in our electric distribution
system, however, our
annual capital costs
expressed on a per-
customer basis are generally in
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Avista Tbtal Annual Capital Cost Per Customer 1950 - 2021
(2O76 Dollars)
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r Actual Annual Spend per Customer TzForecast Annual Spend per Customer
Figure 4. Avista Capital Cost Per Customer
CUSSTICATION OF INFRASTRUCTURE NEED BY "INVESTMENT
DRIvERs,,
As a way to create more clarity around the particular needs being addressed with each investment, as well
as simplifying the organization and understanding of our overall electric distribution plans, the Company
has organized the infrastructure investments described in this report by the classification of need or
"lnvestment Driver". The need for investments associated with each investment driver is briefly defined
below, and in greater detail in the body of this report.
L. Customer Requested - connect new customers or enhance their service as requested.
2. Customer Service Quality & Reliobility - meet our customers' expectations for quality of service and
electric system reliability
3. Mondatory &
Compliance -
compliance with laws,
regulations and
agreements.
4. Performance & Capocity
- ensure our assets
satisfy business needs
and meet performance
standards.
5. Asset Condition - replace
assets at the end of
their useful service life.
6. Foiled Plant &
Operations - replace
failed equipment and
prudently operate our
business.Figure 5. Avista Total Capital Expenditures by Investment Driver
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 10 of 103
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New Service Connects - Since 2005, the Company
has responded to an average of 4,400 requests for a
new electric service connection each year. For the
current five-year planning period, Avista expects to
connect an average of 6,200 new electric customers
each year based on our economic and population
forecasts. At our current and expected unit cost to
connect each new customer, these new connects
will result in an average annual investment of 523.1
million.
CUnnENTLY PI.ANNED INvESTMENTS N ELECTRIc DISTRIBUTIoN
20I7 -20.21
Total Distribution For the current five-year planning horizon Avista expects to spend
SSO:.+ million, allocated across the investment drivers described
above and as shown in Figure 5 above. The planned annual
investments for this period ranges from a low of 573.9 million (in
2021) to a high of 5125.8 million (in 2018), with an annual average of
S100.7 million. Avista's programs for electric distribution
investments are summarized by investment driver below, and are
discussed in detail in the remaining sections of this report.
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Avista Elecfic Customer Connections
Customer Requested
2m5 2m6 2m7 2m8 2m9 2010 2m1 2m2 2m3 20tr4 29t520161017 2m8 20!l) 2020 201
EAdual
-Forsast
Figure 6. Total Annual Electric Customer
Connections: Actual & Proiected
Customer Service Quality & Reliability
Feeder Automotion - Avista considers electric system reliability in nearly all its investment decisions,
however, it does make certain investments solely on the basis of their reliability value. One such effort is
the Company's Feeder Automation Program, which is carried out through our Distribution Grid
Modernization effort. For this planning period, Avista expects to invest an
average of S0.9 million each year to capture reliability benefits through feeder
automation.
Advanced Metering lnfrastructure (AMI) - Avista is in the process of
deploying advanced metering infrastructure (AMl) across its Washington
service territory. This effort keeps pace with the evolving metering standard of
the industry and will deliver a range of cost-effective benefits to our customers.
Among the benefits of advanced metering are tools to help customers better
understand and manage their energy use, notify customers when their energy
use meets predetermined targets the customer has established, enable smart
home options to monitor and control energy use, reduce customer costs by
deterring theft of electricity, eliminate manual reading of meters, reduce
outage time for customers, save energy with more efficient feeder operation,
and improve a range of administrative and back office work processes. The average annual investment for
deployment of advanced metering is approximately S27.1 million.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 11 of 103
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Mandatory & Compliance
Electric Replacement / Relocotion - Avista is required to move its electric distribution infrastructure in
response to municipalities, counties and state-level agency projects to rebuild or realign roads, streets and
highways, and other infrastructure projects. The estimated average
annual investment required to comply with these requirements is
Sz.g miltion.
Washington Deportment of Tronsportdtion (WSDOT)
Franchising - ln a closely related program, Avista works with this
agency to renew and maintain crossing and encroachment permits,
which at times requires the Company to move its distribution
infrastructure at its own expense. The expected average annual
investment related to these activities is S0.2 million.
Environmentol Complionce - The Company must also comply with a range of environmental compliance
rules that will have an expected annual average capital cost of SO.+ million.
Performance & Capacity
Distribution Segment Reconductor ond Feeder Tie Progrom - The infrastructure investments made
under this program remedy the overloading of electric equipment and cable, as well as the conductor sag
that results from overheating of the overhead wirel. These instances of system overloading result from load
growth and shifts in load demand that occur over time on the distribution system. As noted, Avista's
distribution grid contains over 19,000 miles of overhead wires and underground cables.
The Segment Reconductor program targets areas of grid congestion where undersized and overloaded
elements are identified through observation or computer simulation. Avista's internal guide is the
Distribution "500 Amp" System Planning Manual2. This document establishes clear metrics with respect to
system normal and single contingency performance. For example, in urban service areas (e.g. Lewiston-
Clarkston Valley, Coeur d'Alene, Spokane, etc.), distribution circuits are supported via a network of 'feeder
tie switches.' These interconnection points allow for load isolation and restoration during contingency or
planned system outages. Over the next five years, system planners and engineers have identified over 30
reinforcement projects to mitigate thermal overloads and to accommodate load shifting under a variety of
circumstances, including response to system peak loading events. The
planned annual expenditures under this program are levelized at S5.0
million.
Light Emitting Diode (LED) Street and Area Lights - The Company is
replacing all of its street and area lighting with new LED fixtures. ln addition
to providing customers with greater security and safety, the cost of this new
investment is offset by a reduction in long term operating expenses and the
energy savings captured with this highly efficient lighting technology. This
program is slated for completion by year 2021, with an average annual
investment of S1.8 million.
1 When the overhead Wre (conductor) on a distribution feeder is overloaded, the wire overheats and stretches, and in doing so, sags closer to the
ground than designed, which can exceed electric code requiremenls for safety.
2 Available upon request.
Exhibit No. 8
Case No. AVU-E-1 9-04
H. Rosentrater, Avista
Schedule 1, Page 12 ol 103
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Asset Condition
Wood Pole Monogement - Avista has 347 overhead electric feeders that
are supported by approximately 240,000 wood poles. Poles and equipment
comprise the primary infrastructure of the Company's electric distribution
system. Avista's wood pole population is inspected on a 20-year cycle
interval, which means about 12,000 poles are inspected on average each
year. The capital investments made under this program cover the needed
repair and replacement of poles and attached equipment that is identified
during the inspections. The average annual investment planned for this
program is 59.8 million.
Distribution Grid Modernization - Avista is systematically rebuilding and
upgrading its electric distribution feeders, and where cost effective, is
installing feeder automation to improve the reliability of the system. This
program was designed for a 60-year cycle interval and is dovetailed with the
Wood Pole Management program to optimize capital work on our overhead
feeders. While replacing assets at the end of their useful life, Grid Modernization delivers a range of
benefits that include improved reliability, energy conservation, and reduced operating costs. The planned
investments to be made under this program average Sta.0 million annually.
PCB Tronsformer Chonge-Out - The Company is
systematically removing and replacing its aging
fleet of distribution transformers that contain oil
laden with PCBs. This program is planned to be
ramped down by year 2020, when the great
majority of the transformers will have been
exchanged, at which time the remaining
transformers will be replaced under the Wood Pole
Management and Grid Modernization programs.
The planned average annual investment is S1.3
million.
Upgrading the Distribution System in Pullmon
Phys.Org, June 10, 2015, https://phys.org/news/2015-07-nation-
lareest-smart-erid-demo.html
Underground Coble Replacement- Avista
began programmatically replacing its first
generation Underground Residential District
(URD)cable approximately 15 years ago. While
the systematic replacement program has ended,
the Company continues to locate unmapped
sections of this old cable during the course of
each year, typically when the cable has failed. This
program funds the ongoing replacement of
remaining cable on an operational basis. The
average annual investment planned for 2017-2021,
ls So.g million.
replacing-transformers-to-elim inate-pcbs/
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 13 of 103
-T
t F
I
ti
Failed Plant & Operations
Foiled Plant - A portion of our assets in service fail each year due to asset condition and as a result of
damage from storms, vehicle accidents, third-party dig-ins on underground equipment, etc. When this
happens, the Company must quickly respond to replace the failed infrastructure in order to ensure the
continuity of service to our customers. For the current planning period, based on our experience, we expect
to spend an average of 52.2 million each year.
Operotions copitol- ln addition to replacing assets that have failed, Avista's operations staff performs a
wide range of limited capital infrastructure work that does not rise to the level of a project or program.
These investments include the need to reconfigure, replace, repair and/or upgrade electric facilities for a
variety of reasons, including those associated with
customer requests. These improvements are beyond
the tariffed costs for new services, replacement of
equipment based on condition, and ameliorating
system capacity deficiencies. Based on our experience,
annual investments are expected to average 58.9
million.
Spokone Electric Network - Avista operates an
electric distribution system in the core business district
of downtown Spokane. This distribution "network" is
configured as a fully redundant distribution grid that
includes cables encased in concrete reinforced duct
lines and major equipment such as underground
transformers located in concrete vault structures.
Much of this system has reached the end of its useful life
or is near to doing so, with some assets installed over a
century ago. Planned annual investments in this system for
the 2017-2021 time frame are expected to average $2.3
million.
CoNcr-usroN
This report demonstrates that the investments in electric distribution
infrastructure made by the Company over the prior decade were necessary and prudently incurred. The
year-over-year growth in the level of our prior period
investments is not unusual compared with our peers across
the utility industry. Our capital investments on a per-customer
basis are reasonably consistent with the industry, though our
overall average spend has been below the industry average
over the prior 20 years. Our distribution infrastructure
programs have been thoughtfully developed, thoroughly
analyzed and optimized, and adjusted and re-analyzed as
appropriate to ensure that we deliver cost effective value for
our customers. This report also demonstrates that the level of
our investments is somewhat conservative as a result of our
need to balance distribution priorities with our other
infrastructure demands, as well as our effort to manage the impact of these investments on the costs paid
by our customers.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
o
I
I
I\o
o
a
1.,I
A
Schedule 1, Page 14 of 103
--J
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o Provide o comprehensive
summory of the need for
capital investment and the
plan for implementotion;
o Exploin loctors driving
Avista's need for increased
investment over the prior
decade;
c Provide on overview of the
Compony's approoch to
e I ectri c system relio bi lity;
o Simplify the understonding
of the types of needs, or
"investment drivers"
shaping our investment
plon;
o Provide visibility into why
each capitol project ond
progrom is necessary to
meet our electric
distribution system needs,
ond
o Provide a platform for
conti n uous col I o boroti on
with our customers, Energy
and Policy Staff,
Commissioners, and o
range of other
Stakeholders.
Avista Utilities serves approximately 340,000 electric
customers in Washington and ldaho over an extensive
electric distribution system that is designed, built, operated
and maintained by the Company. Avista must continually
invest in its electric distribution system in order to provide
our customers with safe and reliable electric service, at a
reasonable cost, and with service levels that meet their
expectations for quality and satisfaction. This report provides
a summary overview of the Company's recent historic,
current, and planned infrastructure investments in our
electric distribution system for the period 2017 - 2027.
For the purposes ofthis
report we have confined
our discussion of
"i nfrastructu re
investments" to the
physical energy delivery
facilities used to link our
electric substations with
each customer's meter.
These facilities include
overhead (conductor) and
underground (cable) electric lines or "feeders," secondary
transformers, service lines and electric meters.3 We have
also included several operations and maintenance (O&M)
programs such as Vegetation Management that play a key
role in helping us provide safe and reliable service.
o
Collectively, the investments described in this report allow
Avista to effectively respond to customer requests for new
service or service enhancements, meet its regulatory and
other mandatory obligations, replace equipment that is
damaged or fails, support electric operations, address
system performance and capacity issues, and replace
infrastructure at the end of its useful life based on asset
condition. Moreover, the investments described in the plan
are based on what we know about our business today,
including a range of precision in future cost estimates,
applicable laws, regulatory requirements, and the capabilities of current technologies. Though we
frequently report out on many of the individual investment projects and programs that comprise our
overall electric distribution infrastructure plan, we have not previously summarized this information in one
comprehensive report.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
INrnopUCTIoN
3 See Distribution Diagram (Figure 16) on page 18.
Schedule 1, Page 15 of 103
)
i
Report Key
Objectives:
AccoUNTABLE ro Oun CusrorvrERs
Pfudent lnveStment - With each investment, Avista demonstrates that the overall need, evaluations
of alternatives, and the planned timing of implementation is judicious and in our customers' best interest.
Avista believes this report demonstrates that our recent past, current, and planned investments in electric
distribution infrastructure are necessary and prudent, and explains why the failure to make these
investments would impair the performance of our system and harm our ability to deliver safe and reliable
service to our customers. We explain that the investments we make to uphold the current reliability of our
electric distribution system are conservative, thoroughly evaluated, and cost effective for our customers.
We believe the report demonstrates that our distribution investments are needed and necessary in the
timeframes planned in order to prudently conduct our business.
Finally, the report also notes identified and proven needs for
investment that are not fully funded in the current planning cycle in an
effort to balance other priority investment needs.
--ff*r-..-
o
o
Managing Our Costs - With the increasing levels of distribution
and other plant investments made by the Company in recent years, we
have worked to mitigate the cost impact by moving to our present
level of investment more gradually over a period of several years. This
effort often requires Avista to fund programs at less than an optimum
level in an effort to balance the many competing infrastructure needs
we currently face. The Company's efforts to manage the impact of
these increasing infrastructure needs, as well as all other normal
increases in expenses, has allowed us to hold the annual increases in
our customers' electric bill to a reasonable average of 1,.9% over the
past eight years, keeping Avista's electric bills below the national average, below the average for ldaho
(since 2013) and somewhat below the average for electric customers in the state of Washington.a
Providing Reliable Electric Service - Avista is focused on maintaining a high degree of reliability as
an important aspect of the quality of our service, particularly as our society becomes ever more reliant
upon electronic technologies. The Company's objective has been to generally uphold our current level of
reliability, which we believe has been satisfactory to our customers.s Providing a level of system reliability
that is adequate for our customers represents a complex balance of customer expectations, cost, and
performance. Because it is expensive to achieve every new increment of system reliability, and because
these investments must be sustained over a period of many years before the benefit is realized, it is
important to ensure that we are investing only the amount of money it takes to achieve an acceptable level
of performance. Avista believes the current reliability performance of our system effectively achieves this
balance, and represents a cost-effective value for our customers. This assessment is evidenced by our high
level of customer satisfaction with their overall service from Avista (which includes aspects such as electric
reliability), national awards for customer service6, by the low number of complaints we receive each year
that are related to reliability issues, and our performance being in a reasonable range for the electric utility
industry.
a See Appendix A: Avista Customer Costs for a statewide and national customer cost comparison.
5 2016 Avista Service Quality Report Card, Found in Appendix B.
6 Avista has won national awards for customer service, including the Edison Electric lnstitute National Key Accounts Award for Outstanding Customer
Service in 2017 (http://3blmedia.com/News/Avista-Receives-National-Utilitv-Customer-Service-Award) and was rated high byJD Powers in 2016
(http://www.prnewswire.com/news-releases/electric-utility-business-customer-satisfaction+eaches-8-year-high-in-,id-power-study-300203512.htm1)
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule '1 , Page 16 of '103
o
I
o
o
Each year we track and report on how well our system has performed as measured by the number of
service interruptions (electric
outages) and the duration or
length of time of interruptions
that are experienced by our
customers on average. The
Company's annual reliability
performance for the years 2004
through 2016 is shown in Figure
7. Note that we do not directly
measure customer satisfaction
for reliability alone.T
Although our overall reliability
trend is generally stable; the
year-to-year fluctuation in
performance is a common
feature of utility electric
Avista Electric System Reliability
2m4- 2016
250
o
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e
o
ff rsoao
o
't 1m
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o
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oo
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ouo
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1
0.8
0.5
0.4
0.2
0
2m4 2m5 2m5 2m7 2m8 2m9 2010 2011 2012 2073 2074 2075 2075
EAverage Number of 0utages
-Average
Length of Outages (minute$
systems and is the result of Figure 7. The Average Number and Duration of Electric System Outages
factors that can be quite
variable each year and that are largely beyond the control of the Company, such as wind and ice storms,
fires, heavy snowfall, animals, vehicle accidents, etc.8 ln addition to these primary statistics, we report on
several other utility-wide measures of reliability, the geographic areas of greatest reliability concern on our
electric system, and our plans to improve service performance in those areas of greatest concern.
Hlsronrc AND lNousrnv ParrenNs oF Oven^al-L INvESTMENT
Because the Company's annual capital expenditures, including those for electric distribution, have
increased substantially in recent years, we believe it is helpful to provide some context related to Avista's
historic pattern of investment as well as that of the industry in general.
The bulk of Avista and the nation's energy delivery systems were
constructed in the period after World War ll and generally into the
1970s and 1980ss when economic growth and expansion fueled
the demand for new energy infrastructure.lo Nationwide, utility
investment generally slowed during the 1990s. This slowdown was
attributed to several factors, particularly the uncertainty around
disaggregation of vertically-integrated utilities and concerns of
how new plant investment might be treated under the then-
impending federal utility deregulation. Another driver of reduced
spending was the opportunity to take advantage of the robust capacity in distribution, transmission and
generation resources built up in prior decades. By the late 1990s, however, the country's utility industry
recognized the need for increased investment to keep pace with customer growth, replace or rebuild aging
facilities, and to meet increasing customer and regulatory expectations for greater power quality and
7 2016 Avista Service Quality Report Card, Found in Appendix B.
8 The measuring protocol for SAIDI and SAIFI excludes outages caused by very large oulage events such as the windstorm of November 2015.
These major events are refened to a "major event days." Even with these major events excluded, however, we can still experience substantial
variability caused by storms, for example, that do not qualify as major events.
e This cycle of utility investment ended as early as the 1 960s for some utilities and through the early 1980s for others, including Avista.
l0 "Powering a Generation: Power History #3. htto://americanhistorv.si.edu/oowerinq/oasUh2main.htm.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 17 of 103
o
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system reliability. Avista's pattern of overall investment generally follows this national trend, as reflected in
Figure 8.
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5m
4m
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Avista's Annual Capital Expenditures
(in 2O76 dollars)
Iitdc falls.
Saep,
230h1:
OrcpG$FwlBr, ]I6roc
Rcljccnring. H]drc
Rcbuilds, Aldli.l
230k\'TEsi3si6
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1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2m0 200s 2010 2015 2020
IActualE@enditures ..... Fore(astElperditures
-Actnal*of
CustomeE ..... Foccastrof C6tomeE
So
RathdM F..Lr
Figure 8. Avista's Annual Capital Expenditures, L950 to Present With Large Projects Noted
The Company's investments in the 1950s were driven primarily by new generation and transmission
facilities, with more modest growth in electric distribution, office and operations facilities.ll lnvestment
growth in the 1960s and early 1970s was focused primarily on electric and natural gas distribution assets
The surge in infrastructure spending beginning in the late 1970s and continuing into the mid-1980s
supported several new thermal generating resources that included our Kettle Falls station, a share in the
23O kV Transmirsion System 19S1-1959
Satsop nuclear station,12
peaking resources, a share
in Colstrip units 3 and 4,
and associated
transmission in eastern
Montana. The significant
decline in capital spending
experienced by the
Company in the late 1980s
was a direct result of the
financial hardship caused
by the suspension and
termination of the Satsop
projects.
Noxon - 1959
,.+r"+,r* ".9 "te"16"oe"ft"+t *f "".t""r*r"""r."","rdtgtt""t"."e"".F"d$ ".ro.*P
Figure 9. Avista's Aging Infrastructure Timeline
11 Avista'snatural gasoperationscommencedin 1959withitspurchaseoftheSpokaneNatural GasCompany.
12 The Satsop Nuclear Generating Station was the showcase project of the Washington Public Power Supply System's (WPPSS) nuclear program.
Satsop consisted of two developments, abbreviated as WNP-3 and WNP-S. Avista (The Washington Water Power Company) invested
approximately $200 million (nominal) in a 5% share of WNP-3; construction was suspended for this unit in '1983 due to the default on municipal
bonds numbers 5 and 6 by the WPPSS. The plant was approximately 76% complete. The failure of WPPSS to effectively manage cost overruns
and delays and their resulting bond default, coupled with forecasts of load growth for the region that did not materialize, nearly forced the
bankruptcy of the Company.
Exhibit No. I
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 18 of 103
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M ajor Assets Req u i re Sign ifica nt Re i nvestm ent
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o The Company's investments in the 1990s focused on distribution plant additions required to serve new
electric and natural gas customers. Avista, like the broader industry, began to increase its annual
infrastructure investments at the end of the 1990s; however, our
planned increase in spending was disrupted and delayed by the
events associated with the Western Energy Crisis in 2000 and 200113
which had a financial impact on the
Company's ability to acquire capital
on reasonable terms. lnvestment,
while cut sharply, was restored and
then increased to support significant
new transmission and other
investments. Avista's transmission
spending in the period 2OO4-2007
was focused on our 230 kV system,
which after 50 years in service,
combined with issues of regional
congestion, required major re-
investment.
Like the reinvestment in its
230 kV system, the Company
has responded to other
cyclical demands for capital
spending needed to refresh
other major infrastructure
investments, such as those
made in the 1950s, as shown
in Figure 9 above. Examples
include investments required by new
FERC license conditions for our Clark
Fork River hydroelectric projects,
Cabinet Gorge and Noxon Rapids, as
well as the overhaul of the major assets
at these plants. Other significant
reinvestments include the 230 kV transmission system (already noted above)
and our central operating facilities in Spokane.
ln more recent years, Avista, like the industry in general, has made cost-effective investments in smart grid
systems and technologies designed to improve the reliability and resilience of our distribution system. The
Company also invested in early asset management initiatives such as vegetation management and wood
pole replacement. Other examples of investments made during this period are shown in the text box above.
The increasing demand for infrastructure investment experienced by the Company over the prior decade is
essentially in step with the situation across the industry, as shown in the example for electric transmission
and distribution investments in Figure L0.
13 Referred to as the "Western Energy Crisis," this period of time was characterized by an electricity demand and supply gap created by energy
companies, mainly Enron, to create an artificial shortage. Energy traders took power plants offline for maintenance in days of peak demand to
increase the price. Traders were thus able to sell power at premium prices, sometimes up to a factor of 20 times its normal value.
https://en.wikipedia.org/wiki/California_electricity_crisis#Some_key_events
Exhibit No. I
Case No. AVU-E-'|9-04
H. Rosentrater, Avista
Schedule 1, Page 19 of 103
o
. Vegetation
Managernent
r Wood Pole
Managenrent
r First Generation
Underground Electric
Cable
o Priority Aldyl A Pipe
Replacer.nent
r Neu,License
Conditions fbr
Spokane River Hydro
Projects
. Major Hydro Pro.lect
Redevelopment
o Ever-increasing
Complexities of
Information
Technology Systems
. Rapidly Evolving
Technology
Platforms
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Some Recent
lnvestment
Requirements
The pattern of
investments made
by the Company
during this period
bear a striking
resemblance to that
of the industry,
which should not be
a surprise (as was
previously
mentioned)since
we are all
responding to the
same investment
needs. First, the
need to replace an
increasing amount of
"lndustry-wide capex has
more than doubled since
2005... 757% {reater
than the investments
nade in 2004. fhe 2016
projections, if realized,
will be a new high for this
indastry.'
2015 Financial Review:
Annual Report of the U.S.
lnvestor-Owned Electric
Utility lndustry, Edison
E lectric I nstitute
Avisn Total Annual Capital Cost Per Customer 1950 - 2021
(2016 Dollors)
IliltlHt tlltill
Transmission & Distribution Capital Spending
(in 2016 Doildrs)
s1,0mSso,mo
S45,mo
^ s4o,mo
€ S3s,mo
i=s*,'o
$soo
Saoo
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Ssoo
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o
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S1s,mo
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Ss,om
So
o
z
L994 1996 1998 2m0 2fi2 20n4 2m6 2m8 2010 2072 2014
Fe National Spending .*.-Avista SpendinB
Figure L0. National & Avista Transmission & Distribution Capital Spending
Source of Notionol Doto: FERC Form 7
o
o
infrastructure that has reached
the end of its useful life, and second, responding to the need for reliability and technology investments
required to build the integrated energy services grid of the future.
With the increasing levels of investment made by the Company in recent years, Avista has worked to
manage the annual price impact to our customers by moving to our present level of investment more
gradually. But more important than the total amount of the infrastructure investment we make each year is
the annual investment divided by our total number of customers, or the 'capital cost per customer.' Over
the past 65 years Avista's capital cost per customer has varied, sometimes significantly, based on the
amount of our historic levels of investment and the number of customers we served. As shown in Figure 11,
our current level of capital spending on a per-customer basis is generally in line with our trend over the
prior 3O-years, which has remained fairly stable.
gsm
s3,ooo
s2,sm
s2,0m
0,
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U
0,o
8 Slsm
a)
CC s10m
Ssoo
so
1950 1955 1950 1955 1970 1975 1980 1985 1990 1995 2m0 2005 2010 2015 2020
I Actual An nual Spend per Customer *l Forecast Annual Spend per Customer
Figure LL. Avista Cost Per Customer Trend Over the Last 30 Years
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 20 of 1 03
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The Company increased its annual capital spending over this period in direct
response to the growing need for new investment. This increasing need
included a modest increase in the number of new customers connected
each year. The principal driver has been the Company's adoption of new
asset management-based approaches for assessing our infrastructure needs
and developing strategies to optimize the maintenance of our electric
distribution system. Referred to "Asset Maintenance Programs," these
annual investments have increased from about 52 million in year 2005 to
over S20 million today.
Many of these programs are driven by reliability and customer service, such
as the Grid Modernization ("Smart Grid"), Wood Pole Management, and
Underground Residential District (URD) Cable Replacement Programsla
which overhaul aging equipment and help reduce the number and length of
outages.ls Others include safety and environmental stewardship such as the
PCB Transformer Change-Out Program, while others provide energy
efficiency and cost savings for customers, such as the Street Light/LED
Lighting Replacement Program.16 The pattern of investments for these five
programs, for the period 2005 - 20L6 is shown in Figure 12.
Each of these infrastructure programs is discussed in detail in the remaining
sections of this report. This discussion illustrates the need for these
investments, and identifies the consequences to our system and our ability
Avisto "Smo rt" Tran sforme r
Annual InAaskucture Investments in Eleckic Distribution
(Replace Deteriorated Assets, Remove PCB,, Achieve Energy Efficiency)
c.q
E
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c
EaoU'6
=cc
S30
S2s
S20
S1s
S10
5s
So
2005 2@5 2@7 2m8 2@9 2010 2011 2072 20L3 20t4 2015 2016
r LED Lighting I UnderBround Cable a:: Grid Modernization r PCB Transformers r Wood Pole
Figure 12. Electric Distribution Investments 2005 - 20L6
1a Wood Pole Replacement identifles and replaces structures likely to fail; the Underground Cable Replacement Program is replacing all
underground cable installed prior to 1 982, which has a high probability of faulting due to a lack of external jacket to protect the cable from damage
or stray voltage.
1s Smart Grid/Grid Modernization uses automated equipment on the feeder, such as reclosers, along with communication devices and an integrated
distribution management system application, to quickly assess how to isolate the particular section of the feeder where the outage has occurred,
and to reconfigure the feeder system in a manner that allows us to reconnect customers quickly beyond the isolated section of the feeder.
16 Light Emitting Diode ("LED") lighting is super energy efficient, using approximately 80% less energy than High Pressure Sodium lamps, which are
common throughout Avista's service territory.
to deliver safe, reliable
and cost effective service
to our customers if these
investments are not
made in a timely manner
by the Company.
Similar to the overall
pattern of investment, as
shown above in Figure 10
on page 13, the
Company's annual
distribution investments
have been in step with
those of other electric
utilities on a cost per
customer basis.
Exhibit No. 8
Case No. AVU-E-'l9-04
H. Rosentrater, Avista
Schedule 1, Page 21 of 1O3
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Distribution Capital Cost Per Customer
NationalMaximum
Clst per
Nation!l
Coit per Customer Wthout thr "Big
Storm'
2m0 2001 2m2 2@3 2@4 2m5 2006 2@7 2@8 2m9 2010 2011 2012 2013 2014 2015
- -.Avista Distr Cost Per Customer..... I Avista 2015 Without "8iB Storm' Cost
Figure 13 shows the
annual average electric
distribution capital cost
per customer for all
FERC-regulated electric
utilities, as well as the
Company's annual
capital cost per
customer. This chart
shows the maximum
and the average annual
distribution capital cost
per customer for this
national group as
compared to Avista's
distribution
expenditures over the
same time period.
o
5o
-
Max Distr. Cost Per Customer
Natioflal Distr. Ave Cost Per Customer
Figure L3. National & Avista Electric Distribution Capital Cost Per Customer
Source of Notiondl Doto: FERC Form 7
Avista's expenditures tracked the industry average in the late 1990s and then fell well below the average,
when the Company's investments in electric distribution infrastructure were depressed during and
following the Western Energy Crisis, as reflected in our below
average cost per customer. Our need for much greater
investment following this period, as described above, pushed
our per customer cost above the national average in2OO7.
However, our costs have generally converged with the industry
group average since 2012 (and would be equal to the national
average in 2015 as well, if the costs of the "Big Storm" are
removed, as shown by the dotted line in the chart above).
Avista's average capital cost per customer for investments in
electric distribution has been slightly below the average for this utility group over the prior 15+ years
CUNNENTLY PI-ANNED DISTNTSUTION INVESTMENTS (2O t 7 - 2O2I)
Over the next five years Avista
expects to invest an average of
$tot million annually in its electric
distribution system across its six
investment drivers, as shown in
Figure 14. The average investment
by driver for this period is shown in
Figure 15. Detail on the projects
and programs that comprise the
Company's electric distribution
investments for the next five years
are provided for each investment
driver in the following sections of
this report.M.nd.tory & compli.ncq 916.8M
Figure 14. Average Distribution Expenditures by Investment Driver for 2017-202L
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 22of 103
o
o
The massive windstorm that Avista
experienced in November 2075 caused
nearly $23 million in damage to our
equipment and affected over 18Q000
customers for nearly two weeks, the
worst storm in our history.
November 17,2015
Pedormance& // I
capacity,514.3M/ I--..----L
tbilcd Plint &
Operation5,
$58.6M
customer
Requested,
9r15.7M
customer sewice
qual;ty &
Reliability,
s139.9M
Cost pff
oott.d LincCustomer
Asset Condition,
$1,t8.2M
o
o
Electric Distribution Infrastructure Expenditures by Year and Investment Driver
S14o
Suo
Sloo
S80
S60
S40
S20
So
20!7 2078 2079 2020
Performance and Capacity
Mandatory and Compliance
Customer Requested
202L
r Customer Service Quality and Reliability
r Asset Conditionr Failed Plant and operations
Figure 15. Average Infrastructure Investment by Driver: 20L7-2021
The individual investments included in Avista's Distribution lnfrastructure Plan represent a portfolio of
projects and funding levels intended to optimize:
L) The overoll demand for distribution investment,
2) The specific requirements of the projects ond progroms proposed for funding, dnd the potentiol
consequences ossocidted with deferring needed investments, ond
3) A balance among the needs ond priorities of all investment requests ocross the enterprise, ond the
Compony's investment planning principles.rT
The result demonstrates a reasonable balance among competing needs required to maintain the
performance of our systems, as well as our prudent management of the overall enterprise in the best
interest of our customers.
Because of the time horizon over which the Company
must budget its infrastructure investments, there are
inevitable changes in the actual projects funded,
program budgets, and implementation timing. Such
changes may be due to changes in project scope,
changing material or resource costs, changing
customer needs, or a more refined estimate based on
where the project is in its development planning.
External factors, such as new regulatory or legislative
requirements, also drive changes in the plan and
budget. The projects in the Company's portfolio are
continuously reviewed for changes in assumptions,
constraints, project delays, accelerations, weather
impacts, outage coordination,
permitting/licensing/agency approvals, and system operations, performance, safety, and customer-driven
17 ln setting its overall infrastructure spending limits, the Company considers a range of factors referred as "key planning principles."
Exhibit No. 8
Case No. AVU-E-1 9-04
H. Rosentrater, Avista
Schedule 1, Page 23of 103
o
Compliance
Avoid
Lumpiness
Constrain
Spending
Asset
Ob,jectives
0ptimize
Resources
Planning
Principles
Cost to
CustomeB
Cost of Debt
& Equity
lnvestment
Need
br---
s23
s24 523
s23
523
s26
s2ss2s
s2s
527
Safety
Reliability
Service
Retain
Flexibility
needs that arise. The portfolio will be continually updated throughout the year to remain as accurate as
possible. As the Company continues to refresh its infrastructure plan going forward, it will net out
currently-funded projects slated for completion in the five-year plan, in conjunction with including new
incremental needs for investment as we continue to forecast our long-term need for capital.
OUTIOOK FOR FtM.INg UTILITY INVESUTAENT NEEDS
Though utilities across the country, including Avista, have increased investment levels in transmission and
distribution infrastructure in the past L0 years, there remains a demand for new incremental spending well
into the future. The American Society of Civil Engineers in 2011
conducted an extensive review of then-current trends in electric utility
investments, and identified a S37 billion "investment gap" between
those current plans and the infrastructure investments needed by year
202O.rB Their report on electric infrastructure was updated in 2016,
noting the significont increosed investment thot hod been mode by the
industry compared with the 2011 forecast of planned investments, but it
still identified an Stg billion investment gap between current spending
plans and the investments that will be needed by year 2025. The report
noted that 54% of the StS billion gap was attributed to the needs of
electric distribution systems alone.le
Though the Company has raised its annual capital investments over the
prior decade to the current plan of S+OS million, we continue to have
infrastructure needs that have not been fully funded. For example, the
Company's Wood Pole Management
Program initially targeted an inspectio n Adding Grid Modernization
cycle time of 20 years.2o Though we have Technology to o Feeder
remained on track with the 20-year
inspection cycle, the follow-up work to perform needed repairs and
replacements identified during the inspection needs additional funding to
remain on schedule. ln addition to the incremental investment needed for
existing follow-up work, Avista's forecast of the number of poles that will
need to be replaced each year shows a steady increase over the next 20
years, as is discussed in detail in the Wood Pole Management section of
this report (page 57). The increasing number of poles and attached
equipment that need to be replaced each year will drive an additional need
for new investment.
o
o
o
Stubbing a pole can odd an
odditionol 20 years or so to
the life of o pole
Other examples where the Company will have to increase the level of its
current investments include our Grid Modernization Program to rebuild
electric distribution feeders at the end of useful life,21 and ongoing effort to
correct reliability issues causing some customers to experience several
times the annual outage rate experienced by our average customer.
18 Failure to Act. The Economic lmpact of Current lnvestment Trends in Electricity lnfrastructure. American Society of Civil Engineers. 2011,
htto://www.infrastructurereoortcard.orq/wp-contenUuploads/201 6/1 0/ASCE-Failure-to-Act2016-FlNAL.odf, page 1 6.
1e lbid., pages 16 and 17.
20 ln a 20-year cycle, the inspection / replacement activities would cover all of the wood poles in the Company's system, or approximately 240,000
poles.
21 This effort includes the Company's 'grid modernization" and "worst feeders" programs.
Exhibit No. 8
Case No. AVU-E-1 9-04
H. Rosentrater, Avista
Schedule '1, Page 24 of 103
J
B
Itt{Il.l
t,
o
Ovenvrew
Avista operates over 19,000 miles of distribution lines, including both overhead wire and underground
cable systems, interconnected with L33 distribution substations22 in the portion of our system depicted in
Figure 16 below:
Distributio! System
utltt
r!4 IR XSfOtiltI
IR IS,lllSOX
M3T mr
ITIID
*nr4cl urE
IR r$ontrln
Figure L6. Primary Elements of Avista's Electric Generation, Transmission and Distribution System.
Though the bulk of our electric lines (or feeders) are concentrated in urban areas including Spokane, Coeur
d'Alene, Moscow, Pullman, Lewiston and Clarkston, we also serve many rural towns, mining districts and
agricultural and forest areas. Far from being homogenous, Avista's electric distribution system is composed
of a wide range of equipment and diverse operating conditions, and is managed in 12 geographic units or
'operating districts'
in Eastern
Washington and
Northern ldaho.
These districts are
shown below in the
map in Figure 17.
Each operating
district has its own
unique characteristics and associated challenges, including
heavily forested areas, steep mountainous terrain, dense and
very sparse customer numbers, diversity in the size of
customers, exposure to wildfire risk, and ease of accessibility
for crews and equipment. Some of the key characteristics of
each operating district are shown in Table 1.
Distribution Line destroyed by wildfire
22 Though interconnected with electdc distribution feeders, substations are not considered part of the distribution system for the purposes of this
plan and report.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 25 of 103
uiEmno(n|0
o
IaIa
I
II
I
r,,1,,1,, r
II!t
AVISI'A'S D ISTR I B UTIO N SYSTE M
Electric Substatirrs
Ouerhead Lines
U nderground E le+trk {a bles
Serviffi tines
133
7,685 Miks
427l Mihs
6,970 Mihs
o
Ougnwgw OF AVISTA,S ETECTRTC DTsrnnUTIoN Sysrxm
EltrMAICUSIOMTRS
I
.';l
,r' . .#1
o
La Grande.
District 0lfices
Coeur d'Alene - CDC
Colville - C0C
Davenport - 0AC
Deer Park - DPC
Grangeville - G RC
Kellogg - KEC
n Hot
O Lewis-Clark-LCC
a 0thello - oTCO Palouse-PAC
I :l.*::*::t?
Gounties
-WA
ID
rGolde
son
Figure 17. Map of Avista's Seruice Territory in Washington and ldaho o
Exhibit No. I
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 26 of 1 03
District Office:
Coeur d'Alene 530.7 609.0 55,136 13 48.4 38 9,468 23,148
Colville 152r.7 999.6 19,681 7 7,8 26 8,956 23,250
Davenport 541.6 87.6 5,941 4 9,4 13 3,935 71,720
Deer Park 320.9 248.8 10,934 0 t9.2 9 3,025 8,069
Grangeville 474.5 216.9 10,106 72 74.6 22 4,495 9,648
Kellogg 293.0 rn.t 9,834 13 22.1 19 3,353 7,637
Lewis-Clark 390.2 143.0 29,6L5 24 55.5 28 7,676 13,000
0thello 397.5 60.4 7,008 5 15.3 15 3,629 &011
Palouse 1029,5 393.2 40,486 t7 28,4 46 9,381.22,094
Sandpoint 422.2 243,3 74,993 2 22.5 17 4963 LL,902
Spokane 1535,4 835.2 I77,3U 55 72.3 116 28,112 59,536
St. Maries 4 2,159 4,818223.8 136.5 4,575 2 72.7
Overhead
Circuit Miles
Underground
Circuit Miles
Elec.
Customer
Meter Count
Customers
#Primary perCircuit Numberof Numberof Numberof
Meters Mile Feeders Transformers Structures
Toble 7. Avista District Office Stotistics
o
Washington and ldaho Service Territory by District
TEGEND
SDO
a
Grangeville
HO
as of 09/10/2017
Avista District Office Characteristics:
Ave. Cust/Mile, # Feeders, Mile of Line
140
o 12Oo!Erm
EEao
o860o
!ao
o:l 20 l JroEil
300
2500
2@O
1500
1@O
5@
0
oc
=c.F-o
.!o
o
3
0 I E G
-o"o ""$;*"t*.*""':""."to .""-:J 6N **"'o"C o*""*sg
IAve # Customers per Circuit Mile E# of Feeders Miles of Dist. Line
o
o
Figure 18. Avista District Office Characteristics: Customer Count and Miles of Line
The more striking difference
between these districts, however, is
in the number of feeders that
comprise the total miles of line:
Spokane - L'J.6, and Colville - 26. This
difference means that the average
customer in Spokane is connected to
a feeder that is just over 20 miles in
length, while the average Colville
customer is connected to a feeder
that is 97 miles in length. Since the
length of the feeder is one measure
of the exposure of customers to a
service outage, one can easily see
how the operating conditions among
our districts can vary widely. A brief
Some of the key differences
among the statistics for these
districts are shown in Figures
18 and 19. For example, the
Colville and Spokane districts
have nearly the same
numbers of miles of overhead
feeder line, but Colville has a
greater number of overall
feeder miles when
underground facilities are
included. While Spokane has
over 170,000 customer
meters and approximately 72
customers per mile of line,
Colville has just under 20,000
electric meters and just under
8 customers per mile.
Figure 19. Avista District Office Characteristics: Ave.
Cust/Mile # of Feeders, Miles of Linedescription, written by the Districts themselves, of the
characteristics of each operating district is provided below
Right: Linemen in
Spokane working on
congested lines
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 27 ol 103
Avista District Office Characteristics: Customer Count & Miles of Line
180 Greo E
14o 3t120 -
1oo t
80 o
605
40d
o20+
3
o
fE
o
1,800
1,600
1,400
1,200
1,000
8@
5m
400
2m
o
..ono".-'*"o"i*"')"C-..,1".u*t""**-""*.ttt'.r''.rrJ
IOverhead Circuit Miles ii=Underground Circuit Miles
-Elec.
Customer Meter Count
o
{
Left: Windstorm Rolling
into Richlond, WA
(Picture by Skyking3286 ot
Kodlec Hospitol in Richlond
t.
I
Cot-vtt-lE DIsrRIcr
Avista's Colville service territory is one of the
company's largest at approximately 2,400
square miles, serving
about 20,000 electric
customers. lt is also the
most rural, with an
average of only 7.8
customers per circuit mile,
the lowest average in the
Company. However,
Colville also has more
underground circuit miles
(999.6 miles) than our largest operating district
(Spokane) and almost identical amounts of overhead circuit miles (152L.7 miles). They are also responsible
for 61 miles of electric transmission line and a high pressure natural gas line (as well as the associated
regulator stations) starting north of Deer Lake and ending in Kettle Falls. This huge area is served by two
electric line crews, two servicemen, and five local representatives plus one gas local representative and a
four man gas contract crew, all supported by a staff of six.
This Office maintains some of the Company's most geographically challenging terrain. They serve extremely
remote locations as well as heavy timber, mountains, rivers, canyons, marshes and swamps, farmland and
pastures. Though often stretched thin by the vast geographical service territory and the amount of
infrastructure that it contains, this office always finds time to volunteer in their community, serving on the
Colville City Council, Rotary, Lions Club, Kiwanis, and
other civic organizations.
Above: Restoring power a woshout. Right: Wind storm damage
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 'l , Page 28 of 103
o
o
Colville
t52t.7 999.6
Number
Customers Number of Number of
Per Mile Feeders Transformers
Number of
Structures
Overhead
Circuit Miles
Underground
Circuit Miles
Customer
Count
Number
Primary
Meters
o
-1.
s
19,674 7 7.8 26 8.955 23,250
CoTun o,ALENE DISTRICT
The Coeur d'Alene Operating District
encompasses over 1,000 square miles of
Kootenai County, ldaho, made up of both
urban and rural landscapes and geography,
r]rvr rr L
lene
from city regions to mountainous and heavily
timbered areas. This Office provides power to
over. 55,000
customers
1 085 sq
(at about 48 Overhead distribution work
customers per
mile) in urban areas including Coeur d'Alene, Post Falls, and Hayden, to
more rural areas in Rathdrum, Spirit Lake, Lake View, and most of the
Coeur d'Alene Lake area. They support and maintain approximately 531
overhead distribution circuit miles and 609 underground distribution
circuit miles as well as L4 substations that connect 38 feeders. The
District is also responsible for 156 miles of 115 kV and 230 kV
. "'s-, transmission circuit. The office is comprised of four line crews and four
line serviceman who are faced with challenges including snow, ice and
heavy winds
Transmission
line repair in
Coeur d'Alene
District
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
609.0
Coeur d'Alene
s30.7 48.4 9,468 23,748
Number
Customers Number of Number of
Per Mile Feeders Transformers
Number of
Structures
Overhead
Circuit Miles
Underground
Circuit Miles
Customer
Count
Number
Primary
Meters
Schedule '1 , Page 29 of 103
t
f
&.
I
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f;:
55. L23 13 38
KELLOGG DISTRICT
The Kellogg office serves all of the Silver Valley, which has a long and rich mining history. ln the 1970s, half
of the world's silver came from mines located in this valley. ln fact, the Galena and Lucky Friday mines are
two of the largest customers served by the Kellogg office. These mines require
an immense amount of power to pump air in and pump water out of the
mines. The office also serves other large customers, including two major ski
resorts.
The Kellogg District covers over 1,200
square miles, starting at the top of 4th
ofJuly Pass and extending east to the
Montana border. lts northern reach is
just past Murray, ldaho and it runs
south to Medimont, ldaho. The
majority of this territory is
mountainous, heavily timbered, rugged
and extremely difficult to
access. There are 11 employees in the Kellogg office serving approximately 10,000 electric and 6,000
natural gas customers in small towns including: Cataldo, Kingston, Pinehurst, Smelterville, Kellogg, Osburn,
Silverton, Wallace, Mullan, Prichard and Murray. This office is also responsible for approximately 154 miles
of electric transmission lines, 421 miles of electric distribution
and 230 miles of
naturalgas pipeline.
The topography,
weather and remote !
location of the
infrastructure in this
area requires
employees to access
and work on many
structures without
the use of bucket or
line trucks;
frequently, isolated
transmission lines
o
o
Over 1-1-4 averoge inches of snow per yeor
is just one of the challenges faced by the
Kellogg office.
require the use of a helicopter to patrol and access the lines when
the lights go out. The Coeur d'Alene River and its tributaries flood
annually, which also creates many challenges. Wildlife, specifically elk and deer, are a constant presence and
hazard while driving in the winter. Some of the towns served are above 3000' elevation and receive a
substantial amount of snow, an average of 1,14 inches per year in some locations, presenting additional
complications.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 30 of 1 03
Kellogg
Number
Customers Number of Number of
Per Mile Feeders Transformers
Number of
Structu res
Overhead
Circuit Miles
Undergrou nd
Circuit Miles
Customer
Count
Number
Primary
Meters
o
?
rrgE
I
:..
6 r.
,rF
t
L
3,353 7,637293.0 140.1 9,821 13 22.7 19
o LewrsroN€le.nxsroN D r srnrct
The Clarkston Office is situated in the
"Banana Belt" of
the Lewis-Clark
Valley, serving
nearly 30,000
electric and
natural gas
customers. This
District is made up
of two Electric Crews, one Natural Gas
Crew, a combination crew, and four
Servicemen, plus a support staff of six.
This group is responsible for
maintenance and construction of
the electric and natural gas
operations in Washington and
ldaho as well as over 120 miles of
transmission systems spanning
ldaho, Washington, and Oregon.
The Clarkston crews provide and
support service under varied and
diverse conditions, from urban to
rural, wildfires to heavy snowfall.
Their territory includes extreme
back country which requires
Snow Cats, ATV's and helicopters
to access their lines and
C
rel
O
Springtime high above the Snake River equipment. Due to the
size and
complexity of their service territory, they often
partner with the Palouse and Grangeville Districts on
large-scale projects and outages, resulting in more
rapid restoration of service to customers. This group
is also very community minded; they are famous in
the area for their participation in local events and
civic organizations.
Right: Building an occess rood to
reoch downed lines in the winter
Above: Typicol tronsmission right-of-woy
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 31 of 1 03
Lewiston &
Clarkston
390.2 143.O 29,s91,55.5
Number
Customers Number of Number of
Per Mile Feeders Transformers
Number of
Structu res
Overhead
Circuit Miles
Underground
Circuit Miles
Customer
Count
Number
Primary
Meterso
c
flqrl-,,HriiiinVtfit,,rr,.. l. , *'
qr, r
I
I'
"1"
24 28 7,676 13,000
Se.NpporNt Drstnrcr
The Sandpoint Operations staff (approximately 20 employees)
serve roughly 24,000 electric and natural gas customers in 14
small towns that are nestled
deep in the mountains of
North ldaho and Western
Montana. Sandpoint's
service area includes some
of our Company's most
northern communities, with
service territory stretching to within 20 miles of the Canadian
border. This team maintains over 160 miles of distribution and
transmission lines; the Company's two largest hydroelectric
generating stations are also within their area of support.
Sandpoint has the highest average snowfall of all Avista's
service territory and is located at the bottom of Schweitzer
Mountain. Along with the beauty of rugged mountains
and plentiful lakes and rivers comes challenges for
accessing power lines and natural gas facilities. During
winter months much of the transmission in this District
is only accessible by helicopter or by hiking in with
snowshoes, especially along the extreme rugged cliffs
that border Lake Pend Oreille. Winter storms can bring
with them large scale power outages. For a 2015
windstorm, Sandpoint called in 32 crews to help
restore service following a major outage.
Perhaps the most challenging environmental condition
this office regularly faces is water. A tremendous
amount of sloughs and swamps surround many of the
Snow in Sandpoint
lakes and
rivers, and
flooding is
often an
issue. These crews also support a major transmission line that
runs into Montana, crossing the Clark Fork River 15 times. The
Clark Fork often floods in the spring, and at times conditions are
so treacherous that crews cannot even reach downed lines by
boat. There are many areas in this operating district that are only
accessible during a three month period between July and
September.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 32 of 103
o
Above:
accessing
poles on o
mountointop
Lefi: repoiring
o tronsmission
structure ot
Noxon Ropids
Dam
o
oSandpoint
t722.5 ,902243.3 ,953991 2
Overhead
Circuit Miles
Custome r
Count
Number Number
Primary Customers Numberof Numberof
Meters Per Mile Feeders Transformers
Number of
Structu res
Underground
Circuit Miles
I,rL-,
*tr
.I
,!
-!
I a
422.2
o
o
DEER PA.NX DISTNICT
Located just north of Spokane, Deer Park is a
historical sawmill
town. At its peak, the
town had as many as
eight sawmills in
operation, the lumber
from which was used
to help rebuild Spokane after the great fire of
1889. The Deer Park District Office
encompasses several towns including Loon
Lake, Deer Lake, Clayton, Deer Park, Elk,
Chattaroy, Colbert and the North Mead area.
It's ten employees serve approximately
L1,000 electric and 5,100 gas customers, and
sustain and support approximately 50 miles of
transmission, 420 miles of distribution and 330 Deer Pork Crew repairing tronsmission
miles of natural gas lines. The Kettle Falls High Pressure Gas Transmission Line runs through the Deer Park
District from North Spokane to our Kettle Falls Generation plant, and this team (in combination with the
Spokane Crew) helps manage the associated regulator stations and farm taps.
The area they serve is heavily treed, especially around the lakes, and is rugged and extremely difficult to
access, including no truck access at all in some areas, requiring occasional use of helicopters. Wildlife
challenges include bear, cougar, elk, deer and moose. Being
located in the snow-belt creates additional difficulties
during the winter months, and spring runoff often makes
the ground unstable for the trucks. Some outages and
repairs require
line crews to
access facilities
on foot.
Deer Park
employees are
also active in the
communities
they serve,
including City
Upgroding Distribution Council, Chamber,
Rotary, Settlers Day Parade, Kiwanis, Christmas Lighting
celebrations, food banks and other civic organizations. They are
building a new service center starting in 2O\7 which should be
completed in the spring of 201"8.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule '1 , Page 33 of 103
Working on o substation issue
O
Deer Park
320.9 248.8 19.2 9 069934 0
Number
Customers Number of Number of
Per Mile Feeders Transformers
Number of
Structures
Overhead
Circuit Miles
Customer
Count
Number
Primary
Meters
Unde rground
Circuit Miles
3,02s
I
I
E
D^evgr.IpoRT DISTRIcT
The nine-person Davenport District Office is a
microcosm of Avista's
rural service territory. lt
encompasses heavily
timbered areas,
sagebrush desert, and
extensive farmland; it
includes approximately
6,000 electric and natural gas customers in many small
towns, including the Spokane Reservation in Wellpinit,
Ford, Almira, Creston,
Edwall, Fruitland,
Harrington, Hunters,
Odessa, Reardan,
Springdale, and Wilbur,
with an average of only 9.4
customers per mile of
feeder. At approximately
1,000 square miles, the
Davenport four man crew
has to cover a lot of
ground. ln addition, they
are responsible for
maintaining two 1L5 kV
transmission lines that
were built in 1924 and
1962, about 80 miles long
Above ond below: The Davenport crew monoging
equipment ond restoring service through
wildfires ond floods
Left: Crews work diligently during a snow storm
to restore power.
Photo courtesy of lnfinity Rose Photogrophy
https ://www. facebook.com./Infi nityRosePhotography/
____.-__!i_
o
o
o
.\
each, and which require frequent repairs in orderto maintain service. Davenport's territory is troubled by
yearly wildfires which have occasionally destroyed significant segments of these lines in the summer, and by
heavy frost/fog ice loading which causes multiple outages every winter. The size of this territory and its
diverse topography can cause longer than average outages due to travel time, rough terrain, and cross
country power lines.
Almiro, Woshington - Kori McKoy Photogrophy, http://www.olmirowoshington.com/
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 34 of '103
Davenport
547.6
Overhead
Circuit Miles
Underground
Circuit Miles
Customer
Count
Number Number
Primary Customers Numberof Numberof
Meters Per Mile Feeders Transformers
Number of
Structu re s
I it
=l
"!-i[D
,
I
,e
It
I
t
w
87.6 5.937 4 9.4 13 3.935 11..720
o
o
G na.r.IeEuLLE DISTRICT
The Grangeville service territory is comprised of approximately 10,000 customers spread over l-,000 square
miles, overseen by nine field personnel. This territory includes regions such as
Elk City, Cottonwood, Orofino, Pierce, Kamiah, Nez Perce and Winchester. ln
some of these areas the transmission and distribution lines run through
rugged terrain, heavily treed with little or no access by truck even in summer
months. During the winter, these regions are buried under feet of snow and
ice, which can require extraordinary efforts to restore power to customers
during outage situations. This region is also home to rich farmland, creating
unique challenges during the wet season in accessing structures without
harming landowner's
crops or property. The
diverse terrain of this
area creates risks and a
wide range of hazards in
maintaining and
restoring service.
Grongeville is home to some of the areo's most productive formland
G ro n gevi I le District terrai n
G ro ngevi I le's terroi n p resents some
major chollenges. At times helicopters
must be used to occess lines.
Exhibit No. 8
Case No. AVU-E-I9-04
H. Rosentrater, Avista
Schedule 1 , Page 35 of '103
Grangeville
474.5 2t6.9 14.6 4,495 9,ils
Number
Customers Number of Number of
Per Mile Feeders Transformers
Number of
Structu res
Overhead
Circuit Miles
Underground
Circuit Miles
Customer
Count
Number
Prlmary
Meterso
{I'ln!filll.
I\
l
-airr,&i&r"Id*.rl.&/4idi.@
{,
a
I
J',
10.094 t2 22
PeTousE DISTRIcT
The Palouse Construction District Office has
approximately 30 employees and is located between
Pullm WA and Moscow, lD. The District covers around
5,000 square miles and serves
nearly 41,000 natural gas and
electric customers. This group is
made up of two electric crews,
one natural gas crew, two
electric serviceman, two gas
serviceman and five electric local reps along with
supporting staff, performing both distribution and
transmission work.
h
o
o
With such a large service territory, the crews work in
diverse terrains including farm fields, rivers and creeks,
mountainous and back country, along with cities and Left: moving poles and lines for a county rood proiect
small towns, daily facing the challenges that come with
each. Often the work must be scheduled around when areas are even accessible. Located in the Palouse,
honoring the farming community is an abiding concern. For example, farm fields in the winter time are too
wet to access, but these fields are tilled and planted from
approximately May until middle of August, giving crews a
Left: toking core not to domage voluable formlond
Above: Polouse crews use o voriety of equipment
to occess their lines
very smalltime
window to try
to address any
issues in the
fields. The
crews use
several
different kinds
of vehicles to
access
equipment in
the different
terrains, such
as ATV's, Snow
Cats and sometimes helicopters. Even then, at times the
crews have to hike into areas in order to inspect an issue. This service area also intertwines with other utility
companies. Whenever our work involves both, there is a lot of planning and coordination required for both
companies. They also work closely with neighboring Avista District Offices to share resources and equipment
when needed.
Exhibit No. 8
Case No. AVU-E-'19-04
H. Rosentrater, Avista
Schedule 1 , Page 36 of 1 03
o
EmoxEa cnAFl
Palouse
t029.s 393.2 28.4
Overhead
Circuit Miles
Underground
Circuit [Vliles
Customer
Count
Number
Primary
Meters
Number
Customers Number of Number of
Per Mile Feeders Transformers
Number of
Structu res
t i &
40.469 17 46 9,381 22,O94
o
o
Oruer-lo Drstnrct
The Othello District Office consists of nine dedicated employees who serve roughly 7,000 electric and 3,000
gas customers in the Company's western-most portion of its electric service territory. Although most who've
driven through Othello think of it as very flat, it actually contains very rugged country
that is nearly inaccessible. Having been formed by the great Missoula floods, there are
many basalt cliffs and sandy valleys through which the transmission and distribution lines
run. When troubles arise, primarily wind storms, a helicopter is used to patrol the
hundreds of miles of transmission lines rather
than attempt to navigate the basalt scablands with vehicles. At
times, the team has to travel up to L60 miles to reach a line.
This office is responsible for one
of the Northwest grid's key 230
kV transmission lines, which
carries power from the
Wanapum Dam on the
Columbia River 80 miles
towards Walla Walla. They also
maintain the 115 kV
transmission lines that span
from the Hanford Nuclear
Reservation to Warden,
Washington, and from Sprague
to Othello. ln addition Upgroding Othello tronsmission lines
they are responsible for
nearly 400 miles of
distribution lines spread
out over L5 different
feeders, serving the
towns and areas around
Othello, Lind, Ritzville,
Sprague, and Washtucna.
Powerful windstorms in the
Othello oreo con couse mojor
damage
Othello is home to the majority of the Company's irrigation
load, as it is in the heart of the Columbia Basin lrrigation
Project, the largest water reclamation project in the United
States, supplying water to over 680,000 acres. With the highly productive crop land comes enormous
processing plants, two of which are Avista's 5th and 6th largest customers, McCain Foods and Simplot,
respectively. These plants supply French fries to most of the world's McDonalds and Burger King
Restaura nts.
Othello is growing rapidly thanks to its agriculture base, with large residential developments being built
along with large crop storage buildings and processing plants. To accommodate this growth, an additional 30
MW transformer is being added to one of the three Othello substations in the next year.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Othello
397.5 60.4 7,003 15.3
Number
Customers Number of Number of
Per Mile Feeders Transformers
Number of
Structu res
Underground
Circuit Miles
Customer
Count
Number
Primary
Meterso
Schedule 1 , Page 37 of 1 03
7
-z?-.
I,
:
F
)
Overhead
Circuit Miles
5 15 3,629 8,011
Sr. M^A.nres Drsrnrcr o
The St. Maries district consists of a four man
line crew and one local ,ive serving
approximately
5,000 rural
customers in
the St. Joe
River Valley,
including the community of Harrison and the
surrounding areas on the east side of Lake
Coeur d'Alene. The majority of this district is in
mountainous terrain; falling trees and limited
access are continuous hurdles for this small
crew. This District office also serves two major
sawmills, Potlatch and Stimson.
The area is subjected to heavy snows in the winter and major flooding in the spring, creating significant
challenges in serving customers. Fortunately this crew is ingenious in coming up with quick and reliable
solutions. ln one example, heavy snow loading in the trees next to a line was causing multiple outages over a
seven day period. The crew brought in a logger with a specialized piece of equipment to knock all the snow
out of the trees (see the picture on the far right) next to their rural feeders to help minimize outages. What
a great example of Avista employees thinking outside the box to keep our customers in service !
o
Above: Logger shakes snow off trees next to o
line to prevent further snow-shedding outages
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 38 of t 03
I
St. Maries
223.8 136.5 4,573 t2.7
Number
Customers Number of Number of
Per Mile Feeders Transformers
Number of
Structures
Overhead
Circuit Miles
Underground
Circuit Miles
Customer
Count
Number
Primary
Meters o
JI
----?_.'r
2 4 2,L59 4.878
o
o
Spoxa.NE DISTRIGT
The Spokane Electric Operations group constructs and maintains
roughly 1,500 miles of overhead circuits and 850 miles of underground
circuits, as well as over 230 miles of
transmission lines within the Spokane
District, which covers 853 square miles in
and around Spokane County. The Spokane
Operations Team serves approximately
175,000 residential and commercial
electric customers, making it the largest customer-based service
territory within the company. This team of 77 employees is comprised
of ten Line Crews, six servicemen, craft personnel, leadership, and
office staff. These crews are flexible, as they are frequently called to
aid and assist outlying districts with transmission and distribution
support.
#
Above: Setting o pole in o backyard
with a crane due to accessibility issues
Below: Stuck in the mud
Spokone Linemen deol with the
complexity of multiple foreign
utilities located on their poles
The Spokane service territory
is mostly urban, but does include several rural locations. Because
of the mostly urban environment of the Spokane service area,
these crews face some unique challenges when constructing and
maintaining the distribution system in and around Spokane.
Working conditions are often
congested, with multiple
foreign utilities rights-of-way
on their poles as well as
vehicle and human traffic. ln
addition, these crews deal
with the same environmental
conditions faced by the other
districts, including wind,
snow, ice and fire as well as
the unique accessibility issues
that come with a high
customer density.
Just like the
more rural
Districts,
Spokane hos
it's shore of
difficult
circumstonces
ond terrain
Exhibit No. 8
Case No. AVU-E-I9-04
H. Rosentrater, Avista
Schedule 1 , Page 39 of 1 03
The Spokone District is responsible for
a number of transmission lines
835.2
Spokane
1535.4 72.3 116 28,t12 59,536
Number
Customers Number of Number of Number of
Per Mile Feeders Transformers Structures
Overhead
Circuit Miles
Underground
Circuit Miles
Customer
Count
Number
Primary
Meterso
7?
l-
c,
fi.* i fr
#rI7|l.
-i
aryt
t7L,329 55
SPOX^E NE DOYI|NTOWN NETWORK
Avista operates an underground electric distribution system in the core business district of downtown
Spokane. This distribution "network" is configured as a fully redundant distribution grid that includes cables
encased in concrete reinforced duct lines and major equipment such as underground transformers in
concrete vault structures. The Spokane Electric Network encompasses over a thousand underground
PST wmxJ'5 ACCB
1 PSTsffi
n &cts
=aLE'E\ ]
-
{froR( m8 rcUNNttS
-
MEI EIR L@NCNs
-!&II5.1. N r'WTA ACCM| UU Wff tN gztFWAUUn-SfMmNlLilrcW N EW CM &@T. NN PMfr.
2. ffiru CME&ru c&t coucE & rN[ E[r
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nE RIVFRiIDF\-!
RAILRoAD R/',1 162
J
RAILROAD R,/W
slm
I I
I;*
DSIRIBUTION - EI.ICTRIC
DOWNTOWN SPOIGNE
NEilIORK EOUNDARIES & ADJACENT FIIDERS
--------------+#g * - L-3ss7 l
network protectors, 176 relays and an equal number of submersible three-phase transformers, all
maintained by Network cable crews.
One of the primary issues faced by the Downtown Network is aged equipment. Many of the Network's 741
electric services were installed as early as 1907. Over half of the primary cabling in the Downtown Network
is underground Paper lnsulated Lead Cable (PILC) installed in the 1930's. The Network also continually deals
with the complexities of city road move and construction projects and load growth. Even facing these issues,
the Network is inherently reliable, designed to keep customer lights on during the loss of any one piece of
distribution equipment. This system has proven to be very effective -
customer outages are rare, averaging L event every 3 years over the
past 40 years, with the longest
customer outage recorded at less
than 8 hours.
manholes, hand-holes and vaults.
Within the Network's boundaries
there are 175 three-phase
subway style transformers, L76
The complex process of filling
poper insuloted lead coble with
lead to creote o solid splice is o
speciolty of this crew
Mony of the voults in Downtown
Network ore decodes old
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 40 of 1 03
o
o
The Network is truly unique, in its
electrical connectivity (everything
is loop fed), its facilities (all vaults
must be custom designed) and its
work (splicing, especially for their
underground cables), but handling
unique and specialized equipment
under trying circumstances is part
of a normal day for this elite group.
rc-
-
I
o
@ sue*rorE 3urDtNi
P$ '6T SRE EDER]&H BIRD & UTCH TEDER
rus,rJ526
rJ527
I J52EI
99[.Sffitus,1152r
1 J5221J52J -s!
T Lti I
?r'
>t
ti
.69
o
CUSTOTTER REQUESTED INVESTNAENTS
Avista defines these investments as "customer requests for new service connections, line extensions,
tronsmission interconnections, or svstem reinforcements to serve o sinqle lorqe customer." We have often in
the past referred to new service connects as "growth," as in growth in the number of customers, however,
these investments are beyond the control of the Company,
and as such they do not reflect a plan or strategy on the
part of Avista. Responding quickly to these customer
requests is a requirement of providing utility service.23
Customer requested activities are typically limited to the
electric distribution system, but may be extended to
include substation infrastructure and dedicated high
voltage transmission facilities, which are not the subject
of this report. Typical projects include installing electric
facilities in a new housing or commercial development,
installing or replacing electric meters, or adding street or
area lights per a request from an individual customer, a city, or county agency. As would be expected,
fluctuation in the number of new customer connections is largely dependent on local economic conditions
both in the housing and business sectors. Population growth rates in the Avista service territory typically
range from 1-3% with specific outliers such as Liberty Lake and Pullman, where commercial business
development is driving greater increases in local populations.
New Service Connects
Avista currently serves approximately 377,OOO electric customers. The pattern of new connections shows
that our service area is still
recovering from the economic Avista Elecnic customer connections
o
downturn of 2OO7-20L'J-, as
shown in Figure 20.
The five-year forecast for new
customer connections for the
period 2017 -202'J.is
approximately 30,000, for an
annual average of
approximately 5,000, as shown
below in Figure 21. This higher
forecast rate of new additions is
based in part on expected
improvements in local
economic activity. ln addition to
the economic forecast, the
expected number of new
connections is also based on
.9PUoccoU
o
L(,
-o
Efz
epm
8pm
7,0m
5pm
5,0m
4,0m
3,0m
2pm
lpm
0
2ms 2m6 2m7 2m8 2m9 2010 20tr 20rt 2013 2014 201s 2016 2017 2018 20t9 7020 2021
ElActual rfeys66st
Figure 20. Avista Electric Customer Connection Requests - Actual & Forecast
o 23 Avista Corporation provides electdc and natural gas service in five states including Alaska and Montana, however, this report covers only the
regulated eleclric operations of Avista Utilities in our service areas in the states of Washington and ldaho.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 41 of 103
PtentNgp SpgtttptNo By INVESTMENT Datvgn
\I
population trend data and city and
county building permit applications.
The investments needed to support
new customer connects generally
reflect the extension of existing
distribution infrastructure rather than
substantial modification to existing
assets.
o
Figure 2L. Avista Electric Customer
Number of Connections & Cost Per
Customer
Cost of Service
Avista tracks the costs required to meet customers' requests for electric service in the following six
categories:
1) Electric Seruice Extension - the cost of installation labor,
material, procurement, design and associated costs to extend
electric primary and secondary wires and cables from Avista's
distribution grid to the customer's point of service.2l Electric Meters - the cost to purchase and install electric meters
including commercial and industrial class equipment.
3) Distribution Transformers - the cost to purchase and install
overhead and pad mount transformer equipment.
4l Street Lights - the costs to purchase and install roadway street
lights.
5) Area Lights - the costs to purchase and install customer
premise area lights.
6) Tronsmission & Substation - the costs to construct high voltage
transmission lines and associated substation equipment.
Above-ground Service
Responsibility
"/*
o
Table 2 shows the forecasted costs by category, the overall expected investment, the number of new
connections, and the overall cost of service (total investment / number of new connects) for each year in the
current planning period.
Exhibit No. 8
Case No. AVU-E-1 9-04
H. Rosentrater, Avista
Schedule 1, Page 42of 1O3
Jiwsrl
$79,s74,521Exterrsionfi19,272,801,$18,574,437 $19,174,489 $79,472,878
Meters $2,027,379 $2,057,376 $2,774,092 $2,772,453 $2,217,720
ERTs $1,112,771 !$1,73'1,677 $1.,166,113 $1,199,109 fi1,227,269
Regulators w2,795 $481,515 $496,489 $509,220 $51s,989
Cost per Service $3,666 $3,695 $3,694 $3,698 93,71,4
$22,895,746 $22,238,945 $22,951,L83 $23155,303 $23,433,796
2017 2018 2019
Total
2020Customer Requested Electric
Connections
Toble 2. Forecast Electric Customer Connections o
CusroMt]R REeUESTED lU,DCTRrc CoNNtcrroNs
(fl of Connections dnd Cast per Connection)
co
EE0
o
oU
?poo
60m
5,0m
4p00
3,0@
2,0m
!,0{x)
0
7m,
6m0
5q)0
4m)
3mo
2(D0
1000
o
ct0
o
!
E5z
0
2m5 2m6 2g)7 2m8 2m9 2010 2011 20L2 2013
r@tf - Coi of Cldd. Swice S of ElEticConndions
2014
/T'
2021
# Electric Connections 6,245 6,O19 6,213 6,343 6,310
o
o
INVESTMENTS rN CusroMER Senvrce QuiruryAND REuaerlrry
Customer Service Quality and Reliability investments are those "investments required to maintain or
improve the qualitv of services we currentlv provide our customers, to introduce new tvpes of services and
options based on an analysis of customer needs and expectations, to ensure we achieve our customer
service qualitv requirements, and to meet our electric svstem reliabilitv obiectives." Distribution
investments in this category include such programs as the Company's current deployment of advanced
metering infrastructure (AMl) in our Washington service area and deployment of feeder automation
systems to reduce the impact of an outage on our customers. The trend towards automation, distributed
resources, energy storage, and direct consumer interaction is transforming the century-old model of energy
delivery to the "grid services platform" of tomorrow. As the industry adapts and conforms to these
economic and societal drivers, Avista must carefully evaluate and consider how best to align resources
towards common goals and objectives.
Reliability ! nvestments
Avista has in the past referred broadly to individual investments we make as having the purpose of
"improving reliability." This attribution reflects the fact that many investments, especially distribution
investments made to replace deteriorated assets, are very likely to
improve the reliability of the specific infrastructure that is being rebuilt
or replaced. This is the case because the likelihood of failure of an asset
generally increases with age and deterioration over its service life.
Avista's many infrastructure investments often include at least a
mention of these reliability benefits, and some are quantified and
discussed extensively, as in the Company's Grid Modernization Program.
ln the great majority of cases, however, the predominont need for these
investments is to replace assets that have reached the end of their useful
life, or to a lesser degree, to solve capacity and performance issues, and
not for improving reliability.2a But this timely replacement of assets is
crucial to our ability uphold and maintain our current levels of reliability
performance. Accordingly, we separate electric system investments that
are related to reliability into two groups: "Reliability as a Facto/' and
"Reliability Projects and Programs," both discussed below.
Reliobility as a Factor - Reliability benefits are considered in almost
every program and project in Avista's portfolio as well as in the old equipment increoses
alternatives considered. As an example, our Wood Pole Management reliobility risk
Program inspects, repairs and replaces wood poles and associated
equipment based on asset condition. One of the alternatives considered was a shorter inspection cycle. This
option was considered based on potential reliability benefits, but those benefits were superseded by the
additional costs of the shorter cycle and the length of time it would take for any potential reliability
increases to actually enhance overall reliability. To further illustrate this concept, even though reliability is
obviously a factor when we replace equipment damaged by storms or required by the state when a road is
relocated, it is not the primary driver, as this work is required regardless.
2a ln this discussion we distinguish between cases where the rebuilding of a deteriorated feeder will very likely result in that feeder being more reliable
when completed, versus the impact that feeder rebuild has on the reliability of Avista's overall distribution system. The Investment will likely improve
the reliability of that feeder for those cuslomers it serves, but from a system perspective, that investment serves to "uphold' and maintain our current
overall level of system reliability.
Exhibit No. I
Case No. AVU-E-I9-04
H. Rosentrater, Avista
Schedule 'l , Page 43 of 103
o
r
Tt) :E
a
Evaluation of Reliability Results
Reliobility Projects ond Progran'ls - ln contrast with the consideration of
"Reliability as a Factor", Avista defines Reliability Projects and Programs as
being made primarily or exclusively to meet a reliability objective. ln other
words, were it not for the intended reliability benefit, the investment would
likely not be made. An example of this type of investment is the installation of
remote communication capability to a feeder in conjunction with remotely
operated equipment. This combination allows a feeder to be "sectionalized"2s
to isolate that portion where the outage is located, thus reducing the number
of customers who experience a sustained outage. Though this investment
achieves other incremental value beyond the reliability objective, it is made
primarily to benefit the reliability of that feeder for customers. Without that
predominant reliability objective, the incremental investment for the
additional equipment would most likely not be made. Even in this example,
however, the overriding reliability objective is to uphold our current level
of system reliability, not to improve it.Some of the Avista Distribution
poles installed in the 7920's
ond 7930's ore still in service
todoy... and it shows!
A key focus in our annual reporting is understanding and analyzing the
causes of outages, particularly those associated with major events, and identifying any particular pattern
that merits further investigation. As can be seen in Figure 22,over a third of our outages are generally
considered outside of our control (weather, fire, and public caused outages), with weather alone accounting
for an average of 26% of our outages over the past 1.6 years. ln addition to these outages, 17% are
"planned" outages where service must be disconnected in order to perform work on the system.26 Together,
these outages required for system maintenance, upgrade or repair and those beyond our control account
for over half of our overall distribution outage events.
Excluding planned outages
and those beyond our
immediate control, Avista's
"base" system reliability
performance is the product of
a complex network of factors,
and the sum of the individual
performances of a wide range
of individual assets (e.g.
transformers, meters,
conductor, insulators, etc.).
While our overall reliability
trend meets our objective of
upholding and maintaining
our current reliability
performance, the underlying
story is more complex.
Figure 22. Outage Causes 200L - Present
25 This refers to the use of a switch(es) located along the feeder midline that can be opened to effectively divide the feeder into two segments,
allowing service on the section not associated with the outage to be quickly restored.
26 Avista follows a standardized customer notification process for work that requires us to intenupt their electric service.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 44 of 103
o
o
o
Vetetation
Other/Unknown
lLo/o
Fire
Anlmal
13%weather
26%
7%
Public
7%Maintenance
t7%
Human Errorx.
Avista Outages 2001-Present
fi
,"d
Eguipment Failure
L5%
,'
t:t
{.
t
o The reliability of assets is based on how they tend to deteriorate over time, the manner in which they are
maintained, the point in their life cycle when they are replaced, and the impact of specific asset condition or
reliability improvement projects and programs. Avista's Grid Modernization and Wood Pole Management2T
Programs have had a positive impact
on the reliability of overhead
distribution infrastructure by replacing
assets based on condition. ln addition
to repairing and replacing wood poles,
these programs, working jointly, also
install new equipment including
crossa rms, transformers, grounding,
lightning arresters, and cutouts.28
Through the actions of these
programs, these equipment assets are
replaced at the end of their useful life
but before they are likely to fail, which
would have resulted in an outage for
our customers. Replacement of these
assets, based on the Company's asset
Outages from Failed Tiansformers and Cutouts
management strategy, has
had a positive impact on the number of outage events experienced by our customers, as
shown for transformers and cutouts in Figure 23.
While these improvements derive predominantly from the end of life replacement of assets
(or "reliability as a factor"), the Company, as explained above, also makes investments that
are primarily to
improve system
reliability. Among
examples of
Squirrel Guord these Programs
is the Company's
effort to evaluate and install
"squirrel guards" across targeted
areas of our system. A squirrel
guard is a protective rubber boot
that is installed over the insulator
and conductor on transformers,
reclosers, and other distribution
equipment. The squirrel guard
program has achieved a
substantial reduction in the
number of animal-caused Figure 24. Squirrel Related Outages
outages on feeders where they have been
installed, as shown below in Figure 24. This treatment has helped Avista achieve a substantial reduction in
outage events each year, and squirrel guards are now standard on new installed Avista equipment.
27 Please see the Wood Pole Managemenl Program discussion (beginning on page 57) and the Grid Modernization Program (beginning on page 64
in this report) discussions and cha(s for distribution system reliability impacts.
28 Definitions of these asset types are provided in the Wood Pole Management section (beginning on page 57 in this report.)
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 45 of 1 03
Annual Outages Caused By Squinels
@
o
o!
Elz
900
8m
700
5@
500
400
3m
26
1@
0 llhllr
2m1 2002 2m3 2m4 2005 2m6 2@7 2@8 2m9 2010 2071 2012 2013 2074 2015 2016
300
250
200
150
100
50
0
0.,
lfl
C)bo(o
lo
o
(u
-oE
=zE
c
Cutou?s
-
2005 2006 2007 2008 2009 20\o 201.1.2072 20t3 20t4 2015 2076
Figure 23. Outages from Failed Transformers & Cutouts
o a
o
E
H WCufoul
\?L!
I
oln the example noted earlier, equipping a feeder with remote operations capability through feeder
automation has also had a positive impact on our overall system reliability. Automation provides Avista with
the ability to sectionalize the line
to isolate an outage and restore
service to customers served from
the feeder section that is still
serviceable. Through this remote
operation the Company has been
able to avoid sustained outages
for customers that have totaled
an average of over 400,000
minutes per year since 2013.2e
While these management
strategies have a positive impact
in reducing the number and
duration of outage events we
experience on our system, there
Outages Resulting from Failed Poles
60
cgs0U
{Jo!.g 40
=o
3so{J-oE220-6
fEro lh0
2m5 2006 2@7 2W8 2009 2010 20LL 20t2 20L3 20L4 201s 2016
are other trending factors that are at the Figure 25. outages Required for Planned work
same time diminishing the reliability of our
system. An example is the number of outage events that result from the Company's need to "de-energize"
the system in order to complete maintenance, repairs and upgrades. As Avista has increased the level of its
investments in electric distribution infrastructure overthe prior decade, as described above, we have
experienced a corresponding increase in the number of planned outages required to complete this work, as
shown in Figure 25.
The Company is also experiencing an increasing trend in the number of outages caused by poles in its
system that fail, as shown in Figure 26. While the Company's Wood Pole Management Program reduces the
Outages Required for Distribution System Maintenance, Repairs
and Upgrades
co
t!
oo0o
fo
o
tU-o
E1z-6
lcc
4m0
3500
3m0
2500
2000
1500
1m0
5m
0 rIrTI
2005 2006 2co7 2Cf,8 2009 2010 20tt 2072 2013 20L4 2015 2016
number of poles that would be failing if
not for the actions taken under the
program, they are not sufficient to
stabilize the long term reliability and
performance of our wood pole
population. This result is due to the
changing age profile of our pole
population combined with our
conservative 20-year inspection cycle,
which is expected to result in an
increasing number of pole failures in year
2OL7 and beyond.
Another important consideration in
evaluating the Company's approach to
o
Figure 26. Outages Resulting from Failed Poles managing its system reliability is the
significant impact that the type of outage
event has on the number of system interruptions (SAlFl) and outage duration (SAlDl). For example, the
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule '1 , Page 46 of '103
2e Analysis available upon request.o
I
o failure of a distribution transformer will likely impact from one to five customers, the same as with the
failure of a cutout or an outage caused by a squirrel. Accordingly, the outage benefits provided by the
reduction in these types of outages has a proportional impact on the overall reliability of the system. By
contrast, the failure of a pole may interrupt service
for an entire feeder, impacting up to several hundred
customers, and, depending on the location of the
pole, may cause an extended outage.
The same type of magnitude in reliability
improvement can be applied to the benefits provided
by feeder automation. When an outage results in the
interruption of service on the entire feeder, remote
operations can be used to sectionalize the line and
avoid a sustained outage for many of the customers
served on the feeder. For outages resulting from
planned work on the system, the interruption ranges
from impacting a
single customer to affecting an entire feeder, and in unusual cases, an
entire substation, which interrupts all of the feeders tied to that station
(potentially in the range of several thousand customers).
This very brief discussion is intended to illustrate why we often consider
investments in electric distribution as being made to "improve reliability."
Whether we are avoiding outages that would have occurred due to
failures in deteriorated assets, such as with wood poles, or cases where
we are actually bringingthe base assets to a higher reliability standard, as
in the case of squirrel guards and feeder automation, we are increasing
the reliability performance of the targeted infrastructure. But from an
overall system perspective, these individual improvements in reliability,
when combined with the cumulative performance of all of our assets,
allow us to generally uphold and maintain our overall current level of
reliability performance.
Though Avista and other utilities report their reliability for their overall system, this look masks the wide
range in electric reliability among the feeders in an operating district and
among the districts themselves. For example, as described earlier in the
overview of the Company's electric distribution system, the Colville
district has approximately 2,500 miles of distribution feeder lines, both
overhead and underground. These feeders are predominately rural and
serve approximately 19,000 customers. This number of feeder miles
actually exceeds that of the Spokane district, which serves approximately
170,000 customers. More importantly, though, Colville has only 26
individual feeders, compared with 116 feeders in Spokane. This means
the individual Colville feeders are, on average, almost 4.5 times as long as
those in Spokane. Because the number of feeder miles and the length of
feeders represent an index of customer exposure to outages, our Colville
customers have a much greater risk of experiencing an outage than do
our customers in Spokane.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Guard
o
o Typicol terrain in Colville
Schedule 1, Page 47 of 103
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ln addition to the number of miles and the length of feeders in Colville, the locations of the lines themselves
also play a role in service reliability. Colville feeders tend to be located on narrow cross-country rights-of-
way as constructed by the local public utility district (PUD) in the years before Avista acquired the system.
These conditions not only increase the likelihood of an outage, but they make it difficult for crews to patrol
the line to find the cause of the outage and to get material and equipment to the site in order to perform
repairs, thus extending the length of outages. A lengthy trip for our line crews may also be required to reach
the site, since this District encompasses over 2,400 square miles. These differences in feeder characteristics
are manifest in the average number and duration of outages expected for Spokane and Colville in 2077 , as
shown below:
As expected from the feeder data discussed above, Colville customers on average can expect to see five
times the number of outages and 8 times the outage duration as the average customer in the Spokane
District.
ln each of our districts, outages are analyzed by individual
feeder to assess areas of concern for reliability performance.
These "feeders of concern" are most often rural since it's
normal to have a greater number of outages per customer on
these often lengthy and extensive systems. For its "feeders of
concern", Avista develops work plans with individual treatments
designed for each feeder. These treatments include such
improvements, when cost effective, as moving sections of
overhead lines onto public road rights-of-way for easier access,
converting them to underground circuits, accelerated or
targeted vegetation management and wood pole inspection,
improved fuse coordination, dividing individual feeders into two
separate feeders, as well as using feeder automation to
sectionalize individual feeders.
Reliability Strategy
When it comes to the future reliability of our electric system, Avista must be attentive to understanding the
evolving expectations of our customers and evaluating our forward capabilities for meeting them. ln this
respect, we must constantly judge whether our overall service quality meets the expectations of our
customers, balancing the costs and lead time required to deliver that level of service.
ln recent years Avista's approach to electric system reliability has been to generally uphold the current
performance of our overall system, which we believe has been satisfactory to our customers as well as cost-
effective. While we believe we have been successful in striking a reasonable balance among our customers'
reliability expectations, the characteristics of our extensive and often rural system, the quality of our
services, and the cost associated with delivering those services, we also understand that across the industry,
customers' expectations for service reliability are increasing. This trend, coupled with the outage
consequences of recent extreme weather events in our service area, regionally, and nationally, has
prompted the development of new regulatory strategies designed to address the aspect of reliability
referred to as "resilience."
Exhibit No. I
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 48 of 103
o
o
o
System Number of Outages (SAlFl)o.72 3.7
System Duration of Outages (SAlDl)87 Minutes 7O7 Minutes
Reliability Measure Spokane Colville
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a
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/
Rebc8ted
[ineOverhead
I t,
o
Resilience is " robustness ond recovery
c h a r o cte r i sti cs of uti I ity i nf ro st r u ct u r e a n d
operotions, which ovoid or minimize
interruptions of service during on extroordinary
and hazardous event." - National Association of
Regulatory Utility Commissioners (NARUC)
Resilience - ln the electric utility world, the term "reliability" is changing to include the concept of
resiliency.3o Basically this is focusing on the ability to harden the system against - and quickly recover from -
high impact, low frequency events such as severe
weather, natural events such as wildfire or earthquakes,
and attacks (physical and cyber). As an indication of the
value of considering resiliency, in focusing storm
hardening on just 1% of their most at-risk poles, Florida
utilities believe they are providing customer benefits of
almost S+g million per year in reduced outages and/or
outage duration.3l
The National Association of Regulatory Utility Commissioners (NARUC) believes that resiliency is separate
and distinct from traditional reliability; they note the difference between utility cost of outages and /osf
volue to customers.32
Resiliency measures do not necessarily
prevent damage; rather these measures
enable energy systems to continue
operating despite damage and/or
promote rapid return to normal
operations when unexpected events do
occur. This concept incorporates system
hardening (such as undergrounding or
vegetation management), robustness
(ability to bounce back from
unanticipated events as quickly as
possible), com prehensive emergency
response strategies, and the concept of
incorporating lessons learned to stay on a
path of continuous improvement.
Spare
Equipment
& f,laterial
Strategy
o
Avista has put significant effort into
developing a detailed plan for rapidly and
effectively dealing with large scale
emergencies. ln 2015 the Company won
the Edison Electric lnstitute "Emergency The ,,Circte of Resiliency,' from 1EEE Standords Association,
Recovery Award" for "extraordinary efforts to https://standords.ieee.org/events/nesc/brodish-fteemon.pdf
restore power in times of crisis."33 This award is
presented twice annually to EEI member companies to recognize their extraordinary efforts in restoring
power to customers after service disruptions caused by severe weather conditions or other natural events.
30The National lnfrastructure Advisory Council, "Critical lnfrastructure Resilience Finance Report and Recommendations," September 8, 2009, on
page 8, The National lnfrastructure Advisory Council (NIAC) says: "lnfrastructure resilience is the ability to reduce the magnitude and/or duration of
disruptive events. The effectiveness of a resilient infrastructure or enterprise depends upon its ability to anticipate, absorb, adapt to and/or rapidly
recover from a potentially disruplive event."
31 Kury, Ted, "Evidence-Driven Utility Policy with Regard to Storm Hardening Activities,", Augusl27,2012,
http://bear.warrington.ufl.edu/centers/purc/D0CS/PRESENTATIONS/Kury/P0812_Kury_Evidence_Driven_Utility.pdf, page 20
32 Keogh, Miles and Christina Cody, National Association of Regulatory Utility Commissioners, "Resilience in Regulated Utilities", November 2013,
https J/pubs.naruc.org/pub/536F07 E4-2354-D7 1 4-51 53-7A801 984436D
33 EEI Emergency Response Awards - htto://www.eei.oro/abouUawards/Pages/default.aspx and
http//www.spokesman.com/stories/2016/jun/1S/avistagets-awardJor-restoration-work-after-winds/
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 49 of 1 03
ilaintenance
Programs
Renewal &
Selective
Hardening
Asset
Situational
Awareness
& Decision
lncilent
Commsnd
Structure
Grid Resiliency
o
Cyber &
Physical
Security
Support
Planning
Avista believes the time is right for us to evaluate our current
reliability posture in light of the current and trending expectations
of our customers, the likely future performance of our system, and
in consideration of the value of resiliency as an emerging and
integral piece of the reliability picture. ln an increasingly digitized
world, power qualitv now plays a major role; even small transients
or fluctuations can be more disruptive than full power loss. The
value of lost service is growing each year as people depend more
and more on what they consider essential services. Thus, Avista will
continue to explore how resiliency fits into our overall reliability
strategy. ln addition, given the very long life of our electric
transmission and distribution assets as well as the size of the
investments and timeframe required to significantly change their overall performance, frequently revisiting
our reliability and resiliency objectives will help us make targeted and timely adjustments to our strategy in
ways that meet customer expectations and deliver the greatest optimized value.
Setting Actiona ble Targets
Frequently in our industry, there has been interest in establishing performance goals, targets, or
benchmarks for system reliability that the utility is required to meet on an annual basis. As described above,
setting annual targets based on the results of metrics such as the average outage frequency and duration
indices may make no realistic sense, because the often highly-variable results year-to-year are largely out of
the control of the utility, and investments designed to improve these values usually have to be made over a
period of many years in order to meaningfully improve the
trends.
Avista has used reliability indices for goal setting inside our
organization. However, the intent has been more to create
a management and employee focus on finding innovative
ways to support our reliability goals. Going forward, the
Company will be evaluating options for establishing what
we refer to as "actionable" goals and targets for reliability
in lieu of the lagging outage frequency and duration results.
We expect these goals to be based on the accomplishment
of activities:
o
1) That are within the control of the Company;
2) That have a demonstroble impact on the reliability of
our system;
3) That are needed to support our overall reliability
objectives;
4) That are cost-effective and make sense for our customers.
ln this effort, Avista's aim will be similar to the approach taken in
California where performance targets based on SAIFI and SAIDI (with penalties for non-performance) were
abandoned as ineffective and replaced by a programmatic approach to grid investments that are more likely
to ensure that long-term system reliability goals are achieved.3a
3a Approaches to Sefting Electric Distribution Reliability Standards and Outcomes, pages 130 - 136. The Brattle Group, 11d.,2012
Exhibit No. 8
Case No. AVU-E-I9-04
H. Rosentrater, Avista
Schedule 1, Page 50 of 1 03
Transmission Poles showing distribution
lines "underbuilt" below the tronsmission
lines, which puts odditionol stroin ond
wedr on the poles
o
o
o
o
lnvestments to Uphold Customer Service Quality and Reliability
Distribution Vegetation Monagement - Avista's Distribution Vegetation Management group is
responsible for insuring that vegetation-caused outages are kept to a reasonable and cost effective
minimum across our 7,800 miles of overhead electric distribution lines. This group utilizes a multi-pronged
:::il:ilffi :,'.".:'J,::,'f ;:'mHll::ff ,i:H,':l"'
for our customers. I ntcrRtRt trlnN \/FGFTAT|nT\I
Over the prior six years our Avista/contractor team has
essentially re-written the book on how this department
conducts its business. Every aspect, from work planning
and prioritization to contracting philosophy, work
practices, and contractor relationships have been
reviewed and re-vamped as needed to help raise the bar
on our core principles of safety, reliability, and customer
service. New strategies focused on innovation and
results have led to new business processes and
increased efficiencies, as can be seen from the results
listed in the text box on the right.
A foundation of the program
has been the Company's
development of a
comprehensive tree
inventory database,
currently containing data for
about 300,000 trees across
Avista's service territory. The
information in this database,
which is constantly updated,
is used to help design our
vegetation management
approaches under three
distinct programs:
o Routine Cycle Mointenonce
o Risk Tree Mitigotion
o Right of Way Cleoring
Routine Cvcle MatnteEnee is conducted on a five to six
year interval and is focused on trimming practices that
are tailored to the type of landscape and species of trees
along our rights of way, organized by individual
geographic zones referred to as "polygons."
Organization of the work by polygons involves the
prioritization based upon the predominant vegetation
and the geographic location of identified "problem
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 51 of 1 03
o
/ Technologv:
Converted to electron ic/paperless
operation
/ Documentation:
Created a tree inventory of nearly
300,000 trees system wide
/ Qualitv Assurance:
Certified arborist on every crew
/ AccountabiliW:
Keep detailed metrics and perform in
depth auditing
/ Process lmprovement:
Focused on efficiency in manpower and
work performed, increasing the number
of trees trimmed or removed
/ Cost Control:
Created contracts to keep prices flat for
over six years
/ Customer Service:
Higher number of trees worked with
fewer complaints - and an almost equal
number of compliments!
r' Results:
Reduction in outages and wild fire risk
/ Savings:
5700,000 in o&M every year over the
next ten years due to program
efficiencies
I
r-
Avista lndustryAveroge
trees" that require the most attention during the trimming operation. This tailored approach allows Avista
to maximize the efficiency of the work crews; they focus on areas most likely to cause a problem, then
customize work cycles for trimming based upon tree and vegetation type and physical location. For example,
some species of tree can be allowed a fifteen foot clearance (fast growing species), others (slow growers)
can be allowed within five feet of our lines.
Cost per Customer 914 560 Another part of this routine work involves the
Contrihution to SAtFt 0.11 0.60 targeted removal of individual trees that Avista
refers to as "cycle busters," meaning they will
grow quickly enough to require an additional trim during the middle of the cycle interval, which is very
The work process for this routine maintenance can generally be
divided into the four key activities briefly described below:
1) Crew work planners identify areas that need to be
addressed and the work required.
2) A map, location details, tree species information, and the
specifics of the trimming required is created for the crew
so they go to the job prepared.
3) Notification postcards are sent to customers two weeks in
advance of the work so they can also be prepared.
(Note: 64,000 postcards were sent out in 2015.)
4) Crews trim vegetation to a level with a goal of five years
clearance.
The Risk Tree Mitigation program targets individual trees that
pose a hazard based on their potential to either fall across or to grow into lines during the cycle interval
These trees are identified by the following methods:
o Crews on the ground identifying dead, diseased
and dying trees as they perform work in the
field
. Light Detecting and Ranging (LiDAR), a remote
sensing technique that uses pulses of light
from an aerial sensor (such as an airplane or
helicopter) using specialized technology to
evaluate tree health3s
o 3-D imaging to detect low chlorophyll levels (an
indicator of health) and to produce data to
model growth patterns and clearance issues.36
lnteresting Vegetation Management Technique
h tt ps : //w w w. ce oti. co m/ co I I o b o roti v e - p rog r o m s/tr o n s m i s sio n -
d i st r i b uti o n/v mtf-v e g eto ti o n - m o n d g e m e n t/
35 "Light Detection and Ranging (LIDAR): An Emerging Tool for Multiple Resource lnventory," Stephen E. Reutebuch, Hans-ErikAndersen, and
Robert J. McGaughey, September 2005, httpJ/forsys.cfr.washington.edu/JFSP06/publications/Reutebuch_et_al_2005_PR.pdf
36 Tree-mapping drone start-up has sky-high ambitions," BBC World Service, May 2014, htto//www.bbc.com/news/technoloqv-27485418
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule '1, Page 52 of 103
o
o
Once identified in our database and prioritized, the
health of these individual trees is tracked to determine
D I STRI B I'[I'TO N VECETANO N
MANAGEMENT
ATAGTANCE- 2O16:
$ Olstomerc Notified:
Plonned Work 62,295
UN-PIanned Wo* 1,867
Totol il,162
+ coll center@mplointsc.. Total ClaimsMade
* Total Cloims Poid
* Kudos Received
79,
7
30
o
inefficient and expensive. Often the Company will replace a
"cycle buster" tree with a tree species that will not ever reach a
height to pose reliability problems for the overhead feeder line.
r
Li ,.;-, *lrl..,rs
o whether they need to be removed and, if so, when this should occur. The
cycle of removal for these risk trees is "as needed," based on the risks the
individual trees pose as they age.
Avista's Rieht of Wav Clearine program involves the physical removal of
brush and undergrowth on the feeder right-of-way using heavy mowing
equipment and the selective application of herbicides. This work is tailored
to the characteristics and needs of each feeder polygon, as needed, and is
generally conducted near the mid-point of the routine maintenance cycle.
Avista completes this work on approximately L,200 - 1,500 circuit miles
each year, generally during the months of May through October. Performing this work on a regular periodic
basis prevents the undergrowth from reaching the point where a more expensive complete trimming and
removal is needed to safely clear the feeder right of way.
Distibution Vegetation Management Outages Since the implementation of the
Company's new Distribution
Vegetation Management Program in
20L1, tree related outages have been
significantly reduced, as can be seen
in the trend lines shown in Figure 27.
The impact on electric system
reliability caused by reductions in the
budgets for this program is also
clearly evident in the figure for years
2015 and 2016, as outages clearly
increased.
veg.
Trendline After Veg. Mgmt.
Figure 27' Distribution vegetation Management Related outages short-term budget reductions in
those years resulted in a third of our contract tree crews being idled from October 2O'J-5 through May of
2016. Crews cannot afford to remain unemployed (and they are also in high demand), so they find other
work. When budgets are
restored, crews may be
committed to other projects
and no longer available to
Avista for up to several months,
thus a budget reduction can, in
one year, have a ripple impact
into the next year or even
longer. The corresponding
reduction in work performed
has an almost immediate
impact on reliability, as can be
seen in the increased numbers
of tree-related outages for the
years impacted by budget
reductions shown in Figure 27.37 Figure 28. Distribution Vegetation Management Budget Cut Impacts
37 For more information on the impacts of cutting vegetation budgets: "The Economic lmpacts of Defening Electric Utility Tree Maintenance," D. Mark
Browning and Harry V. Wiant, T&D Wodd, httpJ/www.tdworld.com/programs/economic-impacts-defening-electric-utilitytree-maintenance
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 53 of 1 03
350
3m
250
2n
150
100
50
oo
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o 2fi2 2fi4 2m6 2m8 2070
rfrc6 fsll of1sg5 Srevy
2012 2014 2016
S7,m,@o
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s6,60,@
5q.m,m
S6,200,mo
s60(I),oo
s18@,m
St6oo,om
s140,m
5120,m0
5s,oo,000
Distribution Vegetation Management Budget
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-Astuab
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s72,s92,208 s13,032,936
ldeal Budget to Maintoin
Progrom sto,973,382 5tt,3s7,4sI 577,7s4,961 s12,166,38s
2078 2079 2020 2027 2022 2023
Table 3 indicates the budget and the funding Vegetation Management actually received; Table 4 indicates
the budget needed to maintain the program at levels that allow the Company to keep up with tree growth
or dying trees that have been identified as having the potential to impact our system.
Table 3. Distribution Vegetotion Monogement Actuol ond Budget
Toble 4. Distribution Vegetotion Monogement Budget Needed to Maintain Progrom Schedule
Avista depends heavily upon the experience and expertise of the contract crews, and together we have
created a culture focused on customer engagement. Their creative solutions
have proven to be effective with customers. Even with the increased
workload their new processes have allowed, complaints last year (39) were
almost equal to the number of kudos received (30). ln another example,
we are encouraging customers to select utility-friendly tree replacements
that will never have to be trimmed in exchange for removal of old trees.
Avista's Vegetation Management
Program has been awarded the
Arbor Day Foundation Tree Line
USA Award3s for the last five years.
This award is given for best utility
practices in arboriculture based on
the quality of their tree care,
training, best practices, and public
education, and tree-based
conservation efforts.
o
Above: Before Vegetation
Management Work Begins
Right: After Work is Complete
o
I
Condition-Based Asset Replocements - When we evaluate replacement strategies for varied types of
assets based on age, condition or performance, the importance or value associated with its service reliability
is considered in the analysis. Since the failure of some assets does not
immediately impact our security, safety or reliability, they may be managed
under the strategy known as "run to failure." ln other instances, the failure of
an asset may result in an immediate impact to customer service reliability, or
a prohibitive cost to replace it after it has failed. ln these instances, Avista
evaluates the customer benefit of replacing the
asset at the end of its useful life, but prior to its
likely failure, in determining the overall strategy
for managing this asset. ln many such cases an
increment of reliability value is included in the
determination of the appropriate replacement
strategy. The increment of reliability value
considered is generally aimed at upholding our
Exhibit No. 8
Case No. AVU-E-1 9-04
H. Rosentrater, Avista
Schedule 1 , Page 54 of 1 03
S6,1so,oooO&M Budget forVeg. Mgmt.s6,402,000 s6,s18,000 s6,s21,860 S6,842,150 Ss,s9s,179
S6,6s3,020 56,642,46s ss,809,349 ss,796,369 S3,047,61sO&M Adual forVeg. Mgmt.56,174,964
2073 2076 2017207220142075
38 https ://www.arborday.org/prog rams/treeLi neU SIi/o
:-\
o current level of service reliability, and the incremental cost component is embedded in individual projects.
An example of these types of investments include the Company's Wood Pole Management and Grid
Modernization Programs (which are described under the investments based on asset condition).
Woshington Advonced Metering lnfrastructure Project (AMl) - Avista is in the process of deploying
advanced metering infrastructure across its Washington service territory. This effort keeps pace with the
evolving metering standard of the industry and will deliver a range of cost-effective benefits to our
customers.3e Avista is planning to begin deploying advanced metering in its ldaho service territory in 2020.
Some of the benefits of AMI include:
It is a tool to help customers gain more control over their energy
use and participate in actively managing (and hopefully reducing)
their own bills;
Better understanding by the utility of customer usage patterns in
order to customize services;
lncreased communication, including text or email alerts to let
customers know when their usage hits predetermined targets set
by the customer, and providing customers detailed information to
help them make more informed choices;o Smart home options including customer ability to monitor and control home appliances, HVAC
systems and a range of other internet-enabled technologies;
o Easier energy theft detection;o An end to estimated bills, which are a major source of complaints for many customers, as well as
increasing meter reading accuracy, another issue of great interest to customers;
o A reduction in outage duration and impact to customers due to our rapid awareness that an outage
has occurred.
ln addition to energy conservation achieved by customers, Avista will also use the Advanced Metering
lnformation system to save energy through conservation voltage reduction (CVR)40. Energy savings can thus
delay the need for additional utility resources required to meet loads. The advanced metering system will
also help Avista reduce the average duration of system outages, as advanced meters immediately notify the
Company of an outage event, its magnitude, and the
exact location of the customers impacted. This capability
reduces the average time between the outage event and
when the Company becomes aware of the outage,
understands its full extent, and can dispatch crews to
restore service.al The Company has prepared a complete
business case for its advanced metering program, which
is available on request. The planned annual capital
investments for the upcoming five-year period are
shown in Table 5.
3e Avista's Advanced Metering lnfrastructure program business case is available from the Company upon request,
a0 Conservation Voltage Reduction or Voltage Optimization saves energy by keeping the voltage on a distribution circuit to the lower end of a
tolerance band so loads draw less power. Customers don't even notice the change, but it can save up to 4% on a circuit, 80-90% of which is on the
customer side of the meter, a direct customer savings. http//blogs.dnvgl.com/energy/is-conservation-voltage+eduction-truly-energy-efficiency
a1 Today, Avista is generally made aware of an outage event when a customer calls in to report their loss of service. While the elapsed time in many
instances will be fairly small, there are many other cases where the delay in notification can be substantial, such as outages that occur late at night
when customers are asleep, when they are away from home, or when they are not part of a primary outage event (the portion of the gdd where
repairs are being made).
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 55 of 1 03
a
a
a
Avisto Smort Meter
o
o
-=j'-
g'P
It
Washington AMI s32,ooo,ooo 5s3,000,000 s35,ooo,ooo s14,300,000 So
2017 2027207820192020
Toble 5. Woshinqton AMI Planned Annuol lnvestments
Distribution Systems Automotion - ln the prior decade Avista has taken advantage of the opportunity to
deploy new technology systems and equipment that enable us to detect an electric outage and to
automatically restore service to many of the impacted customers much more quickly, thus reducing the
number of customers impacted by a sustained outage. lntroduced as the
"smart circuits" program, this approach uses automated equipment on the
feeder, such as reclosers, along with communications with these devices and
an integrated distribution management system, to quickly assess how to
isolate the particular section of the feeder where the outage has occurred, and
to reconfigure the feeder system in a manner that allows us to reconnect
customers quickly beyond the isolated section of the feeder. This "feeder
automation", which is part of the Company's Grid Modernization Program,
covers the installation of remote communications to a feeder, combined with
equipment that can be remotely operated as needed. lmplementation of Viper Recloser
feeder automation improvements is guided by the Company's Feeder Automation
Strategy.a2 lf the Company did not make these reliability investments, it would likely result in a greater
investment made in other programs as part of our ongoing effort to uphold and maintain our current level
of system reliability. An average of approximately 8.3%43 of the planned annual capital investment under the
Grid Modernization Program is used to fund feeder automation improvements, shown in Table 5.
Toble 6. Grid Modernization Planned lnvestments
Acceleroted Replacement of Problemotic/Failing Assets - A particular class of reliability investments
that are a subset of asset condition-based replacements are those targeting particular assets whose
performance is deteriorating more quickly than was initially expected, and often at an accelerating rate.
Though these replacements may be properly classified
as based on asset condition, their expected rates of
failure rises to level of a significant reliability impact.
An example includes the earliest generations of
Old coble, susceptible to foilure
underground electric cable
first installed by Avista in the
1970s. Because of the
tendency of the cable
insulation to fail, the accelerating rates of failure we were experiencing, and
because of the substantial repair time associated with failed cable, Avista began a
systematic replacement of this material in the 1990s, which has continued to the
present time. This replacement program has helped us avoid what would have been New generotion of
significant impacts to our customer's service reliability. underground coble
a2 Report available upon request.
a3 The average of actual and expected spend for the period 2015 through 2018 is 8.3 percent. This percentage was applied to the expected total
transfers to plant for the Grid Modernization Program lor 2019 - 2021t0 estimate the automation cosls shown in Table 6.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 'l , Page 56 of 103
o
o
o
l'l I t,
Grid Modernizotion S8oo,ooo s100,000 s1,204,9s0 s1,246,s00 s1,288,0s0
2077 2078 2079 2020 2021
o
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M,INoIToRY AND CONTPITE NCE INVESTMENTS
This category of capital spending includes "investments driven tvpicollv bv compliance with lows, rules, ond
contract requirements that ore external to the Componv." Avista operates in a complex regulatory and
business framework and must adhere to national and state laws, state and federal agency rules and
regulations, and county and municipal ordinances. Compliance with these rules, as well as contracts and
settlement agreements, represent obligations that are generally external to the company and largely
outside of our control. The types of electric distribution investments that fall into this driver include our
obligation to relocate our facilities to accommodate state, county and municipal infrastructure projects,
(frequently transportation related) and our compliance with environmental regulations.
Unlike compliance requirements with our electric transmission system and our federal hydroelectric
licenses, as examples, Avista has only three electric distribution investments that are mandatory and largely
outside the control of the Company, and which are described in the brief narrative that follows.
Electric Replacement I Relocation
Each year Avista is required to respond to the projects of municipalities, counties and state-level agencies to
rebuild or realign roads, streets and highways. When these projects impact our distribution facilities located
in public rights-of-way, the Company is required to remove and rebuild
them in the clear zone of the new roadway, or to place them on a new
purchased private easement. This work must be performed at the
Company's expense, and while Avista may have some latitude to
negotiate the timing of the construction, it has no choice with regard to
removing and relocating its infrastructure and paying all of the
associated costs. Our estimated capital expenditures for replacement or
relocation are shown in Table 7:
Toble 7. Required Replqcement/Relocotion Plonned lnvestments
Washington State Department of Transportation (WSDOT) Franchising
As in electric replacement / relocation above, Avista works closely with
the Washington State Department of Transportation (WSDOT) to renew
and maintain crossing and encroachment permits. This work may
require the Company to realign or modify existing infrastructure to
comply with state clear zone, conductor clearance, and other
regulations regarding the location of poles, guy wires, pad mounted
equipment, and overhead conductors. Expected capital expenditures
are shown in Table 8:
Elec Re p lo ce m e nt/ Re lo cotio n S2,4so,ooo s2,700,000 S2,8oo,ooo 53,o00,00o S3,1oo,ooo
2077 20792078 2020 2027
Frachising WSDOT s200,002 s200,002 s200,002 s200,002 s200,002
2078 2079 2020 2027
o Toble 8. Estimated Woshington Dept. of Transportation Required lnvestments
Exhibit No. 8
Case No. AVU-E-1 9-04
H. Rosentrater, Avista
Schedule 1, Page 57 of 1 03
fArEri
2077
Environmental Compliance
These required investments include implementation of U.S. Forest Service Special Use Permits, waste oil
disposal (including transformers containing PCBs), and environmental compliance with storm water
management, water quality protection, property cleanup and related issues tied to the Company's electric
distribution system. The forecast investments under these programs are based on analysis of historic
activities, as well as any specific knowledge of planned major projects, Planned capital investments are
shown in Table 9:
o
Toble 9. Estimoted Environmentol Compliance lnvestments
PenronMANcE AND Capa.cTTY INvESTMENTS
Avista,sprojectsandprogramsgroupedinthiscategoryofneedinclude,,@
address the capability of assets to meet defined performance standards, tvpicallv developed bv the
Company, or to maintain or enhance the performance level of assets based on a demonstrated need or
financial analvsis."
PERFORMANCE
These types of investments target the
maintenance or improvement of the
performance of Company infrastructure
based on demonstrated need or financial
analysis, and in cases not governed by
engineering or other standards.
STANDARDS
The performance of distribution systems is
guided by industry accepted practices,
but prescribed by internal company
policies, procedures, and standards.
These standards have been developed to
ensure the safe, efficient, reliable and
prudent management of utility
infrastructure and operations. A common
example is our objective to operate
within established thermal limits for
electrical equipment. When the Company
determines its operations no longer meet
a given standard, we must assess the
infrastructure needs and make the timely
capital investments necessary to remain
within the limits of the standard.
o
o
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 58 of 103
S3so,ooo s3s0,000 53s0,000En v iro n mento I Co m p lia nce s3so,ooo s3so,ooo
2077 2078 2079 20272020
777
s
t'
L
o
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Virtually all electric energy delivery projects or programs
have a direct or indirect link to the National Electric Safety
Code (or Code). The Code represents the collective
engineering and operating knowledge for electric utility
systems with special emphasis on transmission, substation,
and distribution networks. Though Avista develops and
maintains multiple internal standards guiding the design,
construction, and operation of electric distribution
facilities, each standard is linked to the Code, which has a
significant bearing on our practices and decision-making
strategies. ln addition to the need to comply with prudent
operating standards, Avista is also attentive to investment
opportunities to improve the performance of our
distribution system, when supported by a study or analysis
that demonstrates the cost-effectiveness of the benefits
achieved for our customers. The Company has two electric
distribution programs included under this investment driver: the Distribution Segment Reconductor
program and the LED Street and Area Light replacement program.
Distribution Segment Reconductor and Feeder Tie Program
The annual investments made under this program represent 6.9% of our planned distribution investments,
and remedy the overloading of electric equipment and cable, as well as the conductor sags that results from
overheating of the overhead wire. These instances of system overloading result from load growth and shifts
in load demand that occur over time on the distribution system. Loads on the grid are always changing as a
s lnsulators
result of many factors including weather,
temperature, economic conditions, conservation
efforts, customer usage, and seasonal variability.
Avista's distribution system follows the industry
standard of using relatively short sections of feeder
main trunk supporting longer connected lateral
lines that carry electricity to the customer's service.
Though the overall load on a feeder as it leaves the
substation is often known and monitored in real
Eyebolt\
Hot Clamp
time, the
actual
loading
on the
downstream trunk and lateral branch circuits must be estimated
using a specialized computer model. Avista uses the Synergee
load-flow model to identify and predict problems with equipment
overloading, which we subsequently field test to verify whether a
problem exists. Resolving these overloading issues involves a
combination of two strategies known as "load shifting" and
"segment reconductoring."
e When the overhead wire (conductor) on a distribution feeder is overloaded, the wire overheats and shetches, and in doing so, sags closerto the
ground than designed, which can exceed electric code requirements for safety.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 59 of 1 03
ConsEuctioa
Deslgn
Standards
Personal
P.otective
Grounding
Dlsblhrdon
Feeder
Management
National
Electric Safety
Code
Mate&l
Design
Standards
Distribution
Planning
.Hcutout
Arrestor
o
Feeder
Automation
Laterals
The strategy of lood shifting involves extending existing lines on one feeder to an adjacent feeder that has
the available capacity to carry the additional transferred load. Shifting the load from one feeder to another
not only solves the overloading issue but also helps us capture additional value from our current
investments.
Reconductoring involves the removal of the wire or conductor that is too small in diameter for the current
loading and replacing it with larger conductor that can easily and more efficiently carry the load. lt is the
most direct approach for mitigating overloaded circuits; however, Avista considers a range of options that
not only meet the current need to relieve the loading but that also provide for the optimization of the
overall distribution system. The Company has 30 known projects across our system that are planned for this
five-year cycle, with an expected annual average capital cost of about 55 million as shown in Table 10.
Toble 10. Estimated Segment Reconductor & Feeder Tie Progrom lnvestments
Avista's LED Street and Area Lighting Program
Light Emitting Diode (LED) lighting technology emerged as viable alternative to all types of conventional and
fluorescent lighting around 2009, and by year 2Ot2 over 14 million units had been installed in the U.S. alone.
This rapid adoption of LED lighting represents one of the fastest technology shifts in human history. lt is
estimated that LEDs will save U.S. consumers and businesses SZO million per year within a decade, and
reduce U.S. CO2 emissions by up to 100 million metric tons per year. LED bulbs cut electricity use by up to
85% compared with incandescent bulbs, and 40% compared with fluorescent lighting.as
Government jurisdictions generally take on the responsibility of providing adequate lighting at night for
streets and paths, sidewalks, and/or highways because of its statistically proven reduction in vehicle, bicycle,
and pedestrian accidents, as well as reduction in property thefts.
Avista operates approximately 35,000 street lights we have
installed for many of these jurisdictions across our service territory
as well as area lights requested and paid for by individual
customers. ln 2013, in response to the superior safety performance
of LED lighting, the energy savings potential, and the opportunity to
reduce long-term energy costs, Avista evaluated the benefit of
converting all our Schedule 42a6 street lights from High Pressure
Sodium (HPS)to LED fixtures. ln evaluating the potential benefit,
the Company studied the customer benefits associated with three
different alternatives, which are summarized in the text box on the
next page. For all three cases, Avista used the Availability
Workbench model to assess and compare the public safety risks,
o
o
resource costs, energy savings, and the overall financial benefits for
each case. Though the optimized base case provided the highest benefit LED (left)vs' sodium (right)
to customers based solely on the capital installation and long-term maintenance costs, the LED case
ultimately provided the greatest overall customer benefit due to the incremental value for the electricity
a5 hftpsJ/thinkprogress.org/5-charts{hat-illustrate{he-remarkable-ledJighting+evolution-83ecb6c1 f472.
a6 Schedule 42 available at https://www.myavista.com/-/media/myavista/content-documents/our-rates-and-tariffs/id/id_042.pdf?la=en
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 60 of 1 03
ss,ooo,oooSegment Recondudor ond Feederfie Progrom Ss,17s,848 s4,899,994 $s,ooo,sos ss,ooo,0o0
2017 2018 2019 2020 2021
o
,i'il
Convertlng Hlgh Pressure
Sodlum (HPS) to LightEmlttlng
Dlodes (LED) - The Altematlves:
1) Base Case - continue to rely
on our hiSh pressure sodium
street and area lights, and
continue to replace the bulbs
and fixture as failed lights are
identified on our system.
2) Optimized Ease Case -
Optimize the continued u5e
of our high pressure sodium
street and area liShls by
systematically replacing all of
the bulbs in our system over
a period of five years, and
systematically replacing the
photocell component of the
fixture over a period of 10
years.
3) LED Casc - systematically
replace our existing hi8h
pressure sodium street and
area liShts with new LED
fixtures,
o
o
savings4T that were not achieved in the base and optimized base cases. When considering all factors, the LED
case provided our customers the greatest level of benefit.
The program was launched in 2015 and focused initially on
replacing our 100 watt conventional ("cobrahead") street lights.
Replacing 200 and 400 watt lights was added to the program due
to subsequent price reductions for these wattages. Avista has
targeted this program for completion in 2019, in part to capture
an additional benefit for our customers offered by the State of
Washington's Transportation lmprovement Board (TlB). ln 2015,
this Board established a statewide grant program known as Relight
Washingtonas, which is administered for the state by Avista. This
program provides small communities in our Washington service
area an offset to their street lighting costs when their community
is converted to LED lighting. The Company expects that the timing
of this program will provide our customers with an additional
benefit of 52,289,OO0 that is above and beyond the customer
benefits evaluated in the three alternatives.4s The total
investments for the LED lighting replacement represent
approximately 2.6% of the total distribution investments planned
for this period.
Actuals for the LED program are shown in Table 1L; planned
capital spending for the Distribution Segment Reconductor and
Toble 17. Actuol LED Chonge-Out Progrom
Toble 12. Estimated LED Change-Out Progrom lnvestments *See Footnote 5O
a7 ln addition to saving our customers money, the energy saved also contributed to meeting the Company's mandated targets for energy
conservation.
48 http://www.tib.wa.gov/g rants/smallcity/LE DSmallcity.cfm
ae Annual Energy Savings are estimated to be 75 watts per fixture (100 watt High Pressure Sodium (HPS) bulbs consume 135 watts. These bulbs
are replaced with 100 watt LED bulbs which consume 60 watts.)
s0 Avista's Oracle financial system reflects the individual fixtures charged against the program each year as presented here. Avista's program
manager reports the actual number of installed for 2015 and 2016 as 4,057 and 8,096, respectively. Note that TIB credits are received when all work
has been completed, which does not necessarily fall within the budgeted year.
Exhibit No. 8
Case No. AVU-E-1 9-04
H. Rosentrater, Avista
Schedule 1 , Page 61 of 1 03
LED Change Out Program 52,899,92s s1,999,994 s2,319,930 s2,ooo,ooo So
2017 2078 2019 20212020
s2,320,m0 s1.s00.007 s2.400.m0 s2.ss1.878 4,055 5,378 262,W 3L2,4502015
s4,983,s892016S2,32o,mo s1,558,788 s4,110,000 <s443,866>L0,292 13,@ 3m,0@
2017 s3.300.m0 s2,899,937 9,s38 375,000
s2.0@.000 4.965 4875002018
2019 s2320,000 4,957 600,0@
2020 s2.000.000
lnitial Funding
Request
CPG lnitial
Approved
Budget
CPG Revised
Final Budget
Actual
lnvestment
Planned Actual
Replacements Replacements
Planned Energy
Savings (Watts)
Actual Energy Savings
(watts)TlBCreditsYear
o
I\i
I
t\
LED Street and Area Light Programs, which comprise all distribution infrastructure investments under the
Performance and Capacity investment driver, are shown in Table 12 (see footnoteso). Note "CPG" is the
Capital Planning Group.
INVESTIViENTS BESEP ON ASSET CONOITION
Assets of every type will degrade with age, usage and other factors, and must be replaced or substantially
rebuilt at some point in order to ensure the reliable and acceptable continuation of service. Projects or
programs in this category of need are defined as: " investments to reploce
assets bosed on estoblished asset monooement principles and svstemotic
proarams odopted bv the Companv. which ore desioned to optimize the overall
lifecvcle volue of the investment for our customers." The replacement of assets
based on condition is essentially the practice of removing them from service
and replacing them at the end of their useful life. Across the utility industry,
and likewise for Avista, the replacement of assets based on condition
constitutes a substantial portion of the
infrastructure investments made each year. At
Avista, we aim to manage our assets in a manner
that optimizes their overall value over the lifecycle
of each particular class of asset. We say that asset
replacement strategies are "optimized" in the
sense that a given approach may not achieve the
overall lowest possible lifecycle cost, but rather the
lowest cost that allows us to meet a variety of important performance objectives, such as electric system
reliability or the efficient use of employee crews. Because failure of critical assets is unacceptable, they must
be replaced near the end of their useful life even though they are still providing reliable service. ln other
instances it may be reasonable to wait until an asset fails before it is replaced, a strategy known as "run to
failure." Examples of distribution asset management programs employed by Avista include the replacement
of wood poles based on condition as determined in routine inspections, replacement of transformers based
on age and PCB removal, and replacement of first generation (and failure-prone) underground electric cable.
Overview of Asset Management
All developed economies are underpinned by a vast public and private infrastructure comprised of roads
and other transportation systems, water and waste, telecommunications, internet, and energy systems.
Most of these
systems are taken for
granted until
something fails or no
longer provides the
expected level of
service.
lnfrastructure, such
as our electric and
natural gas systems,
represents a major
investment, much of
which has been built
up progressively over
the last 1-00 years or
longer, and which
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 62 of 103
o
o
o{P
ooSrlr
@
EUSrN€SS
MANAOEI.IENT
CAPITAL
PQOJEC,TS
.L *P*
IMPLEMENTANON
PERFORMANCE
MANAGEMENT
Which molntenonce octions
should I give priority?
RISK.BASEDMAINTENANCT -
&acerrue corrnol !
How do I develop my orgonisotion
ond processes to monoge my ossets?
How do I meosure the
performonce ol my asset
portfolio?
Which investments do I need
to keep my assets in the right
stote?
STRATEGIC
PI.ANNING
How can I get ond keep in
contrcl my CAPEX projects
to dssute thet lifecycle
pe$ormonce?
\ PRO.IECTPI.ANNING7 acoNrnor
o
o
can often have an expected service life of many decades. Maintaining the function, achieving performance
goals, optimizing the useful life, as well as planning for the timely replacement of infrastructure is the
province of the modern science of asset management, as depicted in the diagram.
The "lnternational Organization for Standardization (lSO) has defined the requirements for an asset
management system, which have been adopted for widely ranging infrastructure types, including energy
systems.sl For the "how" to implement an asset management program, industries rely on the lnternational
lnfrastructure Management Manual (Manual).s2 The manual articulates multiple approaches and
methodologies for performing various functions in asset management, as well as providing case studies that
demonstrate the applications. These approaches range from more-easily implemented qualitative processes
to more sophisticated quantitative methods, and combinations of both. Avista's asset program is guided by
these standards, and the Company relies on the lnfrastructure Management Manual for implementation
support.
Asset Management at Avista
Avista's program began with an initial evaluation of the
Company's electric system assets completed in 2003. ln a later
step we adopted a Reliability Centered Maintenance (RCM)
approach to asset management that focused on development of
work plans and financial analyses for each class of assets. ln 2006
the Company acquired the asset management analytical software
"Availability Workbench." Developed by the firm lsograph,s3 this
relia bi I ity-centered mai ntena nce model ca n perform integrated
analysis on a single asset, a system of assets, or an entire asset
system, such as a generating station, based on identified needs and objectives.sa This analysis is used to
optimize maintenance and replacement strategies, analyze individual assets in context of an asset system,
develop lifecycle costs estimates, and provide future projections of performance, allowing actual results to
be validated and the model refined.
Avista's asset management goal is to optimize the value of the infrastructure investments we make in the
service of our customers.ss To this end, an asset management system supports decisions on what assets we
should build or purchase, the type of maintenance program needed to support each asset, how factors such
as system reliability are considered in asset life and performance decisions, and when and how an asset
should be rebuilt or replaced. This optimization allows us to drive down the total cost of ownership while
51 The lntemational Organization for Standardization (lSO) standards 55000 and 55001 specify the requirements for establishment, implementation,
maintenance, and improvement of a management system for asset management. They do not define how an organization should implement asset
management. Rather, as discussed in standard 55002,sr the organization's context and needs should define and drive the asset management
system that is ultimately implemented. ln this context, the ISO standard focuses on 'lvhat an organization should do." Together, standards 55000,
55001, and 55002, encompass the evaluation of costs as well as benefits, risks, and asset performance, both internal and external to the
organization. BSI Standards Publication, BS ISO 550001:2014. httpJ/www.iso.org/iso/home.html
s2 http://www. nams.org. nzlpages/273lintemational-infrastructure-managemen!manual-201 1-edition. htm.
s3 lsograph, founded in 1986, is one of the world's leading companies in the development and provision of integrated Reliability, Availability
Maintainability and Safety software products. The company has offices near Manchester, UK and Salt Lake City, Utah.il Availability Workbench essentially sums all of the probabilities and associated costs and benefits for an asset or system over a given period of
time. The model resolves the complexity of the multiple probability functions, including schedule of maintenance activities and different ages and
costs of assets, to produce mathematical curves representing forecasted failure rates and lifecycle costs. The model integrates asset-related risks,
resource requirements for labor, and material and equipment to produce cost estimates and projections for alternative management decisions.
55 Whether the investment touches the customer directly, such as our customer service or metering systems, or indirectly, such as improving the
capability and efficiency of our employees and work processes, each capital dollar we invest ultimately supports our ability to provide our customers
with safe, reliable, and cost-effective energy services that meets their expectations for quality of service and value.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 63 of 1 03
./2-au
<
o
r
achieving important
performance criteria and
objectives. ln its simplest form,
this optimization is depicted in
the Figure 29 line graph.
ln this depiction for a
generating asset, the present
value of the replacement cost
declines with increasing service
life, which is offset at some
future point by the present
value of the increasing costs
associated with maintena nce
requirements and the
consequences of failure. The
objective of asset management
Oenruut* Tt *n Na to Fongc.asr Rzetecavzt tt
!t
sfoc
c
ooo!o
co
cA
4.000
3.5{n
3,m
2.5m
2.m
1.500
t.m
500
I
Minimw Cost
a1_-
0
d +t'b td .s
-
Rrglrcmert Oost
-
ton Efiicicmy Oppmnity -
Cost Ris k of Defeml
.....Total C6t -
L6t GeneBtion Risk of Defsral
o
is to identify the strategy that Figure 29. Forecast of Optimum Replacement
achieves a reasonable total
lifecycle cost for each type of asset while meeting a range of other important objectives (i.e. identifies that
lowest cost point on the line). lmportantly, each type of asset will have a unique lifecycle cost curve based
on the expected life, maintenance needs, and likelihood and consequence of failure.
Assets supporting critical business functions such as a generator
(i.e. where the consequence of failure is not acceptable) must be
replaced earlier in their lifecycle to avoid the risk of failure, while
certain assets can remain in service until they actually fail before
being replaced (i.e. any negative consequence of failure is
outweighed by the lifecycle value associated with longer service
life).
Avista's electric distribution infrastructure programs under the
Asset Condition driver include Distribution Wood PoleMointoininq o hvdro unit Management, pCB Transformer change-out, Underground cable
Replacement, Grid Modernization, and Worst Feeders. Collectively, the Company relies on these primary
programs for making systematic investments in our distribution plant, which allows us to cost effectively
maintain a safe and highly reliable system that meets the expectations of our customers. Four of these
programs were developed with support from the Company's asset management group, which has continued
to support them as needed through the course of implementation. These programs are discussed in more
detail below.
Wood Pole Management
As noted earlier, Avista has approximately 347 overhead electric feeders that are supported by
approximately 240,000 wood poles. These poles are predominantly cedar (90%) as well as larch, fir and
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 64 of 1 03
o
o
att
/
o
o
steel. The attached equipment includes crossarms, transformers, cutoutss6, insulators and pins,sT wildlife
guards, lightning arresters, guy lines,ss and pole grounding.se Poles and equipment comprise the primary
infrastructure of the Company's electric distribution system.
lnspection Cycle Time lnterval- ln managing these assets it is the Company's goal to repair or replace
aging poles and equipment in our system before they actually fail, but late enough in their expected life
span to capture the overall value of the initial and any follow-up investments. The practical way to
accomplish this is to systematically inspect each pole in the system on a regular basis and to make any
investments needed to replace failed poles
and equipment, ensuring they don't fail
before the next inspection cycle. The
central question is what time interval to use
for the inspection cycles.60 Generally, more
frequent inspections (shorter cycle time)
reduce the likelihood that poles and
associated components will fail sometime
during the interval between inspections,
but they also cost more because the annual
number of poles inspected is greater than
with a longer cycle interval. The optimum
interval for the inspection cycle can be
mathematically determined based on the
characteristics of the wood pole population,
the associated operating expenses, and the
likelihood and cost of customer service
outages resulting from any poles or
equipment that fail between inspections.
Our focus on wood pole management
began in 1988 and attempted to address
the feeders in greatest need based on local
area knowledge. Early funding was limited
in part by the lack of system data and
overarching program goals. The Company's
initialevaluation of the cycle interval,
performed in 2008, pointed to a 2O-year
cycle as preferable to both a shorter 10-
year interval and a much longer L00-year
interval.6l At the time Avista conducted this
analysis, its effective cycle time was in the
56 Fuse devices that protect the feeder and equipment in the event of a fault on the line.
s7 The overhead wire or conductor that canies the electric current is attached to insulators that prevent the conductor from faulting, and each
insulator is attached to the pole or crossarm with a pin.
58 Guy lines are the wire support attached at the upper pa( of the pole and anchored into the ground diagonally to counteract tension on pole as
needed to keep it stable, upright and plumb.
5e Pole grounding is used to ensure the pole and equipment is electrically grounded so that any fault goes safely to ground.
60 The inspection cycle interval is the period of time within which every pole in the system will have been inspected and treated as needed.
61 ln this evaluation, the 100-year interval, which was longer than Avista's effective interval at the time, represented a scenario where most of the
poles that failed would be replaced on an unplanned basis instead of being treated or replaced during the follow-up to inspection.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 65 of 1 03
What's on an Electric Power Pole?
--I
lt
I-LI
r
-?--
GuyWire
lnsulator
Crossarm Cutouts
Transformer
trw
Fotmr
Primary
Wires
Lightning
Arrestor
Neutral
Wire
Secondary
Wire
Telephone
& Cable
Wre6round
Wire
o
*tf|.--
Wood Pole Inspection Cycle Analysis: Customer IRR
7.4%
72%
7.O%s
E 6.8%
Eon 6.6%
6-4%
6.2%
6.O%
20 Year WPM 15 Year WPM 10 Year WPM 5 Year WPM
lnspection Cycle lnspection Cycle lnspection Cycle lnspection Cycle
lt rttt
t-l tt tt ttltttlttt
Figure 30. Wood Pole Inspection Cycle Analysis
This analysis pointed to ten years as the cycle interval, followed in order of value by the five-year, fifteen-
year and the twenty-year cycles. The incremental increase in value captured by a cycle interval shorter than
20 years is the result of avoiding failures in poles that would otherwise occur with longer inspection cycles,
which results in more customer outage time and increased capital and expenses required for unplanned
replacements. Essentially, these increasing costs for unplanned repairs and outage time outweigh the
additional expense of more frequent inspection intervals (in the range of L0 years).
range of 40+ years, and based on
this evaluation, the Company
chose to reduce its inspection
interval to 20 years. ln 2012 Avista
again evaluated the impact of
cycle interval on the long term
value for customers using the
Availability Workbench model. ln
addition to better analytical tools,
we also had better data on our
pole population as well as costs for
inspections and follow-up capital
work. Four cycle intervals were
evaluated ranging from 5 to 20
years and results of the analysis
are shown in Figure 30.
o
Although the above results
demonstrate a greater overall
customer value for a cycle
interval of L0 years, the
Company is continuing with its
20-year inspection cycle. The
reason is that any reduction in
cycle time requires an up-front
increase in expenses to pay for
the increased number of poles
inspected each year, and a
corresponding increase in
requirements for capital
replacements. Though a cycle
time shorter than 20 years Avisto Pole lnspectionwould likely provide our customers greater value over the long term, Avista
believed the incremental increase in costs at that time, in addition to the incremental increase already
absorbed by adopting the 20-year cycle in 2009, would put too much near-term price pressure on our
customers, considered in combination with Avista's many other infrastructure investment needs.62 The
Company remains cognizant of the potential for capturing greater value with a shorter cycle interval as a
reliability improvement strategy, particularly if at some point, we were to adopt a reliability strategy
intended to improve the overall performance of our system compared with the status quo.
62 Please see the report: Avista Utilities lnfrastructure lnvestment Plan, May 2017
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 66 of '103
Rising costs of a single
distribution pole
l960 ro 20lS @ o
o
@
@
@
at"'l
ii, '
,"
rf
1960 1980 2000 2015
Adg odarrE.BdGrcly 2{4OoO
dlfirlbuds ,916 F6 hr aN,te sffory.
o
o
lnspection Progrom - Avista's current Wood Pole Management Program has four primary components:
lnspections,63 Design, Construction/Follow-up, and Auditing. ln order to achieve a 20-year cycle interval
Avista crews must inspect an average of approximately 12,000 distribution poles and crossarms each year.
The number of poles inspected in each year of the program is shown in Figure 31.
During the inspections the actual condition
of each pole is assessed to determine
whether any issues need to be addressed,
rather than relying only upon age
information to categorize the health of the
pole. The inspection process identifies
damage from insects, animals, lightning,
fire, decay, mechanical damage, equipment
failure (such as a leaking transformer),
unauthorized attachments, and other
damage such as a broken guy wire or
grounding/soil issues. Decay is the most
common reason for pole failure and is
readily detectable with proper inspection.
Figure 31. Wood Pole Annual Inspections
Results of the inspections are used to design
the capital repairs and replacements that need to be performed under the activity referred to as "follow-up
work." ln2012 Avista initiated the Grid Modernization Program (described below)which is dovetailed with
the Wood Pole Management Program to make optimized use of crews and materials supporting the
Distribution Wood Poles Inspected Ar:nually
18
c'16!Er+:
21,2F7too38
36o24clz2
0
2009 2010 20Lt 2072 2013 20t4 201s
--lnspections - - -Target
20t6
Company's wood pole
management. ln order to remain on
a 20-year inspection cycle, Avista
must complete the necessary
follow-up work on approximately
385 miles of feeder lines each year,
combined between the Wood Pole
and Grid Modernization Programs.
Since 2008 the Company has
inspected and completed follow-up
capital work on approximately 3,456
miles of overhead electric feeders.
The miles of follow-up work
completed each year since 2009 are
shown in Figure 32.
Annual Number of Feeder Miles Completed for Wood Pole
and Grid Modemization Capital Repair and Replacements
500
450
4m
350
3m
250
2m
150
1m
50
0
2m9 2010 2011 2012 20L3 20L4
rCombined wPM and GM Follow-up miles completed
2015 20L6
- -Target
Fiqure 32' wood Pole Feeder Miles Completed
Since initiation of the program,
Avista's wood pole management protocol has evolved to more effectively utilize crews performing the
inspections. Personnel now identify the need to replace pre-1960s transformers, identify transformers that
may be inefficiently sized, install grounds or guy wires where needed, and insure that equipment meets
current safety standards. Numbers of individual assets that have been replaced or reinforced (repaired)
during the capital follow-up work are shown in Figure 33 (next page).
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 67 of 1 03
o 63 The inspection activities for this program are an operating expense and are not capitalized.
ln each 20-year cycle, all of the
distribution wood poles in our system
will have been inspected and treated as
needed, at which point the cycle
commences again. Starting in 2020
funding from the PCB Transformer
Change-Out Program will be
incorporated into the Wood Pole
Management and Grid Modernization
Programs in order to replace the
remaining pre-L981 transformers in our
system. Planned and actual capital
investments for the Company's Wood
Pole Management Program from 2005
- 2016, as well as the forecast through
year 2021, is shown in Table 13 (see
footnote64). Note "CPG" is the Capital
Planning Group.
Distribution Assets Replaced Based on Inspections
2@9 2010 2011 20t2 2013 2014 2015 2015
r CrossArm Rephcemnts a Pole Replacements r Transformers Repla@d r Reinforcements
Figure 33. Wood Pole Management Assets Replaced
3,500
3,000
2,500
2,000
1,500
1,000
5m
co
EoUGEod.
o
ll
o
o
o
o
435
372
332
274
273
279
326
Toble 13. Wood Pole Monogement Program *See Footnote 64
Growing Demand for New lnvestment - Beyond this current planning period, the need to fund end-of-
life asset replacements for our overhead electric feeders will continue to increase for the foreseeable future
The primary driver for this increasing need is the age distribution of the Company's wood pole population
now in service. Avista's distribution wood poles have an average life span of approximately 80 years as they
are managed in our system today. The current age profile of the population is shown in Figure 34 (next
page). This age profile shows the estimated number of poles by age group in the Company's distribution
system. The brackets and the dashed trend lines highlight the difference between the numbers of poles still
in service that were installed prior to and during the Second World War, compared with the much greater
6aUnits of Work are in Circuit Miles Addressed.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 68 of 1 03
2005 51,2m,oo3l 5L,L28,4L9
2006 51,2oo,oool S1.08s.406
2Co7 Sr,q54,o3sl 5L,968,437
2m8 54,923,0O11 s4,7sO,s73
2m9 S:,zoo,oorl 57,494,569 500
2010 soas4,oorl 57,so7,r44 450
20t7 Sa,ass,szol 59,LL&,377 459
2012 S10,486,300 ss,4ss,zrol s10,121.300 S10.064,203 4L6
2013 s9,486,300 Sg,zsr,eeel Se,2s1,686 $9,2s8,7L3 445
20L4 s11,50O,OOO 5s,sm,orrl Ss,sso,ooo s9,s12,319 4t2
2015 s11.s00.000 sn.ooo.oogl slo.Goo,ooo s9.111,4s3 390
20t6 Sr-1,200 ooo S7,s4o,oo1l S8,44o,ooo 22358,@L,732
2017 s14,7m,OOO ss,ooo,oorl 336
lnitial Funding
Request
CPG lnitial
Approved
Bud8et
CPG Revised
Final Budget
Actual
lnvestment
Planned Circuit Actua! Circuit
Miles Miles
Addressed * Addressed *
Year
3s3
o numbers installed in the period following. The difference in the rates of growth in our system between these
two periods of time is depicted as the difference in "steepness" between the two dashed trend lines.
Age Profile of Electric Distribution Wood Poles as of 2017
0 Crews face o voriety of
unique situotions in
inspecting wood poles
0 5 10 15 20 25 30 35 40 45 50 55 50 55 70 75 80 85 90 95
ABe of Poles
Figure j4. Wood Pole Age Profile
To demonstrate the effect of this age profile on the Company's future need for investment, Figure 35 shows
the same age profile, but only for those poles currently 65 years and older which number about 22,OOO.
As the overall population
continues to age each year,
again, due to the shape of this
age profile, the number of poles
in this 65 years and older group
will increase as depicted in
Figure 36 (next page). ln this
example the number of poles in
this age group will have
increased from 22,000 today to
over 30,000 by year 2024, and
the upper bound of the age
range will have increased from
95 to 103 years.6s
Wood poles tend to fail at
increasingly greater rates each
year as they age, thus the Figure 35. Wood Pole Age Profile as of 2017
65 This increase in the number of poles aged 65+ years, including the upward exlension of the maximum age to over 100 years, does not include the
number of poles that are expected to fail over this period of time, which have been accounted for and subtracted in this forecast.
Exhibit No. 8
Case No. AVU-E-'|9-04
H. Rosentrater, Avista
Schedule 1, Page 69 of 103
5000
5000
4000
3000
2000
1000
o6C
o
0,l)Elz
o
*'"i,l?i',I#""'
Wood Poles lnstalled
1927 - 1946
I
93 95
11u,,.,11,,,1,. il, r
59 7t 73 75 77 79 81 83 85 87 89 9l5765
Age Distribution of Wood Poles 65 Years and Older in 2017
Age of Poles in Years
2500
2m0
1500
1m0
5m
q,
oo-
o
o-o
Efz
0
o
rr
ooo-
o
o!
Efz
3m0
2500
2m0
1500
1m0
5m
0
Age Distibution of WoodPoles 65 Years and Older rm2017 nd2024
I lr I t-.-_l
65 67 69 7L 73 75 77 79 8L 83 85 87 89 91 93 95 98 100102
Age in Years
rAverageAge 2017
-AverageAge
2024
V \A\
I
tl
A lLItI
Figure 36. Wood Pole Age Distribution - 2017 and 2024
continuing our 20-year inspection cycle interval. The known effects of the shifting age profile in our
overhead distribution system allow us to forecast future investment needs with relative confidence. By year
2040 the expected annual investment for the Wood Pole Management and Grid Modernization Programs
will rise from the current annual level of about S24 million to approximately S70 million, as shown below in
Figure 37.66
As noted earlier, this upward trend in distribution investments is far from unique in our industry, where
investments tend to be cyclical,6T as exemplified by the difference in our system growth rates over time. The
once-new investments that came in "waves" generations ago now require a wave of re-investments to
refresh that infrastructure, Forecast ofElectricDistribution Investments 2022-2040
which has delivered a lifetime
of service. Whether noted in
numerous trade publications,
identified in government
reports, documented in
studies like the "investment
gap" report by the American
Society of Civil Engineers, or
as demonstrated here by the
Company, investments in
electric distribution
infrastructure are on the rise
and the need for increasing
levels of investment is
expected to continue for
many years to come.
570
66 An annual inflation rate of 2% is assumed for each year in this forecast.
672015 Financial Review: Annual Report of the U.S. lnvestor-Owned Electric Utility lndustry. Edison Electric lnstitute,
http//www.eei.org/resourcesandmedia/industrydataanalysis/industryfinancialanalysis/finrevieWDocuments/FinancialReview_2015. pdf
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 70 of 1 03
s60
o
= sso
Ea: 540c
OJc.: sx)
OJ
ofc€ sro
so
greater number of poles in this
older age group results in a
greater number of poles that will
have to be repaired or replaced
every year. As a result, the
amount of capital repairs and
replacements that will need to
be completed during the follow
up work each year will increase
in proportion to the increased
number of older poles in the
system. Based on this population
data, Avista used the Availability
Workbench model to forecast
the number of wood poles,
conductor and related
equipment that will have to be
replaced each year based on
2024 2026 2028 2030 2032 2034 2036 2038 2040
r Grid Modernization :; Wood Pole Manatement
Fiqure 37. Proiected Electric Distribution Investments
o
o
2022
o
-l
o Distribution Grid Modernization
Purpose - The purpose of this program is to cyclically rebuild and upgrade every electric feeder in Avista's
distribution system, with the objectives of improving service reliability, capturing energy efficiency savings,
and improving operational ability, code compliance and safety
These objectives are accomplished through the systematic
replacement of aging equipment that has reached the end of
its useful life, such as old poles, conductor and transformers,
with new and more energy efficient equipment that ensures
the long-term operability of the system. On qualifying feeders,
additional system reliability value is captured by installing
distribution line automation devices to help isolate outages,
reducing the number of customers that experience a
sustained outage (feeder automation).
lnitial Progrom Scope - The program was initiated in
20L3 and was built on the 2009 Avista's existing Feeder
Upgrade
program and the
Distribution
System
Efficiencies
analysis and
report which
evaluated the
energy savings potential that could be captured by replacing end-
of-life assets across Avista's distribution system. The report also
prioritized the individual feeders based on their potential
treatment costs and benefits to our customers. The assessment of
costs and benefits was based on analysis of energy losses in
feeder conductors, distribution transformers, and service lines,
the potential savings associated with reactive power
compensation,6s and overall economic analysis. Early in the
program, staff developed a Feeder Prioritization Tool that was
used to assess, score and rank each of the Company's 347 electric
feeders, as discussed below.
The initial scope of Grid Modernization also included the
evaluation and deployment of distribution line automation
devices based in part on the methodology Avista developed for deploying such technology under the
Company's Smart Grid lnvestment Grant through the U.S. Department of Energy.6e A key objective of this
feeder automation effort is to take advantage of the value remote operability provides to quickly
68 ln a simplifled explanation, altemating electric current (AC) has two components, being active power (sometimes also called real power), which
provides the energy used by our customers, and that portion of power that is essentially stored energy that returns to the source of generation in
each cycle, known as reactive power. The degree to which these two components are in-phase or out-of-phase determines the amount of active
power that is delivered. Since the types of customer loads on a feeder have an impact on the respective balance of these two power components,
installing devices that help balance the components can result in energy conservation savings for customers.
6e https://www.smartgrid.gov/recovery_acUoverview/smart_grid_investment_grant_program.html
Exhibit No. 8
Case No. AVU-E-1 9-04
H. Rosentrater, Avista
Schedule 1, Page 71 ot 103
Grid Modernization
lntegrated Programs
F Wood Pole
Management
Program
> PCB Transformer
Change-out Program
F Vegetation
Management
Program
F Segment Reconductor
and FeederTie
Program
z Various budgeted
maintenance
programs
Above: Spokane
Smart Grid
Switching Device
Left: "Smort"
tronsformers
provide the exoct
omount of power
needed, respond
to fluctuations
and oct os o
voltoge regulotoro
o
sectionalize a feeder in order to reduce the overall impact of service outages for our customers. To
accomplish this, Avista installs automated line devices, such as midline reclosers, switchable capacitor banks,
air switches, and the digital communications necessary for the Company to operate the devices from our
dispatch center in response to an outage event.70 ln addition to the energy conservation analyses derived
from the distribution system efficiencies work, Grid Modernization developed estimates of the capital
investment required to implement the efficiencies programs. The effort also relied on the Company's asset
management group using the Availability Workbench model to forecast the long-term reduction in
operating expenses resulting from rebuilding feeders.
Assets addressed under the program include: undersized and
deteriorating conductor, failed and end-of-life assets including
wood and steel poles, cross arms, fuses, insulator guys, arresters,
cutouts, grounds, street and area lights, and avian protection.
Other issues addressed on each feeder include: pole re-alignment
to address accessibility issues, rights-of-way concerns, potential
feeder undergrounding, coordination of joint use facilities and
clear zone compliance. This systematic approach is enabling Avista
to cost-effectively deliver an up-to-date and more robust electric
distribution system that is more energy efficient, easier and less
costly to maintain, and more reliable for our customers.
o Deteriorati ng Conductor
o Foiled lnfrastructure
. End-of-life I nfrostructure
o
o
Grid Modernization was initially optimized at a cycle interval of 60
years, meaning that over that period of time the program would
rebuild and upgrade every feeder in the distribution system.
Selection of this interval related to the average life span of our
distribution infrastructure as well as the 20-year interval cycle for
the Wood Pole Management program. These two programs are
integrated in several important ways. Grid Modernization relies
on the inspection data from Wood Pole Management for its asset
condition assessment, and targets the timing of feeder
construction to optimize the value of wood pole inspections and
follow-up work already performed. Wood Pole Management relies
on the poles replaced by the Grid Modernization Program as
contributing to the total number of poles they have to inspect and
address each year to remain on the 20-year cycle.
Chonges in the Program - Grid Modernization's scope has been
expanded to include replacement of all pre-L981 distribution
transformers during a feeder rebuild, under guidance of the PCB
Transformer Change-Out Program, discussed later in this report.
Avista's Distribution Feeder Management Plan was updated and
refined in 2016 to address the need for additional guidance in
making incremental investment decisions under the Grid
Modernization Program. This work, which included engineers
from the Company's Asset Management and Distribution
. Undersized Conductor
o Wood poles
o Cross Arms
o Fuses
. lnsulators
o Accessibility lssues / Pole
Reolignment
. Right-of-Woy Conce rns
. Potentiolfor
Undergrounding
o Coordinating Joint Use
Facilities
70 Midline reclosers allow prevention of tripping downstream of a fault. Switchable capacitor banks help support voltage and provide power factor
conection - the ability to switch allows them to be used only when needed. Air switches can allow isolating a section of overhead line when a fault
occurs.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 72of 1O3
Asset Groups Rebuilt
Treatments
o
o
o
Standards groups, was also used to help refine the scope of the program. As an example, based on that
evaluation, data on the average lifespan of our wood poles was used to optimize the age at which our poles
are replaced when a feeder is rebuilt. Grid Modernization now replaces cedar poles older than 60 years and
larch poles older than 40 years. Also in 20L4, the Company enhanced its engineering support for the
program, which allowed us to develop a more robust analysis in our Feeder Baseline Reports (more details
on this report are shown in the text box) that included additional scoping guidance and recommendations
for load balancing, power factor support, segments in need of
reconductoring due to capacity limitations, and
recommendations for installation of feeder automation devices
Grid Modernization
Baseline Report
o Anolysis of reliability results
for three indices from 2006 to
present
o Study of the octual loodings
on eoch phose of the feeder
under o ronge of seasonal
conditions
o Modeling overoge ond peak
loadings expected ofter the
phase loads ore balanced
higher-capacity
conductor
installed to avoid
overloading or to
meet future
capacity
requirements
(Segment
Reconductor and
Feeder Tie
Program), all
performed by
one crew, one
set of right-of-
way or clearance zone agreements, and resulting in only one
outage to customers and only one street closure while the work
is performed, versus the potential for causing multiple outages
if each portion of the work was performed under the individual
programs at different times.
ln late 2016, the Company developed its Feeder Automation
StrategyTl, which is used as a reference and guidance document
Exhibit No. I
Case No. AVU-E-1 9-04
H. Rosentrater, Avista
Schedule 1 , Page 73 of 1 03
o Capocity ofthe overhead
conductors, by segments on
the trunk ond laterols,
identifying ony limitotions os
well os potentiol for energy
savings
. Prospective benefits of o
range of physicol
reconfigurotions of the feeder
to improve:
o Voltoge settings
o Fuse coordinotion
o Line losses
o Tronsformer losses
o Power foctor
t Potentiol benefits of
outomotion
o lntegration of osset oge and
condition doto
The Grid Modernization scope provides a holistic approach for
optimizing the value captured with each feeder project. This
approach integrates work performed under various operational
initiatives at Avista including the Wood Pole Management
Program, the PCB Transformer Change-out Program, the
Vegetation Management Program, the Segment Reconductor
and Feeder Tie Program, and various budgeted maintenance
programs. As an example of this coordination, a targeted feeder
or segment will have its older wood poles and cross arms
inspected and replaced (Wood Pole Management), end-of-life
and transformers containing PCBs replaced (PCB Transformer
Change-Out Program), new communications and remotely
operated equipment installed (Grid Modernization), and new
Distribuilon Grid Modernizotion represents o
comprehensive approach to inf rastrucfu re
monogemenl from its dat* ond engineering.driven
onalysis ond evoluation to he woy it serves os o
plotform to betterintegrote a poftion ofthe copital
invertments we moke eoch yeor in our eledric
distribution system.
dEr,lrq
o 71 Available upon request.
by Grid Modernization to help determine what types of automation equipment (if any) will be installed on
each feeder.o
o
Y Reliobility lndex Anolysis
Y Lood Balancing
Y Feeder Reconfigurotion
Y Trunk Conductor Anolysis
Y Laterol Conductor Anolysis
D Hiqh Loss Conductor
Replocement
D FeederTie Creotions
Y Voltage Quolity
lmprovement
Y Voltoge Regulotor Setting
Recommendations
) Fuse Sizing & Coordinotion
Study.r Reduced Line Losses
r Power Factor Anolysis
D Power Factor Correction
D Distribution Line
Automation Devices
Deployment
Y Open Wire Secondary
ldentification, Analysis &
Replacement
Y Pole Anolysis &
Replocement
Y Transformer Evaluation &
Replacement
Y Underground Coble
Analysis & Replocement
Y Vegetation Monagement
Please see Appendix C for the
details reloted these benefits.
Feeder Selection dnd Treatment Design - Candidate feeders
are targeted for Grid Modernization if they have a higher
likelihood of failing, resulting in unplanned outages. They are
replaced with new energy efficient equipment that is more
reliable (because it's replacing deteriorated equipment), has
greater operational capability (which improves reliability) and
additional safety features for our customers and employees.
While focused on rebuilding feeders that are at or nearing the
end of their useful life, the evaluation is complimented by a
range of other selection criteria, such as customer density, urban
versus rural service, and balance among Company operating
districts and jurisdictions. The selection process incorporates
comprehensive data from the Feeder Prioritization Tool noted
above, which incorporates analysis and prioritization information
for each of our 347 feeders, including:
/ lnventory of the individual equipment assets associated with
each feeder;/ Reliablllty performance data;/ Estimated energy savings from replacing transformers and
undersized conductor and installing feeder automation;/ Estimated capital savings modeled based on the feeder
rebuild;/ Modeled reliability savings, and/ Estimated operations and maintenance savings.
ln order to normalize the comparison of data for feeders with
widely-varying characteristics across our system, Avista converts
nominal data into fractional values on the same scale relative to
each feeders' data for each category. These normalized values
are then weighted using the selection criteria weightings that
were established at the beginning of the program. The
summation of the values for each of the three categories creates
the overall score for each feeder. This score is how the feeder is
initially ranked for selection. These results provide a robust
quantitative foundation for further evaluating and selecting the
feeders to be rebuilt under the program.
For feeders that are selected, the Grid Modernization engineer
publishes detailed feeder information, analysis and proposed
treatments in the form of a Feeder Baseline Report. Such
information includes analysis of reliability results for three
indices over the period 2006 to present, study of the actual loadings on each phase of the feeder under a
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 74 of 1 03
o
Grid Modernization
Benefits
o
o
range of seasonal conditions, and modeling of the average and peak loadings
expected after the phase loads are balanced. They also model the capacity of the
overhead conductors, by segments on the trunk and laterals, to identify any
limitations as well as potential for energy savings. Extensive modeling is also
performed to evaluate the potential benefits of a range of physical
reconfigurations of the feeder, taking into account
opportunities to improve voltage settings, fuse
coordination, line losses, transformer losses, and
power factor, as well as the potential benefits of
feeder automation. By integrating all of this
information, along with the full range of asset age
and condition data, engineers recommend a
comprehensive set of treatments that will be applied to the feeder, identifying
the investment requirements and the cumulative estimated benefits. An
example of the reliability improvement measured on feeders that have been
rebuilt under the program is shown in Figure 38.
Future Plons - Avista expects the scope of the program to remain fairly stable
for the foreseeable future, though the structure may change to better optimize
the functions of feeder rebuilding and the installation of feeder automation.
Delivery of these two investments in one project is efficient from a planning and
work coordination perspective, but it also challenges the selection of feeders
because conditions have to be right to maximize the value of both the feeder
rebuild and upgrade and the automation investment. The result has been a
predominant focus on maximizing the value of the feeder rebuild, thus limiting
the opportunities for installation of automation. Through this separation of
activities and also by working more closely with the Company's substation group, the Grid Modernization
program manager believes they can increase the deployment of cost effective feeder automation. lt is also
an advantage to separate the program activities because the process of evaluating the prudence of each
2500
2m0
1500
1m0
5m
o@o)o
o!ooro
=Eo
o
oo
Elz
Sustained Outages Compared with Grid Modernization Feeders
FeederUpgEde Prognm Begins in 2009
1m
0
Grld Modemlzadon ProtEm
(Cur€nt Scope) Beglns ln
o@
805o
aEosod
!o
p406
o+
2013
zcor 2w2 2m3 2fi4 2005 2m5 2@7 2W8 2m9 2010 2017 20L7 20!3 2014 2015 2016
ElgSystem Wide Feeders
-Grid
Mod Feeders
20
0
type of investment is
different.
Staff of the Grid
Modernization and
Wood Pole Management
Programs also continue
to review their strategy
and process for
coordinating both
programs. This is
particularly useful in
maximizing efficiencies
in how the work is
performed under each
program in cases where
funding levels might vary
substantially from year
to year.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
B3c54I
.$.I
o Figure 38. Grid Mod Sustained Outages
Schedule 1 , Page 75 of 1 03
720
lt'
:,t:
li_
I t.I
I
Historic and Planned Progrom lnvestments - Program spendingforthe period 2012- 2016 is provided
below in Table 13. The financial values include the initial budget request made by Grid Modernization staff
for each year of the then-current five-year planning cycle. The beginning budget reflects the amount that
was initially approved by the Company's Capital Planning Group (CPG) for the five-year plan, and the ending
budget is the amount that was finally approved by the planning group for each year. The Company's planned
level of capital investment for the current period 2Ot7 - 2O2tis also provided in the table below (see
footnoteT2):
Toble 14. Grid Modernizotion Budgets and Actuals *See Footnote 72
Distribution Grid Modernization represents a comprehensive approach to infrastructure management from
its data and engineering-driven analysis and evaluation to the way it serves as a platform to better integrate
a portion of the capital investments we make each year in our electric distribution system. Through Grid
Modernization, the Company knows it is targeting
work on the right infrastructure at the right time,
and in a priority that allows us to optimize the
customer value of every investment made under
the program, as well as to optimize the value of
other programs, as explained above.
Due in part to the need to balance priority
infrastructure investments across the Company,
however, Avista has not yet funded the Grid
Modernization program at the level required to
achieve the desired 60-year cycle interval. As a
result, wood pole inspections and replacements
that would have been completed under this
program are shifted to the wood pole management
program and failed plant. This results in lower work
efficiency, which increases our capital and expenses and impacts customer value. The other areas of cost
effective value delivered by the Grid Modernization program are foregone. The benefits of Grid
Modernization are described in detail in Appendix C.
T2Units of Work are in Circuit Miles Addressed. Note that in 2012 the budget was cut but the investments had already been made.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 76 of 1 03
o
o
2072 Sg,ooo,ooo 57,370,690 56,4s2,937 57,362,92s 73
2073 $8,ooo,ooo 57,3L3,766 57,254,0u 57,3L2,362 54
88.820L4522,5oo,ooo s9,700,019 sg,5g6,ooo S10,1rc,G2G
Sr.2,060,9s8 1002015s11,0oo,oo0 S11,ooo,o15 S12,310,ooo
2076 s12,000,000 57,000,894 S1o 8so,ooo S1o 883,80s 97.59
20L7 s17,s00,000 S13,699,503 120
2018 s12500,000 S14ooo,ooo 118
1242079s1g,5oo,ooo s14500,000
2020 s21,s00,000 s1s,000,000 L82
202L s2e5oo,ooo s15 500,000 L46
lnitial Funding
Request
CPG lnitial
Approved
Budget
CPG Revised
Final Budget
Actual
lnvestment
Planned Circuit
Miles
Addressed *
Actua! Circuit
Miles
Addressed *
Year
o
\s
-1, ,
o Distribution Device Management Program
Avista relies on a range of distribution management devices installed on its system to perform operations
that enable our distribution grid to be more reliable and energy efficient. These specialized devices include
reclosers, voltage regulators, capacitors, and automatic
transfer switches. The Distribution Device Management
Program performs equipment inspections, routine
maintenance, data collection, and battery replacement on a
three year systematic schedule for these devices. ln addition
to maintenance, as devices reach their end-of-life and are
ln the first eighteen months of prone to failure, they are programmatically replaced to insure
this Progrdm; the safe and reliable operation of our system.
.i. 15 Automated
Restorations
* 9 Dispatcher Remote
Restorations
* 1.75 Million Avoided
Customer Outage
Minutes
A major consideration of this program is public and worker
safety. A safety risk is created when these devices fail or
function improperly, especially during storm outage
restoration efforts. Crews working on the distribution grid
have safe guards in place to protect them against devices not
functioning properly; however proactively caring for each
device helps reduce any safety risk for our employees as well
as to the general public.
o Program History - Management of Avista's reclosers and other equipment was previously performed by
employees in Avista's Operations and Substation groups. ln 2013, the Company recognized the need for a
more proactive and systematic approach for maintaining and replacing its reclosers and other automated
devices. There are now over 500 automated devices included in this program, which brings all of this
equipment under the same management and maintenance practices, optimizing inspections and
replacements throughout the lifecycle of the devices.
Avista's Distribution Device Management Program is based on a set of optimized inspection, data collection,
and full device replacement practices. lts goal is to maximize the effectiveness of personnel resources,
capture device data for Avista's enterprise asset management system
(Maximo), obtain outage data, help identify outage causes, and improve
safety and operations effectiveness by proactively managing and
maintaining these devices.
Since the Program is in its initiation
phase, its scope is being evaluated
to determine if other devices will be
added to the program and whether
to adjust the amount of data
collected and the frequency of data
collection. However, the success of
the program is already apparent, as
can be seen in the text box above.73 Using a "hot stick" to work on
energized lines
Exhibit No. 8
Case No. AVU-E-'!9-04
H. Rosentrater, Avista
Schedule 1, Page 77 of 103
Automation Successes
o 73'Avista's Smart Grid Technology," John Z. Gibson, https//www.nrel.gov/esif/assets/pdfs/agct_dayl3ibson.pdf
I
I
t
Copitol 5o so so So So
s40,000 54o,o0o S+o,oooo&M S2o,ooo S40,ooo
Dist r ib ut io n Device Ma n ogement
Progrom 2017 2018 2019 2020 2027
These components represent a considerable investment in our company and our ability to enhance
reliability and system performance for our customers. The current five year budget for this Program is
shown in Table 15. As the scope of the program becomes finalized, the budget will be refined to reflect a
best estimate.
Table 15. Distribution Automoted Devices Maintenonce Budget
Replacing Transformers Containing PCBs
Between 1929 and 1979, a family of synthetic organic compounds
known as Polychlorinated Biphenyls (PCBs) were commonly used
in the oil that fills electrical
transformers due to their high
dielectric strengthTa and
resistance to fire. Studies
conducted in the 1960s and
70s revealed, however, that
these compounds are also
toxic, carcinogenic and highly
resistant to biodegradation in
the environment. Their production was banned in the United States in
7979.7s ln the prior decade, Avista monitored a number of local, regional,
and national initiatives focused on the elimination of PCBs and similar
contaminants. ln 2010, the U.S. Environmental Protection Agency (EPA)
issued an Advanced Notice of Proposed Rulemaking on new PCB
regulations. ln addition to these
developments, Avista faced the
possibility of citizen-filed lawsuits
related to PCB contamination in the
Spokane River watershed. As a result
ofthis elevated concern, and our
experience with the risk of aging
transformers leaking or breaking open
when striking the ground as a result of
damage to the feeder, Avista began to
formally analyze alternatives to deal
with its distribution transformers
containing PCBs.
Figure 39. Transformer Replacement Status
7a Dielectric strength refers to the ability of a material to resist carrying an electrical cunent, which is a measure of its potential to insulate against
electric short circuit or fault.
75 "PCBs Questions & Answers," United States Environmental Protection Agency, https://www3.eoa.qovheqion9/pcbs/faq.html.
Exhibit No. I
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 78 of 1 03
o
o
Tiansformers By PCB Status
As of Jonuory 1,2077
c.E
'E
E@G
@Eo
F
o
=
30,(x)o
2s,mo
2qooo
ls,o(x)
1o,mo
5,OOO
3a%
o
3%I
RemdnlrE
TEnfomeE
Predcted ilor
Detst
ActJal NoeDetEt
o
Totd TEnsbmeE
Evduated
J
./jt
u
w rl E-
o
o
ln 2010 the Company conducted a detailed assessment of its distribution transformer population, and the
following year initiated a systematic and prioritized replacement of its transformers known or suspected to
contain PCBs. When the program began in 2011, Avista targeted over 12,000 transformers for replacement.
Because most of these transformers were already 30 years of age and older, the program, irrespective of
eliminating PCBs, is predominantly based on replacements for asset age and condition.
The program was initially slated for completion in 2076, but this timeline
was extended to accommodate the Company's overall capital demand, and
to increase the efficiency by having our line crews engaged in other work
on a feeder also perform these transformer change-outs. Currently, about
900 of the L2,000 targeted transformers remain in the system, as shown in
Figure 39. Under the current plan, all transformers with PCB
concentrations exceeding L part per million should be removed from our
system by year 2019. ln year 2O2O and beyond, the remainder of the pre-
l98L transformers in our system will be removed and replaced as part of
the Wood Pole Management and Grid Modernization Programs. A
significant benefit of the program is the energy savings captured by
removing old and inefficient transformers from the system and replacing
them with new energy efficient units.
Requested, approved, and actual capital investments for the PCB Transformer Change-Out Program are
shown below in Table 16:
Table 16. Tronsformer Replocement Progrom Requested & Actuols
Manoging Avista's Tronslormer Assets - Avista has approximately 82,000 overhead transformers,
37,000 pad mount
transformers, and
about 1,800
submersible
transformers across
our system.
Overhead
transformers are
the most common
type of distribution
transformer on our
system; they
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 79 of 1 03
Submercible
7,779 7%
Working on an Overhead
Transformer
-*--:ar-7-
t
52,9t2,4o3 Se,ooo,ooo 53,87r,624 2,687 40082012sT,ooo,ooo
2013 56,ooo,ooo 52,4L4,oL5 52,924,o!s 52,846,360 2,555 2,625
Ss,aoo,ooo 54,7oo,oo1 sg,gaa,ooo 53,747,953 2,930 272120L4
Sa,zoo,oor s3,7s0,000 s3,28s,514 2,335 2,91920L5s6,900,000
2016 Ss,8oo,ooo 52,2m,oo1 53,75o,ooo 53,552,069 L,530 2310
s3,ooo,oo1 '1,,41920L7s3,000,000
lnitial Funding
Request
CPG lnitial
Approved
Budget
CPG Revised
Final Budget
Actual
lnvestment
Planned
Replacements
Actual
ReplacementsYear
Iu.
\,
o
I
'.t
Pod Mount
37,035 ir%
Averheod
87,&06 68%
provide the final voltage transformation required to serve customers, typically less than 200 kVAi6 and serve
an average of 2.72 customers per unit. Pad mount transformers are typically larger (for commercial and
industrial applications, for example) and commonly range between 100 to 2,000 kVA. Submersible
transformers are typically located below the street level in
vaults, where they are exposed to
a variety of weather conditions
and potential flooding. They come
in a variety of sizes, from l-0 to
over 4,000 kVA.
o
o
Flooding in the Downtown
Network underground
system after a rainstorm
lf a distribution transformer is operated
under ANSI / IEEE basic loading conditionsTT,
it has a normal life expectancy of
about 20 to 30 years assuming it is not
subjected to extreme weather
conditions or overloading on a regular
basis.78 At Avista, our submersible and
pad mount transformers have a typical
lifespan of 44 to 46 years, and
Above: Pad Mount Transformers
awaiting installation
Below: Submersible Transformers
overhead transformers last an average
of 60 years based upon average age at failure. An extended lifespan
is not unexpected if the units are properly serviced, have enough
capacity to handle the expected loads, and are set up with the proper
specifications to meet the application (i.e. residential load versus industrial
load, liquid-filled or dry type).7e
As previously described, Avista has three programs involved in inspecting and
replacing distribution
transformers: the Wood Pole
Management Program, Grid
Modernization Program, and PCB
Transformer Change-Out Program
lnspectors check for leaks, proper
sizing, acceptable clearances,
identify potential safety issues,Placing a Pad Mount Transformerensure adequate grounding of the unit, and make certain labeling is correct.
76 A kVA is 1,000 volt amps - a volt measures electdcal pressure, an amp measures electrical current. A unit of kVA measures "apparent power"
versus a watt, which measures 'teal power." Apparent power is the maximum possible power attainable when the current and voltage are in phase,
that is, how much power a supply can deliver, versus real power or watts, which is the amount of power that does the actual work. Only part of the
kVA is available to do real work, the rest is excess cunent.
77 "Guidelines for Transformer Application Designs," Robert B. Moran, May 1 , 1999, hfto://www.ecmweb.com/contenUquidelines{ransformer-
aoolication-desions and http//members.questline.comiArticle.aspx?articlelD=12304&accountlD=1874&nl=13764
78 "Electric Power Distribution Engineering, Third Edition,'Turan Gonen, 2014, p,114,
https://books.google.com/books?id=JIDSBOAAQBAJ&pg=p41 14glpg=PA114&dq=average+life+expectancy+sf+2n+slectric+distribution+overhead+
transformer&source=bl&ots=LBfDVJz4Gd&sig=aWbuSECTpyeFjDdcT6Fhl-1 pO-
o&hl=en&sa=X&ved=0ahUKEwjAu5fX3v_UAhUi0oMKHdMZBTYQOAEISTAE#v=onepage&q=averageo/o20lite0/o20expeclancyo/o20oP/o20an%20elect
ric%20distribution %20overhead %20transformer&Ffalse
7s 7e dGuidelines for Transformer Application Designs," Robert B. Moran, May 1 , 1999, http://www.ecmweb.com/contenUguidelines-transformer-
application-designs
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 80 of 1 03
Overhead
Pad Mount
Submersible
46
4
@.4
Type Yearc
o
L.
f-u
I rF*t J-fe*
Avista Transformer Life
trEE,
3
Li'
o ln addition to managing the transformers themselves, these programs also replaced failed equipment such
as chance cutouts and they install wildlife guards on applicable feeders.
Through these three projects, the company has replaced the great majority of its oldest transformers (i.e.
beyond their useful life), which has markedly reduced the number of transformer-related outages, as shown
in Figure 41. Less than t% of our overhead and pad mount transformers and less than 5% of our submersible
transformers are beyond their expected lifespan (by Avista standards - 60,44, and 46 years), as can be seen
in Figure 42.
Transformer Related Outages2000
1800
1500
3 rqoo
a0(!5 1200oE 1000
I 8oo
E2 600
4m
2@
0
2005 2005 2co7 2m8 2m9 2010 2071 2012 2013 2014 2015
Year
Figure 41. Transformer Related Outages
Failed Transformer
The reliability benefits resulting from reduced transformer failures are often more substantial than one
would anticipate. The average Avista overhead transformer serves 2.72 customers on average but when it
fails, it can have a domino effect along the feeder, tripping up to ten neighboring transformers and
impacting all the customers they serve. "Cascading" failures in a system of interconnected parts is not
uncommon, as nearby components are often required to compensate for a failed unit, which may cause
unexpected overloading and demand spikes across a number of nodes in the system, rather like the ripples
in a pond. The
Company is aware
of this potential
and is endeavoring
to insure, during
our inspection
process, that our
transformers are
sized appropriately
to reduce the
potential
occurrence of such
multiple outages.
Avista Transformer Age Profile
o 3 6 9 t2L5tA2!242730333639424548s1545760 636669727690
Age in Yeors
-Submersible
eOverheacl
-Pad
Mount
Figure 42. Avista's Distribution Transformer Inventory Age Profile
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 81 of 103
\/
Chonce Cut-
Out
Repldcement
4,500
4,OOO
3,500
3,OOO
2,500
2,OOO
1,500
1,OOO
500
o
Wildlife
Guord
lnstallotions
PCB
Tronsformer
Chonge-Outs
o
eoEo
EEF
o
o0E
=z.
o
I
t\b
-UmHGLUGS
-
LOW-VqiAGE B&|NG
OVEFLOAq gGN& _-
Underground Cable Replacement o
o
80 "Medium Voltage Underground Cable White Paper," Nuclear Energy lnstitute 06{5, April 2006,
https://www.nrc.gov/docs/M1061 ZML06'l 2201 37.pdf
81 Madden, Glenn and Rodney Pickett,'Asset Management 5 Year Plan and Budget Summary," 2010
Underground Residential District Cable (underground cable or
URD) has been used by the utility industry since the 1930s, though
Avista did not begin installing the cable until the late 1950s. During
the 1990s it became apparent that the cable manufactured prior
to the 1990s had numerous problems, as highlighted in the text
box.80
Prior to the underground cable problems becoming apparent to
the industry, Avista had installed over 6,000,000 feet of this type
of cable.81 By the mid-1990s, customers served by this cable began
to experience more prevalent outages that were increasing with
time as the cable aged and continued to deteriorate at an
accelerated rate. Though the Company had initiated a program to
systematically replace this cable, it became apparent that the
effort was insufficient to address the accelerating problem.
Avista estimated that by 20L6 the annual number of outages per
10 miles of cable would exceed 30 under that initial program, as
shown in Figure 43.
Fiqure 43. Proiected Underqround Cable Failures
Avista's asset management group analyzed options for
accelerating the replacement schedule from ten years to a four
year program. The analysis, which was based on savings from
avoiding unplanned outages, estimated that the four-year program
would save customers approximately S7.3 million in capital
Exhibit No. I
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 82 of 1 03
"FIRSTGENERATION"
U N DERGROU ND
CABLE ISSUES
Lack of adequate insulation,
resulting in numerous
faults
Excessive corrosion on the
neutral strands cause
voltage levels to drop
unexpectedly or complete
cable malfunction
Lack of protection against
dig-ins, animaland
vegetation incursions as
wellas flooding and
lightning damage
35
.c
330o?*
E
5zo
o
*rs
o
b10o)-
0
Fault Rate per Ten Miles of Uodergmund (IRD) Cable
Actuol and Estimated @tponatialTrend Line)
L992 r9p4 1996 1998 2m0 2m2 2m4 2@5 2m8 2010 20t2 20!4 20t6
-Actual
Faults Per 10 Miles of Cable
'..... Estimated Faults per 10 Miles of Cable (Based on Polynomial Equation)
y = 1.3567ec1'n'
Rr = 0.9023
o
Splicing (a routine operation)
results in weakness and
premature failure
Water penetration of the
exterior insulation causes
voltage surges and faults
o
o
250
200
ou
E rso
o
ot 100
fz
Underground Gable Related Outages Per Year installation, expenses, and fail ure
consequences.s'With the majority of the
known vintage cable replaced by 2013, the
program was ramped down to an annual
investment of approximately one million
dollars, which provides for the removal and
replacement of this vintage cable as we find
it on the system (usually through responding
to an underground fault). The substantial
reliability benefits of the program for our
customers are shown in Figure 44.
Avista's budgeted and actual capital invested
for underground cable replacement from
2005 - 2015, and forecasted through year
2021,is shown in Figure 45.
Figure 44. Actual Underground Cable Related Outages
This year the Company is conducting a detailed inventory to identify all remaining first generation cable
throughout our underground distribution system. When this study is complete we will have a better
Underground Residential District Cable Replacement Pmgram
Budget and.lctuals
e:
5s
s4
s4
s3
s3
S2
5z
Sr
5r
5o lll lh lll "l u
2m5 2W7 2m9 2011 2013 2015 2017 2019 202L
IBudget lActual
Though this program is centered
on replacing the cable based on Figure 45' underground cable Replacement Program
asset condition (i.e. it has reached
or is nearing the end of its useful service life), our progress has had a measurable impact on the incidence of
cable-related outages on our system, as shown in Figure 44.83
Undergrounding feeders and service lines is often cited as the answer for increasing system reliability, but
the cost effectiveness of each application must be evaluated in this decision. The initial cost of
undergrounding can be much more than constructing overhead distribution lines. Life cycle costs of
underground lines can also be higher due to a shorter useful life and higher repair and replacement costs. ln
82 Savings are based on the outages forecast to occur without the replacement program, minus the actual oulages, multiplied by the average cost of
responding to an average cable outage.
83 This data on cable failures was collected from outages recorded on the Company's outage management system, which became operational in 2005.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
50
2m5 2m5 2007 2m8 2009 2010 207L 2012 2013 2014 Z0l5 20t6
o
Schedule 1, Page 83 of 103
0
understanding of the locations
and footage of this cable
remaining, which will allow us to
optimize our approach to its
removal, as well as forecasting
the future investment need.
addition, outages associated with these lines are harder to locate and repair.8a Avista takes all of these
factors into consideration when deciding whether it is in our customers' best interests to install
underground systems.
Requested, approved, and actual capitalexpenditures forthis program are shown in Table L7. (Note: CPG is
the Capital Planning Group.)
Toble 77. Underground Coble Replacement Progrom Requested & Actuols
Underground lnspection Pilot Program
Avista has over 37,000 pad mount transformers and over L2,7OO
junction enclosuresss throughout our electric distribution system. Our
placement and operation of this equipment is subject to a range of laws,
standards, and codes that are intended to provide for the safety and
security of our customers and employees. Over time the identification
markings, condition and operability of these assets will naturally
deteriorate and the Company must take steps to ensure they are
properly maintained or replaced as needed to guarantee our
compliance with applicable rules and
the safe and reliable operation of
our electric system.
o
o
Underground equipment now in a bog
Once upon a time this was a safety
decal
Over the past few years Avista staff have anecdotally reported that much
of our underground equipment was missing proper marking decals or that
those decals were so deteriorated as to be unreadable. ln other cases,
homeowners had added aesthetic elements that block access for our
workers. Some equipment had also been damaged or its function and
reliability were compromised by age, weather, or local conditions. Based
8a "Power outages often spur questions around burying power lines", U.S. Energy lnformation Administration, Today in Energy, July 25,2012,
https //www.eia.gov/todayinenergy/detail.php?id=7250
8s A junction enclosure is a usually small underground vault where the Company has joined underground electric cables or installed various line
devices.
Exhibit No. 8
Case No. AVU-E-I9-04
H. Rosentrater. Avista
2005 s699,308 s672,080 36,982
2006 s1,000,007 s1,0s9,3s0 93,416
2007 s2,000,006 s3,031,836 L78,868
2008 s3,000.007 s3,295,005 L36,342
2W9 s3,1s6,003 s3,585,es0 178,000 211,059
2010 s4,om,006 54,092,42s 178,000 217,883
2077 s3,s00,003 s3,888,899 178,000 223,29L
2012 s2,2s7,W s1,792,006 s1,792,000 s1,746,s83 178,000 L18,427
2013 s1,0m.m0 s1,ooo,oo7 s1,000,000 s982,81s 28,43
20L4 s1,ooo,m0 s1,000,00s 57s0,000 5737,639 36,465
2015 s1,0m.m0 s1,000,004 s1,000,000 s9s2,136 20,824
20L6 s1,00o,000 s2oo,o10 s1,000,000 s8%,s84 t12,86t
20L7 s1,000,000 ss00,009
CPG lnitial
Approved
Budget
Planned Actuat
Replacements Replacements
(in Feet of (in Feet of
Cable) Cable)
Year CPG Revised
Final Budget
Actual
lnvestment
Initial Funding
Request
Schedule '1, Page 84 of 103
o
37 5
o on these reports, the Company determined it
should develop a consistent, comprehensive
plan to inspect all Company underground
equipment and make any necessary
improvements needed for compliance and safe
operation.
To determine the needs and scope of this
inspection program, the Company conducted a pilot inspection of 474
transformers and 120 junction enclosures over a four week period.
This short-term pilot study found that 96% of the equipment
examined had improper identification decals - the decals were either
outdated or no longer valid, were destroyed by age or weather, were
missing or illegible, or had been removed by property owners. ln addition, over a third of the units were
overgrown with vegetation or had walls, rocks or decorations installed within the required clearance zone.
Other concerns included the potential for unauthorized access, the failure of paint and protective coatings,s6
Legal Requirements for
Underground Equipment
,/ Washington State WAC 296-
24-95605 provides d i rectio n
for exterior marking
,/ IEEE C57 requires specifics
for enclosure integrity (to
prevent unauthorized
access)
,/ Washington State WAC 468-
34-130 350 contains codes
related to locating
equipment along roadways
,/ Washington State wAC 296-
24-95605 directs that the
area around pad mount
equipment be kept free of
obstruction
r' National Electric Safety Code
NESC C2-2007 contains
grounding requirements
Left: Transformer Covered by
Shrubbery
Below: Vines Growing lnside a
Transformer Box
problems related to rust, and equipment that had
settled 'out of level,' creating the potential to leak oil.
Left: Landscaping
features block
Avista access to
equipment
Below: Paint
failure can lead to
rust-through of
cover
These findings
demonstrated the
significant need to
systematically inspect
and remediate these
types of issues,
particularly those that
would pose a safety
threat to our
customers and citizens (as most of these units are
easily accessible in yards, playgrounds, and other
public places).
Based on the pilot program results, a model was
o
developed to determine the optimum inspection cycle based on a comparison of risk, resource needs, and
financial impacts. That work supported development of an inspection program based on a cycle interval in
the range of 8 years, and with an annual capital investment starting at 51.6 million dollars for the
replacement of equipment at or past its useful life, plus $800,000 in O&M expenditures to conduct the
inspections. Avista believes this approach effectively balances the program costs with our obligation to meet
86 Avista studies estimate that 2% of paint failures will result in a Pad Mounted Transformer failing and requiring replacement.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 'l , Page 85 of 103
o
ffiwmE
tril
Lt,
compliance requirements, our commitment to public, customer and employee safety, and the reliability of
our system.o
Avista's inspection protocol is designed to identify damaged,
obscured, or missing safety decals, equipment not accessible
due to vegetation, impeding landscaping or structures, and to
examine the general physical integrity of these assets. To
maximize the efficiency of the inspections, teams will be
equipped with the proper materials and tools to take
immediate corrective actions, which will include removal of
Above: Fire damaged pole
Below: Broken crossarm
o 96%
o 35%
o 3%o
o 8%o
o 8%o
lmproper Decals
Clearance lssues
Transformer Not Level
Failed Tamper-Resistant Bolts
Paint Failure
vegetation, installation of new locks and labels, cleaning and
insuring the integrity of the structures, and to repair the pads. Taking these corrective actions will allow us
be more cost effective and to quickly reduce any potential safety risks. More complex issues will be
reported, tracked and systematically repaired in follow-up work.
This program will allow us to achieve compliance with all applicable codes and regulations, decrease our risk
of safety issues and equipment failures, and to positively impact our system reliability by replacing failing or
failed equipment on a planned basis. Expected expenditures are shown in Table 18.
Toble 18. Underground Equipment lnspection Expenditures
Worst Feeders
As noted in the electric system reliability section above, the Company evaluates
the opportunity to modify certain
segments of its feeders of greatest
reliability concern, which are
implemented through investments
based on the asset condition of the
feeder. Because ofthe many
infrastructure demands we currently
face, the Company has substantially
reduced the funding allocated to this
program, currently
planned for 2017
alone.87
The annual planned
capital investments for
each ofthe asset
condition programs
described above are
presented in Table L9:
Exhibit No. I
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 86 of 103
o
Copital s1,6OO,oOo s1,6OO,OOo S1,6oo,ooo S 1,6oo,ooo s1,600,ooo
o&M s800,ooo SSoo,ooo S8oo,ooo S8oo,ooo s800,ooo
Underground Equipment
lnspection Program 2077 20792074 2020 2027
87 ln addition, the funding for worst feeders has been moved into the Grid Modemization Program.o
t
Pilot Program Results
o
o
Table 19. Plonned Distribution lnvestments: Wood Pole, Grid Mod, Underground, PCB Replocement
FanIep PIa.Nr AND OprNrrrIONS INVESTMENTS
The replacement and capital repair of equipment failures constitute "requirements to reploce assets thot
have failed and which must be reploced in order to provide continuitv and adequacv of service to our
customers (e.a. copital repair of storm-domaaed facilities)." While large-scale outages such as the
windstorm of November 2Ot5 are vividly remembered by both Avista employees and our customers, the
Company responds to thousands of outage events each year that occur
almost every day of the year. The replacement of assets due to equipment
failure or outage events, however, is only one component of the investments
required to operate our electric system. ln addition to outage response,
Avista's nominal operations
involve reconfiguration and
replacement of electric
facilities under a variety of
circumstances. For example,
electric distribution systems are
protected by a network of
fused devices. Changes in
customer demand and load
additions often require
revisions to the system of
'coordinated fusing' in order
to adequately protect for line faults. These
projects may also involve ancillary
activities not directly attributable to the
end-use customer, but necessary to
maintain the safe and reliable operation
of our electric distribution system,
including adding voltage regulators or
reclosing equipment, or replacing a pole,
cross arms, or transformers in poor
condition. Avista monitors circuit loading
and often shifts load from one circuit to
another during winter or summer peak
usage, which often involves extending
overhead or underground primary wires
and cables.
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 87 of 1 03
Above: A pole rots and fails
Below: Replacing old pole with new
(significantly straighter) pole
Top Right: Pole hit by a truck
Bottom Right: Wind storm causes a
pole to sPlit
Wood Pole Monogement s9,0oo,00o s9,soo,oo1 s9,soo,ooo Sg,ooo,ooo S12,ooo,ooo
S12,9oo,ooo S13,9oo,ooo s13,29s,oso s13,7s3,sOO 5L4,271,gsoDist rib u tio n G rid M od e rn izatio n
S1,ooo,oo4 S1,ooo,oo4U n derg rou n d Co ble Rep lo cement Ssoo,ooo s1,OOO,OO4 s1,0oo,oo4
S3,OOO,OOO S1,2oo,ooo S1,2oo,ooo S1,2oo,ooo soPCB Tra n sf o rm er Rep la cem ent
Totol $2,,4OO,OOO s2s,6OO,O0s s24,99s,Os4 s24,9s3,so4 s27,217,9s4
2077 2078 2079 2020 2027
ryi|l,
o
V i*a;
Failed Plant
Avista responds to various types
of equipment failures each year
resulting from a range of factors,
some of which result in service
outages for our customers. The
required investments for
replacing this plant are included
in the program titled
"Distribution Minor Rebuild."
The vast majority of customer
outages occur on the overhead
electric distribution system. ln
2016, there were 7,083 outages
on the distribution grid
compared to only 53 failures Figure 46. Failed Plant & Operations Expenditures
related to substations and
6l associated with
transmission lines. The
majority of these outages
are related to weather (e.g
lightning, wind, rain and
snow), downed trees,
animals (e.g. squirrels and
birds), and equipment
failure. Repairs to the
system often require the
installation of poles,
transformers or crossarms, and may include the installation of overhead conductors. Other failures include
third-party damage to electric cables, as well as the unanticipated failure of assets due to a range of factors
including age and condition. Figure 46 shows the actual and forecasted costs of failed plant and operations
for Avista's electric distribution system
Emergency Storm Response ft
o
o
"Car Hit Pole" Situotions
Avista tracks the costs of these major events through our
Emergency Storm Response program. Figure 48 shows the
actual and forecast level of spend on major storms since 2011.
The emergency storm spending for this period is dominated by
results for 2074 and 2015, which resulted from only four
individual storm events. ln August 2014, Avista suffered three
significant windstorms, which resulted in 20,000 to 50,000
customers losing their electric service during each event. The
I
Linemon in Dovenport restoring
service in o snowstorm.
Courtesy ol lnlinity Rose Photogrophy
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 88 of 103
53,0m
52,sm
52,000
$1,s(Ic
Sl,om
Ssm
_9
516,m0,o00
51dmo,mo
s12,m0,000
s10,@0,000
s8,0m.000
56,om,ooo
54,0m,000
52,om,ooo
So
Electric Distribution Failed Plant & Operations Expenditures
With and Without Major Event Days (MED)
,10ail forccast
o
o
E
E
!3
So
-Failed
Plant Expenditures
-Failed
Plant Expenditures Without MEO
2011 2012 2013 2074 2015 2016 20L7 2018 2019 2020 2027
- - - Failed Plant Expenditures - Forecast
--- Failed Plant ExpendituresWithout MED- Fore€st
November windstorm of 2015 was the largest single day, resulting in a loss
o
I
'l'4
-
-",I
o
o
of service for over 168,400 Avista electric
customers.ss The majority of the outages were
the result of hurricane force winds that
severely impacted the Spokane area.
For the forecast ofthe current five-year period,
we have used a more'typical' level of
investment related to major storms, with an
annual value of approximatelV 5Z.Z million.
Emergency Storm Response Costs
- S3opmEcof szslm
EF
s2opm
srspm
slopo
st@o
So
2071 2012 2073 20t4 20ts 20t6 2077 2078 2019 2020 202t
-ACtual
- - FOreCaSt
Figure 47. Storm Response Costs
Operations Capital
ln addition to replacing assets that have failed, Avista's operations staff
performs a wide range of limited capital infrastructure work that does
not rise to the level of a project or program. The investments described
in this section are included in the distribution minor rebuild program.
This work includes the need to reconfigure, replace, repair and upgrade
electric facilities for a variety of reasons, including:
D lnvestments that ore ossocioted with customer requests for new or modified services
Y Replacement of equipment bosed on asset condition
'r Remedying capacity deficiencies
As noted under customer requested investments, direct costs associated with extending feeder and service
wires and cables to provide requested service to a customer are subject to cost sharing between that
customer and Avista. As the number of customers on a feeder grows over time, however, the Company may
have to replace or upgrade the capacity of trunk line feeders or laterals. The investments needed for this
work, which are included under the operations capital, are paid for by all customers because they are
required to provide reliable service to everyone on our system. Examples of this type of work are shown in
the text box below.
88 'Windslorm Pummels Spokane, Killing Two People and Causing Widespread Blackouts," The Spokesman Review, November 17,2015,
http://www.spokesman.com/storiesl20lSlnovllT lwindstorm-pummels-spokane-killing-two-people-and-c/
Exhibit No. I
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 89 of 1 03
WtNnsroRrra
2Ol5 nY THE
Nurueens:
o 180,000 Avista
customers without
sen'ice at peak
o 369,000 Total Avista
customers
o 500 Linemen from
contractors or other
utilities assisting in the
restoration (the PG&E
crev/ traveled 873 miles)
o 26 severed gas lines
found in one 12-hour
shift
o 54oh of homes and
businesses in North
Idaho and Eastern
Washington experienced
an oumge
o 62 intersections in
Spokane without
stoplights
o Over 3,700 tons of
debris
-
o
Spokane Electric Network
Avista operates an underground electric distribution system in the core business district of downtown
Spokane. This distribution "network" is configured as a fully redundant distribution grid that includes cables
encased in concrete reinforced duct lines and major equipment
. Repair broken or damaged
equipment and fixtures whether or
not they are related to a customer
outage.
o Adding additional phase (overhead
conductor or underground cable) to
support customer loads requiring
three-phase service.
. Replace undersized conductor or
cables as needed to provide
adequate service.
o Reconfigure overhead feeder
conductors to meet the clearance
requirements for joint use facilities,
such as telecom fiber attached to
Avista's poles.
. Load balancing among the phases on
a feeder to reduce the return cunent
on the neutral wire.
o Modifications or line additions to
protect birds and animals.
. Repair or replacement of equipment
damaged by vandalism or theft (e.9.
copper wire theft.)
. Replacement of failed customer
dcmand meiers
such as underground
transformers in
concrete vault
structures. Most
mid-size to large
cities operate such a
network including
Seattle, Portland and
Tacoma. The
Spokane network Working below the streets in the
system dates back to Downtown Network
the early 1900's, with
some vaults carrying a date stamp as early as 1910. Major
expansion ofthe system occurred between 1940 and 1960
with significant modifications made to accommodate the
World's Fair in !976. The expected annual cost of maintaining
the network for the 2017-202L time period is approximately
52.3 million per year.ss
Capital investments associated with the Spokane electric
o
onetwork include
customer requested load
additions, replacements
of assets based on
condition, as well as
replacement of
equipment and
infrastructure that fails.
Spokane's system is
relatively small,
including 100,000 feet
of underground feeder
cable and 125,000 feet
Downtown network crew beginning
the process of filling cable with leod
to creote o solid splice; this type of
work is considered an art
of service cable connecting submersible, vault-type transformers. The
Downtown Network feeder lines are separated into four sub-networks, each of which is capable of
sustaining the loss of one trunk line without losing any customer load. The network requires specialized
material, equipment, tooling, and manpowerto perform maintenance, repairs, planned replacements, and
capacity growth projects. The pace of annual investments for replacements and additions include
approximately 7,500 feet of primary feeder cable (15,000 volts), 7,500 feet of service cable (600 volts), 6 to
8 manholes, 2 to 4 vaults and/or vault roofs and the replacement of L0 street lights.
8s Direct Testimony of Heather L. Rosentrater, February 201 6, UE-1 60228, pg. 41 ,
https://www.utc.wa.govi_layouts/15/CasesPublicWebsite/GetDocument.ashx?doclD=323&year=2016&docketNumber160229
Exhibit No. I
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 90 of 1 03
o
Typical Operations
Activities
1
1
o
o
Today, Riverfront Park is being renovated as part of an effort to redevelop and reinvigorate the core of
downtown Spokane. ln 2015, the Spokane Grand Hotel was added to the skyline in response to the
expansion of the Spokane Convention Center. Efforts are underway to develop all-electric bus routes
through the heart of Spokane extending to the Gonzaga and Spokane Community College Campuses.
Downtown Spokane is growing and Avista continues to meet the challenges associated with that growth
Table 20 provides the expected level of capital investment for each of the program budgets discussed above
for each year of the current planning period.
Table 20. Plonned Distribution Progrom lnvestments
As described and documented in this report, the increasing investments made by the Company over the
prior decade reflect a demonstrated need for new investment in electric distribution infrastructure. The
information provided in this report, and which is supported by more-detailed analysis and documentation,
supports these prior-period investments as necessary and prudently incurred. The year-over-year growth in
our prior investments is not at all unusual in our industry. Compared with our peers across the industry, our
capital investments on a per-customer basis are reasonably consistent with the industry average over time,
though our
cumulative spend
over the prior 20
years is slightly
below the industry
average. These
investments have
allowed the
Company to achieve
a level of electric
system reliability
that we believe is
satisfactory to our
customers and
represents a cost effective value.
Our individual infrastructure programs are responsive to investment demands that are beyond the control
of the Company, such as the case for customer requests for service, mandatory and compliance issues, and
failed plant, or they respond to needs that are necessary and immediate or that are cost effective for our
customers. Our asset management programs have been thoughtfully developed, thoroughly analyzed and
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 91 of 1 03
;u
t
Mojor Storms 53,782,700 53,278,181 53,376,s26 53,L68,a22 S3,2oo,ooo
Distrib utio n M in o r Bla n ket sa,867,27O s8,9OO,000 s8,900,000 s8,900,000 s8,900,000
Meter Minor Blonket Ssos,ooo S3oo,ooo s3O0,O00 s300,000 5300,000
S po ka n e Electric N etwo rk s2,300,000 52,3oo,ooo S2,3oo,ooo S2,3oo,ooo S2,3oo,ooo
Totdl s74,854,970 s74,778,187 s14,876,s26 s74,668,822 ,L4,7OO,OOO
2077 2078 2079 20272020
CotttctusroN
ffil
o
l
optimized, and re-analyzed and adjusted as appropriate to ensure that we deliver cost effective value for
our customers.
Our LED Street and Area Lighting Program, which is 7.8% of our overall distribution investment, delivers
greater safety and security to our customers, and saves them money through operations and energy
efficiency savings, not counting the substantial grant received by Avista that further enhances the customer
value. Likewise, the Company's deployment of advanced metering will allow us to cost effectively improve
our service and reliability for customers as we build the foundation for the emerging energy services grid of
the future. Our efforts to improve our base reliability through feeder automation accounts for less than L%
of our overall planned investment yet plays a significant role in helping the Company uphold and maintain
the overall reliability of its system. LED lighting and feeder automation are the only programs in our primary
distribution investments (not including customer meters) that are not directly tied to the need to repair or
replace infrastructure, to remedy equipment overloading and safety issues, or to connect new electric
customers to our system. These investment drivers and their associated portions of our overall plan in
electric distribution are summarized in Figure 48.
Planned Electric Distribution Spending by Investment Driver 2017 - 2021
Figure 48. Distribution Spending by Investment Driver
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 92 of 1 03
o
o
o
/ Replqce Fqiled &Domoged lnlrastructure/ Support Ongoing Electric Operotions r' nequired by customer RequesB lor Service
End of Seruice Lile Replacements{ Distribution Poles & Attoched Equipment/ Systematic Rebuild of Deteriorated Feeders/ Remove PCB laden Tnnsformers / lmproved Service ond CostSovings/ tlphold evisto's Distribution System Reliability
r' Avoid Equipment Overlooding Code/solety lssues/ Qtstomer BenefiB of Cost Effective Strea Lighting (1.5%J
/ Required by City, County, Stote
Tr onsportation P rojects
13.5%
23.Wo
23.5%
s.3%
21.8%
o
us Electrlc utlllty
Rerldentlal Blll Comparlson
ALA'XA
HAWAII
c^[roRNtA
MASsACHUSETTS
CONNEcIKUT
RI{ODE IILA'{D
NEWIIRTEY
NEW HAMPsHIRE
VTsMONI
MAINE
x€w Yoi(
MICHIGAI'I
MARYLAND
UsA AVERAGE
XAI\6At
M1550URt
COI,ORADO
w6coN5r|
.ENNSYLVAN!A
AIABAMA
OII.AWARE
low^
GEORGIA
ARIZONA
oHlo
lltNots
INOIAXA
'OUTH
CAROI.INA
Ntw Mtxlco
WYOMING
o
olsrRlcr or coruM8lA
UTAH
i,TNNE9OTA
fIORIDA
WE'IVFGIN]A
roRrH caiouNA
'OUTH
OAKO'A
VNGINIA
rrxAs
OREGON
iIEVAOA
Mts9sStPPt
KENIUCXY
LOUEI,A,NA
DAHO
NORTH DAKOIA
OKlAfiOMA
MOX'AITA
WASHINGION
AVISIA DAHO
AiTANIAS
AVTSIAWAsHINGTON
TENNE'SEE
T'. S. ELECTF?IC TJTILITY R ESIDENT'AL ELECTF?IC I?A TE CO MPAT?ISON
93so
S30o
S2so
S2oo
slso
Sso
Ave6ge Residential Bill Per 1,OOO kwh of Usate Per Month
US Averoge
Woshihgbn
lddho
Exhibit No. 8
Case No. AVU-E-1 9-04
H. Rosentrater, Avista
Schedule 1 , Page 93 of 1 03
AeeEtttptx A: AvrsrA Cusro*tEn Cosrs
Averuge Residential Electric Bill
5140
5130
su0
S11o
$too
S90
sao
S70
5so
per 1,000kwh
3
!
o
US Averuge
Idoho Stote Average
Stote Averuge
Avista Averuge
2011 20!2 2013 2014 2m5 2016
o
h
srA 1{
(
'---{*-...-.
I
1 32-
I 10,(
129,t
r29-l
127.y
9G
D'
\JArlsta Resldenflal
, Electric Rrte(-
Electdc Rate
AeegNotx B: CusroMER Sartsre,crroN
Each year AvBta measures how well we perform in meeting our goal to provide
the best customer service posible. ln line with that tradition, we established a
set of Service Quality Measures in collaboration with the Washington Utilities and
Transportation Commission (WUTC) and others. We will be providing this annual
report card to customers sho\ /ing how we are doing on meeting these goals.
For more rnformation, visit www.avistautilities.com.
I lvn
v.1%
025
81.lYo
-Il..l Mnut6
48.4 Mindes
'l3l Minutes
o
o
Fercentage o{ cr]stonEn satistied with our Contfft Center servkes
Percentage of custofiler sathfied with our field seMces
Nrnrln ol comJrhrnts tild with the V JI( .xrrr.rlly Jxr l,(Ix) cr6t(rlr({s
Pt'rccntagc of calls answerexl live within 6l sccomh by our CcltrLrt Conttlt
Avrr.ry. linr klrr crstrnrr crll to aniv.rl ol lrld tt<Jlrrr;rrs
ln r5[rrN. [o (,|{rtr(:5ystrlll et)xtqr{f,ri5
Averqry ilnm lrorn crrstonrr call to,lrivJ ol fi.ld tmlruclrrs
in 16lnrls(' to nJtrlJl qal system orn(YqoKi.s
Ntnrkr ol mn nr.r1r stornr rehted fxffir ortur]es.rrnrully pr crrstonm
Length of non-nuior stqm'related fFvrer Ntages anrually per customer
Keq service appcint nents rhedded with ottr custorFrs
Re5lorc service within 24 iroun ol a <ustorner reportrrE an cutagp(o<duding m;lor stom ercnts)
Turn on pourer wrthn a busrrrcss day of receMng ttn requesr
Pro/ide a co5t eilmate for rrcw electrk c naturd gas seMce wilhin
l0 businets dq6 ol Bceiving the recpest
lnvestiqnte and respond to a tillirg nrqriry wifih 10 hniness dap
il unde to d6ufl a qrFstrdl on fi6t contact
lrwestrgate a reported meta podeo a <andtrct a nrter teit
and report the teruhs withh 20 hrsirrss dap
l0otrty cutofiErs at le6t 24 hous in advare ol a darred porver
oul,aqe lstirE bnqs thil 5 mirute
Totlb
At le.xt q)%
At least 90Yo
Les! than o 40
At hastSo%
No moe than 8) minuts
NomoE tllan 55 mhutes
1M
142 Mintne5
1,477
26,344
1,380
5,424
1,tg)
109
l0,lt6
6&530
1500
1s0
1150
lo
lo
llm
117,450
3lazto
Exhibit No. 8
Case No. AVU-E-'l9-04
H. Rosentrater, Avista
Schedule 1 , Page 94 of 1 03
8(r -0 05
+l N'linutes
10
I
3
0
0
2
v9
!55
o
2016 PerformanceBendrmark AchievedCustomer Service lvleasures
Electric System Reliability lYear Averaoe(2012-2016r lnlYear2016 Performance
t PaidCustomer Service Guarantees
Avista Total Customer Satistaction Ratings
From "Voice of the Customer"
799 2@ 2@7 2@2 2@r 2@ 2ffi 2@ 2@7 2@ 2@ 2010 2071 2012 2011 2011 2015 2016
rm%
95%
9ffi
a5%
M
75%
RE
-
EE
*
d"7 2016 Service Quality
Report Card
IYF \
Successful Missed
sT. ttlaTlllElT
il/IIIIR,{NCIIUECI
rND S0lto0tt-
UORiX
o
o
o Reliability lndex Analysis
Reliability indices are significant components of any utility's ability to measure long-term electric service
performance, and are one indicator of system health or condition. The
common reliability indices of CAlDl, SAlDl, SAlFl, and CEMI-3e0 are used by the
Grid Modernization Program to analyze and illustrate the historical reliability
performance of the feeders, as well as to assist in justifying any proposed
circuit improvements or automation deployments. Each historically averaged
reliability index for a feeder is compared to the Avista target value for that
calendar year to determine the reliability performance of a feeder. The
reliability index performance will also be monitored in future years to quantify
the success and magnitude of the Program's work. Major Event Days (MEDs)
is an industry standard used to evaluate major events, such as severe weather
or storms, which can lead to unusually long outages in comparison to the
distribution system's typical outage. The reliability indices that are being used
do not include MEDs, as is standard in the industry and which is in line with
what is requested by the
Commission.
F
o Load Balancing
lmbalanced load on a feeder has the
ability to create or worsen numerous
problems which contribute to
inefficiency. Unbalanced load can
unnecessarily burden one conductor,
potentially causing the highest
loaded phase conductor to be
overloaded or approach its ampacity
limit. This can in turn create voltage
quality concerns with low voltage
scenarios, which are amplified when
loads are higher. The exercise of load tnstolling underground coble
balancing also promotes the switching of
balanced load between feeders during switching scenarios, which mitigates the
problem of overloading a particular phase on an adjacent feeder when load is
transferred. Load will be approximately balanced on multi-phase laterals,
between sectionalized switching devices or reclosers, and between strategic
points on the feeder trunk. These balancing efforts commence towards the
end(s) of the feeder and roll up to nearly balanced load on each phase at the
substation breakers.
Using o helicopter to
reoch i naccessible oreos
e0 CAIDI (average duration of outages/average restoration time) , SAIDI (outage duration), SAIFI (frequency of outages), and CEMI-3 (number of
customers experiencing three or more outages), htlos://www.oeb.ca/oeb/ Documents/EB-2010-
0249/0EB Customer Soecific Reliabilitv Metrics Reoort.odf and http://www.galvinpower.org/sites/defaulUfiles/Electricity_Reliability_03161 I .pdf
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule '1 , Page 95 of '103
New pole being set
with o crone
AeeeNpx C: Gnp MopgnNunTIoN Bgntgnrs
o
F
I
. Feeder Reconfiguration
The Grid Modernization program supports the efforts to identify and
relocate sections of the distribution feeder where the cost and benefits
of greenfield construction outweigh the significant work required to
rebuild the existing line in place to current standards. ln addition,
overhead facilities can be converted to underground when the benefits
of rebuilding in place are not significant, the cost difference between
overhead versus underground is comparable, or if notable reliability
improvements can be achieved by removing sections of vulnerable
overhead conductors. The ability to reconfigure and convert feeder for
reliability and efficiency improvements is a characteristics that
distinguishes Grid Modernization from other Programmatic or Capital
work.
o Trunk Conductor Anolysis
o
o
o
Feede r Reconfig u rotio n
Primary trunk conductors have the
ability to negatively affect the reliability and efficiency of a distribution
circuit. Primary trunk conductors are analyzed to determine if they are in
acceptable physical condition and modeled to assess if they are
appropriately sized to serve peak loading demands, provide adequate
voltage levels, and do not cause significant and unnecessary line losses.
Primary trunk conductors that do not meet these criteria are replaced
with the most appropriate standard conductor size to improve the
feeder's opera bi I ity, rel ia bi lity, and energy efficiency.
Split Pole - old stub in
bockground
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 96 of 1 03
Guy line issue
o Lateral Conductor Analysis
Lateral trunk conductors also have the ability to negatively affect the
reliability and efficiency of a distribution circuit. Primary lateral
conductors are analyzed to determine if they are in acceptable physical
condition and modeled to assess if they are appropriately sized to serve
peak loading demands, provide adequate voltage levels, and do not
cause significant and unnecessary line losses. Lateral conductors that
do not meet these criteria are replaced with the most appropriate
standard conductor size to improve the feeder's operability, reliability,
and energy efficiency.
. High Loss Conductors Replacement
High loss conductors are inefficient conductors that result in line losses,
especially where there is moderate to heavy loading. The Distribution
Feeder Management Plan (DFMP)calls attention to higher loss
conductors, with emphasis on replacing conductors that have a
resistance greater than 5 ohms per mile. The Grid Modernization program
analyzes all conductor sizes on a feeder to target and locate these higher
Line
Relocated
OYerhed
o
o
Old line on the lefi, new on the right
o Feeder Tie Creations
A reduction in the duration of outages can be achieved through rebuilding existing feeder ties and
establishing new feeder ties. Existing feeder ties can be improved by re-conductoring to higher ampacity
conductors to increase capacity, as well as replacing existing manual switches to devices with
communications that can either be controlled remotely or through a distribution management system
(DMS). New feeder ties can be established for circuits without connections to adjacent feeders or where
additional ties could provide improvements in reliability.
o Voltdge Quolity
Service voltage at the point of delivery between the utility and the customer should be consistent to
allow the safe and reliable operation of electrical equipment. Over-voltage and under-voltage situations
negatively affect the service voltage that is provided, and can also be associated with inefficient
operation of the distribution circuit. The Grid
Modernization Program analyzes feeders to identify
sections of the feeder where the service voltage
level fall outside of the allowable ANSI 84.1 Range A
or B operating limitsel. The feeders are modeled
during both peak loading and average loading
conditions, with both normal and abnormal circuit
configurations. lmprovements to voltage quality can
first be addressed by balancing load on the phases
between numerous strategic locations on the feeder
to eliminate unnecessary overloading of phases that
may worsen line losses due to loading. ln addition,
primary laterals and trunks are re-conductored with Modeled Voltoge Levels at Peak Loading
more efficient conductors to increase sagging voltage
levels. ln some scenarios, an additional conductor phase (or phases) may be installed to offload a heavily
loaded phase and assist in supporting the voltage.
o Voltoge Regulotor Settings
As a complement to the efforts of providing optimal voltage quality, the Grid Modernization Program
analyzes and recalculates the substation and midline (outside the substation) voltage regulator
s1 ANSI C84.1 specifies the steady-state voltage tolerances for an electrical power syslem. The standard divides voltages into two ranges. Range A
is the optimal voltage range. Range B is acceptable, but not optimal. http://www.powerqualityworld.coml20lll04lansr-c}4-1-voltage+atings-60-
hertz.html
Exhibit No. 8
Case No. AVU-E-'!9-04
H. Rosentrater, Avista
Schedule 1 , Page 97 of 1 03
o
loss conductors. An engineering decision can immediately
be made to replace the conductor based on loading,
voltage drop, or line losses; however, a Designer may also
determine that it is best to re-conductor based on the
effects of pole conditions and classifications, the results
from the Wood Pole Management inspection reports,
condition of the primary and neutral overhead conductors,
and potential benefits from relocation as part of the
targeted replacement of these conductors.
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settings. This is performed to reflect the changes to loading and the conductor characteristics that the
Program is proposing as part of the holistic upgrade and rebuild of the circuit. Feeders are modeled
during both peak loading and average loading conditions, with both normal and abnormal circuit
configurations. The result of the analysis is the establishment of regulator settings that bring the voltage
quality back into the permissible ANSI 84.1 ranges for all customers during the modeled scenarios, and
eli m i nate over-voltage a nd u nder-voltage situations.
o Fuse Sizing ond Coordinotion Study
lncorrect fuse sizes can compromise the reliability of the feeder through mis-coordination of operation or
being undersized. For example, if the fuses in series are not
sized correctly, the device furthest downstream from the
source ofthe outage (rather than the fuses closest to the
problem) may operate first, meaning that all of the customers
in between will be out of service. Also, fuses that are
undersized and do not match the load being served can
unexpectedly operate and create outages. A customized fuse
protection and coordination scheme is determined for each
distribution circuit to ensure that a consistent fusing
philosophy is deployed and that all fuses are accurately
sized. This efficiency helps reduce customer outages.
o Line Losses
The distribution of electricity at medium voltage results in energy lost to resistance, which varies
depending on the current magnitude, the resistive characteristic of the conductor(s), and the length of
the conductor(s). The greater the line losses on a feeder, the
higher the inefficiency. Line losses can be minimized by replacing
higher loss conductors with more efficient conductors. Grid
Modernization analyzes and sizes primary conductors
appropriately to meet peak loading conditions, minimize line
losses at peak and average loading conditions during normal
system configuration, and improve voltage levels on feeders. Line
losses are generally first addressed by balancing load on the
phases between numerous strategic locations on the feeder to
eliminate the unnecessary overloading of phases that may worsen
line losses caused by loading. Line losses are then further
minimized by replacing wire with more efficient conductor where conductor resistivity is high and/or
where loading levels are moderate to high.
o Power Fdctor
Power factor is defined as the ratio of the real power in a circuit to the apparent power. The difference
between the two values is caused by the
presence of reactance in the circuit and
represents reactive power that does not
perform useful work, which is a form of line
losses. Power factor is a value that can
fluctuate with variations in loading. The Grid
Modernization Program ana lyzes the
historical power factor scenario of over
Exhibit No. 8
Case No. AVU-E-I9-04
H- Rosentrater, Avista
Schedule 1 , Page 98 of 1 03
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GRID MODERNIZATION RESULTS:
* Increased Reliability
* Reduced Energt Losses
* Reduced Maintenance Costs o
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o 77,000 hourly data pars covering at least a 24 month span to calculate the apparent power and power
factor. The result is a comprehensive tabular and graphical representations that detail and explain the
power factor performance of the feeder, the percent
occurrence of lagging and leading power factors, and
the severity to which a circuit could be lagging and
leading - both in terms of time and quantity.
o Power Factor Correction
The power factor of a circuit can be corrected to offset
the reactance in the system to a more optimal level and
bring the circuit closer to unity. A unity power factor is
desirable in a power system to reduce losses and
improve voltage regulation. The Grid Modernization
Program corrects the circuit power factor and lowers
line losses from reduced reactive power flow by
analyzing the historical power factor scenarios and
enacting a solution. The historical raw watt and VAR
data is reanalyzed with a variable VAR to adjust the
resulting power factor with the known capacitors
values. This exercise allows the ideal amount of
capacitance to be modeled on the circuit for the loads
in order to optimize the power factor at variable
times. ln scenarios with significant or unnecessary
leading power factors, existing fixed capacitor banks are
removed or reduced in size. ln scenarios with
significant or unnecessary lagging power factors, fixed
capacitor banks are installed. ln more severe situations,
to raise the power factor to a reasonable base value,
switched capacitor banks are installed to supplement
the power factor when required by loading. This
approachhelpstooptimizethecorrectionofthepowerfactorandreduceslinelosses. The
establishment of power factor also incorporates the field verification of existing deployed capacitor sizes,
as it is not uncommon to discover capacitor banks that are incorrectly represented in Avista's GIS and
modeling software.
. Di strib utio n Auto m atio n
The Grid Modernization program currently represents Avista's largest centralized program to fully automate
and improve the operating
functionality and efficiency of the
distribution system through the
installation of automated
distribution line devices. Grid
Modernization has been
programmatically addressing the
distribution automation needs of
Avista since the end of 2013. The
program focuses on installing air
switches, reclosers, capacitor
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1 , Page 99 of 1 03
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MoTTEnNIZATION:
A Sr*apsHoT
/ 5 Years as a Program
/ 9 Feeders Completed
/ 8 Feeders Currently Under
Construction
/ 6 Feeders Currently in Design
/ qtq Circuit Miles Upgraded
./ 545 Million in Capital
lnvestments Made
/ 48 Automated Line Devices
lnstalled
/ ]..oo% Quality Assurance
lnspection
/ 50% Contract Labor
Augmentation
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AiFvtsrr DISTAUTOMATION SYSTEM
Remote SwitclEs,
Breakers,
Regulators &
Capacitors
Radio Network OPGW
CellularffRoPoS Fiber
([oSubstations) Backhaul
(Sub toAVA)
Avista DMS
Application
Servers
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banks, and voltage regulators with communications and remote operability. The reduction in the duration
of outages can be achieved through the installation of devices with communications that can either be
controlled remotely or through a distribution management system (DMS). ln addition, the number of
customers impacted by an outage and a reduction in the frequency of outages is achieved through the
installation of devices with fault sensing and tripping capabilities. Time and cost savings are accomplished
through the remote application of hot-line-holds. Fault detection, isolation, and restoration, conservation
voltage reduction, and integrated volt/VAR control are also gained through Grid Modernization when the
necessary substation equipment and components are in
place.1
. Open Wire Secondary ldentification, Analysis and
Replacement
Open wire secondary districts have the ability to
negatively affect reliability due to the physical nature of
construction and configuration. These districts are also
predominantly located in areas with high vegetation
growth and limited crew access. These factors have the
ability to increase the number of outages and the
duration of the outages. A circuit's reliability can be
improved by strategically splitting the districts with
dedicated transformers and replacing these districts with
an appropriately sized dedicated neutral. Grid
Modernization is also initiating a study to analyze and
quantify the estimated amount of open wire districts on
feeders, as well as the amount requiring replacement
based off of the criteria of the Distribution Feeder
Management Plan. This will assist in planning and
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budgeting appropriately to address the needs of the feeders. ldentified open Wire Secondary District
in Spokane
c Poles Anolysis & Replacement
All components of an overhead distribution system rely on the integrity and health of poles to ensure
that the system remains safe, reliable, and operational. The Grid Modernization program performs
engineering and field examination of all of the poles and
structures on a feeder to determine the removal,
installation, replacement, or reinforcement based off of the
criteria of the program (the Distribution Feeder
Management Plan, discussed earlier on page 82). A pole
inspection report is requested and conducted to obtain an
explicit list of poles on the feeder. The pole information from
the inspection report provides detailed information for Grid
Modernization to leverage in the assessment and proposals.
This information includes: number of poles, age of poles,
number of poles past the Mean Time to Failure (optimized
replacement age), yellow and red tag poles (those identified
as needing replacement), and to illustrate the overall
characteristics of the feeder in terms of average age and pole
classification.
Exhibit No. 8
Case No. AVU-E-I9-04
H. Rosentrater, Avista
Schedule 1, Page 100 of 103
Poles ot Mission Compus, woiting to be
looded and instolled
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o . Transformers
Core losses are an inherent characteristics of distribution transformers that negatively affect efficiency
and do not change with fluctuation in loading. The Grid Modernization program analyzes the
approximate energy savings that are achieved
through the reduction in transformer core losses
obtained when transformers are replaced with more
efficient units - whether being replaced due to
overloading or PCB levels. The estimated energy
savings are achieved through the use of a unique
algorithm that was created to: analyze each
transformer on the feeder, determine the PCB/age
replacement status, determine if the transformer is
sized appropriately based on actual loading, make a
Boby Red Toil Howk in a nest on o tronsformer recommendation on the appropriate size for the
load, and then use historical core loss values to
calculate the approximate energy savings that are achieved. All transformers on a feeder are identified
for removal, installation, or replacement. Some transformers will be identified for replacement by the
Transformer Change-Out Program (TCOP) based on the vintage and
PCB level of the unit. However all transformers are analyzed and
sized to most accurately reflect customer loads per the Distribution
Feeder Management Plan (DFMP), incorporating flicker and voltage
drop analysis.
o o Underground Cable ldentification & Analysis
lmprovement in the number of underground primary cable outages
has been achieved by strategically replacing cable that has a known
susceptibility to faulting. This includes the targeted replacement
of all pre-1982 non-jacketed primary cable, which Avista's historical
data (and industry-wide experience) suggests has the highest
failure rate of underground cable. ln addition, the Program
replaces any primary cable section that has multiple documented
failures for either jacketed or non-jacketed primary cable.
c Vegetation Management
Vegetation can pose serious reliability and safety problems for
distribution feeders when not properly maintained. Trees can
grow into overhead distribution lines as they mature, which
creates access issues, public safety concerns, and the
possibility for trees or limbs to fall through the conductors or
to create electrical faults through physical contact. Proper
vegetation maintenance along feeder corridors removes many
of these concerns while improving safety and system
reliability. This includes along easements where feeder re-
conductoring is being performed and where appropriate
clearances need to be reestablished between vegetation and
Avista's primary and secondary conductors. Grid
Modernization's work is optimized when performed in
coordination with Vegetation Management efforts.o
lnstolli ng U nderg round i n
Coeur d'Alene
Vegetoti on M o n oge m e nt I ssue
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 101 of 103
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A recloser or autorecloser is a circuit breaker equipped with a mechanism that can detect and automatically
close and re-energize a line after it is tripped. Since the majority of faults are temporary and transient (such
as those caused by lightning, tree limbs brushing against overhead conductors, wind or birds), using
reclosers can significantly improve reliability, quickly restoring normal
service for our customers. Typically, reclosers are designed to have
three open-close operations followed by a final lock-out. Up to 95% of
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Diagram of a Recloser
One of Avista's core
responsibilities is to
deliver voltage to
customers within a
suitable range.
Minimizing variations
and maintaining the
voltage at an
acceptable level that is
tolerated by electrical
machines is achieved
using voltage
regulators.
Voltage Regulators
e2 "lmproving Network Reliability with Reclosers," Scott Ware, FECA Meeting, June 1 1, 2012, http//studylib.net/doc/18121 18S/recloser and
"Distribution System Protection", University of Western Ontario, May 2008, httpJ/www.eng.uwo.ca/people/tsidhu/Documents/E5586B-
Hesam%20Hosseinzadeh-250441 1 31 .pdf
ss "Voltage lnegularities," Hershey Energy Systems, http//www.hersheyenergy.com/voltage_irregularities.html
faults can be cleared with this
type of recloser operation.e2
Avista has about 330 midline
(outside the substation, thus
belonging to Distribution)
reclosers on our system, and
the Company is adding more
every year.
Voltage regulators are also
included in this program. All
electrical equipment is
designed to operate within
narrow limits; poor voltage
conditions can result in
flickering lights, burned out
motors or other damage to
electrical equipment. Voltage
irregularities are one of the
most critical power quality
issues facing utilities today.e3
IEEE Bushing
lnterface
Vacuum
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Vonage
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Voltage
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Handle
Magnetic
Actuator
Position
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 102 ofI03
RECLOSER
MAINTENANCE
PROGRAM
r Semi-AnnualVisual
Checklist lnspections of
all Breaker Reclosers,
Midline Voltage
Regulators, and Midline
Capacitor Banks
o Monthly to Semi-Annual
Data Readings for all
Voltage Regulators
r Recloser Replacement at
30 years
Monthly lnspections of
Reclosers and Batteries at
Substations
. Battery Replacement at
35 Months
o 3 Year Battery
Replacement Cycle For
Any Smart or Non-Smart
Device Utilizing a 40 Arnp-
Hour Battery
o SCADA Distribution
battery replacement with
major alarm for existing
DMS reclosers
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Another key piece of equipment in distribution operations is a device called a capacitor, which can maintain
voltage at a specific level as needed. Capacitors store energy which
can be used to offset fluctuations and improve a circuit's power
factor (the efficiency of the load current being converted to actual
useful work output.) By installing suitably sized capacitors and
maintaining the correct
power factor, energy waste
(line loss) is minimized,
voltage is maintained at the
correct levels, efficiency is
created at the power plant
level, more energy is
available for consumption,
and customers ultimately
save money by only paying
Above and Betow: capacitors ,tJ.ii"
power they actually
Automatic Transfer switches viper Reclosers
(ATS) are installed at customer's request due to commercial loads
with high reliability requirements. Specifically, the ATS provides the
customers load with access to two separate feeder sources, creating
a redundant supply of power. Examples of such customers are
airports, waste water treatment plants, manufacturing facilities, and
biotech labs. ATS devices, while not many in number, are also
included in Avista's Device Program.
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Above: Automatic Transfer Switch
Exhibit No. 8
Case No. AVU-E-19-04
H. Rosentrater, Avista
Schedule 1, Page 103 of 103
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