20230710Exhibit A - ID AM Refresh Project Staus Report.pdf

Idaho Advanced
Metering Refresh
Project
Status Report
May 26, 2023
Exhibit A
1
Contents
Table of Figures and Tables ................................................................................ 3
Executive Summary | Advanced Metering Refresh .............................................. 5
A.Report Highlights ................................................................................ 5
B.Purpose of this Report ........................................................................ 6
C.Comparison of Costs for AMR Refresh Alternatives ............................ 7
D.Incremental Benefits Associated with AMI Metering ............................ 8
E.Comparison of AMR and AMI Customer Costs / Net Costs ............... 10
F.Conclusion: Avista’s Refresh Decision is Timely and Prudent ........... 11
Section 2 | AMI is a Foundation for the Future ................................................... 13
A.Avista’s Advanced Metering Journey ................................................ 13
B.The Changing Role of Advanced Metering ........................................ 14
C.AMI Has Emerged as the Utility Metering Standard .......................... 15
Section 3 | Project Deployment Overview .......................................................... 17
A.The AMI System Described .............................................................. 17
B.Overview of Project Deployment ....................................................... 19
C.Managing the Uncertainties of Major Technology Applications ......... 21
D.Avista’s Choice to Deploy Itron Meters in Idaho ................................ 21
E.Meter Data Management and Head End Systems ............................ 23
F.Meter Deployment ............................................................................ 23
G.Collection Infrastructure .................................................................... 23
H.Customer Data Privacy, Cyber Security and Disaster Recovery ....... 23
Exhibit A

2
Section 4 | Incremental Customer Benefits with Quantified Financial Value ....... 26
A. Overview ........................................................................................... 26
B. Meter Reading .................................................................................. 27
C. Remote Service Connectivity ............................................................ 27
D. Customer Benefits from Improved Outage Management .................. 28
E. Energy Efficiency Enabled by Advanced Metering ............................ 31
F. Energy Theft and Unbilled Usage ..................................................... 34
G. Billing Accuracy ................................................................................ 35
Section 5 | Summary of Customer Benefits Currently Not Quantified ................. 39
A. All Benefits Are Important to Our Customers..................................... 39
B. Improving Customer Convenience, Experience, and Satisfaction with
their Service ................................................................................................. 39
C. Improving Customer and Utility Employee Safety ............................. 42
D. Operational Awareness of System Health ......................................... 44
E. Design Services and Engineering ..................................................... 45
Section 6 | Expected Future Trends in Customer Benefits ................................. 46
A. Support of Asset Management Planning ........................................... 46
B. Support of Electric System Planning ................................................. 46
C. Enabling Energy Pricing Strategies ................................................... 47

Exhibit A

3
Table of Figures and Tables

TABLE 1-1. INITIAL ESTIMATED CAPITAL COSTS SHOWN ON A NET PRESENT VALUE BASIS FOR
ALTERNATIVE REPLACEMENT SYSTEMS FOR AVISTA’S END OF LIFE AMR SYSTEM IN
IDAHO………………………………. 7
TABLE 1-2. INITIAL ESTIMATED LIFECYCLE EXPENSES SHOWN ON A NET PRESENT VALUE BASIS FOR
ALTERNATIVE REPLACEMENT SYSTEMS FOR AVISTA’S END OF LIFE AMR SYSTEM IN IDAHO…………8
TABLE 1-3. FORECAST OF INCREMENTAL FINANCIAL BENEFITS (NPV) ESTIMATED FOR AVISTA’S PLANNED
DEPLOYMENT OF AMI METERING IN IDAHO, COMPARED WITH AN ALTERNATIVE REPLACEMENT AMR
SYSTEM. MAJOR AREAS OR CATEGORIES OF BENEFITS AND THEIR RESPECTIVE FINANCIAL TOTALS
ARE SHOWN BELOW IN BOLD FONT. INDIVIDUAL BENEFITS COMPRISING EACH MAJOR AREA ARE
INDENTED BENEATH………………………………………………………………………………………9
TABLE 1-4. NET PRESENT VALUE (NPV) OF INITIAL FORECASTED COSTS AND INCREMENTAL FINANCIAL
BENEFITS FOR THE REPLACEMENT ALTERNATIVES OF AN AMR AND AMI SYSTEM FOR AVISTA’S
ADVANCED METERING REFRESH PROJECT. PROJECT COSTS ARE THE LIFECYCLE TOTAL OF BOTH
CAPITAL AND INCREMENTAL EXPENSES FOR EACH ALTERNATIVE…………………………………… 10
FIGURE 1-1. NET COST OF AMR AND AMI IS REPRESENTED BY THE TOTAL OF CAPITAL AND
INCREMENTAL EXPENSES MINUS THE VALUE OF THE INCREMENTAL FINANCIAL BENEFITS…………...10
FIGURE 2-1. ACTUAL AND EXPECTED TREND IN DEPLOYMENT OF AMI METERS IN THE UNITED STATES.
EDISON FOUNDATION, APRIL 2021………………………………………………………………………..
15
FIGURE 3-1. DIAGRAM OF AMI SYSTEM COMPONENTS……………………………………………………….
17
FIGURE 3-2. INITIAL DEPLOYMENT SCHEDULE BY MAJOR PROJECT FOR AVISTA’S IDAHO ADVANCED
METERING REFRESH
PROJECT………………………………………………………………………………………… 19
TABLE 3-1. FORECASTED LIFECYCLE CAPITAL (CAP) AND EXPENSES (EXP), ON A NOMINAL BASIS IN
$MILLIONS, FOR AVISTA’S IDAHO AMI PROJECT FOR EACH YEAR OF THE PROJECT LIFECYCLE…….. 20
TABLE 4-1. FORECASTS OF ESTIMATED INCREMENTAL CUSTOMER BENEFITS FINANCIALLY QUANTIFIED
FOR THE COMPANY’S PLANNED ADVANCED METERING REFRESH PROJECT IN
IDAHO……………………………….. 26
TABLE 4-2. NET PRESENT VALUE OF INCREMENTAL FINANCIAL BENEFITS ESTIMATED FOR METER READING
FOR AVISTA’S IDAHO ADVANCED METERING REFRESH
PROJECT………………………………………………… 27
TABLE 4-3. NET PRESENT VALUE OF INCREMENTAL FINANCIAL BENEFITS ESTIMATED FOR REMOTE
SERVICE CONNECTIVITY FOR AVISTA’S IDAHO ADVANCED METERING REFRESH
PROJECT………………………………. 28
TABLE 4-4. NET PRESENT VALUE OF INCREMENTAL FINANCIAL BENEFITS FOR CUSTOMER SAVINGS
ASSOCIATED WITH MORE EFFICIENT MANAGEMENT OF ELECTRIC SYSTEM OUTAGES AS ENABLED BY
AVISTA’S PLANNED DEPLOYMENT OF AMI IN
IDAHO…………………………………………………………………………... 29
TABLE 4-5. NET PRESENT VALUE OF INCREMENTAL FINANCIAL BENEFITS ESTIMATED FOR ENERGY
EFFICIENCY SAVINGS ENABLED BY AVISTA’S PLANNED DEPLOYMENT OF AMI IN
IDAHO………………………………. 32
Exhibit A

4
TABLE 4-6. NET PRESENT VALUE OF INCREMENTAL FINANCIAL BENEFITS ESTIMATED FOR IMPROVEMENTS
IN ENERGY THEFT AND UNBILLED USAGE ENABLED BY AVISTA’S DEPLOYMENT OF AMI ADVANCED
METERING IN
IDAHO……………………………………………………………………………………………………. 34
TABLE 4-7. NET PRESENT VALUE OF THE INCREMENTAL FINANCIAL BENEFITS ESTIMATED FOR
IMPROVEMENTS IN BILLING ACCURACY TO BE ENABLED BY AMI ADVANCED METERING IN
IDAHO…………………………….. 36

Exhibit A

5
Executive Summary | Advanced Metering Refresh
A. Report Highlights
• Avista Utilities’ Advanced Meter Reading (AMR) system in Idaho was installed beginning in
20051 and has been maintained in service beyond its expected 15-year life.
• Key components of this AMR system are no longer manufactured or supported, and this
system needs to be timely replaced (or “refreshed”) to avoid excessive replacement costs2
and provide continuing reliable service supporting the Company’s electric and natural gas
operations in Idaho.
• Further, AMR does not support Avista’s more customer-centric, technology-enabled
business model for better meeting our customers’ evolving energy service needs. Current
generation Advanced Metering Infrastructure (AMI) 3 is fundamental to addressing these
challenges and opportunities.
• Despite the need for new AMI capabilities in Idaho, the Company evaluated the costs and
benefits of both AMR and AMI metering solutions4 to refresh our end-of-life AMR system.
• Importantly, because developments in AMI technology have been at the forefront of
innovation in advanced metering, this technology is now less expensive to deploy than a
contemporary replacement AMR system. This shift in costs is in part responsible for the
predominant industry trend of replacing ageing AMR systems with new AMI technology.

1 The Idaho Public Utilities Commission approved Avista’s proposed installation, beginning in January of 2005,
of Advanced Meter Reading technology for electric and natural gas services in Idaho, in its Final Order 29602
(AVU-E-04-01). Avista’s forecast of AMR costs and benefits was based on an expected 15 year lifecycle for
the technology.
2 The longer Avista’s existing AMR system is kept in service the greater will be the ultimate total cost of
replacement. This is because end of life equipment is now failing at increasing rates and the remediation of
failed equipment is prohibitively expensive. As an example, a failed meter can be replaced with a new AMR
meter, however, that new meter no longer communicates with the existing collection infrastructure (repeater).
The failed meter, therefore, has a compounding consequence cost because the new investment includes not
only the meter but the associated repeater device. As a consequence, when the existing system is finally
replaced, there will be a much larger balance of unamortized AMR equipment, than current balances, that will
have to be collected through deferral and later recovery.
3 Advanced Metering Infrastructure or “AMI” is the prevalent version of advanced metering being installed in
the U.S. and around the world. AMI differs from AMR primarily in its ability to support two-way communications
as well as providing a platform for end-point software computation, analysis and remote operation.
4 For this analysis, Avista formally compared both costs and benefits of replacement AMR and AMI systems.
An alternative of returning to a process of manually reading customer meters was not formally evaluated for
this project, because in the Company’s most recent financial analysis of AMI in Washington, the AMI solution
produced greater than $56 million in net financial benefits compared with the alternative of continuing to read
customer meters manually. Returning to manual meter reading for our Idaho customers would neither be cost
effective nor prudent.
Exhibit A

6
• Related to this trend, Avista is the only regulated electric utility in Idaho that does not currently
serve its customers with AMI metering.5
• In addition to having a lower total cost6 than AMR, AMI technology will also deliver
incremental financial benefits to our Idaho customers expected to exceed $48 million (NPV)
over the lifecycle of the project. These incremental benefits are above and beyond the
financial benefits provided by AMR technology.
• These incremental financial benefits to customers are real — and will only increase over time
as the Company maximizes the full potential of AMI (including ways not yet imagined or
implemented).
• Of note, these “quantified” financial benefits do not take into account the many other “non-
quantified” (but very real) customer benefits provided by AMI, such as improvements in
safety, power quality, convenience, and service.
• The combination of providing the right solution for Avista’s customer service objectives, at a
lower total cost, combined with the greater financial benefits for customers, makes both
straightforward and prudent Avista’s decision to refresh its Idaho AMR system with new AMI
metering.
B. Purpose of this Report
This status report for Avista’s Idaho Advanced Metering Refresh Project (Report) provides initial
baseline estimates of the costs and benefits of replacing the Company’s existing end-of-life AMR
system with either new AMR or AMI metering technology. A comparison of these costs and benefits,
as well as the applicability of AMI for meeting Avista’s current and long-term customer service
objectives, demonstrates the overall superiority of AMI. These facts clearly support the Company’s
decision to move forward with deployment of a new AMI system in Idaho. This analysis supports
Avista’s accounting petition requesting the tracking and recovery of the unamortized value of AMR
equipment to be removed and replaced during the AMI deployment.7 The Report also provides a
foundation for the Company’s intention to seek cost recovery in a future regulatory proceeding for
then used and useful investments in AMI.8 Finally, the Report provides a high-level overview of the
Company’s planned AMI project, including forecasts of expected capital and operating costs (O&M

5 Idaho Power Company began installing AMI metering for its electric customers in January of 2009, with
completion of its AMI deployment planned for year-end 2011. Customers of Rocky Mountain Power are
currently served with AMI metering, provided in a deployment across their service territory (including Idaho)
that was slated for completion in 2022.
6 Total cost is the combined capital and expenses over the project lifecycle.
7 Because ongoing investments for AMR replacement equipment are required for assets that fail in service,
there is always residual net plant that will not have been fully amortized at the point when the AMR system is
refreshed. The NPV of unamortized assets under the current refresh plan is estimated to be $8,610,728, as
shown below in Table 1-2. Further, because end-of-life AMR system assets are failing at increasing rates,
these increasing replacement costs would only drive greater unamortized balances (than currently expected)
if the AMR refresh were to be deferred or delayed from current plans.
8 Because elements of the AMI system become used and useful in serving customers during the course of
deployment, Avista plans to seek deferral of the depreciation expense associated with deployment, and later
recovery for these investments in applicable proceedings (e.g. rate cases) along the way rather than waiting
for the entirety of the investment in AMI metering to have been completed.
Exhibit A

7
or expenses) and incremental financial and non-financial customer benefits to be delivered by the
new system.
C. Comparison of Costs for AMR Refresh Alternatives
When discussing project financials we sometimes refer to costs and benefits in nominal (or cash)
amounts, though we predominantly state them as the net present value (NPV) of the stream of
annual costs and customer benefits anticipated over the project lifecycle (2023 – 2045). 9 Use of net
present value normalizes the time value of customer costs and benefits to ensure a meaningful
forecast of the cost effectiveness of the investment regardless of when expenditures are made and
when benefits are realized. Here, we express net present value in 2023 dollars when comparing
both costs and financial benefits for both refresh alternatives (AMR & AMI). Estimated capital costs
for installing a replacement AMR system and an alternative AMI system are presented by major
project or cost components10 in Table 1-1, below.
1TABLE 1-1. INITIAL ESTIMATED CAPITAL COSTS11 SHOWN ON A NET PRESENT VALUE BASIS FOR
ALTERNATIVE REPLACEMENT SYSTEMS FOR AVISTA’S END OF LIFE AMR SYSTEM IN IDAHO.
The net present value of the total capital costs for Avista’s planned AMI deployment in Idaho ($75.4
million) is approximately 73 percent of the corresponding costs for the alternative of replacing the
end-of-life AMR system with new AMR technology ($103.8 million).

9 This period of time includes the planned deployment of the AMI system (2023-2027) and 15 full years of
operation. Avista’s analysis was carried slightly beyond the planned 15 year life through year 2045, recognizing
the overlap with deployment of a potential successor metering system.
10 Categories of costs for refresh alternatives, AMR and AMI, are organized by the technologies of Avista’s
existing AMR system (e.g. the “Fixed Network” includes the collection infrastructure and applications, and the
AMR meters themselves). The alternative for AMR was based on a refresh of these systems, and for the
purposes of this comparison, the total cost of AMI deployment was allocated by these same AMR categories.
11 Key differences in the capital costs between AMR and AMI metering lie in two main areas: unit cost of the
meters themselves, and cost of the collector infrastructure network. While AMR meters are substantially less
expensive than AMI meters, the number of field devices that must be installed to capture AMR data is much
greater than that for AMI. The higher cost for AMR data collection devices more than offsets the higher
incremental cost of AMI meters, making the AMI solution less expensive to install.
12 TWACS® is a Power Line Carrier (PLC) communication technology provided by Aclara Technologies, LLC.
Major Cost Components Capital Cost - New AMR
(Net Present Value) Capital Cost - New AMI
(Net Present Value)
Existing Mobile Routes $6,140,748 $7,928,104
Existing Fixed Network System $82,704,068 $53,276,856
Existing TWACS12 System $14,989,928 $14,270,586
Totals $103,834,744 $75,475,546
Exhibit A

8
In addition to the capital costs shown above, we estimated the incremental expenses13 for the
lifecycle of each replacement alternative, shown below by major cost component, in Table 1-2.
2TABLE 1-2. INITIAL ESTIMATED LIFECYCLE EXPENSES SHOWN ON A NET PRESENT VALUE BASIS FOR
ALTERNATIVE REPLACEMENT SYSTEMS FOR AVISTA’S END OF LIFE AMR SYSTEM IN IDAHO.
The net present value of the incremental expense costs for Avista’s planned AMI deployment in
Idaho ($23.1 million) is approximately 41% greater than the estimated incremental expenses for a
replacement AMR system ($13.6 million). In this comparison of alternatives, however, the total
capital and incremental expenses for AMR ($117.4 million) is 16 percent greater than the combined
capital and incremental expenses for the AMI refresh solution ($98.6 million).
D. Incremental Benefits Associated with AMI Metering
In addition to having a lower estimated combined capital and expense cost, as noted just above, the
AMI alternative will also deliver a greater level of financial and non-financial customer benefits than
is achievable with AMR. While many areas of financial benefit produced by AMR and AMI systems
are identical or similar (for example, the ability to eliminate manual meter reading), there are several
types of benefits that can only be achieved through AMI deployment. Avista refers to this greater
level of benefits enabled by AMI as “incremental benefits” because they are additive to the benefits
already provided by our existing (or a replacement) AMR system. Table 1-3, below, shows areas
and amounts of incremental financial benefits achievable with AMI, which are above and beyond
those provided by AMR. These incremental financial benefits are based on Avista’s experience
operating both AMR and AMI systems, scaled to the level of benefits expected for our Idaho

13 In this analysis, ‘incremental expenses’ are those “new costs” the Company would incur in deploying and
operating either a new replacement AMR or AMI system. These incremental costs are above and beyond the
current level of expenses required to support our existing AMR system. In the subsequent discussion covering
the deployment of the new AMI system, Avista presents the total actual expenses or budget for the project,
not just the incremental expenses shown here.
14 Because recovery of the unamortized value of AMR metering equipment is applicable to both refresh
alternatives, AMR and AMI, this cost is not included in the further discussion of the costs for the AMI refresh
project.
Major Cost Components
Incremental Expense
New AMR
(Net Present Value)
Incremental Expense
New AMI
(Net Present Value)
Existing Mobile Routes $1,854,919 $3,765,872
Existing Fixed Network System $1,594,375 $7,305,826
Existing TWACS System $1,541,350 $3,457,405
Recovery of Regulatory Asset14 $8,610,728 $8,610,728
Totals $13,601,371 $23,139,832
Exhibit A

9
customers. As shown in the bottom of the Table, estimated incremental financial benefits from the
Company’s planned AMI deployment total $48.5 million on a net present value basis.
3TABLE 1-3. FORECAST OF INCREMENTAL FINANCIAL BENEFITS (NPV) ESTIMATED FOR AVISTA’S
PLANNED DEPLOYMENT OF AMI METERING IN IDAHO, COMPARED WITH AN ALTERNATIVE REPLACEMENT
AMR SYSTEM. MAJOR AREAS OR CATEGORIES OF BENEFITS AND THEIR RESPECTIVE FINANCIAL TOTALS
ARE SHOWN BELOW IN BOLD FONT. INDIVIDUAL BENEFITS COMPRISING EACH MAJOR AREA ARE
INDENTED BENEATH.

15 Calculation of these costs is shown in the companion “AMI Benefits Workbook” which is available from the
Company as an Excel file. Very slight differences between the totals reflected here and values found in the
Excel file result from small differences in rounding.
Area of Benefit Incremental Financial Value with AMI15
Meter Reading $184,164
Reduce Mobile Meter Reading $184,164
Remote Service Connectivity $4,113,948
Account Open/Close/Transfer $1,502,370
Credit Collections/Connections $2,350,349
After-Hours Fees $261,329
Outage Management $17,472,148
Earlier Outage Notification $14,747,247
Reduced Customer Calls $597,376
Avoided Single Lights Out $1,599,365
Reduced Major Storms Cost $528,161
Energy Efficiency $17,750,714
Conservation Voltage Reduction $5,928,422
Customer Energy Efficiency $1,635,926
Behavioral Energy Efficiency $10,186,366
Energy Theft and Unbilled Usage $7,489,528
Theft and Diversion $1,263,447
Stopped Meters $477,448
Equipment Operation & Validation $5,748,633
Billing Accuracy $1,503,428
Bill Inquiries $1,090,229
Billing Analysis $413,198
Exhibit A

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E. Comparison of AMR and AMI Customer Costs / Net Costs

Table 1-4, below, summarizes the costs and incremental financial benefits for customers for the
alternatives of installing a new AMR or AMI system. The summary includes both capital and
incremental expense costs for each system as well as the incremental financial benefits provided by
AMI alone.
4TABLE 1-4. NET PRESENT VALUE (NPV) OF INITIAL FORECASTED COSTS AND INCREMENTAL FINANCIAL
BENEFITS FOR THE REPLACEMENT ALTERNATIVES OF AN AMR AND AMI SYSTEM FOR AVISTA’S
ADVANCED METERING REFRESH PROJECT. PROJECT COSTS ARE THE LIFECYCLE TOTAL OF BOTH
CAPITAL AND INCREMENTAL EXPENSES FOR EACH ALTERNATIVE.
These data are further illustrated below in Figure 1-1 where the Net Cost of AMI is represented by
the total of capital and incremental expenses minus the value of the incremental financial benefits.
5FIGURE 1-1. NET COST OF AMR AND AMI IS REPRESENTED BY THE TOTAL OF CAPITAL AND
INCREMENTAL EXPENSES MINUS THE VALUE OF THE INCREMENTAL FINANCIAL BENEFITS.

16 Total forecasted lifecycle capital costs of $103,834,744 and lifecycle incremental expenses of $13,601,371
on a net present value basis, as summarized in Tables 1-1 and 1-2.
17 Total forecasted lifecycle capital costs of $75,475,546 and lifecycle incremental expenses of $23,139,832
on a net present value basis, as summarized above in Tables 1-1 and 1-2.
18 Please see the discussion above regarding incremental customer financial benefits for AMR and AMI.
19 Net Customer Cost is the Net of Total Capital and Incremental Expense costs ($98.6 million) minus the
offsetting value of the incremental financial benefits ($48.5 million) provided solely by AMI.
Total Incremental Financial Value $48,513,929
AMR Alternative AMI Alternative
Project Costs
$117.4 million16

Project Costs
$98.6 million17
Incremental Customer Financial Benefits
$018

Incremental Customer Financial Benefits
$48.5 million
Net Customer Cost
$117.4 million

Net Customer Cost
$50.1 million19

Exhibit A

11

The primary incremental benefits discussed in this Report are those quantified for inclusion in the
financial cost-benefit analysis comparing the AMR and AMI alternatives for replacing the Company’s
end-of-life AMR system in Idaho. Additional benefits, which have real value to our customers, such
as safety, power quality, convenience, and service, can be more difficult to assign a financial value
but they should be properly included in the consideration of the prudence of our investment. As
Avista has gained experience in the operation of its existing AMI system we have identified a range
of additional customer benefits not initially envisioned. The Company reasonably expects this range
of AMI benefits to continue to expand in the future. These areas of benefit are listed and their
importance to customers is briefly described in Section 5 of this Report.
F. Conclusion: Avista’s Refresh Decision is Timely and Prudent
As briefly noted above, Avista has experienced rapid transformation in our business as we focus
increasingly on the needs of the individual customer, and on the local distribution grid where they
receive service. We understand the long-term success of our business is founded on identifying and
meeting our customers’ evolving energy service expectations and we’re working now to not only
embrace this change but to incorporate these new realities into a more customer-centric, technology-
enabled business model. AMI metering is fundamental to addressing these challenges and
opportunities. It is not surprising, then, that AMI has not only become the metering standard for the
industry but has already been approved by the Commission for customers served by Idaho’s two
other regulated electric utilities, Rocky Mountain Power and Idaho Power. The planned timing of
Avista’s refresh project is also an important consideration. Not only will the new AMI platform allow
Exhibit A

12
the Company to quickly improve the level of service we provide our Idaho customers, but a delay in
implementation will only make the project more expensive.20
It is fortuitous that the AMI platform is significantly more cost effective for customers today than the
less capable AMR alternative. As illustrated in Table 1-4 and Figure 1-1, above, Avista’s decision to
move forward with deployment of AMI in Idaho is a prudent choice compared with the alternative of
replacing our end-of-life AMR system with new AMR technology. The value of AMI is superior in
every respect, where this technology: 1) provides the platform and capabilities to meet the
Company’s strategic business objectives; 2) has a lower combined cost21 of deployment and
operation than AMR; 3) will deliver greater financial benefits for customers in the immediate and long
term; 4) delivers a wider range of other customer services and benefits not currently quantified
financially, and 5) provides greater opportunity for delivering new customer benefits and value in the
future. Avista believes the prudence of our investment in AMI should be judged on the merits of all
customer benefits provided by the system (both quantified and unquantified benefits) even though
our current analysis clearly demonstrates the cost-effective value for our Idaho customers based
solely on project costs and existing incremental financial benefits.

20 As noted earlier in the discussion of recovery of the value of unamortized AMR assets.
21 Combined cost is the total of capital and incremental expenses.
Exhibit A

13
Section 2 | AMI is a Foundation for the Future
A. Avista’s Advanced Metering Journey
Avista has a deep history and legacy innovating new and better approaches to reducing the costs of
metering for our electric and natural gas customers. In the 1970s, Avista (then “The Washington
Water Power Company”) pioneered with utility partners the application of new computing technology
to the work of reading customer meters, developing the first commercial computer-based meter
reading device in the world. In this endeavor, the Company eventually formed a new independent
company, named Itron, to build, market and innovate new metering devices. Itron, one of the world’s
leaders in metering technology,22 still has its global headquarters in Avista’s service territory. One of
the first ubiquitous products sold by that company was the DataCap H® a rugged hand-held portable
data collection device used by Avista and the industry for manually
reading electric, natural gas and other types of utility meters
(pictured at right). Avista recently phased out use of the modern
DataCap device in 2021 with the completion of its AMI deployment
in Washington.
Through the 1990s, Avista continued to monitor developments in
the emerging field of “Advanced Meter Reading” or “AMR.” The
Company’s first deployment of AMR technology was in limited
application in remote or hazardous locations, where the locale made
cost-effective sense. As AMR technology continued to improve and
prices lowered, Avista deployed AMR more broadly, particularly in
our natural-gas-only service areas in Oregon and California. At the
time the Company proposed to broadly install AMR in its Idaho
service area we reported having in service over 74,000 AMR
devices and 350 Powerline Carrier (PLC) devices. Approximately
1,700 of these devices were in service in Idaho in 2004.
In its Idaho deployment of AMR the Company proposed to install
radio-based AMR technology in areas of higher customer density
and PLC technology in more-rural locations. Other factors governing deployment included
geography, distribution configuration, installation costs and the presence of natural gas service.
Readings from the radio-based AMR meters were initially gathered by a mobile device23 and later
by a fixed network of radio-based collection devices. Avista’s proposal to install AMR in Idaho was
approved by the Idaho Public Utilities Commission (IPUC) in 2004, with planned deployment
commencing in early 2005.

22 Itron has over 8,000 utility company clients in over 100 countries world-wide and is the number one provider
of advanced metering solutions for electric and natural gas service in North America.
23 Mobile meter reading involves use of a vehicle-mounted collector device while typically driving established
meter-reading routes. In this application meters are equipped with radio-based communication technology.
Exhibit A

14
Avista’s experience with AMR in Idaho clearly demonstrated the customer value that could be
unlocked compared with the alternative of manually reading customer meters. The Company did
not, however, immediately move forward with the deployment of AMR in its Washington service
territory. This decision was driven in large part by the desire to capture the emerging capabilities of
the next generation of advanced metering (AMI). In our experience, though AMI systems had proven
financial benefits over AMR, these benefits did not outweigh the deployment and operating costs of
early generations of AMI technology. Based on its 2016 analysis of the costs and benefits of AMI,
the Company moved forward with the planned deployment of AMI in its Washington service area.
While the 2016 analysis forecasted substantial positive net financial benefits for customers ($26.5
million), the Company’s re-evaluation of the costs and benefits, performed in 2021, showed much-
more-robust financial net benefits ($56.3 million) than estimated in 2016. Avista’s AMI system in
Washington was fully deployed in early 2021.
At the time Avista initiated AMI deployment in Washington we had to address the question of
whether it made sense to deploy AMI in Idaho as part of one larger project. Ultimately, the decision
was based on the desire to derive more customer value from the Idaho AMR system, which in 2016,
was mid-stream in its 15-year project lifecycle. With the Idaho AMR system now at technical end-of-
life,24 Avista believes it’s imperative to move forward now with replacement of that system. At the
end of the Company’s planned deployment of AMI in Idaho (year 2027), the existing AMR system
will have been in service more than 20 years, well beyond its expected life of 15 years.
B. The Changing Role of Advanced Metering
Over the prior decade, the typical utility business case portrayed AMI metering as a tool enabling a
familiar number of disparate functions, producing a range of incremental financial savings and
conveniences to customers. In short, AMI was viewed as a useful tool supporting the utility’s historic
service model. What’s better understood and valued today is the central role the AMI platform is
playing in the utility’s changing business and the relationship we have with our customers. There is
a convergence of factors driving an accelerated evolution in our business. For all practical purposes,
this new future, while still maturing, is here, now. The forces we face today are often taking place
outside our familiar business framework. Utilities, emerging service competitors, utility customers,
and utility regulators, themselves, are all reacting to capitalize on new opportunities and meet new,
and sometimes unfamiliar challenges. From Avista’s perspective, these underlying forces can be
aggregated into three groups, very briefly described, below:
Clean Energy and Conservation: Among responses to a call for action has been the societal
and regulatory shift to require a greater percentage of our electricity supply be provided by
renewable resources. The cost of these investments is putting greater price pressure on
customers and will continue to drive an ever-greater need to use electricity more efficiently.
Enabling Technologies: The rise and maturing of new technologies is changing the electricity
landscape. These include significant reductions in the cost and availability of customer-

24 As examples, Avista is already having to replace existing failed electric meters, repeaters, and Encoder
Receiver Transmitters (ERTs) installed as part of the original AMR deployment.
Exhibit A

15
owned renewable electricity generation, control, and storage, coupled with regulatory
changes promoting investment in distributed energy. The digitization of massive volumes of
customer data is now combined with complex, interoperative and integrated control systems,
allowing new market players to provide energy customers with a range of services their utility
provider may not offer, at price that’s ever-more competitive with traditional service.
Customer Empowerment: Utility customers have a growing ability to exercise greater choice
and control over their traditional monopoly utility service. This includes use of technology to
help manage and reduce their energy costs, use of distributed energy resources to reduce
reliance on the serving utility, and the growing opportunity to sell their electricity to others
outside the utility’s control, while otherwise relying on the utility’s dedicated infrastructure.
Finally, the falling price of electricity storage and management systems, coupled with onsite
generation, may provide traditional customers a real option to bypass their utility altogether.
Through all of this, the utility must stand ready to serve while remaining competitive and
relevant.
C. AMI Has Emerged as the Utility Metering Standard
In the last two decades, AMI has gone from a relatively new technology to the mainstream metering
application in our industry. Declining prices of computer chips and modules, coupled with their
growing capabilities, has enabled the industry to consider new ways of bolstering the robustness of
AMI networks.25 Indeed, AMI systems have become the new metering standard in the United
States.26 Itron, Avista’s advanced meter manufacturer, has seen a continual marketplace transition
from non-communicating meters to communicating meters, then to AMI (two-way communicating)
meters. Today the market has substantially matured in North America, with 94% of the meters
shipped being communicating meters. According to Itron, most AMI installations today mirror Avista’s
planned AMI deployment in Idaho, where AMI technology is replacing end-of-life AMR systems.
National trends in advanced meter deployment continue to increase in the familiar pattern shown
below in Figure 2-1. By year-end 2019, utilities had installed more than 99 million AMI meters
(exceeding the prior forecast), covering 75 percent of U.S. households. Based on survey results and
plans approved in 2020, estimated deployments were expected to reach 107 million AMI meters by
the end of 2020 and 115 million by year-end 2021.27
1FIGURE 2-1. ACTUAL AND EXPECTED TREND IN DEPLOYMENT OF AMI METERS in the United States.
Edison Foundation, April 2021.

25 How Standards Are Evolving in the World of Smart. Smart Energy International. https://www.smart-
energy.com/industry-sectors/smart-meters/how-standards-are-evolving-in-the-world-of-smart/
26 Pages 48,49, paragraph 153, Final Order in Dockets UE-190529, UG-190530, UE-190274, UG-190275,
UE-171225, UG-171226, UE-190991 & UG-190992 (Consolidated).
27 Electric Company Smart Meter Deployments: Foundation for a Smart Grid (2021 Update). The Edison
Foundation, Institute for Electric Innovation. Results for year 2022 are not yet available.
Exhibit A

16

Exhibit A

17
Section 3 | Project Deployment Overview
A. The AMI System Described
While there is greater familiarity with advanced metering systems today, we believe it is still helpful
in this discussion to provide a brief overview of the system components. The diagram below
represents the AMI system, including the advanced meters themselves, specialized communications
hardware and software (neighborhood, field, and wide area networks), the head end, meter data
management, and data analytics applications. These key components are depicted in the following
diagram and are briefly described below.
1FIGURE 3-1. DIAGRAM OF AMI SYSTEM COMPONENTS.

AMI Meters - AMI meters28 measure the incoming and outgoing29 flow of energy in configurable
intervals that range from 5 minutes to an hour. This energy use data is remotely transmitted to the
utility, and the meter can also receive and respond to incoming signals and commands. The many
other capabilities of AMI meters important in achieving customer benefits are discussed throughout
this Report.

28 The AMI electric meter replaces conventional or AMR meters depending on the application. AMI metering
for natural gas is accomplished by replacing the mechanical register or the AMR register on the existing natural
gas meter with a new digital, AMI module. The gas meter itself is not replaced.
29 AMI meters measure energy and demand and can also measure the amount of energy being delivered from
a distributed generation source onto the utility distribution system (known as ‘net metering”).
Exhibit A

18
Metering Communications Network - A specialized and secure communication system is required
to carry data and communications between the AMI meter and the utility. While there are various
options for providing this communication linkage, it often consists of three integrated systems
referred to as the Neighborhood Area Network, the Field Area Network and the Wide Area Network.
The Neighborhood Area Network, also known as the “collection system” or “meter mesh
network,” consists of the wireless communication occurring between the individual AMI meters.
Through this network of meter communication, information is transmitted from meter to meter
and in the process is aggregated by a collection device and transmitted to the Field Area
Network or the Wide Area Network, depending on the network design.30

The Field Area Network is a broadband wireless system that may support only one function,
such as advanced metering, but which may also support a full range of advanced grid-device
communications. Avista’s Field Area Network supports communication controls for substations
and transmission facilities, and distribution system sensing, monitoring, and remote operation.

The Wide Area Network, also referred to as the “back-haul,” is a separate computer or cellular
based communication network that connects seamlessly with the Field Area Network. The Wide
Area Network is responsible for transmitting communications and data collected by the Field
Area Network or the Neighborhood Area Network to the utility operations center. The design of
these three network systems is dependent on the characteristics of each utility’s system, the
geography of the service area, and the AMI metering solutions ultimately selected.
Meter Data Collection System (Head End System) - This system is composed of computer
hardware and software applications that control and coordinate the meter communication networks.
In addition to this function, the system aggregates the usage data from the AMI meters in the field
and routes this data to the Meter Data Management system and other specialized software
applications.31 The meter data collection system software is designed and provided by the
manufacturer of the advanced meters.
Meter Data Management System - This system includes computer hardware and software
applications that store, validate, edit, and analyze the interval consumption data, as well as
coordinate specified metering commands. Meter data information from this system is also routed to
other specialized software applications that perform a range of business functions such as customer
billing, use of specialized rate options such as time-of-use, or the web presentment of customer
usage data. The system also serves as the ‘system of record’ for meter consumption data, including
out-of-cycle billing and validation.
Data Analytics - This component of the AMI system includes applications that provide deeper
analysis of the advanced metering data. Meter data is compiled in these systems from both the Meter
Data Management System as well as the Meter Data Collection System and is used to derive

30 This system also carries information transmitted from the utility to the meter.
31 These applications perform a range of business functions such as outage management integration,
conservation voltage monitoring, and theft detection.
Exhibit A

19
customer benefits including operational awareness, theft detection, conservation voltage reduction,
outage management, or utility engineering studies, to name a few.
B. Overview of Project Deployment
Avista’s Idaho AMI project consists of the integration of four interrelated projects or phases
representing several of the systems described above. In delivering the Project, the Company will
employ a project management strategy referred to as an “agile” approach32 where the overlapping
phases are integrated by thoughtful planning and collaboration among multiple internal work groups
and outside vendors. Anticipated timing of initial implementation and duration for these projects is
presented in the Gantt chart in Figure 3-2, below.
2FIGURE 3-1. INITIAL DEPLOYMENT SCHEDULE BY MAJOR PROJECT FOR AVISTA’S IDAHO ADVANCED
METERING REFRESH PROJECT.

As noted previously in this Report, Avista expects deployment capital costs for the Idaho AMI system
to total $75.5 million on a net present value basis over the life of the project. Lifecycle operating

32 Iterative or “agile” project management breaks down complex projects into multiple iterations or incremental
steps toward the completion of a project. Agile approaches are frequently used in software development
projects to promote speed and adaptability since the benefit of iteration is that you can adjust as you go along
rather than following a linear path.
Exhibit A

20
expenses are estimated at $21.3 million (NPV).33 Both capital and expenses are shown on a nominal
(cash) basis for each major component of the AMI system for each year of the project lifecycle in
Table 3-1, below.
3TABLE 3-4. FORECASTED LIFECYCLE CAPITAL (CAP) AND EXPENSES (EXP), ON A NOMINAL BASIS IN
$MILLIONS, FOR AVISTA’S IDAHO AMI PROJECT FOR EACH YEAR OF THE PROJECT LIFECYCLE.

33 For purposes of this discussion, expected costs for the AMI deployment include the capital costs previously
discussed in our comparison of the AMR and AMI alternatives ($75.5M), however, the expense costs represent
the total or budgeted expenses ($21.3 M) rather than the initial estimates of expenses shown in the solution
comparison. Also note, as previously discussed, because the expense related to the unamortized value of
AMR metering equipment was applicable to both the AMR and AMI alternatives, that cost has not been
included in this discussion.
Year Meter Data
Management
Head End
Systems
Collector
Infrastructure
Meter
Deployment Totals
CAP EXP CAP EXP CAP EXP CAP EXP CAP EXP
2023 $0.10 $0.01 $- $- $0.20 $0.02 $1.20 $0.23 $1.50 $0.25
2024 $2.40 $0.04 $2.50 $0.02 $4.20 $0.03 $5.60 $0.44 $14.70 $0.53
2025 $0.20 $0.20 $1.60 $0.05 $5.00 $0.25 $18.20 $0.58 $25.00 $1.08
2026 $0.09 $0.07 $1.10 $0.30 $24.00 $0.73 $25.10 $1.18
2027 $0.10 $0.09 $0.60 $0.35 $24.20 $0.58 $24.80 $1.12
2028 $0.12 $0.03 $0.66 $0.25 $1.06
2029 $0.13 $0.03 $0.68 $0.26 $1.10
2030 $0.13 $0.03 $0.70 $0.27 $1.13
2031 $0.14 $0.03 $0.72 $0.28 $1.16
2032 $0.14 $0.03 $0.74 $0.29 $1.20
2033 $0.14 $0.03 $0.76 $0.29 $1.23
2034 $0.15 $0.04 $0.78 $0.30 $1.27
2035 $0.15 $0.04 $0.81 $0.31 $1.31
2036 $0.16 $0.04 $0.83 $0.32 $1.35
2037 $0.16 $0.04 $0.86 $0.33 $1.39
2038 $0.17 $0.04 $0.88 $0.34 $1.43
2039 $0.17 $0.04 $0.91 $0.35 $1.47
2040 $0.18 $0.04 $0.94 $0.36 $1.52
Exhibit A

21

C. Managing the Uncertainties of Major Technology Applications
A well-known characteristic of the installation of large technology applications is the degree of
uncertainty reflected in the early stages of project scoping and design. While the Idaho AMI project
involves work with major application systems, the key applications themselves have already been
installed and integrated with the Company’s other operating systems. This circumstance
substantially reduces the degree of variability expected in future project costs related to these
systems. For the Idaho AMI project, key technology application costs will cover the operation of an
expanded data collection system required for service in Idaho, the integration of this infrastructure
with the head end and meter data management systems, as well as the scaling of applications and
data bases to accommodate the expected volume, analysis and presentment of new metering data.
D. Avista’s Choice to Deploy Itron Meters in Idaho
Fundamentally, when a utility completes a competitive bidding process for AMI equipment, and
makes a final selection, it’s generally deciding on a platform that will serve metering functions for all
its operations, regardless of the ultimate timing of meter deployment.34 The reason has to do with
the integrated characteristics of the AMI system components, broadly illustrated above in Figure 3-
1. Avista selected Itron as the winning bidder in a very thorough and competitive process for AMI
metering hardware and proprietary software in September 2016. In doing so, the Company was
deciding the architecture that would govern how supporting AMI system hardware and software
(including applications developed by other vendors such as Oracle and Cisco) would be installed
and integrated. In this respect, all the components of the AMI system are integrated to seamlessly
work together in supporting a wide range of business requirements.
A decision to purchase meters from a vendor other than Itron for the Idaho AMI deployment would
have significant financial consequences for customers. Avista would have to purchase not only
different meters, but new proprietary operations software. This software would then have to be

34 An exception to this premise would be at the end of life for an entire metering system when the utility would
once again consider offerings from multiple vendors to replace the entire system.
2041 $0.18 $0.04 $0.96 $0.37 $1.56
2042 $0.19 $0.04 $0.99 $0.38 $1.61
2043 $0.19 $0.05 $1.02 $0.39 $1.66
2044 $0.20 $0.05 $1.05 $0.41 $1.71
2045 $0.05 $0.01 $0.27 $0.10 $0.44
Totals $2.70 $3.19 $4.10 $0.89 $11.10 $15.49 $73.20 $8.18 $91.10 $27.75
Exhibit A

22
configured35 and integrated36 with our existing hardware and software systems to accommodate a
new meter manufacturer. While configuring and integrating new hardware and software with existing
systems sounds simple enough in a narrative, it is a very labor-intensive and expensive process.
Using the Meter Data Management system as one example: cost of the software system purchased
from Oracle was $2.98 million37 and cost of the computer hardware for the system was $2.13 million.
The majority of costs for this system, however, were for custom configuration and integration, which
together totaled $26.26 million. As noted above, if the Company were to now purchase metering
equipment and software from a new vendor, a significant portion of the configuration and integration
work would have to be repeated – even if we continued to rely on the same meter data management
system we have today. In addition, Avista would have to maintain a new separate inventory of
metering hardware, provide new training to metering engineers and technicians, and new training
for software engineers and others who would have to support new proprietary metering software. It’s
simply not an option to change horses in the middle of a race, and it would have significant negative
financial consequences for our customers.
Because the Company will be purchasing new AMI meters38 from its existing provider, Itron, we will
be diligent to ensure we receive the best-possible pricing. Through our 2016 AMI contract with Itron,
the Company is intimately familiar with Itron’s pricing for meters, applications and technical support,
and that in-depth knowledge has been maintained through our continuous work with them. As
expected, this includes, among other services, ongoing updates to applications and firmware,
purchase of new meters for new customer services and replacements as required. The Company
will bring its contracting acumen to bear when we negotiate a new major contract with Itron for
purchase of large volumes of electric meters, natural gas meter modules, collection infrastructure
and other incremental support and services. Finally, the Company has many relationships with other
utilities in the industry, many of whom have installed (or are installing) Itron advanced metering
equipment. Avista will, to the extent appropriate, rely on information gathered from these sources to
validate pricing offered and negotiated with Itron.

35 Software systems are designed to have broad applicability to the needs of each enterprise and include the
flexibility to tailor the software to meet the specific data, data management, business processes, and
functionalities required by each business. Configuration is the process of programming the flexibility options
of the installed software to perform the specific functions required by the business.
36 Any substantial enterprise has multiple different business applications and databases that must all be
‘integrated’ to work seamlessly together in performing a wide range of business functions. These integrations
involve the development of custom software required to enable different applications to ‘talk to one another’ in
sharing information and jointly performing business functions. As an example of the complexity of these
processes, consider Avista’s customer service and work management system, installed in 2015, which had to
be configured and integrated with other systems to successfully perform over 3,500 individual business
requirements.
37 Cost of major applications is typically a small part of the total cost of installing new systems. This is because
the vendor’s cost of developing and updating these huge applications can be spread across a broad global
client base. Accordingly, the cost to each company is relatively small.
38 Avista is planning to install the Itron Open Way Riva meter, which is the same meter installed in our
Washington AMI system.
Exhibit A

23
E. Meter Data Management and Head End Systems
Both the Meter Data Management and Head End Systems are already installed and operational.
Both systems, however, will require additional hardware support and configuration and integration
work to support the transition to AMI metering in Idaho. The capital and expense costs shown above
in Table 3-1 provide for the needed investment and the expense of operations during the project
lifecycle.
F. Meter Deployment
Meter/Module Deployment The deployment phase will cover the physical installation of new
advanced meters and natural gas meter modules, replacing existing advanced meters for all Avista
customers in the State of Idaho.39 Deployment will include a careful inspection of the electric meter
bases and sockets, including the repair of any unsafe or damaged meter sockets identified in this
process. Because this project involves replacement of an advanced meter with a new advanced
meter, the Company is not planning to provide any ‘opt out’ metering alternatives for customers.
Customer Communications Avista’s priority will be to communicate appropriately with customers
as we prepare for the replacement of their existing advanced meters. In our initial outreach, we
expect to deliver a direct mail communication to customers sent before meter installation is slated to
occur in their neighborhood.40 In the next step, we’ll let customers know what to expect when the
replacement meter/module is installed at their home or business (such as a temporary loss of service
when the new electric meter is installed).
G. Collection Infrastructure
Avista will extend its AMI collector infrastructure system across its Idaho service territory, while
evaluating opportunities for limited deployment of alternative metering communications where that
makes financial sense. Installation of collection infrastructure will precede the first installation of AMI
meters. Installation of communications equipment will progress ahead of each phase of meter
deployment to ensure the metering system is operational upon meter installation.
H. Customer Data Privacy, Cyber Security and Disaster Recovery
Throughout the deployment and management of Avista’s advanced metering systems the Company
has continuously revised, improved and updated its capabilities for protecting the privacy of our
customers’ personal data. We have ensured our infrastructure and business operations are safe

39 The project will likely exclude remote areas of natural-gas-only service, where meter reading may be
performed by mobile driving routes. These decisions will be made based on the cost of upgrading services to
AMI compared with alternatives and the expected benefits.
40 Since Avista’s Idaho customers have long been served by AMR meters it is not customary for them to see
Avista personnel (like a meter reader appearing monthly) at their home or business.
Exhibit A

24
from cyber threats and taken steps to safeguard the integrity of our critical business operations
through disaster recovery planning.
(1) CUSTOMER DATA PRIVACY
Avista has long been committed to protecting our customers’ safety, security and privacy. We
recognized early in planning for our advanced metering systems that the increase in the volume and
flow of customer data would raise privacy concerns about what data would be collected, how it would
be used, and how it would be protected. To this end Avista engaged a consultant to perform a “gap
analysis” and create a roadmap for creating a more comprehensive privacy program. The privacy
program includes robust procedures for the collection, use and protection of customers’ personal
information, including any personally-identifying information. Avista has designated a Chief of
Privacy and Data Ethics, who is responsible for ensuring all the Company’s privacy policies comply
with all applicable laws and regulations, and for implementing legal and ethical training for
employees on their role in protecting customer privacy. The privacy program also includes a baseline
inventory to identify all personal information being collected and stored. This inventory will help
identify any areas that may require additional attention and to help establish processes for
responding to customers’ requests about their data.
(2) DATA GOVERNANCE
Avista has also developed a Data Governance Program to consolidate existing processes and work
functions and establish policies, procedures, standards and accountability necessary to create a
sustainable culture of data stewardship, ownership and compliance. As part of the data governance
program, a Data Governance Council was established to provide leadership and decision-making
on issues relating to data governance, such as requests to share data outside the Company. Data
sharing requests are reviewed and approved only with the cross-functional perspective of the leaders
on the Data Governance Council. Any requests to share customer information collected from
advanced meters will be reviewed by the Data Governance Council and any approvals documented
along with any necessary consents and data sharing agreements.
(3) SECURITY CONTROL
As part of implementing the Data Governance Program and privacy program policies, Avista has
implemented extensive security controls to ensure the integrity of its systems and to secure and
protect customers and customer data from cyber threats. Customer information that is gathered,
stored, and transmitted is maintained on secure systems with restricted access. All Company
employees and contractors acting on Avista’s behalf who have access to customer information are
required to comply with Avista’s privacy and security practices and policies.
(4) CYBER SECURITY PROTECTIONS
Avista’s cyber security practices are designed to ensure operational objectives are effectively
achieved, while ensuring the integrity of our data and systems is protected at every level from
possible unintentional incidents and the full range of potential cyber security threats. Because our
Exhibit A

25
advanced metering system can control the delivery of energy, among other key functions, Avista
recognized the need to protect these systems beyond requirements for typical back-office systems.
Ensuring adequate protections starts during the procurement phase where security is embedded in
the Request for Proposals (RFP) process and is scored alongside other business requirements. The
evaluation criteria include and leverage resources from NIST, NERC, DHS,41 and other applicable
security standards to help evaluate the security of the proposed vendor solutions. Additionally, after
a vendor is selected, Avista takes many of the same security elements from the RFP process and
turns them into contractual requirements. This establishes accountabilities for the vendor to deliver
on their stated commitments in the RFP process, both during and following project implementation.
Avista has also created a secure network architecture around the AMI head end systems. This
secure network was modeled after other energy delivery systems security models and leveraged
many of the same controls that are used to protect power systems. Lastly, we will continue to monitor
advancements in security safeguards through our participation in industry working groups and other
forums, ensuring security is effectively managed throughout the lifecycle of the advanced metering
system.
(5) DISASTER RECOVERY
Because the AMI head end systems control the primary communication of meter data from our
advanced meters in the field back to Avista, the project and Executive teams developed and
approved implementation of a disaster recovery plan to support this critical system. Essentially, the
plan addresses emergencies that could interrupt access to Avista’s primary data center and provides
the capability to recover and read meters for web presentment and billing. The required hardware,
software, data storage, network communications, and infrastructure, as well as recovery images,
were added to our disaster recovery systems in our San Jose data center. Avista now has an
updated restoration procedure, combined with daily backups, to ensure the integrity of our head end
system’s critical functions.

41 National Institute of Standards and Technology (NIST), North American Electric Reliability Corporation
(NERC), and Department of Homeland Security (DHS).
Exhibit A

26
Section 4 | Incremental Customer Benefits with
Quantified Financial Value
A. Overview
(1) Current Expectations for Incremental Financial Benefits
As described earlier in this Report, the cost of refreshing the Company’s Idaho AMR system with
AMI metering is less expensive than alternative AMR technology. Beyond this difference in cost, we
have identified incremental financial benefits that are achievable only with AMI, making this system
even more cost effective. Even though AMI is less expensive, Avista recognizes the importance of
ensuring we maximize the potential financial benefits of this system for our customers.
As a baseline, it’s important to note that the AMR system, itself, produces a substantial range of
direct and indirect financial benefits for customers. For the purpose of this discussion, we focus on
incremental financial benefits, those enabled by AMI metering that we are not able to capture with
our existing AMR system in Idaho (or with a likely replacement AMR system). In this discussion of
incremental benefits, Avista is only reporting the difference in financial benefits between AMR and
AMI for those areas of benefit where we have identified a difference. Major areas of incremental
financial benefit are presented below in Table 4-1.
1TABLE 4-2. FORECASTS OF ESTIMATED INCREMENTAL CUSTOMER BENEFITS FINANCIALLY QUANTIFIED
FOR THE COMPANY’S PLANNED ADVANCED METERING REFRESH PROJECT IN IDAHO.
For the complete tabulation of each individual area of benefit please see the master benefits listed
in Table 1-3 in Section 1 of this Report. A brief discussion of each area of incremental financial
benefit is presented below, and the benefits expected for each year of the project are provided in
Excel format in the companion “AMI Benefits Workbook,” provided by the Company upon request.
Major Area of Benefit Incremental Lifecycle Value (NPV)
Meter Reading $184,164
Remote Service Connectivity $4,113,948
Outage Management $17,472,148
Energy Efficiency $17,750,714
Energy Theft and Unbilled Usage $7,489,528
Billing Accuracy $1,503,428
Total $48,513,929
Exhibit A

27
B. Meter Reading
(1) Regular Meter Reads
As expected, when the Company installed AMR in Idaho, the need for manual meter reading was
nearly eliminated, providing substantial operational savings for customers. Expected incremental
financial benefits to be provided by AMI are based on eliminating the labor and vehicle expenses
required for the mobile van currently used for some metering routes in Idaho, recognizing the fact
that some mobile reads will be retained for certain natural-gas only areas that simply are too
expensive to be converted to a full AMI solution. Table 4-2, below, lists the net present value of this
incremental benefit over the project lifecycle.
3TABLE 4-2. NET PRESENT VALUE OF INCREMENTAL FINANCIAL BENEFITS ESTIMATED FOR
IMPROVEMENTS IN METER READING FOR AVISTA’S IDAHO ADVANCED METERING REFRESH PROJECT.
Meter Reading
Area of Benefit Incremental Lifecycle Value (NPV)
Regular Meter Reads $184,164
Total $184,164

C. Remote Service Connectivity
The remote service switch is a feature of the AMI meter that allows it to be remotely disconnected
and reconnected, avoiding what otherwise requires a field visit by an employee to the physical
service location. In addition to reducing operating costs for personnel and vehicles, the process of
reconnecting service for customers, using advanced metering, is obviously much more rapid than
with physical service calls (especially after hours).
(1) Account Open / Close / Transfer
The remote service switch can be used to disconnect service when a customer moves from a
premises without having to send a technician to perform a manual disconnect. Likewise, when a new
customer moves into the premises, service can be remotely restored instead of sending an employee
to perform a manual reconnect. The lifecycle savings of $1,502,370, shown below in Table 4-3,
represents the avoided costs for Avista field personnel and transportation no longer required with
remote service connectivity.
(2) Credit Collections/Connections
Similar to the process of Account Open / Close / and Transfer, the remote service capability provided
by AMI allows the Company to disconnect and reconnect service without having to dispatch field
personnel to the premises. The lifecycle savings of $2,350,249, shown below in Table 4-3,
Exhibit A

28
represents the avoided costs for Avista field personnel and transportation no longer required to
perform these functions.
4TABLE 4-3. NET PRESENT VALUE OF INCREMENTAL FINANCIAL BENEFITS ESTIMATED FOR REMOTE
SERVICE CONNECTIVITY FOR AVISTA’S IDAHO ADVANCED METERING REFRESH PROJECT.
Remote Service Connectivity
Area of Benefit Incremental Lifecycle Value (NPV)
Account Open/Close/Transfer $1,502,370
Credit Collections/Connections $2,350,249
After Hours Fees $261,329
Total $4,113,948

(3) After Hours Fees
With the automated functions described above, eliminating the need to send personnel to the
premises to restore service, customers will no longer be required to pay a tariffed ‘after hours fee’
when their service is restored after normal business hours. The lifecycle value of this benefit for
customers is $261,329 as shown above in Table 4-3.
D. Customer Benefits from Improved Outage Management
(1) The High Cost of Service Outages
It is a well-established fact that interruptions in service cost electric customers money. The degree
of direct financial losses they experience is related to many factors, some of which include the time
of day or night and season of the outage, its duration, whether the customer received advanced
notice, whether they have a backup generator, and importantly, the class of customer impacted
(residential, commercial, industrial, etc.). A key determinant of the financial loss customers
experience is the length of time (outage duration) they are without service. To estimate the electric
outage costs experienced by our customers, Avista uses an industry standard model known as the
Interruption Cost Estimator.42 The model was developed by Lawrence Berkeley National Laboratory
to estimate the cost to customers resulting from electric outages of varying types, times and
durations, among other factors. Among other metrics, the interruption cost estimator calculates a
weighted average hourly cost for all customers for one hour of outage time. Multiplying this value by
the total number of outage hours experienced by customers on our system yields the total cost of all
outages for that year.

42 http://www.icecalculator.com/ice/
Exhibit A

29
(2) The Role of AMI in Outage Management
AMI meters are constantly sensing meter function and communicating with the utility’s data systems
to alert any changes of status at the meter. This includes the knowledge in near real-time of whether
power is being supplied to an individual customer’s meter. When this service is disrupted, the
advanced meter sends an alarm indicating an outage at the customer’s premises. Incremental
financial benefits estimated for this Report are based in part on our use of outage alarms to provide
earlier notice of an outage event,43 and as a result, to respond to outages more quickly on average
to reduce outage duration. In addition to the benefit of earlier notification, Avista has developed
specialized outage management tools and processes, enabled by AMI metering. These tools are
improving our outage restoration processes, which results in additional reduced outage duration and
avoided financial losses for our customers.
(3) Reduced Outage Duration from Earlier Outage Notification
In our experience with AMI, we have documented the average difference in time between the
immediate outage notification provided by AMI meter alarms and the notification we traditionally
received when our customers call in to report the event. This “earlier notification” allows us to begin
the process sooner of analyzing the outage, creating an incident report and dispatching service
crews. The ultimate impact is to reduce the duration of outages that qualify for this earlier notification,
as enabled by AMI, and consequently, to reduce the direct cost impact to our customers.
In our use of AMI in Washington, we have documented an average earlier notification time for
qualifying outages44 of 24.4 minutes, or an average improvement, expressed as a percentage for all
outages of 4.25 minutes. Using the Interruption Cost Estimator we have valued the annual financial
benefit to customers at $1,692,999. The lifecycle NPV financial benefits of $14,747,247 are shown
below in Table 4-4. While the Company also has experience with AMI enabled outage restoration,
demonstrating that the process time following notification (outage analysis and incident report
creation) has also been reduced, we are not assigning a quantified financial value for that benefit at
this time. Avista believes it makes more sense to revisit this benefit once the Company’s new
Advanced Distribution Management System (ADMS) is installed and operational, likely in year 2026.
5TABLE 4-4. NET PRESENT VALUE OF INCREMENTAL FINANCIAL BENEFITS FOR CUSTOMER SAVINGS
ASSOCIATED WITH MORE EFFICIENT MANAGEMENT OF ELECTRIC SYSTEM OUTAGES AS ENABLED BY
AVISTA’S PLANNED DEPLOYMENT OF AMI IN IDAHO.

Outage Management
Area of Benefit Incremental Lifecycle Value (NPV)

43 Without the AMI system, the Company is typically notified of a customer outage only when a customer
contacts Avista to report their loss of service.
44 Qualifying outages are only those events where AMI has been validated as providing earlier notification.
Exhibit A

30
Earlier Outage Notification $14,747,247
Reduced Customer Calls $597,376
Avoided Single Lights Out $1,599,365
Reduced Major Storm Costs $528,161
Total $17,472,148

(4) Reduced Customer Calls
As described above, Avista now has the capability to quickly see a loss of power to the customer’s
service. Though Avista will not discourage its customers with AMI metering from contacting the
Company when they lose service, the Company is using the AMI system to enable new processes
that make it less likely that customers will need to speak with a customer service representative to
report their outage. In addition to having fewer inbound customer calls, the average duration of calls
received will be reduced. This reduction in duration results from the customer service representative
being automatically informed by the system of that customer’s outage as the call is being received,
and the representative not having to collect information from the customer or to use that information
to complete an outage incident Report. In addition to reducing call center staffing costs, the
automated notification of the outage will help improve the customer’s experience and satisfaction.
As shown above in Table 4-4, the Company’s initial estimate of the financial savings for customers
over the life of the project has a net present value of $597,376.
(5) Avoided Single Lights Out
Without AMI, when an outage event appears to be a single customer, Avista tries to help the
customer determine whether the outage is the result of a loss of service to the meter (Avista’s issue)
or a problem with the service panel (or any other issue on the customer’s side of the meter). When
the cause appears to be an issue with Avista’s service, or more often, is simply undeterminable, a
crew is dispatched to the customer’s service to investigate, and if need be, resolve the problem.
Those cases, where the loss of power is ultimately determined to result from electrical problems on
the customer’s side of the meter, are known as “false positives.” With AMI, we now query or “ping”
the meter when the customer calls to determine whether there is power to the meter, substantially
reducing the likelihood of dispatching restoration personnel in response to a false positive. Reducing
the number of false positives reduces time spent on the phones, entering data, and dispatching
service personnel. It also avoids a poor customer experience and allows customers to more quickly
schedule an electrician to repair the problem with their wiring.45 As shown above in Table 4-4, the
Company’s estimate of the incremental financial savings for customers over the life of the project
achieves a net present value of $1,599,365.

45 There is an additional financial benefit that was not included in this cost-benefit analysis. This results from
the efficiency savings realized when crews and servicemen avoid having to stop work on their current
assignment, which requires breakdown and setup, as well as other transition activities, to respond to a false
positive.
Exhibit A

31
(6) Reduced Restoration Expenses for Major Storm Events
Avista has experienced how AMI metering provides better visibility of the many isolated outages
during very large (storm) outage events,46 allowing us to restore outages more efficiently and quickly.
In our review of utility literature on this capability of AMI, we noted results reported by the Electric
Power Board47 showing a 40% reduction in outage duration per customer,48 and a Florida Power
and Light Company report showing a 21% improvement. At present, Avista estimates a more
conservative savings of a 10% reduction in average restoration time for only large outage events.
Although these efficiencies reduce the overall customer outage duration (hours) for large events, we
have not included any financial value here for avoided customer losses (as described earlier in this
section). These estimated financial benefits are based solely on an expected reduction in labor
hours, lodging, meals and vehicle and equipment operating costs. Obviously, there would be no
difference in the amount of damaged infrastructure that has to be repaired or replaced. For a 10%
reduction in restoration time for very large outages, the Company’s estimate of the financial savings
for customers over the life of the project has a net present value of $528,161, as shown above in
Table 4-4.
E. Energy Efficiency Enabled by Advanced Metering
In our experience with AMI metering, the Company has estimated incremental financial value
expected for several different areas of customer benefit including conservation voltage reduction
(CVR), customer actions to improve energy efficiency based on the availability of interval energy use
data and accompanying analytical tools, and behavioral energy efficiency programs, which rely in
part on the load disaggregation, opportunity identification and measurement and verification. We
also mention pending energy pricing strategies as a conservation use case, though we do not include
any estimated financial benefits in this financial analysis.
(1) Conservation Voltage Reduction
The electric distribution system is designed to operate within a voltage range that, historically, is
manually set for each neighborhood “feeder” line at a voltage regulator in the substation. The types
and the magnitude of electrical loads on a feeder (e.g., electric motors vs. lighting) are constantly in
flux, causing variation throughout the day in the actual voltage level along the feeder. Since Avista
is required to maintain at least a minimum line voltage at all times along on feeder, the voltage range
adjusted at the substation is set well above the minimum to ensure there is an adequate buffer to
account for the variation in loads and the natural drop in voltage along the length of the feeder. Since
more electrical energy is required to support higher line voltages, providing this buffer has a cost
that is directly proportional to the size of the buffer. Having actual voltage levels from AMI meters at
each customer’s service has allowed the Company, in some cases, to reduce the size of this buffer
while still meeting the minimum voltage level at each customer’s service. As noted above, reducing

46 Very large outage events are associated with major storms in our service area, including those caused by
high winds, excessive ice and heavy snowfall.
47 Headquartered in Chattanooga, Tennessee.
48 As measured by the utility standard index “System Average Interruption Duration Index” or (SAIDI).
Exhibit A

32
this buffer allows us to spend less on power supply costs and to pass these savings on to customers.
Based on the estimated reductions in feeder level voltage we expect to achieve on electric feeders
in Idaho, Avista estimates incremental financial savings for customers over the life of the project of
$5,928,422, as shown below in Table 4-5.
6TABLE 4-5. NET PRESENT VALUE OF INCREMENTAL FINANCIAL BENEFITS ESTIMATED FOR ENERGY
EFFICIENCY SAVINGS ENABLED BY AVISTA’S PLANNED DEPLOYMENT OF AMI IN IDAHO.
AMI Enabled Energy Efficiency
Area of Benefit Incremental Lifecycle Value (NPV)
Conservation Voltage Reduction $5,928,422
Customer Energy Efficiency $1,635,926
Behavioral Energy Efficiency $10,186,366
Total $17,750,714
(2) Customer Managed Energy Efficiency
(a) Initial Estimate of Project Benefits
When customers have access to detailed and timely energy-use data, coupled with utility-provided
information, education and analytical tools for energy conservation, they have much greater ability
to undertake structural and behavioral changes to reduce their energy use and costs. In driving
greater value from this aspect of AMI metering, Avista has developed energy management tools to
help ensure customers can make best use of their energy-use data to achieve hard conservation
savings. From its experience with AMI, Avista has estimated the incremental lifecycle value of
customer-enabled energy savings to be $1,635,926 on a NPV basis, as shown above in Table 4-5.
Some of the enabling tools supporting these savings are briefly described below.
• Bill-to-Date: The bill-to-date application enables customers to understand their energy
use to date and the accompanying bill amount for that usage.
• Bill Trending: The bill trending tool informs customers of the estimated amount of their
next bill based on their usage to date and their historical pattern of use. It also compares
the current billing period with that of the same period in the prior year. In addition to overall
usage information, the tool provides customers easy access to their interval energy data
Exhibit A

33
and lists actions they can take to reduce
their energy bills. It also links customers
to other energy conservation tools on the
site. A screenshot of the bill trending tool
is pictured at right.
• Budget Alerts: Avista has developed
another tool that allows customers to set
a budget alert threshold and then receive
a push alert in the event the trending tool
predicts they will receive a larger bill than
their budget amount. The application
provides customers easy access to their
interval energy data, points them to other
energy conservation tools on the site, and
lists steps they can take to reduce their
energy consumption and lower the
amount of their bill.
(3) Behavioral Feedback Energy Efficiency Programs
In another conservation step, Avista has launched new initiatives focused on achieving greater
conservation savings for customers through personal behavioral feedback programs. Avista’s
advanced metering system is the foundation for these behavioral programs, which employ load
disaggregation analyses to identify the types of loads being served and the relative opportunity for
customers to reduce energy consumption and save money. Analyzing loads in this manner provides
the opportunity to tailor energy
efficiency programs to the type
of use presenting the greatest
savings opportunity. It also
supports the identification of
customers who may have the
greatest likelihood of taking
actions and the greatest
opportunity to save money by
doing so. An example load
disaggregation report from
Avista’s system is shown in the
illustration at right. Further,
advanced metering provides
the data and analytics for the
measurement and verification
of conservation savings. Our
first behavioral program, titled
Exhibit A

34
“Always On”49 was launched in late 2021 to show customers what their always-on devices are
costing them each month, and to share information and actions they can take to reduce these
‘parasitic’ loads. Additional targeted behavioral campaigns are planned for rollout in subsequent
years with the expected lifecycle benefit for behavioral conservation savings, enabled by AMI,
estimated to be $10,186,366, as shown above in Table 4-5.
F. Energy Theft and Unbilled Usage
(1) Theft and Diversion
Tampering or theft diversion occurs when a customer purposefully alters the meter or service
entrance enabling power to be used at the premises without being registered on the meter. AMI
meters are equipped with tamper alarms that alert the utility in the event a person attempts to
circumvent the metering of energy. Initially, Avista assumed a rate of theft of service based on the
lowest value presented in a range of individual utility studies we reviewed (0.46% of revenue). Since
that time, we have reduced our estimate of the incremental financial benefit for deployment of AMI
to 0.10% of overall revenue. Accordingly, as shown below in Table 4-6, the currently-estimated
incremental benefit is expected to have a lifecycle value of $1,263,447.50
7TABLE 4-6. NET PRESENT VALUE OF INCREMENTAL FINANCIAL BENEFITS ESTIMATED FOR
IMPROVEMENTS IN ENERGY THEFT AND UNBILLED USAGE ENABLED BY AVISTA’S DEPLOYMENT OF AMI
ADVANCED METERING IN IDAHO.
Energy Theft and Unbilled Usage
Area of Benefit Incremental Lifecycle Value (NPV)
Theft and Diversion $1,263,447
Stopped Meters $477,448
Equipment Operation & Validation $5,748,633
Total $7,489,528
(2) Stopped Meters
Without AMI metering, when a meter appears to have stopped recording energy use, it is flagged for
investigation by the Company’s meter technicians. Unfortunately, the great majority of the time,

49 Always On loads represent the energy consumed by devices, such as computers, appliances, internet
devices, charging cords, and many others that are using electricity whether or not the device is currently being
used.
50 As part of the Data Analytics project, Avista has created a new algorithm that is run each day on electric
meters to help detect potential theft. This new tool is integrated with the meter data management system and
evaluates low-side voltage levels on internally disconnected meters to ensure there is no voltage on the
customer side of the meter. Because the internally disconnected meter can still measure service level voltage,
it can be used to identify potential problems with a meter or the occurrence of some modes of theft (in addition
to meter alarms that signal when a meter has been removed from its meter base/socket).
Exhibit A

35
meters are reported as potentially stopped there is simply no use at the premises and the meter is
working properly. This instance is known as a “false positive.” With AMI, the meter automatically
alarms when it fails to properly record energy use, and in addition, the meter can be pinged to
determine whether it is powered and functioning correctly. Reducing the number of field visits to
investigate false positives with AMI metering represents the core savings associated with stopped
meters. As shown above in Table 4-6, the Company’s estimate of the incremental financial savings
for customers over the life of the project has a net present value of $477,448.
(3) Equipment and Operational Validation
Unlike single phase residential electric service, commercial customers (and larger) often require
what is referred to as three phase service. In addition to being served from all three phases on the
feeder, metering for these heavier loads can require additional equipment including use of Current
Transformers to reduce the current to safer and more manageable levels and measure the amount
of electricity used. Over time, these metering installations may be subject to what is referred to as
“loss of phase,” a condition where one of the three phases becomes disconnected from the metering
at the service. This loss of phase may result from a failure in the wiring or equipment, a fault on the
system, or in less frequent instances, issues with the current transformers. When this occurs, it
results in a portion of the electric use not being registered on the meter. This loss of meter registration
(unmetered usage) may range from a small percentage of the electricity used up to 67% or more!
This lack of registration results in a loss in billed revenue ultimately paid for by other customers, and
results in a very poor customer experience when discovered (because their bill increases by the
percentage of registration that wasn’t captured by the meter). Without AMI advanced metering,
detecting a loss of phase is very difficult and often the only way these issues are discovered is during
a manual inspection of the service, which period between inspections can be 10 years or longer.
Using the alarm capabilities of AMI metering we can detect loss of phase and voltage irregularities
and report these events as they happen in real time. Field personnel are now dispatched to inspect
and remediate these issues in a matter of days. Based on the rate of issues already detected and
repaired, we have estimated a lifecycle incremental financial value of $5,748,633 for the rapid
detection of and avoidance of the impact of loss of phase, as shown above in Table 4-6.
G. Billing Accuracy
(1) Bill Inquiries
Without AMI metering, combined with load disaggregation and other tools, customer service
representatives must respond to customer bill inquires with only a limited ability to obtain a current
reading of the customer’s metered usage, to have the customer’s historical usage normalized to the
month, or to analyze any bill trends or usage anomalies. The steps required to provide even a
rudimentary answer to a customer’s billing question involves estimation, assumption, and a
substantial amount of a customer service representative or billing analyst’s time to assemble. Based
on time required for the manual processes to resolve each of these billing inquiries, which are
reduced and avoided with AMI metering, the estimated incremental financial benefit for customers
Exhibit A

36
over the life of the project is estimated to have a net present value of $1,090,229, as shown below
in Table 4-7.
8TABLE 4-7. NET PRESENT VALUE OF THE INCREMENTAL FINANCIAL BENEFITS ESTIMATED FOR
IMPROVEMENTS IN BILLING ACCURACY TO BE ENABLED BY AMI ADVANCED METERING IN IDAHO.
Billing Accuracy
Area of Benefit Incremental Lifecycle Value (NPV)
Bill Inquiries $1,090,229
Billing Analysis $413,198
Total $1,503,428
(2) Billing Analysis
Without AMI, Avista employs billing analysts to review customer billing data each month to look for
anomalies that might suggest a problem with an electric or natural gas meter. Typical billing
situations flagged by analysts include abnormally high or low monthly bills, referred to as
‘exceptions.’ Each exception is flagged and evaluated to determine whether to send a meter
technician to test the subject meter. Avista’s meter data management system is equipped with a
meter health monitoring application that alerts our meter shop to any potential issues with the meter.
The application uses a daily meter read, combined with other meter health indicators, to identify
potential meter anomalies. As expected, this tool has substantially reduced the number of meter
exceptions that need to be evaluated by an analyst or inspected by a meter technician. The
estimated reduction in effort associated with billing analysis is estimated to have an incremental
financial value for Idaho customers over the life of the project of $413,198, as shown above in Table
4-7.

Exhibit A

37
Section 5 | Conclusion
As briefly noted above, Avista has experienced a rapid transformation in our business as we focus
increasingly on the needs of the individual customer, and on the local distribution grid where they
receive service. We understand the long-term success of our business is founded on identifying and
meeting our customers’ evolving energy service expectations and we’re working now to not only
embrace this change but to incorporate these new realities into a more customer-centric, technology-
enabled business model. AMI metering is fundamental to addressing these challenges and
opportunities. It is not surprising, then, that AMI has not only become the metering standard for the
industry but has already been approved by the Commission for customers served by Idaho’s two
other regulated electric utilities, Rocky Mountain Power and the Idaho Power Company. The planned
timing of Avista’s refresh project is also an important consideration. Not only will the new AMI
platform allow the Company to quickly improve the level of service we provide our Idaho customers,
but a delay in implementation will only make the project more expensive.51

It is fortuitous that the AMI platform is significantly more cost effective for customers today than the
less capable AMR alternative. As illustrated in Figure 1-1, reprinted just above, Avista’s decision to
move forward with deployment of AMI in Idaho is a prudent choice compared with the alternative of
replacing our end-of-life AMR system with new AMR technology. The value of AMI is superior in
every respect, where this technology: 1) provides the platform and capabilities to meet the
Company’s strategic business objectives; 2) has a lower combined cost52 of deployment and

51 As noted earlier in the discussion of recovery of the value of unamortized AMR assets.
52 Combined cost is the total of capital and incremental expenses.
Exhibit A

38
operation than AMR; 3) will deliver greater financial benefits for customers in the immediate and long
term; 4) delivers a wider range of other customer services and benefits not currently quantified
financially, and 5) provides greater opportunity for delivering new customer benefits and value in the
future. Avista believes the prudence of our investment in AMI should be judged on the merits of all
customer benefits provided by the system (both quantified and the unquantified benefits described
below) even though our current analysis clearly demonstrates the cost-effective value for our Idaho
customers based solely on project costs and existing incremental financial benefits.

Exhibit A

39
Section 6 | Summary of Customer Benefits Currently
Not Quantified
A. All Benefits Are Important to Our Customers
As described in the prior section, most of the incremental benefits identified in the Company’s
advanced metering system are quantified financially for inclusion in the project cost-benefit analysis.
Additional benefits that have value to our customers but are often difficult to quantify should be
properly included in the consideration of the prudence of our investment. As an example, providing
customers a range of convenient payment options is often neither cost-effective nor financially
valued. Still, it is the right thing to do for customers and the cost to provide these benefits is viewed
as reasonable. The same is true for many of the customer benefits provided by advanced metering,
such as providing them with information and tools they appreciate or improving their overall
experience and satisfaction with their service. Avista is highlighting these areas of benefit, showing
how they have shifted not only how Avista performs its work, but also the Company’s relationship
with its customers. As noted in Section 2 of this Report, the advanced metering platform is allowing
Avista to build a partnership with customers as they share greater influence and participation in our
overall business.
B. Improving Customer Convenience, Experience, and
Satisfaction with their Service
In the Company’s recent experience with advanced metering, new benefits that were once
impractical or impossible to achieve are now being implemented through the new capabilities
provided by AMI. Following is a brief description of benefits now being delivered to our customers.
(1) High and Low Service Voltage
AMI meters provide interval voltage data at each customers’ service and alarms indicating whether
the voltage levels supplied to a customer are too high or too low. Historically, these service issues
would go undetected unless reported to Avista by the customer as a potential power quality issue or
were observed by field personnel performing unrelated service work. Access to interval data and
meter alarms now allows the Company to proactively address issues when voltage is outside defined
service standards.
(2) Neutral Connection
Three-phase meters typically include a neutral connection53 as part of the service. Avista has
experienced many instances where irregular voltage fluctuations and alarms, as enabled by AMI,
helped identify a problem with this neutral connection. In some cases, the neutral connection could

53 Neutral wire is the return conductor of a circuit. In building wiring systems, the neutral wire is connected to
earth ground at only one point.
Exhibit A

40
be tightened, while in others, installation of a new neutral wire was necessary. In some cases, the
alarm helped us identify a wiring problem on the customer’s side of the meter. Had these issues
continued to go undetected, voltage fluctuations could have potentially damaged the customer’s
equipment. Like high and low voltage issues, the Company is now equipped to proactively detect
and resolve issues with the neutral connection instead of waiting for the customer to experience
serious equipment problems before calling us.
(3) Intermittent or Partial Power
The typical residential or small commercial service is served from our transformer by three
conductors (wires). Two of the wires, each referred to as one ‘leg’ of the service, each supply
electricity at 120 volts (V), and the third wire is referred to as the neutral. In the customers’ electric
panel, some circuits are served by one of the legs at 120V, while other circuits combine both 120V
legs together to serve loads at 240V. Heavier loads like electric ranges and water heaters are usually
served at 240V, while 120V is used for light appliances, lighting and plug load. In the course of
service, instances can arise where one of the legs of service can lose connection with the
transformer, referred to as a “partial power.” This results in the loss of 240V service (and some of
the 120V circuits) inside the home or business, which is often not immediately discernable to the
customer. This is especially the case if the problem connection is intermittent in nature. It’s also not
common for the customer to think of calling Avista because they still have electric service, even
though their 240V appliances will not function properly, or not at all. Avista can now proactively
identify these issues using alarms from its AMI meters and quickly repair them for the customer.
(4) High Bill Complaints
As described above, historically, when a customer had a high bill complaint our customer service
representative had only limited tools to help identify the cause. Today, our customer service
representatives have access to AMI meter interval data and load disaggregation tools, which gives
them much greater information and analysis for resolving high bill complaints during the initial
customer call. The speedy resolution of the customers’ concern provides a real enhancement to their
experience and satisfaction with their service. It also helps avoid expensive field testing of the
customer’s meter, as discussed elsewhere in the Report.
(5) Meter-Type Errors
Providing a range of different services to our multiple classes of customers requires an array of types
of metering equipment and applications deployed to our several hundred thousand customers. While
mistakes in these classifications are rare, the Company occasionally finds instances of work process
errors that result, for example, in the wrong class of electric meter being installed for a customer.
These instances can result in a range of issues for both the customer and the Company, which
worsen over time between the installation and detection of the problem. Understandably, these
situations often result in a very poor experience for the customer. Alarms from the advanced
metering system have already proven helpful in catching these types of issues shortly after
installation, resulting in the avoidance of what had been in the past a negative experience for our
customers.
Exhibit A

41
(6) Defective Meters
As briefly described above, during large-scale meter deployments, it is common to have a small
percentage, typically much less than 1%, of meters fail, a common asset phenomenon. AMI meter
alarms have proven helpful in these instances by alerting Avista of a meter defect shortly after
installation, resulting in little to no impact to the customer. Historically, we had to experience a
complete failure of the meter in order to identify a problem, which often resulted in the need to back-
bill customers for unmetered usage. Again, this capability allows us to quickly identify and resolve a
problem and to avoid a potentially very negative experience for our customers.
(7) Customer Access to Interval Energy Usage Data
Customers can use the Avista web portal to view and analyze their energy use to learn more about
how they use energy and partner with Avista in energy conservation. The availability of this data
provides customers information and value and improves their experience and satisfaction even if
they are not immediately inclined to take specific actions to reduce their energy use. The availability
of this information is also expected to reduce the number of customer calls to Avista based on billing
concerns, though we have not attempted to quantify any financial benefits at present.
(8) Load Disaggregation
Building on customers’ access to interval energy use data, we have entered the age where we can
show individual customers what is driving the energy-use patterns at their home or business. This
new insight, enabled by our load disaggregation tool, uses data from our AMI metering system. While
this tool supports our achievement of financial benefits through behavioral energy efficiency and
billing analysis, it also provides our customers a more robust understanding and effective opportunity
to better manage their energy use (compared with the availability of interval usage data alone). This
capability improves the service experience and satisfaction of our customers, above and beyond the
value of any quantified financial benefits.
(9) Energy Alerts Selected by Customer
As described above, the Company has already developed several applications that allow customers
to request alerts for services, including bill amount thresholds, trending bill size, and use comparison.
Customers can select from a range of tools and alerts to customize the combinations of notifications
they can receive to help them better manage their energy use.
(10) AMI Metering Improves Customer Experience and Satisfaction
Our customers have experienced more of the direct benefits of AMI as a result of proactive actions
taken by the Company based on information received from our AMI metering system. As one
example, below is a customer email explaining how Avista used the meter alarm to detect their
service outage and to dispatch a crew and have it repaired before the customer was even aware of
the event.
Exhibit A

42

C. Improving Customer and Utility Employee Safety
Avista is using its AMI metering system as initially planned, and in new innovative ways to reduce
risk to our customers and our employees, and in some instances to reduce the costs of ongoing
operations. Following are several examples of these improvements.
(1) Customer Meter Base/Socket Repair
In Avista’s AMI deployment, a consistent theme we heard from utilities and their meter deployment
contractors was the need to develop a plan for assessing and handling repairs required on customer
meter bases and sockets.54 While our repair of meter bases and sockets provides our customers a
direct financial benefit, there is also a reduction in risk for the customer and the Company that we
have not quantified financially for this analysis. This reduction in risk provides our customers and
employees a direct safety benefit as well as avoiding the inconvenience of a service outage resulting
from the failure of equipment.
(2) Backfeed
Except for net metering applications, electric current should always be moving in one direction, from
our system to the customer’s service point. In certain instances, however, including service outages
when a customer may improperly connect a backup generator to keep their lights on, the electric
current may be moving from their service onto the grid. This situation is known as “backfeeding” and
it can pose a significant safety hazard to field personnel working on the distribution system.
Advanced meters are equipped to send “reverse energy” alarms, that if not associated with a
distributed energy resource, allows us to investigate the cause of the potential backfeed. In a recent
example, a meter technician determined that a customer had an uninterruptible power supply
backfeeding onto Avista’s system. He contacted the customer and explained the hazard to utility

54 The meter socket is the point of connection for the electric meter, which is an integrated part of the meter
base. It is the meter base that is attached to the customers’ residence or business.
- Satisfied Customer
Exhibit A

43
personnel, and the customer was able to reconfigure the power supply to function correctly.
Ultimately, the Company will configure alarms to operate during service outages to identify when
customers’ generators could be backfeeding onto the distribution system.
(3) Miswired Service on Customers’ Side of Meter
Recently, a meter technician was dispatched to investigate a Report of backfeed on a line, and he
was able to trace the issue to a wiring malfunction on the customer’s side of the meter that was
backfeeding to the load side of the meter. During this investigation, the meter technician discovered
a secondary issue creating another safety hazard. As a result, the customer was able to have the
wiring corrected and the safety hazard removed from their home.
(4) Unregulated Solar Generation Systems
Solar generation system installations are becoming more prevalent across Avista’s service territory,
and we have established a program for customers to register their solar installations with the
Company. This process provides for an engineering review of the system to ensure a safe and proper
installation. When systems are installed correctly, the solar panel inverter is specifically designed
not to backfeed onto the grid in an outage scenario. However, if customers do not follow this process,
there is potential for an incorrect installation to allow the solar system to backfeed onto the system.
In a handful of instances, reverse energy alarms from our smart meters have helped identify solar
installations not properly registered. Meter technicians have been dispatched to these locations to
consult with customers and educate them on the proper steps to ensure a safe installation.
(5) High Current
Services to Avista’s customers are designed to accommodate the load anticipated at the time of the
initial installation. Over time, customers many add equipment and loads, and at times to the point
where the capacity of their installed service has been exceeded. Ideally, the customer will notify
Avista of substantial change in their installed load, and the service can be evaluated and upgraded,
if needed, to ensure they have sufficient capacity. But much more often, customers add load
incrementally and never think of calling Avista. Advanced meter alarms can now detect when a
customer’s load has exceeded the capacity of their service, and we have already used these alarms
to identify the need to revamp such services. Having the visibility to detect these instances provides
an important safety measure for the customer and the system and promotes improved reliability for
neighboring customers as well.
(6) Potential Wire Down
When a broken or downed primary conductor (wire on the feeder line) contacts a partially insulated
object like a tree branch or highly resistive soil, there may not be enough current in the fault to
operate the protective devices on the distribution system. This can be extremely dangerous because
the energized primary conductor may be close to, or on the ground, and remain energized. In these
instances, the utility has no way of detecting the problem until either someone observes the problem
and calls it in or there is a complete fault and a resulting service outage. Avista’s early experience
Exhibit A

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with its advanced metering system shows that voltage alarms from advanced meters can be useful
in detecting these issues. Though infrequent, early detection and repair of these issues significantly
reduces the potential of this safety hazard.
D. Operational Awareness of System Health
The following examples show how Avista’s advanced metering system is providing and will continue
to provide even greater benefits for customers related to field operations efficiency, distribution
system management, design services and engineering, and billing.
(1) Detecting Equipment Problems
Advanced meters can now be used to supplement voltage monitoring, not just at a customer’s
service point, but across the entire distribution system. While most voltage issues are related to a
specific location, as described above, there are instances where a voltage issue on the system
impacts multiple customers. We have already used this capability to identify and remedy system
issues such as a problem voltage regulator. We have also detected faulty fuses causing a regulator
not to function properly, as well as configuration settings in voltage regulators, corrected by adjusting
the regulator. Historically, because there was no way to sense and monitor system or service-level
voltages, these issues would not have been detected until they resulted in the failure of Company or
customer equipment.
(2) Overloaded Transformers
Like the instance above where a single customer’s load had increased to the point where the
capacity of their service equipment has been exceeded, it’s also the case that the aggregate load of
multiple customers on a single transformer can sometimes exceed its capacity. Interval data from
AMI metering is used to aggregate the load from all meters served by an individual transformer and
alarms monitor these loads to identify transformers potentially overloaded. Low service voltage,
reduced service life, and transformer failure, resulting in an outage for multiple customers, can result
from overloading. Avista has already used these new tools to identify several overloaded
transformers, which were proactively replaced with a unit capable of serving the existing load. As we
gain more experience with this monitoring and alarming feature, we will be able to better define
thresholds used to systematically monitor and signal the need for a transformer changes.
(3) System Visibility for Employees in the Field
Field workers now have access to information in the field that was not possible before advanced
metering. When a line worker responds to a power outage the outage/restoration status for the
service is accessible from their mobile computer. Avista has already quantified the value of using
AMI data to improve outage response. Beyond outages, however, interval voltage data is also
available to field personnel for troubleshooting issues in the field. The future holds real opportunity
for financial savings related to the expansion of these digital tools and associated training for field
personnel, resulting in optimized field troubleshooting.
Exhibit A

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(4) Mismapped Services
Avista’s outage management system relies on a ”connectivity model” that displays the mapping of
individual customer services to transformers and transformers to the proper phase on the feeder.
This model is important when an outage occurs because this connectivity helps ensure the extent of
the outage is understood, the likely cause is identified, and crews are dispatched to the proper
location to restore all customers associated with the outage. In cases where customers’ services
have not been properly mapped to the correct phase, there can be delays in determining the extent
of the outage and slower restoration efforts. Avista’s connectivity model is highly accurate, but some
factors can result in errors in the model. One such instance occurs during emergency restoration
after large storms, when services sometimes need to be reconfigured for quicker restoration but may
not be updated in the system model. During its initial AMI meter deployment, Avista identified over
60 meters that were not tracking consistently with the mapping in the system. As these instances
arise, corrections are made to ensure the model is more accurate. In the future, Avista will evaluate
the capability to apply more advanced analytics to proactively identify and correct instances of
incorrect mapping.
E. Design Services and Engineering
(1) Transformer Sizing
Traditionally, when additional load is added to an existing transformer, the field designer uses the
”transformer-loading tool” (that uses monthly energy usage to perform a statistical load allocation)
to determine proper transformer and wire size for the attached services. In the future, this tool will
be supplemented by aggregated load data from each meter to give an actual reading of peak loading
on the transformer rather than a statistical load allocation that was traditionally a best approximation.
(2) Load Analysis
Design services and engineering have historically had very little granular data available to support
decision making. As previously discussed, individual smart meter data can be aggregated up to the
transformer level, and many other similar aggregations are being configured for better analyzing our
system now that data is available for every individual meter. As one example, a Company engineer
for our Spokane Downtown Network area needed to determine the least impactful time to schedule
a building outage. Historically this would have been estimated based on the aggregated monthly
load of the multiple meters serving the building. In this instance, however, the engineer aggregated
the load of the entire building using AMI interval data, and the true optimal time was chosen to
perform the required work.
(3) Distribution Planning
As noted throughout this Report, utilities are experiencing the increasing penetration of electric
vehicles and customer-owned distributed generation that, at some threshold, will affect the
performance and predictability of their electric distribution systems. These new dynamics impact the
Exhibit A

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applicability of conventional engineering and asset management models currently used to evaluate
system performance and plan for future infrastructure needs and investment. The availability of AMI
metering data provides an entirely new toolset for the distribution planning process, including the
generation of customer class usage curves. These usage curves are essential for conducting
contemporary distribution analysis and planning. The data provided by advanced metering will also
help engineers better understand the new ways customers are interacting with the system, and to
more accurately model current and future system performance and needs. This capability will result
in the more efficient deployment of capital to meet all the integrated system requirements.

Section 7 | Expected Future Trends in Customer
Benefits
A. Support of Asset Management Planning
Prior to having interval data from advanced metering, Avista used historical service life/failure data
to forecast the average expected life of equipment, such as distribution transformers. Recently, the
Company has developed an algorithm that uses loading data from smart meters to determine how
overloading impacts the expected life of the transformer. This much-more-accurate information
improves the quality of our asset data overall and informs when a transformer should be replaced
before it fails.
B. Support of Electric System Planning
(1) Planning Studies
Traditionally, the electric utility industry (and Avista) used limited load data approximating the total
load for all customers on a feeder to identify when capacity improvements might be required to avoid
overloading the system (e.g., conductor, power transformers, regulators, fuses, etc.).
Fundamentally, these improvements focused on increasing the electric carrying capacity of the
system to meet measured or anticipated periods of peak demand. The range of tools available to
system planning has expanded in recent years, however, as management of the distribution system
has become much more sophisticated, now enabled by communications, remote sensing,
measuring, voluminous data, monitoring, and automation. Among these, AMI data has the greatest
potential for understanding the precise loads being placed on each part of the system by every
customer on the feeder. The advent of AMI metering data and analytic platforms can be used to
disaggregate and analyze loads from wide-ranging end uses to accurately determine what loads in
what locations are driving the timing and magnitude of peaks in demand on the system. This data
can also be re-aggregated by categories of end uses across all customers on a feeder to identify
potential solutions most effective in reducing or shifting the peak in demand (instead of the traditional
response of reinforcing the physical capacity of the infrastructure). This analysis can also be used
to determine how to deploy non-wires solutions for gird-optimal effectiveness.
Exhibit A

47
(2) Electric Vehicle Planning
Avista is continuing to update its plans to accommodate the pending greater penetration of electric
vehicles (EV) in our service area. Using interval data from our system Avista will use load
disaggregation to identify households charging electric vehicles. As a next step we would offer time
of use pilot programs and other tools to these customers to help move vehicle charging away from
periods of peak demand. Overall, AMI enabled tools will help us better optimize long term electric
vehicle loads with the infrastructure capability of our electric system.
C. Enabling Energy Pricing Strategies
In past discussions, we noted how energy prices, including the difference between heavy and light-
load hours and our limited requirement for capacity resources, constrained the need and cost-
effectiveness of retail pricing strategies in our resource portfolio. As part of its 2020 integrated
resource planning process, Avista retained the firm AEG to study the potential of alternative demand
response strategies to meet future capacity requirements for the 25-year planning horizon, 2021 –
2045. The purpose of the study was to develop reliable estimates of the magnitude, timing, and costs
of demand response resources likely available to Avista for meeting both winter and summer peak
loads. Among the alternatives considered were rates options that could be implemented to provide
a demand response resource to help offset our capacity needs. For example, that study forecasted
an average of 40.4 MW of load reduction available as early as year 2022 through time of use55 and
variable peak pricing rates, increasing to an average of 58.25 MW by year 2030. Fundamentally,
these rate mechanisms, whenever they become a reasonable alternative for our Idaho customers,
rely on the capabilities of AMI advanced metering to implement.

55 Time of use rates offered as an “opt-out” option.
Exhibit A