20240920Application Attachment Exhibit 1 - 2024 Idaho FCA Extension.pdf

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EVALUATION
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Hugh Peach-H. Gil Peach &Associates LLC
Mark Thompson-Forefront Economics Inc.
John Joseph-Joseph Associates, Inc.
Final Report
H. Gil Peach
& Associates LLC

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Tableof
Table of Contents i
List of Tables iv
Table of Figures vi
Introduction&Summary 1-1
Section 1. Fidelity Analysis 1-5
2020 Decoupling Mechanism—Electric(Schedule 75)and Gas(Schedule 175) 1-7
Electric Group 1 (Residential)and Group 2(Non-Residential) 1-8
Natural Gas Group 1 (Residential)and Group 2(Non-Residential) 1-21
Earnings Test 2020 1-34
Schedule 75D—Electric Earnings Test 1-34
Schedule 175D—Natural Gas Earnings Test 1-35
Three-Percent Annual Rate Increase Limitation 2020 1-35
Schedule 75E—Electric 3%Rate Increase Test 1-36
Schedule 175E—Natural Gas 3%Rate Increase Test 1-37
2021 Decoupling Mechanism-Electric(Schedule 75)and Natural Gas(Schedule 175)_ 1-38
Electric Group 1 (Residential)and Group 2(Non-Residential) 1-38
Natural Gas Group 1 (Residential)and Group 2(Non-Residential) 1-51
Earnings Test 2021 1-64
Schedule 75D—Electric Earnings Test 1-64
Schedule 175D—Natural Gas Earnings Test 1-64
Three-Percent Annual Rate Increase Limitation 2021 1-65
Schedule 75E—Electric 3%Rate Increase Test 1-65
Schedule 175E—Natural Gas 3%Rate Increase Test 1-67
2022 Decoupling Mechanism—Electric(Schedule 75)and Natural Gas(Schedule 175) _ 1-68
Electric Group 1 (Residential)and Group 2(Non-Residential) 1-68
Natural Gas Group 1 (Residential)and Group 2(Non-Residential) 1-81
2022 Earnings Test 1-91
Schedule 75D—Electric Earnings Test 1-91
Schedule 175D—Natural Gas Earnings Test 1-92
Three-Percent Annual Rate Increase Limitation 2022 1-92
Schedule 75E—Electric 3%Rate Increase Test 1-93
Schedule 175E—Natural Gas 3%Rate Increase Test 1-94
Audit Statements: Is the Source Data Credible? 1-95
Summary-Fidelity 1-99
Section 2. Revenue Effects and Billing Impacts 2-1
Summary of Decoupling Mechanics and Results 2-2
Earnings Test and Rate Cap 2-6
Analysis of Customer Billing Impacts 2-7
Electric 2-7
Natural Gas 2-1 1
Analysis of Revenue Impacts 2-14
i

Has Decoupling Stabilized Revenue 2-14
Revenue Deviations from Planning Assumptions and Causes 2-16
Summary—Revenue and Billing 2-22
Section 3. Fixed Cost Recovery for Non-Decoupled Classes 3-1
Electric Customers 3-1
Natural Gas Customers 3-2
Summary—Recovery of Fixed Charges(Non-Decoupled Classes) 3-3
Section 4. Conservation Trends and Performance 4-1
Performance Trends:Total and by Sector 4-1
Electrical Energy Savings 4-2
Electrical Expenditures 4-2
Natural Gas Energy Savings 4-3
Natural Gas Expenditures 4-3
Residential and Low-Income Program Performance 4-4
Total Residential Electrical Savings Trend 4-4
Low-Income Electric Savings Trends 4-5
Number of Electrical Residential and Low-Income Receiving Conservation Services 4-6
Electric Residential Expenditures 4-7
Total Residential Natural Gas Savings Trend 4-9
Low-Income Natural Gas Savings Trends 4-10
Number of Natural Gas Residential and Low-Income Receiving Conservation Services 4-11
Natural Gas Residential Expenditures 4-1 1
Summary—Conservation 4-14
Section 5. New Customer Analysis 5-1
Summary-New Customers 5-5
Section 6. Impact of Alternative Definitions of Normal Weather 6-1
Normal Weather-Alternative Definitions 6-1
30-Year Normal vs.Actual 6-3
Climate Trends(HDDs and CDDs) 6-4
The Peril of Standard Weather Adjustment 6-5
The Peril of Real-Time Estimation 6-7
Change in Structure of the Weather 6-7
Four Alternative Time Windows for Calculating Normal HDD and CDD 6-8
Considerations for Weather Calculations 6-11
What is"Normal Weather"? 6-13
Decoupling is a Climate Change Adjustment 6-14
Summary—Normal Weather 6-15
Section 7. Cap Analysis 7-1
Alternative Caps—Electric 7-1
Alternative Caps—Natural Gas 7-3
it

Summary—Alternative Caps 7-6
Section 8. Analysis of Possible Adverse Impacts 8-8
Are there Adverse Effects? 8-8
Service Quality-Customer Service Measures 8-9
Service Quality—Electric System Service Quality Indices 8-15
Service Quality—Performance Guarantees 8-17
Price Signals and Conservation Participation 8-21
GAAP Accounting 8-23
Cost Control and Operational Efficiency 8-24
Energy Conservation and Energy Efficiency 8-26
Summary—No Adverse Effects 8-28
Section 9. Findings 9-1
Section 10. Recommendations 10-1
Section 11. Appendix 11-3
Rate Cases and Test Years 11-3
IPCC Precedent for 20-Years 11-3
The "Normal Weather"and "Weather Normals" Problem 11-5
Section 12. Bibliography 12-8
Hi

List of Tables
Table 1-1: 2020 Development of Electric Decoupled Revenue per Customer............................ 1-9
Table 1-2: 2020 Electric Decoupled Revenue per Customer.................................................... 1-10
Table 1-3: 2020 Development of Monthly Electric Decoupled Revenue per Customer........... 1-11
Table 1-4: 2020 Electric Residential Deferral—Format. .......................................................... 1-13
Table 1-5: 2020 Electric Non-Residential Deferral-Format.................................................... 1-16
Table 1-6: 2020 Electric Decoupling-Residential................................................................... 1-17
Table 1-7: 2020 Electric Decoupling-Non-Residential........................................................... 1-18
Table 1-8: 2020 Annual True-Up for Electric Residential and Electric Non-Residential......... 1-19
Table 1-9: 2020 Electric Residential Group Rate Determination............................................... 1-20
Table 1-10: 2020 Electric Non-Residential Group Rate Determination. .................................. 1-21
Table 1-11. 2020 Development of Natural Gas Decoupled Revenue per Customer.................. 1-23
Table 1-12. 2020 Natural Gas Decoupled Revenue per Customer............................................. 1-24
Table 1-13. 2020 Development of Monthly Natural Gas Decoupled Revenue per Customer... 1-25
Table 1-14: 2020 Natural Gas Decoupling-Residential. ......................................................... 1-28
Table 1-15: 2020 Natural Gas Decoupling-Non-Residential.................................................. 1-31
Table 1-16: 2020 Annual December True-Up for Gas Residential and Non-Residential......... 1-32
Table 1-17: 2020 Natural Gas Residential Group Rate Determination...................................... 1-33
Table 1-18: 2020 Natural Gas Non-Residential Rate Determination........................................ 1-33
Table 1-19. 2020 Electric Earnings Test.................................................................................... 1-34
Table 1-20: 2020 Natural Gas Earnings Test............................................................................ 1-35
Table 1-21: 2020 Electric 3%Annual Rate Increase Limitation............................................... 1-36
Table 1-22. 2020 Natural Gas 3%Rate Increase Limitation...................................................... 1-37
Table 1-23: 2021 Development of Electric Decoupled Revenue per Customer. ...................... 1-39
Table 1-24: 2021 Electric Decoupled Revenue per Customer. ................................................. 1-40
Table 1-25: 2021 Development of Monthly Electric Decoupled Revenue per Customer......... 1-41
Table 1-26: 2021 Electric Decoupling-Residential................................................................. 1-45
Table 1-27: 2021 Electric Decoupling-Non-Residential......................................................... 1-48
Table 1-28: 2021 Annual True-Up for Electric Residential and Electric Non-Residential....... 1-49
Table 1-29: 2021 Electric Residential Rate Determination....................................................... 1-50
Table 1-30: 2021 Electric Non-Residential Group Rate Determination. .................................. 1-50
Table 1-31. 2021 Development of Natural Gas Decoupled Revenue per Customer.................. 1-53
Table 1-32. 2021 Natural Gas Decoupled Revenue per Customer............................................. 1-54
Table 1-33. 2021 Development of Monthly Natural Gas Decoupled Revenue per Customer... 1-55
Table 1-34: 2021 Natural Gas Decoupling-Residential. ......................................................... 1-58
Table 1-35: 2021 Natural Gas Decoupling-Non-Residential. ................................................. 1-61
Table 1-36: 2021 Annual True-Up for Natural Gas Residential and Non-Residential. ............ 1-62
Table 1-37: 2021 Natural Gas Non-Residential Rate Determination........................................ 1-63
Table 1-38. 2021 Electric Earnings Test.................................................................................... 1-64
Table 1-39: 2021 Natural Gas Earnings Test............................................................................ 1-65
Table 1-40: 2021 Electric 3%Annual Rate Increase Limitation............................................... 1-66
Table 1-41. 2021 Natural Gas 3%Rate Increase Limitation...................................................... 1-67
Table 1-42. 2022 Development of Electric Decoupled Revenue per Customer......................... 1-70
Table 1-43. 2022 Electric Decoupled Revenue per Customer................................................... 1-71
Table 1-44. 2022 Development of Monthly Electric Decoupled Revenue per Customer.......... 1-72
Table 1-45. 2022 Development of Electric Deferral.................................................................. 1-77
Table 1-46: 2022 Annual (December) True-Up: Electric Residential and Non-Res................. 1-79
Table 1-47: 2022 Electric Residential Group Rate Determination............................................ 1-80
Table 1-48: 2022 Electric Non-Residential Group Rate Determination. .................................. 1-80
Table 1-49. 2022 Development of Natural Gas Decoupled Revenue per Customer.................. 1-83
iv

Table 1-50. 2022 Natural Gas Decoupled Revenue per Customer............................................. 1-84
Table 1-51. 2022 Development of Monthly Natural Gas Decoupled Revenue per Customer... 1-85
Table 1-52: 2022 Natural Gas Residential Group Rate Determination..................................... 1-88
Table 1-53: 2022 Non-Residential Group Rate Determination................................................. 1-88
Table 1-54. 2022 Development of Natural Gas Deferral........................................................... 1-89
Table 1-55. 2022 Electric Earnings Test................................................................................... 1-91
Table 1-56. 2022 Natural Gas Earnings Test............................................................................. 1-92
Table 1-57: 2022 Electric 3%Annual Rate Increase Limitation............................................... 1-93
Table 1-58. 2022 Natural Gas 3%Rate Increase Limitation...................................................... 1-94
Table 2-1: Electric and Gas Rate Groups and Customer Classes (Rate Categories)...................2-1
Table 2-2 Avista Decoupling Deferral Year and Decoupling Rate Year Definitions.................2-2
Table 2-3. Summary Deferral Balances and Decoupling Recovery Rate -Electric.....................2-4
Table 2-4: Summary of Deferral Balances and Decoupling Recovery Rate-Natural Gas.........2-5
Table 2-5. Annual Electric Data-Residential Customer Class (Schedules 1&2)........................2-7
Table 2-6. Annual Electric Data-General Services(Rate Schedules 11, 12, and 13).................2-8
Table 2-7. Annual Electric Data-Large General Services(Rate Schedules 21,22, and 23). .....2-8
Table 2-8. Annual Natural Gas Data-Residential(Rate Schedules 101 & 102)......................2-11
Table 2-9. Annual Natural Gas Data-General Services (Rate Schedule 111)..........................2-12
Table 2-10. Annual Natural Gas Data-Large Gen. Services(Schedules 112, 121,and 122)...2-12
Table 2-11. Authorized and Actual Electric Decoupled Revenue per Customer.......................2-17
Table 2-12. Test Year and Actual Electric Usage, Customers, and Use per Customer..............2-17
Table 2-13. Authorized an Actual Natural Gas Decoupled Revenue per Customer. .................2-20
Table 2-14. Test Year and Actual Natural Gas Usage, Customers, and Use per Customer.......2-20
Table 4-1: Trends(Electricity)..................................................................................................4-15
Table 4-2: Trends(Natural Gas)................................................................................................4-16
Table 5-1. Impact of New Customers on Decoupled Deferred Revenue-Electric.....................5-2
Table 5-2. Impact of New Customers on Decoupled Deferred Revenue-Natural Gas...............5-4
Table 6-1. Comparison of Actual to Normal Weather,2020-2022..............................................6-3
Table 6-2: Climate Effects driving Utility Bills and Rate Adjustments......................................6-8
Table 6-3: Weather Related Deferred Revenue with Alternative Normal DD-Electric............6-8
Table 6-4. Weather Related Deferred Revenue with Alternative Normal DD-Natural Gas......6-9
Table 6-5. Range of Revenue Adjustments -2022 Electric.......................................................6-14
Table 6-6. Range of Revenue Adjustments -2022 Natural Gas.................................................6-14
Table 7-1. Deferrals and Decoupling Recovery Rates, 3 Percent Cap-Electric.........................7-2
Table 7-2. Analysis of Alternative Rate Caps-Electric Non-Residential...................................7-3
Table 7-3. Deferrals and Decoupling Recovery Rates, 3 Percent Cap-Natural Gas..................7-4
Table 7-4. Analysis of Alternative Rate Caps-Natural Gas Residential....................................7-4
Table 7-5. Analysis of Alternative Rate Caps-Natural Gas Non-Residential............................7-5
Table 8-1. 2015 Indicators of Customer Service Quality -Prior Study DR 52.......................8-11
Table 8-2. 2016 Indicators of Customer Service Quality -Prior Study DR 52.......................8-11
Table 8-3. 2017 Indicators of Customer Service Quality -Prior Study DR 52.......................8-12
Table 8-4: 2018 Indicators of Customer Service Quality- Current DR 30...............................8-12
Table 8-5: 2019 Indicators of Customer Service Quality- Current DR 30...............................8-13
Table 8-6: 2020 Indicators of Customer Service Quality- Current DR 30...............................8-13
Table 8-7: 2021 Indicators of Customer Service Quality- Current DR 30...............................8-14
Table 8-8: 2022 Indicators of Customer Service Quality- Current DR 30...............................8-14
Table 8-9: Indicators of Electric Service Reliability-Prior DR 52, Current DR 30................8-15
Table 8-10: 2016 Customer Service Guarantees-Prior DR52. ................................................8-17
Table 8-11. 2017 Customer Service Guarantees-Prior DR 52. ................................................8-18
Table 8-12. 2018 Customer Service Guarantees -Current DR 30.............................................8-18
Table 8-13. 2019 Customer Service Guarantees -Current DR 30.............................................8-19
v

Table 8-14. 2020 Customer Service Guarantees -Current DR 30.............................................8-19
Table 8-15. 2021 Customer Service Guarantees -Current DR 30.............................................8-20
Table 8-16. 2022 Customer Service Guarantees -Current DR 30.............................................8-20
Table 8-17: Summary: Customer Service Guarantees. .............................................................8-21
Table 8-18: Residential Electric Decoupling Signal. ................................................................8-22
Table 8-19: Non-Residential Electric Decoupling Signal.........................................................8-23
Table 8-20: Residential Natural Gas Decoupling Signal...........................................................8-23
Table 8-21: Non-Residential Natural Gas Decoupling Signal. .................................................8-23
Table 11-1: Electric and Natural Gas Cases and Test Years...................................................... 11-3
Table of Figures
Figure 1-1. Timing of Deferral Balance Accumulation and Decoupling Rate............................. 1-5
Figure 1-2.Financial Audit Opinion for Calendar 2020............................................................ 1-96
Figure 1-3. Financial Audit Opinion for Calendar 2021. ........................................................... 1-97
Figure 1-4.Financial Audit Opinion for Calendar 2022. ........................................................... 1-98
Figure 2-1: Annual Schedule 75 Revenue as a Percent of Customer Class Revenues..............2-10
Figure 2-2: Annual Schedule 175 Revenue as a Percent of Customer Class Revenues............2-13
Figure 2-3: Electric Revenue Variability(2020-2022)..............................................................2-15
Figure 2-4: Natural Gas Revenue Variability(2020-2022).......................................................2-16
Figure 2-5: Percentage Change in Use per Customer,Electric Residential..............................2-18
Figure 2-6: Percentage Change in Use per Customer,Electric Non-Residential......................2-19
Figure 2-7: Percentage Change in Use per Customer,Natural Gas Residential. ......................2-21
Figure 2-8: Percentage Change in Use per Customer,Natural Gas Non-Residential...............2-22
Figure 4-1: Electrical Energy Savings(kWh by Sector and Total).............................................4-2
Figure 4-2: Electrical Efficiency Expenditures($)by Sector and Total.....................................4-3
Figure 4-3: Natural Gas Energy Savings (Therms)by Sector and Total.....................................4-3
Figure 4-4: Gas Efficiency Expenditures by Sector and Total....................................................4-4
Figure 4-5: Total Residential Electrical Savings(kWh). ............................................................4-5
Figure 4-6: Low-Income Electrical Savings(kWh)....................................................................4-5
Figure 4-7: Ratio of Low-Income to Total Residential Electrical Savings(%)..........................4-6
Figure 4-8: Number of Residential Electrical Customers Receiving Conservation Services......4-6
Figure 4-9: Residential Electrical Expenditures($)....................................................................4-7
Figure 4-10: Electrical Low-Income Spending($)......................................................................4-8
Figure 4-11: Ratio of Low-Income to Total Residential Electrical Spending(%)......................4-8
Figure 4-12: Average Residential Electric Customer Conservation Expenditures($)................4-9
Figure 4-13: Total Residential Natural Gas Savings(Therms)...................................................4-9
Figure 4-14: Residential Low-Income Natural Gas Savings(Therms).....................................4-10
Figure 4-15: Ratio of Low-Income to Residential Natural Gas Savings(%)............................4-10
Figure 4-16: Number of Gas Residential Customers Receiving Conservation Services...........4-11
Figure 4-17: Natural Gas Total Residential Efficiency Expenditures($). ................................4-11
Figure 4-18: Natural Gas Low-Income Efficiency Expenditures ($)........................................4-12
Figure 4-19: Ratio of Low-Income to Total Natural Gas Residential Spending(%)................4-13
Figure 4-20: Natural Gas Average Residential Customer Conservation Expenditures($).......4-13
Figure 5-1: Percent Over(Under)Allowed RPC—Electric(2020—2022 Average)..................5-3
Figure 5-2.Percent Over(Under)Allowed RPC -Natural Gas(2020 -2022 Average)..............5-5
Figure 6-1: Four Ways to Calculate Normal Weather.................................................................6-1
Figure 6-2: Spokane International Airport Annual Heating Degree Days(1947-2021). ............6-4
Figure 6-3: Spokane International Airport Annual Cooling Degree Days (1947-2021).............6-5
vi

Figure 6-4: Heating Degree Days -Detrended Data—HDD Trend Removed............................6-6
Figure 6-5: Spokane Airport Annual Heating Degree Days(1947-2021)...................................6-6
Figure 6-6: Weather Related Deferred Electric Revenue, 2020-2022.......................................6-10
Figure 6-7. Weather Related Deferred Natural Gas Revenue,2020-2022.................................6-10
Figure 6-8: Spokane -Moving Average HDD of Different Durations (1977-2023).................6-11
Figure 6-9: Relation of Standard Deviation and Years(Spokane)............................................6-12
Figure 6-10: Best Number of Years for Calculation.................................................................6-13
Figure7-1. How the Cap Works..................................................................................................7-1
Figure7-2: Rate Caps..................................................................................................................7-6
Figure 8-1. Identify Adverse Impacts..........................................................................................8-8
Figure 8-2: Finding: Customer Service Measures.....................................................................8-10
Figure 8-3: Finding: Electric Reliability. ..................................................................................8-16
Figure8-4: SAIFI......................................................................................................................8-16
Figure8-5: SAIDI .....................................................................................................................8-16
Figure 8-6: Finding: Customers Service Guarantees................................................................8-21
Figure 8-7. Increasing Earnings in a Decoupled Utility(RAP)..................................................8-24
Figure 8-8. Finding: Staff and Organizational Support.............................................................8-28
Figure 11-1: Exceeding 1.5 Degree Celsius Global Warming Level........................................ 11-4
Figure 11-2: An Average of 20-Years....................................................................................... 11-4
Figure 11-3: Estimates of Future Likely More Accurate. ......................................................... 11-6
vii

Introduction : Summary
This evaluation of Avista's Decoupling Mechanism is partly a compliance evaluation and
partly a policy evaluation of Avista's decoupling as a specific rate reform (alternative
form of rate making) within a specific, three-year, time window: 2020 -2022.
Each section of the evaluation corresponds to a specific task.
• Section 1 is a compliance evaluation: Did Avista comply with the specifics of
the decoupling order?
The overall result in this section of the analysis is that we find the deferrals and
rates to have been calculated by the Company in accordance with the Commission
guidance as operationalized by the methodological specification in Schedule 75
and Schedule 175.
• Section 2 is concerned with revenue effects and billing impacts.Avista's
decoupling mechanism has had a stabilizing effect on revenue, reducing
variability in half for electric and by one-fifth for natural gas of variability
without decoupling.
On the electric side,between 2018 and 2022 the 3% cap on annual rate increases
from the decoupling rate was reached once for residential and twice for non-
residential. For natural gas, the rate cap was reached once between 2018 and 2022
in each rate group, residential and non-residential. Deferral balances are driven
largely by differences in use per customer from test year assumption. Much of the
difference in use per customer is due to weather, especially in electric residential,
natural gas residential and natural gas non-residential. Avista's energy efficiency
programs have also worked to lower use per customer, especially for the electric
non-residential group.
• Section 3 examines the recovery of fixed cost for both Non-Decoupled
and Decoupled customer classes. Fixed costs can be recovered in the
customer charge or in the variable portion of bills, driven by energy use.
To what extent are fixed costs recovered in fixed charges for the customer
classes that are excluded from the Mechanisms?
For the electric rate classes not included in decoupling, Avista recovers
16% of fixed charges for Extra Large General Service and 100% of fixed
charges for Street and Area Lighting through the customer charge. In
comparison, overall (system total), Avista recovers about 14% of total
electric fixed cost through fixed customer charges. The percentage runs
lower for residential and larger for non-residential.
1-1

For natural gas rate classes not included in decoupling, Avista recovers no
fixed charge revenue for Interruptible Service and 7% of fixed charges for
Transportation Service through the customer charge. In comparison,
Avista recovers 32% percent of fixed costs through the customer charge
overall (system total), with a slightly higher percentage of recovery in the
residential customer class than non-residential customer classes.
• Section 4 is focused on conservation trends and performance. In the big
picture, overall electrical savings are trending downwards while costs are trending
upwards. Overall natural gas savings are trending level while cost is trending
upwards. For residential electric low-income households, savings are trending up
while cost is trending level. For residential natural gas households, savings are
trending up, while cost is trending up. With regard to decoupling, there is no
evident impact of decoupling on energy conservation savings. This result is
neither unusual nor unexpected. Decoupling is generally not considered to be a
driver of energy conservation. Rather, decoupling removes a potential barrier to
energy conservation, which is different than driving a direct savings effect.
• Section 5 is an analysis of new customers.New customers are meaningfully
different from existing customers in both use per customer and decoupled
(distribution)revenue generated per customer. Although the effect is stronger for
electric service, and not as pronounced for natural gas service, new Residential
customers use substantially less energy per customer and generate less revenue
per customer than existing residential customers. Because the number of new
customers is small relative to existing customers, the overall impact on deferred
revenue is limited,but still meaningful.
For electric service, had new customers been included over the 2020-2022 period,
electric Residential customers would have received a smaller refund; electric
Non-Residential customers would have received a higher charge through
application of the decoupling tariff(RS 75).
For natural gas service, had new customers been included over the 2020-2022
period, Residential customers would have experienced a higher charge, but Non-
Residential customers would have received a lower charge through the decoupling
tariff(RS 75).
• Section 6 is an analysis of alternative calculations of normal weather. Heating
Degree Days (HDDs) are decreasing. As the planet retains more and more heat,
instead of reflecting it back into space, the planet, considered as a system, has
become unstable in this regard. As the build-up of planetary heat increases,
Cooling Degree Days (CDDs) are increasing. This means more and more cooling
1-2

is needed to counter the increasing heat. The problem of ever-increasing heat is
now a physical feature of the planet, and the assumption of a stable weather
environment does not work. As directed by the WUTC, Avista has carried out
alternative calculations for"normal weather."Each calculation uses an identical
mathematical method but employs rolling average data sets of 30-years, 20-years,
15-years, and 10-years. Tabled results of these calculations include HDDs, CDDs,
energy usage adjustment, and deferred decoupled revenue adjustment for
Residential and Non-Residential customer groups for both electric service and
natural gas service. In examination of these calculations, we find that the
calculations were correctly performed, and we find cause to rule out using the
alternative of 10-years or less. We also found cause to rule out 30-years. This
leaves the 20-year and 15-year calculations as the remaining alternatives. The 15-
year data window is the shortest period that still produces somewhat stable results
of somewhat reasonable accuracy and precision over the observed data and
calculations. The 20-year data window is the longest viable period; beyond this,
analysis is overly weighted toward older weather that, given the advancing
climate trend, is now abnormal.' As to precedent, we note that the selection of 20-
years coincides with the current practice in climate science calculations (see
Appendix).2 Conversely, the selection of 15-years coincides with NOAA's choice
to add a 15-year time series along with its standard 30-year time series for
construction of the Typical Meteorological Year(TMY).3 For decoupling, the 20-
year calculation provides a middle ground from a revenue adjustment perspective,
producing reasonable but more moderate deferred decoupling revenue
adjustments.4
' To be clear,the mathematics works but the calculated result is abnormal weather rather than normal
weather.As discussed in Section 6 and,further,in the Appendix,climate change has weakened the
relevance of the concept of normal weather and continues to drain meaning from the concept.A better
concept would be"modeled weather,"given the effects of climate change(particularly effects of the trend
of planetary accumulation of heat energy),for a particular future year.This would require some creative
reorientation of the decoupling calculation framework but does not challenge the value of decoupling.The
value of decoupling is increase for our climate change era because decoupling becomes an essential climate
practice to ensure revenue stability during climate change.
2 This is for a different calculation(the year we pass the 1.5 degrees Celsius target).
3 NOAA's series are Typical Meteorological Year(TMY)and Avista's series are observations from the
Spokane airport weather station.These are different analytic approaches.NOAA's putting forward the 15-
year data along with the 30-year data is not the same as moving to the 15-year data for TMY,but providing
an extra series in a combination that would put an average of about 22.5 years but could be weighted more
or less towards either series.
4 We suggest that a quest for"normal weather,"though associated with the current decoupling framework,
is becoming increasingly less relevant due to changes in the structure of weather driven by climate change.
Likely the question of"normal weather"will gradually recede and be replaced by a different question—
"what will the weather be in a given future year?For now,however,we are still in the logical/analytic
framework of normal weather. So long as we maintain this question,a time window of 20-years is a
moderate and reasonable adjustment(away from 30-years),with the caveat that in the future 15-years may
be more reasonable,and following that,we will need to change the question to"what will the weather be in
a given future year"without reference to normal weather.
1-3

Examination of the four alternative operational definitions of normal weather
inherently raises the question, "What is normal weather"? This question requires
continued follow-on discussion. Prior to approximately 1988, the problem of
change in structure of the weather(operationalized as trend change in Heating
Degree Days -HDDs) could reasonably be considered to be below need for
consideration. It was not considered in analysis and the topic simply did not rise
to the level of serious discussion. At that time, the "deferred decoupled revenue—
weather component"was not thought to be an indicator of climate change, but to
be covering drops in usage due to energy conservation/energy efficiency and all
other factors. Since at least 1988, the effect size for climate change has become
stronger. Until about 1988 "normal weather" could reasonably be considered a
projection of a moving average of past weather. However, for weather adjustment
the HDD trend line indicates we need to think though a new definition for
"normal weather"that systematically incorporates the trend of ever-increasing
planetary heat energy. The climate trend(operationalized as the HDD trend line)
means that projected weather is no longer a kind of average result set against a
stable background.
Deferred decoupled revenue adjustment continues to remove a barrier to more
aggressive energy conservation/energy efficiency and continues (for those fixed
costs included in decoupling) to improve revenue stability without changing total
collections. However, for weather adjustment, the main driver now is climate
change with conservation/energy efficiency secondary. The decoupling weather
adjustment should be recognized as primarily a climate change methodological
practice to support regular utility revenue in the era of climate change.
• Section 7 is a CAP analysis. The use of a decoupling rate cap on customer
surcharges has the advantage of smoothing out rates and the disadvantage of
prolonging revenue recovery. Raising the rate cap to 5%will sometimes increase
bills for the next rate year, while lowering bills for the year after that. Going to
no-Cap provides quickest recovery.
• Section 8 is a check-analysis on theoretically possible adverse effects of
decoupling. We find no conclusive evidence of any current adverse impact of
decoupling on cost control, operational efficiency,price signals, or service quality.
• Section 9 provides a short list of recommendations.
• Section 10 presents recommendations, Section 11 is a brief appendix, Section
12 is the bibliography.
1-4

AN
Section 1 Analysis
The evaluation objective for the fidelity analysis is to complete a review of whether the
deferrals and rates for the time window examined were calculated in accordance with the
Commission orders approving the mechanisms. That is, were the mechanisms
administered and calculated correctly? This first task is a compliance evaluation.
Operationally, we compare the Decoupling Mechanism Development of Deferrals as
submitted by Avista in 2021 for the 2020 deferral years, as submitted in 2022 for the
2021 deferral year 6, and as submitted in 2023 for the 2022 deferral year to the
specification of method in Schedule 75 for electric service and in Schedule 175 for
natural gas service. This includes the Earnings Test and the 3%Annual Increase Test.
To support discussion, the relation of decoupling years and decoupling application years
in which rates based on data calculations from the decoupling years are applied is shown
in Figure 1-1. Five deferral years are shown in the table. This evaluation includes the first
three deferral years.
Decoupling- Second Five Years
Docket UG-190335
Order 9-March 25,2020
1 2 3 4 5
Deferral Year
Included in this Report Future Decoupling Years
Decoupling Data for calculation
Year of Decoupling 2020 2021 2022 2023 2024
Deferral Balance
Year Decoupling 8/l/2021 8/l/2022 8/l/2023 8/l/2024 8/l/2025
Rate Year Deferral Balance to to to to to
Applied 7/31/2022 7/31/2023 7/31/2024 7/31/2025 7/31/2026
Figure 1-1. Timing of Deferral Balance Accumulation and Decoupling Rate.
5 Joe Miller,Sr.Manager,Rates and Tariffs to Mr.Mark L.Johnson,Executive Director and Secretary,
Washington Utilities and Transportation Commission,May 26,2021,with attachments;for Tariff WN U-
28,Electric Service Electric Decoupling Rate Adjustment;and separate letter for Tariff WN U-29,Natural
Gas Service,Natural Gas Decoupling Rate Adjustment.
6 Joe Miller, Sr.Manager,Rates and Tariffs to Amanda Maxwell,Executive Director and Secretary,
Washington Utilities and Transportation Commission,May 27,2022,with attachments;for Tariff WN U-
28,Electric Service,Electric Decoupling rate Adjustment,and separate letter for Tariff WN U-29,Natural
Gas Service,Natural Gas Decoupling Rate Adjustment.
7 Joe Miller, Sr.Manager,Rates and tariffs to Amanda Maxwell,Executive Director and Secretary,
Washington Utilities and Transportation Commission,May 31,2022,with attachments;for Tariff WN U-
28,Electric Service,Electric Decoupling rate Adjustment,and separate letter for Tariff WN U-29,Natural
Gas Service,Natural Gas Decoupling Rate Adjustment.
1-5

Avista's decoupling mechanism allows for the recovery (or return) of the difference
between allowed revenue and actual revenue in each decoupling rate year. This
difference is referred to as the decoupling deferral balance. It is tracked separately for the
decoupled electric residential and non-residential customer groups and for the decoupled
residential and non-residential natural gas customer groups.
Decoupling Deferral Balance: The difference between allowed revenue and actual
revenue. This value may be positive or negative.
Monthly deferrals are accumulated over a calendar year and used with other determinants
to calculate the decoupling rate required to collect or refund the under or over collected
revenue. Decoupling rates are calculated according to Schedule 75 (electric) and
Schedule 175 (natural gas) and become effective on August 1 of the year following the
year for which deferral balances are calculated.8
The first deferral year examined in this report resulted in a deferral balance at the end of
calendar year 2020 that was used, along with other determinants, to calculate the first
decoupling rate in effect during the first"decoupling rate year" for this cycle is August 1,
2021, through July 31, 2022). The same process is followed for the second deferral year
and for the third deferral year.
There is a 3% limit capping the part of the Decoupling Deferral Balance that may be
applied in the following Decoupling Rate Year. Any overage is carried into the next
Decoupling Rate Year. For example, any overage in a calculation for the first Decoupling
Rate Year would be carried over to be added into the amount calculated for the second
Deferral Year.
Each year, electric and natural gas results are separately developed. Also, within each
year and energy source, Residential and Non-Residential Rate Groups are separately
analyzed.
8 The details of Avista's decoupling mechanism are included in the Final Order("Order 5")for Docket
Numbers UE-140188 and UG-140189(consolidated),November 25,2014.Certain changes,including the
exclusion from decoupling of new meters until the next rate case and an alignment of dates,are specified in
the Final Order(Order 09)in Dockets UG-190334,UG-190335,UE-190222(consolidated),March 25,
2020.Changes affecting calculations are: (1)The effective date of annual rate adjustment filing is moved
from November 1 to August 1. (2)Customers connected to Avista's system after the ratemaking test year
will be excluded from the decoupled deferred revenue calculations.Furthermore,the Company will include
a status update in its yearly decoupling report identifying the number of new customers excluded from the
mechanism and associated costs and revenues. (3)The Company will add an annual revenue-per-customer
true-up to the December deferred revenue calculation.
1-6

We first examine the working of the electric decoupling mechanism and of the natural
gas decoupling mechanisms in detail for the 2020 deferral year. Then, the same detailed
review is repeated for the 2021 and 2022 deferral years.
2020 Decoupling Mechanism—Electric (Schedule 75) and Gas (Schedule 175)
The decoupling mechanism is designed to capture all fixed costs that are to be collected
from the volumetric portion of rates.9 With decoupling, the total amount remaining for
recovery is allocated to customer bills according to a model for recovery in a structured
manner on an ongoing basis.
As specified, for(Electric) Schedule 75 and(Natural Gas) Schedule 175, calculations
were carried out separately and in parallel, for Residential and Non-Residential accounts.
For each of these groups of accounts, the sum of monthly deferral amounts over 2020 is
the cumulative deferral (rebate or surcharge) for 2020. This cumulative deferral for 2020
is then applied over the twelve months beginning August 1, 2021. Amortization of the
cumulative deferral balance developed over calendar 2020 was implemented over the
twelve-month time window from August 1, 2021, to October 31, 2022.
Electric Schedule 75
• For(Electric) Schedule 75, Group 1 is Residential customers (Schedules 1 and 2).
• For(Electric) Schedule 75, Group 2 is Non-Residential customers (Schedules 11,
12, 21, 22, 23, 30, 31 and 32).
• For(Electric) Schedule 75, two customer classes were not decoupled(Schedule 25
—Extra Large General Service and Schedules 41-48 — Street and Area Lighting).
The non-decoupled customer classes are not included in this analysis.
Natural Gas Schedule 175
• For(Natural Gas) Schedule 175, Group 1 is Residential customers (Schedules 101
and 102).
9 Cost-of-service studies follow the principles of cost causation,equal rates of return across rate classes,
and gradualism(Lowell E.Alt Jr.,Electrical Utility Rate Setting,A Practical Guide to the Retail Rate-
Setting Process for Regulated Electric and Natural Gas Utilities,2006).Fair rates,according to the
principle of cost causation,are rates that apply variable costs(costs that vary with the number of energy
units used)to the variable portion of the customer energy bills(the energy charge)and fixed costs(costs
that are caused by being on the system,that do not vary with the number of energy units used)to the fixed
portion of the customer bill(the customer charge). However,commissions,in order to implement federal,
state,or provincial policy,are granted the flexibility to assign costs differently.In decoupling,fixed
charges that have been previously included in the energy charge are recaptured from the energy charge and
an effect of decoupling is to treat these amounts as fixed charges.
1-7

• For(Natural Gas) Schedule 175, Group 2 is Non-Residential customers (Schedules
111, 112, 121, 122, and 131.
• For(Natural Gas) Schedule 175, three rate schedules were excluded from the
decoupling mechanism(Schedules 132, 146, and 148). Non-decoupled customers
are not included in this analysis.
Electric Group 1 (Residential) and Group 2 (Non Residential)
Schedule 75A is used to develop the Decoupled Revenue per Customer. Schedule 75B
uses the results from Schedule 75A to develop the Monthly Decoupling Deferral. There
are seven calculation steps in Schedule 75A. There are eight calculation steps in Schedule
75B. These are developed in this subsection of the report. Results for Schedule 75A for
both Electric Residential and Electric Non-Residential customers are shown in Tables 1-1
through 1-3. Results for Schedule 75B are shown separately for Electric Residential
customers in Tables 1-4 and 1-6, and for Electric Non-Residential customers in Table 1-5
and 1-7. A required true-up for number of customers is shown in Table 1-8.l o
Schedule 75A —Decoupled Revenue per Customer
Calculation of Decoupled Revenue per Customer for Electric Residential and Electric
Non-Residential is specified in seven steps in Schedule 75A." These steps are
implemented in Tables 1-1, 1-2 and 1-3.
Step 1: Determine the Total Normalized Revenue.
Total Normalized Revenue is equal to the final approved base rate revenue approved in
the Company's last general rate case, individually for each Rate Schedule. Table 1-1,
Line 1 shows initial Total Normalized Net Revenue. In Line 2 the Allowed Revenue
Increase is shown. The sum of Line 1 and Line 2 is the Allowed Base Rate Revenue or
Total Normalized Revenue. Note that values in the Total column for Lines 1-6 are not
used since they include results for non-decoupled schedules.
"Tables in this section of the report are from annual decoupling rate filing in May of each year.
11 Schedule 75,Decoupling Mechanism—Electric,WN U-28,Substitute Seventh Revision Sheet 75
canceling Sixth Revision Sheet 75,AVISTA CORPORATION dba Avista Utilities,Issued July 1,2022,
Effective October 1,2022. See attached"DESCRIPTION OF THE ELECTRIC DECOUPLING
MECHANISM:Calculation of Monthly Allowed Delivery Revenue Per Customer,Original Sheet 75A,
Issued June 12,2015,Effective August 1,2015.
1-8

Table ]-]: 2020 Development of Electric Decoupled Revenue per Customer.
Electric Decoupling Mechanism
Development of Decoupled Revenue by Rate Schedule-Electric
Washington Docket No.UE-170485 Compliance Filing
RESIDENTIAL, GENERAL SVC. LG.GEN.SVC. PUMPING EX LG GEN SVC ST&AREA LTG
TOTAL SCHEDULE 1,2 SCH.11,12 SCH.21,22 SCH.30,31,32 SCHEDULE 25 SCH.41-48
1 Total Normalized 12ME Dec 2016 Revenue $ 492,134,000 $ 209,489,000 $ 73,766,000 $ 126,766,000 $ 10,894,000 $ 64,348,000 $ 6,871,000
2 Allowed Revenue Increase(Attachment 1) $ 10,763,000 $ 4,904,000 $ 1,291,000 $ 2,775,000 $ 238,000 $ 1,405,000 $ 150,000
3 Allowed Base Rate Revenue $ 502,897,000 $ 214,393,000 $ 75,057,000 $ 129,541,000 $ 11,132,000 $ 65,753,000 $ 7,021,000
4 Normalized kWhs(12ME Dec 2016 Test Year) 5,658,613,712 2,361,885,989 623,243,883 1,409,459,201 133,495,310 1,107,408,158 23,121,171
5 Retail Revenue Adjustment(line 14) r$ 0.01900 $ 0.01900 $ 0.01900 $ 0.01900 $ 0.01900 $ 0.01900 $ 0.01900
6 Variable Power Supply Revenue(L4'L5) $ 107,513,661 $ 44,875,834 $ 11,841,634 $ 26,779,725 $ 2,536,411 $ 21,040,755 $ 439,302
7 Delivery&Power Plant Revenue(L3-L(J) $ 344,089,397 $ 169,517,166 $ 63,215,366 $ 102,761,275 $ 8,595,589
8 Customer Bills(12ME Dec 2016 Test Year) 2,945,836 2,518,371 375,436 22,836 29,193
9 Allowed Basic Charges $ 9.00 $ 20.00 $ 500.00 $ 20.00
10 Basic Charge Revenue(Ln 8•Lu 9) $ 42,175,919 $ 22,665,339 $ 7,508,720 $ 11,418,000 $ 583,860
11 Decoupled Revenue $ 301,913,478 $ 146,851,827 $ 55,706,646 $ 91,343,275 $ 8,011,729 Excluded From Decoupling
Step 2: Determine the Variable Power Supply Revenue.
This value is shown on Line 6 and is the product of Normalized kWh on Line 4 and
Retail Revenue Credit from Line 5. Values in the Total column for Lines 1-6 are not used
since they include results for non-decoupled schedules.
Step 3: Determine Delivery and Power Plant Revenue.
For the decoupled schedules only, subtract Variable Power Supply Revenue (Line 6)
from the Total Normalized Revenue (Line 3) and enter results on Line 7. Beginning with
Line 7, values in the Total column are valid for decoupling.
Step 4: Remove Basic Charge Revenue.
Because the decoupling mechanism only tracks revenue that varies with customer energy
usage, revenue directly recovered from Fixed Charges is removed in this step. Basic
Charge Revenue is shown on Line 10. It is the product of the number of Customer Bills
(2016 Test Year) on Line 8 times the Allowed Basic Charge (Line 9).12
Step 5: Determine Decoupled Revenue.
Decoupled Revenue is equal to the Delivery and Power Plant Revenue (Step 3; Line 7)
minus the Basic Charge Revenue (Step 4; Line 10). Decoupled Revenue is shown on
Line 11.
fZ Basic charge includes minimum charge revenue for non-residential customers.
1-9

Step 6: Determine Decoupled Revenue per Customer.
In this step, Decoupled Revenue from Line 11 is put on a per customer basis. The
Decoupled Revenue is divided by the approved Rate Year number of customers (by Rate
Group). This determines the annual Allowed Decoupled Revenue per Customer.
Table -7-2: 2020 Electric Decoupled Revenue per Customer.
Avista Utilities
Electric Decoupling Mechanism
Development of Annual Decoupled Revenue Per Customer-Electric
Washington Docket No.UE-170485 Compliance Filing
Line No. Source Residential Non-Residential
Schedules*
(a) (b) (c) (d)
1 Decoupled Revenues Attachment 4,Page 1 $ 146,851,827 $ 155,061,651
2 Revenue Data 209,864 35,622
Test Year#of Customers 12 ME 12.2016
3 (1)/(2) $ 699.75 $ 4,352.97
Decoupled Revenue per Customer
*Schedules 11,12,21,22,31,32.
Attachment 4,Page 2
Revenues
From revenue per customer $ 146,852,334 $ 155,061,497
From basic charge $ 22,665,339 $ 19,510,580
From power supply $ 44,875,834 $ 41,157,769
Total S 214,393,507 $ 215,729,847
Step 7: Determine the Monthly Decoupled Revenue per Customer.
Step 7 converts Allowed Decoupled Revenue per Customer(by Rate Group) into
monthly values. The assignment of monthly values is carried out by modeling monthly
kWh use (by Rate Group) in relationship to the annual kWh (Table 1-3). Kilowatt hours
(kWh) for Group 1 (Residential) for 2020 are shown in Line 3 and for Group 2 (Non-
Residential) in Line 6. Below the monthly values (Lines 4 and 7) monthly percentages
are shown. Lines 11 and 14 show the use of these percentages, applied to annual Allowed
Decoupled Revenue per Customer(by Rate Group) to generate monthly values. Table 1-3
shows the monthly results for both Electric Residential and Electric Non-Residential
decoupling.
1-10

Table 1-3: 2020 Development of Monthly Electric Decoupled Revenue per Customer.
Avista Utilities
Electric Decoapling Mechanism
Development of Mouthly Decoupled Revenue Per Customer-Electric
Washington Docket No.UE-170485 Compliance Filing
SOurtes shr A,, nog Sep Oe1 mr
ra—
W N W (d) W (9 W (n (1) 0) (s) (I) (m) W (o)
1 gkddc$>fY$
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3 W<aIM-Nomeliatl kWO Sale1 M yT, ,, 282,718,944 229,028,914 209,165,396 176,926,076 154,sm,981 143,616,706 190,502,271 1]1,958,392 162,813,881 159,069,574 215,944,%2 264,640,186 2,361,885,989
4 1.1-1 Tolal %OfTohl I1.9N 9.7
O% 8.88% 1— 6.56% 6.08% 8ON 7.2. 6.SH� 6.73% 9.14% 1110% 100—
5 Non-Residerltid^
Wh Sales MOI Test Yea, 171,011,11 11,11,274 1,112,516 846,SJ2 181� 185,499,649 04,J07!14] 192,J88,0'!0 180,'I., 1 72,]41 16;]05,681 193,519,554 ,66198,394
'I %O[NmuaIT. k %d—I 8.2'1% '1.24% ].9C/ 3 2.56% 836% 8.56% 9.43% 8.88% 1.14% s— 2.51% 191% 1 100.ma
e
9 Ruidentiol<c
- - ed"IP.2 L3 Amclorem 4, S UE I]0485Oe<mgl
11 _,I3<cmpled RPC (4)x(10) S s3,76 $ 6I.85 S 6215 $ 52.42 S 41.81 $ 42.55 $ 16. $ 5095 S 4— $ 41.13 $ 63,98 $ ]g40 S 699.7I5
12 Nnx-Res�den0ul^
13 -rl7 8502c lad RPC Amcl a4,P.2L3 $ 4,35z.97
14 �y n<coapl<d RPC (7)x(13) S 359.81 S 33636 S 346.66 S 129.21 $ 36390 S 372.76 $ 410.56 8 1..W $ I., $ 361.48 $ 326.96 S 388.88 S 4,352.97
^Scledolea ll,12,21,22,31,32.
Schedule 75B —Electric Monthly Decoupling Deferral
Monthly values developed in accordance with Schedule 75A are then used in the
implementation of Schedule 75B.
Schedule 75B specifies the method for developing the Monthly Decoupling Deferral for
electric service. The reporting format for calculation of the monthly electric decoupling
deferral for 2020 is shown in Table 1-4 for Electric Residential and in Table 1-5 for
Electric Non-Residential.13 These one-month tables are included to introduce the format
and calculation steps used in the actual tables (Tables 1-6 for Electric Residential & 1-7
for Electric Non-Residential). In Table 1-6 and Table 1-7, the monthly decoupling
deferral amounts across 2020 sum to the annual total decoupling deferral for 2020. For
the electric residential group (Table 1-6), deferred revenue for 2020 is a refund to
customers of$810,734.14 In Table 1-7, deferred revenue for 2020 for the electric non-
residential group is a decoupling surcharge to customers of$10,452,475.15
The Schedule 75B calculation steps for Electric Residential follow. There are eight steps.
The sequence of the line numbers in Table 1-4 are keyed to the eight steps. Steps 1
through 5 are required to remove new customers (new hookups) from the calculation.
These steps apply to the short table (Table 1-4) and the full table (Table 1-5). The short
table is included to introduce the format used in the full table.
"Only one month(April 2020)is shown here to keep the table readable on the page.Full tables are
provided as Table 1-6(Electric Residential)and 1-7(Electric Non-Residential).
14 Table 1-5,Line 24,Balance.
15 Table 1-6,line 26,(Rebate/Surcharge)Balance.
1-11

Electric—Residential(Schedule 7513)
Step 1: Deduct new hookup customers.New hookup customers (Line 5) are deducted
from total actual number of customers (Line 1) to determine the actual number of test
year existing customers each month. The result(actual number of decoupled customers
after subtracting out new customers) is shown on Line 9.
Step 2: Calculate total Allowed Decoupled Revenue each month. This is calculated
by multiplying the number of Actual Customers after removing new customers (Line 9)
by the Monthly Decoupled Revenue per Customer(Line 10). The result is shown on Line
11, Decoupled Revenue.
Step 3: Deduct actual new hookup customer revenue from total actual revenue. This
determines the actual test year existing customer revenue collected in the applicable
month. To form this result, Actual Base Rate Revenue (Line 3) is adjusted by subtracting
New Customer Base Rate Revenue (Line 7). The result is shown on Line 12.
Step 4: Deduct actual new hookup customer fixed charge revenue from total actual
fixed charge revenue. Line 8,New Customer Basic Charge Revenue, is subtracted from
Line 4, Actual Basic Charge Revenue. The result, Actual Basic Charge Revenue (Test
Year Existing), is shown on Line 13.
Step 5: Deduct actual new hookup customer kWh sales from total actual kWh sales.
This is Line 2 (Actual Usage kWh)minus Line 6 (New Customer Usage (kWh). The
result is the Actual Usage (kWh)/Test Year Existing (Line 14) from which new customer
(new hookups) actual usage has been removed. Then, Actual Usage (kWh)/Test Year
Existing in Line 14 is multiplied by the approved Retail Revenue Credit (Line 15). The
result is the revenue collected related to the variable power supply (Variable Power
Supply Payments; Line 16). When Step 5 is completed, all quantities remaining in the
analysis have been adjusted to remove new customers (new hookups).
Step 6: Compute Customer Decoupled Payments. Actual Decoupled Revenue is
calculated by subtracting the Actual Basic Charge Revenue/Test Year Existing in Line 13
and the Variable Power Supply Payments (Line 16) from the Actual Base Rate
Revenue/Test Year Existing (Line 12). Customer Decoupled Payments is shown on Line
17.
1-12

Table 1-4: 2020 Electric Residential Deferral—Format.
Decoupling Mechanism-UE-170485 Base effective 5/1/2018,
Electric Residential
Development of WA Electric Deferrals(Calendar Year 2020)
Month
Line No. Source Apr-20
(a) (b) (f)
1 Actual Customers Revenue System 220,604
2 Actual Usage(kWhs) Revenue System 188,286,073
3 Actual Base Rate Revenue Revenue System $ 17,970,007
4 Actual Basic Charge Revenue Revenue System $ 2,021,544
5 New Customers Revenue System 3,261
6 New Customer Usage(kWhs) Revenue System 1,762,897
7 New Customer Base Rate Revenue Revenue System $ 175,571
8 New Customer Basic Charge Revenue Revenue System $ 29,574
9 Actual Customers/Test Year Existing (1)-(5) 217,343
10 Monthly Decoupled Revenue per Customer Attachment 3, Page 3 $55.20
11 Decoupled Revenue (9)x(10) $ 11,998,161
12 Actual Base Rate Revenue/Test Year Existing (3)-(7) $ 17,794,436
13 Actual Basic Charge Revenue/Test Year Existing (4)-(8) $ 1,991,970
14 Actual Usage(kWbs)/Test Year Existing (2)-(6) 186,523,176
15 Retail Revenue Credit($/kWh) Attachment 3,Page 1 $ 0.01895
16 Variable Power Supply Payments (14)x(15) $ 3,534,614
17 Customer Decoupled Payments (12)-(13)-(16) $ 12,267,852
18 Residential Revenue Per Customer Received (17)/(9) $56.44
19 Deferral-Surcharge(Rebate) (6)-(17) $ (269,691)
20 Deferral-Revenue Related Expenses Rev Conv Factor $ 11,966
21 FERC Rate 4.75%
22 Interest on Deferral Avg Balance Calc $ 8,255
23 Monthly Residential Deferral Totals $ (249,470)
24 Cumulative Deferral(Rebate)/Surcharge Balance E((19),(20),(22)) $ 1,957,141
As approved in Docket No.UE-190334,the Company is required to calculate decoupled revenue using YTD average customers,compare to what
was recorded using monthly customer counts,and record the difference in
December so that the annual decoupled revenue is based on YTD average customers.This amount includes that annual true-up that resulted in a
decrease to decoupled revenue of$10,366.26.
Step 7: Compute Balance to be Deferred by the Company as a Surcharge or as a
Rebate. The result (Deferral— Surcharge/Rebate) is shown on Line 19. It is computed in
Table 1-4 by subtracting Customer Decoupled Payments of$12,267,852 (Line 17) from
Decoupled Revenue of$11,998,161 (Line 11).16
16 Notation of source for Line 19,Deferral—Surcharge(Rebate)is shown as"(6)—(17)".This should be
"(11-17)";the calculation,however,is correct.
1-13

This amount is then adjusted for Revenue Related Expenses (Line 20) and for interest at
the FERC rate (FERC interest rate at Line 21 and interest at Line 22). The result is the
Monthly Electric Residential Deferral Total (Line 23).
These monthly amounts are then cumulated in Line 24. The Total Cumulative Deferral
(Rebate)/Surcharge Balance is tracked in Line 48. The total cumulative deferral for
Electric Residential is a rebate to customers of$810,734.17
Step 8: Comparison.At the end of every 12-month deferral period, the annual
decoupled revenue per customer, by rate group, is multiplied by the average annual
number of actual test year existing customers. The result of that calculation is compared
to the actual deferred revenue for the same 12-month period. The difference between the
actual deferred revenue, and the calculated value, is then added to, or subtracted from, the
total deferred balance by Rate Group. This calculation is shown in Table 1-8.
Electric—Non-Residential(Schedule 75B)
The Schedule 75B calculation for Electric Non-Residential steps follow. There are eight
steps. The sequence of the line numbers are keyed to the eight steps. Steps 1 through 5
are required to remove new customers (new hookups) from the calculation.
Stepl: Deduct new hookup customers.New hookup customers (Line 29) are deducted
from the total actual number of customers (Line 25) to determine the actual number of
test year existing customers each month. The result(actual number of customers after
subtracting out new customers) is in Line 33.
Step 2: Calculate total Allowed Decoupled Revenue each month. This is calculated
by multiplying the number of Actual Customers after removing new customers (Line 33)
by the Monthly Decoupled Revenue per Customer(Line 34). The result is shown on Line
35.
Step 3: Deduct actual new hookup customer revenue from total actual revenue. This
determines the actual test year existing customer revenue collected in the applicable
month. To form this result, Actual Base Rate Revenue (Line 27) is adjusted by
subtracting New Customer Base Rate Revenue (Line 31). The result is shown on Line 36.
17 Table 1-6,line 24,(Rebate/Surcharge)Balance,last column.
1-14

Step 4: Deduct actual new hookup customer fixed charge revenue from total actual
fixed charge revenue. Line 32,New Customer Basic Charge Revenue, is subtracted
from Line 28, Actual Basic Charge Revenue. The result, Actual Basic Charge Revenue
(Test Year Existing), is shown on Line 37.
Step 5: Deduct actual new hookup customer kWh sales from total actual kWh sales.
This is Line 26 (Total Actual kWh Sales) minus Line 30 (New Customer Usage (kWh).
The result is the Actual Usage (kWh) from which new customer actual usage has been
removed. The result is shown in Line 38. Then, Actual Usage (kWh) in Line 38 is
multiplied by the approved Retail Revenue Credit(Line 39). The result is the revenue
collected related to the variable power supply(Variable Power Supply Payments in Line
40). When Step 5 is completed, all remaining quantities have been adjusted to remove
new customers (new hookups).
Step 6: Compute Customer Decoupled Payments. Actual Decoupled Revenue is
calculated by subtracting the Actual Basic Charge Revenue (Test Year Existing) in Line
37 and the Variable Power Supply Payments (Line 40) from the Actual Base Rate
Revenue (Line 36) and is shown on Line 41.
Step 7: Compute Balance to be Deferred by the Company as a Surcharge or as a
Rebate. The Balance (for each month) is computed by subtracting Customer Decoupled
Payments (Line 41) from Decoupled Revenue (Line 35).18 The result (Deferral—
Surcharge/Rebate) is shown on Line 43. This amount is then adjusted for Revenue
Related Expenses (Line 44) and for interest at the FERC rate (Lines 44 and 45). The
result is the Monthly Non-Residential Deferral Total (Line 47). These monthly amounts
are cumulated in Line 48
Monthly Residential Deferral Total for each month is shown just below Line 12. This is
the difference between the Actual Decoupled Revenue (Step 6; Line 9) and the Allowed
Decoupled Revenue (Step 2; Line 3)plus any interest on the deferral.
The Total Cumulative Deferral (Rebate)/Surcharge Balance is tracked in Line 48. The
total cumulative deferral for Electric Non-Residential is a surcharge to customers of
$10,452,475.19
"In Table 1-5,the source for Line 43 is listed as(31)—(41).This should read(35)—(41).Although there
is an error in notation,the calculation is correct.Both notation and calculation are correct in Table 1-6,Line
43.
19 Table 1-6,line 26,(Rebate/Surcharge)Balance.
1-15

Table 1-5: 2020 Electric Non-Residential Deferral-Format.
Decoupling Mechanism-UE-170485 Base effective 5/1/2018,
Electric Non-Residential
Development of WA Electric Deferrals(Calendar Year 2020)
Month
Line No. Source Apr-20
(a) (b) (1)
Non-Residential Group
25 Actual Customers Revenue System 37,426
26 Actual Usage(kWhs) Revenue System 139,907,714
27 Actual Base Rate Revenue Revenue System $ 15,261,341
28 Actual Basic Charge Revenue Revenue System $ 1,726,758
29 New Customers Revenue System 873
30 New Customer Usage(kWhs) Revenue System 2,007,628
31 New Customer Base Rate Revenue Revenue System $ 238,432
32 New Customer Basic Charge Revenue Revenue System $ 33,333
33 Actual Customers/Test Year Existing (25)-(29) 36,553
34 Monthly Decoupled Revenue per Customer Attachment 3,Page 3 $33556
35 Decoupled Revenue (33)x(34) $ 12,265,725
36 Actual Base Rate Revenue/Test Year Existing (27)-(31) $ 15,022,910
37 Actual Basic Charge Revenue/Test Year Existing (28)-(32) $ 1,693,425
38 Actual Usage(kWhs)/Test Year Existing (26)-(30) 137,900,086
39 Retail Revenue Credit($/kWh) Attachment 3,Page 1 $ 0.01895
40 Variable Power Supply Payments (38)x(39) $ 2,613,207
41 Customer Decoupled Payments (36)-(37)-(40) $ 10,716,278
42 Non-Residential Revenue Per Customer Received (41)/(33) $293.17
43 Deferral-Surcharge(Rebate) (31)-(41) $ 1,549,340
44 Deferral-Revenue Related Expenses Rev Conv Factor $ (68,743)
45 FERC Rate 4.75%
46 Interest on Deferral Avg Balance Cale $ 8,689
47 Monthly Non-Residential Deferral Totals $ 1,489,286
48 Currnilative Deferral(Rebate)/Surcharge Balance £((43),(44),(46)) $ 2,944,081
49 Total Cumulative Deferral(Rebate)/Surcharge Balance $ 4,901,223
As approved in Docket No.UE-190334,the Company is required to calculate decoupled revenue using YTD average customers,
compare to what was recorded using monthly customer counts,and record the difference in
December so that the annual decoupled revenue is based on YTD average customers.This amount includes that annual true-up that
resulted in an increase to decouplcd revenue of$262.05.
Step 8: Comparison.At the end of every 12-month deferral period, the annual decoupled
revenue per customer,by rate group, will be multiplied by the average annual number of
actual test year existing customers. The results of that calculation will be compared to the
actual deferred revenue for the same 12-month period. The difference between the actual
deferred revenue and the calculated value will be added to, or subtracted from, the total
deferred balance by Rate Group. This calculation is shown in Table 1-8, and results in a
decrease of$10,366.26 for Residential; and an increase of$262.05 for Non-Residential.20
20 Table 1-8,Net increase/(decrease)to Decoupled Revenue due to Average Calculation(middle of Table for
Residential,bottom line for Non-Residential).
1-16

Table 1-6: 2020 Electric Decoupling-Residential.
Decoupling Mechanism-UE-170485 Base effective 5/1/2018,
UE-190334 Base effective 4/l/2020
Development of WA Electric Deferrals(Calendar Year 2020)
Line No. Source Jan-20 Feb-20 Mar-20 Apr-20 May-20 Jun-20 J.F20 Aug-20 Sep-20 Oct-20 Nov-20 D-20 Total
(a) (b) (e) (d) (e) (f) (9) (h) (1) (j) (k) (1) (m) (n) M
Resldenftal Group
1 Ac ICusemsrs Re-System 220,604 220,212 220,636 220,799 220,884 221,811 221,953 222,003 222,995
2 Ae-I Ueage(kWhs) Revenue System 188,286,073 159,744,333 155,578,204 190,128,187 205,649,832 168,829,432 173,706,610 230,501,382 274,711,064
3 Ae-I Base Rae Revenue Revenue System $ 17,970,007 $ 15,313,338 $ 15,206,666 $ 18,292,550 $ 20,121,070 $ 16,336,511 S 16,643,397 S 22,255,095 $ 26,944,369
4 Ae-I Basic Charge Revenue Revenue Sy- $ 2,021,544 $ 2,023,335 $ 2,043,423 S 2,040,597 $ 2,045,007 $ 2,041,983 S 2,038,977 S 2,036,844 $ 2,040,939
5 New Cmmmers Revenue System 3,261 3,380 3,544 3,916 4,199 4,652 4,942 5,251 5,437
6 New Custnmer Ueage(Mhs) Revenue System 1,762,897 1,373,083 1,398,479 1,613,174 2,155,535 2,320,559 2,018,639 3,258,945 4,691,916
7 New Customer Base Rate Revenue Revenue System $ 175,571 $ 144,960 $ 149,069 $ 169,826 $ 219,597 S 235,292 $ 211,411 $ 326,948 $ 464,626
8 New Customer Basic Charge Revenue Revenue System $ 29,574 $ 30,636 $ 32,742 $ 35,559 $ 37,701 $ 40,851 $ 44,244 $ 47,340 $ 48,843
9 Actual Cuetomem/Test Year Es0ng (11-0) 221,120 220,271 220,636 217,343 216,832 217,092 216,883 216,685 217,159 217,011 216,752 217,558 2,615,342
10 Mon0dy Decoupled Revenue per Customer A PIwnt3' $83.76 $67.85 $62.15 $55.20 $50.42 $48.03 $52.84 $61.70 $46.23 $51.24 $68.57 $86.79 r $735.32
ge
Il Decoupled Revenue (9)x(10) $ 18,521,106 $ 14,946,228 $ 13,711,791 $ 11,998,161 $ 10,933,097 $ 10,426,781 $ 11,459,637 S 13,370,263 S 10,040,141 S 11,119,340 S 14,861,953 $ 18,871,080 ' $ 160,259,577
12 Ae-I Base Rate Re,-/Teat Year Existing (3)-(7) $ 23,579,888 $ 20,630,118 $ 20,089,065 $ 17,794,436 $ 15,168,378 $ 15,057,597 $ 18,122,724 $ 19,901,473 $ 16,101,219 $ 16,431,986 $ 21,928,147 $ 26,479,743 $ 231,284,774
13 Actual Basic Charge Revenue/Test Year (4) (8) $ 2,025,764 $ 2,014,030 $ 2,024,532 $ 1,991970 $ 1,992,699 $ 2,010,681 $ 2,005,038 $ 2,007,306 $ 2,OO1,132 $ 1994,733 $ 1,989,504 $ 1992,096 $ 24,049,485
Existing
14 A-1 Ueage(M.)/Test Year Enfi g (2)-(6) 258,096,251 225,826,180 218,575,770 186,523,176 158,371,250 154,179,725 188,515,013 203,494,297 166,508,873 171,687971 227,242,537 270,019,148 2,429,040,190
15 Retail Revenue Cmdit(VkWh) Ad h-1 3,Page $ 0,01900 $ 0,01900 $ 0.01900 $ 0.01895 $ 0.01895 $ 0.01895 $ 0.01895 $ 0.01895 $ 0,01895 $ 0.01895 $ 0,01895 $ 0.01895
16 Variable Power Supply Payments (14)x(15) $ 4,903,829 $ 4,290,697 $ 4,152,940 $ 3,534,614 $ 3,001,135 $ 2,921,706 $ 3,572,359 $ 3,856,217 $ 3,155,343 $ 3,253,487 $ 4,306,246 $ 5,116,863 $ 46,065,437
17 C.W-r Decoupled Payments (12)-(13)-(16) $ 16,650,296 $ 14,325,391 $ 13,911,593 $ 12,267,852 $ 10,174,544 $ 10,125,210 $ 12,545,326 $ 14,037,950 $ 10,944,744 $ 11,183,766 $ 15,632,397 $ 19,370,784 $ 161,169,853
18 Residential R-no,Per Customer Received (17)/(9) $75.30 $65.04 $63.05 $56.44 546.92 $46.64 $57.84 $64.79 $50.40 $5L54 $72.12 $89.04 r $739.50
19 Def rW-Surcharge(Rebate) (11)-(17) $ 1,870,810 $ 620,838 $ (199,802)$ (269,691)$ 758,552 $ 301,570 $ (1,085,690)$ (667,687)$ (904,603)S (64,427)$ (770,444)$ (499,704) $ (910,276)
20 Defe-I-Revenue Related Expenses Rev Conv Factor $ (87,324)$ (29979)$ 9,326 $ 11966 $ (33,656)$ (13,380)S 48,171 $ 29,625 S 40,136 S 2,859 $ 34,184 $ 22,171 $ 35,098
21 FERC Rae 4.96% 4.96% 4.96% 4.75% 4.75% 4.75% 3.43% 3.43% 3.43% 3.25% 3.25% 3.25%
22 hnerest oo Deferral Avg BWance CWc $ 3,686 $ 8,610 $ 9,475 $ 8,225 $ 9,182 $ 11,223 $ 7,065 $ 4,691 $ 2,557 S 1,176 $ 99 $ 1,545 $ 64,443
23 Mnahly R.sW raial Deferral Totals $ 1,787,172 $ 600,469 $ (181,000)$ (249,500)$ 734,078 $ 299,413 S (1,030,453)$ (633,371)$ (861M9)S (60,392)S (736,162)$ (479,078) $ (810,734)
Cm dative Deferral(Rebate)Bmcharge
24 Balance 7((19),(20),(22)) $ 1,787,172 $ 2,387,641 $ 2,206,641 $ 1,957,141 $ 2,691,218 $ 2,990,632 S 1,960,178 $ 1,326,807 $ 464,897 $ 404,505 $ (331,657)
-As approved fu Docket No.UE-190334,the Company E required to Me lne de-pled revenue using Wit average cmt,m,,compare to what was recorded ad g monthly customer cowls,and record the differcnec in
December so that the annual de-pled reveooe is had oo WD averse enstoraers.This amount ineludes that annual true- that m,Wted in a decrease to decou ed reveooe of$10 366.26.
1-17

Table 1-7: 2020 Electric Decoupling-Non-Residential.
Decoupling Mechanism-UE-170485 Base effective 5/1/2018,
UE-190334 Base effective 4/1/2020
Development of WA Electric Deferrals(Calendar Year 2020)
Line No. Source J-20 Feb20 Mar-20 Apr-20 May-20 Jan-20 JUF20 Aug-20 Sep-20 Oct-20 Nov-20 Der-20 ImA
(a) (b) (o) (d) (e) (f) (9) (h) (1) fJ) (k) (1) (no (n)
Non-Reaklemlal Group
25 Actual Cusamers Revere System 37,426 37,036 37,925 37,616 37,401 37,679 37,795 37,724 37,949
26 Acual Usage(kWhs) Revenue System 139,907,714 148,830,839 164,045,166 185,995,405 181,437,975 172,570,197 186,445,471 152,188,443 168,250,485
27 Aomal Buse Rate Revenue Revenue System $ 15,261,341 $ 15,696,874 $ 17,336,325 $ 19,145,563 $ 18,905,149 $ 18,121,063 $ 19,453,895 $ 16,587,759 $ 17,769,454
28 Acual Basic Charge Revenue Revenue System $ 1,726,758 $ 1,720,550 $ 1,797,846 $ 1,757,369 $ 1,744,423 $ 1,745,238 $ 1,764,533 $ 1,718,318 $ 1,754,820
29 New Customers Revenue System 873 919 1,048 1,135 1,177 1,273 1,363 1,486 1,529
30 New Customer Usage(kWhs) Revenue System 2,007,628 1,811,961 2,179,064 2,350,154 3,078,900 4,524,953 4,003,265 4,655,162 5,333,626
31 New Customer Base Rate Revenue Revenue System $ 238,432 $ 230,638 $ 280,786 S 299,927 $ 367,967 $ 504,817 $ 507,503 $ 551,396 $ 612,911
32 New Customer Basic Charge Revenue Revenue System $ 33,333 $ 34,931 $ 41,255 S 39,311 $ 38,306 $ 42,245 $ 43,531 $ 47,938 $ 52,393
33 Ahasl Customsrs/Tst Year Existing (25)-(29) 37,482 37,041 37,523 36,553 36,117 36,877 36,481 36,224 36,406 36,432 36,238 36,420 439,794
34 Mombly Deaoupled Ravaas,per Customer Ahsoheem 3,Page $359.81 $336.86 $346.66 $335.56 $361.67 $376.01 $413.67 $396.88 $352.61 $379.63 $363.03 $358.52 $4,380,91
35 Decoopled Ravarom (33)x(34) S 13,486,278 $ 12,477,618 $ 13,007,853 $ 12,265,618 S 13,062,557 $ 13,866,018 $ 15,091,182 S 14,376,466 $ 12,837,137 $ 13,830,788 $ 13,155,503 S 13,057,563 ** $ 160,514,581
36 Acaal Base Rate P-ame/Test Year P savg (27)-(31) $ 18,011,842 $ 17,151,617 $ 17,206,940 $ 15,022,910 $ 15,466,236 S 17,055,539 $ 18,945,635 $ 18,537,281 $ 17,616,246 $ 18,946,392 $ 16,036,364 $ 17,156,543 $ 207,053,445
37 ACNal Basic Charge Rc-./Test Year (28)-(32) $ 1,711,699 $ 1,666,204 $ 1,699,799 $ 1,693,425 $ 1,685,619 $ 1,746,591 $ 1,718,059 $ 1,706,117 $ 1,702,993 $ 1,721,002 $ 1,670,380 $ 1,702,427 $ 20,424,3I4
E,sting
38 Ae-I Usage(kW6)/Test Year Existing (26)-(30) 179,782,076 168,654,118 169,349,462 137,900,086 147,018,878 161,866,102 183,645,251 178,359,075 168,045,244 182,442,206 147,533,281 162,916,858 1,987,512,637
39 Retail Revere Credit($/kWh) Attachnem 3,Page $ 0.01900 $ 0.01900 $ 0.01900 $ 0.01995 $ 0.01895 $ 0.01895 $ 0.01895 S 0.01895 $ 0.01895 $ 0.01895 $ 0.01895 $ 0.01995
40 Variable Power Supply Pay-. (38)x(39) $ 3,415,859 $ 3,204,428 $ 3,217,640 $ 2,613,207 $ 2,786,008 S 3,067,363 $ 3,480,078 $ 3,379904 $ 3,184,457 $ 3,457,280 $ 2,795,756 $ 3,087,274 $ 37,689,254
41 Cusmmer Decoupled Payments (36)-(37)-(40) $ 12,884,284 $ 12,280985 $ 12,289,401 $ 10,716,278 $ 10994,609 S 12,241,586 $ 13,647,499 $ 13,451,260 $ 12,728,796 $ 13,768,110 $ 11,570,228 $ 12,366,842 $ 148,939,878
Non-Residential Reverse Per Customer
42 Received (41)/(33) $343.75 $331.55 $327.52 $293.17 $304.42 $331.96 $374.10 $371.34 $349.63 $377.91 $319.28 $339.56 $4,06390
43 Deferral-Surchsrge(Rebate) (35)-(41) $ 601,994 $ 196,633 $ 718,452 $ 1,549,340 $ 2,067,948 $ 1,624,432 $ 1,443,683 $ 925,206 $ 108,341 $ 62,678 $ 1,585,275 $ 690,721 $ 11,574,703
44 Deferral-Revenue Related Expenses Rev Con,Factor $ (28,099)$ (9,179)$ (33,535)$ (68,743)$ (91,753)$ (72,074)$ (64,055)$ (41,050)$ (4,907)$ (2,781)$ (70,337)$ (30,647) $ (517,059)
45 FERC Rate 4.96% 4.96% 4.96% 4.75% 4.75% 4.75% 3.43% 3.43% 3.43%% 3.25% 3.25% 3.25%
46 Interest on Der I Avg Balare Cale $ 1,186 $ 2,764 $ 4,579 $ 8,689 $ 15,565 $ 22,610 $ 20,582 $ 23,876 $ 25,356 $ 24,315 $ 26,514 $ 29,531 $ 205,566
47 Monthly N-Residential Deferral Totals $ 575,081 $ 1901219 S 689,495 $ 1,489,286 $ 1,991,760 $ 1,574.968 $ 1,400,210 $ 908,032 $ 128,890 $ $4,212 $ 1,541,451 $ 699605 $ 11,263,209
C-a.,e Dcfcrral(Rebate)/Surcharge
48 Balance £((43),(44),(46))$ 575,081 $ 765,300 $ 1,454,795 $ 2944,082 $ 4935,842 $ 6,510,810 $ 7911,019 S 8,819,051 $ 8,947941 $ 9,032,153 $ 10,573,605 $ 11,263,209
Total Cammative Deferral! r
49 (Rebate)/Surcharge Belanee #REF? $ 2,362,253 $ 3,152942 $ 3,661,437 $ 4901,223 $ 7,627,060 $ 9,501,441 $ 9,871,198 S 10,145,858 $ 9,412,838 $ 9,436,658 $ 10,241,948 $ ]OA52,475
*-Aa approved yr Docket No.L L-110334,the Company is requhed to calemate de-pled revenue using VM avenge customera,compare to what was recorded uahrg monthly costorrer coons,sad record the difference to
Decemhersolost the annul dcroo,Ic d revenue E based on WD averaecustomen.This a--includes that arrl tme- that reauked to se to deco edrevenue of$262.05.
1-18

Table 1-8: 2020 Annual True-Up for Electric Residential and Electric Non-Residential.
Purpose:As required by UE-190334 (UE-190222, consolidated) paragraph 111, the Company is required to calculate decoupled
revenue using YTD average customers, compare to what was recorded using monthly customer counts,and record the
difference so thatthe annual decoupled revenue is based on YTD average customers.
Procedure:Separately for residential and non-residential, calculated YTD average decoupled (test year existing) customers and
multiplied that by the sum of decoupled revenue per customer by month to calculate total decoupled revenue for the
period based on YTD average customers(for 2020,the YTD was from April through December as the order was effective
4/1/2020). This was compared to the amount recorded using monthly decoupled customers and monthly decoupled
revenue per customer.The difference was recorded with the monthly decoupled revenue for December 2020.
Residential
Average Decoupled Customers(average of line 9 in Deferral Calc for April-Dec 2020) 217,035
Sum of Decoupled Revenue per Customer(sum of line 10 in Deferral Calc for April-Dec 2020) 521.02
Total Decoupled Revenue using Average Decoupled Customers $ 113,080,451.53
Less April-November Decoupled Revenue(sum of line 11 in Deferral Calcfor April-Nov 2020) 94,209,371.45
Decoupled Revenue to record for December to reflecttrue-up $ 18,871,080.08
December Decoupled Customers(line 9,column n in Deferral Calc) 217,558
December Decoupled Revenue per Customer(line 10,column n in Deferral Calc) $ 86.79
Total Decoupled Revenue for December using monthly decoupled customers $ 18,881,446.33
Net increase/(decrease)to Decoupled Revenue due to Average Calculation $ (10,366.26)
Non-Residential
Average Decoupled Customers(average of line 33 in Deferral Calc for April-Dec 2020) 36,416
Sum of Decoupled Revenue per Customer(sum of line 34 in Deferral Calc for April-Dec 2020) $ 3,337.58
Total Decoupled Revenue using Average Decoupled Customers $ 121,542,832.48
Less April-November Decoupled Revenue(sum of line 35 in Deferral Calc for April-Nov 2020) 108,485,269.60
Decoupled Revenue to record for December to reflect true-up $ 13,057,562.88
December Decoupled Customers(line 33,column n in Deferral Calc) 36,420
December Decoupled Revenue per Customer(line 34,column n in Deferral Calc) $ 358.52
Total Decoupled Revenue for December using monthly decoupled customers $ 13,057,300.82
Net increase/(decrease)to Decoupled Revenue due to Average Calculation $ 262.05
1-19

For Electric Residential service, the computations developed deferred revenue ($810,734) in
the rebate direction(Table 1-6, Line 23, Total Column and copied to Table 1-9, 2020
Deferred Revenue). For the annual decoupling filing, adjustments (Table 1-9), including a
Prior Year Carryover Balance of($210,964)plus other adjustments produced a final rebate
result of($1,112,391).21
Table 1-9: 2020 Electric Residential Group Rate Determination.
Residential Electric Service: Adjustments
2020 Deferred Revenue $ (810,734)
Add: Earnings Sharing/DSM Adjustment $
Add:Prior Year Carryover Balance $ (210,964)
Add: Interest through 7/31/2024 $ (31,835)
Add: Revenue Related Expense
A $ (58,858)
Adjustment
Total Requested Recovery $ (1,112,391)
Customer Surcharge Revenue $ (1,112,391)
Carryover Deferred Revenue $ -
For Non-Electric Residential service, the computations developed deferred revenue of
$11,260,209 in the surcharge direction(Table 1-6, Line 48, Cumulative Deferrals
(Rebate)/Surcharge Balance, Dec-20 Column, and copied to Table 1-10, 2020 Deferred
Revenue). For the annual decoupling filing, adjustments (Table 1-10), including a Prior Year
Carryover Balance of$2,433,164)plus other adjustments produced a Customer Surcharge
Revenue amount of$14,489,389 plus a Carryover Deferred Revenue amount of$271,257.22
21 Letter of Joe Miller, Senior Manager of Rates and Tariffs,Regulatory Affairs,Avista to Mark L.Johnson,
Executive Director and Secretary,Washington Utilities and Transportation Commission,Re: Tariff WN U-28,
Electric Service Electric Decoupling Rate Adjustment,May 26,2021,Page 2 of 6.
22 Letter of Joe Miller, Senior Manager of Rates and Tariffs,Regulatory Affairs,Avista to Mark L.Johnson,
Executive Director and Secretary,Washington Utilities and Transportation Commission,Re:Tariff WN U-28,
Electric Service Electric Decoupling Rate Adjustment,May 26,2021,Page 3 of 6.
1-20

Table 1-10: 2020 Electric Non-Residential Group Rate Determination.
Non-Residential Electric Service: Adjustments
2020 Deferred Revenue $ 11,263,209
Add: Earnings Sharing/DSM Adjustment $ -
Add: Prior Year Carryover Balance $ 2,433,164
Add: Interest through 7/31/2024 $ 445,414
Add: Revenue Related Expense Adjustment $ 618,839
Total Requested Recovery $ 14,760,626
Customer Surcharge Revenue $ 14,489,369
Carryover Deferred Revenue $ 271,257
Natural Gas Group I (Residential) and Group 2 (Non-Residential)
For natural gas Decoupled Revenue per Customer (by Rate Group) is developed following
the steps in Schedule 175A.23 Calculation of Decoupled Revenue per Customer is specified
in seven steps. These steps are implemented for Residential Customers in Table 1-9 and for
Non-Residential Customers in Table 1-10. Monthly Decoupled Revenue per Customer for
Group 1: Residential and Group 2: Non-Residential are then used to develop the Monthly
Decoupling Deferral for natural gas, following the steps in Schedule 175B.
Natural Gas Decouplinz Deferral(Schedule 175A)
Step 1: Determine the Total Normalized Revenue. The Total Normalized Revenue is
equal to the final approved base rate revenue approved in the Company's last general rate
case, individually for each rate schedule. Table 1-9, Line 1 shows initial Total Normalized
Net Revenue. In addition, Line 2 shows Allowed Revenue Decrease. The sum of Line 1 and
Line 2 is shown on Line 3 as the Allowed Base Rate Revenue.
Step 2: Determine Variable Gas Supply Revenue. The product of Normalized Therms
(Line 4) from the 2016 test year and PGA Rates (Line 5) is the Variable Gas Supply Revenue
(Line 6).
Step 3: Determine Delivery Revenue. To determine the Delivery Revenue, the Variable
Gas Supply Revenue (Line 6) is subtracted from the Total Normalized Revenue.
zs Avista Corporation,dba Avista Utilities, Schedule 175A,Decoupling Mechanism—Natural Gas,Issued June
12,2015,Effective August 1,2015.
1-21

Step 4: Remove Basic Charge Revenue. Step 4 is to calculate the Basic Charge Revenue.
Because the decoupling mechanism only tracks revenue that is included in the variable
portion of the rate, revenue already allocated to the fixed portion of the rate (customer
charge) is removed. Basic Charge Revenue is the product of the number of Customer Bills in
the 2016 test year(Line 8)times the Settlement Basic Charges (Line 9). The result, Basic
Charge Revenue, is shown on Line 10.24
Step 5: Determine Allowed Decoupled Revenue. The Allowed Decoupled Revenue is
equal to the Delivery Revenue (from Line 7) minus the Basic Charge Revenue (Line 10). The
resulting Decoupled Revenue is shown on Line 11.
Step 6: Determine the Allowed Decoupled Revenue per Customer. In Step 6, Decoupled
Revenue from Line 11 is put on a per customer basis. The Decoupled Revenue (by Rate
Group) is divided by the approved Rate Year number of customers (by Rate Group). This
determines the annual Allowed Decoupled Revenue per Customer(by Rate Group) as shown
in Table 1-10.
Step 7: Determine the Monthly Allowed Decoupled Revenue per Customer. This step
converts the annual Allowed Decoupled Revenue per Customer(by Rate Group) into
monthly values. The assignment of monthly values is carried out by modeling monthly therm
use in relation to the annual therm use for the rate year. This modeling is shown in Table
1-11.
In Table 1-11, the therm use for Group 1 (Residential) is shown in Line 4 and for Group 2
(Non-Residential) in Line 8. Both monthly therm values and the annual therm values are
shown. Below the monthly values,percentages (Lines 5 and 9) are shown. Lines 14 and 18
show the use of these percentages, applied to annual Allowed Decoupled Revenue per
Customer to generate monthly values.
These monthly values are then used in the implementation of Schedule 175B.
24 For natural gas minimum charges are treated like fixed charges.
1-22

(4)
Table 1-11. 2020 Development of Natural Gas Decoupled Revenue per Customer
Avista Utilities
Natural Gas Decoupling Mechanism
Development of Decoupled Revenue by Rate Schedule-Natural Gas
Washington Docket No.UG-170486 Compliance Filing
RESIDENTIAL GENERAL SVC. LG.GEN.SVC. INTERRUPTIBLE SCHEDULES SCHEDULES Schedule
TOTAL SCHEDULE 101/102 SCH.111/112/116 SCH.121/122/126 SCH 131 132 146&148 132
1 Total Normalized 12 ME Dec 2016 Revenue $ 88,831,000 $ 67,622,000 $ 15,462,000 $ 1,024,000 $ $ 190,000 $ 4,533,000 $ 190,000
2 Allowed Revenue Decrease(Attachment 2) $ (2,145,000) $ (1,663,000) $ (380,000) $ (25,000) $ $ (5,000) $ (72,000) $ (5,000)
3 Allowed Base Rate Revenue $ 86,686,000 $ 65,959,000 $ 15,082,000 $ 999,000 $ $ 185,000 $ 4,461,000 $ 185,000
4 Normalized Therms(12ME Dec 2016 Test Year) 252,141,683 119,446,617 47,951,720 4,115,331 901,267 79,726,748 901,267
5 Schedule 150 PGA Rates excluded from base rates $ - $ - $ - $ $ -
6 Variable Gas Supply Revenue $ - $ - $ - $ - $ $ -
7 Delivery Revenue (Ln 3-Ln 6) $ 82,040,000 $ 65,959,000 $ 15,082,000 $ 999,000 $ $ 185,000
8 Customer Bills(12ME Dec 2016 Test Year) 1,881,282 1,847,462 32,983 273 0 24 540 24
9 Allowed Basic/Minimum Charges $9.50 $97.25 $240.44 $0.00 $ -
10 Basic Charge Revenue(Ln 8*Ln 9) $ 20,824,126 $ 17,550,889 $ 3,207,597 $ 65,640 $ $ -
11 Decoupled Revenue $ 61,215,874 $ 48,408,111 $ 11,874,403 $ 933,360 $ Excluded From Decoupling $ 185,000
Residential Non-Residential Group
12 Average Number of Customers(Line 8/12) 153,955 2,771
13 Annual Therms 119,446,617 52,067,051
14 Basic Charge Revenues $ 17,550,889 $ 3,273,237
15 Customer Bills 1,847,462 33,256
16 Average Basic Charge $9.50 $98.43
Attachment 5,Page 1(UG-170486 Compliance Filing)
1-23

(4)
Table 1-12. 2020 Natural Gas Decoupled Revenue per Customer
Avista Utilities
Natural Gas Decoupling Mechanism
Development of Decoupled Revenue Per Customer-Natural Gas
Washington Docket No.UG-170486 Compliance Filing
Line No. Source Residential Non-Residential
Schedules* Schedules**
(a) (b) (c) (d)
1 Decoupled Revenues Attachment 5,Page 1 $ 48,408,111 $ 12,807,763
2 Test Year#of Customers 12 ME 12.2016 Revenue Data 153,955 2,771
3 Decoupled Revenue Per Customer (1)/(3) $ 314.43 $ 4,621.52
*Rate Schedules 101, 102.
**Rate Schedules 111, 112, 116, 121, 122, 126, 131.
Attachment 5, Page 2 (UG-170486 Compliance Filing)
Revenues
From Revenue Per Customer $ 48,408,123 $ 12,807,772
From Basic Charges $ 17,550,889 $ 3,273,237
From Gas Supply $ - $ -
Total $ 65,959,012 $ 16,081,009
1-24

Table 1-13. 2020 Development of Monthly Natural Gas Decoupled Revenue per Customer
Natural Gas Decoupling Mechanism
'Development of Monthly Decoupled Revenue Per Customer-Natural Gas
Washington Docket No.UG-170486 Compliance Filing
Line No. Source Jan Feb Mar Apr May Jan Jul Aug Sep Oct Nov Dec TOTAL
(a) (h) (c) (d) (c) (9) (h) (1) G) (k) (1) O (n) (o)
1
2 Natural Gas Delivery Volame
3 Residential*
4 -Weather-Normalized Therm Delivery Volume Monthly Rate Year 21,124,002 16,814,801 13,702,397 8,379,182 4,880,475 3,154,867 2,296,193 2,357,534 3,002,764 7,503,054 14,548,064 21,683,284 119,446,617
5 -%ofAnnual Total %of Total 17.68% 14.08% 11.47% 7.02% 4.09% 2.64% 1.92% 1.97% 2.51% 6.28% 12.18% 18.15% 100.00%
6
7 Non-Residential-
8 -weather-Normalized Thom Delivery Volume Monthly Rate Year 7,263,564 6,455,069 5,655,268 3,958,871 3,051,972 2,050,065 1,757,090 1,837,589 2,247,269 4,164,398 5,571,304 8,054,593 52,067,051
9 -%of Annual Total %of Total 13.95% 12.40% 10.86% 7.60% 5.86% 3.94% 3.37% 3.53% 4.32% 8.00% 10.70% 15.47% 100.00%
10
11 Monthly Decoupled Revenue Per Customer("RPC"')
12 Residential*
13 -UG-150205 Decoupled RPC Attachment 5,P.2 L 3 $ 314.43
14 -Monthly Decoupled RPC Qx(13) $ 55.61 $ 44.26 $ 36.07 $ 22.06 $ 12.85 $ 8.30 $ 6.04 $ 6.21 $ 7.90 $ 19.75 $ 38.30 $ 57.08 $ 314.43
15
16 Non-Residential-
17 -UG-150205 Decouph d RPC Attachment 5,P.2 L 3 $ 4,621.52
18 -MonthlyDecoupled RPC 0x(17) $ 644.72 $ 572.96 $ 501.97 $ 351.39 $ 270.90 $ 181.97 $ 155.96 $ 163.11 $ 199.47 $ 369.64 $ 494.51 $ 714.93 $ 4,621.52
19
20 *Rate Schedules 101,102.
21 **Rate Schedules 111,112,116,121,122,126,131,
Attachment 5,Page 2(UG-170486 Compliance Filing)
1-25

Natural Gas Monthly Decouplinz Deferral
Schedule 175B specifies the method for developing the Monthly Decoupling Deferral for
natural gas service. The calculation of the monthly natural gas decoupling deferral for 2020
is shown in Table 1-14 for Gas Residential and in Table 1-15 for Gas Non-Residential. The
monthly decoupling deferral amounts across 2020 sum to the annual total decoupling deferral
for 2020.
The Schedule 175B calculation steps for Natural Gas Residential follow. There are eight
steps. The sequence of the line numbers in Table 1-14 are keyed to the eight steps. Steps 1
through 5 are required to remove new customers (new hookups) from the calculation.
Natural Gas—Residential(Schedule 175B)
Step 1: Deduct new hookup customers.New hookup customers (Line 5) are deducted
from total actual number of customers (Line 1) to determine the actual number of test year
existing customers each month. The result (actual test year number of decoupled customers
after subtracting out new customers) is shown on Line 9.
Step 2: Calculate total Allowed Decoupled Revenue each month. This is calculated by
multiplying the number of Actual Customers after removing new customers (Line 9)by the
Monthly Decoupled Revenue per Customer(Line 10). The result is shown on Line 11,
Decoupled Revenue.
Step 3: Deduct actual new hookup customer revenue from total actual revenue. This
determines the actual test year existing customer revenue collected in the applicable month.
To form this result, Actual Base Rate Revenue (Line 3) is adjusted by subtracting New
Customer Base Rate Revenue (Line 7). The result is shown on Line 12.
Step 4: Deduct actual new hookup customer fixed charge revenue from total actual
fixed charge revenue. Line 8,New Customer Basic Charge Revenue, is subtracted from
Line 4, Actual Basic Charge Revenue. The result, Actual Basic Charge Revenue (Test Year
Existing), is shown on Line 13.
Step 5: Deduct actual new hookup customer kWh sales from total actual kWh sales.
This is Line 2 (Actual Usage kWh) minus Line 6 (New Customer Usage (kWh). The result is
the Actual Usage (kWh)/Test Year Existing (Line 14) from which new customer(new
hookups) actual usage has been removed. Then, Actual Usage (kWh)/Test Year Existing in
Line 14 is multiplied by the approved Retail Revenue Credit(Line 15). The result is the
revenue collected related to the variable power supply(Variable Power Supply Payments;
1-26

Line 16). When Step 5 is completed, all quantities remaining in the analysis have been
adjusted to remove new customers (new hookups).
Step 6: Compute Customer Decoupled Payments. Actual Decoupled Revenue is
calculated by subtracting the Actual Basic Charge Revenue/Test Year Existing in Line 13
and the Variable Power Supply Payments (Line 15) from the Actual Base Rate Revenue/Test
Year Existing (Line 12). Customer Decoupled Payments is shown on Line 17.
Step 7: Compute Balance to be Deferred by the Company as a Surcharge or as a
Rebate. The Balance (for each month) is computed by subtracting Customer Decoupled
Payments (Line 15) from Decoupled Revenue (Line 11).25 The result (Deferral—
Surcharge/Rebate) is shown on Line 19.
This amount is then adjusted for Revenue Related Expenses (Line 20) and for interest at the
FERC rate (FERC interest rate at Line 21 and interest at Line 22). The result is the Monthly
Electric Residential Deferral Total (Line 23).
These monthly amounts are then cumulated in Line 24. The Total Cumulative Deferral
(Rebate)/Surcharge Balance is tracked in Line 48. The total cumulative deferral for Natural
Gas Residential is a decoupling surcharge to customers of$1,174,438.21
Step 8: Comparison.At the end of every 12-month deferral period, the annual decoupled
revenue per customer,by rate group, is multiplied by the average annual number of actual
test year existing customers. The result of that calculation is compared to the actual deferred
revenue for the same 12-month period. The difference between the actual deferred revenue,
and the calculated value, is then added to, or subtracted from, the total deferred balance by
Rate Group. This calculation is shown in Table 1-12.
25 In Table 1-14,the source for Deferral-Surcharge(Rebate)is listed as(12)—(15). The source should be
corrected to(11)—(15). The calculated value,however,is correct.
26 Table 1-14,line 24,(Rebate/Surcharge)Balance,last column.
1-27

Table 1-14: 2020 Natural Gas Decoupling-Residential.
Decoupling Mechanism-UG-170486 Base effective 5/1/2018,
UG-190335 Base effective 4/1/2020
Development of WA Natural Gas Deferrals(Calendar Year 2020)
line No. Some Jan-20 Feb-20 Mar-20 Apr-20 May-20 J-20 J&20 Aug-20 Sep-20 Oct-20 Nov-20 Dec-20 Total
(a) (b) W (d) (e) (fl (8) (h) (i) (I) (k) (1) (n) (o)
Residential Group
1 Actual Customers Revenue System 167,876 167,226 168,009 168,008 167,867 168,830 168,858 168,988 169,632
2 Actual Usage("Therms) Revenue System 8,680,515 5,177,292 3,321,590 2,633,258 2,239,101 2,947,296 8,977,249 17,157,823 21,531,918
3 Actual Base Rate Revenue Revenue System S 5,252,399 $ 3,776195 $ 3,110,532 $ 2,761917 $ 2,607,616 $ 2,797,558 $ 5,409,453 $ 9,409,133 $ 11,826,570
4 Actual Fixed Charge Revenue Revenue System S 1,613,347 $ 1,609,140 $ 1,623,885 $ 1,623,370 $ 1,621,147 $ 1,628,022 $ 1,627,063 $ 1,625,840 $ 1,629,450
5 New Customers Revc-System 4,208 4,233 4,349 4,745 4,977 5,290 5,449 5,715 5,901
6 New Customer Usage(Therms) Revenue System 268,677 120936 82,419 54,756 35,744 44,185 100,287 370,194 614,291
7 New Customer Base Rate Revenue Revc-System S 153,301 $ 92,622 $ 77,767 $ 69,541 $ 62,486 $ 69,408 $ 94,795 $ 219,659 $ 343,301
8 New Customer Fixed Charge Revenue Revenue System $ 40,632 $ 41,054 $ 42,532 $ 45,847 $ 47,225 $ 50,372 $ 51,661 $ 54,543 $ 56,079
9 Actual/Test Year Existing CStstomers (I)-(5) 167,769 167,465 167,740 163,668 162993 163,660 163,263 162,890 163,540 163,409 163,273 163,731 1,973,401
10 Monthly Decoupled Revenue per Customer Attachment 4,Page 3 $55.61 544.26 $36.07 $27.53 $16.27 $8.72 $6.48 $6.25 $8.69 $24.18 $45.05 $63.77 $342.87
11 Decoupled Revenue (9)x(10) $ 9,329,063 $ 7,412,520 $ 6,050,389 $ 4,505,527 $ 2,652,551 $ 1,426,598 $ 1,057,715 $ 1,018,372 $ 1,421,151 $ 3,950,883 $ 7,355,157 $ 10,420,882 • $ 56,600,806
12 Act Usage/Test Year Existing (2)-(6) 19,902,225 18,156,995 16,737,084 8,411,838 5,056,357 3,239,171 2,578,501 2,203,357 2,803,112 8,876,962 16,787,629 20,917,527 125,670,758
Actaal Base Rate Revenue/Test Year
13 Existing (3)-(7) $ 11,069,164 $ 9,201,681 $ 8,457,284 $ 5,099,098 $ 3,683,872 $ 2,922,766 $ 2,692,396 $ 2,545,130 $ 2,728,150 $ 5,314,659 $ 9,189,474 $ 11,483,269 $ 74,386,943
Actual Fixed Charge Re-/Test Year
l4 Existing (4)-(8) $ 1,611,951 $ 1,607,724 $ 1,613,623 $ 1,572,716 $ 1,568,086 $ 1,581,354 $ 1,577,523 $ 1,573922 $ 1,577,650 $ 1,575,402 $ 1,571,297 $ 1,573,371 $ 19,004,616
15 Customer Decoupled Paymems (13)-(14) $ 9,457,214 $ 7,593,958 $ 6,843,662 $ 3,526,383 $ 2,115,787 $ 1,341,412 $ 1,114,873 $ 971,208 $ 1,150,500 $ 3,739,257 $ 7,618,177 $ 9,909,898 $ 55,382,328
to RasidetNal Revenue Per Customer Received (15)/(9) $56.37 545.35 $40.80 $21.55 $12.98 $8.20 $6.83 $5.96 $7.03 $22.88 $46.66 $60.53
17 Deferral-Surcharge(Rebate) (12)-(15) $ (128,150) $ (181,437) $ (793,272) $ 979,144 $ 536,764 $ 8505 $ (57,158)$ 47,164 $ 270,651 $ 211,626 $ (263,021)$ 510,984 $ 1,218,479
l8 Deferral-Revenue Related Experees Rev C.-Factor $ 5,955 $ 8,430 $ 36,859 $ (43,234)$ (23,701)$ (3,761)$ 2,524 $ (2,083)$ (11,951) $ (9,344)$ 11,614 $ (22,562) $ (51,254)
19 FERC Rate 4.96% 4.96% 4.96% 4.75% 4.75% 4.75% 3.43% 3.43% 3.43% 3.25% 3.25% 3.25%
20 Ivterest on Deferral Avg Balance Cal. $ (253) $ (864) $ (2,788) $ (2,326)$ 533 $ 1,711 $ 1,279 $ 1,269 $ 1,707 $ 2,246 $ 2,186 $ 2,50 $ 7,214
21 Monthly Residential Deferral Totals $ (122,449)$ (173,870) $ (759,201) $ 933,584 $ 513,596 $ 93,135 $ (53,355)$ 46,350 $ 260,407 $ 204,528 $ (249,221)$ 490934 S 1,174,438
22 C-adative De&rrel(Rebate)Balame E((17),(18),(20)) $ (122,449) $ (296,319) $ (1,055,520) $ (121,936)$ 391,661 $ 474,796 $ 421,441 $ 467,791 $ 728,198 $ 932,726 $ 683,504 $ 1,174,438
•As approved to Docket No.UG-190335,the Company is required to calculate deeoapled revenue using V rD average customers,compare to what was recorded using monthly customer counts,and record the difference in December so that the annual decoupled revenue is based on YID average
rnstome rs.This anreuut inrindes that aanaal t,a,-up that resulted is a decrease t.derou led reve nne of 519,742.07.
The result of these calculations is that for the gas residential group, deferred revenue for 2020 is decoupling surcharge of
$1,174,43827,
27 Table 1-14,Line 22,Cumulative Deferral(Rebate)/Surcharge Balance,Dec-20 Column.
1-28

Natural Gas—Non-Residential(Schedule 175B)
Schedule 175B calculation for Electric Non-Residential steps follow. There are eight steps.
The sequence of the line numbers are keyed to the eight steps. Steps 1 through 5 are required
to remove new customers (new hookups) from the calculation.
Stepl: Deduct new hookup customers.New hookup customers (Line 29) are deducted
from the total actual number of customers (Line 25) to determine the actual number of test
year existing customers each month. The result(actual number of customers after subtracting
out new customers) is in Line 33.
Step 2: Calculate total Allowed Decoupled Revenue each month. This is calculated by
multiplying the number of Actual Customers after removing new customers (Line 33)by the
Monthly Decoupled Revenue per Customer(Line 34). The result is shown on Line 35.
Step 3: Deduct actual new hookup customer revenue from total actual revenue. This
determines the actual test year existing customer revenue collected in the applicable month.
To form this result, Actual Base Rate Revenue (Line 27) is adjusted by subtracting New
Customer Base Rate Revenue (Line 31). The result is shown on Line 36.
Step 4: Deduct actual new hookup customer fixed charge revenue from total actual
fixed charge revenue. Line 32,New Customer Basic Charge Revenue, is subtracted from
Line 28, Actual Basic Charge Revenue. The result, Actual Basic Charge Revenue (Test Year
Existing), is shown on Line 37.
Step 5: Deduct actual new hookup customer kWh sales from total actual kWh sales.
This is Line 26 (Total Actual kWh Sales) minus Line 30 (New Customer Usage (kWh). The
result is the Actual Usage (kWh) from which new customer actual usage has been removed.
The result is shown in Line 38. Then, Actual Usage (kWh) in Line 38 is multiplied by the
approved Retail Revenue Credit (Line 39). The result is the revenue collected related to the
variable power supply (Variable Power Supply Payments in Line 40). When Step 5 is
completed, all remaining quantities have been adjusted to remove new customers (new
hookups).
Step 6: Compute Customer Decoupled Payments. Actual Decoupled Revenue is
calculated by subtracting the Actual Basic Charge Revenue (Test Year Existing) in Line 37
1-29

and the Variable Power Supply Payments (Line 40) from the Actual Base Rate Revenue
(Line 36) and is shown on Line 41.
Step 7: Compute Balance to be Deferred by the Company as a Surcharge or as a
Rebate. The Balance (for each month) is computed by subtracting Customer Decoupled
Payments (Line 41) from Decoupled Revenue (Line 35). The result(Deferral—
Surcharge/Rebate) is shown on Line 43. This amount is then adjusted for Revenue Related
Expenses (Line 44) and for interest at the FERC rate (Lines 44 and 45). The result is the
Monthly Non-Residential Deferral Total (Line 47). These monthly amounts are cumulated in
Line 48
Monthly Residential Deferral Total for each month is shown just below Line 12. This is the
difference between the Actual Decoupled Revenue (Step 6; Line 9) and the Allowed
Decoupled Revenue (Step 2; Line 3)plus any interest on the deferral. The Total Cumulative
Deferral (Rebate)/Surcharge Balance is tracked in Line 48. The total cumulative deferral for
Natural Gas Non-Residential is a surcharge to customers of$11,263,209.28
Step 8: Comparison.At the end of every 12-month deferral period, the annual decoupled
revenue per customer, by rate group, will be multiplied by the average annual number of
actual test year existing customers. The results of that calculation will be compared to the
actual deferred revenue for the same 12-month period. The difference between the actual
deferred revenue and the calculated value will be added to, or subtracted from, the total
deferred balance by Rate Group. This calculation is shown in Table 1-16, and results in a
decrease of$19,742.07 for the Residential Group and a decrease of$12,689.42 for the Non-
Residential Group.29
26 Table 1-15,line 48,Cumulative Deferral(Rebate/Surcharge)Balance.
29 Table 1-16,Net increase(decrease)to Decoupled Revenue due to Average Calculation(middle of table for
Residential;bottom line for Non-Residential).
1-30

Table 1-1 S: 2020 Natural Gas Decoupling-Non-Residential.
Decrupling Mechanism-UG-170486 Base effective 511/2018,
UG-190335 Base effective 4/l/2020
Develgp rent of WA Natural Gas Deferrals(Calendar Year 2020)
Line No. Source Jao-20 Feb20 Maz 20 Apr-20 May-20 Juo-20 du420 Aug-20 Sep-20 Oct-20 Nov-20 Dec-20 Tn[al
(a) (b) (c) (d) (c) (0 (9) (h) () 6) (k) (1) (v0 () t�)
Non-Residential Group
23 Actual Customers Revenue System 3,153 3,122 3,159: 3,148 3,122 3,151 3,156: 3,158 3,173
24 Actual Usage("Therms) Reverwe System 3,634,382 2,904,968 1,882,576 1,780,378 1,674,515 2,068,491 4,988,126 5,823,340 7,851,509
25 Actual lual Ban Rate Reveuue Revenue System $ 1,271,852 $ 1,057,694 $ 769,948 i$ 753,247 $ 745,621 $ 839,523 $ 1,642,483 i$ 1,906,840 $ 2,470,331
26 Actual Fixed Charge Revenue Revenue System $ 322,894 $ 336,113 $ 340,494 $ 339,112 $ 336,676 $ 340,191 $ 340,207 $ 339,539 $ 341,752
27 New Customers Revenue System 41 38 38 i 38 42 37 36 i 44 42
28 New Customer Usage(Therms) Revenue System 108,540 55,253 35,573 22,680 15,266 17,847 28,994 73,866 142,469
29 New Customer Base Rate Revenue Reveue,System $ 32,149 $ 18,348 $ 13,156 i$ 9,775 $ 7,889 $ 8,345 $ 11,208 i$ 23,820 $ 41,807
30 New Customer Fixed Charge Revemte Revenue System $ 4,090 $ 3,928 $ 4,109i$ 4,087 $ 4,252 $ 3,980 $ 3,829i$ 3,860 $ 4,510
31 Test Year Existing Customers (23)-(27) 3,142 3,158 i 3,147 3,112 3,084 3,121 i 3,110 3,080 3,114 3,120 i 3,114 3,131 37,433
32 Monthly Decoupled Revenue per Customers Attachment S,Page 3 $644.72 $572.96i $50L97 $402.99 $292.00 $212.46i $153.39 $167.80 $199.69 $364.00: $552.49 $675.30 $4,739,76
33 Decmquled Rcvcvue (31)x(32) $ 2,025,712 $ 1,809,401 i$ 1,579,690 $ 1,254,106 $ 900,513 $ 663,088 i$ 477,029 $ 516,836 $ 621,830 $ 1,135,675 i$ 1,720,466 $ 2,101,686 ** $ 14,806,033
34 Actual Usage,(Therms)/Test Year Existing i (24)-(28) 8,048,135 7,886,250i 7,168,311 3,525,842 2,849,715 1,847,002i 1,757,698 1,659,248 2,050,644 4,959,132i 5,749,475 7,709,040 55,210,492
Actual Base Rate Revenue/Test Year
35 Existing (25)-(29) $ 2,616,090 $ 2,269,383 i$ 2,087,429 $ 1,239,703 $ 1,039,346 $ 756,791 i$ 743,471 $ 737,732 $ 831,177 $ 1,631,275 i$ 1,883,020 $ 2,428,524 $ 18,263,942
Actin Fixed Charge Revenue/Test Yeaz
36 (26)-(30) $ 306,762 $ 308,694 i$ 307,626 $ 318,804 $ 332,186 $ 336,385 i$ 335,025 $ 332,424 $ 336,211 $ 336,378 i$ 335,679 $ 337,242 $ 3,923,415
Existing
__37 Customer Decoupled Parmeuts________ �352_536�_____$ 2,309,327 $ 1,960,689 $ 1,779,803 $ 92Q899 $ 707,160 $ 420,406 $ 408,447 $ 405,308 $ 494,966 $ 1,294,897 $ 1,547,342 $ 2,09LAE $ 14,340,526
_ i_____ _________________________�_____________________________________________________ ______________________________a_____________________________________________
38 Nov-Residential Revetme Per Customer Recd. (37)/(31) $734.99 $620.86i 1565,56 $295.92 $229.30 $134.70: $131.33 $131.59 $158.95 $415.03: $496.90 $667.93
39 Dclistal-Surcharge(Rebate) (33)-(37) $ (283,615) $ (151,287)i$ (200,113) $ 333,207 $ 193,352 $ 242,682 i$ 68,582 $ 111,528 $ 126,864 $ (159,222)i$ 173,124 $ 10,404 $ 465,506
40 Defrral-R-case Related Epenses Rev Coca,Factor $ 13,178 $ 7,030:$ 9,298 $ (14,713) $ (8,537) $ (10,716):$ (3:028)$ (4,925)$ (5,602) $ 7,030:$ (7,644)$ (459) $ (19,088)
41 FERC Rate 4.96% 4.96%i 4.96% 4.75% 4.75% 4.75%i 3.43% 3.43% 3,43% 3.25%i 3,25% 3.25%
42 Interest on Deferral Avg Balance Cale $ (559) $ (1,418):$ (2,117) $ (1,783) $ (794) $ 28:$ 446 $ 693 $ 1,021 $ 928:$ 948 $ 1,189 $ (1,418)
43 Monthly N-Reaidcalial Deferral Totals i $ (270,996) $ (145,676)i$ (192'9'1) S 316,712 $ 184,021 $ 231,9941$ 65,999 $ 107,297 $ 122,293 $ (151,264)1$ 166,428 $ 11,133 $ 445,001
44 Cmrwlatve Deferral(Rebate)Balance L((39),(40),(42)) $ (270,996) $ (416,672)�$ (609,603) $ (292,892) $ (108,870) $ 123,124 $ 189,124 $ 296,420 $ 418,703 $ 267,439 $ 433,867 $ 445,001
45 Total Cumulative Defcrral(Rchate) (22)+(44) $ (393,444) $ (712,991)!$ (1,665,123) $ (414,827) $ 282,791 $ 597,920 $ 610,564 $ 764,211 $ 1,146,901 $ 1,200,165 $ 1,117,372 $ 1,619,4 99
**As approved in Docket No.UG-190335,ithe Company is required to calculate decoupled revenue using VrD average customs ,conjinre to what was recorded using monthly customer counts,and record the difference in December so that the annual decoupled revenue is based on YFD average
customers.This amount includes that annual true-u that resuked in a decrease[o decou led revenue of$
2 689.42.
The result of these calculations for the natural gas Non-Residential group is a decoupling surcharge to customers of$445,001.'o
30 Table 1-15,Line 48,Cumulative Deferral(Rebate) Surcharge Balance,Dec-20 Column.
1-31

Table 1-16: 2020 Annual December True-Up for Gas Residential and Non-Residential.
Purpose:As required by UG-190335 (UE-190222, consolidated) paragraph 111, the Company is required to calculate decoupled
revenue using YTD average customers, compare to what was recorded using monthly customer counts,and record the
difference so that the annual decoupled revenue is based on YTD average customers.
Procedure:Separately for residential and non-residential, calculated YTD average decoupled (test year existing) customers and
multiplied that by the sum of decoupled revenue per customer by month to calculate total decoupled revenue for the
period based on YTD average customers(for 2020,the YTD was from April through December as the order was effective
4/1/2020). This was compared to the amount recorded using monthly decoupled customers and monthly decoupled
revenue per customer.The difference was recorded with the monthly decoupled revenue for December 2020.
Residential
Average Decoupled Customers(average of line 9 in Deferral Calc for April-Dec 2020) 163,381
Sum of Decoupled Revenue per Customer(sum of line 10 in Deferral Calc for April-Dec 2020) $ 206.93
Total Decoupled Revenue using Average Decoupled Customers $ 33,808,833.58
Less April-November Decoupled Revenue(sum of line 11 in Deferral Calc for April-Nov 2020) 23,387,952.06
Decoupled Revenue to record for December to reflect true-up $ 10,420,881.52
December Decoupled Customers(line 9,column n in Deferral Calc) 163,731
December Decoupled Revenue per Customer(line 10,column n in Deferral Calc) $ 63.77
Total Decoupled Revenue for December using monthly decoupled customers $ 10,440,623.59
Net increase/(decrease)to Decoupled Revenue due to Average Calculation $ (19,742.07)
Non-Residential
Average Decoupled Customers(average of line 33 in Deferral Calc for April-Dec 2020) 3,110
Sum of Decoupled Revenue per Customer(sum of line 34 in Deferral Calc for April-Dec 2020) $ 3,020.12
Total Decoupled Revenue using Average Decoupled Customers $ 9,391,229.07
Less April-November Decoupled Revenue(sum of line 35 in Deferral Calc for April-Nov 2020) 7,289,542.62
Decoupled Revenue to record for December to reflect true-up $ 2,101,686.45
December Decoupled Customers(line 33,column n in Deferral Calc) 3,131
December Decoupled Revenue per Customer(line 34,column n in Deferral Calc) $ 675.30
Total Decoupled Revenue for December using monthly decoupled customers $ 2,114,375.87
Net increase/(decrease)to Decoupled Revenue due to Average Calculation $ (12,689.42)
1-32

The result of these calculations is that for the gas Residential Group, deferred revenue for
2020 is in the surcharge direction with a decoupling surcharge of$1,174,43831
Adjustments, conveyed in the annual filing, result in a final Residential surcharge of
$1,256,386, including a prior year carryover offset of($13,216) and other adjustments
(Table 1-15).32
Table 1-17: 2020 Natural Gas Residential Group Rate Determination.
Residential Natural Gas Service: Adjustments
2020 Deferred Revenue $ 1,174,438
Add: Earnings Sharing/DSM Adjustment $ -
Add:Prior Year Carryover Balance $ (13,216)
Add: Interest through 7/31/2024 $ 40,677
Add: Revenue Related Expense Adjustment $ 54,487
Total Requested Recovery $ 1,256,386
Customer Surcharge Revenue $ 801,749
Carryover Deferred Revenue $For the natural gas Non-Residential group, deferred revenue is in the surcharge direction
with a decoupling surcharge to customers of$445,001.33 Adjustments, conveyed in the
annual filing, result in a final Non-Residential surcharge of$494,874 (Table 1-18).34,35
Table 1-18: 2020 Natural Gas Non-Residential Rate Determination.
Non-Residential Natural Gas Service: Adjustments
2020 Deferred Revenue $ 445,001
Add: Earnings Sharin SM Adjustment $ -
Add:Prior Year Carryover Balance $ 12,745
Add: Interest through 7/31/2024 $ 15,564
Add: Revenue Related Expense Adjustment $ 21,563
Total Requested Recovery $ 494,873
Customer Surcharge Revenue $ 494,873
Carryover Deferred Revenue $ -
31 Table 1-14,Line 22,Cumulative Deferral(Rebate)/Surcharge Balance,Dec-20 Column
32 Letter,re: Tariff WN U-29,Natural Gas Service Decoupling Rate Adjustment from Joe Miller,Avista
Senior Manager for Rates and Tariffs,Regulatory Affairs to Mark L.Johnson,Executive Director and
Secretary,Washington Utilities and Transportation Commission dated May 26,2021,P.2 of 5.
33 Table 1-15,Line 48,Cumulative Deferral(Rebate) Surcharge Balance,Dec-20 Column.
34 Letter,re: Tariff WN U-29,Natural Gas Service Decoupling Rate Adjustment from Joe Miller,Avista
Senior Manager for Rates and Tariffs,Regulatory Affairs to Mark L.Johnson,Executive Director and
Secretary,Washington Utilities and Transportation Commission dated May 26,2021,P.2 of 5.
35 Total Requested Recovery in Table 1-16 is off by one dollar,due to a rounding difference.
1-33

Earnings Test 2020
The decoupling mechanism, in Schedules 75D and 175D,provides for application of an
earnings test, separately for electric service and for natural gas.
Schedule 75D—Electric Earnings Test
According to Schedule 75D, the decoupling mechanism for Electric is subject to an
annual earnings test based on the Company's year-end Commission Basis Reports that
reflect actual decoupling-related revenues and various normalizing adjustments. As
shown in Table 1-19, Line 3, the calculated rate of return on a normalized36 basis in 2020
is 6.39%. This is lower than the Base rate of return authorized, so there are no Excess
Earnings (Line 6).
Table 1-19. 2020 Electric Earnings Test.
2020 Commission Basis Earnings Test for Decoupling
Line No. Electric
1 Rate Base $ 1,700,977,000
2 Net Income $ 108,650,000
3 Calculated ROR 6.39%
4 Base ROR Pro-rated 7.28%
5 Excess ROR -0.89%
6 Excess Earnings $ -
7 Conversion Factor 0.75605u
8 Excess Revenue (Excess Earnings/CF) $ -
9 Sharing% 50%
10 2020 Total Earnings Test Sharing $ -
Since the normalized return is less than the allowed return, the Earnings Test has no
effect for electric customers for 2020.
16"Normalized"in this context means normalized to the commission basis earnings test(it does not refer to
weather normalization,a different use of the same term).
1-34

Schedule 175D—Natural Gas Earnings Test
According to Schedule 175D, the decoupling mechanism for natural gas is subject to an
annual earnings test based on the Company's year-end Commission Basis Reports that
reflect actual decoupling-related revenues and various normalizing adjustments. As
shown in Table 1-16, the rate of return on a normalized basis in 2020 is 6.08%. This is
less than the allowed return. Since the normalized return is less than the allowed return,
the Earnings Test has no effect for natural gas customers for 2020.
Table 1-20: 2020 Natural Gas Earnings Test.
2020 Commission Basis Earnings Test for Decoupling
Line No. Natural Gas
1 Rate Base $ 410,952,000
2 Net Income $ 24,969,000
3 Calculated ROR 6.08%
4 Base ROR Pro-rated 7.28%
5 Excess ROR -1.21%
6 Excess Earnings $ -
7 Conversion Factor _
8 Excess Revenue (Excess Earnings/CF) $ -
9 Sharing% 50%
10 2019 Total Earnings Test Sharing $ -
Three Percent Annual Rate Increase Limitation 2020
Decoupling annual rate adjustment surcharges are subject to a 3% annual rate increase
limitation (there is no reciprocal limit on rebate rate adjustments). The test is to divide the
incremental annual revenue to be collected (proposed surcharge revenue minus present
surcharge revenue)by the total"normalized"revenue for the two Rate Groups for the
most recent January through December.
Normalized revenue is determined by multiplying the weather-corrected usage for the
period by the present rates in effect. If the incremental amount of the proposed surcharge
exceeds 3%, only a 3% incremental rate increase will apply. Any remaining deferred
revenue will be carried over to the following years.
1-35

Schedule 75E—Electric 3% Rate Increase Test
The Electric Incremental Surcharge Test is shown in Table 1-17. Specifications for the
test limit the surcharge to 3%, with any remainder deferred to the following year. For
Residential customers, the result for the Incremental Decoupling Recovery Rate is
negative (Line 7), so there is no Carryover Deferred Revenue.
For Non-Residential customers, the Incremental Surcharge result is 3.14% (Line 7),
which is 0.14% above the 3% limit. Accordingly, the Adjusted Incremental Surcharge for
Non-Residential Electric is set at 3% (Line 12) and there is Carryover Deferred Revenue
for Non-Residential Electric. Following adjustments specified in the letter of Joe Miller,
Senior Manager of Rates and Tariffs, Regulatory Affairs, Avista to Mark L. Johnson,
Executive Director and Secretary, Washington Utilities and Transportation Commission
of May 26, 2021, Table on Page 3 of 6, the Carryover is $271.257.
Table 1-21: 2020 Electric 3%Annual Rate Increase Limitation.
3%Incremental Surcharge Test
Line No. Residential Non-Residential
1 Revenue From 2020 Normalized Loads and Customers at
Present Billing Rates(Note 1) $ 239,238,066 $ 223,195,803
2 August 2021-July 2022 Usage(kWhs) 2,471,980,588 2,133,927,654
3 Proposed Decoupling Recovery Rates -$0.00045 $0.00693
4 Present Decoupling Surcharge Recovery Rates $0.00244 $0.00365
5 Incremental Decoupling Recovery Rates -$0.00289 $0.00328
6 Incremental Decoupling Recovery $ (7,144,024) $ 6,999,283
7 Incremental Surcharge% -2.99% 3.14%
8 3%Test Adjustment(Notes 2) $ - $ (303,409)
9 3%Test Rate Adjustment $0.00000 -$0.00014
10 Adjusted Proposed Decoupling Recovery Rates -$0.00045 $0.00679
11 Adjusted Incremental Decoupling Recovery $ (7,144,024) $ 6,700,533
12 Adjusted Incremental Surcharge% -2.99% 3.00%
Notes
(1) Revenue from 2020 normalized loads and customers at present billing rates effective since April
1,2021.
(2) The carryover balances will differ from the 3%adjustment amounts due to the revenue related
expense gross up partially offset by additional interest on the outstanding balance during the
amortization period.
1-36

Schedule 175E—Natural Gas 3% Rate Increase Test
The Natural Gas Incremental Surcharge Test is shown in Table 1-18. The test limits the
Residential and the Non-Residential Surcharge each to 3%. For both the Residential and
the Non-Residential Groups, the incremental surcharge is below 3% (Line 7), so there is
no Carryover Deferred Revenue amount(Line 8) to be to be deferred to the following
year.
Table 1-22. 2020 Natural Gas 3%Rate Increase Limitation.
3%Incremental Surcharge Test
Line No. Residential Non-Residential
Revenue From 2020 Normalized Loads and
1 Customers at Present Billing Rates(Note 1) $ 123,149,739 $ 34,857,536
2 August 2021-July 2022 Usage 135,825,505 60,870,053
3 Proposed Decoupling Recovery Rates $0.00925 $0.00813
4 Present Decoupling Surcharge Recovery Rates(2) $0.00000 $0.00419
5 Incremental Decoupling Recovery Rates $0.00925 $0.00394
6 Incremental Decoupling Recovery $ 1,256,386 $ 239,828
7 Incremental Surcharge% 1.02% 0.69%
8 3%Test Adjustment(3) $ - $ -
9 3%Test Rate Adjustment $0.00000 $0.00000
10 Adjusted Proposed Decoupling Recovery Rates $0.00925 $0.00813
11 Adjusted Incremental Decoupling Recovery $ 1,256,386 $ 239,828
12 Adjusted Incremental Surcharge% 1.02% 0.69%
Notes
(1) Revenue from 2020 normalized loads and customers at present billing rates effective
since April 1,2021.
(2) As stated on tariff Sheet 175E,the reversal of a rebate rate is not included in the 3%
incremental surcharge test.Therefore the Residential Group rebate of-$0.00685 is$0.00000
in this incremental rate calculation.
(3) The carryover balances will differ from the 3%adjustment amounts due to the revenue
related expense gross up partially offset by additional interest on the outstanding balance
during the amortization period.
1-37

2021 Decoupling Mechanism - Electric (Schedule 75) and Natural Gas
(Schedule 175)
In this section, as specified in Schedule 75 and Schedule 175, calculations were carried
out separately and in parallel for Residential and Non-Residential accounts. For each of
these groups of accounts, the sum of monthly deferral amounts over calendar year 2021 is
the cumulative deferral (rebate or surcharge).
Electric Group I (Residential) and Group 2 (Non Residential)
Schedule 75A is used to develop the Decoupled Revenue per Customer. Schedule 75B
uses the results from Schedule 75A to develop the Monthly Decoupling Deferral. There
are seven calculation steps in Schedule 75A and there are eight calculation steps in
Schedule 75B. These are developed in this subsection of the report. Results for Schedule
75A for both Electric Residential and Electric Non-Residential customers are shown in
Tables 1-23 through 1-25. Results for Schedule 75B are shown separately for Electric
Residential customers in Table 1-26 and for Electric Non-Residential customers in Table
1-27.37
Electric Residential Decoupled Revenue per Customer(Schedule 75A)
Calculation of Decoupled Revenue per Customer for Electric Residential and Electric
Non-Residential is specified in seven steps in Schedule 75A. These steps are
implemented in Tables 1-23, 1-24 and 1-25.
Step l: Determine the Total Normalized Revenue.
Total Normalized Revenue is equal to the final approved base rate revenue approved in
the Company's last general rate case, individually for each Rate Schedule. Table 1-23,
Line 1 shows initial Total Normalized Net Revenue. In Line 2 the Allowed Revenue
Increase is shown. The sum of Line 1 and Line 2 is the Allowed Base Rate Revenue or
Total Normalized Revenue. Note that the results for Line 1 are used, going forward, only
for the individual decoupled schedules. Values in the Total column for Lines 1-6 are not
used since they include results for non-decoupled schedules.
Step 2: Determine the Variable Power Supply Revenue.
This value is shown on Line 6 and is the product of Normalized kWh on Line 4 and
Retail Revenue Credit from Line 5. Values in the Total column for Lines 1-6 are not used
since they include results for non-decoupled schedules.
37 Tables in this subsection are attachments or parts of attachments to the Electric Decoupling Rate
Adjustment filing of May 27,2022.
1-38

Table 1-23: 2021 Development of Electric Decoupled Revenue per Customer.
Electric Decoupling Mechanism
Development of Decoupled Revenue by Rate Schedule-Electric
Washington Docket No.UE-190334 Compliance Filing
RESIDENTIAL GENERAL SVC. LG.GEN.SVC, PUMPING EX LG GEN SVC ST&AREA LTG
TOTAL SCHEDULE 1,2 SCH.11,12 SCH.21,22 SCH.30,31,32 SCHEDULE 25 SCH.41-48
1 Total Normalized 12ME Dec 2018 Revenue $ 502,020,000 $ 216,075,000 $ 75,061,000 $ 125,677,000 $ 12,039,000 $ 66,744,000 $ 6,424,000
2 Allowed Revenue Increase(Attachment l) $ 28,500,000 $ 14,579,000 $ 2,131,000 $ 7,135,000 $ 684,000 $ 3,789,000 $ 182,000
3 Allowed Base Rate Revenue $ 530,520,000 $ 230,654,000 $ 77,192,000 $ 132,812,000 $ 12,723,000 $ 70,533,000 $ 6,606,000
4 Normalized kWhs(12ME Dec 2018 Test Year) 5,637,842,826 2,374,703,689 619,305,952 1,365,904,624 145,822,517 1,113,564,012 18,542,032
5 Retail Revenue Adjustment(line 14) $ 0.01995 $ 0.01895 $ 0.01895 $ 0.01895 $ 0.01895 $ 0.01895 $ 0.01995
6 Variable Power Supply Revenue(L4°L5) $ 106,837,122 $ 45,000,635 $ 11,735,848 $ 25,883,893 $ 2,763,337 $ 21,102,038 $ 351,372
7 Delivery&Power Plant Revenue(L3-L6) $ 367,997,288 $ 185,653,365 $ 65,456,152 $ 106,928,107 $ 9,959,663
8 Customer Bills(12ME Dec 2018 Test Year) 3,027,008 2,587,975 386,800 22,787 29,446
9 Allowed Basic Charges $ 9.00 $ 20.00 $ 550.00 $ 20.00
10 Basic Charge Revenue(Ln 8'Ln 9) $ 44,149,545 $ 23,291,775 $ 7,736,000 $ 12,532,850 $ 588,920
11 Decoupled Revenue $ 323,847,743 $ 162,361,590 $ 57,720,152 $ 94,395,257 $ 9,370,743 Excluded From Decouplmg
12 Retail Revenue Adjustment-(UE-170485 ERM Base $0.01811
13 Gross Up Factor for Revenue Related Exp 104.64%
14 Grossed Up Retail Revenue Adjustment $0.01895
Residential Non-Residential Group
15 Average Number of Customers(Line 8/12) 215,665 36,586
16 Annual kWh 2,374,703,689 2,131,033:093
17 Basic Charge Revenues 23,291,775 20,857,770
18 Customer Bills 2,587,975 439,033
19 Average Basic Charge $9.00 $47.51
Step 3: Determine Delivery and Power Plant Revenue.
For the decoupled schedules only, subtract Variable Power Supply Revenue (Line 6)
from the Total Normalized Revenue (Line 3) and enter results on Line 7. Beginning with
Line 7, values in the Total column are valid for decoupling.
Step 4: Remove Basic Charge Revenue.
Because the decoupling mechanism only tracks revenue that varies with customer energy
usage, revenue directly recovered from Fixed Charges is removed in this step. Basic
Charge Revenue is shown on Line 10. It is the product of the number of Customer Bills
(2018 Test Year) on Line 8 times the Allowed Basic Charge (Line 9).38
Step 5: Determine Decoupled Revenue.
Decoupled Revenue is equal to the Delivery and Power Plant Revenue (Step 3; Line 7)
minus the Basic Charge Revenue (Step 4; Line 10). Decoupled Revenue is shown on
Line 11.
38 Basic charge includes minimum charge revenue for non-residential customers.
1-39

Step 6: Determine Decoupled Revenue per Customer.
In this step, Decoupled Revenue from Line 11 is put on a per customer basis. The
Decoupled Revenue is divided by the approved Rate Year number of customers (by Rate
Group). This determines the annual Allowed Decoupled Revenue per Customer.
Table 1-24: 2021 Electric Decoupled Revenue per Customer.
Avista Utilities
Electric Decoupling Mechanism
Development of Annual Decoupled Revenue Per Customer-Electric
Washington Docket No.UE-190334 Compliance Filing
Line No. Source Residential Non-Residential
Schedules-
(a) (b) (c) (d)
1 Decoupled Revenues Attachment 4,Page 1 $ 162,361,590 $ 161,486,153
2 Revenue Data 215,665 36,586
Test Year 9 of Customers 12 ME 12.2018
3 (1)/(2) $ 752.84 $ 4,413.88
Decoupled Revenue per Customer
*Schedules 11,12,21,22,31,32.
Attachment 4,Page 2
Revenues
From revenue per customer $ 162,361,239 $ 161,486,214
From basic charge $ 23,291,775 $ 20,857,770
From power supply $ 45,000,635 $ 40,383,077
Total $ 230,653,649 $ 222,727,061
Step 7: Determine the Monthly Decoupled Revenue per Customer.
Step 7 converts the annual Allowed Decoupled Revenue per Customer(by Rate Group)
into monthly values. The assignment of monthly values is carried out by modeling
monthly kWh use (by Rate Group) in relationship to the annual kWh use for the rate year.
This modeling is shown in Table 1-21. Kilowatt hours (kWh) for Group 1 (Residential)
for 2020 are shown in Line 3 and for Group 2 (Non-Residential) in Line 6. Both monthly
values and the annual kWh value are shown. Below the monthly values (Lines 4 and 7)
monthly percentages are shown. Lines 11 and 14 show the use of these percentages,
applied to annual Allowed Decoupled Revenue per Customer(by Rate Group) to
generate monthly values. Table 1-215shows the monthly results for both Electric
Residential and Electric Non-Residential decoupling.
The monthly values developed following the steps in Schedule 75A are then used in the
implementation of Schedule 75B.
1-40

Table 1-25: 2021 Development of Monthly Electric Decoupled Revenue per Customer.
Avista utilities
Electric Decoupling Mechanism
Development of Monthly Decoupled Revenue Per Customer-Electric
Washington Docket No.UE-190334 Compliance Filing
Source Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee TOTAL
(a) (b) (c) (d) (e) (f) (9) (h) O O (k) (1) (n) (o)
Electric Sales
Residential
-Weather-Normalized kWh Sales Montbly Test Year 292,945,712 209,125,084 229,152,606 174,130,864 159,047,393 151,500,182 166,667,943 194,633,617 145,837,334 161,623,305 216,281,572 273,758,077 2,374,703,689
-
%ofAnnal Total %of Total 12.34% 8.81% 9.65% 7.33% 6.70% 6.38% 7.02% 8.20% 6.14% 6.81% 9.11% 11.53% 100.00%
Non-Residential•
-Weather-Normalized kWh Sales Montlily Test Year 176,964,441 175,619,317 167,056,292 162,007,860 174,616,873 181,537,287 199,722,134 191,613,197 170,241,283 183,287,817 175,272,145 173,094,449 2,131,033,094
-
%of Annual Total %of Total 8.30% 8.24% 7.84% 7.60% 8.19% 8.52% 9.37% 8.99% 7.99% 8.60% 8.22% 8.12% 100.00%
Monthly Decouoled Revenue Per Customer("RPC")
Residential
-UE-170485 Decoupled RPC Abael—ft 4,P.2 L.3 $ 752.84
-Monthly Decoupled RPC (4)x(10) $ 92.87 $ 66.30 $ 72.65 $ 55.20 $ 50.42 $ 48.03 $ 52.84 $ 61.70 $ 46.23 S 51.24 $ 68.57 $ 86.79 $ 752.94
Non-Residential*
-UE-170485 Decoupled RPC Attachment 4,P.2 L 3 $ 4,413.98
-Montldy Decoupled RPC (7)x(13) $ 366.54 $ 363.75 $ 346.01 $ 335.56 $ 361.67 $ 376.01 $ 413.67 $ 396.88 $ 352.61 S 379.63 $ 363.03 $ 358.52 $ 4,413.88
*Schedt lea I1,12,21,22,31,32.
1-41

Schedule 75B—Electric Monthly Decoupling Deferral
Schedule 75B specifies the method for developing the Monthly Decoupling Deferral for
electric service. The calculation of the monthly electric decoupling deferral for 2021 is
shown in Table 1-26 for Electric Residential and in Table 1-27 for Electric Non-
Residential. The monthly decoupling deferral amounts across 2021 sum to the annual
total decoupling deferral for 2021. The result of these calculations is that for the electric
residential group, deferred revenue for 2021 is a refund to customers of$5,123,505,39 and
for the electric non-residential group a surcharge of$2,389,111.40 However, for the
electric residential group, adjustments result in a final customer rebate of$5,801,102.41
For the electric non-residential group, adjustments result in a final Customer Surcharge
Revenue of$2,747,724.42
Schedule 75B calculation for Electric Residential follows. There are eight steps. The
sequence of the line numbers in Table 1-22 are keyed to the eight steps. Steps 1 through 5
are required to remove new customers (new hookups) from the calculation.
Electric—Residential(Schedule 75B)
Step 1: Deduct new hookup customers.New hookup customers (Line 5) are deducted
from total actual number of customers (Line 1) to determine the actual number of test
year existing customers each month. The result(actual number of decoupled customers
after subtracting out new customers) is shown on Line 5.
Step 2: Calculate total Allowed Decoupled Revenue each month. This is calculated
by multiplying the number of Actual Customers after removing new customers (Line 5)
by the Monthly Decoupled Revenue per Customer(Line 10). The result is shown on Line
11, Decoupled Revenue.
Step 3: Deduct actual new hookup customer revenue from total actual revenue. This
determines the actual test year existing customer revenue collected in the applicable
month. To form this result, Actual Base Rate Revenue (Line 12) is adjusted by
subtracting New Customer Base Rate Revenue (Line 7). The result is shown in Line 8.
"Table 1-26,Line 24,Cumulative Deferral(Rebate)/Surcharge Balance.
4'Table 1-27,Line 48,Cumulative Deferral(Rebate)/Surcharge)Balance.
4' Letter,re: Tariff WN U-28,Electric Service Electric Decoupling Rate Adjustment from Joe Miller,
Avista Senior Manager for Rates and Tariffs,Regulatory Affairs to Amanda Maxwell,Executive Director
and Secretary,Washington Utilities and Transportation Commission dated May 27,2022,P.2 of 5.
42 Letter,re: Tariff WN U-28,Electric Service Electric Decoupling Rate Adjustment from Joe Miller,
Avista Senior Manager for Rates and Tariffs,Regulatory Affairs to Amanda Maxwell,Executive Director
and Secretary,Washington Utilities and Transportation Commission dated May 27,2022,P. 3 of 5
1-42

Step 4: Deduct actual new hookup customer fixed charge revenue from total actual
fixed charge revenue. Line 8,New Customer Basic Charge Revenue, is subtracted from
Line 4, Actual Basic Charge Revenue. The result, Actual Basic Charge Revenue/Test
Year Existing, is shown on Line 13.
Step 5: Deduct actual new hookup customer kWh sales from total actual kWh sales.
This is Line 2 (Actual Usage kWh)minus Line 6 (New Customer Usage (kWh). The
result is the Actual Usage (kWh)/Test Year Existing (Line 14) from which new customer
(new hookups) actual usage has been removed. Then, Actual Usage (kWh)/Test Year
Existing in Line 14 is multiplied by the approved Retail Revenue Credit(Line 15). The
result is the revenue collected related to the variable power supply (Variable Power
Supply Payments; Line 16). When Step 5 is completed, all quantities remaining in the
analysis have been adjusted to remove new customers (new hookups).
Step 6: Compute Customer Decoupled Payments. Actual Decoupled Revenue is
calculated by subtracting the Actual Basic Charge Revenue/Test Year Existing (Line 13
and the Variable Power Supply Payments (Line 16) from the Actual Base Rate
Revenue/Test Year Existing (Line 12). Customer Decoupled Payments is shown in Line
17.
Step 7: Compute Balance to be Deferred by the Company as a Surcharge or as a
Rebate. The Balance (for each month) is computed by subtracting Customer Decoupled
Payments (Line 17) from Decoupled Revenue (Line 11). The result(Deferral—
Surcharge/Rebate) is shown on Line 19.
This amount is then adjusted for Revenue Related Expenses (Line 20) and for interest at
the FERC rate (FERC interest rate at Line 21 and interest at Line 22). The result is the
Monthly Electric -Residential Deferral Totals (Line 23).
These monthly amounts are then cumulated in Line 24 to compute the Cumulative
Deferral (Rebate)/Surcharge Balance for the Electric Residential Group. The Cumulative
Deferral (Rebate)/Surcharge Balance for Electric-Residential is a rebate to customers of
$5,123,505.43 As noted earlier, adjustments included in the letter filing the rate resulted
in a final value of$5,801,102.44
41 Table 1-22,line 24,Cumulative Deferral(Rebate)/Surcharge)Balance,last column.
44 See footnote 31.
1-43

Step 8: Comparison.At the end of every 12-month deferral period, the annual
decoupled revenue per customer, by rate group, is multiplied by the average annual
number of actual test year existing customers. The result of that calculation is compared
to the actual deferred revenue for the same 12-month period. The difference between the
actual deferred revenue, and the calculated value, is then added to, or subtracted from, the
total deferred balance by Rate Group. This calculation is shown in Table 1-28.
1-44

Table 1-26: 2021 Electric Decoupling-Residential.
Avista Utilities
Decoupling Mechanism
UE-190334 Base effective 4/l/2020&UE-200900 Base Effective 10/1/2021
Development of WA Electric Deferrals(Calendar Year 2021)
Rcviscd Revised Rcviscd
Line No. Source Jan-21 Reb21 M-21 Apr-21 May-21 Jun-21 Jol-21 Aug-21 Sep21 Oct-21 Nov-21 Dea-21 Total
(a) (b) (c) (d) (e) (f) (9) (h) W 0) (k) (1) (m) (n) (a)
Residential Group
1 Actual Customers Revenue System 223,405 223,405 223,405 224,063 223,629 223,770 223,958 224,348 224,617 224,905 224,968 225,556
2 Actual Usage(M,) Revenue System 252,707,036 243,176,802 230,221,468 175,211,847 165,160,581 195,418,248 252,257,937 213,300,859 155,388,557 169,159,242 211,413,739 279,622,692
3 Actual Base Rare Revenue Revemre System $ 24,708,907 $ 23,717,932 $ 22,449,787 $ 16,836,457 $ 16,000,581 $ 18,670,121 $ 24,243,886 $ 21,043,709 $ 15,128,317 $ 17,003,721 $ 21,339,119 $ 28,454,380
4 Actual Basic Charge Revenue Revenue System $ 1910,628 $ 1922,490 $ 2,292,716 $ 2,050,768 $ 2,051,037 $ 2,069,712 $ 2,064,231 $ 2,077,094 $ 2,063,601 $ 2,065,050 $ 2,064,460 $ 2,066,931
5 New Cu.-. Revenue System 5,722 5,532 6,496 6,344 6,547 6,971 7,080 7,337 7,567 5,338 5,530 5942
6 New Costumer Usage(Mrs) Revenue System 5,453,471 5,273,613 5,258,143 3,904,551 3,133,924 3,339,318 4,816,736 4,770,441 3,912,316 2,285,907 3,300,094 5,140,312
7 New Customer Base Rote Revenue Revenue System $ 539,229 $ 521,280 $ 522,512 $ 389,461 $ 319,982 $ 340,620 $ 475,648 $ 471,102 $ 394,480 $ 242,626 $ 346,305 $ 532,153
8 New Customer Basic Charge Revenue Revenue System $ 51,707 $ 49,923 $ 58,349 $ 57,206 $ 58,889 $ 62,748 $ 63,749 $ 65,997 $ 68,031 $ 48,006 $ 49,788 $ 53,325
9 Actual Customers/Test Year Existing (1)-(5) 217,683 217,873 216,909 217,719 217,082 216,799 216,878 217,011 217,050 219,567 219,438 219,614 2,613,623
10 Mmably N-pled Revenue per C..- Athwhaeui 3' $92.87 $66.30 $72.65 $55.20 $50.42 $48.03 $52.84 $61.70 $46.23 $61.82 $78.34 $100.31 $787.18
Page 3
11 Decoupled Revenue (9)x(10) $ 20,216,451 $ 14,444,510 $ 15,757,802 $ 12,018,917 $ 10,945,702 $ 10,412,708 $ 11,459,372 $ 13,390,379 $ 10,035,101 $ 13,574,134 $ 17,190,676 $ 22,003,863 * $ 171,449,615
12 Actual Base Rate Reveoac/Test Year Eistng (3)-(7) $ 24,169,678 $ 23,196,653 $ 21,927,275 S 16,446,996 $ 15,680,599 $ 18,329,501 $ 23,768,239 $ 20,572,607 $ 14,733,836 $ 16,761,095 $ 20,992,813 $ 27,922,227 $ 244,501,520
13 Actual Basic Charge Reveaue/Test Year (4) (8) $ 1,858,921 $ 1,872,567 $ 2,234,367 S 1993,562 $ 1,992,148 $ 2,006,964 $ 2,000,482 $ 2,011,097 $ 1,995,570 $ 2,017,044 $ 2,014,672 $ 2,013,606 $ 24,011,000
Existing
14 Achul Usage(kWbs)/Test Year Esaag (2)-(6) 247,253,565 237903,189 224963,326 171,307,296 162,026,657 192,079,931 247,441,200 208,530,417 151,476,241 166,873,335 208,113,644 274,482,380 2,492,451,183
15 Retail Revenue Credit($/kWh) Attach-1 3,Pop $ 0.01895 $ 0.01895 $ 0.01895 S 0.01895 $ 0.01895 $ 0.01895 $ 0,01895 $ 0.01895 $ 0.01995 $ 0.01360 $ 0.01360 $ 0.01360
16 Variable Power Supply Pay- (14)x(15) $ 4,685,455 S 4,508,265 $ 4,263,055 S 3,246,273 $ 3,070,405 S 3,639,915 $ 4,689,011 $ 3,951,651 $ 2,870,475 $ 2,269,477 $ 2,830,346 $ 3,732,960 $ 43,757:289
17 Customer DecoWlcd Pay- (12)-(13)-(16) $ 17,625,302 S 16,815,820 $ 15,429,853 S 11,207,161 $ 10,618,046 $ 12,682,622 $ 17,078,746 $ 14,609,859 $ 9,867,792 $ 12,474,574 $ 16,147,796 $ 22,175,661 $ 176,733232
18 Residential Revenue Per Clts-Received (17)/(9) $80.97 $77.18 $71.14 $51.48 $48.91 $58.50 $78.75 $6732 $45.46 $56.81 $73.59 $100.98 $811.44
19 DekrrA-Smcharge(Rebate) (11)-(17) $ 2,591,149 $ (2,371,311)$ 327,949 $ 811,756 $ 327,656 $ (2,269,914)$ (5,619,374)S (1,219,480)$ 167,310 $ 1,099,560 $ 1,042,880 $ (171,797) $ (5283,617)
20 Deferral-Rcvewe Related Expenses Rev Cow Factor $ (114,967)$ 105,213 $ (14,551)S (36,017)$ (14,538)$ 100,714 $ 249,326 $ 54,107 $ (7,423)$ (48,305)$ (45,815)S 7,547 $ 235,291
21 FERC Rate 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3.25%
22 hderest on Defemal Avg Balace We $ 3,353 S 3,647 $ 1,012 $ 2,490 $ 3971 $ 1,468 $ (8,737)$ (17,611)$ (19,020)$ (17,431)$ (14,705)$ (13,617) $ (75,179)
23 Monday ReAdeuital Deferral Totals $ 2,479,536 $ (2,262,451)$ 314,410 $ 778,229 $ 317,089 $ (2,167,732)$ (5,378,785)$ (1,182,984)8 140,866 $ 1,033,823 $ 982,360 $ (177,867) $ (5,123,505)
Cnmaaavc Defml(Rebate)/Sorcharge
24 Balance £((19),(20),(22)) $ 2,479,536 $ 217,084 $ 531,495 $ 1,309,724 S 1,626,813 $ (540,918)S (5,919,703)$ (7,102,687)$ (6,961,820)$ (5,927,997)$ (4,945,638)
*-As approved to Docket No.UE-190334,the Covpany is required to Men ate decoupled revenue using YTD average custonem,compare to what was recorded ad g monthly customer cowls,aad record the difference to
December so that the annual decoupled revenue is based on WD average customers.This amount inclodes that annual true-up that resulted in a decrease to decoupled reveoue of$24,965.05.
1-45

Electric—Non-Residential(Schedule 75B)
The Schedule 75B calculation for Electric Non-Residential steps follow. There are eight
steps. The sequence of the line numbers in Table 1-23 are keyed to the eight steps. Steps
1 through 5 are required to remove new customers (new hookups) from the calculation.
Stepl: Deduct new hookup customers.New hookup customers (Line 29) are deducted
from the total actual number of customers (Line 25) to determine the actual number of
test year existing customers each month. The result(actual number of customers after
subtracting out new customers) is in Line 33.
Step 2: Calculate total Allowed Decoupled Revenue each month. This is calculated
by multiplying the number of Actual Customers after removing new customers (Line 33)
by the Monthly Decoupled Revenue per Customer(Line 34). The result is shown on Line
35.
Step 3: Deduct actual new hookup customer revenue from total actual revenue. This
determines the actual test year existing customer revenue collected in the applicable
month. To form this result, Actual Base Rate Revenue (Line 27) is adjusted by
subtracting New Customer Base Rate Revenue (Line 31). The result is shown on Line 36.
Step 4: Deduct actual new hookup customer fixed charge revenue from total actual
fixed charge revenue. Line 32,New Customer Basic Charge Revenue, is subtracted
from Line 28, Actual Basic Charge Revenue. The result, Actual Basic Charge Revenue
(Test Year Existing), is shown on Line 37.
Step 5: Deduct actual new hookup customer kWh sales from total actual kWh sales.
This is Line 26 (Total Actual kWh Sales) minus Line 30 (New Customer Usage (kWh).
The result is the Actual Usage (kWh) from which new customer actual usage has been
removed. The result is shown in Line 38. Then, Actual Usage (kWh) in Line 38 is
multiplied by the approved Retail Revenue Credit (Line 39). The result is the revenue
collected related to the variable power supply(Variable Power Supply Payments in Line
40). When Step 5 is completed, all remaining quantities have been adjusted to remove
new customers (new hookups).
Step 6: Compute Customer Decoupled Payments. Actual Decoupled Revenue is
calculated by subtracting the Actual Basic Charge Revenue (Test Year Existing) in Line
1-46

AN
37 and the Variable Power Supply Payments (Line 40) from the Actual Base Rate
Revenue (Line 36) and is shown on Line 41.
Step 7: Compute Balance to be Deferred by the Company as a Surcharge or as a
Rebate. The Balance (for each month) is computed by subtracting Customer Decoupled
Payments (Line 41) from Decoupled Revenue (Line 35). The result(Deferral—
Surcharge/Rebate) is shown on Line 43. This amount is then adjusted for Revenue
Related Expenses (Line 44) and for interest at the FERC rate (Lines 45 and 46). The
result is the Monthly Non-Residential Deferral Total (Line 47). These monthly amounts
are cumulated in Line 48.
Monthly Non-Residential Deferral Total for each month is shown just below Line 12.
This is the difference between the Actual Decoupled Revenue (Step 6; Line 9) and the
Allowed Decoupled Revenue (Step 2; Line 3)plus any interest on the deferral. The Total
Cumulative Deferral (Rebate)/Surcharge Balance is tracked in Line 48. The total
cumulative deferral for Electric Non-Residential is a surcharge to customers of
$2,389,111.4' This result is subject to adjustment.
Step 8: Comparison.At the end of every 12-month deferral period, the annual
decoupled revenue per customer, by rate group, will be multiplied by the average annual
number of actual test year existing customers. The results of that calculation will be
compared to the actual deferred revenue for the same 12-month period. The difference
between the actual deferred revenue and the calculated value will be added to, or
subtracted from, the total deferred balance by Rate Group. This calculation is shown in
Table 1-8, and results in a decrease of$24,965.05 for Residential; and an increase of
$406.83 for Non-Residential.41
45 Table 1-23, line 48,Total Cumulative Deferral(Rebate)/Surcharge)Balance,last column.
46 Table 1-8,Net increase/(decrease)to Decoupled Revenue due to Average Calculation(middle of Table
for Residential,bottom line for Non-Residential).
1-47

Table 1-27: 2021 Electric Decoupling-Non-Residential.
Avie[a Utilities
Decoupling Mechanism
UE-190334 Base effective 4/l/2020&UE-200900 Base Effective 10/1/2021
Development of WA Electric Deferrals(Calendar Year 2021)
Revised Revised Revised
Line No. Source J-21 Feh-21 M-21 Apr-21 May-21 Jun-21 Jal-21 Aug-21 Sep21 Oct-21 Nov-21 D..21 Total
(a) N (e) (d) e) (n (9) (h) (1) 0) (k) m > ) (e)
Non-Resideofial Group
25 Actual Cus-. Revema;System 37,888 37,888 37,888 38,020 37,820 38,221 38,142 38,125 38,161 38,317 38,098 38,370
26 Actual Usage(M.) Revere System 166,909,354 157,727,108 168,214,115 155,684,619 177,821,928 208,606,878 203,985,723 197,901,981 177,337,033 175,624,228 164,220,212 183,526,968
27 Actal Base Rate Revenue Revere System $ 17,448,084 $ 16,763,031 $ 18,238,873 $ 16,657,934 $ 18,676,991 $ 21,340,727 $ 21,029,491 $ 20,469,420 $ 18,597,954 $ 18,846,990 $ 17,834,276 $ 19,526,738
28 Actal Basic Charge Revenue Revere System $ 1,673,037 $ 1,627,814 $ 1,944,698 $ 1,770,531 $ 1,719,333 $ 1,749,355 $ 1,734,734 $ 1,712,436 $ 1,715,536 $ 1,717,925 $ 1,702,423 $ 1,700,077
29 New Cusmmers Revemw System 1,622 1,562 1,805 1,771 1,932 2,007 2,090 2,187 2,190 1,754 1,809 1,885
30 New Cusmmer Usage(k%h) Revewe System 6,267,128 5,493,508 6,239,854 5,228,133 4,910,750 6,230,698 6,242,989 7,306,694 6,780,553 4,854,698 6,655,678 6,497,568
31 New Cusmmer Base Rate Revenue Revema;System $ 708,442 $ 630,898 S 710,227 $ 619,053 S 602,106 S 718,199 $ 729,397 $ 837,328 S 788,169 $ 574,823 $ 747,171 $ 742,227
32 New Customer Basic Charge It- Revalue System $ 54,938 $ 50,447 $ 57,119 $ 55,943 $ 63,565 $ 63,212 $ 67,756 $ 74,043 $ 71,428 $ 54,963 $ 58,272 $ 56,901
33 Actual Cusmmem/Test Year Eaisfiog (25)-(29) 36,266 36,326 36,083 36,249 35,888 36,214 36,052 35,938 35,971 36,563 36,289 36,485 434,324
34 M-Wy Dewupled Re..m per Customer Aaech ant 3,Page $366.54 $363.75 $346.01 $335.56 $361.67 $376.01 $413.67 $396.88 $352.61 $420.52 $365.86 $403.51 S4,502.58
35 DecoupIM Revemte (33).(34) $ 13,292,785 $ 13,213,571 $ 12,485,209 $ 12,163,609 $ 12,979,734 $ 13,616,725 $ 14,913,717 $ 14,262,960 $ 12,683,751 $ 15,375,376 $ 13,276,554 $ 14,722,601 ** $ 162,986,590
36 Actual Base Rate Revemre/Test Year Ei,fig (27)-(31) $ 16,739,642 $ 16,132,133 $ 17,528,645 $ 16,038,881 $ 18,074,885 $ 20,622,528 $ 20,300,094 $ 19,632,092 $ 17,809,784 $ 18,272,166 $ 17,087,105 $ 18,784,511 $ 217,022,467
37 Actual Basic Charge Revenu/Test Year (28).(32) $ 1,618,099 $ 1,577,367 $ 1,887,579 S 1,714,587 S 1,655,768 S 1,686,143 $ 1,666,978 $ 1,638,392 S 1,644,108 $ 1,662,962 $ 1,644,151 $ 1,643,176 $ 20,039,310
Existing
38 A-I Usage(k%h)/Teat Year DdA g (26)-(30) 160,642,227 152,233,600 161,974,261 150,456,487 172,911,179 202,376,180 197,742,734 190,595,286 170,556,480 170,769,530 157,564,534 177,029,400 2,064,851,898
39 Retail Revernx Credit($/kWh) Attclmt3,page $ 0.01895 $ 0.01895 $ 0.01895 $ 0.01895 $ 0,01895 $ 0.01895 $ 0,01895 $ 0.01895 $ 0.01895 $ 0.01360 $ 0.01360 $ 0.01360
40 Variable Power Supply Payments (38)x(39) $ 3,044,170 $ 2,884,827 $ 3,069,412 $ 2,851,150 $ 3,276,667 $ 3,835,029 $ 3,747,225 $ 3,611,781 $ 3,232,045 $ 2,322,466 $ 2,142,878 $ 2,407,600 $ 36,425,249
41 Cwwrrer D-Wled Paymmnts (36)-(37)-(40) $ 12,077,373 $ 11,669,939 $ 12,571,654 $ 11,473,143 $ 13,142,450 $ 15,101,356 $ 14,885,892 $ 14,381,919 $ 12,933,631 $ 14,286,739 $ 13,300,076 $ 14,733,735 $ 160,557,908
42 Non-Residermal Reverwe Par Customer (41)/(33) $333.02 $321.26 $348.41 $316.51 $366.21 S417.00 $412.90 $400.19 $359.56 $390.74 $36650 $403.83 S4,436.08
Race ved
43 Deferral-Surcharge(Rebate) (35)-(41) $ 1,215,412 $ 1,543,632 $ (86,446)$ 690,465 $ (162,716)$ (1,484,631)$ 27,825 $ (118,960)$ (249,880)$ 1,088,637 $ (23,522)$ (11,134) $ 2,428,682
44 Deferral-Revenue Related Expenses Rev C..Factor $ (53,927)$ (68,489)$ 3,836 $ (30,635)$ 7,220 $ 65,872 $ (1,235)$ 5,278 $ 11,087 $ (47,825)$ 1,033 $ 489 $ (107,297)
45 FERC Rate 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3.25%
46 Interest on Deferral Avg Balance Calc $ 1,573 $ 5,148 $ 7,047 $ 7,848 $ 8,552 $ 6,444 $ 4,576 $ 4,470 $ 4,005 $ 5,102 $ 6,495 $ 6,467 $ 67,726
47 M..hly Non-R.Adential Deferral Totals s 1,163,058 $ 1,480,290 $ (75,563)$ 667,678 $ (146,945)$ (1,412,316)$ 31,166 $ (109,211)$ (234,798)$ 1,045,913 S (15,994)S (4,177) $ 2,389,111
Cumwaave Deferral(R6ate)B-1.,e
48 Balance 1:((43),(44),(46)) $ 1,163,058 $ 2,643,348 $ 2,567,785 $ 3,235,463 $ 3,088,519 $ 1,676,202 $ 1,707,369 $ 1,598,157 $ 1,363,370 $ 2,409,283 $ 2,393,289 $ 2,389,111
Total Cumulative Deferral
49 (Rebate)/Surcharge Balance $ 3,642,594 $ 2,860,433 $ 3,099,280 $ 4,545,187 $ 4,715,332 $ 1,135,284 $ (4,212,334)$ (5,504,529)$ (5,598,450)$ (3,518,714)$ (2,552,349)
"-As approved in Docket No.UE-190334,the Company is required to cWalate&-pkd revenue using YTD avenge customers,eonlwrc to what was rccorded.sh g mouldy customer words,and record the difference i.
December so that the annual&-pled revenue is based on Y FD avenge customers.Thk amount includes that annual the-up that restated in an increase to&-pled revenue of$406.83.
1-48

Table 1-28: 2021 Annual True-Up for Electric Residential and Electric Non-Residential.
Purpose:As required by UE-190334(UE-190222,consolidated)paragraph 111,the Company is required to calculate decoupled revenue
using YTD average customers,compare to what was recorded using monthly customer counts,and record the difference so
that the annual decoupled revenue is based on YTD average customers.
Procedure:Separately for residential and non-residential,calculated average customers and multiplied that by the sum of decoupled
revenue by month to calculate total allowed decoupled revenue for the period based on average customers.Note,the average
customer calculation and allowed revenue was broken out into the period of Jan-Sep 2021 when the UE-190334 authorized
base was in effect and Oct-Dec 2021 when the UE-200900 authorized base was in effect.This was compared to the amount
recorded using monthly actual customers and monthly decoupled revenue per customer.The difference was recorded with the
monthly decoupled revenue for December 2021.
Residential
Average Actual Customers(average of line 9 in Deferral Calc for Jan-Sep 2021-UE-190334) 217,223
Sum of Decoupled Revenue(sum of line 10 in Deferral Calc for Jan-Sep 2021-UE-190334) $ 546.25
Total Decoupled Revenue using Average Actual Customers $ 118,657,158.69
Average Actual Customers(average of line 9 in Deferral Calc for Oct-Dec 2021-UE-200900) 219,540
Sum of Decoupled Revenue(sum of line 10 in Deferral Calc for Oct-Dec 2021-UE-200900) $ 240.47
Total Decoupled Revenue using Average Actual Customers $ 52,792,456.33
Total Annual Authorized Decoupled Revenue using Average Actual Customers F A $ 171,449,615.02
Less Jan-November Decoupled Revenue(sum of line 11 in Deferral Calc for Jan-Nov 2021) 149,445,751.74
Decoupled Revenue to record for December to reflect true-up $ 22,003,863.28
December Actual Customers(line 9,column n in Deferral Calc) 219,614
December Decoupled Revenue per Customer(line 10,column n in Deferral Calc) $ 100.31
Total Decoupled Revenue for December using monthly actuals $ 22,028,828.33
Net increase/(decrease)to Decoupled Revenue due to Average Calculation $ (24,965.05)
Non-Residential
Average Actual Customers(average of line 33 in Deferral Calc for Jan-Sep 2021-UE-190334) 36,110
Sum of Decoupled Revenue(sum of line 34 in Deferral Calc for Jan-Sep 2021-UE-190334) $ 3,312.70
Total Decoupled Revenue using Average Actual Customers $ 119,620,361.51
Average Actual Customers(average of line 33 in Deferral Calc for Oct-Dec 2021-UE-200900) 36,446
Sum of Decoupled Revenue(sum of line 34 in Deferral Calc for Oct-Dec 2021-UE-200900) $ 1,189.89
Total Decoupled Revenue using Average Actual Customers $ 43,366,228.88
Total Annual Authorized Decoupled Revenue using Average Actual Customers F B $ 162,986,590.39
Less Jan-November Decoupled Revenue(sum of line 35 in Deferral Calc for Jan-Nov 2021) 148,263,989.26
Decoupled Revenue to record for December to reflect true-up $ 14,722,601.13
December Actual Customers(line 33,column n in Deferral Calc) 36,485
December Decoupled Revenue per Customer(line 34,column n in Deferral Calc) $ 403.51
Total Decoupled Revenue for December using monthly actuals $ 14,722,194.30
Net increase/(decrease)to Decoupled Revenue due to Average Calculation $ 406.83
1-49

The result of these calculations is that for the gas Residential Group, deferred revenue for
2021 is in the rebate direction with a decoupling Deferred Revenue of($5,123,505)47.
Adjustments, conveyed in the annual filing, result in a final Residential rebate of
($5,801,102), including a prior year carryover offset of($224,670) and other adjustments
(Table 1-29).48
Table 1-29: 2021 Electric Residential Rate Determination.
Residential Electric Service: Adjustments
2021 Deferred Revenue $ (5,123,505)
Add: Earnings Sharing/DSM Adjustment $ -
Add:Prior Year Carryover Balance $ (224,670)
Add: Interest through 7/31/2024 $ (187,264)
Add: Revenue Related Expense Adjustment $ (265,663)
Total Requested Recovery $ (5,801,102)
Customer Surcharge Revenue $ (5,801,102)
Carryover Deferred Revenue $ -
For Non-Electric Residential service, the computations developed deferred revenue of
$2,389,111 in the surcharge direction(Table 1-6, Line 48, Cumulative Deferrals
(Rebate)/Surcharge Balance, Dec-21 Column, and Table 1-30, 2021 Deferred Revenue).
Adjustments (Table 1-30), including a Prior Year Carryover Balance of$148,270 and
other adjustments produced a Customer Surcharge Revenue amount of$2,727,724.49
Table 1-30: 2021 Electric Non-Residential Group Rate Determination.
Non-Residential Electric Service: Adjustments
2021 Deferred Revenue $ 2,389,111
Add: Earnings Sharing/DSM Adjustment $ (17,014)
Add:Prior Year Carryover Balance $ 148,270
Add: Interest through 7/31/2024 $ 86,597
Add: Revenue Related Expense Adjustment $ 123,746
Total Requested Recovery $ 2,747,724
Customer Surcharge Revenue $ 2,747,724
Carryover Deferred Revenue $ -
47 Table 1-26,Line 24,Cumulative Deferral(Rebate)/Surcharge Balance,Dec-21 Column.
48 Letter,re: Tariff WN U-29,Natural Gas Service Decoupling Rate Adjustment from Joe Miller,Avista
Senior Manager for Rates and Tariffs,Regulatory Affairs to Amanda Maxwell,Executive Director and
Secretary,Washington Utilities and Transportation Commission dated May 27,2022,P.2 of 5.
49 Letter of Joe Miller, Senior Manager of Rates and Tariffs,Regulatory Affairs,Avista to Amanda
Maxwell,Executive Director and Secretary,Washington Utilities and Transportation Commission,Re:
Tariff WN U-28,Electric Service Electric Decoupling Rate Adjustment,May 26,2022,Page 3 of 6.
1-50

Natural Gas Group I (Residential) and Group 2 (Non Residential)
For natural gas, following steps in Schedule 175A,Decoupled Revenue per Customer (by
Rate Group) is developed.50 Calculation of Decoupled Revenue per Customer(by Rate
Group) is specified in seven steps in Schedule 175A. These steps are implemented in the
Residential Customers in Table 1-9 and for the Non-Residential Customers in Table
1-10.51 Monthly Decoupled Revenue per Customer for Group 1: Residential and Group
2: Non-Residential are then used to develop the Monthly Decoupling Deferral for natural
gas, following the steps in Schedule 175B.
Natural Gas Decouplinz Deferral(Schedule 175A)
Step 1: Determine the Total Normalized Revenue. The Total Normalized Revenue is
equal to the final approved base rate revenue approved in the Company's last general rate
case, individually for each rate schedule. Table 1-25, Line 1 shows initial Total
Normalized Net Revenue. In addition, Line 2 shows Allowed Revenue Decrease. The
sum of Line I and Line 2 is shown on Line 3 as the Allowed Base Rate Revenue.
Step 2: Determine Variable Gas Supply Revenue. The product of Normalized Therms
(Line 4) from the last approved general rate case (2018 Rate Year) and PGA Rates (Line
5) is the Variable Gas Supply Revenue (Line 6).
Step 3: Determine Delivery Revenue. To determine the Delivery Revenue (Line 7), the
Variable Gas Supply Revenue (Line 6) is subtracted from the Total Normalized Revenue
(Line I).
Step 4: Remove Basic Charge Revenue. Step 4 is to calculate the Basic Charge
Revenue. Because the decoupling mechanism only tracks revenue that varies with
customer energy usage, revenue from previously allocated Fixed Charges is removed.
Basic Charge Revenue is the product of the number of Customer Bills in the test period
(2018 Rate Year) on Line 8 times the Settlement Basic Charges (Line 9). The result,
Basic Charge Revenue, is shown on Line 10.52
5' Avista Corporation,dba Avista Utilities, Schedule 175A,Decoupling Mechanism—Natural Gas,Issued
June 12,2015,Effective August 1,2015.
51 All tables in this section are attachments or parts of attachments to the Electric and Natural Gas
Decoupling Rate Adjustment filings of August 31,2016.
52 For natural gas minimum charges are treated like fixed charges.
1-51

Step 5: Determine Allowed Decoupled Revenue. The Allowed Decoupled Revenue is
equal to the Delivery Revenue (from Line 7) minus the Basic Charge Revenue (Line 10).
The resulting Decoupled Revenue is shown on Line 11.
Step 6: Determine the Allowed Decoupled Revenue per Customer. In Step 6,
Decoupled Revenue from Line 11 is put on a per customer basis. The Decoupled
Revenue (by Rate Group) is divided by the approved Rate Year number of customers (by
Rate Group). This determines the annual Allowed Decoupled Revenue per Customer(by
Rate Group) as shown in Table 1-26.
Step 7: Determine the Monthly Allowed Decoupled Revenue per Customer. This
converts the annual Allowed Decoupled Revenue per Customer(by Rate Group) into
monthly values. The assignment of monthly values is carried out by modeling monthly
therm use (by Rate Group) in relationship to the annual therm use for the rate year. This
modeling is shown in Table 1-27.
In Table 1-27, the therm usage for Group 1 (Residential) for 2018 is shown in Line 4 and
for Group 2 (Non-Residential) in Line 8. Both monthly therm values and the annual
therm values are shown. Below the monthly values, percentages (Lines 5 and 9) are
shown. Lines 14 and 18 show the use of these percentages, applied to annual Allowed
Decoupled Revenue per Customer(by Rate Group) to generate monthly values.
These monthly values are then taken forward to be used in the implementation of
Schedule 175B.
1-52

(4)
Table 1-31. 2021 Development of Natural Gas Decoupled Revenue per Customer
Natural Gas Decoupling Mechanism
Development of Decoupled Revenue by Rate Schedule-Natural Gas
Washington Docket No.UG-190355 Compliance Filing
RESIDENTIAL GENERAL SVC. LG.GEN.SVC. INTERRUPTIBLE SCHEDULES SCHEDULES
TOTAL SCHEDULE 101/102 SCH.111/112/116 SCH.121/122/126 SCH 131 132 146&148
1 Total Normalized 12 ME Dec 2018 Revenue $ 93,707,000 $ 71,132,000 $ 17,418,000 $ - $ $ 201,000 $ 4,956,000
2 Allowed Revenue Decrease(Attachment 2) $ 8,000,000 $ 6,187,000 $ 1,515,000 $ $ $ 17,000 $ 281,000
3 Allowed Base Rate Revenue $ 101,707,000 $ 77,319,000 $ 18,933,000 $ $ $ 218,000 $ 5,237,000
4 Normalized Therms(12ME Dec 2018 Test Year) 275,981,665 128,985,980 55,884,877 985,267 90,125,541
5 Schedule 150 PGA Rates excluded from base rates $ $ - $ $
6 Variable Gas Supply Revenue $ $ $ - $ $
7 Delivery Revenue (Ln 3-Ln 6) $ 96,252,000 $ 77,319,000 $ 18,933,000 $ $
8 Customer Bills(12ME Dec 2018 Test Year) 1,978,935 1,941,495 36,876 0 0 24 540
9 Allowed Basic/Minimum Charges $9.50 $107.56 $0.00 $0.00
10 Basic Charge Revenue(Ln 8*Ln 9) $ 22,410,585 $ 18,444,203 $ 3,966,383 $ - S
11 Decoupled Revenue $ 73,841,415 $ 58,874,798 $ 14,966,617 $ - S - Excluded From Decoupling
Residential Non-Residential Group _
12 Average Number of Customers(Line 8/12) 161,791 3,073
13 Annual Therms 128,985,980 55,884,877
14 Basic Charge Revenues $ 18,444,203 $ 3,966,383
15 Customer Bills 1,941,495 36,876
16 Average Basic Charge $9.50 $107.56
1-53

(4)
Table 1-32. 2021 Natural Gas Decoupled Revenue per Customer
Avista Utilities
Natural Gas Decoupling Mechanism
Development of Decoupled Revenue Per Customer-Natural Gas
Washington Docket No.UG-200901 Compliance Filing
Line No. Source Residential Non-Residential
Schedules* Schedules**
(a) (b) (c) (d)
1 Decoupled Revenues Attachment 4,Page 1 $ 67,962,780 $ 16,088,382
2 Test Year#of Customers 12 ME12.2018 Revenue Data 165,362 3,105
3 Decoupled Revenue Per Customer (1)/(3) $ 410.99 $ 5,182.28
*Rate Schedules 101, 102.
**Rate Schedules 111, 112, 116, 131.
Attachment 4, Page 2
Revenues
From Revenue Per Customer $ 67,961,957 $ 16,088,388
From Basic Charges $ 18,851,221 $ 4,449,618
From Gas Supply $ - $ -
Total $ 86,813,178 $ 20,538,006
1-54

(4)
Table 1-33. 2021 Development of Monthly Natural Gas Decoupled Revenue per Customer
Avista Utilities
Natural Gas Decoupling Mechanism
'Development of Monthly Decoupled Revenue Per Customer-Natural Gas
Washington Docket No.UG-200901 Compliance Filing
Line Source Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec TOTAL
No.
(a) (h) (c) (d) (c) (0 (9) (h) O O (k) (1) (m) (n) (o)
1
2 Natural Gas Deli—Volume
3 Residential*
4 -Weather-Nomralized Therm Delivery Volume Monthly Rate Year 22,053,451 17,838,631 15,392,331 9,335,434 6,176,185 3,137,238 2,719,096 2,706,113 2,771,534 10,154,966 17,140,392 22,670,233 132,095,604
5 -%of Annual Total %of Total 16.70% 13.50% 11.65% 7.07% 4.68% 2.37% 2.06% 2.05% 2.10% 7.69% 12.98% 17.16% 100.00%
6
7 Non-
Residential-8 -Weather-Normalized Therm Delivery Volunn Monthly Rate Yen 8,577,346 7,573,569, 6,130,350 4,993,382 3,224,280 2,598,074 2,115,989 2,178,138 2,697,188 4,650,252 6,926,057 8,661,298 60,325,922
9 -%ofAtmual Total %of Total 14.22% 12.55% 10.16% 8.28% 5.34% 4.31% 3.51% 3.61% 4.47% 7.71% 11.48% 14.36% 100.00%
10
11 Monthly Decouoled Revenue Per Custamer("RPC")
12 Residential*
13 -UG-190335Decoupled RPC Attachment 5,P.2 L.3 $ 410.99
14 -Monthly Decoupled RPC Q x(13) $ 68.62 $ 55.50 $ 47.89 $ 29.05 $ 19.22 $ 9.76 $ 8.46 $ 8.42 $ 8.62 $ 31.60 $ 53.33 $ 70.53 $ 410.99
15
16 Non-Residential**
17 -UG-190335 Decoupled RPC Attachment 5,P.2 L,3 $ 5,182.28
18 -Monthly Decoupled RPC Qx(17) $ 736.83 $ 650.61 $ 526.63 $ 428.95 $ 276.98 $ 223.19 $ 181.77 $ 187.11 $ 231.70 $ 399.48 $ 594.98 $ 744.05 $ 5,182.28
19
20 *Rate Schedules 101,102.
21 **Rate Schedules 111,112,I16,131.
1-55

Natural Gas Monthly Decouplinz Deferral
Schedule 175B specifies the method for developing the Monthly Decoupling Deferral for
natural gas service. The calculation of the monthly natural gas decoupling deferral for
2021 is shown in Table 1-28 for Gas Residential and in Table 1-29 for Gas Non-
Residential. The monthly decoupling deferral amounts across 2021 sum to the annual
total decoupling deferral for 2021.
The Schedule 175B calculation steps for Natural Gas Residential follow. There are eight
steps. The sequence of the line numbers in Table 1-14 are keyed to the eight steps. Steps
1 through 5 are required to remove new customers (new hookups) from the calculation.
Natural Gas—Residential(Schedule 175B)
Step 1: Deduct new hookup customers.New hookup customers (Line 5) are deducted
from total actual number of customers (Line 1) to determine the actual number of test
year existing customers each month. The result (actual number of decoupled customers
after subtracting out new customers) is shown on Line 9.
Step 2: Calculate total Allowed Decoupled Revenue each month. This is calculated
by multiplying the number of Actual Customers after removing new customers (Line 9)
by the Monthly Decoupled Revenue per Customer(Line 10). The result is shown on Line
11, Decoupled Revenue.
Step 3: Deduct actual new hookup customer revenue from total actual revenue. This
determines the actual test year existing customer revenue collected in the applicable
month. To form this result, Actual Base Rate Revenue (Line 3) is adjusted by subtracting
New Customer Base Rate Revenue (Line 7). The result is shown on Line 12.
Step 4: Deduct actual new hookup customer fixed charge revenue from total actual
fixed charge revenue. Line 8,New Customer Basic Charge Revenue, is subtracted from
Line 4, Actual Basic Charge Revenue. The result, Actual Basic Charge Revenue (Test
Year Existing), is shown on Line 13.
Step 5: Deduct actual new hookup customer kWh sales from total actual kWh sales.
This is Line 2 (Actual Usage kWh)minus Line 6 (New Customer Usage (kWh). The
result is the Actual Usage (kWh)/Test Year Existing (Line 14) from which new customer
(new hookups) actual usage has been removed. Then, Actual Usage (kWh)/Test Year
Existing in Line 14 is multiplied by the approved Retail Revenue Credit(Line 15). The
result is the revenue collected related to the variable power supply (Variable Power
1-56

AN
Supply Payments; Line 16). When Step 5 is completed, all quantities remaining in the
analysis have been adjusted to remove new customers (new hookups).
Step 6: Compute Customer Decoupled Payments. Actual Decoupled Revenue is
calculated by subtracting the Actual Basic Charge Revenue/Test Year Existing in Line 13
and the Variable Power Supply Payments (Line 16) from the Actual Base Rate
Revenue/Test Year Existing (Line 12). Customer Decoupled Payments is shown on Line
17.
Step 7: Compute Balance to be Deferred by the Company as a Surcharge or as a
Rebate. The Balance (for each month) is computed by subtracting Customer Decoupled
Payments (Line 17) from Decoupled Revenue (Line 11).53 The result(Deferral—
Surcharge/Rebate) is shown on Line 19.
This amount is then adjusted for Revenue Related Expenses (Line 20) and for interest at
the FERC rate (FERC interest rate at Line 21 and interest at Line 22). The result is the
Monthly Electric Residential Deferral Total (Line 23).
These monthly amounts are then cumulated in Line 24. The Total Cumulative Deferral
(Rebate)/Surcharge Balance is tracked in Line 48. The total cumulative deferral for
Natural Gas Residential is a decoupling refund to customers of$.54 However, this is
modified by adjustments in the filing for Tariff U-29,Natural Gas Service Natural Gas
Decoupling Rate Adjustment, dated May 27, 2022.55 In the filing, the Proposed
Decoupling Revenue is set to $5,378,553, and there is a Carryover Deferred Revenue of
$1,642,757.
Step 8: Comparison.At the end of every 12-month deferral period, the annual
decoupled revenue per customer, by rate group, is multiplied by the average annual
number of actual test year existing customers. The result of that calculation is compared
to the actual deferred revenue for the same 12-month period. The difference between the
actual deferred revenue, and the calculated value, is then added to, or subtracted from, the
total deferred balance by Rate Group. This calculation is shown in Table 1-30.
53 The source entry for Deferral—Surcharge(Rebate),Line 15)is"(12)-(15)". This notation should be
corrected to"(11 - 15)".However,the calculation is correct.
54 Table 1-28,line 24,(Rebate/Surcharge)Balance,last column.
55 Letter of Joe Miller,Avista Senior Manager of Rates and Tariffs,Regulatory Affairs to Amanda
Maxwell,Executive Director and Secretary,Washington Utilities and Transportation Commission,re:
Tariff WN U-29,Natural Gas Service Natural Gas Decoupling Rate Adjustment,dated May 27,2022,P.2
of 5.
1-57

Table 1-34: 2021 Natural Gas Decoupling-Residential.
Avista Utilities
Decoupling Mechanism
UG-190335 Base effective 4/1/2020&UG-200901 Base Effective 10-1-2021
Development of WA Natural Gas Deferrals(Calendar Year 2021)
Revised Revised Revised
Line No. Some Jaa-20 Feh-20 Mar-20 Apr-20 May-20 J-20 Jul-20 Aug-20 Sep-20 Oct-20 Nov-20 Dec-20 Total
(a) (b) (e) (d) (e) (9) (h) () 0) (k) (1) Od (n) (o)
Residential Group
1 Acanl Customers Revenue System 170,038 170,038 170,038 170,295 170,263 170,396 170,444 170,724 170,589 171,132 171,256 171,774
2 Actual Usage('The-) Revenue System 20,684,875 21,500,858 14,765,518 8,962,165 4,466,068 2,745,599 2,048,449 2,330,904 3,156,001 8,316,628 14,219,304 23,797,281
3 Actud Base Rate Revenue Revenue System $ 11,496,790 $ 11,782,889 $ 8,420,598 $ 5,288,493 $ 3,492,252 $ 2,800,621 $ 2,499,581 $ 2,697,286 $ 2,845,244 $ 5,661,049 $ 7,955,293 $ 13,471,458
4 Aetual Fixed Charge Revenue Revenue System $ 1,564,897 $ 1,561,449 $ 1,768,948 $ 1,636,898 $ 1,637,981 $ 1,647,015 $ 1,644,906 $ 1,648,687 $ 1,643,700 $ 1,648,858 $ 1,648,972 $ 1,650,321
5 New Customers Revenue System 6,135 5,922 6,787 6,599 6,840 6,970 7,188 7,394 7,540 4,403 4,679 4,909
6 New Customer Usage(The-) Revenue System 701,592 695,498 639,367 402,019 201,657 114,045 68,683 57,571 77,980 116,188 292,557 513,683
7 New Customer Base Rate Revenue Revenue System $ 389,558 $ 384,688 $ 360,703 $ 241,488 $ 152,690 $ 115,222 $ 98,471 $ 94,893 $ 105,266 $ 95,884 $ 192,178 $ 316,498
8 New Customer Fixed Charge Revenue Revenue System $ 58,748 $ 56,269 $ 64,515 $ 62,957 $ 65,237 $ 66,168 $ 68,375 $ 70,158 $ 71,469 $ 41,876 $ 44,698 $ 46,750
9 Actual/Test Year Ededvg Caslomcrs (1)-(5) 163,903 164,116 163,251 163,696 163,423 163,426 163,256 163,330 163,049 166,729 166,577 166,865 1,971,621
10 Monthly Decoupled Revenue per Custoner Attachmem 4,Page 3 $64.18 548.76 544.02 $27.53 $16.27 $8.72 $6.48 $6.25 $8.69 $31.60 $53.33 $70.53 $386.36
11 Decoupled Revenue (9)x(10) $ 10,519,508 $ 8,002,021 $ 7,185,922 $ 4,506,298 $ 2,659,549 $ 1,424,558 $ 1,057,670 $ 1,021,122 $ 1,416,884 $ 5,267,839 $ 8,883,389 $ 11,724,193 $ 63,668,952
12 Actual Usage/Test Year Existing (2)-(6) 19,983,283 20,805,360 14,126,150 8,560,146 4,264,411 2,631,554 1,979,766 2,273,333 3,078,021 9,200,440 13,926,747 23,283,597 123,112,807
Actual Base Rate Revenue/Test Year
13 Existing (3)-(7) $ 11,107,231 $ 11,398,201 $ 8,059,995 $ 5,047,004 $ 3,339,562 $ 2,685,399 $ 2,401,111 $ 2,602,392 $ 2,739,978 $ 5,565,165 $ 7,763,115 $ 13,154,960 $ 75,864,015
Actual Fixed Charge Revenue/Test Year
14 Existing (4)-(8) $ 1,506,149 $ 1,505,180 $ 1,704,433 $ 1,573,941 $ 1,572,744 $ 1,580,848 $ 1,576,531 $ 1,578,530 $ 1,572,231 $ 1,606,982 $ 1,604,275 $ 1,603,572 $ 18,985,414
15 Customer Decoupled Payments (13)-(14) $ 9,601,082 $ 9,893,021 $ 6,355,462 $ 3,473,063 $ 1,766,818 $ 1,104,552 $ 824,579 $ 1,023,863 $ 1,167,747 $ 3,958,183 $ 6,158,841 $ 11,551,389 $ 56,878,601
16 Residemml Revenue Per Customer Received (15)/(9) $58.58 $60.28 $38.93 $21.22 $10.81 $6.76 $5.05 $6.27 $7.16 $23.74 $36.97 $69.23
17 Deferral-Suacharge(Rebste) (12)-(15) $ 918,426 $ (1,891,001) $ 830,460 $ 1,033,234 $ 892,730 $ 320,006 $ 233,090 $ (2,740) $ 249,137 $ 1,309,656 $ 2,724,548 $ 172,804 $ 6,790,351
18 Deferral-Revenue Related Expeases Rev Corw Factor $ (40,553) $ 83,497 $ (36,669) $ (45,622) $ (39,419) $ (14,130) $ (10,292) $ 121 $ (11,001)$ (57,256)$ (119,112) $ (7'555) $ (297,989)
19 FERC Rate 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3,25% 3.25% 3,25% 3,25%
20 Interest on Def al Avg Balanee Cal, $ 1,189 $ (67) $ (1,440) $ 969 $ 3,464 $ 5,043 $ 5,773 $ 6,087 $ 6,422 $ 8,458 $ 13,705 $ 17,494 $ 67,097
21 Monthly Residential Deferral Totals $ 879,061 $ (1,807,570) $ 792,351 $ 988,580 $ 856,776 $ 310,919 $ 228,571 $ 3,467 $ 244,558 $ 1,260,858 $ 2,619,142 $ 182,744 $ 6,559,458
22 Cunwlative Determl(Rebate)Balance £((17),(l8),(20)) $ 879,061 $ (928,509) $ (136,158) $ 852,423 $ 1,709,199 $ 2,020,118 $ 2,248,689 $ 2,252,156 $ 2,496,715 $ 3,757,573 $ 6,376,714 $ 6,559,458
As approved in Docket No.UG-190335,the Company is required to calcuhne droupled revenue using YTD average customers,compare to what was recorded u,i g oasnthly customer counts,and record the difference in December so that the annual decouFled revenue is based on YTD average
customers.This amount includes that annual true-up that resulted in a decrease to decoupled revenue of$19,742.07.
1-58

Natural Gas—Non-Residential(Schedule 175B)
Schedule 175B calculation for Electric Non-Residential steps follow. There are eight steps.
The sequence of the line numbers are keyed to the eight steps, and to Table 1-29. Steps 1
through 5 are required to remove new customers (new hookups) from the calculation.
Stepl: Deduct new hookup customers. The number of new hookup customers (Line 27) is
deducted from the total actual number of customers (Line 23)to determine the actual number
of test year existing customers each month. The result(actual number of customers after
subtracting out new customers) is Test Year Existing Customers (Line 31).
Step 2: Calculate total Allowed Decoupled Revenue each month. This is calculated by
multiplying the number of Actual Customers after removing new customers (Line 31)by the
Monthly Decoupled Revenue per Customer(Line 32). The result is shown on Line 35.
Step 3: Deduct actual new hookup customer revenue from total actual revenue. This
determines the actual test year existing customer revenue collected in the applicable month.
To form this result, Actual Base Rate Revenue (Line 27) is adjusted by subtracting New
Customer Base Rate Revenue (Line 31). The result is shown on Line 36.
Step 4: Deduct actual new hookup customer fixed charge revenue from total actual
fixed charge revenue. Line 32,New Customer Basic Charge Revenue, is subtracted from
Line 28, Actual Basic Charge Revenue. The result, Actual Basic Charge Revenue (Test Year
Existing), is shown on Line 37.
Step 5: Deduct actual new hookup customer kWh sales from total actual kWh sales.
This is Line 26 (Total Actual kWh Sales) minus Line 30 (New Customer Usage (kWh). The
result is the Actual Usage (kWh) from which new customer actual usage has been removed.
The result is shown in Line 38. Then, Actual Usage (kWh) in Line 38 is multiplied by the
approved Retail Revenue Credit (Line 39). The result is the revenue collected related to the
variable power supply (Variable Power Supply Payments in Line 40). When Step 5 is
completed, all remaining quantities have been adjusted to remove new customers (new
hookups).
Step 6: Compute Customer Decoupled Payments. Actual Decoupled Revenue is
calculated by subtracting the Actual Basic Charge Revenue (Test Year Existing) in Line 37
1-59

and the Variable Power Supply Payments (Line 40) from the Actual Base Rate Revenue
(Line 36) and is shown on Line 41.
Step 7: Compute Balance to be Deferred by the Company as a Surcharge or as a
Rebate. The Balance (for each month) is computed by subtracting Customer Decoupled
Payments (Line 37) from Decoupled Revenue (Line 33). The result(Deferral—
Surcharge/Rebate) is shown on Line 39. This amount is then adjusted for Revenue Related
Expenses (Line 44) and for interest at the FERC rate (Lines 44 and 45). The result is the
Monthly Non-Residential Deferral Total (Line 47). These monthly amounts are cumulated in
Line 48
Monthly Residential Deferral Total for each month is shown just below Line 12. This is the
difference between the Actual Decoupled Revenue (Step 6; Line 9) and the Allowed
Decoupled Revenue (Step 2; Line 3)plus any interest on the deferral. The Total Cumulative
Deferral (Rebate)/Surcharge Balance is tracked in Line 48. The total cumulative deferral for
Natural Gas Non-Residential is a surcharge to customers of$11,263,209.56
Step 8: Comparison.At the end of every 12-month deferral period, the annual decoupled
revenue per customer, by rate group, will be multiplied by the average annual number of
actual test year existing customers. The results of that calculation will be compared to the
actual deferred revenue for the same 12-month period. The difference between the actual
deferred revenue and the calculated value will be added to, or subtracted from, the total
deferred balance by Rate Group. This calculation is shown in Table 1-30, and results in a
decrease of$19,742.07 for the Residential Group and a decrease of$12,689.42 for the Non-
Residential Group.57
56 Table 1-15, line 48,Cumulative Deferral(Rebate/Surcharge)Balance.
57 Table 1-16,Net increase(decrease)to Decoupled Revenue due to Average Calculation(middle of table for
Residential;bottom line for Non-Residential).
1-60

NMV
Table 1-35: 2021 Natural Gas Decoupling-Non-Residential.
Avista Utilities
Decoupling Mechanism
UC-190335 Base effective 4/1/2020&UG-200901 Base Effective 10/1/2021
Development of WA Natural Gas Deferrals(Calendar Year 2021)
Revised Revised Revised
Line No. Source Jan-20 Feb-20 Mar-20 Apr-20 May-20 Jm-20 JW-20 Aug-20 Sep20 OM-20 Nov-20 Dec-20 Total
(a) (b) M (d) M (f) (9) (h) (i) 0) (k) (1) (m) (n) (o)
Non-Residential Group
23 Actual Customers Revenue System 3,182 3,182 3,182 3,195 3,179 3,181 3,196 3,193 3,192 3,210 3,225 3,253
24 Actual Usage("Therms) Revenue System 7,591,558 7,598,557 6994,946 4,053,887 2,846,431 1971,230 1,689,800 1,930,413 2,393,928 4,327,020 5,630,045 9,023,138
25 Actual Base Rate Revenue Revenue System $ 1,897,873 $ 2,381,220 $ 2,415,036 $ 1,529,319 $ 1,108,709 $ 862,281 $ 740,371 $ 776,531 $ 876,894 $ 1,321,635 $ 1,460,658 $ 2,486,342
26 Actual Fixed Charge Revenue Rev-System $ 325,728 $ 317,031 $ 385,342 $ 343,857 $ 342,227 $ 343,652 $ 343,736 $ 343,772 $ 343,531 $ 363,468 $ 394,641 $ 389,100
27 New Customers Rev-System 46 49 58 56 63 62 65 69 74 37 41 48
28 New Customer Usage(Therms) Revenue System 185,880 212,999 245,547 124,307 86,274 49,014 36,0tl 31,807 39,268 21,805 44,814 174,933
29 New Customer Base Rate Revenue Revemx System S 50,878 S 58,186 S 67,909 S 39,485 S 31,604 $ 18,933 $ 15,856 $ 14,821 S 17,540 $ 9,059 $ 16,526 $ 49,759
30 New Customer Fixed Charge Revemre Reverme System $ 4,779 $ 4,987 $ 5,961 $ 5,954 $ 6,649 $ 6,531 $ 6,879 $ 6,945 $ 7,718 $ 3,567 $ 4,423 $ 5,979
31 Test Year E fisting Customers (23)-(27) 3,136 3,133 3,124 3,139 3,116 3,119 3,131 3,124 3,118 3,173 3,184 3,205 37,702
32 Monthly Decoupled Revenue per Costumer Anachmen,S,Page 3 $685.77 $646.17 $518.30 $402.99 $292.00 $212.46 $153.39 $167.80 $199.69 $399.48 $594.98 $744.05 $5,017.07
33 Decoupled Revenue (31)x(32) S 2,150,581 $ 2,024,451 $ 1,619,165 $ 1,264,987 $ 909,857 $ 662,663 S 480,250 $ 524,220 $ 622,629 $ 1,267,545 $ 1,894,419 S 2,371,408 ** $ 15,792,174
34 Actual Usage(Therns)/Test Year Existing (24)-(28) 7,405,678 7,385,558 6,749,398 3,929,580 2,760,t57 1922,216 1,653,788 1,898,606 2,354,660 4,305,215 5,585,230 8,948,204 54,798,292
Actual Base Rate Revemre/Test Y..
35 Existing (25)-(29) $ 1,846,995 $ 2,323,034 $ 2,347,127 $ 1,489,834 $ 1,077,105 $ 843,348 $ 724,515 $ 761,710 $ 859,354 $ 1,312,576 $ 1,444,132 $ 2,436,583 $ 17,466,313
36 Actual Fixed Charge Revenue/Test Year (26)-(30) $ 320949 $ 312,044 $ 379,381 $ 337903 $ 335,578 $ 337,121 $ 336,857 $ 336,828 $ 335,813 $ 359,901 $ 380,218 $ 383,121 $ 4,155,711
Existing
37 Custom,D..upled Paymems (35)-(36) $ 1,526,046 $ 2,010,991 $ 1,967,746 $ 1,151,931 $ 741,527 $ 506,227 $ 387,658 $ 424,882 $ 523,542 $ 952,675 $ 1,063,914 $ 2,053,462 $ 13,310,601
38 Non-Residential Revenue Per Costras,Reee (37)/(31) $486.62 $641.87 $629.88 $366.97 $237.97 $162.30 $123.81 $136.01 $167.91 $300.24 $334.14 $640.71
39 Deferral-Sureharge(Rebate) (33)-(37) $ 624,535 $ 13,461 $ (348,582) $ 113,056 $ 168,330 $ 156,436 $ 92,592 $ 99,337 $ 99,087 $ 314,870 $ 830,505 $ 317,946 $ 2,481,573
40 Deferral-Revenue Related Expenses Rev Conv Factor $ (27,576) $ (594) $ 15,392 $ (4,992) $ (7,433)$ (6,907) $ (4,088) $ (4,386) $ (4,375) $ (13,765)$ (36,308) $ (13,900) $ (108,934)
41 FERC Rate 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3?5% 3.25%
42 Interest on Deferral Avg Balance Cale $ 808 $ 1,636 $ 1,207 $ 905 $ 1,272 $ 1,696 $ 2,023 $ 2,277 $ 2,540 $ 3,083 $ 4,574 $ 6,074 $ 28,095
43 Monthly Non-Residential Deferral Totals $ 597,767 S 14,503 $ (331,983) $ 108,969 $ 162,170 $ 151,225 $ 90,526 $ 97,228 $ 97,252 $ 304,187 $ 799,771 $ 310,120 $ 2,400,734
44 Comulative Defrral(Rebate)Balance £((39),(40),(42)) $ 597,767 $ 612,269 $ 280,286 $ 389,255 $ 551,425 $ 702,650 $ 793,176 $ 890,404 $ 987,655 $ 1,291,842 $ 2,090,614 S 2,400,734
45 Total Cutmdative Deferral(Rebate) (22)+(44) S 1,476,828 S (316,240) S 144,128 S 1,24t,678 S 2,260,624 $ 2,722,768 S 3,041,865 $ 3,t42,560 S 3,484,370 $ 5,049,415 $ 8,467,328 S 8,960,191
**As approved vt Docket No.UG-190335,the Company E required to cal,W,t,decoupled revenue using YTD average customers,compare to what was recorded using monthly customer counts,and record the difference vt December so that the annual decoupled revenue is based on YTD average
customer$.This armunt includes that annual true-up that resulted in a decrease to decoupled revenue of$12,689.42.
1-61

Table 1-36: 2021 Annual True-Up for Natural Gas Residential and Non-Residential.
Purpose:As required by UG-190335(UE-190222,consolidated)paragraph 111,the Company is required to calculate decoupled revenue
using YTD average customers,compare to what was recorded using monthly customer counts,and record the difference so that
the annual decoupled revenue is based on YTD average customers.
Procedure:Separately for residential and non-residential,calculated average customers and multiplied that by the sum of decoupled
revenue by month to calculate total allowed decoupled revenue for the period based on average customers.Note,the average
customer calculation and allowed revenue was broken out into the period of Jan-Sep 2021 when the UG-190335 authorized
base was in effect and Oct-Dec 2021 when the UG-200901 authorized base was in effect.This was compared to the amount
recorded using monthly actual customers and monthly decoupled revenue per customer.The difference was recorded with the
monthly decoupled revenue for December 2021.
Residential
Average Actual Customers(average of line 9 in Deferral Calc for Jan-Sep 2021-UG-190335) 163,494
Sum of Decoupled Revenue(sum of line 10 in Deferral Calc for Jan-Sep 2021-UG-190335) $ 230.90
Total Decoupled Revenue using Average Actual Customers $ 37,750,373.39 A
Average Actual Customers(average of line 9 in Deferral Calc for Oct-Dec 2021-UG-200901) 166,724
Sum of Decoupled Revenue(sum of line 10 in Deferral Calc for Oct-Dec 2021-UG-200901) $ 155.46
Total Decoupled Revenue using Average Actual Customers $ 25,918,578.20 A
Total Annual Authorized Decoupled Revenue using Average Actual Customers F A $ 63,668,951.59
Less January-November Decoupled Revenue(sum of line 11 in Deferral Calcfor Jan-Dec 2021) 51,944,758.84
Decoupled Revenue to record for December to reflect true-up $ 11,724,192.75
December Actual Customers(line 9,column n in Deferral Calc) 166,865
December Decoupled Revenue per Customer(line 10,column n in Deferral Calc) $ 70.53
Total Decoupled Revenue for December using monthly actuals $ 11,769,665.72
Net increase/(decrease)to Decoupled Revenue due to Average Calculation $ (45,472.97)
Non-Residential
Average Actual Customers(average of line 33 in Deferral Calc for Jan-Sep 2021-UG-190335) 3,127
Sum of Decoupled Revenue(sum of line 34 in Deferral Calc for Jan-Sep 2021-UG-190335) $ 3,278.56
Total Decoupled Revenue using Average Actual Customers $ 10,250,977.41 B
Average Actual Customers(average of line 33 in Deferral Calc for Oct-Dec 2021-UG-200901) 3,187
Sum of Decoupled Revenue(sum of line 34 in Deferral Calc for Oct-Dec 2021-UG-200901) $ 1,738.51
Total Decoupled Revenue using Average Actual Customers $ 5,541,196.42 B
Total Annual Authorized Decoupled Revenue using Average Actual Customers F B $ 15,792,173.83
Less January-November Decoupled Revenue(sum of line 35 in Deferral Calcfor Jan-Nov 2021) 13,420,765.61
Decoupled Revenue to record for December to reflect true-up $ 2,371,408.22
December Actual Customers(line 33,column n in Deferral Calc) 3,205
December Decoupled Revenue per Customer(line 34,column n in Deferral Calc) $ 744.05
Total Decoupled Revenue for December using monthly actuals $ 2,384,668.03
Net increase/(decrease)to Decoupled Revenue due to Average Calculation $ (13,259.81)
1-62

Table 1-37: 2021 Natural Gas Residential Group Rate Determination.
Residential Natural Gas Service: Adjustments
2021 Deferred Revenue $ 6,559,458
Add: Earnings Sharing/DSM Adjustment $ (57,986)
Add:Prior Year Carryover Balance $ 24,802
Add: Interest through 7/31/2024 $ 266,044
Add: Revenue Related Expense Adjustment $ 228,992
Total Requested Recovery $ 7,021,310
Customer Surcharge Revenue $ 5,378,553
Carryover Deferred Revenue $ 1,642,757
For the natural gas Non-Residential group, deferred revenue is in the surcharge direction
with a decoupling surcharge to customers of$2,400,734.58 Adjustments, conveyed in the
annual filing, result in a Total Requested Recovery of$2,574,424, of which $2,574,424 is
Customer Surcharge Revenue and$1,894,261 is Carryover Deferred Revenue (Table 1-
38) 59,60
Table 1-37: 2021 Natural Gas Non-Residential Rate Determination.
Non-Residential Natural Gas Service: Adjustments
2021 Deferred Revenue $ 2,400,734
Add: Earnings Sharin DSM Adjustment $ (17,014)
Add:Prior Year Carryover Balance $ 18,077
Add: Interest through 7/31/2024 $ 101,106
Add: Revenue Related Expense Adjustment $ 71,521
Total Requested Recovery $ 2,574,424
Customer Surcharge Revenue $ 2,574,424
Carryover Deferred Revenue $ 894,261
58 Table 1-15,Line 48,Cumulative Deferral(Rebate) Surcharge Balance,Dec-20 Column.
59 Letter,re: Tariff WN U-29,Natural Gas Service Decoupling Rate Adjustment from Joe Miller,Avista
Senior Manager for Rates and Tariffs,Regulatory Affairs to Mark L.Johnson,Executive Director and
Secretary,Washington Utilities and Transportation Commission dated May 26,2021,P.2 of 5.
60 Total Requested Recovery in Table 1-16 is off by one dollar,due to a rounding difference.
1-63

Earnings Test 2021
The decoupling mechanism, in Schedules 75D and 175D,provides for application of an
earnings test, separately for electric service and for natural gas.
Schedule 75D—Electric Earnings Test
According to Schedule 75D, the decoupling mechanism for Electric is subject to an
annual earnings test based on the Company's year-end Commission Basis Reports that
reflect actual decoupling-related revenues and various normalizing adjustments. As
shown in Table 1-15, Line 3, the calculated rate of return on a normalized basis in 2021 is
6.59%, which is less than the BASE rate of return of 7.19% (Line 4). This means there
are no Electric Excess Earnings for 2021.
Table 1-38. 2021 Electric Earnings Test.
2021 Commission Basis Earnings Test for Decoupling
Line No. Electric
1 Rate Base $ 1,808,056,000'
2 Net Income $ 119,077,000'
3 Calculated ROR 6.59%
4 Base ROR 7.19%
5 Excess ROR -0.60%
6 Excess Earnings $ -
7 Conversion Factor 0.756186
8 Excess Revenue(Excess Earnings/CF) $ -
9 Sharing% 50%
10 2021 Total Earnings Test Sharing $ -
Schedule 175D —Natural Gas Earnings Test
According to Schedule 175D, the decoupling mechanism for natural gas is subject to an
annual earnings test based on the Company's year-end Commission Basis Reports that
reflect actual decoupling-related revenues and various normalizing adjustments. As
shown in Table 1-34, the rate of return on a normalized basis in 2020 is 7.10% (Line 3).
This is less than the allowed return of 7.19% (Line 4). Since the normalized return is less
than the Base ROR, the Earnings Test has no effect for natural gas customers for 2021.
1-64

Table 1-39: 2021 Natural Gas Earnings Test.
2021 Commission Basis Earnings Test for Decoupling
Line No. Natural Gas
1 Rate Base $ 437,941,000
2 Net Income $ 31,094,000
3 Calculated ROR 7.10%
4 Base ROR Pro-rated 7.19%
5 Excess ROR -0.09%
6 Excess Earnings $ -
7 Conversion Factor 0.756355
8 Excess Revenue(Excess Earnings/CF) $ -
9 Sharing% 50%
10 2019 Total Earnings Test Sharing $ -
Three Percent Annual Rate Increase Limitation 2021
Decoupling annual rate adjustment surcharges are subject to a 3% annual rate increase
limitation(there is no reciprocal limit on rebate rate adjustments). The test is to divide the
incremental annual revenue to be collected (proposed surcharge revenue minus present
surcharge revenue)by the total "normalized"revenue for the two Rate Groups for the
most recent January through December.
Normalized revenue is determined by multiplying the weather-corrected usage for the
period by the present rates in effect. If the incremental amount of the proposed surcharge
exceeds 3%, only a 3% incremental rate increase will apply. Any remaining deferred
revenue will be carried over to the following years.
Schedule 75E—Electric 3% Rate Increase Test
The Electric Incremental Surcharge Test is shown in Table 1-35. Specifications for the
test limit the surcharge to 3%, with any remainder deferred to the following year. For
Residential customers, the result for the Incremental Decoupling Recovery Rate is
negative (Line 7), so there is no Carryover Deferred Revenue for Electric Residential
Customers for 2021. For Non-Residential customers, the Incremental Surcharge result is
negative (Line 7), so there is no Carryover Deferred Revenue for Electric Non-
Residential Customers for 2021.
1-65

Table 1-40: 2021 Electric 3%Annual Rate Increase Limitation.
3%Incremental Surcharge Test
Line No. Residential Non-Residential
1 Revenue From 2021 Normalized Loads and Customers at
Present Billing Rates(Note 1) $ 236,287,828 $ 245,165,869
2 August 2022-July 2023 Usage(kWhs) 2,479,103,469 2,081,609,218
3 Proposed Decoupling Recovery Rates -$0.00234 $0.00132
4 Present Decoupling Surcharge Recovery Rates -$0.00045 $0.00679
5 Incremental Decoupling Recovery Rates -$0.00189 -$0.00547
6 Incremental Decoupling Recovery $ (4,685,506) $ (11,386,402)
7 Incremental Surcharge% -1.98% -4.64%
8 3%Test Adjustment(Note 2) $ - $ -
9 3%Test Rate Adjustment $0.00000 $0.00000
10 Adjusted Proposed Decoupling Recovery Rates -$0.00234 $0.00132
11 Adjusted Incremental Decoupling Recovery $ (4,685,506) $ (11,386,402)
12 Adjusted Incremental Surcharge% -1.98% -4.64%
Notes
(1) Revenue from 2021 normalized loads and customers at present billing rates effective since
November 1,2021.
(2) The carryover balances will differ from the 3%adjustment amounts due to the revenue related
expense gross up partially offset by additional interest on the outstanding balance during the
amortization period.
1-66

Schedule 175E—Natural Gas 3% Rate Increase Test
The Natural Gas Incremental Surcharge Test is shown in Table 1-36. The test limits the
Residential and the Non-Residential Surcharge each to 3%. For both the Residential and
the Non-Residential Groups, the incremental surcharge percent is above 3% (Line 7), so
the surcharge for 2021 is set to 3% for each, and there is Carryover Deferred Revenue
(Line 8)to be to be deferred to the following year.
Table 1-41. 2021 Natural Gas 3%Rate Increase Limitation.
3%Incremental Surcharge Test
Line No. Residential Non-Residential
Revenue From 2021 Normalized Loads and
1 Customers at Present Billing Rates(Note 1) $ 136,763,580 $ 40,127,787
2 August 2022-July 2023 Usage 137,946,985 58,623,989
3 Proposed Decoupling Recovery Rates $0.05125 $0.04436
4 Present Decoupling Surcharge Recovery Rates(2) $0.00925 $0.00813
5 Incremental Decoupling Recovery Rates $0.04200 $0.03623
6 Incremental Decoupling Recovery $ 5,793,773 $ 2,123,947
7 Incremental Surcharge% 4.24% 5.29%
8 3%Test Adjustment(3) $ (1,690,866) $ (920,114)
9 3%Test Rate Adjustment -$0.01226 -$0.01570
10 Adjusted Proposed Decoupling Recovery Rates $0.03899 $0.02866
11 Adjusted Incremental Decoupling Recovery $ 4,102,543 $ 1,203,550
12 Adjusted Incremental Surcharge% 3.00% 3.00%
Notes
(1) Revenue from 2021 normalized loads and customers at present billing rates effective
since November 1,2021.
(3) The carryover balances will differ from the 3%adjustment amounts due to the revenue
related expense gross up partially offset by additional interest on the outstanding balance
during the amortization period.
1-67

2022 Decoupling Mechanism —Electric (Schedule 75) and Natural Gas
(Schedule 175)
In this section, we review analysis of data from 2022, used to develop amounts for
decoupling revenue recovery from August 1, 2023, to July 31, 2024 (the third decoupling
rate year of the three examined in this study). The decoupling mechanism is designed to
arithmetically capture fixed costs from within the variable portion of the rate. Other fixed
costs already accounted for in the customer charge are not included. The captured fixed
cost from the variable portion of the rate, after adjustments, is recovered as deferred
revenue during the rate year that begins August 1, 2023,by monthly allocation to
customer bills according to a model.
As specified in Schedule 75 and Schedule 175, calculations were carried out separately
and in parallel, for Residential and Non-Residential accounts. For each of these groups of
accounts, the sum of monthly deferral amounts over calendar year 2022 is the cumulative
deferral (rebate or surcharge). The cumulative deferral includes adjustments for prior year
carryover balance, interest, and revenue related expense adjustment.
Electric Group 1 (Residential) and Group 2 (Non Residential)
First the electric service analysis is reviewed, then the analysis for natural gas service.
Decoupled Revenue per Customer-Residential and Non Residential(Schedule 75A))
For electric service, following steps in Schedule 75A,Decoupled Revenue per Customer
(by Rate Group) is developed. Calculation of Decoupled Revenue per Customer(by Rate
Group) is specified in seven steps in Schedule 75A.
Step 1: Step 1 is to enter the Total Normalized 12 Month Ending September 2021
Revenue, individually for each Rate Schedule. Table 1-37, Line 1 shows Total
Normalized Net Revenue. Line 2 shows the Allowed Revenue Increase. The sum of Line
1 and Line 2 is the Proposed Base Rate Revenue (Line 3).
Step 2: Step 2 is to determine the Variable Power Supply Revenue (Line 6). This us
shown is the product of Normalized kWh (Line 4) and Retail Revenue Adjustment from
(Line 5).
Step 3: Step 3 is to enter Delivery and Power Plant Revenue (Line 7). This is
constructed by subtraction of Variable Power Supply Revenue (Line 6) from the Total
Normalized Revenue (Line 3).
Step 4: Step 4 is to Remove Basic Charge Revenue (Line 10). Because the decoupling
mechanism only tracks revenue that varies with customer energy usage, revenue from
already specified Fixed Charges is removed. Basic Charge Revenue is shown on Line 10.
It is the product of the number of Customer Bills in the GRC test year(Line 8) and the
Allowed Basic Charge (Line 9).
1-68

Step 5: In Step 5, the Decoupled Revenue is equal to the Delivery and Power Plant
Revenue (Line 7) minus the Basic Charge Revenue (Line 10). Decoupled Revenue is
shown on Line 11.
Step 6: In Step 6, (see Table 1-36) Decoupled Revenue (from Table 1-35, Line 11 is put
on a per customer basis. The Decoupled Revenue (Residential) from Line 1 in Table 1-36
is divided by the approved Test Year number of residential customers (Table 1-36, Line
2). This determines the annual Allowed Decoupled Revenue per Customer, separately for
the Electric Residential and Non-Residential customer groups (Table 1-36, Line 3).
Step 7: Step 7 converts the annual Allowed Decoupled Revenue per Customer(by Rate
Group) into monthly values. The assignment of monthly values is carried out by
modeling monthly kWh use (by Rate Group) in relationship to the annual kWh use for
the test year. This modeling is shown in Table 1-39.
Kilowatt hours for Group 1 (Residential) for the test year are shown in Line 3 and for
Group 2 (Non-Residential) in Line 6. Both monthly values and the annual kWh values
are shown. Below the monthly values (Lines 4 and 7)monthly percentages are shown.
Lines 11 and 14 use this percentage model, applied to annual Allowed Decoupled
Revenue per Customer(by Rate Group), to generate monthly values.
The monthly values developed following the steps in Schedule 75A are then taken
forward to be used in the implementation of Schedule 75B.
1-69

Table 1-42. 2022 Development of Electric Decoupled Revenue per Customer
Avista Utilities
Electric Decoupling Mechanism
Development of Decoupled Revenue by Rate Schedule-Electric
Washington Docket No.UE-220053 Compliance Filing
RESIDENTIAL GENERAL SVC. LG.GEN.SVC. PUMPING EX LG GEN SVC ST&AREA LTG
TOTAL SCHEDULE 1,2 SCH.11,12,13 SCH.21,22,23 SCH.30,31,32 SCH.25,25I SCH.41-48
1 Total Normalized 12ME Sep 2021 Revenue $ 550,652,000 $ 253,459,000 $ 81,570,000 $ 131,153,000 $ 14,579,000 $ 62,990,000 $ 6,901,000
2 Allowed Revenue Increase(Attachment 1) $ 38,000,000 $ 26,025,000 $ 3,264,000 $ 5,247,000 $ 1,497,000 $ 1,258,000 $ 709,000
3 Proposed Base Rate Revenue $ 588,652,000 $ 279,484,000 $ 94,834,000 $ 136,400,000 $ 16,076,000 $ 64,248,000 $ 7,610,000
4 Normalized kWhs(12ME Sep 2021 Test Year) 5,687,021,474 2,499,403,391 634,803,427 1,300,358,712 163,276,886 1,071,217,134 17,961,924
5 Retail Revenue Adjustment(line 14) �$ 0.01311 $ 0.01311 $ 0.01311 $ 0.01311 $ 0.01311 $ 0.01311 $ 0.01311
6 Variable Power Supply Revenue(L4*L5) $ 74,556,852 $ 32,767,178 $ 8,322,273 $ 17,047,703 $ 2,140,560 $ 14,043,657 $ 235,481
7 Delivery&Power Plant Revenue(L3-L6) $ 456,516,286 $ 246,716,822 $ 76,511,727 $ 119,352,297 $ 13,935,440
8 Customer Bills(12ME Sep 2021 Test Year) 3,137,180 2,681,552 403,355 21,942 30,331
9 Allowed Basic Charges $ 9.00 $ 21.00 $ 600.00 $ 21.00
10 Basic Charge Revenue(Ln 8*Ln 9) $ 46,406,574 $ 24,133,968 $ 8,470,455 $ 13,165,200 $ 636,951
11 Decoupled Revenue $ 410,109,712 $ 222,582,854 $ 68,041,272 $ 106,187,097 $ 13,298,489 Excluded From Decoupling
12 Retail Revenue Adjustment-(Attachment 5 Approved $0.01253
13 Gross Up Factor for Revenue Related Exp 104.60%
14 Grossed Up Retail Revenue Adjustment $0.01311
Residential Non-Residential Group
15 Average Number of Customers(Line 8/12) 223,463 37,969
16 Annual kWh 2,499,403,391 2,098,439,025
17 Basic Charge Revenues 24,133,968 22,272,606
18 Customer Bills 2,681,552 455,628
19 Average Basic Charge $9.00 $48.88
1-70

(4)
Table 1-43. 2022 Electric Decoupled Revenue per Customer
Avista Utilities
Electric Decoupling Mechanism
Development of Annual Decoupled Revenue Per Customer-Electric
Washington Docket No.UE-220053 Compliance Filing
Line Source Residential Non-Residential
No. Schedules*
(a) (b) (c) (d)
1 Decoupled Revenues Attachment 3,Page 1 $ 222,582,854 $ 187,526,858
2 Test Year#of Customers 12 ME Revenue Data 223,463 37,969
09.2021
3 Decoupled Revenue per (1)/(2) $ 996.06 $ 4,938.95
Customer
*Schedules 11, 12, 13,21,22,23,31,32.
Attachment 3,Page 2
Revenues
From revenue per customer $ 222,582,556 $ 187,526,993
From basic charge $ 24,133,968 $ 22,272,606
From power supply $ 32,767,178 $ 27,510,536
Total $ 279,483,702 $ 237,310,134
1-71

(4)
Table 1-44. 2022 Development of Monthly Electric Decoupled Revenue per Customer
Avista Utilities
Electric Decoupling Mechanism
Development of Monthly Decoupled Revenue Per Customer-Electric
Washington Docket No.UE-220053 Compliance Filing
T,w Source Jan Feb Mar Apr h4ay Jun JW Aug Sep Oct Nov Dec TOTAL
No.
(a) (b) (e) (d) (e) (fl (9) (h) (1) (I) (k) (1) () (n) (o)
1 Electric Sale.
2 Residential
3 -Weatbn-Normalized kWh Sales Monthly Te.t Year 269,928,495 231,695,829 237,266,610 182,595,902 169,557,272 145,316,369 202,830,169 207,412,726 155,120,595 174,601,948 234,301,988 288,775,489 2,499,403,391
4 -%ofAmual Total %of Total 10.80% 9.27% 9.49% 7.31% 6.79% 5.81% 8.12% 8.30% 6.21% 6.99% 9.37% 11.55% 100.00%
5 Non-
Residential-6 -Weathu-Normalized kWh Sale. Monody Test Yaar 170,832,385 156,477,576 170,321,875 156,304,005 178,494,305 191,690,896 188,791,635 196,116,120 177,255,646 187,317,716 153,304,398 171,542,469 2,098,439,025
7 -%ofAmwl Total %of Total 8.14% 7.46% 8.12% 7.45% 8.51% 9.13% 9.00% 9.35% 8.45% 8.93% 7.31% 8.17% 100.00%
8 MoMbly Dcc000lcd Rcvcnue Pcr Cu.I.—f"RPC"1
9 Residential
10 -Allowed D—.pled RPC Amubmaut 4,P.2 L 3 $ 996.06
11 -Montldy Decoupled RPC (4)x(10) $ 10T57 $ 92.34 $ 94.56 $ 72.77 $ 67.57 $ 57.91 $ 80.83 $ 82.66 $ 61.82 $ 69.58 $ 93.37 $ 115.08 $ 996.06
12 Non-Resid—W-
13 -Allowed Decoupled RPC Att d—M 4,P.2 L 3 $ 4,938.95
14 -Monthly Decoupled RPC (7)x(13) $ 402.08 $ 368.29 $ 400.87 $ 367.88 $ 420.09 $ 451.17 $ 444.35 $ 461.58 $ 417.19 $ 440.88 $ 360.82 $ 403.75 $ 4,938.95
"Suhedde.11,12,13,21,22,23,31,32.
1-/2

Monthly Decouplinz Deferral
Schedule 75B specifies the method for developing the Monthly Decoupling Deferral for
electric service. Table 1-45 is in two sections. Electric Residential is developed in the top
section; Electric Non-Residential is in the bottom section. Electric Residential deferred
revenue for 2022 is a rebate to customers of$16,125,774 (Line 23, Total Column).
Electric Non-Residential deferred revenue for 2022 is in the surcharge direction in the
amount of$384,924 (Line 48, Total Column). These are intermediate results, subject to
adjustment.
The calculation for Electric Residential steps follows. There are eight steps. The sequence
of the line numbers in Table 1-45 are keyed to the eight steps. Steps 1 through 5 are
required to remove new customers (new hookups) from the calculation.
Electric—Residential(Schedule 75B)
Stepl: Deduct new hookup customers.New hookup customers (Line 5) are deducted
from total actual number of customers (Line 1) to determine the actual number of test
year existing customers each month. The result (actual number of customers after
subtracting out new customers) is in Line 9.
Step 2: Calculate total Allowed Decoupled Revenue each month. This is calculated
by multiplying the number of Actual Customers after removing new customers (Line 9)
by the Monthly Decoupled Revenue per Customer(Line 10). The result is shown on Line
11.
Step 3: Deduct actual new hookup customer revenue from total actual revenue. This
determines the actual test year existing customer revenue collected in the applicable
month. To form this result, Actual Base Rate Revenue (Line 3) is adjusted by subtracting
New Customer Base Rate Revenue (Line 7). The result is shown on Line 12.
Step 4: Deduct actual new hookup customer fixed charge revenue from total actual
fixed charge revenue. Line 4, Actual Customer Basic Charge Revenue, minus Line 8,
New Customer Basic Charge Revenue=Actual Basic Charge Revenue (Test Year
Existing), shown on Line 13.
Step 5: Deduct actual new hookup customer kWh sales from total actual kWh sales.
This is Total Actual kWh Sales (Line 2)minus New Customer Usage, kWh (Line 6). The
result is the Actual Usage, kWh from which new customer actual usage has been
removed(Line 14). Then, Actual Usage (kWh) in Line 14 is multiplied by the approved
1-73

Retail Revenue Credit (Line 15). The result is the revenue collected related to the
variable power supply (Variable Power Supply Payments in Line 16). When Step 5 is
completed, all remaining quantities have been adjusted to remove new customers (new
hookups).
Step 6: Compute Customer Decoupled Payments. Customer Decoupled Payments
(Line 17) =Actual Base Rate Revenue (Line 12) minus the Actual Basic Charge Revenue
Test Year Existing (Line 13) minus Variable Power Supply Payments (Line 16).
Step 7: Compute Balance to be Deferred by the Company as a Surcharge or as a
Rebate. The Balance (for each month) is computed by subtracting Customer Decoupled
Payments (Line 17) from Decoupled Revenue (Line 11). The result(Deferral—
Surcharge/Rebate) is shown on Line 19. This amount is then adjusted for Revenue
Related Expenses (Line 20) and for interest at the FERC rate (rate in Line 21; amount in
Line 22). The result is the Monthly Non-Residential Deferral Total (Line 23). These
monthly amounts are cumulated in Line 23.
Step 8: Comparison.At the end of every 12-month deferral period, the annual
decoupled revenue per customer, by rate group, will be multiplied by the average annual
number of actual test year existing customers. The results of that calculation will be
compared to the actual deferred revenue for the same 12-month period. The difference
between the actual deferred revenue and the calculated value will be added to, or
subtracted from, the total deferred balance by Rate Group. This calculation is shown in
Table 1-46, and results in a decrease of$81,997.37. for Residential.61
Electric—Non-Residential(Schedule 75B)
Stepl: Deduct new hookup customers.New hookup customers (Line 29) are deducted
from the total actual number of customers (Line 25) to determine the actual number of
test year existing customers each month. The result (actual number of customers after
subtracting out new customers) is in Line 33.
Step 2: Calculate total Allowed Decoupled Revenue each month. This is calculated
by multiplying the number of Actual Customers after removing new customers (Line 33)
by the Monthly Decoupled Revenue per Customer(Line 34). The result is shown on Line
35.
61 Table 1-46,Net increase/(decrease)to Decoupled Revenue due to Average Calculation(middle of table
for Residential).
1-74

Step 3: Deduct actual new hookup customer revenue from total actual revenue. This
determines the actual test year existing customer revenue collected in the applicable
month. To form this result, Actual Base Rate Revenue (Line 27) is adjusted by
subtracting New Customer Base Rate Revenue (Line 31). The result, Actual Base Rate
Revenue/Test Year Existing, is shown on Line 36.
Step 4: Deduct actual new hookup customer fixed charge revenue from total actual
fixed charge revenue. Line 32,New Customer Basic Charge Revenue, is subtracted
from Line 28, Actual Basic Charge Revenue. The result, Actual Basic Charge Revenue
(Test Year Existing), is shown on Line 37.
Step 5: Deduct actual new hookup customer kWh sales from total actual kWh sales.
This is Total Actual kWh Sales (Line 26) minus New Customer Usage, kWh (Line 30).
The result is the Actual Usage, kWh from which new customer actual usage has been
removed(Line 14).
Then, Actual Usage (kWh) in Line 14 is multiplied by the approved Retail Revenue
Credit(Line 15). The result is the revenue collected related to the variable power supply
(Variable Power Supply Payments in Line 38). When Step 5 is completed, all remaining
quantities have been adjusted to remove new customers (new hookups).
Step 6: Compute Customer Decoupled Payments. Actual Decoupled Revenue is
calculated by subtracting the Actual Basic Charge Revenue (Test Year Existing) in Line
37 and the Variable Power Supply Payments (Line 40) from the Actual Base Rate
Revenue (Line 36) and is shown on Line 41, Customer Decoupled Payments.
Step 7: Compute Balance to be Deferred by the Company as a Surcharge or as a
Rebate. The Balance (for each month) is computed by subtracting Customer Decoupled
Payments (Line 41) from Decoupled Revenue (Line 35). The result(Deferral—
Surcharge/Rebate) is shown on Line 43.
This amount is then adjusted for Revenue Related Expenses (Line 44) and for interest at
the FERC rate (rate on Line 45; amount on Line 46). The result is the Monthly Non-
Residential Deferral Total (Line 47). These monthly amounts are cumulated in Line 48.
The Total Cumulative Deferral (Rebate)/Surcharge Balance is tracked on Line 49. The
total cumulative deferral for Electric Non-Residential is a refund to customers of
$15,740,850.62
Step 8: Comparison.At the end of every 12-month deferral period, the annual
decoupled revenue per customer, by rate group, will be multiplied by the average annual
number of actual test year existing customers. The results of that calculation will be
62 Table 1-45,line 49,Total Cumulative Deferral(Rebate)/Surcharge)Balance,last column.
1-75

compared to the actual deferred revenue for the same 12-month period. The difference
between the actual deferred revenue and the calculated value will be added to, or
subtracted from, the total deferred balance by Rate Group. This calculation is shown in
Table 1-46 and results an increase of$21,215.50 for Non-Residential.63
61 Table 1-46,Net increase/(decrease)to Decoupled Revenue due to Average Calculation(bottom line for
Non-Residential).
1-76

(4)
Table 1-45. 2022 Development of Electric Deferral
Avista Utilities
UE-200900 Base Effective 10/1/2021&UE-220053 Base Effective 12/21/2022
Development of WA Electric Deferrals(Calendar Year 2022)
Lme No. Source J-22 Fcb-22 Mar-22 Apr-22 May-22 J-22 JW-22 Aug-22 Sep-22 Oct-22 Nov-22 Dec-22 Total
(a) (b) (c) (d) (e) M () (h) () 0) (1) (1) (m) () (o)
ResidenBal Group
I A-1 Cus- Reveme System 225,340 225,717 227,174 226,203 226,093 226,925 226,281 227,405 227,331 227,745 228,126 228,468
2 Actual Usage(M.) Revamp System 298,119,667 244,172,704 232,185,970 201,122,968 170,060,699 152,339,120 204,164,001 243,398,035 165,011,836 157,554,288 259,935,819 326,483,029
3 ACaal Base Rate Revema; Reveme System $ 31,037,264 $ 24,795,549 $ 23,925,579 $ 20,482,252 $ 17,165,401 $ 15,556,305 $ 20,539,173 $ 24,510,120 $ 16,867,527 $ 16,166,683 $ 26,202,119 $ 34,651,046
4 Acual Basic Charge Revemre Revamp System $ 1,937,178 $ 1,949,427 $ 2,319,363 $ 2,070,486 $ 2,071,053 S 2,110,131 $ 2,082,672 $ 2,108,088 $ 2,090,421 $ 2,091,636 S 2,080,899 S 2,089,683
5 New Customers Revenue System 6,092 5,979 6,581 6,766 6,807 7,293 7,741 7,757 8,065 8,610 8,513 6982
6 New Customer Usage(Mhs) Revamp System 6,690,600 5966,653 5,382,277 4,504,116 4,066,391 3,357,456 3,676,368 4,956,756 4,566925 3,815,379 6,192,117 8,787,345
7 New Coaa a-Base Rate Revetwe Revemre System $ 696,383 $ 621,045 $ 561,826 $ 469,930 $ 426,600 $ 359,724 $ 392,623 S 514,010 $ 477,865 $ 410,645 $ 643,597 $ 923,716
8 New Cus-Basic Charge Revenge Revamp Sy- $ 55,008 $ 53,775 $ 59,247 $ 61,031 $ 61,281 S 65,457 $ 69,561 $ 70,137 $ 72,702 S 77,431 $ 76,563 $ 62,875
9 Acaal 0aw-/Tact Yem Exisfig (1)-(5) 219,248 219,738 220,593 219,437 219,286 219,632 218,540 219,648 219,266 219,135 219,613 221,486 2,635,622
10 Mon0dy DecoWled Revenue per CmWaxr Aftactment 3,Pap $98.18 $74.15 $82.10 $60,70 $60.39 $52.67 $69,52 $63.911 $55,14 $61.82 $78.34 $105.55 r $71.87
11 1RcoWW Ravemre (9)x00) $ 21,526,148 $ 16,292,582 $ 18,111,195 S 13,320,682 $ 13,243,529 $ 11,568,593 $ 15,192,069 $ 14,038,192 $ 12,090,939 $ 13,547,426 $ 17,204,385 $ 23,295,840 A S 189,431,581
12 Acual Base Rate Revemre/Test Year Exlseng (3)-(7) $ 30,340,881 $ 24,174,504 $ 23,363,753 S 20,012,322 $ 16,738,801 $ 15,196,581 $ 20,145,550 $ 23,996,110 $ 16,389,662 $ 15,756,038 $ 25,558,522 $ 33,727,330 $ 265,400,054
13 Actual Basic Charge Ravemre/Test Yaar (4)-(S) $ 1,982,170 $ 1,895,652 $ 2,260,116 $ 2,009,455 $ 2,009,772 $ 2,044,674 $ 2,013,111 $ 2,037,951 $ 2,017,719 $ 2,014,205 $ 2,004,336 $ 2,026,809 S 24,215,969
Ebsting
14 Ame]Usage(M.)ITest Year Existing (2)-(6) 291,429,067 238,206,051 226,803,693 196,618,851 165,994,308 148981,664 200,487,633 238,441,279 160,444,911 153,738909 253,743,702 317,695,684 2,592,585,751
15 Retail Revenae C,odil($/kWh) Attachmaat 3,Page 1 $ 0.01360 $ 0.01360 $ 0.01360 S 0,01360 $ 0.01360 $ 0.01360 $ 0.01360 $ 0.01360 $ 0.01360 $ 0.01360 $ 0.01360 $ 0.01343
16 Vmiable Power Supply Pay- (14)a(15) $ 3,963,435 $ 3,239,602 $ 3,084,530 $ 2,674,016 $ 2,257,523 $ 2,026,151 $ 2,726,632 $ 3,242,801 S 2,182,051 $ 2,090,849 $ 3,450914 $ 4,265,423 $ 3"203,'28
17 C.-Decoupled Pay-. (12)-(13)-(16) $ 24,495,276 $ 19,039,250 $ 18,019,106 $ 15,328,851 $ 12,471,507 $ 11,125,756 $ 15,405,807 $ 18,715,358 $ 12,189,892 $ 11,650,984 $ 20,103,272 $ 27,435,098 S 205,9.0,156
18 Residendal R-Per Ca-,Received (17)/(9) $111.72 $8665 $81.68 $69,86 556.87 $50,66 $70.49 $85.21 $55,59 $53.17 $9L54 $123.87 r $78A5
19 Defrral-Surcharge(Rabate) (I1)-(17) $ (2,969,128)$ (2,746,668)$ 92,089 $ (2,008,168)$ 772,022 S 442,837 $ (213,739)S (4,677,165)$ (98953)$ 11896,442 S (2,898,896)S (4,139,258) S (16,548,575)
20 Deferral-Revenue Related Expenses Rev Conv Facmr $ 130,438 S 120,665 $ (4,046)S 88,222 $ (33,916)$ (19,454)$ 9,390 $ 205,475 $ 4,347 $ (83:313)A 127,352 $ 181,844 $ 727,003
21 PERC Rats 3.25% 3.25% 3.25% 325% 3.25% 325% 3.60% 3.60% 360% 4.91% 4.91% 4.91%
22 Imerost on Defertal Avg Balance Cale $ (3,844)$ (11,255)$ (14,722)$ (17,242)$ (18,890)$ (17,368)$ (19,962)$ (26,033)$ (32,960)$ (41,573)$ (43,704)$ (57,M9) $ (304,202)
23 Monthly Residendal Deferral Totals S (2,842,534)$ (2,637,258)S 73,321 $ (1,937,189)$ 719,216 $ 406,015 S (223,311)S (4,497,723)$ (127,566)S 1,771,556 S (2,815,238)$ (4,015,063) $ (16,125,774)
Cumulative Deferral(Rebate)/Surcharge
24 Balance L((19),(20),(22)) $ (2,842,534)$ (5,479,791)$ (5,406,470)$ (7,343,659)$ (6,624,443)$ (6,218,428)$ (6,441,739)$ (10,939,462)S (11,067,028)$ (9,295,473)$ (12,110,7t1)$ (16,125,774)
Note: Table continues,below.
1-77

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1-78

Table 1-46: 2022 Annual (December) True-Up:Electric Residential and Non-Res.
Purpose:As required by UE-190334(UE-190222,consolidated)paragraph 111,the Company is required to calculate decoupled revenue using
YTD average customers,compare to what was recorded using monthly customer counts,and record the difference so that the
annual decoupled revenue is based on YTD average customers.
Procedure:Separately for residential and non-residential,calculated average customers and multiplied that by the sum of decoupled revenue
by month to calculate total allowed decoupled revenue for the period based on average customers.Note,the average customer
and decoupled revenue calculations include a proration for the period UE-200900 authorized base was in effect(1/1/2022-
12/20/2022)and when the UE-220053 authorized base was in effect(12/21/2022-12/31/2022).This was compared to the amount
recorded using monthly actual customers and monthly decoupled revenue per customer.The difference was recorded with the
monthly decoupled revenue for December 2022.
Residential
Average Actual Customers(average of line 9 in Deferral Calc) 219,635
Sum of Decoupled Revenue(sum of line 10 in Deferral Calc) $ 862.48
Total Annual Authorized Decoupled Revenue using Average Actual Customers $ 189,431,581.13
Less Jan-November Decoupled Revenue(sum of line 11 in Deferral Calc for Jan-Nov 2022) 166,135,740.77
Decoupled Revenue to record for December to reflect true-up $ 23,295,840.37
December Actual Customers(line 9,column n in Deferral Calc) 221,486
December Decoupled Revenue per Customer(line 10,column n in Deferral Calc) $ 105.55
Total Decoupled Revenue for December using monthly actuals $ 23,377,837.74
Net increase/(decrease)to Decoupled Revenue due to Average Calculation $ (81,997.37)
Non-Residential
Average Actual Customers(average of line 33 in Deferral Calc) 36,333
Sum of Decoupled Revenue(sum of line 34 in Deferral Calc) $ 4,795.38
Total Annual Authorized Decoupled Revenue using Average Actual Customers $ 174,230,251.61
Less Jan-November Decoupled Revenue(sum of line 35 in Deferral Calc for Jan-Nov 2022) 159,555,881.83
Decoupled Revenue to record for December to reflect true-up $ 14,674,369.78
December Actual Customers(line 33,column n in Deferral Calc) 36,299
December Decoupled Revenue per Customer(line 34,column n in Deferral Calc) $ 403.60
Total Decoupled Revenue for December using monthly actuals $ 14,650,154.27
Net increase/(decrease)to Decoupled Revenue due to Average Calculation $ 24,215.50
For Electric Residential service, the computations developed deferred revenue of
$384,924 in the surcharge direction(from Table 1-47, Line 48, Cumulative Deferrals
(Rebate)/Surcharge Balance, Dec-22 Column. This result is carried over to Table 1-47,
Line 1, 2022 Deferred Revenue. Adjustments, including a Prior Year Carryover Balance
in the rebate direction of$361,979 are shown in Table 1-47. The final result is a
Customer Rebate amount of$18,646,149.64 This rebate is shown in the Customer
Surcharge Revenue line in Table 1-47 as ($18,646,149). There is no Carryover Deferred
Revenue.
64 Letter of Joe Miller, Senior Manager of Rates and Tariffs,Regulatory Affairs,Avista to Amanda
Maxwell,Executive Director and Secretary,Washington Utilities and Transportation Commission,Re:
Tariff WN U-28,Electric Service Electric Decoupling Rate Adjustment,May 31,2023,Page 2 of 6.
1-79

Table 1-47: 2022 Electric Residential Group Rate Determination.
Residential Electric Service: Adjustments
2022 Deferred Revenue $ (16,125,744)
Add: Earnings Sharin DSM Adjustment $ -
Add:Prior Year Carryover Balance $ (361,979)
Add: Interest through 7/31/2024 $ (1,299,204)
Add: Revenue Related Expense Adjustment $ (859,222)
Total Requested Recovery $ (18,646,149)
Customer Surcharge Revenue $ (18,646,149)
Carryover Deferred Revenue $ -
For Electric Non-Residential service, the computations developed deferred revenue of
($16,125,144) in the rebate direction (from Table 1-45, Line 48, Cumulative Deferrals
(Rebate)/Surcharge Balance, Dec-22 Column. This result is carried over to Table 1-48,
Line 1, 2022 Deferred Revenue. Adjustments, including a Prior Year Carryover Balance
in the rebate direction of$2,145,962 are shown in Table 1-48. The final result is a
Customer Rebate amount of$1,888,743.65 This rebate is shown in the Customer
Surcharge Revenue line in Table 1-48 as ($1,888,743). There is no Carryover Deferred
Revenue.
Table 1-48: 2022 Electric Non-Residential Group Rate Determination.
Non-Residential Electric Service: Adjustments
2022 Deferred Revenue $ 384,924
Add: Earnings Sharin DSM Adjustment $ -
Add:Prior Year Carryover Balance $ (2,145,962)
Add: Interest through 7/31/2024 $ (49,720)
Add: Revenue Related Expense Adjustment $ (77,985)
Total Requested Recovery $ (1,888,743)
Customer Surcharge Revenue $ (1,888,743)
Carryover Deferred Revenue $ -11
65 Letter of Joe Miller, Senior Manager of Rates and Tariffs,Regulatory Affairs,Avista to Amanda
Maxwell,Executive Director and Secretary,Washington Utilities and Transportation Commission,Re:
Tariff WN U-28,Electric Service Electric Decoupling Rate Adjustment,May 31,2023,Page 3 of 6.
1-80

Natural Gas Group I (Residential) and Group 2 (Non-Residential)
For natural gas, following steps in Schedule 175A, the Decoupled Revenue per Customer(by
Rate Group) is developed. These steps are implemented in Table 1-49 and Table 1-50.
Monthly Decoupled Revenue per Customer for Group 1: Residential and Group 2: Non-
Residential are then used to develop the Monthly Decoupling Deferral for natural gas in
Table 1-5 1, following the steps in Schedule 175B.
Schedule 175A —Decoupled Revenue per Customer
Step 1: Step I is to enter the Total Normalized Revenue, the final approved base rate
revenue approved in the Company's last general rate case, for each rate class. Table 1-49,
Line I shows 12 ME September 2021 Total Normalized Net Revenue. Line 2 shows Allowed
Revenue Increase. The sum of Line I and Line 2 is shown on Line 3 as the Allowed Rate
Base Recovery.
Step 2: Step 2 is to determine the Variable Gas Supply Revenue. This Variable Gas Supply
Revenue is shown on Line 6. It is the product of Normalized Therms by rate schedule from
the last approved general rate case from Line 4 times the PGA Rates from Line 5.
Step 3: Step 3 is to determine Delivery Revenue, which is entered on Line 7. To determine
the Delivery Revenue, the Variable Gas Supply Revenue is (Line 6) is subtracted from the
Allowed Base Rate Revenue (Line 3).
Step 4: Step 4 is to calculate the Basic Charge Revenue. Because the decoupling mechanism
only tracks revenue that varies with customer energy usage, revenue from Fixed Charges is
removed. It is the product of the number of Customer Bills in the test period on Line 8 times
the Allowed Basic Charges (Line 9). The result, Basic Charge Revenue, is shown on Line 10.
Step 5: Determine the Allowed Decoupled Revenue. The Allowed Decoupled Revenue is
equal to the Delivery(from Line 7)minus the Basic Charge Revenue (Line 10). The resulting
Decoupled Revenue is shown on Line 11.
Step 6: In Step 6, Decoupled Revenue from Line 11 is put on a per customer basis. The
Decoupled Revenue (by Rate Group) is divided by the approved Test Year number of
customers (by Rate Group). This determines the annual Allowed Decoupled Revenue per
Customer(by Rate Group) as shown in Table 1-50.
Step 7: Step 7 is different from the other steps because it converts the annual Allowed
Decoupled Revenue per Customer(by Rate Group) into monthly values. The assignment of
1-81

monthly values is carried out by first calculating the distribution of monthly therm use in the
test year. This calculation is shown in Table 1-51. In Table 51, the therm use for Group 1
(Residential) for test year is shown on Line 4 and for Group 2 (Non-Residential) on Line 8.
Both monthly therm values and the annual therm values are shown. Below the monthly
values, percentages (Lines 5 and 9) are shown. Lines 14 and 18 show the use of these
percentages, applied to annual Allowed Decoupled Revenue per Customer(by Rate Group)
to generate monthly values.
These monthly values are then taken forward to be used in the implementation of Schedule
175B.
1-82

Table 1-49. 2022 Development of Natural Gas Decoupled Revenue per Customer
Natural Gas Decoupling Mechanism
Development of Decoupled Revenue by Rate Schedule-Natural Gas
Washington Docket No.UG-220054 Compliance Filing
RESIDENTIAL GENERAL SVC. LG.GEN.SVC. INTERRUPTIBLE SCHEDULES SCHEDULES
TOTAL SCHEDULE 101/102 SCH.111/112/116 SCH.121/122/126 SCH 131 132 146&148
1 Total Normalized 12 ME Sep 2021 Revenue $ 114,860,000 $ 89,621,000 $ 20,023,000 $ - $ $ 225,000 $ 4,991,000
2 Allowed Revenue Increase(Attachment 2) $ 7,500,000 $ 5,931,000 $ 1,325,000 $ - $ $ 15,000 $ 229,000
3 Allowed Base Rate Revenue $ 122,360,000 $ 95,552,000 $ 21,348,000 $ $ $ 240,000 $ 5,220,000
4 Normalized Therms(12ME Sep 2021 Test Year) 276,863,928 137,376,752 58,747,734 974,878 79,764,564
5 Schedule 150 PGA Rates excluded from base rates $ $ - $ $
6 Variable Gas Supply Revenue $ $ $ - $ $
7 Delivery Revenue (Ln 3-Ln 6) $ 116,900,000 $ 95,552,000 $ 21,348,000 $ $
8 Customer Bills(12ME Sep 2021 Test Year) 2,078,989 2,040,304 38,169 0 0 516
9 Allowed Basic/Minimum Charges $9.50 $128.72 $0.00 $0.00
10 Basic Charge Revenue(Ln 8*Ln 9) $ 24,296,002 $ 19,382,888 $ 4,913,114 $ - $
11 Decoupled Revenue $ 92,603,998 $ 76,169,112 $ 16,434,886 $ - $ - Excluded From Decoupling
Residential Non-Residential Group
12 Average Number of Customers(Line 8/12) 170,025 3,181
13 Annual Therms 137,376,752 58,747,734
14 Basic Charge Revenues $ 19,382,888 $ 4,913,114
15 Customer Bills 2,040,304 38,169
16 Average Basic Charge $9.50 $128.72
1-83

(4)
Table 1-50. 2022 Natural Gas Decoupled Revenue per Customer
Avista Utilities
Natural Gas Decoupling Mechanism
Development of Decoupled Revenue Per Customer-Natural Gas
Washington Docket No.UG-220054 Compliance Filing
Line Residential Non-Residential
No. Source Schedules* Schedules**
(a) (b) (c) (d)
1 Decoupled Revenues Attachment 4,Pagel $ 76,169,112 $ 16,434,886
2 Test Year#of Customers 12 ME 09.2021 Revenue Data 170,025 3,181
3 Decoupled Revenue Per Customer (1)/(3) $ 447.99 $ 5,166.98
*Rate Schedules 101, 102.
**Rate Schedules 111, 112, 116, 131.
1-84

(4)
Table 1-51. 2022 Development of Monthly Natural Gas Decoupled Revenue per Customer
Arista Utilities
Natural Gas Decoupling Mechanism
'Development of Monthly Decoupled Revenue Per Customer-Natural Gas
Washington Docket No.UG-220054 Compliance Filing
Li. Source Jan Feb Mar Apr May Jm Jo1 Aug Sep Oct Nov Dec TOTAL
No.
(a) (b) (e) (d) (e) (fl (9) (b) (1) 0) (k) (1) 00 (n) (n)
1
2 Natural Gas Defie Valume
3 Resident!,!'
4 -Weather-Normalized ThrmDelivery Volume MomWy Rate Year 23,237,417 19,799,163 15,809,740 10,273,404 5,010,740 3,853,445 2,550,010 2,388,834 3,773,642 9,230,472 17,833,780 23,616,107 137,376,752
5 -%ofA-1 Total %of Total 16.92% 14,41% 11.51% 7,48% 3.65% 2.81% 1,86% 1,74% 2.75% 6.72% 12.98% 17.19% 100.00%
6
7 Non-Residentad
8 -Weather-Normalized Tt—Delivery Volume ModWy Rate Year 8,388,798 7,067,063 7,321,090 4,504,842 3,032,887 2,350,236 1,876,476 1,951,922 2,623,332 5,074,866 6,054,567 8,501,656 58,747,734
9 -%ofAmtual Total %ofTotW 14.28% 12.03% 12,46% 7,67% 5.16% 4.00% 3.19% 3,32% 4.47% 8.64% 10,31% 14.47% 100.00%
10
11 M,al Deeouoled Ravenoe Per Customer IMPC")
12 Residential`
13 -Allowed Decoupled RPC Aoaclaned 5,P.2 L 3 $ 447.99
14 -MoutNy Decoupled RPC (5)x(13) $ 75.78 $ 64.57 $ 51.56 $ 33.50 $ 16.34 $ 1257 $ 8.32 S 7.79 $ 12.31 $ 30.10 $ 58.16 $ 7701 $ 447.99
15
16 Non-Reside i,I"
17 -Allowed Dec Wr d RPC Aire hl 5,P.2 L 3 $ 5,166.98
18 -Moalhly Decoupled RPC (9)x(17) $ 737.81 $ 621.56 $ 643.90 $ 396.21 $ 266.75 $ 206.71 $ 165.04 $ 171.68 $ 230.73 $ 446.34 $ 532.51 $ 74T74 $ 5,166.98
19
20 *Rate Schddes 101,102.
21 "Rate SOWWea 111,112,116,131.
1-85

Schedule 175B specifies the method for developing the Monthly Decoupling Deferral for
natural gas service. For Group 1 (Residential), the monthly decoupling deferral amounts
across 2022 sum to the annual total decoupling deferral for 2022. As shown in the top
section of Table 1-43, Line 22, the annual total decoupling deferral for Residential
natural gas is in the direction of a rebate to customers ($1,069,341). The annual total
decoupling deferral for Non-Residential natural gas (bottom section of Table 1-43, Line
44) is $1,302,276 in the direction of a surcharge. These are intermediate results, subject
to adjustment.
There are seven steps. The sequence of the line numbers in Table 1-44 are keyed to the
eight steps. Steps 1 through 5 are required to remove new customers (new hookups) from
the calculation.
Stepl: Deduct new hookup customers. For Residential natural gas, the number of new
hookup customers (Line 5) is deducted from the total actual number of customers (Line
1) to determine the actual number of test year existing customers each month(Line 9)
For Non-Residential natural gas, the number of new hookup customers (Line 27) is
deducted from total actual number of customers (Line 23) to determine the actual number
of test year existing customers each month. The result (actual number of customers after
subtracting out new customers) is in Line 31.
Step 2: Calculate total Allowed Decoupled Revenue each month. For Residential, this
is calculated by multiplying the number of Actual Customers after removing new
customers (Line 9)by the Monthly Decoupled Revenue per Customer(Line 10). The
result is shown on Line 11.
For Non-Residential, this is calculated by multiplying the number of Actual Customers
after removing new customers (Line 31)by the Monthly Decoupled Revenue per
Customer(Line 32). The result is shown on Line 33.
Step 3: Deduct actual new hookup customer revenue from total actual revenue. This
determines the actual test year existing customer revenue collected in the applicable
month. For Residential, Actual Base Rate Revenue (Line 3) is adjusted by subtracting
New Customer Base Rate Revenue (Line 7). The result is shown on Line 13.
For Non-Residential, Actual Base Rate Revenue (Line 25) is adjusted by subtracting New
Customer Base Rate Revenue (Line 29). The result is shown on Line 35.
Step 4: Deduct actual new hookup customer fixed charge revenue from total actual
fixed charge revenue. For Residential,New Customer Fixed Charge Revenue (Line 8),
is subtracted from Line 4, Actual Fixed Charge Revenue. The result, Actual Fixed Charge
Revenue (Test Year Existing), is shown on Line 14. For Non-Residential,New Customer
Fixed Charge Revenue (Line 30), is subtracted from Line 26, Actual Fixed Charge
Revenue. The result, Actual Fixed Charge Revenue (Test Year Existing), is shown on
Line 36.
1-86

Step 5: Calculate Actual Decoupled Revenue. For test year existing customers,
subtract the basic charge revenue (Step 4) from the total actual monthly revenue
(Step 3).
For Residential, this is Line 13 minus Line 14, and the result is shown in Line 15.
For Non-Residential, this is Line 35 minus Line 36, and the result is shown in Line 37.
When Step 5 is completed, all remaining quantities have been adjusted to remove new
customers (new hookups).
Step 6: Compute the difference between the Actual Decoupled Revenue (Step 5)
and the Allowed Decoupled Revenue (Step 2).
For Residential, this is Allowed Decoupled Revenue (Line 11) minus Actual Decoupled
Revenue (Line 15). The result, Deferral— Surcharge (Rebate) is shown on Line 17.
For Non-Residential, this is Allowed Decoupled Revenue (Line 33) minus Actual
Decoupled Revenue (Line 37). The result, Deferral—Surcharge (Rebate) is shown on
Line 39.
Step 7: Compute Balance to be Deferred by the Company as a Surcharge or as a
Rebate. The Balance (for each month) is computed by subtracting Customer Decoupled
Payments (Line 17) from Decoupled Revenue (Line 11).66 The result (Deferral—
Surcharge/Rebate) is shown on Line 19. This amount is then adjusted for Revenue
Related Expenses (Line 20) and for interest at the FERC rate (rate in Line 21; amount in
Line 22). The result is the Monthly Non-Residential Deferral Total (Line 23). These
monthly amounts are cumulated in Line 24. For Residential Natural Gas, the Total
Cumulative Deferral (Rebate)/Surcharge Balance is tracked in Line 24. The total
cumulative deferral for Residential Natural Gas is a refund to customers of$1,069,341.67
Adjustments, conveyed in the filing, result in a final Residential surcharge of$801,749,
which includes a prior year carryover balance of$1,852,020 and other adjustments (Table
1-52).68
66 There is a typing error in Table 1-54 on Line 17. The Source on this line is"(12)—(15)".The Source
should be corrected to(11)—(15).However,the calculation is correct.
67 Table 1-38,line 23,Total Cumulative Deferral(Rebate)/Surcharge)Balance,last column.
68 Letter,re: Tariff WN U-29,Natural Gas Service Decoupling Rate Adjustment from Joe Miller,Avista
Senior Manager for Rates and Tariffs,Regulatory Affairs to Amanda Maxwell,Executive Director and
Secretary,Washington Utilities and Transportation Commission dated May 31,2023,P.2 of 5.
1-87

Table 1-52: 2022 Natural Gas Residential Group Rate Determination.
Residential Natural Gas Service: Adjustments
2022 Deferred Revenue $(1,069,341)
Add: Earnings Sharing/DSM Adjustment $ -
Add:Prior Year Carryover Balance $ 1,852,020
Add: Interest through 7/31/2024 $ (18,168)
Add: Revenue Related Expense Adjustment $ 37,238
Total Requested Recovery $ 801,749
Customer Surcharge Revenue $ 801,749
Carryover Deferred Revenue $ -
For Non-Residential Natural Gas, the Total Cumulative Deferral (Rebate)/Surcharge
Balance is tracked in Line 44. The total cumulative deferral for Non-Residential Natural
Gas is a surcharge to customers of$1,302,276.69 Adjustments, conveyed in the filing,
result in a final Non-Residential surcharge of$2,439,376, including a prior year
carryover balance of$893,830 and other adjustments (Table 1-53).70
Table 1-53: 2022 Non-Residential Group Rate Determination.
Non-Residential Natural Gas Service: Adjustments
2022 Deferred Revenue $ 1,302,276
Add: Earnings Sharing/DSM Adjustment $ -
Add:Prior Year Carryover Balance $ 893,830
Add: Interest through 7/31/2024 $ 133,503
Add: Revenue Related Expense Adjustment $ 109,587
Total Requested Recovery $ 2,439,196
Customer Surcharge Revenue $ 2,439,196
Carryover Deferred Revenue $ -
69 Table 1-53,line 1;also Table 1-54.2022 Development of Natural Gas Deferral,Line 44,Col. for Dec 22.
70 Letter,re: Tariff WN U-29,Natural Gas Service Decoupling Rate Adjustment from Joe Miller,Avista
Senior Manager for Rates and Tariffs,Regulatory Affairs to Amanda Maxwell,Executive Director and
Secretary,Washington Utilities and Transportation Commission dated May 31,2023,P.3 of 5.
1-88

(4)
Table 1-54. 2022 Development of Natural Gas Deferral
Avista Utilities
UG-200901 Base effective 10/1/2021&UG-220054 Base Effective 12/21/2022
Development of WA Natural Gas Deferrals(Calendar Year 2022)
Line No. Source Jan-22 Feb-22 Mar-22 Apr-22 May-22 J-22 JU1-22 Aug-22 Sep-22 Oct-22 Nov-22 Dec-22 Total
(a) (b) (e) (d) (a) (fl (9) (h) () 0) (k) (1) (m) () (o)
Reai&ntial Group
1 Actual Customers Re-System 171,222 172,123 172,311 171,878 171972 172,276 171,944 172,697 172,525 173,078 173,064 173,277
2 Aetnal Osage("Therms) Revenue System 24,141,719 19,934,381 14,505,566 12,164,376 7,551,453 3,523,739 2,229,894 1990,698 2,613,036 5,706,305 21,188,427 26,644,710
3 Actual Base Rare Revenue Revenue System $ 16,278,380 $ 12,143,142 $ 9,194,876 $ 7,613,021 $ 5,236,420 $ 3,052,464 $ 2,735,719 $ 2,495,087 $ 2,973,593 $ 4,046,731 $ 9,960,873 $ 16,063,880
4 Actual Fixed Charge Revenue Reversre System $ 1,582,909 $ 1,580,810 $ 1,785,307 $ 1,651,167 $ 1,647,338 $ 1,675,182 $ 1,656,962 $ 1,668,096 S 1,661,351 $ 1,664,609 $ 1,657,076 $ 1,664,875
5 Nev,Cusroners Revenue System 5,027 4,919 5,319 5,486 5,626 5,909 6,020 6,131 6,263 6,507 6,548 5,495
6 New C..-Osage(The-) Revenue System 733,867 586,310 484,749 359,959 276,701 147,883 68,159 46,312 52,212 97,214 418,653 704,118
7 New Customer Base Rate Reveras, Revenue System $ 445,830 $ 358,010 $ 300,613 $ 232,206 $ 189,753 $ 127,268 $ 90,171 $ 80,566 $ 84,774 $ 110,000 $ 274,521 $ 433,567
8 New Customer Fixed Chazge Rever- Revenue System $ 47,890 $ 46,674 $ 50,531 $ 51,984 $ 53,447 $ 56,041 $ 57,257 $ 58,373 $ 59,656 $ 62,339 $ 62,482 $ 52,033
9 Actual/Test Year Existing Customers (1)-(5) 166,195 167,204 166,992 166,392 166,346 166,367 165,924 166,566 166,262 166,571 166,516 167,782 1,999,117
10 Moaddy Decoupled Revenue per Cas- Attachment 4,Page 3 $68.62 $55.50 $47.89 $29.05 $19.22 $9.76 $8.46 $8.42 $8.62 $31.60 $53.33 $72.83 $413.29
11 De-TI,iRevenue (9)x(10) $ 11,403,480 $ 9,280,066 $ 7,997,292 $ 4,832,923 $ 3,196,506 $ 1,623,893 $ 1,403,708 $ 1,402,411 $ 1,433,693 $ 5,262,847 $ 8,880,136 $ 12,084,082 A $ 68,801,036
12 Act"'t Urge/Test Year Existing (2)-(6) 23,407,852 19,348,071 14,020,817 11,804,417 7,274,752 3,375,856 2,161,734 1,944,385 2,560,824 5,609,092 20,769,773 25,940,592 138,218,167
Actual Base Rate Be,-/Test Year
13 Enietiog (3)-(7) $ 15,832,549 $ 11,785,133 $ 8,894,264 $ 7,380,815 S 5,046,667 $ 2,925,197 $ 2,645,549 $ 2,414,521 $ 2,888,819 $ 3,936,730 $ 9,686,351 $ 15,630,313 $ 89,066,907
14 Actad Fixed Charge Revenue/Test Year (4) (g) $ 1,535,020 $ 1,534,136 $ 1,734,776 $ 1,599,183 $ 1,593,891 $ 1,619,141 $ 1,599,705 $ 1,609,722 $ 1,601,695 $ 1,602,270 $ 1,594,594 $ 1,612,842 $ 19,236,973
Existing
15 Custom Decoupled Payments (13)-(14) $ 14,297,530 $ 10,250,997 $ 7,159,488 $ 5,781,633 S 3,452,776 $ 1,306,056 $ 1,045,844 $ 804,799 $ 1,287,124 $ 2,334,460 $ 8,091,757 $ 14,017,471 $ 69,829933
16 Residential Revenue Per C.-r Received (15)/(9) $86.03 $61.31 $42.87 $34.75 $20.76 $7.85 $6.30 $4.83 $7.74 $14.01 $48.59 $83.55
17 Deferral-Surcharge(Rehate) (12)-(15) $ (2,894,050)$ (970,931)$ 837,805 $ (948,710)$ (256,270)$ 317,838 $ 357,864 $ 597,612 $ 146,569 $ 2,928,387 $ 788,379 $ (1,933,389)
18 Deknal-Revenue Related Experaes Rev Cony Factor $ 126,522 $ 42,447 $ (36,627)$ 41,476 $ 11,204 $ (13,895)$ (15,645)$ (26,126)$ (6,408)$ (128,023)$ (34,466)$ 84,524 $ 44,981
19 FERC Rare 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 3.60% 3.60% 3.60% 4.91% 4.91% 4.91%
20 hawreat on Deferral Avg Balance Cale $ (3,747.69)$ (8,763)$ (8,959)$ (9,127)$ (10,712)$ (10,661)$ (10,872)$ (9,534)$ (8,495)$ (5,606)$ 1,643 $ (590) $ (85,425)
21 Monthly Residential Deferral Totals $ (2,771,275)$ (937,246)$ 792,219 $ (916,361)$ (255,778)$ 293,291 $ 331,347 $ 56051 $ 131,666 $ 2,794,758 $ 755,555 $ (1,949,456) $ (1,069,341)
22 Cunmlative Deferral(Rebate)Balaree £((17),(18),(20)) $ (2,771,275)$ (3,708,522)$ (2916,303)$ (3,832,664)$ (4,088,443)$ (3,795,161)$ (3,463,815) $ (2901,863)$ (2,770,198)$ 24,560 $ 780,115
Note: Table continues on following page.
1-89

nA
t'(.;.WWI B.v./Rcew.301:021A UG.-W064 B-I Rwta.l221'=
Dw.hwmtat oft,.,N w-.1 Ge:D.I-k:t C.1 da Y-W=)
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14m-Pesideaiel Gronp
23 .steal C- P.-D- 3.651 19DD 3366 3.304 33C2 3381 3314 3361 3354 3356 3385 3
24 .k-IU-_-(Tr-s) F->;ne 2yti- 89ILM 7.967.454 4530.M 594897 3861S43 140098 L968103 1.313.652 2.235.429 4267.107 8.418.166 10113
25 .k-1&e Pate Rew-- Pet-->p 2- $ 3.409.446 S Z35IL346 S 2.333.718 S 1$74®B S 14r.454 S 1.061,047 $ 795556 S 821.185 S 868.71. S MUM S 1.3649DD S 3.234
26 .steal Flied C2-R-- P,-se 2- S 37Ur S 36919 S 444.113 $ 395127 $ 394593 $ 404.747 S 395900 S 401.159 S 401540 $ 40034D S 4(3.849 S 412
27 "zn Cwtrn-s F.,->Y 2y- 56 55 65 65 A 72 73 74 79 90 87
28 2' C. -ikale(ib-o h..,->E�.- 214.127 170S57 116.646 137 W 119-796 95.403 PL553 105933 105-227 168681 225347 268
29 Pet--se 2,-- i 63.655 S 51363 S 39.917 S 41740 S 40.09 S 31.494 S 22304 S 31.144 S RAN S 47.M S 4s-w S 81
30 Nr.-C.i -Fiu6 Chats Panne F.- 2y- S 7519 $ 4454 S 7512 S 7.84 S 8.116 $ 8.448 S 8564 S Mel $ 9.098 S 1044D S 10.033 S 9
31 Tesff-EtnfigO. -s (23)-(27) 3595 1345 3301 1239 3.232 3309 3.241 3267 3275 3.266 3298 3
32 XbttH,SY=1e6Ree- MCwo-r S:3683 SOD-61 55260 S42895 S2,M8 S22319 SIM 77 Sir,11 S23170 S39948 S59498 A,
33 Ikcovped IL-tie (31)1(32) S 1648.919 $ 1850972 $ L738392 S 1389.385 S 895,21R S M-10 S 58RI28 $ 61508 $ 75ILS21 S MOT S 1962247 S 2481
34 -4casal Tkap(TTemz Test Ye-Fiii6q (24)-(26) 8.697.7(3 7.794597 6414.194 5397198 3741.747 2305A35 LVCL551 1.707.719 2.13D101 4098423 8.191819 9.841
.anal Bae Rate Rewae Test Y+-
35 Eastim (251429) S 3345.791 S 1504993 S 2343900 S 1-934960 S 1447390 S 1.029554 S 7662A S 10-040 S 877239 S 950307 S 1301-29 S 3.15-1
36 .4,w1Fhe6C1,e Re- TestY"est
F.i.th. (35)-( S 366380 S 363264 S 436531 S 387443 $ 386.479 S 396298 S 387336 $ 392476 $ 392443 S 3849W S 393.817 S 409
37 Ctw®-SXovpLdlt ->G (35)-(36) S 29�.411 S 114319 S L907370 S 1.447.515 S L060911 S 633155 S 378917 $ 397564 S 444..W $ 560401 S 907.723 S 24-1
38 1k.Rei6etwl F--S4Cwc-sR- (37)!(31) S8287 $75350 $57.82 SOU0 $32325 S19137 $11691 $12095 $13582 51159 S2'S23 SE
39 Ik-1-Swd p?hte) (33)-(3-) $ (330.492)$ (292741)$ PdB-wm$ (A131)S (1d000I)$ 105.ro S 20,211 $ 217.474 $ 314995 S 744.20 $ 1.05494 S (262
40 Tkfettal-Re-Rehe6 Fip-ras Rn Can Fxex S 14.448 S 12798 $ 7387 S 2.341 S 7244 S (4-MI)3 (2190)S (9.SOq S (13.72%3 (32537)S (46.102)S 11
41 FFRC Rae 3-25'.: 375% 31511. 325% 3251:6 325% 364: 3.WX 3-COX 491X 4.91'. 4
42 lte tmlkiatal AaSBahrce Cat S 1429)S (1238 1 elR3-)1 I"t,1 QA-S (151-)S (1343)S (I AT S (9901 S 731 S 433 t
43 U thk N-R-&.ti.l1k A! .dunk. $ (316,471)$ (281,1&9 S (163,428)S (57,716) S (160.PT)S 98.140 S 194678 S 206230 $ 299317 S 111481 S 1,012,675 S (244
44 Ctr U da-Ikfettal(Rehse)Baler- 2((39).(40).(42)) $ (316.471)$ (597.06)$ (761.084)S (81881) $ (9A.i07$ (88155M $ (818:9)S (4115.649!S (I-33Z $ 535142 $ 1547.814 $ I.
45 T9.IC.-htk.lkferti(Reh.te) (22)+(44) S (3.067.747)S (4304173)$ (3677387)$ (4.65t474) S (5068.149)$ (4.616.18) $ (4144699)S (337651A S (2.%7.R9i S $59.710 $ 2327940 S 232
Note: For December(only) there is an additional workpaper.
1-90

2022 Earnings Test
The decoupling mechanism, in Schedules 75D and 175D provides for application of an
earnings test,71 separately for electric and for natural gas.72
Schedule 75D—Electric Earnings Test
According to Schedule 75D, the decoupling mechanism for decoupled electric customers
is subject to an annual earnings test based on the Company's year-end Commission Basis
Reports that reflect actual decoupling-related revenues and various normalizing
adjustments. As shown in Table 1-55, Line 3, the rate of return on a normalized basis in
2022 is 6.12%. This is less than the 7.03% allowed return. If the return on a normalized
basis had been above 7.03%, one-half of the revenue in excess of the allowed rate of
return would have been shared with customers through the decoupling rate adjustment.
Since the return on a normalized basis is less than the allowed rate of return, no earnings'
sharing adjustment is applied to the 2022 deferred balances for Residential or for Non-
Residential Electric Service.
Table 1-55. 2022 Electric Earnings Test
2022 Commission Basis Earnings Test for Decoupling
Line No. Electric
1 Rate Base $ 2,019,378,000'
2 Net Income $ 123,620,000'
3 Calculated FOR 6.12%
4 Base ROR 7.03%
5 Excess ROR -0.91%
6 Excess Earnings $ -
7 Conversion Factor 0.755295
8 Excess Revenue(Excess Earnings/CF) $ -
9 Sharing% 50 o
10 2021 Total Earnings Test Sharing
71 Information on the background of the Earnings Test is limited to information provided in the Tariff.In
response to Data Request 092,Avista states that"[t]he calculation of excess earnings was agreed upon as
part of the Settlement process in Docket Nos. 140188 and 140189. All information regarding the excess
earnings test is included in the Tariff Schedule 75D."
72 Rate of Return is not related to the operation of the 3%cap.In response to DR 091,Avista states that
"Rate of Return(ROR)is net income divided by rate base for a given annual period.The combination of
three elements,namely revenues,expenses,and rate base,determine the resulting ROR.Changes to the
relationship among all of these elements will impact the actual or normalized actual ROR achieved each
year. The 3%cap impacts the timing of amortization of prior year deferred revenue and as such does not
impact earnings or rate base during the amortization period because surcharge revenues from customers are
offset by deferred revenue amortization for a net income impact of$0 and the deferred revenue on the
balance sheet is not included in rate base."
1-91

Schedule 175D —Natural Gas Earnings Test
According to Schedule 175D, the decoupling mechanism for natural gas is subject to an
annual earnings test based on the Company's year-end Commission Basis Reports that
reflect actual decoupling-related revenues and various normalizing adjustments. As
shown in Table 1-56, the rate of return on a normalized basis in 2012 is 6.35% (Line 3).
This is less than the 7.03% allowed return(Line 4). Since the calculated rate of return is
less than the allowed rate of return, no earnings' sharing adjustment is applied to the 2022
decoupling deferred balances for Residential Natural Gas service or for Non-Residential
Natural Gas service.
Table 1-56. 2022 Natural Gas Earnings Test
2022 Commission Basis Earnings Test for Decoupling
Line No. Natural Gas
1 Rate Base $ 497,381,000
2 Net Income $ 31,582,000
3 Calculated ROR 6.35%
4 Base ROR Pro-rated 7.03%
5 Excess ROR -0.68%
6 Excess Earnings $ -
7 Conversion Factor 0.755463
8 Excess Revenue(Excess Earnings/CF) $ -
9 Sharing% 50%
10 2022 Total Earnings Test Sharing $
Three Percent Annual Rate Increase Limitation 2022
Decoupling annual rate adjustment surcharges are subject to a 3% annual rate increase
limitation (there is no reciprocal limit on rebate rate adjustments). The test is to divide the
incremental annual revenue to be collected (proposed surcharge revenue minus present
surcharge revenue)by the total "normalized"revenue for the two Rate Groups for the
most recent January through December.
Normalized revenue is determined by multiplying the weather-corrected usage for the
period by the present rates in effect. If the incremental amount of the proposed surcharge
exceeds 3%, only a 3% incremental rate increase will apply. Any remaining deferred
revenue will be carried over to the following years, in this instance to 2024.
1-92

Schedule 75E—Electric 3% Rate Increase Test
The Electric Incremental Surcharge Test is shown in Table 1-57. Specifications for the
test limit the surcharge to 3%, with any remainder deferred to the following year. For
both Residential customers and Non-Residential customers, the result for the Incremental
Decoupling Recovery Rate is negative (Line 7), so there is no Carryover Deferred
Revenue.
Table 1-57: 2022 Electric 3%Annual Rate Increase Limitation.
3%Incremental Surcharge Test
Line No. Residential Non-Residential
1 Revenue From 2021 Normalized Loads and Customers at
Present Billing Rates(Note 1) $ 268,876,060 $ 230,393,192
2 August 2022-July 2023 Usage(kWhs) 2,571,886,722 2,146,299,272
3 Proposed Decoupling Recovery Rates -$0.00725 -$0.00088
4 Present Decoupling Surcharge Recovery Rates -$0.00234 $0.00132
5 Incremental Decoupling Recovery Rates -$0.00491 -$0.00220
6 Incremental Decoupling Recovery $ (12,627,964) $ (4,721,858)
7 Incremental Surcharge% -4.70% -2.05%
8 3%Test Adjustment(Note 2) $ - $ -
9 3%Test Rate Adjustment $0.00000 $0.00000
10 Adjusted Proposed Decoupling Recovery Rates -$0.00725 -$0.00088
11 Adjusted Incremental Decoupling Recovery $ (12,627,964) $ (4,721,858)
12 Adjusted Incremental Surcharge% -4.70% -2.05%
Notes
(1) Revenue from 2022 normalized loads and customers at present billing rates effective since
December 21,2022.
(2) The carryover balances will differ from the 3%adjustment amounts due to the revenue related
expense gross up partially offset by additional interest on the outstanding balance during the
amortization period.
1-93

Schedule 175E—Natural Gas 3% Rate Increase Test
The Natural Gas Incremental Surcharge Test is shown in Table 1-58 The test limits the
Residential and the Non-Residential Surcharge each to 3%. For the Residential Group,
the Incremental Surcharge Percent (Line 7) is negative, so there is no Carryover Deferred
Revenue (Line 8). For the Non-Residential Group, the incremental surcharge is below 3%
(Line 7), so there is no Carryover Deferred Revenue amount(Line 8)to be to be deferred
to the following year.
Table 1-58. 2022 Natural Gas 3%Rate Increase Limitation.
3%Incremental Surcharge Test
Line No. Residential Non-Residential
Revenue From 2022 Normalized Loads and
1 Customers at Present Billing Rates(Note 1) $ 184,901,129 $ 58,976,140
2 August 2023-July 2024 Usage 136,584,128 61,178,736
3 Proposed Decoupling Recovery Rates $0.00587 $0.03987
4 Present Decoupling Surcharge Recovery Rates(2) $0.03899 $0.02866
5 Incremental Decoupling Recovery Rates -$0.03312 $0.01121
6 Incremental Decoupling Recovery $ (4,523,666) $ 685,814
7 Incremental Surcharge% -2.45% 1.16%
8 3%Test Adjustment(3) $ - $ -
9 3%Test Rate Adjustment $0.00000 $0.00000
10 Adjusted Proposed Decoupling Recovery Rates $0.00587 $0.03987
11 Adjusted Incremental Decoupling Recovery $ (4,523,666) $ 685,814
12 Adjusted Incremental Surcharge% -2.45% 1.16%
Notes
(1) Revenue from 2022 normalized loads and customers at present billing rates effective
since November,2023.
(3) The carryover balances will differ from the 3%adjustment amounts due to the revenue
related expense gross up partially offset by additional interest on the outstanding balance
during the amortization period.
1-94

Audit Statements: Is the Source Data Credible?
Having reviewed calculations for conformance to Schedule 75 and Schedule 175, the
second step in the Task 1 analysis is to validate the general credibility of the test period
costs and revenues, balance sheets, load projections, and other company financial data.
Since this data was audited by a professional audit team (Deloitte & Touche LLP)that
provides an opinion regarding the accuracy of the data, we are relying on their
professional opinion to validate the financial integrity of the data.
The Reports of the Independent Registered Public Accounting Firm for the Avista
Corporation and subsidiaries for calendar years 2020'73 2021,74 and 2022,7'based on
certified audits of the company's accounting practices are shown in Figures 1-2, 1-3, and
1-4, respectively. Each Independent Registered Public Accounting Report expresses an
unqualified opinion on the Company's internal control over financial reporting. These
opinions validate the data used to implement the Avista electric and natural gas
decoupling mechanisms.
The Deloitte & Touche LLP "Report of Independent Registered Public Accounting Firm"
for the twelve-month period ending December 31, 2020, is shown as Figure 1-2. The
audit statements for 2021 and 2022 are shown in Figure 1-3 and 1-4.
73 Avista Energy,US Securities and Exchange Commission,Form IOK,February 23,2021,P. 138.
74 Avista Energy,US Securities and Exchange Commission,Form IOK,February 22,2022,P. 137.
75 Avista Energy,US Securities and Exchange Commission,Form IOK,February 23,2023,P. 137.
1-95

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM To the shareholders and the Board of Directors of Avista Corporation
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Avista Corporation and subsidiaries(the"Company")as of December 31,2020,based on
criteria established in Internal Control-Integrated Framework(2013)issued by the Committee of Sponsoring Organizations of the Treadway
Commission(COSO).In our opinion,the Company maintained,in all material respects,effective internal control over financial reporting as of December
31,2020,based on criteria established in Internal Control-Integrated Framework(2013)issued by COSO.
We have also audited,in accordance with the standards of the Public Company Accounting Oversight Board(United States)(PCAOB),the consolidated
financial statements as of and for the year ended December 31,2020,of the Company and our report dated February 23,2021,expressed an unqualified
opinion on those financial statements.
Basis for Opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness
of internal control over financial reporting,included in the accompanying Management's Report on Internal Control Over Financial Reporting.Our
responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.We are a public accounting firm
registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S.federal securities laws and the
applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB.Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether effective internal control over financial reporting was maintained in all material respects.Our audit included obtaining an
understanding of internal control over financial reporting,assessing the risk that a material weakness exists,testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk,and performing such other procedures as we considered necessary in the circumstances.We
believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting)
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.A company's internal
control over financial reporting includes those policies and procedures that(1)pertain to the maintenance of records that,in reasonable detail,accurately
and fairly reflect the transactions and dispositions of the assets of the company;(2)provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with generally accepted accounting principles,and that receipts and expenditures of
the company are being made only in accordance with authorizations of management and directors of the company;and(3)provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition,use,or disposition of the company's assets that could have a material effect on the
financial statements.
Because of its inherent limitations,internal control over financial reporting may not prevent or detect misstatements.Also,projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions,or that the degree of
compliance with the policies or procedures may deteriorate.
/s/Deloitte&Touche LLP
Portland,Oregon
February 23,2021
Figure 1-2. Financial Audit Opinion for Calendar 2020
1-96

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM To the shareholders and the Board of Directors of Avista
Corporation Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Avista Corporation and subsidiaries(the"Company")as of December 31,2021,
based on criteria established in Internal Control—Integrated Framework(2013)issued by the Committee of Sponsoring Organizations of the
Treadway Commission(COSO).In our opinion,thel Company maintained,in all material respects,effective internal control over financial reporting
as of December 31,2021,based on criteria established in Internal Control—Integrated Framework(2013)issued by COSO.
We have also audited,in accordance with the standards of the Public Company Accounting Oversight Board(United States)(PCAOB),the
consolidated financial statements as of and for the year ended December 31,2021,of the Company and our report dated February 22,
2022,expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting,included in the accompanying Management's Report on Internal Control Over Financial
Reporting.Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.We are a public
accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S.federal
securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB.Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.Our
audit included obtaining an understanding of internal control over financial reporting,assessing the risk that a material weakness exists,
testing and evaluating the design and operating effectiveness of internal control based on the assessed risk,and performing such other
procedures as we considered necessary in the circumstances.We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles.A company's internal control over financial reporting includes those policies and procedures that(1)pertain to the maintenance of
records that,in reasonable detail,accurately and fairly reflect the transactions and dispositions of the assets of the company;(2)provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally
accepted accounting principles,and that receipts and expenditures of the company are being made only in accordance with authorizations of
management and directors of the company;and(3)provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition,use,or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations,internal control over financial reporting may not prevent or detect misstatements.Also,projections of any
evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may deteriorate.
/s/Deloitte&Touche LLP
Portland,Oregon
February 22,2022
Figure 1-3. Financial Audit Opinion for Calendar 2021.
1-97

PORT OF INDEPENDENT REGISTERED
UBLIC ACCOUNTING FIRM To the
shareholders and the Board of Directors of Avista
Corporation Opinion on Internal Control over
Financial Reporting
e have audited the internal control over financial reporting of Avista Corporation and subsidiaries(the"Company")as of
December 31,2022,based on criteria established in Internal Control—Integrated Framework(2013)issued by the
Committee of Sponsoring Organizations of the Treadway Commission(COSO).In our opinion,the Company maintained,
in all material respects,effective internal control over financial reporting as of December 31,2022,based on criteria
established in Internal Control—Integrated Framework(2013)issued by COSO.
We have also audited,in accordance with the standards of the Public Company Accounting Oversight Board(United States)
(PCAOB),the consolidated financial statements as of and for the year ended December 31,2022,of the Company and our
report dated February 21,2023,expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting,included in the accompanying Management's
Report on Internal Control Over Financial Reporting.Our responsibility is to express an opinion on the Company's internal
control over financial reporting based on our audit.We are a public accounting firm registered with the PCAOB and are
required to be independent with respect to the Company in accordance with the U.S.federal securities laws and the
applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
e conducted our audit in accordance with the standards of the PCAOB.Those standards require that we plan and perform
he audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in
all material respects.Our audit included obtaining an understanding of internal control over financial reporting,assessing the
risk that a material weakness exists,testing and evaluating the design and operating effectiveness of internal control based
on the assessed risk,and performing such other procedures as we considered necessary in the circumstances.We believe that
our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles.A company's internal control over financial reporting includes those policies and
procedures that(1)pertain to the maintenance of records that,in reasonable detail,accurately and fairly reflect the
transactions and dispositions of the assets of the company;(2)provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with generally accepted accounting principles,and that
receipts and expenditures of the company are being made only in accordance with authorizations of management and
directors of the company;and(3)provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition,use,or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations,internal control over financial reporting may not prevent or detect misstatements.Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions,or that the degree of compliance with the policies or procedures may deteriorate.
sl Deloitte&Touche LLP
Portland,Oregon
lFebruary 21,2023
Figure 1-4. Financial Audit Opinion for Calendar 2022.
1-98

Summary - Fidelity
Based on our analysis of three years of data, we conclude that Avista has calculated rates
and deferrals for the first through the third Decoupling Years in accordance with the
Commission Order approving the decoupling mechanisms.
The purpose of the Decoupling Mechanism is to decouple the Company's Commission-
authorized revenues from sales, such that the portion of the Company's fixed costs
planned for recovery through volumetric sales and not otherwise recovered from actual
energy sales will be recovered through the mechanism. In decoupling, the revenue
requirement for a given year is first set. The portion of fixed costs collected through the
fixed portion of customer bills is not included in the analysis. Since volumetric sales
fluctuate and may not fully cover the fixed cost component included within the
volumetric portions of customer rates, the difference between actual decoupling-related
revenue received from customers through volumetric rates, and the decoupling-related
revenue approved for recovery through volumetric rates is accumulated in deferred
revenue accounts.
Operationally, this compliance verification was carried out in two steps:
• First, we traced calculations to insure conformance with Schedule
75(A, B, C, D, E) and Schedule 175(A, B, C, D, E). In carrying out this
analysis, we checked to see that the reported calculations matched the
methodological specifications in each Schedule. Also, we checked for
2020, 2021 and 2022 the component Excel spreadsheets introduced as
Avista Exhibits for the annual filings for Tariff WN U-28 Electric
Service for Electric Decoupling Rate Adjustment; and for Tariff WN
U-29 Natural Gas Service for Natural Gas Decoupling Rate Adjustment
for each of the three years examined.
• Second, we have included the opinions of the independent auditor for
2020, 2021 and 2022 to indicate the validity of the financial data upon
which the calculations depend.
The overall result in this section of the analysis is that we find the deferrals and rates to
have been calculated by the Company in accordance with the Commission guidance as
operationalized by the methodological specification in Schedule 75 and Schedule 175.
1-99

Section 1 Billing Impacts
In this section we present the findings of analysis designed to address evaluation
objectives and tasks related to an assessment of customer billing and revenue impacts.
The discussion in this section and throughout this report use the customer classes (rate
categories) customarily used by Avista for decoupling filings. These customer classes are
listed in Table 2-1 below for electric and natural gas customers.76
Table 2-1: Electric and Gas Rate Groups and Customer Classes (Rate Categories).
Electric Ser-lce Natural Gas Service
Rate Group Customer Customer Rate Decoupled Rate Customer Customer Rate Decoupled
Class Code Class Schedules Group Class Code Class Schedules
Residential E1 Residential 1.2 Yes Residential G: Residential 101.102 Yes
on- E2A General 11,12.13 es Non- General 111 Yes
Residential - Sem': G- Senices
Non- Lai_ Non- Lw-e G>n>ra1 112,121,
Residential =,s General 21,22,23 Yes Residential G_'B seni,- 122 Yes
Sen-ice=
Non- E`C Pumping =0,31,32 1
Residential Yes Residenua: `-,� -nt�ru�[il;le 131 Yes
Extra Lan!-.
Non- Excluded�e:cupl E,a General 25 No Decouplec - 5chedulesl 132 No
Senwes
,vim Street& Non- Excluded
Decoupled E3B Axea 41-d8 No Deeoup f G,B Schedules 2 146,148 No
Lighting
For reporting and referencing purposes, we have defined a Customer Class Code for each
rate category. The Customer Class Code identifies the fuel in the first character, electric
(E) or natural gas (G), decoupling rate group in the second and a subset of the rate group
defined by one or more rate schedules in the third. Separately for electric and natural gas,
and as explained in the section of the evaluation covering Task 1, the decoupling
mechanism defines two groups of customers subject to the decoupling tracker adjustment,
residential (Rate Group 1) and non-residential (Rate Group 2). We also define Rate
Group 3, non-residential customers not subject to the decoupling tariff. The aggregation
level hierarchy listed from highest level of aggregation to the lowest is as follows:
1. Rate Group
2. Customer Class(Rate Category)
3. Rate Schedule
76 Electric rate schedules 13 and 23,optional electric vehicle rate for general service and large general
service customers,respectively,were added in 2021.Natural gas service experienced the following changes
over the evaluation period:rate schedule 112 was decoupled in 2018 and rate schedules 121 and 122 were
discontinued in 2020. There have been no customers on rate schedule 131 since 2012,the first year of
history reviewed in the first decoupling evaluation.
2-1

For example, Customer Class Code E1 is electric decoupling Rate Group 1, the
residential customer class, and includes rate schedules 1 and 2. A third character is not
necessary since Rate Group 1 only includes residential rate schedules. Rate Group 2 is
non-residential customers subject to the decoupling adjustment tariff. There are three
customer classes (collection of rate schedules) included in Rate Group 2 for both electric
and natural gas service. Rate Group 3 is used to identify customers not subject to the
decoupling tariff adjustment. Electric and natural gas each have two customer classes that
belong to Rate Group 3.
Summary of Decoupling Mechanics and Results
Before examining the impact of decoupling by rate class it is useful to take a high-level
look at the mechanics of the decoupling mechanism, actual deferrals, requested recovery
amounts and decoupling rates. Avista's decoupling mechanism allows for the recovery of
the difference between actual revenue and allowed revenue." This difference is referred
to as the decoupling deferral balance and is tracked for the two electric and two natural
gas rate groups subject to decoupling; residential and non-residential.
Beginning in 2015, monthly deferrals are accumulated over a calendar year and used with
other determinants to calculate the decoupling rate required to collect or refund the under
or over collected revenue. Decoupling rates become effective in Schedule 75 (electric)
and Schedule 175 (natural gas)August I" of the year following the year in which deferral
balances were calculated.78 The timing of deferral balance accumulation and decoupling
rate adjustments is shown in Table 2-2.
Table 2-2 Avista Decoupling Deferral Year and Decoupling Rate Year Definitions.
Decoupling Deferral Balance Accumulation Decoupling Rates
Year Calendar Year Effective
1 2015 Nov 1,2016—Oct 31,2017
2 2016 Nov 1,2017—Oct 31,2018
3 2017 Nov 1,2018—Oct 31,2019
4 2018 Nov 1,2019—Jul 31,2020
5 2019 Aug1,2020—Jul 31,2021
6 2020 Aug1,2021 —Jul 31,2022
7 2021 Aug1,2022—Jul 31,2023
8 2022 -------TAug 1,2023—Jul 31,2024
The first deferral year resulted in a deferral balance at the end of 2015 that was used,
along with other determinants, to calculate the decoupling rate in effect during the first
rate year(November 1, 2016, through October 31, 2017). The same process is followed
17 The details of Avista's decoupling mechanism are included in Final Order("Order 5")for Docket
Numbers UE-140188 and UG-140189.
78 The date which the decoupling rider becomes effective in rates was changed from November Pt to
August lst in 2020(Final Order 09,Dockets UE-190334,UG-190335,and UE-190222(Consolidated)).
This change was made to coincide with other annual rate adjustments to minimize rate changes experienced
by Avista customers and to aid Avista in the timely recovery of deferred revenue.
2-2

in the second deferral year and rate year. Any deferral balance carried over from a prior
year due to the application of the 3% cap is included in the calculations of decoupling
rates in effect during the next rate year.
A summary of decoupling deferral results and decoupling tracker rates is shown in Table
2-3 for last five decoupling years, 2018-2022.
Years shown in Table 2-3 correspond to the deferral years and rate years shown in Table
2-2. For example, the 2019 column refers to calculations made from data for deferral year
five (2019) and the resulting decoupling rate in effect from August 1, 2020, through July
31, 2021. The "Summary of Deferred Revenue" sections of the table show key results for
each decoupling year including the deferral balance for the year, customer surcharge
(rebate)revenue, and any carryover due to the rate increase cap. The "Summary of
Decoupling Rate Adjustment" sections of the table present key results related to the
decoupling adjustment rate including the results of the earnings test, whether or not the
3% cap on rates was reached and the resulting decoupling rate per unit of energy.
As a specific example, consider the workings of the decoupling mechanism as shown for
the natural gas residential rate group in 2022. Cumulative deferral balances during the
2022 calendar year amounted to a negative $1.069 million. The negative deferral balance
would, considered in isolation, suggest a customer rebate through a negative decoupling
rate (Schedule 175). However, the prior year decoupling rate adjustment was limited by
the 3% cap, resulting in a$1.643 million carryover from 2021 to 2022. This carryover
along with adjustments, combined with the negative deferral in 2022, resulting in a
customer surcharge of$0.802 million. Although positive, the surcharge was significantly
lower than the $5.379 million surcharge requested from 2021 results. Consequently, the
decoupling rate (Schedule 175) fell from 3.899 to 0.587 cents per therm for the
residential rate group, effective August 1, 2023. The rate adjustment was not impacted by
either the earning test or the 3% cap,both of which are examined in greater detail later in
this section.
An important characteristic of the Avista decoupling mechanism is the ability of the
mechanism to clear deferral balances even with a rate cap and even in the face of
unusual circumstances, such as,persistently warmer than normal winters over
consecutive years. Because the 3%test is applied using current rates, including the
current decoupling rate, the new decoupling rate will adjust higher and be capable of
amortizing higher levels of requested recovery.79 At some point, even if weather or other
conditions that caused initially high deferral carryovers persist, the decoupling rate will
eventually adjust to a level that recovers 100 percent of requested recovery and carryover
deferral balances will fall to zero. This greatly reduces the possibility of snow-balling
deferral balances even in the face of persistently warm winters over consecutive heating
seasons.
79 This is a feature of the Avista decoupling mechanism that makes the mechanism flexible.
2-3

�J
Table 2-3. Summary Deferral Balances and Decoupling Recovery Rate-Electric.
-----------------------------------Electric-----------------------------------
Residential Group Non-Residential Group
Notes 2048 2019 2020 2021 2022 2018 2019 2020 2021 2022
Summary of Deferred Revenue 1,000 $
Deferred revenue 8,620 1,182 (811) (5,124) (16,126) 7,052 6,860 11,263 2,389 385
Requested recovery A 9,571 5,904 (1,112) (5,801) (18,646) 7,956 9,830 14,761 2,748 (1,889)
Customer surcharge rebate revenue 6,627 5,904 (1,112) (5,801) (18,646) 7,890 7,878 14,489 2,748 (1,889)
Carryover deferred revenue 2,943 0 0 0 0 65 1,952 271 0 0
Summary of Decoupling Rate
Adjustment
Earnings Test Results Over/Under B Under Under Under Under Under Under Under Under Under Under
Decoupling rate (schedule 75) C 0.279 0.244 (0.045) (0.234) (0.725) 0.365 0.365 0.679 0.132 (0.088)
cents/kWh
Incremental revenue (percent) 4.3% -0.4% -3.0% -2.0% -4.7% 3.0% 0.0% 3.0% -4.9% -2.0%
Limited by 3% cap? D Yes No No No No Yes No Yes No No
Notes
A: Requested recovery is equal to deferred revenue after adjusting for shared excess earnings(if applicable),deferral balance carryover from prior year(if
any),interest,and revenue related expenses.
B: Indicates whether or not earnings were over or under Avista's allowed return.When earnings exceed Avista's allowed return,half of excess earnings are
shared with customers through the decoupling rate adjustment.
C: Decoupling rates Schedule 75 (electric)and Schedule 175 (natural gas)take effect on November 1st,2019,for 2018 results and August 1 st of the following
year for 2019-2022 results.
D: As a response to the COVID 19 pandemic,Avista proposed replacing the 3%cap with a 0%cap on the decoupling rate adjustment effective August 1 st,
2020,shown in the 2019 column of this table. This change only applied to 2019 results and only impacted the electric non-residential rate group as this
group was the only one that would have resulted in an increase in rates.
2-4

(4)
Table 2-4: Summary of Deferral Balances and Decoupling Recovery Rate -Natural Gas.
-----------------------------------Natural Gas-----------------------------------
Residential Group Non-Residential Group
Notes 2018 2019 2020 2021 2022 2018 2019 2020 2021 2022
Summary of Deferred Revenue 1,000 $
Deferred revenue 741 (1,054) 1,174 6,559 (1,069) 984 63 445 2,401 1,302
Requested recovery A 556 (896) 1,256 7,021 802 1,075 253 495 2,574 2,439
Customer surcharge rebate revenue 556 (896) 1,256 5,379 802 1,075 253 495 1,680 2,439
Carryover deferred revenue 0 0 0 1,643 0 0 0 0 894 0
Summary of Decoupling Rate
Adjustment:
Earnings Test Results Over/Under B Over Under Under Under Under Over Under Under Under Under
Decoupling rate (schedule 175) C 0.420 (0.685) 0.925 3.899 0.587 1.841 0.419 0.813 2.866 3.987
cents/therm
Incremental revenue (percent) 4.2 0 -1.2% 1.8% 3.0 0 -2.5% 2.2% -2.2% 0.7% 3.0 0 1.2%
Limited by 3% cap? D No No No Yes No No No No Yes No
Notes
A: Requested recovery is equal to deferred revenue after adjusting for shared excess earnings(if applicable),deferral balance carryover from prior year(if
any),interest,and revenue related expenses.
B: Indicates whether or not earnings were over or under Avista's allowed return.When earnings exceed Avista's allowed return,half of excess earnings are
shared with customers through the decoupling rate adjustment.
C: Decoupling rates Schedule 75 (electric)and Schedule 175 (natural gas)take effect on November 1st,2019,for 2018 results and August 1st of the
following year for 2019-2022 results.
D: As a response to the COVID 19 pandemic,Avista proposed replacing the 3%cap with a 0%cap on the decoupling rate adjustment effective August Is,
2020,shown in the 2019 column of this table.This change only applied to 2019 results and only impacted the electric non-residential rate group as this
group was the only one that would have resulted in an increase in rates.
2-5

Earnings Test and Rate Cap
The question as stated in the RFP is:
"Please provide analysis and trends on whether the rate cap was reached and the results
of the earnings test?"
The earnings test in Avista's decoupling mechanism incorporates a method of sharing
excess earnings, if any, in a decoupling year between rate payers and share owners. When
Avista's rate of return exceeds the Commission approved rate of return, one-half of the
revenue over and above the allowed rate of return is shared with customers. Excess
revenue shared with customers is split between the residential and non-residential
customer groups based on the percentage of total revenue from each group. Excess
earnings, when present, have the effect of reducing the requested recovery for the
decoupling year.
The results of the annual earnings test are shown in Table 2-3 in the row labeled
"Earnings Test Results". A value of"Over" is used to indicate when earnings exceeded
the allowed rate of return and"Under" is used when earnings were lower than allowed.
As shown in Table 2-3, Avista's rate of return for electric distribution did not exceed the
allowed rate of return over the 2018 through 2022 decoupling years. There were excess
earnings for natural gas distribution in 2018 which served to reduce the requested
decoupling recovery for both rate groups.
Avista's decoupling mechanism includes a provision that limits annual decoupling rate
adjustment surcharges to no more than a 3% increase. After excess earnings resulting
from application of the earnings test are applied, if any, the requested recovery is
subjected to a 3% cap. The cap only applies to surcharges, not rebates, and only to the
portion of the surcharge above zero. Decoupling rate declines are not limited by the cap.
Results of the 3% cap are shown in Table 2-3 in the row labeled"Limited by 3% Cap?".
A value of Yes means that a portion of the requested recovery was withheld and rolled
over to the following year so that the resulting increase in the decoupling rate does not
exceed 3%. The decoupling surcharge for residential electric customers was limited by
the 3% cap once (2018) over decoupling years 2018 through 2022. The cap limited the
surcharge for non-residential electric customers in 2018 and 2020. The only time the 3%
cap limited decoupling surcharges for natural gas customers over the 2018 to 2022 period
was in 2021 for both the residential and non-residential rate groups.
A one-time adjustment to the cap was used for 2019 so that the decoupling surcharge
would not be increased for either customer group, essentially a rate cap of zero percent.
The 2019 surcharge had an effective date of August 1, 2020, a time when the impacts of
the pandemic were especially hard hitting. Avista decided to not allow the 2019
decoupling surcharge to result in an increase in rates given the overall economic
environment. Non-residential electric was the only customer group impacted by this one-
time lowering of the cap to zero percent. The decoupling rate declined for all other
2-6

customer groups that year, resulting in a rate drop from decoupling effective August 1,
2020.
Analysis of Customer Billing Impacts
In this section we examine the following evaluation question:
"Were there any differences in Decoupling tracker adjustments between rate
classes?"
Annual data from 2018 through 2022 for customer counts,usage, revenue, and revenue
from the decoupling rate (Schedule 75 for electric and Schedule 175 for natural gas) are
examined. The data reviewed in this section are calendarized actual values and have not
been normalized for weather. We begin our analysis and reporting with electric customer
classes followed by natural gas customer classes.
Electric
Avista serves nearly 270 thousand electric customers in the state of Washington. All but
about 500 of these customers are subject to the decoupling tracker adjustment. Annual
data for the residential customer class is shown in Table 2-5. The residential customer
class is Avista's largest electric customer class by customers, volumes delivered(MWh)
and revenue.
Table 2-5. Annual Electric Data -Residential Customer Class (Schedules 1&2).
Annual Totals Per Customer
Usage Revenue Schedule 75Usage Schedule Pct of
Year Customers (MWh) (Millions$) Revenue kWh Revenue 75 Bill
Millions$
2018 215,665 2,366,635 $228.7 $8.7 10,974 $1,061 $40.46 3.8%
2019 218,293 2,436,265 $227.3 -$1.5 11,161 $1,041 -$6.70 -0.6%
2020 221,160 2,435,082 $229.7 $6.5 11,010 $1,039 $29.28 2.8%
2021 224,169 2,545,508 $241.7 $3.7 11,355 $1,078 $16.37 1.5%
2022 226,868 2,638,378 $250.5 -$2.3 11,630 $1,104 -$10.08 -0.9%
Avista serves just over a quarter of a million residential electric customers, averaging
between 11,000 and 12,000 kWh usage per year. Since 2018, the revenue per residential
customer has averaged between$1,000 and$1,110. Revenue from Schedule 75, the
decoupling tracker, has fluctuated annually between a rebate of$10.08 to an average
surcharge of$40.46. This equates to a range of-0.9%to 3.8% as a percentage of the
annual electric bill.
Annual data for General Service customers are shown in Table 2-6.
2-7

Table 2-6. Annual Electric Data - General Services (Rate Schedules 11, 12, and 13).
Annual Totals Per Customer
Usage Revenue Schedule 75 Usage Schedule Pet of
Year Customers (MWh) (Millions$) (Millions$) kWh Revenue 75 Bill
2018 32,233 622,703 $78.5 $0.3 19,319 $2,435 $8 0.3%
2019 32,650 627,094 $80.4 $0.6 19,207 $2,462 $18 0.7%
2020 1 33,177 1 595,000 1 $77.8 1 $2.2 1 17,934 1 $2,344 1 $66 1 2.8%
2021 33,746 650,970 $85.6 $3.1 19,290 $2,536 $93 3.7%
2022 34,287 686,667 $91.8 $3.9 20,027 $2,677 $113 4.2%
Avista serves about 34 thousand general service electric customers. Average customer
usage has ranged from just under 18,000 kWh to just over 20,000 kWh. Annual customer
bills have averaged around $2,500. Schedule 75 revenue has increased from $8 to $113
per custom since 2018. As a percentage of the average customer bill, Schedule 75 has
increased from 0.3% in 2018 to 4.2% in 2022. The pattern of increasing Schedule 75
charges is common in the non-residential electric customer classes and is examined closer
later in this section.
Annual data for Large General Services customers are shown in Table 2-7.
Table 2-7. Annual Electric Data -Large General Services (Rate Schedules 21, 22, and
23).
Annual Totals Per Customer
Schedule
Usage Revenue 75 Usage Schedule Pet of
Year Customers (MWh) (Millions$) (Millions kWh Revenue 75 Bill
2018 1,899 1,380,340 $131.6 $0.6 726,909 $69,282 $303 0.4%
2019 1,912 1,376,029 $133.8 $1.3 719,775 $69,995 $661 0.9%
2020 1,885 1,273,220 $128.2 $4.6 675,568 $68,048 $2,465 3.6%
2021 1,805 1,320,096 $135.6 $6.3 731,321 $75,124 $3,517 4.7%
2022 1 1,711 1,325,181 1 $139.5 $7.5 1 774,657 1 $81,546 $4,377 5.4%
Large general service customers number less than two thousand and account for between
$130 to $140 million annually since 2018. Customers in this class are the largest of the
decoupled customer classes, averaging about three-quarters of a million kWh per year
with an average annual bill between $70,000 and $80,000. Like general service
2-8

customers, this customer class has seen rising Schedule 75 bills in absolute and as a
percentage of bill basis since 2018.
Annual data for pumping customers are shown in Table 2-7. The pumping customer class
is comprised mostly of municipal and agricultural pumping applications such as water
treatment and irrigation.
Table 2-7. Annual Electric Data Pumping (Rate Schedules 30, 31, and 32)
Annual Totals Per Customer
Schedule
Usage Revenue 75 Usage Schedule Pct of
Year Customers (MWh) (Millions$) (Millions kWh Revenue 75 Bill
2018 2,454 145,808 $12.5 $0.1 59,420 $5,095 $24 0.5%
2019 2,458 139,560 $12.2 $0.1 56,786 $4,980 $38 0.8%
2020 2,488 144,620 $13.0 $0.5 58,131 $5,218 $214 4.1%
2021 2,527 161,841 $14.8 $0.8 64,051 $5,868 $306 5.2%
2022 2,533 139,673 $13.5 $0.9 55,147 $5,316 $338 6.4%
About 2,500 customers are served in Avista's pumping customer class, contributing
between$12 million and $15 million annually since 2018. Pumping customers used an
average of 55,000 to 64,000 kWh per year between 2018 and 2022. Schedule 75 revenue
has increased over the 2018-2022 period to over 6% of the average customer bill in 2022.
This increasing pattern is examined further below.
To visualize and contrast the impacts on customer electric revenues between customer
classes, the percentage of electric revenues attributed to Schedule 75 over the 2018 to
2022 period is shown in Figure 2-1.
2-9

AN
7.0%
6.4%
6.0%
5.4% 5.2%
5.0% 4.7%
4.2% 4.1%
4.0% 3.8% 3.7% 3.6%
m J2.8% 2.8%
0 3.0%
c
2.0%
v
a 1.0% 0,7 11 0.9% 0.8%
0.31 0.4% 0.5%
0.0%
-1.0% 69f�
-0.9%
-2.0%
Residential General Services Large General Services Pumping
Customer Class
■2018 2019 2020 _2021 0 2022
Figure 2-1: Annual Schedule 75 Revenue as a Percent of Customer Class Revenues.
Figure 2-1 shows annual Schedule 75 revenue as a percentage of total revenue for each
customer class subject to decoupling. When observing the impact of decoupling on rates
and revenues it is useful to consider that because decoupling rate becomes effective
August 1st of the year following the decoupling year, decoupling credits and surcharges
are observed with a lag.80 For example, 2020 decoupling results are observed in rates for
five calendar months of 2021 (August through December) and seven calendar months of
2022 (January through July). The greater number of months in year two after the
decoupling year along with the typically larger weather impacts in January through July
compared to August through December means that the results from a decoupling year are
observed in customer rates and revenues in the first and second calendar year following
the decoupling year and the largest impact is in the second year.
The residential rate group is comprised of only one customer class, residential. From
2018 through 2022, Schedule 75 revenue as a percent of annual residential customer bills
varied between a negative 0.9 percent to 3.8 percent. Unlike the non-residential customer
classes, there appears to be a trend over this timeframe with decoupling accounting for a
declining percentage of the annual residential bill. Annual use and revenue per customer
have been trending higher since 2020, which would impact pattern shown in Figure 2-1
81 Prior to the fifth decoupling year(2019),decoupling results became effective in rates on November V of
the following year. See Table 2-2 for a complete history of deferral years and the dates decoupling rates
became effective.
2-10

with a lag. An analysis of factors contributing to variation in usage and revenue per
customer is presented later in this report.
The non-residential rate group is comprised of three decoupled non-residential customer
classes. These non-residential customer classes are shown in Figure 2-1. For the non-
residential customer classes, Schedule 75 had the impact of increasing customer bills in
every calendar year between 2018-2022. A couple of patterns are evident in the data
shown in Figure 2-1. In each of the three non-residential customer classes, decoupling
charges as a percentage of the bill is increasing over the 2018 through 2022 period. Also,
there appears to be a difference in the level of percentage impact between the classes with
the large general services class showing higher percentages than the general services
class and the pumping class larger than the large general services class. These differences
between the customer classes are simply noted for now. Possible reasons will be explored
later in the report.
Natural Gas
Avista serves approximately 175,000 natural gas customers in the state of Washington.
All but about fifty of these customers are subject to the decoupling tracker adjustment.
Annual data from 2018 through 2022 for residential customers are shown in Table 2-8.
The residential customer class is Avista's largest natural gas customer class by
customers, volumes delivered(therms) and revenue.
Table 2-8. Annual Natural Gas Data—Residential (Rate Schedules 101 & 102).
Annual Totals Per Customer
Usage Schedule Schedule
(1,000 Revenue 175 Usage 175 Pct of
Year Customers Therms) (Millions$ Revenue $ Therms Revenue Revenue Bill
2018 161,791 123,968 $105.3 $4,947,487 766 $651 $30.58 4.7%
2019 165,362 137,563 $106.0 -$2,909,847 832 $641 -$17.60 -2.7%
2020 168,189 125,794 $112.0 $76,322 748 $666 $0.45 0.1%
2021 170,582 125,317 $116.8 -$243,034 735 $685 -$1.42 -0.2%
2022 172,357 141,758 $154.2 $2,484,396 822 $895 $14.41 1.6%
Avista serves over 170 thousand residential natural gas customers, with average annual
usage per customer ranging between 735 and 832 therms since 2018. Since 2018, the
revenue per residential customer has averaged between $641 and $895. Revenue from
Schedule 175, the decoupling tracker, has fluctuated annually between a rebate of$17.60
to a surcharge of$30.58 per customer. This equates to a range of-2.7%to 4.7% as a
percentage of the annual natural gas bill.
Annual data for General Service customers are shown in Table 2-9.
2-11

Table 2-9. Annual Natural Gas Data- General Services (Rate Schedule 111).
Annual Totals Per Customer
Usage Schedule Schedule Pct
(1,000 Revenue 175 Usage 175 of
Year Customers Therms) (Millions$ Revenue $ Therms Revenue Revenue Bill
2018 3,102 57,162 $34.0 $1,820,085 18,430 $10,958 $587 5.4%
2019 3,098 58,877 $32.6 $526,664 19,003 $10,516 $170 1.6%
2020 3,145 52,359 $33.3 $712,032 16,650 $10,578 $226 2.1%
2021 3,195 54,507 $35.6 $298,952 17,061 $11,148 $94 0.8%
2022 3,345 63,585 $51.3 $864,335 19,008 $15,324 $258 1 1.7%
Avista serves over three thousand general service natural gas customers. Average
customer usage has ranged from a low of 16,650 therms during 2020, the year most
impacted by the pandemic, to just over 19,000 therms in 2019 and 2022. Annual average
customer bills have ranged between about $10,500 to $15,300 and Schedule 175 revenue
has ranged from $94 to $587 per custom since 2018. As a percentage of the average
customer bill, Schedule 175 has ranged from 0.8% in 2021 to 5.4% in 2018.
Annual data for Large General Services customers are shown in Table 2-10.
Table 2-10. Annual Natural Gas Data -Large Gen. Services (Schedules 112, 121, and
122).
Annual Totals Per Customer
Usage Schedule Schedule Pct
(1,000 Revenue 175 Usage 175 of
Year Customers Therms) (Millions$ Revenue $ Therms Revenue Revenue Bill
2018 -29 -2,756 -$2.1 -$15,102 96,705 $75,232 $530 0.7%
2019 5 2,852 $1.4 $23,530 526,580 $249,496 $4,344 1.7%
2020 5 3,206 $1.5 $54,639 712,393 $344,207 $12,142 3.5%
2021 3 687 $0.4 $3,333 265,956 $141,722 $1,290 0.9%
2022 1 164 $0.1 $3,926 245,809 $185,308 $5,889 3.2%
There are only a few large general service natural gas customers and, excluding
accounting system adjustments in 2018, the customer count has fallen from five in 2019
and 2020 to only one customer in 2022. Per customer usage has varied widely, averaging
around a quarter million therms over the last two years. As a percentage of the average
customer bill, Schedule 175 has ranged from 0.9% in 2021 to 3.5% in 2020.
There were no interruptible natural gas customers, Schedule 131, over the 2018 to 2022
period.
To visualize and contrast the impacts on natural gas revenues between customer classes,
the percentage of natural gas revenues attributed to Schedule 175 over the 2018 to 2022
period is shown in Figure 2-2.
2-12

AN
7.0%
6.0%
5.4%
5.0% 4.7%
4.0% 3.5%
3.2%
_ 3.0%
m 2.1%
2.0% 1.6% 1.6% 1.7% 1.7%
i 1.0%
-0.2%
-1.0%
-2.0%
-3.0% -2.7%
-4.0%
Residential General Services Large General Services
Customer Class
0 2018 0 2019 0 2020 .2021 ■2022
Figure 2-2: Annual Schedule 175 Revenue as a Percent of Customer Class Revenues.
Figure 2-2 shows annual Schedule 175 revenue as a percentage of total revenue for each
customer class subject to decoupling. As previously discussed, when observing the
impact of decoupling on rates and revenues it is useful to consider that because
decoupling rate becomes effective August 1st of the year following the decoupling year,
decoupling credits and surcharges are observed with a lag.81 For example, 2020
decoupling results are observed in rates for five calendar months of 2021 (August
through December) and seven calendar months of 2022 (January through July). The
greater number of months in year two after the decoupling year along with the typically
larger weather impacts in January through July compared to August through December
means that the results from a decoupling year are observed in customer rates and
revenues in the first and second calendar year following the decoupling year and the
largest impact is typically in the second year.
The residential rate group is comprised of only one customer class, residential. From
2018 through 2022, Schedule 175 revenue as a percent of annual residential customer
bills varied between a negative 2.7 percent to a positive 4.7 percent. There does not
appear to be any discernable trend since 2018.
81 Prior to the fifth decoupling year(2019),decoupling results became effective in rates on November V of
the following year. See Table 2-2 for a complete history of deferral years and the dates decoupling rates
became effective.
2-13

The non-residential rate group is comprised of three decoupled non-residential customer
classes. The two non-residential customer classes with customer data to report are shown
in Figure 2-2. For the non-residential customer classes, Schedule 175 had the impact of
increasing customer bills in every calendar year between 2018-2022. Other than adding
to customer bills in each calendar year since 2018, there does not appear to be any
discernable trend in the non-residential data shown in Figure 2-2. Excluding 2018, the
percentage that Schedule 175 charges make up of an average customers' bill appears to
be somewhat higher in the large general services customer class over general services
customers.
Analysis of Revenue Impacts
In this section we examine the effects of the decoupling mechanisms on Avista's revenue.
The objective of Task 4, as stated in the request for proposal, is shown below:
"Analysis of the Mechanism's impact on Company revenues (i.e., whether
there has been a stabilizing effect)."
Relating to this objective are the following evaluation questions, also taken from the
RFP:
"What impact did the Mechanisms have on the Company's revenues (i.e.,
whether there has been a stabilizing effect)?"
What were the causes of the deviation of actual revenue per-customer from
authorized revenue-per-customer?"
"What factors impacted the deferral and rate changes, and what was the
magnitude of that impact? (e.g., weather, customer counts, conservation,
economy, etc)"
"What was the impact of the Decoupling deferral on Avista's revenues and
rates?"
"What was the effect of updates to the decoupling baseline and resulting
effects on deferrals under the mechanisms?"
Our discussion in this section is organized by each of the evaluation questions listed
above. Much of the data used to address these questions has been presented in earlier
sections of this report and is repeated here for ease of discussion and the convenience of
the reader.
Has Decoupling Stabilized Revenue
The question as stated in the REP is:
"What impact did the Mechanisms have on the Avista's revenues (i.e.,
whether there has been a stabilizing effect)?"
2-14

This is a straightforward question and easy to answer by comparing actual revenue with
actual revenue plus deferred revenue. In order to answer this question, we calculated the
annual variation in revenue over the 2020 to 2022 period with and without the revenue
from decoupling deferrals. This time period includes the three primary years under
evaluation and has the added advantage of encompassing the time period where the
decoupling mechanism applied only to existing customers and includes only pandemic
impacted years.82 We used the coefficient of variation, calculated as the standard
deviation divided by the mean, as our measure of variability.83 Figure 2-3 shows the
results of our calculations for electric revenue.
8.0%
7.0%
7.0%
c 6.0%
5.2%
Y
5.0%
w 3.9°'
0 4.0% 3.4%
C
Gl
3 3.0% 2.4%
U 2.0%
0.8%
1.0% 1 i I
0.� n
Res Non-Res Total
■Without Decoupling ❑With Decoupling
Figure 2-3: Electric Revenue Variability (2020-2022).
The bars labeled"Without Decoupling"refer to base rate revenue only and does not
include deferred revenue through the decoupling mechanism. Bars labeled"With
Decoupling" include base rate and decoupling deferral revenue. Results are shown for
both decoupled rate groups and their total. It is clear from the results shown in Figure 2-3
that there has been a stabilizing effect on revenue as a result of decoupling. For
residential and non-residential rate groups, variability is roughly 60% and 25%,
82 New customers were excluded from the decoupling deferral calculations beginning with April 2020.The
first state mandated shutdowns to combat the COVID-19 pandemic began in mid-March 2020.By April
2020,the U.S.unemployment rate shot to a high of 14.7%from 4.4%in March and 3.5%in February.
83 The coefficient of variation shows the extent of variability in relation to the mean by dividing the
standard deviation of a distribution by its mean,producing a measure of relative variation.It is used to
compare the variability between groups.In finance it is used to indicate volatility or risk.Here it shows that
variability is reduced with decoupling(the green bars in Figure 2-3 and Figure 2-4 are shorter than the blue
bars).
2-15

respectively, of the level of variability without decoupling. For both rate groups
combined, decoupling has reduced revenue variability by well over half.
Variation in natural gas revenue is shown in Figure 2-4.
12.0%
10.1%
10.0% 9.6%
c
0
7.6% 7.8% 7.5%
8.0% 7.3%
c�
° 6.0%
c
v
U
jF 4.0%
v
0
U
2.0%
0.0%
Res Non-Res Total
■Without Decoupling O With Decoupling
Figure 2-4: Natural Gas Revenue Variability (2020-2022).
For natural gas revenues, variability has also been reduced by decoupling but not to the
extent as seen for decoupled electric rate groups. Revenue variability in natural gas
residential is about 2.5 percentage points lower with decoupling. For non-residential
customers, revenue variability has been reduced by about one half of a percentage point.
For both rate groups combined, decoupling has reduced revenue variability in natural gas
to about 80% of the level of variability without decoupling.84
Revenue Deviations from Planning Assumptions and Causes
Some of the revenue related evaluation questions have to do with the magnitude and
causes for deviations from planning assumptions. These questions as stated in the RFP
are:
"What were the causes of the deviation of actual revenue-per-customer from
authorized revenue-per-customer?"
"What factors impacted the deferral and rate changes, and what was the
magnitude of that impact? (e.g., weather, customer counts, conservation,
economy, etc)"
84 The 2018 evaluation report,based on analysis of 2015-2017 revenues,found that decoupling reduced
natural gas revenue variation by a greater degree than the findings in this evaluation(Avista Decoupling
Evaluation,2018,p 4-2).Although it should be pointed out that both evaluations are based on a relatively
short three-year period.
2-16

Actual and authorized revenue-per-customer is shown for electric rate groups in Table
2-11.
Table 2-11. Authorized and Actual Electric Decoupled Revenue per Customer.
----------Residential---------- ----------Non-Residential--------
Percent Percent
Year Authorized Received Difference Authorized Received Difference
2020 $735 $739 0.6% $4,380 $4,064 -7.2%
2021 $787 $811 3.1% $4,503 $4,436 -1.5%
2022 $862 $938 8.7% $4,795 $4,785 -0.2%
Avista received more decoupled revenue per customer from the residential group than
was authorized in each of the evaluation years, 2020 through 2022. The difference was
the largest in 2022. Decoupled revenue per customer for the non-residential rate group
fell short of authorized levels in each evaluation year shown in Table 2-11, with the
largest difference observed in 2020. Analysis of the factors behind these differences is
presented in this section.
Test year and actual electric usage, customer counts and use per customer are shown for
each deferral year in Table 2-12.
Table 2-12. Test Year and Actual Electric Usage, Customers, and Use per Customer.
2020 2021 2022
Use per Use per Use per
Usage Customer Usage Customer Usage Customer
MWh Customers kWh h Customers kWh h Customers kWh
--------------------Residential--------------------
Test Year 2,374,704 215,665 11,011 2,374,704 215,665 11,011 2,395,486 218,293 10,974
Actual(Existing) 2,429,040 217,945 11,145 2,492,451 217,802 11,444 2,592,586 219,635 11,804
Change From 54,337 2,280 134 117,747 2,137 433 197,100 1,342 830
Test Year
Percent Change 2.3% 1.1% 1.2% 5.0% 1.0% 3.9% 8.2% 0.6% 7.6%
--------------------Non-Residential--------------------
Test Year 2,131,033 36,586 58,247 2,131,033 36,586 58,247 2,131,091 37,020 57,567
Actual(Existing) 1,987,513 36,650 54,230 2,064,852 36,194 57,050 2,071,402 36,333 57,012
Change From (143,520) 64 (4,017) (66,181) (392) (1,197) (59,689) (687) (555)
Test Year
Percent Change -6.7% 0.2% -6.9% -3.1% -1.1% -2.1% -2.8% -1.9% -1.0%
Avista relies on volumetric charges to recover a portion of fixed costs for all decoupled
rate groups and fuels. This causes use per customer to be an important factor in
determining deferral balances and decoupling rates through the decoupling mechanism.
More specifically, changes in use per customer from levels used in the test year to set
decoupled revenue per customer will lead to positive or negative deferral balances
depending on the direction of change, all other things equal. Higher use per customer will
2-17

cause negative deferrals and lower use per customer will result in higher deferrals, again
all other things equal.
Considering electric residential as an example, actual decoupled revenue per customer
was 8.7%higher than authorized in 2022 (Table 2-11). During the same period existing
customer counts were 0.6 percent higher than the test year and use per customer was
7.6%higher(Table 2-12).85 As designed,use per customer explains nearly all of the
higher than authorized revenue per customer. A comparison of the values in Table 2-11
and Table 2-12 shows that almost all of the variance in revenue per customer can be
explained by differences in use per customer.
Two important factors causing use per customer to vary from test year are actual weather
deviations from normal weather and acquired energy efficiency savings through Avista
programs.86 There are other factors, of course, but these two are either known in the case
of energy efficiency or readily measurable in the case of weather. Changes due to
weather are straightforward calculations. Avista provided the weather impacts and
supporting monthly details by rate schedule showing the deviation in heating and cooling
degree days from normal and the corresponding weather impacts. Energy efficiency
impacts are calculated as cumulative savings from Avista programs since the applicable
test year.
The results of these calculations are shown in Figure 2-5 for the electric residential rate
group.
8.0% 7.5%
6.0%
[4.2%
4.0% 3.6% 3.6%
2.0% 1.21i- 1.2%
ALI I
0.0% I -1 — LJ
-0.7%
-2.0% 1.3%-1.1%
I------2020------I I----2021-----I I------202 2------I
■Total ■Weather ■Energy Efficiency OOther
Figure 2-5: Percentage Change in Use per Customer, Electric Residential.
85 As a result of UE-190334,effective April 1,2020,new customers are excluded from decoupling
deferrals.
86 This analysis uses Avista's rolling thirty-year average,updated annually,for normal weather.
2-18

Considering 2021 results,use per customer was 3.9%higher than test year assumptions.
Weather impacts alone are estimated to have pushed electric residential use per customer
3.4%higher. The 2021 weather impact was slightly offset by a 0.7% drop in use per
customer due to Avista's energy efficiency achievements. The "Other" category is simply
the difference between the total and the readily quantifiable factors of weather and energy
efficiency. Other unidentified factors caused 2021 residential electric use per customer to
be 1.2%higher. Weather and other factors are the primary reasons why user per customer
varies from the test year.
For electric residential customers it is clear that weather impacts on use per customer can
be large and work in either direction. It is also true that energy efficiency impacts always
push use per customer lower and that downward influence becomes more pronounced the
further in time an evaluation year is from a test year. Cumulative energy efficiency
savings will reset with a new rate case and test year.
Figure 2-6 shows a plot of total and each factor's influence on the percent change in use
per customer from the test year for the electric non-residential rate group.
4.0% —
2.1%
2.W.0.0% L-1 F1
-
o.ass
-2.0% L LLI
r-2.4%-4.0%
-6.0%
-8.0% -6.9%
1-----2 02 0------I I------2021------I I----2022-----
■Total ■Weather O Energy Efficiency ❑Other
Figure 2-6: Percentage Change in Use per Customer, Electric Non-Residential.
For the non-residential electric group, weather is less a factor in use per customer
variance than energy efficiency and other factors. Avista's energy efficiency
achievements have been an important factor influencing changing use per customer in the
electric non-residential group. Considering 2022, energy efficiency improvements were
more than enough to offset greater usage due to weather and other factors, resulting in a
drop of 1.0% in use per customer from test year levels. Weather appears to be far less
influential in electric non-residential customer usage than it is for the electric residential
group.
2-19

Actual and authorized revenue-per-customer is shown for natural gas rate groups in Table
2-13.
Table 2-13. Authorized an Actual Natural Gas Decoupled Revenue per Customer.
----------Residential---------- ----------Non-Residential----------
Col.1 Col.2 Col.3 Col.4 Col.5 Col.6
Year Percent Percent
Authorized Received Difference Authorized Received Difference
2020 $344 $337 -2.2% $4,746 $4,597 -3.1%
2021 $388 $346 -10.7% $5,026 $4,237 -15.7%
2022 $413 $419 1.5% $5,184 $4,766 -8.1%
For reasons discussed above for electric, the percentage difference between authorized
and actual revenue per customer shown in Table 2-13 generally follows the difference
between actual and planned use per customer. However, there are notable differences,
especially within the non-residential group. Actual revenue for 2021 per existing non-
residential customer was much lower(15.7% lower-see Column 6) than authorized, for
example. Use per customer that year was also lower(4.1% lower-see Table 2-14,
Column 6, last row), a percentage far less than the 15.7% difference in revenue per
customer in Table 2-13.
Test year and actual natural gas usage, customer counts and use per customer are shown
for each deferral year in Table 2-14.
Table 2-14. Test Year and Actual Natural Gas Usage, Customers, and Use per Customer.
2020 2021 2022
Use per Use per Use per
Usage Customer Usage Customer Usage Customer
(MWh) Customers (kWh) (MWh) Customers (kWh) (MWh) Customers (kWh)
Coll Col.2 Col3. Col.4 Col.5 Col.6 Col.7 1 Col.8 Col.9
----------------Residential------------------
Test Year 128,985,980 161,791 797 128,985,980 161,791 797 132,095,604 165,362 799
Actual(Existing) 125,670,758 164,450 764 123,112,807 164,302 749 138,218,167 166,593 830
Change From Test Year 3,315,222 2,659 33 5,873,173 2,511 48 6,122,563 1,232 31
Percent Change -2.6%1 1.6% -4.1% -4.6%1 1.6% -6.0% 4.6%1 0.7%1 3.9%
--------------Non-Residential---------------
Test Year 55,884,877 3,073 18,186 55,884,877 3,073 18,186 60,325,922 3,105 19,432
Actual(Existing) 55,210,492 3,119 17,699 54,798,292 3,142 17,442 62,203,363 3,274 18,998
Change From Test Year 674,385 46 487 1,086,585 69 744 1,877,441 170 434
Percent Change -1.2% 1.5% -2.7% -1.9% 2.2% -4.1% 3.1% 5.5% 2.2%
For residential natural gas customers,use per customer differences from test year values
followed the same pattern as revenue per customer differences from authorized. For
2-20

example, in 2021 revenue per customer was 10.7 percent under the authorized level
(Table 2-13, Column 3).
The drop in use per customer explains most of the shortfall between actual and authorized
revenue per residential customer in 2021. This is not the case for the non-residential rate
group in 2021 where the use per customer drop of 4.1 percent (Table 2-14, Column 6,
Percent Change) explains less than half of the 15.7 percent shortfall in actual revenue per
customer from authorized levels (Table 2-13, 2021, Column 6). A similar pattern is
present in 2022 non-residential.
Two important factors causing use per customer to vary from test year are actual weather
deviations from normal weather and acquired energy efficiency savings through Avista
programs. There are other factors, of course,but these two are either known in the case of
energy efficiency or readily measurable in the case of weather. Changes due to weather
are also straightforward calculations. Avista provided the weather impacts and supporting
monthly details by rate group showing the deviation in heating and cooling degree days
from normal and the corresponding weather impact on usage. Energy efficiency impacts
are calculated as cumulative savings from Avista programs since the applicable test year.
The results of these calculations are shown in Figure 2-7 for the natural gas residential
rate group.
3.9%
4.0%
3.0%
2.7%
0.0%
o ��.oi U
-0.6%
-4.0%
-6.0% -
-6.4%
6.0%-6.2%
-8.0%
I-----2020-----I I----2021-----I I----2022-----
■Total ■Weather ■Energy Efficiency ❑Other
Figure 2-7: Percentage Change in Use per Customer, Natural Gas Residential.
Weather is clearly the predominant factor in understanding changes in residential therm
use per customer from the test year. The total change in use per customer tracks the
warmer than normal heating seasons in calendar years 2020 and 2021 and slightly colder
than normal heating season in calendar year 2022. Energy efficiency impacts on use per
2-21

customer usage are a small factor in understanding overall change from the test year.
Other unidentified factors were largest in 2020 and 2022 but relatively small in 2021.
Figure 2-8 shows a plot of total and each factor's influence on the percent change in use
per customer from test year assumptions for the natural gas non-residential rate group.
3.0% 2.7%
2.00/6 1.2% 1.4%
1.0% I I ■
0.0%
-1.0% -0.4% .596
7-1
-2.0%
-3.0% -2.7% -2.4%
2.9%
-4.0%
-5.0% 4.1%
-4.9% -4.8%
-6.0%
I-----2020-----I 1------2021-----1 I----2022-----
■Total ❑Weather ❑Energy Efficiency pother
Figure 2-8: Percentage Change in Use per Customer, Natural Gas Non-Residential.
Use per customer declines in 2020 and 2021 are largely explained by warmer than normal
weather. Considered independently, weather in 2022 tended to increase use per customer.
However other factors and energy efficiency more than offset weather leading to a drop
of 2.4 percent. Other factors are by definition unquantified but could include increased
efficiency outside of Avista's energy efficiency programs, lower use of natural gas due to
fuel substitution (e.g., increased use of biomass in cogeneration) and cutbacks in
customer facility operations. Energy efficiency has contributed to increasingly lower use
per non-residential natural gas customers.
Results of Avista's electric and natural gas energy efficiency programs are discussed in
detail in Section 4 of this report.
Summary — Revenue and Billing
Avista's decoupling mechanism has had a stabilizing effect on revenue, reducing
variability in half for electric and by one-fifth for natural gas of variability without
decoupling. On the electric side, between 2018 and 2022 the 3% cap on annual rate
increases from the decoupling rate was reached once for residential and twice for non-
residential. For natural gas, the rate cap was reached once between 2018 and 2022 in each
rate group, residential and non-residential.
2-22

Since 2018, the requested recovery from decoupling deferrals have worked to both
increase (customer surcharge) and decrease (customer rebate)Avista's revenues in all but
the natural gas non-residential rate group. Requested recovery from deferrals in the
natural gas non-residential rate group have worked to increase Avista revenues in each
decoupling year between 2018 and 2022. Deferral balances are driven largely by
differences in use per customer from test year assumption. Much of the difference in use
per customer is due to weather, especially in electric residential, natural gas residential
and natural gas non-residential. Avista's energy efficiency programs have also worked to
lower use per customer, especially for the electric non-residential group.
2-23

Section 1 Cost Recovery1 1 1 1 1 Classes
Here we examine fixed costs and fixed charges for electric and natural gas customer
classes.
The objective of this section, as stated in the request for proposal, is shown below:
"Analysis of the extent to which fixed costs are recovered infixed charges for
the customer classes, excluded from the Mechanisms. "
Relating to this objective is the following evaluation question, also taken from the RFP:
"How much of Avista's fixed costs recovered from non-decoupling customer
classes are recovered infixed charges?"
The scope of this section was expanded to include decoupled electric and natural gas
customer classes to facilitate comparison to customer classes excluded from the
decoupling mechanisms. To address the evaluation objective, it is necessary to compare
revenues from fixed charges to fixed costs for these customer classes. Fixed cost and
revenue collected from fixed charges was provided by Avista in response to the data
needs associated with this section. The data provided by Avista were based on their most
recent cost of service completed in 2020 and approved cost of service values from rate
cases in 2021 (UE-200900 for electric and UG-200901 for natural gas). Beginning with
electric customer classes, we examine the recovery of fixed costs through fixed charges
and the relationships presented in the data.
Electric Customers
Fixed customer charges as a percentage of fixed cost are shown in Figure 3-1 by
customer classes included in Avita's cost of service study. This data shows the
percentage of fixed cost recovered through fixed charges by electric customer class. The
Non-Decoupled classes are Extra Large General Service and Street &Area Lighting.
140%
120% 116%
V
100%
E
Q 80%
60%
0
40%
o. 20% -1*% 15% 18% 16%
30%
6%
0%
System Total Residential General Service Large General Pumping Service Extra Large General Street&Area
Service Service Lighting
TOTAL DECOUPLED DECOUPLED DECOUPLED DECOUPLED NON-DECOUPLED NON-DECOUPLED
3-1

Figure 3-1. Percent Electric Fixed Cost covered by Fixed Charges.
Overall, fixed charges for total electric distribution recover about 14 percent of fixed
cost. The customer class that covers the highest percentage of fixed costs through fixed
charges is street and area lighting, with over 100 percent of fixed cost recovered through
fixed charges. The customer class collecting the smallest percentage of fixed costs
through fixed charges is pumping services. Pumping services recover 6 percent of fixed
cost through fixed charges. Only about 10 percent of residential fixed costs are recovered
through fixed charges compared to 15 to 18 percent for non-residential, excluding
pumping services.
Natural Gas Customers
Annual revenue from fixed charges and fixed costs are shown for natural gas customer
classes in Figure 3-2.87 The Non-Decoupled classes are Interruptible Service and
Transportation Service.
100%
v
m
V 80%
XX
60%
E
0
40% 34%
0 32% 30%
`w
0
u
a, 20°+_
� 7g'o
I
u 00 0% I I
a Residential General Service Interruptible Transportation
Service Service
TOTAL DECOUPLED DECOUPLED NOW NON-
DECOUPLED DECOUPLED
Figure 3-2. Percent Natural Gas Fixed Cost covered by Fixed Charges.
Overall, fixed charges for total natural gas recover around 32 percent of fixed cost. At 34
percent, residential customers cover the highest percentage of fixed costs through fixed
charges. General services recover 30 percent of fixed costs through fixed charges. Non-
"Avista's natural gas cost of service studies use different customer groupings than the decoupling
mechanism. The cost-of-service roll-up combines Schedules 111 (General Services)and Schedule 112
(Large General Services). Consequently,only one non-residential decoupled customer class is shown in the
analysis of natural gas recovery of fixed cost through fixed charges.
3-2

decoupled customer classes recover the smallest percentage of fixed cost through fixed
charges. Fixed charges revenue as a percentage of fixed cost is zero for interruptible
services. Fixed costs are a very small level of the total costs for this customer class. The
percentage of fixed cost recovered through fixed charges from transportation service is
about 7 percent.
Summary—Recovery of Fixed Charges (Non-Decoupled Classes)
For electric non-decoupled classes, Avista recovers 16% of fixed charges for Extra Large
General Service and 100% of fixed charges for Street and Area Lighting through the
customer charge. For natural gas non-decoupled classes, Avista recovers no revenue for
Interruptible Service and 7% of fixed charges for Transportation Service through the
customer charge.
Overall (system total), Avista recovers about 14 percent of total electric fixed cost
through fixed customer charges. The percentage runs lower for residential and larger for
non-residential. On the natural gas side, overall fixed charges recover 32 percent of fixed
costs with a slightly higher percentage of recovery in the residential customer class than
non-residential customer classes.
3-3

AN
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3-4

Section 1 1n Trends and Performance
This section provides an analysis of each Mechanism's impact on conservation
achievement, in total and by sector(residential, low-income, non-residential), and
identification of conclusive or meaningful trends in the performance of Avista's electric
and natural gas conservation programs since the inception of the Mechanisms (i.e., did
Avista achieve a higher level of savings with the mechanisms in effect). This analysis is
based on information already available as part of Avista's biennial conservation
achievement evaluations filed with the Commission including changes to program
delivery strategies as reported in annual evaluations, significant changes in program
budgets, or reported savings levels. The specific questions addressed in this section are:
1. Were there any differences in conservation program savings, expenditures, and
customers served between low-income customers and the rest of the residential
class related to Decoupling?
2. Were there any trends in the performance of Avista's conservation programs since
the inception of the Mechanisms,both in total and by sector(i.e., low-income,
residential, and non-residential)?
3. Have the Mechanisms had an impact on natural gas conservation savings?
4. Have the Mechanisms had an impact on electric conservation savings (excluding
the decoupling commitment to energy savings of 5%)?
Performance Trends: Total and by Sector
The analysis of performance Trends of Avista's Washington conservation programs is
based on the energy savings and efficiency expenditures reported in the Washington
Avista Annual Conservation Reports (2014-2022). These reports validate and summarize
energy savings and expenditure data for Avista's Washington Electric and Natural Gas
Conservation Programs and provide the source of annual data for trend analysis. The data
was copied from the individual annual reports and compiled into spreadsheets to develop
a conservation program trend analysis of performance and expenditures. The
performance trend analysis provides a set of graphs and tables designed to identify
conclusive and meaningful trends based on reported energy savings and expenditures
data. In this section of the report, analysis identifies trends but does not attempt to
attribute causality to the trends, except for noting negative performance effects
attributable to the Covid pandemic in the 2021 Avista Conservation Report. For this
analysis `Total Residential' includes information for both `Residential' and `Low-Income
Residential.'
4-1

Electrical Energy Savings
Total Annual Electrical Conservation program savings (Figure 4-1) increased 131% in
2016, the year following the implementation of the Mechanism in 2015. However, since
2016, the Total Savings line has trended downward, with one annual increase in 2021, in
the non-residential sector. Overall, the negative electrical savings trend is driven by
declines in the residential sector's annual savings rate. The residential downward trend
accelerates in 2020 with a 42% decline from the savings achieved in 2019, which can be
reasonably attributed to the impact of the Covid-19 Pandemic. The residential sector
savings rate continues to remain substantially below pre-pandemic levels through 2022.
WA Avista Electrical Savings(kWh)by Sector and Total
80,000,000 140%
70,000,000 120%
%Change 100%
60,000,000
80%
..............
50,000,000 ""'•
...........
40,000,000 •'••"'•• Trendline
Total
•........30,000,000 20%
0%
20,000,000
-20%
10,000,000 -40%
0 -60%
2014 2015 2016 2017 2018 2019 2020 2021 2022
�TotalResidential 23,784,974 10,926,176 33,589,134 23,330,658 13,607,612 16,307,468 3,601,842 1,874,877 2,119,973
Non-residential 16,226,327 19,167,758 37,420,578 40,859,838 32,834,855 25,433,281 20,584,356 28,743,276 20,900,684
Generation and Distribution 885,000 877,000 561,990 476,000 0 0 0 0 0
Total Savings 40,896,301 30,970,934 71,571,702 64,666,496 46,442,467 41,740,749 24,186,198 30,618,153 23,020,657
_%Change Total Savings -24% 131% -10% -28% -10% -42% 27% -25%
Figure 4-1: Electrical Energy Savings (kWh by Sector and Total).
Electrical Expenditures
The total annual electrical efficiency program expenditure data (Figure 4-2) indicates a
general upward trend in spending over the 2014-2022 period, with leveling and a slight
decline since 2017. Annual kWh savings high reached in 2017 ($21,787,386) has not
been matched as of 2022 reported data. There is a clear downward trend in residential
electrical efficiency expenditures since 2017, with a precipitous decrease in 2020 which
can be reasonably attributed to the Covid-19 pandemic. This decrease in residential
expenditure mirrors the Covid impact of residential kwh annual savings rates.
Counter to the residential decline,Non-Residential (Commercial and Industrial) spending
began a strong upward trend just as residential expenditures were declining.
4-2

WA Avista Electical Efficiency Expenditures by Sector and Total
$25,000,000 70%
%Change 60%
$20,000,000 Trendline 50%
Total •••••••••
........ .......... 30%
$15,000,000 ""
.......................
20%
S10,000,000 - - 10%
0%
$5,000,000 ' ' -10%
-20%
$0 -30%
2014 2015 2016 2017 2018 2019 2020 2021 2022
Total Residential $4,115,619 $4,468,709 $5,828,459 $7,904,390 $6,724,100 $7,096,768 $2,298,239 $1,322,625 $1,978,613
Nonresidential $3,781,678 $4,162,940 $10,339,410$10,147,062 $7,148,781 $5,392,870 $9,181,515 $12,369,954$10,722,483
iiiiiiiiiiiiia Regional 8,General $3,157,730 $3,389,514 $3,458,742 $3,745,934 $3,546,495 $3,799,768 $5,131,183 $5,712,259 $5,500,711
Total Efficiency Expenditures $11,055,027$12,021,163$19,636,611$21,797,386$17,419,376$16,289,406$16,610,937$19,404,838$18,201,807
-%Change Total Expenditures 9% 63% 11% -20% -6% 2% 17% -6%
Figure 4-2: Electrical Efficiency Expenditures ($) by Sector and Total.
Natural Gas Energy Savings
The total Natural Gas Savings trend line is level with some cyclicality(Figure 4-3 The
natural gas savings rate for the residential sector generally exceeds that in the
nonresidential sector. Nonresidential savings showed strong increases in 2020 and 2021
and then declined in 2022.
WA Avista Natural Gas Savings(therms)by Sector and Total
1,200,000 100%
1,000,000 80%
%Change
60%
800,000
Trendline Total 40%
600,000
20%
400,000
0%
200,000 20%
0 40%
2014 2015 2016 2017 2018 2019 2020 2021 2022
Total Residential 284,732 114,150 386,381 776,064 636,781 418,545 422,975 442,852 486,950
IIIIIIIIII�Nonresidential 245,031 544,883 162,375 270,293 100,205 85,567 172,357 327,595 58,819
IIIIIIIIII�Total Savings 529,763 659,033 548,756 1,046,357 736,986 504,112 595,332 770,447 545,769
�%Change Total Savings 24% -17% 91% -30% -32% 18% 29% -29%
Figure 4-3: Natural Gas Energy Savings (Therms) by Sector and Total.
Natural Gas Expenditures
Total Annual Natural Gas Efficiency Program Expenditures trended level over the 2014-
2022 period with inflection to higher rates of increase in 2019 (Figure 4-4, green dotted
4-3

line). Total Residential Natural Gas expenditures show a steady but modest increase over
2014-2022 period and there was a strong (55%) year-to-year nonresidential spending
increase in 2020. The 2018 to 2022 period also shows a positive trend in Regional and
General efficiency expenditures.
WA Avista Natural Gas Efficiency Expenditures by Sector and Total
$12,000,000 60%
%Change 50%
$10,000,000
40%
$8,000,000
30%
Trendline
$6,000,000 Total..•• 20%
$4,000,000 10%
0%
$2,000,000
$- -20%
2014 2015 2016 2017 2018 2019 2020 2021 2022
Total Residential $2,442,161 $1,634,429 $2,448,066 $2,888,384 $2,796,144 $4,179,976 $3,113,383 $3,817,998 $4,649,743
Nonresidential $938,800 $1,932,810 $551,980 $797,860 $510,295 $307,902 $3,928,502 $4,124,612 1$4,930,808
Regional and General $444,593 $560,536 $579,608 $595,526 $459,745 $706,489 $1,026,591 $1,465,278 $1,881,948
Total Efficiency Expenditures $3,825,554 $4,127,775 $3,579,654 $4,281,770 $3,766,184 $5,194,367 $8,068,476 $9,407,888 $11,462,499
�%Change Total Expenditures 8% -13% 1 20% -12% 38% 55% 17% 22%
Figure 4-4: Gas Efficiency Expenditures by Sector and Total.
Residential and Low-Income Program Performance
Total Residential Electrical Savings Trend
As shown in Figure 4-5, overall, the trend line for Total Annual Residential Electrical
decreases (green dotted line, sloping downward) over the 2014-2022 period. After
increasing in 2015 by 24%, the savings rate increases in 2016 by 131%. In 2017, annual
residential savings began a declining trend through 2022. This decline began in 2018,
three years before the Covid-19 pandemic.
Savings rates were then significantly impacted by Covid-19 with a 42% drop in 2020.
Recovery to pre-Covid level has not been attained.
4-4

WA Avista Total Residential Electric Savings(kWh)
40,000,000 250%
35,000,000
200%
30,000,000 Trendline
Total 150%
25,000,000
100%
20,000,000
50%
15,000,000
%Change
0%
10,000,000
5,000,000 -50%
0 -100%
2014 2015 2016 2017 2018 2019 2020 2021 2022
i�Total Residential 23,784,974 10,926,176 33,589,134 23,330,658 13,607,612 16,307,468 3,601,842 1,874,877 2,119,973
-%Change Total Residential -54% 207% -31% -42% 20% -78% -48% 13%
Figure 4-5: Total Residential Electrical Savings (kWh).
Low Income Electric Savings Trends
In contrast to Total Residential (Figure 4-5), the Low-income Savings (kwh) trend line
increased from 2014 to 2022 (Figure 4-6, blue dotted line,upward sloping). Low-income
savings as a percentage of Total residential savings was fairly level from 2014 through
2019 (Figure 4-7). In 2020, there was a strong increase of 55% over 2019 as Covid shut
down much regular residential work. There was a further increase of 17% from 2020 to
2021, and an increase of 22% from 2021 to 2022.
WA Avista Low Income Electrical Savings (kWh)
450,000 250%
Trendline
400,000 %Change Total 200%
350,000 150%
300,000 100%
250,000 50%
200,000 0%
150,000 -50%
100,000 100%
2014 2015 2016 2017 2018 2019 2020 2021 2022
Low Income 198,392 209,567 272,438 191,457 362,748 399,536 341,277 306,466 358,437
_%Change Total Residential -54% 207% -31% -42% 20% -78% -48% 13%
Figure 4-6: Low-Income Electrical Savings (kWh).
4-5

The Low-Income percentage of Total Residential savings also increased(Figure 1-7).
WA Avista Low Income Electric Savings as%of Total Residential
20% 250%
200%
15%
%Change 150%
10% Trendline Total 100%
5% 50%
0%
0%
-50%
-5% -100%
2014 2015 2016 2017 2018 2019 2020 2021 2022
iiiiiiiiiiiim Low Income%of Total 1% 2% 1% 1% 3% 2% 9% 16% 17%
_%Change Total Residential -54% 207% -31% -42% 20% -78% -48% 13%
Figure 4-7: Ratio of Low-Income to Total Residential Electrical Savings (%).
Number of Electrical Residential and Low Income Receiving
Conservation Services
The 2016-2022 trend line in the number of WA Avista electrical residential customers
(Figure 4-8) served with conservation services was negative. The percentage of Low-
Income customers served remained stable, averaging 16% over the period.
WA Avista Electric Residential Customers Receiving Conservation Services
4500 20%
4000 18%
3500 Low Income 16%
3000 14%
12%
2500
10%
2000 Trendline
Total 8%
1500
6%
1000
4%
500 � 2%
0 0%
2016 2017 2018 2019 2020 2021 2022
Low Income 313 352 325 306 223 352 325
Total Residential 2313 3850 2901 2554 860 1526 1228
_%Low Income 16% 17% 16% 15% 11% 17% 16%
Figure 4-8: Number of Residential Electrical Customers Receiving Conservation
Services.
4-6

Electric Residential Expenditures
The Total Residential Electrical Efficiency Expenditures trend line (orange dotted line in
Figure 4-9) shows the general downward trend in expenditures during the entire 2014-
2022 period. Within this trend, however, expenditures increased 30% in 2016 and 36%
2017 and stabilized through 2018 and 2019. In 2020 residential electric efficiency
expenditures declined by 68%, reasonably attributed to the Covid-19 pandemic. Total
Residential efficiency expenditure decreased again in 2021 by 42%, again reasonably
attributed to the pandemic. In 2022 expenditures increased by 50% over the 2021 low
point.
WA Avista Electrical Efficiency Expenditures
$9,000,000 60%
$8,000,000
40%
$7,000,000 TrendlineTotal
%Change 20%
$6,000,000
$5,000,000 0%
............
$4,000,000
$3,000,000 ..
-40%
$2,000,000
$1,000,00
$0 d -60%
2014 2015 2016 2017 2018 2019 2020 2021 2022 -80%
Low Income $1,270,313 $1,208,586 $877,030 $916,648 $1,334,642 $1,446,993 $1,323,322 $920,555 $1,147,284
Total Residential $4,115,619 $4,468,709 $5,829,459 $7,904,390 $6,724,100 $7,096,768 $2,298,239 $1,322,625 $1,978,613
-%Change Total Residential 9% 30% 365 -15% 6% -68% -42% 50%
Figure 4-9: Residential Electrical Expenditures ($).
As shown in Figure 4-10, the Low-Income electrical efficiency expenditures trend line
(dotted blue horizontal line) is level with variations from year to year.
Figure 4-11 shows the increase in low-income spending for electrical efficiency(upward
sloping, dotted brown line) from year to year. Within this overall trend, the proportion of
low-income spending decreased from 2014 through 2017, then showed strong year-over-
year increases from 2018 through 2021 with a decrease from 2021 to 2022.
4-7

WA Avista Low Income Electrical Efficiency Expenditures
$1,500,000 60%
$1,400,000 %Change
40%
$1,300,000
20%
$1,200,000
$1,100,000 Trendline Total 0%
$1,000,000 -20%
$900,000
-40%
$800,000
$700,000 -60%
$600,000 -80%
2014 2015 2016 2017 2018 2019 2020 2021 2022
iiiiiiii=Low Income $1,270,313$1,208,586 $877,030 $916,648 $1,334,642$1,446,993$1,323,322 $920,555 $1,147,284
-%Change Total Residential 9% 30% 36% -15% 6% -68% -42% 50%
Figure 4-10: Electrical Low-Income Spending ($).
WA Avista Low Income as % of Total Residential Electrical Efficiency
Expenditures
80% 60%
70% 40%
%Change
60%
20%
50%
0%
40%
Trendline -20%
30% Total,..
4
20% 0%
10% ' , -600
0/ -80%
2014 2015 2016 2017 2018 2019 2020 2021 2022
iiiiiiiiiim%ofTotal Residential 31% 27% 15% 12% 20% 20% 58% 70% 58%
_%Change Total Residential 9% 30% 36% -15% 6% -68% -42% 50%
Figure 4-11: Ratio of Low-Income to Total Residential Electrical Spending (%).
On average, per customer, electrical conservation expenditures reflected a relatively
stable slightly increasing trend(Figure 4-12) from 2017 to 2020.Average expenditures
dropped in 2021 with a slight recovery in 2022.Average electric conservation
expenditures for low-income customers are slightly higher than for non-low-income
residential customers.
4-8

Electric Average Residential Customer Conservation Expenditures
$7,000
$6,000
$5,000
$4,000
$3,000
$2,000
$1,000
$0
2016 2017 2018 2019 2020 2021 2022
-Average Residential $2,520 $2,053 $2,318 $2,779 $2,672 $867 $1,611
-Average Low Income $2,802 $2,604 $4,107 $4,729 $5,934 $2,615 $3,530
Figure 4-12: Average Residential Electric Customer Conservation Expenditures ($).
Total Residential Natural Gas Savings Trend
The trend in Residential Natural Gas Savings (therms) has been positive with some
variability from year to year in the annual rate (Figure 4-13), upward sloping brown
dotted line). Within this trend, there was a decrease of 60% from 2014 to 2015, an
increase of 238% from 2015 to 2016, an increase of 101% from 2016 to 2017, and then a
decrease of 18% from 2017 to 2018 and a further decrease of 34% from 2018 to 2019.
From 2019 through 2022, there has been a slow increase in residential natural gas
savings.
WA Avista Natural Gas Savings (therms)
900,000 300%
800,000 250%
700,000
200%
%Change
600,000
Trendline Total 150%
500,000
100%
400,000
50%
300,000
200,000 0%
100,000 -50%
0 -100%
2014 2015 2016 2017 2018 2019 2020 2021 2022
Total Residential 284,732 114,150 386,381 776,064 636,781 418,545 422,975 442,852 486,950
_%Change Total Residential -60% 238% 101% -18% -34% 1% 5% 10%
Figure 4-13: Total Residential Natural Gas Savings (Therms).
4-9

Low Income Natural Gas Savings Trends
The overall Low Income Natural Gas Savings trend reflects a modest annual increase in
savings with variability from year to year(Figure 4-14)
Low Income savings as a percent of Total Residential Natural Gas Energy Savings was
relatively consistant from 2014 to 2022, ranging from under one-percent to about 6%.
The slope of the curve is slightly downwards (dotted blue line in Figure 4-15).
WA Avista Low Income Natural Gas Savings (therms)
25,000 300%
%Change 250%
20,000
Trendline 200%
15,000 Total 150%
100%
10,000 ..
50%
0%
5,000
-50%
0 , -100%
2014 2015 2016 2017 2018 2019 2020 2021 2022
Low Income 8,310 6,539 18,490 3,034 15,400 20,943 14,450 12,455 11,705
_%Change Total Residential -60% 238% 101% -18% -34% 1% 5% 10%
Figure 4-14: Residential Low-Income Natural Gas Savings (Therms).
WA Avista Low Income Natural Gas Savings as % of Total
Residential
7% 300%
6% %Change 250%
5% 200%
Trendline 150%
Total "
3% .
........ ..
50%
2% 0%
1% -50%
0% -100%
2014 2015 2016 2017 2018 2019 2020 2021 2022
%of Total Residential 3% 6% 5% 0% 2% 5% 4% 3% 2%
_%Change Total Residential -60% 238% 101% -18% -34% 1% 5% 10%
Figure 4-15: Ratio of Low-Income to Residential Natural Gas Savings (%).
4-10

Number of Natural Gas Residential and Low-Income Receiving
Conservation Services
The 2016-2022 trend line (Figure 4-16) was level for the number of natural gas
conservation customers. The percentage low-income remained relatively stable,
averaging 8% over the period.
WA Avista Natural Gas Residential Customers Receiving Conservation Services
9000 12%
8000 %Low Income
10%
7000 Trendline Total
......... .......... ................ ....... .... ................................... .... ..........
6000 8%
5000
6%
4000
3000 4%
2000
2%
1000
0 0%
2016 2017 2018 2019 2020 2021 2022
Low Income 429 510 493 573 393 547 493
Total Residential 4758 7713 7208 6668 6129 8300 5073
%Low Income 10% 7% 7% 9% 7% 7% 11%
Figure 4-16: Number of Gas Residential Customers Receiving Conservation Services.
Natural Gas Residential Expenditures
The Natural Gas Total Residential Efficiency Expenditure trend line has been upward
during the whole 2014 to 2022 period(blue,upward sloping dotted line in Figure 4-17).
WA Avista Natural Gas Efficiency Expenditures
ss,000.a0o bon
$4,500,000 sow
$4,t700,000 Trendllne 9096
..........
%Change Totai
$3,500,000 30%
$3,000,000 20%
$2,500,000 10%
$2,o00.0o0 .........................
0%
51,500,000 -:M
51,000,00o -M
ssoo,ow -30%
50 —
2014 2015 2016 2017 2018 2011 2020 2021 2022
�Total Residential $2,442,161 $1,634,429 $2,448,066 $2,888,384 $2,796,144 $4,179,976 $3,113,383 $3,817,999 $4,649,743
4a4�-1,_ $70,937 $755,611 51,128,251 $1,045,703 $1,163,678 $1.859,392 $1,076,136 $1,157,076 $1,292,900
Change Total Residential 33% 50% 18% 3% 49% 26% 23% 22%
Figure 4-17: Natural Gas Total Residential Efficiency Expenditures ($).
4-11

The overall trend for Low-Income program expenditures is an increase (Figure 4-18,
upward sloping dotted blue line). Within this overall trend, spending increased from 2014
to 2019. This upward pattern was broken by a severe drop from 2019 to 2020, reasonably
attributable to the Covid pandemic.
WA Avista Low Income Natural Gas Efficiency Expenditures
$2,000,000 60%
$1,800,000 so%
%Change 40%
$1,600,000 30%
$1,400,000 20%
L"
$1,200,000
0'
$1,000,000 TrendlineTotal 1L
-20%
$800,000
-30%
$600,000 -40%
2014 2015 2016 2017 2018 2019 2020 2021 2022
I�Low Income $768,937 $755,611 $1,128,251 $1,045,703 $1,163,678 $1,859,392 $1,076,136 $1,157,076 $1,292,900
_%Change Total Residential -33% 50% 18% -3% 49% -26% 23% 22%
Figure 4-18: Natural Gas Low-Income Efficiency Expenditures ($).
The rate of increase, shown by the slope of the overall trend line is similar but higher for
Total Residential expenditures, than for Low-Income Natural Gas Efficiency
Expenditures. This falling relative share is shown in Figure 4-19 by the downward
sloping dotted blue trend line.
4-12

WA Avista Natural Gas Low Income Efficiency Expenditures as
of Total Residential
90% 60%
Trendline 50%
80% Total
40%
70% 30%
%Change
60% 20%
10%
50%
0%
40% -10%
20%
30% -30%
20% -40%
2014 2015 2016 2017 2018 2019 2020 2021 2022
%of Total Residential 46% 86% 85% 57% 71% 80% 53% 43% 39%
%Change Total Residential -33% 50% 18% -3% 49% -26% 23% 22%
Figure 4-19: Ratio of Low-Income to Total Natural Gas Residential Spending (%).
On average, per customer, natural gas conservation expenditures reflected stable and
level trend from 2017 to 2022, with a slight rise (Figure 4-20).Average natural gas
conservation expenditures for low-income customers are considerable higher than for
non-low-income residential customers, and, overall, are level.
Natural Gas Average Residential Customer Conservation Expenditures
$3,500
$3,000
$2,500
$2,000
$1,500
$1,000
$500 /
$0
2016 2017 2018 2019 2020 2021 2022
-Average Residential $515 $374 $388 $627 $508 $460 $917
-Average Low Income $2,630 $2,050 $2,360 $3,245 $2,738 $2,115 $2,623
Figure 4-20: Natural Gas Average Residential Customer Conservation Expenditures ($).
4-13

Summary— Conservation
The specific questions in this section of the study, along with short answers, are as
follows:
1. Were there any differences in conservation program savings, expenditures, and
customers served between low-income customers and the rest of the residential
class related to Decoupling?
• We find no reason to suggest a relationship between decoupling and
conservation results for program savings, expenditures, and customers
served. In other words, the relationships shown in the data in this section
of the study are as likely to have occurred in the absence of decoupling as
they actually occurred with decoupling.
• We also find no relationship to be evident between low-income customers
and the rest of the residential class related to decoupling. There are
changes, but we find no reason to suggest these changes have a
relationship to decoupling. The changes are likely driven by other factors.
2. Were there any trends in the performance ofAvista's conservation programs
since the inception of the Mechanisms, both in total and by sector(i.e., low-
income, residential, and non-residential)?
• For electricity, the overall energy savings trend is down, (Figure 4-1)
dominated by the downward trend for Total Residential (Figure 4-5). The
trend line for Total Residential Electric Savings shows an overall decline
from 2014 to 2022 (negative slope indicated by the green dotted line in
Figure 4-5). Spending is also down for Total Residential (Figure 4-9).
Total Residential Electric Savings have declined substantially over the
years examined.
4-14

tk
NMV
Table 4-1: Trends (Electricity).
Trends(Electricity)
Energy Savings Efficiency Spend
Sector Slope Graph Sector Slope Graph
Overall Electrical(kWh) Down Figure 1-1 Overall Electrical($) Up Figure 1-2
Non-Residential(kWh) Slight Up Figure 1-1 Non-Residential($) Up Figure 1-2
Total Residential(kWh) Down Figure 1-5 Total Residential($) Down Figure 1-9
Residential Low-hicome(kWh) Up Figure 1-6 Residential Low-Income($) Level Figure 1-10
Ratio of Low-hicome to Total Up Figure 1-7 Ratio of Low-Income to Total U Figure 1-I I
Residential Savings(%) Residential Savings(%) p
Number of Residential Electric Slight Down Figure 1-8 Average Electric Level Figure 1-12
Conservation Customers Conservation Spending
Number of Low-hicome Average Electric Low-hicome
Conservation Customers Level Figure 1-8 Conservation Spending Slight Up Figure 1-12
• In contrast, Low-Income Residential Electric Savings have increased both
absolutely(Figure 4-6) and as a percentage of Total Residential Electric
Savings (Figure 4-7). For Low-Income Electric Savings (kWh) the trend
line slopes upward over the same range of years examined(blue dotted
line in Figure 4-6). Also, the Low-Income Electric Savings as a percentage
of Total Residential Electric Savings increased from one percent(1%) to
seventeen percent(17%) from 2014 to 2022 (Figure 4-7).
• For natural gas, Residential energy savings trends for both Total
Residential and Low Income are sloping slightly upward(Figure 4-13 and
Figure 4-14), the Ratio of Low-Income to Total Residential Savings (%)
slopes slightly downward(Figure 4-15).
4-15

Table 4-2: Trends (Natural Gas).
Trends(Natural Gas)
Energy Savings Efficiency Spend
Sector Slope Graph Sector Slope Graph
Overall Natural Gas(Therms) Level Figure 1-3 Overall($) Up Figure 1-4
Non-Residential(Therms) Slight Down Figure 1-3 Non-Residential(Therms) Up Figure 1-4
Total Residential(Therms) Up Figure 1-13 Total Residential($) Up Figure 1-17
Residential Low-Income
(Therms) Up Figure 1-14 Residential Low-Income($) Up Figure 1-18
Ratio of Low-hicome to Total Sight Down Figure 1-15 Ratio of Low-hicomeoto Total Down Figure 1-19
Residential Savings(%) Residential Savings(/o)
Number of Residential Gas Level Figure 1-16 Average Natural Gas Level Figure 1-20
Conservation Customers Conservation Spending
Number of Low-hicome Gas Average Gas Low-Income
Conservation Customers Level Figure 1-16 Conservation Spending Level Figure 1-20
3. Have the Mechanisms had an impact on natural gas conservation savings?
• Based on the reports reviewed for this analysis, it is not evident that the
mechanisms have had a positive or negative impact on natural gas
conservation savings. Generally, it is likely that exogenous factors have
provided substantial impact on natural gas conservation savings. However,
since the slopes for both Total Residential and Residential Low-Income
Natural Gas savings are positive, these results are consistent with the
mechanisms having a positive effect on natural gas conservations savings.
While the slope of the trend line for Non-Residential savings for natural
gas is downwards, it is only slightly downwards.
4. Have the Mechanisms had an impact on electric conservation savings
(excluding the decoupling commitment to energy savings of 5%)?
• Based on the reports reviewed for this analysis, it is not evident that the
mechanisms have had a positive or negative impact on electric
conservation savings. Total Electrical savings are down, dominated by
Total Residential. Non-Residential savings are up, but only slightly. While
Total Residential is down, Residential Low-Income is up.
4-16

AN
• The Annual Conservation Reports do not break down savings to exclude
the 5% decoupling commitment.$$ The additional 5% decoupling savings
data is addressed in setting targets in the Annual Conservation Plan but is
not reported in the Annual Conservation Reports which provide the source
data for the analysis here. Since the results of the 5% decoupling
commitment are not specifically broken out in the Annual Conservation
Reports, the Annual Conservation Plan, or the Biennial Program
Evaluations, the 5%results cannot be addressed here.
In the big picture, overall electrical savings are trending downwards (Figure 4-1)while
costs are trending upwards (Figure 4-2). Overall natural gas savings are trending level
(Figure 4-3) while cost is trending upwards. For residential electric low-income
households, savings are trending up while cost is trending level (Table 4-1). For
residential natural gas households, savings are trending up, while cost is trending up
(Table 4-2). Other results are summarized in Table 4-1, Trends (Electricity) and in Table
4-2 (Trends,Natural Gas).
With regard to decoupling, there is no evident impact of decoupling on energy
conservation savings. This result is neither unusual nor unexpected. Decoupling is
generally not considered to be a driver of energy conservation. Rather, decoupling
removes a potential barrier to energy conservation, which is different than driving a direct
savings effect.
88 In the General Rate Case Settlement Agreement(Docket Nos UE-140188 and UG-140189),the Company agreed,in
consideration for receiving a full electric decoupling mechanism,to increase its electric energy conservation
achievement by 5%over the conservation target approved by the Commission.
4-17

Section 5. New Customer Analysis
Avista's decoupling mechanism currently applies only to customers on the system during
the test year89 used to establish allowed decoupled revenue per customer.91 Such
customers are referred to "existing" or"test-year" customers and customers added to the
system after the test year are referred to as "new" customers. It is important to understand
that in this context"existing" and"new"refer to premises on the system, rather than
people or households.91
The purpose of this section is to assess the impact of new customers if they had been
included in the decoupling mechanism. Avista has provided data that breaks out new
customers from all customers in each decoupled rate class to determine decoupled
revenue from existing customers. The same breakout allows us to also compare new
customers to existing customers.
A summary of this analysis for the electric system is shown in Table 5-1. Table 5-1
shows the number of customers,use per customer, actual decoupled revenue per
customer(RPC), allowed RPC, the difference between actual and allowed RPC, and the
deferred revenue before interest or revenue related expenses for each year in the analysis.
This information is shown for existing customers, new customers, and all customers
(existing and new combined) for each customer class. What stands out from the data in
Table 5-1 is that new customers are meaningfully different from existing customers in
both use per customer and decoupled(distribution)revenue generated per customer.
Consider the non-residential customer class in 2022. Although the number of new
customers is small relative to the number of existing customers, when calculated on a per
customer basis, the generated decoupled revenue per customer is significantly smaller
and substantially under the allowed revenue per customer for non-residential customers
in 2022. Had new customers been included in the decoupling mechanism in 2022,
deferred revenue in the non-residential customer class would have totaled$3.6 million
89 The"test year"refers to the twelve-month period used in a utility ratemaking proceeding to establish
number of customers and"typical"customer usage.A table of rate cases and associated test years is in the
appendix.
90 In Docket UE-190334 the Commission approved the Company's proposal to continue the Decoupling
Mechanism for an additional five years,beginning April 1,2020.A modification of the program specified
by the Commission is that customers connected to Avista's system after the ratemaking test year will be
excluded from the decoupled deferred revenue calculations.Furthermore,the Company will include a
status update in its yearly decoupling report identifying the number of new customers excluded from the
mechanism and associated costs and revenues.
91 A premise on the system during the test year that subsequently experiences a change in occupancy is not
considered a new customer.A premise added to the system that was not served on the system during the
test year is considered a new customer.Examples of new customers in this context include new natural gas
service to properties not previously served by natural gas and electric and natural gas service added to
newly constructed homes and commercial structures.Although excluded from the decoupling mechanism
in effect at the time the new service is established,these new customers would become existing customers
in the next rate case.
5-1

instead of the $0.4 million actually reported based only on existing customers. In other
words, including new customers would have resulted in an additional $3.2 million in
deferred revenue that, along with additional interest revenue expenses, would be charged
to customers through the decoupling tariff(RS 75).
Table 5-1. Impact of New Customers on Decoupled Deferred Revenue-Electric.
Residential Non-Residential
Existing New All Existing New All
--2022-
Number of Customers 219,635 7,266 226,901 36,333 2,234 38,567
Use Per Customer kWh 11,804 8,528 11,699 57,012 36,361 55,815
Decou led Rev.per Customer $938 $671 $929 $4,785 $3,344 $4,702
Allowed Rev.Per Customer $862 $862 $862 $4,795 $4,795 $4,795
Over Under Allowed RPC $75 $192 $67 $10 $1,452 $94
Deferred Revenue * $16,548,575 $1,394,840 $15,153,735 $364,447 $3,243,230 $3,607,677
--2021-
Number of Customers 217,802 6,367 224,169 36,194 1,885 38,078
Use Per Customer kWh 11,444 7,945 11,344 57,050 38,582 56,136
Decou led Rev.Per Customer $811 $553 $804 $4,436 $3,394 $4,385
Allowed Rev.Per Customer $787 $787 $787 $4,503 $4,503 $4,503
Over Under Allowed RPC $24 $234 $17 $67 $1,109 $119
Deferred Revenue * $5,283,617 $1,492,551 $3,791,066 $2,428,682 $2,089,408 $4,518,090
--2020--
Number of Customers 217,945 3,215 221,160 36,650 900 37,550
Use Per Customer kWh 11,145 6,405 11,076 54,230 33,263 53,728
Decou led Rev.Per Customer $739 $423 $735 $4,064 $2,947 $4,037
Allowed Rev.Per Customer 1 $735 $735 $735 $4,380 $4,380 $4,380
Over Under Allowed RPC $4 $313 $0 $316 $1,433 $343
Deferred Revenue * $910,276 $1,004,907 $94,631 $11,574,703 $1,289,651 $12,864,354
*Before interest and revenue related expenses
Although not always as striking, each of the six comparisons between existing and new
customers shown in Table 5-1 (three years and two customer classes) show a similar
result as the non-residential customer class in 2022. New customers differ from existing
customers in magnitudes that meaningfully impact deferred revenues. These differences
in revenue per customer are graphically illustrated in Figure 5-1.
5-2

5% 4.4% 3.5%
0% • -
-5%
' -4.1%
-10%
-15%
-20%
-25%
-30%
-29.2%
-35% -31.0%
Existing New All Existing New All
Residential Non-Residential
Figure 5-1: Percent Over (Under)Allowed RPC—Electric (2020—2022 Average)
The average decoupled revenue per customer over the 2020-2022 period as a percentage
of the allowed revenue per customer is shown for both of the decoupled electric customer
classes in Figure 5-1. The substantial difference between new and existing customers is
clear in the chart. Had new customers been included, electric Residential customers
would have received a smaller refund; electric Non-Residential customers would have
received a higher charge through application of the decoupling tariff(RS 75).
A comparison of deferral related calculations for existing and new customers is shown
for the natural gas system in Table 5-2.92
12 Table 5-2 follows the same structure as Table 5-1.
5-3

Table 5-2. Impact of New Customers on Decoupled Deferred Revenue-Natural Gas.
Residential I Non-Residential
Existing TNew All Existing I New All
-2022--
Number of Customers 166,593 5,771 172,364 3,274 73 3,347
Use Per Customer therms 830 689 825 18,998 25,019 19,129
Decou led Rev.Per Customer $419 $358 $417 $4,766 $6,195 $4,797
Allowed Rev.Per Customer $413 $413 $413 $5,184 $5,184 $5,184
Over(Under)Allowed RPC $6 $55 $4 $417 $1,011 $386
Deferred Revenue * $1,028,897 $314,713 $714,184 $1,366,877 $73,570 $1,293,308
-2021--
Number of Customers 164,302 6,281 170,582 3,142 56 3,198
Use Per Customer therms 749 618 744 17,442 22,503 17,530
Decou led Rev.Per Customer $346 $291 $344 $4,237 $5,752 $4,263
Allowed Rev.Per Customer $388 $388 $388 $5,026 $5,026 $5,026
Over Under Allowed RPC $41 $96 $43 $790 $725 $763
Deferred Revenue * $6,790,351 $603,447 $7,393,797 $2,481,573 $40,380 $2,441,193
--2020--
Number of Customers 164,450 3,739 168,189 3,119 30 3,149
Use Per Customer therms 764 452 757 17,699 16,870 17,691
Decou led Rev.Per Customer $337 $201 $334 $4,597 $4,377 $4,595
Allowed Rev.Per Customer $344 $344 $344 $4,746 $4,746 $4,746
Over(Under)Allowed RPC $7 $143 $10 $149 $369 $151
Deferred Revenue * $1,218,479 $533,931 $1,752,410 $465,506 $10,958 $476,464
*Before interest and revenue related expenses
Although the differences are not as pronounced for natural gas as electric, the information
in Table 5-2 shows that new residential customers use substantially fewer therms per
customer and generate less decoupled revenue per customer than existing customers.
Except for 2020, new non-residential customers had substantially higher usage per
customer and generated more decoupled revenue per customer than existing customers.
Because the number of new customers is small relative to existing customers, the overall
impact on deferred revenue is limited but still meaningful. For example, the deferred
revenue credit back to residential customers in 2022 would have been reduced by about
30%had new customers been included in the determination of deferred revenue.
Differences in revenue per customer relative to allowed RPC is illustrated in Figure 5-2
for natural gas customer classes.
5-4

15%
10% 9.1%
5%
-5%
-3.7% -4.3%
-10%
-9.1% -8.7%
-15%
-20%
-25%
-25.6%
-30%
Existing New All Existing New All
Residential Nan-Residential
Figure 5-2. Percent Over (Under)Allowed RPC-Natural Gas (2020-2022 Average).
The average decoupled revenue per customer over the 2020-2022 period as a percentage
of the allowed revenue per customer is shown separately for both Residential and Non-
Residential decoupled natural gas customer classes (Figure 5-2). The substantial
difference between new and existing customers is clear in the chart. Had new customers
been included over the 2020-2022 period, residential customers would have experienced
a higher charge, but non-residential customers would have received a lower charge
through the decoupling tariff(RS 75).
Summary - New Customers
From 2020 through 2022 Avista's decoupling mechanism applies only to customers on
the system during the test year. New customers (operationalized as premises) will not be
added to the decoupling mechanism until the next rate case (with a new test year). This
raises the question of what the impact of new customers would have been if they had
been included in decoupling. The WUTC has directed analysis of this question.
New customers are meaningfully different from existing customers in both use per
customer and decoupled (distribution) revenue generated per customer. Although the
effect is stronger for electric service, and not as pronounced for natural gas service, new
Residential customers use substantially less energy per customer and generate less
revenue per customer than existing customers. Because the number of new customers is
small relative to existing customers, the overall impact on deferred revenue is limited, but
still meaningful.
For electric service, had new customers been included over the 2020-2022 period, electric
Residential customers would have received a smaller refund; electric Non-Residential
customers would have received a higher charge through application of the decoupling
tariff(RS 75).
5-5

For natural gas service, had new customers been included over the 2020-2022 period,
Residential customers would have experienced a higher charge,but Non-Residential
customers would have received a lower charge through the decoupling tariff(RS 175).
5-6

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5-7

Section 1. Impact of Alternative Definitions of Normal
Weather
Normal Weather - Alternative Definitions
Avista uses a rolling 30-year average to define "normal weather". Establishing
meteorological normals over a 30-year period has long been a standard used by NOAA
and adopted by many industries, including the energy industry. Climate change, however,
has resulted in increasing winter and summer temperatures to the point that the traditional
30-year definition of normal needs to be reconsidered. The issue is that a 30-year period
may produce inappropriate results when an underlying trend is present. Recognizing this
need, one of the decoupling evaluation objectives is to examine the impact of alternative
durations in the definition of normal weather. Specifically, as directed by Commission93,
Avista is interested in understanding the impact of using a 20-, 15- and 10-year period for
calculating normal weather instead of the historical standard of 30 years (Figure 6-1).94
Alternative Weather Calculations
Analysis of using a moving average of
weather data shorter than 30 years based on
the data gathered by Avista regarding a 30-,
20-, 15-, and 10-year moving average.
Figure 6-1: Four Ways to Calculate Normal Weather.
9s The Avista calculations use Spokane airport weather data and calculate a moving average.For each new
year for which"normal weather"is calculated,the most recent complete data year is used,and the year
farthest back is dropped from the data series.Avista's alternative calculations of normal weather are 30-
year,20-year, 15-year and 10-year calculations. Each alternative calculation yields a different answer for
normal weather.
"The prior decoupling evaluation(2018)included the following recommendation: "Consider a redefinition
of normal weather that moves away from the 30-year moving average to a 20-year moving average,and
also maintain a moving average indicator for 15 years and 10 years to see how that behaves empirically,
since"normal"has become a flow variable and it is rapidly getting warmer as a secular trend."Peach,
Hugh.,Mark Thompson,and John Joseph,Avista Decoupling Evaluation,Final Report.Beaverton,
Oregon: H. Gil Peach&Associates,October 1,2018,p. 10-1.NWEC has recommended that the
Commission move to a 20-year moving average and consider the effect of using alternative definitions
(DOCKETS UE-190334,UG-190335,UE-190222(Consolidated)Final Order 09,p.37. In this order,the
Commission found the record insufficient to move to a 20-year standard,but directed study of this question
by Avista,and directed review of the Avista results in the current evaluation: "...[W]e reject the proposal
to adopt a 20-year moving average of weather data for Avista's decoupling mechanisms at this juncture but
determine that the Commission should engage in a broader conversation with stakeholders about the value
of moving towards using more recent periods of weather data.To aid in this discussion and to better
understand how weather variability affects Avista's decoupling mechanisms,we require Avista to maintain
and present data for 30-,20-, 15-,and 10-year moving averages,and that this design element and data be
analyzed by the third-party evaluator." Final Order(Order 09)in Dockets UG-190334,UG-190335,UE-
190222(consolidated),March 25,2020,P. 3.
6-1

Climate change requires re-thinking or the 30-year calculation standard. Currently, due to
carbon loading of the atmosphere, continually, an amount of solar heat that in prior times
was re-radiated into space is retained in the earth's atmosphere, water, and land, so that
heat energy is constantly increased on a planetary scale. This has resulted in a trend of
increasing winter and summer temperatures to the point that the traditional 30-year
definition of"normal weather"must be reconsidered. The issue is that climate change has
become strong enough to cause the 30-year calculation to produce an estimate of what
weather would have been in the absence of climate change, rather than normal weather.
The 30-year calculation produces an estimate of abnormal weather rather than normal
weather. In statistical terms, the standard 30-year calculation now produces a biased
estimate of projected temperatures.95
In the context of decoupling, alternative definitions of normal weather have the potential
for impacting deferred revenue from decoupling. Variations result from differences
between actual and expected energy use per customer. These can be driven by differences
between expected and actual temperatures, energy efficiency improvements, economic
changes, and other factors.
Differences in use per customer due to weather are observed when weather deviates from
normal. The climate trend in the data is the major source of this variation. Since
decoupling has evolved as a practice without taking climate trend into account,
statistically speaking, we can initially regard the climate trend as a bias: the observed
differences between actual and normal weather are due not only to the typical deviations
of actual from normal weather as understood in a calculation with no climate trend,but
now also include the climate trend bias embedded in the calculation of normal weather.
When the definition of normal weather is biased, decoupling deferrals will also be biased.
Consider a class of customers before the climate trend became quantitatively important.
In this hypothetical example, in the absence of a strong climate trend, apparently random
changes in weather are the primary physical variable driving the differences between
decoupled revenue per customer and allowed revenue per customer.96 Further assuming
that normal weather is accurately defined in the test year,because the primary physical
driver is random weather changes, deferred revenues would be expected to average zero
over time with above normal fluctuations and below normal fluctuations averaging out.
95 Because we are moving between frameworks,it can be difficult to grasp the high importance of this
change.Reference texts and existing industry algorithms provide methods for calculating"normal
weather."However,in a climate change framework,looking for"normal weather"becomes problematic.
From about 1935 to 1988,it would have been the right question to ask.Now,going forward,the relevant
question is"what will the weather be like for the year we are trying to estimate"?The"new normal
weather"would take climate trend(here operationalized as Heating Degree Days)into account.Because
the effect has become strong and continues to become stronger,the term"normal"no longer makes sense,
unless it includes climate trend. The older calculations(30-year rolling average or the alternative 30-year
Typical Meteorological Year)produce an estimate of normal weather which may be useful to adjust
revenues for climate change,but it is an estimate of"abnormal weather"—weather as it would have been if
the process of climate change were not happening.
96 Along with any conservation effect,economic effects,and other factors.
6-2

If, however, calculated normal weather includes the climate trend, then deferred revenue
will be driven by the climate trend and will not average out over time.97
In this section we explore in greater depth the impact of alternative definitions of normal
weather using data compiled by Avista. Before doing so it is useful to understand how
actual weather compared to normal weather over the evaluation period.
30-Year Normal vs. Actual
Comparison of Avista 30-year rolling average Heating Degree Days (HDDs) and Cooling
Degree Day (CDDs) to actual HDDs and CDDs is shown in Table 6-1.
Table 6-1. Comparison of Actual to Normal Weather, 2020-2022
Heating Degree Days Cooling Degree Days
2020 2021 2022 2020 2021 2022
Actual 6,056 6,038 6,677 556 919 765
Normal 6,514 6,485 6,509 506 524 533
Percentage _7 0% -6.9% 2.6% 9.9% 75.4% 43.5%
Difference
By the standard used by Avista to calculate normal degree days (30-year historical period
updated annually), 2020 and 2021 were warmer heating seasons than normal (fewer
heating degree days) and the heating season of 2022 was slightly colder than normal
(more heating degree days). Summers were warmer than normal each year.
This is the kind of pattern we would expect when the estimate of normal weather
overstates the heating degree days and understates cooling degree days. In 2022, when
actual heating degree days exceeded normal, the percentage deviation from normal was
far less than the absolute percentage deviation from normal in 2020 and 2021 when actual
heating degree were lower than normal.
Since the structure of weather has changed, and continues to change, it is reasonable to
conclude that methods of weather adjustment should be modified with reference to actual
climate conditions as indicated by the temperature trend, to take changes in structure into
97 While this simple and hypothetical customer class example allows us to conceptualize the climate trend
bias associated with inaccurately defined normal weather,in practice and in the short run,the combined
irregularities of actual weather along with changing economic conditions and customer behavior may
sometimes swamp the embedded climate trend bias in calculated normal weather.
6-3

account.98 The climate trends, in the form of HDDs and CDDs, have become well
defined.
Climate Trends (HDDs and CDDs)
The downward trend for Heating Degree Days (HDD) is shown in Figure 6-2. The
upward trend for Cooling Degree Days (CDD) is shown in Figure 6-3.99 The physical
realities underlying these regression lines violate the assumption of steady state
relationship among relevant variables over time. The downward slope of the regression
line for HDDs (Figure 6-2) means that regardless of decoupling or energy
conservation/energy efficiency, customer requirement for heating energy is decreasing.
Similarly, in Figure 6-3, the graph shows that, regardless of decoupling or energy
conservation, customer need for cooling energy is substantively increasing.
Spokane internatioal Airport Annual HDD
8,500
8,000
7,500
7,000 A.
6,500
6,000
5,500
a R V1 VI Vl Vl Vl O O O D O l� l� l� l� l� OD OD 00 00 00 T T O O T O O O O O ..a .w N
rl rl rl rl rl rl rl rl ti ti ti ti ti ti ti ti . rl rl rl rl rl rI rI rI rI rI N N N N N N N N N N N
Figure 6-2: Spokane International Airport Annual Heating Degree Days (1947-2021).
98"Structure change"refers to a substantive change in the way relationships among variables operate
among points in time.When we use time series data and one or more equations to project to a future
situation;and if the structure of the relationships modeled by the equation(s)does not change,then the
equation(s)can correctly project(predict by approximation)the future value. When structure changes over
the years included in an analysis,it is necessary to explicitly take structure change into account. "In
prediction under changed structure...predictions are to be made about a process that(because of the
structural change)has some feature(s)that have never been observed before:hence the problem is more
difficult."Christ,Carl F.,Econometric Models and Methods.New York,London& Sydney: John Wiley
&Sons,Inc., 1966,P. 13. For weather adjustment mechanisms,the primary problem is in two variables,
Heating Degree Days(HDD)and Cooling Degree Days(CDD),though additional,more complex weather
relationships are also affected.
99 Spokane International Airport Annual HDD and Annual CDD graphs were provided by Avista.
6-4

Spokane International Airport Annual CDD
1,000
900
800
700
600
500
400
300
200
100
0
h Q. ti M N r a ti M N r a ti M N r a ti M N r a ti M N r a ti M N r O. ti M N r a ti
O. O. O. O. O. O. O. O. O. O. O. O. O. O. O. O. O. O. O. - O. - O. - O O O O O O O O O O O
.� H .� H .� H .� H .� H .� H .� H .� H .� H .� H .� H .� H .� H .� N N N N N N N N N N N
Figure 6-3: Spokane International Airport Annual Cooling Degree Days (1947-2021).
The Peril of Standard Weather Adjustment
Many utilities using the standard weather adjustment mechanism are experiencing
problems because their weather adjustment algorithms, which worked well for several
decades, may no longer produce reasonable estimates of normal weather. Instead, the
weather adjustment algorithm will project a weather estimate much like what weather
would have been if there were no climate change.100 This means that, for Heating Degree
Days, the algorithm will operate primarily to adjust customer bills and/or rates upwards
to compensate for the revenue loss due to climate change.101
Standard weather adjustment algorithms worked well for a situation without climate
change (Figure 6-4). In this picture, the weather system is stable; the decreasing HDD
trend shown in Figure 6-2 has been removed by detrending the data and the increasing
CDD trend shown in Figure 6-3 is not included. This picture is consistent with an
understanding of"normal weather,"which was a reasonable simplification prior to about
1988.102 This picture is no longer true.
loo Weather could be thought of as an essentially stable system with various occasional perturbations.But
not exactly,since the underlying data is a mix of older data,not representative of normal weather when
there has been structure change,and recent data,more representative of normal weather under continuing
structure change.
10'Warmer temperatures mean decreasing HDDs,and less need for energy for heating.However,since
warmer temperatures occur across all seasons,there is more need for energy for cooling. Since natural gas
is used for heating but not for cooling,climate change means increasing loss of revenue for gas. Since
electricity is used for both heating and cooling,increased cooling load will,to some extent,offset decreased
heating load.
102 Analysis based on HDD data from Spokane airport(1947-2021)provided by Avista(DR 12-DR 14).
For Figure 6-4,the y-axis value for the blue horizonal line is adjusted from 0 to 7,084(the trend HDD
value of the 1948 data point)to facilitate comparison.All of the data points making up the curve have been
detrended.What is left in the data is the cyclical-irregular El Nino Southern Oscillation(ENSO)and
irregulars due to weather and all other factors.The HDD trend has been removed.See Frederick E,Dudley
J. Cowden,and Sidney Klein,Applied General Statistics.Englewood Cliffs,New Jersey:Prentice-Hall,
1967,p.229.
6-5

Heating Degree Days
(Detrended)
—ADJDetrended
Horizontal
6s00
N
a
A
N
d 7500
W
d
C
� 6500 'If y 11,y
2
5500
N N N N N N
f0 u7 W (O f0 f0 (D f0 0J fO f0 0 O O O O_ _O O
A U W W W ti Do DO CO
W f0 00 O O O N
W NM O A W N W O A W N W O A W N W O
Year
Figure 6-4: Heating Degree Days -Detrended Data—HDD Trend Removed.
As shown in Figure 6-6, which is presented in a format to match Figure 6-4, the structure
of weather has changed, and continues to change.103
Heating Degree Days and HDD Trend Line
Trend Line Values
asoo
LAVA Spokane HDD
8000
N
)n
Q 7500
d
N 7000
0
C
C
6500
2
6000
5500
> > N N N N N N
t0 f0 47 t0 t0 f0 f0 tD t0 O f0 O O O O O O O
(.rl W W W 0! W W W f0 W O O O N
DoN 0)W O A W N W O A W N W C. A W N W O
Year
Figure 6-5: Spokane Airport Annual Heating Degree Days (1947-2021).
If the stable system picture (Figure 6-4)were true, then accuracy would not be a problem
and the more years included in the analysis, the more precise the result. In the true,
"I The information in Figure 6-5 is identical to the information in Figure 6-2,only the formatting is
different.The derived equation for the(red)HDD climate change trend line in Figure 6-5 is:y=24,158—
(8.765 *Year).
6-6

destabilized system (Figure 6-5), the more years included in the analysis, the lower the
standard deviation of the estimated result but, though apparent precision is increased,
accuracy is diminished since as more years are included in the calculation, the projected
estimate becomes more and more like conditions years ago rather than like conditions as
they have become.
The Peril of Real-Time Estimation
For some utilities, the peril in weather adjustment is severe. These utilities apply a
standard 30-day or 20-day approach, using a real-time monthly bill adjustment on a per
customer basis. Utilities using monthly, per customer, adjustment will likely find their
standard method continues to work in summers and winters. However, the "shoulder
months" of May and September can be particularly affected.104 Absurdly high bills are
typically associated with customers on billing cycles that 20 or 30 years ago had many
days with high Heating Degree Days (HDDs),but the corresponding days of the billing
cycle now show zero HHDs and very small numbers of HDDs in a transitional month.los
Avista's calculation method avoids this severe problem since the large decreases in
HDDs in May and September due to climate change average out on a yearly basis. Also,
Avista's decoupling adjustment is not a real-time individual bill adjustment. It is a rate
adjustment(separately for Residential and Non-Residential) for all customers in a
customer group in the following year, rather than individual customer monthly bill
adjustments in real time. For Avista, climate structure change is present in the data, but
its impact in calculation results is not severe.
Change in Structure of the Weather
Aspects of climate change are shown in Table 6-2.106 Considered as a system, the earth is
now unstable due to increasing retention of heat energy, with heat intensifying, year by
year. There are also smaller associated effects in seasonal weather patterns. One of these
is that, for North America, the cyclical El Nino Southern Oscillation(ENSO) is becoming
stronger, creating a cyclical-irregular effect. There are also irregular changes in
components of weather due to shifts in the jet stream and atmospheric rivers, such as
incidents of heavy rain, incidents of arctic vortex, increased numbers and strength of
104 As climate change continues to intensify,the problem with May and September will occur in additional
months.
10s HDDs are used as an example,rather than CDDs since HDD effect sizes are currently much stronger
than CDD effect sizes,though this will vary by location.Heating loads are decreasing,leading to decreased
sales,so standard weather adjustments are increasing heating bills to compensate.Cooling loads are
increasing,so standard weather adjustments are decreasing cooling bill to compensate.Generally natural
gas and electric utilities are more focused on HDDs,while water utilities are more concerned with CDDs.
106 There are various approaches to time series analysis. Table 6-2,following Wesely Clair Mitchell,uses
the classification of four elements,trend(T),seasonal(S),cyclical(C),and irregular(I).Our focus here is
on the trend. See: See Sections 11, 12,and 22 in Frederick E.Croxton,Cowden,Dudley J.,and Klein,
Sidney,Applied General Statistics, Third Edition.Englewood Cliff,New Jersey:Prentice-Hall, 1967.
6-7

hurricanes and tornados, and intense slow-moving heat domes. Here we focus on the
climate trend of HDDs, determined by increasing temperatures.
Table 6-2: Climate Effects driving Utility Bills and Rate Adjustments.
Structural Change in Weather driving Utility Bills and Rate Adjustments
Trend Seasonal Cyclical Irregular
Climate trend: Seasonal changes in Heavy rain,Arctic
Increased heat,year by weather have shifted El Nino-Southern vortex,More and
year(fewer HHDs, and continue to shift Oscillation(ENSO): El stronger hurricanes,
more and more CDDs expected weather by Nino and La Nina Shift in pattern and
each year). about 1 to 1.5 months increasing in strength strength of tornados,
so far. Flooding,Heat domes.
For the ENSO,see the National Weather Service: What is ENSO?(weather.gov)or the Wikipedia entry
at:https:Hen.wikipedia.org/wiki/El_Ni%C3%Blo%E2%80%93Southem Oscillation.
Four Alternative Time Windows for Calculating Normal HDD and
CDD
Beginning with reporting for 2020, Avista included estimates of usage and deferred
decoupling revenue using alternatives to a 30-year period for calculating normal degree
days. Specifically, Avista reports calculations and results using 30-, 20-, 15- and 10-year
historical periods for calculating normal weather. Shorter periods improve accuracy but
lower precision. Avista alternative time windows for electric calculation are shown in the
second column of Table 6-3.
Table 6-3: Weather Related Deferred Revenue with Alternative Normal DD-Electric.
2022—Electric
Normal Usage Adjustment(kWh) Deferred Decoupled Revenue-
Years Weather Component
HDD CDD Residential Non-Residential Residential Non-
Residential
Coll Col.2 Col.3 Col.4 Col.5 Col.6 Col.7
Row 1 30 6,509 533 (102,767,540) (31,406,543) $(9,188,469) $(2,022,240)
Row 2 20 6,401 598 (91,713,224) (24,843,367) $(8,214,575) $(1,610,457)
Row 3 15 6,396 617 (83,904,681) (21,877,433) $(7,518,542) $(1,420,340)
Row 4 10 6,213 682 (82,437,359) (16,546,392) $(7,405,508) $(1,093,695)
6-8

In this table, it is clear that moving to shorter historical periods for determining normal
degree days lowers the number of HDDs (customers require less heating energy due to
warmer heating seasons) and increases the number of CDDs (due to warmer summers
and shoulder seasons, customers require more energy to run air conditioning). For electric
service, the increased number of CDDs has offsetting impacts, lowering usage for heating
but increasing usage for cooling. Table 6-3 shows the net effect for electric customers in
2022. Using the residential customer class as an example, had the test year used a 15-year
period for normal, the estimated deferral of decoupled revenue would have been a
negative $7.5 million, lower in absolute terms than the negative $9.2 million weather
related deferral obtained using the 30-year based normals. A similar result is observed for
the non-residential class.
For natural gas, there is no offsetting effect that would stimulate more gas use due to
more CDDs, since gas is not used to cool buildings. This means that as heat increases
year after year, the requirement for natural gas decreases. Avista alternative normal DD
calculations are shown for natural gas in Table 6-4. The normal heating and cooling
degree days shown in the natural gas table are the same as the electric table because both
systems use the same single weather station for reporting weather.
Using the residential customer class as an example, had the test year used a 15-year
period to define normal weather, the estimated deferral of decoupled revenue would have
been a negative $2.6 million, higher in absolute terms than the negative $1.5 million
weather related deferral obtained using the 30-year based normals. A similar result is
observed for the non-residential class.
Table 6-4. Weather Related Deferred Revenue with Alternative Normal DD—Natural
Gas.
2022-Natural Gas
Normal Usage Adjustment(therms) Deferred Decoupled Revenue-
Row Years Weather Component
HDD CDD Residential Non-Residential Residential Non-
Residential
Col.1 Col.2 Col.3 Col.4 Col.5 Col.6 Col.7
Row 1 30 6,509 533 (2,666,349) (841,837) $(1,507,517) $(250,167)
Row 2 20 6,401 598 (4,718,131) (1,574,635) $(2,572,725) $(452,386)
Row 15 6,396 617 (4,789,779) (1,608,894) $(2,602,771) $(460,800)
Row 10 6,213 1 682 1 (8,175,340) (2,792,897) $(4,373,457) 1 $(789,442)
Note that 2022 had colder than normal weather, even using a rolling 30-year average.
Using shorter periods to calculate normal weather pushes the weather impacts in 2022
higher than estimated with 30-year normals. Considering the period 2020 through 2022
together provides an arguably more representative look, averaging the two warmer than
normal heating seasons of 2020 and 2021 with the colder than normal heating season of
2022. The cooling seasons are also averaged in the 2020 through 2022 period, all of
6-9

which were warmer than the 30-year normal. The average weather-related deferrals are
shown for electric customers in Figure 6-6.
Weather Related Deferred Electric Revenue
(Average 2020-2022)by
Number of Years Used for Normal DD
—30— —20— —Is— _10—
u U
2 U
0.0
o -1.0 u
-,.'. -0.9 -0.7
o -2.0 1 -
0
-3.0 —
2.9 -3.0
-4.0 -4 4
-5.0 -4.4
■Residential ■Non-Residential
Figure 6-6: Weather Related Deferred Electric Revenue, 2020-2022.
Results shown in Figure 6-7 show that, as expected, the absolute level of deferred electric
decoupled revenue declines as the period for calculating normal weather is reduced from
30 years. Similar results are obtained from both the 15- and 10-year estimates of normal
weather.
Figure 6-7 shows average weather-related revenue deferrals for natural gas.
Weather Related Deferred National Gas
Revenue (Average 2020-2022)by
Number of Years Used for Normal DD
—30— —20— —is— —10—
E 2.5
2.1
`m
6 2.0
O
0 1.5
0 1.0
0.0 n E r__]
— o—o
-0.5 _0.2
■Residential ■Non-Residential
Figure 6-7. Weather Related Deferred Natural Gas Revenue, 2020-2022
6-10

Results (Figure 6-7) show that, as expected, the level of deferred natural gas decoupled
revenue declines as the period for calculating normal weather is reduced from 30 years.
The large difference between the 15- and 10-year results highlights the greater volatility
of normal weather based on short periods of data. The 15-year period seems to be the
shortest period that still produces stable results over the observed data and the
calculations.
The time trend for moving averages of different durations provides visual confirmation of
the problem with 5-year and 10-year analysis. The 5-year moving average, as shown by
the orange line in Figure 6-8 is highly influenced by the ENSO, and the 10-year moving
average (shown by the blue line) also appears to be increasingly influenced by the ENSO,
over time.
Time Trend of Moving Averages of Different Periods,1972023
7,300
7,100
G
= 6,900
0hoc
m 6,700 -30
m
-25
G 6,500 -20
m
c
S -15
0
6,300 -10
-5
6,100
5,900
r` r` W 00 0p 00 00 C1 m m m m O O C N N
N . . . . . N N N N . e�i N N N N N N N N N N N N
Year
Figure 6-8: Spokane-Moving Average HDD of Different Durations (1977-2023).
Considerations for Weather Calculations
• Rule out stable system calculation: Since the system is no longer stable with
respect to heat, we need to rule out calculations based on the stable picture
(Figure 6-4), even though this was the model in use for doing decoupling weather
adjustment and it worked well prior to the emergence of the strong climate change
trend. Instead, we must take climate change into account(Figure 6-5).
• Rule out 10-years: It might seem that the 10-year moving average would be
preferable, since the result would be derived from the ten years just before the
year estimated and would best reflect the structure change. However, as noted
above, in addition to the trend, an irregular periodic variation occurs -the El Nino
6-11

Southern Oscillation(ENSO).107 Since the ENSO is a cyclical-irregular with a
duration of approximately 3 -7 years, it can override the trend in short-period
analysis. For this reason, estimation using a 10-year calculation(or less) should be
ruled out.
• Rule out 30-years: If the weather were stable (if there were no climate change),
it would be useful to select the maximum number of years for inclusion in
analysis (30 years). This would minimize variation, giving increased precision.108
The standard deviation is one measure of variation. As shown in Figure
6-9, the standard deviation of the HDD moving average becomes meaningfully
smaller as the number of years included in the moving average calculation are
increased.
Relationship Between Moving Average Period and Moving Average Standard
Deviation
300
250
,o y=1E-04x°-0.0188x'+0.9923x'-22.984x+344,57
R'=0.9993
0 200
E
E
m 150
Q
100
50
0 1 :J
0 5 10 15 20 25 30 35
Moving Average Period
Figure 6-9: Relation of Standard Deviation and Years (Spokane).
However, this approach, while giving the appearance of precision, only provides
better precision under the assumption of unchanged structure (Figure 6-4), which
is not true. This would be a false precision, meaning that it would create a
prediction most closely fitting to a planet without climate change, rather than our
actual situation in which the physics of the planet have changed, and continue to
change as more and more heat is retained. Precision of the false estimate would be
high,but since the estimate would be false, accuracy would diminish with
107 The oscillation has two periods,El Nino,and La Nina,with a neutral period in between. The full
oscillation is irregular and occurs over three to seven years. See:National Weather Service description at:
What is ENSO?(weather.gov);Wikipedia:
https:Hen.wikipedia.or,g/wiki/El Ni%C3%Blo%E2%80%93Southern Oscillation.
"I precision is a measure of the extent to which repeated measurements agree with one another.Accuracy
reflects the proximity of measurements to the true value.
6-12

increasing numbers of years included in the calculation. For this reason we rule
out the 30-year calculation.
• Consider the NOAA and climate science precedents. Although Avista does not
use TMY data,NOAA's addition of 15-year time series TMY data to the standard
30-year TMY time series data is an argument for the relative reliability of a 15-
year calculation for the analysis. However, as a practical matter, use of both a 30-
year calculation and a 15-year calculation is likely to produce a discussion similar
to that for a 20-year analysis. Also, we note that climate scientists, in trying to
arrive at a best method of calculation to determine the effects of climate change,
tend to use a 20-year analysis.109 With these considerations, the 15-year period
seems to be the shortest period that still produces stable results over the observed
data and calculations, while the 20-year period is the longest period that does not
over-weight the calculation towards weather than can no longer be expected.
Finding: The 15-year period seems to be the shortest period that
still produces stable results over the observed data and
calculations. The 20-year period is the longest period that does
not over-weight the calculation towards weather than can no
longer be reasonably be expected.
Figure 6-10: Best Number of Years for Calculation.
What is "Normal Weather"?
What is "normal weather"? Though values are different, each calculation reviewed(30-
year, 20-year, 15-year, 10-year) is identical in mathematical operations. Each calculation
produces an operational estimate of"normal weather," and each of these estimates drives
a different revenue adjustment. We should not use a calculation of ten years of less due to
the ENSO cyclical-irregular110 For the remaining three operational definitions,precision
improves with more years included, but accuracy decreases. These two considerations
rule out the 30-year calculation and the 10-year calculation.
However, if it were decided that by"normal weather"we mean developing an estimate
based on what weather would have been like if there were no climate change, we would
use the 30-year calculation. This would fully compensate the utility for climate-related
loss of revenue for the fixed costs included in decoupling. If we want a more moderate
adjustment, we could operationalize "normal weather" as 20-years. We should not go
below 15 years.
...This is a different problem,in that the"pre"reference temperature to which results are compared is
taken from the pre-industrial era.However,with that difference,the emerging standard is to use 20-years of
time series data in the analysis.
"o Unless a method can be constructed specifically taking the ENSO into account.
6-13

Table 6-5 & Table 6-6 show the ranges of these calculated revenue adjustments for 2022
for electric service and for natural gas.111
Table 6-5. Range of Revenue Adjustments - 2022 Electric.
2022 Electric
Deferred Decoupled Revenue-
Row Years Weather Component
Residential Non-Residential
Row 1 30 $(9,188,469) $(2,022,240)
Row 2 20 $(8,214,575) $(1,610,457)
Row 3 15 $(7,518,542) $(1,420,340)
Row 10 $(7,405,508) $(1,093,695)
Table 6-6. Range of Revenue Adjustments - 2022 Natural Gas.
2022 Natural Gas
Deferred Decoupled Revenue-
Row Years Weather Component
Residential Non-Residential
Row 1 30 $ (1,507,517) $(250,167)
Row 2 20 $(2,572,725) $(452,386)
Row 3 15 $(2,602,771) $(460,800)
Row 4 10 $ (4,373,457) $(789,442)
Decoupling is a Climate Change Adjustment
Weather adjustment associated with decoupling now primarily reflects the strength of
climate change, rather than other factors, such as energy conservation and energy
efficiency improvements. This is a change. Decoupling would not have been a climate
change adjustment prior to about 1988 when the climate effect(here analyzed in the form
of Heating Degree Days -HDDs)was weaker. The weather adjustment model for HDDs
was designed without recognition of climate change. Decoupling was introduced to
remove a potential barrier to energy conservation and energy efficiency, and to improve
revenue stability for utilities by providing for a more regular revenue recovery
(equivalent to revenue recovery which would occur in the absence of decoupling). With
climate change there is a change in the structure of the weather. The climate change
Table 6-5 is a subset of Table 6-3; Table 6-6 is a subset of Table 6-4.
6-14

effect is much stronger than the conservation/efficiency effect. While the weather
adjustment mechanism associated with decoupling continues to cover energy
conservation/energy efficiency and continues to improve revenue stability(for those
fixed costs included in decoupling), the major driver now is climate change
operationalized as the declining trend of HDDs). Decoupling is, going forward,best
understood as a climate change practice, incorporating more timely revenue recovery.112
For Avista, however, since the decoupling adjustment is set using a test year, the
calculations by Avista and the calculations here do not change bills but provide
alternative determinations for the calculation of relative percent of deferred decoupled
revenue due to change in the structure of the weather.
Summary—Normal Weather
As directed by the WUTC, Avista has developed four alternative calculations of normal
weather, using rolling moving averages of 30-years, 20-years, 15-years, and 10-years.
The calculations have no effect on decoupling rates and bills since deferral amounts are
set in reference to a test year. However, the calculations permit better understanding of
the partition of deferral results between the part driven by weather and the part of deferral
driven by all other factors. For this study, the third-party evaluator was directed by the
WUTC and by Avista to review Avista data and calculations to help support discussion
and better understanding of how weather variability affects Avista's decoupling
mechanisms.
Comparison of computed"normal weather"Heating Degree Days (HDDs) and Cooling
Degree Days (CDDs)using the standard 30-year rolling average and compared with
actuals (Table 6-1) shows two substantive changes:
112 If decoupling has become more important as a climate change practice rather than as an energy
conservation/energy efficiency practice,why were we not aware of this,even in the recent past,as
decoupling studies were designed,approved,an analyzed?The answer is in the increasing physical strength
of climate effects,which were previously weak,and are strong and becoming stronger,compelling us to
change the way we think about decoupling.To understand the kind of change in perception we are
experiencing,we can consider studies developed by Ron Westrum,organizational analyst and sociologist
who has studied several shifts in social perception of phenomena"hidden in plain sight."For example,
Westrum found that medical professionals did not recognize parental or caretaker physical abuse of
children until the late 1940s,but now are professionally required to look for and report suspected physical
abuse as a medical standard any time injured children are brought for medical attention. Similarly,
Westrum has researched the recognition of meteorites,which,although farmers and rural people knew they
were real,were not recognized in science until England's Royal Society authorized a formal study.Even
though something might be"hidden in plain sight,"whether we notice it or not can depend on a variety of
factors.We appear to be experiencing a transition from calculation from an energy conservation and
efficiency paradigm to primary calculation form a climate physics paradigm.This is discussed further in
the appendix.
6-15

• HDDs are decreasing. As the planet retains more and more heat, instead of
reflecting it back into space, the planet, considered as a system, has become
unstable in this regard. The associated HDD graph, with a downward-sloping
regression line, shows the decreasing HDDs (Figure 6-2).
• CDDs are increasing. This means, from our human perspective, that more and
more cooling is needed to counter the increasing heat. The associated graph, with
an upward-sloping regression line, shows the increasing CDDs (Figure 6-3).
These climate change trends are causing severe billing problems for utilities using a real-
time monthly bill adjustment for individual customers based on billing cycles. However
Avista's method of calculation avoids severe problems since it averages variation across
all customers over a year and applies the adjustment as a rate adjustment in the following
year, rather than as individual monthly bill adjustment in real-time. However, the
problem of ever-increasing heat is now a physical feature of the planet, and the
assumption of a stable weather environment does not work.
Avista's results for each of the four calculations of"normal weather" are shown in Table
6-3 for Natural Gas and in Table 6-4 for Electric. These tables show HDDs, CDDs,
energy usage adjustment for residential and non-residential, and adjustment in the form
deferred decoupled revenue for Residential and Non-Residential customer groups. In
examination of these calculations, we find cause to rule out using the alternative of 10-
years or less. We also find cause to rule out 30-years. This leaves the 20-year calculation
and the 15-year calculation as the preferred alternative.
The 15-year data window is the shortest period that still produces stable results of
reasonable accuracy over the observed data and calculations. This choice also coincides
with NOAA's choice to add a 15-year TMY as an alternative to its standard 30-year
TMY. However,using both the traditional 30-year TMY data and the new 15-Year TMY
data is likely to result in discussion that is functionally equivalent to an analysis similar to
a 20-year TMY analysis if 20-year TMY data were available. Also, we note that climate
scientists, in working on a balanced approach to averaging for defining when a certain
increase from the base case occurs (for the separate problem of detecting the year in
which the 1.5-degree Celsius target is reached) tend to use 20-year averaging.
Examination of the four alternative operational definitions of normal weather inherently
raises the question, "What is normal weather"? Prior to approximately 1988, the problem
of change in structure of the weather(operationalized as trend change in Heating Degree
Days -HDDs) could reasonably be considered to be below need for consideration. It was
not considered in analysis and the topic simply did not rise to the level of serious
discussion. At that time, the "deferred decoupled revenue—weather component"was not
thought to be an indicator of climate change, and the decoupling mechanism was
developed, in part to cover drops in energy usage due to energy conservation/energy
6-16

efficiency and all other factors by providing more stable revenue recovery."' Since at
least 1988, the effect size for climate change has become stronger. Until about 1988
"normal weather" could reasonably be considered a projection of a moving average of
past weather with inclusion of more years in the analysis leading to increased precision.
However, the HDD trend line indicates we need to think though a new definition for
"normal weather"that systematically incorporates the trend of ever-increasing planetary
heat energy.
The climate trend(operationalized as the HDD trend line) means that projected weather
is not a kind of average result, subject to more or less random weather variation, set
against a stable background. The 15-year and the 20-year calculations are currently
superior to the alternatives.
Deferred decoupled revenue adjustment continues to remove a barrier to more aggressive
energy conservation/energy efficiency and continues (for those fixed costs included in
decoupling) to improve revenue stability without changing total collections. Now, and
going forward the structure of weather has changed, driven by climate change. For
weather adjustment, the main driver now is climate change with conservation/energy
efficiency secondary. The decoupling weather adjustment should be recognized as
primarily a climate change practice to support provision of regular utility revenue in the
era of climate change.
13 Decoupling would recover the same revenue that would have been recovered through rate cases,but
recovery would be more stable.
6-17

Section 1 Analysis
Avista uses a rolling 30-year average to define "normal weather". Establishing
meteorological normals Currently Avista's decoupling tariff has a feature that limits the
percent increase in rates due to the annual decoupling adjustment to no more than a 3
percent increase. This feature is described as the decoupling rate cap. The objective in
this section is to present analysis of two alternatives to the 3 percent cap, a 5 percent cap
and no cap.
The cap feature only applies to the portion of the decoupling adjustment that is greater
than zero. In other words, the rate cap does not apply to customer rebates. For example, if
the current decoupling rate is negative (a rebate to customers) and the proposed
decoupling rate is positive (a customer surcharge) then the 3 percent cap only applies to
the increase in rates from zero to the new proposed rate and not to the increase between
the current negative rate to the new proposed positive rate. Use of a rate cap to limit the
decoupling charge to customers has the impact of extending the time to recover deferred
decoupled revenue beyond the time deferred revenue would have been collected without
the cap.114
If the current decoupling rate is negative (a rebate to
customers) and the proposed decoupling rate is positive (a
customer surcharge)then the 3 percent cap only applies to
the increase in rates from zero to the new proposed rate and
not to the increase between the current negative rate to the
new proposed positive rate.
Figure 7-1. How the Cap Works.
Alternative Caps —Electric
Both alternatives to the current 3 percent cap (5 percent cap and no cap) are less
restrictive than the current cap. This means that for years when the 3 percent cap did not
have a limiting effect on the decoupling rate, the alternatives of 5 percent and no cap
would have resulted in the same decoupling rate as the 3 percent cap. Table 7-1 shows
what happens when the current decoupling rate adjustment is negative (a rebate to
customers), and the proposed decoupling rate adjustment is positive (a customer
surcharge). Then the 3 percent cap only applies to the increase in rates from zero to the
newly proposed rate and not to the increase between the current negative rate and the new
proposed positive rate.
14 The pace that Avista recovers deferred decoupled revenue from a customer rate class is dependent on
the decoupled rate(Rate Schedule 75 for electric and Rate Schedule 175 for natural gas)and the actual
units of energy(kWh or therms)delivered to existing customers in that rate class.
7-1

Table 7-1 shows a summary of decoupling deferral results and decoupling tracker rates for
both decoupled electric rate groups over the three decoupling years of this evaluation.
Table 7-1. Deferrals and Decoupling Recovery Rates, 3 Percent Cap -Electric.
Electric
Residential Group Non-Residential Group
Notes 1 2020 1 2021 1 2022 2020 1 2021 F 2022
Summary of Deferred Revenue(1,000 S)
Deferred revenue (811) (5,124) (16,126) 11,263 2,389 385
Requested recovery A (1,112) (5,801) (18,646) 14,761 2,748 (1,889)
Customer surcharge(rebate)revenue (1,112) (5,801) (18,646) 14,489 2,748 (1,889)
Carryover deferred revenue 0 0 0 271 0 0
Summary of Decoupling Rate Adjustment
Decoupling rate(schedule 75)(cents/kWh) B (0.045) (0.234) (0.725) 0.679 0.132 (0.088)
Percent incremental surcharge(credit) -3.0% -2.0% -4.7% 3.0% -4.9% -2.0%
Limited by 3%cap? No No No Yes No No
Notes:
A: Requested recovery is equal to deferred revenue after adjusting for shared excess earnings(if applicable),deferral balance
carryover from prior year(if any),interest,and revenue related expenses.
B: Decoupling rates Schedule 75(electric)and Schedule 175(natural gas)take effect on August 1 st of the following year.
As shown in, the level of deferred revenue used to establish the decoupling rate (schedule
75) in the residential rate group was not limited by the 3 percent cap. This means that had
the less restrictive caps of 5 percent and no-cap been in effect during these decoupling
years they would have produced the same results as a 3 percent cap for the electric
Residential rate group. However, the 3 percent cap was a limiting factor for the electric
Non-Residential rate group in 2020. Analysis of the impact of alternative caps is shown
for the electric non-residential rate group in Table 7-2.
7-2

Table 7-2. Analysis of Alternative Rate Caps—Electric Non-Residential.
Electric Non-Residential Rate Group
Current 3%Cap 5%Cap Analysis
2020 2021 1 2022 2020 2021 2022
Summary of Deferred Revenue(1,000$)
Row Deferred revenue 11,263 2,389 385 11,263 2,389 385
Row Requested recovery 14,761 2,748 (1,889) 14,788 2,644 (1,889)
Row Customer surcharge(rebate)revenue 14,489 2,748 (1,889) 14,788 2,644 (1,889)
Row 4 Carryover deferred revenue 271 0 0 0 0 0
Summary of Decoupling Rate Adjustment
Row s Decoupling rate(schedule 75) 0.679 0.132 (0.088) 0.693 0.127 (0.088)
cents/kWh
Row 6 Percent incremental surcharge(credit) 3.0% 4 6% -2.0% 3.1% -4.8% -2.0%
Row 7 Limited by cap? Yes No No No No No
* The no cap scenario is not shown since it produces the same results as a 5%cap in 2020,2021 and
2022.
Table 7-2 shows the results of using the 3 percent cap side-by-side with results using a 5
percent cap. Because the 5 percent cap was not reached in 2020-2022 (see Row 6)results
of using no-cap are identical to the 5 percent cap results.
Using a 3 percent cap had the result of excluding a relatively small amount($0.3 million)
of the requested recovery of$14.8 million of deferred decoupling revenue from
determination of the decoupling rate effective August 1, 2021. The excluded amount
resulted in a slightly lower decoupling rate from the 2020 results (effective August 1,
2021) and a slightly higher rate from the 2021 results (effective August 1, 2022)than
would have resulted using a 5 percent cap or a no-cap mechanism.
Decoupling rates from 2022 results (effective August 1, 2023) would have been the same
using a 3 percent, 5 percent, or no-cap mechanism. As shown in Table 7-2 the percent
change in revenue from the decoupling rate over the 2020, 2021 and 2022 decoupling
years was 3.0%, -4.6% and-2.0%respectively,using the 3 percent cap compared to
3.1%, -4.8%, and -2.0%respectively had a 5 percent or no-cap mechanism been in place.
Alternative Caps —Natural Gas
Table 7-3 shows a summary of decoupling deferral results and decoupling tracker rates
for both decoupled natural gas rate groups over the three decoupling years of this
evaluation.
A significant portion of the requested deferral recovery in both rate groups was limited by
the 3 percent cap in 2021. The 3 percent cap had no effect on the decoupling results from
the 2020 and 2022 decoupling years on either natural gas rate group. Our analysis of the
impact of alternative caps is shown for the natural gas residential rate group in Table 7-4.
7-3

Table 7-3. Deferrals and Decoupling Recovery Rates, 3 Percent Cap—Natural Gas
Natural Gas
Residential Group Non-Residential
Grou
Notes 2020 2021 2022 2020 1 20 FF2022
Summary of Deferred Revenue(1,000$)
Deferred revenue 1,174 6,559 (1,069 445 2,401 1,302
Requested recovery A 1,256 7,021 802 495 2,574 2,439
Customer surcharge(rebate)revenue 1,256 5,379 802 495 1,680 2,439
Carryover deferred revenue 0 1,643 0 0 894 0
Summary of Decoupling Rate Adjustment
Decoupling rate(schedule 175) B 0.925 3.899 0.587 0.813 2.866 3.987
cents/therm
Percent incremental surcharge(credit) 1.8% 3.0% -2.5% 0.7% 3.0% 1.2%
Limited by 3%cap? No Yes No No Yes No
Notes:
A: Requested recovery is equal to deferred revenue after adjusting for shared excess earnings(if applicable),
deferral balance carryover from prior year if any),interest,and revenue related expenses.
B: Decoupling rates Schedule 75(electric)and Schedule 175(natural gas)take effect on August 1 st of the
following year.
Table 7-4. Analysis of Alternative Rate Caps—Natural Gas Residential
Natural Gas Residential Rate Group
FBI Current 3%Cap 5%Cap Analysis
2020 2021 1 2022 2020 2021 2022
Summary of Deferred Revenue(1,000$)
Row I Deferred revenue 1,174 6,559 (1,069) 1,174 6,559 (1,069)
Row 2 Requested recovery 1,256 7,021 802 1,256 7,070 (1,076)
Row Customer surcharge(rebate)revenue 1,256 5,379 802 1,256 7,070 (1,076)
Row 4 Carryover deferred revenue 0 1,643 0 0 0 0
Summary of Decoupling Rate Adjustment
Rows Decoupling rate(schedule 175) 0.925 3.899 0.587 0.925 5.125 (0.788)
cents/therm
Row Percent incremental surcharge credit 1.0% 3.0% -2.5% 1.0% 4.2% -4.4%
Raw 7 Limited by cap? No Yes No No No No
* The no cap scenario is not shown since it produces the same results as a 5%cap in 2020,2021 and 2022.
Table 7-4 shows the results of using the 3 percent cap side-by-side with results using a 5
percent cap. Because the 5 percent cap was not reached in 2020, 2021 or 2022 (see Row
6) results of using no-cap are identical to the 5 percent cap results.
7-4

Using a 3 percent cap had the 2021 result of excluding $1.6 million of the $7.0 million
requested recovery of deferred decoupling revenue from determination of the decoupling
rate effective August 1, 2022. The excluded amount resulted in a lower decoupling rate
from the 2021 results (effective August 1, 2022) and a higher rate from the 2022 results
(effective August 1, 2023) than would have resulted using a 5 percent cap or a non-cap
mechanism.
As shown in Table 7-4 the percentage of incremental revenue from the decoupling rate
over the 2020, 2021 and 2022 decoupling years was 1.0%, 3.0% and-2.5%respectively,
using the 3 percent cap compared to positive 1.0%,positive 4.2%, and a 4.4% decline,
respectively, had a 5 percent or no-cap mechanism been in place.
Our analysis of the impact of alternative caps is shown for the natural gas Non-
Residential rate group in Table 7-5.
Table 7-5. Analysis of Alternative Rate Caps—Natural Gas Non-Residential.
Natural Gas Non-Residential Rate Group
FMW_ Current 3%Cap 5%Cap Analysis No Cap Analysis
2020 2021 2022 2020 1 2021 2022 2020 1 2021 F2022
Summary of Deferred Revenue(1,000$)
Row 1 Deferred revenue 445 2,401 1,302 445 2,401 1,032 445 2,401 1,302
Row 2 Requested recovery 495 2,574 2,439 495 2,596 1,498 495 2,601 1,374
Rows Customer surcharge 495 1,680 2,439 495 2,483 1,498 495 2,601 1,374
rebate revenue
Row a Carryover deferred 0 894 0 0 114 0 0 0 0
revenue
Summary of Decoupling Rate Adjustment
Decoupling rate
Row s (schedule 175) 0.813 2.866 3.987 0.813 4.235 2.449 0.813 4.436 2.246
cents/therm
Row Percent incremental 0.7% 3.0% 1.2% 0.7% 5.0% 0.7% 5.3%
surcharge credit 1.9% 2.3%
Row 7 Limited by cap? No Yes No No Yes No No No No
The results of the Non-Residential natural gas rate group for the 2021 deferral year were
impacted by the 3 percent cap and the 5 percent cap (see Row 6). This rate group is the
only one of the three that would have been limited by a 5 percent cap. Roughly a third of
the requested 2021 recovery was cleared by the 3 percent cap. A 5 percent cap would
have cleared all but about $0.1 million of the requested $2.6 million recovery.
All of the natural gas Non-Residential requested recovery would have been included in
the decoupling rate from the 2021 results (effective August 1, 2022) if there would have
been no-cap in the Avista decoupling mechanism. Looking at both the decoupling rate
(Row 5) and the percent change in revenue from the decoupling rate (Row 6) it is clear
that moving from the most restrictive cap on the decoupling rate adjustment (3 percent)to
the least restrictive (no cap)results in increasingly more volatile rates and increasingly
7-5

faster rates of recovery of decoupled deferred revenue. This can be seen in the no-cap
analysis which produces the highest decoupling rate (Rate Schedule 175) from 2021
results (4.436 cents/therm; Row 6, Column for 2021) and the lowest decoupling rate from
2022 results (2.246 cents/therm; Row 6, Column for 2022).
Summary—Alternative Caps
The use of a decoupling rate cap on customer surcharges has the advantage of smoothing
out rates and the disadvantage of prolonging recovery of decoupled revenue. Raising the
rate cap to 5 percent would have allowed for full amortization of decoupled revenue from
2020, 2021 and 2022 decoupling years in the next rate adjustment for each of the four
rate groups except the natural gas Non-Residential rate group.
Residential electric customers were not restricted by the 3 percent cap in results from
2020, 2021, or 2022; so less restrictive caps would have had no impact on this rate group
over these years. Residential natural gas customers would have had more volatile rates
had a 5 percent cap been in place over the three-year evaluation period. At average
residential customer usage of sixty-seven therms each month, a 5% cap would have
resulted in $0.82 higher monthly residential bills over the August 2022 through July 2023
rate year, which is $9.84 annually, and lower bills over the August 2023 through July
2024 period by equivalent amounts.115
Finding: The use of a decoupling rate cap on customer surcharges has the
advantage of smoothing out rates and the disadvantage of prolonging revenue
recovery. Raising the rate cap to 5%will sometimes increase bills for the next
rate year, while lowering bills for the rate year after that. Going to no-Cap
provides quickest recovery.
Figure 7-2: Rate Caps.
115 Average residential customer usage of sixty-seven therms is an Avista reporting standard and not a
statistical average produced by our analysis.The increase in bills in the August 2022 through July 2023 rate
year followed by lower bills in the next rate year is equivalent but not equal due to interest charges and
revenue related expenses.
7-6

AN
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7-7

Section i Analysis of Possible1Impacts
Establishing meteorological normals Decoupling is a purposive reform designed"...to ensure
that utilities have a reasonable opportunity to earn the same revenues that they would under
conventional regulation, independent of changes in sales volume."16 This objective, stated
in the form of a test, could be considered the"revenue opportunity test."Another goal in
regulatory decoupling, beyond meeting the revenue opportunity test, is to remove the
inherent management and organizational drive to increase energy sales ("the throughput
incentive").
Sometimes, purposive programs have unintended side effects, which may be positive or
negative. Here we focus on possible adverse impacts caused by or associated with decoupling
(Figure 7-1).
Task 7: Analysis of Possible Adverse Impacts
Identification of any conclusive evidence to suggest that the Mechanisms
adversely impacted customer service, distorted price signals for customers
resulting in lower participation in conservation programs, or eroded Avista's
incentive to control costs and improve efficiency and/or Washington required
service quality measures.
Figure 8-1. Identify Adverse Impacts
Are there Adverse Effects?
Both formal learning and lessons of experience teach us that any rationally designed and
purposive program may develop unanticipated side effects.117 No matter how knowledgeable
the staff, no matter how skilled the development, no matter how high the degree of
11'Lazar,Jim,"Examples of Good,Bad,and Ugly Decoupling Mechanisms,"presentation to NARUC
Symposium:Aligning Regulatory Incentives with Demand-Side Resources. San Francisco,California August 2,
2006(https://pubs.naruc.org/pub.cfm?id=4AC7A83F-2354-D714-5130-4C68971713CB).Note that this
emphasis on keeping revenue opportunity the same as under conventional regulation is both fuel-neutral and
neutral with regard to other purposes for engaging regulatory decoupling.
117 Although the recognition of unintended/unanticipated consequences is currently attributed to Merton,Merton
himself notes a deep historic chain of prior writers:"In some one of its numerous forms,the problem of the
unanticipated consequences of purposive action has been treated by virtually every substantial contributor to the
history of social thought."See:Merton,Robert K,"The Unanticipated Consequences of Purposive Social
Action,"American Sociological Review,Vol. 1,No.6,December 1936,pp. 894-904.Beyond this,by
observation,intelligent animals,for example cats,experience unanticipated consequences, so it is quite likely
that,being a phenomenon observed in animals,experiential recognition of unintended consequences is older
than human history. This observation of the historically deep experience of unanticipated consequences fits the
Darwinian model for social evolution and organizational development.Things happen,we experience reality as
different than we imagined,and we evolve and adapt.The social Darwinian model is a central analytic tool of
the evolutionary epistemology(selection theory)approach to organizational analysis.Heyes,Cecilia&David L.
Hull,eds.,Selection Theory and Social Construction, The Evolutionary Naturalistic Epistemology of Donald T.
Campbell.Albany,New York: State University of New York.
8-8

institutional integrity and the degree of social, technical, managerial, and executive insight
from which a program springs, any policy reform may have unanticipated and unintended
consequences.118 Utilities are both high-tech and complex systems. In organizational
analysis, it is understood that unanticipated and unintended consequences happen in high-
tech complex systems.119
The high-level question in this section of the evaluation is to determine if there is any
conclusive evidence to suggest that the Mechanisms adversely impacted Avista's customer
service, created price signals that lowered participation in conservation programs, or eroded
Avista's incentive to control costs and improve efficiency and/or Washington required
service quality measures.120
Following the research questions for this evaluation, we focus on three sub-areas:
• Did decoupling impact Avista's service quality, on the Washington required service
quality measures?
• Were there decoupling price signals that resulted in lower participation in conservation
programs?
• Did decoupling erode Avista's incentive to control costs and improve efficiency?
Service Quality- Customer Service Measures
Avista implements the State of Washington required Service Quality Indices (SQI) and
reliability measures.121 The existence of this series of yearly reports permits examination of
customer service metrics to see if service goals have been met since the beginning of
decoupling in 2015 with the first impact of decoupling on energy bills in November 2016 and
with the first full year of decoupled bills in 2017. For this study, the data runs through 2022.
11'Following Donald Campbell,the terms"program"and"reform"are used interchangeably: a new approach
or program,such as decoupling—a policy reform effected in governance and institutional practice,is both a
program and a reform.Campbell,Donald T.,"The Experimenting Society,"Pp.35-68 in Dunn,William N.,ed.,
The Experimenting Society,Essays in Honor of Donald T. Campbell, Policy Studies Review Annual, Volume IL
New Brunswick,New Jersey&London: Transaction Publishers, 1998;Dunn,William N.,"Reforms as
Arguments,"Pp.294-326 in Knowledge: Creation, Diffusion, Utilization,Volume 3,Number 3,March 1982;
Campbell,Donald T.,"Experiments as Arguments,"Pp. 327-337 in Knowledge: Creation,Diffusion,
Utilization,Volume 3,Number 3,March 1982.
"I The problem of human limits was developed in the 1200's in the systematic philosophic and theological
studies of Thomas Acquinas,which contributed to the development of what eventually became scientific
method.Today,organizational and policy analysts are aware that high tech and complex organizations may
experience unexpected effects,including latent organizational drift and normal accidents.Perrow,Charles,
Normal Accidents.Princeton,New Jersey:Princeton University Press, 1999;Dekker,Sidney,Drift into Failure.
Burlington,Vermont&Farnham, Surrey,England:Ashgate Publishing Limited,2011.
...Sometimes side effects are not seen by anyone; sometimes side effects may be anticipated by some parties
while the preponderance of parties involved in shaping,managing,and implementing a program may not see a
side effect,except retrospectively.In such a case we might say,to use an analytic category developed by
organizational,policy,and social scientist Ron Westrum,that the effect was"hidden in plain sight."
12. The Washington Utilities and Transportation Commission(UTC)required Service Quality Indices are
provided by Avista in response to H. Gil Peach&Associates LLC Data Request No.52 in the prior study,and
Data Request No. 30 in this study.
8-9

First, we examine Avista Service Quality Indices following decoupling to see if service goals
were met, keeping in mind that calendar 2017 is the first year fully within the "after
decoupling"time window from a customer perspective. As shown in the tables for 2015
through 2022 good performance on service goals were achieved each year. There were no
negative effects on these SQI indicators. Across all calendar years in this study, SQI results
exceeded targets and stayed within a narrow band above target levels.
The complex nature of the formation of indicator values in terms of context(for example,
weather and human behavior) suggests that as a general rule of method, key performance
indicators (KPIs) should not be over-interpreted. We expect results on each KPI to dance
around from year to year within a reasonably judgmentally assessed neutral bandwidth,
without the size or direction of differences conveying meaning. A sense for defining a
"neutral band" is developed from practical experience.
Conceptually this "neutral band" is made up of movements in indicators that result from a
very large mix of small influences from a large range of factors including both proximate and
remote influences. In addition, many of the active factors are likely random. So,performance
tables like Table 7-1 through Table 7-8 usually cannot be used to analyze these small
differences (positive or negative). Small differences do not provide substantive meaning,
unless there is also a pattern.
Though not useful for assessing small differences, KPIs provide a powerful tool that
regulators can use to monitor a utility's performance. The primary use of the KPIs is to make
achievement or non-achievement of regulatory goals explicit. This is shown, using check
boxes in the final columns of Table 8-1Table 1-1: 2020 Development of Electric Decoupled
Revenue per Customer. through Table 8-8.
For a regulatory reform, in this case decoupling, a secondary use of KPIs is to determine if
there has been a correlated systematic structure of change in KPI results (either a
directionally consistent string of positive or negative results by year(regardless of size) or a
directionally consistent string of large positive or negative results by year). These results may
be positive or negative.
If either a directionally consistent string of small changes or a directionally consistent string
of large changes is found, then the question shifts from correlation to possible causation. For
example, in Washington it would not be unusual to find that severe weather events or severe
weather patterns are the primary cause for change in KPI results. Also, when customer
contact or services are outsourced, change can be due to performance of a particular service
vendor or replacement by a different service vendor.
Finding: For the Customer Service Measures, we find no directionally
consistent set of either small or large changes in this analysis. There are no
meaningful patterns of negative effects.
Figure 8-2: Finding: Customer Service Measures.
8-10

Table 8-1. 2015 Indicators of Customer Service Quality —Prior Study DR 52.
2015
Customer Service Measures Benchmark Performance Achieved
Percent of customers satisfied with our Contact At least 90% 96.1% ✓
Center services,based on survey results
Percent of customers satisfied with field At least 90% 96.8% ✓
services,based on survey results
Number of complaints to the WUTC per 1,000 /
c Less than 0.40 0.17
customers,per year
Percent of calls answered live within 60 At least 80% 80.7%* ✓
seconds by our Contact Center
Average time from customer call to arrival of No more than 80 /
field technicians in response to electric system minutes 44 Minutes ,/
emergencies,per year
Average time from customer call to arrival of No more than 55 /
field technicians in response to natural gas minutes 51 Minutes
system emergencies,per year
* Results for 2015 on percent of calls answered live within 60 seconds by the Avista Contact Center include all
calls received for the year,including the nearly 56,000 calls answered during the November Windstorm event
from November 17 through November 27,2015.
Table 8-2. 2016 Indicators of Customer Service Quality —Prior Study DR 52.
2016
Customer Service Measures Benchmark Performance Achieved
Percent of customers satisfied with our Contact
Center services,based on survey results At least 90% 92.7%
Percent of customers satisfied with field
services,based on survey results At least 90% 94.7% V/
Number of complaints to the WUTC per 1,000
Less than 0.40 0.25
customers,per year
Percent of calls answered live within 60 seconds
by our Contact Center At least 80% 81.7%
Average time from customer call to arrival of
No more than 80
field technicians in response to electric system minutes 39.3 Minutes
emergencies,per year
Average time from customer call to arrival of
No more than 55
field technicians in response to natural gas minutes 48.4 Minutes
system emergencies,per year
8-11

Table 8-3. 2017 Indicators of Customer Service Quality —Prior Study DR 52.
2017
Customer Service Measures Benchmark Performance Achieved
Percent of customers satisfied with our Contact At least 90% ° ✓
Center services,based on survey results 93.6/o
Percent of customers satisfied with field services, At least 90% ° ✓
based on survey results 95.2/o
Number of complaints to the WUTC per 1,000 /
customers,per year Less than 0.40 0.16 ,/
Percent of calls answered live within 60 seconds /
At least 80% 81.5%
by our Contact Center
Average time from customer call to arrival of field
No more than
technicians in response to electric system 80 minutes 39.9 Minutes
emergencies,per year
Average time from customer call to arrival of field
No more than /
technicians in response to natural gas system 55 minutes 50.29 Minutes �/
emergencies,per year
Table 8-4: 2018 Indicators of Customer Service Quality- Current DR 30.
2018
Customer Service Measures Benchmark Performance Achieved
Percent of customers satisfied with our Contact At least 90% 96% ✓
Center services,based on survey results
Percent of customers satisfied with field services,
based on survey results At least 90% 97%
Number of complaints to the WUTC per 1,000
Less than 0.40 0.11
customers,per year
Percent of calls answered live within 60 seconds At least 80% 81.5% ✓
by our Contact Center
Average time from customer call to arrival of field
No more than
technicians in response to electric system 80 minutes 39.9 Minutes
emergencies,per year
Average time from customer call to arrival of field
No more than /
technicians in response to natural gas system 55 minutes 42 Minutes �/
emergencies,per year
8-12

Table 8-5: 2019 Indicators of Customer Service Quality- Current DR 30.
2019
Customer Service Measures Benchmark Performance Achieved
Percent of customers satisfied with our Contact At least 90% 94.4/o° ✓
Center services,based on survey results
Percent of customers satisfied with field services, At least 90% ° ✓
based on survey results 94.4/o
Number of complaints to the WUTC per 1,000
customers,per year Less than 0.40 0.13
Percent of calls answered live within 60 seconds
by our Contact Center At least 80% 80.7%
Average time from customer call to arrival of field
No more than
technicians in response to electric system 80 minutes 44.3 Minutes V
emergencies,per year
Average time from customer call to arrival of field
No more than
technicians in response to natural gas system 55 minutes 43 Minutes
emergencies,per year
Table 8-6: 2020 Indicators of Customer Service Quality- Current DR 30.
2020
Customer Service Measures Benchmark Performance Achieved
Percent of customers satisfied with our Contact At least 90% 93.6/°° ✓
Center services,based on survey results
Percent of customers satisfied with field services, At least 90% 95.2/°° ✓
based on survey results
Number of complaints to the WUTC per 1,000
Less than 0.40 0.16
customers,per year
Percent of calls answered live within 60 seconds
by our Contact Center At least 80% 81.5%
Average time from customer call to arrival of field
No more than
technicians in response to electric system 80 minutes 39.9 Minutes
emergencies,per year
Average time from customer call to arrival of field
No more than
technicians in response to natural gas system 55 minutes 50.29 Minutes
emergencies,per year
8-13

Table 8-7: 2021 Indicators of Customer Service Quality- Current DR 30.
2021
Customer Service Measures Benchmark Performance Achieved
Percent of customers satisfied with our Contact At least 90% 96% ✓
Center services,based on survey results
Percent of customers satisfied with field services, At least 90% 96% ✓
based on survey results
Number of complaints to the WUTC per 1,000
customers,per year Less than 0.40 0.03
Percent of calls answered live within 60 seconds
by our Contact Center At least 80% 86%
Average time from customer call to arrival of field
No more than /
technicians in response to electric system 80 minutes 53 Minutes �/
emergencies,per year
Average time from customer call to arrival of field
No more than /
technicians in response to natural gas system 55 minutes 49 Minutes
emergencies,per year
Table 8-8: 2022 Indicators of Customer Service Quality- Current DR 30.
2022
Customer Service Measures Benchmark Performance Achieved
Percent of customers satisfied with our Contact At least 90% 97/o° ✓
Center services,based on survey results
Percent of customers satisfied with field services, At least 90% 97/°° ✓
based on survey results
Number of complaints to the WUTC per 1,000
Less than 0.40 0.05
customers,per year
Percent of calls answered live within 60 seconds
by our Contact Center At least 80% 81
Average time from customer call to arrival of field
No more than /
technicians in response to electric system 80 minutes 52 Minutes
emergencies,per year
Average time from customer call to arrival of field
No more than
technicians in response to natural gas system 55 minutes 48 Minutes
emergencies,per year
8-14

Service Quality—Electric System Service Quality Indices
For electrical reliability, there are two SQI measures (Table 8-9). The System Average
Interruption Frequency Index, SAIFI, indicates the frequency of long-term(greater than five
minutes) service interruptions. The System Average Interruption Duration Index, SAIDI
measures the duration of long-term (greater than five minutes) service interruptions. For both
measures, the smaller the size of the indicator result, the better. As shown in the table, values
of both indicators vary from year to year. The highest values for both occur in 2017, the first
full post decoupling year and the lowest values for both occur in 2018. There is no indication
of a meaningful change in either SAIFI or SAIDI. It would be necessary to see a pattern
before drawing a systematic conclusion (negative or positive). The SAIFI graph is shown in
Figure 8-4. The SAIDI graph is shown in Figure 8-5.
Table 8-9: Indicators of Electric Service Reliability—Prior DR 52, Current DR 30.
lElectric System Reliability
Year 2012 2013 2014 2015 2016 2017
SAIFI Frequency of Non-Major-Storm Power 1.14 1.05 1.11 1.05 0.86 1.2
Interruptions/Year/Customer
SAIDI Length of Power 138 138 139 163 133 183
Outage/Year/Customer(minutes)
Year 2018 2019 2020 2021 2022
SAIFI Frequency of Non-Major-Storm Power 0.81 0.94 0.89 1.24 0.92
Inters uptions/Year/Customer
SAIDI Length of Power 126 137 132 164 146
Outage/Year/Customer(minutes)
Note:The System Average Interruption Frequency Index or"SAIFI"is the average number of sustained interruptions(outages)per customer for the
year.
Note:The System Average Interruption Duration Index or"SAIDI"is the average duration of sustained interruptions(outages)per customer for the
year(measured in minutes).
With reference to understanding normal fluctuation of SAIFI and SAIDI, Avista notes that
"approximately two-thirds of the utility's system performance each year is subject to random
forces such as weather patterns and storms, or other random events such as an outage caused
by a car striking a pole, which factors are generally beyond the control of the utility.
Consequently, there is a natural variation in results (both up and down) from year to year,
due largely to the interaction of these random factors. The "direction"of the annual results
and the magnitude of the variation generally reflects the combination of the frequency and
magnitude of weather-related events, the contribution of other randomly occurring factors, as
8-15

well as the effect of standardized adjustments made to the yearly results based on "major
event days" 122
Finding: There is no adverse effect
evident for Electric System Reliability.
Figure 8-3: Finding: Electric Reliability.
Frequency of Non-Major-Storm Interruptions per Year per Customer
1.20
w 100
d
C
R
N 80
C
O
60
E
Z
40
LL_
Q
.20
.00
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Year
Figure 8-4: SAIFI.
Length of Power Outages per Year per Customer(Minutes).
200 00
NV/
C
Q
N
50.00
.00
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Year
Figure 8-5: SAIDI
122 Response to prior study DR 080,citing from pages 53-47 of Avista's Customer Service Quality and Electric
System Reliability report for 2017.
8-16

Service Quality—Performance Guarantees
Beginning January 1, 2016, Avista introduced a new set of performance indicators called
"performance guarantees". These new indicators can also be considered a very visible tool to
motivate Washington staff.123 There are seven specific performance guarantees. Missing the
goal for performance on a guarantee results in a payment of a fifty-dollar($50)bill credit to
affected customers.124
As shown in Table 8-10 through Table 8-16, Avista's performance on these indicators is very
good.125
Table 8-10: 2016 Customer Service Guarantees -Prior DR52.
Customer Service Guarantee Successful Missed $Paid
Keeping Our Electric and Natural Gas Service Appointments 1,477 10 $500
scheduled with our customers
Restore service within 24 hours of a customer reporting an 26,344 1 $50
outage(excluding major storm events
Turn on power within a business day of receiving the request 3,380 3 $150
Provide a cost estimate for new electric or natural gas service 5,024 0 $0
within 10 business days of receiving the request
Investigate and respond to a billing inquiry within 10 business 1,760 0 $0
days if unable to answer a question on first contact
Investigate a reported meter problem or conduct a meter test 309 2 $100
and report the results within 20 business days
Notify customers at least 24 hours in advance of a planned 30,336 349 $17,450
power outage lasting longer than 5 minutes
Totals 68,630 365 $18,250
Success Rate: 99.5%
123 See:Response to prior study Data Request 081 and:https://www.myavista.com/about-us/contact-
us/customer-service-guarantees.
124 Subject to conditions. There is no payment if a customer cancels or misses an appointment or if the
Company reschedules an appointment with at least 24-hours'notice;or,if there is a major weather event that
impacts a large number of customers or lasts for a longer period of time,such as a major snow,ice,or wind
storm;or,if there is an action or default by someone other an Avista employee or outside of Avista's control;
or,if construction is required before service can be energized,evidence that all required government inspections
have been satisfied has not been received by Avista,required payments to Avista have not been received,or
service has been disconnected for non-payment or there has been theft/diversion of electric service;or,when
power is interrupted for less than five minutes,power is interrupted because of work on a meter,or the safety of
the public or of Avista employees or the imminent failure of Avista equipment was a factor causing the
interruption in service.
121 For Table 8-10 through Table 8-16 the Success Rate is computed as [Successful/(Successful+Missed)] and
expressed as a percentage in the last row of each table.
8-17

Table 8-11. 2017 Customer Service Guarantees -Prior DR 52.
Customer Service Guarantee Successful Missed $Paid
Electric and natural gas service appointments 1,584 11 $550
Electric outage restoration within 24 hours of notification from 30,669 23 $1,150
customer,excluding major storm events
Switch on power within a business day of request 9,557 0 $0
Provide cost estimate for new electric or natural gas service 3,929 0 $0
within 10 business days
Investigate and respond to billing inquiries within 10 business 1,623 0 $0
days
Investigate customer-reported problems with a meter,or 1,082 1 $50
conduct a meter test,and report results within 20 business days
Provide notification at least 24 hours in advance of 17,079 115 $5,750
disconnecting service for scheduled electric interruptions
Totals 65,523 1 150 1 $7500
Success Rate: 99.8%
Table 8-12. 2018 Customer Service Guarantees - Current DR 30.
Customer Service Guarantee Successful Missed $Paid
Electric and natural gas service appointments 2,216 5 $250
Electric outage restoration within 24 hours of notification from 4,661 11 $550
customer,excluding major storm events
Switch on power within a business day of request 7,997 1 $50
Provide cost estimate for new electric or natural gas supply 2,356 0 $0
within 10 business days
Investigate and respond to billing inquiries within 10 business 990 1 $50
days
Investigate customer-reported problems with a meter,or 741 3 $150
conduct a meter test,and report results within 20 business days
Provide notification at least 24 hours in advance of 42,014 298 $14,900
disconnecting service for scheduled electric interruptions
Totals 60,975 1 319 1 $15,950
Success Rate: 99.5%
8-18

Table 8-13. 2019 Customer Service Guarantees - Current DR 30.
Customer Service Guarantee Successful Missed $Paid
Electric&Natural Gas service appointments $2,774 31 $1550
Electric outage restoration within 24 hours of notification from 39,687 16 $800
customer,excluding major events
Switch on power within a business day of receiving the request 5,557 2 $100
Provide cost estimate for new electric or natural gas supply 1,824 0 $0
within 10 business days
Investigate and respond to billing inquiries within 10 business 911 0 $0
days
Investigate customer-reported problems with a meter,or 844 4 $200
conduct a meter test,and report results within 20 business days
Provide notification at least 24 hours in advance of 22,092 125 $6,250
disconnecting service for scheduled electric interruptions
Totals 73,689 1 178 1 $8,900
Success Rate: 99.8%
Table 8-14. 2020 Customer Service Guarantees - Current DR 30.
Customer Service Guarantee Successful Missed $Paid
Electric&Natural Gas service appointments 2,776 8 $400
Electric outage restoration within 24 hours of notification from 44,813 0 $0
customer,excluding major events
Switch on power within a business day of receiving the request 1,024 1 S50
Provide cost estimate for new electric or natural gas supply 1,446 0 $0
within 10 business days
Investigate and respond to billing inquiries within 10 business 1,027 0 $0
days
Investigate customer-reported meter problem or conduct a 448 9 $450
meter test and report the results within 20 business days
Provide notification at least 24 hours in advance of 22,101 615 $30,750
disconnecting service for scheduled electric interruptions
Totals 73,635 633 $31,650
Success Rate: 99.1%
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Table 8-15. 2021 Customer Service Guarantees - Current DR 30.
Customer Service Guarantee Successful Missed $Paid
Electric&Natural Gas service appointments 3,171 53 $2,650
Electric outage restoration within 24 hours of notification from 50,031 6 $300
customer,excluding major events
Switch on power within a business day of receiving the request 474 0 $0
Provide cost estimate for new electric or natural gas supply 1,697 0 $0
within 10 business days
Investigate and respond to billing inquiries within 10 business 824 0 $0
days
Investigate customer-reported meter problem or conduct a 355 3 $150
meter test and report the results within 20 business days
Provide notification at least 24 hours in advance of 30,140 143 $7,150
disconnecting service for scheduled electric interruptions
Totals 89,692 205 $10,250
Success Rate: 99.8%
Table 8-16. 2022 Customer Service Guarantees - Current DR 30.
Customer Service Guarantee Successful Missed $Paid
Electric&Natural Gas service appointments 2,896 16 $800
Electric outage restoration within 24 hours of notification from 25,337 136 $6,800
customer,excluding major events
Switch on power within a business day of receiving the request 503 1 $50
Provide cost estimate for new electric or natural gas supply 1,328 0 $0
within 10 business days
Investigate and respond to billing inquiries within 10 business 1,042 0 0
days
Investigate customer-reported meter problem or conduct a 526 4 $200
meter test and report the results within 20 business days
Provide notification at least 24 hours in advance of 27,155 645 $32,250
disconnecting service for scheduled electric interruptions
Totals 58,787 802 $40,100
Success Rate: 98.7%
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Table 8-17: Summary: Customer Service Guarantees.
Customer Service Guarantees
Year Successful Missed Success Rate
2016 68,630 365 99.5%
2017 65,523 150 99.8%
2018 60,975 319 99.5%
2019 73,689 178 99.8%
2020 73,635 633 99.1%
2021 891692 205 99.8%
2022 58,787 802 98.7%
Average 99.5%
Finding: Avista's success rate for Customer Service Guarantees
from 2016-2022 averages 99.5%.
Figure 8-6: Finding: Customers Service Guarantees
Price Signals and Conservation Participation
Determination of the revenue requirement associated with fixed costs is a step in the process of
developing a cost-of-service analysis. Cost-of-service analysis is a separate form of analysis
that occurs independent of the form of recovery. When recovery occurs through decoupling,
the decoupling mechanism recovers selected fixed costs annually, and balances any under-
recovery or over-recovery annually. Decoupling does not change the overall amount of fixed
costs to be recovered. It changes the timing of recovery and reduces volatility by recovering a
set of selected fixed costs not already recovered from volumetric charges. These amounts are
recovered in small yearly increments.126
With or without decoupling, once established as a revenue requirement, the established fixed
cost is allocated to customer groups. Projected recovery involves construction of planning
targets(projections based on experience). In decoupling, selected fixed costs are either
recovered in the volumetric charge (if energy usage matches planned energy usage); or if there
is under-recovery, are programmed to be recovered through an adjustment in volumetric rates
126 The more frequent yearly rate effect with decoupling should sum to the(theoretical)less frequent aggregated
rate recovery impact(without decoupling)over a set of rate cases.
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in the following rate year. The amount of recovery to be collected is subject to certain control
tools, including the three percent(3%) cap on the amount to be recovered in any one year. The
amount larger than the cap is then rolled forward, with interest, to be recovered in a second
forward rate year. The decoupling mechanism is balanced; any over-recovery is refunded
through a reduction in volumetric rates in the following rate year.127 The decoupling allocation
of fixed costs for a customer group is based on the group's actual energy use in relation to the
group's projected energy use.
For utilities in general with or without decoupling) some fixed costs are recovered as fixed
costs through the customer charge, and other fixed costs are recovered in volumetric revenue,
that is, for the cost per unit of energy. In Avista's decoupling, two separate time windows are
used: a measurement time window, during which the data for decoupling adjustment for the
next implementation time window is collected; and the next rate year,the time window for
which the rate adjustment is applied. In Avista's decoupling, the measurement time windows
are calendar years. When, during a measurement window calendar year, a customer group
decreases energy usage so that the average usage for the group falls below the planning
projection for that group for that year,the decoupling adjustment automatically makes up the
lost revenue in the next rate year by requiring an increase in the group's volumetric cost per
unit(cost per kWh or cost per therm). Conversely, if in a measurement time window calendar-
year the average usage for a group exceeds the planning projection,the mechanism will require
a reduction in unit cost for the next 12-month implementation time window(rate year).
Given the decoupling price signals observed, did decoupling price signals influence energy
conservation effort?
For electric customers, the decoupling price signal (as a percentage of average bill) is shown
for Residential in Table 8-18: Residential Electric Decoupling Signal. and for Non-
Residential in Table 8-19: Non-Residential Electric Decoupling Signal. Price signals for
rebates to customers, or neutral are shown in light blue; price signals in the direction of
revenue recovery for the company are shown in yellow.
Table 8-18: Residential Electric Decoupling Signal.
Electric Residential Group
2018 2019 2020 2021 2022
Decoupling Price Signal 4.3% (0.4%) (3.0%) (2.0%) (4.7%)
Limited by 3% cap? Yes No No No No
127 There is no cap on payments to customers.
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Table 8-19: Non-Residential Electric Decoupling Signal.
Electric Non-Residential Group
2018 2019 2020 2021 2022
Decoupling Price Signal 3.0% 0.0% 3.0% (4.9%) (2.0%)
Limited by 3%cap? Yes No Yes No No
For natural gas customers, the decoupling signal as a percentage of average bill is shown in
Table 8-20 for Residential customers and in Table 8-21 for Non-Residential customers.
Table 8-20: Residential Natural Gas Decoupling Signal.
Natural Gas Residential Group
2018 2019 2020 2021 2022
Decoupling Signal 4.2% (1.2%) 1.8% 3.0% (2.5%)
Limited by 3%cap? No No No Yes No
Table 8-21: Non-Residential Natural Gas Decoupling Signal.
Natural Gas Non-Residential Group
2018 2019 2020 2021 2022
Decoupling Signal 2.2% (2.2%) 0.7% (3.0%) (1.2%)
Limited by 3% cap? No No No Yes No
As recorded in these tables, most of the decoupling price signals for both electric and natural
gas were in the direction of customer rebates. These would not be expected to influence
customer energy conservation efforts. The price signals for increasing return to the utility
were interspersed with these signals in the direction of the customer. All of the price signals
were small enough to likely be below any threshold of perception to influence energy
conservation effort either one way or the other. Through 2022, decoupling is operating as
expected(as planned) and is not presenting price signals that would adversely affect
conservation.
GAAP Accounting
We note that sustained or snowballing deferral can have an impact on GAAP accounting,
which requires that revenues be recovered within two years.128 Avista refers to decoupling
deferrals that go unreported in revenue due to GAAP accounting rules as contra-decoupling
deferrals. Contra-decoupling deferrals were recorded for natural gas in both 2015 and 2016.
Patterns like those in Table 8-18 through Table 8-21 do not indicate a tendency for sustained
or snowballing deferral.
121 In the Response to Prior Study Data Request 064,Avista notes that"GAAP reporting rules do not allow for
recognition of revenues from a mechanism like decoupling in excess of the amount expected to be recovered
within 24 months of the end of the deferral period."
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Cost Control and Operational Efficiency
Since decoupling is designed to produce recovery of selected fixed costs equal to recovery that
would occur through rate cases if there were no recovery,we would expect no adverse effect of
decoupling on the utility's incentive to control costs.
Avista's perspective is that"[t]he adoption of decoupling has not resulted in a change of efforts
by the Company to operate efficiently,rather the Company has,prior to decoupling, and with
decoupling, strived to be as efficient as possible while at the same time providing safe and
reliable service for our customers."129Further,the Company points out that"[t]he decoupling
mechanisms provide recovery of fixed costs, on a revenue per customer basis,that were
approved by the Commission in a prior general rate case for recovery. To the extent those fixed
costs increase, or escalate, over time, the mechanisms do not provide for recovery of the
change in costs above the approved level already embedded in the allowed revenue per
customer. The Company continues to bear the risk of changes in costs between general rate
cases, and therefore must(and has)manage the business in a prudent manner."130
By removing the focus on sales, decoupling may permit utility executive management to focus
more effectively on other goals. Because cost recovery proceeds in a decoupled utility
following a target revenue requirement that has already been projected in a commission
proceeding, costs have been anticipated. A focus on cost control can function within this
already established revenue requirement to improve earnings. This does not mean that current
cost-control projects derive directly from decoupling. Avista has continually developed cost-
control projects prior to decoupling. However, with decoupling,Avista cannot increase profits
by increasing sales but can only positively improve profits by improving cost control and
operational efficiency. The nature of this relationship under decoupling has been described by
the Regulatory Assistance Project(Figure 7-2).
Decoupling does not guarantee utilities a level of earnings,only an assurance
of a level of revenue. If the utility reduces costs, it increases earnings,just as it
would under traditional regulation.Also,because the utility cannot increase
profits by increasing sales,improved operational efficiency is the only means
by which it can boost profits.
Source: The Regulatory Assistance Project,Revenue Regulation&Decoupling:A
Guide to Theory and Application.Montpelier,Vermont:Regulatory Assistance
Project,June 2011,P.45.
Figure 8-7. Increasing Earnings in a Decoupled Utility (RAP)
129 Response to Prior DR 063.
'30 Response to Prior DR 063.
8-24

The Company has provided examples of ways that it is lowering operational expenses to
benefit customers:13 1 Each of these changes was introduced in 2020 or prior and was
included in the prior study. There are no additions for 2020 through 2022, however, each
change remains in effect.132
Careful evaluation of each component of overall compensation.
We note that utilities typically re-evaluate each element of overall compensation yearly or
every few years. This cost-control tool is likely the same focus that would be implemented
with or without decoupling. Whether or not deriving specifically or in part from decoupling
in the current context, this is an approach to reducing operational expenses.
A current hiring restriction which requires approval of the hiring manager, as well as
the President of Avista, the CFO,the CEO and the Sr.VP for Human Resources for all
replacement or new hire positions.
This step is not a standard cost-control tool and may or may not be related to the influence of
decoupling. It is unusual for a utility to implement this level of review for all replacement or
new hire positions, although utilities may find it prudent to implement controls from time to
time or(alternatively)to open up for new hiring in certain areas or for certain scarce special
skills from time to time. Whether or not deriving specifically or in part from decoupling in
the current context, this is an approach to control operational expenses.
Effective January 1, 2014,Avista no longer contributes toward medical insurance
premiums for the retiree medical plan.
Beginning January 1, 2020, a new calculation method will shift more expenses to
retirees.
To reduce the number of medical office visits, the Company is providing web and
phone-based 24/7 telemedicine and there is an on-site clinic.
Beginning in 2017,the Company offered a High Deductible Health Plan along with the
current self-insured plan.
Medical costs are an area that requires constant vigilance for cost-control. Medical cost-
control steps (no longer contributing to premiums for the retiree medical plan, shifting more
expenses to retirees, introducing a telemedicine option, and offering a High Deductible
Health Plan option) are all ways to reduce Company medical costs.
Since escalation of medical costs has been a very visible and long-term social problem in the
United States, it is likely that the medical area would have been similarly addressed with or
without decoupling. Whether or not deriving specifically or in part from decoupling, these
steps lower operational expenses.
Effective January 1, 2014, the defined benefit pension plan was closed to all non-union
employees hired or re-hired after January 1, 2014. This transfers risk to employees. The
131 Response to Prior DR 063.
112 Response to Current DR 35.
8-25

Company also now offers a lump sum payout to non-union employees, further reducing
risk to the Company.
Utilities typically subscribe to high quality utility organizational surveys that provide
industry benchmarks for employee salaries and benefits and then adjust salaries and benefits
where possible to approximate these national benchmarks. This is one of the reasons why
utility pay, and benefit packages are generally better than those offered in most sectors of the
national economy or in local communities.
We note the general trend across business sectors towards the replacement of defined benefit
pensions by 401K plans. Although comparatively slow to develop in the utility industry, this
is now also a utility industry trend.
The Company is introducing more automation for IS/IT and is working towards
providing longer contracts to venders in return for discounts.
From experience, the Information Services/Information Technologies areas have long been
somewhat independent of utility organizational cultures. Utilities are very reliant on data and
computer systems, yet these systems tend to be operated somewhat by their own internal
logics which can sometimes present unexpected yet necessary new costs. Working towards
discounts from venders in these areas is a useful approach to cost-control. Whether or not
deriving specifically or in part from decoupling, this step lowers operational expenses.
We see no current adverse impact on cost control and operational efficiency.
Energy Conservation and Energy Efficiency
In discussion with Avista energy conservation management staff, we explored the possibility
of adverse effects on conservation effort.
• The response from staff is that"...our job is to get customers to use less of our
product," and that "decoupling was put into place to offset the loss of revenue" from
helping customers reduce their energy use.
• Staff say there is no negative feedback from the executive level when planned energy
savings are exceeded.
• Staff feel backing from management and the organization. The goal is to "get
maximum savings."
According to staff there was a slowdown during the pandemic, and there was not a quick
bounce back. However, there is a new midstream program that will help meet conservation
goals. At the same time, the programs are experiencing higher costs and supply chain
problems and interest rates are up. There is also a lack of skilled workers for the energy
efficiency agencies. There are continuing building structure and health and safety issues that
noticeably affect residential programs.
8-26

We detected no negativity or"off mission" indications from staff. Staff appear to be working
diligently, with a sense of confidence in the full backing from management and executive
levels for energy conservation and energy efficiency engagement. From the perspective of
staff, decoupling is having no adverse impact on energy conservation and energy efficiency
effort.
These responses coincide with general knowledge of the current utility industry. The
pandemic did cause slowdowns in goal achievement across virtually all utility energy
conservation programs in the US and Canada. That cost per unit of energy conservation
achievement goes up while savings per unit of program investment decreases is an artifact of
approximately fifty years of operation under the "least cost planning" framework and
associated cost controls on programs. For about fifty years, lower-cost projects and programs
have been authorized while higher costs have been avoided, saving the high-cost work for
last. Now, however, we are in the future and wish that more of the higher cost work had been
addressed first, and more of the lower cost work had been deferred for us to include in
projects now.133
At the recent ACEEE Energy Efficiency as a Resource conference in Philadelphia, the low-
income panel had three presentations on the cost of weatherization of homes requiring
structural rehab and health and safety work to permit full weatherization.134 These homes,
133 Climate change is a different world than least cost planning.In climate work,the important guideline is to do
high-cost and more difficult measures first. "The longer we delay meeting total climate investment needs,the
higher the costs will be,both to mitigate global temperature rise and to deal with its impacts."Climate Policy
Initiative,Global Landscape of Climate Finance 2023,
https://www.climatepolicyinitiative'ora/publication/global-landscape-of-climate-finance-2023/. (Search for
"The Costs of Inaction.")The other consideration is that government and institutional ability to fund and
accomplish measures will substantively deteriorate due to climate change as we move forward into the future.
This means that discounting the future is not part of the planning framework.In fact,a realistic approach is to
discount the present in favor of the future so that much of the most difficult work will have been accomplished
(be appropriate sunk cost)by specific dates,such as 2050,2075,2100,or 2150.This is a different planning
framework than we are used to,but appropriate and necessary for the climate era.
134 Each of the three presentations is focused on the problem of weatherizing low-income homes,and,
specifically,the approximately one-third of low-income homes that require substantial rehab prior to installing
the weatherization measures.These are homes that would normally be treated as"walkaways" and not counted
as completed,or homes that are given minimal measures and counted as completions. The framework running
on'least-cost,first" for fifty years automatically accumulates an extensive list of higher cost projects put off to
the future.We are now in the future and wish that these had been addressed over the last fifty years.Costs
include bringing homes to current weatherization standards,but do not include new climate adaption measures.
Minor-Baetens works for Guidehouse.Popkin is weatherization manager for the Philadelphia Gas Works,and
Goodgal is policy manager for an association of weatherization companies in Pennsylvania.Minor-Baetens
does studies,Popkin makes things work on the ground,and Goodgal works on getting the money.Generally,
these initial projects require special funding,and pooling funds from different sources.The federal government
ran a pilot for some of these homes,with full funding,and some states have followed up with state funding.The
thing is,when advocates say"just weatherize low-income homes and electrify"the intent is good,but the tacit
knowledge is missing.We can do it,but the cost is a high multiple per dwelling unit of what passes a DSM era
cost effectiveness test. So,if we want to do it all we have to change from a least-cost,first approach and
actually do it all.Minor-Baetens,Jessica,"Home Repair as a Prerequisite to Energy Efficiency Equity in
8-27

normally"walkaways," are being addressed under the goal of social inclusion and consist of
about 30% of low-income homes in Michigan and Pennsylvania. It takes approximately
$30,000 to $50,000 to successfully treat each of these homes. The estimate to treat Michigan
homes, developed by Guidehouse, is between$3 and $4 billion dollars. This is the cost of
full standard weatherization; it does not include costs of making homes climate hardened.
Washington has a similar"walkaway" and cost problem.
At the same time, shortage of experienced energy conservation/energy efficiency staff is
occurring throughout the US and Canada, and as we go forward, supply chain problems
continue to occur, although not as frequently as during the pandemic.
These are current problems throughout energy conservation/energy efficiency programs in
the US and Canada. There is no indication that the current problems are related to the
presence or absence of decoupling. They are not related to decoupling.
Finding: We see no adverse effect of decoupling on conservation staff and
conservation effort. There are problems of increasing cost, shortages of experienced
workers, and supply chain problems, but these are currently occurring throughout the
US and Canada and are not associated with the presence or absence of decoupling.
Figure 8-8. Finding: Staff and Organizational Support.
Summary—No Adverse Effects
We find no conclusive evidence of any current adverse impact of decoupling on cost control,
operational efficiency,price signals, or service quality.
Michigan;"Popkin,Zachaery,Joshua Smith&Alon Abrahamson,"Health and Safety Solutions for Low-
Income Philadelphians;Goodgal,Rachel,"Whole-Home Repairs—Pathway to Energy Equity in Pennsylvania."
Presentations to the ACEEE Energy Efficiency as a Resource Conference,Philadelphia,Pennsylvania,October
2023.
8-28

AN
Section 1
(1) We find the deferrals and rates for Decoupling to have been calculated by the
Company in accordance with the Commission guidance as operationalized by the
methodological specification in Schedule 75 and Schedule 175. (Page 1-99)
(2) An important characteristic of the Avista decoupling mechanism is the ability of
the mechanism to clear deferral balances even with a rate cap and even in the face
of unusual circumstances, such as persistently warmer than normal winters over
consecutive years. Because the 3%test is applied using current rates, including the
current decoupling rate, the new decoupling rate will adjust higher and be capable
of amortizing higher levels of requested recovery. At some point, even if weather
or other conditions that caused initially higher deferral carryovers persist, the
decoupling rate will eventually adjust to a level that recovers 100 percent of
requested recovery and carryover deferral balance will fall to zero. (Page 2-3)
(3) Avista's decoupling mechanism has had a stabilizing effect on revenue, reducing
variability in half for electric and by one-fifth for natural gas of variability
without decoupling (Page 2-22)
(4) For electric non-decoupled classes, Avista recovers 16% of fixed charges for
Extra Large General Service and 100% of fixed charges for Street and Area
Lighting through the customer charge. For natural gas non-decoupled classes,
Avista recovers no revenue for Interruptible Service and 7% of fixed charges for
Transportation Services through the customer charge. (Page 3-3)
(5) We find no reason to suggest a relationship between decoupling and conservation
results for program savings, expenditures, or customers served. These
relationships are as likely to have occurred in the absence of decoupling as they
occurred with decoupling. (Page 4-13)
(6) We find no relationship to be evident between low-income customers and the rest
of the residential class related to decoupling. There are changes,but we find no
reason to suggest these changes have a relationship to decoupling. The changes
are likely driven by other factors. (Page 4-13)
(7) For electricity, the overall energy savings trend is down, dominated by the
downward trend for Total Residential. The trend line for Total Residential
Electric Savings shows an overall decline from 2014 to 2022. Spending is also
down for Total Residential. Total Residential Electric Savings have declined
substantially over the years examined. (Page 4-14)
9-1

(8) Low-Income Residential Electric Savings have increased both absolutely, and as
a percentage of Total Residential Electric Savings. For Low-Income Electric
Savings (kWh)the trend line slopes upward over the range of years examined.
Also, the Low-Income Electric Savings as a percentage of Total Residential
Electric Savings increased from one percent(I%) to seventeen percent (17%)
from 2014 to 2022. (Page 4-14)
(9) For natural gas, Residential energy savings trends for both Total Residential and
Low Income are sloping slightly upward, while the Ratio of Low-Income to Total
Residential Savings (%) slopes slightly downward. (Page 4-15)
(10) Based on the reports reviewed for this analysis, it is not evident that the
mechanisms have had a positive or negative impact on natural gas conservation
savings. Generally, it is likely that exogenous factors have provided substantial
impact on natural gas conservation savings. However, since the slopes for both
Total Residential and Residential Low-Income Natural Gas savings are positive,
these results are consistent with the mechanisms having a positive effect on
natural gas conservations savings. While the slope of the trend line for Non-
Residential savings for natural gas is downwards, it is only slightly downwards.
(Page 4-15)
(11) Based on the reports reviewed for this analysis, it is not evident that the
decoupling mechanisms have had a positive or negative impact on electric
conservation savings. Total Electrical savings are down, dominated by Total
Residential. Non-Residential savings are up,but only slightly. While Total
Residential is down, Residential Low-Income is up. (Page 4-16)
(12) The Annual Conservation Reports do not break down savings to exclude
the 5% decoupling commitment.135 The additional 5% decoupling savings data is
addressed in setting targets in the Annual Conservation Plan but is not reported in
the Annual Conservation Reports which provide the source data for the analysis
here. Since the results of the 5% decoupling commitment are not specifically
broken out in the Annual Conservation Reports, the Annual Conservation Plan, or
the Biennial Program Evaluations, the 5%results cannot be addressed here. (Page
4-16)
(13) New customers are meaningfully different from existing customers in both
use per customer and decoupled(distribution)revenue generated per customer.
Although the effect is stronger for electric service, and not as pronounced for
135 In the General Rate Case Settlement Agreement(Docket Nos UE-140188 and UG-140189),the Company agreed,in
consideration for receiving a full electric decoupling mechanism,to increase its electric energy conservation
achievement by 5%over the conservation target approved by the Commission.
9-2

natural gas service, new Residential customers use substantially less energy per
customer and generate less revenue per customer than existing customers.
Because the number of new customers is small relative to existing customers, the
overall impact on deferred revenue is limited, but still meaningful. (Page 5-1)
(14) For electric service, had new customers been included, electric Residential
customers would have received a smaller refund; electric Non-Residential
customers would have received a higher charge through application of the
decoupling tariff(RS 75). (Page 5-5)
(15) For natural gas service, had new customers been included over the 2020-
2022 period, Residential customers would have experienced a higher charge, but
Non-Residential customers would have received a lower charge through the
decoupling tariff(RS 175). (Page 5-5)
(16) Comparison of computed"normal weather"Heating Degree Days (HDDs)
and Cooling Degree Days (CDDs)using the standard 30-year rolling average and
compared with actuals shows two substantive changes: HDDs are decreasing. As
the planet retains more and more heat, instead of reflecting it back into space, the
planet, considered as a system, has become unstable in this regard. The associated
HDD graph, with a downward-sloping regression line, shows the decreasing
HDDs. CDDs are increasing. This means more and more cooling is needed to
counter the increasing heat. The associated graph, with an upward-sloping
regression line, shows the increasing CDDs). (Page 6-15)
(17) In a review of 30-year, 20-year, 15-year, and 10-year calculations
resulting in alternative operational definitions of"normal weather", the 15-year
period seems to be the shortest period that still produces relatively accurate results
with acceptable precision the observed data and calculations. The 20-year period
is the longest period(Page 6-12). Outside these limits there is a serious loss of
accuracy or precision.
(18) While the weather adjustment mechanism associated with decoupling
continues to the planned effects for removing barriers to energy
conservation/energy efficiency and improving revenue stability(for those fixed
costs included in decoupling), the major driver of change in energy use is now
climate change operationalized as the declining trend of HDDs. Decoupling is,
going forward,best understood as a climate change practice, incorporating more
timely revenue recovery. (Pages 6-14 to 6-15)
(19) The use of a decoupling rate cap on customer surcharges has the
advantage of smoothing out rates and the disadvantage of prolonging revenue
recovery. Raising the rate cap to 5%will sometimes increase bills for the next rate
9-3

year, while lowering bills for the year after that. Going to no-Cap provides
quickest recovery. (Page 7-6)
(20) For the annual Customer Service Measures, we find no directionally
consistent set of either small or large changes in this analysis. There are no
meaningful patterns of negative effects on any of the Section 7 KPIs from 2015
through 2022. (Section 8)
(21) Avista's success rate for Customer Service Guarantees from 2016-2022
averages 99.5%. (Page 8-14)
(22) We find no conclusive evidence of any current adverse impact of
decoupling on cost control, operational efficiency,price signals, or service quality.
(Page 8-21)
9-4

Section 1 1 1
(1) Continuation. The decoupling mechanisms have worked as expected to stabilize
revenue without impacting utility operations and energy efficiency programs. We
also found no evidence of adverse impacts to any customer groups. Since the
program continues to work as planned in this second evaluation, we recommend
the electric and natural gas mechanisms be continued.
(2) Direct Consultant for Biennial Program Evaluations to address 5% adder. In
developing this decoupling study, we were not able to specifically address the 5%
adder for energy savings since there was not a specific breakout of this in the
Biennial Program Evaluations. We recommend that the evaluator for the Biennial
Program Evaluations be assigned to specifically address the 5% adder for energy
savings in future evaluations, so that this information will be readily available.
(3) Direct Biennial Program Evaluations to break out spend by service. In
developing this decoupling study, we note a need for the Biennial Program
Evaluations to add a table showing planned and resulting energy savings and
conservation spend separately for electric and natural gas conservation annually,
beginning with 2014. Inclusion of a subtask for the evaluator for the Biennial
Program Evaluations to report spend separately for electric and natural gas
conservation annually,beginning with 2014 would add useful trend information
to the evaluations.
(4) Direct specific treatment of 5% adder in Conservation planning and
achievement reports. For Conservation planning and Conservation achievement
reports, it would be useful for future reports to require specifically addressing the
5% adder for energy savings.
(5) Direct reporting of separate spend for Conservation planning and
Conservation achievement reports. It would be useful for future reports to
require the addition of a table showing planned and resulting energy savings and
conservation spend separately for electric and natural gas conservation annually,
beginning with 2014. This would add useful trend information to the evaluations.
(1) Operational definition of normal weather: In a review of Avista's calculations
using a 30-year, 20-year, 15-year, and 10-year rolling average as alternative
operational definitions of normal weather, we recommend the 20-year period as
the longest time window and the 15-year period as the shortest time window for
consideration. We also note that climate scientists are tending to consider a 20-
year calculation for the separate, but similar,problem of estimating the year that
1.5 degrees Celsius change has been reached(rather than 30-years—see
Appendix). In addition, NOAA has selected 15-years as the time window for an
10-1

additional TMY series to accommodate climate change (to run alongside the
traditional 30-year TMY data). The NOAA choice to add a 15-years calculation is
not actually a choice for 15-years but a decision to provide both 30-year data and
15-year data, which together bound a center of 22.5 years (though weighting
could be used to produce other results). The primary advantage of a 20-year
period is that it is less weighted towards weather that is not likely to recur(less
than would be the case for a longer period), while avoiding the greater instability
of shorter time windows. The primary advantage of a 15-year time window is that
it provides more stability in estimation than any period shorter than this. We are
in a time in which the concept of"normal weather"is becoming less and less
meaningful—it was meaningful in a stable framework that did not include a
strong and strengthening climate trend, but that is not reality. Yet the decoupling
framework makes an estimation of normal weather necessary. Moving to 20-years
is a moderate step towards incorporating what is essentially a dynamic situation.
It might be tried for some years as a reasonable step, and then, based on practical
experience, if the question of normal weather continues to have relevance, the
increasing build-up of planetary heat energy may suggest a move to 15-years.
And then, further on, we can anticipate finding ourselves unsure of why we once
thought the question of normal weather was meaningful and we will be asking a
different question within a climate change framework. While frameworks shift for
understanding and describing what are doing, decoupling and associated
calculations continue to provide increased revenue stability.
10-2

Section 1 1 ' 1
This appendix contains three topics. First, a table of rate cases and test years. Second, a
citation to the use of 20-year analysis by the Intergovernmental Panel on Climate Change
(IPCC). Third, a short but deeper further discussion of the problem of"normal weather."
Rate Cases and Test Years
Rate cases and test years are shown in Table 11-1. When two test years are relevant for a
single calculation, Avista derives the results as a weighted average of the two test years,
according to the number of months from each.
Rate cases may include more than one test year. In such cases, the operative test year may
be formed from months in different test years. Avista's computer results are typically
computed using a single test year. The natural gas and electric cases use the same test
years, so while there are eight rate cases there are four test years.
When two test years are relevant for a single calculation, Avista derives the result as a
weighted average of the two test years, according to the number of months from each test
year.
Table 11-1: Electric and Natural Gas Cases and Test Years.
Decoupled Revenue Per Customer History Base Year Base Year Decoupled
Normalized KWh Usage Customers kWh Use Per Customer Revenue Per Customer
Electric Rate
Case Effective Test Year Ending Res Non-Res Res Non-Res Res Non-Res Res Non-Res
UE-170485 5/1/2018 12/31/2016 2,361,885,989 2,166,198,394 209,864 35,622 11,254 60,811 $699.75 $ 4,352.96
UE-190334 4/1/2020 12/31/2018 2,374,703,689 2,131,033,094 215,665 36,586 11,011 58,247 $752.94 $ 4,413.88
UE-200900 10/1/2021 12/31/2019 2,395,485,525 2,131,091,333 218,293 37,020 10,974 57,567 $857.24 $ 4,795.30
UE-220053 12/21/2022 9/30/2021 2,499,403,391 2,098,439,025 223,463 37,969 11,185 55,267 $996.06 $ 4,938.95
Decoupled Revenue Per Customer History Base Year Base Year Decoupled
Natural Gas Normalized Therm Usage Customers Therm Use Per Customer Revenue Per Customer
Rate Case Effective Test Year Ending Res Non-Res Res Non-Res Res Non-Res Res Non-Res
UG-170486 5/1/2018 12/31/2016 119,446,617 52,067,051 153,955 2,771 776 18,798 $314.43 $ 4,621.52
UG-190335 4/1/2020 12/31/2018 128,985,980 55,884,877 161,791 3,073 797 18,186 $363.89 $ 4,870.36
UG-200901 10/1/2021 12/31/2019 132,095,604 60,325,922 165,362 3,105 799 19,432 $410.99 $ 5,182.28
UG-220054 12/21/2022 9/30/2021 137,376,752 58,747,734 170,025 3,181 808 18,470 $447.99 $ 5,166.98
Notes:
Test year definitions from Workbook"B"of each annual filing.See Worksheet titled"Pg?UE-000000 Auth-2"where UE-0000000 refers to docket number of rate case.
IPCC Precedent for 20-Years
A separate, but related, problem from the decoupling weather estimation problem is
determining the year in which the planet passes the 1.5-degree Celsius mark(and other
11-3

AN
global warning levels).136 Since weather has variability(seasonals, cyclicals, cyclical-
irregular, and irregulars) as well as trend, the specific problem is to know the year in
which the 1.5-degree Celsius mark is exceeded, without waiting for a full 20 years for
confirmation. For this problem, the base case has been defined as the average weather
from 1850-1900. The year that we exceed 1.5-degree Celsius global warming level is
defined as the midpoint of the 20-year period at or beyond the 1.5-degree level (Figure
By this definition, 1.5 degrees Celsius of warming would be confirmed once the
observed temperature rise has reached that level,on average,over a 20-year period."
"Any definition must be consistent with how 1.5 degrees Celsius is already defined by
the IPCC;that is,using 20-year averages attached to a midpoint."
"The IPCC already uses long-term averages over recent decades for such baselines;it
does not use the end point of 30-year trends or statistical smoothing."
Betts,et al,Nature,Vol 624,7 December 2023,P. 34.
Figure ]]-]: Exceeding 1.5 Degree Celsius Global Warming Level.
The suggested solution is to use the immediately available last 10 years plus a projection
of ten future years (Figure 11-2).
"We propose...the 20-year average temperature rise centered around the current year.
This is estimated by blending the observations for the past 10 years with the climate
model projections or forecasts for the next 10 years,and taking an average over the
20-year period."
Betts,et al,Nature,Vol 624,7 December 2023,Pp. 34-35.
Figure 11-2: An Average of 20-Years.
The part of this solution that is most relevant to the decoupling weather estimation
problem is the use of a 20-year period both as a standard of the Intergovernmental Panel
on Climate Change (IPCC) and in the specific design of the solution suggested.
"'Betts,Richard A., Stephen E.Belcher,Leon Hermanson,Albert Klein Tank,Jason A.Lowe,Chris D.
Jones,Colin P.Morice,Nick A.Rayner,Adam A. Scaife&Peter A. Stott,"Approaching 1.5 Degrees
Celsius:How will we know we've reached this crucial warming mark?Nature,Vol. 624,7 December
2023,Pp. 33-35.
11-4

The "Normal Weather" and "Weather Normals" Problem
Weather adjustment associated with decoupling now primarily reflects the strength of
climate change, rather than other factors, such as energy conservation and energy
efficiency improvements. Decoupling weather adjustment may now be seen as an
essential climate practice, to keep utilities solvent during climate change, though
calculations will need to be changed away from the concept of"normal weather."As
discussed in Section 6, the concept of"normal weather" (and, with it, the use of
calculated"weather normals") is losing meaning. Since the climate trends towards fewer
heating degree days and more cooling degree days are now strong and becoming
stronger, calculation of weather normals is questionable. Not that the calculations,using
30-years of data cannot be performed as easily as in the past,but the results are abnormal
weather(weather as it would have been if there were no climate change), rather than
normal weather(the hotter weather than is now becoming a normal expectation). The
method put forward by Betts, et al, above for solution of a different problem—
determination of the year at which we fail to protect against a 1.5-degree Celsius global
warming level,137 points towards a different concept for calculation of weather, a concept
which involves taking the trend toward ever increasing planetary heat energy retention
(trend towards increasing HDD and trend towards decreasing CDD) into explicit account
in the estimation process. Drury and Gattie-Garza propose a different but similar
approach to the separate problem of improving estimates of energy savings of
conservation measures by taking climate trends into account—using regression
estimation to project incremental changes (plus and minus)to energy savings (of a
measure or a measure package)by year due to effects of the ever increasing planetary
retention of heat energy on measure performance (Figure 11-3).138
117 The focus of Betts,et al is on the problem of determining the year in which the 1.5 degree Celsius of
global warming since pre-industrial time is reached(or,more generally,when each climate degree target is
reached,for example,2.0 degrees,3.0 degrees,or 4.0 degrees Celsius).They propose using a standard 20-
year calculation approach but using 10-years of actual data with 10-years of projected data.
"'The focus of Drury and Gattie-Garza is on the problem of improving energy savings estimates from
energy conservation measures and measure packages,in order to adjust expected performance for the
increased heat energy in the environment—they show cooling measures show increasing energy savings
over time while heating measures tend to show less decreasing energy savings over time as heat energy in
the environment increases.
11-5

AN
"While future projections or modeling introduce additional uncertainty to energy
savings estimates,they represent a method we can use to try and estimate future
energy savings and are likely more accurate than using weather data based on
previous averages."
"Moving forward,we need to use as close to real-time data as possible to ensure we
are accounting for a changing climate as it continues to unfold before us."
Drury,Matt,PE,Opinion Dynamics&Mallorie Gattie-Garza,Opinion Dynamics,
"Climate Change and its Effect on Weather Data",American Council for an Energy
Efficient Economy,2016 ACEEE Summer Study on Energy Efficiency in
Buildings,Proceedings,Pp.9-1 to 9-11. See P.9-7&9-10
Figure 11-3: Estimates of Future Likely More Accurate.
Dealing with operational definition and computation methods as planetary physical
reality changes requires a shift of analytic frameworks. In this shift, comprehension and
communication become challenging. Kuhn, in The Structure of Scientific Revolutions,
which was written as an analysis of science in general, but is primarily focused on
physics, talks about this kind of shift of conceptual and analytic frameworks as more like
conversion than rational theory choice.139 Conversion can be understood as analogous to
religious conversion. In the transition, communication among cooperating specialists
with different knowledge and experience (and with adherence or mixed-adherence to
different frameworks) can become difficult, but a kind of"trading language" can develop,
permitting progress.140 This seems to be what is happening with the problem of
projecting "normal weather", as the standard calculation now produces "abnormal
weather"—weather as it would have been if the planet had not become unstable by the
ever-increasing retention of heat energy.141 Normal weather is now something else. As
Kuhn points out, shifting to a new framework can mean the loss of existing questions as
well as an emerging focus on new questions and new kinds of results.
"I Hacking,Ian,Introductory Essay in Kuhn,Thomas S.,The Structure of Scientific Revolutions,501
Anniversary Edition(Fourth Edition).Chicago&London: The University of Chicago Press,2012,P.xxxi.
141 Hacking,Ian,op cit.,P.xxxii.
141 Here,Westrum's work on"hidden in plain sight"is relevant.For Kuhn,conversion leads to vision from
the new framework("I was blind,but now I see").But prior to conversion,to quote Westrum,"An event
may be described as hidden;if its occurrence is so implausible that those who observe it hesitate to report it
because they do not expect to be believed.The implausibility may cause the observer to doubt his own
perceptions,leading to the event's denial or misidentification."(P. 382)"It Can't Be,Therefore it Isn't"(P.
383).Between frameworks(during transition)perception and discussion are awkward.That is where we
are now.Clarity,involving both a completion in frameworks and a shift in questions addressed,is coming
as climate effects become stronger.Westrum,Ron,"Social Intelligence about Human Events,"Knowledge:
Creation,Diffusion, Utilization,Vol. 3,March 1982,Pp. 381-400.
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11-7

Section Bibliography
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AVISTA DECOUPLING
EVALUATION
(2020-2022)