20170609Morehouse Exhibit 7 - Natural Gas IRP Appendices.pdf

2016
Natural Gas
Integrated Resource Plan
Appendices
August 31, 2016
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 1 of 648
Safe Harbor Statement

This document contains forward-looking statements. Such statements are subject to a
variety of risks, uncertainties and other factors, most of which are beyond the Company’s
control, and many of which could have a significant impact on the Company’s operations, results of operations and financial condition, and could cause actual results to differ materially from those anticipated.

For a further discussion of these factors and other important factors, please refer to the
Company’s reports filed with the Securities and Exchange Commission. The forward-looking statements contained in this document speak only as of the date hereof. The Company undertakes no obligation to update any forward-looking statement or
statements to reflect events or circumstances that occur after the date on which such
statement is made or to reflect the occurrence of unanticipated events. New risks,
uncertainties and other factors emerge from time to time, and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the Company’s business or the extent to which any such factor, or combination of
factors, may cause actual results to differ materially from those contained in any forward-
looking statement.

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 2 of 648
TABLE OF CONTENTS: APPENDICES
Appendix 0.1 TAC Member List ............................................................................. Page 1
0.2 Comments and Responses to the 2014 IRP ............................................. 2
Appendix 1.1 Avista Corporation 2014 Natural Gas IRP Work Plan ................................ 4
1.2 IRP Guideline Compliance Summaries ..................................................... 7
Appendix 2.1 Economic Outlook and Customer Count Forecast ................................... 22
2.2 Customer Forecasts by Region ............................................................... 39
2.3 Demand Coefficient Calculations ............................................................ 69
2.4 Heating Degree Day Data ....................................................................... 75
2.5 Demand Sensitivities and Demand Scenarios ......................................... 80
2.6 Demand Forecast Sensitivities and Scenarios Descriptions .................... 82
2.7 Annual Demand, Avg Day Demand & Peak Day Demand (Net of DSM) . 85
2.8 Demand Before and After DSM ............................................................... 89
2.9 Detailed Demand Data ............................................................................ 93
Appendix 3.1 Avista Gas CPA Report Final 4/23/2014 ............................................... 103
3.2 Environmental Externalities ................................................................... 164
Appendix 4.1 Current Transportation/Storage Rates and Assumptions ...................... 167
4.2 Alternate Supply Scenarios ................................................................... 168
Appendix 5.1 Monthly Price Data by Basin ................................................................. 169
5.2 Weighted Average Cost of Capital ........................................................ 175
5.3 Supply Side Resource Options ............................................................. 176
5.4 Avoided Costs Detail ............................................................................. 177
Appendix 6.1 High Case Demand and Resources Selected Graphs ........................... 192
6.2 Other Scenario Peak Day Demand Table ............................................. 194
Appendix 7.1 Distribution System Modeling ............................................................... 198
7.2 Oregon Capital Projects ........................................................................ 202 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 3 of 648
Appendix 8.1 TAC Meeting #1 ................................................................................ 214
8.2 TAC Meeting #2 ................................................................................ 299
8.3 TAC Meeting #3 ................................................................................ 396
8.4 TAC Meeting #4 ................................................................................ 533

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 4 of 648
APPENDIX 0.1: TAC MEMBER LIST
ORGANIZATION REPRESENTATIVES

Applied Energy Group Bridget Kester

Avista Terrence Browne
Mike Dillon Leslie Filer
Ryan Finesilver
Grant Forsyth James Gall
Alison Kenyon
John Lyons David Machado
Joe Miller
Jody Morehouse Tom Pardee
Karen Schuh
Kaylene Schultz Eric Scott
Kerry Shroy
Debbie Simock Erik Soreng

Cascade Natural Gas Company Chris Robbins Brian Robertson Mark Sellers-Vaughn

Idaho Public Utility Commission Johanna Bell
Terri Carlock Stacey Donohue
Matt Elam
Kevin Keyt Rick Sterling

Northwest Gas Association Dan Kirschner Connor Reiten

Northwest Industrial Gas Users Ed Finklea Chad Stokes

Northwest Natural Gas Ryan Bracken
Tammy Linver
Steve Storm

Oregon Citizens Utility Board Nadine Hanhan Jaime McGovern

Oregon Public Utility Commission Erik Colville Lisa Gorsuch Max St. Brown

Puget Sound Energy Kacee Chandler

TransCanada Jay Story David White

Washington Utilities and Transportation
Commission
Chris McGuire

Williams Northwest Pipeline Mike Rasmuson Ray Warner

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 5 of 648
APPENDIX 0.2: COMMENTS AND RESPONSES TO 2016 DRAFT INTEGRATED
RESOURCE PLAN
The following table summarizes the significant comments on our DRAFT as submitted by TAC members
and Avista’s responses. These comments are those not directly incorporated into the primary document.
The planning environment in this IRP cycle was especially challenging given some of the most challenging
economic volatility seen in decades coupled with industry changing dynamics in natural gas production.
We continued our robust, flexible demand forecasting methodology that captured a broad range of demand
forecasts fully vetted with our TAC. This IRP produced reduced forecasted demand scenarios and no near
term resource needs even in our most robust demand scenario. We appreciate the time and effort invested
by all our TAC members throughout the IRP process. Many good suggestions have been made and we have
incorporated those that enhance the document.
Document
Reference[1] Comment/Question Avista Response
4 – SUPPLY SIDE
RESOURCES
Page 13, first paragraph – The peak
day is listed in Table 2 Executive Summary as being 362,000 Dth/day.
Suggest adding text describing why Jackson Prairie deliverability of
492,232 Dth/day (398,667 plus the additional 95,565) is considerably
greater than the peak day.
Avista has the ability to withdraw 401,290
from Jackson Prairie. 398,667 is Avista's owned storage capacity withdrawal
amount. 95,565 is Avista's leased capacity from NWP with 2,623 of
withdrawal. This does not represent the take away or transportation capacity from
the facility to Avista's service territories. Please also refer to comment above.
In order for Avista to maintain it's 1/3 ownership of Jackson Prairie the
agreement has the three partners (Northwest Pipeline, Puget Sound Energy
and Avista) and each will bear 1/3 of the operating costs as well as obtain 1/3 of
the storage capacity both future and current.
6 – Alternate
Scenarios, Portfolios and
Stochastic Analysis
A problem from Avista’s 2014 IRP
remains in this draft 2016 IRP. While this problem will remedy itself in the
future when a resource deficiency is found, Staff is concerned the
integrity of past IRP analyses will be impugned when the problem is
remedied. To avoid that result, Staff again suggests the portfolio
evaluation/analysis and selection process description be revised to
eliminate that problem
The Sendout model was loaded with the
list of potential resources found in Chapter 6 Scenarios, Portfolios,
Stochastic Analysis. The model would choose a different resource if given the
opportunity to provide demand at lowest cost. If a new resource had been chosen
a separate portfolio would have been created to compare the ability to serve
demand via less cost and comparing against a total PVRR. Alternate
scenarios have been added to Chapter 6 to address this concern with
accompanying text to explain the logic
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 6 of 648
6 – Alternate
Scenarios, Portfolios and
Stochastic Analysis
The upsized compressor and increased operating pressure
selected by the model are not mentioned in Chapter 7 Distribution
Planning.
This is a compressor on the GTN pipeline not internal distribution as a fix to push
more gas down the Medford Lateral from the GTN mainline.
7 – ALTERNATE
SCENARIOS
1. Expand the text to comply with Order No. 16-109 in Docket UG 288,
in which the Commission provided its expectations related to
justification of distribution system projects, as follows:
“Finally, as part of the IRP-vetting process and subsequent rate
proceedings, we expect that Avista conduct and present comprehensive
analyses of its system upgrades. Such analyses should provide: (1) a
comprehensive cost-benefit analysis of whether and when the investment
should be built; (2) evaluation of a range of alternative build dates and
the impact on reliability and customer rates; (3) credible
evidence on the likelihood of disruptions based on historical
experience; (4) evidence on the range of possible reliability incidents;
(5) evidence about projected loads and customers in the area; and (6)
adequate consideration of alternatives, including the use of
interruptibility or increased demand-side measures to improve reliability
and system resiliency.”
The distribution planning section of the IRP contains only a subset of all capital
investment in Avista’s gas distribution systems. This is a planning document
and the distribution projects included are projects that are planned over a relatively
longer time horizon. Other capital investments may be driven by regulation,
system maintenance, leak repair, franchise/right-of-way agreements, etc.
These investments are not addressed in this section.
7 –
DISTRIBUTION PLANNING
Page 8 Table 7.2 – suggest adding text to communicate that “Cost” is a
planning level value that will likely change as the projects approach the
time of implementation. Also suggest that estimating contingencies be
included in derivation of the “Cost” to minimize instances where the values
need to be revised. In addition to estimating contingencies, suggest
adding text to discuss the sensitivity of distribution system project
evaluation to changes in “Cost.”
“These projects are preliminary estimates of timing and costs of City Gate Station
Upgrades…” Because all of the Gate Station projects are scheduled for 2019+
and have no cost assigned, contingencies to cost cannot be included.
8 – ACTION PLAN
2. Page 1, 2015-2016 Action Plan Review – the two Action Items listed
were not Action Items but rather were ongoing activities. Please
correct the text.
Action items addressed in 2015-2016 Action Plan Review are taken directly
from the final Natural Gas IRP document filed in each commission on August 29,
2016. These actions are called out so Avista prefers to address them as
actions.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 7 of 648
APPENDIX 1.1: AVISTA CORPORATION 2016 NATURAL GAS INTEGRATED
RESOURCE PLAN WORK PLAN
IRP WORK PLAN REQUIREMENTS
Section 480-90-238 (4), of the natural gas Integrated Resource Plan (“IRP”) rules, specify requirements for
the IRP Work Plan:
Not later than twelve months prior to the due date of a plan, the utility must provide a work
plan for informal commission review. The work plan must outline the content of the
integrated resource plan to be developed by the utility and the method for assessing
potential resources.
Additionally, Section 480-90-238 (5) of the WAC states:
The work plan must outline the timing and extent of public participation.
OVERVIEW
This Work Plan outlines the process Avista will follow to complete its 2016 Natural Gas IRP by August
31, 2016. Avista uses a public process to obtain technical expertise and guidance throughout the planning
period via Technical Advisory Committee (TAC) meetings. The TAC will be providing input into
assumptions, scenarios, and modeling techniques.
PROCESS
The 2016 IRP process will be similar to that used to produce the previously published plan. Avista will use
SENDOUT® (a PC based linear programming model widely used to solve natural gas supply and
transportation optimization questions) to develop the risk adjusted least-cost resource mix for the 20 year
planning period.
This plan will continue to include demand analysis, demand side management and avoided cost
determination, existing and potential supply-side resource analysis, resource integration and alternative
sensitivities and scenario analysis.
Additionally, Avista intends to incorporate action plan items identified in the 2018 Natural Gas IRP
including more detailed demand analysis regarding use per customer, demand side management results and
possible price elastic responses to evolving economic conditions, an updated assessment of conservation
potential in our service territories, consideration of alternate forecasting methodologies, and the changing
landscape of natural gas supply (i.e. shale gas, Canadian exports, and US LNG exports) and its implications
to the planning process. Further details about Avista’s process for determining the risk adjusted least-cost
resource mix is shown in Exhibit 1.

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 8 of 648
TIMELINE
The following is Avista’s TENTATIVE 2018 Natural Gas IRP timeline:
subject to change

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 9 of 648
EXHIBIT 1: AVISTA’S 2018 NATURAL GAS IRP MODELING PROCESS

Demand Forecast by Area and Class
Customer counts
Use per customer
Elasticity
Basis differential
Volatility
Seasonal Spreads
Costs
Operational Characteristics

Assess DSM resource options
Integrate DSM in resource portfolio
20-year NOAA average by area plus

SENDOUT®
Optimization
Run

Identify when and where
deficiencies occur in the 20-
Enter all Future Resource Options:
Demand-Side
Supply-Side
Optimization
Run

Solve for deficiencies and
incorporate those into the
least costs resource mix for
Determine Base
Case Scenario
Avoided Cost
Determination
Compile Data and Write
the IRP Document.
Key Considerations
Resource Cost
Peak vs. Base Load
Lead Time Requirements
Resource Usefulness
“Lumpiness” of Resource Options
Analysis
Customer Counts
Use per customer
DSM
Monte Carlo
Etc.
Price Curve
Analysis
Gate Station
Analysis
Planning
Standard Review
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 10 of 648
APPENDIX 1.2: WASHINGTON PUBLIC UTILITY COMMISSION IRP POLICIES AND
GUIDELINES – WAC 480-90-238
Rule Requirement Plan
Citation
WAC 480-90-238(4) Work plan filed no later than 12 months before next IRP due date. Work plan submitted to the WUTC on August 31, 2015, See
attachment to this Appendix 1.1.
WAC 480-90-238(4) Work plan outlines content of IRP. See work plan attached to this Appendix 0.1.
WAC 480-90-238(4) Work plan outlines method for
assessing potential resources. (See LRC analysis below)
See Appendix 1.1.
WAC 480-90-238(5) Work plan outlines timing and extent of
public participation.
See Appendix 1.1.
WAC 480-90-238(4) Integrated resource plan submitted within two years of previous plan. Last Integrated Resource Plan was submitted on August 31, 2014
WAC 480-90-238(5) Commission issues notice of public hearing after company files plan for
review.
TBD
WAC 480-90-238(5) Commission holds public hearing. TBD
WAC 480-90-238(2)(a) Plan describes mix of natural gas
supply resources.
See Chapter 4 on Supply Side
Resources
WAC 480-90-238(2)(a) Plan describes conservation supply. See Chapter 3 on Demand Side Resources
WAC 480-90-238(2)(a) Plan addresses supply in terms of
current and future needs of utility and ratepayers.
See Chapter 4 on Supply Side
Resources and Chapter 5 Integrated Resource Portfolio
WAC 480-90-
238(2)(a)&(b)
Plan uses lowest reasonable cost
(LRC) analysis to select mix of resources.
See Chapters 3 and 4 for Demand
and Supply Side Resources. Chapters 5 and 6 details how
Demand and Supply come together to select the least
cost/best risk portfolio for ratepayers.
WAC 480-90-238(2)(b) LRC analysis considers resource
costs.
See Chapters 3 and 4 for Demand
and Supply Side Resources. Chapters 5 and 6 details how
Demand and Supply come together to select the least
cost/best risk portfolio for ratepayers.
WAC 480-90-238(2)(b) LRC analysis considers market-
volatility risks.
See Chapter 4 on Supply Side
Resources
WAC 480-90-238(2)(b) LRC analysis considers demand side uncertainties. See Chapter 2 Demand Forecasting
WAC 480-90-238(2)(b) LRC analysis considers resource
effect on system operation.
See Chapter 4 and Chapter 5
WAC 480-90-238(2)(b) LRC analysis considers risks
imposed on ratepayers.
See Chapter 4 procurement plan
section. We seek to minimize but cannot eliminate price risk for our
customers.
WAC 480-90-238(2)(b) LRC analysis considers public policies regarding resource preference See Chapter 2 demand scenarios
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 11 of 648
adopted by Washington state or
federal government.
WAC 480-90-238(2)(b) LRC analysis considers cost of risks
associated with environmental effects including emissions of carbon dioxide.
See Chapters 2 and 5 on demand
scenarios and Integrated Resource Portfolio
WAC 480-90-238(2)(b) LRC analysis considers need for
security of supply.
See Chapter 4 on Supply Side
Resources
Rule Requirement Plan Citation
WAC 480-90-238(2)(c) Plan defines conservation as any
reduction in natural gas consumption that results from increases in the
efficiency of energy use or distribution.
See Chapter 3 on Demand Side
Resources
WAC 480-90-238(3)(a) Plan includes a range of forecasts of future demand. See Chapter 2 on Demand Forecast
WAC 480-90-238(3)(a) Plan develops forecasts using
methods that examine the effect of economic forces on the consumption
of natural gas.
See Chapter 2 on Demand
Forecast
WAC 480-90-238(3)(a) Plan develops forecasts using methods that address changes in the
number, type and efficiency of natural gas end-uses.
See Chapter 2 on Demand Forecast
WAC 480-90-238(3)(b) Plan includes an assessment of
commercially available conservation, including load management.
See Chapter 3 on Demand Side
Management including demand response section.
WAC 480-90-238(3)(b) Plan includes an assessment of
currently employed and new policies and programs needed to obtain the
conservation improvements.
See Chapter 3 and Appendix 3.1.
WAC 480-90-238(3)(c) Plan includes an assessment of conventional and commercially
available nonconventional gas supplies.
See Chapter 4 on Supply Side Resources
WAC 480-90-238(3)(d) Plan includes an assessment of
opportunities for using company-owned or contracted storage.
See Chapter 4 on Supply Side
Resources
WAC 480-90-238(3)(e) Plan includes an assessment of
pipeline transmission capability and reliability and opportunities for
additional pipeline transmission resources.
See Chapter 4 on Supply Side
Resources
WAC 480-90-238(3)(f) Plan includes a comparative evaluation
of the cost of natural gas purchasing strategies, storage options, delivery
resources, and improvements in conservation using a consistent
method to calculate cost-effectiveness.
See Chapter 3 on Demand Side
Resources and Chapter 4 on Supply Side Resources
WAC 480-90-238(3)(g) Plan includes at least a 10 year long-range planning horizon. Our plan is a comprehensive 20 year plan.
WAC 480-90-238(3)(g) Demand forecasts and resource evaluations are integrated into the long range plan for resource acquisition.
Chapter 5 Integrated Resource Portfolio details how demand and supply come together to form the
least cost/best risk portfolio.
WAC 480-90-238(3)(h) Plan includes a two-year action plan
that implements the long range plan.
See Section 8 Action Plan
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 12 of 648
WAC 480-90-238(3)(i) Plan includes a progress report on the implementation of the previously filed
plan.
See Section 8 Action Plan
WAC 480-90-238(5) Plan includes description of consultation with commission staff.
(Description not required)
See Section 0 Introduction
WAC 480-90-238(5) Plan includes description of completion of work plan. (Description not required) See Appendix 1.1.

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 13 of 648
APPENDIX 1.2: IDAHO PUBLIC UTILITY COMMISSION IRP POLICIES AND
GUIDELINES – ORDER NO. 2534
DESCRIPTION OF REQUIREMENT FULLFILLMENT OF REQUIREMENT
1 Purpose and Process. Each gas utility regulated by the Idaho Public Utilities Commission with retail
sales of more than 10,000,000,000 cubic feet in a calendar year (except gas utilities doing business
in Idaho that are regulated by contract with a regulatory commission of another State) has the
responsibility to meet system demand at least cost to the utility and its ratepayers. Therefore, an
‘‘integrated resource plan’’ shall be developed by each gas utility subject to this rule.
Avista prepares a comprehensive 20 year Integrated Resource Plan every two years.
Avista will be filing its 2016 IRP on or before August 31, 2016.
2 Definition. Integrated resource planning.
‘‘Integrated resource planning’’ means planning by the use of any standard, regulation, practice, or
policy to undertake a systematic comparison between demand-side management measures and
the supply of gas by a gas utility to minimize life-cycle costs of adequate and reliable utility services
to gas customers. Integrated resource planning shall take into account necessary features for
system operation such as diversity, reliability, dispatchability, and other factors of risk and shall
treat demand and supply to gas consumers on a consistent and integrated basis.
Avista's IRP brings together dynamic
demand forecasts and matches them against demand-side and supply-side resources in
order to evaluate the least cost/best risk portfolio for its core customers. While the
primary focus has been to ensure customer's needs are met under peak or design weather
conditions, this process also evaluates the resource portfolio under normal/average
operating conditions. The IRP provides the framework and methodology for evaluating
Avista's natural gas demand and resources.
3 Elements of Plan. Each gas utility shall submit to the Commission on a biennial basis an integrated
resource plan that shall include:
2016 IRP to be filed on or before August 31, 2016. The last IRP was filed on August 31,
2014.
A range of forecasts of future gas demand in firm and interruptible markets for each customer class
for one, five, and twenty years using methods that examine the effect of economic forces on the
consumption of gas and that address changes in the number, type and efficiency of gas end-uses.
See Chapter 2 - Demand Forecasts and
Appendix 2 et.al. for a detailed discussion of
how demand was forecasted for this IRP.
An assessment for each customer class of the technically feasible improvements in the efficient
use of gas, including load management, as well as the policies and programs needed to obtain the
efficiency improvements.
See Chapter 3 - Demand Side
Management and DSM Appendices 3 et.al.
for detailed information on the DSM potential evaluated and selected for this IRP and the
operational implementation process.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 14 of 648
An analysis for each customer class of gas supply
options, including: (1) a projection of spot market versus long-term purchases for both firm and
interruptible markets; (2) an evaluation of the opportunities for using company-owned or
contracted storage or production; (3) an analysis of prospects for company participation in a gas
futures market; and (4) an assessment of opportunities for access to multiple pipeline
suppliers or direct purchases from producers.
See Chapter 4 - Supply-Side Resources for
details about the market, storage, and pipeline transportation as well as other
resource options considered in this IRP. See also the procurement plan section in this
same chapter for supply procurement strategies.
A comparative evaluation of gas purchasing options and improvements in the efficient use of
gas based on a consistent method for calculating cost-effectiveness.
See Methodology section of Chapter 3 -
Demand-Side Resources where we
describe our process on how demand-side and supply-side resources are compared on
par with each other in the SENDOUT® model. Chapter 3 also includes how results
from the IRP are then utilized to create operational business plans. Operational
implementation may differ from IRP results due to modeling assumptions.
The integration of the demand forecast and
resource evaluations into a long-range (e.g., twenty-year) integrated resource plan describing
the strategies designed to meet current and future needs at the lowest cost to the utility and its
ratepayers.
See Chapter 5 - Integrated Resource
Portfolio for details on how we model demand and supply coming together to
provide the least cost/best risk portfolio of resources.
A short-term (e.g., two-year) plan outlining the specific actions to be taken by the utility in
implementing the integrated resource plan.
See Chapter 8 - Action Plan for actions to be taken in implementing the IRP.
4 Relationship Between Plans. All plans following the
initial integrated resource plan shall include a progress report that relates the new plan to the previously filed plan.
Avista strives to meet at least bi-annually with
Staff and/or Commissioners to discuss the state of the market, procurement planning practices, and any other issues that may
impact resource needs or other analysis
within the IRP.
5 Plans to Be Considered in Rate Cases. The integrated resource plan will be considered with
other available information to evaluate the performance of the utility in rate proceedings before the Commission.
We prepare and file our plan in part to establish a public record of our plan.
6 Public Participation. In formulating its plan, the gas
utility must provide an opportunity for public participation and comment and must provide
methods that will be available to the public of validating predicted performance.
Avista held four Technical Advisory
Committee meetings beginning in January and ending in April. See Chapter 0 -
Introduction for more detail about public
participation in the IRP process.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 15 of 648
7 Legal Effect of Plan. The plan constitutes the base line against which the utility's performance will
ordinarily be measured. The requirement for implementation of a plan does not mean that the
plan must be followed without deviation. The requirement of implementation of a plan means that
a gas utility, having made an integrated resource plan to provide adequate and reliable service to its
gas customers at the lowest system cost, may and should deviate from that plan when presented with
responsible, reliable opportunities to further lower its planned system cost not anticipated or identified
in existing or earlier plans and not undermining the utility's reliability.
See section titled "Avista's Procurement Plan" in Chapter 4 - Supply-Side
Resources. Among other details we discuss plan revisions in response to changing
market conditions.
In order to encourage prudent planning and prudent
deviation from past planning when presented with opportunities for improving upon a plan, a gas
utility's plan must be on file with the Commission and available for public inspection. But the filing of
a plan does not constitute approval or disapproval of the plan having the force and effect of law, and
deviation from the plan would not constitute violation of the Commission's Orders or rules. The
prudence of a utility's plan and the utility's prudence in following or not following a plan are matters that
may be considered in a general rate proceeding or other proceedings in which those issues have been
noticed.
See also section titled "Alternate Supply-Side
Scenarios" in Chapter 5 - Integrated
Resource Portfolio where we discuss
different supply portfolios that are responsive to changing assumptions about resource
alternatives.

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 16 of 648
APPENDIX 1.2: OREGON PUBLIC UTILITY COMMISSION IRP STANDARD AND
GUIDELINES – ORDER 07- 002
Guideline 1: Substantive Requirements
1.a.1 All resources must be evaluated on
a consistent and comparable basis.
All resource options considered, including demand-
side and supply-side are modeled in SENDOUT®
utilizing the same common general assumptions,
approach and methodology.
1.a.2 All known resources for meeting the
utility’s load should be considered,
including supply-side options which
focus on the generation, purchase
and transmission of power – or gas
purchases, transportation, and
storage – and demand-side options
which focus on conservation and
demand response.
Avista considered a range of resources including
demand-side management, distribution system
enhancements, capacity release recalls, interstate
pipeline transportation, interruptible customer supply,
and storage options including liquefied natural gas.
Chapter 3 and Appendix 3.1 documents Avista’s
demand-side management resources considered.
Chapter 4 and Appendix 5.3 documents supply-side
resources. Chapter 5 and 6 documents how Avista
developed and assessed each of these resources.

1.a.3 Utilities should compare different
resource fuel types, technologies,
lead times, in-service dates,
durations and locations in portfolio
risk modeling.
Avista considered various combinations of
technologies, lead times, in-service dates, durations,
and locations. Chapter 5 provides details about the
modeling methodology and results. Chapter 4
describes resource attributes and Appendix 5.3
summarizes the resources’ lead times, in-service
dates and locations.
1.a.4 Consistent assumptions and
methods should be used for
evaluation of all resources.
Appendix 5.2 documents general assumptions used in
Avista’s SENDOUT® modeling software. All portfolio
resources both demand and supply-side were
evaluated within SENDOUT® using the same sets of
inputs.
1.a.5 The after-tax marginal weighted-
average cost of capital (WACC)
should be used to discount all future
resource costs.
Avista applied its after-tax WACC of 4.34% to discount
all future resource costs. (See general assumptions at
Appendix 5.2)
1.b.1 Risk and uncertainty must be
considered. Electric utilities only
Not Applicable
1.b.2 Risk and uncertainty must be
considered. Natural gas utilities
should consider demand (peak,
swing and base-load), commodity
supply and price, transportation
availability and price, and costs to
comply with any regulation of
greenhouse gas (GHG) emissions.
Risk and uncertainty are key considerations in long
term planning. In order to address risk and
uncertainties a wide range of sensitivity, scenario and
portfolio analysis is completed. A description of risk
associated with each scenario is included in Appendix
2.6.

One of the key risks is the “flat demand” risk as
described in Chapter 1. Avista performed 15
sensitivities on demand. From there five demand
scenarios were developed (Table 1.1) for SENDOUT®
modeling purposes. Monthly demand coefficients were
developed for base, heating demand while peak
demand was contemplated through modeling a
weather planning standard of the coldest day on
record (see heating degree day data in Appendix 2.4).
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 17 of 648
Avista evaluated several price forecasts and selected
high, medium and low price scenarios for modeling
purposes. The annual average prices are then
weighted by month using fundamental forecast data.
Additionally, the Henry Hub price forecasts are basis
adjusted using the same fundamental forecast data.

Four supply scenarios were also evaluated, see Table
4.3. These supply scenarios were combined with
demand scenarios in order to establish portfolios for
evaluation. Ultimately 9 portfolios were evaluated
(See Table 6.3 for the PVRR results).

Avista stochastic modeling techniques for price and
weather variables to analyze weather sensitivity and
to quantify the risk to customers under varying price
environments. While there continues to be some
uncertainty around GHG emission, Avista considered
GHG emissions regulatory compliance costs in
Appendix 3.2. As currently modeled, we include a
carbon adder to our price curve to capture the costs of
emission regulation.
Utilities should identify in their plans
any additional sources of risk and
uncertainty.
Avista evaluated additional risks and uncertainties.
Risks associated with the planning environment are
detailed in Chapter 0 Introduction. Avista also
analyzed demand risk which is detailed in Chapter 2.
Chapter 3 discusses the uncertainty around how much
DSM is achievable. Supply-side resource risks are
discussed in Chapter 4. Chapter 5 and 6 discusses
the variables modeled for scenario and stochastic risk
analysis.
1c The primary goal must be the
selection of a portfolio of resources
with the best combination of
expected costs and associated risks
and uncertainties for the utility and
its customers.
Avista evaluated cost/risk tradeoffs for each of the risk
analysis portfolios considered. See Chapter 5 and 6
plus supporting information in Appendix 2.6 for
Avista’s portfolio risk analysis and determination of the
preferred portfolio.
The planning horizon for analyzing
resource choices should be at least
20 years and account for end
effects. Utilities should consider all
costs with a reasonable likelihood of
being included in rates over the long
term, which extends beyond the
planning horizon and the life of the
resource.
Avista used a 20-year study period for portfolio
modeling. Avista contemplated possible costs beyond
the planning period that could affect rates including
end effects such as infrastructure decommission costs
and concluded there were no significant costs
reasonably likely to impact rates under different
resource selection scenarios.
Utilities should use present value of
revenue requirement (PVRR) as the
key cost metric. The plan should
include analysis of current and
estimated future costs of all long-
lived resources such as power
plants, gas storage facilities and
pipelines, as well as all short-lived
Avista’s SENDOUT® modeling software utilizes a
PVRR cost metric methodology applied to both long
and short-lived resources.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 18 of 648
resources such as gas supply and
short-term power purchases.
To address risk, the plan should
include at a minimum: 1) Two
measures of PVRR risk: one that
measures the variability of costs and
one that measures the severity of
bad outcomes. 2) Discussion of the
proposed use and impact on costs
and risks of physical and financial
hedging.
Avista, through its stochastic analysis, modeled 200
scenarios around varying gas price inputs via Monte
Carlo iterations developing a distribution of Total 20
year cost estimates utilizing SENDOUT®’s PVRR
methodology. Chapter 6 further describes this
analysis. The variability of costs is plotted against the
Expected Case while the scenarios beyond the 95th
percentile capture the severity of outcomes. Chapter 4
discusses Avista’s physical and financial hedging
methodology.
The utility should explain in its plan
how its resource choices
appropriately balance cost and risk.
Chapter 4, 5, and 6 describe various specific resource
considerations and related risks, and describes what
criteria we used to determine what resource
combinations provide an appropriate balance between
cost and risk.
1d The plan must be consistent with
the long-run public interest as
expressed in Oregon and federal
energy policies.
Avista considered current and expected state and
federal energy policies in portfolio modeling. Chapter
5 describes the decision process used to derive
portfolios, which includes consideration of state
resource policy directions.
Guideline 2: Procedural Requirements
2a The public, including other utilities,
should be allowed significant
involvement in the preparation of the
IRP. Involvement includes
opportunities to contribute
information and ideas, as well as to
receive information. Parties must
have an opportunity to make
relevant inquiries of the utility
formulating the plan.
Chapter 0 provides an overview of the public process
and documents the details on public meetings held for
the 2016 IRP. Avista encourages participation in the
development of the plan, as each party brings a
unique perspective and the ability to exchange
information and ideas makes for a more robust plan.
While confidential information must
be protected, the utility should make
public, in its plan, any non-
confidential information that is
relevant to its resource evaluation
and action plan.
The entire IRP, as well as the TAC process, includes
all of the non-confidential information the company
used for portfolio evaluation and selection. Avista also
provided stakeholders with non-confidential
information to support public meeting discussions via
email. The document and appendices will be available
on the company website for viewing.
The utility must provide a draft IRP
for public review and comment prior
to filing a final plan with the
Commission.
Avista distributed a draft IRP document for external
review to all TAC members on May 27, 2016 and
requested comments by June 30, 2016.
Guideline 3: Plan Filing, Review and Updates
3a Utility must file an IRP within two
years of its previous IRP
acknowledgement order.
This Plan complies with this requirement as the 2014
Natural Gas IRP was acknowledged on March 2,
2015.
3b Utility must present the results of its
filed plan to the Commission at a
public meeting prior to the deadline
for written public comment.
Avista will work with Staff to fulfill this guideline
following filing of the IRP.
3c Commission staff and parties should
complete their comments and
Pending
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 19 of 648
recommendations within six months
of IRP filing
3d The Commission will consider
comments and recommendations on
a utility’s plan at a public meeting
before issuing an order on
acknowledgment. The Commission
may provide the utility an
opportunity to revise the plan before
issuing an acknowledgment order
Pending
3e The Commission may provide
direction to a utility regarding any
additional analyses or actions that
the utility should undertake in its
next IRP.
Pending
3f Each utility must submit an annual
update on its most recently
acknowledged plan. The update is
due on or before the
acknowledgment order anniversary
date. Once a utility anticipates a
significant deviation from its
acknowledged IRP, it must file an
update with the Commission, unless
the utility is within six months of
filing its next IRP. The utility must
summarize the update at a
Commission public meeting. The
utility may request acknowledgment
of changes in proposed actions
identified in an update
The annual update was submitted on March 1, 2016.
The filing was primarily an informational filing only as
Avista intends to file an updated IRP by August 31,
2016. In addition to the filing, Avista has provided
updates and comparisons to its 2014 IRP during its
2016
IRP TAC meetings held on January 21, 2016,
February 18, 2016, March 30, 2016, and April 21,
2016, in which Commission Staff and other TAC
members were present. In addition the Company
provided an update during its Natural Gas Quarterly
update meeting held on March 3, 2016. No request
for acknowledgement was required as no significant
deviation from the 2014 IRP was anticipated.
3g Unless the utility requests
acknowledgement of changes in
proposed actions, the annual update
is an informational filing that:
 Describes what actions the utility has taken to implement the plan;
 Provides an assessment of what has changed since the
acknowledgment order that affects the action plan, including
changes in such factors as load, expiration of resource contracts,
supply-side and demand-side resource acquisitions, resource
costs, and transmission availability; and
 Justifies any deviations from the acknowledged action plan.
The updates described in 3f above explained changes
since acknowledgment of the 2014 IRP and an update
of emerging planning issues. The updates did not
request acknowledgement of any changes.

Guideline 4: Plan Components
At a minimum, the plan must include
the following
elements:

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 20 of 648
4a An explanation of how the utility met
each of the substantive and
procedural requirements.
This table summarizes guideline compliance by
providing an overview of how Avista met each of the
substantive and procedural requirements for a natural
gas IRP.
4b Analysis of high and low load growth
scenarios in addition to stochastic
load risk analysis with an
explanation of major assumptions.
Avista developed six demand growth forecasts for
scenario analysis. Stochastic variability of demand
was also captured in the risk analysis. Chapter 1
describes the demand forecast data and Chapter 5
provides the scenario and risk analysis results.
Appendix 5 details major assumptions.
4c For electric utilities only Not Applicable
4d A determination of the peaking,
swing and base-load gas supply and
associated transportation and
storage expected for each year of
the plan, given existing resources;
and identification of gas supplies
(peak, swing and base-load),
transportation and storage needed
to bridge the gap between expected
loads and resources.
Figures 6, 7, and 8 summarize graphically projected
annual peak day demand and the existing and
selected resources by year to meet demand for the
expected case. Appendix 6.1 and 6.2 summarizes the
peak day demand for the other demand scenarios.
4e Identification and estimated costs of
all supply-side and demand-side
resource options, taking into
account anticipated advances in
technology
Chapter 3 and Appendix 3.1 identify the demand-side
potential included in this IRP. Chapter 4 and 5 and
Appendix 5.3 identify the supply-side resources.
4f Analysis of measures the utility
intends to take to provide reliable
service, including cost-risk tradeoffs.
Chapter 5, 6, and 7 discusses the modeling tools,
customer growth forecasting and cost-risk
considerations used to maintain and plan a reliable
gas delivery system. These Chapters also capture a
summary of the reliability analysis process
demonstrated at the second TAC meeting.
Chapter 4 discusses the diversified infrastructure and
multiple supply basin approach that acts to mitigate
certain reliability risks. Appendix 2.6 highlights key
risks associated with each portfolio.
4g Identification of key assumptions
about the future (e.g. fuel prices and
environmental compliance costs)
and alternative scenarios
considered.
Appendix 5 and Chapter 5 describe the key
assumptions and alternative scenarios used in this
IRP.
4h Construction of a representative set
of resource portfolios to test various
operating characteristics, resource
types, fuels and sources,
technologies, lead times, in-service
dates, durations and general
locations - system-wide or delivered
to a specific portion of the system.
This Plan documents the development and results for
portfolios evaluated in this IRP (see Table 4.3 for
supply scenarios considered).
4i Evaluation of the performance of the
candidate portfolios over the range
of identified risks and uncertainties.
We evaluated our candidate portfolio by performing
stochastic analysis using SENDOUT® varying price
under 200 different scenarios. Additionally, we test
the portfolio of options with the use of SENDOUT®
under deterministic scenarios where demand and
price vary. For resources selected, we assess other
risk factors such as varying lead times required and Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 21 of 648
potential for cost overruns outside of the amounts
included in the modeling assumptions.
4j Results of testing and rank ordering
of the portfolios by cost and risk
metric, and interpretation of those
results.
Avista’s four distinct geographic Oregon service
territories limit many resource option synergies which
inherently reduces available portfolio options.
Feasibility uncertainty, lead time variability and
uncertain cost escalation around certain resource
options also reduce reasonably viable options.
Chapter 4 describes resource options reviewed
including discussion on uncertainties in lead times and
costs as well as viability and resource availability (e.g.
LNG). Appendix 5.3 summarizes the potential
resource options identifying investment and variable
costs, asset availability and lead time requirements
while results of resources selected are identified in
Table 5.5 as well as graphically presented in Figure
5.18 and 5.19 for the Expected Case and Appendix
6.1 for the High Growth case.
4k Analysis of the uncertainties
associated with each portfolio
evaluated
See the responses to 1.b above.
4l Selection of a portfolio that
represents the best combination of
cost and risk for the utility and its
customers
Avista evaluated cost/risk tradeoffs for each of the risk
analysis portfolios considered. Chapter 5 and
Appendix 2.6 show the company’s portfolio risk
analysis, as well as the process and determination of
the preferred portfolio.
4m Identification and explanation of any
inconsistencies of the selected
portfolio with any state and federal
energy policies that may affect a
utility's plan and any barriers to
implementation
This IRP is presumed to have no inconsistencies.
4n An action plan with resource
activities the utility intends to
undertake over the next two to four
years to acquire the identified
resources, regardless of whether
the activity was acknowledged in a
previous IRP, with the key attributes
of each resource specified as in
portfolio testing.
Chapter 8 presents the IRP Action Plan with focus on
the following areas:
 Modeling
 Supply/capacity
 Forecasting
 Regulatory communication
 DSM
Guideline 5: Transmission
5 Portfolio analysis should include
costs to the utility for the fuel
transportation and electric
transmission required for each
resource being considered. In
addition, utilities should consider
fuel transportation and electric
transmission facilities as resource
options, taking into account their
value for making additional
purchases and sales, accessing
less costly resources in remote
Not applicable to Avista’s gas utility operations.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 22 of 648
locations, acquiring alternative fuel
supplies, and improving reliability.
Guideline 6: Conservation
6a Each utility should ensure that a
conservation potential study is
conducted periodically for its entire
service territory.
AEG performed a conservation potential assessment
study for our 2016 IRP. A discussion of the study is
included in Chapter 3. The full study document is in
Appendix 3.1. Avista incorporates a comprehensive
assessment of the potential for utility acquisition of
energy-efficiency resources into the regularly-
scheduled Integrated Resource Planning process.
6b To the extent that a utility controls
the level of funding for conservation
programs in its service territory, the
utility should include in its action
plan all best cost/risk portfolio
conservation resources for meeting
projected resource needs,
specifying annual savings targets.
A discussion on the treatment of conservation
programs is included in Chapter 3 while selection
methodology is documented in Chapter 5. The action
plan details conservation targets, if any, as developed
through the operational business planning process.
These targets are updated annually, with the most
current avoided costs. Given the challenge of the low
cost environment, current operational planning and
program evaluation is still underway and targets for
Oregon have not yet been set.
6c To the extent that an outside party
administers conservation programs
in a utility's service territory at a
level of funding that is beyond the
utility's control, the utility should: 1)
determine the amount of
conservation resources in the best
cost/ risk portfolio without regard to
any limits on funding of conservation
programs; and 2) identify the
preferred portfolio and action plan
consistent with the outside party's
projection of conservation
acquisition.
Not applicable. See the response for 5.b above.
Guideline 7: Demand Response
7 Plans should evaluate demand response resources,
including voluntary rate programs, on par with other
options for meeting energy, capacity, and transmission
needs (for electric utilities) or gas supply and
transportation needs (for natural gas utilities).
Avista has periodically evaluated
conceptual approaches to
meeting capacity constraints
using demand-response and
similar voluntary programs.
Technology, customer
characteristics and cost issues
are hurdles for developing
effective programs. See Chapter
3 Demand Response section for
more discussion.
Guideline 8: Environmental Costs
8 Utilities should include, in their base-case analyses, the
regulatory compliance costs they expect for CO2, NOx,
SO2, and Hg emissions. Utilities should analyze the
range of potential CO2 regulatory costs in Order No. 93-
695, from $0 - $40 (1990$). In addition, utilities should
perform sensitivity analysis on a range of reasonably
possible cost adders for NOx, SO2, and Hg, if applicable.
Avista’s current direct gas
distribution system infrastructure
does not result in any CO2, NOx,
SO2, or Hg emissions. Upstream
gas system infrastructure
(pipelines, storage facilities, and
gathering systems) do produce
CO2 emissions via compressors Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 23 of 648
used to pressurize and move gas
throughout the system. The
Environmental Externalities
discussion in Appendix 3.2
describes our analysis
performed. See also the
guidelines addendum reflecting
revised guidance for
environmental costs per Order
08-339.

Guideline 9: Direct Access Loads
9 An electric utility's load-resource balance should exclude
customer loads that are effectively committed to service
by an alternative electricity supplier.
Not applicable to Avista’s gas
utility operations.
Guideline 10: Multi-state utilities
10 Multi-state utilities should plan their generation and
transmission systems, or gas supply and delivery, on an
integrated-system basis that achieves a best cost/risk
portfolio for all their retail customers.
The 2014 IRP conforms to the
multi-state planning approach.
Guideline 11: Reliability
11 Electric utilities should analyze reliability within the risk
modeling of the actual portfolios being considered. Loss
of load probability, expected planning reserve margin,
and expected and worst-case unserved energy should
be determined by year for top-performing portfolios.
Natural gas utilities should analyze, on an integrated
basis, gas supply, transportation, and storage, along with
demand-side resources, to reliably meet peak, swing,
and base-load system requirements. Electric and natural
gas utility plans should demonstrate that the utility’s
chosen portfolio achieves its stated reliability, cost and
risk objectives.
Avista’s storage and transport
resources while planned around
meeting a peak day planning
standard, also provides
opportunities to capture off
season pricing while providing
system flexibility to meet swing
and base-load requirements.
Diversity in our transport options
enables at least dual fuel source
options in event of a transport
disruption. For areas with only
one fuel source option the cost of
duplicative infrastructure is not
feasible relative to the risk of
generally high reliability
infrastructure.

Guideline 12: Distributed Generation
12 Electric utilities should evaluate distributed
generation technologies on par with other supply-side
resources and should consider, and quantify where
possible, the additional benefits of distributed generation.
Not applicable to Avista’s gas
utility operations.
Guideline 13: Resource Acquisition
13a An electric utility should: identify its proposed acquisition
strategy for each resource in its action plan; Assess the
advantages and disadvantages of owning a resource
instead of purchasing power from another party; identify
any Benchmark Resources it plans to consider in
competitive bidding.
Not applicable to Avista’s gas
utility operations.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 24 of 648
13b Natural gas utilities should either describe in the IRP
their bidding practices for gas supply and transportation,
or provide a description of those practices following IRP
acknowledgment.
A discussion of Avista’s
procurement practices is detailed
in Chapter 4.
Guideline 8: Environmental Costs
a. BASE CASE AND OTHER COMPLIANCE SCENARIOS:
The utility should construct a base-case scenario to
reflect what it considers to be the most likely regulatory
compliance future for carbon dioxide (CO2), nitrogen
oxides, sulfur oxides, and mercury emissions. The utility
also should develop several compliance scenarios
ranging from the present CO2 regulatory level to the
upper reaches of credible proposals by governing
entities. Each compliance scenario should include a time
profile of CO2 compliance requirements. The utility
should identify whether the basis of those requirements,
or “costs”, would be CO2 taxes, a ban on certain types of
resources, or CO2 caps (with or without flexibility
mechanisms such as allowance or credit trading or a
safety valve). The analysis should recognize significant
and important upstream emissions that would likely have
a significant impact on its resource decisions. Each
compliance scenario should maintain logical consistency,
to the extent practicable, between the CO2 regulatory
requirements and other key inputs.
Avista’s current direct gas
distribution system infrastructure
does not result in any CO2, NOx,
SO2, or Hg emissions. Upstream
gas system infrastructure
(pipelines, storage facilities, and
gathering systems) do produce
CO2 emissions via compressors
used to pressurize and move gas
throughout the system.

The Environmental Externalities
discussion in Appendix 3.2
describes our process for
addressing these costs.

b. TESTING ALTERNATIVE PORTFOLIOS AGAINST THE
COMPLIANCE SCENARIOS: The utility should
estimate, under each of the compliance scenarios, the
present value of revenue requirement (PVRR) costs and
risk measures, over at least 20 years, for a set of
reasonable alternative portfolios from which the preferred
portfolio is selected. The utility should incorporate end-
effect considerations in the analyses to allow for
comparisons of portfolios containing resources with
economic or physical lives that extend beyond the
planning period. The utility should also modify projected
lifetimes as necessary to be consistent with the
compliance scenario under analysis. In addition, the
utility should include, if material, sensitivity analyses on a
range of reasonably possible regulatory futures for
nitrogen oxides, sulfur oxides, and mercury to further
inform the preferred portfolio selection.
The Environmental Externalities
discussion in Appendix 3.2
describes our process for
addressing these costs.

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 25 of 648
APPENDIX 2.1: ECONOMIC OUTLOOK AND CUSTOMER COUNT FORECAST
I. Service Area Economic Performance and Outlook

Avista’s core service area for natural gas includes Eastern Washington, Northern Idaho, and Southwest Oregon.
Smaller service islands are also located in rural South-Central Washington and Northeast Oregon. Our service area
is dominated by four metropolitan statistical areas (MSAs): the Spokane-Spokane Valley, WA MSA (Spokane-
Stevens counties); the Coeur d’Alene, ID MSA (Kootenai County); the Lewiston-Clarkson ID-WA, MSA (Nez Perce-
Asotin counties); and the Medford, OR MSA (Jackson County). These four MSAs represent the primary demand for
Avista’s natural gas and account for 75% of both customers (i.e., meters) and load. The remaining 25% of
customers and load are spread over low density rural areas in all three states.

Figure 1: Employment and Population Recovery, December 2007- December 2015

Data source: Employment from the BLS; population from the U.S. Census.

In the wake of the Great Recession, our service area recovered more slowly than the U.S. Although the U.S.
recession officially ended in June 2009 (dated by the National Bureau of Economic Research), our service area did
not start a significant employment recovery until the second half of 2012 (Figure 1, top and bottom graph).
-7%
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Avista WA-ID-OR MSAs U.S.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 26 of 648
However, by the start of 2015, year-over-year employment growth slightly exceeded U.S. growth and employment
levels returned to pre-recession levels. As a result, service area population growth, which is significantly
influenced by in-migration through employment opportunities, also improved in 2014 and 2015 (Figure 2).

Figure 2: Avista MSA Annual Population Growth, 2005-2015

In 2011, Avista’s MSA population growth fell to around 0.6%, the lowest since the late 1980s, but has increased to
around 1% by 2014. This is important because population growth is a significant contributor to overall customer
growth.

Figure 3 shows that compared to forecasted customer growth in the 2014 IRP, actual average customer growth
over the 2014-2015 period has been slightly higher, reflecting stronger than expected service area growth. Given
the improving economy and increased population growth, this IRP, compared to the 2014 IRP, shows an upward
revision of approximately 5,500 forecasted customers in WA-ID and 7,000 in OR by 2035 (Figure 4). System-wide,
this is an upward revision of approximately 12,500 customers. Table 1 shows the change in the customer forecast
by class between the 2016 and 2014 IRPs for WA-ID, OR, and system-wide.

1.6%1.7%
1.7%
1.3%
1.0%
0.7%
0.6%0.6%
0.8%
1.1%
1.0%
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
1.4%
1.6%
1.8%
2.0%
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 27 of 648
Figure 3: Comparison of 2014-IRP Customer Growth Forecasts to Actuals, 2014-2015

Data source: Company data.

Table 1: Change in Forecast between the 2016 IRP and 2014 IRP in 2035
WA-ID +7,394 -1,928 +30 +5,496
OR +6,980 +38 -1 +7,017
System +14,374 -1,890 +29 +12,513

This upward revision in residential customers reflects two factors. First, the recent economic and population
recovery has resulted in a higher population forecast, which is a significant forecast driver of residential customer
growth. That is, population growth is a proxy for new household formation. Second, the forecast methodology for
residential customers has been improved so that growth through retrofitting is better captured. In this context,
retrofitting means existing households adding natural gas as an energy source. Therefore, new customers are
generated through new households that build-in gas as an energy source and older households retrofitting with
gas. This can be seen in Figure 5 (top graph WA-ID; bottom graph OR). Excluding the weak post-recession
recovery period (2009-2011), annual residential customer growth exceeds population growth. The convergence of
customer and population growth in the 2009-2011 period reflects a decline in retrofitting due to lower
1.11%1.18%1.15%1.15%
1.29%1.22%
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
1.4%
2014 2015 2014-2015 Average
WA-ID Forecasted vs. Actual Customer Growth Rates
WA-ID 2014 IRP Forecast WA-ID Actual
0.86%
0.78%0.82%0.78%
1.09%
0.94%
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
2014 2015 2014-2015 Average
OR Forecasted vs. Actual Customer Growth Rates
OR 2014 IRP Forecast OR Actual
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 28 of 648
discretionary spending by households. From 2005 to 2015, the average customer-population growth spread in
WA-ID and OR was 0.5%.

Figure 4: Comparison IRP Forecasted Customer Growth in WA-ID and OR, 2016-2035
Data source: Company data.

Again referring to Table 1, although the improving economic conditions increased the forecast for residential
customers, this is not the case for commercial customers in WA-ID. The current modeling approach for the
majority of commercial customers assumes that residential customer growth is a driver of commercial customer
growth. The use of residential customers as forecast driver for commercial customers reflects the historically high
correlation between residential and commercial customer growth rates. However, in the case of WA-ID, the
relative ratio of annual (firm) commercial customer growth to firm residential growth has been on a downward
trend since 2009. This ratio is shown in Figure 6 for the 2005-2015 period and includes OR for comparison. Note
that the ratios for both areas declined following the start of the great recession.

300,000
320,000
340,000
360,000
380,000
400,000
420,000
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
WA-ID-OR-Base 2014 IRP WA-ID-OR-Base 2016 IRP
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 29 of 648
Figure 5: Customer and Population Growth, 2005-2015
Data source: Company data.
OR’s fell fairly dramatically, but rebounded starting in 2012. In contrast, WA-ID’s continued its downward trend
after a brief rebound in 2012. For an econometric forecasting perspective, this means a given increase in WA-ID
residential customers is associated with a smaller change in commercial customers compared to the pre-Great
Recession period. As a result, the upward revision in residential customers in WA-ID did not result in an upward
revision in commercial customers.

0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
3.5%
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
OR Population Growth vs. Residential Customer Growth
OR Customer Growth OR Population Growth
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
3.5%
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
WA-ID Population Growth vs. Residential Customer Growth
WA-ID Customer Growth WA-ID Population Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 30 of 648
Figure 6: Ratio of Commercial Customer Growth to Residential Customer Growth, 2005-2015

Data source: Company data.

The forecast for system-wide industrial customers is slightly higher than the 2014 IRP. This reflects an increase in
the WA-ID forecast; as of 2015, approximately 90% of industrial customers are in WA-ID. Figure 7 (top graph)
shows total system-wide firm industrial customers since 2004. Following a sharp drop over the 2004-2006 period,
firm industrial customers have remained stable at around 260. Separating out WA-ID and OR (middle graph), the
number of firm customers in WA-ID continuously fell over the 2004-2011 period. In contrast, OR customers
increased over the 2004-2011 period (bottom graph). However, since 2011 the customer counts in both regions
have been relatively flat. That is, over the last five years there has been no appreciable change in firm industrial
customers our service area. Therefore, in contrast to the 2014 IRP, the current forecast shows flat rather than
declining industrial customers.

-0.4
-0.2
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
WA-ID Growth Ratio OR Growth Ratio
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 31 of 648
Figure 7: Industrial Customer Count, 2004-2015

Data source: Company data.

240
245
250
255
260
265
270
275
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
WA-ID-OR Firm Industrial Customers
200
210
220
230
240
250
260
270
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
WA-ID Firm Industrial Customers
0
5
10
15
20
25
30
35
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
OR Firm Industrial Customers
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 32 of 648
II. IRP Forecast Process and Methodology

The customer forecasts are generated from forecasting models that are either regression models with ARIMA error
corrections or simple smoothing models. The ARIMA error correction models are estimated using SAS/ETS
software. The customer forecasts are used as input into Sendout® to generate the IRP load forecasts.
Population growth is the key driver for the residential and commercial customer forecasts. Other variables include
(1) seasonal dummy variables and (2) outlier dummy variables that control for extreme customer counts
associated with double billing, software conversions, and customer movements from one billing schedule to
another.

Population growth forecast is the key driver behind the customer forecast for residential schedules 101 in WA-ID
and 410 in OR. These two schedules represent the majority of customers and, therefore, drive overall residential
customer growth. Because of their size and growth potential, a multi-step forecasting process has been
developed for the Spokane-Spokane Valley, Coeur d’Alene, and Medford MSAs. The process for forecasting
population growth starts with an intermediate forecast horizon (six years). This intermediate forecast is typically
used for the annual financial forecast. However, during IRP years, this intermediate forecast horizon is augmented
with third party forecasts that cover the next twenty years. Starting with Figure 8, the six-year population forecast
is a multi-step process that begins with a GDP forecast that drives the regional employment forecast, which in turn,
drives a six year population forecast.

Figure 8: Forecasting Population Growth, 2016-2021

The forecasting models for regional employment growth are:

[1] 𝐺𝐸𝑀𝑃𝑦,𝑆𝑃𝐾= 𝜗0 + 𝜗1𝐺𝐺𝐷𝑃𝑦,𝑈𝑆+ 𝜗2𝐺𝐺𝐷𝑃𝑦−1,𝑈𝑆+ 𝜗3𝐺𝐺𝐷𝑃𝑦−2,𝑈𝑆+ 𝜔𝑆𝐶𝐷𝐾𝐶,1998−2000=1+ 𝜔𝑆𝐶𝐷𝐻𝐵,2005−2007=1 + 𝜖𝑡,𝑦

[2] 𝐺𝐸𝑀𝑃𝑦,𝐾𝑂𝑂𝑇= 𝛿0 + 𝛿1𝐺𝐺𝐷𝑃𝑦,𝑈𝑆+ 𝛿2𝐺𝐺𝐷𝑃𝑦−1,𝑈𝑆+ 𝛿3𝐺𝐺𝐷𝑃𝑦−2,𝑈𝑆+ 𝜔𝑂𝐿𝐷1994=1+ 𝜔𝑂𝐿𝐷2009=1 + 𝜔𝑆𝐶𝐷𝐻𝐵,2005−2007=1 + 𝜖𝑡,𝑦

[3] 𝐺𝐸𝑀𝑃𝑦,𝐽𝐴𝐶𝐾= 𝜙0 + 𝜙1𝐺𝐺𝐷𝑃𝑦,𝑈𝑆+ 𝜙2𝐺𝐺𝐷𝑃𝑦−1,𝑈𝑆+ 𝜙3𝐺𝐺𝐷𝑃𝑦−2,𝑈𝑆+ 𝜔𝑆𝐶𝐷𝐻𝐵,2004−2005=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (1,0,0)(0,0,0)12

SPK is Spokane, WA (Spokane MSA), KOOT is Kootenai, ID (Coeur d’Alene MSA), and JACK is for Jackson County, OR
(Medford MSA). GEMPy is employment growth in year y, GGDPy,US is U.S. real GDP growth in year y. DKC is a
dummy variable for the collapse of Kaiser Aluminum in Spokane, and DHB, is a dummy for the housing bubble,
specific to each region. The average GDP forecasts are used in the estimated model to generate five-year
employment growth forecasts. The employment forecasts are then averaged with GI’s forecasts for the same
counties so that:

[4] 𝐹𝐴𝑣𝑔(𝐺𝐸𝑀𝑃𝑦,𝑆𝑃𝐾)= 𝐹(𝐺𝐸𝑀𝑃𝑦,𝑆𝑃𝐾)+𝐹(𝐺𝐺𝐼𝐸𝑀𝑃)𝑦,𝑆𝑃𝐾)
2

[5] 𝐹𝐴𝑣𝑔(𝐺𝐸𝑀𝑃𝑦,𝐾𝑂𝑂𝑇) = 𝐹(𝐺𝐸𝑀𝑃𝑦,𝐾𝑂𝑂𝑇 )+𝐹(𝐺𝐺𝐼𝐸𝑀𝑃𝑦,𝐾𝑂𝑂𝑇)
2
Average GDP Growth
Forecasts:
FOMC,
Bloomberg, Wall
Street Journal,
etc.
Average forecasts
out 5-yrs.
Growth Model:
Model links year y, y-1,
and y-2 GDP growth to
year y regional
employment growth.
Forecast out 6-yrs.
Averaged with GI

Model links regional, U.S., and CA
year y-1 employment growth to year
y county population growth.
Forecast out 6-yrs for Spokane, WA;
Kootenai, ID; and Jackson, OR.
Averaged with IHS forecasts for ID
and OR and OFM forecasts for WA.
Growth rates used to generate
population forecasts for customer
forecasts for residential schedules 1,
101, and 410.
EMP GDP
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 33 of 648

[6] 𝐹𝐴𝑣𝑔(𝐺𝐸𝑀𝑃𝑦,𝐽𝐴𝐶𝐾)= 𝐹(𝐺𝐸𝑀𝑃𝑦,𝐽𝐴𝐶𝐾 )+𝐹(𝐺𝐺𝐼𝐸𝑀𝑃𝑦,𝐽𝐴𝐶𝐾)
2

Averaging reduces the systematic errors of a single-source forecast. The averages [8.4] through [8.6] are used to
generate the population growth forecasts, which are described next.

The forecasting models for regional population growth are:

[7] 𝐺𝑃𝑂𝑃𝑦,𝑆𝑃𝐾= 𝜅0 + 𝜅1𝐺𝐸𝑀𝑃𝑦−1,𝑆𝑃𝐾+ 𝜅2𝐺𝐸𝑀𝑃𝑦−2,𝑈𝑆+ 𝜔𝑂𝐿𝐷2001=1+𝜖𝑡,𝑦

[8] 𝐺𝑃𝑂𝑃𝑦,𝐾𝑂𝑂𝑇= 𝛼0 + 𝛼1𝐺𝐸𝑀𝑃𝑦−1,𝐾𝑂𝑂𝑇+ 𝛼2𝐺𝐸𝑀𝑃𝑦−2,𝑈𝑆+ 𝜔𝑂𝐿𝐷1994=1 + 𝜔𝑂𝐿𝐷2002=1+ 𝜔𝑆𝐶𝐷𝐻𝐵,2007↑=1 + 𝜖𝑡,𝑦

[9] 𝐺𝑃𝑂𝑃𝑦,𝐽𝐴𝐶𝐾= 𝜓0 + 𝜓1𝐺𝐸𝑀𝑃𝑦−1,𝐽𝐴𝐶𝐾+ 𝜓2𝐺𝐸𝑀𝑃𝑦−2,𝐶𝐴+ 𝜔𝑂𝐿𝐷1991=1+ 𝜔𝑆𝐶𝐷𝐻𝐵,2004−2006=1 + 𝜖𝑡,𝑦

D2001=1 and D1991=1 are a dummy variables for recession impacts. GEMPy-1,US is U.S. employment growth in year y-1
and GEMPy-2, and CA is California Employment growth in year y-1. Because of its close proximity to CA, CA
employment growth is better predictor of Jackson, OR employment growth than U.S. growth. The averages [4]
through [6] are used in [7] through [9] to generate population growth forecasts. These forecasts are combined
with IHS’s forecasts for Kootenai, ID and Jackson, OR and the Office for Financial Management (OFM) for Spokane,
WA in the form of a simple average:

[10] 𝐹𝐴𝑣𝑔(𝐺𝑃𝑂𝑃𝑦,𝑆𝑃𝐾) = 𝐹(𝐺𝑃𝑂𝑃𝑦,𝑆𝑃𝐾)+𝐹(𝐺𝑂𝐹𝑀𝑃𝑂𝑃𝑦,𝑆𝑃𝐾)
2

[11] 𝐹𝐴𝑣𝑔(𝐺𝑃𝑂𝑃𝑦,𝐾𝑂𝑂𝑇) = 𝐹(𝐺𝑃𝑂𝑃𝑦,𝐾𝑂𝑂𝑇 )+𝐹(𝐺𝐺𝐼𝑃𝑂𝑃𝑦,𝐾𝑂𝑂𝑇)
2

[12] 𝐹𝐴𝑣𝑔(𝐺𝑃𝑂𝑃𝑦,𝐽𝐴𝐶𝐾) = 𝐹(𝐺𝑃𝑂𝑃𝑦,𝐽𝐴𝐶𝐾 )+𝐹(𝐺𝐺𝐼𝑃𝑂𝑃𝑦,𝐽𝐴𝐶𝐾)
2

Here, FAvg(GPOPy) is used to forecast population to forecast residential customers in schedules 101 (WA-ID) and
410 (OR) for the Spokane, Kootenai, and Medford areas. In the case of Spokane, OFM forecasts are used because
the IHS’s forecasts exhibit a level and time-path that is inconsistent with recent population behavior. The
population growth forecasts for the Douglas (Roseburg), Klamath (Klamath Falls); and Union (La Grande) counties
come directly from IHS. Since all forecasted growth rates are annualized, they are converted to monthly rates as
FAvg(GPOPt,y)= [1+ FAvg(GPOPy)]1/12 – 1. By way of example, the following is regression model for residential 101
customers for the Spokane region:

𝐶𝑡,𝑦,𝑊𝐴101.𝑟= 𝛼0 + 𝜏𝑃𝑂𝑃𝑡,𝑦,𝑆𝑃𝐾+𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑆𝐶𝐷𝐽𝑎𝑛 2007↑=1 + 𝛾𝑅𝐴𝑀𝑃𝑇𝐽𝑎𝑛 2007 + 𝜔𝑂𝐿𝐷𝐴𝑢𝑔 2010=1+ 𝜔𝑂𝐿𝐷𝑆𝑒𝑝𝑡 2012=1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (9,1,0)(0,0,0)12

Where:

POPt,y,SPK =  is the coefficient to be estimated and POPt,y,SPK is the interpolated population level in month t, in
year y, for Spokane. The monthly interpolation of historical data assumes that between years, population
accumulates following the standard population growth model: POPy,SPK = POPy-1,SPKer.

SDDt,y = SD is a vector of seasonal dummy (SD) coefficients to be estimated and Dt,y is a vector monthly
seasonal dummies to account of customer seasonality. Dt,y = 1 for the relevant month.

SCDJan 2007↑=1 + RampTJan 2007 = structural change (SC) and trend (Ramp) coefficients and variables that control
for the sharp fall in residential customer growth that cannot be fully accounted for by the population
variable. This reflects the impact of the housing bubble collapse and the subsequent Great Recession. DJan
2007↑=1 takes a value of 1 over both the estimation and forecast period starting in January 2007, and TJan 2007 is
a linear time-trend that starts in January 2007 and continues over the estimation and forecast period.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 34 of 648

OLDAug 2010=1 = OL outlier (OL) coefficient to be estimated and D is a dummy that equals 1 for August 2010.
There are three additional outlier dummies that follow August 2010.

ARIMAt,y(9,1,0)(0,0,0)12 = is the error correction applied to the model’s initial error structure. This term
follows the following from ARIMAt,y (p,d,q)(pk,dk,qk)k. The term p is the autoregressive (AR) order, d is the
differencing order, and q is the moving average (MA) order. The term pk is the order of seasonal AR terms, dk
is the order of seasonal differencing, and qk is the seasonal order of MA terms. The seasonal values are
related to “k,” which is the frequency of the data. With the current data set, k = 12.

The customer forecast is generated by inputting forecasted values of POPt,y,SPK into the model estimated with
historical data. All customer forecast equations are shown in the last section.

The above describes the population forecast for the annual six-year forecast. For IRP years, the customer forecast
needs to be extended out an additional 15 years beyond the five-year forecast. This is done using the IHS
population forecast for Kootenai, Jackson, Douglas, Klamath, and Union counties. That is, IHS is the sole source for
forecasted population growth beyond the six-year time horizon generated by [10] through [12]. In the case of
Spokane County, the forecast from Washington’s Office of Financial Management (OFM) is instead of IHS’s. The
choice to use OFM’s forecasts reflects the unusually sharp changes that have occurred in the IHS forecasts for the
Spokane MSA over a short period of time. Figure 9 shows how much these forecasts have changed in level and
shape since June 2012. Between the October 2015 and March 2016 forecasts, there was as significant change for
the 2015-2019 period. There is no clear rational for why IHS’s forecasts can change so significantly between 2012
and 2016.

Figure 10: Spokane MSA Forecast Comparison

Data source: IHS, Washington State of Office of Financial Management, and U.S. Census.

0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
IHS June 2012 Forecast IHS October 2015 Forecast IHS March 2016 Forecast OFM 2012 Actual
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 35 of 648
Figure 10: Annual Customer Growth for the Three Rate Classes, 2005-2015

Data source: Company data.
Figure 10 demonstrates that residential and commercial growth rates are highly correlated and maintain similar
levels over the long-run—both classes’ growth rates averaged about 1% over this period. This growth is slightly
higher than population growth because of the housing boom and existing households retrofitting with natural gas.
However, by 2009, with the collapse of the housing bubble and increased natural gas saturation, customer growth
moved closer to population growth.

In contrast, the behavior of Industrial customer growth looks quite different. Customer growth is both lower and
more volatile. The average growth rate since 2005 is -1.0%, reflecting a trend of nearly flat or slowly declining
customers, depending on the jurisdiction. In addition, the standard deviation of year-over-year growth is 2.1%
compared to 0.9% for residential and 0.7% for commercial growth. The current IRP forecast reflects this historical
trend of weak growth. Some energy industry analysts believe the U.S.’s increased supply of natural gas and oil will
attract industrial production back from overseas locations. However, in this IRP, we do not assume plentiful
energy supplies in the U.S. will alter long-run trends in industrial customer growth in our service area.

Establishing High-Low Cases for IRP Customer Forecast

The customer forecasts for this IRP include high and low cases that set the expected bounds around the base-case.
Table 2 shows the base, low, and high customer forecasts along with the underlying population growth
assumption. The underlying population forecast is the primary driver for each of the three cases.

Table 2: Alternative Growth Cases
WA-ID:
WA-ID Customers 0.6% 1.1% 1.5%
WA Population 0.4% 0.8% 1.2%
ID Population 1.0% 1.5% 2.0%

OR:
OR Customers 0.7% 1.2% 1.6%
OR Population 0.4% 0.8% 1.3%
System:
System Customers 0.7% 1.1% 1.5%
System Population 0.5% 0.9% 1.3%
-5%
-4%
-3%
-2%
-1%
0%
1%
2%
3%
4%
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
Residential Commercial Industrial
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 36 of 648

III. IRP Customer Forecast Equations

1. Washington and Idaho Residential Forecasting Models by Schedule
WA residential customer forecasts:

[13] 𝐶𝑡,𝑦,𝑊𝐴101.𝑟= 𝛼0 + 𝜏𝑃𝑂𝑃𝑡,𝑦,𝑆𝑃𝐾+𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑆𝐶𝐷𝐽𝑎𝑛 2007↑=1 + 𝛾𝑅𝐴𝑀𝑃𝑇𝐽𝑎𝑛 2007 + 𝜔𝑂𝐿𝐷𝐴𝑢𝑔 2010=1 +
𝜔𝑂𝐿𝐷𝑆𝑒𝑝𝑡 2012=1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (9,1,0)(0,0,0)12

[13] Model notes:
1. SC dummy and ramping time trend control for a change in the time-path of customer growth staring in January 2007.

[14] 𝐶𝑡,𝑦,𝑊𝐴111.𝑟= 𝛼0 + 𝛾𝑅𝐴𝑀𝑃𝑇𝑆𝑒𝑝𝑡 2010 + 𝜔𝑆𝐶𝐷𝑂𝑐𝑡 2011↑=1 + 𝜔𝑆𝐶𝐷𝑂𝑐𝑡 2013↑=1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2005=1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2006=1 +
𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2007=1 + 𝜔𝑂𝐿𝐷𝑆𝑒𝑝𝑡 2007=1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2007=1 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2011=1 + 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2015=1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 +
𝜔𝑂𝐿𝐷𝐴𝑝𝑟 2015=1 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (1,1,0)(0,0,0)12 𝑓𝑜𝑟 𝑡,𝑦 = 𝐹𝑒𝑏 2007 ↑

[14] Model notes:
1. Ramping time trend controls for a change in the time-path of customer growth staring in the September 2010.
2. SC dummies control for a step-up in customers starting in October 2011 and October 2013.
3. Model is restricted to February 2007  because of a large step-up in customers.

Similarly for ID:

[15] 𝐶𝑡,𝑦,𝐼𝐷101.𝑟= 𝛽0 + 𝜏𝑃𝑂𝑃𝑡,𝑦,𝐾𝑂𝑂𝑇+𝝎𝑺𝑫𝑫𝒕,𝒚+𝜔𝑆𝐶𝐷𝐽𝑎𝑛 2007↑=1 + 𝛾𝑅𝐴𝑀𝑃𝑇𝐽𝑎𝑛 2007 +
𝜔𝑂𝐿𝐷𝑀𝑎𝑦 2005=1 + 𝜔𝑂𝐿𝐷𝐽𝑢𝑙 2005=1 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2005=1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2005=1+𝜔𝑂𝐿𝐷𝐽𝑢𝑛 2006=1 +
𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2006=1 + 𝜔𝑂𝐿𝐷𝐽𝑢𝑛 2007=1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2007=1 + 𝜔𝑂𝐿𝐷𝐴𝑢𝑔 2009=1 + 𝜔𝑂𝐿𝐷𝐴𝑢𝑔 2011=1 +
𝜔𝑂𝐿𝐷𝑆𝑒𝑝𝑡 2011=1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (2,1,0)(0,0,0)12

[15] Model notes:
1. SC dummy and ramping time trend control for a change in the time-path of customer growth staring in January 2007.

[16] 𝐶𝑡,𝑦,𝐼𝐷111.𝑟= 𝛽0+𝜔𝑆𝐶𝐷𝐷𝑒𝑐 2008↑=1+𝜔𝑆𝐶𝐷𝐷𝑒𝑐 2011↑=1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2008=1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2010=1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2011=1 +
𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2011=1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (9,1,0)(0,0,0)12

[16] Model notes:
1. SC dummies control for a step-up in customers starting in December 2008 and December 2011.

2. Washington and Idaho Commercial Forecasting Models by Schedule
Commercial customer baseline forecasts are a mix of simple ARIMA and smoothing models. The WA models are:

[17] 𝐶𝑡,𝑦,𝑊𝐴101.𝑐= 𝛼0 + 𝛼1𝐶𝑡,𝑦,𝑊𝐴101.𝑟+ 𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (1,1,0)(0,0,0)12

[17] Model notes:
1. Ct,y,WA101.r are residential customers from residential schedule 101. They are being used as a forecast driver because of the historical positive
correlation between residential and commercial customer growth.

[18] 𝐶𝑡,𝑦,𝑊𝐴111.𝑐= 𝛼0 + 𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2007=1 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2013=1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 +
𝜔𝑂𝐿𝐷𝐴𝑝𝑟 2015=1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (2,1,0)(0,0,0)12

[18] Model notes:
1. Distribution of error terms not quite normal; however, they do pass the white-noise test.

[19] 𝐶𝑡,𝑦,𝑊𝐴121+122.𝑐= 1
12 ∑𝐶𝑡−𝑗12𝑗=1

[19] Model notes:
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 37 of 648
1. Customer count is around 25 without any clear trend or seasonality. For unknown reasons, customer county volatility fell substantially in
January 2012.
2. Due to the Compass software conversion, February 2015 is excluded from the historical data. The conversion resulted in a double counting
of customers in February 2015. Therefore, including this month leads to a significant over-forecast of customers.

[20] 𝐶𝑡,𝑦,𝑊𝐴132.𝑐= 𝐶𝑡−1

[20] Model notes:
1. Stable customer count; no econometric model required. Customer count has been at 2 since December 2012.

Similarly for ID:

[21] 𝐶𝑡,𝑦,𝐼𝐷101.𝑐= 𝛽0 + 𝛽1𝐶𝑡,𝑦,𝐼𝐷101.𝑟+ 𝝎𝑺𝑫𝑫𝒕,𝒚+𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2005↑=1+𝜔𝑆𝐶𝐷𝑆𝑒𝑝 2006↑=1+𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2007↑=1 +
𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2005=1 + 𝜔𝑂𝐿𝐷𝐽𝑢𝑛 2005=1 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2005=1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2005=1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2007=1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 +
+𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (0,1,0)(2,0,0)12

[21] Model notes:
1. Ct,y,ID101.r are residential customers from residential schedule 101. They are being used as a forecast driver because of the historical positive
correlation between residential and commercial customer growth.
2. SC dummies control for a step-up in customers in November 2005, September 2006, and November 2007.

[22] 𝐶𝑡,𝑦,𝐼𝐷111.𝑐= 𝑊𝑖𝑛𝑡𝑒𝑟′𝑠 𝑀𝑒𝑡ℎ𝑜𝑑− 𝐴𝑑𝑑𝑖𝑡𝑖𝑣𝑒

[23] 𝐶𝑡,𝑦,𝐼𝐷132.𝑐=1
12∑𝐶𝑡−𝑗12𝑗=1

3. Washington and Idaho Industrial Forecasting Models by Schedule

Customer forecasts for WA:

[24] 𝐶𝑡,𝑦,𝑊𝐴101.𝑖= 𝛼0 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2006=1 +
𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2007=1+ 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2007=1+ 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2013=1+ 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2014=1+ 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2015=1+ 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (2,0,0)(0,0,0)12

[25] 𝐶𝑡,𝑦,𝑊𝐴111.𝑖=
𝛼0 + 𝜔𝑂𝐿𝐷𝑆𝑒𝑝𝑡 2005=1+ 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2006=1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2006=1+ 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2007=1+ 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2007=1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2008=1+ 𝜔𝑂𝐿𝐷𝐽𝑢𝑛𝑒 2014=1 +
𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1+ 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (1,0,0)(0,0,0)12

[26] 𝐶𝑡,𝑦,𝑊𝐴121+122.𝑖=1
12∑𝐶𝑡−𝑗12𝑗=1

[26] Model notes:
1. Customer count for schedule 122 fell to zero in 2012. Schedule 121 customers fluctuate between 2 and 4 customers without any clear trend
or seasonality.

Similarly for ID:

[27] 𝐶𝑡,𝑦,𝐼𝐷101.𝑖= 𝛽0 + 𝜔𝑆𝐶𝐷𝐷𝑒𝑐 2010↑=1+ 𝜔𝑆𝐶𝐷𝑁𝑜𝑣 2011↑=1+ 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2005=1 +
𝜔𝑂𝐿𝐷𝐴𝑢𝑔 2005=1+ 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2005=1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2006=1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2007=1+ 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2008=1 +
𝜔𝑂𝐿𝐷𝐴𝑢𝑔 2011=1+ 𝜔𝑂𝐿𝐷𝐽𝑢𝑙𝑦 2014=1 + 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2015=1+ 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (4,0,0)(0,0,0)12

[27] Model notes:
1. SC dummies control for step-downs in customers.

[28] 𝐶𝑡,𝑦,𝐼𝐷111.𝑖= 1
12 ∑𝐶𝑡−𝑗12𝑗=1 ,𝑟𝑒𝑠𝑡𝑟𝑖𝑐𝑡 𝑡𝑜 𝑑𝑎𝑡𝑎 𝑡,𝑦 = 𝐴𝑢𝑔𝑢𝑠𝑡 2009 ↑

[28] Model notes:
1. Period of restriction reflects the restriction on the UPC model for this schedule.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 38 of 648
2. Due to the Compass software conversion, February 2015 is excluded from the historical data. The conversion resulted in a double counting
of customers in February 2015. Therefore, including this month leads to a significant over-forecast of customers.

[29] 𝐶𝑡,𝑦,𝐼𝐷112.𝑖= 1
12 ∑𝐶𝑡−𝑗12𝑗=1

4. Medford, OR Forecasting Models

The forecasting models for the Medford region (Jackson County) are given below for the residential, commercial,
and industrial sectors:

Residential Sector, Customers:
[30] 𝐶𝑡,𝑦,𝑀𝐸𝐷410.𝑟= 𝛼0 + 𝛼1𝑃𝑂𝑃𝑡,𝑦,𝐽𝐴𝐶𝐾𝑆𝑂𝑁+𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑆𝐶𝐷𝐽𝑎𝑛 2008↑ =1 + 𝛾𝑅𝐴𝑀𝑃𝑇𝐽𝑎𝑛 2008 +
𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2004 =1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2004 =1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2005 =1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015 =1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (11,1,0)(0,0,0)12

[30] Model notes:
1. SC dummy and ramping time trend control for a change in the time-path of customer growth staring in January 2008.

Commercial Sector, Customers:
[31] 𝐶𝑡,𝑦,𝑀𝐸𝐷420.𝑐= 𝛼0 +𝛼1𝐶𝑡,𝑦,𝑀𝐸𝐷410.𝑟 + 𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2004=1 + 𝜔𝑂𝐿𝐷𝑆𝑒𝑝𝑡 2005 =1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2009 =1 +
𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015 =1 +𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (3,1,0)(1,0,0)12

[31] Model notes:
1. Ct,y,MED410.r are residential customers from residential schedule 410. They are being used as a forecast driver because of the historical positive
correlation between residential and commercial customer growth.

[32] 𝐶𝑡,𝑦,𝑀𝐸𝐷424.𝑐= 𝐶𝑡,𝑦−1 + 1

[32] Model notes:
1. Schedule adds about one customer per year.
2. Due to the Compass software conversion, February 2015 is excluded from the historical data. The conversion resulted in a double counting
of customers in February 2015. Therefore, including this month leads to a significant over-forecast of customers.

[33] 𝐶𝑡,𝑦,𝑀𝐸𝐷444.𝑐= 1 𝑖𝑓 (𝑇𝐻𝑀/𝐶𝑡,𝑦)𝑀𝐸𝐷,440.𝑐> 0

[33] Model notes:
1. There is typically only one customer served by this schedule. Therefore, the customer forecast is automatically set to one whenever the load
forecast is greater than zero.

Industrial Sector, Customers:

[34] 𝐶𝑡,𝑦,𝑀𝐸𝐷420.𝑖= 1
12 ∑𝐶𝑡−𝑗12𝑗=1

[34] Model notes:
1. Data starts November 2006. Excluding outliers in November 2006, November 2009, and February 2011, the customer count fluctuates
between 9 and 16 without any clear trend or seasonality. Changes in the customer count occur in steps between prolonged periods of
stability.

[35] 𝐶𝑡,𝑦,𝑀𝐸𝐷424.𝑖=1
12 ∑𝐶𝑡−𝑗12𝑗=1

[35] Model notes:
1. Data starts January 2009. Excluding a January 2009 outlier, the customer count fluctuates between 1 and 3 without any clear trend or
seasonality. Customer count is most frequently reported as 2.

5. Roseburg, OR Forecasting Models
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 39 of 648
The forecasting models for the Roseburg region (Douglas County) are given below for the residential, commercial,
and industrial sectors:

Residential Sector, Customers:

[36] 𝐶𝑡,𝑦,𝑅𝑂𝑆410.𝑟= 𝜑0+𝜑1𝑃𝑂𝑃𝑡,𝑦,𝐷𝑂𝑈𝐺𝐿𝐴𝑆+ 𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑆𝐶𝐷𝐷𝑒𝑐 2004 =1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2004 =1 + 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2005 =1 +
𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2005 =1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2005 =1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2006 =1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2007 =1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2007 =1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2008 =1 +
𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2009 =1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015 =1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (11,1,0)(0,0,0)12

[36] Model notes:
1. POP is population for Douglas County, OR.
2. SC dummy controls for a step-up in customers starting in January 2004.

Commercial Sector, Customers:

[37] 𝐶𝑡,𝑦,𝑅𝑂𝑆420.𝑐= 𝜑0 + 𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑆𝐶𝐷𝐷𝑒𝑐 2004↑ =1 + 𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2004 =1 + 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2008 =1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2009=1 +
𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (12,1,0)(0,0,0)12

[37] Model notes:
1. Model does not use schedule 410 customers as driver. This reflects the lack of correlation between residential 410 and commercial 420
customer growth.
2. The lack of correlation noted in Point 1 could reflect Roseburg’s position between larger cities that offer a range of commercial activities.
Competition from these cities may be inhibiting commercial growth in Roseburg.
3. SC dummy controls for a significant step-up in customers starting in December 2004.

[38] 𝐶𝑡,𝑦,𝑅𝑂𝑆424.𝑐= 1
12∑𝐶𝑡−𝑗12𝑗=1

Industrial Sector, Customers:

[39] 𝐶𝑡,𝑦,𝑅𝑂𝑆420.𝑖= 1
12 ∑𝐶𝑡−𝑗12𝑗=1

[39] Model notes:
1. Due to the Compass software conversion, February 2015 is excluded from the historical data. The conversion resulted in a double counting
of customers in February 2015. Therefore, including this month leads to a significant over-forecast of customers.

[40] 𝐶𝑡,𝑦,𝑅𝑂𝑆424.𝑖= 1
12 ∑𝐶𝑡−𝑗12𝑗=1

[40] Model notes:
1. Schedule appears to have died. No customers are currently being reported.

6. Klamath Falls, OR Forecasting Models

The forecasting models for the Klamath Falls region (Klamath County) are given below for the residential,
commercial, and industrial sectors:
Residential Sector, Customers:

[41] 𝐶𝑡,𝑦,𝐾𝐿𝑀410.𝑟= 𝛽0 + 𝛽1𝑃𝑂𝑃𝑡,𝑦,𝐾𝐿𝐴𝑀𝐴𝑇𝐻+ 𝝎𝑺𝑫𝑫𝒕,𝒚 +𝜔𝑂𝐿𝐷𝑁𝑜𝑣 2004=1+ 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015 =1+ 𝜔𝑂𝐿𝐷𝐴𝑝𝑟 2015 =1 +
𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (7,1,0)(0,0,0)12

[41] Model notes:
1. POP is population for Klamath County.

Commercial Sector, Customers:

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 40 of 648
[42] 𝐶𝑡,𝑦,𝐾𝐿𝑀420.𝑐= 𝛽0 + 𝛽1𝐶𝑡,𝑦,𝐾𝐿𝑀410.𝑟+ 𝝎𝑺𝑫𝑫𝒕,𝒚 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2005=1 + 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2006=1 + 𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (11,1,0)(2,0,0)12

[42] Model notes:
1. Ct,y,KLM410.r are residential customers from residential schedule 410. They are being used as a forecast driver because of the historical positive
correlation between residential and commercial customer growth.

[43] 𝐶𝑡,𝑦,𝐾𝐿𝑀424.𝑐= 1
12 ∑𝐶𝑡−𝑗12𝑗=1

[43] Model notes:
1. Data starts January 2004. From January 2004 to March 2010, the customer count fluctuated between 19 and 24. Afterwards, the customer
count has dropped to fluctuate between 11 and 16. There is no clear trend or seasonality.

Industrial Sector, Customers:

[44] 𝐶𝑡,𝑦,𝐾𝐿𝑀420.𝑖= 1
12 ∑𝐶𝑡−𝑗12𝑗=1

[44] Model notes:
1. Data starts December 2006. The customer count fluctuates between 4 and 9 without any clear trend or seasonality.

[45] 𝐶𝑡,𝑦,𝐾𝐿𝑀424.𝑖= 1
12∑𝐶𝑡−𝑗12𝑗=1

[45] Model notes:
1. Data starts April 2009. The customer count fluctuates between 1 and 4 without any clear trend or seasonality.

7. La Grande, OR Forecasting Models

The forecasting models for the La Grande region (Union County) are given below for the residential, commercial,
and industrial sectors:
Residential Sector, Customers:

[46] 𝐶𝑡,𝑦,𝐿𝑎𝐺410.𝑟= 𝜃0 + 𝜃1𝑃𝑂𝑃𝑡,𝑦,𝑈𝑁𝐼𝑂𝑁+ 𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝜔𝑂𝐿𝐷𝑂𝑐𝑡 2004=1 + 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2009=1+ 𝜔𝑂𝐿𝐷𝐽𝑢𝑙 2006=1+ 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2015=1 +
𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (9,1,0)(1,0,0)12

[46] Model notes:
1. POP is population for Douglas County.

Commercial Sector, Customers:

[47] 𝐶𝑡,𝑦,𝐿𝑎𝐺420.𝑐= 𝜃0 + 𝜃1𝐶𝑡,𝑦,𝐿𝑎𝐺410.𝑟+ 𝜔𝑂𝐿𝐷𝐷𝑒𝑐 2008 =1 + 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2011 =1 +
𝐴𝑅𝐼𝑀𝐴𝜖𝑡,𝑦 (12,1,0)(0,0,0)12

[47] Model notes:
1. Ct,y,LaG410.r are residential customers from residential schedule 410. They are being used as a forecast driver because of the historical positive
correlation between residential and commercial customer growth.

[48] 𝐶𝑡,𝑦,𝐿𝑎𝐺424.𝑐= 1
12 ∑𝐶𝑡−𝑗12𝑗=1

[48] Model notes:
1. Data starts January 2007. The customer count fluctuates between 2 and 4 without any clear trend or seasonality. Changes in the customer
count appear as steps after prolonged periods of stability.

[49] 𝐶𝑡,𝑦,𝐿𝑎𝐺444.𝑐= 𝛼 𝑖𝑓 (𝑇𝐻𝑀/𝐶𝑡,𝑦)𝐿𝑎𝑔,444.𝑐> 0

[49] Model notes: Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 41 of 648
1. Data starts September 2011. The customer forecast is a derivative of the schedule’s load forecast.
2. α = the average historical customer count when THM/C > 0. The value of α is usually slighter greater than one.

Industrial Sector, Customers:
[50] 𝑪𝒕,𝒚,𝑳𝒂𝑮𝟒𝟒𝟒.𝒊= 𝜽𝟎 + 𝝎𝑺𝑫𝑫𝒕,𝒚+ 𝝎𝑶𝑳𝑫𝑨𝒖𝒈 𝟐𝟎𝟎𝟕=𝟏+ 𝝎𝑶𝑳𝑫𝑺𝒆𝒑𝒕 𝟐𝟎𝟎𝟖 =𝟏+ 𝝎𝑶𝑳𝑫𝑵𝒐𝒗 𝟐𝟎𝟎𝟗 =𝟏+ 𝝎𝑶𝑳𝑫𝑱𝒂𝒏 𝟐𝟎𝟏𝟎 =𝟏+
+ 𝝎𝑶𝑳𝑫𝑵𝒐𝒗 𝟐𝟎𝟏𝟎=𝟏+ 𝝎𝑶𝑳𝑫𝑨𝒖𝒈 𝟐𝟎𝟏𝟏 =𝟏+ 𝝎𝑶𝑳𝑫𝑨𝒖𝒈 𝟐𝟎𝟏𝟐 =𝟏+ 𝝎𝑶𝑳𝑫𝑵𝒐𝒗 𝟐𝟎𝟏𝟐 =𝟏+ 𝝎𝑶𝑳𝑫𝑫𝒆𝒄 𝟐𝟎𝟏𝟐=𝟏+ 𝝎𝑶𝑳𝑫𝑱𝒂𝒏 𝟐𝟎𝟏𝟑 =𝟏+
𝝎𝑶𝑳𝑫𝑭𝒆𝒃 𝟐𝟎𝟏𝟑 =𝟏+ 𝝎𝑶𝑳𝑫𝑱𝒂𝒏 𝟐𝟎𝟏𝟒 =𝟏+ 𝑨𝑹𝑰𝑴𝑨𝝐𝒕,𝒚 (𝟗,𝟎,𝟎)(𝟎,𝟎,𝟎)𝟏𝟐

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 42 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
WASHINGTON AND IDAHO

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Nov-15 210,786 22,852 231 210,786 22,852 231 210,786 22,852 231
Dec-15 211,651 23,321 227 211,651 23,321 227 211,651 23,321 227
Jan-16 211,372 22,931 235 211,963 22,995 235 210,732 22,861 235
Feb-16 211,351 22,981 236 212,027 23,055 236 210,620 22,901 236
Mar-16 211,222 22,941 235 211,982 23,024 235 210,400 22,852 235
Apr-16 211,153 22,944 235 211,997 23,037 236 210,240 22,845 235
May-16 211,150 22,917 235 212,079 23,019 236 210,146 22,808 235
Jun-16 210,930 22,920 236 211,942 23,031 236 209,836 22,801 235
Jul-16 211,207 22,924 236 212,301 23,044 236 210,025 22,796 235
Aug-16 211,369 22,923 236 212,544 23,052 236 210,099 22,785 235
Sep-16 211,864 22,915 236 213,122 23,052 236 210,504 22,768 235
Oct-16 212,439 22,922 236 213,783 23,068 236 210,989 22,765 235
Nov-16 213,174 22,992 236 214,604 23,148 236 211,632 22,826 235
Dec-16 213,881 23,065 236 215,396 23,230 237 212,246 22,889 235
Jan-17 214,171 23,085 236 215,770 23,259 237 212,446 22,899 235
Feb-17 214,131 23,135 236 215,812 23,318 237 212,319 22,939 235
Mar-17 214,043 23,108 236 215,805 23,300 237 212,144 22,903 235
Apr-17 213,929 23,106 236 215,772 23,307 237 211,944 22,891 235
May-17 213,886 23,085 236 215,810 23,294 237 211,814 22,861 235
Jun-17 213,657 23,074 236 215,661 23,292 237 211,500 22,841 235
Jul-17 213,893 23,063 236 215,985 23,290 237 211,642 22,820 235
Aug-17 214,062 23,055 236 216,242 23,291 237 211,718 22,802 235
Sep-17 214,541 23,063 236 216,812 23,309 237 212,101 22,800 235
Oct-17 215,132 23,075 236 217,495 23,330 237 212,592 22,802 235
Nov-17 215,893 23,141 236 218,351 23,406 237 213,252 22,858 235
Dec-17 216,618 23,240 236 219,171 23,516 238 213,876 22,946 235
Jan-18 216,950 23,256 236 219,595 23,541 238 214,112 22,952 235
Feb-18 216,923 23,303 236 219,655 23,598 238 213,993 22,988 235
Mar-18 216,857 23,279 236 219,675 23,583 238 213,835 22,954 235
Apr-18 216,755 23,263 236 219,658 23,577 238 213,642 22,929 235
May-18 216,715 23,236 236 219,705 23,559 238 213,510 22,892 235
Jun-18 216,492 23,235 236 219,566 23,567 238 213,199 22,881 235
Jul-18 216,718 23,229 236 219,884 23,570 238 213,328 22,865 235
Aug-18 216,885 23,228 236 220,142 23,579 238 213,399 22,854 235
Sep-18 217,360 23,238 236 220,713 23,599 238 213,774 22,854 235
Oct-18 217,954 23,244 236 221,404 23,614 238 214,263 22,850 235
Nov-18 218,721 23,308 236 222,273 23,689 238 214,924 22,903 235
Dec-18 219,455 23,395 236 223,109 23,787 238 215,551 22,979 235
Jan-19 219,797 23,408 237 223,546 23,809 239 215,793 22,981 234
Feb-19 219,780 23,456 237 223,619 23,868 239 215,682 23,018 234
Washington and Idaho -
High Growth
Washington and Idaho -
Low Growth
Washington and Idaho -
Expected Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 43 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
WASHINGTON AND IDAHO

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Mar-19 219,724 23,428 237 223,651 23,849 239 215,532 22,981 234
Apr-19 219,628 23,417 237 223,643 23,847 239 215,344 22,960 234
May-19 219,592 23,390 237 223,697 23,830 239 215,215 22,923 234
Jun-19 219,371 23,393 237 223,562 23,842 239 214,904 22,916 234
Jul-19 219,600 23,390 237 223,887 23,849 239 215,033 22,903 234
Aug-19 219,771 23,390 237 224,154 23,859 239 215,104 22,893 234
Sep-19 220,251 23,392 237 224,735 23,871 239 215,476 22,885 234
Oct-19 220,849 23,399 237 225,438 23,888 239 215,965 22,881 234
Nov-19 221,624 23,465 237 226,323 23,965 239 216,626 22,935 234
Dec-19 222,365 23,546 237 227,173 24,058 239 217,253 23,004 234
Jan-20 222,716 23,563 237 227,626 24,085 239 217,499 23,011 234
Feb-20 222,708 23,612 237 227,711 24,145 239 217,394 23,048 234
Mar-20 222,661 23,585 237 227,756 24,127 239 217,250 23,012 234
Apr-20 222,572 23,579 237 227,759 24,131 239 217,066 22,995 234
May-20 222,544 23,554 237 227,824 24,116 240 216,942 22,961 234
Jun-20 222,331 23,551 237 227,700 24,122 240 216,638 22,947 234
Jul-20 222,565 23,546 237 228,035 24,128 240 216,767 22,932 234
Aug-20 222,741 23,542 237 228,310 24,134 240 216,839 22,918 234
Sep-20 223,225 23,546 237 228,903 24,148 240 217,212 22,911 234
Oct-20 223,829 23,555 237 229,618 24,167 240 217,701 22,910 234
Nov-20 224,608 23,623 237 230,514 24,247 240 218,359 22,965 233
Dec-20 225,356 23,710 237 231,379 24,347 240 218,987 23,039 233
Jan-21 225,714 23,727 237 231,844 24,374 240 219,235 23,045 233
Feb-21 225,712 23,775 237 231,938 24,434 240 219,133 23,081 233
Mar-21 225,671 23,751 237 231,993 24,420 240 218,993 23,048 233
Apr-21 225,590 23,741 237 232,007 24,420 240 218,815 23,027 233
May-21 225,567 23,716 237 232,081 24,404 240 218,694 22,993 233
Jun-21 225,359 23,714 237 231,964 24,412 240 218,393 22,980 233
Jul-21 225,574 23,706 237 232,272 24,413 240 218,513 22,963 233
Aug-21 225,731 23,703 237 232,519 24,419 240 218,577 22,951 233
Sep-21 226,195 23,709 237 233,084 24,435 240 218,938 22,947 233
Oct-21 226,778 23,718 237 233,771 24,453 241 219,414 22,947 233
Nov-21 227,537 23,784 237 234,641 24,530 241 220,060 23,001 233
Dec-21 228,265 23,871 237 235,480 24,629 241 220,675 23,076 233
Jan-22 228,603 23,885 237 235,916 24,653 241 220,913 23,080 233
Feb-22 228,582 23,934 237 235,981 24,713 241 220,803 23,118 233
Mar-22 228,521 23,907 237 236,006 24,694 241 220,656 23,083 233
Apr-22 228,419 23,897 237 235,988 24,693 241 220,468 23,064 233
May-22 228,377 23,869 237 236,033 24,673 241 220,339 23,028 233
Jun-22 228,150 23,868 237 235,886 24,681 241 220,032 23,017 233
Washington and Idaho -
High Growth
Washington and Idaho -
Low Growth
Washington and Idaho -
Expected Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 44 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
WASHINGTON AND IDAHO

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Jul-22 228,362 23,864 237 236,190 24,686 241 220,149 23,004 232
Aug-22 228,515 23,862 237 236,434 24,693 241 220,210 22,993 232
Sep-22 228,978 23,867 237 237,000 24,707 241 220,570 22,989 232
Oct-22 229,558 23,873 237 237,686 24,723 241 221,042 22,986 232
Nov-22 230,315 23,940 237 238,556 24,801 241 221,684 23,041 232
Dec-22 231,041 24,023 237 239,396 24,896 241 222,295 23,112 232
Jan-23 231,378 24,040 237 239,831 24,923 241 222,531 23,119 232
Feb-23 231,353 24,088 237 239,892 24,982 241 222,420 23,156 232
Mar-23 231,289 24,060 237 239,913 24,962 241 222,272 23,120 232
Apr-23 231,186 24,051 237 239,893 24,961 242 222,086 23,103 232
May-23 231,141 24,024 237 239,933 24,943 242 221,955 23,067 232
Jun-23 230,911 24,024 237 239,782 24,952 242 221,647 23,058 232
Jul-23 231,122 24,017 237 240,085 24,953 242 221,764 23,043 232
Aug-23 231,272 24,016 237 240,326 24,961 242 221,824 23,033 232
Sep-23 231,732 24,018 237 240,889 24,972 242 222,180 23,026 232
Oct-23 232,309 24,026 237 241,574 24,989 242 222,648 23,025 232
Nov-23 233,064 24,092 237 242,445 25,067 242 223,287 23,079 232
Dec-23 233,787 24,178 237 243,282 25,165 242 223,893 23,153 232
Jan-24 234,120 24,193 237 243,715 25,190 242 224,126 23,158 232
Feb-24 234,093 24,243 237 243,773 25,251 242 224,015 23,197 231
Mar-24 234,027 24,214 237 243,790 25,229 242 223,867 23,161 231
Apr-24 233,920 24,205 237 243,765 25,229 242 223,679 23,143 231
May-24 233,873 24,179 237 243,802 25,211 242 223,549 23,109 231
Jun-24 233,642 24,177 237 243,647 25,218 242 223,242 23,099 231
Jul-24 233,851 24,171 237 243,950 25,220 242 223,357 23,084 231
Aug-24 234,001 24,169 237 244,192 25,227 242 223,416 23,073 231
Sep-24 234,460 24,173 237 244,757 25,240 242 223,770 23,068 231
Oct-24 235,037 24,181 237 245,444 25,257 243 224,236 23,067 231
Nov-24 235,792 24,247 237 246,319 25,335 243 224,872 23,122 231
Dec-24 236,514 24,332 237 247,159 25,433 243 225,474 23,194 231
Jan-25 236,847 24,349 237 247,593 25,460 243 225,706 23,201 231
Feb-25 236,820 24,397 237 247,651 25,519 243 225,595 23,238 231
Mar-25 236,753 24,369 237 247,668 25,498 243 225,447 23,203 231
Apr-25 236,646 24,360 237 247,642 25,498 243 225,260 23,185 231
May-25 236,600 24,333 237 247,681 25,478 243 225,131 23,151 231
Jun-25 236,367 24,331 237 247,523 25,485 243 224,824 23,140 231
Jul-25 236,571 24,324 237 247,819 25,487 243 224,936 23,125 231
Aug-25 236,715 24,323 237 248,053 25,494 243 224,992 23,116 230
Sep-25 237,168 24,327 237 248,611 25,507 243 225,342 23,111 230
Oct-25 237,740 24,335 237 249,293 25,524 243 225,804 23,111 230
Washington and Idaho -
High Growth
Washington and Idaho -
Low Growth
Washington and Idaho -
Expected Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 45 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
WASHINGTON AND IDAHO

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Nov-25 238,490 24,400 237 250,162 25,600 243 226,434 23,164 230
Dec-25 239,206 24,485 237 250,997 25,698 243 227,032 23,236 230
Jan-26 239,532 24,500 237 251,423 25,723 243 227,259 23,242 230
Feb-26 239,500 24,549 237 251,474 25,783 243 227,147 23,280 230
Mar-26 239,427 24,520 237 251,481 25,761 243 226,996 23,244 230
Apr-26 239,315 24,511 237 251,447 25,760 243 226,808 23,227 230
May-26 239,262 24,486 237 251,474 25,742 244 226,675 23,195 230
Jun-26 239,023 24,483 237 251,308 25,748 244 226,367 23,184 230
Jul-26 239,225 24,477 237 251,602 25,750 244 226,479 23,170 230
Aug-26 239,367 24,475 237 251,834 25,756 244 226,533 23,160 230
Sep-26 239,819 24,479 237 252,392 25,769 244 226,881 23,155 230
Oct-26 240,388 24,486 237 253,073 25,785 244 227,340 23,154 230
Nov-26 241,136 24,551 237 253,942 25,861 244 227,966 23,207 230
Dec-26 241,850 24,637 237 254,778 25,961 244 228,560 23,280 230
Jan-27 242,175 24,653 237 255,204 25,986 244 228,787 23,287 230
Feb-27 242,140 24,701 237 255,250 26,045 244 228,673 23,324 230
Mar-27 242,065 24,673 237 255,254 26,024 244 228,522 23,290 229
Apr-27 241,951 24,664 237 255,216 26,023 244 228,333 23,273 229
May-27 241,897 24,637 237 255,243 26,003 244 228,202 23,239 229
Jun-27 241,656 24,635 237 255,072 26,009 244 227,894 23,229 229
Jul-27 241,855 24,630 237 255,364 26,013 244 228,003 23,216 229
Aug-27 241,995 24,626 237 255,593 26,017 244 228,057 23,204 229
Sep-27 242,444 24,630 237 256,149 26,029 244 228,401 23,200 229
Oct-27 243,013 24,638 237 256,831 26,046 244 228,858 23,200 229
Nov-27 243,757 24,703 237 257,699 26,123 245 229,480 23,253 229
Dec-27 244,469 24,788 237 258,535 26,221 245 230,071 23,325 229
Jan-28 244,792 24,803 237 258,959 26,245 245 230,295 23,331 229
Feb-28 244,755 24,852 237 259,003 26,306 245 230,182 23,369 229
Mar-28 244,678 24,824 237 259,004 26,284 245 230,030 23,335 229
Apr-28 244,563 24,815 237 258,964 26,283 245 229,842 23,318 229
May-28 244,506 24,788 237 258,986 26,263 245 229,710 23,285 229
Jun-28 244,262 24,786 237 258,810 26,269 245 229,401 23,275 229
Jul-28 244,459 24,779 237 259,100 26,270 245 229,509 23,260 229
Aug-28 244,597 24,777 237 259,327 26,276 245 229,562 23,251 229
Sep-28 245,044 24,781 237 259,882 26,289 245 229,904 23,246 228
Oct-28 245,611 24,788 237 260,563 26,304 245 230,358 23,245 228
Nov-28 246,353 24,854 237 261,431 26,383 245 230,977 23,299 228
Dec-28 247,063 24,939 237 262,267 26,481 245 231,565 23,371 228
Jan-29 247,383 24,954 237 262,688 26,505 245 231,787 23,377 228
Feb-29 247,343 25,003 237 262,728 26,565 245 231,672 23,415 228
Washington and Idaho -
High Growth
Washington and Idaho -
Low Growth
Washington and Idaho -
Expected Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 46 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
WASHINGTON AND IDAHO

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Mar-29 247,265 24,975 237 262,725 26,544 245 231,521 23,381 228
Apr-29 247,146 24,965 237 262,681 26,542 245 231,332 23,364 228
May-29 247,086 24,938 237 262,699 26,521 245 231,198 23,331 228
Jun-29 246,841 24,935 237 262,520 26,526 246 230,891 23,320 228
Jul-29 247,036 24,930 237 262,808 26,529 246 230,998 23,308 228
Aug-29 247,170 24,928 237 263,030 26,535 246 231,048 23,298 228
Sep-29 247,615 24,932 237 263,583 26,547 246 231,388 23,294 228
Oct-29 248,178 24,938 237 264,261 26,562 246 231,839 23,292 228
Nov-29 248,918 25,004 237 265,129 26,640 246 232,455 23,347 228
Dec-29 249,625 25,088 237 265,964 26,738 246 233,038 23,417 228
Jan-30 249,942 25,104 237 266,382 26,763 246 233,258 23,425 228
Feb-30 249,900 25,152 237 266,418 26,822 246 233,143 23,462 228
Mar-30 249,819 25,124 237 266,411 26,800 246 232,991 23,428 228
Apr-30 249,697 25,114 237 266,362 26,798 246 232,801 23,411 227
May-30 249,635 25,087 237 266,376 26,777 246 232,668 23,378 227
Jun-30 249,387 25,086 237 266,193 26,784 246 232,361 23,370 227
Jul-30 249,579 25,078 237 266,476 26,784 246 232,466 23,355 227
Aug-30 249,713 25,076 237 266,697 26,789 246 232,516 23,345 227
Sep-30 250,153 25,079 237 267,246 26,801 246 232,852 23,341 227
Oct-30 250,713 25,087 237 267,922 26,817 246 233,300 23,341 227
Nov-30 251,450 25,152 237 268,788 26,894 246 233,913 23,394 227
Dec-30 252,154 25,238 237 269,621 26,994 247 234,493 23,466 227
Jan-31 252,469 25,252 237 270,038 27,017 247 234,711 23,472 227
Feb-31 252,425 25,301 237 270,069 27,077 247 234,596 23,510 227
Mar-31 252,340 25,273 237 270,058 27,055 247 234,443 23,477 227
Apr-31 252,216 25,263 237 270,004 27,053 247 234,254 23,460 227
May-31 252,151 25,236 237 270,014 27,032 247 234,119 23,427 227
Jun-31 251,899 25,233 237 269,824 27,037 247 233,811 23,417 227
Jul-31 252,091 25,228 237 270,109 27,039 247 233,916 23,405 227
Aug-31 252,225 25,225 237 270,331 27,044 247 233,966 23,395 227
Sep-31 252,666 25,229 237 270,883 27,056 247 234,302 23,391 227
Oct-31 253,226 25,236 237 271,562 27,072 247 234,748 23,390 226
Nov-31 253,963 25,300 237 272,431 27,148 247 235,358 23,442 226
Dec-31 254,667 25,385 237 273,267 27,247 247 235,936 23,514 226
Jan-32 254,983 25,402 237 273,686 27,273 247 236,155 23,522 226
Feb-32 254,938 25,448 237 273,717 27,331 247 236,038 23,557 226
Mar-32 254,854 25,422 237 273,706 27,311 247 235,887 23,526 226
Apr-32 254,730 25,411 237 273,653 27,307 247 235,698 23,508 226
May-32 254,665 25,384 237 273,663 27,286 247 235,564 23,476 226
Jun-32 254,414 25,383 237 273,474 27,293 248 235,258 23,468 226
Jul-32 254,606 25,375 237 273,758 27,292 248 235,363 23,453 226
Washington and Idaho -
High Growth
Washington and Idaho -
Low Growth
Washington and Idaho -
Expected Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 47 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
WASHINGTON AND IDAHO

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Aug-32 254,737 25,371 237 273,977 27,296 248 235,412 23,442 226
Sep-32 255,176 25,376 237 274,528 27,309 248 235,745 23,439 226
Oct-32 255,735 25,384 237 275,207 27,325 248 236,190 23,439 226
Nov-32 256,470 25,447 237 276,076 27,401 248 236,797 23,490 226
Dec-32 257,172 25,533 237 276,912 27,501 248 237,371 23,563 226
Jan-33 257,487 25,548 237 277,330 27,525 248 237,588 23,569 226
Feb-33 257,440 25,597 237 277,358 27,586 248 237,472 23,607 226
Mar-33 257,354 25,569 237 277,345 27,563 248 237,321 23,574 226
Apr-33 257,228 25,558 237 277,288 27,559 248 237,132 23,557 226
May-33 257,161 25,532 237 277,295 27,539 248 236,998 23,526 225
Jun-33 256,909 25,530 237 277,104 27,545 248 236,692 23,517 225
Jul-33 257,099 25,524 237 277,386 27,547 248 236,795 23,504 225
Aug-33 257,230 25,520 237 277,605 27,550 248 236,845 23,493 225
Sep-33 257,668 25,524 237 278,157 27,562 248 237,176 23,490 225
Oct-33 258,225 25,531 237 278,836 27,577 248 237,618 23,489 225
Nov-33 258,960 25,595 237 279,707 27,654 248 238,224 23,541 225
Dec-33 259,662 25,681 237 280,545 27,755 248 238,796 23,613 225
Jan-34 259,974 25,696 237 280,961 27,779 249 239,011 23,619 225
Feb-34 259,927 25,743 237 280,989 27,837 249 238,896 23,656 225
Mar-34 259,839 25,717 237 280,973 27,817 249 238,743 23,625 225
Apr-34 259,712 25,706 237 280,914 27,813 249 238,555 23,607 225
May-34 259,645 25,679 237 280,921 27,792 249 238,422 23,575 225
Jun-34 259,392 25,677 237 280,726 27,797 249 238,117 23,566 225
Jul-34 259,580 25,670 237 281,008 27,798 249 238,219 23,553 225
Aug-34 259,709 25,667 237 281,225 27,802 249 238,267 23,543 225
Sep-34 260,146 25,670 237 281,777 27,813 249 238,597 23,539 225
Oct-34 260,703 25,678 237 282,457 27,829 249 239,038 23,539 225
Nov-34 261,436 25,744 237 283,329 27,908 249 239,640 23,593 224
Dec-34 262,137 25,828 237 284,168 28,007 249 240,209 23,663 224
Jan-35 262,449 25,842 237 284,585 28,030 249 240,424 23,669 224
Feb-35 262,400 25,890 237 284,610 28,090 249 240,308 23,706 224
Mar-35 262,312 25,863 237 284,594 28,068 249 240,157 23,674 224
Apr-35 262,184 25,853 237 284,533 28,065 249 239,969 23,658 224
May-35 262,115 25,826 237 284,537 28,044 249 239,835 23,626 224
Jun-35 261,861 25,824 237 284,340 28,049 249 239,530 23,617 224
Jul-35 262,049 25,816 237 284,622 28,048 250 239,632 23,603 224
Aug-35 262,177 25,813 237 284,839 28,053 250 239,680 23,593 224
Sep-35 262,615 25,818 237 285,394 28,066 250 240,010 23,591 224
Oct-35 263,171 25,825 237 286,075 28,081 250 240,449 23,590 224
Nov-35 263,904 25,890 237 286,948 28,159 250 241,048 23,643 224
Dec-35 264,605 25,975 237 287,791 28,259 250 241,617 23,714 224
Washington and Idaho -
High Growth
Washington and Idaho -
Low Growth
Washington and Idaho -
Expected Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 48 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
MEDFORD

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Nov-15 52,922 6,658 15 52,922 6,658 15 52,922 6,658 15
Dec-15 53,276 6,675 15 53,276 6,675 15 53,276 6,675 15
Jan-16 53,448 6,720 16 53,632 6,743 16 53,247 6,695 16
Feb-16 53,447 6,748 16 53,658 6,775 16 53,218 6,719 16
Mar-16 53,523 6,747 16 53,761 6,777 16 53,265 6,714 16
Apr-16 53,613 6,725 16 53,877 6,758 16 53,325 6,688 16
May-16 53,668 6,739 16 53,959 6,776 17 53,351 6,699 16
Jun-16 53,657 6,737 16 53,975 6,777 17 53,312 6,694 16
Jul-16 53,552 6,717 16 53,895 6,760 17 53,180 6,670 16
Aug-16 53,460 6,709 16 53,827 6,755 16 53,061 6,659 16
Sep-16 53,356 6,686 16 53,748 6,735 17 52,931 6,633 16
Oct-16 53,517 6,689 16 53,936 6,741 17 53,063 6,632 16
Nov-16 53,818 6,725 16 54,265 6,781 17 53,334 6,664 16
Dec-16 54,124 6,774 16 54,599 6,833 17 53,609 6,710 16
Jan-17 54,379 6,796 16 54,882 6,859 17 53,834 6,728 16
Feb-17 54,432 6,825 16 54,962 6,891 17 53,859 6,753 16
Mar-17 54,533 6,819 16 55,090 6,889 17 53,931 6,744 16
Apr-17 54,648 6,817 16 55,232 6,889 17 54,016 6,738 16
May-17 54,660 6,812 16 55,271 6,888 17 54,000 6,730 16
Jun-17 54,586 6,801 16 55,222 6,880 17 53,899 6,715 16
Jul-17 54,432 6,784 16 55,093 6,866 17 53,719 6,695 16
Aug-17 54,288 6,771 16 54,973 6,856 17 53,549 6,679 16
Sep-17 54,194 6,752 16 54,904 6,840 17 53,428 6,657 16
Oct-17 54,367 6,761 16 55,106 6,853 17 53,571 6,662 16
Nov-17 54,705 6,804 16 55,475 6,900 17 53,875 6,701 16
Dec-17 55,072 6,854 16 55,874 6,954 17 54,208 6,747 16
Jan-18 55,382 6,885 16 56,216 6,989 17 54,485 6,773 16
Feb-18 55,467 6,917 16 56,329 7,024 17 54,540 6,801 16
Mar-18 55,580 6,914 16 56,471 7,025 17 54,622 6,795 16
Apr-18 55,668 6,904 16 56,587 7,018 17 54,680 6,781 16
May-18 55,639 6,902 16 56,585 7,019 17 54,623 6,776 16
Jun-18 55,527 6,890 16 56,498 7,011 17 54,485 6,761 16
Jul-18 55,338 6,868 16 56,333 6,992 17 54,270 6,736 16
Aug-18 55,184 6,855 16 56,204 6,982 17 54,091 6,719 16
Sep-18 55,103 6,836 16 56,148 6,966 17 53,983 6,697 16
Oct-18 55,307 6,845 16 56,383 6,978 17 54,154 6,702 16
Nov-18 55,693 6,890 16 56,805 7,028 17 54,503 6,743 16
Dec-18 56,104 6,944 16 57,251 7,086 17 54,876 6,792 16
Jan-19 56,440 6,974 16 57,622 7,120 17 55,176 6,818 16
Feb-19 56,532 7,007 16 57,744 7,157 17 55,236 6,846 16
Medford -
Expected Growth
Medford -
Low Growth
Medford -
High Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 49 of 648

APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
MEDFORD

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Mar-19 56,629 7,002 16 57,871 7,156 17 55,302 6,838 16
Apr-19 56,686 6,992 16 57,958 7,148 17 55,328 6,824 16
May-19 56,624 6,986 16 57,922 7,146 17 55,238 6,815 16
Jun-19 56,484 6,971 16 57,807 7,134 17 55,073 6,797 16
Jul-19 56,282 6,950 16 57,628 7,116 17 54,847 6,773 16
Aug-19 56,136 6,937 16 57,506 7,106 17 54,676 6,757 16
Sep-19 56,080 6,919 16 57,477 7,091 17 54,592 6,735 16
Oct-19 56,320 6,932 16 57,750 7,108 17 54,797 6,745 16
Nov-19 56,739 6,979 16 58,208 7,160 17 55,176 6,787 16
Dec-19 57,170 7,034 16 58,678 7,220 17 55,566 6,837 16
Jan-20 57,511 7,066 16 59,057 7,256 17 55,868 6,864 16
Feb-20 57,586 7,097 16 59,162 7,291 17 55,911 6,891 16
Mar-20 57,661 7,091 16 59,268 7,289 17 55,954 6,881 16
Apr-20 57,690 7,079 16 59,326 7,279 17 55,953 6,865 16
May-20 57,604 7,071 16 59,267 7,275 17 55,840 6,854 16
Jun-20 57,453 7,056 16 59,140 7,263 17 55,664 6,836 16
Jul-20 57,258 7,035 16 58,967 7,245 17 55,446 6,812 16
Aug-20 57,133 7,024 16 58,867 7,237 17 55,296 6,798 16
Sep-20 57,105 7,008 16 58,867 7,224 17 55,240 6,779 16
Oct-20 57,373 7,022 16 59,172 7,242 17 55,470 6,789 16
Nov-20 57,811 7,071 16 59,652 7,296 17 55,864 6,833 16
Dec-20 58,248 7,126 16 60,132 7,357 17 56,256 6,882 16
Jan-21 58,581 7,157 16 60,505 7,392 17 56,548 6,909 16
Feb-21 58,641 7,187 16 60,596 7,427 17 56,576 6,934 16
Mar-21 58,690 7,180 16 60,676 7,423 17 56,593 6,923 16
Apr-21 58,700 7,166 16 60,716 7,412 17 56,573 6,906 16
May-21 58,606 7,158 16 60,648 7,407 17 56,453 6,895 16
Jun-21 58,460 7,143 16 60,526 7,395 17 56,282 6,877 16
Jul-21 58,264 7,122 16 60,349 7,377 17 56,068 6,854 16
Aug-21 58,143 7,111 16 60,248 7,368 17 55,926 6,840 16
Sep-21 58,120 7,095 16 60,250 7,355 17 55,878 6,821 16
Oct-21 58,386 7,110 16 60,551 7,374 17 56,108 6,833 16
Nov-21 58,812 7,157 16 61,018 7,425 17 56,492 6,875 16
Dec-21 59,225 7,211 16 61,472 7,485 17 56,863 6,923 15
Jan-22 59,526 7,240 16 61,810 7,518 17 57,126 6,948 15
Feb-22 59,550 7,268 16 61,861 7,550 17 57,123 6,972 15
Mar-22 59,567 7,258 16 61,905 7,543 17 57,113 6,959 15
Apr-22 59,552 7,242 16 61,915 7,529 17 57,072 6,940 15
May-22 59,443 7,233 16 61,827 7,523 17 56,942 6,929 15
Jun-22 59,292 7,218 16 61,696 7,511 17 56,771 6,911 15
Medford -
Expected Growth
Medford -
Low Growth
Medford -
High Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 50 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
MEDFORD

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Jul-22 59,108 7,198 16 61,529 7,493 17 56,571 6,889 15
Aug-22 58,999 7,187 16 61,440 7,484 17 56,442 6,876 15
Sep-22 58,984 7,173 16 61,449 7,473 17 56,403 6,859 15
Oct-22 59,249 7,187 16 61,749 7,490 17 56,632 6,870 15
Nov-22 59,664 7,234 16 62,207 7,542 17 57,004 6,911 15
Dec-22 60,061 7,287 16 62,645 7,601 17 57,358 6,959 15
Jan-23 60,341 7,314 16 62,962 7,632 17 57,601 6,982 15
Feb-23 60,348 7,340 16 62,995 7,662 17 57,583 7,004 15
Mar-23 60,352 7,330 16 63,024 7,655 17 57,561 6,991 15
Apr-23 60,333 7,314 16 63,029 7,640 17 57,518 6,972 15
May-23 60,229 7,305 16 62,945 7,634 18 57,394 6,961 15
Jun-23 60,086 7,291 16 62,821 7,623 18 57,233 6,945 15
Jul-23 59,915 7,271 16 62,667 7,605 18 57,046 6,923 15
Aug-23 59,817 7,261 16 62,589 7,597 18 56,928 6,910 15
Sep-23 59,804 7,247 16 62,600 7,586 18 56,891 6,894 15
Oct-23 60,065 7,261 16 62,898 7,603 18 57,115 6,904 15
Nov-23 60,471 7,307 16 63,348 7,655 18 57,477 6,945 15
Dec-23 60,855 7,359 16 63,775 7,712 18 57,817 6,992 15
Jan-24 61,124 7,386 16 64,082 7,743 18 58,048 7,014 15
Feb-24 61,124 7,411 16 64,107 7,773 18 58,023 7,035 15
Mar-24 61,129 7,401 16 64,138 7,765 18 58,003 7,022 15
Apr-24 61,116 7,385 16 64,149 7,751 18 57,965 7,004 15
May-24 61,022 7,377 16 64,076 7,746 18 57,851 6,994 15
Jun-24 60,890 7,364 16 63,962 7,736 18 57,702 6,978 15
Jul-24 60,728 7,345 16 63,817 7,719 18 57,523 6,957 15
Aug-24 60,634 7,335 16 63,743 7,711 18 57,410 6,945 15
Sep-24 60,619 7,321 16 63,752 7,699 18 57,371 6,929 15
Oct-24 60,873 7,334 16 64,045 7,716 18 57,587 6,938 15
Nov-24 61,270 7,380 16 64,487 7,768 18 57,938 6,979 15
Dec-24 61,646 7,431 16 64,909 7,824 18 58,268 7,024 15
Jan-25 61,911 7,458 16 65,213 7,856 18 58,494 7,046 15
Feb-25 61,912 7,483 16 65,240 7,885 18 58,470 7,067 15
Mar-25 61,922 7,473 16 65,276 7,878 18 58,454 7,054 15
Apr-25 61,919 7,458 16 65,298 7,865 18 58,426 7,037 15
May-25 61,834 7,451 16 65,234 7,861 18 58,321 7,028 15
Jun-25 61,710 7,438 16 65,129 7,850 18 58,179 7,012 15
Jul-25 61,550 7,419 16 64,985 7,833 18 58,004 6,992 15
Aug-25 61,453 7,409 16 64,908 7,826 18 57,888 6,979 15
Sep-25 61,432 7,394 16 64,911 7,813 18 57,844 6,962 15
Oct-25 61,677 7,407 16 65,195 7,829 18 58,050 6,971 15
Medford -
Expected Growth
Medford -
Low Growth
Medford -
High Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 51 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
MEDFORD

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Nov-25 62,066 7,453 16 65,631 7,881 18 58,392 7,012 15
Dec-25 62,436 7,503 16 66,048 7,937 18 58,715 7,056 15
Jan-26 62,700 7,530 16 66,353 7,969 18 58,939 7,078 15
Feb-26 62,704 7,556 16 66,382 7,999 18 58,918 7,100 15
Mar-26 62,720 7,546 16 66,425 7,992 18 58,908 7,087 15
Apr-26 62,723 7,531 16 66,454 7,978 18 58,886 7,070 15
May-26 62,643 7,524 16 66,394 7,975 18 58,786 7,061 15
Jun-26 62,520 7,511 16 66,290 7,964 18 58,646 7,046 15
Jul-26 62,358 7,492 16 66,143 7,947 18 58,470 7,025 15
Aug-26 62,255 7,482 16 66,059 7,939 18 58,349 7,013 15
Sep-26 62,227 7,467 16 66,054 7,926 18 58,299 6,996 15
Oct-26 62,466 7,479 16 66,333 7,942 18 58,499 7,004 15
Nov-26 62,849 7,524 16 66,765 7,993 18 58,833 7,043 15
Dec-26 63,219 7,575 16 67,183 8,050 18 59,155 7,088 15
Jan-27 63,484 7,601 16 67,490 8,081 18 59,379 7,109 15
Feb-27 63,492 7,628 16 67,524 8,112 18 59,361 7,132 15
Mar-27 63,513 7,618 16 67,572 8,105 18 59,357 7,119 15
Apr-27 63,519 7,604 16 67,604 8,092 18 59,338 7,103 15
May-27 63,440 7,597 16 67,545 8,089 18 59,239 7,094 15
Jun-27 63,316 7,584 16 67,439 8,078 18 59,099 7,079 15
Jul-27 63,148 7,564 16 67,285 8,059 18 58,919 7,057 15
Aug-27 63,038 7,554 16 67,192 8,052 18 58,793 7,045 15
Sep-27 63,003 7,538 16 67,179 8,038 18 58,736 7,028 15
Oct-27 63,237 7,550 16 67,454 8,053 18 58,931 7,036 15
Nov-27 63,618 7,595 16 67,885 8,104 18 59,262 7,075 15
Dec-27 63,987 7,646 16 68,304 8,162 18 59,582 7,120 15
Jan-28 64,255 7,672 16 68,615 8,193 18 59,808 7,141 15
Feb-28 64,265 7,699 16 68,651 8,224 18 59,793 7,163 15
Mar-28 64,288 7,690 16 68,701 8,218 18 59,790 7,152 15
Apr-28 64,294 7,675 16 68,733 8,204 18 59,772 7,135 15
May-28 64,212 7,668 16 68,670 8,200 18 59,672 7,126 15
Jun-28 64,083 7,655 16 68,557 8,189 18 59,528 7,111 15
Jul-28 63,908 7,635 16 68,394 8,171 18 59,343 7,090 15
Aug-28 63,792 7,624 16 68,294 8,162 18 59,212 7,077 14
Sep-28 63,752 7,607 16 68,276 8,147 18 59,152 7,058 14
Oct-28 63,982 7,619 16 68,546 8,163 18 59,342 7,067 14
Nov-28 64,362 7,664 16 68,978 8,214 18 59,672 7,106 14
Dec-28 64,731 7,715 16 69,398 8,271 18 59,991 7,150 14
Jan-29 65,000 7,741 16 69,711 8,302 18 60,217 7,171 14
Feb-29 65,010 7,768 16 69,747 8,334 18 60,203 7,194 14
Medford -
Expected Growth
Medford -
Low Growth
Medford -
High Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 52 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
MEDFORD

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Mar-29 65,031 7,758 16 69,794 8,326 18 60,199 7,182 14
Apr-29 65,034 7,744 16 69,822 8,314 18 60,178 7,165 14
May-29 64,948 7,736 16 69,754 8,308 18 60,076 7,156 14
Jun-29 64,813 7,723 16 69,634 8,297 18 59,927 7,141 14
Jul-29 64,633 7,702 16 69,464 8,278 18 59,739 7,119 14
Aug-29 64,512 7,691 16 69,358 8,269 18 59,604 7,106 14
Sep-29 64,469 7,675 16 69,336 8,254 18 59,542 7,088 14
Oct-29 64,699 7,687 16 69,607 8,270 18 59,732 7,097 14
Nov-29 65,079 7,731 16 70,040 8,320 18 60,061 7,135 14
Dec-29 65,450 7,782 16 70,463 8,378 18 60,380 7,179 14
Jan-30 65,718 7,809 16 70,776 8,410 19 60,605 7,201 14
Feb-30 65,728 7,835 16 70,811 8,441 19 60,591 7,223 14
Mar-30 65,747 7,826 16 70,856 8,434 19 60,586 7,212 14
Apr-30 65,746 7,811 16 70,880 8,420 19 60,562 7,195 14
May-30 65,655 7,803 16 70,806 8,415 19 60,456 7,185 14
Jun-30 65,515 7,789 16 70,679 8,403 19 60,304 7,169 14
Jul-30 65,331 7,768 16 70,504 8,383 19 60,113 7,148 14
Aug-30 65,206 7,757 16 70,392 8,374 19 59,977 7,135 14
Sep-30 65,161 7,740 16 70,367 8,358 19 59,914 7,117 14
Oct-30 65,389 7,752 16 70,636 8,374 19 60,102 7,125 14
Nov-30 65,768 7,796 16 71,069 8,424 19 60,428 7,163 14
Dec-30 66,137 7,847 16 71,492 8,482 19 60,745 7,207 14
Jan-31 66,404 7,874 16 71,804 8,514 19 60,969 7,230 14
Feb-31 66,410 7,900 16 71,834 8,545 19 60,952 7,251 14
Mar-31 66,425 7,890 16 71,874 8,537 19 60,944 7,239 14
Apr-31 66,419 7,875 16 71,891 8,523 19 60,917 7,222 14
May-31 66,322 7,867 16 71,810 8,518 19 60,806 7,213 14
Jun-31 66,177 7,852 16 71,676 8,505 19 60,651 7,196 14
Jul-31 65,990 7,831 16 71,497 8,484 19 60,459 7,175 14
Aug-31 65,863 7,820 16 71,382 8,475 19 60,322 7,162 14
Sep-31 65,816 7,803 16 71,353 8,459 19 60,258 7,144 14
Oct-31 66,043 7,815 16 71,622 8,475 19 60,445 7,153 14
Nov-31 66,421 7,859 16 72,055 8,526 19 60,770 7,190 14
Dec-31 66,788 7,910 16 72,476 8,584 19 61,084 7,234 14
Jan-32 67,052 7,936 16 72,786 8,615 19 61,304 7,256 14
Feb-32 67,054 7,962 16 72,811 8,646 19 61,285 7,277 14
Mar-32 67,064 7,952 16 72,845 8,637 19 61,273 7,265 14
Apr-32 67,053 7,936 16 72,856 8,622 19 61,242 7,248 14
May-32 66,953 7,928 16 72,770 8,617 19 61,129 7,238 14
Jun-32 66,805 7,913 16 72,633 8,603 19 60,973 7,222 14
Jul-32 66,615 7,892 16 72,448 8,583 19 60,779 7,201 14
Medford -
Expected Growth
Medford -
Low Growth
Medford -
High Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 53 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
MEDFORD

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Aug-32 66,487 7,881 16 72,331 8,574 19 60,642 7,188 14
Sep-32 66,439 7,864 16 72,301 8,558 19 60,578 7,170 14
Oct-32 66,665 7,875 16 72,569 8,572 19 60,764 7,178 14
Nov-32 67,041 7,920 16 73,001 8,624 19 61,086 7,217 14
Dec-32 67,406 7,970 16 73,421 8,681 19 61,398 7,260 14
Jan-33 67,667 7,996 16 73,728 8,712 19 61,615 7,281 14
Feb-33 67,666 8,022 16 73,749 8,743 19 61,594 7,302 14
Mar-33 67,672 8,012 16 73,778 8,735 19 61,579 7,291 14
Apr-33 67,658 7,996 16 73,786 8,720 19 61,545 7,273 14
May-33 67,554 7,987 16 73,695 8,713 19 61,430 7,263 14
Jun-33 67,404 7,972 16 73,554 8,699 19 61,273 7,247 14
Jul-33 67,213 7,951 16 73,367 8,679 19 61,080 7,225 14
Aug-33 67,084 7,940 16 73,248 8,670 19 60,943 7,213 14
Sep-33 67,035 7,923 16 73,216 8,654 19 60,879 7,195 14
Oct-33 67,259 7,934 16 73,483 8,668 19 61,062 7,203 14
Nov-33 67,634 7,978 16 73,915 8,719 19 61,383 7,241 14
Dec-33 67,996 8,029 16 74,332 8,777 19 61,692 7,285 14
Jan-34 68,253 8,054 16 74,635 8,807 19 61,905 7,305 14
Feb-34 68,249 8,080 16 74,653 8,838 19 61,881 7,326 14
Mar-34 68,252 8,069 16 74,679 8,829 19 61,864 7,314 14
Apr-34 68,235 8,054 16 74,682 8,814 19 61,828 7,297 14
May-34 68,130 8,045 16 74,589 8,808 19 61,713 7,287 14
Jun-34 67,978 8,030 16 74,445 8,794 19 61,555 7,271 14
Jul-34 67,786 8,009 16 74,256 8,773 19 61,362 7,250 14
Aug-34 67,655 7,997 16 74,134 8,763 19 61,225 7,237 14
Sep-34 67,605 7,980 16 74,100 8,747 19 61,160 7,219 14
Oct-34 67,827 7,991 16 74,365 8,761 19 61,342 7,227 14
Nov-34 68,199 8,035 16 74,795 8,812 19 61,659 7,264 14
Dec-34 68,558 8,085 16 75,210 8,869 19 61,964 7,307 14
Jan-35 68,813 8,111 16 75,511 8,901 19 62,175 7,329 14
Feb-35 68,806 8,136 16 75,525 8,931 19 62,149 7,349 14
Mar-35 68,806 8,125 16 75,547 8,921 19 62,130 7,337 14
Apr-35 68,788 8,109 16 75,549 8,905 19 62,094 7,319 13
May-35 68,680 8,101 16 75,452 8,900 19 61,977 7,310 13
Jun-35 68,527 8,085 16 75,306 8,885 19 61,820 7,294 13
Jul-35 68,335 8,064 16 75,116 8,864 19 61,627 7,272 13
Aug-35 68,205 8,053 16 74,994 8,855 19 61,491 7,260 13
Sep-35 68,154 8,035 16 74,959 8,837 19 61,426 7,242 13
Oct-35 68,375 8,047 16 75,224 8,853 19 61,606 7,250 13
Nov-35 68,746 8,091 16 75,653 8,904 19 61,921 7,288 13
Dec-35 69,104 8,141 16 76,069 8,962 19 62,225 7,331 13
Medford -
Expected Growth
Medford -
Low Growth
Medford -
High Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 54 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
ROSEBURG

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Nov-15 13,361 2,132 2 13,361 2,132 2 13,361 2,132 2
Dec-15 13,503 2,159 2 13,503 2,159 2 13,503 2,159 2
Jan-16 13,582 2,157 2 13,603 2,161 2 13,565 2,154 2
Feb-16 13,555 2,163 2 13,579 2,167 2 13,536 2,160 2
Mar-16 13,559 2,173 2 13,586 2,178 2 13,537 2,170 2
Apr-16 13,544 2,154 2 13,574 2,159 2 13,520 2,150 2
May-16 13,515 2,154 2 13,548 2,159 2 13,488 2,150 2
Jun-16 13,445 2,146 2 13,481 2,152 2 13,416 2,142 2
Jul-16 13,386 2,141 2 13,425 2,147 2 13,355 2,136 2
Aug-16 13,333 2,130 2 13,376 2,137 2 13,299 2,125 2
Sep-16 13,329 2,130 2 13,375 2,138 2 13,292 2,124 2
Oct-16 13,422 2,135 2 13,472 2,143 2 13,382 2,129 2
Nov-16 13,579 2,144 2 13,633 2,153 2 13,536 2,137 2
Dec-16 13,693 2,162 2 13,751 2,171 2 13,647 2,155 2
Jan-17 13,726 2,162 2 13,788 2,172 2 13,677 2,154 2
Feb-17 13,707 2,166 2 13,772 2,176 2 13,655 2,158 2
Mar-17 13,705 2,176 2 13,774 2,187 2 13,650 2,167 2
Apr-17 13,698 2,162 2 13,770 2,174 2 13,641 2,153 2
May-17 13,657 2,159 2 13,732 2,171 2 13,597 2,150 2
Jun-17 13,588 2,155 2 13,666 2,168 2 13,525 2,145 2
Jul-17 13,533 2,145 2 13,615 2,158 2 13,468 2,135 2
Aug-17 13,464 2,138 2 13,550 2,152 2 13,396 2,127 2
Sep-17 13,471 2,138 2 13,560 2,152 2 13,400 2,127 2
Oct-17 13,565 2,137 2 13,659 2,152 2 13,490 2,125 2
Nov-17 13,712 2,152 2 13,811 2,168 2 13,633 2,140 2
Dec-17 13,840 2,167 2 13,944 2,183 2 13,757 2,154 2
Jan-18 13,874 2,164 2 13,982 2,181 2 13,788 2,151 2
Feb-18 13,859 2,171 2 13,971 2,189 2 13,770 2,157 2
Mar-18 13,861 2,178 2 13,977 2,196 2 13,769 2,164 2
Apr-18 13,848 2,166 2 13,968 2,185 2 13,753 2,151 2
May-18 13,814 2,163 2 13,938 2,183 2 13,716 2,148 2
Jun-18 13,741 2,158 2 13,868 2,178 2 13,640 2,142 2
Jul-18 13,682 2,151 2 13,813 2,172 2 13,578 2,135 2
Aug-18 13,620 2,141 2 13,754 2,162 2 13,513 2,124 2
Sep-18 13,623 2,144 2 13,761 2,166 2 13,513 2,127 2
Oct-18 13,715 2,143 2 13,858 2,166 2 13,601 2,125 2
Nov-18 13,865 2,155 2 14,014 2,178 2 13,746 2,137 2
Dec-18 13,992 2,173 2 14,147 2,197 2 13,869 2,154 2
Jan-19 14,030 2,169 2 14,190 2,194 2 13,903 2,150 2
Feb-19 14,016 2,176 2 14,180 2,202 2 13,886 2,156 2
Roseburg -
Expected Growth
Roseburg -
Low Growth
Roseburg -
High Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 55 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
ROSEBURG

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Mar-19 14,017 2,184 2 14,185 2,210 2 13,884 2,163 2
Apr-19 14,008 2,170 2 14,180 2,197 2 13,872 2,149 2
May-19 13,970 2,168 2 14,146 2,195 2 13,831 2,147 2
Jun-19 13,898 2,163 2 14,077 2,191 2 13,756 2,141 2
Jul-19 13,842 2,155 2 14,025 2,184 2 13,697 2,133 2
Aug-19 13,777 2,147 2 13,963 2,176 2 13,629 2,124 2
Sep-19 13,781 2,147 2 13,972 2,177 2 13,630 2,124 2
Oct-19 13,873 2,148 2 14,069 2,179 2 13,717 2,124 2
Nov-19 14,023 2,160 2 14,226 2,191 2 13,862 2,135 2
Dec-19 14,153 2,177 2 14,362 2,209 2 13,987 2,152 2
Jan-20 14,190 2,174 2 14,405 2,207 2 14,020 2,148 2
Feb-20 14,177 2,180 2 14,396 2,214 2 14,004 2,154 2
Mar-20 14,180 2,189 2 14,403 2,224 2 14,003 2,162 2
Apr-20 14,169 2,175 2 14,397 2,210 2 13,989 2,148 2
May-20 14,133 2,173 2 14,365 2,209 2 13,950 2,145 2
Jun-20 14,062 2,168 2 14,297 2,204 2 13,876 2,140 2
Jul-20 14,005 2,160 2 14,244 2,197 2 13,816 2,131 2
Aug-20 13,941 2,151 2 14,183 2,189 2 13,750 2,122 2
Sep-20 13,945 2,152 2 14,192 2,190 2 13,750 2,122 2
Oct-20 14,037 2,152 2 14,290 2,191 2 13,837 2,122 2
Nov-20 14,188 2,165 2 14,449 2,205 2 13,982 2,134 2
Dec-20 14,318 2,182 2 14,586 2,223 2 14,107 2,150 2
Jan-21 14,357 2,179 2 14,630 2,221 2 14,141 2,146 2
Feb-21 14,344 2,185 2 14,622 2,228 2 14,125 2,152 2
Mar-21 14,347 2,193 2 14,630 2,236 2 14,124 2,159 2
Apr-21 14,337 2,180 2 14,624 2,224 2 14,110 2,146 2
May-21 14,301 2,177 2 14,592 2,222 2 14,071 2,142 2
Jun-21 14,230 2,172 2 14,525 2,217 2 13,998 2,137 2
Jul-21 14,174 2,165 2 14,472 2,211 2 13,939 2,129 2
Aug-21 14,110 2,156 2 14,412 2,202 2 13,872 2,120 2
Sep-21 14,113 2,157 2 14,420 2,204 2 13,872 2,120 2
Oct-21 14,206 2,157 2 14,519 2,205 2 13,959 2,120 2
Nov-21 14,357 2,170 2 14,679 2,219 2 14,104 2,132 2
Dec-21 14,487 2,187 2 14,816 2,237 2 14,228 2,148 2
Jan-22 14,526 2,183 2 14,861 2,234 2 14,263 2,144 2
Feb-22 14,514 2,190 2 14,854 2,241 2 14,247 2,150 2
Mar-22 14,516 2,198 2 14,861 2,250 2 14,245 2,157 2
Apr-22 14,507 2,184 2 14,856 2,237 2 14,233 2,143 2
May-22 14,471 2,182 2 14,825 2,235 2 14,193 2,140 2
Jun-22 14,400 2,177 2 14,757 2,231 2 14,120 2,135 2
Roseburg -
Expected Growth
Roseburg -
Low Growth
Roseburg -
High Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 56 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
ROSEBURG

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Jul-22 14,344 2,169 2 14,704 2,224 2 14,061 2,126 2
Aug-22 14,280 2,161 2 14,643 2,216 2 13,995 2,118 2
Sep-22 14,284 2,162 2 14,652 2,218 2 13,995 2,118 2
Oct-22 14,377 2,162 2 14,753 2,219 2 14,082 2,118 2
Nov-22 14,528 2,174 2 14,913 2,232 2 14,227 2,129 2
Dec-22 14,658 2,191 2 15,051 2,250 2 14,350 2,145 2
Jan-23 14,698 2,188 2 15,097 2,248 2 14,385 2,142 2
Feb-23 14,685 2,195 2 15,089 2,256 2 14,369 2,148 2
Mar-23 14,688 2,203 2 15,097 2,265 2 14,368 2,155 2
Apr-23 14,679 2,189 2 15,093 2,251 2 14,355 2,141 2
May-23 14,643 2,187 2 15,061 2,250 2 14,316 2,138 2
Jun-23 14,573 2,182 2 14,994 2,245 2 14,244 2,133 2
Jul-23 14,516 2,174 2 14,940 2,238 2 14,184 2,125 2
Aug-23 14,452 2,165 2 14,879 2,229 2 14,118 2,115 2
Sep-23 14,456 2,166 2 14,888 2,231 2 14,119 2,116 2
Oct-23 14,548 2,167 2 14,987 2,233 2 14,205 2,116 2
Nov-23 14,699 2,179 2 15,148 2,246 2 14,348 2,127 2
Dec-23 14,829 2,196 2 15,287 2,264 2 14,472 2,143 2
Jan-24 14,868 2,193 2 15,332 2,262 2 14,506 2,140 2
Feb-24 14,856 2,200 2 15,324 2,270 2 14,490 2,146 2
Mar-24 14,858 2,208 2 15,331 2,279 2 14,489 2,153 2
Apr-24 14,849 2,194 2 15,327 2,265 2 14,476 2,139 2
May-24 14,813 2,192 2 15,295 2,263 2 14,437 2,137 2
Jun-24 14,742 2,186 2 15,226 2,258 2 14,364 2,130 2
Jul-24 14,685 2,179 2 15,172 2,251 2 14,305 2,123 2
Aug-24 14,621 2,170 2 15,111 2,243 2 14,239 2,114 2
Sep-24 14,624 2,171 2 15,119 2,245 2 14,239 2,114 2
Oct-24 14,716 2,171 2 15,218 2,245 2 14,325 2,113 2
Nov-24 14,867 2,184 2 15,379 2,259 2 14,468 2,126 2
Dec-24 14,996 2,201 2 15,518 2,278 2 14,590 2,142 2
Jan-25 15,035 2,198 2 15,563 2,275 2 14,625 2,138 2
Feb-25 15,022 2,204 2 15,554 2,282 2 14,608 2,143 2
Mar-25 15,024 2,212 2 15,561 2,291 2 14,607 2,151 2
Apr-25 15,015 2,199 2 15,556 2,278 2 14,594 2,138 2
May-25 14,978 2,196 2 15,523 2,276 2 14,555 2,134 2
Jun-25 14,907 2,191 2 15,454 2,272 2 14,482 2,129 2
Jul-25 14,850 2,184 2 15,399 2,265 2 14,423 2,121 2
Aug-25 14,785 2,175 2 15,337 2,256 2 14,357 2,112 2
Sep-25 14,788 2,176 2 15,344 2,258 2 14,356 2,113 2
Oct-25 14,880 2,176 2 15,444 2,259 2 14,442 2,112 2
Roseburg -
Expected Growth
Roseburg -
Low Growth
Roseburg -
High Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 57 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
ROSEBURG

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Nov-25 15,030 2,189 2 15,605 2,273 2 14,584 2,124 2
Dec-25 15,160 2,206 2 15,744 2,291 3 14,707 2,140 2
Jan-26 15,198 2,202 2 15,789 2,288 3 14,740 2,136 1
Feb-26 15,185 2,209 2 15,780 2,296 3 14,724 2,142 1
Mar-26 15,187 2,217 2 15,786 2,305 3 14,722 2,149 1
Apr-26 15,177 2,203 2 15,781 2,291 3 14,709 2,135 1
May-26 15,140 2,201 2 15,747 2,289 3 14,670 2,133 1
Jun-26 15,069 2,196 2 15,678 2,285 3 14,598 2,127 1
Jul-26 15,012 2,188 2 15,623 2,277 3 14,539 2,119 1
Aug-26 14,948 2,180 2 15,561 2,270 3 14,473 2,111 1
Sep-26 14,951 2,181 2 15,569 2,271 3 14,473 2,111 1
Oct-26 15,044 2,181 2 15,671 2,272 3 14,559 2,111 1
Nov-26 15,194 2,193 2 15,832 2,285 3 14,701 2,122 1
Dec-26 15,324 2,210 2 15,973 2,304 3 14,823 2,138 1
Jan-27 15,363 2,207 2 16,018 2,301 3 14,857 2,134 1
Feb-27 15,350 2,214 2 16,009 2,309 3 14,841 2,141 1
Mar-27 15,353 2,222 2 16,018 2,318 3 14,840 2,148 1
Apr-27 15,343 2,208 2 16,012 2,304 3 14,826 2,134 1
May-27 15,307 2,206 2 15,979 2,303 3 14,788 2,131 1
Jun-27 15,235 2,201 2 15,909 2,299 3 14,715 2,126 1
Jul-27 15,179 2,193 2 15,855 2,291 3 14,657 2,118 1
Aug-27 15,114 2,184 2 15,792 2,282 3 14,591 2,109 1
Sep-27 15,117 2,185 2 15,800 2,284 3 14,590 2,109 1
Oct-27 15,210 2,186 2 15,902 2,286 3 14,676 2,109 1
Nov-27 15,360 2,198 2 16,064 2,299 3 14,818 2,121 1
Dec-27 15,490 2,215 2 16,205 2,317 3 14,939 2,136 1
Jan-28 15,529 2,212 2 16,251 2,315 3 14,973 2,133 1
Feb-28 15,516 2,218 2 16,242 2,322 3 14,957 2,138 1
Mar-28 15,518 2,226 2 16,249 2,331 3 14,955 2,145 1
Apr-28 15,508 2,213 2 16,243 2,318 3 14,942 2,132 1
May-28 15,472 2,211 2 16,210 2,317 3 14,904 2,130 1
Jun-28 15,401 2,205 2 16,141 2,311 3 14,832 2,124 1
Jul-28 15,344 2,198 2 16,086 2,304 3 14,773 2,116 1
Aug-28 15,279 2,189 2 16,022 2,296 3 14,707 2,107 1
Sep-28 15,282 2,190 2 16,030 2,297 3 14,707 2,108 1
Oct-28 15,374 2,190 2 16,131 2,298 3 14,792 2,107 1
Nov-28 15,524 2,203 2 16,294 2,312 3 14,933 2,119 1
Dec-28 15,654 2,220 2 16,435 2,331 3 15,054 2,135 1
Jan-29 15,692 2,216 2 16,480 2,327 3 15,087 2,131 1
Feb-29 15,679 2,223 2 16,471 2,335 3 15,071 2,137 1
Roseburg -
Expected Growth
Roseburg -
Low Growth
Roseburg -
High Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 58 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
ROSEBURG

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Mar-29 15,681 2,231 2 16,478 2,345 3 15,070 2,144 1
Apr-29 15,671 2,217 2 16,472 2,330 3 15,057 2,130 1
May-29 15,635 2,215 2 16,439 2,329 3 15,019 2,128 1
Jun-29 15,563 2,210 2 16,368 2,324 3 14,946 2,123 1
Jul-29 15,506 2,203 2 16,312 2,318 3 14,888 2,115 1
Aug-29 15,441 2,194 2 16,249 2,309 3 14,822 2,106 1
Sep-29 15,443 2,195 2 16,255 2,311 3 14,821 2,107 1
Oct-29 15,535 2,195 2 16,357 2,311 3 14,906 2,106 1
Nov-29 15,685 2,208 2 16,519 2,326 3 15,046 2,118 1
Dec-29 15,814 2,224 2 16,660 2,343 3 15,167 2,133 1
Jan-30 15,852 2,221 2 16,704 2,341 3 15,200 2,130 1
Feb-30 15,838 2,228 2 16,694 2,349 3 15,183 2,136 1
Mar-30 15,840 2,236 2 16,701 2,358 3 15,181 2,143 1
Apr-30 15,830 2,222 2 16,695 2,344 3 15,168 2,129 1
May-30 15,793 2,220 2 16,661 2,342 3 15,130 2,127 1
Jun-30 15,721 2,215 2 16,589 2,338 3 15,057 2,122 1
Jul-30 15,663 2,207 2 16,532 2,330 3 14,999 2,114 1
Aug-30 15,596 2,198 2 16,465 2,321 3 14,932 2,105 1
Sep-30 15,598 2,200 2 16,471 2,323 3 14,931 2,106 1
Oct-30 15,688 2,200 2 16,570 2,324 3 15,014 2,106 1
Nov-30 15,837 2,212 2 16,732 2,337 3 15,154 2,117 1
Dec-30 15,965 2,229 2 16,871 2,356 3 15,273 2,133 1
Jan-31 16,002 2,226 2 16,914 2,353 3 15,306 2,129 1
Feb-31 15,987 2,233 2 16,903 2,361 3 15,288 2,136 1
Mar-31 15,988 2,241 2 16,908 2,370 3 15,286 2,143 1
Apr-31 15,976 2,227 2 16,899 2,356 3 15,272 2,129 1
May-31 15,938 2,225 2 16,863 2,354 3 15,233 2,127 1
Jun-31 15,865 2,220 2 16,790 2,350 3 15,160 2,122 1
Jul-31 15,807 2,212 2 16,732 2,342 3 15,102 2,113 1
Aug-31 15,740 2,203 2 16,665 2,333 3 15,035 2,105 1
Sep-31 15,741 2,204 2 16,670 2,334 3 15,033 2,105 1
Oct-31 15,831 2,205 2 16,769 2,336 3 15,116 2,106 1
Nov-31 15,980 2,217 2 16,931 2,349 3 15,256 2,117 1
Dec-31 16,108 2,234 2 17,070 2,368 3 15,375 2,133 1
Jan-32 16,144 2,231 2 17,112 2,365 3 15,407 2,129 1
Feb-32 16,129 2,237 2 17,100 2,372 3 15,390 2,135 1
Mar-32 16,129 2,245 2 17,104 2,381 3 15,387 2,142 1
Apr-32 16,118 2,232 2 17,096 2,368 3 15,374 2,129 1
May-32 16,079 2,229 2 17,059 2,365 3 15,334 2,126 1
Jun-32 16,006 2,224 2 16,985 2,360 3 15,261 2,121 1
Jul-32 15,947 2,217 2 16,927 2,353 3 15,202 2,114 1
Roseburg -
Expected Growth
Roseburg -
Low Growth
Roseburg -
High Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 59 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
ROSEBURG

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Aug-32 15,880 2,208 2 16,859 2,344 3 15,136 2,105 1
Sep-32 15,881 2,209 2 16,864 2,346 3 15,134 2,105 1
Oct-32 15,971 2,209 2 16,963 2,346 3 15,217 2,105 1
Nov-32 16,119 2,222 2 17,124 2,361 3 15,355 2,117 1
Dec-32 16,247 2,239 2 17,264 2,379 3 15,474 2,133 1
Jan-33 16,283 2,235 2 17,306 2,376 3 15,506 2,129 1
Feb-33 16,268 2,242 2 17,294 2,384 3 15,489 2,135 1
Mar-33 16,268 2,250 2 17,298 2,393 3 15,486 2,142 1
Apr-33 16,256 2,236 2 17,289 2,378 3 15,472 2,128 1
May-33 16,218 2,234 2 17,252 2,377 3 15,433 2,126 1
Jun-33 16,144 2,229 2 17,177 2,372 3 15,360 2,121 1
Jul-33 16,085 2,221 2 17,118 2,364 3 15,301 2,113 1
Aug-33 16,018 2,213 2 17,051 2,356 3 15,235 2,105 1
Sep-33 16,019 2,214 2 17,056 2,357 3 15,233 2,106 1
Oct-33 16,109 2,214 2 17,155 2,358 3 15,316 2,105 1
Nov-33 16,257 2,226 2 17,316 2,371 3 15,454 2,116 1
Dec-33 16,384 2,243 2 17,455 2,390 3 15,572 2,132 1
Jan-34 16,421 2,240 2 17,499 2,387 3 15,605 2,129 1
Feb-34 16,405 2,247 2 17,485 2,395 3 15,587 2,135 1
Mar-34 16,405 2,255 2 17,489 2,404 3 15,584 2,142 1
Apr-34 16,393 2,241 2 17,480 2,390 3 15,570 2,129 1
May-34 16,354 2,239 2 17,442 2,388 3 15,530 2,126 1
Jun-34 16,281 2,234 2 17,368 2,383 3 15,458 2,121 1
Jul-34 16,221 2,226 2 17,308 2,375 3 15,399 2,113 1
Aug-34 16,155 2,217 2 17,241 2,366 3 15,333 2,104 1
Sep-34 16,155 2,218 2 17,245 2,368 3 15,331 2,105 1
Oct-34 16,245 2,219 2 17,344 2,369 3 15,414 2,106 1
Nov-34 16,393 2,231 2 17,506 2,383 3 15,551 2,117 1
Dec-34 16,520 2,248 2 17,645 2,401 3 15,669 2,132 1
Jan-35 16,556 2,245 2 17,688 2,399 3 15,701 2,129 1
Feb-35 16,541 2,251 2 17,675 2,406 3 15,684 2,135 1
Mar-35 16,541 2,260 2 17,679 2,416 3 15,681 2,143 1
Apr-35 16,528 2,246 2 17,669 2,401 3 15,666 2,129 1
May-35 16,490 2,244 2 17,632 2,400 3 15,628 2,127 1
Jun-35 16,416 2,238 2 17,557 2,394 3 15,555 2,121 1
Jul-35 16,357 2,231 2 17,497 2,387 3 15,496 2,114 1
Aug-35 16,290 2,222 2 17,429 2,378 3 15,430 2,105 1
Sep-35 16,290 2,223 2 17,433 2,379 3 15,428 2,105 1
Oct-35 16,380 2,223 2 17,533 2,380 3 15,510 2,105 1
Nov-35 16,528 2,236 2 17,695 2,394 3 15,648 2,117 1
Dec-35 16,655 2,253 2 17,834 2,413 3 15,766 2,133 1
Roseburg -
Expected Growth
Roseburg -
Low Growth
Roseburg -
High Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 60 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
KLAMATH FALLS

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Nov-15 14,242 1,689 7 14,242 1,689 7 14,242 1,689 7
Dec-15 14,380 1,707 7 14,380 1,707 7 14,380 1,707 7
Jan-16 14,409 1,708 8 14,409 1,708 8 14,409 1,708 8
Feb-16 14,448 1,720 8 14,448 1,720 8 14,448 1,720 8
Mar-16 14,438 1,715 8 14,438 1,715 8 14,438 1,715 8
Apr-16 14,445 1,707 8 14,445 1,707 8 14,445 1,707 8
May-16 14,427 1,701 8 14,427 1,701 8 14,427 1,701 8
Jun-16 14,333 1,700 8 14,333 1,700 8 14,333 1,700 8
Jul-16 14,255 1,695 8 14,259 1,695 8 14,251 1,694 8
Aug-16 14,172 1,690 8 14,180 1,690 8 14,163 1,688 8
Sep-16 14,165 1,688 8 14,177 1,689 8 14,152 1,686 8
Oct-16 14,302 1,688 8 14,318 1,689 8 14,284 1,685 8
Nov-16 14,440 1,703 8 14,460 1,705 8 14,417 1,700 8
Dec-16 14,560 1,715 8 14,584 1,717 8 14,532 1,711 8
Jan-17 14,630 1,728 8 14,658 1,731 8 14,598 1,724 8
Feb-17 14,657 1,730 8 14,689 1,733 8 14,620 1,725 8
Mar-17 14,654 1,727 8 14,690 1,731 8 14,612 1,722 8
Apr-17 14,634 1,721 8 14,674 1,725 8 14,588 1,715 8
May-17 14,599 1,719 8 14,643 1,724 8 14,548 1,713 8
Jun-17 14,510 1,715 8 14,558 1,720 8 14,455 1,708 8
Jul-17 14,425 1,708 8 14,477 1,714 8 14,365 1,700 8
Aug-17 14,348 1,702 8 14,404 1,708 8 14,284 1,694 8
Sep-17 14,352 1,700 8 14,413 1,707 8 14,282 1,691 8
Oct-17 14,499 1,705 8 14,565 1,712 8 14,423 1,696 8
Nov-17 14,649 1,719 8 14,721 1,727 8 14,567 1,709 8
Dec-17 14,772 1,729 8 14,849 1,738 8 14,684 1,718 8
Jan-18 14,842 1,742 8 14,924 1,751 8 14,749 1,731 8
Feb-18 14,868 1,744 8 14,955 1,754 8 14,769 1,732 8
Mar-18 14,860 1,743 8 14,951 1,753 8 14,756 1,730 8
Apr-18 14,835 1,741 8 14,931 1,752 8 14,726 1,728 8
May-18 14,798 1,735 8 14,898 1,746 8 14,684 1,721 8
Jun-18 14,708 1,729 8 14,812 1,741 8 14,589 1,715 8
Jul-18 14,625 1,722 8 14,734 1,734 8 14,501 1,707 8
Aug-18 14,552 1,716 8 14,665 1,729 8 14,423 1,700 8
Sep-18 14,560 1,717 8 14,678 1,730 8 14,426 1,701 8
Oct-18 14,711 1,726 8 14,835 1,740 8 14,570 1,709 8
Nov-18 14,863 1,737 8 14,993 1,752 8 14,715 1,719 8
Dec-18 14,986 1,747 8 15,123 1,762 8 14,831 1,728 8
Jan-19 15,056 1,762 8 15,198 1,778 8 14,895 1,743 8
Feb-19 15,080 1,766 8 15,228 1,783 8 14,913 1,746 8
Klamath Falls -
Low Growth
Klamath Falls -
High Growth
Klamath Falls -
Expected Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 61 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
KLAMATH FALLS

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Mar-19 15,071 1,763 8 15,223 1,780 8 14,898 1,742 8
Apr-19 15,045 1,758 8 15,202 1,776 8 14,867 1,737 8
May-19 15,008 1,753 8 15,170 1,771 8 14,824 1,731 8
Jun-19 14,919 1,748 8 15,085 1,767 8 14,731 1,725 8
Jul-19 14,838 1,741 8 15,008 1,761 8 14,645 1,718 8
Aug-19 14,766 1,735 8 14,941 1,755 8 14,568 1,711 8
Sep-19 14,775 1,735 8 14,955 1,756 8 14,571 1,711 8
Oct-19 14,927 1,743 8 15,114 1,764 8 14,715 1,718 8
Nov-19 15,080 1,756 8 15,275 1,778 9 14,860 1,730 8
Dec-19 15,204 1,767 8 15,405 1,790 9 14,976 1,740 8
Jan-20 15,273 1,780 8 15,481 1,804 9 15,038 1,752 8
Feb-20 15,298 1,784 8 15,512 1,808 9 15,057 1,755 8
Mar-20 15,288 1,781 8 15,507 1,806 9 15,041 1,752 8
Apr-20 15,263 1,776 8 15,487 1,802 9 15,010 1,746 8
May-20 15,226 1,771 8 15,455 1,797 9 14,968 1,740 8
Jun-20 15,138 1,767 8 15,371 1,794 9 14,875 1,736 8
Jul-20 15,058 1,760 8 15,295 1,787 9 14,790 1,728 8
Aug-20 14,987 1,754 8 15,229 1,782 9 14,714 1,722 8
Sep-20 14,997 1,754 8 15,245 1,782 9 14,718 1,721 8
Oct-20 15,150 1,761 8 15,406 1,790 9 14,862 1,727 8
Nov-20 15,303 1,774 8 15,567 1,804 9 15,006 1,739 8
Dec-20 15,427 1,785 8 15,699 1,816 9 15,121 1,749 8
Jan-21 15,497 1,799 8 15,776 1,831 9 15,183 1,762 8
Feb-21 15,522 1,801 8 15,807 1,834 9 15,201 1,763 8
Mar-21 15,513 1,800 8 15,804 1,833 9 15,186 1,762 8
Apr-21 15,488 1,795 8 15,784 1,829 9 15,155 1,756 8
May-21 15,452 1,790 8 15,753 1,824 9 15,113 1,750 8
Jun-21 15,365 1,785 8 15,670 1,820 9 15,022 1,745 8
Jul-21 15,285 1,778 8 15,594 1,814 9 14,937 1,737 8
Aug-21 15,214 1,773 8 15,528 1,809 9 14,862 1,731 8
Sep-21 15,224 1,773 8 15,544 1,810 9 14,865 1,731 8
Oct-21 15,377 1,780 8 15,706 1,818 9 15,008 1,737 8
Nov-21 15,531 1,793 8 15,869 1,832 9 15,152 1,749 8
Dec-21 15,654 1,804 8 16,001 1,843 9 15,266 1,759 8
Jan-22 15,724 1,818 8 16,078 1,858 9 15,327 1,772 8
Feb-22 15,749 1,821 8 16,110 1,862 9 15,345 1,774 7
Mar-22 15,740 1,819 8 16,106 1,861 9 15,330 1,771 7
Apr-22 15,716 1,814 8 16,088 1,856 9 15,300 1,766 7
May-22 15,680 1,809 8 16,057 1,852 9 15,259 1,760 7
Jun-22 15,593 1,804 8 15,974 1,848 9 15,167 1,754 7
Klamath Falls -
Low Growth
Klamath Falls -
High Growth
Klamath Falls -
Expected Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 62 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
KLAMATH FALLS

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Jul-22 15,513 1,797 8 15,898 1,841 9 15,083 1,747 7
Aug-22 15,443 1,792 8 15,832 1,837 9 15,009 1,741 7
Sep-22 15,453 1,792 8 15,848 1,837 9 15,012 1,740 7
Oct-22 15,606 1,799 8 16,011 1,845 9 15,154 1,746 7
Nov-22 15,760 1,812 8 16,175 1,859 9 15,297 1,758 7
Dec-22 15,884 1,823 8 16,308 1,871 9 15,411 1,768 7
Jan-23 15,954 1,837 8 16,386 1,886 9 15,472 1,781 7
Feb-23 15,979 1,840 8 16,418 1,890 9 15,489 1,783 7
Mar-23 15,971 1,838 8 16,416 1,889 9 15,475 1,780 7
Apr-23 15,946 1,833 8 16,397 1,884 9 15,444 1,775 7
May-23 15,911 1,828 8 16,367 1,880 9 15,404 1,769 7
Jun-23 15,824 1,823 8 16,283 1,875 9 15,313 1,764 7
Jul-23 15,744 1,817 8 16,207 1,870 9 15,229 1,757 7
Aug-23 15,673 1,811 8 16,140 1,864 9 15,154 1,751 7
Sep-23 15,684 1,811 8 16,157 1,865 9 15,158 1,750 7
Oct-23 15,836 1,819 8 16,319 1,874 9 15,299 1,757 7
Nov-23 15,990 1,831 8 16,484 1,887 9 15,441 1,768 7
Dec-23 16,114 1,842 8 16,618 1,899 9 15,554 1,778 7
Jan-24 16,183 1,856 8 16,695 1,914 9 15,614 1,790 7
Feb-24 16,208 1,859 8 16,727 1,918 9 15,632 1,792 7
Mar-24 16,200 1,857 8 16,725 1,917 9 15,618 1,790 7
Apr-24 16,175 1,852 8 16,705 1,912 9 15,587 1,784 7
May-24 16,139 1,847 8 16,674 1,908 9 15,546 1,779 7
Jun-24 16,052 1,842 8 16,591 1,903 9 15,456 1,773 7
Jul-24 15,972 1,836 8 16,514 1,898 9 15,372 1,767 7
Aug-24 15,901 1,830 8 16,446 1,892 9 15,298 1,760 7
Sep-24 15,911 1,830 8 16,462 1,893 9 15,301 1,759 7
Oct-24 16,063 1,838 8 16,625 1,902 9 15,441 1,766 7
Nov-24 16,216 1,850 8 16,789 1,915 9 15,582 1,777 7
Dec-24 16,339 1,861 8 16,923 1,927 9 15,694 1,787 7
Jan-25 16,409 1,875 8 17,001 1,942 9 15,755 1,800 7
Feb-25 16,433 1,878 8 17,032 1,946 9 15,772 1,802 7
Mar-25 16,424 1,876 8 17,028 1,945 9 15,757 1,799 7
Apr-25 16,399 1,871 8 17,008 1,940 9 15,727 1,794 7
May-25 16,363 1,866 8 16,977 1,936 9 15,686 1,788 7
Jun-25 16,276 1,861 8 16,893 1,931 9 15,596 1,783 7
Jul-25 16,195 1,854 8 16,814 1,924 9 15,513 1,775 7
Aug-25 16,123 1,849 8 16,745 1,920 9 15,438 1,770 7
Sep-25 16,133 1,849 8 16,761 1,920 9 15,441 1,769 7
Oct-25 16,285 1,856 8 16,925 1,928 9 15,581 1,775 7
Klamath Falls -
Low Growth
Klamath Falls -
High Growth
Klamath Falls -
Expected Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 63 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
KLAMATH FALLS

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Nov-25 16,437 1,869 8 17,088 1,943 9 15,720 1,787 7
Dec-25 16,560 1,880 8 17,222 1,955 9 15,832 1,797 7
Jan-26 16,629 1,893 8 17,299 1,969 9 15,892 1,809 7
Feb-26 16,654 1,896 8 17,331 1,973 9 15,909 1,811 7
Mar-26 16,644 1,894 8 17,327 1,971 9 15,894 1,808 7
Apr-26 16,618 1,889 8 17,305 1,967 9 15,863 1,803 7
May-26 16,582 1,884 8 17,274 1,962 9 15,822 1,797 7
Jun-26 16,494 1,879 8 17,188 1,958 9 15,732 1,792 7
Jul-26 16,413 1,873 8 17,109 1,952 9 15,649 1,785 7
Aug-26 16,342 1,867 8 17,040 1,946 9 15,576 1,779 7
Sep-26 16,351 1,867 8 17,055 1,947 9 15,579 1,778 7
Oct-26 16,502 1,874 8 17,218 1,955 9 15,717 1,784 7
Nov-26 16,655 1,887 8 17,383 1,969 9 15,857 1,796 7
Dec-26 16,777 1,898 8 17,516 1,981 9 15,967 1,806 7
Jan-27 16,846 1,911 8 17,594 1,995 9 16,027 1,818 7
Feb-27 16,870 1,915 8 17,625 2,000 9 16,044 1,821 7
Mar-27 16,860 1,913 8 17,620 1,999 9 16,028 1,818 7
Apr-27 16,834 1,907 8 17,598 1,993 9 15,998 1,812 7
May-27 16,797 1,902 8 17,565 1,989 9 15,957 1,806 7
Jun-27 16,709 1,897 8 17,479 1,984 9 15,867 1,801 7
Jul-27 16,627 1,890 8 17,399 1,977 9 15,784 1,794 7
Aug-27 16,556 1,885 8 17,330 1,973 9 15,711 1,788 7
Sep-27 16,564 1,885 8 17,343 1,973 9 15,713 1,788 7
Oct-27 16,716 1,892 8 17,508 1,981 9 15,851 1,794 7
Nov-27 16,868 1,905 8 17,673 1,995 9 15,990 1,805 7
Dec-27 16,990 1,916 8 17,806 2,008 9 16,100 1,815 7
Jan-28 17,058 1,929 8 17,883 2,022 9 16,158 1,827 7
Feb-28 17,082 1,932 8 17,913 2,026 9 16,175 1,829 7
Mar-28 17,072 1,930 8 17,908 2,024 9 16,160 1,826 7
Apr-28 17,045 1,925 8 17,886 2,019 9 16,129 1,821 7
May-28 17,008 1,920 8 17,852 2,015 9 16,088 1,816 7
Jun-28 16,920 1,915 8 17,765 2,010 9 15,999 1,810 7
Jul-28 16,838 1,908 8 17,684 2,003 9 15,917 1,803 7
Aug-28 16,765 1,902 8 17,613 1,998 9 15,843 1,797 7
Sep-28 16,773 1,902 8 17,626 1,998 9 15,845 1,796 7
Oct-28 16,923 1,910 8 17,789 2,007 9 15,981 1,803 7
Nov-28 17,075 1,922 8 17,953 2,020 9 16,120 1,814 7
Dec-28 17,196 1,933 8 18,086 2,033 9 16,229 1,824 7
Jan-29 17,264 1,946 8 18,162 2,047 9 16,288 1,836 7
Feb-29 17,287 1,949 8 18,192 2,051 9 16,304 1,838 7
Klamath Falls -
Low Growth
Klamath Falls -
High Growth
Klamath Falls -
Expected Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 64 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
KLAMATH FALLS

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Mar-29 17,276 1,947 8 18,185 2,049 9 16,289 1,835 7
Apr-29 17,249 1,942 8 18,162 2,044 9 16,258 1,830 7
May-29 17,211 1,937 8 18,127 2,040 9 16,217 1,825 7
Jun-29 17,122 1,932 8 18,038 2,035 9 16,128 1,819 7
Jul-29 17,038 1,925 8 17,954 2,028 9 16,044 1,812 7
Aug-29 16,965 1,919 8 17,882 2,022 9 15,970 1,806 7
Sep-29 16,972 1,919 8 17,894 2,023 9 15,972 1,806 7
Oct-29 17,122 1,926 8 18,057 2,031 9 16,109 1,812 7
Nov-29 17,273 1,939 8 18,221 2,045 10 16,246 1,823 7
Dec-29 17,393 1,949 8 18,352 2,056 10 16,354 1,832 7
Jan-30 17,460 1,963 8 18,427 2,071 10 16,412 1,845 7
Feb-30 17,482 1,966 8 18,455 2,075 10 16,428 1,847 7
Mar-30 17,470 1,964 8 18,447 2,073 10 16,412 1,845 7
Apr-30 17,443 1,958 8 18,424 2,068 10 16,382 1,838 7
May-30 17,404 1,953 8 18,387 2,063 10 16,341 1,833 7
Jun-30 17,314 1,948 8 18,297 2,058 10 16,251 1,828 7
Jul-30 17,231 1,941 8 18,214 2,051 10 16,169 1,821 7
Aug-30 17,157 1,935 8 18,140 2,045 10 16,095 1,815 7
Sep-30 17,164 1,935 8 18,152 2,046 10 16,097 1,814 7
Oct-30 17,314 1,942 8 18,315 2,054 10 16,233 1,820 7
Nov-30 17,464 1,955 8 18,478 2,068 10 16,369 1,832 7
Dec-30 17,585 1,966 8 18,611 2,080 10 16,477 1,842 7
Jan-31 17,652 1,979 8 18,686 2,094 10 16,535 1,853 7
Feb-31 17,673 1,982 8 18,713 2,098 10 16,550 1,856 7
Mar-31 17,662 1,980 8 18,706 2,097 10 16,535 1,853 7
Apr-31 17,634 1,975 8 18,681 2,092 10 16,504 1,848 7
May-31 17,595 1,969 8 18,645 2,086 10 16,463 1,842 7
Jun-31 17,505 1,964 8 18,554 2,081 10 16,374 1,837 7
Jul-31 17,422 1,957 8 18,471 2,074 10 16,292 1,830 7
Aug-31 17,349 1,952 8 18,398 2,070 10 16,219 1,824 7
Sep-31 17,356 1,951 8 18,410 2,069 10 16,221 1,823 7
Oct-31 17,506 1,959 8 18,574 2,078 10 16,356 1,830 7
Nov-31 17,657 1,971 8 18,739 2,091 10 16,492 1,841 7
Dec-31 17,777 1,982 8 18,871 2,104 10 16,599 1,850 7
Jan-32 17,844 1,995 8 18,947 2,118 10 16,657 1,862 7
Feb-32 17,867 1,998 8 18,977 2,122 10 16,674 1,864 6
Mar-32 17,855 1,996 8 18,969 2,120 10 16,657 1,862 6
Apr-32 17,827 1,991 8 18,944 2,115 10 16,626 1,856 6
May-32 17,789 1,986 8 18,909 2,110 10 16,586 1,851 6
Jun-32 17,699 1,981 8 18,818 2,106 10 16,497 1,846 6
Jul-32 17,616 1,973 8 18,734 2,098 10 16,415 1,838 6
Klamath Falls -
Low Growth
Klamath Falls -
High Growth
Klamath Falls -
Expected Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 65 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
KLAMATH FALLS

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Aug-32 17,543 1,968 8 18,662 2,093 10 16,342 1,833 6
Sep-32 17,551 1,968 8 18,675 2,094 10 16,345 1,832 6
Oct-32 17,700 1,975 8 18,838 2,102 10 16,479 1,838 6
Nov-32 17,851 1,987 8 19,004 2,115 10 16,614 1,849 6
Dec-32 17,972 1,998 8 19,138 2,127 10 16,722 1,859 6
Jan-33 18,039 2,012 8 19,214 2,143 10 16,779 1,871 6
Feb-33 18,061 2,014 8 19,243 2,145 10 16,795 1,872 6
Mar-33 18,050 2,012 8 19,236 2,144 10 16,779 1,870 6
Apr-33 18,022 2,007 8 19,211 2,139 10 16,748 1,865 6
May-33 17,984 2,002 8 19,175 2,134 10 16,708 1,860 6
Jun-33 17,894 1,997 8 19,084 2,129 10 16,619 1,854 6
Jul-33 17,812 1,990 8 19,002 2,122 10 16,538 1,847 6
Aug-33 17,739 1,984 8 18,929 2,117 10 16,466 1,841 6
Sep-33 17,746 1,984 8 18,941 2,117 10 16,467 1,841 6
Oct-33 17,896 1,991 8 19,107 2,125 10 16,601 1,847 6
Nov-33 18,047 2,004 8 19,273 2,140 10 16,736 1,858 6
Dec-33 18,168 2,015 8 19,407 2,152 10 16,844 1,868 6
Jan-34 18,235 2,028 8 19,484 2,166 10 16,901 1,879 6
Feb-34 18,258 2,031 8 19,513 2,170 10 16,917 1,881 6
Mar-34 18,246 2,029 8 19,506 2,169 10 16,901 1,879 6
Apr-34 18,219 2,024 8 19,482 2,164 10 16,871 1,874 6
May-34 18,180 2,019 8 19,445 2,159 10 16,830 1,869 6
Jun-34 18,091 2,013 8 19,355 2,153 10 16,742 1,862 6
Jul-34 18,008 2,006 8 19,271 2,146 10 16,660 1,855 6
Aug-34 17,935 2,001 8 19,198 2,141 10 16,588 1,850 6
Sep-34 17,942 2,000 8 19,210 2,141 10 16,590 1,849 6
Oct-34 18,092 2,008 8 19,376 2,150 10 16,723 1,856 6
Nov-34 18,243 2,020 8 19,543 2,163 10 16,858 1,866 6
Dec-34 18,364 2,031 8 19,677 2,176 10 16,965 1,876 6
Jan-35 18,431 2,044 8 19,754 2,190 10 17,022 1,887 6
Feb-35 18,453 2,047 8 19,783 2,194 10 17,037 1,890 6
Mar-35 18,441 2,045 8 19,775 2,192 10 17,021 1,887 6
Apr-35 18,414 2,040 8 19,751 2,188 10 16,991 1,882 6
May-35 18,375 2,035 8 19,714 2,183 10 16,950 1,877 6
Jun-35 18,285 2,030 8 19,623 2,178 10 16,862 1,872 6
Jul-35 18,202 2,023 8 19,539 2,171 10 16,781 1,865 6
Aug-35 18,129 2,017 8 19,465 2,165 10 16,709 1,859 6
Sep-35 18,136 2,017 8 19,477 2,166 10 16,711 1,858 6
Oct-35 18,286 2,024 8 19,643 2,174 10 16,844 1,864 6
Nov-35 18,436 2,037 8 19,810 2,188 10 16,977 1,875 6
Dec-35 18,557 2,047 8 19,945 2,200 10 17,084 1,884 6
Klamath Falls -
Low Growth
Klamath Falls -
High Growth
Klamath Falls -
Expected Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 66 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
LA GRANDE

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Nov-15 6,571 905 2 6,571 905 2 6,571 905 2
Dec-15 6,623 915 2 6,623 915 2 6,623 915 2
Jan-16 6,680 909 1 6,689 910 1 6,673 908 1
Feb-16 6,666 911 2 6,676 912 2 6,658 910 2
Mar-16 6,651 912 1 6,662 913 1 6,642 910 1
Apr-16 6,642 910 1 6,655 911 1 6,632 908 1
May-16 6,634 907 1 6,648 909 1 6,623 905 1
Jun-16 6,620 904 1 6,635 906 1 6,608 902 1
Jul-16 6,589 903 1 6,606 905 1 6,576 901 1
Aug-16 6,556 901 3 6,574 904 3 6,542 899 3
Sep-16 6,545 899 7 6,565 902 7 6,530 897 7
Oct-16 6,579 901 7 6,600 903 7 6,562 898 6
Nov-16 6,654 901 3 6,677 904 3 6,636 898 3
Dec-16 6,695 909 2 6,720 912 2 6,676 906 2
Jan-17 6,714 911 1 6,741 914 1 6,693 908 1
Feb-17 6,711 913 2 6,739 917 2 6,689 910 2
Mar-17 6,694 913 1 6,724 918 1 6,671 910 1
Apr-17 6,681 913 1 6,713 918 1 6,657 910 1
May-17 6,677 911 1 6,710 916 1 6,651 908 1
Jun-17 6,651 907 1 6,686 912 1 6,624 904 1
Jul-17 6,609 906 1 6,645 911 2 6,581 902 1
Aug-17 6,581 905 3 6,619 910 3 6,551 901 3
Sep-17 6,574 903 7 6,614 908 7 6,543 899 7
Oct-17 6,619 905 6 6,661 910 7 6,586 900 6
Nov-17 6,691 904 3 6,736 910 3 6,656 899 3
Dec-17 6,737 912 2 6,784 919 2 6,701 907 2
Jan-18 6,758 915 1 6,807 921 1 6,720 910 1
Feb-18 6,755 917 2 6,806 924 2 6,716 911 2
Mar-18 6,741 917 1 6,794 924 1 6,700 911 1
Apr-18 6,726 917 1 6,781 924 1 6,684 911 1
May-18 6,715 915 1 6,771 922 1 6,671 909 1
Jun-18 6,684 911 1 6,742 919 1 6,639 905 1
Jul-18 6,640 910 1 6,700 918 2 6,594 903 1
Aug-18 6,614 908 3 6,676 917 3 6,566 902 2
Sep-18 6,606 906 7 6,670 915 7 6,557 900 7
Oct-18 6,656 908 6 6,722 917 7 6,605 901 6
Nov-18 6,731 908 3 6,800 917 3 6,678 901 3
Dec-18 6,778 916 2 6,849 925 2 6,723 908 2
Jan-19 6,802 918 1 6,876 928 1 6,745 910 1
Feb-19 6,800 920 2 6,876 931 2 6,741 912 2
La Grande -
Low Growth
La Grande -
High Growth
La Grande -
Expected Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 67 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
LA GRANDE

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Mar-19 6,785 921 1 6,863 931 1 6,725 912 1
Apr-19 6,768 920 1 6,848 931 1 6,706 912 1
May-19 6,754 918 1 6,836 929 1 6,691 909 1
Jun-19 6,721 914 1 6,804 926 1 6,657 906 1
Jul-19 6,676 913 1 6,761 925 2 6,610 904 1
Aug-19 6,650 912 3 6,737 924 3 6,583 903 2
Sep-19 6,642 910 7 6,731 922 7 6,573 900 7
Oct-19 6,694 912 6 6,786 924 7 6,623 902 6
Nov-19 6,770 911 3 6,865 924 3 6,697 901 3
Dec-19 6,819 919 2 6,917 932 2 6,744 909 2
Jan-20 6,844 922 1 6,945 935 1 6,767 911 1
Feb-20 6,843 924 2 6,946 938 2 6,764 913 2
Mar-20 6,828 924 1 6,933 938 1 6,747 913 1
Apr-20 6,810 924 1 6,917 938 1 6,728 912 1
May-20 6,795 922 1 6,904 936 1 6,711 910 1
Jun-20 6,760 918 1 6,871 933 1 6,675 906 1
Jul-20 6,714 917 1 6,826 932 2 6,628 905 1
Aug-20 6,688 915 3 6,802 931 3 6,600 903 2
Sep-20 6,680 913 7 6,796 929 7 6,591 901 6
Oct-20 6,733 915 6 6,852 931 7 6,641 903 6
Nov-20 6,811 915 3 6,934 931 3 6,716 902 3
Dec-20 6,861 923 2 6,987 940 2 6,764 910 2
Jan-21 6,886 925 1 7,015 942 2 6,787 912 1
Feb-21 6,886 927 2 7,018 945 2 6,785 914 2
Mar-21 6,870 927 1 7,004 946 1 6,767 914 1
Apr-21 6,852 927 1 6,988 945 2 6,748 913 1
May-21 6,836 925 1 6,974 944 1 6,730 911 1
Jun-21 6,801 921 1 6,941 940 1 6,694 907 1
Jul-21 6,754 920 1 6,895 939 2 6,646 905 1
Aug-21 6,727 919 3 6,870 938 3 6,618 904 2
Sep-21 6,720 917 7 6,865 937 7 6,609 902 6
Oct-21 6,773 919 6 6,921 939 7 6,659 903 6
Nov-21 6,851 918 3 7,004 939 3 6,734 903 3
Dec-21 6,902 926 2 7,058 947 2 6,783 910 2
Jan-22 6,928 929 1 7,087 950 2 6,806 912 1
Feb-22 6,928 931 2 7,090 952 2 6,805 914 1
Mar-22 6,912 931 1 7,076 953 1 6,787 914 1
Apr-22 6,894 931 1 7,060 953 2 6,768 913 1
May-22 6,877 929 1 7,045 951 1 6,749 911 1
Jun-22 6,842 925 1 7,011 948 2 6,713 907 1
La Grande -
Low Growth
La Grande -
High Growth
La Grande -
Expected Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 68 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
LA GRANDE

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Jul-22 6,794 924 1 6,964 947 2 6,664 906 1
Aug-22 6,767 922 3 6,939 946 3 6,636 904 2
Sep-22 6,760 920 7 6,934 944 7 6,627 902 6
Oct-22 6,814 922 6 6,992 946 7 6,678 904 6
Nov-22 6,892 922 3 7,074 946 3 6,753 903 3
Dec-22 6,943 930 2 7,129 955 2 6,801 911 2
Jan-23 6,969 932 1 7,158 957 2 6,825 913 1
Feb-23 6,969 934 2 7,161 960 2 6,823 915 1
Mar-23 6,954 934 1 7,148 961 1 6,806 915 1
Apr-23 6,935 934 1 7,131 960 2 6,786 914 1
May-23 6,918 932 1 7,116 959 1 6,767 912 1
Jun-23 6,883 928 1 7,082 955 2 6,731 908 1
Jul-23 6,835 927 1 7,035 954 2 6,683 906 1
Aug-23 6,808 926 3 7,009 953 3 6,655 905 2
Sep-23 6,800 924 7 7,003 951 7 6,646 903 6
Oct-23 6,854 925 6 7,061 953 7 6,697 904 6
Nov-23 6,932 925 3 7,143 953 3 6,772 904 3
Dec-23 6,983 933 2 7,198 962 2 6,820 911 2
Jan-24 7,010 935 1 7,228 965 2 6,845 913 1
Feb-24 7,010 938 2 7,230 967 2 6,843 915 1
Mar-24 6,994 938 1 7,216 968 1 6,826 915 1
Apr-24 6,975 938 1 7,198 968 2 6,806 915 1
May-24 6,958 936 1 7,183 966 1 6,788 913 1
Jun-24 6,922 932 1 7,148 962 2 6,751 909 1
Jul-24 6,874 931 1 7,100 961 2 6,703 907 1
Aug-24 6,847 929 3 7,074 960 3 6,675 906 2
Sep-24 6,839 927 7 7,068 958 7 6,666 904 6
Oct-24 6,893 929 6 7,125 960 7 6,717 905 6
Nov-24 6,971 929 3 7,208 960 3 6,792 905 3
Dec-24 7,022 937 2 7,262 969 2 6,840 912 2
Jan-25 7,049 939 1 7,292 971 2 6,865 914 1
Feb-25 7,049 941 2 7,294 974 2 6,863 916 1
Mar-25 7,032 941 1 7,279 974 1 6,845 916 0
Apr-25 7,014 941 1 7,262 974 2 6,827 916 1
May-25 6,996 939 1 7,245 972 1 6,808 914 0
Jun-25 6,960 935 1 7,210 969 2 6,771 910 1
Jul-25 6,912 934 1 7,162 968 2 6,723 909 1
Aug-25 6,885 933 3 7,136 967 3 6,696 907 2
Sep-25 6,877 931 7 7,129 965 7 6,687 905 6
Oct-25 6,931 932 6 7,187 967 7 6,738 906 6
La Grande -
Low Growth
La Grande -
High Growth
La Grande -
Expected Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 69 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
LA GRANDE

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Nov-25 7,009 932 3 7,269 967 3 6,812 906 2
Dec-25 7,060 940 2 7,324 975 2 6,861 914 1
Jan-26 7,087 942 1 7,354 978 2 6,886 916 1
Feb-26 7,086 945 2 7,354 980 2 6,883 918 1
Mar-26 7,070 945 1 7,340 981 1 6,867 918 0
Apr-26 7,051 945 1 7,322 981 2 6,847 917 1
May-26 7,034 942 1 7,306 979 1 6,829 915 0
Jun-26 6,998 939 1 7,270 975 2 6,793 911 1
Jul-26 6,950 938 1 7,223 974 2 6,745 910 1
Aug-26 6,923 936 3 7,197 973 3 6,717 908 2
Sep-26 6,915 934 7 7,191 971 7 6,707 906 6
Oct-26 6,969 936 6 7,249 974 7 6,758 908 6
Nov-26 7,048 936 3 7,334 974 3 6,833 907 2
Dec-26 7,099 944 2 7,389 982 2 6,881 915 1
Jan-27 7,126 946 1 7,420 985 2 6,905 917 1
Feb-27 7,126 948 2 7,422 987 2 6,903 918 1
Mar-27 7,110 948 1 7,408 988 1 6,886 919 0
Apr-27 7,091 948 1 7,390 988 2 6,866 918 1
May-27 7,074 946 1 7,375 986 1 6,848 916 0
Jun-27 7,038 942 1 7,340 983 2 6,811 912 1
Jul-27 6,990 941 1 7,293 982 2 6,763 910 1
Aug-27 6,964 940 3 7,268 981 3 6,735 909 2
Sep-27 6,957 938 7 7,264 979 7 6,726 907 6
Oct-27 7,011 939 6 7,324 981 7 6,776 908 6
Nov-27 7,090 939 3 7,409 981 4 6,851 907 2
Dec-27 7,141 947 2 7,466 990 3 6,898 915 1
Jan-28 7,168 949 1 7,497 993 2 6,921 917 1
Feb-28 7,169 952 2 7,501 996 2 6,920 919 1
Mar-28 7,153 952 1 7,487 996 2 6,902 919 0
Apr-28 7,135 951 1 7,472 996 2 6,883 918 1
May-28 7,118 949 1 7,457 995 2 6,864 916 0
Jun-28 7,082 946 1 7,422 991 2 6,827 912 1
Jul-28 7,035 945 1 7,377 990 2 6,780 910 1
Aug-28 7,008 943 3 7,352 990 3 6,751 909 2
Sep-28 7,001 941 7 7,348 988 7 6,742 906 6
Oct-28 7,055 943 6 7,408 990 7 6,791 908 6
Nov-28 7,134 943 3 7,494 990 4 6,865 907 2
Dec-28 7,186 951 2 7,552 999 3 6,913 914 1
Jan-29 7,213 953 1 7,584 1,002 2 6,936 916 1
Feb-29 7,214 955 2 7,589 1,005 2 6,934 918 1
La Grande -
Low Growth
La Grande -
High Growth
La Grande -
Expected Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 70 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
LA GRANDE

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Mar-29 7,198 955 1 7,576 1,005 2 6,917 918 0
Apr-29 7,180 955 1 7,560 1,006 2 6,897 917 1
May-29 7,164 953 1 7,547 1,004 2 6,879 915 0
Jun-29 7,128 949 1 7,512 1,000 2 6,842 911 1
Jul-29 7,080 948 1 7,465 1,000 2 6,794 910 1
Aug-29 7,054 947 3 7,441 999 3 6,766 908 2
Sep-29 7,046 945 7 7,435 997 7 6,756 906 6
Oct-29 7,101 946 6 7,496 999 7 6,807 907 6
Nov-29 7,180 946 3 7,583 999 4 6,880 907 2
Dec-29 7,231 954 2 7,640 1,008 3 6,927 914 1
Jan-30 7,258 956 1 7,672 1,011 2 6,951 916 1
Feb-30 7,259 959 2 7,676 1,014 2 6,949 918 1
Mar-30 7,243 959 1 7,662 1,014 2 6,932 918 0
Apr-30 7,225 958 1 7,647 1,014 2 6,912 917 1
May-30 7,208 956 1 7,632 1,013 2 6,894 915 0
Jun-30 7,172 953 1 7,597 1,009 2 6,857 911 1
Jul-30 7,124 951 1 7,549 1,008 2 6,809 909 1
Aug-30 7,098 950 3 7,524 1,007 3 6,782 908 2
Sep-30 7,090 948 7 7,518 1,005 7 6,773 906 6
Oct-30 7,144 950 6 7,578 1,008 7 6,823 907 6
Nov-30 7,223 950 3 7,665 1,008 4 6,896 907 2
Dec-30 7,274 957 2 7,722 1,016 3 6,943 914 1
Jan-31 7,301 960 1 7,753 1,019 2 6,967 916 1
Feb-31 7,302 962 2 7,757 1,022 2 6,966 918 1
Mar-31 7,286 962 1 7,743 1,023 2 6,948 918 0
Apr-31 7,267 962 1 7,725 1,023 2 6,928 917 1
May-31 7,250 960 1 7,710 1,021 2 6,910 915 0
Jun-31 7,215 956 1 7,676 1,017 2 6,875 911 1
Jul-31 7,167 955 1 7,627 1,016 2 6,827 910 1
Aug-31 7,140 954 3 7,601 1,015 3 6,800 908 2
Sep-31 7,132 952 7 7,595 1,013 7 6,790 906 6
Oct-31 7,186 953 6 7,655 1,016 7 6,840 907 6
Nov-31 7,265 953 3 7,742 1,016 4 6,913 907 2
Dec-31 7,316 961 2 7,799 1,024 3 6,960 914 1
Jan-32 7,343 963 1 7,830 1,027 2 6,984 916 1
Feb-32 7,343 966 2 7,833 1,030 3 6,982 918 1
Mar-32 7,327 966 1 7,818 1,031 2 6,965 918 0
Apr-32 7,309 965 1 7,801 1,030 2 6,946 918 1
May-32 7,292 963 1 7,786 1,029 2 6,929 915 0
Jun-32 7,256 960 1 7,750 1,025 2 6,893 912 0
Jul-32 7,208 958 1 7,701 1,024 2 6,845 910 1
La Grande -
Low Growth
La Grande -
High Growth
La Grande -
Expected Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 71 of 648
APPENDIX 2.2: CUSTOMER FORECASTS BY REGION
LA GRANDE

Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Residential
Customers
Commercial
Customers
Industrial
Customers
Aug-32 7,181 957 3 7,674 1,023 3 6,818 909 2
Sep-32 7,173 955 7 7,668 1,021 8 6,809 907 6
Oct-32 7,227 957 6 7,728 1,023 7 6,859 908 6
Nov-32 7,305 957 3 7,814 1,023 4 6,931 908 2
Dec-32 7,356 964 2 7,871 1,032 3 6,978 915 1
Jan-33 7,383 967 1 7,902 1,035 2 7,002 917 0
Feb-33 7,383 969 2 7,904 1,037 3 7,000 919 1
Mar-33 7,367 969 1 7,889 1,038 2 6,984 919 0
Apr-33 7,349 969 1 7,872 1,038 2 6,965 918 0
May-33 7,331 967 1 7,855 1,036 2 6,946 916 0
Jun-33 7,296 963 1 7,820 1,032 2 6,912 912 0
Jul-33 7,247 962 1 7,769 1,031 2 6,864 911 1
Aug-33 7,220 961 3 7,742 1,030 4 6,837 910 2
Sep-33 7,212 959 7 7,735 1,028 8 6,828 908 6
Oct-33 7,266 960 6 7,795 1,030 7 6,878 909 6
Nov-33 7,344 960 3 7,881 1,030 4 6,951 909 2
Dec-33 7,395 968 2 7,937 1,039 3 6,998 916 1
Jan-34 7,422 970 1 7,968 1,042 2 7,022 918 0
Feb-34 7,422 973 2 7,970 1,044 3 7,021 920 1
Mar-34 7,406 973 1 7,955 1,045 2 7,004 920 0
Apr-34 7,387 972 1 7,936 1,045 2 6,985 919 0
May-34 7,369 970 1 7,919 1,043 2 6,967 917 0
Jun-34 7,333 967 1 7,882 1,039 2 6,931 914 0
Jul-34 7,285 965 1 7,832 1,038 2 6,885 912 1
Aug-34 7,258 964 3 7,805 1,037 4 6,858 911 2
Sep-34 7,250 962 7 7,798 1,035 8 6,849 909 6
Oct-34 7,303 964 6 7,857 1,037 7 6,898 910 6
Nov-34 7,382 964 3 7,944 1,037 4 6,972 910 2
Dec-34 7,433 971 2 8,000 1,046 3 7,018 917 1
Jan-35 7,459 974 1 8,030 1,048 2 7,042 919 0
Feb-35 7,459 976 2 8,032 1,051 3 7,040 921 1
Mar-35 7,443 976 1 8,017 1,052 2 7,024 921 0
Apr-35 7,424 976 1 7,998 1,051 2 7,005 921 0
May-35 7,407 974 1 7,981 1,049 2 6,988 919 0
Jun-35 7,371 970 1 7,944 1,046 2 6,952 915 0
Jul-35 7,322 969 1 7,893 1,045 2 6,905 914 1
Aug-35 7,295 968 3 7,866 1,043 4 6,878 912 2
Sep-35 7,287 966 7 7,859 1,041 8 6,870 910 6
Oct-35 7,341 967 6 7,919 1,043 7 6,919 912 6
Nov-35 7,419 967 3 8,005 1,043 4 6,992 911 2
Dec-35 7,470 975 2 8,062 1,052 3 7,039 919 1
La Grande -
Low Growth
La Grande -
High Growth
La Grande -
Expected Growth
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 72 of 648
APPENDIX 2.3: DEMAND COEFFICIENTS

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 73 of 648
APPENDIX 2.3: WA/ID BASE COEFFICIENT CALCULATION

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 74 of 648
APPENDIX 2.3: MEDFORD BASE COEFFICIENT CALCULATION

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 75 of 648
APPENDIX 2.3: ROSEBURG BASE COEFFICIENT CALCULATION

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 76 of 648
APPENDIX 2.3: KLAMATH FALLS BASE COEFFICIENT CALCULATION

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 77 of 648
APPENDIX 2.3: LA GRANDE BASE COEFFICIENT CALCULATION

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 78 of 648
APPENDIX 2.4: HEATING DEGREE DAY DATA MONTHLY TABLES
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 79 of 648

APPENDIX 2.4: HEATING DEGREE DAY DATA MONTHLY TABLES

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 80 of 648
APPENDIX 2.4: HEATING DEGREE DAILY MONTH BY AREA

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 81 of 648
APPENDIX 2.4: HEATING DEGREE DAILY MONTH BY AREA

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 82 of 648
APPENDIX 2.4: HEATING DEGREE DAILY MONTH BY AREA

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 83 of 648
APPENDIX 2.5: DEMAND SENSITIVITIES
SUMMARY OF ASSUMPTIONS – DEMAND SCENARIOS
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 84 of 648

APPENDIX 2.5: DEMAND SCENARIOS
PROPOSED SCENARIOS

Proposed Scenarios Expected Expected High Growth Low Growth Cold Day 20yr
INPUT ASSUMPTIONS Case - Low Prices Case & Low Prices & High Prices Weather Std
Customer Growth Rate Reference Case
Cust Growth Rates
Reference Case
Cust Growth Rates High Growth Rate Low Growth Rate Reference Case
Cust Growth Rates
Use per Customer 3 yr Flat +3 yr Flat +3 yr Flat +3 yr Flat +3 yr Flat +
Price Elast.Price Elast.Price Elast. +Price Elast.Price Elast.
CNG/NGV
Demand Side Management Yes Yes Yes Yes Yes
Weather Planning Standard Coldest Day Coldest Day Coldest Day Coldest Day
Alternate Planning
Standard
Prices
Price curve Low Expected Low High Expected
Carbon Legislation ($/Ton)$9.89 - 19.93 $9.89 - 19.93 None $9.89 - 19.93 $9.89 - 19.93
First Gas Year Unserved
WA/ID N/A N/A 2033 N/A N/A
Medford N/A N/A 2027 N/A N/A
Roseburg N/A N/A 2027 N/A N/A
Klamath N/A N/A 2034 N/A N/A
La Grande N/A N/A 2031 N/A N/A
Evaluates the
expected case
attributes and
combines it with the
low price curve to
determine whether
low prices will
drastically change
case outcome.
Most aggressive
peak planning case
utilizing Average
Case assumptions
as a starting point
and layering in
coldest weather on
record. The
likelihood of
occurrence is low.
Aggressive growth
assumptions in order
to evaluate when our
earliest resource
shortage could occur.
Not likely to occur.
Stagnant growth
assumptions in order
to evaluate if a
shortage does occur.
Not likely to occur.
Evaluates adopting
an alternate peak
weather standard.
Helps provide some
bounds around our
sensitivity to
weather.
Indirect influencers including elasticity and price are also important assumptions. The two go hand in hand, as price changes it will
influence how much customers consume. If forecasted prices remain relatively stable over the planning horizon, our current
elasticity assumption will not provide much decreased usage. However, price adders or an overall steepening of the price curve will
trigger a greater decline in usage due to the price elastic response. The magnitude of the elasticity adjustment is also important.
We are using a long run elasticity factor as calculated by the AGA. We continue to evaluate this assumption and are looking to
update the study as part of our Action Plan.
RESULTS
Scenario Summary
Risk Assessment
Higher or lower customer growth rates, which are heavily based on economic recovery. Higher or lower growth rates will lead to
accelerated or delayed unserved demand. Looking at various growth assumptions off the Expected Case allows us to capture the
risk in terms of the change in demand linked to customer growth.
Higher or lower use per customer will also lead to accelerated or delayed unserved demand. Use per customer can differ in many
ways. Direct use per customer influencers, such as demand side management, NGV/CNG usage, and derivation of the use per
customer starting point (i.e. one year, three year, etc.). Again, varying these assumptions under our forecasting methodology allows
us to quantify the change each assumption has to our forecast.
Weather volatility and predictability are a key risk. As the most correlated direct demand influencer, varying weather assumptions is
key to understanding the weather related risks.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 85 of 648
APPENDIX 2.6: DEMAND FORECAST SENSITIVITIES AND SCENARIOS
DESCRIPTIONS
DEFINITIONS
DYNAMIC DEMAND METHODOLOGY – Avista’s demand forecasting approach wherein we 1) identify key
demand drivers behind natural gas consumption, 2) perform sensitivity analysis on each demand driver,
and 3) combine demand drivers under various scenarios to develop alternative potential outcomes for
forecasted demand.
DEMAND INFLUENCING FACTORS – Factors that directly influence the volume of natural gas consumed by our
core customers.
PRICE INFLUENCING FACTORS – Factors that, through price elasticity response, indirectly influence the volume
of natural gas consumed by our core customers.
REFERENCE CASE – A baseline point of reference that captures the basic inputs for determining a demand
forecast in SENDOUT® which includes number of customers, use per customer, average daily weather
temperatures and expected natural gas prices.
SENSITIVITIES – Focused analysis of a specific natural gas demand driver and its impact on forecasted
demand relative to the Reference Case when underlying input assumptions are modified.
SCENARIOS – Combination of natural gas demand drivers that make up a demand forecast.
Avista evaluates each sensitivities impact.
SENSITIVITIES
The following Sensitivities were performed on identified demand drivers against the reference case for
consideration in Scenario development. Note that Sensitivity assumptions reflect incremental adjustments
we estimate are not captured in the underlying reference case forecast.
Following are the Demand Influencing (Direct) Sensitivities we evaluated:
REFERENCE CASE PLUS PEAK – Same assumptions as in the Reference Case with and adjustment made to
normal weather to incorporate peak weather conditions. The peak weather data being the coldest day on
record for each weather area.
LOW & HIGH CUSTOMER GROWTH – Discussed in detail in Appendix 2.1: Economic Outlook and Customer
Count Forecast.
NATURAL GAS VEHICLES (NGV) AND/OR COMPRESSED NATURAL GAS (CNG) VEHICLES – NGV/CNG vehicles
assumed to produce a 5% cumulative incremental demand over our 20 year planning horizon. Our
assumption utilized market consumption estimates from an independent analysis on NGV/CNG vehicle
viability. The analysis indicates significant challenges exist to widespread adoption but did provide a
scenario for significant market penetration.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 86 of 648
ALTERNATE WEATHER STANDARD (COLDEST DAY 20 YRS) – Peak Day weather temperature reduced to coldest
average daily temperature (HDDs) experienced in the most recent 20 years in each region.
DSM – Reference case assumptions including the potential DSM identified by the Conservation Potential
Assessment provided by Applied Energy Group. See Appendix 3.1 for full assessment report.
PEAK PLUS DSM – Reference plus peak weather assumptions including the potential DSM identified by the
Conservation Potential Assessment provided by Applied Energy Group. See Appendix 3.1 for the full
assessment report.
ALTERNATE USE PER CUSTOMER – Reference case use per customer was based upon three years of actual use
per customer per heating degree day data. This sensitivity used five years of historical use per customer
per heating degree day data.
Following are the Price Influencing (Indirect) Sensitivities we evaluated:
EXPECTED ELASTICITY – For our expected elasticity Sensitivity, we incorporate reduced consumption in
response to higher natural gas prices utilizing a price elasticity study prepared by the American Gas
Association.
LOW & HIGH PRICES – To capture a wide band of alternative prices forecasts, a Monte Carlo simulation
using historical daily cash price data at the Henry Hub trading point dating back to 2009 was developed.
From this simulation, a high and low price were selected from the derived 500 draws.
CARBON LEGISLATION LOW CASE – Assumes no carbon adder throughout the entire study horizon.
CARBON LEGISLATION MEDIUM CASE –Utilizes carbon cost adders quantified by independent analysis from
Consultant #1. They identify both an adder reflecting carbon allowances as well as an adder to capture
the effect of increased natural gas demand as more gas turbines come online to replace coal plants and
back up wind generation. The allowance adder escalates from $9.89/ton in 2018 to $19.93/ton by 2035.
This is the expected carbon adder utilized in our carbon case sensitivities.
CARBON LEGISLATION HIGH CASE – Utilizes carbon cost adders quantified by independent analysis from
Consultant #1. They identify both an adder reflecting carbon allowances as well as an adder to capture
the effect of increased natural gas demand as more gas turbines come online to replace coal plants and
back up wind generation. The allowance adder escalates from $15/ton in 2018 to $43/ton by 2035.
EXPORTED LNG – Beginning in 2019, we apply an estimate of $.25/mmbtu incremental adder each year to
regional natural gas prices to capture upward price pressure because of exports of LNG to Asian and
European counties. There is much uncertainty about the region price impact LNG will have. It is highly
dependent on many things including which export facilities get built and the pipeline infrastructure used
to serve them. There are several analyses that have been conducted where the price impact can be
minimal to $1.00/mmbtu.
SCENARIOS
After identifying the above demand drivers and analyzing the various Sensitivities, we have developed
the following demand forecast Scenarios:
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 87 of 648
AVERAGE CASE – This Scenario we believe represents the most likely average demand forecast modeled.
We assume service territory customer growth rates consistent with the reference case, rolling 20 year
normal weather in each service territory, our expected natural gas price forecast (blend of two consultants,
along with the NYMEX forward strip), expected price elasticity, the CO2 cost adders from our Carbon
Legislation Medium Case Sensitivity, and DSM. The Scenario does not include incremental cost adders
for declining Canadian imports or drilling restrictions beyond what is incorporated in the selected price
forecast.
EXPECTED CASE – This Scenario represents the peak demand forecast. We assume service territory customer
growth rates consistent with the reference case, a weather standard of coldest day on record in each
service territory, our expected natural gas price forecast (blend of two consultants, along with the
NYMEX forward strip), expected price elasticity, DSM, and the CO2 cost adders from our Carbon
Legislation Medium Case Sensitivity.
HIGH GROWTH, LOW PRICE – This Scenario models a rapid return to robust growth in part spurred on by low
energy prices. We assume higher customer growth rates than the reference case, coldest day on record
weather standard, incremental demand from NGV/CNG, our low natural gas price forecast, expected
price elasticity, DSM, and no CO2 adders.
LOW GROWTH, HIGH PRICE – This Scenario models an extended period of slow economic growth in part
resulting from high energy prices. We assume lower customer growth rates than the reference case,
coldest day on record weather standard, our high natural gas price forecast, expected price elasticity,
DSM, and CO2 adders from our Carbon Legislation Medium Case Sensitivity.
ALTERNATE WEATHER STANDARD – This Scenario models all the same assumptions as the Expected Case
Scenario, except for the change in the weather planning standard from coldest day on record to coldest
day in 20 years for each service territory. As noted in the Sensitivity analysis, this change does not affect
the Klamath Falls and La Grande service territories, which have each experienced their coldest day on
record within the last 20 years.
EXPECTED GROWTH, LOW PRICES – This Scenario models all the same assumptions as the Expected Case
Scenario, except our low natural gas price forecast is used rather than our expected natural gas price
forecast.
A case incorporating Exported LNG was not included in this IRP’s scenario analysis. There is much
uncertainty about the location and timing of exported LNG and its potential price impacts. The
forecasters we subscribe to have incorporated some level of export LNG into their price forecasts and
therefore our expected price curve does include an export LNG assumption. At this time, the effects of
LNG are minimal given the robust North American supply picture. Avista will closely monitor
developments with export LNG for the potential price and infrastructure impacts.

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 88 of 648
APPENDIX 2.7: ANNUAL DEMAND, AVERAGE DAY DEMAND AND PEAK DAY
DEMAND (NET OF DSM) – CASE AVERAGE

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 89 of 648
APPENDIX 2.7: ANNUAL DEMAND, AVERAGE DAY DEMAND AND PEAK DAY
DEMAND (NET OF DSM) – CASE HIGH

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 90 of 648
APPENDIX 2.7: ANNUAL DEMAND, AVERAGE DAY DEMAND AND PEAK DAY
DEMAND (NET OF DSM) – CASE LOW

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 91 of 648
APPENDIX 2.7: ANNUAL DEMAND, AVERAGE DAY DEMAND AND PEAK DAY
DEMAND (NET OF DSM) – CASE COLDEST IN 20

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 92 of 648
APPENDIX 2.8: PEAK DAY DEMAND BEFORE AND AFTER DSM
WA/ID

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 93 of 648
APPENDIX 2.8: PEAK DAY DEMAND BEFORE AND AFTER DSM
MEDFORD/ROSEBURG

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 94 of 648
APPENDIX 2.8: PEAK DAY DEMAND BEFORE AND AFTER DSM
KLAMATH FALLS

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 95 of 648
APPENDIX 2.8: PEAK DAY DEMAND BEFORE AND AFTER DSM
LA GRANDE

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 96 of 648
APPENDIX 2.9: DETAILED DEMAND DATA
EXPECTED MIX

Area
2015-2016:
Residential
2015-2016:
Commercial
2015-2016:
Ind FirmSale
2015-2016
Total
2016-2017:
Residential
2016-2017:
Commercial
2016-2017:
Ind FirmSale
2016-2017
Total
2017-2018:
Residential
2017-2018:
Commercial
2017-2018:
Ind FirmSale
2017-2018
Total
Klam Falls 878.84 456.42 13.31 1,348.57 883.84 455.69 13.71 1,353.23 895.19 458.09 13.70 1,366.98
La Grande 523.95 341.99 49.90 915.84 524.18 339.49 51.77 915.43 526.69 339.78 51.72 918.19
Medford GTN 2,179.41 1,398.52 18.60 3,596.53 2,201.01 1,403.03 18.92 3,622.96 2,237.36 1,416.04 18.92 3,672.31
Medford NWP 979.15 628.32 8.36 1,615.83 988.86 630.35 8.50 1,627.71 1,005.19 636.19 8.50 1,649.88
Roseburg 651.55 517.12 7.00 1,175.67 654.28 513.56 6.96 1,174.80 660.22 512.27 6.94 1,179.42
OR Sub-Total 5,212.90 3,342.37 97.17 8,652.43 5,252.16 3,342.11 99.86 8,694.13 5,324.64 3,362.37 99.77 8,786.79
Wa/Id Both 9,075.48 5,521.47 319.24 14,916.18 9,098.71 5,480.27 320.42 14,899.40 9,179.15 5,485.86 320.41 14,985.42
Wa/Id GTN 1,251.79 761.58 44.03 2,057.40 1,254.99 755.90 44.20 2,055.09 1,266.09 756.67 44.19 2,066.95
Wa/Id NWP 5,320.11 3,236.72 187.14 8,743.97 5,333.73 3,212.57 187.83 8,734.13 5,380.88 3,215.85 187.83 8,784.55
WA/ID Sub-Total 15,647.38 9,519.77 550.41 25,717.56 15,687.44 9,448.74 552.44 25,688.61 15,826.12 9,458.37 552.43 25,836.92
Case Total 20,860.28 12,862.14 647.57 34,369.99 20,939.60 12,790.85 652.30 34,382.74 21,150.75 12,820.75 652.21 34,623.71
Area
2018-2019:
Residential
2018-2019:
Commercial
2018-2019:
Ind FirmSale
2018-2019
Total
2019-2020:
Residential
2019-2020:
Commercial
2019-2020:
Ind FirmSale
2019-2020
Total
2020-2021:
Residential
2020-2021:
Commercial
2020-2021:
Ind FirmSale
2020-2021
Total
Klam Falls 906.72 461.25 13.69 1,381.66 922.88 466.18 13.72 1,402.79 930.50 466.70 13.68 1,410.88
La Grande 529.18 339.96 51.62 920.76 533.79 341.44 51.66 926.89 533.99 339.97 51.59 925.55
Medford GTN 2,275.51 1,428.93 18.91 3,723.35 2,323.97 1,447.29 18.94 3,790.20 2,352.68 1,453.80 18.88 3,825.37
Medford NWP 1,022.33 641.98 8.49 1,672.81 1,044.10 650.23 8.51 1,702.84 1,057.00 653.16 8.48 1,718.64
Roseburg 666.40 510.92 6.92 1,184.24 675.76 511.29 6.92 1,193.97 679.30 507.30 6.88 1,193.48
OR Sub-Total 5,400.13 3,383.05 99.63 8,882.82 5,500.50 3,416.43 99.76 9,016.69 5,553.47 3,420.93 99.52 9,073.92
Wa/Id Both 9,257.29 5,487.36 320.20 15,064.85 9,377.78 5,511.46 320.84 15,210.08 9,420.59 5,488.29 319.43 15,228.31
Wa/Id GTN 1,276.87 756.88 44.17 2,077.91 1,293.49 760.20 44.25 2,097.94 1,299.39 757.01 44.06 2,100.46
Wa/Id NWP 5,426.69 3,216.73 187.70 8,831.12 5,497.32 3,230.86 188.08 8,916.26 5,522.41 3,217.28 187.25 8,926.94
WA/ID Sub-Total 15,960.85 9,460.97 552.06 25,973.89 16,168.59 9,502.52 553.17 26,224.28 16,242.39 9,462.58 550.74 26,255.71
Case Total 21,360.98 12,844.02 651.70 34,856.70 21,669.09 12,918.95 652.93 35,240.97 21,795.87 12,883.51 650.26 35,329.63
Area
2021-2022:
Residential
2021-2022:
Commercial
2021-2022:
Ind FirmSale
2021-2022
Total
2022-2023:
Residential
2022-2023:
Commercial
2022-2023:
Ind FirmSale
2022-2023
Total
2023-2024:
Residential
2023-2024:
Commercial
2023-2024:
Ind FirmSale
2023-2024
Total
Klam Falls 942.55 469.32 13.67 1,425.54 954.61 471.70 13.66 1,439.97 971.13 476.10 13.69 1,460.92
La Grande 536.28 339.81 51.59 927.67 538.47 339.51 51.59 929.57 542.77 340.58 51.65 934.99
Medford GTN 2,385.62 1,463.65 18.87 3,868.14 2,413.83 1,471.44 18.86 3,904.14 2,451.23 1,484.50 18.90 3,954.64
Medford NWP 1,071.80 657.58 8.48 1,737.86 1,084.48 661.08 8.48 1,754.03 1,101.28 666.95 8.49 1,776.72
Roseburg 685.82 505.13 6.86 1,197.81 692.31 502.62 6.84 1,201.77 701.75 502.13 6.84 1,210.72
OR Sub-Total 5,622.07 3,435.48 99.47 9,157.02 5,683.69 3,446.36 99.43 9,229.48 5,768.15 3,470.26 99.58 9,337.99
Wa/Id Both 9,497.09 5,487.32 318.94 15,303.36 9,566.75 5,484.84 318.41 15,370.00 9,676.67 5,507.15 318.82 15,502.63
Wa/Id GTN 1,309.94 756.87 43.99 2,110.81 1,319.55 756.53 43.92 2,120.00 1,334.71 759.61 43.98 2,138.29
Wa/Id NWP 5,567.26 3,216.71 186.97 8,970.93 5,608.09 3,215.25 186.65 9,010.00 5,672.53 3,228.33 186.89 9,087.75
WA/ID Sub-Total 16,374.30 9,460.90 549.90 26,385.10 16,494.40 9,456.62 548.98 26,500.00 16,683.91 9,495.08 549.69 26,728.68
Case Total 21,996.37 12,896.38 649.37 35,542.12 22,178.09 12,902.98 648.41 35,729.48 22,452.06 12,965.34 649.26 36,066.67
Area
2024-2025:
Residential
2024-2025:
Commercial
2024-2025:
Ind FirmSale
2024-2025
Total
2025-2026:
Residential
2025-2026:
Commercial
2025-2026:
Ind FirmSale
2025-2026
Total
2026-2027:
Residential
2026-2027:
Commercial
2026-2027:
Ind FirmSale
2026-2027
Total
Klam Falls 977.72 476.11 13.64 1,467.47 988.49 478.03 13.64 1,480.16 998.86 479.88 13.63 1,492.37
La Grande 542.26 338.76 51.59 932.61 543.84 338.33 51.59 933.75 545.49 337.86 51.58 934.93
Medford GTN 2,467.10 1,485.67 18.84 3,971.61 2,492.86 1,492.53 18.83 4,004.22 2,517.84 1,499.09 18.82 4,035.75
Medford NWP 1,108.41 667.47 8.47 1,784.35 1,119.98 670.56 8.46 1,799.00 1,131.21 673.50 8.46 1,813.16
Roseburg 704.42 497.35 6.80 1,208.58 709.90 494.56 6.78 1,211.24 715.33 491.69 6.76 1,213.78
OR Sub-Total 5,799.91 3,465.36 99.34 9,364.62 5,855.07 3,474.01 99.30 9,428.37 5,908.72 3,482.02 99.25 9,489.99
Wa/Id Both 9,695.50 5,480.64 317.22 15,493.36 9,753.71 5,478.07 316.56 15,548.34 9,807.58 5,475.50 315.86 15,598.95
Wa/Id GTN 1,337.31 755.95 43.75 2,137.02 1,345.34 755.60 43.66 2,144.60 1,352.77 755.24 43.57 2,151.58
Wa/Id NWP 5,683.57 3,212.79 185.96 9,082.31 5,717.69 3,211.28 185.57 9,114.55 5,749.27 3,209.78 185.16 9,144.21
WA/ID Sub-Total 16,716.37 9,449.38 546.94 26,712.69 16,816.74 9,444.95 545.80 26,807.49 16,909.62 9,440.52 544.59 26,894.74
Case Total 22,516.29 12,914.74 646.28 36,077.31 22,671.80 12,918.96 645.10 36,235.86 22,818.35 12,922.54 643.84 36,384.73
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 97 of 648
APPENDIX 2.9: DETAILED DEMAND DATA
EXPECTED MIX

Area
2027-2028:
Residential
2027-2028:
Commercial
2027-2028:
Ind FirmSale
2027-2028
Total
2028-2029:
Residential
2028-2029:
Commercial
2028-2029:
Ind FirmSale
2028-2029
Total
2029-2030:
Residential
2029-2030:
Commercial
2029-2030:
Ind FirmSale
2029-2030
Total
Klam Falls 1,013.91 483.84 13.66 1,511.40 1,018.60 483.10 13.61 1,515.31 1,027.67 484.40 13.60 1,525.67
La Grande 549.70 338.84 51.65 940.18 549.43 336.92 51.58 937.93 551.45 336.40 51.58 939.44
Medford GTN 2,553.18 1,511.59 18.86 4,083.63 2,565.19 1,511.31 18.80 4,095.31 2,587.15 1,516.61 18.79 4,122.54
Medford NWP 1,147.08 679.12 8.47 1,834.68 1,152.48 679.00 8.45 1,839.92 1,162.34 681.37 8.44 1,852.16
Roseburg 724.07 490.92 6.76 1,221.75 726.08 485.95 6.72 1,218.75 731.18 482.97 6.70 1,220.85
OR Sub-Total 5,987.94 3,504.31 99.39 9,591.64 6,011.78 3,496.28 99.16 9,607.22 6,059.79 3,501.75 99.11 9,660.66
Wa/Id Both 9,905.61 5,498.42 316.14 15,720.17 10,157.79 5,964.84 272.10 16,394.73 9,956.47 5,469.60 313.66 15,739.72
Wa/Id GTN 1,366.29 758.40 43.60 2,168.30 1,401.07 822.74 37.53 2,261.34 1,373.31 754.43 43.26 2,171.00
Wa/Id NWP 5,806.74 3,223.21 185.32 9,215.27 5,954.56 3,496.63 159.51 9,610.70 5,836.55 3,206.32 183.87 9,226.73
WA/ID Sub-Total 17,078.65 9,480.04 545.06 27,103.75 17,513.42 10,284.21 469.14 28,266.77 17,166.33 9,430.34 540.79 27,137.45
Case Total 23,066.58 12,984.35 644.45 36,695.39 23,525.20 13,780.49 568.30 37,873.99 23,226.12 12,932.09 639.90 36,798.11
Area
2030-2031:
Residential
2030-2031:
Commercial
2030-2031:
Ind FirmSale
2030-2031
Total
2031-2032:
Residential
2031-2032:
Commercial
2031-2032:
Ind FirmSale
2031-2032
Total
2032-2033:
Residential
2032-2033:
Commercial
2032-2033:
Ind FirmSale
2032-2033
Total
Klam Falls 1,036.52 485.61 13.59 1,535.72 1,050.60 488.68 13.62 1,552.90 1,054.50 487.22 13.57 1,555.29
La Grande 553.32 335.84 51.58 940.75 557.45 336.53 51.65 945.62 556.72 334.33 51.58 942.63
Medford GTN 2,607.75 1,521.20 18.78 4,147.72 2,638.29 1,530.54 18.81 4,187.64 2,644.60 1,527.00 18.75 4,190.35
Medford NWP 1,171.60 683.44 8.44 1,863.47 1,185.32 687.63 8.45 1,881.40 1,188.15 686.04 8.43 1,882.62
Roseburg 735.80 479.95 6.68 1,222.42 743.49 478.46 6.68 1,228.62 744.20 472.89 6.64 1,223.73
OR Sub-Total 6,104.98 3,506.04 99.07 9,710.09 6,175.15 3,521.83 99.21 9,796.19 6,188.17 3,507.47 98.97 9,794.61
Wa/Id Both 10,001.73 5,468.16 312.88 15,782.77 10,093.08 5,491.61 312.93 15,897.62 10,087.42 5,463.91 310.97 15,862.30
Wa/Id GTN 1,379.55 754.23 43.16 2,176.93 1,392.15 757.46 43.16 2,192.78 1,391.37 753.64 42.89 2,187.90
Wa/Id NWP 5,863.08 3,205.47 183.41 9,251.97 5,916.63 3,219.22 183.44 9,319.29 5,913.32 3,202.98 182.29 9,298.59
WA/ID Sub-Total 17,244.37 9,427.86 539.44 27,211.67 17,401.87 9,468.28 539.54 27,409.69 17,392.10 9,420.53 536.16 27,348.79
Case Total 23,349.35 12,933.90 638.51 36,921.76 23,577.02 12,990.12 638.75 37,205.88 23,580.27 12,928.00 635.13 37,143.40
Area
2033-2034:
Residential
2033-2034:
Commercial
2033-2034:
Ind FirmSale
2033-2034
Total
2034-2035:
Residential
2034-2035:
Commercial
2034-2035:
Ind FirmSale
2034-2035
Total
Klam Falls 1,063.67 488.25 13.56 1,565.49 1,075.10 491.99 13.56 1,580.65
La Grande 558.28 333.61 51.58 943.47 560.98 334.59 51.58 947.15
Medford GTN 2,661.38 1,529.49 18.74 4,209.60 2,682.89 1,539.57 18.74 4,241.20
Medford NWP 1,195.69 687.16 8.42 1,891.27 1,205.36 691.69 8.42 1,905.47
Roseburg 748.29 469.45 6.61 1,224.35 754.40 469.84 6.61 1,230.85
OR Sub-Total 6,227.31 3,507.95 98.92 9,834.19 6,278.73 3,527.68 98.92 9,905.32
Wa/Id Both 10,128.43 5,463.40 309.97 15,901.81 10,223.55 5,492.78 309.81 16,026.14
Wa/Id GTN 1,397.02 753.57 42.76 2,193.35 1,410.14 757.63 42.73 2,210.50
Wa/Id NWP 5,937.35 3,202.68 181.71 9,321.75 5,993.12 3,219.91 181.61 9,394.64
WA/ID Sub-Total 17,462.81 9,419.66 534.44 27,416.91 17,626.81 9,470.31 534.15 27,631.28
Case Total 23,690.12 12,927.61 633.36 37,251.10 23,905.54 12,997.99 633.07 37,536.60
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 98 of 648
APPENDIX 2.9: DETAILED DEMAND DATA
LOW GROWTH HIGH PRICE

Area
2015-2016:
Residential
2015-2016:
Commercial
2015-2016:
Ind FirmSale
2015-2016
Total
2016-2017:
Residential
2016-2017:
Commercial
2016-2017:
Ind FirmSale
2016-2017
Total
2017-2018:
Residential
2017-2018:
Commercial
2017-2018:
Ind FirmSale
2017-2018
Total
Klam Falls 878.73 456.34 13.25 1,348.33 784.79 413.85 12.94 1,211.58 785.84 411.79 12.74 1,210.37
La Grande 523.38 341.60 49.54 914.51 476.91 311.28 47.68 835.86 475.28 309.11 46.64 831.02
Medford GTN 2,171.64 1,392.98 18.54 3,583.15 1,954.24 1,271.50 17.93 3,243.67 1,960.80 1,268.08 17.71 3,246.59
Medford NWP 975.66 625.83 8.33 1,609.82 877.99 571.25 8.06 1,457.30 880.94 569.72 7.96 1,458.61
Roseburg 650.80 516.46 6.93 1,174.19 583.95 468.19 6.62 1,058.76 583.64 463.08 6.42 1,053.14
OR Sub-Total 5,200.21 3,333.21 96.59 8,630.00 4,677.88 3,036.07 93.22 7,807.17 4,686.50 3,021.76 91.47 7,799.73
Wa/Id Both 9,048.98 5,504.45 318.94 14,872.37 8,044.49 4,898.26 300.26 13,243.01 8,013.36 4,843.68 298.32 13,155.35
Wa/Id GTN 1,248.13 759.23 43.99 2,051.36 1,109.59 675.62 41.42 1,826.62 1,105.29 668.09 41.15 1,814.53
Wa/Id NWP 5,304.57 3,226.74 186.97 8,718.29 4,715.74 2,871.39 176.02 7,763.15 4,697.49 2,839.40 174.87 7,711.76
WA/ID Sub-Total 15,601.68 9,490.43 549.90 25,642.02 13,869.82 8,445.27 517.69 22,832.78 13,816.14 8,351.17 514.34 22,681.64
Case Total 20,801.89 12,823.64 646.49 34,272.02 18,547.70 11,481.34 610.92 30,639.96 18,502.63 11,372.93 605.81 30,481.37
Area
2018-2019:
Residential
2018-2019:
Commercial
2018-2019:
Ind FirmSale
2018-2019
Total
2019-2020:
Residential
2019-2020:
Commercial
2019-2020:
Ind FirmSale
2019-2020
Total
2020-2021:
Residential
2020-2021:
Commercial
2020-2021:
Ind FirmSale
2020-2021
Total
Klam Falls 783.45 408.90 12.53 1,204.88 793.17 410.93 12.39 1,216.48 795.15 408.89 12.19 1,216.22
La Grande 472.03 305.89 45.47 823.39 474.50 306.08 44.66 825.24 472.94 303.57 43.74 820.24
Medford GTN 1,960.85 1,260.45 17.47 3,238.77 1,988.78 1,267.45 17.34 3,273.57 1,999.20 1,263.80 17.12 3,280.12
Medford NWP 880.96 566.29 7.85 1,455.10 893.51 569.43 7.79 1,470.73 898.19 567.80 7.69 1,473.68
Roseburg 581.16 456.43 6.22 1,043.82 587.22 454.96 6.04 1,048.23 588.03 449.48 5.84 1,043.34
OR Sub-Total 4,678.46 2,997.96 89.54 7,765.95 4,737.18 3,008.85 88.22 7,834.26 4,753.50 2,993.53 86.56 7,833.60
Wa/Id Both 7,945.45 4,767.49 295.58 13,008.51 7,996.43 4,755.97 295.26 13,047.67 7,978.70 4,702.37 293.03 12,974.10
Wa/Id GTN 1,095.92 657.58 40.77 1,794.28 1,102.96 656.00 40.73 1,799.68 1,100.51 648.60 40.42 1,789.53
Wa/Id NWP 4,657.68 2,794.73 173.27 7,625.68 4,687.56 2,787.99 173.09 7,648.63 4,677.17 2,756.56 171.78 7,605.51
WA/ID Sub-Total 13,699.05 8,219.80 509.61 22,428.46 13,786.95 8,199.96 509.08 22,495.98 13,756.38 8,107.53 505.23 22,369.14
Case Total 18,377.50 11,217.77 599.15 30,194.42 18,524.13 11,208.81 597.30 30,330.24 18,509.88 11,101.06 591.80 30,202.73
Area
2021-2022:
Residential
2021-2022:
Commercial
2021-2022:
Ind FirmSale
2021-2022
Total
2022-2023:
Residential
2022-2023:
Commercial
2022-2023:
Ind FirmSale
2022-2023
Total
2023-2024:
Residential
2023-2024:
Commercial
2023-2024:
Ind FirmSale
2023-2024
Total
Klam Falls 801.00 408.70 12.02 1,221.72 806.22 408.03 11.84 1,226.10 815.60 409.27 11.71 1,236.58
La Grande 473.29 302.26 42.89 818.44 473.32 300.68 42.04 816.04 475.53 300.51 41.24 817.29
Medford GTN 2,014.60 1,263.93 16.94 3,295.47 2,025.55 1,262.12 16.76 3,304.43 2,045.26 1,265.36 16.63 3,327.25
Medford NWP 905.11 567.85 7.61 1,480.57 910.03 567.04 7.53 1,484.60 918.88 568.50 7.47 1,494.85
Roseburg 591.51 445.68 5.64 1,042.84 594.56 441.34 5.45 1,041.35 600.45 438.96 5.27 1,044.69
OR Sub-Total 4,785.51 2,988.43 85.10 7,859.04 4,809.69 2,979.20 83.62 7,872.52 4,855.73 2,982.60 82.32 7,920.65
Wa/Id Both 7,994.38 4,670.94 291.71 12,957.02 8,000.69 4,636.81 290.25 12,927.75 8,045.32 4,626.57 289.73 12,961.62
Wa/Id GTN 1,102.67 644.27 40.24 1,787.18 1,103.54 639.56 40.03 1,783.14 1,109.70 638.15 39.96 1,787.81
Wa/Id NWP 4,686.36 2,738.14 171.00 7,595.49 4,690.06 2,718.13 170.14 7,578.34 4,716.22 2,712.13 169.84 7,598.19
WA/ID Sub-Total 13,783.41 8,053.34 502.94 22,339.69 13,794.30 7,994.50 500.43 22,289.23 13,871.24 7,976.85 499.54 22,347.63
Case Total 18,568.92 11,041.77 588.04 30,198.73 18,604.00 10,973.70 584.05 30,161.74 18,726.97 10,959.45 581.86 30,268.28
Area
2024-2025:
Residential
2024-2025:
Commercial
2024-2025:
Ind FirmSale
2024-2025
Total
2025-2026:
Residential
2025-2026:
Commercial
2025-2026:
Ind FirmSale
2025-2026
Total
2026-2027:
Residential
2026-2027:
Commercial
2026-2027:
Ind FirmSale
2026-2027
Total
Klam Falls 812.99 405.29 11.49 1,229.77 817.28 404.38 11.32 1,232.98 821.70 403.61 11.15 1,236.45
La Grande 472.05 296.96 40.26 809.27 471.96 295.55 39.41 806.92 471.88 294.06 38.57 804.51
Medford GTN 2,038.17 1,254.11 16.38 3,308.67 2,046.96 1,251.60 16.20 3,314.76 2,055.95 1,249.30 16.03 3,321.29
Medford NWP 915.70 563.44 7.36 1,486.50 919.65 562.31 7.28 1,489.24 923.69 561.28 7.20 1,492.17
Roseburg 598.00 431.38 5.07 1,034.45 600.28 426.97 4.87 1,032.13 602.73 422.63 4.68 1,030.05
OR Sub-Total 4,836.91 2,951.19 80.56 7,868.66 4,856.13 2,940.80 79.09 7,876.02 4,875.96 2,930.89 77.63 7,884.47
Wa/Id Both 7,976.79 4,556.38 286.73 12,819.91 7,974.78 4,524.52 285.19 12,784.49 7,973.22 4,495.21 283.68 12,752.11
Wa/Id GTN 1,100.25 628.47 39.55 1,768.26 1,099.97 624.07 39.34 1,763.38 1,099.75 620.03 39.13 1,758.91
Wa/Id NWP 4,676.05 2,670.98 168.09 7,515.12 4,674.87 2,652.30 167.18 7,494.36 4,673.95 2,635.12 166.30 7,475.37
WA/ID Sub-Total 13,753.09 7,855.84 494.37 22,103.30 13,749.62 7,800.89 491.71 22,042.22 13,746.92 7,750.36 489.10 21,986.39
Case Total 18,590.01 10,807.03 574.93 29,971.96 18,605.76 10,741.69 570.80 29,918.24 18,622.88 10,681.25 566.73 29,870.86
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 99 of 648
APPENDIX 2.9: DETAILED DEMAND DATA
LOW GROWTH HIGH PRICE

Area
2027-2028:
Residential
2027-2028:
Commercial
2027-2028:
Ind FirmSale
2027-2028
Total
2028-2029:
Residential
2028-2029:
Commercial
2028-2029:
Ind FirmSale
2028-2029
Total
2029-2030:
Residential
2029-2030:
Commercial
2029-2030:
Ind FirmSale
2029-2030
Total
Klam Falls 829.89 404.59 11.01 1,245.50 827.03 400.66 10.79 1,238.49 829.81 399.28 10.62 1,239.71
La Grande 473.52 293.53 37.77 804.82 469.83 289.62 36.83 796.28 468.96 287.43 35.97 792.36
Medford GTN 2,073.14 1,251.89 15.89 3,340.92 2,065.09 1,240.80 15.66 3,321.55 2,069.47 1,236.51 15.48 3,321.46
Medford NWP 931.41 562.44 7.14 1,500.99 927.79 557.46 7.04 1,492.29 929.76 555.54 6.95 1,492.25
Roseburg 607.86 420.04 4.50 1,032.40 605.41 412.80 4.29 1,022.50 606.88 408.03 4.10 1,019.01
OR Sub-Total 4,915.82 2,932.50 76.31 7,924.63 4,895.16 2,901.35 74.61 7,871.11 4,904.89 2,886.80 73.12 7,864.80
Wa/Id Both 8,006.61 4,486.72 283.02 12,776.36 7,935.51 4,423.54 280.09 12,639.15 7,918.39 4,390.87 278.35 12,587.61
Wa/Id GTN 1,104.36 618.86 39.04 1,762.26 1,094.55 610.14 38.63 1,743.33 1,092.19 605.64 38.39 1,736.22
Wa/Id NWP 4,693.53 2,630.15 165.91 7,489.59 4,651.85 2,593.11 164.19 7,409.15 4,641.82 2,573.96 163.17 7,378.95
WA/ID Sub-Total 13,804.50 7,735.73 487.96 22,028.20 13,681.92 7,626.80 482.92 21,791.63 13,652.40 7,570.47 479.91 21,702.78
Case Total 18,720.33 10,668.23 564.28 29,952.83 18,577.07 10,528.14 557.53 29,662.75 18,557.29 10,457.26 553.03 29,567.58
Area
2030-2031:
Residential
2030-2031:
Commercial
2030-2031:
Ind FirmSale
2030-2031
Total
2031-2032:
Residential
2031-2032:
Commercial
2031-2032:
Ind FirmSale
2031-2032
Total
2032-2033:
Residential
2032-2033:
Commercial
2032-2033:
Ind FirmSale
2032-2033
Total
Klam Falls 831.73 397.56 10.44 1,239.73 838.13 397.40 10.30 1,245.82 837.66 394.06 10.10 1,241.82
La Grande 467.86 285.17 35.09 788.12 468.99 284.12 34.27 787.38 466.82 281.11 33.39 781.32
Medford GTN 2,071.20 1,230.91 15.29 3,317.41 2,081.92 1,229.56 15.15 3,326.63 2,076.84 1,219.53 14.93 3,311.30
Medford NWP 930.54 553.02 6.87 1,490.43 935.36 552.41 6.80 1,494.57 933.07 547.90 6.71 1,487.68
Roseburg 607.56 403.05 3.90 1,014.52 611.14 399.54 3.72 1,014.39 609.96 393.17 3.52 1,006.64
OR Sub-Total 4,908.90 2,869.71 71.60 7,850.21 4,935.54 2,863.02 70.24 7,868.80 4,924.35 2,835.76 68.65 7,828.76
Wa/Id Both 7,892.35 4,355.20 276.46 12,524.01 7,906.68 4,341.60 275.35 12,523.64 7,857.20 4,294.09 272.70 12,423.99
Wa/Id GTN 1,088.60 600.72 38.13 1,727.45 1,090.58 598.84 37.98 1,727.40 1,083.75 592.29 37.61 1,713.65
Wa/Id NWP 4,626.55 2,553.05 162.06 7,341.66 4,634.95 2,545.08 161.41 7,341.44 4,605.95 2,517.22 159.86 7,283.03
WA/ID Sub-Total 13,607.50 7,508.97 476.65 21,593.12 13,632.20 7,485.53 474.75 21,592.48 13,546.90 7,403.60 470.17 21,420.67
Case Total 18,516.40 10,378.68 548.25 29,443.33 18,567.74 10,348.55 544.98 29,461.27 18,471.25 10,239.37 538.81 29,249.43
Area
2033-2034:
Residential
2033-2034:
Commercial
2033-2034:
Ind FirmSale
2033-2034
Total
2034-2035:
Residential
2034-2035:
Commercial
2034-2035:
Ind FirmSale
2034-2035
Total
Klam Falls 839.85 392.15 9.92 1,241.91 845.13 393.31 9.76 1,248.19
La Grande 466.13 279.12 32.53 777.78 467.06 279.09 31.68 777.83
Medford GTN 2,076.80 1,212.82 14.75 3,304.37 2,083.81 1,214.86 14.58 3,313.25
Medford NWP 933.05 544.89 6.62 1,484.57 936.21 545.81 6.55 1,488.56
Roseburg 610.56 388.05 3.32 1,001.92 613.78 387.10 3.15 1,004.03
OR Sub-Total 4,926.38 2,817.03 67.14 7,810.55 4,945.99 2,820.16 65.71 7,831.86
Wa/Id Both 7,830.22 4,261.56 270.65 12,362.43 7,865.82 4,263.33 269.57 12,398.72
Wa/Id GTN 1,080.03 587.80 37.33 1,705.16 1,084.94 588.05 37.18 1,710.17
Wa/Id NWP 4,590.13 2,498.16 158.65 7,246.94 4,611.00 2,499.19 158.02 7,268.21
WA/ID Sub-Total 13,500.38 7,347.52 466.63 21,314.53 13,561.77 7,350.57 464.77 21,377.10
Case Total 18,426.76 10,164.54 533.78 29,125.08 18,507.75 10,170.73 530.48 29,208.96
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 100 of 648
APPENDIX 2.9: DETAILED DEMAND DATA
HIGH GROWTH LOW PRICE

Area
2015-2016:
Residential
2015-2016:
Commercial
2015-2016:
Ind FirmSale
2015-2016
Total
2016-2017:
Residential
2016-2017:
Commercial
2016-2017:
Ind FirmSale
2016-2017
Total
2017-2018:
Residential
2017-2018:
Commercial
2017-2018:
Ind FirmSale
2017-2018
Total
Klam Falls 879.42 456.91 13.40 1,349.73 886.26 457.41 13.98 1,357.65 901.22 461.87 14.17 1,377.26
La Grande 525.19 342.86 50.38 918.43 527.22 341.59 53.30 922.11 531.92 343.36 54.32 929.60
Medford GTN 2,188.06 1,405.08 18.70 3,611.84 2,224.48 1,419.59 19.22 3,663.29 2,275.38 1,442.37 19.42 3,737.17
Medford NWP 983.04 631.27 8.40 1,622.71 999.40 637.79 8.63 1,645.83 1,022.27 648.02 8.72 1,679.02
Roseburg 652.93 518.47 7.08 1,178.48 657.86 516.88 7.23 1,181.97 666.35 517.78 7.40 1,191.53
OR Sub-Total 5,228.65 3,354.58 97.95 8,681.19 5,295.23 3,373.25 102.37 8,770.85 5,397.13 3,413.41 104.04 8,914.58
Wa/Id Both 9,105.46 5,541.59 319.99 14,967.04 9,176.71 5,530.67 322.39 15,029.77 9,305.69 5,566.49 323.70 15,195.88
Wa/Id GTN 1,255.93 764.36 44.14 2,064.42 1,265.75 762.85 44.47 2,073.07 1,283.54 767.79 44.65 2,095.98
Wa/Id NWP 5,337.68 3,248.52 187.58 8,773.78 5,379.45 3,242.12 188.99 8,810.56 5,455.06 3,263.11 189.76 8,907.93
WA/ID Sub-Total 15,699.06 9,554.47 551.71 25,805.24 15,821.92 9,535.64 555.84 25,913.40 16,044.29 9,597.39 558.10 26,199.79
Case Total 20,927.71 12,909.05 649.66 34,486.42 21,117.14 12,908.90 658.21 34,684.24 21,441.43 13,010.80 662.14 35,114.37
Area
2018-2019:
Residential
2018-2019:
Commercial
2018-2019:
Ind FirmSale
2018-2019
Total
2019-2020:
Residential
2019-2020:
Commercial
2019-2020:
Ind FirmSale
2019-2020
Total
2020-2021:
Residential
2020-2021:
Commercial
2020-2021:
Ind FirmSale
2020-2021
Total
Klam Falls 916.82 467.32 14.36 1,398.50 937.37 474.69 14.58 1,426.65 949.84 477.85 14.73 1,442.42
La Grande 536.84 345.16 55.30 937.30 544.04 348.34 56.43 948.81 547.02 348.70 57.44 953.16
Medford GTN 2,329.05 1,465.54 19.62 3,814.20 2,393.73 1,494.55 19.87 3,908.15 2,439.32 1,511.97 20.01 3,971.30
Medford NWP 1,046.38 658.43 8.81 1,713.63 1,075.45 671.46 8.93 1,755.84 1,095.93 679.29 8.99 1,784.21
Roseburg 675.36 518.80 7.58 1,201.74 687.75 521.64 7.77 1,217.15 694.56 520.25 7.93 1,222.74
OR Sub-Total 5,504.46 3,455.24 105.67 9,065.36 5,638.33 3,510.69 107.58 9,256.60 5,726.67 3,538.06 109.11 9,373.83
Wa/Id Both 9,435.79 5,599.81 324.82 15,360.42 9,610.88 5,656.98 326.81 15,594.66 9,711.36 5,668.18 326.75 15,706.29
Wa/Id GTN 1,301.49 772.39 44.80 2,118.68 1,325.64 780.27 45.08 2,150.99 1,339.50 781.82 45.07 2,166.39
Wa/Id NWP 5,531.32 3,282.65 190.41 9,004.39 5,633.96 3,316.16 191.58 9,141.70 5,692.87 3,322.73 191.54 9,207.14
WA/ID Sub-Total 16,268.60 9,654.85 560.04 26,483.49 16,570.48 9,753.41 563.46 26,887.34 16,743.73 9,772.72 563.36 27,079.81
Case Total 21,773.06 13,110.09 665.71 35,548.85 22,208.81 13,264.09 671.04 36,143.94 22,470.39 13,310.78 672.47 36,453.65
Area
2021-2022:
Residential
2021-2022:
Commercial
2021-2022:
Ind FirmSale
2021-2022
Total
2022-2023:
Residential
2022-2023:
Commercial
2022-2023:
Ind FirmSale
2022-2023
Total
2023-2024:
Residential
2023-2024:
Commercial
2023-2024:
Ind FirmSale
2023-2024
Total
Klam Falls 967.06 483.26 14.92 1,465.24 984.36 488.46 15.11 1,487.92 1,006.50 495.84 15.35 1,517.69
La Grande 552.21 350.44 58.53 961.18 557.28 352.02 59.62 968.93 564.42 354.93 60.80 980.15
Medford GTN 2,488.57 1,532.30 20.22 4,041.08 2,532.03 1,549.99 20.42 4,102.43 2,585.61 1,573.46 20.67 4,179.74
Medford NWP 1,118.05 688.42 9.08 1,815.56 1,137.58 696.37 9.17 1,843.12 1,161.65 706.91 9.29 1,877.86
Roseburg 704.56 520.79 8.10 1,233.46 714.55 520.98 8.28 1,243.81 727.72 523.29 8.48 1,259.48
OR Sub-Total 5,830.45 3,575.21 110.86 9,516.52 5,925.80 3,607.82 112.61 9,646.22 6,045.90 3,654.43 114.59 9,814.92
Wa/Id Both 9,844.66 5,700.76 327.64 15,873.05 9,968.46 5,730.12 328.46 16,027.04 10,135.92 5,785.90 330.28 16,252.10
Wa/Id GTN 1,357.88 786.31 45.19 2,189.39 1,374.96 790.36 45.30 2,210.63 1,398.06 798.06 45.56 2,241.67
Wa/Id NWP 5,771.01 3,341.82 192.06 9,304.89 5,843.58 3,359.04 192.54 9,395.16 5,941.75 3,391.74 193.61 9,527.10
WA/ID Sub-Total 16,973.55 9,828.89 564.89 27,367.33 17,187.00 9,879.52 566.31 27,632.83 17,475.72 9,975.70 569.45 28,020.87
Case Total 22,804.00 13,404.10 675.75 36,883.85 23,112.80 13,487.34 678.91 37,279.05 23,521.63 13,630.12 684.04 37,835.79
Area
2024-2025:
Residential
2024-2025:
Commercial
2024-2025:
Ind FirmSale
2024-2025
Total
2025-2026:
Residential
2025-2026:
Commercial
2025-2026:
Ind FirmSale
2025-2026
Total
2026-2027:
Residential
2026-2027:
Commercial
2026-2027:
Ind FirmSale
2026-2027
Total
Klam Falls 1,018.41 498.67 15.49 1,532.57 1,034.61 503.46 15.69 1,553.76 1,050.14 508.06 15.88 1,574.08
La Grande 566.40 354.73 61.83 982.95 570.42 355.88 62.93 989.23 574.79 357.17 64.04 996.00
Medford GTN 2,617.04 1,584.62 20.82 4,222.48 2,659.19 1,601.94 21.03 4,282.16 2,700.20 1,618.77 21.23 4,340.19
Medford NWP 1,175.77 711.93 9.35 1,897.06 1,194.71 719.71 9.45 1,923.87 1,213.13 727.27 9.54 1,949.94
Roseburg 733.89 521.11 8.64 1,263.63 742.95 520.94 8.82 1,272.70 751.91 520.64 9.00 1,281.55
OR Sub-Total 6,111.51 3,671.05 116.14 9,898.70 6,201.88 3,701.94 117.91 10,021.72 6,290.17 3,731.91 119.67 10,141.75
Wa/Id Both 10,209.33 5,790.84 330.04 16,330.21 10,323.85 5,820.46 330.77 16,475.09 10,431.66 5,848.64 331.43 16,611.73
Wa/Id GTN 1,408.18 798.74 45.52 2,252.44 1,423.98 802.82 45.62 2,272.43 1,438.85 806.71 45.71 2,291.27
Wa/Id NWP 5,984.78 3,394.63 193.47 9,572.88 6,051.91 3,411.99 193.90 9,657.81 6,115.11 3,428.51 194.29 9,737.91
WA/ID Sub-Total 17,602.29 9,984.21 569.04 28,155.54 17,799.75 10,035.28 570.30 28,405.32 17,985.62 10,083.86 571.43 28,640.91
Case Total 23,713.80 13,655.27 685.17 38,054.24 24,001.62 13,737.21 688.21 38,427.04 24,275.79 13,815.77 691.10 38,782.66
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 101 of 648
APPENDIX 2.9: DETAILED DEMAND DATA
HIGH GROWTH LOW PRICE

Area
2027-2028:
Residential
2027-2028:
Commercial
2027-2028:
Ind FirmSale
2027-2028
Total
2028-2029:
Residential
2028-2029:
Commercial
2028-2029:
Ind FirmSale
2028-2029
Total
2029-2030:
Residential
2029-2030:
Commercial
2029-2030:
Ind FirmSale
2029-2030
Total
Klam Falls 1,070.79 514.95 16.12 1,601.86 1,080.40 516.79 16.27 1,613.46 1,094.37 520.67 16.46 1,631.50
La Grande 582.64 360.48 65.23 1,008.35 586.26 361.03 66.27 1,013.56 592.25 363.01 67.39 1,022.65
Medford GTN 2,752.96 1,642.30 21.49 4,416.75 2,780.71 1,652.04 21.64 4,454.39 2,819.12 1,667.76 21.84 4,508.73
Medford NWP 1,236.84 737.85 9.65 1,984.34 1,249.31 742.22 9.72 2,001.25 1,266.56 749.28 9.81 2,025.66
Roseburg 764.61 522.67 9.20 1,296.48 770.23 520.24 9.36 1,299.82 779.05 519.84 9.54 1,308.43
OR Sub-Total 6,407.84 3,778.25 121.69 10,307.78 6,466.91 3,792.32 123.25 10,382.48 6,551.36 3,820.57 125.04 10,496.98
Wa/Id Both 10,589.01 5,905.03 333.15 16,827.19 10,646.38 5,908.17 332.78 16,887.33 10,750.43 5,937.95 333.43 17,021.81
Wa/Id GTN 1,460.55 814.49 45.95 2,320.99 1,468.47 814.92 45.90 2,329.29 1,482.82 819.03 45.99 2,347.84
Wa/Id NWP 6,207.35 3,461.57 195.29 9,864.21 6,240.98 3,463.41 195.08 9,899.47 6,301.98 3,480.86 195.46 9,978.30
WA/ID Sub-Total 18,256.92 10,181.08 574.39 29,012.39 18,355.83 10,186.49 573.76 29,116.08 18,535.23 10,237.84 574.88 29,347.94
Case Total 24,664.76 13,959.33 696.09 39,320.17 24,822.74 13,978.81 697.01 39,498.56 25,086.59 14,058.41 699.92 39,844.92
Area
2030-2031:
Residential
2030-2031:
Commercial
2030-2031:
Ind FirmSale
2030-2031
Total
2031-2032:
Residential
2031-2032:
Commercial
2031-2032:
Ind FirmSale
2031-2032
Total
2032-2033:
Residential
2032-2033:
Commercial
2032-2033:
Ind FirmSale
2032-2033
Total
Klam Falls 1,108.07 524.42 16.66 1,649.15 1,127.49 530.27 16.90 1,674.66 1,136.19 531.33 17.05 1,684.57
La Grande 597.76 364.75 68.51 1,031.03 605.46 367.67 69.73 1,042.87 607.68 367.33 70.77 1,045.79
Medford GTN 2,855.97 1,682.67 22.05 4,560.68 2,903.56 1,702.79 22.32 4,628.66 2,924.52 1,708.66 22.46 4,655.64
Medford NWP 1,283.12 755.98 9.91 2,049.00 1,304.50 765.02 10.03 2,079.54 1,313.91 767.66 10.09 2,091.67 Roseburg 787.15 519.22 9.72 1,316.09 798.39 520.17 9.93 1,328.49 802.16 516.68 10.09 1,328.93
OR Sub-Total 6,632.06 3,847.04 126.85 10,605.95 6,739.40 3,885.93 128.91 10,754.23 6,784.46 3,891.67 130.47 10,806.59
Wa/Id Both 10,852.38 5,967.92 334.06 17,154.37 11,004.70 6,024.98 335.59 17,365.27 11,052.65 6,026.60 334.98 17,414.23
Wa/Id GTN 1,496.88 823.16 46.08 2,366.12 1,517.89 831.03 46.29 2,395.21 1,524.50 831.26 46.20 2,401.96
Wa/Id NWP 6,361.74 3,498.44 195.83 10,056.01 6,451.03 3,531.89 196.73 10,179.64 6,479.14 3,532.83 196.37 10,208.34
WA/ID Sub-Total 18,711.01 10,289.53 575.97 29,576.50 18,973.62 10,387.90 578.61 29,940.13 19,056.30 10,390.69 577.55 30,024.54
Case Total 25,343.07 14,136.56 702.81 40,182.44 25,713.02 14,273.83 707.52 40,694.36 25,840.76 14,282.36 708.02 40,831.13
Area
2033-2034:
Residential
2033-2034:
Commercial
2033-2034:
Ind FirmSale
2033-2034
Total
2034-2035:
Residential
2034-2035:
Commercial
2034-2035:
Ind FirmSale
2034-2035
Total
Klam Falls 1,150.68 535.13 17.24 1,703.05 1,167.40 541.60 17.45 1,726.45
La Grande 612.05 368.38 71.91 1,052.34 617.39 371.02 73.04 1,061.45
Medford GTN 2,956.89 1,721.12 22.67 4,700.69 2,993.61 1,740.99 22.89 4,757.49
Medford NWP 1,328.46 773.26 10.19 2,111.90 1,344.96 782.18 10.28 2,137.43
Roseburg 809.53 515.46 10.27 1,335.26 818.86 518.02 10.48 1,347.35
OR Sub-Total 6,857.62 3,913.34 132.28 10,903.25 6,942.22 3,953.81 134.15 11,030.17
Wa/Id Both 11,151.67 6,057.67 335.41 17,544.75 11,304.35 6,118.24 336.65 17,759.24
Wa/Id GTN 1,538.16 835.54 46.26 2,419.97 1,559.22 843.89 46.43 2,449.55
Wa/Id NWP 6,537.19 3,551.05 196.62 10,284.85 6,626.69 3,586.55 197.35 10,410.59
WA/ID Sub-Total 19,227.02 10,444.26 578.29 30,249.57 19,490.26 10,548.69 580.44 30,619.38
Case Total 26,084.64 14,357.61 710.57 41,152.82 26,432.47 14,502.49 714.58 41,649.55
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 102 of 648
APPENDIX 2.9: DETAILED DEMAND DATA
AVERAGE MIX

Area
2015-2016:
Residential
2015-2016:
Commercial
2015-2016:
Ind FirmSale
2015-2016
Total
2016-2017:
Residential
2016-2017:
Commercial
2016-2017:
Ind FirmSale
2016-2017
Total
2017-2018:
Residential
2017-2018:
Commercial
2017-2018:
Ind FirmSale
2017-2018
Total
Klam Falls 850.06 444.21 13.19 1,307.46 854.74 443.45 13.58 1,311.77 865.67 445.75 13.57 1,325.00
La Grande 505.58 330.86 49.79 886.23 505.70 328.40 51.66 885.75 508.09 328.65 51.60 888.34
Medford GTN 2,094.68 1,356.35 18.43 3,469.46 2,115.07 1,360.38 18.74 3,494.18 2,149.88 1,372.86 18.73 3,541.47
Medford NWP 941.09 609.38 8.28 1,558.74 950.25 611.18 8.42 1,569.85 965.89 616.79 8.41 1,591.10
Roseburg 621.74 497.82 6.98 1,126.54 624.15 494.28 6.94 1,125.37 629.75 492.94 6.92 1,129.62
OR Sub-Total 5,013.14 3,238.63 96.66 8,348.43 5,049.90 3,237.69 99.33 8,386.92 5,119.28 3,257.00 99.24 8,475.52
Wa/Id Both 8,762.08 5,348.54 314.56 14,425.18 8,782.21 5,307.62 315.68 14,405.51 8,858.55 5,311.94 315.67 14,486.15
Wa/Id GTN 1,208.56 737.73 43.39 1,989.68 1,211.34 732.09 43.54 1,986.97 1,221.87 732.68 43.54 1,998.09
Wa/Id NWP 5,136.39 3,135.35 184.40 8,456.14 5,148.19 3,111.36 185.05 8,444.61 5,192.94 3,113.90 185.05 8,491.88
WA/ID Sub-Total 15,107.03 9,221.63 542.34 24,871.00 15,141.75 9,151.07 544.27 24,837.09 15,273.36 9,158.52 544.25 24,976.13
Case Total 20,120.17 12,460.25 639.01 33,219.43 20,191.65 12,388.76 643.60 33,224.02 20,392.64 12,415.52 643.49 33,451.65
Area
2018-2019:
Residential
2018-2019:
Commercial
2018-2019:
Ind FirmSale
2018-2019
Total
2019-2020:
Residential
2019-2020:
Commercial
2019-2020:
Ind FirmSale
2019-2020
Total
2020-2021:
Residential
2020-2021:
Commercial
2020-2021:
Ind FirmSale
2020-2021
Total
Klam Falls 876.78 448.78 13.56 1,339.11 892.50 453.57 13.59 1,359.66 899.68 453.96 13.54 1,367.18
La Grande 510.46 328.79 51.51 890.76 514.96 330.22 51.55 896.72 515.04 328.71 51.47 895.22
Medford GTN 2,186.38 1,385.19 18.72 3,590.29 2,233.15 1,402.98 18.76 3,654.89 2,260.17 1,408.92 18.70 3,687.79
Medford NWP 982.29 622.33 8.41 1,613.03 1,003.30 630.32 8.43 1,642.05 1,015.44 632.99 8.40 1,656.83
Roseburg 635.60 491.55 6.90 1,134.05 644.61 491.88 6.90 1,143.39 647.78 487.84 6.86 1,142.49
OR Sub-Total 5,191.50 3,276.63 99.10 8,567.23 5,288.52 3,308.97 99.22 8,696.72 5,338.10 3,312.43 98.98 8,749.52
Wa/Id Both 8,932.48 5,312.30 315.45 14,560.22 9,048.65 5,335.24 316.09 14,699.98 9,087.02 5,310.86 314.68 14,712.55
Wa/Id GTN 1,232.07 732.73 43.51 2,008.31 1,248.09 735.90 43.60 2,027.58 1,253.38 732.53 43.40 2,029.32
Wa/Id NWP 5,236.28 3,114.11 184.92 8,535.30 5,304.38 3,127.56 185.29 8,617.23 5,326.87 3,113.26 184.47 8,624.60
WA/ID Sub-Total 15,400.82 9,159.14 543.87 25,103.84 15,601.12 9,198.70 544.98 25,344.79 15,667.27 9,156.65 542.55 25,366.47
Case Total 20,592.32 12,435.76 642.97 33,671.06 20,889.63 12,507.67 644.20 34,041.51 21,005.38 12,469.08 641.53 34,115.98
Area
2021-2022:
Residential
2021-2022:
Commercial
2021-2022:
Ind FirmSale
2021-2022
Total
2022-2023:
Residential
2022-2023:
Commercial
2022-2023:
Ind FirmSale
2022-2023
Total
2023-2024:
Residential
2023-2024:
Commercial
2023-2024:
Ind FirmSale
2023-2024
Total
Klam Falls 911.27 456.44 13.54 1,381.26 922.88 458.69 13.53 1,395.09 938.94 462.95 13.56 1,415.45
La Grande 517.21 328.51 51.47 897.19 519.29 328.17 51.47 898.93 523.47 329.19 51.53 904.20
Medford GTN 2,291.59 1,418.24 18.69 3,728.51 2,318.50 1,425.57 18.68 3,762.74 2,354.64 1,438.17 18.72 3,811.53
Medford NWP 1,029.56 637.18 8.40 1,675.13 1,041.64 640.47 8.39 1,690.51 1,057.88 646.14 8.41 1,712.43
Roseburg 653.93 485.63 6.84 1,146.41 660.04 483.08 6.83 1,149.95 669.11 482.55 6.82 1,158.48
OR Sub-Total 5,403.56 3,326.00 98.94 8,828.50 5,462.35 3,335.98 98.90 8,897.22 5,544.05 3,359.00 99.04 9,002.09
Wa/Id Both 9,159.26 5,308.69 314.19 14,782.14 9,224.82 5,305.07 313.65 14,843.54 9,330.68 5,326.21 314.06 14,970.96
Wa/Id GTN 1,263.35 732.23 43.34 2,038.92 1,272.39 731.73 43.26 2,047.38 1,286.99 734.65 43.32 2,064.96
Wa/Id NWP 5,369.22 3,111.99 184.18 8,665.39 5,407.65 3,109.87 183.87 8,701.38 5,469.71 3,122.26 184.11 8,776.08
WA/ID Sub-Total 15,791.83 9,152.92 541.70 25,486.45 15,904.86 9,146.66 540.78 25,592.30 16,087.38 9,183.13 541.49 25,812.00
Case Total 21,195.39 12,478.91 640.64 34,314.94 21,367.20 12,482.64 639.68 34,489.52 21,631.43 12,542.13 640.53 34,814.09
Area
2024-2025:
Residential
2024-2025:
Commercial
2024-2025:
Ind FirmSale
2024-2025
Total
2025-2026:
Residential
2025-2026:
Commercial
2025-2026:
Ind FirmSale
2025-2026
Total
2026-2027:
Residential
2026-2027:
Commercial
2026-2027:
Ind FirmSale
2026-2027
Total
Klam Falls 945.08 462.83 13.51 1,421.42 955.41 464.62 13.50 1,433.54 965.35 466.34 13.49 1,445.19
La Grande 522.86 327.33 51.47 901.67 524.33 326.85 51.47 902.66 525.87 326.35 51.47 903.69
Medford GTN 2,369.26 1,438.88 18.66 3,826.80 2,393.77 1,445.29 18.64 3,857.70 2,417.52 1,451.40 18.63 3,887.55
Medford NWP 1,064.45 646.46 8.38 1,719.29 1,075.46 649.33 8.38 1,733.17 1,086.13 652.08 8.37 1,746.58
Roseburg 671.41 477.73 6.79 1,155.93 676.53 474.89 6.77 1,158.19 681.60 471.98 6.74 1,160.33
OR Sub-Total 5,573.07 3,353.23 98.81 9,025.11 5,625.50 3,361.00 98.76 9,085.26 5,676.48 3,368.15 98.72 9,143.34
Wa/Id Both 9,345.48 5,298.56 312.47 14,956.50 9,399.72 5,294.85 311.81 15,006.38 9,449.72 5,291.16 311.11 15,051.99
Wa/Id GTN 1,289.03 730.84 43.10 2,062.97 1,296.51 730.32 43.01 2,069.85 1,303.41 729.82 42.91 2,076.14
Wa/Id NWP 5,478.38 3,106.05 183.17 8,767.60 5,510.18 3,103.88 182.78 8,796.84 5,539.49 3,101.72 182.37 8,823.58
WA/ID Sub-Total 16,112.89 9,135.44 538.74 25,787.07 16,206.41 9,129.05 537.60 25,873.06 16,292.62 9,122.69 536.40 25,951.71
Case Total 21,685.96 12,488.67 637.55 34,812.18 21,831.91 12,490.05 636.37 34,958.33 21,969.09 12,490.85 635.11 35,095.05
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 103 of 648
APPENDIX 2.9: DETAILED DEMAND DATA
AVERAGE MIX

Area
2027-2028:
Residential
2027-2028:
Commercial
2027-2028:
Ind FirmSale
2027-2028
Total
2028-2029:
Residential
2028-2029:
Commercial
2028-2029:
Ind FirmSale
2028-2029
Total
2029-2030:
Residential
2029-2030:
Commercial
2029-2030:
Ind FirmSale
2029-2030
Total
Klam Falls 979.97 470.17 13.52 1,463.67 984.26 469.31 13.48 1,467.05 992.93 470.50 13.47 1,476.90
La Grande 529.97 327.28 51.53 908.78 529.58 325.32 51.47 906.37 531.48 324.76 51.47 907.71
Medford GTN 2,451.63 1,463.47 18.67 3,933.77 2,462.47 1,462.75 18.61 3,943.83 2,483.29 1,467.62 18.60 3,969.51
Medford NWP 1,101.46 657.50 8.39 1,767.35 1,106.33 657.18 8.36 1,771.87 1,115.68 659.37 8.36 1,783.40
Roseburg 689.98 471.17 6.74 1,167.89 691.62 466.16 6.70 1,164.49 696.37 463.14 6.68 1,166.20
OR Sub-Total 5,753.01 3,389.59 98.86 9,241.46 5,774.25 3,380.72 98.63 9,253.60 5,819.75 3,385.38 98.58 9,303.71
Wa/Id Both 9,543.88 5,312.95 311.38 15,168.22 9,543.57 5,284.81 309.66 15,138.04 9,587.13 5,281.89 308.90 15,177.91
Wa/Id GTN 1,316.40 732.82 42.95 2,092.17 1,316.35 728.94 42.71 2,088.01 1,322.36 728.54 42.61 2,093.51
Wa/Id NWP 5,594.69 3,114.49 182.53 8,891.71 5,594.51 3,097.99 181.52 8,874.02 5,620.04 3,096.28 181.08 8,897.40
WA/ID Sub-Total 16,454.97 9,160.27 536.86 26,152.10 16,454.44 9,111.74 533.89 26,100.07 16,529.53 9,106.70 532.59 26,168.82
Case Total 22,207.99 12,549.85 635.72 35,393.56 22,228.69 12,492.46 632.52 35,353.67 22,349.28 12,492.09 631.17 35,472.53
Area
2030-2031:
Residential
2030-2031:
Commercial
2030-2031:
Ind FirmSale
2030-2031
Total
2031-2032:
Residential
2031-2032:
Commercial
2031-2032:
Ind FirmSale
2031-2032
Total
2032-2033:
Residential
2032-2033:
Commercial
2032-2033:
Ind FirmSale
2032-2033
Total
Klam Falls 1,001.41 471.58 13.46 1,486.45 1,015.11 474.54 13.49 1,503.13 1,018.61 472.97 13.44 1,505.02
La Grande 533.23 324.16 51.47 908.86 537.24 324.80 51.53 913.58 536.40 322.56 51.47 910.43
Medford GTN 2,502.79 1,471.81 18.59 3,993.19 2,532.31 1,480.75 18.63 4,031.69 2,537.64 1,476.83 18.57 4,033.04
Medford NWP 1,124.44 661.25 8.35 1,794.04 1,137.70 665.26 8.37 1,811.34 1,140.10 663.50 8.34 1,811.95
Roseburg 700.66 460.07 6.66 1,167.39 708.04 458.55 6.66 1,173.24 708.44 452.93 6.62 1,167.99
OR Sub-Total 5,862.54 3,388.87 98.53 9,349.94 5,930.40 3,403.90 98.67 9,432.98 5,941.20 3,388.79 98.44 9,428.43
Wa/Id Both 9,628.65 5,279.33 308.12 15,216.11 9,716.29 5,301.68 308.18 15,326.15 9,706.92 5,272.87 306.22 15,286.01 Wa/Id GTN 1,328.09 728.18 42.50 2,098.77 1,340.18 731.27 42.51 2,113.95 1,338.89 727.29 42.24 2,108.42
Wa/Id NWP 5,644.38 3,094.78 180.62 8,919.79 5,695.75 3,107.88 180.66 8,984.29 5,690.27 3,090.99 179.51 8,960.77
WA/ID Sub-Total 16,601.13 9,102.30 531.25 26,234.67 16,752.22 9,140.83 531.34 26,424.39 16,736.08 9,091.16 527.96 26,355.20
Case Total 22,463.66 12,491.17 629.78 35,584.61 22,682.62 12,544.73 630.01 35,857.37 22,677.27 12,479.96 626.40 35,783.62
Area
2033-2034:
Residential
2033-2034:
Commercial
2033-2034:
Ind FirmSale
2033-2034
Total
2034-2035:
Residential
2034-2035:
Commercial
2034-2035:
Ind FirmSale
2034-2035
Total
Klam Falls 1,027.40 473.88 13.43 1,514.71 1,038.44 477.50 13.43 1,529.37 La Grande 537.85 321.80 51.47 911.12 540.45 322.73 51.47 914.65 Medford GTN 2,553.49 1,478.95 18.55 4,051.00 2,574.12 1,488.69 18.55 4,081.36 Medford NWP 1,147.22 664.46 8.34 1,820.01 1,156.49 668.83 8.34 1,833.65 Roseburg 712.23 449.45 6.60 1,168.28 718.04 449.80 6.59 1,174.43
OR Sub-Total 5,978.19 3,388.54 98.39 9,465.12 6,027.53 3,407.55 98.38 9,533.47
Wa/Id Both 9,744.26 5,271.27 305.22 15,320.75 9,835.72 5,299.55 305.05 15,440.33
Wa/Id GTN 1,344.04 727.07 42.10 2,113.21 1,356.65 730.97 42.08 2,129.70
Wa/Id NWP 5,712.15 3,090.06 178.92 8,981.13 5,765.77 3,106.64 178.82 9,051.23
WA/ID Sub-Total 16,800.44 9,088.40 526.24 26,415.08 16,958.14 9,137.16 525.95 26,621.25
Case Total 22,778.63 12,476.94 624.63 35,880.20 22,985.67 12,544.72 624.34 36,154.72
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 104 of 648
APPENDIX 2.9: DETAILED DEMAND DATA
COLDEST IN 20 YEARS

Area
2015-2016:
Residential
2015-2016:
Commercial
2015-2016:
Ind FirmSale
2015-2016
Total
2016-2017:
Residential
2016-2017:
Commercial
2016-2017:
Ind FirmSale
2016-2017
Total
2017-2018:
Residential
2017-2018:
Commercial
2017-2018:
Ind FirmSale
2017-2018
Total
Klam Falls 876.38 455.38 13.30 1,345.06 881.35 454.65 13.70 1,349.70 892.67 457.04 13.69 1,363.40
La Grande 523.11 341.47 49.79 914.36 523.33 338.97 51.66 913.95 525.83 339.26 51.60 916.70
Medford GTN 2,181.91 1,399.90 18.59 3,600.40 2,203.59 1,404.39 18.91 3,626.89 2,240.02 1,417.44 18.90 3,676.36
Medford NWP 980.28 628.94 8.35 1,617.57 990.02 630.96 8.50 1,629.47 1,006.38 636.82 8.49 1,651.70
Roseburg 647.79 514.41 6.99 1,169.19 650.46 510.85 6.95 1,168.27 656.36 509.55 6.94 1,172.84
OR Sub-Total 5,209.46 3,340.10 97.03 8,646.58 5,248.76 3,339.81 99.71 8,688.28 5,321.27 3,360.11 99.63 8,781.00
Wa/Id Both 9,047.29 5,505.91 318.84 14,872.04 9,070.21 5,464.64 320.02 14,854.88 9,150.28 5,470.12 320.02 14,940.41
Wa/Id GTN 1,247.90 759.44 43.98 2,051.32 1,251.06 753.74 44.14 2,048.95 1,262.11 754.50 44.14 2,060.75
Wa/Id NWP 5,303.58 3,227.60 186.91 8,718.09 5,317.02 3,203.41 187.60 8,708.03 5,363.95 3,206.62 187.60 8,758.17
WA/ID Sub-Total 15,598.77 9,492.95 549.73 25,641.45 15,638.30 9,421.80 551.76 25,611.86 15,776.34 9,431.24 551.76 25,759.33
Case Total 20,808.22 12,833.05 646.76 34,288.03 20,887.05 12,761.61 651.48 34,300.14 21,097.60 12,791.35 651.38 34,540.33
Area
2018-2019:
Residential
2018-2019:
Commercial
2018-2019:
Ind FirmSale
2018-2019
Total
2019-2020:
Residential
2019-2020:
Commercial
2019-2020:
Ind FirmSale
2019-2020
Total
2020-2021:
Residential
2020-2021:
Commercial
2020-2021:
Ind FirmSale
2020-2021
Total
Klam Falls 904.16 460.19 13.68 1,378.03 920.29 465.11 13.71 1,399.11 927.87 465.62 13.67 1,407.15
La Grande 528.32 339.44 51.51 919.27 532.93 340.91 51.55 925.39 533.12 339.44 51.47 924.04
Medford GTN 2,278.23 1,430.34 18.89 3,727.47 2,326.73 1,448.72 18.93 3,794.38 2,355.49 1,455.25 18.87 3,829.61
Medford NWP 1,023.55 642.62 8.49 1,674.66 1,045.34 650.87 8.51 1,704.72 1,058.26 653.81 8.48 1,720.55
Roseburg 662.50 508.20 6.92 1,177.61 671.82 508.56 6.92 1,187.30 675.31 504.56 6.88 1,186.75
OR Sub-Total 5,396.76 3,380.79 99.49 8,877.04 5,497.11 3,414.17 99.61 9,010.89 5,550.05 3,418.67 99.37 9,068.09
Wa/Id Both 9,228.04 5,471.52 319.80 15,019.37 9,348.14 5,495.51 320.45 15,164.10 9,390.55 5,472.24 319.04 15,181.82
Wa/Id GTN 1,272.83 754.69 44.11 2,071.64 1,289.40 758.00 44.20 2,091.60 1,295.25 754.79 44.01 2,094.04
Wa/Id NWP 5,409.54 3,207.44 187.47 8,804.46 5,479.94 3,221.51 187.85 8,889.30 5,504.80 3,207.86 187.02 8,899.69
WA/ID Sub-Total 15,910.42 9,433.66 551.39 25,895.46 16,117.48 9,475.02 552.50 26,145.00 16,190.60 9,434.89 550.06 26,175.55
Case Total 21,307.18 12,814.44 650.87 34,772.50 21,614.59 12,889.20 652.11 35,155.89 21,740.65 12,853.57 649.43 35,243.65
Area
2021-2022:
Residential
2021-2022:
Commercial
2021-2022:
Ind FirmSale
2021-2022
Total
2022-2023:
Residential
2022-2023:
Commercial
2022-2023:
Ind FirmSale
2022-2023
Total
2023-2024:
Residential
2023-2024:
Commercial
2023-2024:
Ind FirmSale
2023-2024
Total
Klam Falls 939.88 468.22 13.66 1,421.76 951.90 470.59 13.65 1,436.14 968.38 474.98 13.68 1,457.04
La Grande 535.41 339.28 51.47 926.16 537.59 338.98 51.47 928.04 541.88 340.05 51.53 933.46
Medford GTN 2,388.44 1,465.10 18.86 3,872.40 2,416.68 1,472.91 18.85 3,908.44 2,454.11 1,485.98 18.89 3,958.97
Medford NWP 1,073.07 658.23 8.47 1,739.78 1,085.75 661.74 8.47 1,755.97 1,102.57 667.61 8.49 1,778.67
Roseburg 681.79 502.39 6.86 1,191.03 688.22 499.88 6.84 1,194.94 697.62 499.38 6.84 1,203.83
OR Sub-Total 5,618.58 3,433.22 99.33 9,151.13 5,680.15 3,444.09 99.28 9,223.52 5,764.56 3,467.99 99.43 9,331.98
Wa/Id Both 9,466.67 5,471.16 318.55 15,256.38 9,535.96 5,468.57 318.01 15,322.55 9,645.51 5,490.78 318.43 15,454.71
Wa/Id GTN 1,305.75 754.64 43.94 2,104.33 1,315.30 754.29 43.86 2,113.45 1,330.42 757.35 43.92 2,131.68
Wa/Id NWP 5,549.43 3,207.23 186.74 8,943.39 5,590.04 3,205.72 186.42 8,982.18 5,654.26 3,218.73 186.66 9,059.66
WA/ID Sub-Total 16,321.84 9,433.03 549.22 26,304.10 16,441.31 9,428.57 548.30 26,418.18 16,630.19 9,466.86 549.01 26,646.05
Case Total 21,940.43 12,866.25 648.55 35,455.23 22,121.45 12,872.67 647.58 35,641.71 22,394.75 12,934.85 648.44 35,978.03
Area
2024-2025:
Residential
2024-2025:
Commercial
2024-2025:
Ind FirmSale
2024-2025
Total
2025-2026:
Residential
2025-2026:
Commercial
2025-2026:
Ind FirmSale
2025-2026
Total
2026-2027:
Residential
2026-2027:
Commercial
2026-2027:
Ind FirmSale
2026-2027
Total
Klam Falls 974.94 474.97 13.63 1,463.54 985.67 476.89 13.62 1,476.18 996.00 478.73 13.61 1,488.35
La Grande 541.37 338.23 51.47 931.07 542.95 337.79 51.47 932.21 544.59 337.32 51.47 933.38
Medford GTN 2,470.01 1,487.15 18.83 3,975.99 2,495.81 1,494.03 18.82 4,008.66 2,520.83 1,500.60 18.81 4,040.24
Medford NWP 1,109.71 668.14 8.46 1,786.32 1,121.30 671.23 8.46 1,800.99 1,132.55 674.18 8.45 1,815.18
Roseburg 700.24 494.60 6.80 1,201.64 705.67 491.80 6.78 1,204.25 711.06 488.92 6.76 1,206.73
OR Sub-Total 5,796.28 3,463.09 99.20 9,358.57 5,851.40 3,471.74 99.15 9,422.29 5,905.02 3,479.76 99.10 9,483.88
Wa/Id Both 9,663.98 5,464.16 316.83 15,444.97 9,721.83 5,461.49 316.17 15,499.49 9,775.36 5,458.82 315.47 15,549.65
Wa/Id GTN 1,332.96 753.68 43.70 2,130.34 1,340.94 753.31 43.61 2,137.86 1,348.33 752.94 43.51 2,144.78
Wa/Id NWP 5,665.09 3,203.13 185.73 9,053.95 5,699.00 3,201.56 185.34 9,085.91 5,730.38 3,200.00 184.93 9,115.31
WA/ID Sub-Total 16,662.03 9,420.97 546.26 26,629.26 16,761.78 9,416.36 545.12 26,723.26 16,854.07 9,411.76 543.91 26,809.74
Case Total 22,458.31 12,884.06 645.45 35,987.83 22,613.17 12,888.11 644.27 36,145.55 22,759.09 12,891.52 643.02 36,293.62
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 105 of 648
APPENDIX 2.9: DETAILED DEMAND DATA
COLDEST IN 20 YEARS

Area
2027-2028:
Residential
2027-2028:
Commercial
2027-2028:
Ind FirmSale
2027-2028
Total
2028-2029:
Residential
2028-2029:
Commercial
2028-2029:
Ind FirmSale
2028-2029
Total
2029-2030:
Residential
2029-2030:
Commercial
2029-2030:
Ind FirmSale
2029-2030
Total
Klam Falls 1,011.01 482.67 13.64 1,507.33 1,015.67 481.93 13.60 1,511.20 1,024.70 483.22 13.59 1,521.51
La Grande 548.79 338.30 51.53 938.62 548.52 336.38 51.47 936.37 550.54 335.85 51.47 937.86
Medford GTN 2,556.20 1,513.12 18.85 4,088.17 2,568.25 1,512.86 18.79 4,099.89 2,590.24 1,518.16 18.78 4,127.18 Medford NWP 1,148.44 679.81 8.47 1,836.72 1,153.85 679.69 8.44 1,841.98 1,163.73 682.07 8.44 1,854.24 Roseburg 719.76 488.14 6.76 1,214.65 721.71 483.17 6.72 1,211.60 726.77 480.19 6.70 1,213.65
OR Sub-Total 5,984.20 3,502.05 99.25 9,585.49 6,008.01 3,494.02 99.01 9,601.04 6,055.98 3,499.49 98.97 9,654.44
Wa/Id Both 9,873.04 5,481.64 315.74 15,670.43 9,876.22 5,454.52 314.02 15,644.76 9,923.21 5,452.61 313.26 15,689.09
Wa/Id GTN 1,361.80 756.09 43.55 2,161.44 1,362.24 752.35 43.31 2,157.90 1,368.72 752.08 43.21 2,164.01
Wa/Id NWP 5,787.65 3,213.38 185.09 9,186.11 5,789.51 3,197.48 184.08 9,171.06 5,817.06 3,196.36 183.64 9,197.05
WA/ID Sub-Total 17,022.49 9,451.11 544.38 27,017.97 17,027.96 9,404.34 541.41 26,973.72 17,108.99 9,401.05 540.11 27,050.15
Case Total 23,006.69 12,953.15 643.63 36,603.47 23,035.97 12,898.36 640.43 36,574.76 23,164.97 12,900.54 639.08 36,704.59
Area
2030-2031:
Residential
2030-2031:
Commercial
2030-2031:
Ind FirmSale
2030-2031
Total
2031-2032:
Residential
2031-2032:
Commercial
2031-2032:
Ind FirmSale
2031-2032
Total
2032-2033:
Residential
2032-2033:
Commercial
2032-2033:
Ind FirmSale
2032-2033
Total
Klam Falls 1,033.53 484.41 13.58 1,531.52 1,047.58 487.47 13.61 1,548.66 1,051.44 486.00 13.56 1,551.00
La Grande 552.40 335.30 51.47 939.17 556.53 335.98 51.53 944.04 555.79 333.78 51.47 941.03
Medford GTN 2,610.86 1,522.77 18.76 4,152.40 2,641.43 1,532.12 18.80 4,192.35 2,647.77 1,528.59 18.74 4,195.10
Medford NWP 1,173.00 684.14 8.43 1,865.57 1,186.73 688.34 8.45 1,883.52 1,189.58 686.76 8.42 1,884.75
Roseburg 731.35 477.15 6.67 1,215.17 739.00 475.66 6.67 1,221.33 739.67 470.09 6.63 1,216.39
OR Sub-Total 6,101.13 3,503.78 98.92 9,703.83 6,171.26 3,519.57 99.06 9,789.89 6,184.24 3,505.21 98.83 9,788.27
Wa/Id Both 9,968.14 5,451.07 312.48 15,731.70 10,059.16 5,474.42 312.54 15,846.11 10,053.16 5,446.62 310.58 15,810.36
Wa/Id GTN 1,374.92 751.87 43.10 2,169.89 1,387.47 755.09 43.11 2,185.67 1,386.64 751.26 42.84 2,180.74
Wa/Id NWP 5,843.39 3,195.46 183.18 9,222.03 5,896.75 3,209.14 183.21 9,289.10 5,893.23 3,192.85 182.06 9,268.14
WA/ID Sub-Total 17,186.45 9,398.40 538.77 27,123.62 17,343.37 9,438.65 538.86 27,320.89 17,333.03 9,390.73 535.48 27,259.24
Case Total 23,287.58 12,902.18 637.69 36,827.45 23,514.64 12,958.22 637.92 37,110.78 23,517.27 12,895.93 634.30 37,047.51
Area
2033-2034:
Residential
2033-2034:
Commercial
2033-2034:
Ind FirmSale
2033-2034
Total
2034-2035:
Residential
2034-2035:
Commercial
2034-2035:
Ind FirmSale
2034-2035
Total
Klam Falls 1,060.58 487.03 13.55 1,561.16 1,071.98 490.75 13.55 1,576.28
La Grande 557.34 333.06 51.47 941.87 560.04 334.03 51.47 945.54
Medford GTN 2,664.57 1,531.08 18.73 4,214.39 2,686.11 1,541.18 18.73 4,246.02
Medford NWP 1,197.13 687.88 8.41 1,893.42 1,206.80 692.42 8.41 1,907.63
Roseburg 743.72 466.64 6.61 1,216.97 749.79 467.02 6.61 1,223.42
OR Sub-Total 6,223.34 3,505.68 98.78 9,827.80 6,274.72 3,525.40 98.77 9,898.89
Wa/Id Both 10,093.84 5,446.02 309.58 15,849.44 10,188.63 5,475.30 309.41 15,973.34 Wa/Id GTN 1,392.25 751.18 42.70 2,186.13 1,405.33 755.21 42.68 2,203.22 Wa/Id NWP 5,917.08 3,192.49 181.48 9,291.05 5,972.65 3,209.66 181.38 9,363.68
WA/ID Sub-Total 17,403.17 9,389.69 533.76 27,326.62 17,566.60 9,440.17 533.47 27,540.25
Case Total 23,626.51 12,895.37 632.54 37,154.42 23,841.33 12,965.57 632.24 37,439.14
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 106 of 648

APPENDIX 3.1: AVISTA GAS CPA REPORT 4/21/2016

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 107 of 648
Avista Natural Gas Conservation
Potential Assessment Results
April 21, 2016
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 108 of 648
2
Topics
•Overview of analysis approach
•Results for each state
•Market characterization
•Baseline projection
•Conservation potential estimates
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 109 of 648
3
Overview of Analysis Approach
Develop energy market
profiles and project the
baseline
Customer surveys (optional)
Secondary data
Forecast assumptions
Prototypes and
energy analysis
Characterize the market
Utility data
Customer surveys (optional)
Secondary data
DSM measure list
Measure description
Avoided costs
Perform measure
screening
Apply customer
participation rates
Recent program results
Best-practices research
Base-year energy
use by fuel &
segment
Base-year
profiles and
baseline projection
by fuel, segment &
end use
Technical and
economic potential
Achievable potential
Input Data Analysis Steps Results
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 110 of 648
4
Overview of Analysis Approach
Dimension Segmentation Variable Description
1 State Washington, Idaho, Oregon
2 Sector Residential, commercial, industrial
3 Segment
Residential: single family, multi family, mobile
homes and low income
Commercial: office, restaurant, retail, grocery,
school, college, health, lodging, warehouse,
miscellaneous
Industrial: total
4 Vintage Existing and new construction
5 End uses Heating, water heat, process, etc.
(as appropriate by sector)
6 Appliances/end uses and
technologies
Technologies such as furnaces, boilers, water
heaters, etc.
7 Equipment efficiency levels
for new purchases
Baseline and higher-efficiency options as
appropriate for each technology Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 111 of 648
Washington
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 112 of 648
6
High-level Market Characterization -Washington
2015 Natural Gas
Sales by Sector
Segment Annual Sales
(DTh)% of Sales
Residential 9,188,898 60%
Commercial 5,734,759 38%
Industrial 268,452 2%
Total 30,375 100%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 113 of 648
7
Residential Market Characterization -Washington
Washington 2015 Sales
(DTh)# of Customers
Average Use per
Household
(Therms/HH)
Single Family 6,016,941 85,875 701
Multifamily 349,141 7,909 441
Mobile Home 299,264 5,085 589
Low Income 2,523,553 42,372 596
Washington Total 9,188,898 141,241 651
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 114 of 648
8
Residential Market Profiles -Washington
Base-year annual energy use by segment and end use
Annual Intensity for Average Household
Data Sources:
•GenPOP Survey
•RBSA
•Utility billing data
•AEG Market Profiles Database
•Secondary data as needed to fill gaps
Annual Use by End Use
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 115 of 648
9
Residential Energy Market Profile -Washington
•This market profile
represents the residential
sector as a whole.
Individual segment market
profiles are provided in the
report.
•Saturations were
developed using the
GenPOP residential
survey as the primary data
source.
Washington
Total
Total Households:
End Use Technology Saturation UEC Intensity Usage
(Therms)(Therms/(DTh)
Space Heating Furnace 88.2% 509.5 449.1 6,343,260
Space Heating Boiler 2.3% 609.8 13.8 194,390
Space Heating Other Heating 9.6% 488.4 46.8 661,509
Water Heating Water Heater 56.6% 211.0 119.4 1,686,433
Appliances Clothes Dryer 9.9% 27.3 2.7 38,181
Appliances Stove/Oven 8.5% 57.3 4.9 68,899
Miscellaneous Pool Heater 0.7% 217.5 1.6 22,019
Miscellaneous Miscellaneous 100.0% 12.3 12.3 174,206
650.6 9,188,898
141,241
DTh 9,188,898
Total
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 116 of 648
10
Residential Baseline Projection -Washington
•Baseline projection provides foundation for estimating potential future savings from conservation
initiatives and reflects
•Household growth and electricity price forecasts (from Avista)
•Appliance standards in place at end of 2015 (AEG database)
•Frozen efficiency
•Does not include future utility programs
•Baseline projection increases 38% between 2015 and 2036, or an average of 1.5% per year
Residential Baseline Energy Projection (DTh)
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 117 of 648
11
Residential Savings Potential -Washington
From 2017 to 2018, cumulative
achievable potential energy savings
are 62,492 DTh or 0.6% of the
baseline.
By 2036, cumulative savings are
almost 10% of the baseline
projection, or about 0.5% per year.
Uses the UCT cost effectiveness test
2017 2018 2021 2026 2036
Baseline Projection (DTh)10,067,567 10,191,025 10,534,588 11,198,918 12,661,346
Cumulative Savings (DTh)
Achievable Potential 27,598 62,492 207,653 497,074 1,226,734
Economic Potential 132,960 267,157 678,668 1,382,067 2,721,626
Technical Potential 187,192 377,121 956,051 1,951,370 3,828,466
Energy Savings (% of Baseline)
Achievable Potential 0.3%0.6%2.0%4.4%9.7%
Economic Potential 1.3%2.6%6.4%12.3%21.5%
Technical Potential 1.9%3.7%9.1%17.4%30.2%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 118 of 648
12
Residential Savings Potential -Washington
Cumulative achievable potential in 2018
Cumulative Achievable Potential (DTh)
Cumulative Achievable Potential in 2018
Rank Measure / Technology
2018
Achievable
Savings
(Cum. DTh)
% of Total
1 Windows -High Efficiency 20,516 32.8%
2 Heating –Furnace (EF 0.98)19,873 31.8%
3 Furnace -Maintenance 4,025 6.4%
4 Water Heater -Low-Flow Showerheads 3,270 5.2%
5 Water Heater -Temperature Setback 2,983 4.8%
6 Insulation -Ceiling 2,914 4.7%
7 Ducting -Repair and Sealing 2,243 3.6%
8 Water Heating -Water Heater (EF 0.67)1,831 2.9%
9 Thermostat -Programmable/Interactive 1,797 2.9%
10 Water Heater -Pipe Insulation 1,582 2.5%
11 Heating –Boiler (EF 0.98)527 0.8%
12 Water Heater -Faucet Aerators 484 0.8%
13 Boiler -Maintenance 248 0.4%
14 Boiler -Pipe Insulation 199 0.3%
15 Insulation -Wall Sheathing 1 0.0%
Total 62,492 100%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 119 of 648
13
Commercial Market Characterization -Washington
Washington 2015 Sales
(DTh)
Floor Space
(sq. ft.)
Intensity
(therms/sqft)
Office 608,320 23,532,683 0.26
Restaurant 357,257 1,615,817 2.21
Retail 609,276 20,141,347 0.30
Grocery 253,760 4,311,977 0.59
School 472,964 11,620,730 0.41
College 439,038 5,467,474 0.80
Health 648,945 9,103,062 0.71
Lodging 353,904 6,773,279 0.52
Warehouse 272,231 13,377,462 0.20
Miscellaneous 1,719,065 32,222,397 0.53
Washington Total 5,734,759 128,166,227 0.45
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 120 of 648
14
Commercial Market Profiles -Washington
Base-year annual energy use by segment and end use
Annual Intensity per Square Foot
Data Sources:
•CBSA
•Utility billing data
•AEG Market Profiles Database
•Secondary data as needed to fill gaps
Annual Use by End Use
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 121 of 648
15
Commercial Energy Market Profile -Washington
•This market profile
represents the
Commercial sector as a
whole. Individual segment
market profiles are
provided in the report.
•Saturations were
developed using the CBSA
survey as the primary data
source.
EUI Intensity Usage
(therm)(therm/Sqft)(DTh)
Heating Furnace 54.3% 0.21 0.11 1,467,831
Heating Boiler 33.1% 0.48 0.16 2,030,710
Heating Unit Heater 4.7% 0.09 0.00 55,570
Water Heating Water Heater 68.7% 0.19 0.13 1,651,292
Food Preparation Oven 25.1% 0.02 0.00 56,768
Food Preparation Fryer 7.5% 0.12 0.01 114,766
Food Preparation Broiler 13.7% 0.04 0.01 67,939
Food Preparation Griddle 16.7% 0.03 0.00 61,216
Food Preparation Range 18.3% 0.03 0.01 69,753
Food Preparation Steamer 2.0% 0.03 0.00 8,759
Food Preparation Commercial Food Prep Other 0.1% 0.01 0.00 69
Miscellaneous Pool Heater 0.9% 0.00 0.00 356
Miscellaneous Other Miscellaneous 100.0% 0.01 0.01 149,731
0.45 5,734,759Total
Gas Market Profiles
End Use Technology Saturation
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 122 of 648
16
Commercial Baseline Projection -Washington
•Baseline projection provides foundation for estimating potential future savings from conservation
initiatives and reflects
•Customer growth (from Avista)
•Building Codes and appliance standards in place at end of 2015 (AEG database)
•Frozen efficiency
•Does not include future utility programs
•Baseline projection increases 23% between 2015 and 2036, or an average of 1% per year
Commercial Baseline Energy Projection (DTh)
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 123 of 648
17
Estimating Conservation Potential
•The study analyzed 100 measures covering residential, commercial and industrial sectors.
•Cost-effectiveness screening to estimate economic potential was done using utility cost
test for Washington and Idaho, and using the TRC for Oregon
•Customer adoption or “ramp rates” are needed to estimate achievable potential. The study
used regional ramp rates to start and then calibrated based on Avista’s program history
•The study uses AEG’s
LoadMAP model to
estimate potential Technical Potential
Theoretical upper limit of EE, where all efficiency
measures are phased in regardless of cost
Economic Potential
Also a theoretical upper limit of EE, but includes
only cost-effective measures
Achievable Potential
EE potential that can be realistically achieved by
utilities, accounting for customer adoption rates
and how quickly programs can be implemented
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 124 of 648
18
Commercial Savings Potential -Washington
From 2017 to 2018, cumulative
achievable potential energy savings
are 53,246 DTh or 0.9% of the
baseline.
By 2036, cumulative savings are
over 12% of the baseline
projection, or about 0.7% per year.
Uses the UCT cost effectiveness test
2017 2018 2021 2026 2036
Baseline Projection (DTh)6,220,478 6,236,027 6,305,231 6,490,547 7,066,197
Cumulative Savings (DTh)
Achievable Potential 22,978 53,246 176,816 413,219 878,225
Economic Potential 70,810 140,765 339,275 637,762 1,124,744
Technical Potential 108,572 214,053 512,953 960,878 1,686,375
Energy Savings (% of Baseline)
Achievable Potential 0.4%0.9%2.8%6.4%12.4%
Economic Potential 1.1%2.3%5.4%9.8%15.9%
Technical Potential 1.7%3.4%8.1%14.8%23.9%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 125 of 648
19
Commercial Savings Potential -Washington
Cumulative achievable potential in 2018
Cumulative Achievable Potential (DTh)
Cumulative Achievable Potential in 2018
Rank Measure / Technology
2018
Achievable
Savings
(Cum. DTh)
% of Total
1 Retrocommissioning 13,476 25.3%
2 Heating –Boiler (EF 0.96)11,887 22.3%
3 Gas Boiler -Hot Water Reset 5,159 9.7%
4 Heating –Furnace (EF 0.96)4,102 7.7%
5 Insulation -Ceiling 3,360 6.3%
6 Water Heating -Water Heater (Tankless)2,826 5.3%
7 Water Heater -Faucet Aerators/Low Flow Nozzles 2,150 4.0%
8 Water Heater -Central Controls 1,979 3.7%
9 Strategic Energy Management 1,784 3.4%
10 Water Heater -Pre-Rinse Spray Valve 1,564 2.9%
11 Gas Boiler -Parallel Positioning Control 1,540 2.9%
12 Food Preparation –Fryer (ENERGY STAR)740 1.4%
13 Steam Trap Maintenance 657 1.2%
14 Food Preparation -Oven (ENERGY STAR)386 0.7%
15 HVAC -Shut Off Damper 304 0.6%
16 Food Preparation -Griddle (ENERGY STAR)235 0.4%
17 Windows -High Efficiency 223 0.4%
18 Water Heater -Pipe Insulation 204 0.4%
19 Food Preparation -Steamer (ENERGY STAR)184 0.3%
20 Heating -Unit Heater (Condensing)171 0.3%
Total 52,933 99.4%Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 126 of 648
20
Industrial Energy Market Profile -Washington
•This market profile
represents the Industrial
sector as a whole. The
industrial sector is not
large enough to warrant
further segmentation.
EUI Intensity Usage
(Therms)(Therms/sqft)(Dth)
Space Heating Furnace 56.5%0.028 0.02 5,563
Space Heating Boiler 34.4%0.089 0.03 10,891
Space Heating Other Heating 4.9%0.014 0.00 239
Process Process Heating 100.0% 0.369 0.37 131,596
Process Process Boiler 100.0% 0.282 0.28 100,538
Process Process Cooling 100.0% 0.001 0.00 407
Process Other Process 100.0% 0.004 0.00 1,580
Other Other Uses 100.0% 0.049 0.05 17,638
0.75 268,452
Washington
Industrial
Total Sq Ft:3,567,948
DTh 268,452
Total
End Use Technology Saturation
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 127 of 648
21
Industrial Baseline Projection -Washington
•Baseline projection provides foundation for estimating potential future savings from conservation
initiatives and reflects
•Customer growth (from Avista)
•Building Codes and appliance standards in place at end of 2015 (AEG database)
•Frozen efficiency
•Does not include future utility programs
•Baseline projection increases 35% between 2015 and 2036, or an average of 1.4% per year
Industrial Baseline Energy Projection (DTh)
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 128 of 648
22
Industrial Savings Potential -Washington
From 2017 to 2018, cumulative
achievable potential energy savings
are 777 DTh or 0.3% of the baseline.
By 2036, cumulative savings are
2.3% of the baseline projection, or
about 0.1% per year.
Uses the UCT cost effectiveness test
2017 2018 2021 2026 2036
Baseline Projection (DTh)283,824 287,571 298,345 318,546 363,144
Cumulative Savings (DTh)
Achievable Potential 383 777 1,993 4,050 8,414
Economic Potential 876 1,757 4,413 8,941 18,457
Technical Potential 3,195 6,425 16,314 33,603 71,042
Energy Savings (% of Baseline)
Achievable Potential 0.1%0.3%0.7%1.3%2.3%
Economic Potential 0.3%0.6%1.5%2.8%5.1%
Technical Potential 1.1%2.2%5.5%10.5%19.6%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 129 of 648
23
Industrial Savings Potential -Washington
Cumulative achievable potential in 2018
Cumulative Achievable Potential (DTh)
Cumulative Achievable Potential in 2018
Rank Measure / Technology
2018
Achievable
Savings
(Cum. DTh)
% of Total
1 Custom 415 53.5%
2 Boiler -Hot Water Reset 205 26.4%
3 Boiler -Parallel Positioning Control 97 12.5%
4 Boiler -Maintenance 46 5.9%
5 Steam Trap Maintenance 11 1.5%
6 Gas Furnace -Maintenance 2 0.3%
Total 777 100.0%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 130 of 648
Idaho
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 131 of 648
25
High-level Market Characterization -Idaho
2015 Natural Gas
Sales by Sector
Segment Annual Sales
(DTh)% of Sales
Residential 4,304,740 62%
Commercial 2,456,621 35%
Industrial 187,203 3%
Total 6,948,564 100%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 132 of 648
26
Residential Market Characterization -Idaho
Idaho 2015 Sales
(DTh)# of Customers
Average Use per
Household
(Therms/HH)
Single Family 2,814,373 42,852 657
Multifamily 142,894 3,454 414
Mobile Home 174,973 3,172 552
Low Income 1,172,501 21,003 558
Idaho Total 4,304,740 70,481 611
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 133 of 648
27
Residential Market Profiles -Idaho
Base-year annual energy use by segment and end use
Annual Intensity for Average Household
Data Sources:
•GenPOP Survey
•RBSA
•Utility billing data
•AEG Market Profiles Database
•Secondary data as needed to fill gaps
Annual Use by End Use
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 134 of 648
28
Residential Energy Market Profile -Idaho
•This market profile
represents the residential
sector as a whole.
Individual segment market
profiles are provided in the
report.
•Saturations were
developed using the
GenPOP residential
survey as the primary data
source.
Idaho
Total
Total Households:
End Use Technology Saturation UEC Intensity Usage
(Therms)(Therms/(DTh)
Space Heating Furnace 84.2% 484.5 407.8 2,873,917
Space Heating Boiler 2.0% 579.2 11.8 83,322
Space Heating Other Heating 13.8% 466.4 64.4 453,852
Water Heating Water Heater 54.3% 200.8 109.1 768,890
Appliances Clothes Dryer 9.2% 29.0 2.7 18,876
Appliances Stove/Oven 9.2% 60.1 5.5 39,043
Miscellaneous Pool Heater 0.3% 217.4 0.6 4,134
Miscellaneous Miscellaneous 100.0% 8.9 8.9 62,706
610.8 4,304,740
70,481
DTh 4,304,740
Total
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 135 of 648
29
Residential Baseline Projection -Idaho
•Baseline projection provides foundation for estimating potential future savings from conservation
initiatives and reflects
•Household growth and electricity price forecasts (from Avista)
•Appliance standards in place at end of 2015 (AEG database)
•Frozen efficiency
•Does not include future utility programs
•Baseline projection increases 44% between 2015 and 2036, or an average of 1.7% per year
Residential Baseline Energy Projection (DTh)
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 136 of 648
30
Residential Savings Potential -Idaho
From 2017 to 2018, cumulative
achievable potential energy savings
are 62,492 DTh or 0.6% of the
baseline.
By 2036, cumulative savings are
almost 10% of the baseline
projection, or about 0.5% per year.
Uses the UCT cost effectiveness test
2017 2018 2021 2026 2036
Baseline Projection (DTh)4,741,736 4,802,813 4,992,555 5,366,588 6,213,091
Cumulative Savings (DTh)
Achievable Potential 11,138 25,406 85,812 208,875 536,817
Economic Potential 53,686 108,042 276,801 577,890 1,198,833
Technical Potential 82,162 165,579 422,556 873,781 1,776,196
Energy Savings (% of Baseline)
Achievable Potential 0.2%0.5%1.7%3.9%8.6%
Economic Potential 1.1%2.2%5.5%10.8%19.3%
Technical Potential 1.7%3.4%8.5%16.3%28.6%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 137 of 648
31
Residential Savings Potential -Idaho
Cumulative achievable potential in 2018
Cumulative Achievable Potential (DTh)
Cumulative Achievable Potential in 2018
Rank Measure / Technology
2018
Achievable
Savings
(Cum. DTh)
% of Total
1 Windows -High Efficiency 9,778 38.5%
2 Heating –Furnace (EF 0.98)6,692 26.3%
3 Furnace -Maintenance 1,821 7.2%
4 Water Heater -Low-Flow Showerheads 1,480 5.8%
5 Insulation -Ceiling 1,379 5.4%
6 Water Heater -Temperature Setback 1,365 5.4%
7 Thermostat -Programmable/Interactive 861 3.4%
8 Water Heater -Pipe Insulation 725 2.9%
9 Water Heating -Water Heater (EF 0.67)660 2.6%
10 Heating –Boiler (EF 0.98)235 0.9%
11 Water Heater -Faucet Aerators 219 0.9%
12 Boiler -Maintenance 106 0.4%
13 Boiler -Pipe Insulation 86 0.3%
Total 25,406 100%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 138 of 648
32
Commercial Market Characterization -Idaho
Idaho 2015 Sales
(DTh)
Floor Space
(sq. ft.)
Intensity
(therms/sqft)
Office 214,228 8,388,655 0.26
Restaurant 55,373 253,503 2.18
Retail 314,742 10,531,910 0.30
Grocery 97,810 1,682,340 0.58
School 387,333 9,633,126 0.40
College 360,160 4,540,014 0.79
Health 222,359 3,157,269 0.70
Lodging 135,614 2,627,216 0.52
Warehouse 110,269 5,484,890 0.20
Miscellaneous 558,735 10,601,048 0.53
Idaho Total 2,456,621 56,899,971 0.43
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 139 of 648
33
Commercial Market Profiles -Idaho
Base-year annual energy use by segment and end use
Annual Intensity per Square Foot
Data Sources:
•CBSA
•Utility billing data
•AEG Market Profiles Database
•Secondary data as needed to fill gaps
Annual Use by End Use
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 140 of 648
34
Commercial Energy Market Profile -Idaho
•This market profile
represents the
Commercial sector as a
whole. Individual segment
market profiles are
provided in the report.
•Saturations were
developed using the CBSA
survey as the primary data
source.
EUI Intensity Usage
(therm)(therm/Sqft)(DTh)
Heating Furnace 51.2% 0.20 0.10 588,380
Heating Boiler 36.0% 0.45 0.16 930,819
Heating Unit Heater 4.9% 0.09 0.00 25,385
Water Heating Water Heater 69.3% 0.19 0.13 734,648
Food Preparation Oven 24.5% 0.02 0.00 27,505
Food Preparation Fryer 7.7% 0.09 0.01 40,765
Food Preparation Broiler 14.0% 0.03 0.00 22,933
Food Preparation Griddle 16.3% 0.02 0.00 20,023
Food Preparation Range 18.3% 0.02 0.00 23,972
Food Preparation Steamer 3.0% 0.02 0.00 4,249
Food Preparation Commercial Food Prep Other 0.1% 0.00 0.00 29
Miscellaneous Pool Heater 0.8% 0.00 0.00 119
Miscellaneous Other Miscellaneous 100.0% 0.01 0.01 37,793
0.43 2,456,621
Gas Market Profiles
End Use Technology Saturation
Total
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 141 of 648
35
Commercial Baseline Projection -Idaho
•Baseline projection provides foundation for estimating potential future savings from conservation
initiatives and reflects
•Customer growth (from Avista)
•Building Codes and appliance standards in place at end of 2015 (AEG database)
•Frozen efficiency
•Does not include future utility programs
•Baseline projection increases 23% between 2015 and 2036, or an average of 1% per year
Commercial Baseline Energy Projection (DTh)
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 142 of 648
36
Commercial Savings Potential -Idaho
From 2017 to 2018, cumulative
achievable potential energy savings
are 21,619 DTh or 0.8% of the
baseline.
By 2036, cumulative savings are
almost 12% of the baseline
projection, or about 0.6% per year.
Uses the UCT cost effectiveness test
2017 2018 2021 2026 2036
Baseline Projection (DTh)2,656,853 2,664,007 2,695,763 2,776,753 3,021,253
Cumulative Savings (DTh)
Achievable Potential 9,311 21,619 72,680 170,883 359,503
Economic Potential 29,135 58,035 140,114 263,474 459,135
Technical Potential 47,785 94,237 226,002 423,332 744,715
Energy Savings (% of Baseline)
Achievable Potential 0.4%0.8%2.7%6.2%11.9%
Economic Potential 1.1%2.2%5.2%9.5%15.2%
Technical Potential 1.8%3.5%8.4%15.2%24.6%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 143 of 648
37
Commercial Savings Potential -Idaho
Cumulative achievable potential in 2018
Cumulative Achievable Potential (DTh)
Cumulative Achievable Potential in 2018
Rank Measure / Technology
2018
Achievable
Savings
(Cum. DTh)
% of Total
1 Retrocommissioning 5,761 26.6%
2 Heating –Boiler (EF 0.96)4,812 22.3%
3 Gas Boiler -Hot Water Reset 2,364 10.9%
4 Heating –Furnace (EF 0.96)1,919 8.9%
5 Water Heating -Water Heater (Tankless)1,343 6.2%
6 Insulation -Ceiling 1,105 5.1%
7 Water Heater -Faucet Aerators/Low Flow Nozzles 955 4.4%
8 Water Heater -Central Controls 892 4.1%
9 Water Heater -Pre-Rinse Spray Valve 631 2.9%
10 Gas Boiler -Parallel Positioning Control 598 2.8%
11 Steam Trap Maintenance 294 1.4%
12 Food Preparation –Fryer (ENERGY STAR)264 1.2%
13 Food Preparation –Oven (ENERGY STAR)188 0.9%
14 Water Heater -Pipe Insulation 91 0.4%
15 Food Preparation -Steamer (ENERGY STAR)90 0.4%
16 Food Preparation -Griddle (ENERGY STAR)77 0.4%
17 Windows -High Efficiency 77 0.4%
18 Food Preparation -Broiler (ENERGY STAR)55 0.3%
19 Heating -Unit Heater (Condensing)47 0.2%
20 HVAC -Duct Repair and Sealing 27 0.1%
Total 21,592 99.9%Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 144 of 648
38
Industrial Energy Market Profile -Idaho
•This market profile
represents the Industrial
sector as a whole. The
industrial sector is not
large enough to warrant
further segmentation.EUI Intensity Usage
(Therms)(Therms/sqft)(Dth)
Space Heating Furnace 56.5% 0.026 0.01 3,879
Space Heating Boiler 34.4% 0.085 0.03 7,595
Space Heating Other Heating 4.9% 0.013 0.00 167
Process Process Heating 100.0% 0.353 0.35 91,768
Process Process Boiler 100.0% 0.270 0.27 70,109
Process Process Cooling 100.0% 0.001 0.00 284
Process Other Process 100.0% 0.004 0.00 1,102
Other Other Uses 100.0% 0.047 0.05 12,299
0.72 187,203
Idaho
Industrial
Total Sq Ft:2,596,257
DTh 187,203
Total
End Use Technology Saturation
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 145 of 648
39
Industrial Baseline Projection -Idaho
•Baseline projection provides foundation for estimating potential future savings from conservation
initiatives and reflects
•Customer growth (from Avista)
•Building Codes and appliance standards in place at end of 2015 (AEG database)
•Frozen efficiency
•Does not include future utility programs
•Baseline projection increases 70% between 2015 and 2036, or an average of 2.5% per year
Industrial Baseline Energy Projection (DTh)
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 146 of 648
40
Industrial Savings Potential -Idaho
From 2017 to 2018, cumulative
achievable potential energy savings
are 641 DTh or 0.3% of the
baseline.
By 2036, cumulative savings are
4.3% of the baseline projection, or
about 0.1% per year.
Uses the UCT cost effectiveness test
2017 2018 2021 2026 2036
Baseline Projection (DTh)211,629 216,490 229,739 256,083 318,182
Cumulative Savings (DTh)
Achievable Potential 306 641 1,809 4,411 13,717
Economic Potential 700 1,450 4,005 9,723 29,846
Technical Potential 2,446 5,049 13,661 31,578 81,807
Energy Savings (% of Baseline)
Achievable Potential 0.1%0.3%0.8%1.7%4.3%
Economic Potential 0.3%0.7%1.7%3.8%9.4%
Technical Potential 1.2%2.3%5.9%12.3%25.7%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 147 of 648
41
Industrial Savings Potential-Idaho
Cumulative achievable potential in 2018
Cumulative Achievable Potential (DTh)
Cumulative Achievable Potential in 2018
Rank Measure / Technology
2018
Achievable
Savings
(Cum. DTh)
% of Total
1 Custom 338 52.7%
2 Boiler -Hot Water Reset 171 26.7%
3 Boiler -Parallel Positioning Control 81 12.7%
4 Boiler -Maintenance 39 6.0%
5 Steam Trap Maintenance 10 1.5%
6 Gas Furnace -Maintenance 2 0.3%
Total 641 100.0%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 148 of 648
Oregon
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 149 of 648
43
High-level Market Characterization -Oregon
2015 Natural Gas
Sales by Sector
Segment Annual Sales
(DTh)% of Sales
Residential 4,303,206 61%
Commercial 2,699,252 38%
Industrial 51,369 1%
Total 7,053,827 100%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 150 of 648
44
Residential Market Characterization -Oregon
Oregon 2015 Sales
(DTh)# of Customers
Average Use per
Household
(Therms/HH)
Single Family 2,811,856 53,617 524
Multifamily 81,940 2,480 330
Mobile Home 271,183 6,156 441
Low Income 1,138,226 25,534 446
Oregon Total 4,303,206 87,787 490
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 151 of 648
45
Residential Market Profiles -Oregon
Base-year annual energy use by segment and end use
Annual Intensity for Average Household
Data Sources:
•RBSA
•Utility billing data
•AEG Market Profiles Database
•Secondary data as needed to fill gaps
Annual Use by End Use
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 152 of 648
46
Residential Energy Market Profile -Oregon
•This market profile
represents the residential
sector as a whole.
Individual segment market
profiles are provided in the
report.
•Saturations were
developed using the RBSA
survey as the primary data
source.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 153 of 648
47
Residential Baseline Projection -Oregon
•Baseline projection provides foundation for estimating potential future savings from conservation
initiatives and reflects
•Household growth and electricity price forecasts (from Avista)
•Appliance standards in place at end of 2015 (AEG database)
•Frozen efficiency
•Does not include future utility programs
•Baseline projection increases 30% between 2015 and 2036, or an average of 1.2% per year
Residential Baseline Energy Projection (DTh)
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 154 of 648
48
Residential Savings Potential -Oregon
From 2017 to 2018, cumulative
achievable potential energy savings
are 13,839 DTh or 0.3% of the
baseline.
By 2036, cumulative savings are
almost 5% of the baseline
projection, or about 0.2% per year.
Uses the TRC cost effectiveness test
2017 2018 2021 2026 2036
Baseline Projection (DTh)4,808,069 4,852,168 4,931,394 5,137,402 5,588,507
Cumulative Savings (DTh)
Achievable Potential 6,507 13,839 38,671 94,086 260,939
Economic Potential 21,867 44,161 111,658 228,569 483,538
Technical Potential 83,073 167,062 418,531 844,811 1,615,605
Energy Savings (% of Baseline)
Achievable Potential 0.1%0.3%0.8%1.8%4.7%
Economic Potential 0.5%0.9%2.3%4.4%8.7%
Technical Potential 1.7%3.4%8.5%16.4%28.9%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 155 of 648
49
Residential Savings Potential -Oregon
Cumulative achievable potential in 2018
Cumulative Achievable Potential (DTh)
Cumulative Achievable Potential in 2018
Rank Measure / Technology
2018
Achievable
Savings
(Cum. DTh)
% of Total
1 Heating -Furnace 7,400 53.5%
2 Water Heater -Low-Flow Showerheads 1,743 12.6%
3 Water Heater -Temperature Setback 1,640 11.9%
4 Furnace -Maintenance 1,477 10.7%
5 Water Heater -Pipe Insulation 871 6.3%
6 Water Heater -Faucet Aerators 257 1.9%
7 Windows -High Efficiency 235 1.7%
8 Boiler -Maintenance 108 0.8%
9 Boiler -Pipe Insulation 86 0.6%
10 Heating –Boiler (EF 0.98)22 0.2%
Total 13,839 100%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 156 of 648
50
Commercial Market Characterization -Oregon
Oregon 2015 Sales
(DTh)
Floor Space
(sq. ft.)
Intensity
(therms/sqft)
Office 406,757 8,388,655 0.16
Restaurant 302,349 253,503 1.39
Retail 401,181 10,531,910 0.19
Grocery 173,578 1,682,340 0.37
School 273,450 9,633,126 0.26
College 34,880 4,540,014 0.50
Health 401,052 3,157,269 0.45
Lodging 174,610 2,627,216 0.33
Warehouse 143,426 5,484,890 0.13
Miscellaneous 387,969 10,601,048 0.34
Oregon Total 2,699,252 56,899,971 0.27
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 157 of 648
51
Commercial Market Profiles -Oregon
Base-year annual energy use by segment and end use
Annual Intensity per Square Foot
Data Sources:
•CBSA
•Utility billing data
•AEG Market Profiles Database
•Secondary data as needed to fill gaps
Annual Use by End Use
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 158 of 648
52
Commercial Energy Market Profile -Oregon
•This market profile
represents the
Commercial sector as a
whole. Individual segment
market profiles are
provided in the report.
•Saturations were
developed using the CBSA
survey as the primary data
source.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 159 of 648
53
Commercial Baseline Projection -Oregon
•Baseline projection provides foundation for estimating potential future savings from conservation
initiatives and reflects
•Customer growth (from Avista)
•Building Codes and appliance standards in place at end of 2015 (AEG database)
•Frozen efficiency
•Does not include future utility programs
•Baseline projection increases 38% between 2015 and 2036, or an average of 1.5% per year
Commercial Baseline Energy Projection (DTh)
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 160 of 648
54
Commercial Savings Potential -Oregon
From 2017 to 2018, cumulative
achievable potential energy savings
are 17,527 DTh or 0.5% of the
baseline.
By 2036, cumulative savings are
almost 10% of the baseline
projection, or about 0.5% per year.
Uses the TRC cost effectiveness test
2017 2018 2021 2026 2036
Baseline Projection (DTh)3,215,033 3,219,537 3,264,933 3,383,711 3,729,054
Cumulative Savings (DTh)
Achievable Potential 7,921 17,527 54,701 142,594 363,123
Economic Potential 22,299 44,184 110,800 228,191 470,854
Technical Potential 56,697 109,388 262,836 500,789 919,302
Energy Savings (% of Baseline)
Achievable Potential 0.2%0.5%1.7%4.2%9.7%
Economic Potential 0.7%1.4%3.4%6.7%12.6%
Technical Potential 1.8%3.4%8.1%14.8%24.7%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 161 of 648
55
Commercial Savings Potential -Oregon
Cumulative achievable potential in 2018
Cumulative Achievable Potential (DTh)
Cumulative Achievable Potential in 2018
Rank Measure / Technology
2018
Achievable
Savings
(Cum. DTh)
% of Total
1 Retrocommissioning 5,781 33.0%
2 Gas Boiler -Hot Water Reset 1,954 11.2%
3 Water Heater -Central Controls 1,711 9.8%
4 Heating -Boiler 1,700 9.7%
5 Water Heating -Water Heater 1,316 7.5%
6 Commissioning 1,162 6.6%
7 Water Heater -Faucet Aerators/Low Flow
Nozzles 1,098 6.3%
8 Water Heater -Pre-Rinse Spray Valve 1,009 5.8%
9 Food Preparation -Fryer 519 3.0%
10 Steam Trap Maintenance 384 2.2%
11 Food Preparation -Oven 215 1.2%
12 Food Preparation -Griddle 160 0.9%
13 Windows -High Efficiency 144 0.8%
14 Food Preparation -Steamer 115 0.7%
15 Water Heater -Pipe Insulation 106 0.6%
16 Water Heater -Drainwater Heat Recovery 68 0.4%
17 HVAC -Duct Repair and Sealing 46 0.3%
18 Food Preparation -Broiler 37 0.2%
19 Gas Boiler -Parallel Positioning Control 2 0.0%
20 Food Preparation -Range 0 0.0%
Total 17,527 100.0%Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 162 of 648
56
Industrial Energy Market Profile -Oregon
•This market profile
represents the Industrial
sector as a whole. The
industrial sector is not
large enough to warrant
further segmentation.
EUI Intensity Usage
(Therms)(Therms/sqft)(Dth)
Space Heating Furnace 56.5% 0.025 0.01 1,064
Space Heating Boiler 34.4% 0.081 0.03 2,084
Space Heating Other Heating 4.9% 0.013 0.00 46
Process Process Heating 100.0% 0.338 0.34 25,181
Process Process Boiler 100.0% 0.258 0.26 19,238
Process Process Cooling 100.0% 0.001 0.00 78
Process Other Process 100.0% 0.004 0.00 302
Other Other Uses 100.0% 0.045 0.05 3,375
0.69 51,369
Oregon
Industrial
51,369
Total Sq Ft:744,804
DTh
End Use Technology Saturation
Total
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 163 of 648
57
Industrial Baseline Projection -Oregon
•Baseline projection provides foundation for estimating potential future savings from conservation
initiatives and reflects
•Customer growth (from Avista)
•Building Codes and appliance standards in place at end of 2015 (AEG database)
•Frozen efficiency
•Does not include future utility programs
•Baseline projection increases 31% between 2015 and 2036, or an average of 1.4% per year
Industrial Baseline Energy Projection (DTh)
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 164 of 648
58
Industrial Savings Potential -Oregon
From 2017 to 2018, cumulative
achievable potential energy savings
are 641 DTh or 0.3% of the
baseline.
By 2036, cumulative savings are
4.3% of the baseline projection, or
about 0.1% per year.
Uses the TRC cost effectiveness test
2017 2018 2021 2026 2036
Baseline Projection (DTh)51,346 52,041 54,200 58,303 67,465
Cumulative Savings (DTh)
Achievable Potential 73 147 379 773 1,622
Economic Potential 166 333 839 1,707 3,557
Technical Potential 602 1,209 3,078 6,371 13,602
Energy Savings (% of Baseline)
Achievable Potential 0.0%0.1%0.2%0.3%0.5%
Economic Potential 0.1%0.2%0.4%0.7%1.1%
Technical Potential 0.3%0.6%1.3%2.5%4.3%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 165 of 648
59
Industrial Savings Potential-Oregon
Cumulative achievable potential in 2018
Cumulative Achievable Potential (DTh)
Cumulative Achievable Potential in 2018
Rank Measure / Technology
2018
Achievable
Savings
(Cum. DTh)
% of Total
1 Custom 338 52.7%
2 Boiler -Hot Water Reset 171 26.7%
3 Boiler -Parallel Positioning Control 81 12.7%
4 Boiler -Maintenance 39 6.0%
5 Steam Trap Maintenance 10 1.5%
6 Gas Furnace -Maintenance 2 0.3%
Total 641 100.0%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 166 of 648
Ingrid Rohmund
[e-mail]
Bridget Kester
[e-mail]
Fuong Nguyen
[e-mail]
Joe Reilly
[e-mail]
Thank You!
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 167 of 648
APPENDIX 3.2: ENVIRONMENTAL EXTERNALITIES OVERVIEW
(OREGON JURISDICTION ONLY)
The methodology for determining avoided costs from reduced incremental natural gas usage considers
commodity and variable transportation costs only. These avoided cost streams do not include environmental
externality costs related to the gathering, transmission, distribution or end-use of natural gas.
Per traditional economic theory and industry practice, an environmental externality factor is typically added
to the avoided cost when there is an opportunity to displace traditional supply-side resources with an
alternative resource with no adverse environmental impact.
REGULATORY GUIDANCE
The Oregon Public Utility Commission (OPUC) issued Order 93-965 (UM-424) to address how utilities
should consider the impact of environmental externalities in planning for future energy resources. The
Order required analysis on the potential natural gas cost impacts from emitting carbon dioxide (CO2) and
nitric-oxide (NOx).
The OPUC’s Order No. 07-002 in Docket UM 1056 (Investigation Into Integrated Resource Planning)
established the following guideline for the treatment of environmental costs used by energy utilities that
evaluate demand-side and supply-side energy choices:
UM 1056, Guideline 8 - Environmental Costs
“Utilities should include, in their base-case analyses, the regulatory compliance costs they expect
for carbon dioxide (CO2), nitrogen oxides (NOx), sulfur oxides (SO2), and mercury (Hg) emissions.
Utilities should analyze the range of potential CO2 regulatory costs in Order No. 93-695, from $0
- $40 (1990$). In addition, utilities should perform sensitivity analysis on a range of reasonably
possible cost adders for nitrogen oxides (NOx), sulfur dioxide (SO2), and mercury (Hg), if
applicable.
In June 2008, the OPUC issued Order 08-338 (UM1302) which revised UM1056, Guideline 8. The revised
guideline requires the utility should construct a base case portfolio to reflect what it considers to be the
most likely regulatory compliance future for the various emissions. Additionally the guideline requires the
utility to develop several compliance scenarios ranging from the present CO2 regulatory level to the upper
reaches of credible proposals and each scenario should include a time profile of CO2 costs. The utility is
also required to include a “trigger point” analysis in which the utility must determine at what level of carbon
costs its selection of portfolio resources would be significantly different.
ANALYSIS
Unlike electric utilities, environmental cost issues rarely impact a natural gas utility's supply-side resource
options. This is because the only supply-side energy resource is natural gas. The utility cannot choose
between say "dirty" coal-fired generation and "clean" wind energy sources. The supply-side implication of
environmental externalities generally relates to combustion of fuel to move or compress natural gas.
Avista’s direct gas distribution system infrastructure relies solely on the upstream line pressure of the
interstate pipeline transportation network to distribute natural gas to its customers and thus does not directly
combust fuels that result in any CO2, NOx, SO2, or Hg emissions. Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 168 of 648
Upstream gas system infrastructure (pipelines, storage facilities, and gathering systems), however, do
produce CO2 emissions via compressors used to pressurize and move natural gas. Accessing CO2 emissions
data on these upstream activities to perform detailed meaningful analysis is challenging. In the 2009 Natural
Gas IRP there was significant momentum regarding GHG legislation and the movement towards the
creation of carbon cap and trade markets or tax structure. Since then, the momentum has slowed
significantly. Where there is still a focus on reducing GHG emissions and improving the nation’s carbon
footprint, the timing of implementing a carbon cap and trade/tax framework has been delayed.
Additionally, the pricing level of the framework has been greatly reduced.. Whichever structure ultimately
gets implemented, Avista believes the cost pass through mechanisms for upstream gas system infrastructure
will not make a difference in supply-side resource selection although the amount of cost pass through could
differ widely.
Table 3.2.1 summarizes a range of environmental cost adders we believe capture several compliance futures
including our expected scenario. The CO2 cost adders reflect outlooks we obtained from one of our
consultants, and following discussion and feedback from the TAC, have been incorporated into our
Expected, Low Growth/High Price, and Alternate Planning Standard portfolios.
The guidelines also call for a trigger point analysis that reflects a “turning point” at which an alternate
resource portfolio would be selected at different carbon cost adders levels. Because natural gas is the only
supply resource applicable to LDC’s any alternate resource portfolio selection would be a result of delivery
methods of natural gas to customers. Conceptually, there could be differing levels of cost adders applicable
to pipeline transported supply versus in service territory LNG storage gas. From a practical standpoint
however, the differences in these relative cost adders would be very minor and would not change supply-
side resource selection regardless of various carbon cost adder levels. We do acknowledge there is influence
to the avoided costs which would impact the cost effectiveness of demand-side measures in the DSM
business planning process.
CONSERVATON COST ADVANTAGE
For this IRP, we also incorporated a 10 percent environmental externality factor into our assessment of the
cost-effectiveness of existing demand-side management programs. Our assessment of prospective demand-
side management opportunities is based on an avoided cost stream that includes this 10 percent factor.
Environmental externalities were evaluated in the IRP by adding the cost per therm equivalent of the
externality cost values to supply-side resources as described in OPUC Order No. 93-965. Avista found that
the environmental cost adders had no impact on the company’s supply-side choices, although they did
impact the level of demand-side measures that could be cost-effective to acquire.
REGULATORY FILING
Avista will file revised cost-effectiveness limits (CELs) based upon the updated avoided costs available
from this IRP process within the prescribed regulatory timetable.

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 169 of 648
TABLE 3.2.1: ENVIRONMENTAL EXTERNALITIES COST ADDER ANALYSIS (2015$)

2020 2025 2030 2035
$/ton $ 2,500 $ 2,500 $ 2,500 $ 2,500
$/lb $ 1.25 $ 1.25 $ 1.25 $ 1.25
lbs/therm 0.008 0.008 0.008 0.008
NOx Adder
$/therm $ 0.01 $ 0.01 $ 0.01 $ 0.01
$/ton $ 10.55 $ 11.71 $ 14.99 $ 19.93
$/lb $ 0.0053 $ 0.0059 $ 0.0075 $ 0.0100
lbs/therm 11.64 11.64 11.64 11.64
CO2 Adder
$/therm $ 0.06 $ 0.07 $ 0.09 $ 0.12
To
t
a
l
Total Adders
$/therm $ 0.07 $ 0.08 $ 0.10 $ 0.13
2020 2025 2030 2035
$/ton $ 2,500 $ 2,500 $ 2,500 $ 2,500
$/lb $ 1.25 $ 1.25 $ 1.25 $ 1.25
lbs/therm 0.008 0.008 0.008 0.008
NOx Adder
$/therm $ 0.01 $ 0.01 $ 0.01 $ 0.01
$/ton $ 25.88 $ 30.73 $ 36.50 $ 43.35
$/lb $ 0.0129 $ 0.0154 $ 0.0182 $ 0.0217
lbs/therm 11.64 11.64 11.64 11.64
CO2 Adder
$/therm $ 0.15 $ 0.18 $ 0.21 $ 0.25
To
t
a
l
Total Adders
$/therm $ 0.16 $ 0.19 $ 0.22 $ 0.26
2020 2025 2030 2035
$/ton $ 500 $ 500 $ 500 $ 500
$/lb $ 0.25 $ 0.25 $ 0.25 $ 0.25
lbs/therm 0.008 0.008 0.008 0.008
NOx Adder
$/therm $ 0.00 $ 0.00 $ 0.00 $ 0.00
$/ton $ - $ - $ - $ -
$/lb $ - $ - $ - $ -
lbs/therm 11.64 11.64 11.64 11.64
CO2 Adder
$/therm $ - $ - $ - $ -
To
t
a
l
Total Adders
$/therm $ 0.00 $ 0.00 $ 0.00 $ 0.00
CO
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Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 170 of 648
APPENDIX 4.1: CURRENT TRANSPORTATION/STORAGE RATES AND ASSUMPTIONS

Reservation Commodity Fuel Rate
TransCanada NGTL System Firm Rates (2)
FT-D Demand Rate Alberta-B.C. Border $5.08CAD/GJ/month N/a N/a
TransCanada Foothills BC System Firm Rates (3)
FT A/BC to Kingsgate $2.48CAD/GJ/month N/a 1.60%
GTN FTS-1 Rates
Mileage Based - Representative Example
Kingsgate to Spokane $0.081391/Dth/day $0.001733/Dth/day 0.0036% per Dth/mile
Kingsgate to Malin $0.3/Dth/day $0.009799/Dth/day 0.0036% per Dth/mile
Medford Lateral $0.247709/Dth/day $0.002291/Dth/day N/a
Spectra Energy/Westcoast System Firms Rates (4)
Postage Stamp Rates
Station 2 to Huntingdon/Sumas $365.16CAD/103m3/month N/a N/a
Williams NWP
Postage Stamp Rates
TF-1 $0.40888/Dth/day $0.03/Dth/day 1.19%
TF-2 $0.40888/Dth/day $0.03/Dth/day 1.19%
SGS-2F $0.01558/Dth/day $0.00057/Dth/day N/a
(1) Rates and Fuel reported are from current tariffed rates in the established currency and energy units of each pipeline
(2) Rate does not reflect current term-differentiation or Abandonment Surcharge
(3) Rate does not include Abandonment Surcharge
(4) Rate changes annually
Current Tariff Rates (1)
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 171 of 648
APPENDIX 4.2: ALTERNATE SUPPLY SCENARIOS

Existing Resources Existing + Expected Available GTN Fully Subscribed
Resources
Currently contracted
capacity net of long term
releases
Currently contracted capacity
net of long term releases
Currently contracted capacity
net of long term releases
Currently available GTN
Capacity Release Recalls Capacity Release Recalls
NWP Expansions NWP Expansions
Satellite LNG Satellite LNG
Rates Current Rates Current Rates Current Rates
INPUT ASSUMPTIONS
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 172 of 648
APPENDIX 5.1: MONTHLY PRICE DATA BY BASIN
EXPECTED PRICE

Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
Expected Case AECo 2015-2016 1.91$ 1.63$ 2.05$ 1.84$ 1.77$ 1.74$ 1.72$ 1.74$ 1.78$ 1.87$ 1.86$ 1.86$
Expected Case AECo 2016-2017 2.03$ 2.19$ 2.36$ 2.33$ 2.24$ 2.13$ 2.11$ 2.08$ 2.11$ 2.19$ 2.16$ 2.17$
Expected Case AECo 2017-2018 2.39$ 2.50$ 3.20$ 3.14$ 2.84$ 2.63$ 2.56$ 2.52$ 2.57$ 2.61$ 2.64$ 2.66$
Expected Case AECo 2018-2019 2.90$ 3.03$ 3.10$ 3.06$ 2.63$ 2.43$ 2.43$ 2.46$ 2.52$ 2.57$ 2.66$ 2.70$
Expected Case AECo 2019-2020 2.97$ 3.12$ 3.18$ 3.16$ 2.86$ 2.56$ 2.56$ 2.56$ 2.58$ 2.61$ 2.66$ 2.65$
Expected Case AECo 2020-2021 3.07$ 3.22$ 3.26$ 3.32$ 2.99$ 2.70$ 2.72$ 2.71$ 2.66$ 2.70$ 2.94$ 2.96$
Expected Case AECo 2021-2022 3.22$ 3.35$ 3.39$ 3.44$ 3.03$ 2.77$ 2.79$ 2.78$ 2.78$ 2.82$ 2.87$ 2.88$
Expected Case AECo 2022-2023 3.14$ 3.21$ 3.17$ 3.22$ 2.89$ 2.74$ 2.79$ 2.79$ 2.81$ 2.83$ 3.02$ 3.03$
Expected Case AECo 2023-2024 3.42$ 3.51$ 3.51$ 3.51$ 3.20$ 2.97$ 2.98$ 2.97$ 3.07$ 3.11$ 3.23$ 3.24$
Expected Case AECo 2024-2025 3.70$ 3.78$ 3.81$ 3.81$ 3.45$ 3.17$ 3.26$ 3.25$ 3.33$ 3.36$ 3.49$ 3.47$
Expected Case AECo 2025-2026 3.93$ 4.09$ 3.79$ 3.79$ 3.27$ 3.11$ 3.19$ 3.18$ 3.28$ 3.34$ 3.42$ 3.43$ Expected Case AECo 2026-2027 4.00$ 3.98$ 3.75$ 3.75$ 3.33$ 3.20$ 3.24$ 3.27$ 3.37$ 3.42$ 3.64$ 3.67$
Expected Case AECo 2027-2028 4.21$ 4.28$ 4.15$ 4.14$ 3.65$ 3.55$ 3.58$ 3.59$ 3.69$ 3.71$ 3.87$ 3.90$
Expected Case AECo 2028-2029 4.37$ 4.51$ 4.41$ 4.42$ 3.90$ 3.75$ 3.82$ 3.80$ 3.83$ 3.86$ 4.01$ 4.01$
Expected Case AECo 2029-2030 4.48$ 4.63$ 4.54$ 4.59$ 4.04$ 3.88$ 3.90$ 3.94$ 4.04$ 4.07$ 4.20$ 4.24$
Expected Case AECo 2030-2031 4.74$ 4.96$ 4.74$ 4.78$ 4.19$ 4.09$ 4.11$ 4.12$ 4.18$ 4.21$ 4.37$ 4.39$
Expected Case AECo 2031-2032 4.80$ 5.06$ 4.95$ 4.94$ 4.42$ 4.26$ 4.28$ 4.29$ 4.30$ 4.38$ 4.46$ 4.49$
Expected Case AECo 2032-2033 4.91$ 5.22$ 4.95$ 4.99$ 4.38$ 4.26$ 4.25$ 4.28$ 4.37$ 4.44$ 4.51$ 4.54$
Expected Case AECo 2033-2034 4.99$ 5.30$ 5.05$ 5.08$ 4.44$ 4.32$ 4.31$ 4.33$ 4.39$ 4.42$ 4.56$ 4.57$
Expected Case AECo 2034-2035 4.96$ 5.28$ 5.05$ 5.06$ 4.60$ 4.44$ 4.43$ 4.32$ 4.37$ 4.49$ 4.60$ 4.59$
Expected Case Malin 2015-2016 2.20$ 2.03$ 2.49$ 2.34$ 2.28$ 2.22$ 2.26$ 2.31$ 2.37$ 2.40$ 2.41$ 2.44$
Expected Case Malin 2016-2017 2.71$ 2.84$ 2.91$ 2.86$ 2.77$ 2.64$ 2.64$ 2.68$ 2.74$ 2.74$ 2.80$ 2.84$
Expected Case Malin 2017-2018 3.02$ 3.08$ 3.61$ 3.57$ 3.33$ 3.15$ 3.15$ 3.17$ 3.23$ 3.27$ 3.29$ 3.35$
Expected Case Malin 2018-2019 3.47$ 3.59$ 3.67$ 3.63$ 3.31$ 3.19$ 3.18$ 3.19$ 3.21$ 3.28$ 3.35$ 3.38$
Expected Case Malin 2019-2020 3.52$ 3.61$ 3.69$ 3.66$ 3.39$ 3.28$ 3.21$ 3.20$ 3.23$ 3.31$ 3.32$ 3.32$
Expected Case Malin 2020-2021 3.56$ 3.66$ 3.77$ 3.77$ 3.46$ 3.37$ 3.36$ 3.33$ 3.40$ 3.46$ 3.48$ 3.53$
Expected Case Malin 2021-2022 3.79$ 3.87$ 3.97$ 3.98$ 3.59$ 3.48$ 3.45$ 3.43$ 3.49$ 3.51$ 3.53$ 3.54$
Expected Case Malin 2022-2023 3.80$ 3.88$ 3.95$ 3.97$ 3.62$ 3.48$ 3.48$ 3.48$ 3.50$ 3.56$ 3.56$ 3.57$
Expected Case Malin 2023-2024 3.89$ 3.99$ 4.00$ 3.97$ 3.65$ 3.60$ 3.58$ 3.56$ 3.59$ 3.69$ 3.70$ 3.72$
Expected Case Malin 2024-2025 4.06$ 4.18$ 4.24$ 4.24$ 3.89$ 3.83$ 3.80$ 3.79$ 3.85$ 3.91$ 3.91$ 3.92$
Expected Case Malin 2025-2026 4.28$ 4.54$ 4.27$ 4.30$ 3.84$ 3.74$ 3.71$ 3.71$ 3.78$ 3.85$ 3.86$ 3.88$
Expected Case Malin 2026-2027 4.31$ 4.52$ 4.36$ 4.37$ 3.93$ 3.82$ 3.79$ 3.79$ 3.84$ 3.91$ 3.92$ 4.00$
Expected Case Malin 2027-2028 4.46$ 4.67$ 4.53$ 4.53$ 4.10$ 4.01$ 3.99$ 3.98$ 4.03$ 4.10$ 4.11$ 4.16$
Expected Case Malin 2028-2029 4.60$ 4.82$ 4.77$ 4.78$ 4.32$ 4.20$ 4.18$ 4.15$ 4.17$ 4.22$ 4.24$ 4.27$
Expected Case Malin 2029-2030 4.73$ 4.98$ 4.88$ 4.91$ 4.46$ 4.30$ 4.30$ 4.30$ 4.33$ 4.41$ 4.47$ 4.51$
Expected Case Malin 2030-2031 5.01$ 5.25$ 5.03$ 5.06$ 4.61$ 4.46$ 4.42$ 4.42$ 4.46$ 4.53$ 4.60$ 4.63$
Expected Case Malin 2031-2032 5.08$ 5.32$ 5.23$ 5.23$ 4.73$ 4.61$ 4.54$ 4.53$ 4.56$ 4.66$ 4.71$ 4.75$
Expected Case Malin 2032-2033 5.23$ 5.46$ 5.23$ 5.25$ 4.77$ 4.63$ 4.55$ 4.55$ 4.66$ 4.74$ 4.77$ 4.82$ Expected Case Malin 2033-2034 5.32$ 5.62$ 5.40$ 5.41$ 4.86$ 4.72$ 4.69$ 4.68$ 4.73$ 4.80$ 4.82$ 4.84$
Expected Case Malin 2034-2035 5.31$ 5.63$ 5.39$ 5.41$ 4.86$ 4.72$ 4.74$ 4.72$ 4.80$ 4.86$ 4.87$ 4.89$
Expected Case Rockies 2015-2016 2.01$ 1.81$ 2.32$ 2.21$ 2.17$ 2.16$ 2.18$ 2.22$ 2.27$ 2.34$ 2.37$ 2.42$
Expected Case Rockies 2016-2017 2.63$ 2.76$ 2.84$ 2.81$ 2.69$ 2.55$ 2.58$ 2.62$ 2.66$ 2.69$ 2.75$ 2.77$
Expected Case Rockies 2017-2018 2.91$ 3.01$ 3.57$ 3.53$ 3.28$ 3.11$ 3.09$ 3.11$ 3.15$ 3.20$ 3.25$ 3.26$
Expected Case Rockies 2018-2019 3.40$ 3.52$ 3.59$ 3.56$ 3.25$ 3.14$ 3.13$ 3.13$ 3.15$ 3.22$ 3.26$ 3.29$
Expected Case Rockies 2019-2020 3.44$ 3.53$ 3.61$ 3.59$ 3.33$ 3.22$ 3.17$ 3.17$ 3.18$ 3.25$ 3.27$ 3.25$
Expected Case Rockies 2020-2021 3.49$ 3.60$ 3.70$ 3.70$ 3.42$ 3.32$ 3.31$ 3.33$ 3.35$ 3.41$ 3.43$ 3.46$
Expected Case Rockies 2021-2022 3.71$ 3.82$ 3.90$ 3.90$ 3.54$ 3.43$ 3.42$ 3.42$ 3.43$ 3.46$ 3.47$ 3.47$
Expected Case Rockies 2022-2023 3.72$ 3.83$ 3.86$ 3.89$ 3.54$ 3.43$ 3.43$ 3.41$ 3.42$ 3.51$ 3.52$ 3.51$
Expected Case Rockies 2023-2024 3.81$ 3.93$ 3.90$ 3.88$ 3.60$ 3.55$ 3.54$ 3.52$ 3.55$ 3.65$ 3.66$ 3.68$
Expected Case Rockies 2024-2025 4.00$ 4.15$ 4.19$ 4.18$ 3.86$ 3.80$ 3.76$ 3.75$ 3.81$ 3.87$ 3.87$ 3.87$
Expected Case Rockies 2025-2026 4.20$ 4.49$ 4.23$ 4.24$ 3.80$ 3.71$ 3.67$ 3.68$ 3.73$ 3.81$ 3.81$ 3.82$
Expected Case Rockies 2026-2027 4.23$ 4.45$ 4.29$ 4.29$ 3.87$ 3.78$ 3.75$ 3.75$ 3.80$ 3.86$ 3.87$ 3.92$
Expected Case Rockies 2027-2028 4.35$ 4.59$ 4.45$ 4.45$ 4.03$ 3.96$ 3.94$ 3.92$ 3.97$ 4.04$ 4.05$ 4.08$
Expected Case Rockies 2028-2029 4.50$ 4.75$ 4.68$ 4.70$ 4.24$ 4.15$ 4.12$ 4.10$ 4.10$ 4.15$ 4.18$ 4.19$
Expected Case Rockies 2029-2030 4.66$ 4.89$ 4.80$ 4.82$ 4.38$ 4.27$ 4.25$ 4.25$ 4.27$ 4.36$ 4.39$ 4.45$
Expected Case Rockies 2030-2031 4.94$ 5.18$ 4.95$ 4.98$ 4.53$ 4.41$ 4.38$ 4.37$ 4.41$ 4.48$ 4.52$ 4.56$
Expected Case Rockies 2031-2032 5.01$ 5.24$ 5.15$ 5.15$ 4.66$ 4.57$ 4.49$ 4.47$ 4.50$ 4.59$ 4.62$ 4.67$
Expected Case Rockies 2032-2033 5.14$ 5.39$ 5.16$ 5.18$ 4.69$ 4.57$ 4.49$ 4.50$ 4.53$ 4.64$ 4.70$ 4.74$
Expected Case Rockies 2033-2034 5.22$ 5.49$ 5.26$ 5.27$ 4.79$ 4.67$ 4.62$ 4.60$ 4.61$ 4.71$ 4.76$ 4.76$
Expected Case Rockies 2034-2035 5.20$ 5.47$ 5.24$ 5.26$ 4.78$ 4.67$ 4.68$ 4.63$ 4.69$ 4.78$ 4.82$ 4.81$
2014$
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 173 of 648
APPENDIX 5.1: MONTHLY PRICE DATA BY BASIN
EXPECTED PRICE

Expected Case Stanfield 2015-2016 2.17$ 1.98$ 2.42$ 2.27$ 2.19$ 2.15$ 2.19$ 2.23$ 2.27$ 2.34$ 2.34$ 2.37$
Expected Case Stanfield 2016-2017 2.63$ 2.76$ 2.88$ 2.85$ 2.72$ 2.58$ 2.58$ 2.64$ 2.67$ 2.68$ 2.73$ 2.78$
Expected Case Stanfield 2017-2018 2.94$ 3.03$ 3.58$ 3.54$ 3.29$ 3.14$ 3.09$ 3.12$ 3.15$ 3.20$ 3.25$ 3.27$
Expected Case Stanfield 2018-2019 3.39$ 3.50$ 3.58$ 3.54$ 3.24$ 3.11$ 3.11$ 3.10$ 3.13$ 3.20$ 3.26$ 3.29$
Expected Case Stanfield 2019-2020 3.43$ 3.51$ 3.59$ 3.56$ 3.29$ 3.21$ 3.14$ 3.11$ 3.16$ 3.23$ 3.25$ 3.24$
Expected Case Stanfield 2020-2021 3.47$ 3.56$ 3.67$ 3.67$ 3.37$ 3.30$ 3.28$ 3.25$ 3.32$ 3.38$ 3.39$ 3.44$
Expected Case Stanfield 2021-2022 3.70$ 3.78$ 3.87$ 3.88$ 3.50$ 3.41$ 3.38$ 3.36$ 3.41$ 3.43$ 3.42$ 3.44$
Expected Case Stanfield 2022-2023 3.70$ 3.78$ 3.84$ 3.87$ 3.53$ 3.41$ 3.40$ 3.39$ 3.42$ 3.48$ 3.49$ 3.48$
Expected Case Stanfield 2023-2024 3.80$ 3.89$ 3.95$ 3.86$ 3.58$ 3.55$ 3.52$ 3.49$ 3.52$ 3.61$ 3.62$ 3.67$
Expected Case Stanfield 2024-2025 4.00$ 4.12$ 4.16$ 4.17$ 3.83$ 3.79$ 3.75$ 3.74$ 3.78$ 3.85$ 3.84$ 3.86$
Expected Case Stanfield 2025-2026 4.23$ 4.48$ 4.21$ 4.24$ 3.79$ 3.69$ 3.66$ 3.66$ 3.71$ 3.80$ 3.81$ 3.83$
Expected Case Stanfield 2026-2027 4.26$ 4.47$ 4.30$ 4.30$ 3.88$ 3.78$ 3.76$ 3.76$ 3.81$ 3.87$ 3.88$ 3.95$
Expected Case Stanfield 2027-2028 4.42$ 4.62$ 4.46$ 4.47$ 4.04$ 3.97$ 3.95$ 3.93$ 3.98$ 4.04$ 4.05$ 4.10$
Expected Case Stanfield 2028-2029 4.55$ 4.75$ 4.68$ 4.71$ 4.25$ 4.16$ 4.14$ 4.11$ 4.10$ 4.16$ 4.17$ 4.20$
Expected Case Stanfield 2029-2030 4.67$ 4.90$ 4.81$ 4.84$ 4.39$ 4.27$ 4.26$ 4.26$ 4.29$ 4.35$ 4.42$ 4.44$
Expected Case Stanfield 2030-2031 4.93$ 5.18$ 4.96$ 4.99$ 4.56$ 4.42$ 4.39$ 4.38$ 4.43$ 4.49$ 4.54$ 4.55$
Expected Case Stanfield 2031-2032 5.02$ 5.25$ 5.16$ 5.16$ 4.66$ 4.57$ 4.48$ 4.49$ 4.52$ 4.62$ 4.65$ 4.69$
Expected Case Stanfield 2032-2033 5.17$ 5.40$ 5.15$ 5.18$ 4.71$ 4.60$ 4.51$ 4.51$ 4.62$ 4.69$ 4.69$ 4.75$
Expected Case Stanfield 2033-2034 5.25$ 5.55$ 5.32$ 5.34$ 4.80$ 4.68$ 4.65$ 4.64$ 4.68$ 4.74$ 4.75$ 4.77$
Expected Case Stanfield 2034-2035 5.24$ 5.55$ 5.31$ 5.34$ 4.80$ 4.65$ 4.69$ 4.67$ 4.73$ 4.78$ 4.79$ 4.83$
Expected Case Sumas 2015-2016 2.16$ 1.93$ 2.39$ 2.19$ 2.04$ 1.96$ 1.86$ 1.89$ 1.90$ 2.02$ 2.17$ 2.23$
Expected Case Sumas 2016-2017 2.49$ 2.80$ 2.84$ 2.78$ 2.66$ 2.50$ 2.48$ 2.44$ 2.49$ 2.55$ 2.62$ 2.60$
Expected Case Sumas 2017-2018 2.87$ 3.04$ 3.55$ 3.49$ 3.24$ 3.04$ 2.81$ 2.81$ 2.85$ 2.97$ 3.01$ 3.15$
Expected Case Sumas 2018-2019 3.29$ 3.44$ 3.54$ 3.51$ 3.15$ 2.94$ 2.86$ 2.80$ 2.87$ 3.00$ 3.08$ 3.17$
Expected Case Sumas 2019-2020 3.32$ 3.45$ 3.52$ 3.51$ 3.23$ 3.06$ 2.95$ 2.85$ 2.97$ 3.06$ 3.13$ 3.16$
Expected Case Sumas 2020-2021 3.39$ 3.50$ 3.62$ 3.66$ 3.35$ 3.19$ 3.12$ 3.04$ 3.15$ 3.23$ 3.32$ 3.36$
Expected Case Sumas 2021-2022 3.57$ 3.63$ 3.74$ 3.75$ 3.46$ 3.31$ 3.21$ 3.19$ 3.22$ 3.30$ 3.37$ 3.37$
Expected Case Sumas 2022-2023 3.60$ 3.63$ 3.70$ 3.76$ 3.48$ 3.33$ 3.24$ 3.24$ 3.26$ 3.37$ 3.41$ 3.40$
Expected Case Sumas 2023-2024 3.70$ 3.84$ 3.83$ 3.80$ 3.52$ 3.43$ 3.31$ 3.31$ 3.34$ 3.49$ 3.55$ 3.57$
Expected Case Sumas 2024-2025 3.89$ 3.94$ 4.07$ 4.10$ 3.78$ 3.66$ 3.55$ 3.51$ 3.58$ 3.71$ 3.75$ 3.75$
Expected Case Sumas 2025-2026 4.05$ 4.30$ 4.04$ 4.06$ 3.68$ 3.57$ 3.45$ 3.41$ 3.52$ 3.65$ 3.67$ 3.67$
Expected Case Sumas 2026-2027 4.09$ 4.29$ 4.12$ 4.13$ 3.78$ 3.64$ 3.59$ 3.54$ 3.63$ 3.71$ 3.77$ 3.89$
Expected Case Sumas 2027-2028 4.32$ 4.59$ 4.47$ 4.47$ 3.98$ 3.90$ 3.79$ 3.81$ 3.85$ 3.99$ 4.03$ 4.07$
Expected Case Sumas 2028-2029 4.55$ 4.76$ 4.71$ 4.73$ 4.25$ 4.11$ 4.00$ 3.98$ 4.00$ 4.12$ 4.14$ 4.18$
Expected Case Sumas 2029-2030 4.68$ 4.92$ 4.82$ 4.85$ 4.40$ 4.22$ 4.16$ 4.18$ 4.18$ 4.32$ 4.42$ 4.47$
Expected Case Sumas 2030-2031 4.96$ 5.20$ 4.97$ 5.01$ 4.56$ 4.37$ 4.30$ 4.31$ 4.32$ 4.45$ 4.55$ 4.58$
Expected Case Sumas 2031-2032 5.03$ 5.27$ 5.18$ 5.18$ 4.68$ 4.52$ 4.44$ 4.43$ 4.41$ 4.57$ 4.64$ 4.69$
Expected Case Sumas 2032-2033 5.17$ 5.41$ 5.17$ 5.19$ 4.71$ 4.54$ 4.42$ 4.42$ 4.46$ 4.63$ 4.69$ 4.78$
Expected Case Sumas 2033-2034 5.31$ 5.62$ 5.41$ 5.41$ 4.83$ 4.65$ 4.55$ 4.53$ 4.55$ 4.70$ 4.76$ 4.80$
Expected Case Sumas 2034-2035 5.30$ 5.63$ 5.41$ 5.43$ 4.84$ 4.68$ 4.65$ 4.59$ 4.65$ 4.77$ 4.82$ 4.85$
2014$
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 174 of 648
APPENDIX 5.1: MONTHLY PRICE DATA BY BASIN
HIGH GROWTH LOW PRICE

Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
High Growth & Low Prices AECo 2015-2016 1.91$ 1.63$ 1.82$ 1.88$ 1.50$ 1.22$ 1.43$ 1.48$ 1.98$ 1.87$ 1.29$ 1.56$
High Growth & Low Prices AECo 2016-2017 1.23$ 0.86$ 1.56$ 1.71$ 1.42$ 1.25$ 1.55$ 1.48$ 1.97$ 1.85$ 1.32$ 1.44$
High Growth & Low Prices AECo 2017-2018 1.35$ 0.96$ 1.71$ 1.84$ 1.47$ 1.23$ 1.42$ 1.42$ 1.93$ 1.75$ 1.30$ 1.35$
High Growth & Low Prices AECo 2018-2019 1.32$ 1.07$ 1.60$ 1.74$ 1.28$ 1.01$ 1.28$ 1.37$ 1.89$ 1.71$ 1.20$ 1.41$
High Growth & Low Prices AECo 2019-2020 1.33$ 0.99$ 1.61$ 1.75$ 1.41$ 1.03$ 1.30$ 1.36$ 1.87$ 1.70$ 1.40$ 1.37$
High Growth & Low Prices AECo 2020-2021 1.37$ 1.05$ 1.64$ 1.84$ 1.47$ 1.10$ 1.38$ 1.42$ 1.83$ 1.66$ 1.34$ 1.44$
High Growth & Low Prices AECo 2021-2022 1.36$ 1.02$ 1.56$ 1.76$ 1.40$ 1.06$ 1.35$ 1.40$ 1.89$ 1.73$ 1.32$ 1.43$
High Growth & Low Prices AECo 2022-2023 1.25$ 0.85$ 1.36$ 1.55$ 1.25$ 1.01$ 1.32$ 1.38$ 1.88$ 1.70$ 1.40$ 1.62$ High Growth & Low Prices AECo 2023-2024 1.58$ 1.03$ 1.63$ 1.80$ 1.50$ 1.12$ 1.39$ 1.44$ 2.02$ 1.85$ 1.51$ 1.53$
High Growth & Low Prices AECo 2024-2025 1.58$ 1.16$ 1.68$ 1.83$ 1.50$ 1.08$ 1.43$ 1.48$ 2.02$ 1.85$ 1.61$ 1.54$
High Growth & Low Prices AECo 2025-2026 1.51$ 1.03$ 1.61$ 1.75$ 1.37$ 1.10$ 1.43$ 1.47$ 2.03$ 1.88$ 1.50$ 1.54$
High Growth & Low Prices AECo 2026-2027 1.55$ 0.93$ 1.50$ 1.64$ 1.34$ 1.10$ 1.41$ 1.49$ 2.05$ 1.89$ 1.61$ 1.70$
High Growth & Low Prices AECo 2027-2028 1.64$ 1.10$ 1.74$ 1.87$ 1.50$ 1.27$ 1.56$ 1.63$ 2.18$ 1.99$ 1.50$ 1.74$
High Growth & Low Prices AECo 2028-2029 1.71$ 1.19$ 1.80$ 1.93$ 1.57$ 1.29$ 1.70$ 1.68$ 2.19$ 2.02$ 1.67$ 1.76$
High Growth & Low Prices AECo 2029-2030 1.66$ 1.40$ 1.81$ 1.99$ 1.59$ 1.32$ 1.60$ 1.70$ 2.24$ 2.06$ 1.81$ 1.78$
High Growth & Low Prices AECo 2030-2031 1.67$ 1.43$ 1.87$ 2.05$ 1.62$ 1.41$ 1.69$ 1.76$ 2.26$ 2.08$ 1.79$ 1.84$
High Growth & Low Prices AECo 2031-2032 1.80$ 1.28$ 1.88$ 2.04$ 1.72$ 1.46$ 1.82$ 1.80$ 2.27$ 2.15$ 1.77$ 1.84$
High Growth & Low Prices AECo 2032-2033 1.67$ 1.43$ 1.92$ 2.09$ 1.69$ 1.48$ 1.85$ 1.81$ 2.34$ 2.20$ 1.62$ 1.84$
High Growth & Low Prices AECo 2033-2034 1.90$ 1.32$ 1.92$ 2.09$ 1.64$ 1.43$ 1.70$ 1.78$ 2.29$ 2.12$ 1.96$ 1.85$
High Growth & Low Prices AECo 2034-2035 1.67$ 1.33$ 1.95$ 2.09$ 1.83$ 1.56$ 1.80$ 1.74$ 2.24$ 2.14$ 1.78$ 1.82$
High Growth & Low Prices Malin 2015-2016 2.20$ 2.03$ 2.26$ 2.38$ 2.01$ 1.70$ 1.97$ 2.05$ 2.57$ 2.40$ 1.84$ 2.14$
High Growth & Low Prices Malin 2016-2017 1.91$ 1.51$ 2.12$ 2.25$ 1.95$ 1.76$ 2.08$ 2.08$ 2.60$ 2.41$ 1.96$ 2.11$
High Growth & Low Prices Malin 2017-2018 1.98$ 1.54$ 2.12$ 2.27$ 1.97$ 1.75$ 2.01$ 2.07$ 2.59$ 2.41$ 1.94$ 2.04$
High Growth & Low Prices Malin 2018-2019 1.88$ 1.63$ 2.16$ 2.31$ 1.97$ 1.77$ 2.03$ 2.09$ 2.58$ 2.43$ 1.89$ 2.08$ High Growth & Low Prices Malin 2019-2020 1.88$ 1.48$ 2.11$ 2.25$ 1.93$ 1.74$ 1.94$ 2.00$ 2.52$ 2.40$ 2.05$ 2.03$
High Growth & Low Prices Malin 2020-2021 1.86$ 1.49$ 2.14$ 2.29$ 1.94$ 1.76$ 2.02$ 2.03$ 2.58$ 2.42$ 1.88$ 2.01$
High Growth & Low Prices Malin 2021-2022 1.92$ 1.55$ 2.14$ 2.30$ 1.96$ 1.76$ 2.01$ 2.05$ 2.59$ 2.42$ 1.97$ 2.10$
High Growth & Low Prices Malin 2022-2023 1.91$ 1.51$ 2.14$ 2.31$ 1.97$ 1.75$ 2.00$ 2.07$ 2.57$ 2.43$ 1.94$ 2.17$
High Growth & Low Prices Malin 2023-2024 2.04$ 1.50$ 2.13$ 2.26$ 1.94$ 1.74$ 1.99$ 2.03$ 2.54$ 2.43$ 1.97$ 2.02$
High Growth & Low Prices Malin 2024-2025 1.95$ 1.55$ 2.11$ 2.26$ 1.93$ 1.74$ 1.97$ 2.02$ 2.54$ 2.40$ 2.03$ 1.99$
High Growth & Low Prices Malin 2025-2026 1.86$ 1.47$ 2.09$ 2.26$ 1.94$ 1.73$ 1.95$ 2.01$ 2.53$ 2.39$ 1.94$ 1.99$ High Growth & Low Prices Malin 2026-2027 1.86$ 1.47$ 2.11$ 2.26$ 1.94$ 1.72$ 1.96$ 2.02$ 2.52$ 2.38$ 1.90$ 2.03$
High Growth & Low Prices Malin 2027-2028 1.89$ 1.50$ 2.11$ 2.27$ 1.95$ 1.73$ 1.97$ 2.02$ 2.52$ 2.38$ 1.74$ 2.01$
High Growth & Low Prices Malin 2028-2029 1.95$ 1.50$ 2.15$ 2.30$ 1.99$ 1.74$ 2.05$ 2.03$ 2.52$ 2.38$ 1.91$ 2.02$
High Growth & Low Prices Malin 2029-2030 1.91$ 1.74$ 2.15$ 2.31$ 2.02$ 1.75$ 2.00$ 2.05$ 2.53$ 2.41$ 2.07$ 2.05$
High Growth & Low Prices Malin 2030-2031 1.94$ 1.71$ 2.17$ 2.33$ 2.03$ 1.78$ 2.00$ 2.05$ 2.54$ 2.40$ 2.02$ 2.07$
High Growth & Low Prices Malin 2031-2032 2.09$ 1.53$ 2.17$ 2.33$ 2.03$ 1.80$ 2.08$ 2.04$ 2.53$ 2.43$ 2.01$ 2.10$
High Growth & Low Prices Malin 2032-2033 1.99$ 1.68$ 2.19$ 2.35$ 2.08$ 1.85$ 2.15$ 2.08$ 2.63$ 2.50$ 1.87$ 2.12$
High Growth & Low Prices Malin 2033-2034 2.22$ 1.64$ 2.27$ 2.42$ 2.07$ 1.84$ 2.08$ 2.13$ 2.63$ 2.50$ 2.23$ 2.12$
High Growth & Low Prices Malin 2034-2035 2.02$ 1.67$ 2.29$ 2.44$ 2.09$ 1.84$ 2.10$ 2.14$ 2.66$ 2.51$ 2.05$ 2.13$
High Growth & Low Prices Rockies 2015-2016 2.01$ 1.81$ 2.10$ 2.25$ 1.90$ 1.64$ 1.89$ 1.96$ 2.47$ 2.34$ 1.79$ 2.12$
High Growth & Low Prices Rockies 2016-2017 1.83$ 1.43$ 2.05$ 2.20$ 1.87$ 1.67$ 2.03$ 2.02$ 2.52$ 2.36$ 1.90$ 2.04$
High Growth & Low Prices Rockies 2017-2018 1.88$ 1.46$ 2.07$ 2.23$ 1.92$ 1.71$ 1.96$ 2.02$ 2.51$ 2.35$ 1.90$ 1.95$
High Growth & Low Prices Rockies 2018-2019 1.82$ 1.55$ 2.09$ 2.23$ 1.91$ 1.72$ 1.98$ 2.04$ 2.52$ 2.36$ 1.80$ 1.99$
High Growth & Low Prices Rockies 2019-2020 1.80$ 1.40$ 2.03$ 2.18$ 1.88$ 1.68$ 1.91$ 1.97$ 2.47$ 2.34$ 2.00$ 1.97$
High Growth & Low Prices Rockies 2020-2021 1.79$ 1.43$ 2.07$ 2.22$ 1.90$ 1.71$ 1.97$ 2.03$ 2.53$ 2.37$ 1.83$ 1.94$
High Growth & Low Prices Rockies 2021-2022 1.85$ 1.50$ 2.07$ 2.22$ 1.91$ 1.72$ 1.97$ 2.04$ 2.54$ 2.37$ 1.92$ 2.03$ High Growth & Low Prices Rockies 2022-2023 1.82$ 1.47$ 2.05$ 2.22$ 1.90$ 1.70$ 1.95$ 2.00$ 2.49$ 2.38$ 1.90$ 2.11$
High Growth & Low Prices Rockies 2023-2024 1.97$ 1.44$ 2.03$ 2.17$ 1.89$ 1.70$ 1.95$ 1.99$ 2.50$ 2.39$ 1.94$ 1.98$
High Growth & Low Prices Rockies 2024-2025 1.89$ 1.53$ 2.06$ 2.20$ 1.90$ 1.71$ 1.94$ 1.99$ 2.50$ 2.36$ 1.99$ 1.94$
High Growth & Low Prices Rockies 2025-2026 1.78$ 1.42$ 2.04$ 2.19$ 1.90$ 1.69$ 1.91$ 1.98$ 2.48$ 2.35$ 1.89$ 1.93$
High Growth & Low Prices Rockies 2026-2027 1.78$ 1.40$ 2.04$ 2.18$ 1.88$ 1.69$ 1.92$ 1.97$ 2.48$ 2.32$ 1.84$ 1.95$
High Growth & Low Prices Rockies 2027-2028 1.78$ 1.41$ 2.03$ 2.18$ 1.88$ 1.69$ 1.91$ 1.96$ 2.46$ 2.33$ 1.68$ 1.92$
High Growth & Low Prices Rockies 2028-2029 1.84$ 1.42$ 2.07$ 2.22$ 1.90$ 1.70$ 2.00$ 1.98$ 2.45$ 2.32$ 1.84$ 1.93$
High Growth & Low Prices Rockies 2029-2030 1.84$ 1.66$ 2.07$ 2.22$ 1.93$ 1.72$ 1.96$ 2.00$ 2.47$ 2.36$ 2.00$ 2.00$
High Growth & Low Prices Rockies 2030-2031 1.87$ 1.64$ 2.08$ 2.24$ 1.95$ 1.73$ 1.95$ 2.00$ 2.49$ 2.35$ 1.94$ 2.01$
High Growth & Low Prices Rockies 2031-2032 2.02$ 1.46$ 2.09$ 2.25$ 1.96$ 1.77$ 2.03$ 1.99$ 2.47$ 2.36$ 1.93$ 2.03$ High Growth & Low Prices Rockies 2032-2033 1.89$ 1.61$ 2.12$ 2.28$ 1.99$ 1.78$ 2.10$ 2.03$ 2.49$ 2.40$ 1.80$ 2.04$
High Growth & Low Prices Rockies 2033-2034 2.13$ 1.51$ 2.13$ 2.29$ 2.00$ 1.79$ 2.01$ 2.04$ 2.51$ 2.41$ 2.17$ 2.05$
High Growth & Low Prices Rockies 2034-2035 1.91$ 1.52$ 2.14$ 2.29$ 2.01$ 1.79$ 2.04$ 2.05$ 2.55$ 2.43$ 1.99$ 2.04$
2014$
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 175 of 648
APPENDIX 5.1: MONTHLY PRICE DATA BY BASIN
HIGH GROWTH LOW PRICE

High Growth & Low Prices Stanfield 2015-2016 2.17$ 1.98$ 2.19$ 2.31$ 1.92$ 1.63$ 1.90$ 1.97$ 2.47$ 2.34$ 1.77$ 2.07$
High Growth & Low Prices Stanfield 2016-2017 1.84$ 1.43$ 2.09$ 2.23$ 1.91$ 1.71$ 2.02$ 2.04$ 2.52$ 2.34$ 1.89$ 2.05$
High Growth & Low Prices Stanfield 2017-2018 1.91$ 1.48$ 2.09$ 2.23$ 1.92$ 1.74$ 1.95$ 2.02$ 2.51$ 2.35$ 1.90$ 1.96$
High Growth & Low Prices Stanfield 2018-2019 1.81$ 1.54$ 2.07$ 2.22$ 1.89$ 1.70$ 1.96$ 2.01$ 2.50$ 2.34$ 1.80$ 2.00$ High Growth & Low Prices Stanfield 2019-2020 1.79$ 1.38$ 2.01$ 2.15$ 1.84$ 1.68$ 1.87$ 1.91$ 2.45$ 2.33$ 1.98$ 1.96$
High Growth & Low Prices Stanfield 2020-2021 1.78$ 1.40$ 2.05$ 2.18$ 1.86$ 1.69$ 1.94$ 1.96$ 2.50$ 2.34$ 1.78$ 1.92$
High Growth & Low Prices Stanfield 2021-2022 1.84$ 1.45$ 2.04$ 2.19$ 1.88$ 1.70$ 1.94$ 1.98$ 2.52$ 2.34$ 1.86$ 2.00$
High Growth & Low Prices Stanfield 2022-2023 1.81$ 1.41$ 2.04$ 2.20$ 1.88$ 1.68$ 1.93$ 1.98$ 2.49$ 2.36$ 1.87$ 2.08$
High Growth & Low Prices Stanfield 2023-2024 1.96$ 1.41$ 2.07$ 2.15$ 1.88$ 1.69$ 1.94$ 1.97$ 2.46$ 2.35$ 1.90$ 1.96$
High Growth & Low Prices Stanfield 2024-2025 1.89$ 1.50$ 2.04$ 2.19$ 1.88$ 1.70$ 1.93$ 1.98$ 2.47$ 2.34$ 1.96$ 1.93$
High Growth & Low Prices Stanfield 2025-2026 1.81$ 1.42$ 2.02$ 2.19$ 1.88$ 1.68$ 1.90$ 1.95$ 2.46$ 2.34$ 1.89$ 1.94$ High Growth & Low Prices Stanfield 2026-2027 1.81$ 1.41$ 2.05$ 2.19$ 1.89$ 1.69$ 1.93$ 1.99$ 2.48$ 2.34$ 1.85$ 1.98$
High Growth & Low Prices Stanfield 2027-2028 1.85$ 1.44$ 2.04$ 2.20$ 1.89$ 1.70$ 1.93$ 1.96$ 2.47$ 2.32$ 1.68$ 1.94$
High Growth & Low Prices Stanfield 2028-2029 1.89$ 1.42$ 2.07$ 2.23$ 1.92$ 1.71$ 2.02$ 1.99$ 2.45$ 2.32$ 1.83$ 1.95$
High Growth & Low Prices Stanfield 2029-2030 1.85$ 1.67$ 2.08$ 2.24$ 1.95$ 1.72$ 1.96$ 2.01$ 2.49$ 2.35$ 2.02$ 1.98$
High Growth & Low Prices Stanfield 2030-2031 1.86$ 1.65$ 2.10$ 2.26$ 1.98$ 1.74$ 1.96$ 2.02$ 2.50$ 2.36$ 1.97$ 2.00$
High Growth & Low Prices Stanfield 2031-2032 2.03$ 1.47$ 2.09$ 2.25$ 1.96$ 1.77$ 2.03$ 2.00$ 2.49$ 2.39$ 1.96$ 2.04$
High Growth & Low Prices Stanfield 2032-2033 1.92$ 1.61$ 2.11$ 2.28$ 2.01$ 1.81$ 2.11$ 2.04$ 2.58$ 2.45$ 1.80$ 2.05$
High Growth & Low Prices Stanfield 2033-2034 2.16$ 1.57$ 2.19$ 2.35$ 2.01$ 1.80$ 2.04$ 2.09$ 2.58$ 2.44$ 2.15$ 2.06$
High Growth & Low Prices Stanfield 2034-2035 1.95$ 1.60$ 2.20$ 2.36$ 2.02$ 1.78$ 2.06$ 2.09$ 2.59$ 2.43$ 1.97$ 2.06$
High Growth & Low Prices Sumas 2015-2016 2.16$ 1.93$ 2.16$ 2.23$ 1.76$ 1.44$ 1.57$ 1.63$ 2.10$ 2.02$ 1.60$ 1.93$
High Growth & Low Prices Sumas 2016-2017 1.70$ 1.47$ 2.05$ 2.16$ 1.84$ 1.63$ 1.92$ 1.84$ 2.35$ 2.21$ 1.78$ 1.87$
High Growth & Low Prices Sumas 2017-2018 1.84$ 1.49$ 2.05$ 2.19$ 1.88$ 1.64$ 1.67$ 1.72$ 2.21$ 2.12$ 1.66$ 1.84$
High Growth & Low Prices Sumas 2018-2019 1.70$ 1.48$ 2.04$ 2.19$ 1.80$ 1.52$ 1.71$ 1.71$ 2.24$ 2.14$ 1.62$ 1.87$
High Growth & Low Prices Sumas 2019-2020 1.68$ 1.32$ 1.94$ 2.10$ 1.78$ 1.52$ 1.68$ 1.65$ 2.25$ 2.15$ 1.86$ 1.88$
High Growth & Low Prices Sumas 2020-2021 1.69$ 1.33$ 2.00$ 2.17$ 1.83$ 1.58$ 1.78$ 1.74$ 2.33$ 2.19$ 1.71$ 1.84$
High Growth & Low Prices Sumas 2021-2022 1.71$ 1.31$ 1.91$ 2.06$ 1.83$ 1.60$ 1.77$ 1.81$ 2.32$ 2.21$ 1.82$ 1.92$ High Growth & Low Prices Sumas 2022-2023 1.71$ 1.27$ 1.89$ 2.09$ 1.84$ 1.61$ 1.77$ 1.83$ 2.33$ 2.25$ 1.79$ 2.00$
High Growth & Low Prices Sumas 2023-2024 1.86$ 1.36$ 1.96$ 2.09$ 1.82$ 1.58$ 1.72$ 1.79$ 2.28$ 2.23$ 1.82$ 1.86$
High Growth & Low Prices Sumas 2024-2025 1.77$ 1.32$ 1.94$ 2.12$ 1.82$ 1.57$ 1.72$ 1.75$ 2.27$ 2.19$ 1.87$ 1.82$
High Growth & Low Prices Sumas 2025-2026 1.63$ 1.23$ 1.85$ 2.02$ 1.78$ 1.56$ 1.69$ 1.71$ 2.27$ 2.19$ 1.74$ 1.78$
High Growth & Low Prices Sumas 2026-2027 1.64$ 1.23$ 1.87$ 2.02$ 1.79$ 1.55$ 1.76$ 1.77$ 2.31$ 2.18$ 1.74$ 1.92$
High Growth & Low Prices Sumas 2027-2028 1.75$ 1.41$ 2.05$ 2.21$ 1.83$ 1.63$ 1.77$ 1.84$ 2.34$ 2.27$ 1.66$ 1.92$
High Growth & Low Prices Sumas 2028-2029 1.90$ 1.44$ 2.09$ 2.25$ 1.92$ 1.65$ 1.87$ 1.86$ 2.35$ 2.29$ 1.80$ 1.93$ High Growth & Low Prices Sumas 2029-2030 1.86$ 1.68$ 2.09$ 2.25$ 1.96$ 1.67$ 1.87$ 1.94$ 2.39$ 2.31$ 2.02$ 2.01$
High Growth & Low Prices Sumas 2030-2031 1.89$ 1.66$ 2.11$ 2.27$ 1.98$ 1.69$ 1.88$ 1.94$ 2.39$ 2.32$ 1.97$ 2.02$
High Growth & Low Prices Sumas 2031-2032 2.04$ 1.49$ 2.12$ 2.28$ 1.98$ 1.72$ 1.98$ 1.95$ 2.38$ 2.34$ 1.95$ 2.04$
High Growth & Low Prices Sumas 2032-2033 1.93$ 1.62$ 2.14$ 2.29$ 2.02$ 1.76$ 2.02$ 1.95$ 2.43$ 2.39$ 1.80$ 2.08$
High Growth & Low Prices Sumas 2033-2034 2.21$ 1.64$ 2.28$ 2.42$ 2.03$ 1.77$ 1.94$ 1.98$ 2.45$ 2.40$ 2.17$ 2.08$
High Growth & Low Prices Sumas 2034-2035 2.01$ 1.68$ 2.31$ 2.45$ 2.07$ 1.81$ 2.01$ 2.01$ 2.52$ 2.42$ 2.00$ 2.08$
2014$
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 176 of 648
APPENDIX 5.1: MONTHLY PRICE DATA BY BASIN
LOW GROWTH HIGH PRICE

Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
Low Growth_High Prices AECo 2015-2016 1.91$ 1.63$ 7.19$ 7.41$ 7.42$ 4.22$ 4.17$ 4.47$ 4.14$ 4.29$ 3.53$ 4.29$
Low Growth_High Prices AECo 2016-2017 3.78$ 5.33$ 6.93$ 7.25$ 7.01$ 4.25$ 4.22$ 4.48$ 4.13$ 4.28$ 3.48$ 4.26$
Low Growth_High Prices AECo 2017-2018 3.86$ 5.40$ 7.59$ 7.89$ 7.92$ 4.74$ 4.68$ 4.93$ 4.61$ 4.70$ 3.98$ 4.76$ Low Growth_High Prices AECo 2018-2019 4.43$ 5.96$ 7.50$ 7.81$ 7.58$ 4.54$ 4.56$ 4.90$ 4.59$ 4.68$ 3.99$ 4.79$
Low Growth_High Prices AECo 2019-2020 4.46$ 6.00$ 7.52$ 7.84$ 7.88$ 4.57$ 4.59$ 4.90$ 4.58$ 4.68$ 3.99$ 4.77$
Low Growth_High Prices AECo 2020-2021 4.51$ 6.07$ 7.56$ 7.94$ 7.26$ 4.65$ 4.68$ 4.98$ 4.56$ 4.65$ 4.12$ 4.91$
Low Growth_High Prices AECo 2021-2022 4.46$ 5.98$ 7.50$ 7.87$ 7.91$ 4.63$ 4.66$ 4.97$ 4.62$ 4.73$ 4.03$ 4.83$
Low Growth_High Prices AECo 2022-2023 4.38$ 5.85$ 7.31$ 7.67$ 6.32$ 4.59$ 4.65$ 4.97$ 4.62$ 4.71$ 4.15$ 4.96$ Low Growth_High Prices AECo 2023-2024 4.61$ 6.08$ 7.60$ 7.94$ 8.02$ 4.71$ 4.73$ 5.04$ 4.78$ 4.87$ 4.25$ 5.03$
Low Growth_High Prices AECo 2024-2025 4.69$ 6.13$ 7.66$ 7.97$ 8.03$ 4.69$ 4.78$ 5.09$ 4.79$ 4.88$ 4.27$ 5.05$
Low Growth_High Prices AECo 2025-2026 4.71$ 6.10$ 7.60$ 7.91$ 7.91$ 4.72$ 4.79$ 5.09$ 4.81$ 4.93$ 4.27$ 5.06$
Low Growth_High Prices AECo 2026-2027 4.77$ 6.01$ 7.53$ 7.83$ 7.32$ 4.76$ 4.81$ 5.15$ 4.87$ 4.97$ 4.44$ 5.23$
Low Growth_High Prices AECo 2027-2028 4.89$ 6.23$ 7.80$ 8.11$ 7.87$ 4.96$ 4.99$ 5.32$ 5.04$ 5.12$ 4.53$ 5.34$
Low Growth_High Prices AECo 2028-2029 4.95$ 6.35$ 7.90$ 8.21$ 7.78$ 5.03$ 5.10$ 5.41$ 5.09$ 5.18$ 4.59$ 5.40$
Low Growth_High Prices AECo 2029-2030 4.99$ 6.39$ 7.96$ 8.30$ 8.29$ 5.10$ 5.12$ 5.47$ 5.18$ 5.27$ 4.66$ 5.47$
Low Growth_High Prices AECo 2030-2031 5.04$ 6.50$ 8.07$ 8.41$ 8.37$ 5.24$ 5.26$ 5.58$ 5.25$ 5.34$ 4.75$ 5.56$
Low Growth_High Prices AECo 2031-2032 5.08$ 6.57$ 8.12$ 8.45$ 7.32$ 5.33$ 5.34$ 5.67$ 5.30$ 5.45$ 4.81$ 5.62$
Low Growth_High Prices AECo 2032-2033 5.14$ 6.67$ 8.21$ 8.55$ 7.50$ 5.40$ 5.40$ 5.73$ 5.43$ 5.55$ 4.88$ 5.67$
Low Growth_High Prices AECo 2033-2034 5.19$ 6.72$ 8.27$ 8.60$ 7.36$ 5.41$ 5.43$ 5.75$ 5.44$ 5.53$ 4.92$ 5.73$
Low Growth_High Prices AECo 2034-2035 5.23$ 6.78$ 8.36$ 8.67$ 8.22$ 5.60$ 5.58$ 5.78$ 5.44$ 5.61$ 4.98$ 5.76$
Low Growth_High Prices Malin 2015-2016 2.20$ 2.03$ 7.63$ 7.92$ 7.93$ 4.69$ 4.71$ 5.04$ 4.73$ 4.83$ 4.08$ 4.88$
Low Growth_High Prices Malin 2016-2017 4.46$ 5.98$ 7.48$ 7.78$ 7.54$ 4.76$ 4.74$ 5.08$ 4.76$ 4.83$ 4.11$ 4.93$
Low Growth_High Prices Malin 2017-2018 4.49$ 5.98$ 8.00$ 8.32$ 8.41$ 5.26$ 5.27$ 5.58$ 5.27$ 5.36$ 4.62$ 5.45$
Low Growth_High Prices Malin 2018-2019 4.99$ 6.52$ 8.07$ 8.38$ 8.27$ 5.30$ 5.31$ 5.63$ 5.28$ 5.39$ 4.67$ 5.47$
Low Growth_High Prices Malin 2019-2020 5.01$ 6.48$ 8.03$ 8.34$ 8.41$ 5.29$ 5.23$ 5.54$ 5.23$ 5.38$ 4.64$ 5.44$ Low Growth_High Prices Malin 2020-2021 5.01$ 6.51$ 8.07$ 8.39$ 7.74$ 5.32$ 5.32$ 5.59$ 5.30$ 5.41$ 4.66$ 5.48$
Low Growth_High Prices Malin 2021-2022 5.02$ 6.51$ 8.08$ 8.41$ 8.46$ 5.33$ 5.32$ 5.62$ 5.33$ 5.42$ 4.69$ 5.49$
Low Growth_High Prices Malin 2022-2023 5.04$ 6.51$ 8.09$ 8.43$ 7.04$ 5.33$ 5.33$ 5.65$ 5.31$ 5.45$ 4.70$ 5.50$
Low Growth_High Prices Malin 2023-2024 5.07$ 6.55$ 8.09$ 8.40$ 8.47$ 5.34$ 5.33$ 5.63$ 5.30$ 5.45$ 4.71$ 5.52$
Low Growth_High Prices Malin 2024-2025 5.06$ 6.53$ 8.09$ 8.40$ 8.47$ 5.35$ 5.33$ 5.63$ 5.31$ 5.43$ 4.69$ 5.51$
Low Growth_High Prices Malin 2025-2026 5.06$ 6.55$ 8.08$ 8.42$ 8.48$ 5.35$ 5.32$ 5.63$ 5.31$ 5.44$ 4.71$ 5.51$
Low Growth_High Prices Malin 2026-2027 5.07$ 6.56$ 8.13$ 8.45$ 7.92$ 5.38$ 5.36$ 5.67$ 5.34$ 5.46$ 4.72$ 5.57$
Low Growth_High Prices Malin 2027-2028 5.14$ 6.62$ 8.18$ 8.50$ 8.32$ 5.43$ 5.40$ 5.71$ 5.38$ 5.50$ 4.77$ 5.61$
Low Growth_High Prices Malin 2028-2029 5.18$ 6.66$ 8.26$ 8.57$ 8.19$ 5.48$ 5.46$ 5.76$ 5.42$ 5.55$ 4.83$ 5.66$
Low Growth_High Prices Malin 2029-2030 5.24$ 6.74$ 8.30$ 8.62$ 8.72$ 5.53$ 5.52$ 5.83$ 5.48$ 5.62$ 4.93$ 5.74$
Low Growth_High Prices Malin 2030-2031 5.31$ 6.78$ 8.36$ 8.69$ 8.78$ 5.60$ 5.57$ 5.88$ 5.53$ 5.66$ 4.97$ 5.80$
Low Growth_High Prices Malin 2031-2032 5.37$ 6.83$ 8.41$ 8.74$ 7.63$ 5.68$ 5.61$ 5.91$ 5.57$ 5.74$ 5.05$ 5.88$
Low Growth_High Prices Malin 2032-2033 5.46$ 6.91$ 8.49$ 8.82$ 7.89$ 5.78$ 5.70$ 6.00$ 5.72$ 5.85$ 5.13$ 5.94$
Low Growth_High Prices Malin 2033-2034 5.51$ 7.04$ 8.62$ 8.94$ 7.79$ 5.82$ 5.80$ 6.11$ 5.77$ 5.90$ 5.19$ 6.00$
Low Growth_High Prices Malin 2034-2035 5.58$ 7.12$ 8.69$ 9.02$ 8.48$ 5.88$ 5.88$ 6.18$ 5.86$ 5.98$ 5.25$ 6.07$
Low Growth_High Prices Rockies 2015-2016 2.01$ 1.81$ 7.46$ 7.78$ 7.82$ 4.64$ 4.63$ 4.96$ 4.63$ 4.77$ 4.03$ 4.86$
Low Growth_High Prices Rockies 2016-2017 4.38$ 5.89$ 7.41$ 7.74$ 7.46$ 4.67$ 4.69$ 5.02$ 4.68$ 4.78$ 4.06$ 4.86$
Low Growth_High Prices Rockies 2017-2018 4.39$ 5.90$ 7.95$ 8.28$ 8.36$ 5.22$ 5.21$ 5.53$ 5.18$ 5.29$ 4.58$ 5.37$
Low Growth_High Prices Rockies 2018-2019 4.92$ 6.44$ 7.99$ 8.31$ 8.20$ 5.26$ 5.26$ 5.57$ 5.22$ 5.33$ 4.58$ 5.38$
Low Growth_High Prices Rockies 2019-2020 4.93$ 6.40$ 7.94$ 8.27$ 8.36$ 5.23$ 5.20$ 5.51$ 5.18$ 5.32$ 4.59$ 5.37$
Low Growth_High Prices Rockies 2020-2021 4.93$ 6.44$ 8.00$ 8.32$ 7.69$ 5.27$ 5.28$ 5.59$ 5.25$ 5.36$ 4.61$ 5.41$
Low Growth_High Prices Rockies 2021-2022 4.94$ 6.46$ 8.01$ 8.33$ 8.41$ 5.29$ 5.29$ 5.61$ 5.27$ 5.37$ 4.63$ 5.42$ Low Growth_High Prices Rockies 2022-2023 4.95$ 6.47$ 8.00$ 8.34$ 6.97$ 5.28$ 5.28$ 5.58$ 5.24$ 5.40$ 4.66$ 5.44$
Low Growth_High Prices Rockies 2023-2024 4.99$ 6.49$ 7.99$ 8.31$ 8.42$ 5.30$ 5.29$ 5.59$ 5.25$ 5.42$ 4.68$ 5.48$
Low Growth_High Prices Rockies 2024-2025 5.00$ 6.50$ 8.04$ 8.35$ 8.44$ 5.32$ 5.29$ 5.60$ 5.27$ 5.39$ 4.65$ 5.45$
Low Growth_High Prices Rockies 2025-2026 4.98$ 6.50$ 8.03$ 8.35$ 8.44$ 5.31$ 5.28$ 5.60$ 5.26$ 5.40$ 4.65$ 5.46$
Low Growth_High Prices Rockies 2026-2027 4.99$ 6.49$ 8.06$ 8.38$ 7.87$ 5.34$ 5.32$ 5.63$ 5.30$ 5.41$ 4.67$ 5.48$
Low Growth_High Prices Rockies 2027-2028 5.03$ 6.54$ 8.09$ 8.42$ 8.25$ 5.38$ 5.35$ 5.65$ 5.32$ 5.45$ 4.71$ 5.52$
Low Growth_High Prices Rockies 2028-2029 5.07$ 6.58$ 8.18$ 8.49$ 8.11$ 5.43$ 5.40$ 5.72$ 5.35$ 5.48$ 4.76$ 5.57$
Low Growth_High Prices Rockies 2029-2030 5.17$ 6.65$ 8.22$ 8.54$ 8.63$ 5.49$ 5.48$ 5.78$ 5.42$ 5.57$ 4.85$ 5.68$
Low Growth_High Prices Rockies 2030-2031 5.24$ 6.71$ 8.28$ 8.61$ 8.71$ 5.56$ 5.52$ 5.83$ 5.48$ 5.60$ 4.90$ 5.73$
Low Growth_High Prices Rockies 2031-2032 5.30$ 6.75$ 8.33$ 8.66$ 7.56$ 5.64$ 5.56$ 5.86$ 5.51$ 5.66$ 4.97$ 5.80$
Low Growth_High Prices Rockies 2032-2033 5.36$ 6.84$ 8.42$ 8.74$ 7.81$ 5.71$ 5.64$ 5.95$ 5.58$ 5.76$ 5.06$ 5.87$
Low Growth_High Prices Rockies 2033-2034 5.42$ 6.90$ 8.48$ 8.80$ 7.71$ 5.77$ 5.73$ 6.02$ 5.65$ 5.82$ 5.13$ 5.93$
Low Growth_High Prices Rockies 2034-2035 5.47$ 6.96$ 8.54$ 8.87$ 8.40$ 5.83$ 5.82$ 6.09$ 5.75$ 5.89$ 5.20$ 5.98$
2014$
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 177 of 648
APPENDIX 5.1: MONTHLY PRICE DATA BY BASIN
LOW GROWTH HIGH PRICE

Low Growth_High Prices Stanfield 2015-2016 2.17$ 1.98$ 7.56$ 7.84$ 7.84$ 4.63$ 4.64$ 4.97$ 4.63$ 4.77$ 4.01$ 4.80$
Low Growth_High Prices Stanfield 2016-2017 4.39$ 5.90$ 7.45$ 7.77$ 7.49$ 4.70$ 4.69$ 5.03$ 4.68$ 4.77$ 4.05$ 4.87$
Low Growth_High Prices Stanfield 2017-2018 4.42$ 5.92$ 7.97$ 8.29$ 8.37$ 5.25$ 5.21$ 5.53$ 5.18$ 5.29$ 4.58$ 5.37$
Low Growth_High Prices Stanfield 2018-2019 4.92$ 6.43$ 7.98$ 8.29$ 8.19$ 5.23$ 5.23$ 5.54$ 5.20$ 5.31$ 4.58$ 5.38$
Low Growth_High Prices Stanfield 2019-2020 4.92$ 6.39$ 7.93$ 8.24$ 8.32$ 5.22$ 5.16$ 5.46$ 5.16$ 5.30$ 4.57$ 5.36$
Low Growth_High Prices Stanfield 2020-2021 4.92$ 6.41$ 7.97$ 8.28$ 7.65$ 5.25$ 5.25$ 5.52$ 5.22$ 5.33$ 4.57$ 5.38$
Low Growth_High Prices Stanfield 2021-2022 4.93$ 6.41$ 7.98$ 8.30$ 8.38$ 5.27$ 5.25$ 5.55$ 5.25$ 5.34$ 4.58$ 5.39$
Low Growth_High Prices Stanfield 2022-2023 4.94$ 6.42$ 7.99$ 8.32$ 6.95$ 5.27$ 5.26$ 5.56$ 5.24$ 5.37$ 4.62$ 5.41$ Low Growth_High Prices Stanfield 2023-2024 4.98$ 6.46$ 8.04$ 8.29$ 8.40$ 5.29$ 5.27$ 5.56$ 5.22$ 5.38$ 4.64$ 5.46$
Low Growth_High Prices Stanfield 2024-2025 5.00$ 6.47$ 8.02$ 8.34$ 8.42$ 5.31$ 5.28$ 5.58$ 5.24$ 5.38$ 4.62$ 5.44$
Low Growth_High Prices Stanfield 2025-2026 5.01$ 6.49$ 8.01$ 8.35$ 8.43$ 5.30$ 5.26$ 5.57$ 5.25$ 5.39$ 4.66$ 5.46$
Low Growth_High Prices Stanfield 2026-2027 5.02$ 6.50$ 8.07$ 8.38$ 7.87$ 5.35$ 5.33$ 5.64$ 5.30$ 5.42$ 4.68$ 5.51$
Low Growth_High Prices Stanfield 2027-2028 5.10$ 6.57$ 8.11$ 8.44$ 8.26$ 5.39$ 5.37$ 5.66$ 5.33$ 5.45$ 4.71$ 5.54$ Low Growth_High Prices Stanfield 2028-2029 5.12$ 6.59$ 8.17$ 8.51$ 8.13$ 5.44$ 5.42$ 5.73$ 5.35$ 5.49$ 4.75$ 5.59$
Low Growth_High Prices Stanfield 2029-2030 5.18$ 6.67$ 8.23$ 8.56$ 8.65$ 5.49$ 5.49$ 5.79$ 5.44$ 5.56$ 4.88$ 5.66$
Low Growth_High Prices Stanfield 2030-2031 5.23$ 6.72$ 8.29$ 8.62$ 8.74$ 5.56$ 5.53$ 5.84$ 5.49$ 5.61$ 4.92$ 5.72$
Low Growth_High Prices Stanfield 2031-2032 5.31$ 6.77$ 8.33$ 8.67$ 7.57$ 5.64$ 5.55$ 5.88$ 5.53$ 5.69$ 5.00$ 5.82$
Low Growth_High Prices Stanfield 2032-2033 5.39$ 6.85$ 8.41$ 8.75$ 7.82$ 5.74$ 5.66$ 5.97$ 5.67$ 5.80$ 5.06$ 5.88$
Low Growth_High Prices Stanfield 2033-2034 5.45$ 6.97$ 8.54$ 8.87$ 7.72$ 5.77$ 5.76$ 6.07$ 5.72$ 5.85$ 5.11$ 5.94$
Low Growth_High Prices Stanfield 2034-2035 5.51$ 7.05$ 8.61$ 8.94$ 8.42$ 5.81$ 5.84$ 6.12$ 5.79$ 5.89$ 5.17$ 6.00$
Low Growth_High Prices Sumas 2015-2016 2.16$ 1.93$ 7.53$ 7.76$ 7.69$ 4.43$ 4.31$ 4.63$ 4.26$ 4.45$ 3.84$ 4.66$
Low Growth_High Prices Sumas 2016-2017 4.25$ 5.93$ 7.41$ 7.70$ 7.43$ 4.62$ 4.59$ 4.84$ 4.51$ 4.64$ 3.93$ 4.69$
Low Growth_High Prices Sumas 2017-2018 4.35$ 5.93$ 7.93$ 8.24$ 8.32$ 5.15$ 4.92$ 5.23$ 4.89$ 5.06$ 4.34$ 5.26$
Low Growth_High Prices Sumas 2018-2019 4.81$ 6.37$ 7.94$ 8.26$ 8.10$ 5.06$ 4.99$ 5.24$ 4.94$ 5.11$ 4.41$ 5.26$
Low Growth_High Prices Sumas 2019-2020 4.81$ 6.33$ 7.85$ 8.18$ 8.26$ 5.07$ 4.97$ 5.20$ 4.97$ 5.13$ 4.45$ 5.28$ Low Growth_High Prices Sumas 2020-2021 4.83$ 6.34$ 7.92$ 8.27$ 7.62$ 5.14$ 5.08$ 5.30$ 5.05$ 5.18$ 4.50$ 5.30$
Low Growth_High Prices Sumas 2021-2022 4.81$ 6.27$ 7.85$ 8.17$ 8.33$ 5.17$ 5.08$ 5.38$ 5.06$ 5.21$ 4.53$ 5.32$
Low Growth_High Prices Sumas 2022-2023 4.84$ 6.27$ 7.84$ 8.22$ 6.91$ 5.19$ 5.09$ 5.41$ 5.08$ 5.26$ 4.55$ 5.33$
Low Growth_High Prices Sumas 2023-2024 4.88$ 6.41$ 7.92$ 8.22$ 8.34$ 5.17$ 5.06$ 5.38$ 5.04$ 5.25$ 4.56$ 5.36$
Low Growth_High Prices Sumas 2024-2025 4.88$ 6.29$ 7.92$ 8.27$ 8.36$ 5.18$ 5.07$ 5.35$ 5.04$ 5.23$ 4.53$ 5.33$
Low Growth_High Prices Sumas 2025-2026 4.83$ 6.30$ 7.84$ 8.18$ 8.33$ 5.17$ 5.05$ 5.33$ 5.05$ 5.24$ 4.51$ 5.31$
Low Growth_High Prices Sumas 2026-2027 4.85$ 6.32$ 7.89$ 8.21$ 7.77$ 5.20$ 5.16$ 5.43$ 5.13$ 5.26$ 4.57$ 5.46$
Low Growth_High Prices Sumas 2027-2028 4.99$ 6.54$ 8.12$ 8.44$ 8.20$ 5.32$ 5.21$ 5.53$ 5.20$ 5.40$ 4.69$ 5.51$
Low Growth_High Prices Sumas 2028-2029 5.13$ 6.60$ 8.20$ 8.52$ 8.13$ 5.39$ 5.28$ 5.60$ 5.25$ 5.45$ 4.73$ 5.57$
Low Growth_High Prices Sumas 2029-2030 5.19$ 6.68$ 8.24$ 8.56$ 8.66$ 5.44$ 5.39$ 5.71$ 5.33$ 5.52$ 4.88$ 5.69$
Low Growth_High Prices Sumas 2030-2031 5.27$ 6.73$ 8.30$ 8.63$ 8.73$ 5.51$ 5.45$ 5.76$ 5.38$ 5.57$ 4.92$ 5.75$
Low Growth_High Prices Sumas 2031-2032 5.32$ 6.78$ 8.36$ 8.69$ 7.58$ 5.59$ 5.51$ 5.82$ 5.42$ 5.65$ 4.99$ 5.82$
Low Growth_High Prices Sumas 2032-2033 5.39$ 6.86$ 8.43$ 8.76$ 7.83$ 5.69$ 5.57$ 5.87$ 5.52$ 5.74$ 5.05$ 5.90$
Low Growth_High Prices Sumas 2033-2034 5.50$ 7.03$ 8.63$ 8.94$ 7.75$ 5.74$ 5.66$ 5.95$ 5.59$ 5.80$ 5.13$ 5.96$
Low Growth_High Prices Sumas 2034-2035 5.57$ 7.13$ 8.71$ 9.03$ 8.46$ 5.84$ 5.79$ 6.04$ 5.72$ 5.89$ 5.20$ 6.02$
2014$
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 178 of 648
APPENDIX 5.2: WEIGHTED AVERAGE COST OF CAPITAL

From 2015 Rate Case Settlement
Cost of Capital Percent of
Total Capital Cost Component After Tax
L/T Debt 51.50% 5.20% 2.68% 1.74%

Common Equity 48.50% 9.50% 4.61% 4.61%

TOTAL 100.00%7.29% 6.35%
Agreed-upon
Cost of Capital Percent of
Total Capital Cost Component
L/T Debt 50.00% 5.34% 2.67% 1.74%

Common Equity 50.00% 9.50% 4.75% 4.75%
TOTAL 100.00%7.42% 6.49%
Agreed-upon
Cost of Capital Percent of
Total Capital Cost Component
L/T Debt 50.00% 5.52% 2.76% 1.79%
Common Equity 50.00% 9.40% 4.70% 4.70%
TOTAL 100.00%7.46% 6.49%
2015 Year End Gas Net Rate Base AMA
WA 269,072$ 46%
ID 126,932$ 22%
OR 189,415$ 32%
585,419$
System Weighted Average Cost of Capital (Nominal)*6.42%
GDP price deflator 2.00%
Real After Tax WACC 4.34%
WASHINGTON
IDAHO
Avista Corporation Captial Structure and Overall Rate of Return
OREGON
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 179 of 648
APPENDIX 5.3: POTENTIAL SUPPLY SIDE RESOURCE OPTIONS

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 180 of 648
APPENDIX 5.4: EXPECTED CASE AVOIDED COST

Scenario Gas Year Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual
Expected Case 2015-2016 1.88$ 2.17$ 1.88$ 1.88$ 1.88$ 1.88$ 1.84$ 2.16$ 1.96$ 1.94$ Expected Case 2016-2017 2.27$ 2.97$ 2.27$ 2.27$ 2.27$ 2.31$ 2.20$ 2.95$ 2.49$ 2.41$ Expected Case 2017-2018 2.79$ 3.45$ 2.79$ 2.79$ 2.79$ 2.79$ 2.72$ 3.44$ 2.99$ 2.92$
Expected Case 2018-2019 2.80$ 3.54$ 2.80$ 2.80$ 2.80$ 2.83$ 2.74$ 3.52$ 3.03$ 2.95$
Expected Case 2019-2020 2.88$ 3.62$ 2.88$ 2.88$ 2.88$ 2.93$ 2.83$ 3.61$ 3.12$ 3.03$
Expected Case 2020-2021 3.04$ 3.77$ 3.04$ 3.04$ 3.04$ 3.09$ 2.97$ 3.76$ 3.27$ 3.18$
Expected Case 2021-2022 3.15$ 3.90$ 3.15$ 3.15$ 3.15$ 3.16$ 3.05$ 3.87$ 3.36$ 3.30$ Expected Case 2022-2023 3.15$ 3.91$ 3.15$ 3.15$ 3.15$ 3.13$ 3.01$ 3.88$ 3.34$ 3.30$ Expected Case 2023-2024 3.35$ 3.97$ 3.35$ 3.35$ 3.35$ 3.38$ 3.27$ 3.95$ 3.53$ 3.48$
Expected Case 2024-2025 3.61$ 4.14$ 3.61$ 3.61$ 3.61$ 3.61$ 3.53$ 4.12$ 3.75$ 3.71$
Expected Case 2025-2026 3.59$ 4.10$ 3.59$ 3.59$ 3.59$ 3.58$ 3.53$ 4.06$ 3.72$ 3.69$
Expected Case 2026-2027 3.66$ 4.17$ 3.66$ 3.66$ 3.66$ 3.66$ 3.59$ 4.11$ 3.79$ 3.76$
Expected Case 2027-2028 3.97$ 4.38$ 3.97$ 3.97$ 3.97$ 3.95$ 3.91$ 4.34$ 4.06$ 4.05$ Expected Case 2028-2029 4.17$ 4.54$ 4.17$ 4.17$ 4.17$ 4.13$ 4.11$ 4.50$ 4.25$ 4.24$ Expected Case 2029-2030 4.33$ 4.73$ 4.33$ 4.33$ 4.33$ 4.30$ 4.26$ 4.70$ 4.42$ 4.41$
Expected Case 2030-2031 4.54$ 4.87$ 4.54$ 4.54$ 4.54$ 4.50$ 4.46$ 4.84$ 4.60$ 4.60$
Expected Case 2031-2032 4.68$ 4.97$ 4.68$ 4.68$ 4.68$ 4.64$ 4.61$ 4.94$ 4.73$ 4.73$
Expected Case 2032-2033 4.73$ 5.03$ 4.73$ 4.73$ 4.73$ 4.69$ 4.65$ 5.01$ 4.78$ 4.79$
Expected Case 2033-2034 4.78$ 5.15$ 4.78$ 4.78$ 4.78$ 4.75$ 4.70$ 5.13$ 4.86$ 4.86$ Expected Case 2034-2035 4.82$ 5.05$ 4.82$ 4.82$ 4.82$ 4.79$ 4.74$ 5.01$ 4.85$ 4.87$
Scenario Gas Year Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Winter OR Winter
Expected Case 2015-2016 1.87$ 2.09$ 1.87$ 1.87$ 1.87$ 2.00$ 1.79$ 2.09$ 1.96$ 1.91$
Expected Case 2016-2017 2.31$ 2.97$ 2.31$ 2.31$ 2.31$ 2.42$ 2.14$ 2.94$ 2.50$ 2.44$
Expected Case 2017-2018 2.70$ 3.41$ 2.70$ 2.70$ 2.70$ 2.77$ 2.48$ 3.40$ 2.88$ 2.85$
Expected Case 2018-2019 3.15$ 3.55$ 3.15$ 3.15$ 3.15$ 3.26$ 3.01$ 3.51$ 3.26$ 3.23$ Expected Case 2019-2020 3.22$ 3.64$ 3.22$ 3.22$ 3.22$ 3.36$ 3.09$ 3.60$ 3.35$ 3.30$ Expected Case 2020-2021 3.33$ 3.78$ 3.33$ 3.33$ 3.33$ 3.49$ 3.19$ 3.75$ 3.48$ 3.42$
Expected Case 2021-2022 3.60$ 3.91$ 3.60$ 3.60$ 3.60$ 3.63$ 3.33$ 3.85$ 3.61$ 3.66$
Expected Case 2022-2023 3.58$ 3.93$ 3.58$ 3.58$ 3.58$ 3.54$ 3.22$ 3.86$ 3.54$ 3.65$
Expected Case 2023-2024 3.76$ 4.01$ 3.76$ 3.76$ 3.76$ 3.81$ 3.51$ 3.97$ 3.76$ 3.81$
Expected Case 2024-2025 3.98$ 4.18$ 3.98$ 3.98$ 3.98$ 4.01$ 3.79$ 4.12$ 3.97$ 4.02$ Expected Case 2025-2026 4.19$ 4.24$ 4.19$ 4.19$ 4.19$ 4.10$ 4.07$ 4.14$ 4.10$ 4.20$ Expected Case 2026-2027 4.18$ 4.30$ 4.18$ 4.18$ 4.18$ 4.11$ 4.04$ 4.13$ 4.09$ 4.20$
Expected Case 2027-2028 4.41$ 4.48$ 4.41$ 4.41$ 4.41$ 4.36$ 4.30$ 4.38$ 4.34$ 4.43$
Expected Case 2028-2029 4.60$ 4.67$ 4.60$ 4.60$ 4.60$ 4.54$ 4.50$ 4.58$ 4.54$ 4.61$
Expected Case 2029-2030 4.72$ 4.84$ 4.72$ 4.72$ 4.72$ 4.70$ 4.61$ 4.76$ 4.69$ 4.75$
Expected Case 2030-2031 5.02$ 5.09$ 5.02$ 5.02$ 5.02$ 4.94$ 4.91$ 4.99$ 4.95$ 5.03$ Expected Case 2031-2032 5.09$ 5.20$ 5.09$ 5.09$ 5.09$ 5.07$ 5.00$ 5.13$ 5.06$ 5.12$ Expected Case 2032-2033 5.23$ 5.33$ 5.23$ 5.23$ 5.23$ 5.18$ 5.13$ 5.24$ 5.19$ 5.25$
Expected Case 2033-2034 5.33$ 5.48$ 5.33$ 5.33$ 5.33$ 5.28$ 5.22$ 5.35$ 5.28$ 5.36$
Expected Case 2034-2035 5.32$ 5.46$ 5.32$ 5.32$ 5.32$ 5.25$ 5.19$ 5.32$ 5.25$ 5.35$
1/ Avoided costs are before Environmental Externalities adder.
Annual Avoided Costs 1/
2014$
Winter Avoided Costs 1/
2014$
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 181 of 648
APPENDIX 5.4: LOW GROWTH CASE AVOIDED COST

Scenario Gas Year Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual
Low Growth & High Prices 2015-2016 4.68$ 5.03$ 4.68$ 4.68$ 4.68$ 4.63$ 4.61$ 4.98$ 4.74$ 4.75$ Low Growth & High Prices 2016-2017 5.09$ 5.72$ 5.08$ 5.08$ 5.08$ 4.99$ 5.00$ 5.70$ 5.23$ 5.21$ Low Growth & High Prices 2017-2018 5.57$ 6.20$ 5.57$ 5.57$ 5.57$ 5.46$ 5.48$ 6.16$ 5.70$ 5.69$
Low Growth & High Prices 2018-2019 5.59$ 6.27$ 5.58$ 5.58$ 5.58$ 5.49$ 5.50$ 6.24$ 5.75$ 5.72$
Low Growth & High Prices 2019-2020 5.63$ 6.27$ 5.63$ 5.63$ 5.63$ 5.52$ 5.55$ 6.23$ 5.77$ 5.76$
Low Growth & High Prices 2020-2021 5.63$ 6.26$ 5.62$ 5.62$ 5.62$ 5.53$ 5.55$ 6.25$ 5.78$ 5.75$
Low Growth & High Prices 2021-2022 5.66$ 6.35$ 5.66$ 5.66$ 5.66$ 5.55$ 5.58$ 6.31$ 5.81$ 5.80$ Low Growth & High Prices 2022-2023 5.50$ 6.22$ 5.49$ 5.49$ 5.49$ 5.33$ 5.41$ 6.15$ 5.63$ 5.64$ Low Growth & High Prices 2023-2024 5.79$ 6.34$ 5.79$ 5.79$ 5.79$ 5.68$ 5.71$ 6.31$ 5.90$ 5.90$
Low Growth & High Prices 2024-2025 5.82$ 6.29$ 5.82$ 5.82$ 5.82$ 5.71$ 5.73$ 6.27$ 5.90$ 5.91$
Low Growth & High Prices 2025-2026 5.81$ 6.25$ 5.81$ 5.81$ 5.81$ 5.70$ 5.72$ 6.23$ 5.88$ 5.89$
Low Growth & High Prices 2026-2027 5.79$ 6.20$ 5.78$ 5.78$ 5.78$ 5.69$ 5.70$ 6.21$ 5.87$ 5.87$
Low Growth & High Prices 2027-2028 6.01$ 6.34$ 6.00$ 6.00$ 6.00$ 5.91$ 5.92$ 6.35$ 6.06$ 6.07$ Low Growth & High Prices 2028-2029 6.07$ 6.37$ 6.06$ 6.06$ 6.06$ 5.97$ 5.98$ 6.38$ 6.11$ 6.12$ Low Growth & High Prices 2029-2030 6.18$ 6.48$ 6.17$ 6.17$ 6.17$ 6.06$ 6.09$ 6.47$ 6.21$ 6.23$
Low Growth & High Prices 2030-2031 6.27$ 6.53$ 6.27$ 6.27$ 6.27$ 6.16$ 6.18$ 6.53$ 6.29$ 6.32$
Low Growth & High Prices 2031-2032 6.25$ 6.48$ 6.24$ 6.24$ 6.24$ 6.15$ 6.16$ 6.48$ 6.26$ 6.29$
Low Growth & High Prices 2032-2033 6.33$ 6.56$ 6.32$ 6.32$ 6.32$ 6.12$ 6.25$ 6.45$ 6.27$ 6.37$
Low Growth & High Prices 2033-2034 6.35$ 6.64$ 6.35$ 6.35$ 6.35$ 6.12$ 6.26$ 6.51$ 6.30$ 6.41$ Low Growth & High Prices 2034-2035 6.50$ 6.65$ 6.49$ 6.49$ 6.49$ 6.37$ 6.40$ 6.59$ 6.46$ 6.52$
Scenario Gas Year Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Winter OR Winter
Low Growth & High Prices 2015-2016 1.88$ 2.14$ 1.88$ 1.88$ 1.88$ 2.02$ 1.79$ 2.14$ 1.98$ 1.93$
Low Growth & High Prices 2016-2017 4.78$ 5.71$ 4.79$ 4.79$ 4.79$ 4.69$ 4.63$ 5.71$ 5.01$ 4.97$
Low Growth & High Prices 2017-2018 4.85$ 5.74$ 4.85$ 4.85$ 4.85$ 4.75$ 4.70$ 5.74$ 5.06$ 5.03$
Low Growth & High Prices 2018-2019 5.42$ 6.12$ 5.42$ 5.42$ 5.42$ 5.32$ 5.27$ 6.11$ 5.57$ 5.56$ Low Growth & High Prices 2019-2020 5.44$ 6.04$ 5.44$ 5.44$ 5.44$ 5.36$ 5.31$ 6.04$ 5.57$ 5.56$ Low Growth & High Prices 2020-2021 5.50$ 6.02$ 5.50$ 5.50$ 5.50$ 5.42$ 5.37$ 6.02$ 5.60$ 5.60$
Low Growth & High Prices 2021-2022 5.44$ 6.01$ 5.44$ 5.44$ 5.44$ 5.35$ 5.30$ 6.00$ 5.55$ 5.55$
Low Growth & High Prices 2022-2023 5.35$ 6.15$ 5.35$ 5.35$ 5.35$ 5.24$ 5.19$ 6.12$ 5.52$ 5.51$
Low Growth & High Prices 2023-2024 5.56$ 6.08$ 5.56$ 5.56$ 5.56$ 5.47$ 5.42$ 6.08$ 5.66$ 5.66$
Low Growth & High Prices 2024-2025 5.61$ 5.91$ 5.61$ 5.61$ 5.61$ 5.54$ 5.49$ 5.90$ 5.64$ 5.67$ Low Growth & High Prices 2025-2026 5.62$ 5.88$ 5.62$ 5.62$ 5.62$ 5.54$ 5.49$ 5.87$ 5.63$ 5.67$ Low Growth & High Prices 2026-2027 5.61$ 5.93$ 5.61$ 5.61$ 5.61$ 5.52$ 5.47$ 5.93$ 5.64$ 5.68$
Low Growth & High Prices 2027-2028 5.77$ 6.09$ 5.77$ 5.77$ 5.77$ 5.69$ 5.64$ 6.09$ 5.81$ 5.83$
Low Growth & High Prices 2028-2029 5.85$ 6.14$ 5.85$ 5.85$ 5.85$ 5.78$ 5.73$ 6.14$ 5.88$ 5.90$
Low Growth & High Prices 2029-2030 5.90$ 6.26$ 5.90$ 5.90$ 5.90$ 5.82$ 5.77$ 6.26$ 5.95$ 5.97$
Low Growth & High Prices 2030-2031 5.97$ 6.31$ 5.97$ 5.97$ 5.97$ 5.90$ 5.85$ 6.31$ 6.02$ 6.03$ Low Growth & High Prices 2031-2032 6.02$ 6.35$ 6.02$ 6.02$ 6.02$ 5.96$ 5.91$ 6.35$ 6.07$ 6.09$ Low Growth & High Prices 2032-2033 6.10$ 6.42$ 6.10$ 6.10$ 6.10$ 6.04$ 5.99$ 6.42$ 6.15$ 6.16$
Low Growth & High Prices 2033-2034 6.16$ 6.50$ 6.16$ 6.16$ 6.16$ 6.09$ 6.04$ 6.50$ 6.21$ 6.23$
Low Growth & High Prices 2034-2035 6.22$ 6.56$ 6.22$ 6.22$ 6.22$ 6.14$ 6.09$ 6.56$ 6.26$ 6.28$
1/ Avoided costs are before Environmental Externalities adder.
Annual Avoided Costs 1/
2014$
Winter Avoided Costs 1/
2014$
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 182 of 648
APPENDIX 5.4: HIGH GROWTH CASE AVOIDED COST

Scenario Gas Year Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual
High Growth & Low Prices 2015-2016 1.69$ 2.02$ 1.69$ 1.69$ 1.69$ 1.70$ 1.65$ 2.01$ 1.79$ 1.75$ High Growth & Low Prices 2016-2017 1.57$ 2.13$ 1.57$ 1.57$ 1.57$ 1.60$ 1.49$ 2.12$ 1.74$ 1.68$ High Growth & Low Prices 2017-2018 1.57$ 2.14$ 1.57$ 1.57$ 1.57$ 1.59$ 1.50$ 2.13$ 1.74$ 1.69$
High Growth & Low Prices 2018-2019 1.53$ 2.15$ 1.53$ 1.53$ 1.53$ 1.55$ 1.42$ 2.13$ 1.70$ 1.65$
High Growth & Low Prices 2019-2020 1.55$ 2.14$ 1.55$ 1.55$ 1.55$ 1.57$ 1.44$ 2.12$ 1.71$ 1.67$
High Growth & Low Prices 2020-2021 1.59$ 2.15$ 1.59$ 1.59$ 1.59$ 1.60$ 1.48$ 2.12$ 1.73$ 1.70$
High Growth & Low Prices 2021-2022 1.59$ 2.23$ 1.59$ 1.59$ 1.59$ 1.59$ 1.46$ 2.20$ 1.75$ 1.72$ High Growth & Low Prices 2022-2023 1.58$ 2.26$ 1.58$ 1.58$ 1.58$ 1.54$ 1.40$ 2.22$ 1.72$ 1.72$ High Growth & Low Prices 2023-2024 1.68$ 2.20$ 1.68$ 1.68$ 1.68$ 1.69$ 1.55$ 2.17$ 1.80$ 1.78$
High Growth & Low Prices 2024-2025 1.68$ 2.13$ 1.68$ 1.68$ 1.68$ 1.71$ 1.58$ 2.10$ 1.80$ 1.77$
High Growth & Low Prices 2025-2026 1.64$ 2.08$ 1.64$ 1.64$ 1.64$ 1.67$ 1.54$ 2.04$ 1.75$ 1.73$
High Growth & Low Prices 2026-2027 1.67$ 2.11$ 1.67$ 1.67$ 1.67$ 1.68$ 1.54$ 2.05$ 1.75$ 1.76$
High Growth & Low Prices 2027-2028 1.77$ 2.09$ 7.23$ 7.23$ 7.23$ 1.78$ 1.67$ 2.09$ 1.84$ 5.11$ High Growth & Low Prices 2028-2029 1.83$ 2.12$ 7.30$ 7.30$ 7.30$ 1.84$ 1.73$ 2.10$ 1.89$ 5.17$ High Growth & Low Prices 2029-2030 1.87$ 2.19$ 7.35$ 7.35$ 7.35$ 1.88$ 1.77$ 2.18$ 1.94$ 5.22$
High Growth & Low Prices 2030-2031 1.91$ 7.66$ 12.86$ 12.86$ 12.86$ 1.92$ 1.81$ 2.18$ 1.97$ 9.63$
High Growth & Low Prices 2031-2032 1.94$ 7.64$ 12.86$ 12.86$ 12.86$ 7.41$ 1.84$ 7.63$ 5.63$ 9.63$
High Growth & Low Prices 2032-2033 1.95$ 7.67$ 12.89$ 12.89$ 12.89$ 7.43$ 1.85$ 7.67$ 5.65$ 9.66$
High Growth & Low Prices 2033-2034 1.97$ 7.72$ 12.92$ 12.92$ 12.92$ 7.44$ 1.86$ 7.71$ 5.67$ 9.69$ High Growth & Low Prices 2034-2035 7.45$ 7.67$ 12.92$ 12.92$ 12.92$ 7.44$ 1.85$ 7.66$ 5.65$ 10.77$
Scenario Gas Year Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Winter OR Winter
High Growth & Low Prices 2015-2016 1.87$ 1.98$ 1.87$ 1.87$ 1.87$ 1.96$ 1.79$ 1.98$ 1.91$ 1.89$
High Growth & Low Prices 2016-2017 1.31$ 2.07$ 1.31$ 1.31$ 1.31$ 1.38$ 1.06$ 2.07$ 1.50$ 1.46$
High Growth & Low Prices 2017-2018 1.45$ 2.06$ 1.45$ 1.45$ 1.45$ 1.48$ 1.17$ 2.06$ 1.57$ 1.58$
High Growth & Low Prices 2018-2019 1.51$ 2.04$ 1.51$ 1.51$ 1.51$ 1.56$ 1.21$ 2.04$ 1.60$ 1.62$ High Growth & Low Prices 2019-2020 1.52$ 1.91$ 1.52$ 1.52$ 1.52$ 1.53$ 1.18$ 1.91$ 1.54$ 1.60$ High Growth & Low Prices 2020-2021 1.54$ 1.91$ 1.55$ 1.55$ 1.55$ 1.57$ 1.22$ 1.88$ 1.56$ 1.62$
High Growth & Low Prices 2021-2022 1.56$ 1.96$ 1.56$ 1.56$ 1.56$ 1.57$ 1.21$ 1.92$ 1.57$ 1.64$
High Growth & Low Prices 2022-2023 1.55$ 2.06$ 1.55$ 1.55$ 1.55$ 1.45$ 1.06$ 2.02$ 1.51$ 1.66$
High Growth & Low Prices 2023-2024 1.70$ 2.03$ 1.71$ 1.71$ 1.71$ 1.70$ 1.32$ 1.99$ 1.67$ 1.77$
High Growth & Low Prices 2024-2025 1.61$ 1.95$ 1.63$ 1.63$ 1.63$ 1.75$ 1.39$ 1.88$ 1.67$ 1.69$ High Growth & Low Prices 2025-2026 1.55$ 1.81$ 1.57$ 1.57$ 1.57$ 1.64$ 1.28$ 1.73$ 1.55$ 1.61$ High Growth & Low Prices 2026-2027 1.63$ 1.84$ 1.64$ 1.64$ 1.64$ 1.61$ 1.25$ 1.76$ 1.54$ 1.68$
High Growth & Low Prices 2027-2028 1.75$ 1.86$ 34.52$ 34.52$ 34.52$ 1.72$ 1.39$ 1.86$ 1.66$ 21.43$
High Growth & Low Prices 2028-2029 1.77$ 1.91$ 34.54$ 34.54$ 34.54$ 1.80$ 1.47$ 1.91$ 1.73$ 21.46$
High Growth & Low Prices 2029-2030 1.91$ 2.06$ 34.67$ 34.67$ 34.67$ 1.90$ 1.55$ 2.06$ 1.84$ 21.60$
High Growth & Low Prices 2030-2031 1.90$ 2.06$ 67.42$ 67.42$ 67.42$ 1.92$ 1.57$ 2.06$ 1.85$ 41.24$ High Growth & Low Prices 2031-2032 1.85$ 2.00$ 67.38$ 67.38$ 67.38$ 1.93$ 1.56$ 2.00$ 1.83$ 41.20$ High Growth & Low Prices 2032-2033 1.87$ 2.04$ 67.39$ 67.39$ 67.39$ 1.95$ 1.57$ 2.04$ 1.85$ 41.21$
High Growth & Low Prices 2033-2034 2.00$ 2.12$ 67.52$ 67.52$ 67.52$ 2.02$ 1.63$ 2.13$ 1.93$ 41.34$
High Growth & Low Prices 2034-2035 34.70$ 2.14$ 67.47$ 67.47$ 67.47$ 1.97$ 1.52$ 2.15$ 1.88$ 47.85$
1/ Avoided costs are before Environmental Externalities adder.
Annual Avoided Costs 1/
2014$
Winter Avoided Costs 1/
2014$
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 183 of 648
APPENDIX 5.4: CARBON LEGISLATION – MEDIUM CASE AVOIDED COST

Scenario Gas Year Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual
Carbon Legislation - Medium Case 2015-2016 1.88$ 2.17$ 1.88$ 1.88$ 1.88$ 1.89$ 1.84$ 2.16$ 1.96$ 1.94$ Carbon Legislation - Medium Case 2016-2017 2.28$ 2.97$ 2.28$ 2.28$ 2.28$ 2.31$ 2.20$ 2.95$ 2.49$ 2.41$ Carbon Legislation - Medium Case 2017-2018 2.78$ 3.45$ 2.78$ 2.78$ 2.78$ 2.78$ 2.72$ 3.44$ 2.98$ 2.91$
Carbon Legislation - Medium Case 2018-2019 2.79$ 3.53$ 2.79$ 2.79$ 2.79$ 2.81$ 2.74$ 3.51$ 3.02$ 2.94$
Carbon Legislation - Medium Case 2019-2020 2.88$ 3.61$ 2.88$ 2.88$ 2.88$ 2.90$ 2.83$ 3.60$ 3.11$ 3.02$
Carbon Legislation - Medium Case 2020-2021 3.03$ 3.76$ 3.03$ 3.03$ 3.03$ 3.06$ 2.97$ 3.75$ 3.26$ 3.18$
Carbon Legislation - Medium Case 2021-2022 3.11$ 3.88$ 3.11$ 3.11$ 3.11$ 3.13$ 3.05$ 3.87$ 3.35$ 3.27$ Carbon Legislation - Medium Case 2022-2023 3.10$ 3.89$ 3.10$ 3.10$ 3.10$ 3.11$ 3.01$ 3.87$ 3.33$ 3.26$ Carbon Legislation - Medium Case 2023-2024 3.33$ 3.96$ 3.33$ 3.33$ 3.33$ 3.35$ 3.27$ 3.95$ 3.52$ 3.46$
Carbon Legislation - Medium Case 2024-2025 3.59$ 4.10$ 3.59$ 3.59$ 3.59$ 3.59$ 3.53$ 4.08$ 3.73$ 3.69$
Carbon Legislation - Medium Case 2025-2026 3.59$ 4.06$ 3.59$ 3.59$ 3.59$ 3.56$ 3.53$ 4.04$ 3.71$ 3.68$
Carbon Legislation - Medium Case 2026-2027 3.66$ 4.13$ 3.66$ 3.66$ 3.66$ 3.64$ 3.59$ 4.10$ 3.78$ 3.76$
Carbon Legislation - Medium Case 2027-2028 3.97$ 4.34$ 3.97$ 3.97$ 3.97$ 3.93$ 3.91$ 4.33$ 4.06$ 4.05$ Carbon Legislation - Medium Case 2028-2029 4.17$ 4.50$ 4.17$ 4.17$ 4.17$ 4.12$ 4.11$ 4.48$ 4.23$ 4.24$ Carbon Legislation - Medium Case 2029-2030 4.33$ 4.68$ 4.33$ 4.33$ 4.33$ 4.28$ 4.26$ 4.67$ 4.40$ 4.40$
Carbon Legislation - Medium Case 2030-2031 4.53$ 4.84$ 4.53$ 4.53$ 4.53$ 4.49$ 4.46$ 4.83$ 4.59$ 4.59$
Carbon Legislation - Medium Case 2031-2032 4.68$ 4.94$ 4.68$ 4.68$ 4.68$ 4.62$ 4.61$ 4.92$ 4.72$ 4.73$
Carbon Legislation - Medium Case 2032-2033 4.72$ 5.01$ 4.72$ 4.72$ 4.72$ 4.68$ 4.65$ 5.00$ 4.78$ 4.78$
Carbon Legislation - Medium Case 2033-2034 4.77$ 5.12$ 4.77$ 4.77$ 4.77$ 4.74$ 4.70$ 5.12$ 4.85$ 4.84$ Carbon Legislation - Medium Case 2034-2035 4.82$ 5.11$ 4.82$ 4.82$ 4.82$ 4.78$ 4.74$ 5.10$ 4.87$ 4.88$
Scenario Gas Year Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual
Carbon Legislation - Medium Case 2015-2016 1.87$ 2.09$ 1.87$ 1.87$ 1.87$ 2.01$ 1.79$ 2.09$ 1.96$ 1.91$
Carbon Legislation - Medium Case 2016-2017 2.32$ 2.97$ 2.32$ 2.32$ 2.32$ 2.42$ 2.14$ 2.94$ 2.50$ 2.45$
Carbon Legislation - Medium Case 2017-2018 2.61$ 3.41$ 2.61$ 2.61$ 2.61$ 2.74$ 2.48$ 3.40$ 2.87$ 2.77$
Carbon Legislation - Medium Case 2018-2019 3.12$ 3.54$ 3.12$ 3.12$ 3.12$ 3.22$ 3.01$ 3.49$ 3.24$ 3.20$ Carbon Legislation - Medium Case 2019-2020 3.19$ 3.62$ 3.19$ 3.19$ 3.19$ 3.31$ 3.09$ 3.59$ 3.33$ 3.28$ Carbon Legislation - Medium Case 2020-2021 3.30$ 3.77$ 3.30$ 3.30$ 3.30$ 3.42$ 3.19$ 3.75$ 3.45$ 3.39$
Carbon Legislation - Medium Case 2021-2022 3.47$ 3.89$ 3.47$ 3.47$ 3.47$ 3.56$ 3.33$ 3.85$ 3.58$ 3.55$
Carbon Legislation - Medium Case 2022-2023 3.42$ 3.91$ 3.42$ 3.42$ 3.42$ 3.48$ 3.22$ 3.86$ 3.52$ 3.52$
Carbon Legislation - Medium Case 2023-2024 3.63$ 3.99$ 3.63$ 3.63$ 3.63$ 3.75$ 3.51$ 3.95$ 3.74$ 3.70$
Carbon Legislation - Medium Case 2024-2025 3.91$ 4.12$ 3.91$ 3.91$ 3.91$ 3.94$ 3.79$ 4.08$ 3.94$ 3.95$ Carbon Legislation - Medium Case 2025-2026 4.19$ 4.20$ 4.19$ 4.19$ 4.19$ 4.07$ 4.07$ 4.11$ 4.08$ 4.19$ Carbon Legislation - Medium Case 2026-2027 4.18$ 4.19$ 4.18$ 4.18$ 4.18$ 4.09$ 4.04$ 4.10$ 4.08$ 4.18$
Carbon Legislation - Medium Case 2027-2028 4.41$ 4.41$ 4.41$ 4.41$ 4.41$ 4.33$ 4.30$ 4.34$ 4.32$ 4.41$
Carbon Legislation - Medium Case 2028-2029 4.60$ 4.60$ 4.60$ 4.60$ 4.60$ 4.51$ 4.50$ 4.53$ 4.51$ 4.60$
Carbon Legislation - Medium Case 2029-2030 4.72$ 4.74$ 4.72$ 4.72$ 4.72$ 4.64$ 4.61$ 4.68$ 4.64$ 4.73$
Carbon Legislation - Medium Case 2030-2031 5.02$ 5.05$ 5.02$ 5.02$ 5.02$ 4.93$ 4.91$ 4.98$ 4.94$ 5.02$ Carbon Legislation - Medium Case 2031-2032 5.09$ 5.14$ 5.09$ 5.09$ 5.09$ 5.02$ 5.00$ 5.08$ 5.03$ 5.10$ Carbon Legislation - Medium Case 2032-2033 5.23$ 5.30$ 5.23$ 5.23$ 5.23$ 5.16$ 5.13$ 5.24$ 5.18$ 5.24$
Carbon Legislation - Medium Case 2033-2034 5.33$ 5.39$ 5.33$ 5.33$ 5.33$ 5.25$ 5.22$ 5.32$ 5.26$ 5.34$
Carbon Legislation - Medium Case 2034-2035 5.32$ 5.38$ 5.32$ 5.32$ 5.32$ 5.22$ 5.19$ 5.30$ 5.24$ 5.33$
1/ Avoided costs are before Environmental Externalities adder.
Annual Avoided Costs 1/
2014$
Winter Avoided Costs 1/
2014$
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 184 of 648
APPENDIX 5.4: COLD DAY 20 YR WEATHER STANDARD AVOIDED COST

Scenario Gas Year Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual
Cold Day 20yr Weather Std 2015-2016 1.88$ 2.17$ 1.88$ 1.88$ 1.88$ 1.88$ 1.84$ 2.16$ 1.96$ 1.94$
Cold Day 20yr Weather Std 2016-2017 2.27$ 2.96$ 2.27$ 2.27$ 2.27$ 2.31$ 2.20$ 2.95$ 2.49$ 2.41$
Cold Day 20yr Weather Std 2017-2018 2.80$ 3.45$ 2.80$ 2.80$ 2.80$ 2.79$ 2.72$ 3.44$ 2.99$ 2.93$
Cold Day 20yr Weather Std 2018-2019 2.80$ 3.54$ 2.80$ 2.80$ 2.80$ 2.83$ 2.74$ 3.52$ 3.03$ 2.95$ Cold Day 20yr Weather Std 2019-2020 2.88$ 3.62$ 2.88$ 2.88$ 2.88$ 2.93$ 2.83$ 3.60$ 3.12$ 3.03$ Cold Day 20yr Weather Std 2020-2021 3.04$ 3.77$ 3.04$ 3.04$ 3.04$ 3.08$ 2.97$ 3.75$ 3.27$ 3.18$
Cold Day 20yr Weather Std 2021-2022 3.13$ 3.89$ 3.13$ 3.13$ 3.13$ 3.16$ 3.05$ 3.87$ 3.36$ 3.29$
Cold Day 20yr Weather Std 2022-2023 3.15$ 3.91$ 3.15$ 3.15$ 3.15$ 3.13$ 3.01$ 3.87$ 3.34$ 3.30$
Cold Day 20yr Weather Std 2023-2024 3.36$ 3.97$ 3.36$ 3.36$ 3.36$ 3.38$ 3.27$ 3.95$ 3.53$ 3.48$ Cold Day 20yr Weather Std 2024-2025 3.61$ 4.14$ 3.61$ 3.61$ 3.61$ 3.61$ 3.53$ 4.12$ 3.75$ 3.72$
Cold Day 20yr Weather Std 2025-2026 3.59$ 4.09$ 3.59$ 3.59$ 3.59$ 3.58$ 3.53$ 4.06$ 3.72$ 3.69$
Cold Day 20yr Weather Std 2026-2027 3.66$ 4.16$ 3.66$ 3.66$ 3.66$ 3.66$ 3.59$ 4.11$ 3.79$ 3.76$
Cold Day 20yr Weather Std 2027-2028 3.97$ 4.38$ 3.97$ 3.97$ 3.97$ 3.95$ 3.91$ 4.34$ 4.06$ 4.05$ Cold Day 20yr Weather Std 2028-2029 4.17$ 4.54$ 4.17$ 4.17$ 4.17$ 4.13$ 4.11$ 4.50$ 4.25$ 4.24$
Cold Day 20yr Weather Std 2029-2030 4.33$ 4.71$ 4.33$ 4.33$ 4.33$ 4.30$ 4.26$ 4.69$ 4.41$ 4.41$
Cold Day 20yr Weather Std 2030-2031 4.54$ 4.87$ 4.54$ 4.54$ 4.54$ 4.50$ 4.46$ 4.84$ 4.60$ 4.60$
Cold Day 20yr Weather Std 2031-2032 4.68$ 4.97$ 4.68$ 4.68$ 4.68$ 4.64$ 4.61$ 4.94$ 4.73$ 4.74$ Cold Day 20yr Weather Std 2032-2033 4.73$ 5.03$ 4.73$ 4.73$ 4.73$ 4.69$ 4.65$ 5.01$ 4.78$ 4.79$ Cold Day 20yr Weather Std 2033-2034 4.79$ 5.15$ 4.79$ 4.79$ 4.79$ 4.75$ 4.70$ 5.12$ 4.86$ 4.86$
Cold Day 20yr Weather Std 2034-2035 4.83$ 5.05$ 4.83$ 4.83$ 4.83$ 4.79$ 4.74$ 5.01$ 4.85$ 4.87$
Scenario Gas Year Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual
Cold Day 20yr Weather Std 2015-2016 1.86$ 2.09$ 1.86$ 1.86$ 1.86$ 2.00$ 1.79$ 2.09$ 1.96$ 1.91$
Cold Day 20yr Weather Std 2016-2017 2.29$ 2.97$ 2.29$ 2.29$ 2.29$ 2.42$ 2.14$ 2.94$ 2.50$ 2.43$
Cold Day 20yr Weather Std 2017-2018 2.69$ 3.41$ 2.69$ 2.69$ 2.69$ 2.77$ 2.48$ 3.40$ 2.88$ 2.84$
Cold Day 20yr Weather Std 2018-2019 3.12$ 3.55$ 3.12$ 3.12$ 3.12$ 3.26$ 3.01$ 3.51$ 3.26$ 3.21$ Cold Day 20yr Weather Std 2019-2020 3.19$ 3.63$ 3.19$ 3.19$ 3.19$ 3.36$ 3.09$ 3.60$ 3.35$ 3.28$
Cold Day 20yr Weather Std 2020-2021 3.30$ 3.77$ 3.30$ 3.30$ 3.30$ 3.49$ 3.19$ 3.75$ 3.48$ 3.40$
Cold Day 20yr Weather Std 2021-2022 3.52$ 3.90$ 3.52$ 3.52$ 3.52$ 3.63$ 3.33$ 3.85$ 3.61$ 3.59$
Cold Day 20yr Weather Std 2022-2023 3.55$ 3.92$ 3.55$ 3.55$ 3.55$ 3.54$ 3.22$ 3.86$ 3.54$ 3.63$
Cold Day 20yr Weather Std 2023-2024 3.74$ 4.01$ 3.74$ 3.74$ 3.74$ 3.81$ 3.51$ 3.97$ 3.76$ 3.80$ Cold Day 20yr Weather Std 2024-2025 3.97$ 4.17$ 3.97$ 3.97$ 3.97$ 4.01$ 3.79$ 4.12$ 3.97$ 4.01$
Cold Day 20yr Weather Std 2025-2026 4.16$ 4.23$ 4.16$ 4.16$ 4.16$ 4.10$ 4.07$ 4.14$ 4.10$ 4.18$
Cold Day 20yr Weather Std 2026-2027 4.15$ 4.29$ 4.15$ 4.15$ 4.15$ 4.11$ 4.04$ 4.13$ 4.09$ 4.18$
Cold Day 20yr Weather Std 2027-2028 4.39$ 4.48$ 4.39$ 4.39$ 4.39$ 4.36$ 4.30$ 4.38$ 4.34$ 4.41$ Cold Day 20yr Weather Std 2028-2029 4.59$ 4.66$ 4.59$ 4.59$ 4.59$ 4.54$ 4.50$ 4.58$ 4.54$ 4.61$
Cold Day 20yr Weather Std 2029-2030 4.71$ 4.81$ 4.71$ 4.71$ 4.71$ 4.68$ 4.61$ 4.73$ 4.68$ 4.73$
Cold Day 20yr Weather Std 2030-2031 5.02$ 5.09$ 5.02$ 5.02$ 5.02$ 4.94$ 4.91$ 4.99$ 4.95$ 5.03$
Cold Day 20yr Weather Std 2031-2032 5.09$ 5.20$ 5.09$ 5.09$ 5.09$ 5.07$ 5.00$ 5.13$ 5.06$ 5.11$ Cold Day 20yr Weather Std 2032-2033 5.23$ 5.33$ 5.23$ 5.23$ 5.23$ 5.18$ 5.13$ 5.24$ 5.19$ 5.25$ Cold Day 20yr Weather Std 2033-2034 5.32$ 5.48$ 5.32$ 5.32$ 5.32$ 5.27$ 5.22$ 5.33$ 5.27$ 5.35$
Cold Day 20yr Weather Std 2034-2035 5.32$ 5.46$ 5.32$ 5.32$ 5.32$ 5.25$ 5.19$ 5.32$ 5.25$ 5.35$
1/ Avoided costs are before Environmental Externalities adder.
Annual Avoided Costs 1/
2014$
Winter Avoided Costs 1/
2014$
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 185 of 648
APPENDIX 5.4: WASHINGTON AND IDAHO AVOIDED COSTS -
LOW GROWTH/HIGH PRICE CASE

APPENDIX 5.4: NATURAL GAS OREGON AVOIDED COSTS -
LOW GROWTH/HIGH PRICE CASE

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 186 of 648
APPENDIX 5.4: LOW GROWTH – HIGH PRICE MONTHLY DETAIL

Scenario Gas Year Month Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual
Low Growth_High Prices 2015-2016 Nov 1.96$ 2.16$ 1.96$ 1.96$ 1.96$ 1.93$ 1.93$ 2.16$ 2.01$ 2.00$
Low Growth_High Prices 2015-2016 Dec 1.80$ 2.11$ 1.80$ 1.80$ 1.80$ 2.10$ 1.65$ 2.11$ 1.95$ 1.86$
Low Growth_High Prices 2015-2016 Jan 7.38$ 7.41$ 7.38$ 7.38$ 7.38$ 7.28$ 7.28$ 7.28$ 7.28$ 7.38$
Low Growth_High Prices 2015-2016 Feb 7.60$ 7.72$ 7.60$ 7.60$ 7.60$ 7.35$ 7.50$ 7.35$ 7.40$ 7.63$
Low Growth_High Prices 2015-2016 Mar 7.62$ 7.71$ 7.62$ 7.62$ 7.62$ 7.46$ 7.52$ 7.59$ 7.52$ 7.64$
Low Growth_High Prices 2015-2016 Apr 4.33$ 4.73$ 4.33$ 4.33$ 4.33$ 4.27$ 4.27$ 4.73$ 4.42$ 4.41$
Low Growth_High Prices 2015-2016 May 4.29$ 4.70$ 4.29$ 4.29$ 4.29$ 4.23$ 4.23$ 4.70$ 4.38$ 4.37$
Low Growth_High Prices 2015-2016 Jun 4.59$ 4.70$ 4.59$ 4.59$ 4.59$ 4.53$ 4.53$ 4.70$ 4.58$ 4.61$
Low Growth_High Prices 2015-2016 Jul 4.25$ 4.70$ 4.25$ 4.25$ 4.25$ 4.19$ 4.19$ 4.70$ 4.36$ 4.34$
Low Growth_High Prices 2015-2016 Aug 4.41$ 4.70$ 4.41$ 4.41$ 4.41$ 4.35$ 4.35$ 4.70$ 4.46$ 4.47$
Low Growth_High Prices 2015-2016 Sep 3.63$ 4.63$ 3.63$ 3.63$ 3.63$ 3.57$ 3.57$ 4.70$ 3.95$ 3.83$
Low Growth_High Prices 2015-2016 Oct 4.41$ 5.13$ 4.41$ 4.41$ 4.41$ 4.35$ 4.35$ 5.13$ 4.61$ 4.55$
Low Growth_High Prices 2016-2017 Nov 3.88$ 4.81$ 3.88$ 3.88$ 3.88$ 3.83$ 3.83$ 4.81$ 4.15$ 4.07$
Low Growth_High Prices 2016-2017 Dec 5.66$ 6.58$ 5.66$ 5.66$ 5.66$ 5.52$ 5.40$ 6.58$ 5.83$ 5.84$
Low Growth_High Prices 2016-2017 Jan 7.11$ 7.11$ 7.11$ 7.11$ 7.11$ 7.02$ 7.02$ 7.02$ 7.02$ 7.11$
Low Growth_High Prices 2016-2017 Feb 7.44$ 7.55$ 7.29$ 7.29$ 7.29$ 7.07$ 7.34$ 7.07$ 7.16$ 7.37$
Low Growth_High Prices 2016-2017 Mar 7.19$ 7.35$ 7.19$ 7.19$ 7.19$ 7.08$ 7.10$ 7.27$ 7.15$ 7.22$
Low Growth_High Prices 2016-2017 Apr 4.36$ 5.08$ 4.36$ 4.36$ 4.36$ 4.30$ 4.30$ 5.08$ 4.56$ 4.51$
Low Growth_High Prices 2016-2017 May 4.33$ 5.08$ 4.33$ 4.33$ 4.33$ 4.27$ 4.27$ 5.08$ 4.54$ 4.48$
Low Growth_High Prices 2016-2017 Jun 4.60$ 5.09$ 4.60$ 4.60$ 4.60$ 4.53$ 4.53$ 5.09$ 4.72$ 4.69$
Low Growth_High Prices 2016-2017 Jul 4.24$ 5.09$ 4.24$ 4.24$ 4.24$ 4.18$ 4.18$ 5.09$ 4.48$ 4.41$
Low Growth_High Prices 2016-2017 Aug 4.39$ 5.09$ 4.39$ 4.39$ 4.39$ 4.33$ 4.33$ 5.09$ 4.58$ 4.53$
Low Growth_High Prices 2016-2017 Sep 3.57$ 4.73$ 3.57$ 3.57$ 3.57$ 3.52$ 3.52$ 5.09$ 4.04$ 3.80$
Low Growth_High Prices 2016-2017 Oct 4.38$ 5.21$ 4.38$ 4.38$ 4.38$ 4.32$ 4.32$ 5.21$ 4.61$ 4.54$
Low Growth_High Prices 2017-2018 Nov 3.97$ 4.93$ 3.97$ 3.97$ 3.97$ 3.91$ 3.91$ 4.93$ 4.25$ 4.16$
Low Growth_High Prices 2017-2018 Dec 5.71$ 6.53$ 5.71$ 5.71$ 5.71$ 5.57$ 5.47$ 6.53$ 5.85$ 5.87$
Low Growth_High Prices 2017-2018 Jan 7.78$ 7.78$ 7.78$ 7.78$ 7.78$ 7.68$ 7.68$ 7.68$ 7.68$ 7.78$
Low Growth_High Prices 2017-2018 Feb 8.09$ 8.19$ 8.06$ 8.06$ 8.06$ 7.74$ 7.99$ 7.74$ 7.82$ 8.09$
Low Growth_High Prices 2017-2018 Mar 8.12$ 8.15$ 8.11$ 8.11$ 8.11$ 7.90$ 8.01$ 7.96$ 7.96$ 8.12$
Low Growth_High Prices 2017-2018 Apr 4.87$ 5.66$ 4.87$ 4.87$ 4.87$ 4.80$ 4.80$ 5.66$ 5.09$ 5.02$
Low Growth_High Prices 2017-2018 May 4.80$ 5.52$ 4.80$ 4.80$ 4.80$ 4.74$ 4.74$ 5.52$ 5.00$ 4.95$
Low Growth_High Prices 2017-2018 Jun 5.06$ 5.52$ 5.06$ 5.06$ 5.06$ 4.99$ 4.99$ 5.52$ 5.17$ 5.15$
Low Growth_High Prices 2017-2018 Jul 4.73$ 5.52$ 4.73$ 4.73$ 4.73$ 4.66$ 4.66$ 5.52$ 4.95$ 4.89$
Low Growth_High Prices 2017-2018 Aug 4.82$ 5.52$ 4.82$ 4.82$ 4.82$ 4.75$ 4.75$ 5.52$ 5.01$ 4.96$
Low Growth_High Prices 2017-2018 Sep 4.09$ 5.29$ 4.09$ 4.09$ 4.09$ 4.03$ 4.03$ 5.52$ 4.53$ 4.33$
Low Growth_High Prices 2017-2018 Oct 4.89$ 5.85$ 4.89$ 4.89$ 4.89$ 4.82$ 4.82$ 5.85$ 5.17$ 5.08$
Low Growth_High Prices 2018-2019 Nov 4.55$ 5.29$ 4.55$ 4.55$ 4.55$ 4.48$ 4.48$ 5.29$ 4.75$ 4.69$
Low Growth_High Prices 2018-2019 Dec 6.26$ 6.92$ 6.26$ 6.26$ 6.26$ 6.13$ 6.03$ 6.91$ 6.36$ 6.39$
Low Growth_High Prices 2018-2019 Jan 7.69$ 7.69$ 7.69$ 7.69$ 7.69$ 7.59$ 7.59$ 7.59$ 7.59$ 7.69$
Low Growth_High Prices 2018-2019 Feb 8.01$ 8.12$ 7.84$ 7.84$ 7.84$ 7.65$ 7.91$ 7.65$ 7.74$ 7.93$
Low Growth_High Prices 2018-2019 Mar 7.78$ 7.93$ 7.78$ 7.78$ 7.78$ 7.66$ 7.68$ 7.85$ 7.73$ 7.81$
Low Growth_High Prices 2018-2019 Apr 4.67$ 5.67$ 4.67$ 4.67$ 4.67$ 4.60$ 4.60$ 5.67$ 4.96$ 4.87$
Low Growth_High Prices 2018-2019 May 4.68$ 5.64$ 4.68$ 4.68$ 4.68$ 4.62$ 4.62$ 5.64$ 4.96$ 4.87$
Low Growth_High Prices 2018-2019 Jun 5.03$ 5.64$ 5.03$ 5.03$ 5.03$ 4.97$ 4.97$ 5.64$ 5.19$ 5.15$
Low Growth_High Prices 2018-2019 Jul 4.71$ 5.64$ 4.71$ 4.71$ 4.71$ 4.65$ 4.65$ 5.64$ 4.98$ 4.90$
Low Growth_High Prices 2018-2019 Aug 4.80$ 5.64$ 4.80$ 4.80$ 4.80$ 4.74$ 4.74$ 5.64$ 5.04$ 4.97$
Low Growth_High Prices 2018-2019 Sep 4.09$ 5.27$ 4.09$ 4.09$ 4.09$ 4.04$ 4.04$ 5.64$ 4.57$ 4.33$
Low Growth_High Prices 2018-2019 Oct 4.92$ 5.83$ 4.92$ 4.92$ 4.92$ 4.85$ 4.85$ 5.83$ 5.18$ 5.10$ Low Growth_High Prices 2019-2020 Nov 4.58$ 5.26$ 4.58$ 4.58$ 4.58$ 4.52$ 4.52$ 5.26$ 4.76$ 4.72$ Low Growth_High Prices 2019-2020 Dec 6.27$ 6.80$ 6.27$ 6.27$ 6.27$ 6.17$ 6.07$ 6.79$ 6.35$ 6.38$ Low Growth_High Prices 2019-2020 Jan 7.72$ 7.72$ 7.72$ 7.72$ 7.72$ 7.62$ 7.62$ 7.62$ 7.62$ 7.72$ Low Growth_High Prices 2019-2020 Feb 8.04$ 8.15$ 8.01$ 8.01$ 8.01$ 7.67$ 7.93$ 7.67$ 7.76$ 8.05$ Low Growth_High Prices 2019-2020 Mar 8.09$ 8.10$ 8.08$ 8.08$ 8.08$ 7.84$ 7.98$ 7.88$ 7.90$ 8.09$ Low Growth_High Prices 2019-2020 Apr 4.70$ 5.66$ 4.70$ 4.70$ 4.70$ 4.63$ 4.63$ 5.66$ 4.97$ 4.89$ Low Growth_High Prices 2019-2020 May 4.71$ 5.60$ 4.71$ 4.71$ 4.71$ 4.65$ 4.65$ 5.60$ 4.96$ 4.89$ Low Growth_High Prices 2019-2020 Jun 5.04$ 5.60$ 5.04$ 5.04$ 5.04$ 4.97$ 4.97$ 5.60$ 5.18$ 5.15$ Low Growth_High Prices 2019-2020 Jul 4.70$ 5.60$ 4.70$ 4.70$ 4.70$ 4.64$ 4.64$ 5.60$ 4.96$ 4.88$ Low Growth_High Prices 2019-2020 Aug 4.80$ 5.60$ 4.80$ 4.80$ 4.80$ 4.74$ 4.74$ 5.60$ 5.03$ 4.96$ Low Growth_High Prices 2019-2020 Sep 4.09$ 5.28$ 4.09$ 4.09$ 4.09$ 4.04$ 4.04$ 5.60$ 4.56$ 4.33$ Low Growth_High Prices 2019-2020 Oct 4.90$ 5.90$ 4.90$ 4.90$ 4.90$ 4.83$ 4.83$ 5.90$ 5.19$ 5.10$ Low Growth_High Prices 2020-2021 Nov 4.63$ 5.25$ 4.63$ 4.63$ 4.63$ 4.57$ 4.57$ 5.25$ 4.80$ 4.76$ Low Growth_High Prices 2020-2021 Dec 6.33$ 6.77$ 6.33$ 6.33$ 6.33$ 6.24$ 6.14$ 6.77$ 6.38$ 6.42$ Low Growth_High Prices 2020-2021 Jan 7.76$ 7.76$ 7.76$ 7.76$ 7.76$ 7.66$ 7.66$ 7.66$ 7.66$ 7.76$ Low Growth_High Prices 2020-2021 Feb 8.14$ 8.23$ 7.98$ 7.98$ 7.98$ 7.73$ 8.04$ 7.73$ 7.83$ 8.06$ Low Growth_High Prices 2020-2021 Mar 7.45$ 7.58$ 7.45$ 7.45$ 7.45$ 7.36$ 7.36$ 7.52$ 7.41$ 7.48$ Low Growth_High Prices 2020-2021 Apr 4.78$ 5.72$ 4.78$ 4.78$ 4.78$ 4.71$ 4.71$ 5.72$ 5.05$ 4.97$ Low Growth_High Prices 2020-2021 May 4.80$ 5.72$ 4.80$ 4.80$ 4.80$ 4.74$ 4.74$ 5.72$ 5.06$ 4.99$ Low Growth_High Prices 2020-2021 Jun 5.11$ 5.72$ 5.11$ 5.11$ 5.11$ 5.04$ 5.04$ 5.72$ 5.27$ 5.23$
Low Growth_High Prices 2020-2021 Jul 4.68$ 5.72$ 4.68$ 4.68$ 4.68$ 4.61$ 4.61$ 5.72$ 4.98$ 4.89$
Low Growth_High Prices 2020-2021 Aug 4.77$ 5.72$ 4.77$ 4.77$ 4.77$ 4.71$ 4.71$ 5.72$ 5.04$ 4.96$
Low Growth_High Prices 2020-2021 Sep 4.23$ 5.20$ 4.23$ 4.23$ 4.23$ 4.17$ 4.17$ 5.72$ 4.69$ 4.42$
Low Growth_High Prices 2020-2021 Oct 5.04$ 5.80$ 5.04$ 5.04$ 5.04$ 4.97$ 4.97$ 5.80$ 5.25$ 5.19$
Low Growth_High Prices 2021-2022 Nov 4.58$ 5.25$ 4.58$ 4.58$ 4.58$ 4.51$ 4.51$ 5.25$ 4.76$ 4.71$
Low Growth_High Prices 2021-2022 Dec 6.27$ 6.74$ 6.27$ 6.27$ 6.27$ 6.15$ 6.06$ 6.72$ 6.31$ 6.37$
Low Growth_High Prices 2021-2022 Jan 7.70$ 7.70$ 7.70$ 7.70$ 7.70$ 7.59$ 7.59$ 7.59$ 7.59$ 7.70$
Low Growth_High Prices 2021-2022 Feb 8.07$ 8.20$ 8.04$ 8.04$ 8.04$ 7.66$ 7.96$ 7.66$ 7.76$ 8.08$
Low Growth_High Prices 2021-2022 Mar 8.11$ 8.13$ 8.10$ 8.10$ 8.10$ 7.82$ 8.00$ 7.86$ 7.89$ 8.11$
Low Growth_High Prices 2021-2022 Apr 4.75$ 5.81$ 4.75$ 4.75$ 4.75$ 4.69$ 4.69$ 5.81$ 5.06$ 4.97$
Low Growth_High Prices 2021-2022 May 4.79$ 5.79$ 4.79$ 4.79$ 4.79$ 4.72$ 4.72$ 5.79$ 5.08$ 4.99$
Low Growth_High Prices 2021-2022 Jun 5.10$ 5.79$ 5.10$ 5.10$ 5.10$ 5.03$ 5.03$ 5.79$ 5.29$ 5.24$
Low Growth_High Prices 2021-2022 Jul 4.74$ 5.79$ 4.74$ 4.74$ 4.74$ 4.68$ 4.68$ 5.79$ 5.05$ 4.95$
Low Growth_High Prices 2021-2022 Aug 4.85$ 5.79$ 4.85$ 4.85$ 4.85$ 4.79$ 4.79$ 5.79$ 5.12$ 5.04$
Low Growth_High Prices 2021-2022 Sep 4.14$ 5.33$ 4.14$ 4.14$ 4.14$ 4.08$ 4.08$ 5.79$ 4.65$ 4.38$
Low Growth_High Prices 2021-2022 Oct 4.96$ 5.91$ 4.96$ 4.96$ 4.96$ 4.89$ 4.89$ 5.91$ 5.23$ 5.15$
1/ Avoided costs are before Environmental Externalities adder.
Monthly Avoided Costs 1/
2014$
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 187 of 648
APPENDIX 5.4: LOW GROWTH – HIGH PRICE MONTHLY DETAIL

Scenario Gas Year Month Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual
Low Growth_High Prices 2022-2023 Nov 4.50$ 5.40$ 4.50$ 4.50$ 4.50$ 4.43$ 4.43$ 5.40$ 4.76$ 4.68$
Low Growth_High Prices 2022-2023 Dec 6.18$ 6.87$ 6.18$ 6.18$ 6.18$ 6.02$ 5.93$ 6.83$ 6.26$ 6.32$
Low Growth_High Prices 2022-2023 Jan 7.50$ 7.50$ 7.50$ 7.50$ 7.50$ 6.94$ 7.41$ 6.94$ 7.10$ 7.50$
Low Growth_High Prices 2022-2023 Feb 7.87$ 8.07$ 7.77$ 7.77$ 7.77$ 7.21$ 7.77$ 7.21$ 7.39$ 7.85$
Low Growth_High Prices 2022-2023 Mar 6.48$ 6.67$ 6.48$ 6.48$ 6.48$ 6.40$ 6.40$ 6.67$ 6.49$ 6.52$
Low Growth_High Prices 2022-2023 Apr 4.71$ 5.89$ 4.71$ 4.71$ 4.71$ 4.65$ 4.65$ 5.89$ 5.06$ 4.95$
Low Growth_High Prices 2022-2023 May 4.77$ 5.81$ 4.77$ 4.77$ 4.77$ 4.71$ 4.71$ 5.81$ 5.08$ 4.98$
Low Growth_High Prices 2022-2023 Jun 5.10$ 5.82$ 5.10$ 5.10$ 5.10$ 5.03$ 5.03$ 5.82$ 5.29$ 5.24$
Low Growth_High Prices 2022-2023 Jul 4.75$ 5.82$ 4.75$ 4.75$ 4.75$ 4.68$ 4.68$ 5.82$ 5.06$ 4.96$
Low Growth_High Prices 2022-2023 Aug 4.84$ 5.82$ 4.84$ 4.84$ 4.84$ 4.77$ 4.77$ 5.82$ 5.12$ 5.04$
Low Growth_High Prices 2022-2023 Sep 4.26$ 5.25$ 4.26$ 4.26$ 4.26$ 4.21$ 4.21$ 5.82$ 4.74$ 4.46$
Low Growth_High Prices 2022-2023 Oct 5.09$ 5.82$ 5.09$ 5.09$ 5.09$ 5.02$ 5.02$ 5.82$ 5.29$ 5.23$
Low Growth_High Prices 2023-2024 Nov 4.73$ 5.26$ 4.73$ 4.73$ 4.73$ 4.66$ 4.66$ 5.26$ 4.86$ 4.84$
Low Growth_High Prices 2023-2024 Dec 6.36$ 6.88$ 6.36$ 6.36$ 6.36$ 6.25$ 6.16$ 6.88$ 6.43$ 6.47$
Low Growth_High Prices 2023-2024 Jan 7.80$ 7.79$ 7.80$ 7.80$ 7.80$ 7.69$ 7.69$ 7.69$ 7.69$ 7.80$
Low Growth_High Prices 2023-2024 Feb 8.14$ 8.26$ 8.14$ 8.14$ 8.14$ 7.75$ 8.04$ 7.75$ 7.85$ 8.16$
Low Growth_High Prices 2023-2024 Mar 8.23$ 8.24$ 8.22$ 8.22$ 8.22$ 7.93$ 8.12$ 7.97$ 8.01$ 8.23$
Low Growth_High Prices 2023-2024 Apr 4.84$ 5.73$ 4.84$ 4.84$ 4.84$ 4.77$ 4.77$ 5.73$ 5.09$ 5.02$
Low Growth_High Prices 2023-2024 May 4.85$ 5.73$ 4.85$ 4.85$ 4.85$ 4.78$ 4.78$ 5.73$ 5.10$ 5.03$
Low Growth_High Prices 2023-2024 Jun 5.17$ 5.73$ 5.17$ 5.17$ 5.17$ 5.10$ 5.10$ 5.73$ 5.31$ 5.28$
Low Growth_High Prices 2023-2024 Jul 4.90$ 5.74$ 4.90$ 4.90$ 4.90$ 4.84$ 4.84$ 5.74$ 5.14$ 5.07$
Low Growth_High Prices 2023-2024 Aug 5.00$ 5.74$ 5.00$ 5.00$ 5.00$ 4.94$ 4.94$ 5.74$ 5.20$ 5.15$
Low Growth_High Prices 2023-2024 Sep 4.37$ 5.21$ 4.37$ 4.37$ 4.37$ 4.31$ 4.31$ 5.74$ 4.78$ 4.53$
Low Growth_High Prices 2023-2024 Oct 5.16$ 5.79$ 5.16$ 5.16$ 5.16$ 5.09$ 5.09$ 5.79$ 5.33$ 5.29$
Low Growth_High Prices 2024-2025 Nov 4.82$ 5.17$ 4.82$ 4.82$ 4.82$ 4.75$ 4.75$ 5.17$ 4.89$ 4.89$
Low Growth_High Prices 2024-2025 Dec 6.38$ 6.63$ 6.38$ 6.38$ 6.38$ 6.30$ 6.21$ 6.62$ 6.37$ 6.43$
Low Growth_High Prices 2024-2025 Jan 7.86$ 7.86$ 7.86$ 7.86$ 7.86$ 7.76$ 7.76$ 7.76$ 7.76$ 7.86$
Low Growth_High Prices 2024-2025 Feb 8.18$ 8.28$ 8.16$ 8.16$ 8.16$ 7.81$ 8.07$ 7.81$ 7.90$ 8.19$
Low Growth_High Prices 2024-2025 Mar 8.24$ 8.25$ 8.24$ 8.24$ 8.24$ 7.99$ 8.13$ 8.02$ 8.05$ 8.24$
Low Growth_High Prices 2024-2025 Apr 4.81$ 5.77$ 4.81$ 4.81$ 4.81$ 4.75$ 4.75$ 5.77$ 5.09$ 5.01$
Low Growth_High Prices 2024-2025 May 4.91$ 5.68$ 4.91$ 4.91$ 4.91$ 4.84$ 4.84$ 5.68$ 5.12$ 5.07$
Low Growth_High Prices 2024-2025 Jun 5.22$ 5.68$ 5.22$ 5.22$ 5.22$ 5.15$ 5.15$ 5.68$ 5.33$ 5.31$
Low Growth_High Prices 2024-2025 Jul 4.92$ 5.68$ 4.92$ 4.92$ 4.92$ 4.85$ 4.85$ 5.68$ 5.13$ 5.07$
Low Growth_High Prices 2024-2025 Aug 5.01$ 5.68$ 5.01$ 5.01$ 5.01$ 4.95$ 4.95$ 5.68$ 5.19$ 5.15$
Low Growth_High Prices 2024-2025 Sep 4.39$ 5.13$ 4.39$ 4.39$ 4.39$ 4.33$ 4.33$ 5.68$ 4.78$ 4.54$
Low Growth_High Prices 2024-2025 Oct 5.19$ 5.70$ 5.19$ 5.19$ 5.19$ 5.12$ 5.12$ 5.70$ 5.31$ 5.29$
Low Growth_High Prices 2025-2026 Nov 4.84$ 5.05$ 4.84$ 4.84$ 4.84$ 4.77$ 4.77$ 5.05$ 4.86$ 4.88$
Low Growth_High Prices 2025-2026 Dec 6.37$ 6.68$ 6.37$ 6.37$ 6.37$ 6.27$ 6.18$ 6.67$ 6.37$ 6.43$
Low Growth_High Prices 2025-2026 Jan 7.79$ 7.79$ 7.79$ 7.79$ 7.79$ 7.69$ 7.69$ 7.69$ 7.69$ 7.79$
Low Growth_High Prices 2025-2026 Feb 8.11$ 8.23$ 8.08$ 8.08$ 8.08$ 7.75$ 8.01$ 7.75$ 7.83$ 8.12$
Low Growth_High Prices 2025-2026 Mar 8.12$ 8.15$ 8.11$ 8.11$ 8.11$ 7.89$ 8.01$ 7.95$ 7.95$ 8.12$
Low Growth_High Prices 2025-2026 Apr 4.84$ 5.74$ 4.84$ 4.84$ 4.84$ 4.78$ 4.78$ 5.74$ 5.10$ 5.02$
Low Growth_High Prices 2025-2026 May 4.92$ 5.65$ 4.92$ 4.92$ 4.92$ 4.85$ 4.85$ 5.65$ 5.12$ 5.07$
Low Growth_High Prices 2025-2026 Jun 5.22$ 5.65$ 5.22$ 5.22$ 5.22$ 5.15$ 5.15$ 5.65$ 5.32$ 5.31$
Low Growth_High Prices 2025-2026 Jul 4.94$ 5.65$ 4.94$ 4.94$ 4.94$ 4.87$ 4.87$ 5.65$ 5.13$ 5.08$
Low Growth_High Prices 2025-2026 Aug 5.06$ 5.66$ 5.06$ 5.06$ 5.06$ 4.99$ 4.99$ 5.66$ 5.21$ 5.18$
Low Growth_High Prices 2025-2026 Sep 4.38$ 5.14$ 4.38$ 4.38$ 4.38$ 4.32$ 4.32$ 5.66$ 4.77$ 4.53$
Low Growth_High Prices 2025-2026 Oct 5.19$ 5.66$ 5.19$ 5.19$ 5.19$ 5.12$ 5.12$ 5.66$ 5.30$ 5.29$ Low Growth_High Prices 2026-2027 Nov 4.89$ 5.04$ 4.89$ 4.89$ 4.89$ 4.83$ 4.83$ 5.04$ 4.90$ 4.92$ Low Growth_High Prices 2026-2027 Dec 6.31$ 6.80$ 6.31$ 6.31$ 6.31$ 6.19$ 6.09$ 6.79$ 6.36$ 6.41$ Low Growth_High Prices 2026-2027 Jan 7.72$ 7.72$ 7.72$ 7.72$ 7.72$ 7.62$ 7.62$ 7.62$ 7.62$ 7.72$ Low Growth_High Prices 2026-2027 Feb 8.04$ 8.18$ 7.94$ 7.94$ 7.94$ 7.68$ 7.93$ 7.68$ 7.76$ 8.00$ Low Growth_High Prices 2026-2027 Mar 7.51$ 7.69$ 7.51$ 7.51$ 7.51$ 7.41$ 7.41$ 7.63$ 7.49$ 7.55$ Low Growth_High Prices 2026-2027 Apr 4.89$ 5.74$ 4.89$ 4.89$ 4.89$ 4.82$ 4.82$ 5.74$ 5.13$ 5.06$ Low Growth_High Prices 2026-2027 May 4.93$ 5.65$ 4.93$ 4.93$ 4.93$ 4.87$ 4.87$ 5.65$ 5.13$ 5.08$ Low Growth_High Prices 2026-2027 Jun 5.28$ 5.65$ 5.28$ 5.28$ 5.28$ 5.21$ 5.21$ 5.65$ 5.36$ 5.36$ Low Growth_High Prices 2026-2027 Jul 5.00$ 5.65$ 5.00$ 5.00$ 5.00$ 4.93$ 4.93$ 5.65$ 5.17$ 5.13$ Low Growth_High Prices 2026-2027 Aug 5.11$ 5.65$ 5.11$ 5.11$ 5.11$ 5.04$ 5.04$ 5.65$ 5.24$ 5.22$ Low Growth_High Prices 2026-2027 Sep 4.56$ 4.99$ 4.56$ 4.56$ 4.56$ 4.49$ 4.49$ 5.65$ 4.88$ 4.64$ Low Growth_High Prices 2026-2027 Oct 5.37$ 5.78$ 5.37$ 5.37$ 5.37$ 5.30$ 5.30$ 5.78$ 5.46$ 5.45$ Low Growth_High Prices 2027-2028 Nov 5.02$ 5.19$ 5.02$ 5.02$ 5.02$ 4.96$ 4.96$ 5.19$ 5.03$ 5.06$ Low Growth_High Prices 2027-2028 Dec 6.48$ 6.96$ 6.48$ 6.48$ 6.48$ 6.40$ 6.30$ 6.96$ 6.56$ 6.58$ Low Growth_High Prices 2027-2028 Jan 8.00$ 8.00$ 8.00$ 8.00$ 8.00$ 7.90$ 7.90$ 7.90$ 7.90$ 8.00$ Low Growth_High Prices 2027-2028 Feb 8.32$ 8.36$ 8.23$ 8.23$ 8.23$ 7.95$ 8.21$ 7.95$ 8.04$ 8.27$ Low Growth_High Prices 2027-2028 Mar 8.07$ 8.20$ 8.07$ 8.07$ 8.07$ 7.96$ 7.97$ 8.13$ 8.02$ 8.10$ Low Growth_High Prices 2027-2028 Apr 5.10$ 5.78$ 5.10$ 5.10$ 5.10$ 5.03$ 5.03$ 5.78$ 5.28$ 5.23$ Low Growth_High Prices 2027-2028 May 5.13$ 5.70$ 5.13$ 5.13$ 5.13$ 5.06$ 5.06$ 5.70$ 5.27$ 5.24$ Low Growth_High Prices 2027-2028 Jun 5.46$ 5.70$ 5.46$ 5.46$ 5.46$ 5.39$ 5.39$ 5.70$ 5.49$ 5.51$
Low Growth_High Prices 2027-2028 Jul 5.17$ 5.70$ 5.17$ 5.17$ 5.17$ 5.10$ 5.10$ 5.70$ 5.30$ 5.27$
Low Growth_High Prices 2027-2028 Aug 5.25$ 5.70$ 5.25$ 5.25$ 5.25$ 5.18$ 5.18$ 5.70$ 5.35$ 5.34$
Low Growth_High Prices 2027-2028 Sep 4.65$ 4.98$ 4.65$ 4.65$ 4.65$ 4.59$ 4.59$ 5.70$ 4.96$ 4.72$
Low Growth_High Prices 2027-2028 Oct 5.48$ 5.79$ 5.48$ 5.48$ 5.48$ 5.41$ 5.41$ 5.79$ 5.53$ 5.54$
Low Growth_High Prices 2028-2029 Nov 5.08$ 5.30$ 5.08$ 5.08$ 5.08$ 5.01$ 5.01$ 5.30$ 5.11$ 5.12$
Low Growth_High Prices 2028-2029 Dec 6.59$ 6.95$ 6.59$ 6.59$ 6.59$ 6.52$ 6.43$ 6.95$ 6.63$ 6.66$
Low Growth_High Prices 2028-2029 Jan 8.11$ 8.11$ 8.11$ 8.11$ 8.11$ 8.00$ 8.00$ 8.00$ 8.00$ 8.11$
Low Growth_High Prices 2028-2029 Feb 8.42$ 8.46$ 8.32$ 8.32$ 8.32$ 8.06$ 8.31$ 8.06$ 8.14$ 8.37$
Low Growth_High Prices 2028-2029 Mar 7.98$ 8.09$ 7.98$ 7.98$ 7.98$ 7.87$ 7.87$ 8.03$ 7.93$ 8.00$
Low Growth_High Prices 2028-2029 Apr 5.16$ 5.85$ 5.16$ 5.16$ 5.16$ 5.09$ 5.09$ 5.85$ 5.34$ 5.30$
Low Growth_High Prices 2028-2029 May 5.24$ 5.73$ 5.24$ 5.24$ 5.24$ 5.16$ 5.16$ 5.73$ 5.35$ 5.33$
Low Growth_High Prices 2028-2029 Jun 5.56$ 5.73$ 5.56$ 5.56$ 5.56$ 5.48$ 5.48$ 5.73$ 5.56$ 5.59$
Low Growth_High Prices 2028-2029 Jul 5.22$ 5.73$ 5.22$ 5.22$ 5.22$ 5.15$ 5.15$ 5.73$ 5.34$ 5.32$
Low Growth_High Prices 2028-2029 Aug 5.32$ 5.73$ 5.32$ 5.32$ 5.32$ 5.25$ 5.25$ 5.73$ 5.41$ 5.40$
Low Growth_High Prices 2028-2029 Sep 4.72$ 5.03$ 4.72$ 4.72$ 4.72$ 4.65$ 4.65$ 5.73$ 5.01$ 4.78$
Low Growth_High Prices 2028-2029 Oct 5.54$ 5.84$ 5.54$ 5.54$ 5.54$ 5.46$ 5.46$ 5.84$ 5.59$ 5.60$
1/ Avoided costs are before Environmental Externalities adder.
Monthly Avoided Costs 1/
2014$
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 188 of 648
APPENDIX 5.4: LOW GROWTH – HIGH PRICE MONTHLY DETAIL

Scenario Gas Year Month Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual
Low Growth_High Prices 2029-2030 Nov 5.13$ 5.45$ 5.13$ 5.13$ 5.13$ 5.06$ 5.06$ 5.45$ 5.19$ 5.19$
Low Growth_High Prices 2029-2030 Dec 6.64$ 7.04$ 6.64$ 6.64$ 6.64$ 6.57$ 6.47$ 7.04$ 6.69$ 6.72$
Low Growth_High Prices 2029-2030 Jan 8.16$ 8.16$ 8.16$ 8.16$ 8.16$ 8.06$ 8.06$ 8.06$ 8.06$ 8.16$
Low Growth_High Prices 2029-2030 Feb 8.52$ 8.56$ 8.49$ 8.49$ 8.49$ 8.12$ 8.41$ 8.12$ 8.22$ 8.51$
Low Growth_High Prices 2029-2030 Mar 8.51$ 8.53$ 8.50$ 8.50$ 8.50$ 8.28$ 8.40$ 8.33$ 8.34$ 8.51$
Low Growth_High Prices 2029-2030 Apr 5.24$ 5.89$ 5.24$ 5.24$ 5.24$ 5.17$ 5.17$ 5.89$ 5.41$ 5.37$
Low Growth_High Prices 2029-2030 May 5.26$ 5.76$ 5.26$ 5.26$ 5.26$ 5.19$ 5.19$ 5.76$ 5.38$ 5.36$
Low Growth_High Prices 2029-2030 Jun 5.62$ 5.77$ 5.62$ 5.62$ 5.62$ 5.54$ 5.54$ 5.77$ 5.62$ 5.65$
Low Growth_High Prices 2029-2030 Jul 5.32$ 5.75$ 5.32$ 5.32$ 5.32$ 5.25$ 5.25$ 5.77$ 5.42$ 5.41$
Low Growth_High Prices 2029-2030 Aug 5.41$ 5.77$ 5.41$ 5.41$ 5.41$ 5.33$ 5.33$ 5.77$ 5.48$ 5.48$
Low Growth_High Prices 2029-2030 Sep 4.79$ 5.18$ 4.79$ 4.79$ 4.79$ 4.72$ 4.72$ 5.77$ 5.07$ 4.87$
Low Growth_High Prices 2029-2030 Oct 5.61$ 5.99$ 5.61$ 5.61$ 5.61$ 5.54$ 5.54$ 5.99$ 5.69$ 5.69$
Low Growth_High Prices 2030-2031 Nov 5.17$ 5.54$ 5.17$ 5.17$ 5.17$ 5.10$ 5.10$ 5.54$ 5.25$ 5.25$
Low Growth_High Prices 2030-2031 Dec 6.73$ 7.04$ 6.74$ 6.74$ 6.74$ 6.68$ 6.58$ 7.04$ 6.77$ 6.80$
Low Growth_High Prices 2030-2031 Jan 8.28$ 8.28$ 8.28$ 8.28$ 8.28$ 8.17$ 8.17$ 8.17$ 8.17$ 8.28$
Low Growth_High Prices 2030-2031 Feb 8.63$ 8.65$ 8.60$ 8.60$ 8.60$ 8.23$ 8.52$ 8.23$ 8.33$ 8.61$
Low Growth_High Prices 2030-2031 Mar 8.59$ 8.61$ 8.58$ 8.58$ 8.58$ 8.38$ 8.48$ 8.44$ 8.43$ 8.59$
Low Growth_High Prices 2030-2031 Apr 5.38$ 5.90$ 5.38$ 5.38$ 5.38$ 5.30$ 5.30$ 5.90$ 5.50$ 5.48$
Low Growth_High Prices 2030-2031 May 5.40$ 5.81$ 5.40$ 5.40$ 5.40$ 5.33$ 5.33$ 5.81$ 5.49$ 5.48$
Low Growth_High Prices 2030-2031 Jun 5.73$ 5.81$ 5.73$ 5.73$ 5.73$ 5.65$ 5.65$ 5.81$ 5.70$ 5.74$
Low Growth_High Prices 2030-2031 Jul 5.39$ 5.81$ 5.39$ 5.39$ 5.39$ 5.31$ 5.31$ 5.81$ 5.48$ 5.47$
Low Growth_High Prices 2030-2031 Aug 5.48$ 5.81$ 5.48$ 5.48$ 5.48$ 5.40$ 5.40$ 5.81$ 5.54$ 5.54$
Low Growth_High Prices 2030-2031 Sep 4.87$ 5.20$ 4.87$ 4.87$ 4.87$ 4.81$ 4.81$ 5.81$ 5.14$ 4.94$
Low Growth_High Prices 2030-2031 Oct 5.71$ 6.01$ 5.71$ 5.71$ 5.71$ 5.63$ 5.63$ 6.01$ 5.76$ 5.77$
Low Growth_High Prices 2031-2032 Nov 5.22$ 5.61$ 5.22$ 5.22$ 5.22$ 5.15$ 5.15$ 5.61$ 5.30$ 5.30$
Low Growth_High Prices 2031-2032 Dec 6.80$ 7.06$ 6.80$ 6.80$ 6.80$ 6.75$ 6.66$ 7.06$ 6.82$ 6.85$
Low Growth_High Prices 2031-2032 Jan 8.33$ 8.33$ 8.33$ 8.33$ 8.33$ 8.22$ 8.22$ 8.22$ 8.22$ 8.33$
Low Growth_High Prices 2031-2032 Feb 8.67$ 8.70$ 8.60$ 8.60$ 8.60$ 8.28$ 8.56$ 8.28$ 8.37$ 8.63$
Low Growth_High Prices 2031-2032 Mar 7.51$ 7.58$ 7.51$ 7.51$ 7.51$ 7.41$ 7.41$ 7.52$ 7.45$ 7.52$
Low Growth_High Prices 2031-2032 Apr 5.47$ 5.96$ 5.47$ 5.47$ 5.47$ 5.40$ 5.40$ 5.96$ 5.58$ 5.57$
Low Growth_High Prices 2031-2032 May 5.48$ 5.81$ 5.48$ 5.48$ 5.48$ 5.41$ 5.41$ 5.81$ 5.54$ 5.55$
Low Growth_High Prices 2031-2032 Jun 5.82$ 5.81$ 5.81$ 5.81$ 5.81$ 5.74$ 5.74$ 5.81$ 5.76$ 5.81$
Low Growth_High Prices 2031-2032 Jul 5.45$ 5.81$ 5.45$ 5.45$ 5.45$ 5.37$ 5.37$ 5.81$ 5.52$ 5.52$
Low Growth_High Prices 2031-2032 Aug 5.59$ 5.81$ 5.59$ 5.59$ 5.59$ 5.52$ 5.52$ 5.81$ 5.62$ 5.64$
Low Growth_High Prices 2031-2032 Sep 4.93$ 5.26$ 4.93$ 4.93$ 4.93$ 4.87$ 4.87$ 5.81$ 5.18$ 5.00$
Low Growth_High Prices 2031-2032 Oct 5.76$ 6.10$ 5.76$ 5.76$ 5.76$ 5.69$ 5.69$ 6.10$ 5.82$ 5.83$
Low Growth_High Prices 2032-2033 Nov 5.27$ 5.68$ 5.27$ 5.27$ 5.27$ 5.20$ 5.20$ 5.68$ 5.36$ 5.36$
Low Growth_High Prices 2032-2033 Dec 6.89$ 7.14$ 6.89$ 6.89$ 6.89$ 6.84$ 6.75$ 7.14$ 6.91$ 6.94$
Low Growth_High Prices 2032-2033 Jan 8.43$ 8.43$ 8.43$ 8.43$ 8.43$ 7.59$ 8.32$ 7.59$ 7.83$ 8.43$
Low Growth_High Prices 2032-2033 Feb 8.77$ 8.79$ 8.69$ 8.69$ 8.69$ 7.78$ 8.66$ 7.78$ 8.07$ 8.73$ Low Growth_High Prices 2032-2033 Mar 7.69$ 7.78$ 7.69$ 7.69$ 7.69$ 7.59$ 7.59$ 7.72$ 7.64$ 7.71$ Low Growth_High Prices 2032-2033 Apr 5.54$ 6.08$ 5.54$ 5.54$ 5.54$ 5.47$ 5.47$ 6.08$ 5.67$ 5.65$ Low Growth_High Prices 2032-2033 May 5.54$ 5.85$ 5.54$ 5.54$ 5.54$ 5.46$ 5.46$ 5.85$ 5.59$ 5.60$ Low Growth_High Prices 2032-2033 Jun 5.88$ 5.85$ 5.85$ 5.85$ 5.85$ 5.80$ 5.80$ 5.85$ 5.82$ 5.85$ Low Growth_High Prices 2032-2033 Jul 5.57$ 5.85$ 5.57$ 5.57$ 5.57$ 5.50$ 5.50$ 5.85$ 5.61$ 5.63$ Low Growth_High Prices 2032-2033 Aug 5.70$ 5.85$ 5.70$ 5.70$ 5.70$ 5.62$ 5.62$ 5.85$ 5.70$ 5.73$ Low Growth_High Prices 2032-2033 Sep 5.01$ 5.34$ 5.01$ 5.01$ 5.01$ 4.94$ 4.94$ 5.85$ 5.24$ 5.07$ Low Growth_High Prices 2032-2033 Oct 5.82$ 6.18$ 5.82$ 5.82$ 5.82$ 5.74$ 5.74$ 6.18$ 5.89$ 5.89$ Low Growth_High Prices 2033-2034 Nov 5.33$ 5.75$ 5.33$ 5.33$ 5.33$ 5.25$ 5.25$ 5.75$ 5.42$ 5.41$ Low Growth_High Prices 2033-2034 Dec 6.97$ 7.23$ 6.97$ 6.97$ 6.97$ 6.90$ 6.80$ 7.23$ 6.98$ 7.02$ Low Growth_High Prices 2033-2034 Jan 8.48$ 8.48$ 8.48$ 8.48$ 8.48$ 7.48$ 8.37$ 7.48$ 7.78$ 8.48$ Low Growth_High Prices 2033-2034 Feb 8.83$ 8.85$ 8.75$ 8.75$ 8.75$ 7.70$ 8.71$ 7.70$ 8.04$ 8.79$ Low Growth_High Prices 2033-2034 Mar 7.55$ 7.71$ 7.55$ 7.55$ 7.55$ 7.45$ 7.45$ 7.65$ 7.52$ 7.58$ Low Growth_High Prices 2033-2034 Apr 5.55$ 6.18$ 5.55$ 5.55$ 5.55$ 5.48$ 5.48$ 6.18$ 5.71$ 5.68$ Low Growth_High Prices 2033-2034 May 5.57$ 5.99$ 5.57$ 5.57$ 5.57$ 5.49$ 5.49$ 5.99$ 5.66$ 5.65$ Low Growth_High Prices 2033-2034 Jun 5.91$ 5.99$ 5.91$ 5.91$ 5.91$ 5.83$ 5.83$ 5.99$ 5.88$ 5.92$ Low Growth_High Prices 2033-2034 Jul 5.58$ 5.96$ 5.58$ 5.58$ 5.58$ 5.50$ 5.50$ 5.99$ 5.67$ 5.66$ Low Growth_High Prices 2033-2034 Aug 5.67$ 6.00$ 5.67$ 5.67$ 5.67$ 5.60$ 5.60$ 6.00$ 5.73$ 5.74$
Low Growth_High Prices 2033-2034 Sep 5.05$ 5.44$ 5.05$ 5.05$ 5.05$ 4.99$ 4.99$ 6.00$ 5.32$ 5.13$
Low Growth_High Prices 2033-2034 Oct 5.88$ 6.24$ 5.88$ 5.88$ 5.88$ 5.80$ 5.80$ 6.24$ 5.95$ 5.95$
Low Growth_High Prices 2034-2035 Nov 5.37$ 5.82$ 5.37$ 5.37$ 5.37$ 5.30$ 5.30$ 5.82$ 5.47$ 5.46$
Low Growth_High Prices 2034-2035 Dec 7.03$ 7.27$ 7.03$ 7.03$ 7.03$ 6.96$ 6.86$ 7.27$ 7.03$ 7.08$
Low Growth_High Prices 2034-2035 Jan 8.57$ 8.57$ 8.57$ 8.57$ 8.57$ 8.32$ 8.46$ 8.32$ 8.37$ 8.57$
Low Growth_High Prices 2034-2035 Feb 8.89$ 8.90$ 8.79$ 8.79$ 8.79$ 8.42$ 8.77$ 8.42$ 8.54$ 8.83$
Low Growth_High Prices 2034-2035 Mar 8.43$ 8.49$ 8.43$ 8.43$ 8.43$ 8.32$ 8.32$ 8.43$ 8.36$ 8.44$
Low Growth_High Prices 2034-2035 Apr 5.75$ 6.17$ 5.75$ 5.75$ 5.75$ 5.67$ 5.67$ 6.17$ 5.84$ 5.83$
Low Growth_High Prices 2034-2035 May 5.72$ 5.93$ 5.72$ 5.72$ 5.72$ 5.65$ 5.65$ 5.93$ 5.74$ 5.76$
Low Growth_High Prices 2034-2035 Jun 5.93$ 5.93$ 5.93$ 5.93$ 5.93$ 5.85$ 5.85$ 5.93$ 5.87$ 5.93$
Low Growth_High Prices 2034-2035 Jul 5.58$ 5.73$ 5.58$ 5.58$ 5.58$ 5.51$ 5.51$ 5.73$ 5.58$ 5.61$
Low Growth_High Prices 2034-2035 Aug 5.75$ 5.73$ 5.73$ 5.73$ 5.73$ 5.68$ 5.68$ 5.73$ 5.69$ 5.74$
Low Growth_High Prices 2034-2035 Sep 5.11$ 5.11$ 5.11$ 5.11$ 5.11$ 5.04$ 5.04$ 5.11$ 5.07$ 5.11$
Low Growth_High Prices 2034-2035 Oct 5.91$ 6.31$ 5.91$ 5.91$ 5.91$ 5.83$ 5.83$ 6.31$ 5.99$ 5.99$
1/ Avoided costs are before Environmental Externalities adder.
Monthly Avoided Costs 1/
2014$
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 189 of 648
APPENDIX 5.4: EXPECTED MONTHLY DETAIL

Scenario Gas Year Month Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual
Expected Case 2015-2016 Nov 1.96$ 2.10$ 1.96$ 1.96$ 1.96$ 1.93$ 1.93$ 2.10$ 1.99$ 1.99$
Expected Case 2015-2016 Dec 1.78$ 2.07$ 1.78$ 1.78$ 1.78$ 2.07$ 1.65$ 2.07$ 1.93$ 1.84$
Expected Case 2015-2016 Jan 2.11$ 2.15$ 2.11$ 2.11$ 2.11$ 2.11$ 2.08$ 2.11$ 2.10$ 2.12$
Expected Case 2015-2016 Feb 1.92$ 2.20$ 1.92$ 1.92$ 1.92$ 1.96$ 1.86$ 2.13$ 1.98$ 1.98$
Expected Case 2015-2016 Mar 1.83$ 2.11$ 1.83$ 1.83$ 1.83$ 1.80$ 1.80$ 2.11$ 1.90$ 1.88$
Expected Case 2015-2016 Apr 1.79$ 2.22$ 1.79$ 1.79$ 1.79$ 1.76$ 1.76$ 2.22$ 1.92$ 1.88$
Expected Case 2015-2016 May 1.78$ 2.11$ 1.78$ 1.78$ 1.78$ 1.75$ 1.75$ 2.11$ 1.87$ 1.84$
Expected Case 2015-2016 Jun 1.79$ 2.11$ 1.79$ 1.79$ 1.79$ 1.76$ 1.76$ 2.11$ 1.88$ 1.85$
Expected Case 2015-2016 Jul 1.83$ 2.11$ 1.83$ 1.83$ 1.83$ 1.80$ 1.80$ 2.11$ 1.90$ 1.89$
Expected Case 2015-2016 Aug 1.92$ 2.11$ 1.92$ 1.92$ 1.92$ 1.89$ 1.89$ 2.11$ 1.96$ 1.96$
Expected Case 2015-2016 Sep 1.92$ 2.11$ 1.92$ 1.92$ 1.92$ 1.88$ 1.88$ 2.11$ 1.96$ 1.95$
Expected Case 2015-2016 Oct 1.91$ 2.66$ 1.91$ 1.91$ 1.91$ 1.88$ 1.88$ 2.66$ 2.14$ 2.06$
Expected Case 2016-2017 Nov 2.08$ 2.93$ 2.08$ 2.08$ 2.08$ 2.10$ 2.05$ 2.93$ 2.36$ 2.25$
Expected Case 2016-2017 Dec 2.53$ 3.01$ 2.53$ 2.53$ 2.53$ 2.72$ 2.22$ 2.95$ 2.63$ 2.63$
Expected Case 2016-2017 Jan 2.47$ 2.97$ 2.47$ 2.47$ 2.47$ 2.86$ 2.39$ 2.94$ 2.73$ 2.57$
Expected Case 2016-2017 Feb 2.48$ 3.02$ 2.48$ 2.48$ 2.48$ 2.61$ 2.36$ 2.95$ 2.64$ 2.59$
Expected Case 2016-2017 Mar 2.31$ 2.94$ 2.31$ 2.31$ 2.31$ 2.27$ 2.27$ 2.94$ 2.49$ 2.43$
Expected Case 2016-2017 Apr 2.19$ 2.94$ 2.19$ 2.19$ 2.19$ 2.16$ 2.16$ 2.94$ 2.42$ 2.34$
Expected Case 2016-2017 May 2.17$ 2.94$ 2.17$ 2.17$ 2.17$ 2.14$ 2.14$ 2.94$ 2.40$ 2.32$
Expected Case 2016-2017 Jun 2.14$ 2.94$ 2.14$ 2.14$ 2.14$ 2.11$ 2.11$ 2.94$ 2.39$ 2.30$
Expected Case 2016-2017 Jul 2.17$ 2.94$ 2.17$ 2.17$ 2.17$ 2.14$ 2.14$ 2.94$ 2.41$ 2.33$
Expected Case 2016-2017 Aug 2.25$ 2.94$ 2.25$ 2.25$ 2.25$ 2.22$ 2.22$ 2.94$ 2.46$ 2.39$
Expected Case 2016-2017 Sep 2.23$ 2.94$ 2.23$ 2.23$ 2.23$ 2.19$ 2.19$ 2.94$ 2.44$ 2.37$
Expected Case 2016-2017 Oct 2.23$ 3.09$ 2.23$ 2.23$ 2.23$ 2.20$ 2.20$ 3.09$ 2.50$ 2.40$
Expected Case 2017-2018 Nov 2.46$ 3.40$ 2.46$ 2.46$ 2.46$ 2.47$ 2.42$ 3.40$ 2.76$ 2.64$
Expected Case 2017-2018 Dec 2.94$ 3.43$ 2.94$ 2.94$ 2.94$ 3.06$ 2.54$ 3.41$ 3.00$ 3.04$
Expected Case 2017-2018 Jan 3.29$ 3.45$ 3.29$ 3.29$ 3.29$ 3.42$ 3.24$ 3.42$ 3.36$ 3.32$
Expected Case 2017-2018 Feb 3.23$ 3.51$ 3.23$ 3.23$ 3.23$ 3.31$ 3.18$ 3.42$ 3.30$ 3.28$
Expected Case 2017-2018 Mar 2.92$ 3.40$ 2.92$ 2.92$ 2.92$ 2.87$ 2.87$ 3.40$ 3.05$ 3.01$
Expected Case 2017-2018 Apr 2.70$ 3.52$ 2.70$ 2.70$ 2.70$ 2.66$ 2.66$ 3.52$ 2.95$ 2.87$
Expected Case 2017-2018 May 2.64$ 3.40$ 2.64$ 2.64$ 2.64$ 2.60$ 2.60$ 3.40$ 2.86$ 2.79$
Expected Case 2017-2018 Jun 2.59$ 3.40$ 2.59$ 2.59$ 2.59$ 2.55$ 2.55$ 3.40$ 2.83$ 2.75$
Expected Case 2017-2018 Jul 2.64$ 3.40$ 2.64$ 2.64$ 2.64$ 2.60$ 2.60$ 3.40$ 2.87$ 2.79$
Expected Case 2017-2018 Aug 2.68$ 3.40$ 2.68$ 2.68$ 2.68$ 2.64$ 2.64$ 3.40$ 2.89$ 2.82$
Expected Case 2017-2018 Sep 2.72$ 3.40$ 2.72$ 2.72$ 2.72$ 2.68$ 2.68$ 3.40$ 2.92$ 2.86$
Expected Case 2017-2018 Oct 2.73$ 3.72$ 2.73$ 2.73$ 2.73$ 2.69$ 2.69$ 3.72$ 3.03$ 2.93$
Expected Case 2018-2019 Nov 2.98$ 3.50$ 2.98$ 2.98$ 2.98$ 2.99$ 2.94$ 3.50$ 3.14$ 3.09$
Expected Case 2018-2019 Dec 3.31$ 3.61$ 3.31$ 3.31$ 3.31$ 3.53$ 3.07$ 3.53$ 3.38$ 3.37$
Expected Case 2018-2019 Jan 3.19$ 3.55$ 3.19$ 3.19$ 3.19$ 3.51$ 3.14$ 3.51$ 3.39$ 3.27$
Expected Case 2018-2019 Feb 3.16$ 3.61$ 3.16$ 3.16$ 3.16$ 3.30$ 3.10$ 3.51$ 3.30$ 3.25$
Expected Case 2018-2019 Mar 2.70$ 3.50$ 2.70$ 2.70$ 2.70$ 2.66$ 2.66$ 3.50$ 2.94$ 2.86$
Expected Case 2018-2019 Apr 2.50$ 3.52$ 2.50$ 2.50$ 2.50$ 2.46$ 2.46$ 3.52$ 2.81$ 2.70$
Expected Case 2018-2019 May 2.50$ 3.50$ 2.50$ 2.50$ 2.50$ 2.46$ 2.46$ 3.50$ 2.81$ 2.70$
Expected Case 2018-2019 Jun 2.53$ 3.50$ 2.53$ 2.53$ 2.53$ 2.50$ 2.50$ 3.50$ 2.83$ 2.73$
Expected Case 2018-2019 Jul 2.59$ 3.50$ 2.59$ 2.59$ 2.59$ 2.55$ 2.55$ 3.50$ 2.87$ 2.77$
Expected Case 2018-2019 Aug 2.64$ 3.50$ 2.64$ 2.64$ 2.64$ 2.60$ 2.60$ 3.50$ 2.90$ 2.81$
Expected Case 2018-2019 Sep 2.74$ 3.50$ 2.74$ 2.74$ 2.74$ 2.70$ 2.70$ 3.50$ 2.96$ 2.89$
Expected Case 2018-2019 Oct 2.78$ 3.71$ 2.78$ 2.78$ 2.78$ 2.73$ 2.73$ 3.71$ 3.06$ 2.96$ Expected Case 2019-2020 Nov 3.05$ 3.58$ 3.05$ 3.05$ 3.05$ 3.10$ 3.01$ 3.58$ 3.23$ 3.16$ Expected Case 2019-2020 Dec 3.38$ 3.70$ 3.38$ 3.38$ 3.38$ 3.61$ 3.16$ 3.62$ 3.46$ 3.44$ Expected Case 2019-2020 Jan 3.27$ 3.64$ 3.27$ 3.27$ 3.27$ 3.61$ 3.22$ 3.61$ 3.48$ 3.35$ Expected Case 2019-2020 Feb 3.25$ 3.69$ 3.25$ 3.25$ 3.25$ 3.49$ 3.20$ 3.61$ 3.43$ 3.33$ Expected Case 2019-2020 Mar 2.94$ 3.58$ 2.94$ 2.94$ 2.94$ 2.89$ 2.89$ 3.58$ 3.12$ 3.06$ Expected Case 2019-2020 Apr 2.64$ 3.62$ 2.64$ 2.64$ 2.64$ 2.60$ 2.60$ 3.62$ 2.94$ 2.83$ Expected Case 2019-2020 May 2.64$ 3.58$ 2.64$ 2.64$ 2.64$ 2.60$ 2.60$ 3.58$ 2.93$ 2.83$ Expected Case 2019-2020 Jun 2.63$ 3.58$ 2.63$ 2.63$ 2.63$ 2.59$ 2.59$ 3.58$ 2.92$ 2.82$ Expected Case 2019-2020 Jul 2.65$ 3.58$ 2.65$ 2.65$ 2.65$ 2.61$ 2.61$ 3.58$ 2.94$ 2.84$ Expected Case 2019-2020 Aug 2.68$ 3.58$ 2.68$ 2.68$ 2.68$ 2.64$ 2.64$ 3.58$ 2.96$ 2.86$ Expected Case 2019-2020 Sep 2.74$ 3.58$ 2.74$ 2.74$ 2.74$ 2.70$ 2.70$ 3.58$ 2.99$ 2.91$ Expected Case 2019-2020 Oct 2.73$ 3.75$ 2.73$ 2.73$ 2.73$ 2.69$ 2.69$ 3.75$ 3.04$ 2.93$ Expected Case 2020-2021 Nov 3.15$ 3.74$ 3.15$ 3.15$ 3.15$ 3.24$ 3.11$ 3.74$ 3.36$ 3.27$ Expected Case 2020-2021 Dec 3.50$ 3.81$ 3.50$ 3.50$ 3.50$ 3.73$ 3.26$ 3.75$ 3.58$ 3.56$ Expected Case 2020-2021 Jan 3.40$ 3.86$ 3.40$ 3.40$ 3.40$ 3.75$ 3.31$ 3.75$ 3.60$ 3.49$ Expected Case 2020-2021 Feb 3.42$ 3.83$ 3.42$ 3.42$ 3.42$ 3.66$ 3.37$ 3.77$ 3.60$ 3.50$ Expected Case 2020-2021 Mar 3.07$ 3.74$ 3.07$ 3.07$ 3.07$ 3.03$ 3.03$ 3.74$ 3.27$ 3.21$ Expected Case 2020-2021 Apr 2.78$ 3.74$ 2.78$ 2.78$ 2.78$ 2.74$ 2.74$ 3.74$ 3.07$ 2.97$ Expected Case 2020-2021 May 2.79$ 3.74$ 2.79$ 2.79$ 2.79$ 2.75$ 2.75$ 3.74$ 3.08$ 2.98$ Expected Case 2020-2021 Jun 2.79$ 3.74$ 2.79$ 2.79$ 2.79$ 2.75$ 2.75$ 3.74$ 3.08$ 2.98$
Expected Case 2020-2021 Jul 2.73$ 3.75$ 2.73$ 2.73$ 2.73$ 2.69$ 2.69$ 3.75$ 3.04$ 2.93$
Expected Case 2020-2021 Aug 2.77$ 3.75$ 2.77$ 2.77$ 2.77$ 2.73$ 2.73$ 3.75$ 3.07$ 2.97$
Expected Case 2020-2021 Sep 3.02$ 3.75$ 3.02$ 3.02$ 3.02$ 2.98$ 2.98$ 3.75$ 3.23$ 3.17$
Expected Case 2020-2021 Oct 3.04$ 3.83$ 3.04$ 3.04$ 3.04$ 3.00$ 3.00$ 3.83$ 3.28$ 3.20$
Expected Case 2021-2022 Nov 3.31$ 3.85$ 3.31$ 3.31$ 3.31$ 3.40$ 3.27$ 3.85$ 3.51$ 3.42$
Expected Case 2021-2022 Dec 3.88$ 3.97$ 3.88$ 3.88$ 3.88$ 3.86$ 3.39$ 3.86$ 3.70$ 3.90$
Expected Case 2021-2022 Jan 3.65$ 4.01$ 3.65$ 3.65$ 3.65$ 3.87$ 3.43$ 3.87$ 3.72$ 3.72$
Expected Case 2021-2022 Feb 3.56$ 3.98$ 3.56$ 3.56$ 3.56$ 3.78$ 3.48$ 3.88$ 3.71$ 3.64$
Expected Case 2021-2022 Mar 3.12$ 3.85$ 3.12$ 3.12$ 3.12$ 3.07$ 3.07$ 3.85$ 3.33$ 3.26$
Expected Case 2021-2022 Apr 2.85$ 3.93$ 2.85$ 2.85$ 2.85$ 2.81$ 2.81$ 3.93$ 3.18$ 3.07$
Expected Case 2021-2022 May 2.87$ 3.85$ 2.87$ 2.87$ 2.87$ 2.83$ 2.83$ 3.85$ 3.17$ 3.07$
Expected Case 2021-2022 Jun 2.86$ 3.85$ 2.86$ 2.86$ 2.86$ 2.82$ 2.82$ 3.85$ 3.16$ 3.06$
Expected Case 2021-2022 Jul 2.86$ 3.85$ 2.86$ 2.86$ 2.86$ 2.82$ 2.82$ 3.85$ 3.16$ 3.06$
Expected Case 2021-2022 Aug 2.90$ 3.85$ 2.90$ 2.90$ 2.90$ 2.85$ 2.85$ 3.85$ 3.19$ 3.09$
Expected Case 2021-2022 Sep 2.95$ 3.85$ 2.95$ 2.95$ 2.95$ 2.91$ 2.91$ 3.85$ 3.22$ 3.13$
Expected Case 2021-2022 Oct 2.96$ 3.94$ 2.96$ 2.96$ 2.96$ 2.91$ 2.91$ 3.94$ 3.25$ 3.15$
1/ Avoided costs are before Environmental Externalities adder.
Monthly Avoided Costs 1/
2014$
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 190 of 648
APPENDIX 5.4: EXPECTED MONTHLY DETAIL

Scenario Gas Year Month Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual
Expected Case 2022-2023 Nov 3.23$ 3.86$ 3.23$ 3.23$ 3.23$ 3.32$ 3.18$ 3.86$ 3.45$ 3.35$
Expected Case 2022-2023 Dec 3.91$ 4.01$ 3.91$ 3.91$ 3.91$ 3.75$ 3.25$ 3.87$ 3.62$ 3.93$
Expected Case 2022-2023 Jan 3.72$ 4.03$ 3.72$ 3.72$ 3.72$ 3.67$ 3.21$ 3.86$ 3.58$ 3.78$
Expected Case 2022-2023 Feb 3.39$ 4.03$ 3.39$ 3.39$ 3.39$ 3.65$ 3.26$ 3.90$ 3.60$ 3.52$
Expected Case 2022-2023 Mar 2.97$ 3.86$ 2.97$ 2.97$ 2.97$ 2.93$ 2.93$ 3.86$ 3.24$ 3.15$
Expected Case 2022-2023 Apr 2.81$ 4.01$ 2.81$ 2.81$ 2.81$ 2.77$ 2.77$ 4.01$ 3.19$ 3.05$
Expected Case 2022-2023 May 2.87$ 3.86$ 2.87$ 2.87$ 2.87$ 2.83$ 2.83$ 3.86$ 3.17$ 3.07$
Expected Case 2022-2023 Jun 2.87$ 3.86$ 2.87$ 2.87$ 2.87$ 2.83$ 2.83$ 3.86$ 3.17$ 3.07$
Expected Case 2022-2023 Jul 2.88$ 3.86$ 2.88$ 2.88$ 2.88$ 2.84$ 2.84$ 3.86$ 3.18$ 3.08$
Expected Case 2022-2023 Aug 2.91$ 3.86$ 2.91$ 2.91$ 2.91$ 2.86$ 2.86$ 3.86$ 3.20$ 3.10$
Expected Case 2022-2023 Sep 3.10$ 3.86$ 3.10$ 3.10$ 3.10$ 3.06$ 3.06$ 3.86$ 3.32$ 3.25$
Expected Case 2022-2023 Oct 3.11$ 3.86$ 3.11$ 3.11$ 3.11$ 3.06$ 3.06$ 3.86$ 3.33$ 3.26$
Expected Case 2023-2024 Nov 3.52$ 3.93$ 3.52$ 3.52$ 3.52$ 3.61$ 3.47$ 3.93$ 3.67$ 3.60$
Expected Case 2023-2024 Dec 4.00$ 4.09$ 4.00$ 4.00$ 4.00$ 4.00$ 3.56$ 4.00$ 3.85$ 4.02$
Expected Case 2023-2024 Jan 3.67$ 4.08$ 3.67$ 3.67$ 3.67$ 3.99$ 3.55$ 3.99$ 3.85$ 3.75$
Expected Case 2023-2024 Feb 3.62$ 4.02$ 3.62$ 3.62$ 3.62$ 3.86$ 3.56$ 3.96$ 3.79$ 3.70$
Expected Case 2023-2024 Mar 3.29$ 3.92$ 3.29$ 3.29$ 3.29$ 3.24$ 3.24$ 3.92$ 3.47$ 3.42$
Expected Case 2023-2024 Apr 3.05$ 3.97$ 3.05$ 3.05$ 3.05$ 3.01$ 3.01$ 3.97$ 3.33$ 3.23$
Expected Case 2023-2024 May 3.06$ 3.93$ 3.06$ 3.06$ 3.06$ 3.01$ 3.01$ 3.93$ 3.32$ 3.23$
Expected Case 2023-2024 Jun 3.05$ 3.94$ 3.05$ 3.05$ 3.05$ 3.01$ 3.01$ 3.94$ 3.32$ 3.23$
Expected Case 2023-2024 Jul 3.16$ 3.94$ 3.16$ 3.16$ 3.16$ 3.11$ 3.11$ 3.94$ 3.39$ 3.32$
Expected Case 2023-2024 Aug 3.20$ 3.94$ 3.20$ 3.20$ 3.20$ 3.15$ 3.15$ 3.94$ 3.41$ 3.34$
Expected Case 2023-2024 Sep 3.32$ 3.94$ 3.32$ 3.32$ 3.32$ 3.28$ 3.28$ 3.94$ 3.50$ 3.45$
Expected Case 2023-2024 Oct 3.33$ 3.98$ 3.33$ 3.33$ 3.33$ 3.28$ 3.28$ 3.98$ 3.51$ 3.46$
Expected Case 2024-2025 Nov 3.80$ 4.09$ 3.80$ 3.80$ 3.80$ 3.85$ 3.75$ 4.09$ 3.89$ 3.86$
Expected Case 2024-2025 Dec 4.16$ 4.26$ 4.16$ 4.16$ 4.16$ 4.16$ 3.83$ 4.16$ 4.05$ 4.18$
Expected Case 2024-2025 Jan 3.91$ 4.26$ 3.91$ 3.91$ 3.91$ 4.15$ 3.86$ 4.15$ 4.05$ 3.98$
Expected Case 2024-2025 Feb 3.92$ 4.21$ 3.92$ 3.92$ 3.92$ 4.08$ 3.86$ 4.13$ 4.02$ 3.97$
Expected Case 2024-2025 Mar 3.55$ 4.09$ 3.55$ 3.55$ 3.55$ 3.50$ 3.50$ 4.09$ 3.69$ 3.66$
Expected Case 2024-2025 Apr 3.26$ 4.24$ 3.26$ 3.26$ 3.26$ 3.21$ 3.21$ 4.24$ 3.55$ 3.45$
Expected Case 2024-2025 May 3.35$ 4.09$ 3.35$ 3.35$ 3.35$ 3.30$ 3.30$ 4.09$ 3.56$ 3.49$
Expected Case 2024-2025 Jun 3.34$ 4.09$ 3.34$ 3.34$ 3.34$ 3.29$ 3.29$ 4.09$ 3.56$ 3.49$
Expected Case 2024-2025 Jul 3.42$ 4.09$ 3.42$ 3.42$ 3.42$ 3.37$ 3.37$ 4.09$ 3.61$ 3.56$
Expected Case 2024-2025 Aug 3.45$ 4.09$ 3.45$ 3.45$ 3.45$ 3.40$ 3.40$ 4.09$ 3.63$ 3.58$
Expected Case 2024-2025 Sep 3.59$ 4.09$ 3.59$ 3.59$ 3.59$ 3.54$ 3.54$ 4.09$ 3.72$ 3.69$
Expected Case 2024-2025 Oct 3.57$ 4.10$ 3.57$ 3.57$ 3.57$ 3.52$ 3.52$ 4.10$ 3.71$ 3.67$
Expected Case 2025-2026 Nov 4.04$ 4.10$ 4.04$ 4.04$ 4.04$ 4.02$ 3.98$ 4.10$ 4.03$ 4.05$
Expected Case 2025-2026 Dec 4.33$ 4.38$ 4.33$ 4.33$ 4.33$ 4.18$ 4.15$ 4.18$ 4.17$ 4.34$
Expected Case 2025-2026 Jan 3.89$ 4.29$ 3.89$ 3.89$ 3.89$ 4.16$ 3.84$ 4.16$ 4.05$ 3.97$
Expected Case 2025-2026 Feb 3.90$ 4.22$ 3.90$ 3.90$ 3.90$ 4.07$ 3.84$ 4.13$ 4.01$ 3.96$
Expected Case 2025-2026 Mar 3.36$ 4.06$ 3.36$ 3.36$ 3.36$ 3.31$ 3.31$ 4.06$ 3.56$ 3.50$
Expected Case 2025-2026 Apr 3.20$ 4.11$ 3.20$ 3.20$ 3.20$ 3.15$ 3.15$ 4.11$ 3.47$ 3.38$
Expected Case 2025-2026 May 3.28$ 4.00$ 3.28$ 3.28$ 3.28$ 3.23$ 3.23$ 4.00$ 3.49$ 3.42$
Expected Case 2025-2026 Jun 3.26$ 4.00$ 3.26$ 3.26$ 3.26$ 3.22$ 3.22$ 4.00$ 3.48$ 3.41$
Expected Case 2025-2026 Jul 3.37$ 4.00$ 3.37$ 3.37$ 3.37$ 3.32$ 3.32$ 4.00$ 3.55$ 3.50$
Expected Case 2025-2026 Aug 3.43$ 4.00$ 3.43$ 3.43$ 3.43$ 3.38$ 3.38$ 4.00$ 3.59$ 3.54$
Expected Case 2025-2026 Sep 3.51$ 4.00$ 3.51$ 3.51$ 3.51$ 3.46$ 3.46$ 4.00$ 3.64$ 3.61$
Expected Case 2025-2026 Oct 3.52$ 4.00$ 3.52$ 3.52$ 3.52$ 3.47$ 3.47$ 4.00$ 3.65$ 3.62$ Expected Case 2026-2027 Nov 4.11$ 4.11$ 4.11$ 4.11$ 4.11$ 4.06$ 4.05$ 4.08$ 4.07$ 4.11$ Expected Case 2026-2027 Dec 4.24$ 4.49$ 4.24$ 4.24$ 4.24$ 4.17$ 4.03$ 4.17$ 4.12$ 4.29$ Expected Case 2026-2027 Jan 3.90$ 4.32$ 3.90$ 3.90$ 3.90$ 4.15$ 3.80$ 4.15$ 4.03$ 3.98$ Expected Case 2026-2027 Feb 3.86$ 4.26$ 3.86$ 3.86$ 3.86$ 4.06$ 3.79$ 4.13$ 4.00$ 3.94$ Expected Case 2026-2027 Mar 3.42$ 4.08$ 3.42$ 3.42$ 3.42$ 3.37$ 3.37$ 4.08$ 3.61$ 3.55$ Expected Case 2026-2027 Apr 3.28$ 4.16$ 3.28$ 3.28$ 3.28$ 3.24$ 3.24$ 4.16$ 3.54$ 3.46$ Expected Case 2026-2027 May 3.33$ 4.08$ 3.33$ 3.33$ 3.33$ 3.28$ 3.28$ 4.08$ 3.54$ 3.48$ Expected Case 2026-2027 Jun 3.36$ 4.08$ 3.36$ 3.36$ 3.36$ 3.31$ 3.31$ 4.08$ 3.56$ 3.50$ Expected Case 2026-2027 Jul 3.46$ 4.08$ 3.46$ 3.46$ 3.46$ 3.41$ 3.41$ 4.08$ 3.64$ 3.59$ Expected Case 2026-2027 Aug 3.52$ 4.08$ 3.52$ 3.52$ 3.52$ 3.47$ 3.47$ 4.08$ 3.67$ 3.63$ Expected Case 2026-2027 Sep 3.74$ 4.08$ 3.74$ 3.74$ 3.74$ 3.68$ 3.68$ 4.08$ 3.81$ 3.80$ Expected Case 2026-2027 Oct 3.77$ 4.20$ 3.77$ 3.77$ 3.77$ 3.72$ 3.72$ 4.20$ 3.88$ 3.85$ Expected Case 2027-2028 Nov 4.33$ 4.33$ 4.33$ 4.33$ 4.33$ 4.29$ 4.27$ 4.33$ 4.29$ 4.33$ Expected Case 2027-2028 Dec 4.50$ 4.64$ 4.50$ 4.50$ 4.50$ 4.43$ 4.33$ 4.43$ 4.39$ 4.53$ Expected Case 2027-2028 Jan 4.26$ 4.61$ 4.26$ 4.26$ 4.26$ 4.41$ 4.20$ 4.41$ 4.34$ 4.33$ Expected Case 2027-2028 Feb 4.25$ 4.43$ 4.25$ 4.25$ 4.25$ 4.34$ 4.19$ 4.37$ 4.30$ 4.29$ Expected Case 2027-2028 Mar 3.75$ 4.31$ 3.75$ 3.75$ 3.75$ 3.70$ 3.70$ 4.31$ 3.90$ 3.86$ Expected Case 2027-2028 Apr 3.64$ 4.35$ 3.64$ 3.64$ 3.64$ 3.59$ 3.59$ 4.35$ 3.84$ 3.78$ Expected Case 2027-2028 May 3.68$ 4.31$ 3.68$ 3.68$ 3.68$ 3.62$ 3.62$ 4.31$ 3.85$ 3.80$ Expected Case 2027-2028 Jun 3.69$ 4.31$ 3.69$ 3.69$ 3.69$ 3.64$ 3.64$ 4.31$ 3.86$ 3.82$
Expected Case 2027-2028 Jul 3.79$ 4.31$ 3.79$ 3.79$ 3.79$ 3.73$ 3.73$ 4.31$ 3.93$ 3.89$
Expected Case 2027-2028 Aug 3.81$ 4.31$ 3.81$ 3.81$ 3.81$ 3.76$ 3.76$ 4.31$ 3.94$ 3.91$
Expected Case 2027-2028 Sep 3.97$ 4.31$ 3.97$ 3.97$ 3.97$ 3.92$ 3.92$ 4.31$ 4.05$ 4.04$
Expected Case 2027-2028 Oct 4.00$ 4.33$ 4.00$ 4.00$ 4.00$ 3.95$ 3.95$ 4.33$ 4.07$ 4.07$
Expected Case 2028-2029 Nov 4.49$ 4.53$ 4.49$ 4.49$ 4.49$ 4.46$ 4.42$ 4.53$ 4.47$ 4.49$
Expected Case 2028-2029 Dec 4.71$ 4.81$ 4.71$ 4.71$ 4.71$ 4.63$ 4.57$ 4.63$ 4.61$ 4.73$
Expected Case 2028-2029 Jan 4.53$ 4.81$ 4.53$ 4.53$ 4.53$ 4.62$ 4.47$ 4.62$ 4.57$ 4.58$
Expected Case 2028-2029 Feb 4.53$ 4.65$ 4.53$ 4.53$ 4.53$ 4.57$ 4.47$ 4.58$ 4.54$ 4.56$
Expected Case 2028-2029 Mar 4.01$ 4.52$ 4.01$ 4.01$ 4.01$ 3.95$ 3.95$ 4.52$ 4.14$ 4.11$
Expected Case 2028-2029 Apr 3.85$ 4.56$ 3.85$ 3.85$ 3.85$ 3.79$ 3.79$ 4.56$ 4.05$ 3.99$
Expected Case 2028-2029 May 3.92$ 4.43$ 3.92$ 3.92$ 3.92$ 3.87$ 3.87$ 4.43$ 4.05$ 4.02$
Expected Case 2028-2029 Jun 3.90$ 4.43$ 3.90$ 3.90$ 3.90$ 3.85$ 3.85$ 4.43$ 4.04$ 4.01$
Expected Case 2028-2029 Jul 3.94$ 4.43$ 3.94$ 3.94$ 3.94$ 3.88$ 3.88$ 4.43$ 4.07$ 4.04$
Expected Case 2028-2029 Aug 3.96$ 4.43$ 3.96$ 3.96$ 3.96$ 3.91$ 3.91$ 4.43$ 4.08$ 4.06$
Expected Case 2028-2029 Sep 4.11$ 4.43$ 4.11$ 4.11$ 4.11$ 4.06$ 4.06$ 4.43$ 4.18$ 4.18$
Expected Case 2028-2029 Oct 4.12$ 4.43$ 4.12$ 4.12$ 4.12$ 4.06$ 4.06$ 4.43$ 4.18$ 4.18$
1/ Avoided costs are before Environmental Externalities adder.
Monthly Avoided Costs 1/
2014$
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 191 of 648
APPENDIX 5.4: EXPECTED MONTHLY DETAIL

Scenario Gas Year Month Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual
Expected Case 2029-2030 Nov 4.60$ 4.71$ 4.60$ 4.60$ 4.60$ 4.59$ 4.54$ 4.71$ 4.61$ 4.62$
Expected Case 2029-2030 Dec 4.84$ 4.97$ 4.84$ 4.84$ 4.84$ 4.81$ 4.69$ 4.81$ 4.77$ 4.87$
Expected Case 2029-2030 Jan 4.71$ 4.96$ 4.71$ 4.71$ 4.71$ 4.80$ 4.59$ 4.80$ 4.73$ 4.76$
Expected Case 2029-2030 Feb 4.71$ 4.81$ 4.71$ 4.71$ 4.71$ 4.76$ 4.65$ 4.76$ 4.72$ 4.73$
Expected Case 2029-2030 Mar 4.15$ 4.70$ 4.15$ 4.15$ 4.15$ 4.09$ 4.09$ 4.70$ 4.30$ 4.26$
Expected Case 2029-2030 Apr 3.98$ 4.64$ 3.98$ 3.98$ 3.98$ 3.92$ 3.92$ 4.64$ 4.16$ 4.11$
Expected Case 2029-2030 May 4.00$ 4.64$ 4.00$ 4.00$ 4.00$ 3.95$ 3.95$ 4.64$ 4.18$ 4.13$
Expected Case 2029-2030 Jun 4.05$ 4.64$ 4.05$ 4.05$ 4.05$ 3.99$ 3.99$ 4.64$ 4.21$ 4.17$
Expected Case 2029-2030 Jul 4.14$ 4.59$ 4.14$ 4.14$ 4.14$ 4.09$ 4.09$ 4.64$ 4.27$ 4.23$
Expected Case 2029-2030 Aug 4.18$ 4.64$ 4.18$ 4.18$ 4.18$ 4.12$ 4.12$ 4.64$ 4.29$ 4.27$
Expected Case 2029-2030 Sep 4.32$ 4.65$ 4.32$ 4.32$ 4.32$ 4.26$ 4.26$ 4.65$ 4.39$ 4.38$
Expected Case 2029-2030 Oct 4.36$ 4.75$ 4.36$ 4.36$ 4.36$ 4.30$ 4.30$ 4.75$ 4.45$ 4.44$
Expected Case 2030-2031 Nov 4.86$ 4.93$ 4.86$ 4.86$ 4.86$ 4.84$ 4.80$ 4.93$ 4.86$ 4.88$
Expected Case 2030-2031 Dec 5.17$ 5.25$ 5.17$ 5.17$ 5.17$ 5.04$ 5.03$ 5.04$ 5.04$ 5.18$
Expected Case 2030-2031 Jan 4.94$ 5.13$ 4.94$ 4.94$ 4.94$ 5.03$ 4.80$ 5.03$ 4.95$ 4.97$
Expected Case 2030-2031 Feb 4.91$ 5.01$ 4.91$ 4.91$ 4.91$ 4.97$ 4.85$ 4.97$ 4.93$ 4.93$
Expected Case 2030-2031 Mar 4.31$ 4.90$ 4.31$ 4.31$ 4.31$ 4.25$ 4.25$ 4.90$ 4.46$ 4.43$
Expected Case 2030-2031 Apr 4.20$ 4.74$ 4.20$ 4.20$ 4.20$ 4.15$ 4.15$ 4.74$ 4.34$ 4.31$
Expected Case 2030-2031 May 4.22$ 4.72$ 4.22$ 4.22$ 4.22$ 4.16$ 4.16$ 4.72$ 4.35$ 4.32$
Expected Case 2030-2031 Jun 4.24$ 4.71$ 4.24$ 4.24$ 4.24$ 4.18$ 4.18$ 4.73$ 4.36$ 4.33$
Expected Case 2030-2031 Jul 4.29$ 4.73$ 4.29$ 4.29$ 4.29$ 4.23$ 4.23$ 4.73$ 4.40$ 4.38$
Expected Case 2030-2031 Aug 4.33$ 4.73$ 4.33$ 4.33$ 4.33$ 4.27$ 4.27$ 4.73$ 4.42$ 4.41$
Expected Case 2030-2031 Sep 4.49$ 4.73$ 4.49$ 4.49$ 4.49$ 4.43$ 4.43$ 4.73$ 4.53$ 4.54$
Expected Case 2030-2031 Oct 4.51$ 4.82$ 4.51$ 4.51$ 4.51$ 4.45$ 4.45$ 4.82$ 4.57$ 4.57$
Expected Case 2031-2032 Nov 4.93$ 5.08$ 4.93$ 4.93$ 4.93$ 4.95$ 4.86$ 5.08$ 4.96$ 4.96$
Expected Case 2031-2032 Dec 5.26$ 5.32$ 5.26$ 5.26$ 5.26$ 5.18$ 5.13$ 5.18$ 5.16$ 5.27$
Expected Case 2031-2032 Jan 5.08$ 5.30$ 5.08$ 5.08$ 5.08$ 5.17$ 5.01$ 5.17$ 5.12$ 5.12$
Expected Case 2031-2032 Feb 5.08$ 5.16$ 5.08$ 5.08$ 5.08$ 5.11$ 5.01$ 5.11$ 5.08$ 5.09$
Expected Case 2031-2032 Mar 4.53$ 4.98$ 4.53$ 4.53$ 4.53$ 4.47$ 4.47$ 4.98$ 4.64$ 4.62$
Expected Case 2031-2032 Apr 4.37$ 4.88$ 4.37$ 4.37$ 4.37$ 4.31$ 4.31$ 4.88$ 4.50$ 4.47$
Expected Case 2031-2032 May 4.39$ 4.79$ 4.39$ 4.39$ 4.39$ 4.33$ 4.33$ 4.79$ 4.48$ 4.47$
Expected Case 2031-2032 Jun 4.40$ 4.75$ 4.40$ 4.40$ 4.40$ 4.34$ 4.34$ 4.79$ 4.49$ 4.47$
Expected Case 2031-2032 Jul 4.41$ 4.79$ 4.41$ 4.41$ 4.41$ 4.35$ 4.35$ 4.79$ 4.50$ 4.49$
Expected Case 2031-2032 Aug 4.50$ 4.79$ 4.50$ 4.50$ 4.50$ 4.43$ 4.43$ 4.79$ 4.55$ 4.55$
Expected Case 2031-2032 Sep 4.58$ 4.79$ 4.58$ 4.58$ 4.58$ 4.52$ 4.52$ 4.79$ 4.61$ 4.62$
Expected Case 2031-2032 Oct 4.61$ 4.96$ 4.61$ 4.61$ 4.61$ 4.54$ 4.54$ 4.96$ 4.68$ 4.68$
Expected Case 2032-2033 Nov 5.04$ 5.19$ 5.04$ 5.04$ 5.04$ 5.06$ 4.98$ 5.19$ 5.07$ 5.07$
Expected Case 2032-2033 Dec 5.41$ 5.48$ 5.41$ 5.41$ 5.41$ 5.30$ 5.28$ 5.30$ 5.29$ 5.42$
Expected Case 2032-2033 Jan 5.19$ 5.36$ 5.19$ 5.19$ 5.19$ 5.29$ 5.02$ 5.29$ 5.20$ 5.22$
Expected Case 2032-2033 Feb 5.12$ 5.24$ 5.12$ 5.12$ 5.12$ 5.22$ 5.05$ 5.22$ 5.16$ 5.14$ Expected Case 2032-2033 Mar 4.50$ 5.09$ 4.50$ 4.50$ 4.50$ 4.44$ 4.44$ 5.09$ 4.65$ 4.62$ Expected Case 2032-2033 Apr 4.37$ 4.93$ 4.37$ 4.37$ 4.37$ 4.31$ 4.31$ 4.93$ 4.52$ 4.48$ Expected Case 2032-2033 May 4.36$ 4.81$ 4.36$ 4.36$ 4.36$ 4.30$ 4.30$ 4.81$ 4.47$ 4.45$ Expected Case 2032-2033 Jun 4.40$ 4.81$ 4.40$ 4.40$ 4.40$ 4.33$ 4.33$ 4.81$ 4.49$ 4.48$ Expected Case 2032-2033 Jul 4.49$ 4.77$ 4.49$ 4.49$ 4.49$ 4.42$ 4.42$ 4.81$ 4.55$ 4.54$ Expected Case 2032-2033 Aug 4.56$ 4.81$ 4.56$ 4.56$ 4.56$ 4.49$ 4.49$ 4.81$ 4.60$ 4.61$ Expected Case 2032-2033 Sep 4.64$ 4.81$ 4.64$ 4.64$ 4.64$ 4.57$ 4.57$ 4.81$ 4.65$ 4.67$ Expected Case 2032-2033 Oct 4.67$ 5.04$ 4.67$ 4.67$ 4.67$ 4.60$ 4.60$ 5.04$ 4.75$ 4.74$ Expected Case 2033-2034 Nov 5.12$ 5.29$ 5.12$ 5.12$ 5.12$ 5.16$ 5.06$ 5.29$ 5.17$ 5.16$ Expected Case 2033-2034 Dec 5.53$ 5.67$ 5.53$ 5.53$ 5.53$ 5.40$ 5.37$ 5.40$ 5.39$ 5.55$ Expected Case 2033-2034 Jan 5.29$ 5.47$ 5.29$ 5.29$ 5.29$ 5.38$ 5.11$ 5.38$ 5.29$ 5.32$ Expected Case 2033-2034 Feb 5.21$ 5.34$ 5.21$ 5.21$ 5.21$ 5.32$ 5.14$ 5.32$ 5.26$ 5.24$ Expected Case 2033-2034 Mar 4.55$ 5.21$ 4.55$ 4.55$ 4.55$ 4.49$ 4.49$ 5.21$ 4.73$ 4.69$ Expected Case 2033-2034 Apr 4.43$ 5.07$ 4.43$ 4.43$ 4.43$ 4.37$ 4.37$ 5.07$ 4.60$ 4.56$ Expected Case 2033-2034 May 4.43$ 4.96$ 4.43$ 4.43$ 4.43$ 4.37$ 4.37$ 4.96$ 4.57$ 4.54$ Expected Case 2033-2034 Jun 4.45$ 4.96$ 4.45$ 4.45$ 4.45$ 4.38$ 4.38$ 4.96$ 4.58$ 4.55$ Expected Case 2033-2034 Jul 4.51$ 4.91$ 4.51$ 4.51$ 4.51$ 4.45$ 4.45$ 4.96$ 4.62$ 4.59$ Expected Case 2033-2034 Aug 4.54$ 4.96$ 4.54$ 4.54$ 4.54$ 4.48$ 4.48$ 4.96$ 4.64$ 4.62$
Expected Case 2033-2034 Sep 4.68$ 4.96$ 4.68$ 4.68$ 4.68$ 4.61$ 4.61$ 4.96$ 4.73$ 4.73$
Expected Case 2033-2034 Oct 4.69$ 5.06$ 4.69$ 4.69$ 4.69$ 4.62$ 4.62$ 5.06$ 4.77$ 4.76$
Expected Case 2034-2035 Nov 5.10$ 5.26$ 5.10$ 5.10$ 5.10$ 5.13$ 5.03$ 5.26$ 5.14$ 5.13$
Expected Case 2034-2035 Dec 5.54$ 5.66$ 5.54$ 5.54$ 5.54$ 5.37$ 5.35$ 5.37$ 5.36$ 5.57$
Expected Case 2034-2035 Jan 5.25$ 5.47$ 5.25$ 5.25$ 5.25$ 5.35$ 5.12$ 5.35$ 5.27$ 5.29$
Expected Case 2034-2035 Feb 5.20$ 5.41$ 5.20$ 5.20$ 5.20$ 5.39$ 5.13$ 5.39$ 5.30$ 5.24$
Expected Case 2034-2035 Mar 4.72$ 5.06$ 4.72$ 4.72$ 4.72$ 4.66$ 4.66$ 5.06$ 4.79$ 4.79$
Expected Case 2034-2035 Apr 4.56$ 4.99$ 4.56$ 4.56$ 4.56$ 4.50$ 4.50$ 4.99$ 4.66$ 4.65$
Expected Case 2034-2035 May 4.55$ 4.72$ 4.55$ 4.55$ 4.55$ 4.49$ 4.49$ 4.72$ 4.56$ 4.58$
Expected Case 2034-2035 Jun 4.43$ 4.72$ 4.43$ 4.43$ 4.43$ 4.37$ 4.37$ 4.72$ 4.49$ 4.49$
Expected Case 2034-2035 Jul 4.49$ 4.72$ 4.49$ 4.49$ 4.49$ 4.43$ 4.43$ 4.72$ 4.53$ 4.54$
Expected Case 2034-2035 Aug 4.61$ 4.72$ 4.61$ 4.61$ 4.61$ 4.55$ 4.55$ 4.72$ 4.61$ 4.63$
Expected Case 2034-2035 Sep 4.72$ 4.72$ 4.72$ 4.72$ 4.72$ 4.66$ 4.66$ 4.72$ 4.68$ 4.72$
Expected Case 2034-2035 Oct 4.71$ 5.12$ 4.71$ 4.71$ 4.71$ 4.65$ 4.65$ 5.12$ 4.80$ 4.79$
1/ Avoided costs are before Environmental Externalities adder.
Monthly Avoided Costs 1/
2014$
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 192 of 648
APPENDIX 5.4: HIGH GROWTH – LOW PRICE MONTHLY DETAIL

Scenario Gas Year Month Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual
High Growth_Low Prices 2015-2016 Nov 1.96$ 1.96$ 1.96$ 1.96$ 1.96$ 1.93$ 1.93$ 1.96$ 1.94$ 1.96$
High Growth_Low Prices 2015-2016 Dec 1.77$ 2.00$ 1.77$ 1.77$ 1.77$ 1.99$ 1.65$ 1.99$ 1.88$ 1.82$
High Growth_Low Prices 2015-2016 Jan 1.88$ 1.99$ 1.88$ 1.88$ 1.88$ 1.96$ 1.85$ 1.96$ 1.93$ 1.90$
High Growth_Low Prices 2015-2016 Feb 1.93$ 2.09$ 1.93$ 1.93$ 1.93$ 1.96$ 1.90$ 2.00$ 1.96$ 1.96$
High Growth_Low Prices 2015-2016 Mar 1.55$ 1.97$ 1.55$ 1.55$ 1.55$ 1.52$ 1.52$ 1.97$ 1.67$ 1.63$
High Growth_Low Prices 2015-2016 Apr 1.26$ 1.97$ 1.26$ 1.26$ 1.26$ 1.24$ 1.24$ 1.97$ 1.48$ 1.40$
High Growth_Low Prices 2015-2016 May 1.48$ 1.97$ 1.48$ 1.48$ 1.48$ 1.45$ 1.45$ 1.97$ 1.62$ 1.58$
High Growth_Low Prices 2015-2016 Jun 1.52$ 1.97$ 1.52$ 1.52$ 1.52$ 1.50$ 1.50$ 1.97$ 1.65$ 1.61$
High Growth_Low Prices 2015-2016 Jul 2.03$ 2.01$ 2.01$ 2.01$ 2.01$ 2.00$ 2.00$ 2.01$ 2.01$ 2.02$
High Growth_Low Prices 2015-2016 Aug 1.92$ 1.97$ 1.92$ 1.92$ 1.92$ 1.89$ 1.89$ 1.97$ 1.92$ 1.93$
High Growth_Low Prices 2015-2016 Sep 1.33$ 1.97$ 1.33$ 1.33$ 1.33$ 1.31$ 1.31$ 1.97$ 1.53$ 1.46$
High Growth_Low Prices 2015-2016 Oct 1.61$ 2.36$ 1.61$ 1.61$ 1.61$ 1.58$ 1.58$ 2.36$ 1.84$ 1.76$
High Growth_Low Prices 2016-2017 Nov 1.27$ 2.09$ 1.27$ 1.27$ 1.27$ 1.29$ 1.25$ 2.09$ 1.54$ 1.43$
High Growth_Low Prices 2016-2017 Dec 1.35$ 2.05$ 1.35$ 1.35$ 1.35$ 1.46$ 0.88$ 2.05$ 1.46$ 1.49$
High Growth_Low Prices 2016-2017 Jan 1.71$ 2.13$ 1.71$ 1.71$ 1.71$ 2.06$ 1.59$ 2.10$ 1.91$ 1.79$
High Growth_Low Prices 2016-2017 Feb 1.82$ 2.21$ 1.82$ 1.82$ 1.82$ 1.92$ 1.74$ 2.11$ 1.92$ 1.90$
High Growth_Low Prices 2016-2017 Mar 1.47$ 2.10$ 1.47$ 1.47$ 1.47$ 1.44$ 1.44$ 2.10$ 1.66$ 1.59$
High Growth_Low Prices 2016-2017 Apr 1.29$ 2.10$ 1.29$ 1.29$ 1.29$ 1.27$ 1.27$ 2.10$ 1.55$ 1.45$
High Growth_Low Prices 2016-2017 May 1.60$ 2.10$ 1.60$ 1.60$ 1.60$ 1.57$ 1.57$ 2.10$ 1.75$ 1.70$
High Growth_Low Prices 2016-2017 Jun 1.53$ 2.10$ 1.53$ 1.53$ 1.53$ 1.50$ 1.50$ 2.10$ 1.70$ 1.64$
High Growth_Low Prices 2016-2017 Jul 2.03$ 2.10$ 2.03$ 2.03$ 2.03$ 2.00$ 2.00$ 2.10$ 2.03$ 2.04$
High Growth_Low Prices 2016-2017 Aug 1.91$ 2.10$ 1.91$ 1.91$ 1.91$ 1.88$ 1.88$ 2.10$ 1.95$ 1.95$
High Growth_Low Prices 2016-2017 Sep 1.36$ 2.10$ 1.36$ 1.36$ 1.36$ 1.34$ 1.34$ 2.10$ 1.59$ 1.51$
High Growth_Low Prices 2016-2017 Oct 1.49$ 2.36$ 1.49$ 1.49$ 1.49$ 1.46$ 1.46$ 2.36$ 1.76$ 1.66$
High Growth_Low Prices 2017-2018 Nov 1.40$ 2.10$ 1.40$ 1.40$ 1.40$ 1.42$ 1.37$ 2.10$ 1.63$ 1.54$
High Growth_Low Prices 2017-2018 Dec 1.51$ 2.02$ 1.51$ 1.51$ 1.51$ 1.54$ 0.97$ 2.03$ 1.51$ 1.61$
High Growth_Low Prices 2017-2018 Jan 1.83$ 2.14$ 1.83$ 1.83$ 1.83$ 2.12$ 1.73$ 2.12$ 1.99$ 1.89$
High Growth_Low Prices 2017-2018 Feb 1.91$ 2.23$ 1.91$ 1.91$ 1.91$ 2.00$ 1.86$ 2.13$ 2.00$ 1.97$
High Growth_Low Prices 2017-2018 Mar 1.52$ 2.10$ 1.52$ 1.52$ 1.52$ 1.49$ 1.49$ 2.10$ 1.70$ 1.64$
High Growth_Low Prices 2017-2018 Apr 1.27$ 2.10$ 1.27$ 1.27$ 1.27$ 1.24$ 1.24$ 2.10$ 1.53$ 1.43$
High Growth_Low Prices 2017-2018 May 1.47$ 2.11$ 1.47$ 1.47$ 1.47$ 1.44$ 1.44$ 2.11$ 1.66$ 1.60$
High Growth_Low Prices 2017-2018 Jun 1.46$ 2.11$ 1.46$ 1.46$ 1.46$ 1.44$ 1.44$ 2.11$ 1.66$ 1.59$
High Growth_Low Prices 2017-2018 Jul 1.99$ 2.11$ 1.99$ 1.99$ 1.99$ 1.95$ 1.95$ 2.11$ 2.01$ 2.01$
High Growth_Low Prices 2017-2018 Aug 1.81$ 2.11$ 1.81$ 1.81$ 1.81$ 1.78$ 1.78$ 2.11$ 1.89$ 1.87$
High Growth_Low Prices 2017-2018 Sep 1.34$ 2.11$ 1.34$ 1.34$ 1.34$ 1.31$ 1.31$ 2.11$ 1.58$ 1.49$
High Growth_Low Prices 2017-2018 Oct 1.39$ 2.39$ 1.39$ 1.39$ 1.39$ 1.37$ 1.37$ 2.39$ 1.71$ 1.59$
High Growth_Low Prices 2018-2019 Nov 1.36$ 2.11$ 1.36$ 1.36$ 1.36$ 1.48$ 1.34$ 2.11$ 1.64$ 1.51$
High Growth_Low Prices 2018-2019 Dec 1.65$ 1.98$ 1.65$ 1.65$ 1.65$ 1.64$ 1.08$ 1.97$ 1.57$ 1.72$
High Growth_Low Prices 2018-2019 Jan 1.93$ 2.23$ 1.93$ 1.93$ 1.93$ 2.10$ 1.62$ 2.11$ 1.94$ 1.99$
High Growth_Low Prices 2018-2019 Feb 1.84$ 2.26$ 1.84$ 1.84$ 1.84$ 2.05$ 1.76$ 2.15$ 1.98$ 1.93$
High Growth_Low Prices 2018-2019 Mar 1.32$ 2.11$ 1.32$ 1.32$ 1.32$ 1.30$ 1.30$ 2.11$ 1.57$ 1.48$
High Growth_Low Prices 2018-2019 Apr 1.04$ 2.11$ 1.04$ 1.04$ 1.04$ 1.02$ 1.02$ 2.11$ 1.39$ 1.26$
High Growth_Low Prices 2018-2019 May 1.32$ 2.11$ 1.32$ 1.32$ 1.32$ 1.30$ 1.30$ 2.11$ 1.57$ 1.48$
High Growth_Low Prices 2018-2019 Jun 1.41$ 2.11$ 1.41$ 1.41$ 1.41$ 1.39$ 1.39$ 2.11$ 1.63$ 1.55$
High Growth_Low Prices 2018-2019 Jul 1.94$ 2.11$ 1.94$ 1.94$ 1.94$ 1.91$ 1.91$ 2.11$ 1.98$ 1.98$
High Growth_Low Prices 2018-2019 Aug 1.77$ 2.12$ 1.77$ 1.77$ 1.77$ 1.74$ 1.74$ 2.12$ 1.86$ 1.84$
High Growth_Low Prices 2018-2019 Sep 1.24$ 2.12$ 1.24$ 1.24$ 1.24$ 1.22$ 1.22$ 2.12$ 1.52$ 1.42$
High Growth_Low Prices 2018-2019 Oct 1.45$ 2.40$ 1.45$ 1.45$ 1.45$ 1.43$ 1.43$ 2.40$ 1.75$ 1.64$ High Growth_Low Prices 2019-2020 Nov 1.37$ 2.09$ 1.37$ 1.37$ 1.37$ 1.50$ 1.35$ 2.09$ 1.64$ 1.52$ High Growth_Low Prices 2019-2020 Dec 1.66$ 1.75$ 1.66$ 1.66$ 1.66$ 1.56$ 1.01$ 1.74$ 1.44$ 1.68$ High Growth_Low Prices 2019-2020 Jan 1.95$ 2.21$ 1.95$ 1.95$ 1.95$ 2.11$ 1.63$ 2.13$ 1.95$ 2.00$ High Growth_Low Prices 2019-2020 Feb 1.84$ 2.24$ 1.84$ 1.84$ 1.84$ 2.05$ 1.77$ 2.16$ 1.99$ 1.92$ High Growth_Low Prices 2019-2020 Mar 1.45$ 2.13$ 1.45$ 1.45$ 1.45$ 1.42$ 1.42$ 2.13$ 1.66$ 1.59$ High Growth_Low Prices 2019-2020 Apr 1.06$ 2.13$ 1.06$ 1.06$ 1.06$ 1.04$ 1.04$ 2.13$ 1.40$ 1.28$ High Growth_Low Prices 2019-2020 May 1.34$ 2.13$ 1.34$ 1.34$ 1.34$ 1.31$ 1.31$ 2.13$ 1.59$ 1.50$ High Growth_Low Prices 2019-2020 Jun 1.40$ 2.13$ 1.40$ 1.40$ 1.40$ 1.38$ 1.38$ 2.13$ 1.63$ 1.55$ High Growth_Low Prices 2019-2020 Jul 1.92$ 2.13$ 1.92$ 1.92$ 1.92$ 1.89$ 1.89$ 2.13$ 1.97$ 1.97$ High Growth_Low Prices 2019-2020 Aug 1.75$ 2.13$ 1.75$ 1.75$ 1.75$ 1.73$ 1.73$ 2.13$ 1.86$ 1.83$ High Growth_Low Prices 2019-2020 Sep 1.44$ 2.13$ 1.44$ 1.44$ 1.44$ 1.41$ 1.41$ 2.13$ 1.65$ 1.58$ High Growth_Low Prices 2019-2020 Oct 1.41$ 2.45$ 1.41$ 1.41$ 1.41$ 1.39$ 1.39$ 2.45$ 1.74$ 1.62$ High Growth_Low Prices 2020-2021 Nov 1.41$ 2.07$ 1.41$ 1.41$ 1.41$ 1.53$ 1.39$ 2.07$ 1.66$ 1.55$ High Growth_Low Prices 2020-2021 Dec 1.66$ 1.75$ 1.67$ 1.67$ 1.67$ 1.61$ 1.07$ 1.71$ 1.46$ 1.69$ High Growth_Low Prices 2020-2021 Jan 2.07$ 2.34$ 2.07$ 2.07$ 2.07$ 2.14$ 1.66$ 2.15$ 1.98$ 2.13$ High Growth_Low Prices 2020-2021 Feb 1.93$ 2.26$ 1.93$ 1.93$ 1.93$ 2.11$ 1.86$ 2.19$ 2.05$ 2.00$ High Growth_Low Prices 2020-2021 Mar 1.52$ 2.15$ 1.52$ 1.52$ 1.52$ 1.49$ 1.49$ 2.15$ 1.71$ 1.64$ High Growth_Low Prices 2020-2021 Apr 1.13$ 2.15$ 1.13$ 1.13$ 1.13$ 1.11$ 1.11$ 2.15$ 1.46$ 1.34$ High Growth_Low Prices 2020-2021 May 1.42$ 2.15$ 1.42$ 1.42$ 1.42$ 1.39$ 1.39$ 2.15$ 1.65$ 1.56$ High Growth_Low Prices 2020-2021 Jun 1.46$ 2.15$ 1.46$ 1.46$ 1.46$ 1.44$ 1.44$ 2.15$ 1.68$ 1.60$
High Growth_Low Prices 2020-2021 Jul 1.89$ 2.15$ 1.89$ 1.89$ 1.89$ 1.86$ 1.86$ 2.15$ 1.95$ 1.94$
High Growth_Low Prices 2020-2021 Aug 1.71$ 2.15$ 1.71$ 1.71$ 1.71$ 1.68$ 1.68$ 2.15$ 1.84$ 1.80$
High Growth_Low Prices 2020-2021 Sep 1.38$ 2.15$ 1.38$ 1.38$ 1.38$ 1.35$ 1.35$ 2.15$ 1.62$ 1.53$
High Growth_Low Prices 2020-2021 Oct 1.49$ 2.30$ 1.49$ 1.49$ 1.49$ 1.46$ 1.46$ 2.30$ 1.74$ 1.65$
High Growth_Low Prices 2021-2022 Nov 1.41$ 2.12$ 1.41$ 1.41$ 1.41$ 1.53$ 1.38$ 2.12$ 1.68$ 1.55$
High Growth_Low Prices 2021-2022 Dec 1.70$ 1.81$ 1.71$ 1.71$ 1.71$ 1.62$ 1.04$ 1.72$ 1.46$ 1.73$
High Growth_Low Prices 2021-2022 Jan 2.18$ 2.41$ 2.18$ 2.18$ 2.18$ 2.06$ 1.58$ 2.22$ 1.96$ 2.23$
High Growth_Low Prices 2021-2022 Feb 1.88$ 2.34$ 1.88$ 1.88$ 1.88$ 2.14$ 1.78$ 2.25$ 2.06$ 1.97$
High Growth_Low Prices 2021-2022 Mar 1.45$ 2.22$ 1.45$ 1.45$ 1.45$ 1.42$ 1.42$ 2.22$ 1.69$ 1.60$
High Growth_Low Prices 2021-2022 Apr 1.10$ 2.22$ 1.10$ 1.10$ 1.10$ 1.08$ 1.08$ 2.22$ 1.46$ 1.32$
High Growth_Low Prices 2021-2022 May 1.39$ 2.22$ 1.39$ 1.39$ 1.39$ 1.37$ 1.37$ 2.23$ 1.65$ 1.56$
High Growth_Low Prices 2021-2022 Jun 1.45$ 2.23$ 1.45$ 1.45$ 1.45$ 1.42$ 1.42$ 2.23$ 1.69$ 1.60$
High Growth_Low Prices 2021-2022 Jul 1.94$ 2.23$ 1.94$ 1.94$ 1.94$ 1.91$ 1.91$ 2.23$ 2.02$ 2.00$
High Growth_Low Prices 2021-2022 Aug 1.78$ 2.23$ 1.78$ 1.78$ 1.78$ 1.75$ 1.75$ 2.23$ 1.91$ 1.87$
High Growth_Low Prices 2021-2022 Sep 1.36$ 2.23$ 1.36$ 1.36$ 1.36$ 1.34$ 1.34$ 2.23$ 1.63$ 1.53$
High Growth_Low Prices 2021-2022 Oct 1.48$ 2.47$ 1.48$ 1.48$ 1.48$ 1.45$ 1.45$ 2.47$ 1.79$ 1.68$
1/ Avoided costs are before Environmental Externalities adder.
Monthly Avoided Costs 1/
2014$
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 193 of 648
APPENDIX 5.4: HIGH GROWTH – LOW PRICE MONTHLY DETAIL

Scenario Gas Year Month Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual
High Growth_Low Prices 2022-2023 Nov 1.29$ 2.23$ 1.29$ 1.29$ 1.29$ 1.41$ 1.27$ 2.23$ 1.64$ 1.48$
High Growth_Low Prices 2022-2023 Dec 1.81$ 1.90$ 1.81$ 1.81$ 1.81$ 1.48$ 0.86$ 1.81$ 1.38$ 1.83$
High Growth_Low Prices 2022-2023 Jan 2.23$ 2.49$ 2.23$ 2.23$ 2.23$ 1.86$ 1.38$ 2.23$ 1.82$ 2.28$
High Growth_Low Prices 2022-2023 Feb 1.71$ 2.39$ 1.71$ 1.71$ 1.71$ 2.08$ 1.57$ 2.27$ 1.97$ 1.84$
High Growth_Low Prices 2022-2023 Mar 1.29$ 2.23$ 1.29$ 1.29$ 1.29$ 1.27$ 1.27$ 2.23$ 1.59$ 1.48$
High Growth_Low Prices 2022-2023 Apr 1.04$ 2.26$ 1.04$ 1.04$ 1.04$ 1.02$ 1.02$ 2.26$ 1.44$ 1.29$
High Growth_Low Prices 2022-2023 May 1.36$ 2.23$ 1.36$ 1.36$ 1.36$ 1.34$ 1.34$ 2.23$ 1.64$ 1.54$
High Growth_Low Prices 2022-2023 Jun 1.43$ 2.23$ 1.43$ 1.43$ 1.43$ 1.40$ 1.40$ 2.23$ 1.68$ 1.59$
High Growth_Low Prices 2022-2023 Jul 1.93$ 2.23$ 1.93$ 1.93$ 1.93$ 1.90$ 1.90$ 2.23$ 2.01$ 1.99$
High Growth_Low Prices 2022-2023 Aug 1.75$ 2.24$ 1.75$ 1.75$ 1.75$ 1.72$ 1.72$ 2.24$ 1.90$ 1.85$
High Growth_Low Prices 2022-2023 Sep 1.44$ 2.24$ 1.44$ 1.44$ 1.44$ 1.42$ 1.42$ 2.24$ 1.69$ 1.60$
High Growth_Low Prices 2022-2023 Oct 1.67$ 2.44$ 1.67$ 1.67$ 1.67$ 1.64$ 1.64$ 2.44$ 1.91$ 1.82$
High Growth_Low Prices 2023-2024 Nov 1.63$ 2.20$ 1.63$ 1.63$ 1.63$ 1.79$ 1.60$ 2.20$ 1.87$ 1.74$
High Growth_Low Prices 2023-2024 Dec 1.78$ 1.87$ 1.79$ 1.79$ 1.79$ 1.61$ 1.04$ 1.79$ 1.48$ 1.80$
High Growth_Low Prices 2023-2024 Jan 2.09$ 2.40$ 2.09$ 2.09$ 2.09$ 2.13$ 1.66$ 2.24$ 2.01$ 2.15$
High Growth_Low Prices 2023-2024 Feb 1.90$ 2.30$ 1.90$ 1.90$ 1.90$ 2.22$ 1.83$ 2.26$ 2.10$ 1.98$
High Growth_Low Prices 2023-2024 Mar 1.54$ 2.19$ 1.54$ 1.54$ 1.54$ 1.52$ 1.52$ 2.19$ 1.74$ 1.67$
High Growth_Low Prices 2023-2024 Apr 1.15$ 2.19$ 1.15$ 1.15$ 1.15$ 1.13$ 1.13$ 2.19$ 1.48$ 1.36$
High Growth_Low Prices 2023-2024 May 1.43$ 2.19$ 1.43$ 1.43$ 1.43$ 1.40$ 1.40$ 2.19$ 1.67$ 1.58$
High Growth_Low Prices 2023-2024 Jun 1.49$ 2.19$ 1.49$ 1.49$ 1.49$ 1.46$ 1.46$ 2.19$ 1.70$ 1.63$
High Growth_Low Prices 2023-2024 Jul 2.08$ 2.19$ 2.08$ 2.08$ 2.08$ 2.04$ 2.04$ 2.19$ 2.09$ 2.10$
High Growth_Low Prices 2023-2024 Aug 1.91$ 2.19$ 1.91$ 1.91$ 1.91$ 1.87$ 1.87$ 2.19$ 1.98$ 1.96$
High Growth_Low Prices 2023-2024 Sep 1.56$ 2.19$ 1.56$ 1.56$ 1.56$ 1.53$ 1.53$ 2.19$ 1.75$ 1.68$
High Growth_Low Prices 2023-2024 Oct 1.58$ 2.25$ 1.58$ 1.58$ 1.58$ 1.55$ 1.55$ 2.25$ 1.78$ 1.71$
High Growth_Low Prices 2024-2025 Nov 1.63$ 2.02$ 1.63$ 1.63$ 1.63$ 1.77$ 1.61$ 2.02$ 1.80$ 1.71$
High Growth_Low Prices 2024-2025 Dec 1.59$ 1.89$ 1.62$ 1.62$ 1.62$ 1.74$ 1.18$ 1.75$ 1.56$ 1.67$
High Growth_Low Prices 2024-2025 Jan 2.07$ 2.39$ 2.07$ 2.07$ 2.07$ 2.18$ 1.71$ 2.19$ 2.03$ 2.13$
High Growth_Low Prices 2024-2025 Feb 1.92$ 2.28$ 1.92$ 1.92$ 1.92$ 2.20$ 1.85$ 2.22$ 2.09$ 1.99$
High Growth_Low Prices 2024-2025 Mar 1.54$ 2.16$ 1.54$ 1.54$ 1.54$ 1.52$ 1.52$ 2.16$ 1.73$ 1.67$
High Growth_Low Prices 2024-2025 Apr 1.12$ 2.12$ 1.12$ 1.12$ 1.12$ 1.10$ 1.10$ 2.12$ 1.44$ 1.32$
High Growth_Low Prices 2024-2025 May 1.48$ 2.12$ 1.48$ 1.48$ 1.48$ 1.45$ 1.45$ 2.12$ 1.68$ 1.61$
High Growth_Low Prices 2024-2025 Jun 1.53$ 2.12$ 1.53$ 1.53$ 1.53$ 1.50$ 1.50$ 2.12$ 1.71$ 1.65$
High Growth_Low Prices 2024-2025 Jul 2.08$ 2.12$ 2.08$ 2.08$ 2.08$ 2.05$ 2.05$ 2.12$ 2.07$ 2.09$
High Growth_Low Prices 2024-2025 Aug 1.90$ 2.12$ 1.90$ 1.90$ 1.90$ 1.87$ 1.87$ 2.12$ 1.96$ 1.95$
High Growth_Low Prices 2024-2025 Sep 1.66$ 2.12$ 1.66$ 1.66$ 1.66$ 1.63$ 1.63$ 2.12$ 1.80$ 1.75$
High Growth_Low Prices 2024-2025 Oct 1.59$ 2.14$ 1.59$ 1.59$ 1.59$ 1.56$ 1.56$ 2.14$ 1.76$ 1.70$
High Growth_Low Prices 2025-2026 Nov 1.56$ 1.83$ 1.56$ 1.56$ 1.56$ 1.66$ 1.53$ 1.83$ 1.67$ 1.61$
High Growth_Low Prices 2025-2026 Dec 1.55$ 1.79$ 1.57$ 1.57$ 1.57$ 1.61$ 1.04$ 1.63$ 1.43$ 1.61$
High Growth_Low Prices 2025-2026 Jan 2.00$ 2.40$ 2.00$ 2.00$ 2.00$ 2.11$ 1.63$ 2.13$ 1.95$ 2.08$
High Growth_Low Prices 2025-2026 Feb 1.85$ 2.28$ 1.85$ 1.85$ 1.85$ 2.18$ 1.78$ 2.18$ 2.05$ 1.93$
High Growth_Low Prices 2025-2026 Mar 1.41$ 2.13$ 1.41$ 1.41$ 1.41$ 1.40$ 1.38$ 2.13$ 1.64$ 1.55$
High Growth_Low Prices 2025-2026 Apr 1.13$ 2.08$ 1.13$ 1.13$ 1.13$ 1.11$ 1.11$ 2.08$ 1.44$ 1.32$
High Growth_Low Prices 2025-2026 May 1.48$ 2.08$ 1.48$ 1.48$ 1.48$ 1.45$ 1.45$ 2.08$ 1.66$ 1.60$
High Growth_Low Prices 2025-2026 Jun 1.52$ 2.08$ 1.52$ 1.52$ 1.52$ 1.49$ 1.49$ 2.08$ 1.69$ 1.63$
High Growth_Low Prices 2025-2026 Jul 2.09$ 2.08$ 2.09$ 2.09$ 2.09$ 2.05$ 2.05$ 2.09$ 2.06$ 2.09$
High Growth_Low Prices 2025-2026 Aug 1.93$ 2.09$ 1.93$ 1.93$ 1.93$ 1.90$ 1.90$ 2.09$ 1.96$ 1.96$
High Growth_Low Prices 2025-2026 Sep 1.55$ 2.09$ 1.55$ 1.55$ 1.55$ 1.52$ 1.52$ 2.09$ 1.71$ 1.65$
High Growth_Low Prices 2025-2026 Oct 1.58$ 2.09$ 1.58$ 1.58$ 1.58$ 1.56$ 1.56$ 2.09$ 1.73$ 1.69$ High Growth_Low Prices 2026-2027 Nov 1.60$ 1.81$ 1.60$ 1.60$ 1.60$ 1.68$ 1.57$ 1.81$ 1.69$ 1.64$ High Growth_Low Prices 2026-2027 Dec 1.66$ 1.86$ 1.67$ 1.67$ 1.67$ 1.53$ 0.94$ 1.71$ 1.39$ 1.71$ High Growth_Low Prices 2026-2027 Jan 2.04$ 2.56$ 2.04$ 2.04$ 2.04$ 2.00$ 1.52$ 2.09$ 1.87$ 2.14$ High Growth_Low Prices 2026-2027 Feb 1.77$ 2.27$ 1.77$ 1.77$ 1.77$ 2.14$ 1.68$ 2.14$ 1.98$ 1.87$ High Growth_Low Prices 2026-2027 Mar 1.38$ 2.09$ 1.38$ 1.38$ 1.38$ 1.37$ 1.36$ 2.09$ 1.61$ 1.53$ High Growth_Low Prices 2026-2027 Apr 1.14$ 2.09$ 1.14$ 1.14$ 1.14$ 1.12$ 1.12$ 2.09$ 1.44$ 1.33$ High Growth_Low Prices 2026-2027 May 1.45$ 2.09$ 1.45$ 1.45$ 1.45$ 1.42$ 1.42$ 2.09$ 1.65$ 1.58$ High Growth_Low Prices 2026-2027 Jun 1.54$ 2.09$ 1.54$ 1.54$ 1.54$ 1.51$ 1.51$ 2.09$ 1.71$ 1.65$ High Growth_Low Prices 2026-2027 Jul 2.11$ 2.09$ 2.09$ 2.09$ 2.09$ 2.08$ 2.08$ 2.09$ 2.08$ 2.10$ High Growth_Low Prices 2026-2027 Aug 1.95$ 2.09$ 1.95$ 1.95$ 1.95$ 1.92$ 1.92$ 2.09$ 1.97$ 1.98$ High Growth_Low Prices 2026-2027 Sep 1.66$ 2.09$ 1.66$ 1.66$ 1.66$ 1.63$ 1.63$ 2.09$ 1.79$ 1.75$ High Growth_Low Prices 2026-2027 Oct 1.75$ 2.20$ 1.75$ 1.75$ 1.75$ 1.72$ 1.72$ 2.20$ 1.88$ 1.84$ High Growth_Low Prices 2027-2028 Nov 1.71$ 1.91$ 1.71$ 1.71$ 1.71$ 1.78$ 1.67$ 1.91$ 1.79$ 1.75$ High Growth_Low Prices 2027-2028 Dec 1.79$ 1.81$ 66.26$ 66.26$ 66.26$ 1.67$ 1.12$ 1.81$ 1.53$ 40.48$ High Growth_Low Prices 2027-2028 Jan 2.03$ 2.36$ 2.03$ 2.03$ 2.03$ 2.16$ 1.76$ 2.16$ 2.02$ 2.10$ High Growth_Low Prices 2027-2028 Feb 1.96$ 2.23$ 1.96$ 1.96$ 1.96$ 2.18$ 1.90$ 2.18$ 2.09$ 2.01$ High Growth_Low Prices 2027-2028 Mar 1.55$ 2.10$ 1.55$ 1.55$ 1.55$ 1.53$ 1.52$ 2.10$ 1.72$ 1.66$ High Growth_Low Prices 2027-2028 Apr 1.31$ 2.10$ 1.31$ 1.31$ 1.31$ 1.29$ 1.29$ 2.10$ 1.56$ 1.47$ High Growth_Low Prices 2027-2028 May 1.60$ 2.10$ 1.60$ 1.60$ 1.60$ 1.58$ 1.58$ 2.10$ 1.75$ 1.70$ High Growth_Low Prices 2027-2028 Jun 1.68$ 2.10$ 1.68$ 1.68$ 1.68$ 1.65$ 1.65$ 2.10$ 1.80$ 1.76$
High Growth_Low Prices 2027-2028 Jul 2.24$ 2.22$ 2.22$ 2.22$ 2.22$ 2.21$ 2.21$ 2.22$ 2.21$ 2.22$
High Growth_Low Prices 2027-2028 Aug 2.05$ 2.10$ 2.05$ 2.05$ 2.05$ 2.02$ 2.02$ 2.10$ 2.05$ 2.06$
High Growth_Low Prices 2027-2028 Sep 1.55$ 1.92$ 1.55$ 1.55$ 1.55$ 1.52$ 1.52$ 2.10$ 1.72$ 1.62$
High Growth_Low Prices 2027-2028 Oct 1.79$ 2.14$ 1.79$ 1.79$ 1.79$ 1.76$ 1.76$ 2.14$ 1.89$ 1.86$
High Growth_Low Prices 2028-2029 Nov 1.80$ 2.04$ 1.80$ 1.80$ 1.80$ 1.86$ 1.74$ 2.04$ 1.88$ 1.84$
High Growth_Low Prices 2028-2029 Dec 1.74$ 1.79$ 66.24$ 66.24$ 66.24$ 1.75$ 1.20$ 1.79$ 1.58$ 40.45$
High Growth_Low Prices 2028-2029 Jan 2.07$ 2.37$ 2.07$ 2.07$ 2.07$ 2.16$ 1.82$ 2.16$ 2.05$ 2.13$
High Growth_Low Prices 2028-2029 Feb 2.03$ 2.26$ 2.03$ 2.03$ 2.03$ 2.20$ 1.98$ 2.20$ 2.12$ 2.08$
High Growth_Low Prices 2028-2029 Mar 1.62$ 2.11$ 1.62$ 1.62$ 1.62$ 1.64$ 1.59$ 2.11$ 1.78$ 1.72$
High Growth_Low Prices 2028-2029 Apr 1.33$ 2.11$ 1.33$ 1.33$ 1.33$ 1.31$ 1.31$ 2.11$ 1.57$ 1.49$
High Growth_Low Prices 2028-2029 May 1.75$ 2.11$ 1.75$ 1.75$ 1.75$ 1.72$ 1.72$ 2.11$ 1.85$ 1.82$
High Growth_Low Prices 2028-2029 Jun 1.73$ 2.11$ 1.73$ 1.73$ 1.73$ 1.70$ 1.70$ 2.11$ 1.84$ 1.80$
High Growth_Low Prices 2028-2029 Jul 2.25$ 2.23$ 2.23$ 2.23$ 2.23$ 2.22$ 2.22$ 2.23$ 2.22$ 2.23$
High Growth_Low Prices 2028-2029 Aug 2.08$ 2.11$ 2.08$ 2.08$ 2.08$ 2.05$ 2.05$ 2.11$ 2.07$ 2.09$
High Growth_Low Prices 2028-2029 Sep 1.72$ 2.07$ 1.72$ 1.72$ 1.72$ 1.69$ 1.69$ 2.11$ 1.83$ 1.79$
High Growth_Low Prices 2028-2029 Oct 1.81$ 2.15$ 1.81$ 1.81$ 1.81$ 1.78$ 1.78$ 2.15$ 1.90$ 1.88$
1/ Avoided costs are before Environmental Externalities adder.
Monthly Avoided Costs 1/
2014$
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 194 of 648

APPENDIX 5.4: HIGH GROWTH – LOW PRICE MONTHLY DETAIL

Scenario Gas Year Month Klam Falls La Grande Medford GTN Medford NWP Roseburg Wa/Id Both Wa/Id GTN Wa/Id NWP WA/ID Annual OR Annual
High Growth_Low Prices 2029-2030 Nov 1.78$ 2.08$ 1.78$ 1.78$ 1.78$ 1.85$ 1.68$ 2.08$ 1.87$ 1.84$
High Growth_Low Prices 2029-2030 Dec 2.03$ 2.05$ 66.49$ 66.49$ 66.49$ 1.94$ 1.41$ 2.05$ 1.80$ 40.71$
High Growth_Low Prices 2029-2030 Jan 2.06$ 2.39$ 2.06$ 2.06$ 2.06$ 2.22$ 1.83$ 2.22$ 2.09$ 2.13$
High Growth_Low Prices 2029-2030 Feb 2.07$ 2.29$ 2.07$ 2.07$ 2.07$ 2.24$ 2.03$ 2.24$ 2.17$ 2.11$
High Growth_Low Prices 2029-2030 Mar 1.64$ 2.16$ 1.64$ 1.64$ 1.64$ 1.66$ 1.61$ 2.16$ 1.81$ 1.75$ High Growth_Low Prices 2029-2030 Apr 1.37$ 2.16$ 1.37$ 1.37$ 1.37$ 1.34$ 1.34$ 2.16$ 1.62$ 1.53$ High Growth_Low Prices 2029-2030 May 1.65$ 2.16$ 1.65$ 1.65$ 1.65$ 1.62$ 1.62$ 2.16$ 1.80$ 1.75$ High Growth_Low Prices 2029-2030 Jun 1.75$ 2.16$ 1.75$ 1.75$ 1.75$ 1.72$ 1.72$ 2.16$ 1.87$ 1.83$ High Growth_Low Prices 2029-2030 Jul 2.31$ 2.28$ 2.28$ 2.28$ 2.28$ 2.27$ 2.27$ 2.28$ 2.27$ 2.29$ High Growth_Low Prices 2029-2030 Aug 2.12$ 2.17$ 2.12$ 2.12$ 2.12$ 2.09$ 2.09$ 2.17$ 2.11$ 2.13$ High Growth_Low Prices 2029-2030 Sep 1.86$ 2.17$ 1.86$ 1.86$ 1.86$ 1.83$ 1.83$ 2.17$ 1.94$ 1.92$ High Growth_Low Prices 2029-2030 Oct 1.84$ 2.26$ 1.84$ 1.84$ 1.84$ 1.81$ 1.81$ 2.26$ 1.96$ 1.92$ High Growth_Low Prices 2030-2031 Nov 1.84$ 2.13$ 1.84$ 1.84$ 1.84$ 1.87$ 1.69$ 2.13$ 1.90$ 1.90$ High Growth_Low Prices 2030-2031 Dec 1.95$ 1.98$ 130.87$ 130.87$ 130.87$ 1.97$ 1.45$ 1.98$ 1.80$ 79.31$ High Growth_Low Prices 2030-2031 Jan 2.17$ 2.35$ 2.17$ 2.17$ 2.17$ 2.23$ 1.90$ 2.23$ 2.12$ 2.21$ High Growth_Low Prices 2030-2031 Feb 2.13$ 73.63$ 2.13$ 2.13$ 2.13$ 2.26$ 2.09$ 2.26$ 2.20$ 16.43$ High Growth_Low Prices 2030-2031 Mar 1.67$ 2.17$ 1.67$ 1.67$ 1.67$ 1.68$ 1.64$ 2.17$ 1.83$ 1.77$ High Growth_Low Prices 2030-2031 Apr 1.46$ 2.11$ 1.46$ 1.46$ 1.46$ 1.43$ 1.43$ 2.17$ 1.68$ 1.59$ High Growth_Low Prices 2030-2031 May 1.74$ 2.17$ 1.74$ 1.74$ 1.74$ 1.71$ 1.71$ 2.17$ 1.87$ 1.83$ High Growth_Low Prices 2030-2031 Jun 1.81$ 2.17$ 1.81$ 1.81$ 1.81$ 1.78$ 1.78$ 2.17$ 1.91$ 1.88$ High Growth_Low Prices 2030-2031 Jul 2.32$ 2.30$ 2.30$ 2.30$ 2.30$ 2.29$ 2.29$ 2.30$ 2.29$ 2.30$ High Growth_Low Prices 2030-2031 Aug 2.14$ 2.17$ 2.14$ 2.14$ 2.14$ 2.11$ 2.11$ 2.17$ 2.13$ 2.15$ High Growth_Low Prices 2030-2031 Sep 1.85$ 2.15$ 1.85$ 1.85$ 1.85$ 1.82$ 1.82$ 2.17$ 1.94$ 1.91$
High Growth_Low Prices 2030-2031 Oct 1.89$ 2.24$ 1.89$ 1.89$ 1.89$ 1.86$ 1.86$ 2.24$ 1.99$ 1.96$
High Growth_Low Prices 2031-2032 Nov 1.95$ 2.19$ 1.95$ 1.95$ 1.95$ 2.05$ 1.83$ 2.19$ 2.03$ 2.00$
High Growth_Low Prices 2031-2032 Dec 1.75$ 1.81$ 130.70$ 130.70$ 130.70$ 1.81$ 1.30$ 1.81$ 1.64$ 79.13$
High Growth_Low Prices 2031-2032 Jan 2.18$ 2.36$ 2.18$ 2.18$ 2.18$ 2.24$ 1.91$ 2.24$ 2.13$ 2.21$
High Growth_Low Prices 2031-2032 Feb 2.12$ 71.20$ 2.12$ 2.12$ 2.12$ 71.14$ 2.08$ 71.14$ 48.12$ 15.94$
High Growth_Low Prices 2031-2032 Mar 1.77$ 2.18$ 1.77$ 1.77$ 1.77$ 1.80$ 1.74$ 2.18$ 1.91$ 1.85$
High Growth_Low Prices 2031-2032 Apr 1.50$ 2.14$ 1.50$ 1.50$ 1.50$ 1.48$ 1.48$ 2.16$ 1.71$ 1.63$
High Growth_Low Prices 2031-2032 May 1.87$ 2.16$ 1.87$ 1.87$ 1.87$ 1.84$ 1.84$ 2.16$ 1.95$ 1.93$
High Growth_Low Prices 2031-2032 Jun 1.85$ 2.17$ 1.85$ 1.85$ 1.85$ 1.82$ 1.82$ 2.17$ 1.94$ 1.92$
High Growth_Low Prices 2031-2032 Jul 2.33$ 2.31$ 2.31$ 2.31$ 2.31$ 2.30$ 2.30$ 2.31$ 2.30$ 2.31$
High Growth_Low Prices 2031-2032 Aug 2.21$ 2.19$ 2.19$ 2.19$ 2.19$ 2.18$ 2.18$ 2.19$ 2.18$ 2.19$
High Growth_Low Prices 2031-2032 Sep 1.82$ 2.14$ 1.82$ 1.82$ 1.82$ 1.79$ 1.79$ 2.17$ 1.91$ 1.88$
High Growth_Low Prices 2031-2032 Oct 1.89$ 2.27$ 1.89$ 1.89$ 1.89$ 1.86$ 1.86$ 2.27$ 2.00$ 1.97$
High Growth_Low Prices 2032-2033 Nov 1.86$ 2.17$ 1.86$ 1.86$ 1.86$ 1.98$ 1.69$ 2.17$ 1.95$ 1.92$
High Growth_Low Prices 2032-2033 Dec 1.87$ 1.91$ 130.80$ 130.80$ 130.80$ 1.91$ 1.45$ 1.91$ 1.76$ 79.24$
High Growth_Low Prices 2032-2033 Jan 2.17$ 2.38$ 2.17$ 2.17$ 2.17$ 2.23$ 1.95$ 2.23$ 2.13$ 2.21$
High Growth_Low Prices 2032-2033 Feb 2.17$ 73.66$ 2.17$ 2.17$ 2.17$ 73.61$ 2.13$ 73.61$ 49.78$ 16.47$
High Growth_Low Prices 2032-2033 Mar 1.74$ 2.17$ 1.74$ 1.74$ 1.74$ 1.77$ 1.71$ 2.17$ 1.88$ 1.83$
High Growth_Low Prices 2032-2033 Apr 1.52$ 2.15$ 1.52$ 1.52$ 1.52$ 1.50$ 1.50$ 2.17$ 1.72$ 1.65$
High Growth_Low Prices 2032-2033 May 1.91$ 2.17$ 1.91$ 1.91$ 1.91$ 1.88$ 1.88$ 2.17$ 1.98$ 1.96$
High Growth_Low Prices 2032-2033 Jun 1.86$ 2.17$ 1.86$ 1.86$ 1.86$ 1.83$ 1.83$ 2.17$ 1.95$ 1.92$
High Growth_Low Prices 2032-2033 Jul 2.41$ 2.38$ 2.38$ 2.38$ 2.38$ 2.37$ 2.37$ 2.38$ 2.37$ 2.39$
High Growth_Low Prices 2032-2033 Aug 2.26$ 2.24$ 2.24$ 2.24$ 2.24$ 2.23$ 2.23$ 2.24$ 2.23$ 2.24$
High Growth_Low Prices 2032-2033 Sep 1.67$ 2.04$ 1.67$ 1.67$ 1.67$ 1.64$ 1.64$ 2.18$ 1.82$ 1.74$
High Growth_Low Prices 2032-2033 Oct 1.90$ 2.30$ 1.90$ 1.90$ 1.90$ 1.87$ 1.87$ 2.30$ 2.01$ 1.98$
High Growth_Low Prices 2033-2034 Nov 2.03$ 2.24$ 2.03$ 2.03$ 2.03$ 2.15$ 1.92$ 2.24$ 2.10$ 2.07$
High Growth_Low Prices 2033-2034 Dec 1.96$ 2.02$ 130.90$ 130.90$ 130.90$ 1.90$ 1.34$ 2.02$ 1.75$ 79.34$
High Growth_Low Prices 2033-2034 Jan 2.22$ 2.40$ 2.22$ 2.22$ 2.22$ 2.28$ 1.94$ 2.28$ 2.17$ 2.26$
High Growth_Low Prices 2033-2034 Feb 2.17$ 73.71$ 2.17$ 2.17$ 2.17$ 73.66$ 2.13$ 73.66$ 49.82$ 16.48$
High Growth_Low Prices 2033-2034 Mar 1.69$ 2.22$ 1.69$ 1.69$ 1.69$ 1.73$ 1.66$ 2.22$ 1.87$ 1.80$
High Growth_Low Prices 2033-2034 Apr 1.48$ 2.21$ 1.48$ 1.48$ 1.48$ 1.45$ 1.45$ 2.22$ 1.71$ 1.62$
High Growth_Low Prices 2033-2034 May 1.75$ 2.22$ 1.75$ 1.75$ 1.75$ 1.73$ 1.73$ 2.22$ 1.89$ 1.85$
High Growth_Low Prices 2033-2034 Jun 1.83$ 2.22$ 1.83$ 1.83$ 1.83$ 1.80$ 1.80$ 2.22$ 1.94$ 1.91$
High Growth_Low Prices 2033-2034 Jul 2.36$ 2.33$ 2.33$ 2.33$ 2.33$ 2.32$ 2.32$ 2.33$ 2.33$ 2.34$
High Growth_Low Prices 2033-2034 Aug 2.18$ 2.22$ 2.18$ 2.18$ 2.18$ 2.15$ 2.15$ 2.23$ 2.17$ 2.19$
High Growth_Low Prices 2033-2034 Sep 2.02$ 2.23$ 2.02$ 2.02$ 2.02$ 1.99$ 1.99$ 2.23$ 2.07$ 2.06$
High Growth_Low Prices 2033-2034 Oct 1.90$ 2.31$ 1.90$ 1.90$ 1.90$ 1.87$ 1.87$ 2.31$ 2.02$ 1.98$
High Growth_Low Prices 2034-2035 Nov 1.87$ 2.21$ 1.87$ 1.87$ 1.87$ 2.03$ 1.70$ 2.21$ 1.98$ 1.94$
High Growth_Low Prices 2034-2035 Dec 66.48$ 2.07$ 130.95$ 130.95$ 130.95$ 1.90$ 1.35$ 2.09$ 1.78$ 92.28$
High Growth_Low Prices 2034-2035 Jan 2.23$ 2.39$ 2.23$ 2.23$ 2.23$ 2.29$ 1.98$ 2.29$ 2.18$ 2.26$
High Growth_Low Prices 2034-2035 Feb 2.19$ 73.70$ 2.19$ 2.19$ 2.19$ 73.64$ 2.14$ 73.64$ 49.81$ 16.49$
High Growth_Low Prices 2034-2035 Mar 1.88$ 2.21$ 1.88$ 1.88$ 1.88$ 1.90$ 1.85$ 2.21$ 1.99$ 1.95$
High Growth_Low Prices 2034-2035 Apr 1.61$ 2.08$ 1.61$ 1.61$ 1.61$ 1.59$ 1.59$ 2.08$ 1.75$ 1.71$
High Growth_Low Prices 2034-2035 May 1.85$ 2.08$ 1.85$ 1.85$ 1.85$ 1.82$ 1.82$ 2.08$ 1.91$ 1.90$
High Growth_Low Prices 2034-2035 Jun 1.79$ 2.08$ 1.79$ 1.79$ 1.79$ 1.76$ 1.76$ 2.08$ 1.87$ 1.85$ High Growth_Low Prices 2034-2035 Jul 2.30$ 2.28$ 2.28$ 2.28$ 2.28$ 2.27$ 2.27$ 2.28$ 2.27$ 2.28$ High Growth_Low Prices 2034-2035 Aug 2.20$ 2.18$ 2.18$ 2.18$ 2.18$ 2.17$ 2.17$ 2.18$ 2.17$ 2.18$ High Growth_Low Prices 2034-2035 Sep 1.83$ 2.08$ 1.83$ 1.83$ 1.83$ 1.80$ 1.80$ 2.08$ 1.90$ 1.88$ High Growth_Low Prices 2034-2035 Oct 1.88$ 2.32$ 1.88$ 1.88$ 1.88$ 1.85$ 1.85$ 2.32$ 2.00$ 1.96$ 1/ Avoided costs are before Environmental Externalities adder.
Monthly Avoided Costs 1/
2014$
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 195 of 648
APPENDIX 6.1: HIGH GROWTH CASES
SELECTED RESOURCES VS. PEAK DAY DEMAND
EXISTING PLUS EXPECTED AVAILABLE

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 196 of 648
APPENDIX 6.1: HIGH GROWTH CASES
SELECTED RESOURCES VS. PEAK DAY DEMAND
EXISTING PLUS EXPECTED AVAILABLE

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 197 of 648
APPENDIX 6.2: PEAK DAY DEMAND TABLE
HIGH GROWTH

Scenario Gas Year
LaGrande
Served
LaGrande
Unserved
LaGrande
Total
LaGrande %
of Peak Day
Served WA/ID Served WA/ID Unserved WA/ID Total
WA/ID % of Peak
Day Served
High Growth_Low Prices 2015-2016 8.07 - 8.07 100%268.99 - 268.99 100%
High Growth_Low Prices 2016-2017 8.10 - 8.10 100%271.70 - 271.70 100%
High Growth_Low Prices 2017-2018 8.16 - 8.16 100%275.19 - 275.19 100%High Growth_Low Prices 2018-2019 8.23 - 8.23 100%278.70 - 278.70 100%
High Growth_Low Prices 2019-2020 8.30 - 8.30 100%282.34 - 282.34 100%
High Growth_Low Prices 2020-2021 8.37 - 8.37 100%286.10 - 286.10 100%
High Growth_Low Prices 2021-2022 8.44 - 8.44 100%289.71 - 289.71 100%High Growth_Low Prices 2022-2023 8.50 - 8.50 100%293.10 - 293.10 100%
High Growth_Low Prices 2023-2024 8.57 - 8.57 100%296.62 - 296.62 100%
High Growth_Low Prices 2024-2025 8.62 - 8.62 100%299.85 - 299.85 100%High Growth_Low Prices 2025-2026 8.68 - 8.68 100%303.12 - 303.12 100%
High Growth_Low Prices 2026-2027 8.73 - 8.73 100%306.24 - 306.24 100%
High Growth_Low Prices 2027-2028 8.81 - 8.81 100%309.62 - 309.62 100%High Growth_Low Prices 2028-2029 8.89 - 8.89 100%312.57 - 312.57 100%
High Growth_Low Prices 2029-2030 8.97 - 8.97 100%315.67 - 315.67 100%
High Growth_Low Prices 2030-2031 8.98 0.06 9.04 99%318.74 - 318.74 100%High Growth_Low Prices 2031-2032 6.73 2.38 9.11 74%322.05 - 322.05 100%
High Growth_Low Prices 2032-2033 6.51 2.66 9.17 71%322.02 2.78 324.80 99%
High Growth_Low Prices 2033-2034 6.50 2.72 9.23 70%321.82 6.01 327.83 98%High Growth_Low Prices 2034-2035 8.95 0.35 9.30 96%319.61 12.14 331.75 96%
Scenario Gas Year
Klamath
Falls
Served
Klamath
Falls
Unserved
Klamath
Falls Total
Klamath
Falls % of
Peak Day
Served

Medford/Roseburg
Served

Medford/Roseburg
Unserved
Medford/Roseburg
Total
Medford/Roseburg
% of Peak Day
Served
High Growth_Low Prices 2015-2016 13.32 - 13.32 100%71.97 - 71.97 100%
High Growth_Low Prices 2016-2017 13.43 - 13.43 100%73.29 - 73.29 100%High Growth_Low Prices 2017-2018 13.63 - 13.63 100%74.61 - 74.61 100%
High Growth_Low Prices 2018-2019 13.85 - 13.85 100%76.04 - 76.04 100%
High Growth_Low Prices 2019-2020 14.07 - 14.07 100%77.51 - 77.51 100%High Growth_Low Prices 2020-2021 14.31 - 14.31 100%79.02 - 79.02 100%
High Growth_Low Prices 2021-2022 14.54 - 14.54 100%80.43 - 80.43 100%
High Growth_Low Prices 2022-2023 14.78 - 14.78 100%81.66 - 81.66 100%High Growth_Low Prices 2023-2024 15.02 - 15.02 100%82.86 - 82.86 100%
High Growth_Low Prices 2024-2025 15.26 - 15.26 100%84.05 - 84.05 100%
High Growth_Low Prices 2025-2026 15.49 - 15.49 100%85.23 - 85.23 100%High Growth_Low Prices 2026-2027 15.71 - 15.71 100%86.38 - 86.38 100%
High Growth_Low Prices 2027-2028 15.93 - 15.93 100%87.18 0.37 87.55 100%
High Growth_Low Prices 2028-2029 16.14 - 16.14 100%87.10 1.59 88.69 98%High Growth_Low Prices 2029-2030 16.34 - 16.34 100%87.02 2.77 89.79 97%
High Growth_Low Prices 2030-2031 16.53 - 16.53 100%86.93 3.92 90.85 96%
High Growth_Low Prices 2031-2032 16.72 - 16.72 100%86.85 5.01 91.85 95%
High Growth_Low Prices 2032-2033 16.92 - 16.92 100%86.76 6.05 92.81 93%
High Growth_Low Prices 2033-2034 17.12 - 17.12 100%86.68 7.06 93.74 92%
High Growth_Low Prices 2034-2035 17.24 0.10 17.33 99%86.66 8.03 94.70 92%
Peak Day Demand - Served and Unserved (MDth/d)
Before Resource Additions & Net of DSM Savings
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 198 of 648
APPENDIX 6.2: PEAK DAY DEMAND TABLE
LOW GROWTH

Scenario Gas Year
LaGrande
Served
LaGrande
Unserved
LaGrande
Total
LaGrande
% of Peak
Day
Served WA/ID Served WA/ID Unserved WA/ID Total
WA/ID % of Peak
Day Served
Low Growth_High Prices 2015-2016 8.05 - 8.05 100%267.17 - 267.17 100%
Low Growth_High Prices 2016-2017 7.05 - 7.05 100%232.26 - 232.26 100%
Low Growth_High Prices 2017-2018 7.00 - 7.00 100%230.85 - 230.85 100%
Low Growth_High Prices 2018-2019 6.92 - 6.92 100%228.16 - 228.16 100%Low Growth_High Prices 2019-2020 6.92 - 6.92 100%228.60 - 228.60 100%
Low Growth_High Prices 2020-2021 6.92 - 6.92 100%228.86 - 228.86 100%
Low Growth_High Prices 2021-2022 6.91 - 6.91 100%229.25 - 229.25 100%Low Growth_High Prices 2022-2023 6.90 - 6.90 100%229.40 - 229.40 100%
Low Growth_High Prices 2023-2024 6.90 - 6.90 100%229.85 - 229.85 100%
Low Growth_High Prices 2024-2025 6.86 - 6.86 100%228.67 - 228.67 100%
Low Growth_High Prices 2025-2026 6.86 - 6.86 100%228.78 - 228.78 100%
Low Growth_High Prices 2026-2027 6.85 - 6.85 100%228.99 - 228.99 100%
Low Growth_High Prices 2027-2028 6.84 - 6.84 100%229.38 - 229.38 100%
Low Growth_High Prices 2028-2029 6.80 - 6.80 100%228.35 - 228.35 100%Low Growth_High Prices 2029-2030 6.78 - 6.78 100%228.16 - 228.16 100%
Low Growth_High Prices 2030-2031 6.75 - 6.75 100%227.70 - 227.70 100%
Low Growth_High Prices 2031-2032 6.73 - 6.73 100%227.64 - 227.64 100%Low Growth_High Prices 2032-2033 6.72 - 6.72 100%227.47 - 227.47 100%
Low Growth_High Prices 2033-2034 6.70 - 6.70 100%227.07 - 227.07 100%
Low Growth_High Prices 2034-2035 6.71 - 6.71 100%227.90 - 227.90 100%
Scenario Gas Year
Klamath
Falls Served
Klamath
Falls
Unserved
Klamath
Falls Total
Klamath
Falls % of
Peak Day
Served
Medford/Roseburg
Served
Medford/Roseburg
Unserved
Medford/Roseburg
Total
Medford/Roseburg
% of Peak Day
Served
Low Growth_High Prices 2015-2016 13.32 - 13.32 100%71.95 - 71.95 100%
Low Growth_High Prices 2016-2017 11.64 - 11.64 100%62.78 - 62.78 100%
Low Growth_High Prices 2017-2018 11.63 - 11.63 100%62.67 - 62.67 100%Low Growth_High Prices 2018-2019 11.55 - 11.55 100%62.32 - 62.32 100%
Low Growth_High Prices 2019-2020 11.63 - 11.63 100%62.78 - 62.78 100%
Low Growth_High Prices 2020-2021 11.70 - 11.70 100%63.23 - 63.23 100%Low Growth_High Prices 2021-2022 11.77 - 11.77 100%63.63 - 63.63 100%
Low Growth_High Prices 2022-2023 11.83 - 11.83 100%63.90 - 63.90 100%
Low Growth_High Prices 2023-2024 11.90 - 11.90 100%64.18 - 64.18 100%
Low Growth_High Prices 2024-2025 11.90 - 11.90 100%64.09 - 64.09 100%Low Growth_High Prices 2025-2026 11.96 - 11.96 100%64.31 - 64.31 100%
Low Growth_High Prices 2026-2027 12.02 - 12.02 100%64.55 - 64.55 100%
Low Growth_High Prices 2027-2028 12.07 - 12.07 100%64.78 - 64.78 100%Low Growth_High Prices 2028-2029 12.08 - 12.08 100%64.73 - 64.73 100%
Low Growth_High Prices 2029-2030 12.11 - 12.11 100%64.83 - 64.83 100%
Low Growth_High Prices 2030-2031 12.13 - 12.13 100%64.85 - 64.85 100%Low Growth_High Prices 2031-2032 12.16 - 12.16 100%64.88 - 64.88 100%
Low Growth_High Prices 2032-2033 12.20 - 12.20 100%65.00 - 65.00 100%
Low Growth_High Prices 2033-2034 12.22 - 12.22 100%64.98 - 64.98 100%
Low Growth_High Prices 2034-2035 12.27 - 12.27 100%65.09 - 65.09 100%
Peak Day Demand - Served and Unserved (MDth/d)
Before Resource Additions & Net of DSM Savings
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 199 of 648
APPENDIX 6.2: PEAK DAY DEMAND TABLE
COLDEST IN 20 YEARS

Scenario Gas Year
LaGrande
Served

LaGrande
Unserved
LaGrande
Total
LaGrande
% of Peak
Day
Served WA/ID Served WA/ID Unserved WA/ID Total
WA/ID % of Peak
Day Served
Cold Day 20yr Weather Std 2015-2016 8.05 - 8.05 100%249.82 - 249.82 100%
Cold Day 20yr Weather Std 2016-2017 8.07 - 8.07 100%251.31 - 251.31 100%
Cold Day 20yr Weather Std 2017-2018 8.10 - 8.10 100%253.32 - 253.32 100%
Cold Day 20yr Weather Std 2018-2019 8.14 - 8.14 100%255.25 - 255.25 100%Cold Day 20yr Weather Std 2019-2020 8.17 - 8.17 100%257.27 - 257.27 100%
Cold Day 20yr Weather Std 2020-2021 8.20 - 8.20 100%259.27 - 259.27 100%
Cold Day 20yr Weather Std 2021-2022 8.23 - 8.23 100%261.18 - 261.18 100%Cold Day 20yr Weather Std 2022-2023 8.25 - 8.25 100%262.96 - 262.96 100%
Cold Day 20yr Weather Std 2023-2024 8.28 - 8.28 100%264.84 - 264.84 100%
Cold Day 20yr Weather Std 2024-2025 8.30 - 8.30 100%266.42 - 266.42 100%
Cold Day 20yr Weather Std 2025-2026 8.32 - 8.32 100%268.06 - 268.06 100%
Cold Day 20yr Weather Std 2026-2027 8.35 - 8.35 100%269.63 - 269.63 100%
Cold Day 20yr Weather Std 2027-2028 8.37 - 8.37 100%271.39 - 271.39 100%
Cold Day 20yr Weather Std 2028-2029 8.40 - 8.40 100%272.72 - 272.72 100%Cold Day 20yr Weather Std 2029-2030 8.42 - 8.42 100%274.21 - 274.21 100%
Cold Day 20yr Weather Std 2030-2031 8.45 - 8.45 100%275.68 - 275.68 100%
Cold Day 20yr Weather Std 2031-2032 8.47 - 8.47 100%277.38 - 277.38 100%Cold Day 20yr Weather Std 2032-2033 8.49 - 8.49 100%278.54 - 278.54 100%
Cold Day 20yr Weather Std 2033-2034 8.51 - 8.51 100%279.95 - 279.95 100%
Cold Day 20yr Weather Std 2034-2035 8.55 - 8.55 100%282.29 - 282.29 100%
Scenario Gas Year
Klamath
Falls Served
Klamath
Falls
Unserved
Klamath
Falls Total
Klamath
Falls % of
Peak Day
Served
Medford/Roseburg
Served
Medford/Roseburg
Unserved
Medford/Roseburg
Total
Medford/Roseburg
% of Peak Day
Served
Cold Day 20yr Weather Std 2015-2016 13.32 - 13.32 100%64.18 - 64.18 100%
Cold Day 20yr Weather Std 2016-2017 13.42 - 13.42 100%64.88 - 64.88 100%
Cold Day 20yr Weather Std 2017-2018 13.57 - 13.57 100%65.70 - 65.70 100%Cold Day 20yr Weather Std 2018-2019 13.73 - 13.73 100%66.60 - 66.60 100%
Cold Day 20yr Weather Std 2019-2020 13.90 - 13.90 100%67.51 - 67.51 100%
Cold Day 20yr Weather Std 2020-2021 14.06 - 14.06 100%68.43 - 68.43 100%Cold Day 20yr Weather Std 2021-2022 14.23 - 14.23 100%69.26 - 69.26 100%
Cold Day 20yr Weather Std 2022-2023 14.39 - 14.39 100%69.96 - 69.96 100%
Cold Day 20yr Weather Std 2023-2024 14.56 - 14.56 100%70.63 - 70.63 100%
Cold Day 20yr Weather Std 2024-2025 14.72 - 14.72 100%71.28 - 71.28 100%Cold Day 20yr Weather Std 2025-2026 14.88 - 14.88 100%71.92 - 71.92 100%
Cold Day 20yr Weather Std 2026-2027 15.03 - 15.03 100%72.55 - 72.55 100%
Cold Day 20yr Weather Std 2027-2028 15.17 - 15.17 100%73.17 - 73.17 100%Cold Day 20yr Weather Std 2028-2029 15.31 - 15.31 100%73.76 - 73.76 100%
Cold Day 20yr Weather Std 2029-2030 15.44 - 15.44 100%74.33 - 74.33 100%
Cold Day 20yr Weather Std 2030-2031 15.57 - 15.57 100%74.87 - 74.87 100%Cold Day 20yr Weather Std 2031-2032 15.70 - 15.70 100%75.37 - 75.37 100%
Cold Day 20yr Weather Std 2032-2033 15.83 - 15.83 100%75.83 - 75.83 100%
Cold Day 20yr Weather Std 2033-2034 15.96 - 15.96 100%76.28 - 76.28 100%
Cold Day 20yr Weather Std 2034-2035 16.10 - 16.10 100%76.77 - 76.77 100%
Peak Day Demand - Served and Unserved (MDth/d)
Before Resource Additions & Net of DSM Savings
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 200 of 648
APPENDIX 6.2: ALTERNATE SUPPLY RESOURCES

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 201 of 648
APPENDIX 7.1: DISTRIBUTION SYSTEM MODELING

OVERVIEW
The primary goal of distribution system planning is to design for present needs and to plan for future
expansion in order to serve demand growth. This allows Avista to satisfy current demand-serving
requirements, while taking steps toward meeting future needs. Distribution system planning identifies
potential problems and areas of the distribution system that require reinforcement. By knowing when and
where pressure problems may occur, the necessary reinforcements can be incorporated into normal
maintenance. Thus, more costly reactive and emergency solutions can be avoided.

COMPUTER MODELING
When designing new main extensions, computer modeling can help determine the optimum size facilities
for present and future needs. Undersized facilities are costly to replace, and oversized facilities incur
unnecessary expenses to Avista and its customers.

THEORY AND APPLICATION OF STUDY
Natural gas network load studies have evolved in the last decade to become a highly technical and useful
means of analyzing the operation of a distribution system. Using a pipeline fluid flow formula, a specified
parameter of each pipe element can be simultaneously solved. Through years of research, pipeline
equations have been refined to the point where solutions obtained closely represent actual system
behavior.

Avista conducts network load studies using GL Noble Denton’s Synergi® 4.8.0 software. This computer-
based modeling tool runs on a Windows operating system and allows users to analyze and interpret
solutions graphically.

CREATING A MODEL
To properly study the distribution system, all natural gas main information is entered (length, pipe
roughness and size) into the model. "Main" refers to all pipelines supplying services.
Nodes are placed at all pipe intersections, beginnings and ends of mains, changes in pipe
diameter/material, and to identify all large customers. A model element connects two nodes together.
Therefore, a "to node" and a "from node" will represent an element between those two nodes. Almost all
of the elements in a model are pipes.

Regulators are treated like adjustable valves in which the downstream pressure is set to a known value.
Although specific regulator types can be entered for realistic behavior, the expected flow passing through
the actual regulator is determined and the modeled regulator is forced to accommodate such flows.

FLUID MECHANICS OF THE MODEL
Pipe flow equations are used to determine the relationships between flow, pressure drop, diameter and
pipe length. For all models, the Fundamental Flow equation (FM) is used due to its demonstrated
reliability.
Efficiency factors are used to account for the equivalent resistance of valves, fittings and angle changes
within the distribution system. Starting with a 95 percent factor, the efficiency can be changed to fine tune
the model to match field results.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 202 of 648
Pipe roughness, along with flow conditions, creates a friction factor for all pipes within a system. Thus,
each pipe may have a unique friction factor, minimizing computational errors associated with generalized
friction values.

LOAD DATA
All studies are considered steady state; all natural gas entering the distribution system must equal the
natural gas exiting the distribution system at any given time.

Customer loads are obtained from Avista’s customer billing system and converted to an algebraic format
so loads can be generated for various conditions. Customer Management Module (CMM), an add-on
application for Synergi, processes customer usage history and generates a base load (non-temperature
dependent) and heat load (varying with temperature) for each customer.

In the event of a peak day or an extremely cold weather condition, it is assumed that all curtailable loads
are interrupted. Therefore, the models will be conducted with only core loads.

DETERMINING NATURAL GAS CUSTOMERS’ MAXIMUM HOURLY USAGE
DETERMINING DESIGN PEAK HOURLY LOAD
The design peak hourly load for a customer is estimated by adding the hourly base load and the hourly
heat load for a design temperature. This estimate reflects highest system hourly demands, as shown in
Table 1:

This method differs from the approach that is used for IRP peak day load planning. The primary reason
for this difference is due to the importance of responding to hourly peaking in the distribution system,
while IRP resource planning focuses on peak day requirements to the city gate.

APPLYING LOADS
Having estimated the peak loads for all customers in a particular service area, the model can be loaded.
The first step is to assign each load to the respective node or element.

GENERATING LOADS
Temperature-based and non-temperature-based loads are established for each node or element, thus loads
can be varied based on any temperature (HDD). Such a tool is necessary to evaluate the difference in flow
and pressure due to different weather conditions.

GEOGRAPHIC INFORMATION SYSTEM (GIS)
Several years ago Avista converted the natural gas facility maps to GIS. While the GIS can provide a
variety of map products, the true power lies in the analytical capabilities. A GIS consists of three
components: spatial operations, data association and map representation.

A GIS allows analysts to conduct spatial operations (relating a feature or facility to another
geographically). A spatial operation is possible if a facility displayed on a map maintains a relationship to
other facilities. Spatial relationships allow analysts to perform a multitude of queries, including:
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 203 of 648

number of customers assigned to particular pipes in Emergency Operating Procedure zones
(geographical areas defined to aid in the safe isolation in the event of an emergency)
-pressure pipeline proximity criteria

The second component of the GIS is data association. This allows analysts to model relationships
between facilities displayed on a map to tabular information in a database. Databases store facility
information, such as pipe size, pipe material, pressure rating, or related information (e.g., customer
databases, equipment databases and work management systems). Data association allows interactive
queries within a map-like environment.

Finally, the GIS provides a means to create maps of existing facilities in different scales, projections and
displays. In addition, the results of a comparative or spatial analysis can be presented pictorially. This
allows users to present complex analyses rapidly and in an easy-to-understand method.

BUILDING SYNERGI® MODELS FROM A GIS
The GIS can provide additional benefits through the ease of creation and maintenance of load studies.
Avista can create load studies from the GIS based on tabular data (attributes) installed during the mapping
process.

MAINTENANCE USING A GIS
The GIS helps maintain the existing distribution facility by allowing a design to be initiated on a GIS.
Currently, design jobs for the company’s natural gas system are managed through Avista’s Maximo tool.
Once jobs are completed, the as-built information is automatically updated on GIS, eliminating the need
to convert physical maps to a GIS at a later date. Because the facility is updated, load studies can remain
current by refreshing the analysis.

DEVELOPING A PRESENT CASE LOAD STUDY
In order for any model to have accuracy, a present case model has to be developed that reflects what the
system was doing when downstream pressures and flows are known. To establish the present case,
pressure recording instruments located throughout the distribution system are used.

These field instruments record pressure and temperature throughout the winter season. Various locations
recording simultaneously are used to validate the model. Customer loads on Synergi® are generated to
correspond with actual temperatures recorded on the instruments. An accurate model’s downstream
pressures will match the corresponding field instrument’s pressures. Efficiency factors are adjusted to
further refine the model's pressures and better match the actual conditions.

Since telemetry at the gate stations record hourly flow, temperature and pressure, these values are used to
validate the model. All loads are representative of the average daily temperature and are defined as hourly
flows. If the load generating method is truly accurate, all natural gas entering the actual system (physical)
equals total natural gas demand solved by the simulated system (model).

DEVELOPING A PEAK CASE LOAD STUDY
Using the calculated peak loads, a model can be analyzed to identify the behavior during a peak day. The
efficiency factors established in the present case are used throughout subsequent models.

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 204 of 648
ANALYZING RESULTS
After a model has been balanced, several features within the Synergi® model are used to interpret results.
Color plots are generated to depict flow direction, pressure, and pipe diameter with specific break points.
Reinforcements can be identified by visual inspection. When user edits are completed and the model is re-
balanced, pressure changes can be visually displayed, helping identify optimum reinforcements.

PLANNING CRITERIA
In most instances, models resulting in node pressures below 15 psig indicate a likelihood of distribution
low pressure, and therefore necessitate reinforcements. For most Avista distribution systems, a minimum
of 15 psig will ensure deliverability as natural gas exits the distribution mains and travels through service
pipelines to a customer’s meter. Some Avista distribution areas operate at lower pressures and are
assigned a minimum pressure of 5 psig for model results. Given a lower operating pressure, service
pipelines in such areas are sized accordingly to maintain reliability.

DETERMINING MAXIMUM CAPACITY FOR A SYSTEM
Using a peak day model, loads can be prorated at intervals until area pressures drop to 15 psig. At that
point, the total amount of natural gas entering the system equals the maximum capacity before new
construction is necessary. The difference between natural gas entering the system in this scenario and a
peak day model is the maximum additional capacity that can be added to the system.

Since the approximate natural gas usage for the average customer is known, it can be determined how
many new customers can be added to the distribution system before necessitating system reinforcements.
The above models and procedures are utilized with new construction proposals or pipe reinforcements to
determine the potential increase in capacity.

FIVE-YEAR FORECASTING
The intent of the load study forecasting is to predict the system’s behavior and reinforcements necessary
within the next five years. Various Avista personnel provide information to determine where and why
certain areas may experience growth.
By combining information from Avista’s demand forecast, IRP planning efforts, regional growth plans
and area developments, proposals for pipeline reinforcements and expansions are evaluated with
Synergi®.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 205 of 648
Appendix 7.2

Oregon Public Utility Commission Order No. 16-109 (the Order) included the following
language:

Finally, as part of the IRP-vetting process and subsequent rate proceedings, we expect
that Avista conduct and present comprehensive analyses of its system upgrades. Such
analyses should provide: (1) a comprehensive cost-benefit analysis of whether and when
the investment should be built; (2) evaluation of a range of alternative build dates and
the impact on reliability and customer rates; (3) credible evidence on the likelihood of
disruptions based on historical experience; (4) evidence on the range of possible
reliability incidents; (5) evidence about projected loads and customers in the area; and
(6) adequate consideration of alternatives, including the use of interruptibility or
increased demand-side measures to improve reliability and system resiliency.

In order to address this portion of the Order, Avista has prepared this appendix, which
includes documentation addressing the six points above for each of the natural gas
distribution system enhancements included in the 2016 Natural Gas Integrated Resource
Plan (IRP) for Avista’s Oregon service territory. Each of these three enhancement projects
represents a significant, discrete project which is out of the ordinary course of business (that
is to say, different from ongoing capital investment to address Federal or State regulatory
requirements, relocation of pipe or facilities as requested by others, failed pipe or facilities,
etc., all of which occur routinely over time and which are discussed below).

The routine, ongoing capital investments can be loosely classified in the following categories
(which are not mutually exclusive):

 Safety – Ongoing safety related capital investment includes the repair or replacement
of obsolete or failed pipe and facilities. This category includes, but is not necessarily
limited to, investment to address deteriorated or isolated steel pipe, cathodic
protection, and the replacement of pipeline which has been built over, as well as the
remedy of shallow pipe or the repair or replacement of leaking pipe.
 System Maintenance – Ongoing capital investment related to system maintenance
includes replacement of facilities or pipe that has reached the end of their useful
lives, as well as other general investment required to maintain Avista’s ability to
reliably serve customers.
 Relocation Requested by Others – Ongoing capital investment related to relocation
requested by others falls primarily into two categories, relocation requested by other
parties which is required under the terms of our franchise agreements (such as
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 206 of 648
relocations required to accommodate road or highway construction or relocation),
or relocation requested by customers or others (in which case the customer would
be responsible for the cost of the immediate request, but in which case Avista may
perform additional work, such as the replacement of a steel service with
polyethylene to reduce future maintenance or cathodic protection requirements on
that pipe).
 Mandated System Investment – Ongoing capital investment in this category is driven
by Federal or State regulatory requirements, such as investment that results from
TIMP/DIMP programs, among other programs.
Avista’s Aldyl-A replacement program has been addressed in substantial detail in Oregon
Public Utility Commission Docket UG-246, Avista/500-501.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 207 of 648
La Grande High Pressure Reinforcement

1. A comprehensive cost-benefit analysis of whether and when the investment should be built

High pressure reinforcements are primarily driven by load studies, whereby an inability to
reliably serve customers on a design day drives investment needs. (Evidence regarding the
inability to reliably serve customers on a design day is given in #4, below.) Given this, the
threshold consideration regarding a high pressure reinforcement is driven primarily by
models indicating an inability to serve customers on a design day, rather than a strict
application of cost-benefit analysis. Said differently, to a customer, the loss of natural gas
service on a design day (74 HDD, or average daily temperature of -9° Fahrenheit, in La
Grande) is not a question of cost-benefit, but rather of physical safety and comfort.

2. Evaluation of a range of alternative build dates and the impact on reliability and customer
rates

As discussed in #1, above, the identification of areas in need of reinforcement is the primary
threshold consideration that establishes the need for and timing of planned completion. The
number/scope of reinforcement projects that are completed in any given year may be
constrained by such things as the availability of project management, skilled labor, and the
need to complete other critical-path projects first in order to enable the functionality of the
given project. Because of these constraints, the areas of concern within Avista’s natural gas
distribution systems are risk-ranked against each other, to ensure that the areas of highest
risk are corrected first.

In the case of this La Grande High Pressure Reinforcement, there were a number of system
capacity issues in the La Grande area, including gate station capacity constraints at both the
La Grande city gate station (station #0815) and the Ladd Canyon gate station (station #0817),
as well as low design day pressures identified for the cities of Elgin and Union, Oregon.

In the evaluation of these capacity constraints and low design day pressures, three critical
points were identified—the La Grande city gate station, the Ladd Canyon gate station, and the
remaining system pressure at the end of the high pressure pipeline connecting Elgin to the
distribution system (where a minimum design pressure of 100 psig is required to serve Elgin
on a design day, but where the actual pressure on a design day was found to be 35 psig). The
evaluation further identified that increasing the capacity of the La Grande gate station would
alleviate the gate station constraint, but would not address the low pressure at Elgin.
However, the evaluation found that replacement of the Ladd Canyon gate station and the
investment in the La Grande High Pressure Reinforcement project would alleviate all three
critical points, requiring only two projects. This analysis resulted in the lowest cost solution,
given that this solution avoids the need to upsize the La Grande city gate station to address
that gate station’s capacity constraint.

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 208 of 648
Given the interrelated nature of these critical points and the two projects, the investment in
the La Grande High Pressure Reinforcement could not occur until the new Ladd Canyon gate
station (station #7080) was completed (this station was placed in service in December 2015).

At existing rates, an incremental addition of $1 million to distribution gross plant would
result in an increase in billed revenue to Oregon customers of approximately one-tenth of one
percent of present billed revenue.

3. Credible evidence on the likelihood of disruptions based on historical experience

As discussed in Chapter 7: Distribution Planning in the Natural Gas IRP, the distribution
scenario decision-making process relies upon the analyses performed on each of Avista’s LDC
systems under design day conditions to identify areas where potential outages may occur.

Avista’s design heating degree day for distribution system modeling is determined using the
coldest day on record for each given service area. This practice is consistent with the peak
day demand forecast utilized in Avista’s natural gas Integrated Resource Plan, in the
“Weather Forecast” section of Chapter 2, which explains the methodology for determining
the peak day demand forecast as follows:

The peak day demand forecast includes adjustments to average weather to reflect a five-
day cold weather event. This consists of adjusting the middle day of the five-day cold
weather event to the coldest temperature on record for a service territory….

The IRP, in the “Weather Forecast” section of Chapter 2, goes on to describe the coldest days
on record for each of the Oregon service areas, stating the following:

Medford experienced the coldest day on record, a 61 HDD, on Dec. 9, 1972. This is equal
to an average daily temperature of 4 degrees Fahrenheit. Medford has experienced only
one 61 HDD in the last 40 years; however, it has also experienced 59 and 58 HDD events
on Dec. 8, 1972 and Dec. 21, 1990, respectively.

The other three areas in Oregon have similar weather days. For Klamath Falls, a 72 HDD
occurred on Dec. 8, 2013; in La Grande a 74 HDD occurred on Dec. 23, 1983; and a 55
HDD occurred in Roseburg on Dec. 22, 1990. As with Washington/Idaho and Medford,
these days are the peak day weather standard for modeling purposes.

The IRP also addresses the appropriateness of the use of the coldest day on record as the
planning standard, stating, in the “Weather Forecast” section of Chapter 2:

Utilizing a peak planning standard of the coldest temperature on record may seem
aggressive given a temperature experienced rarely, or only once. Given the potential
impacts of an extreme weather event on customers’ personal safety and property
damage to customer appliances and Avista’s infrastructure, it is a prudent regionally
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 209 of 648
accepted planning standard. While remote, peak days do occur, as on Dec. 8, 2013, when
Avista matched the previous peak HDD [72 HDD] in Klamath Falls.

Prior to the December 8, 2013 design heating degree day in Klamath Falls, Oregon, the
previous design heating degree day in Klamath Falls had occurred on December 21, 1990.
Further, in the 20 years preceding the completion of Avista’s 2012 Natural Gas IRP, the
coldest day in 20 years in Klamath Falls had been a 64 heating degree day.

These factors, along with the recent December 8, 2013 design heating degree day,
demonstrate that the absence of a design heating degree day in the past 20 years does not
mean that a design heating degree day will not happen. In fact, this further confirms that the
design heating degree day is a prudent planning standard.

4. Evidence on the range of possible reliability incidents

The following pages illustrate the results of the Synergi™ study with regards to the
aforementioned low pressure on a design day at Elgin, Oregon. As discussed in Avista
testimony in Docket No. UG-288 (Avista/1500, Webb/20), the system pressure upon
reaching Elgin is less than 35 psig on a design day, while the system design criteria dictate
that the pressure should be 100 psig at this point in order to reliably serve Elgin. Given the
substantial disparity between 35 psig and 100 psig, the low system pressure upon reaching
Elgin is likely to persist at temperatures higher than the design day temperature (i.e., the
probability of losing customers in this area is relatively higher). Similarly, given that the
system demand on the La Grande gate station on a design day is modeled to be 158% of
physical capacity (as shown in Appendix 7.1), the capacity shortfall at the La Grande gate
station is likely to persist at higher temperatures than the design day temperature.

Both of these factors contributed to the identification of this project as a high priority for
completion.

5. Evidence about projected loads and customers in the area

Given that the Synergi™ load studies used to determine the need for reinforcement or other
remedy are based upon existing system load, this reinforcement investment determination
was necessary to serve existing loads, irrespective of projected loads and customers in the
area.

While the determination that a project is necessary to support the distribution system is
made irrespective of projected customer or load growth, as discussed in the materials
included in Appendix 7.1, once a project need has been identified through the load studies,
expected growth in load or customers in the area is considered (when available) in
appropriately scoping the project in order to avoid the incremental cost of having to perform
incremental reinforcement in a given area that would likely be required if this information
were not considered.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 210 of 648

6. Adequate consideration of alternatives, including the use of interruptibility or increased
demand-side measures to improve reliability and system resiliency

As discussed in Avista testimony in Docket No. UG-288 (Avista/1500, Webb/20), while it is
true that loads can be interrupted or curtailed in the event of supply or capacity shortfalls,
the load studies performed to model the Company’s natural gas distribution system on design
days consider only firm load. That is to say, Avista’s design heating degree day models
presume that all interruptible customers have already been interrupted, and only firm loads
are being served. Therefore, the capacity deficits shown in the previously discussed load
studies could not be alleviated through interruption.

Additionally, as discussed in the “Conservation Resources” section of Chapter 7 (Distribution
Planning) of the IRP:

The evaluation of distribution system constraints includes consideration of targeted
conservation resources to reduce or delay distribution system enhancements. The
consumer is still the ultimate decision-maker regarding the purchase of a conservation
measure. Because of this, Avista attempts to influence conservation through the DSM
measures discussed in Chapter 3 – Demand-Side Resources, but does not depend on
estimates of peak day demand reductions from conservation to eliminate near-term
distribution system constraints. Over the longer-term, targeted conservation programs
may provide a cumulative benefit that could offset potential constraint areas and may
be an effective strategy.
Thus, while Avista certainly considers the importance of demand-side measures, and
encourages such conservation programs, the conservation benefits accomplished by
demand-side measures occur over a longer period than would be required to
prudently address the existing, near-term distribution system constraints.

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 211 of 648
Klamath Falls (#2703) Gate Station

1. A comprehensive cost-benefit analysis of whether and when the investment should be built

Gate station upgrades are primarily driven by the City Gate Analysis (as discussed in the
materials included in Appendix 7.1), whereby a capacity constraint impacting Avista’s ability
to reliably serve customers drives investment needs. (Evidence regarding the inability to
reliably serve customers on a design day is given in #4, below.) Given this, the threshold
consideration regarding gate station investment is driven primarily by models indicating a
capacity deficit on a design day, rather than a strict application of cost-benefit analysis. Said
differently, to a customer, the loss of natural gas service on a design day (72 HDD, or average
daily temperature of -7° Fahrenheit, in Klamath Falls) is not a question of cost-benefit, but
rather of physical safety and comfort.

2. Evaluation of a range of alternative build dates and the impact on reliability and customer
rates

As discussed in #1, above, the identification of capacity shortfalls on a design day is the
primary threshold consideration that establishes the need for and timing of planned
completion. The number/scope of reinforcement projects that are completed in any given
year may be constrained by such things as the availability of project management, skilled
labor, and the need to complete other critical-path projects first in order to enable the
functionality of the given project. Because of these constraints, the areas of concern within
Avista’s natural gas distribution systems are risk-ranked against each other, to ensure that
the areas of highest risk are corrected first.

Given that the capacity constraint at the Klamath Falls gate station (Station #2703) was
modeled to be 106% on a design day as of the most recent City Gate Analysis (a relatively
small capacity constraint), and the relative risk ranking compared with other natural gas
distribution projects, this project has been included in planning considerations, with planned
completion slated for 2019 or later. The assessed capacity constraint will continue to be
regularly evaluated, and an increase in the assessed shortfall might warrant acceleration of
the project, while a reduction in demand that eliminates the shortfall would defer the project.

At existing rates, an incremental addition of $1 million to distribution gross plant would
result in an increase in billed revenue to Oregon customers of approximately one-tenth of one
percent of present billed revenue.

3. Credible evidence on the likelihood of disruptions based on historical experience

As discussed in Chapter 7: Distribution Planning in the Natural Gas IRP, the distribution
scenario decision-making process relies upon the analyses performed on each of Avista’s LDC
systems under design day conditions to identify areas where potential outages may occur.

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 212 of 648
Avista’s design heating degree day for distribution system modeling is determined using the
coldest day on record for each given service area. This practice is consistent with the peak
day demand forecast utilized in Avista’s natural gas Integrated Resource Plan, in the
“Weather Forecast” section of Chapter 2, which explains the methodology for determining
the peak day demand forecast as follows:

The peak day demand forecast includes adjustments to average weather to reflect a five-
day cold weather event. This consists of adjusting the middle day of the five-day cold
weather event to the coldest temperature on record for a service territory….

The IRP, in the “Weather Forecast” section of Chapter 2, goes on to describe the coldest days
on record for each of the Oregon service areas, stating the following:

Medford experienced the coldest day on record, a 61 HDD, on Dec. 9, 1972. This is equal
to an average daily temperature of 4 degrees Fahrenheit. Medford has experienced only
one 61 HDD in the last 40 years; however, it has also experienced 59 and 58 HDD events
on Dec. 8, 1972 and Dec. 21, 1990, respectively.

The other three areas in Oregon have similar weather days. For Klamath Falls, a 72 HDD
occurred on Dec. 8, 2013; in La Grande a 74 HDD occurred on Dec. 23, 1983; and a 55
HDD occurred in Roseburg on Dec. 22, 1990. As with Washington/Idaho and Medford,
these days are the peak day weather standard for modeling purposes.

The IRP also addresses the appropriateness of the use of the coldest day on record as the
planning standard, stating, in the “Weather Forecast” section of Chapter 2:

Utilizing a peak planning standard of the coldest temperature on record may seem
aggressive given a temperature experienced rarely, or only once. Given the potential
impacts of an extreme weather event on customers’ personal safety and property
damage to customer appliances and Avista’s infrastructure, it is a prudent regionally
accepted planning standard. While remote, peak days do occur, as on Dec. 8, 2013, when
Avista matched the previous peak HDD [72 HDD] in Klamath Falls.

Prior to the December 8, 2013 design heating degree day in Klamath Falls, Oregon, the
previous design heating degree day in Klamath Falls had occurred on December 21, 1990.
Further, in the 20 years preceding the completion of Avista’s 2012 Natural Gas IRP, the
coldest day in 20 years in Klamath Falls had been a 64 heating degree day.

These factors, along with the recent December 8, 2013 design heating degree day,
demonstrate that the absence of a design heating degree day in the past 20 years does not
mean that a design heating degree day will not happen. In fact, this further confirms that the
design heating degree day is a prudent planning standard.

4. Evidence on the range of possible reliability incidents
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 213 of 648

Given that the system demand on the Klamath Falls gate station on a design day is modeled
to be 106% of physical capacity, the capacity shortfall at the Klamath Falls gate station
primarily exists at temperatures near the design day temperature. (See TAC Meeting #3
materials, “City Gate Analysis Results,” for tables documenting the results of the most recent
City Gate Analysis).

5. Evidence about projected loads and customers in the area

Given that the City Gate Analysis used to determine the need for reinforcement or other
remedy is based upon existing system load, gate station upgrade investment decisions are
made upon the basis of existing customers, irrespective of projected loads and customers in
the area.

6. Adequate consideration of alternatives, including the use of interruptibility or increased
demand-side measures to improve reliability and system resiliency

While it is true that loads can be interrupted or curtailed in the event of supply or capacity
shortfalls, the City Gate Analysis performed to model gate station capacity deficits on design
days consider only firm load. That is to say, Avista’s City Gate Analysis models presume that
all interruptible customers have already been interrupted, and only firm loads are being
served. Therefore, the capacity deficits shown in the City Gate Analysis could not be alleviated
through interruption.

Additionally, as discussed in the “Conservation Resources” section of Chapter 7 (Distribution
Planning) of the IRP:

The evaluation of distribution system constraints includes consideration of targeted
conservation resources to reduce or delay distribution system enhancements. The
consumer is still the ultimate decision-maker regarding the purchase of a conservation
measure. Because of this, Avista attempts to influence conservation through the DSM
measures discussed in Chapter 3 – Demand-Side Resources, but does not depend on
estimates of peak day demand reductions from conservation to eliminate near-term
distribution system constraints. Over the longer-term, targeted conservation programs
may provide a cumulative benefit that could offset potential constraint areas and may
be an effective strategy.
Thus, while Avista certainly considers the importance of demand-side measures, and
encourages such conservation programs, the conservation benefits accomplished by
demand-side measures occur over a longer period than would be required to
prudently address the existing, near-term gate station constraints.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 214 of 648
Sutherlin (#2626) Gate Station

1. A comprehensive cost-benefit analysis of whether and when the investment should be built

Gate station upgrades are primarily driven by the City Gate Analysis (as discussed in the
materials included in Appendix 7.1), whereby a capacity constraint impacting Avista’s ability
to reliably serve customers drives investment needs. (Evidence regarding the inability to
reliably serve customers on a design day is given in #4, below.) Given this, the threshold
consideration regarding gate station investment is driven primarily by models indicating a
capacity deficit on a design day, rather than a strict application of cost-benefit analysis. Said
differently, to a customer, the loss of natural gas service on a design day (55 HDD, or average
daily temperature of 10° Fahrenheit, in Roseburg) is not a question of cost-benefit, but rather
of physical safety and comfort.

2. Evaluation of a range of alternative build dates and the impact on reliability and customer
rates

As discussed in #1, above, the identification of capacity shortfalls on a design day is the
primary threshold consideration that establishes the need for and timing of planned
completion. The number/scope of reinforcement projects that are completed in any given
year may be constrained by such things as the availability of project management, skilled
labor, and the need to complete other critical-path projects first in order to enable the
functionality of the given project. Because of these constraints, the areas of concern within
Avista’s natural gas distribution systems are risk-ranked against each other, to ensure that
the areas of highest risk are corrected first.

Given that the capacity constraint at the Sutherlin gate station (Station #2626) was modeled
to be 102% on a design day as of the most recent City Gate Analysis (a relatively small
capacity constraint), and the relative risk ranking compared with other natural gas
distribution projects, this project has been included in planning considerations, with planned
completion slated for 2019 or later. The assessed capacity constraint will continue to be
regularly evaluated, and an increase in the assessed shortfall might warrant acceleration of
the project, while a reduction in demand that eliminates the shortfall would defer the project.

At existing rates, an incremental addition of $1 million to distribution gross plant would
result in an increase in billed revenue to Oregon customers of approximately one-tenth of one
percent of present billed revenue.

3. Credible evidence on the likelihood of disruptions based on historical experience

As discussed in Chapter 7: Distribution Planning in the Natural Gas IRP, the distribution
scenario decision-making process relies upon the analyses performed on each of Avista’s LDC
systems under design day conditions to identify areas where potential outages may occur.

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 215 of 648
Avista’s design heating degree day for distribution system modeling is determined using the
coldest day on record for each given service area. This practice is consistent with the peak
day demand forecast utilized in Avista’s natural gas Integrated Resource Plan, in the
“Weather Forecast” section of Chapter 2, which explains the methodology for determining
the peak day demand forecast as follows:

The peak day demand forecast includes adjustments to average weather to reflect a five-
day cold weather event. This consists of adjusting the middle day of the five-day cold
weather event to the coldest temperature on record for a service territory….

The IRP, in the “Weather Forecast” section of Chapter 2, goes on to describe the coldest days
on record for each of the Oregon service areas, stating the following:

Medford experienced the coldest day on record, a 61 HDD, on Dec. 9, 1972. This is equal
to an average daily temperature of 4 degrees Fahrenheit. Medford has experienced only
one 61 HDD in the last 40 years; however, it has also experienced 59 and 58 HDD events
on Dec. 8, 1972 and Dec. 21, 1990, respectively.

The other three areas in Oregon have similar weather days. For Klamath Falls, a 72 HDD
occurred on Dec. 8, 2013; in La Grande a 74 HDD occurred on Dec. 23, 1983; and a 55
HDD occurred in Roseburg on Dec. 22, 1990. As with Washington/Idaho and Medford,
these days are the peak day weather standard for modeling purposes.

The IRP also addresses the appropriateness of the use of the coldest day on record as the
planning standard, stating, in the “Weather Forecast” section of Chapter 2:

Utilizing a peak planning standard of the coldest temperature on record may seem
aggressive given a temperature experienced rarely, or only once. Given the potential
impacts of an extreme weather event on customers’ personal safety and property
damage to customer appliances and Avista’s infrastructure, it is a prudent regionally
accepted planning standard. While remote, peak days do occur, as on Dec. 8, 2013, when
Avista matched the previous peak HDD [72 HDD] in Klamath Falls.

Prior to the December 8, 2013 design heating degree day in Klamath Falls, Oregon, the
previous design heating degree day in Klamath Falls had occurred on December 21, 1990.
Further, in the 20 years preceding the completion of Avista’s 2012 Natural Gas IRP, the
coldest day in 20 years in Klamath Falls had been a 64 heating degree day.

These factors, along with the recent December 8, 2013 design heating degree day,
demonstrate that the absence of a design heating degree day in the past 20 years does not
mean that a design heating degree day will not happen. In fact, this further confirms that the
design heating degree day is a prudent planning standard.

4. Evidence on the range of possible reliability incidents
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 216 of 648

Given that the system demand on the Sutherlin gate station on a design day is modeled to be
102% of physical capacity, the capacity shortfall at the Klamath Falls gate station primarily
exists at temperatures near the design day temperature. (See TAC Meeting #3 materials, “City
Gate Analysis Results,” for tables documenting the results of the most recent City Gate
Analysis).

5. Evidence about projected loads and customers in the area

Given that the City Gate Analysis used to determine the need for reinforcement or other
remedy is based upon existing system load, gate station upgrade investment decisions are
made upon the basis of existing customers, irrespective of projected loads and customers in
the area.

6. Adequate consideration of alternatives, including the use of interruptibility or increased
demand-side measures to improve reliability and system resiliency

While it is true that loads can be interrupted or curtailed in the event of supply or capacity
shortfalls, the City Gate Analysis performed to model gate station capacity deficits on design
days consider only firm load. That is to say, Avista’s City Gate Analysis models presume that
all interruptible customers have already been interrupted, and only firm loads are being
served. Therefore, the capacity deficits shown in the City Gate Analysis could not be alleviated
through interruption.

Additionally, as discussed in the “Conservation Resources” section of Chapter 7 (Distribution
Planning) of the IRP:

The evaluation of distribution system constraints includes consideration of targeted
conservation resources to reduce or delay distribution system enhancements. The
consumer is still the ultimate decision-maker regarding the purchase of a conservation
measure. Because of this, Avista attempts to influence conservation through the DSM
measures discussed in Chapter 3 – Demand-Side Resources, but does not depend on
estimates of peak day demand reductions from conservation to eliminate near-term
distribution system constraints. Over the longer-term, targeted conservation programs
may provide a cumulative benefit that could offset potential constraint areas and may
be an effective strategy.

Thus, while Avista certainly considers the importance of demand-side measures, and
encourages such conservation programs, the conservation benefits accomplished by
demand-side measures occur over a longer period than would be required to prudently
address the existing, near-term gate station constraints.

Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 217 of 648
1 1
2016 Avista Natural Gas IRP
Technical Advisory Committee Meeting
January 21, 2016
Portland, Oregon
St. Helens A
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 218 of 648
2 2
Agenda
•Introductions & Logistics
•Purpose of IRP and Avista’s IRP Process
•Avista’s Demand Overview and 2014 IRP Revisited
•Economic Outlook and Customer Count Forecast
•Demand Forecast Methodology
•Dynamic Demand Forecasting
•Demand Side Management
•Questions/Wrap Up
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 219 of 648
3 3
2016 IRP Timeline
•August 31, 2015 –Work Plan filed with WUTC
•January through April 2016 –Technical Advisory Committee
meetings. Meeting topics will include:
–Demand Forecast and Demand Side Management –
January 21
–Supply/Infrastructure, Natural Gas Pricing, and Potential Case
Discussion–February 18
–Distribution Planning, SENDOUT® Preliminary Output Results
and Further Case Discussion –March 16
–SENDOUT® results –April 21
•May 30, 2016 –Draft of IRP document to TAC
•June 30, 2016 –Comments on draft due back to Avista
•July 2016 –TAC final review meeting (if necessary)
•August 31, 2016 –File finalized IRP document
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 220 of 648
4 4
Purpose of Gas Integrated Resource
Planning
•Comprehensive long-range resource planning tool
•Fully integrates forecasted demand requirements with
potential demand side and supply side resources
•Process determines the least cost, risk adjusted
means for meeting demand requirements for our firm
residential, commercial and industrial customers
•Responsive to Idaho, Oregon and Washington rules
and/or orders
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 221 of 648
5 5
Avista’s IRP Process
•Comprehensive analysis bringing demand forecasting and
existing and potential supply-side and demand-side
resources together into a 20-year, risk adjusted least-cost
plan
•Considers:
–Customer growth and usage
–Weather planning standard
–Demand-side management opportunities
–Existing and potential supply-side resource options
–Risk
–Public participation through Technical Advisory Committee meetings (TAC)
–Distribution upgrades
•2014 IRP filed in all three jurisdictions on
August 31, 2014 and acknowledged Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 222 of 648
6 6
Avista’s Demand Overview and 2014 IRP Re-
Visited
Tom Pardee
Manager of Natural Gas Planning
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 223 of 648
7 7
Avista’s Demand Overview
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 224 of 648
8 8
–Population of service area 1.5 million
371,000 electric customers
330,000 natural gas customers
•Has one of the smallest carbon
footprints among America’s 100
largest investor-owned utilities
•Committed to environmental
stewardship and efficient use
of resources
Service Territory and Customer Overview
•Serves electric and natural gas customers in eastern Washington and northern Idaho,
and natural gas customers in southern and eastern Oregon
State Total Customers % of Total
Washington 156,000 46%
Oregon 99,000 30%
Idaho 79,000 24%
Total 334,000 100%Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 225 of 648
1010
2015 Customer Make Up and Demand Mix
88.44%
11.54%0.03%
Customer Make Up
Oregon
89.99%
9.91%0.10%
Customer Make up
WA-ID
62.9%
35.7%
1.4%
Annual Demand
WA-ID
64.2%
35.5%
0.3%
Annual Demand
Oregon
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 226 of 648
1111
Historical Demand Mix
0%
20%
40%
60%
80%
100%
2015 2014 2013 2012 2011 2010
Industrial 1%2%1%1%2%2%
Commercial 36%36%36%36%37%37%
Residential 63%63%63%63%61%61%
WA-ID
0%
20%
40%
60%
80%
100%
2015 2014 2013 2012 2011 2010
Industrial 0%0%0%0%0%0%
Commercial 36%38%37%38%37%37%
Residential 64%62%63%62%63%63%
Medford/Roseburg
0%
20%
40%
60%
80%
100%
2015 2014 2013 2012 2011 2010
Industrial 1%1%1%1%0%0%
Commercial 32%32%32%32%32%34%
Residential 67%67%68%67%67%66%
Klamath Falls
0%
20%
40%
60%
80%
100%
2015 2014 2013 2012 2011 2010
Industrial 0%0%0%0%0%0%
Commercial 38%37%37%36%37%37%
Residential 62%63%63%64%63%63%
LaGrande
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 227 of 648
1212
Seasonal Demand Profiles
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 228 of 648
1313
Daily Demand Profiles
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
020406080100
De
k
a
t
h
e
r
m
s
2015 Average Temp (°F)
Medford/Roseburg
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 229 of 648
1414
Avista’s 2014 Natural Gas IRP Re-Visited
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 230 of 648
1515 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 231 of 648
1616 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 232 of 648
1717 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 233 of 648
1818 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 234 of 648
1919 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 235 of 648
2020 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 236 of 648
2121
Year First Unserved
Scenario Comparisons
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 237 of 648
2222
Best Cost/Risk Resources
Expected Case –WA/ID
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
Dth
Existing GTN Existing NWP Spokane Supply GTN Capacity Add Peak Day Demand
Current Short
Figure 1.10 - Expected Case - WA/ID Selected Resources vs. Peak Day Demand
(Net of DSM )
FEB 15
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 238 of 648
2323
Best Cost/Risk Resources
Expected Case –Medford/Roseburg
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 239 of 648
2424
Best Cost/Risk Resources
Expected Case –Klamath Falls
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 240 of 648
2525
Our Biggest Risk Last IRP
“Flat Demand” Risk
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 241 of 648
2626
Near Term Action Items
•Demand trend monitoring
•Demand side management cost effectiveness and
targets
•Gate station analysis
On-going Action Items
•Price elasticity study inquiry
•NGV/CNG and other demand potential
•Supply side resource trends/availability
•Meet regularly with Commission Staff
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 242 of 648
2727
Avista Natural Gas Forecasting
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 243 of 648
2828
Load Forecasts-Two Step Process
•First, forecast customers (C) by month by schedule (s) by
residential (r), commercial (c), industrial (i)—for example, Ct,y,s.r
•Forecast use per customer (U) by month by schedule by
class—for example, Ut,y,s.r
•Load forecast (L) is the product of the two:
Lt,y,s.r = Ct,y,s.r X Ut,y,s.r
For weather sensitive schedules a
20-yr MA defines normal weather.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 244 of 648
2929
The Basic Forecast Approach
Population Growth
Forecast
Residential Customer
Forecast ARIMA Model
Commercial Customer
ARIMA Forecast Model
Vary Population Growth
Assumptions
Firm Residential and
Commercial Firm Industrial
No Drivers
Forecast of no Significant
Growth
Vary “No Growth”
Assumption
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 245 of 648
3030
System Industrial Customers, 2004-2015
260
280
300
320
340
360
380
400
Ja
n
-04
Ju
l
-04
Ja
n
-05
Ju
l
-05
Ja
n
-06
Ju
l
-06
Ja
n
-07
Ju
l
-07
Ja
n
-08
Ju
l
-08
Ja
n
-09
Ju
l
-09
Ja
n
-10
Ju
l
-10
Ja
n
-11
Ju
l
-11
Ja
n
-12
Ju
l
-12
Ja
n
-13
Ju
l
-13
Ja
n
-14
Ju
l
-14
Ja
n
-15
Ju
l
-15
No real change since January 2007
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 246 of 648
3131
Getting to Population as a Driver, 2016-2021 & 2022-2035
Average GDP Growth
Forecasts:
•IMF, FOMC,
Bloomberg, etc.
•Average forecasts
out 5-yrs.
Non-farm Employment
Growth Model:
•Model links year y, y-1, and
y-2 GDP growth to year y
regional employment
growth.
•Forecast out 5-yrs.
•Averaged with GI forecasts.
Regional Population Growth Models:
•Model links regional, U.S., and CA
year y-1 employment growth to year y
county population growth.
•Forecast out 6-yrs for Spokane, WA;
Kootenai, ID; and Jackson, OR.
•Averaged with IHS forecasts.
•Growth rates used to generate
population forecasts for customer
forecasts for residential schedules 101
and 410.
EMPGDP
2016-2021 For Spokane, WA; Kootenai,
ID, and Jackson, OR counties
OR Douglas, Klamath, and Douglas counties: IHS population growth forecasts for 2016-2035
Kootenai and Jackson: IHS population growth forecasts for 2022-2035
Spokane: OFM population growth forecasts for 2022-2035
Interpolation assumes: PN = P0erN
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 247 of 648
3232
The Relationship Between Classes
Customers Residential Commercial Industrial Load Residential Commercial Industrial
Residential 1.00 Residential 1.00
Commercial 0.83 1.00 Commercial 0.94 1.00
Industrial -0.44 -0.35 1.00 Industrial 0.33 0.34 1.00
Year-over-year Growth, Gas Correlations by Class, Jan. 2006-May 2013
Residential customer growth is approximately equal
to population growth in the long-run.
Commercial customer growth is highly correlated
with residential growth in the long-run.
Industrial’s correlation to residential is lower and
negative. Customer numbers stable or slightly
declining.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 248 of 648
3333
WA-ID Region Firm Customers: 2016 IRP and 2014 IRP
210,000
220,000
230,000
240,000
250,000
260,000
270,000
280,000
290,000
300,000
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
WA-ID-Base 2014 WA-ID-Base
+5,500
IRP Avg.Annual Growth
2016-2035
2014 1.0%
2016 1.1%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 249 of 648
3434
OR Region Firm Customers: 2016 IRP and 2014 IRP
80,000
85,000
90,000
95,000
100,000
105,000
110,000
115,000
120,000
125,000
130,000
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
OR-Base 2014 OR-Base
IRP Avg.Annual Growth
2016-2035
2014 0.9%
2016 1.2%
+7,000
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 250 of 648
3535
System Firm Customers: 2016 IRP and 2014 IRP
300,000
320,000
340,000
360,000
380,000
400,000
420,000
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
WA-ID-OR-Base 2014 WA-ID-OR-Base
+12,500
IRP Avg.Annual Growth
2016-2035
2014 1.0%
2016 1.1%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 251 of 648
3636
WA-ID Region Firm Customer Range, 2016-2035
210,000
230,000
250,000
270,000
290,000
310,000
330,000
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
WA-ID-Base WA-ID-High WA-ID-Low
Variable Low
Growth
Base
Growth
High
Growth
Customers 0.6%1.1%1.5%
WA Population 0.4%0.8%1.2%
ID Population 1.0%1.5%2.0%
WA-ID Population 0.6%1.0%1.4%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 252 of 648
3737
OR Region Firm Customer Range, 2016-2035
80,000
90,000
100,000
110,000
120,000
130,000
140,000
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
OR-Base OR-High OR-Low
Variable Low
Growth
Base
Growth
High
Growth
Customers 0.7%1.2%1.6%
Population 0.4%0.8%1.3%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 253 of 648
3838
System Firm Customer Range, 2016-2035
300,000
320,000
340,000
360,000
380,000
400,000
420,000
440,000
460,000
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
WA-ID-OR-Base WA-ID-OR-High WA-ID-OR-Low
Variable Low
Growth
Base
Growth
High
Growth
Customers 0.7%1.1%1.5%
Population 0.5%0.9%1.3%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 254 of 648
3939
Summary of Growth Rates
System Base-Case High Low
Res 1.2%1.6%0.7%
Com 0.7%1.1%0.2%
Ind 0.0%0.4%-0.4%
Total 1.1%1.5%0.7%
WA Base-Case High Low
Res 1.0%1.4%0.6%
Com 0.7%1.1%0.3%
Ind 0.0%0.3%-0.2%
Total 1.0%1.4%0.6%
ID Base-Case High Low
Res 1.4%1.8%0.9%
Com 0.4%0.9%-0.1%
Ind 0.0%0.3%-0.3%
Total 1.3%1.7%0.8%
OR Base-Case High Low
Res 1.2%1.6%0.8%
Com 0.8%1.2%0.3%
Ind 0.0%1.1%-1.4%
Total 1.2%1.6%0.7%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 255 of 648
4040
Demand Forecast Methodology
Tom Pardee
Manager of Natural Gas Planning
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 256 of 648
4141
Natural Gas Demand Forecasting
Financial
Planning and
Analysis
Resource
Accounting Gas Supply Rates Regulatory
Staff
Industry
Stakeholders
Average
Demand
Procurement
Planning
PGA Corporate
Budget
IRP
Peak Day
Planning
IRP
Scenario
Analysis
Other
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 257 of 648
4242
Natural Gas Demand Forecast
Use per
Customer
Weather
Forecast
Customer
Forecast
What goes into the Natural Gas Demand
Forecast?
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 258 of 648
4343
Customer
Forecast
by Class
Start with national
economic forecasts
then drill down to
regional economies
Population growth
expectations and
employment
Company-specific
knowledge about
sub-regional
construction activity,
trends and historical
data
The Customer Forecast
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 259 of 648
4444
Weather
Forecast
Most
recent 20
year HDD’s
Planning
Standard
Other
The Weather Forecast
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 260 of 648
4545
Weather
•NOAA 20 year actual average daily HDD’s (1996-
2015)
•Peak weather includes two winter storms (5 day
duration), one in December and one in February
•Planning Standard –coldest day on record
•Sensitivity around planning standard including
–Normal/Average
–Coldest in 20 years
–Monte Carlo simulation
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 261 of 648
4646
Use per
Customer
Most recent year(s) of
historical use:
•“Big Meter” Data
•5 Areas
•Allocated based on
“little meter” data
Determine
Base
Demand
Determine
Heat
Demand
Determine
“Super Peak”
Demand
The Use per Customer Forecast
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 262 of 648
4747
The Use per Customer Forecast cont.
•Historical data is used to determine initial base and heat
coefficients.
•Adjustments are made to incorporate DSM and price
elastic responses.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 263 of 648
4848 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 264 of 648
4949 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 265 of 648
5050 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 266 of 648
5151 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 267 of 648
5252 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 268 of 648
5353
Demand Modeling Equation –a closer look
SENDOUT® requires inputs expressed in the below format to
compute daily demand in dekatherms. The base and weather
sensitive usage (degree-day usage) factors are developed
outside the model and capture a variety of demand usage
assumptions.
# of customers x Daily weather sensitive usage / customer
# of customers x Daily base usage / customer
Plus
Table 3.2 Basic Demand Formula
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 269 of 648
5454
1.Customer annual growth rates:
2.Use per customer coefficients –Flat all classes,5 year, 3 year or last year
average use per HDD per customer
3.Weather planning standard –coldest day on record
WA/ID 82; Medford 61; Roseburg 55; Klamath 72; La Grande 74
Developing a Reference Case
Customer
count
forecast
Use per
customer
coefficients
Weather Reference
Case Demand
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 270 of 648
5555
Dynamic Demand Methodology
Tom Pardee
Manager of Natural Gas Planning
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 271 of 648
5656
Dynamic Demand Methodology
Demand Influencing
–Conditions that DIRECTLY
affect core customer
volume consumed
Price Influencing
–PRICE SENSITIVE
conditions that, through price
elasticity, INDIRECTLY affect
core customer volume
consumed
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 272 of 648
5757
Demand
Customer Growth
•New Construction
•Conversion/Direct Use
•Economy
Customer Mix Shifts
•Res/Com/Ind
•Core vs. Transport
•Interruptible
Weather
•Normal
•Planning Standard
•Other
Technology
•Increased
efficiency/DSM
•New Uses
•Demand Response
3rd Party Demand
Trends
•Thermal Generation
•Non-Core Customer
•LNG Exports Supply Trends
•Conventional vs.
Unconventional
•Canadian Imports
•LNG
Pipeline Trends
•Regional Pipeline
Projects
•National Pipeline
Projects
•International Pipeline
Projects
Other
•Storage
•Climate Change
Legislation
•Energy Correlations
(i.e. oil and gas)
Demand Drivers
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 273 of 648
5858
Customer Growth and Mix –Demand
Influencing
•Key driver in demand growth
•Can change the timing and/or location of resource
needs
•Currently we model expected, high, and low growth
scenarios
•New construction vs. conversions
•Residential/Commercial/Industrial vs. Transportation
•New uses –CNG/NGV
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 274 of 648
5959
Weather Standard –Demand Influencing
•Has the potential to significantly change timing of
resource needs
•Significant qualitative considerations
–No infrastructure response time if standard
exceeded
–Significant safety and property damage risks
•Current Peak HDD Planning Standards
–WA/ID 82
–Medford 61
–Roseburg 55
–Klamath 72
–La Grande 74
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 275 of 648
6060
Technology –Demand Influencing
•Demand side management initiatives will reduce
demand HOWEVER, it is dependent upon customers
willingness/ability to participate.
•Development of new uses for natural gas
•CNG
•NGV
•LNG
•???NG
•Demand response (Smart Grid)
•New technologies in Demand Side Management
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 276 of 648
6161
Price Elasticity Factors Defined
•Price elasticity is usually expressed as a numerical factor
that defines the relationship of a consumer’s consumption
change in response to price change.
•Typically, the factor is a negative number as consumers
normally reduce their consumption in response to higher
prices or will increase their consumption in response to
lower prices.
•For example, a price elasticity factor of -0.13 means:
–A 10% price increase will prompt a 1.3% consumption
decrease
–A 10% price decrease will prompt a 1.3%
consumption increase Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 277 of 648
6262
Price Elasticity
•Establishes factors for use in other price influencing
scenarios
•Very complex relationship –we use historical data
however……
•Historical data has DSM, rate changes (PGA,
general rate, etc.), economic conditions,
technological changes, etc.
•History is not necessarily the best predictor of future
behavior
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 278 of 648
6363
2007 AGA Study Results
•American Gas Assn Study
–National results
•Short-run -0.09
•Long-run -0.18
–Pacific & Mtn Region
results
•Short-run -0.07 & -0.07
•long-run -0.12 & -0.10
–Min-Max range
•Short-run +0.01 to -
0.13
•Long-run -.01 to -.29
•Avista Specific Results
–Oregon
•Short-run -0.08
•long-run -0.13
–Idaho
•Short-run -0.05
•long-run -0.10
–Washington
•Short-run -0.12
•long-run -0.14
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 279 of 648
6464
Price Elasticity Assumptions
From 2014 IRP
Elasticity
Assumption
Real Price annual increase
within 30%
High Negative .20
Expected Negative .15
Low No response
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 280 of 648
6565
3rd Party Demand Trends –Price Influencing
•Gas fired generation –the largest contributor to
future growth
•Coal plant retirements driving gas for power
•CNG/NGV Transportation Fleets
•Export LNG
•Non-firm customer trends
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 281 of 648
6666
Supply Trends –Price Influencing
•Shale is Everywhere
•LNG Export
•Basis -Location, location, location
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 282 of 648
6767
Pipeline Trends –Price Influencing
•Regional Pipeline Proposals
•N-Max/Palomar –cross Cascades pipeline (NWN,
GTN and NWP)
•Pacific Connector –from Jordan Cove LNG to
various interconnects in the Pacific Northwest
(Williams, Fort Chicago Energy Partners, and
PG&E)
•Trail West (GTN to NWP –Molalla area)
•National Pipeline Proposals
•International Pipeline Proposals (GTN to NWP
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 283 of 648
6868
Other Supply Issues –Price Influencing
•Storage
•Climate Change and Carbon Legislation
•Energy Correlations
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 284 of 648
6969
Sensitivities, Scenarios, Portfolios
Sensitivities
Demand
Supply
Scenarios
Group demand
drivers into
meaningful sets
Group supply
drivers into
meaningful sets
Portfolios
Bringing together demand and supply scenarios
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 285 of 648
7070
Demand Sensitivities from 2014 IRP
What do we want to consider for 2016?Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 286 of 648
7171
Mix and Match to Make Scenarios
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 287 of 648
7272
The Goal –A Bunch of Meaningful Lines
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 288 of 648
7373
Forecast Methodology Considerations
•Know the goal –what is the purpose of the forecast?
•Know your data –what you have, what you need
•Is there sufficient quantitative data available?
•Is the change small or large?
•Is their conflict among decision makers?
•Are the relationships among variable complicated?
•Have there been similar situations?
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 289 of 648
7474
Demand Side Management
Mike Dillon
DSM Planning and Analytics Manager
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 290 of 648
7575
Agenda
•DSM in the last IRP
–Target/Acquisition
•What’s happened since the last IRP
•What’s different with avoided costs?
•Proposed DSM modeling methodology
•Business planning process
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 291 of 648
7676
DSM in the 2014 IRP –Annual (WA/ID)
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 292 of 648
7777
DSM in the 2014 IRP –Peak Day (WA/ID)
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 293 of 648
7878
DSM in the 2014 IRP –Annual (OR)
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 294 of 648
7979
DSM in the 2014 IRP –Peak Day (OR)
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 295 of 648
8080
2014 IRP DSM Targets
•2015 targets & (Unverified) acquisition (achievable potential)
•OPUC established “minimum” target
State Therms Target % Achieved
Idaho ---
Oregon 207,036 161,000 128.6%
Washington 780,530 602,010 129.7%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 296 of 648
8181
Recap of Recent History
•Relook at components of conservation avoided costs and
compare with other gas utilities
–Include total cost to deliver from well to meter (Schedule 150
Demand)
–Estimated Carbon Tax in Washington (assumptions could already be
dated)
–Working with Natural Gas Planning on analyzing the value of
conservation in deferring pipeline investments
•Idaho –Schedule 190 resumed 1/1/16
•Oregon –As part of GRC, Oregon non-LI transition to ETO
•Washington –Proposed Initiatives, Potential Legislation and
Executive Orders… Oh My!
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 297 of 648
8282
Henry Hub vs. Levelized Avoided Costs
0
2
4
6
8
10
12
14
16
Ja
n
-
0
5
Ma
y
-
0
5
Se
p
-
0
5
Ja
n
-
0
6
Ma
y
-
0
6
Se
p
-
0
6
Ja
n
-
0
7
Ma
y
-
0
7
Se
p
-
0
7
Ja
n
-
0
8
Ma
y
-
0
8
Se
p
-
0
8
Ja
n
-
0
9
Ma
y
-
0
9
Se
p
-
0
9
Ja
n
-
1
0
Ma
y
-
1
0
Se
p
-
1
0
Ja
n
-
1
1
Ma
y
-
1
1
Se
p
-
1
1
Ja
n
-
1
2
Ma
y
-
1
2
Se
p
-
1
2
Ja
n
-
1
3
Ma
y
-
1
3
Se
p
-
1
3
Ja
n
-
1
4
Ma
y
-
1
4
Se
p
-
1
4
Ja
n
-
1
5
Ma
y
-
1
5
Se
p
-
1
5
Monthly Henry Hub vs. Levelized IRP Avoided Costs
Monthly Henry Hub Prices $/MMBTU 2014 Average IRP Levelized AC
2012 Average IRP Levelized AC 2009 Average IRP Levelized AC
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 298 of 648
8383
Proposed DSM Modeling Methodology
Initial Sendout Run
(AVA)
Preliminary
Avoided Costs
(AVA)
Initial Loadmap Run
(AEG)
Initial CE Calcs
(AEG)
Initial DSM
Potential (AEG)
Feed new potential
in SENDOUT (AVA)
Iterate Sendout till
Avoided Cost
Convergence (AVA)
Feed LoadMAP with
final Avoided Costs
(AEG)
Final CE Calcs (AEG)DSM Potential
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 299 of 648
8484
Business Planning Process
•IRP generated target (CPA achievable potential)
•Bottom-up evaluation of all measures regardless
of cost-effectiveness
•Forecast throughput for the following year
•Add in non-incentive utility costs
•Evaluate with final avoided costs
•Update Business Plan Annually for through put,
estimated budgets and cost-effectiveness by
state and fuel.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 300 of 648
8585
2016 IRP Timeline
•August 31, 2015 –Work Plan filed with WUTC
•January through April 2016 –Technical Advisory Committee
meetings. Meeting topics will include:
–Demand Forecast and Demand Side Management –January
21
–Supply/Infrastructure, Natural Gas Pricing, and Potential
Case Discussion–February 18
–Distribution Planning, SENDOUT® Preliminary Output Results
and Further Case Discussion –March 16
–SENDOUT® results –April 21
•May 30, 2016 –Draft of IRP document to TAC
•June 30, 2016 –Comments on draft due back to Avista
•July 2016 –TAC final review meeting (if necessary)
•August 31, 2016 –File finalized IRP document
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 301 of 648
8686
Tentative Agenda for the Next TAC Meeting
•Natural Gas Prices
•Supply Side Resources (Current and Future)
•Transportation
•Storage
•Other
•Gate Station Analysis
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 302 of 648
1
2016 Avista Natural Gas IRP
Technical Advisory Committee Meeting
February 18, 2016
Spokane, WA
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 303 of 648
22
Agenda
•Introductions & Logistics
•Update from TransCanada and Williams
•Regional and Avista’s Supply Side Resources
•Storage and Transportation Optimization
•Transport Modeling in Sendout
•Solving Unserved Demand
•Carbon Legislation
2
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 304 of 648
33
2016 IRP Timeline
•August 31, 2015 –Work Plan filed with WUTC
•January through April 2016 –Technical Advisory Committee
meetings. Meeting topics will include:
–Demand Forecast and Demand Side Management –January
21
–Supply/Infrastructure and Potential Case Discussion–
February 18
–Distribution Planning, Natural Gas Pricing, SENDOUT®
Preliminary Output Results and Further Case Discussion –
March 30
–SENDOUT® results –April 21
•May 30, 2016 –Draft of IRP document to TAC
•June 30, 2016 –Comments on draft due back to Avista
•July 2016 –TAC final review meeting (if necessary)
•August 31, 2016 –File finalized IRP document
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 305 of 648
44 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 306 of 648
55
TransCanada
Corporation
(TSX/NYSE: TRP)
•57,000 km (35,500 mi) of
wholly owned natural gas
pipeline
•Interests in an additional
11,500 km (7,000 mi) of
natural gas pipeline
•250 Bcf of regulated natural
gas storage capacity
•Unparalleled connections
from traditional and
emerging basins to growing
markets
•Average daily volume of
approximately 14 Bcf/d of
North American demand
2
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 307 of 648
66
NGTL System
3
WCSB
Pacific NW /California
BC / AlbertaDeliveries
MidwesternUSA
CBM
DEEP
BASIN
CORDOVA
HORN
RIVER
West CoastLNG
Eastern Canada /Northeast USA
Potential Mackenzie Delta Supply
•32,000+ km of pipe –combined
assets of NGTL and ATCO Pipelines
•Over 1000 receipt and 1000
delivery points on system
•Transports over 75% of WCSB
production
•Over 400 Tcf of WCSB supply
•400+ Bcf of WCSB gas storage
•50 to 70 Bcf/d of trading liquidity DUVERNAY
MONTNEY
PotentialAlaska Supply
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 308 of 648
77
Prince Rupert Gas Transmission (Proposed)
4
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 309 of 648
88
Coastal Gas Link Pipeline (Proposed)
5
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 310 of 648
99
NGTL Mainline Facilities for Specific Area Requirements
Proposed Compressor
LEGEND:
Proposed Pipe
Proposed Facility
Approved & Under Construction Applied-for To Be Applied-for
1
2
4
3
5
6 MAP
I.D.
PREVIOUSLY APPLIED FOR FACILITIES DESCRIPTION TARGET IN-
SERVICE DATE
CAPITAL
COST
($Millions)
1 Medicine Hat Compressor Station 3.5 MW Apr-17 66
TOTAL 66
NEW FACILITIES
2 James River Interchange Modifications -Aug-16 6
3 ATCO Pipelines Inland Looping 19 km NPS 24 Nov-16 45
4 ATCO Pembina Expansion Phases 1 & 2 20.2 km NPS 24 Nov-16 60
5 Lodgepole Unit Addition 5.0 MW Nov-17 62
6 South Kirby Expansion Project 39 km NPS 24 Apr-18 137
7 Western Alberta Mainline Loop 33km NPS 42 Nov-18 240
TOTAL 550
Approved Applied-for To Be Applied-for7
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 311 of 648
1010
Western Alberta Mainline Loop
Purpose of the facility:
•To meet increasing design flow requirements
underpinned by FT-D Group 1, 2, and 3
contracts
FT-D Contracts:
•Total FT-D Group 1: 61,669 103m3/d (2,331
TJ/d)
Scope:
•Western Alberta Mainline Loop–33 km NPS
42
Estimated Cost:
•Total: ~$240 Million
Capacity:
•Expected Existing Capacity: ~60 106m3/d
(2,118 mmcf/d)
•Incremental Capacity: ~10 106m3/d (353
mmcf/d)
Schedule:
•NEB s.58 Application –Q4 2016
•In-service –Q4 2018
7
Contractual trigger and scope for Western Alberta
Mainline Loop or facilities is contingent on
renewals and results of upcoming open season
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 312 of 648
11
e lin pe Pi t es
hw rt No
I D A H O
A L B E R TA
B R I T I S H C O L U M B I A
MP-90
M O N TA N A
Ya kim a
STARBU CK C/S #7 I D A H O
BEND C/S #12
BONANZA C/S #14
Sa c ra m ento
NGTL System Kingsgate
Foothills Pipeline
MP-10 B O U N D A R Y MP-30
EASTP ORT C/S #3
Sea ttle
Lancaster LLC Rathdrum CT Spokane
B O N N E R MP-70
MP-110
SANDP OINT C/S #4 MP-50 ATHOL C/S #5 Coeur d 'Alene
Ea st W ena tc hee
W A S H I N G T O N S P O K A N E MP-130 K O O TE N A I
MP-150 ROSALIA C/S #6
W H I T M A N Oregon LNG (Proposed)

Jackson Prairie Storage

Calpine HPP
Hermiston Generating Coyote Spring I Coyote Spring II

MP-210 WA LL A WA L LA MP-230 MP-250
MP-170 Palouse
MP-190 C O L U M B I A

Lewiston
Mist Storage Carty Generating (Proposed) W ALLU LA C/S #8 MP-270 STANFIELD C/S
GTN MAINLINE MILEPOSTS
Stanfield U M A TI L L A Na m e Type M ilepost P ortla nd WA S C O
S H E R M A N
MP-370
G I L LI A M MP-310 IONE C/S #9 M O R R O W
M oyie Springs Bonner’s Ferry Sc hweitzer Sa nd point
Ta p Ta p Ta p Ta p
22 27.04 55.5 59.26 MP-390 JE FF E R S O N
MP-410
KENT C/S #10 Athol Ra thd rum City Ra thd rum CT La nc a ster LCC Cha se Roa d Spoka ne (NPC)
Ta p Ta p Ta p Ta p Ta p Interc onnec t
84.77 97.64 97.64 99.78 102 108.29 Jordon Cove Energy (Proposed) Coos Ba y
Eugen e
MP-430
MP-450
D E S C H U TE S MP-470 MP-490
MP-510
MP-530
M ADRAS C/S #11 C R O O K
MALIN AREA TIE-IN DETAIL
Spoka ne (Avista ) M ic a Spa ngle Rosa lia St. John Pa louse La c rosse Kosm os Fa rm Sta nfield Sta nfield City Ca lpine HPP South Herm iston Coyote Springs M a d ra s
Ta p Ta p Ta p Ta p Ta p Interc onnec t Ta p Ta p Interc onnec t Ta p Ta p Ta p La tera l Ta p
108.29 121.15 134.18 145.71 158.89 172.07 182.79 271.66 277.37 282.76 282.82 289.83 304.25 410.16 Gra nts P a ss
JA C K S O N Klamath Expansion
K L A M AT H
CHEM U LT C/S #13
MP-550
MP-570
Main Meter S tation M.P. 609.80
Turquois e Flats Prineville Red m ond Pronghorn North Bend Bend
Ta p Ta p Ta p Ta p Ta p
426.8 438.3 445.8 450.28 454.51 M ed ford Medford Lateral
Kla m a th Fa lls MP-590 Turquoise Flats
M.P. 612.46
Ruby
South Bend Stea rns La Pine Gilc hrist
Ta p Ta p Ta p Ta p
457.5 469.19 483.9 500.97 Klamath Cogen MP-610 Malin Sapphire Mountain Oregan
Califor nia
Sapphire Mtn Chem ult Kla m a th Fa lls M ed ford
Ta p Interc onnec t La tera l
519.44 599.2 599.2
See MALIN AREA TIE-IN DETAIL
C A L I F O R N I A
RADAR C/S LIKELY C/S
Tusc a rora Turquoise Fla ts (Ruby) M a lin
Interc onnec t Interc onnec t Interc onnec t
609.8 609.8 612.46

GTN LATERAL MILEPOSTS
SHOETREE C/S GTN System
2015
La tera l Coyote Springs Coyote Springs M ed ford M ed ford M ed ford M ed ford
Ta ps
Coyote Springs I Coyote Springs II Kla m a th Cogen Kla m a th Expa nsion W est Kla m a th Phoenix
M ilepo st
18.5 18.5 22.8 22.86 22.85 88.03
Reno Tracy 1 & 2
W ADSW ORTH (BOOSTER) C/S
Na tura lGa s Tra nsm ission Gas Transmission Northwest
Tuscarora Pipeline
NGTL Sysytem Foothills Pipeline
PIPELINE INTERCONNECTS (MMcf/d) Compressor Station
Major Meter Station Interc onnec ts Kingsga te (Foothills) Spoka ne (Avista ) Spoka ne (W illia m s) Pa louse (W illia m s) Sta nfield (W illia m s) Delivery Rec eipt M a lin (Tusc a rora ) Turquoise Fla ts (Ruby) M a lin (P G&E)
W in ter 2,745 65 300 40 680 240 228 1200 2,067
Sum m er 2,593 65 300 40 680 240 228 1200 1,970
0 50 0
Milepost (M.P.)
Power Plant Interconnect
GTN_System_Map_20150401.mxd - April 1 - Hao - TC Mapping 100 200 300 Kilometres 50 100 200 Miles
GTN System Map
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 313 of 648
1212
Currently Available GTN Capacity
9
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 314 of 648
1313
Historical GTN Rates
10
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 315 of 648
1414
Current GTN Rates (1/1/16 –12/31/19)
11
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 316 of 648
1515
GTN Average Day System Throughput
1,992 1,893 1,882 1,901 1,883 1,984
1,751
1,924 1,893 1,897 1,815
1,946
0
500
1,000
1,500
2,000
2,500
3,000
Jan
2015
Feb
2015
Mar
2015
Apr
2015
May
2015
Jun
2015
Jul
2015
Aug
2015
Sep
2015
Oct
2015
Nov
2015
Dec
2015
MD
t
h
/
d
a
y
Kingsgate Throughput Capacity Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 317 of 648
1616
IDAHO
WASHINGTON
Victoria
Sumas
Portland
Seattle
Sandpoint
Redmond
Bend
Salem
Spokane
Pasco
Lewiston
Walla Walla
Yakima
Northwest Pipeline
Molalla
Trail West Pipeline (Proposed)
13
•106 mile, 30 -36”
pipeline
•Receipt point from GTN mainline near
Madras
•Delivery points into
NWN and NWP at
Molalla
•Compression-based
expandability up to
approximately 1Bcf/d
•Open Season Q4
2016
•In-Service: Nov. 2021
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 318 of 648
17
NWP Presentation
17
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 319 of 648
18 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 320 of 648
19 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 321 of 648
20 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 322 of 648
21 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 323 of 648
22 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 324 of 648
23 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 325 of 648
24 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 326 of 648
25 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 327 of 648
26 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 328 of 648
27 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 329 of 648
28 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 330 of 648
29 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 331 of 648
30 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 332 of 648
31 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 333 of 648
32 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 334 of 648
33 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 335 of 648
34 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 336 of 648
35 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 337 of 648
36 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 338 of 648
37 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 339 of 648
38 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 340 of 648
39 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 341 of 648
40 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 342 of 648
41 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 343 of 648
42 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 344 of 648
43 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 345 of 648
44 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 346 of 648
45 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 347 of 648
46 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 348 of 648
47 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 349 of 648
48 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 350 of 648
49 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 351 of 648
50 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 352 of 648
51 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 353 of 648
52 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 354 of 648
53
Regional and Avista’s Supply Side
Resources
Eric Scott
Manager of Natural Gas Resources
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 355 of 648
5454
Connecting Supply and Storage with Customers
54
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 356 of 648
55
•TransCanada Alberta (NOVA)
–Transporting gas out of Alberta,
Canada
•TransCanada BC (ANG)
–Transporting gas through BC,
Canada to US
•Spectra Energy (WestCoast)
–Transporting gas from western BC
Canada to US
•Gas Transmission Northwest (GTN)
–Transporting gas from Canada/US
border to CA
•Williams Pipeline West (NWP)
–Transporting gas from western BC
and US Rockies
•El Paso Ruby Pipeline
–Transporting gas from the
Rockies to Malin
Regional Transportation
Resources
Source: NWGA55
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 357 of 648
5656
Interstate Pipeline Resources
•The Integrated Resource Plan (IRP) brings together the various
components necessary to ensure proper resource planning for
reliable service to utility customers.
•One of the key components for natural gas service is interstate
pipeline transportation. Low prices, firm supply and storage
resources are rendered meaningless to a utility customer without
the ability to transport the gas reliably during cold weather events.
•Acquiring firm interstate pipeline transportation provides the most
reliable delivery of supply.
56
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 358 of 648
57
Pipeline Contracting
Simply stated: The right to move (transport) a
specified amount of gas from Point A to Point B
A B
57
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 359 of 648
5858
Rate Structure
•Pipeline charges a higher demand charge
and a lower variable or commodity charge
Straight Fixed
Variable (SFV)
•Pipeline charges a lower demand charge
and a higher variable or commodity charge
Enhanced
fixed variable
•Pay the same demand and variable costs
regardless of how far the gas is transported
Postage Stamp
Rate
•Pay a variable and demand charge based
on how far the gas is transportedMileage Based
58
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 360 of 648
5959
Types of Pipeline Contracts
Firm Transport
•Contractual rights to:
•Receive
•Transport
•Deliver
•From point A to point B
Interruptible Transport
•Contractual rights to:
•Receive
•Transport
•Deliver
•From point A to Point B AFTER FIRM TRANSPORT HAS BEEN SCHEDULED –and can be BUMPED later!
Seasonal Transport
•Firm service available for limited periods (Nov-Mar) or for a limited amount (TF2 on NWP)
•Usually matched, paired or utilized with storage.
Alternate Firm Transport
•The use of firm transport outside of the primary path
•Priority rights below firm
•Priority rights above interruptible
59
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 361 of 648
6060
Segmentation
Primary Path:
Sumas to CDA
10,000 Dth/day
Guaranteed
Delivery
60
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 362 of 648
6161
Segmentation
Segment:
Sumas to JP –FIRM
10,000 Dth/day
JP to CDA –FIRM
10,000 Dth/day
61
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 363 of 648
6262
Contract Provisions -NWP
62
•Grandfathered Unilateral Evergreen (TF-1, TF-2, SGS-2F)
–Roll-over 1 year
–Shipper has sole option to extend or renew
•Standard Unilateral Evergreen
–Roll-over 1 year
–5 year termination provision
•Standard Bi-lateral Evergreen
–Either transporter OR shipper may terminate
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 364 of 648
6363
Contract Provisions -GTN
63
•Bilateral Evergreen
–Either transporter OR shipper may terminate contract
•Unilateral Evergreen
–Shipper alone may terminate contract
•Right of First Refusal (ROFR)
–Provides “last look”
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 365 of 648
6464
Capacity Releases
64
Example:
AVA released 35,000 Dths/day at full tariff rate to Clark PUD
until 10/31/2025 recapturing over $5.2mm annually all of
which goes to customers.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 366 of 648
6565
Natural Gas Liquids -Extraction
65
•Wet natural gas from
AB/BC has many liquid
components that may be
taken from stream. Each
component is used in
industrial processes and
has value.
•Avista negotiates with an
extraction plant near
Calgary to purchase
these liquids
components.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 367 of 648
6666
Natural Gas Liquids -Extraction
66
•Formula = [0.XX*{{Sum((72%xC3)+(12%*NC4)+(9%*IC4)+(7%x(WTI/42))-gas price) -$0.XX}}]
2013 2014 2015
Liquids revenue
($CAD)$2,323,000 $2,510,000 $840,000
All the revenue goes directly to reducing the price of natural
gas for our customers in all of our service areas!
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 368 of 648
6767
Natural Gas Liquids -Extraction
67
0.00
20.00
40.00
60.00
80.00
100.00
120.00
0.000
0.200
0.400
0.600
0.800
1.000
1.200
1.400
1.600
Au
g
-
1
3
Oc
t
-
1
3
De
c
-
1
3
Fe
b
-
1
4
Ap
r
-
1
4
Ju
n
-
1
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Au
g
-
1
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Oc
t
-
1
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De
c
-
1
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Fe
b
-
1
5
Ap
r
-
1
5
Ju
n
-
1
5
Au
g
-
1
5
Oc
t
-
1
5
De
c
-
1
5
Oil and Liquids Prices
Propane Butane ISO WTI
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
0.000
0.200
0.400
0.600
0.800
1.000
1.200
1.400
1.600
Au
g
-
1
3
Oc
t
-
1
3
De
c
-
1
3
Fe
b
-
1
4
Ap
r
-
1
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Ju
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-
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Au
g
-
1
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-
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-
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-
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Ap
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-
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-
1
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Au
g
-
1
5
Oc
t
-
1
5
De
c
-
1
5
Oil Prices and Liquid Extraction
Propane Butane ISO Revenue
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 369 of 648
68
Storage and Transportation Optimization
Leslie Filer
Manager of Natural Gas Acquisition
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 370 of 648
6969
Year First Unserved
Scenario Comparisons
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 371 of 648
7070
Storage –A valuable asset
•Peaking resource
•Improves reliability
•Enables capture of price spreads between time
periods
•Enables efficient counter cyclical utilization of
transportation (i.e. summer injections)
•May require transportation to service territory
•In-service territory storage offers most flexibility
70
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 372 of 648
71
The Facility
•Jackson Prairie is a
series of deep,
underground reservoirs
–basically thick,
porous sandstone
deposits. •The sand layers lie
approximately 1,000 to
3,000 feet below the
ground surface. •Large compressors and
pipelines are employed
to both inject and
withdraw natural gas at
54 wells spread across
the 3,200 acre facility.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 373 of 648
7272
1.2 Bcf per day (energy equivalent)
•10 coal trains with 100 -50 ton cars each
•29 -500 MW gas-fired power plants
•13 Hanford-sized nuclear power plants
•2 Grand Coulee-sized hydro plants (biggest in US)
46 Bcf of stored gas
•12” pipeline 11,000,000 miles long (226,000 miles to the moon)
•1,400 Safeco Fields (Baseball Stadiums)
•Average flow of the Columbia River for 2 days
•Cube -3,550 feet on a side
Jackson Prairie Interesting Energy Comparisons
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 374 of 648
73
Washington and Idaho
Owned Jackson Prairie
•7.7 Bcf of Capacity with approximately 346,000 Dth/d of
deliverability
Oregon
Owned Jackson Prairie
•823,000 Dth of Capacity with approximately 52,000 Dth/d of
deliverability
Leased Jackson Prairie
•95,565 Dth of Capacity with approximately 2,654 Dth/d of
deliverability
Avista’s Storage Resources
73
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 375 of 648
7474
Optimization
•Optimization helps Avista to recover costs, for
our customers, on assets when not in use for
load.
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 376 of 648
75
Buy 75,000 Dth & Inject Sell 2,500 Dth/Day In November& schedule the withdrawal
Sell 77,500 Dth &
withdraw
Buy 2,500 Dth/Day In August
& cancel scheduled withdrawal
Cash To Forwards
Forward To Cash
Standard
Apr
$3.00
May
$3.10
Jun
$3.00
Jul
$2.50
Aug
$2.75
Sep
$3.25
Oct
3.35
Nov
$3.50
Dec
$3.60
Jan
$3.70
Feb
$3.50
Mar
$3.25
Today
CASH
$3.00
2
1
2
1
Example
Storage Optimization
Example of Storage Opt Deals
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 377 of 648
7676
Transportation
Optimization
AECO to MALIN
Demand $.45
Cost to transport .10
*AECO = $1.45
MALIN = $2.00
$.55 -$.10 = $.45
Lowered cost to
ratepayers by $.45
This is referred to as a
location spread.
Malin
AECO
*2/10/16 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 378 of 648
77
Optimization Overall
•Combine all optimization to create more value
•Optimization has the following effects on rates:
–WA/ID
For every $2.5M of optimization, rates
decrease by ~1%
–OR
For every $1M of optimization, rates
decrease by ~1%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 379 of 648
78
Transportation Modeling in Sendout and
solving unserved demand
Tom Pardee
Manager of Natural Gas Planning
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 380 of 648
7979
Modeling Transportation In SENDOUT®
•Start with a point in time look at each jurisdiction’s resources
•Contracts –Receipt and Delivery Points
•Rates
•Contractual vs. Operational
•Contractual can be overly restrictive
•Operational can be overly flexible
•Incorporating operational realities into our modeling can defer
the need to acquire new resources.
•Gas Supply’s job is to get gas from the supply basin to the
pipeline citygate.
•Gas Engineering/Distribution’s job is to take gas from the
pipeline gate to our customers.
•The major limiting factor is receipt quantity –how much can you
bring into the system?
79
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 381 of 648
80
Modeling Challenges
•Supply needs to get gas to the gate.
•Contracts were created years ago, based on demand projections at that
point in time.
•Stuff happens (i.e. growth differs from forecast).
•Sum of receipt quantity and aggregated delivery quantity don’t identify
resource deficiency for quite some time however…..
•The aggregated look can mask individual city gate issues, and the
disaggregated look can create deficiencies where they don’t exist.
•In many cases operational capacity is greater than contracted.
•Transportation resources are interconnected (two pipes can serve one
area).
•WARNING –we need to be mindful of the modeling limitations.
80
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 382 of 648
8181
What is in SENDOUT®?
Inside:
•Demand forecasts at an aggregated level
•Existing firm transportation resources and current
rates
•Receipt point to aggregated delivery
points/“zone”
•Jurisdictional considerations
•Long term capacity releases
•Potential resources, both supply and demand side
81
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 383 of 648
8282
What is outside SENDOUT®?
Outside:
•Gate station analysis
•Forecasted demand behind the gate
•Growth rates consistent with IRP assumptions
•Actual hourly/daily city gate flow data
•Gate station MDDO’s
•Gate station operational capacities
82
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 384 of 648
83 CONFIDENTIAL –Do Not Distribute83
InterconnectSupply
Storage
Transport
Demand
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 385 of 648
84
Solving Unserved Demand
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 386 of 648
85
When unserved demand does show up……
There are a few questions we need to ask:
1.Why is the demand unserved?
2.What is the magnitude of the short? (i.e Are we 1 Dth or 1000
Dth’s short?)
3.What are my options to meet it?
85
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 387 of 648
8686
When current resources don’t meet demand
what do we consider?
•Transport capacity release recalls
•“Firm” backhauls
•Contract for existing available transportation
•Expansions of current pipelines
•Peaking arrangements with other utilities (swaps/mutual assistance
agreements) or marketers
•In-service territory storage
•Satellite/Micro LNG (storage inside service territory)
•Large scale LNG with corresponding pipeline build into our service
territory
•Structured products/exchange agreements delivered to city gates
•Biogas
•Avista distribution system enhancements
•Demand side management
86
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 388 of 648
8787
New Resource Risk Considerations
•Does is get supply to the gate?
•Is it reliable/firm?
•Does it have a long lead time?
•How much does it cost?
•New build vs. depreciated cost
•The rate pancake
•Is it a base load resource or peaking?
•How many dekatherms do I need?
•What is the “shape” of resource?
•Is it tried and true technology, new technology, or yet to be discovered?
•Who else will be competing for the resource?
87
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 389 of 648
88
Demand and
Supply Side
Sensitivities
Optimize
Resource
Portfolio
Stochastic
Cost/Risk Analysis
Prices and
Weather
Highest
Performing
Portfolios
selection
Preferred
Portfolio
selection
Core Cases Price Forecast
Sensitivities, Scenarios, Portfolios
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 390 of 648
89
Supply Scenarios for the 2016 IRP
Supply Scenarios
?????
?????
?????
?????
•Do they get gas to the gate?
•Does this affect pricing at the
basins?
•Rank the risk of these
scenarios.
89
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 391 of 648
90
2016 Natural Gas IRP
Carbon Issues
John Lyons, Ph.D.
Second Technical Advisory Committee Meeting
February , 2015
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 392 of 648
9191
Carbon Laws and Regulations
•Mixed bag of federal and state laws and proposals
•Regulatory mandates
•Cap and trade programs
•Carbon taxes
•Focus tends to be on electric generation
–Some proposals (Washington I-732) and laws (California AB32)
directly impact the natural gas markets or the distribution
companies
91
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 393 of 648
9292
Federal
•Many past attempts, current focus under a regulatory model
through the Clean Air Act (CAA)
•Clean Power Plan (CPP) –reduce greenhouse gas emissions
from covered existing power plants 32 percent below 2005
levels by 2030 under section 111(d) of the CAA through three
building blocks:
1.Improve heat rate of coal plants
2.Increase utilization of natural gas-fired plants and reduce coal plant use
3.Increase use of renewable resources
•CPP stayed by US Supreme Court on February 9, 2016
•Oral arguments June 2, 2016 at DC Circuit Court of Appeals
92
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 394 of 648
9393
Idaho
•No active or proposed greenhouse gas legislation
•Provided comments about the CPP and the federal
implementation plan
•Were working towards submitting a state implementation
plan by September 2016 –no official word on the current
plans with the stay from the Supreme Court. Will
probably stop working on the plan until the outcome of
the court case is known.
93
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 395 of 648
9494
Oregon
•HB 4036: “Coal to Clean” bill voted out of committee
–50 percent renewable by 2040
–Eliminate coal power in rates by 2030
–Compromise to a ballot measure
•SB 1574: replace greenhouse gas emission goal with a
cap and trade program for 2025. Probably dead for this
session.
•HB 4068: repeal greenhouse gas emissions goals and
require Environmental Quality Commission to adopt
goals for 2025 and limits for 2035 and 2050. Officially
dead for this session
94
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 396 of 648
9595
Washington
•I-732 Initiative to the Legislature
–Revenue neutral $25 per metric ton tax escalating 3.5 percent
per year plus inflation until $100 per ton in 2016 dollars
–Taxes natural gas
–Hearings held on I-732, but expected to go to the November
ballot
–Other proposals have been discussed for alternatives
•Possible competing ballot initiative
•Clean Air Rule proposal
95
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 397 of 648
96
Questions?
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 398 of 648
9797
2016 IRP Timeline
•August 31, 2015 –Work Plan filed with WUTC
•January through April 2016 –Technical Advisory Committee
meetings. Meeting topics will include:
–Demand Forecast and Demand Side Management –January
21
–Supply/Infrastructure and Potential Case Discussion–February
18
–Distribution Planning, Natural Gas Pricing, SENDOUT®
Preliminary Output Results and Further Case Discussion –
March 30
–SENDOUT® results –April 21
•May 30, 2016 –Draft of IRP document to TAC
•June 30, 2016 –Comments on draft due back to Avista
•July 2016 –TAC final review meeting (if necessary)
•August 31, 2016 –File finalized IRP document
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 399 of 648
1
2016 Avista Natural Gas IRP
Technical Advisory Committee Meeting
March 30, 2016
Spokane, WA
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 400 of 648
22
Agenda
•Introductions & Logistics
•CNG/NGV Initiatives
•Distribution System Planning
•Gate Station Analysis
•Procurement Planning
•Natural Gas Pricing
•Preliminary Results and Scenario Discussion
Following TAC #3 Meeting:
•Sendout overview
2
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 401 of 648
33
2016 IRP Timeline
•August 31, 2015 –Work Plan filed with WUTC
•January through April 2016 –Technical Advisory Committee
meetings. Meeting topics will include:
–Demand Forecast and Demand Side Management –January
21
–Supply/Infrastructure and Potential Case Discussion–February
18
–Distribution Planning, Natural Gas Pricing, SENDOUT®
Preliminary Output Results and Further Case Discussion –
March 30
–SENDOUT® results –April 21
•May 30, 2016 –Draft of IRP document to TAC
•June 30, 2016 –Comments on draft due back to Avista
•July 2016 –TAC final review meeting (if necessary)
•August 31, 2016 –File finalized IRP document
3
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 402 of 648
4
Compressed Natural Gas Services
Marc Schaffner, Strategic Initiatives Manager
Natural Gas Technical Advisory Committee
March 30, 2016
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 403 of 648
5
Natural Gas Reserves and Utilization
U.S. Natural Gas Reserves
The U.S.’s total recoverable resource base at 2,515 trillion cubic feet
Projected to meet total domestic demand over the next 100 years
PGC’s year-end estimate for 2014 rose 5.5 percent from 2012
Source: Potential Gas Committee (PGC)
Natural Gas Vehicles (NGV) Worldwide
Estimated 15.2 million natural gas vehicles (NGVs)
Asia and Middle East 8.8M, South America 4.3 M, Africa .16M and North America .14M
The U.S. is number 17 in the world with less than 1 percent of the NGVs in use
NGVs on U.S. Highways
Estimated 150,000 NGVs on U.S. highways
Estimated 15,000 NGVs were added to U.S. highways in 2012
Source: U.S. Department of Energy
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 404 of 648
6
U.S. CNG Infrastructure
About 1,620 Private and Public
Refueling Stations
Source: U.S. Department of Energy, February 2016
<5% in Washington,
Oregon and Idaho
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 405 of 648
7
U.S. CNG Infrastructure
About 900 are Public Refueling Stations
Source: U.S. Department of Energy, February 2016 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 406 of 648
8
The Benefits of Compressed Natural Gas
Environmentally responsible
It’s clean and efficient
25% less greenhouse gas emissions than gasoline
or diesel
A vital part of an alternative transportation portfolio
Cost effective
Lowers fuel costs
Tax credits and incentives
Reduces dependency on imported fuel sources
Natural gas is an abundant, domestic resource
A clean fueling solution across an increasing range of NGV
classes
Aimed at extending benefits to commercial fleet operators
Mobilizes safe and reliable CNG equipment
85 light duty NGVs
CNG refueling infrastructure
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 407 of 648
9
Over the past 25 years Avista has fueled light duty vehicles,
service continuity equipment and fork lifts with CNG
Ten of our gas operating centers have maintained private CNG
refueling infrastructure over that time period
2011, we began devising plans to upgrade CNG infrastructure at
our highest volume service centers in Washington and Idaho
2012, we completed construction of a new refueling station at
our Mission Avenue service center in Spokane, WA
2013, we completed a second Spokane refueling station at our
Dollar Road gas service center
2014, we finished construction of a new refueling station at our
electric and gas operations center in Coeur d‘ Alene, ID
Avista’s Investment in CNG
Mission Avenue Refueling
Station -Spokane
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 408 of 648
10
Avista’s CNG Refueling Stations
CNG Refueling
Location
Project
Status
Compression
Capability
Storage
Capacity
Mission Avenue SC
Spokane, Wash.Completed 2012
125 HP Compressor
202 SCFM 280 GGE at 4500 psi
Dollar Road SC
Spokane, Wash.Completed 2013 125 HP Compressor
202 SCFM 280 GGE at 4500 psi
Coeur d’Alene SC
Coeur d’Alene, Idaho Completed 2014 (2) 50 HP Compressors
75 SCFM 280 GGE at 4500 psi
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 409 of 648
11
Source: Clean Cities Alternative Fuel Price Report, October 2015
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 410 of 648
12 Source: Clean Cities Alternative Fuel Price Report, October 2015 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 411 of 648
13Source: Clean Cities Alternative Fuel Price Report, October 2015 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 412 of 648
14
Natural Gas Vehicle Investment Recovery*
Waste Hauling NGV
Customer Investment $35,000 per vehicle
Miles per gallon 3
Annual mileage 25,000
CNG per gallon $2.00
Diesel per gallon $4.00
Estimated payback 25 months
Annual fuel savings $16,800
* Q1 2014
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 413 of 648
15
Natural Gas Vehicle Investment Recovery*
Waste Hauling NGV
Customer Investment $35,000 per vehicle
Miles per gallon 3
Annual mileage 25,000
CNG per gallon $2.09
Diesel per gallon $2.59
Estimated payback 7.75 years
Annual fuel savings $4,583
* Q4 2015
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 414 of 648
16
Avista CNG Services Tariffs
•February 2015,we established a Compressed Natural Gas
Service tariff (Schedule 441)in Oregon;which allows us to
provide Company-owned CNG refueling infrastructure for
transportation sited on the customer’s premise
•We have secured (“non-tariffed”)authority,provided by WUTC
staff,to serve NGV operators in the same way (as Schedule 441
Oregon)in Washington
•Effective May 22,2015,we established a Backup and
Supplemental Compressed Natural Gas Service tariff (Schedule
149)that allows Avista to fuel (under contract)NGV fleet
operators
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 415 of 648
17
Thank You
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 416 of 648
18
Appendix
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 417 of 648
19
Avista Contributors
Energy Solutions
Account Executives
Customer Solutions
Regional Business Managers
Government Relations
Lobbyists
Legal Counsel
Risk
Real Estate
Contract Administration
Real Estate
Legal
Property Acquisition
Regulatory
Rates & Tariffs
Treasury
Billing Analysis
Financial Planning &
Analysis
Facilities
Project Management
Fleet
NGV Management
CNG Infrastructure Maintenance
Distribution Infrastructure
Gas Engineering Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 418 of 648
20
Organizational Capability
What are we learning?
•The value of broad-based collaboration occurring across a dynamic natural gas for
transportation marketplace. Private & public sector customers, industry
associations, government, contractors and vendors
What skills are we developing?
•NGV acquisition and maintenance
•CNG fueling infrastructure planning, construction and maintenance
•CNG/NGV consultation
What value does Avista’s CNG capability provide our employees, customers
and business community?
•A more robust portfolio of energy offerings
•Enhanced revenue and cost saving opportunities for regional businesses
•An innovative, sustainable way to positively affect environmental
quality and energy independence
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 419 of 648
21
Distribution System Planning
Terrence Browne, Senior Gas Planning Engineer
Natural Gas Technical Advisory Committee
March 30, 2016
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 420 of 648
2222
Mission
•Using technology to plan and design a safe, reliable, and
economical distribution system
22
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 421 of 648
2323
Gas Distribution Planning Game Plan
•Review
•Scope of Gas Distribution Planning
•SynerGi Load Study Tool
•Planning Criteria
•Interpreting Results
•Long-term Planning Objectives
•Historical Temperatures
•Monitoring Our System
•The (Customer) Forecast
•Gate Station Capacity Review
•Project Examples
23
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 422 of 648
24
–Population of service area 1.5 million
370,000 electric customers
330,000 natural gas customers
Service Territory and Customer Overview
•Serves electric and natural gas customers in eastern Washington and northern Idaho,
and natural gas customers in southern and eastern Oregon
24
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 423 of 648
2525
Daily Demand Profiles
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
020406080100
De
k
a
t
h
e
r
m
s
2015 Average Temp (°F)
Medford/Roseburg
25
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 424 of 648
26
Seasonal Demand Profiles
26
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 425 of 648
2727
Our Planning Models
•122 cities
•40 load study models
27
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 426 of 648
2828
__
Pup Pdown
Q
L ||
D
__
5 Variables for Any Given Pipe
28
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 427 of 648
2929
Scope of Gas Distribution Planning
Supplier Pipeline
High Pressure Main
Reg.
Distribution Main and Services
Reg.Reg.
Gate
Sta.
29
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 428 of 648
3030
Scope of Gas Distrib. Planning cont.
Gate
Sta.
Reg.Reg.Reg.
Reg.Reg.
Gate
Sta.
Gate
Sta.
30
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 429 of 648
3131
SynerGi (SynerGEE, Stoner) Load Study
•Simulate distribution behavior
•Identify low pressure areas
•Coordinate reinforcements with expansions
•Measure reliability
31
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 430 of 648
32
35 DD
30’ F
32
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 431 of 648
33
Preparing a Load Study
•Estimating Customer Usage
•Creating a Pipeline Network
•Join Customer Loads to Pipes
•Convert to Load Study
33
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 432 of 648
3434
Estimating Customer Usage
•Gathering Data
–Days of service
–Degree Days
–Usage
–Name, Address, Revenue Class, Rate Schedule…
34
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 433 of 648
3535
Estimating Customer Usage cont.
•Degree Days
–Heating (HDD)
–Cooling (CDD)
•Temperature -Usage Relationship
–Load vs. HDD’s
–Base Load (constant)
–Heat Load (variable)
–High correlation with residential
Avg. Daily Heating Cooling
Temperature Degree Days Degree Days
('Fahrenheit) (HDD) (CDD)
85 20
80 15
75 10
70 5
65 0 0
60 5
55 10
50 15
45 20
40 25
35 30
30 35
25 40
20 45
15 50
10 55
5 60
4 61
0 65
-5 70
-10 75
-15 80
-17 82
35
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 434 of 648
3636
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 435 of 648
37
Heat Base
37
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 436 of 648
3838
Estimating Customer Usage cont.
•Peaking Factor
–Peaking Factor = 6.25% of daily load
–“Observed ratio” of greatest hourly flow to total daily flow at
Gate Stations
•Industrial Customers
–Model maximum hourly usage per Contractual Agreement
–Firm Transportation customers only
–Low Temperature-Usage correlation
38
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 437 of 648
3939
Creating a Pipeline Model
•Elements
–Pipes, regulators, valves
–Attributes: Length, internal diameter,
roughness
•Nodes
–Sources, usage points, pipe ends
–Attributes: Flow, pressure
39
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 438 of 648
4040
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 439 of 648
4141
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 440 of 648
4242
Join Customer Loads to a Model
•Residential and commercial loads are assigned to pipes
•Industrial or other large loads are assigned to nodes
42
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 441 of 648
4343
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 442 of 648
4444
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 443 of 648
4545
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 444 of 648
4646
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 445 of 648
4747
Balancing Model
•Simulate system for any temperature
–HDD’s
•Solve for pressure at all nodes
47
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 446 of 648
48
35 DD
30˚F
48
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 447 of 648
4949
Validating Model
•Simulate recorded condition
•Pressure Recorders
–Do calculated results match field data?
•Gate Station Telemetry
–Do calculated results match source data?
•Possible Errors
–Missing pipe
–Source pressure changed
–Industrial loads
49
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 448 of 648
50
41 psig
Location: N. Orchard, Moscow ID
Observation Date: Friday, March 1st
Hi = 35˚ F
Low = 25˚F
Avg = 30˚F
= 35 DD
Validating Model cont.
50
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 449 of 648
51
35 DD
30˚F
N. Orchard Moscow, ID
51
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 450 of 648
5252
•Reliability during design HDD
–Spokane 82 HDD
–Medford 61 HDD
–Klamath Falls 72 HDD
–La Grande 74 HDD
–Roseburg 55 HDD
•Maintain minimum of 15 psig in system at all times
–5 psig in lower MAOP areas
Planning Criteria
52
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 451 of 648
5353
•Reliability during design HDD
–Spokane 82 HDD (avg. daily temp. -17’ F)
–Medford 61 HDD (avg. daily temp. 4’ F)
–Klamath Falls 72 HDD (avg. daily temp. -7’ F)
–La Grande 74 HDD (avg. daily temp. -9’ F)
–Roseburg 55 HDD (avg. daily temp. 10’ F)
•Maintain minimum of 15 psig in system at all times
–5 psig in lower MAOP areas
Planning Criteria
53
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 452 of 648
54
35 DD
30˚F
54
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 453 of 648
55
50 DD
15˚F
55
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 454 of 648
56
65 DD
0˚F
56
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 455 of 648
5757
Interpreting Results
•Identify Low Pressure Areas
–Number of feeds
–Proximity to source
•Looking for Most Economical Solution
–Length (minimize)
–Construction obstacles (minimize)
–Customer growth (maximize)
57
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 456 of 648
585858
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 457 of 648
595959
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 458 of 648
60
65 DD
0’ F
60
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 459 of 648
61
65 DD
0’ F
R
61
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 460 of 648
62
82 DD
-17’ F
R
62
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 461 of 648
6363
Long-term Planning Objectives
•Future Growth/Expansion
•Design Day Conditions
•Facilitate Customer Installation Targets
63
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 462 of 648
6464
Historical Temperatures
64
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 463 of 648
6565
•Reliability during design HDD
–Spokane 82 HDD (avg. daily temp. -17’ F)
–Medford 61 HDD (avg. daily temp. 4’ F)
–Klamath Falls 72 HDD (avg. daily temp. -7’ F)
–La Grande 74 HDD (avg. daily temp. -9’ F)
–Roseburg 55 HDD (avg. daily temp. 10’ F)
Historical Temperatures
65
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 464 of 648
6666
•Reliability during design HDD
–Spokane 82 HDD (avg. daily temp. -17’ F)
•11/23/10: 64 HDD
–Medford 61 HDD (avg. daily temp. 4’ F)
–Klamath Falls 72 HDD (avg. daily temp. -7’ F)
–La Grande 74 HDD (avg. daily temp. -9’ F)
–Roseburg 55 HDD (avg. daily temp. 10’ F)
Historical Temperatures
66
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 465 of 648
6767
•Reliability during design HDD
–Spokane 82 HDD (avg. daily temp. -17’ F)
•11/23/10: 64 HDD
•12/6/13 and 12/8/13: 58 HDD
–Medford 61 HDD (avg. daily temp. 4’ F)
•12/8/13: 52 HDD
–Klamath Falls 72 HDD (avg. daily temp. -7’ F)
•12/8/13: 72 HDD
–La Grande 74 HDD (avg. daily temp. -9’ F)
•12/8/13: 65 HDD
–Roseburg 55 HDD (avg. daily temp. 10’ F)
•12/8/13: 44 HDD
Historical Temperatures
67
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 466 of 648
6868
•Reliability during design HDD
–Spokane 82 HDD (avg. daily temp. -17’ F)
•11/23/10: 64 HDD
•12/6/13 and 12/8/13: 58 HDD
•1/1/16: 55 HDD
–Medford 61 HDD (avg. daily temp. 4’ F)
•12/8/13: 52 HDD
–Klamath Falls 72 HDD (avg. daily temp. -7’ F)
•12/8/13: 72 HDD
•1/2/16: 62 HDD
–La Grande 74 HDD (avg. daily temp. -9’ F)
•12/8/13: 65 HDD
–Roseburg 55 HDD (avg. daily temp. 10’ F)
•12/8/13: 44 HDD
Historical Temperatures
68
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 467 of 648
6969
Monitoring Our System
69
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 468 of 648
7070
Monitoring Our System
•Validates our Load Studies
•Mechanical >>> Electronic
•Daily Feedback
•Real time if necessary
70
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 469 of 648
71
Post Falls State Line
71
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 470 of 648
72
Hayden Lake
72
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 471 of 648
73
South Hayden Lake
73
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 472 of 648
7474
Real-time Pressure & Flow Monitoring
74
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 473 of 648
7575
One-line Diagrams
•schematic
•connectivity
•hierarchy
•framework
•normal operations
•emergencies
75
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 474 of 648
7676
Sprechen El Similar Lingua
•Translating the Forecast
•Gas Planning Layers
•Gate Station Capacity Review
76
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 475 of 648
7777
WA-ID Region Firm Customers: 2016 IRP and 2014 IRP
210,000
220,000
230,000
240,000
250,000
260,000
270,000
280,000
290,000
300,000
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
WA-ID-Base 2014 WA-ID-Base
+5,500
IRP Avg.Annual Growth
2016-2035
2014 1.0%
2016 1.1%
77
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 476 of 648
7878
OR Region Firm Customers: 2016 IRP and 2014 IRP
80,000
85,000
90,000
95,000
100,000
105,000
110,000
115,000
120,000
125,000
130,000
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
OR-Base 2014 OR-Base
IRP Avg.Annual Growth
2016-2035
2014 0.9%
2016 1.2%
+7,000
78
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 477 of 648
7979
System Firm Customers: 2016 IRP and 2014 IRP
300,000
320,000
340,000
360,000
380,000
400,000
420,000
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
WA-ID-OR-Base 2014 WA-ID-OR-Base
+12,500
IRP Avg.Annual Growth
2016-2035
2014 1.0%
2016 1.1%
79
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 478 of 648
8080
Strategic Gas Growth Projects
Project Name AREA STATUS Forecasted
Connects (3yr)
Forker Road Spokane Complete 15
Rolling Hills Estates Roseburg 5,000 ft constructed, 65% complete Est.
Comp date Feb 2016 164
Connell -NW Davis St.Spokane Complete 15
Debbie Drive Klamath Falls Complete 27
West side of Kenwood St Roseburg Complete 5
Bonanza Klamath Falls In construction Est. Comp date April 2016
–River Crossing Permit 152
Ridge Road Spokane Complete 12
N Newport Hwy Spokane Waiting for Gas Engineering 3
Midland Rd Klamath Falls Complete 90
Austin Road -Phase I Spokane Complete 14
Austin Road -Phase II Spokane Complete 30
Austin Road -Phase III Spokane Starting December 15, 2015 21
Sunwest Airway Heights Starting Jan-Feb 2016 30
Santa Maria Estates Roseburg Est. start date mid March 2016 40
Linda Way Post Falls Complete 12
Kooken Estates Roseburg Est. start date June/July 2016 38
Round Lake Klamath Falls Est. start date June/July 2016 128
Neyland Rd Spokane Completed 8
Winch Rd –Wild Ridge Coeur ‘d Alene Complete 21
TOTAL 825
80
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 479 of 648
8181
22 Home Development in Warden, WA
81
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 480 of 648
8282
Gas Planning Layers
•Gas Planning Proposals
•Gas Planning AOI
82
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 481 of 648
8383
Gas Planning Proposals
Add
4”
83
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 482 of 648
8484
Gas Planning AOI
Low
pressure
Future
Growth
84
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 483 of 648
85
City Gate Analysis Results
Terrence Browne, Senior Gas Planning Engineer
Natural Gas Technical Advisory Committee
March 26, 2014
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 484 of 648
8686
City Gate Analysis Issues to Address
•MDQ vs. MDDO
•Our gate vs. Pipeline gate
•Operational capacity vs. contracted capacity
•Pipeline differences
•Zonal vs. Point Specific
•Laterals and Mainlines
86
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 485 of 648
87
Forecasting Demand Behind the Gate
•Our IRP desire has always been to forecast to as granular a level
as possible using the available data.
•Attempts to forecast demand behind the gate using existing
forecasting methodology has been challenging.
•Revenue data does not have daily meter reads for core
customers making regression analysis on a use per HDD per
customer difficult.
•DSM would become more burdensome than it already is.
•Some towns can be served by multiple pipelines and the mix
can change over time.
87
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 486 of 648
88
Forecasting Demand Behind the Gate cont.
While there are challenges, there is modeling that we can do to
help identify more granular city gate deficiencies.
•Utilize daily/hourly pipeline flow data from each meter
station to estimate what demand could be on a peak day or
any heating degree day.
•Apply growth factors to estimate what the demand could
grow to consistent with IRP assumptions/methodology.
88
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 487 of 648
8989
Gate Station Capacity Review
89
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 488 of 648
9090
Gate Station Capacity Review cont.
Spokane,
CDA Service
Areas
90
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 489 of 648
9191
y = 0.1278x + 3.5481
R² = 0.64840
5
10
15
20
25
30
35
0 10 20 30 40 50 60 70 80 90 100
Fl
o
w

(
m
c
f
h
)
HDDCity Gate Station # X
Daily Peak Flow (mcfh)
GTN Physical Capacity
(31 mcfh)
Design Day Peak Flow
(14.0 mcfh; 82 HDD)
Contractual Amount
(21.9 mcfh, Diversity
Factor = 1.5)
Linear (Daily Peak Flow
(mcfh))
82 HDD
Gate Station Capacity Review
91
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 490 of 648
9292
y = 2.1146x + 65.605
R² = 0.63080
50
100
150
200
250
300
0 10 20 30 40 50 60 70 80 90 100
Fl
o
w

(
m
c
f
h
)
HDD
City Gate Station # Y
Daily Peak Flow (mcfh)
NWP Physical Capacity
(206.0 mcfh, Diversity
Factor = 1.44)
Design Day Peak Flow
(239.0 mcfh; 82 HDD)
Contractual Amount
(121.8 mcfh, Diversity
Factor = 1.44)
Linear (Daily Peak Flow
(mcfh))
82 HDD
Gate Station Capacity Review
92
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 491 of 648
9393
Gate Station Capacity Review: WA
106%
118%
120%
138%
0%20%40%60%80%100%120%140%160%
Mica
Pullman
Sprague
Colton
DESIGN DAY DEMAND: % OF PHYSICAL CAPACITY
93
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 492 of 648
9494
Gate Station Capacity Review: OR
102%
106%
158%
0%20%40%60%80%100%120%140%160%180%
Sutherlin
Klamath Falls
LaGrande
DESIGN DAY DEMAND: % OF PHYSICAL CAPACITY
94
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 493 of 648
9595
Gate Station Capacity Review: ID
105%
106%
104%105%105%106%106%107%
CDA East
Bonners Ferry
DESIGN DAY DEMAND: % OF PHYSICAL CAPACITY
95
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 494 of 648
96
Natural Gas Prices
Tom Pardee
Manager of Natural Gas Planning
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 495 of 648
97
What Drives the Natural Gas Market?
Natural Gas Spot Prices (AECO)
Supply
–Type: Conventional vs.
Non-conventional
–Location
–Cost
Demand
–Residential/Commercial/I
ndustrial
–Power Generation
–Natural Gas Vehicles
Legislation
–Environmental
Energy Correlations
–Oil vs. Gas
–Coal vs. Gas
–Natural Gas Liquids
Weather
Storage
97
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 496 of 648
98
Short Term Market Perspective
98
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 497 of 648
99
The Short Term Fundamentals
Bulls
Dwindling rig counts
Economic recovery
LNG & Methanol Plants
Weather –Normal is now bullish
Power Demand
Bears
Demand is weak
Storage is full
Oil Prices are near 10+ year lows
Record Production
Increased drilling efficiency
Stealth/Ghost Wells
99
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 498 of 648
100100
The Long Term Fundamentals
Demand
•Economy (Recession, Depression, Inflation,
etc.)
•Industrial Demand
•Power Generation
•LNG, NGV, CNG
US Natural Gas Supply and Production
•Resource Base
•Drilling Efficiency
•Associated Gas
Global Dynamics –LNG Imports and Exports
North American Storage Capacity
Correlation (or lack thereof) with other energy
products
The Environment
•Carbon Legislation
•Fracking
•Renewable Portfolio Standards
100
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 499 of 648
101
The Changing the Flow Dynamics
101
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 500 of 648
102
Forecasted Natural Gas Production
102
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 501 of 648
103103
Canadian Production
Source: “Canada’s Energy Future 2016”National Energy Board Outlook 103
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 502 of 648
104104
LNG
Source: FERC
104
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 503 of 648
105105
Oil and Gas Rigs & Production
372 92
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 504 of 648
106106
US –Drilling efficiency
•EIA DPR -7 most prolific areas in the US, which account
for all natural gas production growth during 2011 -2014106
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 505 of 648
107107
How prices affect IRP Planning?
•Major component of the total cost
•Change in price can trigger price elastic response
•THE major piece of avoided costs and therefore cost effectiveness
of DSM
•Can change resource selection based on basin differentials
•Storage utilization
107
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 506 of 648
108
IRP Natural Gas Price Forecast
Methodology
1.Two fundamental forecasts (Consultant #1 & Consultant #2)
2.Forward prices
3.Year 1 -forward price only
4.Year 2 -75% forward price / 25% average consultant forecasts
5.Year 3 -50% forward price / 50% average consultant forecasts
6.Year 4 –6 25% forward price / 75% average consultant forecasts
7.Year 7 -50% average consultant without CO2 / 50% average consultant with
CO2
108
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 507 of 648
109109
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 508 of 648
110
2014 IRP
Low –Med –High
REAL
110
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 509 of 648
111
2016 IRP
Low –Med –High
REAL
111
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 510 of 648
112112
Carbon Adder –Expected
•Includes carbon pricing from 2026-2035 from our
consultant
•Avista added pricing starting from 2018 to address
incremental adders from legislation in our service
territory jurisdictions.
–We assume floor pricing the same as California’s cap and trade
of $10 back at the programs initial auction in 2013.
112
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 511 of 648
113113
Carbon Prices
Expected = 2 Sigma of “Likely Policy” &
No carbon & i-732 @ equally distributed between remaining probability
2018
$9.89
$19.93
113
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 512 of 648
114114
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 513 of 648
115
Regional Price Assumptions
115
Regional Price as a percent of Henry Hub Price
AECO Sumas Rockies Malin Stanfield
Consultant1 89.9%98.8%95.4%101.4%100.4%Forecast Average
Consultant2 85.3%94.2%96.7%98.6%96.8%Forecast Average
Historic Cash 86.8%97.2%97.1%99.6%97.5%Three Yr Average
Prior IRP 82.5%90.8%88.9%94.5%92.1%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 514 of 648
116
Monthly Price Shape
116
Monthly Price as a percent of Average Price
Jan Feb Mar Apr May Jun
Consult1 113.2%113.8%92.8%90.7%91.5%92.0%
Consult2 99.9%99.7%98.7%97.1%97.7%98.6%
Prior IRP 102.9%102.9%99.2%97.4%97.7%98.4%
Jul Aug Sep Oct Nov Dec
Consult1 93.5%94.5%94.3%95.3%109.7%118.9%
Consult2 100.5%101.7%102.1%102.1%100.6%101.3%
Prior IRP 99.3%99.5%99.6%99.4%100.8%103.2%
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 515 of 648
117
Procurement Planning
Tom Pardee, Manager of Natural Gas Planning
Natural Gas Technical Advisory Committee
March 16, 2016
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 516 of 648
118118
Procurement Plan Philosophy
•Mission
•To provide a diversified portfolio of reliable
supply and a level of price certainty in volatile
markets.
•We cannot accurately predict what natural gas prices will do, however we
can use experience, market intelligence, and fundamental market analysis to
structure and guide our procurement strategies.
•Our goal is to develop a plan that utilizes customer resources (storage and
transportation), layers in pricing over time for stability (time averaging),
allows discretion to take advantage of pricing opportunities should they arise,
and appropriately manages risk.
118
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 517 of 648
119
Review conducted with SOG includes:
•Mission statement and approach
•Current and future market dynamics
•Hedge type and percentage
•Resources available (i.e. storage and
transportation)
•Hedge windows (how many, how long)
•Long term hedging approach
•Storage utilization
•Analysis (volatility, past performance, scenarios,
etc.)
•Market opportunities
Comprehensive Review of Previous Plan
119
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 518 of 648
120120
A Thorough Evaluation of Risks
Risk
Assessment
Load
Volatility
•Seasonal
Swings
Price
•Cash vs.
Forward
Market
Liquidity
•Is there
enough?
Counterparty
•Who can we
transact with?
Foreign
Currency
•What’s our
exposure?
Legislation
•Does it impact
our plan?
120
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 519 of 648
121121
Procurement Plan Structure
•The procurement plan incorporates a portfolio approach
that is diversified in terms of:
–Components: The plan utilizes a mix of index, fixed price, and storage
transactions.
–Transaction Dates:Hedge windows are developed to distribute the
transactions throughout the plan.
–Supply Basins:Plan to primarily utilize AECO, execute at lowest price basis
at the time.
–Delivery Periods:Hedges are completed in annual and/or seasonal
timeframes. Long-term hedges may be executed.
•Transactions are executed pursuant to a plan and
process; however, the procurement plan allows Avista to
be flexible to market conditions and opportunistic when
appropriate.
121
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 520 of 648
122122
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 521 of 648
123
Preliminary Modeling Results
Tom Pardee, Manager of Natural Gas Planning
Natural Gas Technical Advisory Committee
March 26, 2014
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 522 of 648
124124
1.Customer annual growth rates:
2.Use per customer coefficients –3 year average use per HDD per customer
3.Weather planning standard –coldest day on record
WA/ID 82; Medford 61; Roseburg 55; Klamath 72; La Grande 74
Developing a Reference Case
Customer
count
forecast
Use per
customer
coefficients
Weather Reference
Case Demand
124
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 523 of 648
125
Reference Demand Case
125
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 524 of 648
126
Demand Sensitivities
126
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 525 of 648
127
Demand Sensitivities-Preliminary Results
127
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 526 of 648
128
Mix and Match to Make Scenarios
128
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 527 of 648
129
Demand Scenarios –Proposed
129
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 528 of 648
130
Weather Modeling
130
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 529 of 648
131
Coldest on Record Dates
WA/ID –December 30, 1968
Medford –December 9, 1972
Roseburg –December 22, 1990
Klamath Falls –December 8, 2013
La Grande –December 23,1983
Area Coldest in 20 Year
HDD
Coldest on Record
HDD
WA-ID 76 82
Klamath Falls 72 72
La Grande 74 74
Medford 54 61
Roseburg 48 55
Planning Standard Assumptions
131
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 530 of 648
132132*2016 Reference Plus “ “ sensitivity132
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 531 of 648
133133 *2016 Reference Plus “ “ sensitivity133
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 532 of 648
134*2016 Reference Plus “ “ sensitivity134
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 533 of 648
135 *2016 Reference Plus “ “ sensitivity135
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 534 of 648
136 *2016 Reference Plus “ “ sensitivity136
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 535 of 648
137137
2016 IRP Timeline
•August 31, 2015 –Work Plan filed with WUTC
•January through April 2016 –Technical Advisory Committee
meetings. Meeting topics will include:
–Demand Forecast and Demand Side Management –January
21
–Supply/Infrastructure and Potential Case Discussion–February
18
–Distribution Planning, Natural Gas Pricing, SENDOUT®
Preliminary Output Results and Further Case Discussion –
March 30
–SENDOUT® results –April 21
•May 30, 2016 –Draft of IRP document to TAC
•June 30, 2016 –Comments on draft due back to Avista
•July 2016 –TAC final review meeting (if necessary)
•August 31, 2016 –File finalized IRP document
137
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 536 of 648
1
2016 Avista Natural Gas IRP
Technical Advisory Committee Meeting
April 21, 2016
Spokane, WA
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 537 of 648
22
Agenda
•Introductions & Logistics
•Avista Natural Gas Conservation Potential Assessment
Results
•Assumptions Review
•Demand Sensitivities and Scenarios Updates
•Supply Side Resource Options
•Stochastic Analysis
•Key Issues & Document Discussion
2
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 538 of 648
33
2016 IRP Timeline
•August 31, 2015 –Work Plan filed with WUTC
•January through April 2016 –Technical Advisory Committee
meetings. Meeting topics will include:
–Demand Forecast and Demand Side Management –January
21
–Supply/Infrastructure and Potential Case Discussion–February
18
–Distribution Planning, Natural Gas Pricing, SENDOUT®
Preliminary Output Results and Further Case Discussion –
March 30
–SENDOUT® results –April 21
•May 30, 2016 –Draft of IRP document to TAC
•June 30, 2016 –Comments on draft due back to Avista
•July 2016 –TAC final review meeting (if necessary)
•August 31, 2016 –File finalized IRP document
3
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 539 of 648
4 Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 540 of 648
5
Topics
•Overview of analysis approach
•Results for each state
–Market characterization
–Baseline projection
–Conservation potential estimates
5
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 541 of 648
6
Overview of Analysis Approach
Develop energy market
profiles and project the
baseline
Customer surveys (optional)
Secondary data
Forecast assumptions
Prototypes and
energy analysis
Characterize the market
Utility data
Customer surveys (optional)
Secondary data
DSM measure list
Measure description
Avoided costs
Perform measure
screening
Apply customer
participation rates
Recent program results
Best-practices research
Base-year energy
use by fuel &
segment
Base-year
profiles and
baseline projection
by fuel, segment &
end use
Technical and
economic potential
Achievable potential
Input Data Analysis Steps Results
6
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 542 of 648
7
Overview of Analysis Approach
Dimension Segmentation Variable Description
1 State Washington, Idaho, Oregon
2 Sector Residential, commercial, industrial
3 Segment
Residential: single family, multi family, mobile
homes and low income
Commercial: office, restaurant, retail, grocery,
school, college, health, lodging, warehouse,
miscellaneous
Industrial: total
4 Vintage Existing and new construction
5 End uses Heating, water heat, process, etc.
(as appropriate by sector)
6 Appliances/end uses and
technologies
Technologies such as furnaces, boilers, water
heaters, etc.
7 Equipment efficiency levels
for new purchases
Baseline and higher-efficiency options as
appropriate for each technology
7
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 543 of 648
Washington
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 544 of 648
9
High-level Market Characterization -
Washington
2015 Natural Gas
Sales by Sector
Segment Annual Sales
(DTh)% of Sales
Residential 9,188,898 60%
Commercial 5,734,759 38%
Industrial 268,452 2%
Total 30,375 100%
9
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 545 of 648
10
Residential Market Characterization -
Washington
Washington 2015 Sales
(DTh)# of Customers Average Use per
Household (Therms/HH)
Single Family 6,016,941 85,875 701
Multifamily 349,141 7,909 441
Mobile Home 299,264 5,085 589
Low Income 2,523,553 42,372 596
Washington Total 9,188,898 141,241 651
10
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 546 of 648
11
Residential Market Profiles -Washington
Base-year annual energy use by segment and end use
Annual Intensity for Average Household
Data Sources:
•GenPOP Survey
•RBSA
•Utility billing data
•AEG Market Profiles Database
•Secondary data as needed to fill gaps
Annual Use by End Use
11
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 547 of 648
12
Residential Energy Market Profile -
Washington
•This market profile
represents the residential
sector as a whole. Individual
segment market profiles are
provided in the report.
•Saturations were developed
using the GenPOP residential
survey as the primary data
source.
Washington
Total
Total Households:
End Use Technology Saturation UEC Intensity Usage
(Therms)(Therms/(DTh)
Space Heating Furnace 88.2% 509.5 449.1 6,343,260
Space Heating Boiler 2.3% 609.8 13.8 194,390
Space Heating Other Heating 9.6% 488.4 46.8 661,509
Water Heating Water Heater 56.6% 211.0 119.4 1,686,433
Appliances Clothes Dryer 9.9% 27.3 2.7 38,181
Appliances Stove/Oven 8.5% 57.3 4.9 68,899
Miscellaneous Pool Heater 0.7% 217.5 1.6 22,019
Miscellaneous Miscellaneous 100.0% 12.3 12.3 174,206
650.6 9,188,898
141,241
DTh 9,188,898
Total
12
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 548 of 648
13
Residential Baseline Projection -
Washington
•Baseline projection provides foundation for estimating potential future savings from conservation
initiatives and reflects
–Household growth and electricity price forecasts (from Avista)
–Appliance standards in place at end of 2015 (AEG database)
–Frozen efficiency
–Does not include future utility programs
•Baseline projection increases 38% between 2015 and 2036, or an average of 1.5% per year
Residential Baseline Energy Projection (DTh)
13
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 549 of 648
14
Residential Savings Potential -
Washington
From 2017 to 2018, cumulative
achievable potential energy savings
are 62,492 DTh or 0.6% of the
baseline.
By 2036, cumulative savings are
almost 10% of the baseline
projection, or about 0.5% per year.
Uses the UCT cost effectiveness test
2017 2018 2021 2026 2036
Baseline Projection (DTh)10,067,567 10,191,025 10,534,588 11,198,918 12,661,346
Cumulative Savings (DTh)
Achievable Potential 27,598 62,492 207,653 497,074 1,226,734
Economic Potential 132,960 267,157 678,668 1,382,067 2,721,626
Technical Potential 187,192 377,121 956,051 1,951,370 3,828,466
Energy Savings (% of Baseline)
Achievable Potential 0.3%0.6%2.0%4.4%9.7%
Economic Potential 1.3%2.6%6.4%12.3%21.5%
Technical Potential 1.9%3.7%9.1%17.4%30.2%
14
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 550 of 648
15
Residential Savings Potential -
Washington
Cumulative achievable potential in 2018
Cumulative Achievable Potential (DTh)
Cumulative Achievable Potential in 2018
Rank Measure / Technology
2018
Achievable
Savings
(Cum. DTh)
% of Total
1 Windows -High Efficiency 20,516 32.8%
2 Heating –Furnace (EF 0.98)19,873 31.8%
3 Furnace -Maintenance 4,025 6.4%
4 Water Heater -Low-Flow Showerheads 3,270 5.2%
5 Water Heater -Temperature Setback 2,983 4.8%
6 Insulation -Ceiling 2,914 4.7%
7 Ducting -Repair and Sealing 2,243 3.6%
8 Water Heating -Water Heater (EF 0.67)1,831 2.9%
9 Thermostat -Programmable/Interactive 1,797 2.9%
10 Water Heater -Pipe Insulation 1,582 2.5%
11 Heating –Boiler (EF 0.98)527 0.8%
12 Water Heater -Faucet Aerators 484 0.8%
13 Boiler -Maintenance 248 0.4%
14 Boiler -Pipe Insulation 199 0.3%
15 Insulation -Wall Sheathing 1 0.0%
Total 62,492 100%
15
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 551 of 648
16
Commercial Market Characterization -
Washington
Washington 2015 Sales
(DTh)
Floor Space
(sq. ft.)
Intensity
(therms/sqft)
Office 608,320 23,532,683 0.26
Restaurant 357,257 1,615,817 2.21
Retail 609,276 20,141,347 0.30
Grocery 253,760 4,311,977 0.59
School 472,964 11,620,730 0.41
College 439,038 5,467,474 0.80
Health 648,945 9,103,062 0.71
Lodging 353,904 6,773,279 0.52
Warehouse 272,231 13,377,462 0.20
Miscellaneous 1,719,065 32,222,397 0.53
Washington Total 5,734,759 128,166,227 0.45
16
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 552 of 648
17
Commercial Market Profiles -Washington
Base-year annual energy use by segment and end use
Annual Intensity per Square Foot
Data Sources:
•CBSA
•Utility billing data
•AEG Market Profiles Database
•Secondary data as needed to fill gaps
Annual Use by End Use
17
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 553 of 648
18
Commercial Energy Market Profile -
Washington
•This market profile
represents the Commercial
sector as a whole. Individual
segment market profiles are
provided in the report.
•Saturations were developed
using the CBSA survey as the
primary data source.
EUI Intensity Usage
(therm)(therm/Sqft)(DTh)
Heating Furnace 54.3% 0.21 0.11 1,467,831
Heating Boiler 33.1% 0.48 0.16 2,030,710
Heating Unit Heater 4.7% 0.09 0.00 55,570
Water Heating Water Heater 68.7% 0.19 0.13 1,651,292
Food Preparation Oven 25.1% 0.02 0.00 56,768
Food Preparation Fryer 7.5% 0.12 0.01 114,766
Food Preparation Broiler 13.7% 0.04 0.01 67,939
Food Preparation Griddle 16.7% 0.03 0.00 61,216
Food Preparation Range 18.3% 0.03 0.01 69,753
Food Preparation Steamer 2.0% 0.03 0.00 8,759
Food Preparation Commercial Food Prep Other 0.1% 0.01 0.00 69
Miscellaneous Pool Heater 0.9% 0.00 0.00 356
Miscellaneous Other Miscellaneous 100.0% 0.01 0.01 149,731
0.45 5,734,759Total
Gas Market Profiles
End Use Technology Saturation
18
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 554 of 648
19
Commercial Baseline Projection -
Washington
•Baseline projection provides foundation for estimating potential future savings from conservation
initiatives and reflects
–Customer growth (from Avista)
–Building Codes and appliance standards in place at end of 2015 (AEG database)
–Frozen efficiency
–Does not include future utility programs
•Baseline projection increases 23% between 2015 and 2036, or an average of 1% per year
Commercial Baseline Energy Projection (DTh)
19
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 555 of 648
20
Estimating Conservation Potential
•The study analyzed 100 measures covering residential, commercial and industrial
sectors.
•Cost-effectiveness screening to estimate economic potential was done using utility cost
test for Washington and Idaho, and using the TRC for Oregon
•Customer adoption or “ramp rates” are needed to estimate achievable potential. The
study used regional ramp rates to start and then calibrated based on Avista’s program
history
•The study uses AEG’s
LoadMAP model to
estimate potential
Technical Potential
Theoretical upper limit of EE, where all efficiency
measures are phased in regardless of cost
Economic Potential
Also a theoretical upper limit of EE, but includes
only cost-effective measures
Achievable Potential
EE potential that can be realistically achieved by
utilities, accounting for customer adoption rates
and how quickly programs can be implemented
20
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 556 of 648
21
Commercial Savings Potential -
Washington
From 2017 to 2018, cumulative
achievable potential energy savings
are 53,246 DTh or 0.9% of the
baseline.
By 2036, cumulative savings are
over 12% of the baseline
projection, or about 0.7% per year.
Uses the UCT cost effectiveness test
2017 2018 2021 2026 2036
Baseline Projection (DTh)6,220,478 6,236,027 6,305,231 6,490,547 7,066,197
Cumulative Savings (DTh)
Achievable Potential 22,978 53,246 176,816 413,219 878,225
Economic Potential 70,810 140,765 339,275 637,762 1,124,744
Technical Potential 108,572 214,053 512,953 960,878 1,686,375
Energy Savings (% of Baseline)
Achievable Potential 0.4%0.9%2.8%6.4%12.4%
Economic Potential 1.1%2.3%5.4%9.8%15.9%
Technical Potential 1.7%3.4%8.1%14.8%23.9%
21
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 557 of 648
22
Commercial Savings Potential -
Washington
Cumulative achievable potential in 2018
Cumulative Achievable Potential (DTh)
Cumulative Achievable Potential in 2018
Rank Measure / Technology
2018
Achievable
Savings
(Cum. DTh)
% of Total
1 Retrocommissioning 13,476 25.3%
2 Heating –Boiler (EF 0.96)11,887 22.3%
3 Gas Boiler -Hot Water Reset 5,159 9.7%
4 Heating –Furnace (EF 0.96)4,102 7.7%
5 Insulation -Ceiling 3,360 6.3%
6 Water Heating -Water Heater (Tankless)2,826 5.3%
7 Water Heater -Faucet Aerators/Low Flow Nozzles 2,150 4.0%
8 Water Heater -Central Controls 1,979 3.7%
9 Strategic Energy Management 1,784 3.4%
10 Water Heater -Pre-Rinse Spray Valve 1,564 2.9%
11 Gas Boiler -Parallel Positioning Control 1,540 2.9%
12 Food Preparation –Fryer (ENERGY STAR)740 1.4%
13 Steam Trap Maintenance 657 1.2%
14 Food Preparation -Oven (ENERGY STAR)386 0.7%
15 HVAC -Shut Off Damper 304 0.6%
16 Food Preparation -Griddle (ENERGY STAR)235 0.4%
17 Windows -High Efficiency 223 0.4%
18 Water Heater -Pipe Insulation 204 0.4%
19 Food Preparation -Steamer (ENERGY STAR)184 0.3%
20 Heating -Unit Heater (Condensing)171 0.3%
Total 52,933 99.4%Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 558 of 648
23
Industrial Energy Market Profile -
Washington
•This market profile
represents the Industrial
sector as a whole. The
industrial sector is not large
enough to warrant further
segmentation.
EUI Intensity Usage
(Therms)(Therms/sqft)(Dth)
Space Heating Furnace 56.5%0.028 0.02 5,563
Space Heating Boiler 34.4%0.089 0.03 10,891
Space Heating Other Heating 4.9%0.014 0.00 239
Process Process Heating 100.0% 0.369 0.37 131,596
Process Process Boiler 100.0% 0.282 0.28 100,538
Process Process Cooling 100.0% 0.001 0.00 407
Process Other Process 100.0% 0.004 0.00 1,580
Other Other Uses 100.0% 0.049 0.05 17,638
0.75 268,452
Washington
Industrial
Total Sq Ft:3,567,948
DTh 268,452
Total
End Use Technology Saturation
23
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 559 of 648
24
Industrial Baseline Projection -
Washington
•Baseline projection provides foundation for estimating potential future savings from conservation
initiatives and reflects
–Customer growth (from Avista)
–Building Codes and appliance standards in place at end of 2015 (AEG database)
–Frozen efficiency
–Does not include future utility programs
•Baseline projection increases 35% between 2015 and 2036, or an average of 1.4% per year
Industrial Baseline Energy Projection (DTh)
24
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 560 of 648
25
Industrial Savings Potential -Washington
From 2017 to 2018, cumulative
achievable potential energy savings
are 777 DTh or 0.3% of the baseline.
By 2036, cumulative savings are
2.3% of the baseline projection, or
about 0.1% per year.
Uses the UCT cost effectiveness test
2017 2018 2021 2026 2036
Baseline Projection (DTh)283,824 287,571 298,345 318,546 363,144
Cumulative Savings (DTh)
Achievable Potential 383 777 1,993 4,050 8,414
Economic Potential 876 1,757 4,413 8,941 18,457
Technical Potential 3,195 6,425 16,314 33,603 71,042
Energy Savings (% of Baseline)
Achievable Potential 0.1%0.3%0.7%1.3%2.3%
Economic Potential 0.3%0.6%1.5%2.8%5.1%
Technical Potential 1.1%2.2%5.5%10.5%19.6%
25
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 561 of 648
26
Industrial Savings Potential -Washington
Cumulative achievable potential in 2018
Cumulative Achievable Potential (DTh)
Cumulative Achievable Potential in 2018
Rank Measure / Technology
2018
Achievable
Savings
(Cum. DTh)
% of Total
1 Custom 415 53.5%
2 Boiler -Hot Water Reset 205 26.4%
3 Boiler -Parallel Positioning Control 97 12.5%
4 Boiler -Maintenance 46 5.9%
5 Steam Trap Maintenance 11 1.5%
6 Gas Furnace -Maintenance 2 0.3%
Total 777 100.0%
26
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 562 of 648
Idaho
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 563 of 648
28
High-level Market Characterization -
Idaho
2015 Natural Gas
Sales by Sector
Segment Annual Sales
(DTh)% of Sales
Residential 4,304,740 62%
Commercial 2,456,621 35%
Industrial 187,203 3%
Total 6,948,564 100%
28
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 564 of 648
29
Residential Market Characterization -
Idaho
Idaho 2015 Sales
(DTh)# of Customers Average Use per
Household (Therms/HH)
Single Family 2,814,373 42,852 657
Multifamily 142,894 3,454 414
Mobile Home 174,973 3,172 552
Low Income 1,172,501 21,003 558
Idaho Total 4,304,740 70,481 611
29
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 565 of 648
30
Residential Market Profiles -Idaho
Base-year annual energy use by segment and end use
Annual Intensity for Average Household
Data Sources:
•GenPOP Survey
•RBSA
•Utility billing data
•AEG Market Profiles Database
•Secondary data as needed to fill gaps
Annual Use by End Use
30
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 566 of 648
31
Residential Energy Market Profile -Idaho
•This market profile
represents the residential
sector as a whole. Individual
segment market profiles are
provided in the report.
•Saturations were developed
using the GenPOP residential
survey as the primary data
source.
Idaho
Total
Total Households:
End Use Technology Saturation UEC Intensity Usage
(Therms)(Therms/(DTh)
Space Heating Furnace 84.2% 484.5 407.8 2,873,917
Space Heating Boiler 2.0% 579.2 11.8 83,322
Space Heating Other Heating 13.8% 466.4 64.4 453,852
Water Heating Water Heater 54.3% 200.8 109.1 768,890
Appliances Clothes Dryer 9.2% 29.0 2.7 18,876
Appliances Stove/Oven 9.2% 60.1 5.5 39,043
Miscellaneous Pool Heater 0.3% 217.4 0.6 4,134
Miscellaneous Miscellaneous 100.0% 8.9 8.9 62,706
610.8 4,304,740
70,481
DTh 4,304,740
Total
31
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 567 of 648
32
Residential Baseline Projection -Idaho
•Baseline projection provides foundation for estimating potential future savings from conservation
initiatives and reflects
–Household growth and electricity price forecasts (from Avista)
–Appliance standards in place at end of 2015 (AEG database)
–Frozen efficiency
–Does not include future utility programs
•Baseline projection increases 44% between 2015 and 2036, or an average of 1.7% per year
Residential Baseline Energy Projection (DTh)
32
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 568 of 648
33
Residential Savings Potential -Idaho
From 2017 to 2018, cumulative
achievable potential energy savings
are 62,492 DTh or 0.6% of the
baseline.
By 2036, cumulative savings are
almost 10% of the baseline
projection, or about 0.5% per year.
Uses the UCT cost effectiveness test
2017 2018 2021 2026 2036
Baseline Projection (DTh)4,741,736 4,802,813 4,992,555 5,366,588 6,213,091
Cumulative Savings (DTh)
Achievable Potential 11,138 25,406 85,812 208,875 536,817
Economic Potential 53,686 108,042 276,801 577,890 1,198,833
Technical Potential 82,162 165,579 422,556 873,781 1,776,196
Energy Savings (% of Baseline)
Achievable Potential 0.2%0.5%1.7%3.9%8.6%
Economic Potential 1.1%2.2%5.5%10.8%19.3%
Technical Potential 1.7%3.4%8.5%16.3%28.6%
33
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 569 of 648
34
Residential Savings Potential -Idaho
Cumulative achievable potential in 2018
Cumulative Achievable Potential (DTh)
Cumulative Achievable Potential in 2018
Rank Measure / Technology
2018
Achievable
Savings
(Cum. DTh)
% of Total
1 Windows -High Efficiency 9,778 38.5%
2 Heating –Furnace (EF 0.98)6,692 26.3%
3 Furnace -Maintenance 1,821 7.2%
4 Water Heater -Low-Flow Showerheads 1,480 5.8%
5 Insulation -Ceiling 1,379 5.4%
6 Water Heater -Temperature Setback 1,365 5.4%
7 Thermostat -Programmable/Interactive 861 3.4%
8 Water Heater -Pipe Insulation 725 2.9%
9 Water Heating -Water Heater (EF 0.67)660 2.6%
10 Heating –Boiler (EF 0.98)235 0.9%
11 Water Heater -Faucet Aerators 219 0.9%
12 Boiler -Maintenance 106 0.4%
13 Boiler -Pipe Insulation 86 0.3%
Total 25,406 100%
34
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 570 of 648
35
Commercial Market Characterization -
Idaho
Idaho 2015 Sales
(DTh)
Floor Space
(sq. ft.)
Intensity
(therms/sqft)
Office 214,228 8,388,655 0.26
Restaurant 55,373 253,503 2.18
Retail 314,742 10,531,910 0.30
Grocery 97,810 1,682,340 0.58
School 387,333 9,633,126 0.40
College 360,160 4,540,014 0.79
Health 222,359 3,157,269 0.70
Lodging 135,614 2,627,216 0.52
Warehouse 110,269 5,484,890 0.20
Miscellaneous 558,735 10,601,048 0.53
Idaho Total 2,456,621 56,899,971 0.43
35
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 571 of 648
36
Commercial Market Profiles -Idaho
Base-year annual energy use by segment and end use
Annual Intensity per Square Foot
Data Sources:
•CBSA
•Utility billing data
•AEG Market Profiles Database
•Secondary data as needed to fill gaps
Annual Use by End Use
36
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 572 of 648
37
Commercial Energy Market Profile -
Idaho
•This market profile
represents the Commercial
sector as a whole. Individual
segment market profiles are
provided in the report.
•Saturations were developed
using the CBSA survey as the
primary data source.
EUI Intensity Usage
(therm)(therm/Sqft)(DTh)
Heating Furnace 51.2% 0.20 0.10 588,380
Heating Boiler 36.0% 0.45 0.16 930,819
Heating Unit Heater 4.9% 0.09 0.00 25,385
Water Heating Water Heater 69.3% 0.19 0.13 734,648
Food Preparation Oven 24.5% 0.02 0.00 27,505
Food Preparation Fryer 7.7% 0.09 0.01 40,765
Food Preparation Broiler 14.0% 0.03 0.00 22,933
Food Preparation Griddle 16.3% 0.02 0.00 20,023
Food Preparation Range 18.3% 0.02 0.00 23,972
Food Preparation Steamer 3.0% 0.02 0.00 4,249
Food Preparation Commercial Food Prep Other 0.1% 0.00 0.00 29
Miscellaneous Pool Heater 0.8% 0.00 0.00 119
Miscellaneous Other Miscellaneous 100.0% 0.01 0.01 37,793
0.43 2,456,621
Gas Market Profiles
End Use Technology Saturation
Total
37
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 573 of 648
38
Commercial Baseline Projection -Idaho
•Baseline projection provides foundation for estimating potential future savings from conservation
initiatives and reflects
–Customer growth (from Avista)
–Building Codes and appliance standards in place at end of 2015 (AEG database)
–Frozen efficiency
–Does not include future utility programs
•Baseline projection increases 23% between 2015 and 2036, or an average of 1% per year
Commercial Baseline Energy Projection (DTh)
38
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 574 of 648
39
Commercial Savings Potential -Idaho
From 2017 to 2018, cumulative
achievable potential energy savings
are 21,619 DTh or 0.8% of the
baseline.
By 2036, cumulative savings are
almost 12% of the baseline
projection, or about 0.6% per year.
Uses the UCT cost effectiveness test
2017 2018 2021 2026 2036
Baseline Projection (DTh)2,656,853 2,664,007 2,695,763 2,776,753 3,021,253
Cumulative Savings (DTh)
Achievable Potential 9,311 21,619 72,680 170,883 359,503
Economic Potential 29,135 58,035 140,114 263,474 459,135
Technical Potential 47,785 94,237 226,002 423,332 744,715
Energy Savings (% of Baseline)
Achievable Potential 0.4%0.8%2.7%6.2%11.9%
Economic Potential 1.1%2.2%5.2%9.5%15.2%
Technical Potential 1.8%3.5%8.4%15.2%24.6%
39
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 575 of 648
40
Commercial Savings Potential -Idaho
Cumulative achievable potential in 2018
Cumulative Achievable Potential (DTh)
Cumulative Achievable Potential in 2018
Rank Measure / Technology
2018
Achievable
Savings
(Cum. DTh)
% of Total
1 Retrocommissioning 5,761 26.6%
2 Heating –Boiler (EF 0.96)4,812 22.3%
3 Gas Boiler -Hot Water Reset 2,364 10.9%
4 Heating –Furnace (EF 0.96)1,919 8.9%
5 Water Heating -Water Heater (Tankless)1,343 6.2%
6 Insulation -Ceiling 1,105 5.1%
7 Water Heater -Faucet Aerators/Low Flow Nozzles 955 4.4%
8 Water Heater -Central Controls 892 4.1%
9 Water Heater -Pre-Rinse Spray Valve 631 2.9%
10 Gas Boiler -Parallel Positioning Control 598 2.8%
11 Steam Trap Maintenance 294 1.4%
12 Food Preparation –Fryer (ENERGY STAR)264 1.2%
13 Food Preparation –Oven (ENERGY STAR)188 0.9%
14 Water Heater -Pipe Insulation 91 0.4%
15 Food Preparation -Steamer (ENERGY STAR)90 0.4%
16 Food Preparation -Griddle (ENERGY STAR)77 0.4%
17 Windows -High Efficiency 77 0.4%
18 Food Preparation -Broiler (ENERGY STAR)55 0.3%
19 Heating -Unit Heater (Condensing)47 0.2%
20 HVAC -Duct Repair and Sealing 27 0.1%
Total 21,592 99.9%
40
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 576 of 648
41
Industrial Energy Market Profile -Idaho
•This market profile
represents the Industrial
sector as a whole. The
industrial sector is not large
enough to warrant further
segmentation.EUI Intensity Usage
(Therms)(Therms/sqft)(Dth)
Space Heating Furnace 56.5% 0.026 0.01 3,879
Space Heating Boiler 34.4% 0.085 0.03 7,595
Space Heating Other Heating 4.9% 0.013 0.00 167
Process Process Heating 100.0% 0.353 0.35 91,768
Process Process Boiler 100.0% 0.270 0.27 70,109
Process Process Cooling 100.0% 0.001 0.00 284
Process Other Process 100.0% 0.004 0.00 1,102
Other Other Uses 100.0% 0.047 0.05 12,299
0.72 187,203
Idaho
Industrial
Total Sq Ft:2,596,257
DTh 187,203
Total
End Use Technology Saturation
41
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 577 of 648
42
Industrial Baseline Projection -Idaho
•Baseline projection provides foundation for estimating potential future savings from conservation
initiatives and reflects
–Customer growth (from Avista)
–Building Codes and appliance standards in place at end of 2015 (AEG database)
–Frozen efficiency
–Does not include future utility programs
•Baseline projection increases 70% between 2015 and 2036, or an average of 2.5% per year
Industrial Baseline Energy Projection (DTh)
42
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 578 of 648
43
Industrial Savings Potential -Idaho
From 2017 to 2018, cumulative
achievable potential energy savings
are 641 DTh or 0.3% of the
baseline.
By 2036, cumulative savings are
4.3% of the baseline projection, or
about 0.1% per year.
Uses the UCT cost effectiveness test
2017 2018 2021 2026 2036
Baseline Projection (DTh)211,629 216,490 229,739 256,083 318,182
Cumulative Savings (DTh)
Achievable Potential 306 641 1,809 4,411 13,717
Economic Potential 700 1,450 4,005 9,723 29,846
Technical Potential 2,446 5,049 13,661 31,578 81,807
Energy Savings (% of Baseline)
Achievable Potential 0.1%0.3%0.8%1.7%4.3%
Economic Potential 0.3%0.7%1.7%3.8%9.4%
Technical Potential 1.2%2.3%5.9%12.3%25.7%
43
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 579 of 648
44
Industrial Savings Potential-Idaho
Cumulative achievable potential in 2018
Cumulative Achievable Potential (DTh)
Cumulative Achievable Potential in 2018
Rank Measure / Technology
2018
Achievable
Savings
(Cum. DTh)
% of Total
1 Custom 338 52.7%
2 Boiler -Hot Water Reset 171 26.7%
3 Boiler -Parallel Positioning Control 81 12.7%
4 Boiler -Maintenance 39 6.0%
5 Steam Trap Maintenance 10 1.5%
6 Gas Furnace -Maintenance 2 0.3%
Total 641 100.0%
44
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 580 of 648
Oregon
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 581 of 648
46
High-level Market Characterization -
Oregon
2015 Natural Gas
Sales by Sector
Segment Annual Sales
(DTh)% of Sales
Residential 4,303,206 61%
Commercial 2,699,252 38%
Industrial 51,369 1%
Total 7,053,827 100%
46
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 582 of 648
47
Residential Market Characterization -
Oregon
Oregon 2015 Sales
(DTh)# of Customers Average Use per
Household (Therms/HH)
Single Family 2,811,856 53,617 524
Multifamily 81,940 2,480 330
Mobile Home 271,183 6,156 441
Low Income 1,138,226 25,534 446
Oregon Total 4,303,206 87,787 490
47
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 583 of 648
48
Residential Market Profiles -Oregon
Base-year annual energy use by segment and end use
Annual Intensity for Average Household
Data Sources:
•RBSA
•Utility billing data
•AEG Market Profiles Database
•Secondary data as needed to fill gaps
Annual Use by End Use
48
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 584 of 648
49
Residential Energy Market Profile -
Oregon
•This market profile
represents the residential
sector as a whole. Individual
segment market profiles are
provided in the report.
•Saturations were developed
using the RBSA survey as the
primary data source.
49
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 585 of 648
50
Residential Baseline Projection -Oregon
•Baseline projection provides foundation for estimating potential future savings from conservation
initiatives and reflects
–Household growth and electricity price forecasts (from Avista)
–Appliance standards in place at end of 2015 (AEG database)
–Frozen efficiency
–Does not include future utility programs
•Baseline projection increases 30% between 2015 and 2036, or an average of 1.2% per year
Residential Baseline Energy Projection (DTh)
50
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 586 of 648
51
Residential Savings Potential -Oregon
From 2017 to 2018, cumulative
achievable potential energy savings
are 13,839 DTh or 0.3% of the
baseline.
By 2036, cumulative savings are
almost 5% of the baseline
projection, or about 0.2% per year.
Uses the TRC cost effectiveness test
2017 2018 2021 2026 2036
Baseline Projection (DTh)4,808,069 4,852,168 4,931,394 5,137,402 5,588,507
Cumulative Savings (DTh)
Achievable Potential 6,507 13,839 38,671 94,086 260,939
Economic Potential 21,867 44,161 111,658 228,569 483,538
Technical Potential 83,073 167,062 418,531 844,811 1,615,605
Energy Savings (% of Baseline)
Achievable Potential 0.1%0.3%0.8%1.8%4.7%
Economic Potential 0.5%0.9%2.3%4.4%8.7%
Technical Potential 1.7%3.4%8.5%16.4%28.9%
51
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 587 of 648
52
Residential Savings Potential -Oregon
Cumulative achievable potential in 2018
Cumulative Achievable Potential (DTh)
Cumulative Achievable Potential in 2018
Rank Measure / Technology
2018
Achievable
Savings
(Cum. DTh)
% of Total
1 Heating -Furnace 7,400 53.5%
2 Water Heater -Low-Flow Showerheads 1,743 12.6%
3 Water Heater -Temperature Setback 1,640 11.9%
4 Furnace -Maintenance 1,477 10.7%
5 Water Heater -Pipe Insulation 871 6.3%
6 Water Heater -Faucet Aerators 257 1.9%
7 Windows -High Efficiency 235 1.7%
8 Boiler -Maintenance 108 0.8%
9 Boiler -Pipe Insulation 86 0.6%
10 Heating –Boiler (EF 0.98)22 0.2%
Total 13,839 100%
52
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 588 of 648
53
Commercial Market Characterization -
Oregon
Oregon 2015 Sales
(DTh)
Floor Space
(sq. ft.)
Intensity
(therms/sqft)
Office 406,757 8,388,655 0.16
Restaurant 302,349 253,503 1.39
Retail 401,181 10,531,910 0.19
Grocery 173,578 1,682,340 0.37
School 273,450 9,633,126 0.26
College 34,880 4,540,014 0.50
Health 401,052 3,157,269 0.45
Lodging 174,610 2,627,216 0.33
Warehouse 143,426 5,484,890 0.13
Miscellaneous 387,969 10,601,048 0.34
Oregon Total 2,699,252 56,899,971 0.27
53
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 589 of 648
54
Commercial Market Profiles -Oregon
Base-year annual energy use by segment and end use
Annual Intensity per Square Foot
Data Sources:
•CBSA
•Utility billing data
•AEG Market Profiles Database
•Secondary data as needed to fill gaps
Annual Use by End Use
54
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 590 of 648
55
Commercial Energy Market Profile -
Oregon
•This market profile
represents the Commercial
sector as a whole. Individual
segment market profiles are
provided in the report.
•Saturations were developed
using the CBSA survey as the
primary data source.
55
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 591 of 648
56
Commercial Baseline Projection -
Oregon
•Baseline projection provides foundation for estimating potential future savings from conservation
initiatives and reflects
–Customer growth (from Avista)
–Building Codes and appliance standards in place at end of 2015 (AEG database)
–Frozen efficiency
–Does not include future utility programs
•Baseline projection increases 38% between 2015 and 2036, or an average of 1.5% per year
Commercial Baseline Energy Projection (DTh)
56
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 592 of 648
57
Commercial Savings Potential -Oregon
From 2017 to 2018, cumulative
achievable potential energy savings
are 17,527 DTh or 0.5% of the
baseline.
By 2036, cumulative savings are
almost 10% of the baseline
projection, or about 0.5% per year.
Uses the TRC cost effectiveness test
2017 2018 2021 2026 2036
Baseline Projection (DTh)3,215,033 3,219,537 3,264,933 3,383,711 3,729,054
Cumulative Savings (DTh)
Achievable Potential 7,921 17,527 54,701 142,594 363,123
Economic Potential 22,299 44,184 110,800 228,191 470,854
Technical Potential 56,697 109,388 262,836 500,789 919,302
Energy Savings (% of Baseline)
Achievable Potential 0.2%0.5%1.7%4.2%9.7%
Economic Potential 0.7%1.4%3.4%6.7%12.6%
Technical Potential 1.8%3.4%8.1%14.8%24.7%
57
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 593 of 648
58
Commercial Savings Potential -Oregon
Cumulative achievable potential in 2018
Cumulative Achievable Potential (DTh)
Cumulative Achievable Potential in 2018
Rank Measure / Technology
2018
Achievable
Savings
(Cum. DTh)
% of Total
1 Retrocommissioning 5,781 33.0%
2 Gas Boiler -Hot Water Reset 1,954 11.2%
3 Water Heater -Central Controls 1,711 9.8%
4 Heating -Boiler 1,700 9.7%
5 Water Heating -Water Heater 1,316 7.5%
6 Commissioning 1,162 6.6%
7 Water Heater -Faucet Aerators/Low Flow
Nozzles 1,098 6.3%
8 Water Heater -Pre-Rinse Spray Valve 1,009 5.8%
9 Food Preparation -Fryer 519 3.0%
10 Steam Trap Maintenance 384 2.2%
11 Food Preparation -Oven 215 1.2%
12 Food Preparation -Griddle 160 0.9%
13 Windows -High Efficiency 144 0.8%
14 Food Preparation -Steamer 115 0.7%
15 Water Heater -Pipe Insulation 106 0.6%
16 Water Heater -Drainwater Heat Recovery 68 0.4%
17 HVAC -Duct Repair and Sealing 46 0.3%
18 Food Preparation -Broiler 37 0.2%
19 Gas Boiler -Parallel Positioning Control 2 0.0%
20 Food Preparation -Range 0 0.0%
Total 17,527 100.0%
58
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 594 of 648
59
Industrial Energy Market Profile -Oregon
•This market profile
represents the Industrial
sector as a whole. The
industrial sector is not large
enough to warrant further
segmentation.
EUI Intensity Usage
(Therms)(Therms/sqft)(Dth)
Space Heating Furnace 56.5% 0.025 0.01 1,064
Space Heating Boiler 34.4% 0.081 0.03 2,084
Space Heating Other Heating 4.9% 0.013 0.00 46
Process Process Heating 100.0% 0.338 0.34 25,181
Process Process Boiler 100.0% 0.258 0.26 19,238
Process Process Cooling 100.0% 0.001 0.00 78
Process Other Process 100.0% 0.004 0.00 302
Other Other Uses 100.0% 0.045 0.05 3,375
0.69 51,369
Oregon
Industrial
51,369
Total Sq Ft:744,804
DTh
End Use Technology Saturation
Total
59
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 595 of 648
60
Industrial Baseline Projection -Oregon
•Baseline projection provides foundation for estimating potential future savings from conservation
initiatives and reflects
–Customer growth (from Avista)
–Building Codes and appliance standards in place at end of 2015 (AEG database)
–Frozen efficiency
–Does not include future utility programs
•Baseline projection increases 31% between 2015 and 2036, or an average of 1.4% per year
Industrial Baseline Energy Projection (DTh)
60
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 596 of 648
61
Industrial Savings Potential -Oregon
From 2017 to 2018, cumulative
achievable potential energy savings
are 641 DTh or 0.3% of the
baseline.
By 2036, cumulative savings are
4.3% of the baseline projection, or
about 0.1% per year.
Uses the TRC cost effectiveness test
2017 2018 2021 2026 2036
Baseline Projection (DTh)51,346 52,041 54,200 58,303 67,465
Cumulative Savings (DTh)
Achievable Potential 73 147 379 773 1,622
Economic Potential 166 333 839 1,707 3,557
Technical Potential 602 1,209 3,078 6,371 13,602
Energy Savings (% of Baseline)
Achievable Potential 0.0%0.1%0.2%0.3%0.5%
Economic Potential 0.1%0.2%0.4%0.7%1.1%
Technical Potential 0.3%0.6%1.3%2.5%4.3%
61
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 597 of 648
62
Industrial Savings Potential-Oregon
Cumulative achievable potential in 2018
Cumulative Achievable Potential (DTh)
Cumulative Achievable Potential in 2018
Rank Measure / Technology
2018
Achievable
Savings
(Cum. DTh)
% of Total
1 Custom 338 52.7%
2 Boiler -Hot Water Reset 171 26.7%
3 Boiler -Parallel Positioning Control 81 12.7%
4 Boiler -Maintenance 39 6.0%
5 Steam Trap Maintenance 10 1.5%
6 Gas Furnace -Maintenance 2 0.3%
Total 641 100.0%
62
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 598 of 648
Ingrid Rohmund
[e-mail]
Bridget Kester
[e-mail]
Fuong Nguyen
[e-mail]
Joe Reilly
[e-mail]
Thank You!
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 599 of 648
64
Assumptions Review
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 600 of 648
6565
1.Customer annual growth rates:
2.Use per customer coefficients –3 year average use per HDD per customer
3.Weather planning standard –coldest day on record
WA/ID 82; Medford 61; Roseburg 55; Klamath 72; La Grande 74
Developing a Reference Case
Customer
count
forecast
Use per
customer
coefficients
Weather Reference
Case Demand
65
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 601 of 648
6666
WA-ID Region Firm Customers: 2016 IRP and 2014 IRP
210,000
220,000
230,000
240,000
250,000
260,000
270,000
280,000
290,000
300,000
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
WA-ID-Base 2014 WA-ID-Base
+5,500
IRP Avg.Annual Growth
2016-2035
2014 1.0%
2016 1.1%
66
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 602 of 648
6767
OR Region Firm Customers: 2016 IRP and 2014 IRP
80,000
85,000
90,000
95,000
100,000
105,000
110,000
115,000
120,000
125,000
130,000
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
OR-Base 2014 OR-Base
IRP Avg.Annual Growth
2016-2035
2014 0.9%
2016 1.2%
+7,000
67
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 603 of 648
6868
System Firm Customers: 2016 IRP and 2014 IRP
300,000
320,000
340,000
360,000
380,000
400,000
420,000
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
WA-ID-OR-Base 2014 WA-ID-OR-Base
+12,500
IRP Avg.Annual Growth
2016-2035
2014 1.0%
2016 1.1%
68
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 604 of 648
69
2016 IRP
Low –Med –High
REAL
69
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 605 of 648
70
Price Elasticity: What does the research
show?
70
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 606 of 648
7171
Price Elasticity Proposed Assumptions
•The data is a mixed bag at best:
•8 of 9 super regions have statistically significant short
and long run elasticity's.
•At a state level only 10 of 50 show statistical
significant elasticity's.
•In some cases, the estimated elasticity's are positive.
–We incorporated a -.15 price elastic response for our
expected elasticity assumption.
71
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 607 of 648
7272
Carbon Adder –Expected
•Includes carbon pricing from 2026-2035 from our
consultant
•Avista added pricing starting from 2018 to address
incremental adders from legislation in our service
territory jurisdictions.
–We assume floor pricing the same as California’s cap and trade
of $10 back at the programs initial auction in 2013.
72
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 608 of 648
73
Coldest on Record Dates
WA/ID –December 30, 1968
Medford –December 9, 1972
Roseburg –December 22, 1990
Klamath Falls –December 21,1990
LaGrande –December 23,1983
Area Coldest in 20 Year
HDD
Coldest on Record
HDD
WA-ID 76 82
Klamath Falls 72 72
La Grande 74 74
Medford 54 61
Roseburg 48 55
73
Planning Standard Assumptions
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 609 of 648
74
Demand Sensitivities & Scenarios
Update
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 610 of 648
75
Demand and
Supply Side
Sensitivities
Optimize
Resource
Portfolio
Stochastic
Cost/Risk Analysis
Prices and
Weather
Highest
Performing
Portfolios
selection
Preferred
Portfolio
selection
Core Cases Price Forecast
Sensitivities, Scenarios, Portfolios
75
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 611 of 648
76
Sensitivity Analysis
76
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 612 of 648
7777 Demand Sensitivity Analysis –DIRECT
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 613 of 648
787878 Demand Sensitivity Analysis –DIRECT
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 614 of 648
7979 Demand Sensitivity Analysis –DIRECT79
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 615 of 648
808080 Demand Sensitivity Analysis –DIRECT
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 616 of 648
818181 Demand Sensitivity Analysis –DIRECT
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 617 of 648
828282 Demand Sensitivity Analysis –DIRECT
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 618 of 648
8383 Demand Sensitivity Analysis –INDIRECT
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 619 of 648
8484 Demand Sensitivity Analysis –INDIRECT
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 620 of 648
8585
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 621 of 648
86
Scenario Analysis
86
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 622 of 648
87
Proposed Scenarios
87
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 623 of 648
8888
Existing Resources vs. Peak Day Demand
88
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 624 of 648
8989
Existing Resources vs. Peak Day Demand
Expected Case –Medford/Roseburg (DRAFT)
89
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 625 of 648
9090
Existing Resources vs. Peak Day Demand
Expected Case –Klamath Falls (DRAFT)
90
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 626 of 648
9191
Existing Resources vs. Peak Day Demand
Expected Case –La Grande (DRAFT)
91
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 627 of 648
9292
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 628 of 648
9393
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 629 of 648
9494
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 630 of 648
95
Resource Options for Meeting
Unserved Demand
95
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 631 of 648
9696
Potential New Supply Resources
Considerations
•Availability
–By Region –which region(s) can the resource be utilized?
–Lead time considerations –when will it be available?
•Type of Resource
–Peak vs. Base load
–Firm or Non-Firm
–“Lumpiness”
•Usefulness
–Does it get the gas where we need it to be?
–Last mile issues
•Cost
96
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 632 of 648
9797
Supply Resources Available
Additional Resource Size Cost/Rates Availability Notes
Capacity Release Recall 27,000 Dth NWPL Rate 2018 Recall of previously released capacity
Unsubscribed GTN Capacity Up to 50,000 Dth GTN Rate plus
Upstream TCPL
Now Currently available unsubscribed capacity from
Kingsgate to Stanfield or Malin plus associated
Alberta transport
NWP Expansion Up to 50,000 Dth $0.74 / Dth 2018 Expansion from Sumas to JP
Citygate Deliveries Variable Varies Now Represents the ability to buy a delivered
product from another utility or marketer.
Limited counterparties
Satellite LNG 90,000 Dth
w/30,000 Dth
deliverability
$7 Million capital
cost plus $375K
O&M
2018 Provides for peaking services and alleviates
the need for costly pipeline expansions.
97
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 633 of 648
9898
Supply Resources Available
Additional Resource Size Cost/Rates Availability Notes
Medford Lateral Exp 50,000 Dth $10M / GTN Rate 2018 Additional compression to facilitate more gas
to flow from mainline GTN to Medford.
Malin Backhauls 50,000 GTN Rate Now Currently available
98
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 634 of 648
9999
Future Supply Resources
Other Resources Considered
Additional Resource Size Cost/Rates Availability Notes
Co. Owned LNG 600,000 Dth w/
150,000 of
deliverability
$75 Million plus
$2 Million annual
O&M
2022 On site, in service territory liquefaction and
vaporization facility
Various pipelines –Pacific
Connector, Cross-Cascades,
etc.
Varies Precedent
Agreement Rates
2020 Requires additional mainline capacity on
NWPL or GTN to get to service territory
Large Scale LNG Varies Commodity less Fuel 2020 Speculative, needs pipeline transport
In Ground Storage Varies Varies Varies Requires additional mainline transport to
get to service territory
99
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 635 of 648
100100
DSM Avoided Cost
•Avoided cost determined by comparison to the marginal supply side
resources to meet incremental demand, primarily commodity costs.
•Preliminary avoided costs were provided to AEG for cost
effectiveness testing and development of the DSM acquirable
potential.
•Potential is then input into SENDOUT® and avoided costs are re-
evaluated.
100
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 636 of 648
101101
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 637 of 648
102
Stochastic Analysis
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 638 of 648
103103
What is it?
•Stochastic vs. Deterministic
•Facilitates a statistical approach to analysis
•Reiterative runs of SENDOUT (e.g. 200 “Draws”)
•Utilizes statistically generated price curves and weather
patterns derived from historical data
•Develops a distribution of the “draws” results
–Normal (Weather) and lognormal (Index) distribution
103
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 639 of 648
104104
Analytical Objectives
•Weather
–Validate reasonableness of our weather planning standard
–Compare demand and unserved results
–Quantify potential alternate weather planning standards via comparison
of alternate aggregate NPV portfolio costs
•Price
–Substantiate preferred portfolio selection (commodity cost perspective)
–Compare distribution of aggregate NPV cost to preferred portfolio
104
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 640 of 648
105105
Avistsa IRP Total 20 Year Cost
0
5
10
15
20
25
30
35
40
45
$9.2
8
$9.3
4
$9.4
0
$9.4
6
$9.5
1
$9.5
7
$9.6
3
$9.6
8
$9.7
4
$9.8
0
$9.8
5
$9.9
1
$9.9
7
$10.
0
2
$10.
0
8
$10.
1
4
$10.
1
9
$10.
2
5
$10.
3
1
$10.
3
7
$10.
4
2
$10.
4
8
$ Billions
Fr
e
q
u
e
n
c
y
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Cu
m
u
l
a
t
i
v
e
Frequency
Cumulative
Mean 90th Percentile 95th
Percentile
5%
P(Cost>10.127)=5%
10%
P(Cost>10.067)=10%
Average: 9.854
StdDev: 0.169
Min: 9.285
90% percentile: 10.067
95% percentile: 10.127
Max: 10.422
VectorGas™ Reports
EXAMPLE ONLY
105
Avista 20 Year Total Cost
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 641 of 648
106106
Sample Weather Pattern
Medford HDDs -Four example draws
Medford Monte Carlo HDD Results
0
10
20
30
40
50
60
70
Nov-
0
9
Jan-
1
0
Mar-1
0
May-
1
0
Jul-1
0
Sep-
1
0
Nov-
1
0
Jan-
1
1
Mar-1
1
May-
1
1
Jul-1
1
Sep-
1
1
Nov-
1
1
Jan-
1
2
Mar-1
2
Da
i
l
y

H
D
D
Draw 4 Draw 12 Draw 46 Draw 148
106
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 642 of 648
107
Key Issues / Document Discussion
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 643 of 648
108108
Highlights of the 2016 IRP
•No near-term resource needs under most
scenarios.
•Higher long term customer growth rates.
•Updated DSM potential and resultant avoided
costs.
•Lower prices.
108
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 644 of 648
109109
2014 IRP Acknowledgement Comments
•Include a section that discusses the ongoing management of Avista’s surplus
capacity
•Provide more detail on the distribution model results and analysis that identify specific
distribution system needs
•Provide the resource portfolio solution that fills any demand not served for each
scenario
•Ensure that the entity performing the Conservation Potential Assessment (CPA)
evaluates the effect of the temporary operation under a Utility Cost Test (UCT) cost-
effectiveness metric on near-term, achievable conservation potential, while
maintaining the longer-term assumption that Avista will eventually be reverting back
to a TRC test cost-effectiveness metric.
•Evaluation of state-specific resource needs when a resource deficiency is identified
•The appropriateness of using a 1 in 572 event for peak day planning
•The need for stress-testing the Company’s storage resources during a peak event in
a high-demand year
109
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 645 of 648
110110
2014 IRP Acknowledgement Comments
•As part of its next IRP process, Avista must convene workshops with Staff and
stakeholders to explore how best to model major resource acquisitions and major
capital investments.
•For the next IRP, Avista must work with Staff and stakeholders to resolve forecasting
methodology concerns, and seek to identify the most reliable methodology so that
future resource needs may be clearly identified.
•In its next IRP, Avista must include a clear presentation of how Avista decides which
distribution system projects to include in the IRP, and a clear description of the
included projects, along with a justification for recommending or proceeding with the
projects.
•As part of its next IRP process, Avista must convene discussions with Staff and
stakeholders to discuss potential impacts associated with: (1) new regulations to
reduce methane emissions; and (2) potential increases in natural gas prices
stemming from increased demand for natural gas for generation under Section 111 (
d) of the Clean Air Act.
110
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 646 of 648
111111
Key Questions
•Low Demand?
–What are the impacts on consumption? Temporary or permanent change?
•Low Prices
–Cheap gas for 20 years?
•Environmental Impacts
–Carbon Tax?
–Hydraulic Fracturing Bans?
•Market
–Increasing production?
–Increasing drilling efficiency?
–Increasing demand from power?
111
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 647 of 648
112112
2016 IRP Timeline
•August 31, 2015 –Work Plan filed with WUTC
•January through April 2016 –Technical Advisory Committee
meetings. Meeting topics will include:
–Demand Forecast and Demand Side Management –January
21
–Supply/Infrastructure and Potential Case Discussion–February
18
–Distribution Planning, Natural Gas Pricing, SENDOUT®
Preliminary Output Results and Further Case Discussion –
March 30
–SENDOUT® results –April 21
–May 30, 2016 –Draft of IRP document to TAC
•June 30, 2016 –Comments on draft due back to Avista
•July 2016 –TAC final review meeting (if necessary)
•August 31, 2016 –File finalized IRP document
112
Exhibit No. 7
Case No. AVU-G-17-01 J. Morehouse, Avista
Schedule 1, Page 648 of 648