20150601Morehouse Exhibit 7.pdf

DAVID J. MEYER VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS AVISTA CORPORATION P.O. BOX 3727 1411 EAST MISSION AVENUE SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone] FACSIMILE: [phone] [e-mail]

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-G-15-01 OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES ) AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) Exhibit No. 7 AND NATURAL GAS CUSTOMERS IN THE ) STATE OF IDAHO ) JODY MOREHOUSE
)
FOR AVISTA CORPORATION
(NATURAL GAS ONLY)

2014 Natural Gas
Integrated Resource Plan
August 31, 2014
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 1 of 152

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 2 of 152
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 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-15-01
J. Morehouse, Avista
Schedule 1, P. 3 of 152

TABLE OF CONTENTS
0 Executive Summary ................................................................................ Page 1
1 Introduction ........................................................................................... Page 15
2 Demand Forecasts ................................................................................ Page 25
3 Demand Side Resources ...................................................................... Page 43
4 Supply Side Resources ......................................................................... Page 61
5 Integrated Resource Portfolio................................................................ Page 81
6 Alternate Scenarios, Portfolios, and Stochastic Analysis .................... Page 111
7 Distribution Planning ........................................................................... Page 125
8 Action Plan .......................................................................................... Page 133
9 Glossary of Terms and Acronyms ....................................................... Page 137

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 4 of 152
Executive Summary

Executive Summary
Avista Corporation’s 2014 Natural Gas Integrated Resource Plan (IRP) identifies a
strategic natural gas resource portfolio to meet customer demand requirements over the
next 20 years. While the primary focus of the IRP is meeting customers’ needs under
peak weather conditions, this process also provides a methodology for evaluating
customer needs under normal or average conditions. The formal exercise of bringing
together customer demand forecasts with comprehensive analyses of resource options,
including supply-side resources and demand-side measures, is valuable to Avista, its
customers, regulatory agencies, and other stakeholders for long-range planning.

IRP Process and Stakeholder Involvement
The IRP is a coordinated effort by several Avista departments along with input from our
Technical Advisory Committee (TAC), which includes
Commission Staff, peer utilities, customers, and other
stakeholders. This group is a vital component of our
IRP process, as it provides a forum for the exchange of
ideas from multiple perspectives, identifies issues and
risks, and improves analytical methods. Topics
discussed with the TAC include natural gas demand
forecasts, demand-side management (DSM), supply-
side resources, modeling tools, and distribution
planning. The process results in a resource portfolio
designed to serve our customers’ natural gas needs while balancing cost and risk.

Planning Environment
A long- term resource plan must address the uncertainties inherent in any planning
exercise. Compared to prior planning cycles, there is more certainty about the
availability of natural gas and that much of it can be extracted at favorable prices for
consumers. However, some of the uses of this plentiful and economic energy resource
are unknown. There are questions concerning an industrial renaissance, the amount of
liquefied natural gas (LNG) exports, the market for natural gas vehicles, and power
generation. We continue to challenge key assumptions by evaluating multiple scenarios
over a range of possible outcomes to address the uncertainties.

Demand Forecasts
Avista defines eight distinct demand areas in this IRP structured around the pipeline
transportation and storage resources that serve them. Demand areas include four large
Avista service territories (Washington/Idaho; Medford/Roseburg, Oregon; Klamath Falls,
Avista’s collaborative
planning process
results in a resource
portfolio that meets
customers’ long-term
needs considering cost
and risk.
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Executive Summary

Oregon and La Grande, Oregon) and then disaggregated by the pipelines that serve
them. The Washington/Idaho service territory includes areas served only by Northwest
Pipeline (NWP), only by Gas Transmission Northwest (GTN), and by both pipelines.
The Medford service territory includes an area served by NWP and GTN.
Avista’s approach to demand forecasting focuses on customer growth and use-per-
customer as the base components of demand. Avista recognizes and accounts for
weather as the most significant direct demand-influencing factor. Other demand
influencing factors studied include population, employment trends, age and income
demographics, construction trends, conservation technology, new uses (e.g. natural gas
vehicles), and use-per-customer trends.
Recognizing that customers may adjust consumption in response to price, Avista
analyzed factors that could influence natural gas prices and demand through price
elasticity. These included:
 Supply Trends: shale gas, Canadian supply availability, and export LNG.
 Infrastructure Trends: regional pipeline projects, national pipeline projects,
and storage.
 Regulatory Trends: subsidies, market transparency/speculation, and carbon
legislation.
 Other Trends: thermal generation and energy correlations (i.e. oil/gas,
coal/gas, liquids/gas).
Avista developed a historical-based reference case and conducted sensitivity analysis
on key demand drivers by varying assumptions to understand how demand changes.
Using this information and incorporating input from the TAC, Avista created several
alternate demand scenarios for detailed analysis. Table 1 summarizes these scenarios,
which represent a range of potential outcomes. The Average Case represents Avista’s
demand forecast for normal planning purposes. The Expected Case is the most likely
scenario for peak day planning purposes.

Table 1: Demand Scenarios
2014 IRP Demand Scenarios
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Executive Summary

The IRP process defines the methodology for the development of two primary types of
demand forecasts – annual average daily and peak day. The annual average daily
demand forecast is useful for preparing revenue budgets, developing natural gas
procurement plans, and preparing purchased gas adjustment filings. Forecasts of peak
day demand are critical for determining the adequacy of existing resources or the timing
for new resource acquisitions to meet our customers’ natural gas needs in extreme
weather conditions. The demand forecasts from the Average and Expected Cases
revealed the following as shown in Table 2:
Annual Average Daily Demand – Expected average day, system-wide
core demand increases from an average of 91,352 dekatherms per day
(Dth/day) in 2014 to 102,937 Dth/day in 2033. This is an annual average
growth rate of 0.7 percent and is net of projected conservation savings
from DSM programs. Appendix 3.9 shows gross demand, DSM savings
and net demand.
Peak Day Demand – Expected coincidental peak day, system-wide core
demand increases from a peak of 358,736 Dth/day in 2014 to 404,122
Dth/day in 2033. Forecasted non-coincidental peak day demand peaks at
333,129 Dth/day in 2014 and increases to 375,747 Dth/day in 2033 a 0.6
percent compounded growth rate in peak day requirements. This is also
net of projected conservation savings from DSM programs.

Table 2: Annual Average and Peak Day Demand Cases (Dth/day)
Year Annual Average Daily
Demand
Peak Day Demand Non-coincidental
Peak Day Demand

Figure 1 shows forecasted average daily demand for the five main demand scenarios
modeled over the IRP planning horizon.

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Figure 1: Average Daily Demand

Figure 2 shows forecasted system-wide peak day demand for the five main demand
scenarios modeled over the IRP planning horizon.

Figure 2: Peak Day Demand Scenarios (Net of DSM Savings)

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Executive Summary

Natural Gas Price Forecasts
Natural gas prices are a fundamental component of integrated resource planning
because the commodity price is a significant component of the total cost of a resource
option. This affects the avoided cost threshold for determining cost-effectiveness of
conservation measures. The price of natural gas also influences the consumption of
natural gas by customers. A price elasticity adjustment to use per customer reflects
customer response to changing natural gas prices.
With more information known about the costs and volumes produced by shale gas there
appears to be consensus that production costs will continue to stay low for quite some
time. Avista expects continued low prices even with increased incremental demand for
LNG exports, transportation fuels, and increased industrial consumption.
The carbon legislation debate continues. Avista’s current thinking is that carbon
legislation at the federal level may not occur, but will occur at the state level or in a
regulatory setting like the Environmental Protection Agency’s (EPA) recent proposals to
regulate carbon emissions from electric generation. Current IRP price forecasts include
a lower federal carbon tax that occurs later than prior IRPs. To address the uncertainty
about carbon legislation, Avista analyzed three carbon sensitivities and their impact to
the demand forecasts.
Avista reviewed several price forecasts from credible sources and selected high,
medium, and low price forecasts to represent a reasonable range of pricing possibilities
for the IRP analysis. The range of prices provides necessary variation for addressing
uncertainty of future prices. Figure 1.3 depicts the price forecasts used in this IRP.

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Figure 3: Low/Medium/High Henry Hub Forecasts (Real $/Dth)

Historical statistical analysis shows a long run consumption response to price changes.
In order to model consumption response to these price curves, Avista utilized an
expected elasticity response factor that was applied under various scenarios. Avista will
continue to monitor and research this assumption and make any necessary adjustments
as described in the Ongoing Activities section of Chapter 8 – Action Items.

Existing and Potential Resources
Avista has a diversified portfolio of natural gas supply resources, including access to
and contracts for the purchase of natural gas from several supply basins; owned and
contracted storage providing supply source flexibility; and firm capacity rights on six
pipelines. For potential resource additions, Avista considers incremental pipeline
transportation, storage options, distribution enhancements, and various forms of LNG
storage or service.
Avista models aggregated conservation potential that reduces demand if the
conservation programs are cost-effective over the planning horizon. The identification
and incorporation of conservation savings into the SENDOUT® model utilize projected
natural gas prices and the estimated cost of alternative supply resources. The
operational business planning process starts with IRP identified savings and ultimately
determines the near term program offerings. Given current avoided costs, a limited
number of programs are cost effective in Idaho, Oregon, and Washington. Currently,
Avista is not running natural gas DSM programs in Idaho. Avista actively promotes cost-
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effective efficiency measures to our customers as one component of a comprehensive
strategy to arrive at mix of best cost/risk adjusted resources.

Resource Needs
In the Average Case demand scenario, using Avista’s existing supply resources, the
analysis showed no resource deficiencies in the 20-year planning horizon. The
Expected Case demand scenario, using the existing resources, determined when the
first year peak day demand would not be fully served. Figure 4 summarizes the results
of this portfolio. Avista is not resource deficient in the Expected Case in the 20-year
planning horizon.

Figure 4: Expected Case – First Year Demand Not Met with Existing Resources
Figures 5 through 8 illustrate Avista’s peak day demand by service territory for both this
and the prior IRP. These charts compare existing peak day resources to expected peak
day demand by year and show the timing and extent of resource deficiencies, if any, for
the Expected Case. Based on this information, Avista has time to carefully monitor, plan
and take action on potential resource additions as described in Chapter 8 – Ongoing
Activities.

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Figure 5: Expected Case – WA/ID Existing Resources vs. Peak Day Demand (Net of DSM)

Figure 6: Expected Case – Medford/Roseburg Existing Resources vs. Peak Day Demand
(Net of DSM)

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Figure 7: Expected Case – Klamath Falls Existing Resources vs. Peak Day Demand
(Net of DSM)

Figure 8: Expected Case – La Grande Existing Resources vs. Peak Day Demand
(Net of DSM)

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A critical risk is the slope of forecasted demand growth, which is almost flat in Avista’s
current projections. This outlook implies that existing resources will be sufficient within
the planning horizon to meet demand. However, if demand growth accelerates, the
steeper demand curve could quickly accelerate resource shortages by several years.
Figure 1.9 conceptually illustrates this risk. In this hypothetical example, a resource
shortage does not occur until year eight in the initial demand case. However, the
shortage dramatically accelerates by five years under the revised demand case to year
three. This “flat demand risk” necessitates close monitoring of accelerating demand, as
well as careful evaluation of lead times to acquire the preferred incremental resource.

Figure 9: Flat Demand Risk Example

Alternate Demand Scenarios
Avista performed the same analysis for four other demand scenarios- Average, High
Growth/Low Price, Low Growth/High Price, and Coldest in 20 years. As expected, the
High Growth/Low Price scenario has the most rapid growth and is the only scenario with
unserved demand. This “steeper” demand lessens the “flat demand risk” discussed
above, yet resource deficiencies occur very late in the planning horizon. Figure 10
shows first year resource deficiencies under each scenario.
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Figure 10: Scenario Comparisons of First Year Peak Demand Not Met with Existing
Resources

Issues and Challenges
Even with the planning, analysis, and conclusions reached in this IRP, there is still
uncertainty requiring diligent monitoring of the following issues and challenges.

Demand Issues
The recent recession had a significant impact on the future customer growth trajectory
in Avista’s service territory leading to a declining use per customer. Because of this the
long-term forecast for natural gas demand has declined dramatically. Considering a
broad range of demand scenarios provides insight into how quickly resource needs can
change if demand varies from the Expected Case.
With an increase in natural supply and subsequent low costs, there is increasing
interest in using natural gas. Avista does not anticipate that traditional residential and
commercial customers will provide growth in demand. There is potential for increased
natural gas usage in other markets, such as transportation fuel and power generation,
or as an industrial feedstock. Most of these emerging markets will not be core
customers of the LDC, however they will affect regional gas infrastructure and could
affect natural gas pricing.
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Executive Summary

Price Issues Shale gas has changed the face of North American gas supply. The abundance of shale
along with lagging demand has created a near-term supply glut that kept prices at low
levels. The winter of 2013-2014 brought increased demand and rebalanced the market,
reversing the downward pricing trend. However, the relatively higher prices are a short-
term phenomenon and forecasters anticipate a return to lower prices. This would be
beneficial for customers, but experience has shown that markets can change quickly
and dramatically. To address this uncertainty, this plan includes high and low price
scenarios along with stochastic price analysis to capture a range of possible prices.

LNG Exports
The availability of plentiful amounts of natural gas in North America has changed global
LNG dynamics. Existing and new LNG facilities are looking to export low cost North
American gas to the higher priced Asian and European markets. In Canada, 16 LNG
export projects are in various stages of the permitting process. In the Northwest, there
are 2 proposed terminals in Oregon. How many of these terminals actually get approval
and ultimately built is yet to be determined. However, LNG exporting has the potential to
alter the price, constrain existing pipeline networks, stimulate development of new
pipeline resources, and change flows of natural gas across North America.

Action Plan
Avista’s 2015-2016 Action Plan outlines activities identified by the IRP team, with input
from management and TAC members, for development and inclusion in this IRP. The
purpose of these action items is to position Avista to provide the best cost/risk resource
portfolio and to support and improve IRP planning. The Action Plan identifies needed
supply and demand side resources and highlights key analytical needs in the near term.
It also highlights essential ongoing planning initiatives and gas industry trends Avista
will be monitoring as a part of its routine planning processes (Chapter 8 – Action Items).
The IRP analysis indicates there is no near term needs to acquire additional supply side
resources to meet customer demand. Therefore, appropriate management of existing
resources is paramount. Optimizing underutilized resources reduces costs to customers
while providing reliability if customers’ needs exceed forecasted expectations.
Avista also pursues cost-effective demand-side solutions, but recognizes the challenges
of the current low cost environment. Within the IRP, Washington and Idaho
conservation measures aim to reduce demand by approximately 151,500 dekatherms in
2015. In Oregon, conservation measures aim to reduce demand by approximately
16,100 dekatherms in 2015.
Avista will comply with Commission findings to try to increase the cost effectiveness of
measures within the portfolio by reducing administration and audit costs, analyzing non-
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Executive Summary

natural gas benefits, and increasing measure lives. Natural gas prices will be monitored
as a leading indicator for increasing avoided costs. If avoided costs increase, DSM
programs will be evaluated for cost-effectiveness and Avista will be proactive in
submitting to the Commissions to resume natural gas DSM options.
Completion of the gate station analysis to assess any resource deficiencies masked by
Avista’s aggregated IRP analysis. Should deficiencies be identified we will discuss
findings and potential solutions with Commission Staff. Avista will continue to coordinate
analytic efforts between Gas Supply, Gas Engineering, and the intrastate pipelines to
perform gate station analysis and develop least cost solutions for any future
deficiencies.
Key ongoing components of the Action Plan include:
 Monitor actual demand for growth exceeding the forecast to respond
aggressively to address potential accelerated resource deficiencies arising
from exposure to “flat demand” risk. This will include providing Commission
Staff with IRP demand forecast-to-actual variance analysis on customer
growth and use per customer. Avista will provide these updates to each
Commission Staff at least bi-annually.
 Continue to monitor supply resource trends including the availability and price
of natural gas to the region, LNG exports, Canadian natural gas supply
availability and interprovincial consumption, and pipeline and storage
infrastructure availability.
 Monitor availability of current resource options and assess new resource
lead-time requirements relative to resource need to preserve flexibility.
 Meet regularly with Commission Staff to provide information on market
activities and significant changes in assumptions and/or status of Avista
activities related to the IRP or natural gas procurement practices.

CONCLUSION
Anticipated low customer growth has eliminated the need for Avista to acquire additional
supply-side resources, therefore appropriate management of underutilized resources to
reduce costs until resources are needed is essential. Additionally, the lower cost of
natural gas continues to challenge the cost-effectiveness of DSM programs. While
Avista believes adoption of conservation is the best strategy for minimizing costs to
customers and promoting a cleaner environment, this IRP shows a lower conservation
potential than previous IRP’s because of the relatively low avoided cost of natural gas.
The IRP has many objectives, but foremost is to ensure that proper planning will enable
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Executive Summary

Avista to continue delivering safe, reliable, and economic natural gas service to our
customers.

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Chapter 1: Introduction

1: Introduction

Avista is involved in the production, transmission and distribution of natural gas and
electricity, as well as other energy-related businesses. Avista was founded in 1889 as
Washington Water Power and has been providing reliable, efficient and competitively
priced energy to customers for over 125 years.

Avista entered the natural gas business with the purchase of Spokane Natural Gas
Company in 1958. In 1970, it expanded into natural gas storage with Washington
Natural Gas (now Puget Sound Energy) and El Paso Natural Gas (its interest
subsequently purchased by NWP) to develop the Jackson Prairie natural gas
underground storage facility in Chehalis, Wash. In 1991, Avista added 63,000
customers with the acquisition of CP National Corporation’s Oregon and California
properties. Avista subsequently sold the California properties and its 18,000 South Lake
Tahoe customers to Southwest Gas in 2005. Figure 1.1 shows where Avista currently
provides natural gas service to approximately 325,000 customers in eastern
Washington, northern Idaho and several communities in northeast and southwest
Oregon. Figure 1.2 shows the number of natural gas customers by state.

Figure 1.1: Avista Service Territory

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Chapter 1: Introduction

Figure 1.2: Avista’s Natural Gas Customer Counts

Avista manages its natural gas operation through two operating divisions – North and
South:
 The North Division covers about 26,000 square miles, primarily in eastern
Washington and northern Idaho. Over 840,000 people live in Avista’s
Washington/Idaho service area. It includes urban areas, farms, timberlands, and
the Coeur d’Alene mining district. Spokane is the largest metropolitan area with
a regional population of approximately 470,000 followed by the Lewiston,
Idaho/Clarkston, Washington and Coeur d’Alene, Idaho areas. The North
Division has about 74 miles of natural gas distribution mains and 5,000 miles of
distribution lines. The North Division receives natural gas at more than 40 points
along interstate pipelines and distributes it to over 227,000 customers.
 The South Division serves four counties in southwest Oregon and one county in
northeast Oregon. The combined population of these areas is over 480,000
residents. The South Division includes urban areas, farms and timberlands. The
Medford, Ashland and Grants Pass areas, located in Jackson and Josephine
Counties, is the largest single area served by Avista in this division with a
regional population of approximately 290,000 residents. The South Division
consists of about 67 miles of natural gas distribution mains and 2,000 miles of
distribution lines. Avista receives natural gas at more than 20 points along
interstate pipelines and distributes it to almost 96,000 customers.
144,941
82,079 98,700
325,720
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Total Natural Gas Customers
as of Dec. 31, 2013
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Chapter 1: Introduction
Customers
Avista provides natural gas services to “core” and “transportation-only” customer
classes. Core or retail customers purchase natural gas directly from Avista with delivery
to their home or business under a bundled rate. Core customers on firm rate schedules
are entitled to receive any volume of gas they require. Some core customers are on
interruptible rate schedules. These customers pay a lesser rate than firm customers
since their service can be interrupted. Interruptible customers are not considered in
peak day IRP planning.
Transportation-only customers purchase natural gas from third parties who deliver the
purchased gas to our distribution system. Avista delivers this gas to their business
charging a distribution rate only. Avista can interrupt the delivery service when following
the priority of service tariff. The long-term resource planning exercise excludes
transportation-only customers because they purchase their own gas and utilize their
own interstate pipeline transportation contracts. However, distribution planning
exercises include these customers.
Avista’s core or retail customers include residential, commercial and industrial
categories. Most of Avista’s customers are residential, followed by commercial and
relatively few industrial accounts (Figure 1.3).

Figure 1.3 Firm Customer Mix

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Chapter 1: Introduction
The mix is more balanced between residential and commercial accounts on an annual
volume basis (Figure 1.4). Volume consumed by core industrial customers is not
significant to the total, partly because most industrial customers in Avista’s service
territories are transportation-only customers.

Figure 1.4 Therms by Class

Core customer demand is seasonal, especially residential accounts in service territories
with colder winters (Figure 1.5). Industrial demand, which is typically not weather
sensitive, has very little seasonality. However, the La Grande service territory has
several industrially classified agricultural processing facilities that produce a late
summer seasonal demand spike.

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Chapter 1: Introduction
Figure 1.5: Customer Demand by Service Territory

Integrated Resource Planning
Avista’s IRP involves a comprehensive analytical process to ensure that core firm
customers receive long-term reliable natural gas service at a competitive price. The IRP
includes evaluation, identification, and planning for the acquisition of an optimal
combination of expected costs and associated risk of existing and future resources to
meet average daily and peak-day demand delivery requirements over a 20-year
planning horizon.

Purpose of the IRP
Avista’s 2014 Natural Gas IRP:
 Provides a comprehensive long-range planning tool.
 Fully integrates forecasted requirements with existing and potential resources.
 Determines the most cost-effective, risk-adjusted means for meeting future
demand requirements.
 Responds to Washington, Idaho and Oregon rules, orders, and guidelines.

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Chapter 1: Introduction
Avista’s IRP Process The IRP process considers:
 Customer growth and usage.
 Weather planning standard.
 DSM opportunities.
 Existing and potential supply-side resource options.
 Current and potential legislation/regulation.
 Risk.

Public Participation
Avista’s TAC members play a key role and have a significant impact in development of
the IRP. TAC members include Commission Staff, peer utilities, public interest groups,
customers, academics, government agencies, and other interested parties. TAC
members provide important input on modeling, planning assumptions, and the general
direction of the process.
Avista sponsored four TAC meetings to facilitate stakeholder involvement in the 2014
IRP. The first meeting convened on January 24, 2014, and the last meeting occurred on
April 23, 2014. Meetings are at a variety of locations convenient for stakeholders and
are electronically available for those unable to attend in person. Each meeting included
a broad spectrum of stakeholders. The meetings focused on specific planning topics,
reviewing the progress of planning activities, and soliciting input on IRP development.
TAC members received a draft of this IRP on May 30, 2014, for their review. Avista
addressed the comments and concerns about that draft, and they enhanced this
document. Avista appreciates all of the time and effort TAC members gave to the IRP
process; they provided valuable input through their participation in the TAC process.
Preparation of the IRP is a coordinated endeavor by several departments within Avista
with involvement and guidance from management. We are grateful for their efforts and
contributions.

Regulatory Requirements Avista submits an IRP to the public utility commissions in Idaho, Oregon and
Washington on or before August 31 every two years as required by state regulation.
There is a statutory obligation to provide reliable natural gas service to customers at
rates, terms and conditions that are fair, just, reasonable and sufficient. Avista regards

1 The Washington IRP requirements are in WAC 480-90-238 on Integrated Resource Planning. Case No. GNR-G-93-2, Order No. 25342 outlines the Idaho IRP requirements. Order Nos. 07-002, 07-047 and 08-339 outline the Oregon IRP requirements. Appendix 2.2 provides details of these requirements and how this IRP meets those requirements.
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Chapter 1: Introduction
the IRP as a means for identifying and evaluating potential resource options and as a
process to establish an Action Plan for resource decisions. Ongoing investigation,
analysis and research may cause Avista to determine that alternative resources are
more cost effective than resources reviewed and selected in this IRP. Avista will
continue to review and refine our understanding of resource options and will act to
secure these risk-adjusted, least-cost options when appropriate.

Planning Model
Consistent with prior IRPs, Avista used the SENDOUT planning model to perform
comprehensive natural gas supply planning and analysis for this IRP. SENDOUT is a
linear programming-based model that is widely used to solve natural gas supply,
storage and transportation optimization problems. This model uses present value
revenue requirement (PVRR) methodology to perform least-cost optimization based on
daily, monthly, seasonal and annual assumptions related to the following:
 Customer growth and customer natural gas usage to form demand forecasts.
 Existing and potential transportation and storage options.
 Existing and potential natural gas supply availability and pricing.
 Revenue requirements on all new asset additions.
 Weather assumptions.
 Demand-Side management.
Avista incorporated stochastic modeling by utilizing a SENDOUT module to simulate
weather and price uncertainty. The module generates Monte Carlo weather and price
simulations, running concurrently to account for events and to provide a probability
distribution of results that aid resource decisions. Some examples of the types of
stochastic analysis provided include:
 Price and weather probability distributions.
 Probability distributions of costs (i.e. system costs, storage costs, commodity
costs).
 Resource mix (optimally sizing a contract or asset level of competing resources).
These computer-based planning tools were used to develop the 20-year best cost/risk
resource portfolio plan to serve customers.

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Chapter 1: Introduction
Planning Environment
Even though Avista publishes an IRP biannually, the process is ongoing with new
information and developments. In normal circumstances, the process can become
complex as underlying assumptions evolve, impacting previously completed analyses.
Every planning cycle has challenges and uncertainties; this cycle was no different. For
example, the recession greatly impacted Avista’s forecasted demand growth and has
significantly reduced long-term natural gas needs. Widespread agreement on the
availability of shale gas and the ability to produce it at lower prices has increased
interest in the use of natural gas for LNG exports and for more transportation and
industrial uses. However, there is uncertainty about the timing and size of those
markets.

IRP Planning Strategy
Planning for an uncertain future requires robust analysis that encompasses a wide
range of possibilities. Avista has determined that the planning approach needs to:
 Recognize that historical trends may be fundamentally altered.
 Critically review all assumptions.
 Stress test assumptions via sensitivity analysis.
 Pursue a spectrum of possible scenarios.
 Develop a flexible analytical framework to accommodate changes.
 Maintain a long-term perspective.
With these objectives in mind, Avista developed a strategy encompassing all required
planning criteria. This produced a complete IRP that effectively analyzes risks and
resource options, which sufficiently ensures customers will receive safe and reliable
energy delivery services with the best-risk, lease-cost, long-term solutions.

Summary of changes from the 2012 IRP
Chapter Issue 2014 Natural Gas IRP 2012 Natural Gas IRP
Demand Expected Customer
Growth
Expected Case customer
growth is 1% compounded
annually.
Expected Case customer
growth of 1.8% compounded
annually.
High/Low Growth High and low growth based on
forecasted long run
employment growth.
Based on Washington State
Office of Financial
Management, 40% below and
60% above expected growth.
Price Elasticity Utilized a -0.15 response based
on multiple historic analysis.
Incorporated mechanism to
Utilized a -0.13 response
based on AGA survey.
Applied to change year-over-
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Chapter 1: Introduction
Demand Side
Management
Environmental
Issues
Supply Side
Resources

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Chapter 1: Introduction

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Chapter 2: Demand Forecasts

2: Demand Forecasts

Overview
The integrated resource planning process begins with the development of forecasted
demand. Understanding and analyzing key demand drivers and their potential impact on
forecasts is vital to the planning process. Utilization of historical data provides a reliable
baseline, however past trends may not be indicative of future trends. This IRP mitigates
the uncertainty by considering a range of scenarios to evaluate and prepare for a broad
spectrum of outcomes.

Demand Areas
Avista defined eight demand areas, structured around the pipeline transportation
resources that serve them, within the SENDOUT model (Table 2.1). These demand
areas are aggregated into four service territories and further summarized into two
divisions for presentation throughout this IRP.

Table 2.1 Geographic Demand Classifications

Demand Forecast Methodology
Avista uses the IRP process to develop two types of demand forecasts – “annual” and
“peak day.” Annual average demand forecasts are useful for several purposes,
including preparing revenue budgets, developing natural gas procurement plans, and
preparing purchased gas adjustment filings. Peak day demand forecasts are critical for
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determining the adequacy of existing resources or the timing for acquiring new
resources to meet customers’ natural gas needs in extreme weather conditions.
In general, if existing resources are sufficient to meet peak day demand, they will be
sufficient to meet annual average day demand. Developing annual average demand
first and evaluating it against existing resources is an important step in understanding
the performance of the portfolio under normal circumstances. It also facilitates
synchronization of modeling processes and assumptions for all planning purposes.
Peak weather analysis aids in assessing not only resource adequacy, but differences, if
any, in resource utilization. For example, storage may be dispatched differently under
peak weather scenarios.

Demand Modeling Equation
Because natural gas demand can vary widely from day-to-day, especially in winter
months when heating demand is at its highest, developing daily demand forecasts is
essential. In its most basic form, natural gas demand is a function of customer base
usage (non-weather sensitive usage) plus customer weather sensitive usage. Basic
demand takes the formula in Table 2.2:
Table 2.2: Basic Demand Formula

SENDOUT® requires inputs as expressed in the Table 2.3 format to compute daily
demand in dekatherms (Dth):
Table 2.3: SENDOUT® Demand Formula

Table 3.3 SENDOUT® Demand Formula
# of customers x Daily Dth base usage / customer
Plus
# of customers x Daily Dth weather sensitive usage / customer x # of daiy degree days
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SENDOUT performs this calculation daily for each customer class and each demand
area. The base and weather sensitive usage (heating degree day usage) factors use
customer demand coefficients developed outside the SENDOUT model, and the
coefficients capture a variety of demand usage assumptions. This is discussed in more
detail in the Use-per-Customer Forecast section below. The number of daily degree
days is simply heating degree days (HDDs), which are further discussed in the Weather
Forecast section later in this chapter.

Customer Forecasts
Avista’s customer base includes residential, commercial and industrial categories. For
each of the customer categories, Avista develops customer forecasts incorporating
national economic forecasts and then drilling down into regional economies. U.S. GDP
growth, U.S. and regional employment growth, and regional population growth
expectations are key drivers in regional economic forecasts and are useful in estimating
the number of natural gas customers. A detailed description of the customer forecast is
found in Appendix 2.1. Avista combines this data with local knowledge about sub-
regional construction activity, age and other demographic trends, and historical data to
develop the 20-year customer forecasts.
Several departments within Avista use these forecasts, but Finance, Accounting, Rates,
and Gas Supply are the primary users of these forecasts. Additionally, the distribution
engineering group utilizes the forecast data for system optimization and planning
purposes (see further discussion in Chapter 7 – Distribution Planning).
Forecasting customer growth is an inexact science, so it is important to consider
alternative forecasts. Two alternative growth forecasts were developed for consideration
in this IRP. Avista developed High and Low growth forecasts to provide potential paths
and test resource adequacy. Appendix 2.1 contains a description of how these
alternatives were developed.
Figure 2.1 shows these three customer growth forecasts. Due to a change in
forecasting customer growth, the expected case customer counts are lower than the last
IRP. This has impacted forecasted demand from both and average and peak day
perspective. Detailed customer count data by region and class for all three scenarios is
in Appendix. 2.2.

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Chapter 2: Demand Forecasts

Figure 2.1: Customer Growth Scenarios

Use-per-Customer Forecast
The goal for a use-per-customer forecast is to develop base and weather sensitive
demand coefficients that can be combined and applied to HDD weather parameters to
reflect average use per customer. This produces a reliable forecast because of the high
correlation between usage and temperature as depicted in the example scatter plot in
Figure 2.2.

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Chapter 2: Demand Forecasts

Figure 2.2: Example Demand vs. Average Temperature – WA/ID

The first step in developing demand coefficients was gathering daily historical gas flow
data for all of Avista’s city gates. The use of city gate data over revenue data is due to
the tight correlation between weather and demand. The revenue system does not
capture data on a daily basis and, therefore, makes a statistical analysis with tight
correlations on a daily basis virtually impossible. Avista reconciles city gate flow data to
revenue data to ensure that total demand is properly captured.
The historical city gate data was gathered, sorted by service territory/temperature zone,
and then by month. As in the last IRP, Avista used three years of historical data to
derive the use-per-customer coefficients, but also considered varying the number of
years of historical data. When comparing five years of historical use-per-customer to the
three years of data, the five-year data had slightly lower use-per-customer, which may
understate use as the economy moderately recovers and customers’ usage patterns
return to pre-recession patterns. Three years struck a balance between historical and
current customer usage patterns. Figure 2.3 illustrates the annual demand differences
between the three and five-year use-per-customer with normal and peak weather
conditions.

0
50,000
100,000
150,000
200,000
250,000
-20 0 20 40 60 80 100
Dth
Farenheit
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Chapter 2: Demand Forecasts

Figure 2.3: Annual Demand – Demand Sensitivities 3-Year vs. 5-Year Use-per-Customer

The base usage calculation used three years of July data to derive coefficients. Average
usage in these months divided by the average number of customers provides the base
usage coefficient input into SENDOUT.This calculation is done for each area and
customer class based on customer billing data demand ratios.
To derive weather sensitive demand coefficients for each monthly data subset, Avista
removed base demand from the total and plotted usage by HDD in a scatter plot chart
to verify correlation visually. The process included the application of a linear regression
to the data by month to capture the linear relationship of usage to HDD. The slopes of
the resulting lines are the monthly weather sensitive demand coefficients input into
SENDOUT. Again, this calculation is done by area and by customer class using
allocations based on customer billing data demand ratios.
In extreme weather conditions, demand can begin to flatten out relative to the linear
relationships at less extreme temperatures. This occurs, for example, when furnaces
reach maximum output and do not consume any more natural gas, regardless of how
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Chapter 2: Demand Forecasts

much colder temperatures get. Avista sought to capture this phenomenon through
development of super peak coefficients.
The methodology for deriving super peak coefficients was derived by averaging the heat
coefficients for December, January and February. One inherent drawback to this
methodology is the lack of sufficient data points to develop a strong linear relationship.
Avista will continue to test this theory and monitor trends as described in Chapter 8 -
Ongoing Activities.
As a final step, coefficient reasonableness was checked by applying the coefficients to
actual customer count and weather data to backcast demand. This was compared to
actual demand with satisfactory results.

Weather Forecast
The last input in the demand modeling equation is weather (specifically HDDs). This
started with the most current 20 years of daily weather data from the National Oceanic
Atmospheric Administration (NOAA), converted to HDDs, and used to compute an
average for each day to develop the weather forecast. The Oregon weather input used
four weather stations, corresponding to the areas where Avista provides natural gas
services. HDD weather patterns between these areas are uncorrelated. Weather data
for the Spokane Airport is used for the eastern Washington and northern Idaho portions
of the service area, as HDD weather patterns within that region are correlated.
The NOAA 20-year average weather serves as the base weather forecast to prepare
the annual average demand forecast. 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, as well as adjusting the two days on either
side of the coldest day to temperatures slightly warmer than the coldest day. For the
Washington/Idaho and La Grande service territories, the model assumes this event on
and around February 15 each year. For the southwestern Oregon service territories
(Medford, Roseburg, Klamath Falls), the model assumes this event on and around
December 20 each year.
The following section provides details about the coldest days on record for each service
territory.
The Washington/Idaho service areas coldest day on record was an 82 HDD for
Spokane and occurred on Dec. 30, 1968. This is equal to an average daily temperature
of -17 degrees Fahrenheit. Only one 82 HDD has been experienced in the last 40 years
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for this area; however, within that same time period, 80, 79 and 74 HDD events
occurred on Dec. 29, 1968, Dec. 31,1978 and Jan. 5, 2004, respectively.
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 data. 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.
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 planning
standard. While remote, peak days do occur, as on Dec. 8, 2014, when Avista matched
the previous peak HDD in Klamath Falls.
Avista analyzes an alternate planning standard using the coldest temperature in the last
twenty years the Washington/Idaho service area uses a 76 HDD, which is equal to an
average daily temperature of -11 degrees Fahrenheit. In Medford, the coldest day in 20
years is a 54 HDD, equivalent to a temperature of 11 degrees Fahrenheit. In Roseburg,
the coldest day in 20 years is a 48 HDD, equivalent to a temperature of 17 degrees
Fahrenheit. In Klamath Falls, the coldest day in 20 years is a 72 HDD, equivalent to a
temperature of -7 degree Fahrenheit. In La Grande, the coldest day in 20 years is a 64
HDD, equivalent to a temperature of 1 degree Fahrenheit.
The HDDs by area, class and day entered into SENDOUT® are in Appendix 2.4.

Global Warming
In previous IRP’s, an adjustment has been made to NOAA weather data to incorporate
estimates for global warming. This adjustment was based on analysis of historical
weather data in each of the areas served. In this IRP, Avista moved away from
adjusting the weather data in favor of moving from a rolling 30-year average to a 20-
year average.
Avista chose a 20-year average for several reasons. First, NASA climate studies
indicate that the distribution of temperatures in North America began to shift upwards
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significantly about 20 years ago.1 In this case, a 20-year average coincides with the
period when the temperature shift occurred. Second, there is a tradeoff between the
length of the normal weather definition and its volatility.2 For example, although a 10-
year moving average captures turning points in climate trends more quickly than 15, 20
or 30-year averages, it will do so at the cost of larger year-to-year changes in the
measurement of normal weather. That is, short-term weather variations not necessarily
related to climate change will play a larger role in the defining normal weather as the
number of years used for calculating the moving average declines. This can lead to
excessive forecast volatility for each update to the 10-year average. In this respect, the
20-year average is a compromise between the traditional 30-year average, which may
not capture climate trends, and the 10-year average, which greatly increases the
volatility of year-to-year normal weather.
Avista was unable to find any definitive evidence to support a peak day warming trend.
After discussion with the TAC, Avista decided to discontinue global warming trend
adjustments to the peak day weather events in the HDD forecast. Therefore, the
modeling and analysis with respect to peak day planning is unaffected by global
warming.

Developing a Reference Case
To adjust for uncertainty, Avista developed a dynamic demand forecasting methodology
that is flexible to changing assumptions. To understand how various alternative
assumptions influence forecasted demand Avista needed a reference point for
comparative analysis. For this, Avista defined the reference case demand forecast
shown in Figure 2.4. This case is only a starting point to compare other cases.

1 See Hansen, J.; M. Sato; and R. Ruedy, “Global Temperature Update Through 2012,” Science
Summary of NASA’s 2012 Temperature Summary January 2013,
http://www.nasa.gov/topics/earth/features/2012-temps.html 2 For a detailed discussion of this issue, see Livezey, R. E., and P. Q. Hanser, “Redefining Normal
Temperatures: Resource Planning and Forecasting in a Changing Environment,” Public Utilities
Fortnightly, May 2013, 151(5), pp. 28-33,56.
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Chapter 2: Demand Forecasts

Figure 2.4: Reference Case Assumptions

Dynamic Demand Methodology

The dynamic demand planning strategy examines a range of potential outcomes. The
approach consists of:
 Identifying key demand drivers behind natural gas consumption.
 Performing sensitivity analysis on each demand driver.
 Combining demand drivers under various scenarios to develop alternative
potential outcomes for forecasted demand.
 Matching demand scenarios with supply scenarios to identify unserved demand.
Figure 2.5 represents our methodology of starting with sensitivities, progressing to
scenarios, and ultimately creating portfolios.

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Chapter 2: Demand Forecasts

Figure 2.5: Sensitivities, Scenarios and Portfolios

Sensitivity Analysis
In analyzing demand drivers, Avista grouped them into two categories based on:
 Demand Influencing Factors directly influencing the volume of natural gas
consumed by core customers.
 Price Influencing Factors indirectly influencing the volume of natural gas
consumed by core customers through a price elasticity response.
After identifying demand and price influencing factors, Avista developed sensitivities to
focus on the analysis of a specific natural gas demand driver and its impact on
forecasted demand relative to the Reference Case when modifying the underlying input
assumptions.
Sensitivity assumptions reflect incremental adjustments not captured in the underlying
Reference Case forecast. Avista analyzed 17 demand sensitivities to determine the
results relative to the reference case. Table 2.4 lists these sensitivities. Detailed
information about these sensitivities is in Appendix 3.6.

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Chapter 2: Demand Forecasts

Table 2.4: Demand Sensitivities

Figure 2.6 shows the annual demand from each of the sensitivities modeled for this IRP.

Figure 2.6: 2014 IRP Demand Sensitivities

Scenario Analysis
After testing the sensitivities, Avista grouped them into meaningful combinations of
demand drivers to develop demand forecasts representing scenarios. Table 2.5
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Chapter 2: Demand Forecasts

identifies the scenarios developed. The Average Demand Case represents the case
used for normal planning purposes, such as corporate budgeting, procurement
planning, and PGA/General Rate Cases. The Expected Case reflects the demand
forecast Avista believes is most likely given peak weather conditions. The High
Growth/Low Price and Low Growth/High Price cases represent a range of possibilities
for customer growth and future prices. The Alternate Weather Standard case utilizes the
coldest day in Avista’s service territories in the last 20 years. Each of these scenarios
provides a “what if” analysis given the volatile nature of key assumptions, including
weather and price. Appendix 2.6 lists the specific assumptions within the scenarios
while Appendix 2.7 contains a detailed description of each scenario.

Table 2.5: Demand Scenarios

Price Elasticity
The economic theory of price elasticity states that the quantity demanded for a good or
service will change with its price. Price elasticity is a numerical factor that identifies the
relationship of a consumer’s consumption change in response to a 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 negative 0.15 for a particular
good or service means a 10 percent price increase will prompt a 1.5 percent
consumption decrease and a 10 percent price decrease will prompt a 1.5 percent
consumption increase.
Complex relationships influence price elasticity and given the current economic
environment, Avista questions whether current behavior will become normal or if
customers will return to historic usage patterns. Furthermore, complex regulatory pricing
mechanisms shield customers from price volatility, thereby dampening price signals and
affecting price elastic responses. For example, budget billing averages a customer’s
bills into equal payments throughout the year. This popular program helps customers
2014 IRP Demand Scenarios
Average Case
Expected Case
High Growth, Low Price
Low Growth, High Price
Alternate Weather Standard
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Chapter 2: Demand Forecasts

manage household budgets, but does not send a timely price signal. Additionally,
natural gas cost adjustments, such as the Purchased Gas Adjustment (PGA), annually
adjusts the commodity cost which shields customers from daily gas price volatility.
These mechanisms do not completely remove price signals, but they can significantly
dampen the potential demand impact.
When considering a variety of studies on energy price elasticity, a range of potential
outcomes was identified, including the existence of positive price elastic adjustments to
demand. One study looking at the regional differences in price elasticity of demand for
energy found that the statistical significance of price becomes more uncertain as the
geographic area of measurement shrinks.3 This is particularly important given Avista’s
geographically diverse and relatively small service territories.
Avista acknowledges changing price levels can and do influence natural gas usage, so
this IRP includes a price elasticity of demand factor of -0.15 into the modeling
assumptions to allow use-per-customer to vary into the future as the natural gas price
forecast changes.
Recent usage data indicates that even with declines in the retail rate for natural gas,
long run use-per-customer continues to decline. This likely includes a confluence of
factors including high unemployment, increased investments in energy efficiency
measures, building code improvements, behavioral changes, and heightened focus of
consumers’ household budgets.

Results
During 2014, the Average Case demand forecast indicates Avista will serve an average
of 324,606 core natural gas customers with 33,343,423 dekatherms of natural gas. By
2033, Avista projects 391,203 core natural gas customers with an annual demand of
over 38,069,627 dekatherms. In Washington/Idaho, the projected number of customers
increases at an average annual rate of 0.99 percent with demand growing at a
compounded average annual rate of 1.03 percent. In Oregon, the projected number of
customers increases at an average annual rate of 1.7percent, with demand growing 1.3
percent per year.
During 2014, the Expected Case demand forecast indicates Avista will serve an
average of 324,606 core natural gas customers with 34,095,766 dekatherms of natural
gas. By 2033, Avista projects 391,203 core natural gas customers with an annual
demand of over 38,889,977 dekatherms.
3 Bernstein, M.A. and J. Griffin (2005). Regional Differences in Price-Elasticity of Demand for Energy, Rand Corporation.
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Figure 2.7 shows system forecasted demand for the demand scenarios on an average
daily basis for each year.4

Figure 2.7: Average Daily Demand – 2014 IRP Scenarios

Figure 2.8 shows system forecasted demand for the Expected, High and Low Demand
cases on a peak day basis for each year relative to the Average case average daily
winter demand. Detailed data for all demand scenarios is in Appendix 2.8.

4 Appendix 3.9 shows gross demand, DSM savings and net demand.
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Figure 2.8: February 15th – Peak Day – 2014 IRP Demand Scenarios

The purpose of the IRP is to balance forecasted demand with existing and new supply
alternatives. Since new supply sources include conservation resources, which act as a
demand reduction, the demand forecasts prepared and described in this section include
existing efficiency standards and normal market acceptance levels. The methodology
for modeling DSM initiatives is in Chapter 3 – Demand-Side Resources.

Alternative Forecasting Methodologies
There are many forecasting methods available and used throughout different industries.
Avista strives to use methods that enhance forecast accuracy, facilitate meaningful
variance analysis, and allows for modeling flexibility to incorporate different
assumptions. Avista believes the statistical methodology to be sound and provides a
robust range of demand considerations. The methodology allows for the analysis of
different statistical inputs by considering both qualitative and quantitative factors. These
factors can come from data, surveys of market information, fundamental forecasts, and
industry experts. Avista is always open to new methods of forecasting natural gas
demand and will continue to assess which, if any, alternative methodologies to include
in the dynamic demand forecasting methodology.
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Chapter 2: Demand Forecasts

Key Issues Demand forecasting is a critical component of the IRP requiring careful evaluation of the
current methodology and use of sufficient scenario planning to understand how changes
to the underlying assumptions will affect the results. The evolution of demand
forecasting over recent years has been dramatic, causing a heightened focus on
variance analysis and trend monitoring. Current techniques have provided sound
forecasts with appropriate variance capabilities. However, Avista is mindful of the
importance of the assumptions driving current forecasts and understands that these can
and will change over time. Therefore, monitoring key assumptions driving the demand
forecast is an ongoing effort that will be shared with the TAC as they develop.

Price Elasticity
Avista continues to study how to incorporate a price elastic response to demand given
the complex cross commodity relationships, regulatory pricing mechanisms, flat forward
price curve and changing technologies in energy efficiency that make discerning how
much demand response to expect over the long term.
An action item from the previous IRP was to explore the possibility of a regional
elasticity study facilitated by Avista in conjunction with a third-party such as the NWGA
or the AGA. Avista approached the NWGA and they are willing to assess regional
interest and facilitate the process. Avista is developing the scope, assessing who is best
to conduct a study, and determining the associated costs. Avista will assess the interest
level of regional stakeholders before deciding to proceed with the study.

Flat Demand Risk
Forecasting customer usage is a complex process because of the number of underlying
assumptions and the relative uncertainty of future patterns of usage with a goal of
increasing forecast accuracy. There are many factors that can be incorporated into
these models, assessing which ones are significant and improving the accuracy are
key. Avista continues to evaluate economic and non-economic drivers to determine
which factors improve forecasting accuracy. The forecasting process will continue to
review research on climate change and the best way to incorporate the results of that
research into the forecasting process.
For the last few planning cycles, the TAC has discussed the changing slope of
forecasted demand. Growth has slowed due to the recent recession and declining use-
per-customer. This is primarily driven by energy efficiency and responses to higher
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Chapter 2: Demand Forecasts

commodity costs and general inflation. Use-per-customer seems to have stabilized, but
customer growth in Avista’s service territory may not return to pre-recession levels.
This reduced demand pushes the need for resources beyond the planning horizon,
which means no new investment in resources is necessary. However, should
assumptions about lower customer growth prove to be inaccurate and there is a
rebound in demand, new resource needs will occur sooner than expected. Therefore,
careful monitoring of demand trends in order to identify signposts of accelerated
demand growth is critical to the identification of new resource needs coming earlier.

Emerging Natural Gas Demand
The shale gas revolution has fundamentally changed the long-term availability and price
of natural gas. This revolution prompts an evolution in the increased use of natural gas.
From fertilizer plants to food processors, interest in industrial processes that use natural
gas as a feedstock is growing. Another likely demand growth area is in the
transportation sector; both land-based and marine fleets are turning to natural gas for
their fuel supply due to its low price and better environmental footprint when compared
to diesel. It remains to be seen if these new customers are served by an LDC, in all
likelihood they will not be firm sales customers. , However, their demands will have an
impact on regional supply which could trigger price movement.

Conclusion
Recessionary impacts have significantly reduced Avista’s outlook for customer growth
and reduced the long-term demand forecasts. Avista’s dynamic demand methodology
provides a means to assess the individual and collective demand impact of a variety of
economic and non-economic drivers. The results of this comprehensive analysis
provides a better understanding of the possible outcomes with respect to core
consumption of natural gas and helps drive resource decisions based on changing
consumer needs.
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Chapter 3: Demand-Side Resources

Chapter 3: Demand-Side Resources

Overview
Avista is committed to offering natural gas DSM portfolios to residential, commercial and
industrial customers when it is feasible to do so in a cost-effective manner as prescribed
within each jurisdiction. In recent years, customers have benefitted from precipitous
declines in natural gas avoided costs. At the same time, these falling avoided costs
have made it more challenging to design a cost effective DSM portfolio as well as
limiting the cost incentives that efficiency programs have with retail customers. The
Avista continues to work with regulators and key external stakeholders on potential
natural gas DSM opportunities to achieve a cost effective portfolio in each of its
jurisdictions. Currently, the status of the Avista’s natural gas DSM programs differs
significantly in each of its three jurisdictions.
Avista manages the Washington and Idaho DSM programs, to the extent possible, as a
single portfolio due to the geography and communications inherent within that portion of
the service territory. Previous analysis, using the then-prevailing avoided cost that were
more favorable to DSM resources, led Avista to the conclusion that it was not possible
to field a Washington and Idaho natural gas DSM portfolio that would be cost-effective
under the traditional Total Resource Cost (TRC) test. The TRC cost-benefit test is a
measurement of the success that a portfolio has in reducing the customer’s total energy
cost for providing end-use services. As a result, in May 2012 Avista proposed revisions
to its natural gas energy efficiency tariffs in Washington and Idaho that would have, if
adopted as filed, suspended all incentives and direct marketing of natural gas efficiency
programs. As happened with the Company's previous experience of suspending natural
gas programs in 1997, Avista committed to reinstitute natural gas programs when and if
natural gas avoided costs increased to a level sufficient to field a cost-effective portfolio.
Due to the inability to offer a TRC cost-effective portfolio, in Idaho, Avista received
approval for the suspension of the natural gas DSM portfolio.
The Washington Utilities and Transportation Commission responded to Avista’s request
to suspend its natural gas DSM portfolio by initiating a rulemaking proceeding.1 After
much discussion and process, at the direction of the Commission, the Company
withdrew its filing and applied the Program Administrator Cost (PAC) test (also known
as the Utility Cost Test) in place of the TRC test. The PAC cost-effectiveness test takes
the perspective of managing only the customer’s utility bill through efficiency programs
1 Docket No. UG-121207 - The result of this rulemaking was a Policy Statement on the “Evaluation of the
Cost-Effectiveness of Natural Gas Conservations Programs.”
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J. Morehouse, Avista
Schedule 1, P. 47 of 152
Chapter 3: Demand-Side Resources

and not the customers total cost of energy. It does this by excluding from consideration
the customer’s incremental investment in purchasing efficiency beyond incentives paid
by the utility. Since incentives are almost invariably only part of the incremental cost
associated with efficiency measures, the restricted cost definition of the PAC test leads
to higher benefit-to-cost ratios. Avista found it necessary to reduce financial incentives,
but was able to design a DSM portfolio anticipated to be cost-effective under the more
narrowly defined PAC test.
Avista’s Oregon DSM portfolio is distinctly separate from the portfolios offered in the
Washington and Idaho jurisdictions. In September of 2012, Avista filed to suspend
certain programs and modify many others within its Oregon DSM portfolio for the same
reasons it did so in Washington and Idaho. However, on April 30, 2013 the Oregon
Public Utility Commission granted a two-year exception period for Avista to identify and
implement strategies that could potentially have a significant impact on the cost-
effectiveness of the DSM portfolio in a low avoided cost environment. Many of these
strategies have been completed and more are in-progress with favorable impacts upon
the cost-effectiveness performance to date.

Conservation Potential Assessment Methodology
Avista engaged EnerNOC (now Applied Energy Group) to perform an independent
evaluation of the technical, economic and achievable DSM potential within each of
Avista’s three jurisdictions over a 20-year planning horizon. This process involves
indexing existing nationally recognized Conservation Potential Assessment (CPA)
models to the Avista service territory load forecast, housing stock, end-use saturations
and other key characteristics. Additional consideration of the impact of energy codes
and appliance standards for end-use equipment at both the state and national level are
incorporated into the projection of energy use and the baseline for the evaluation of
efficiency options. The modeling process also utilizes ramp rates for the acquisition of
efficiency resources over time in a manner generally consistent with the assumptions
used by the Northwest Power Planning Council. This includes adjusted ramp rates to
better align with Avista’s recent program accomplishments and adjusted in the later
years for some measures.
The process described above defines an Avista-specific supply curve for conservation
resources. Simultaneously, the avoided cost of natural gas consistent with serving the
full forecasted demand was defined as part of the SENDOUT® modeling of the Avista
system. The preliminary cost-effective conservation potential is determined by applying
the stream of annual natural gas avoided costs to the Avista-specific supply curve for
conservation resources. This quantity of conservation acquisition is then decremented
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J. Morehouse, Avista
Schedule 1, P. 48 of 152
Chapter 3: Demand-Side Resources

from the load, which the utility must serve, and the SENDOUT® model run against the
modified (reduced) load requirements. The resulting avoided costs are compared to
those obtained from the previous iteration of SENDOUT® avoided costs. This reiteration
process continues until the differential between the avoided cost streams of the most
recent and the immediately previous iteration becomes immaterial. At that point both
supply and demand side options are functioning from comparable (including a 10
percent preference for DSM resources) avoided costs and the resulting load is meeting
all load requirements.
Figure 3.1 is a graphical depiction of the previously described methodology used in the
presentation of this methodology to the TAC.

Figure 3.1 – Integration of DSM into the IRP Process

Integrating the DSM portfolio into the IRP process by equilibrating the avoided costs in
this iterative process is useful since Avista’s DSM acquisition is small relative to the total
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 49 of 152
Chapter 3: Demand-Side Resources

western natural gas market used to establish the commodity prices driving the avoided
cost stream. Therefore, few iterations are necessary to reach a stable avoided cost.
Additionally it provides some assurance, at least at the aggregate level, that the quantity
of DSM resource selected will be cost-effective when the final avoided cost stream is
used in retrospective portfolio evaluation.
It should be noted that, based upon guidance provided by the Washington Commission,
and as previously explained, the cost-effectiveness metric applied in developing the
Washington DSM supply curve was the PAC test rather than the TRC test used in past
IRP evaluations of Washington and continues to be used in the Idaho and Oregon
jurisdictions. The PAC tests narrower definition of costs led to proportionately higher
DSM acquisition targets within the Washington jurisdiction.

Environmental Externalities
The gathering, transmission, distribution and end-use of natural gas involve some
inherent environmental costs that are not necessarily borne by the parties to the
transaction or the user of the resource. These costs are externalities since they
represent those costs that are external to the parties involved in the transaction. It is
difficult to quantify the value of these externalities since they are borne by individuals
within society who may drastically differ on the value that they place on the absence of
these impacts. Furthermore, there are no well-defined markets for measuring the
economic impact of these externalities.
This IRP intends to consider the full cost of the resources acquired by the utility and
used by customers in the resource selection process. Towards that end, Avista
incorporates a DSM preference in recognition of the lower environmental externality
cost incurred when efficiency resources meet customer end-use needs rather than
supply resources. The CPA incorporates this preference by increasing the avoided cost
used to determine if DSM resources are within 10 percent of being cost-effective. By
artificially increasing the avoided cost price signal, DSM measures that would not
otherwise pass the cost-effectiveness test are accepted into the optimized DSM
portfolio and incorporated within the acquisition target. This preference for DSM
resources is separate from, and in addition to, any quantifiable non-energy impacts
(generally benefits) that Avista is able to quantify for inclusion as an efficiency resource
option benefit within the TRC cost-effectiveness test.

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 50 of 152
Chapter 3: Demand-Side Resources

Conservation Potential Assessment Findings
Prior to the development of potential estimates, EnerNOC created a baseline end-use
forecast to quantify the use of natural gas by end-use, in the base year, and projections
of consumption in the future in the absence of utility programs and naturally occurring
conservation. The end-use forecast includes the relatively certain impacts of codes and
standards that will unfold over the study timeframe. All such mandates that were defined
as of January 2013 are included in the baseline. The baseline forecast is the foundation
for the analysis of savings from future DSM efforts as well as the metric against which
potential savings are measured.
Inputs to the baseline forecast include current economic growth forecasts, natural gas
price forecasts, trends in fuel shares and equipment saturations developed by
EnerNOC, existing and approved changes to building codes and equipment standards,
and Avista’s internally developed load forecast.
According to the CPA completed for Avista, the residential sector natural gas
consumption for all end uses and technologies increases primarily due to the projected
1.0 percent annual growth in the number of households, but also due to the slight
increase in the average home size. Other heating, which includes unit wall heaters and
miscellaneous loads, have a relatively high growth rate compared to other loads.
However, at the end of the 20-year planning period these loads represent only a small
part of overall natural gas use.
For the commercial and industrial sectors, natural gas use continues to grow slowly
over the 20-year planning horizon as new construction increases the overall square
footage in this sector. Growth in heating, ventilation and air conditioning (HVAC) and
water heating end uses is moderate. Food preparation, though a small percentage of
total usage, grows at a higher rate than other end uses. Consumption by miscellaneous
equipment and process heating are also projected to increase.
Table 3.1 illustrates the system-wide baseline forecast of natural gas use across all
sectors for selected years to include the baseline year, annually for the years to the next
IRP cycle, and selected years thereafter. This baseline increases by 11 percent over the
20-year planning horizon corresponding to an annualized growth of 0.5 percent. Overall,
the forecast projects steady growth over the next 20 years with growth in the residential
sector making up for the decrease in industrial sector sales. Idaho is projected to
experience the highest level of growth, with Oregon having the next highest level of
growth.

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 51 of 152
Chapter 3: Demand-Side Resources

Table 3.1 Baseline Forecast Summary (1,000’s of therms)
Sector 2013 2015 2016 2019 2024 2034 % Change
(2013-2034)
Avg.
Growth
Rate
(2013-
2034)
Residential 199,115 197,496 199,264 204,876 206,391 232,976 17% 0.7%
Commercial 126,489 126,009 127,191 129,099 127,577 129,402 2% 0.1%
Industrial 5,015 5,252 5,524 5,867 5,477 4,491 -10% -0.5%
Total 330,619 328,757 331,980 339,842 339,444 366,869 11% 0.5%

State 2013 2015 2016 2019 2024 2034 % Change
(2013-2034)
Avg.
Growth
Rate
(2013-
2034)
Washington 173,409 171,422 172,719 176,166 175,134 183,693 6% 0.3%
Idaho 76,250 77,988 79,291 82,207 82,739 91,603 20% 0.9%
Oregon 80,960 79,346 79,969 81,469 81,571 91,574 13% 0.6%
Total 330,619 328,757 331,980 339,842 339,444 366,869 11% 0.5%

The next step in the study is the development of the three types of potential: technical,
economic and achievable. Technical potential is the theoretical upper limit of
conservation potential. This assumes that all customers replace equipment with the
most efficient option available and adopt the most efficient energy use practices
possible at every opportunity without regard to cost-effectiveness. Economic potential
represents the adoption of all cost-effective conservation measures based on the TRC
test in Idaho and Oregon and the PAC test in Washington. The achievable potential
takes into account market maturity, customer preferences for energy efficiency
technologies and expected program participation. Achievable potential establishes a
realistic target for conservation savings that a utility can expect to achieve through its
efficiency programs.
DSM measures that achieve generally uniform year round energy savings independent
of weather are considered base load measures. Examples include high efficiency water
heaters, cooking equipment and front load clothes washers. Weather sensitive
measures are those which are influenced by HDD factors and include higher efficiency
furnaces, ceiling/wall/floor insulation, weather stripping, insulated windows, duct work
improvements (tighter sealing to reduce leaks) and ventilation heat recovery systems
(capturing chimney heat). Weather sensitive measures are often referred to as winter
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 52 of 152
Chapter 3: Demand-Side Resources

load shape measures and are typically valued using a higher avoided cost (due to
summer to winter pricing differentials) while base load measures (often called annual
load shape measures) are valued at a lower avoided cost.
Avista offers conservation measures to residential, non-residential and low-income
customers.2 Measures offered to residential customers are almost universally on a
prescriptive basis, meaning they have a fixed incentive for all customers and do not
require individual pre-project analysis by the utility. Low income customers are treated
with a more flexible approach through cooperative arrangements with participating
Community Action Agency partnerships. Non-residential customers have access to
prescriptive and site-specific conservation measures. Site-specific measures
customized to specific applications have cost and therm savings unique to the individual
facility.
In Oregon, some conservation measures are legally required and therefore their costs
and benefits become part of the portfolio without being subject to cost-effectiveness
testing. These measures, for example, include energy audits that do not in and of
themselves generate energy savings absent customer action and the timing and cost-
effectiveness of the action(s) taken by the customer are uncertain.
See Table 3.2 for residential, commercial and industrial measures evaluated in this
study for all three states.

2 For purposes of tables, figures and targets, low-income is a subset of residential class.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 53 of 152
Chapter 3: Demand-Side Resources

Table 3.2 Conservation Measures

Residential Measures Commercial and Industrial Measures
Furnace – Maintenance Furnace – Maintenance
Boiler – Pipe Insulation Boiler – Maintenance Insulation – Ducting Boiler – Hot Water Reset
Insulation – Infiltration Control Boiler – High Efficiency Hot Water Circulation Insulation – Ceiling Space Heating – Heat Recovery Ventilator
Insulation – Wall Cavity Insulation – Ducting Insulation – Attic Hatch Insulation – Ceiling
Insulation – Foundation (new only) Insulation – Wall Cavity Ducting – Repair and Sealing Ducting – Repair and Sealing
Doors – Storm and Thermal Windows – High Efficiency Windows – ENERGY STAR Energy Management System
Thermostat – Clock/Programmable Thermostat – Clock/Programmable Water Heating – Faucet Aerators Water Heating – Faucet Aerators
Water Heating – Low Flow Showerheads Water Heating – Pipe Insulation Water Heating – Pipe Insulation Water Heating – Tank Blanket/Insulation
Water Heating – Tank Blanket/Insulation Water Heating – Hot Water Saver Water Heating – Thermostat Setback Advanced New Construction Designs (new only)
Water Heating – Timer Comprehensive Commissioning Water Heating – Hot Water Saver Process – Boiler Hot Water Reset (industrial only)
Water Heating – Drain Water Heat Recovery (new only)
Home Energy Management System Advanced new Construction Designs (new only)
ENERGY STAR Homes (new only)

Conservation Potential Assessment Results
Based upon the previously described methodology and baseline forecasts, EnerNOC
developed technical, economic and achievable potentials by jurisdiction and segment
over a 20-year horizon.
The technical potential for Avista’s service territory for the 20-year IRP period reaches
46.5 percent of the baseline end-use forecast. This would be the full DSM potential
without regard for cost effectiveness.
Economic potential applies the cost-effectiveness metric appropriate to each jurisdiction
to measures identified within the technical potential and quantifies the impact of the
adoption of cost-effective DSM measures. By the end of the 20-year timeframe, this
represents 13.5 percent of the baseline energy forecast. The significant difference
between the technical and economic potential is a reflection of the economic impact of
falling natural gas avoided costs as well as the market saturation achieved in previous
years with higher prevailing natural gas avoided costs. Past adoption of the most cost-
effective measures leads to progressively higher costs for the remaining measures. At
the same time the avoided cost value of these future adoptions is falling.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 54 of 152
Chapter 3: Demand-Side Resources

The achievable potential across the residential, commercial and industrial sectors,
incorporating ramp rates derived from the Northwest Power and Conservation Council,
is 10.1 percent of the baseline energy forecast by the end of 2034.
Tables 3.3 and 3.4 summarize cumulative conservation for each potential type for
selected years across the 20-year CPA and IRP horizon. Initially, the large commercial
sector provides a relatively higher percentage of the achievable savings compared with
its share of sales, but this situation reverses so the residential sector’s share of savings
is the greatest due to growth in residential customer count. Please refer to the natural
gas CPA provided in Appendix 3.1 for more details.

Table 3.3 Summary of Cumulative Achievable, Economic and Conservation Potential
2015 2016 2019 2024 2034
Baseline projection (1,000’s of Therms) 328,757 331,980 339,842 339,444 366,869
Cumulative Natural Gas Savings (1,000’s of Therms)
Achievable Potential 1,677 2,639 9,890 20,615 36,887
Economic Potential 4,152 5,877 17,371 32,580 49,566
Technical Potential 12,512 19,298 53,433 100,103 170,543
Cumulative Natural Gas as a percentage of Baseline
Achievable Potential 0.5% 0.8% 2.9% 6.1% 10.1%
Economic Potential 1.3% 1.8% 5.1% 9.6% 13.5%
Technical Potential 3.8% 5.8% 15.7% 29.5% 46.5%

The overall achievable potential is presented first by state and then by sector in Table
3.4.

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 55 of 152
Chapter 3: Demand-Side Resources

Table 3.4 Summary of Cumulative Achievable Potential by State and Sector
Cumulative Savings
(1,000’s of Therms) 2015 2016 2019 2024 2034
Washington 1,287 2,024 7,781 15,822 26,997
Idaho 228 342 1,029 2,316 4,504
Oregon 161 272 1,080 2,477 5,386
Total 1,677 2,639 9,890 20,615 36,887
Cumulative Savings
(1,000’s of Therms) 2015 2016 2019 2024 2034
Residential 384 727 5,279 10,154 15,957
Small Commercial 296 480 1,400 3,286 6,924
Large Commercial 969 1,390 3,085 6,907 13,599
Industrial 27 42 126 268 407
Total 1,677 2,639 9,890 20,615 36,887

Figure 3.1 illustrates the impact of the DSM potential forecast upon the end-use
baseline absent any DSM acquisition. By the end of the 20-year period, the achievable
potential (indicated by the light blue line) offsets 102 percent of the growth in the
baseline forecast for the Avista service territory. This is in part the consequence of low
load growth as well as the higher level of achievable DSM identified within Washington
(Avista’s largest jurisdiction) using the more generous PAC cost-effectiveness test
metric.

Figure 3.1 - Conservation Potential Energy Forecast (1000’s of therms)

Energy
Consumption
(1,000Thrm)
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J. Morehouse, Avista
Schedule 1, P. 56 of 152
Chapter 3: Demand-Side Resources

Residential Potential Results
Single-family homes represent 78 percent of Avista’s residential natural gas customers,
but account for 83 percent of the sector’s consumption in the study base year 2013. The
state of Washington is a disproportionate quantity of the savings since the target
acquisition relies on the PAC test while Oregon and Idaho relies on the TRC test.
Table 3.5 provides a distribution of achievable potential by state for the residential
sector.

Table 3.5 – Residential Cumulative Achievable Potential by State, Selected Years
2015 2016 2019 2024 2034
Baseline Projection (1,000’s of Therms)
Washington 101,488 102,205 105,064 105,708 116,970
Idaho 46,978 47,633 49,224 49,670 58,109
Oregon 49,029 49,426 50,589 51,012 57,897
Total 197,496 199,264 204,876 206,391 232,976
Natural Gas Cumulative Savings (1,000’s of Therms)
Washington 370 682 4,643 8,898 13,676
Idaho 6 18 261 493 875
Oregon 8 27 375 763 1,405
Total 384 727 5,279 10,154 15,957
% of Total Residential Savings
Washington 96% 94% 88% 88% 86%
Idaho 1% 3% 5% 5% 5%
Oregon 2% 4% 7% 8% 9%

Most residential potential exists in space heating end-uses and water heating
applications. Appliances and miscellaneous end-use loads contribute a small
percentage of potential. Based on measure-by-measure finding of the potential study
the greatest sources of residential achievable potential across all three jurisdictions are:
 Shell measures and insulation.
 Thermostats and home energy monitoring systems.
 Water-saving devices, such as low-flow showerheads and faucet aerators.
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J. Morehouse, Avista
Schedule 1, P. 57 of 152
Chapter 3: Demand-Side Resources

 Water heater tank blankets and pipe insulation.

Commercial and Industrial Potential Results
The baseline forecast for the commercial and industrial sector grows steadily during the
forecast period. Consequently, energy efficiency opportunities are significant for this
sector. However, similar to the residential sector, the historically low avoided cost
projections limit the achievable potential.
The large commercial sector provides the greatest opportunities for savings. Although
potential as a percentage of baseline use varies from one sector to the next, results do
not vary greatly among the three states under the TRC test; Washington has higher
savings due to using the PAC cost effectiveness test. Tables 3.6 and 3.7 show the
commercial and industrial achievable potential by sector for selected years.

Table 3.6 – Commercial and Industrial Cumulative Achievable Potential by Selected Years
2015 2016 2019 2024 2034
Baseline projection (1,000’s of Therms)
Small Commercial 51,170 51,514 51,931 50,861 52,475
Large Commercial 74,839 75,677 77,168 76,716 76,927
Industrial 5,252 5,524 5,867 5,477 4,491
Total 178,239 180,349 184,098 182,156 189,882
Natural Gas Savings (1,000’s of Therms)
Small Commercial 296 480 1,400 3,286 6,924
Large Commercial 969 1,390 3,085 6,907 13,599
Industrial 27 42 126 268 407
Total 1,292 1,912 4,611 10,461 20,930
% of Total Commercial and Industrial Savings
Small Commercial 23% 25% 30% 31% 33%
Large Commercial 75% 73% 67% 66% 65%
Industrial 2% 2% 3% 3% 2%

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 58 of 152
Chapter 3: Demand-Side Resources

Table 3.7 – Commercial and Industrial Cumulative Achievable Potential by State, Selected
Years
Cumulative Savings
(1,000’s of Therms) 2015 2016 2019 2024 2034
Washington 917 1,343 3,138 6,924 13,321
Idaho 223 324 768 1,824 3,629
Oregon 153 245 705 1,714 3,981
Total 1,292 1,912 4,611 10,461 20,930
Cumulative Natural Gas Savings (% of Statewide Baseline)
Washington 1.3% 1.9% 4.4% 10.0% 20.0%
Idaho 0.7% 1.0% 2.3% 5.5% 10.8%
Oregon 0.5% 0.8% 2.3% 5.6% 11.8%
Total 1.0% 1.4% 3.4% 7.9% 15.6%

Similar to residential sector, most of the commercial and industrial potential exists in
space and water heating applications. Food preparation, process and miscellaneous
represents a smaller proportion of potential. Primary sources of commercial and
industrial sector achievable savings are:
 Energy management systems and programmable thermostats.
 Boiler operating measures such as maintenance.
 Hot water reset and efficient circulation.
 Equipment upgrades for furnaces, boilers and unit heaters.
 Food service equipment.

Aggregate Potential Results
The following three tables provide the 2015-2016 CPA identified DSM opportunities for
Idaho, Oregon and Washington, respectively.

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 59 of 152
Chapter 3: Demand-Side Resources

Table 3.8 – Idaho Natural Gas Savings Target (2015-2016)
Incremental Annual Savings
(1,000’s of Therms) 2015 2016
Residential 6 13
Commercial & Industrial 223 101
Total 228 114

Table 3.9 – Oregon Natural Gas Savings Target (2015-2016)
Incremental Annual Savings
(1,000’s of Therms) 2015 2016
Residential 8 19
Commercial & Industrial 153 92
Total 161 111

Table 3.10 – Washington Natural Gas Savings Target (2015-2016)
Incremental Annual Savings
(1,000’s of Therms) 2015 2016
Residential 370 311
Commercial & Industrial 917 426
Total 1,287 737

CPA Uses and Applications
It is useful to place the IRP process, and the CPA component of that process, into the
larger perspective of Avista’s efforts to acquire all available cost-effective DSM
resources. Those activities outside the immediate scope of the IRP process include the
formal annual business planning and annual cost-effectiveness and acquisition
reporting processes, in addition to the ongoing management of the DSM portfolio.
The IRP process establishes a 20-year avoided cost stream that is essential not only to
determining the quantity of DSM resources that are cost-effective when compared to the
CPA-identified DSM supply curve, but also and perhaps more importantly the
management of the DSM portfolio between the two-year IRP cycles. The avoided costs
are critical to the selection and optimization of DSM delivery options on a real-time basis
and as part of a comprehensive annual business planning process. The IRP-identified
avoided costs also serve as the foundation for calculating the portfolios actual cost-
effectiveness performance as part of Avista’s retrospective DSM Annual Report.
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J. Morehouse, Avista
Schedule 1, P. 60 of 152
Chapter 3: Demand-Side Resources

These related and coordinated processes contribute to the planning and management
of the DSM portfolio towards meeting its cost-effectiveness and acquisition goals.
The relationship between the CPA and the annual business planning process is of
particular note. The CPA is a high-level tool useful for establishing aggregate targets
and identifying general target markets and target measures. However, the CPA must
make certain broad assumptions regarding key characteristics that are fine-tuned in the
operational business plan. Some of the most frequently modified assumptions include
market segmentation, customer eligibility, measure definition, incentive level, interaction
between measures and opportunities for packaging measures or coordinating the
delivery of measures.
The increased level of detail in the operational business planning process generally
improves the cost-effectiveness of the individual measures and the overall portfolio.
Eligibility and measure definitions can be fine-tuned to target the most cost-effective
elements of a measure in such a way that marginally cost-ineffective measures can be
become cost-effective contributors to the portfolio. However, it can also be true that the
high-level assumptions made as part of the CPA may be overly optimistic when applied
to individual programs.
One issue that inevitably arises when moving from the CPA to the business planning
process is the treatment of market segments. The CPA defines market segments (e.g.
by residential building type or vintage) to appropriately define the cost-effective potential
for efficiency options and to ensure consistency with system loads and load forecasts.
However, it is often infeasible to recognize these distinctions on an operational basis.
This may result in aggregations of market segments into programs that could lead to
more or less operationally achievable savings.
The continuation of the downward trend in natural gas avoided cost expectations is
causing a growing deviation between the CPA and business planning process. CPA
processes generally make the simplifying assumption that non-incentive utility costs are
a constant percentage of the customer’s incremental cost or of the offered incentive.
Operationally there may be fixed and incremental components to these non-incentive
costs and there may be economies of scale when enlarging the size of the portfolio (or
conversely diseconomies of scale when the portfolio decreases due to lower avoided
costs). CPA processes often function at too high of a level to recognize these
operational details and are unable to predict the point at which the quantity of cost-
effective DSM and the cost-effectiveness margin associated with those measures are
insufficient to offset fixed portfolio costs and diseconomies of scale. These challenges
are more appropriately left to the operational business planning processes.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 61 of 152
Chapter 3: Demand-Side Resources

Conclusion
Avista has a long-term commitment to responsibly pursuing all available and cost-
effective efficiency options as an important means to reduce customer’s energy costs.
Cost-effective DSM options are a key element in Avista’s strategy to meet those
commitments. Falling avoided costs and low growth in customer demand have led to a
reduced role for DSM in the natural gas portfolio, although as a consequence of the
lower growth and the change in the cost-effectiveness metric applicable to the
Washington jurisdiction, DSM greatly offset future load growth.
Avista is working to optimize how natural gas efficiency resource acquisition under this
radically different economic environment. Important factors that must be considered
within this optimization include:
 The criteria for adopting measures within the portfolio.
 The nature of Avista’s non-incentive utility cost.
 The level of incentives established with particular attention to their implications
upon the PAC test performance.
 Alternative means of moving cost-effective efficiency options forward.
In June 2014, Avista will begin developing the Washington and Idaho 2015 DSM
Business Plan. This process is an opportunity to review the electric and natural gas
DSM portfolios and perform the optimizations noted above. Within Washington, where
the PAC test is being applied to this optimization process, there will be a review of the
customer financial incentives to determine if the lower avoided costs are sufficient to
support existing incentive levels. The Idaho portfolio review will determine if there are
new opportunities that would allow a TRC cost-effective portfolio offering.
In Oregon the on-going optimization of the DSM portfolio has led to significant
improvements in TRC cost-effectiveness performance in 2013, though revised unit
energy savings may make it difficult to deliver the same level of performance in 2014.
Nevertheless, there is a favorable trend occurring in the cost-effectiveness of the non-
mandated portfolio components.
Perhaps of most importance in the long-term are Avista’s ongoing efforts to work with
others to develop a regional natural gas market transformation organization and
portfolio. This concept has been developing for nearly a decade, but current
circumstances have moved the discussion closer to the realization of such an
organization. Regional natural gas utilities are actively working with the Northwest
Energy Efficiency Alliance (NEEA) to develop a proposal for a natural gas market
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
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Chapter 3: Demand-Side Resources

transformation entity similar to the electric market transformation efforts. The viability of
market transformation efforts are likely to be less impacted by falling avoided costs
since they focus upon technologies and markets where strategically selected market
transformation interventions can have a disproportionate impact upon markets for
efficient products and services. This makes market transformation a valuable tool in a
lower avoided cost environment.
The CPA does not specify market transformation since it focuses on conservation
potential without regard to how that potential is achieved. The prospect for a regional
market transformation entity will potentially bring a valuable tool in working towards the
achievement of the cost-effective conservation opportunities identified in the CPA.
Avista is also working with regional natural gas utilities on an ad hoc natural gas heat
pump water heater technology pilot in anticipation of a future market transformation
portfolio. The progress and prospective funding of this venture is a favorable indication
that a cooperative regional market transformation effort is viable.
Avista anticipates that a proposal for a permanent natural gas market transformation
organization will advance for regional discussion by the end of 2014. It is hoped that
successes in this area will augment cost-effective local efforts and create additional
local programmatic DSM opportunities.

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 63 of 152
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Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 64 of 152
Chapter 4: Supply-Side Resources

4: Supply-Side Resources

Overview
Avista analyzed a range of future demand scenarios and possible cost-effective
conservation measures to reduce demand. This chapter discusses supply options to
meet net demand. Avista’s objective is to provide reliable natural gas to customers with
an appropriate balance of price stability and prudent cost under changing market
conditions. To achieve this objective, Avista evaluates a variety of supply-side
resources and attempts to build a diversified natural gas supply portfolio. The resource
acquisition and commodity procurement programs resulting from the evaluation
consider physical and financial risks, market-related risks, and procurement execution
risks; and identify the methods to mitigate these risks.
Avista manages natural gas procurement and related activities on a system-wide basis
with several regional supply options available to serve core customers. Supply options
include firm and non-firm supplies, firm and interruptible transportation on six interstate
pipelines, and storage. Because Avista’s core customers span three states, the diversity
of delivery points and demand requirements adds to the options available to meet
customers’ needs. The utilization of these components varies depending on demand
and operating conditions. This chapter discusses the available regional commodity
resources and Avista’s procurement plan strategies, the regional pipeline resource
options available to deliver the commodity to customers, and the storage resource
options available to provide additional supply diversity, enhanced reliability, favorable
price opportunities, and flexibility to meet a varied demand profile. Non-traditional
resources are also considered.

Commodity Resources

Supply Basins Avista is fortunate to be located near the two largest natural gas producing regions in
North America – the Western Canadian Sedimentary Basin (WCSB), located in the
Canadian provinces of Alberta and British Columbia, and the Rocky Mountain (Rockies)
gas basin, located in Wyoming, Utah and Colorado. Avista sources most of its natural
gas supplies from these two basins.
Several large pipelines connect the WCSB and Rockies gas basins to the Pacific
Northwest, Southwest, Midwest and Northeast sections of the continent. Historically,
natural gas supplies from the WCSB and Rockies cost less relative to other parts of the
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country. Shale gas production from the Northeast has altered flow dynamics and helped
sustain the regional pricing discount. Forecasts show a long-term regional price
advantage for WCSB and Rockies basins as the need for these supplies in the East
diminishes as more shale gas supply develops in the East.
Increased availability of North American natural gas has prompted a change in the
global LNG landscape. Excess supply has prompted LNG developers to consider
exporting natural gas to capture higher prices in the Asian and European markets.
Regionally, there are two proposed projects in Oregon - Jordan Cove and Oregon LNG.
Jordan Cove and Oregon LNG have each received their FERC export authorization.
There are 16 announced export LNG projects in British Columbia. While there is much
uncertainty about the number of completed facilities, the bigger question is the impact of
exports on regional infrastructure and prices.

Regional Market Hubs
There are numerous regional market hubs where natural gas is traded extending from
the two primary basins. These regional hubs are typically located at pipeline
interconnects. Avista is located near and transacts at most of the Pacific Northwest
regional market hubs, enabling flexible access to several supply points. These supply
points include:
 AECO – The AECO-C/Nova Inventory Transfer market center located in Alberta
is a major connection region to long-distance transportation systems, which take
natural gas to points throughout Canada and the United States. Alberta is the
major Canadian exporter of natural gas to the U.S. and historically produced 90
percent of Canada's natural gas.
 Rockies – This pricing point represents several locations on the southern end of
the NWP system in the Rocky Mountain region. The system draws on Rocky
Mountain natural gas-producing areas clustered in areas of Colorado, Utah and
Wyoming.
 Sumas/Huntingdon – This pricing point at Sumas, Washington, is on the
U.S./Canadian border where the northern end of the NWP system connects with
Spectra Energy’s Westcoast Pipeline and predominantly markets Canadian gas
from Northern British Columbia.
 Malin – This pricing point is at Malin, Oregon, on the California/Oregon border
where the pipelines of TransCanada Gas Transmission Northwest (GTN) and
Pacific Gas & Electric Company connect.
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 Station 2 – Located at the center of the Spectra Energy/Westcoast Pipeline
system connecting to northern British Columbia natural gas production.
 Stanfield – Located near the Washington/Oregon border at the intersection of
the NWP and GTN pipelines.
 Kingsgate – Located at the U.S./Canadian (Idaho) border where the GTN
pipeline connects with the TransCanada Foothills pipeline.
Given the ability to transport natural gas across North America, natural gas pricing is
often compared to the Henry Hub price for natural gas. Henry Hub, located in Louisiana,
is the primary natural gas pricing point in the U.S. and is the trading point used in
NYMEX futures contracts.
Figure 4.1 shows historic natural gas prices for first-of-month index physical purchases
at AECO, Sumas, Rockies and Henry Hub. The figure illustrates there is usually a tight
relationship among the regional market hubs; however, there have been periods where
one or more price points have disconnected.

Figure 4.1: Monthly Index Prices

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Northwest regional natural gas prices typically move together; however, the basis
differential can change depending on market or operational factors. This includes
differences in weather patterns, pipeline constraints, and the ability to shift supplies to
higher-priced delivery points in the U.S. or Canada. By monitoring these price shifts,
Avista can often purchase at the lowest-priced trading hubs on a given day, subject to
operational and contractual constraints.
Liquidity is generally sufficient in the day-markets at most Northwest supply points.
AECO continues to be the most liquid supply point, especially for longer-term
transactions. Sumas has historically been the least liquid of the four major supply points
(AECO, Rockies, Sumas and Malin). This illiquidity contributes to generally higher
relative prices in the high demand winter months.
Avista procures natural gas via contracts. Contract specifics vary from transaction-to-
transaction, and many of those terms or conditions affect commodity pricing. Some of
the terms and conditions include:
 Firm vs. Non-Firm: Most term contracts specify that supplies are firm except for
force majeure conditions. In the case of non-firm supplies, the standard provision
is that they may be cut for reasons other than force majeure conditions.
 Fixed vs. Floating Pricing: The agreed-upon price for the delivered gas may be
fixed or based on a daily or monthly index.
 Physical vs. Financial: Certain counterparties, such as banking institutions,
may not trade physical natural gas, but are still active in the natural gas markets.
Rather than managing physical supplies, those counterparties choose to transact
financially rather than physically. Financial transactions provide another way for
Avista to financially hedge price.
 Load Factor/Variable Take: Some contracts have fixed reservation charges
assessed during each of the winter months, while others have minimum daily or
monthly take requirements. Depending on the specific provisions, the resulting
commodity price will contain a discount or premium compared to standard terms.
 Liquidated Damages: Most contracts contain provisions for symmetrical
penalties for failure to take or supply natural gas.
For this IRP, the SENDOUT® model assumes natural gas purchases under a firm,
physical, fixed-price contract, regardless of contract execution date and type of contract.
Avista pursues a variety of contractual terms and conditions to capture the most value
for customers. Avista‘s natural gas buyers actively assess the most cost-effective way
to meet customer demand and optimize unutilized resources.
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J. Morehouse, Avista
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Chapter 4: Supply-Side Resources

Avista’s Procurement Plan
No company can accurately predict future natural gas prices, but market conditions and
experience help shape the overall approach. Avista’s natural gas procurement plan
process seeks to acquire natural gas supplies while reducing exposure to short-term
price volatility. The procurement strategy includes hedging, storage utilization and index
purchases. Although the specific provisions of the procurement plan will change based
on ongoing analysis and experience, the following principles guide Avista’s procurement
plan.
Avista employs a time, location and counterparty diversified hedging strategy. It
is appropriate to hedge over a period and establish hedge periods when portions of
future demand are physically and/or financially hedged. Avista views hedging as an
appropriate part of a diversified procurement plan and provides a level of known pricing
and stability to customers. Hedges may not be at the lowest possible price, but they still
protect customers from price volatility. With access to multiple supply basins, Avista
transacts with the lowest priced basin at the time of the hedge. Furthermore, Avista
transacts with a range of counterparties to spread supply among a wider range of
market participants.
Avista uses a disciplined, but flexible hedging approach. In addition to establishing
periods when hedges are to be completed, Avista also sets upper and lower pricing
points. This reduces Avista’s exposure to extreme price spikes in a rising market and
encourages capturing the benefit associated with lower prices.
Avista regularly reviews its procurement plan in light of changing market
conditions and opportunities. Avista’s plan is open to change in response to ongoing
review of the procurement plan assumptions. Even though the initial plan establishes
various targets, policies provide flexibility to exercise judgment to revise targets in
response to changing conditions.
Avista utilizes a number of tools to help mitigate financial risks. Avista purchases gas in
the spot market and forward markets. Spot purchases are for the next day or weekend.
Forward purchases are for future delivery. Many of these tools are financial instruments
or derivatives that can provide fixed prices or dampen price volatility. Avista continues to
evaluate how to manage daily demand volatility, whether through option tools from
counterparties or through access to additional storage capacity and/or transportation.

Market-Related Risks and Risk Management
There are several definitions of risk management. The IRP focuses on two areas of risk:
the financial risk where the cost to supply customers will be unreasonably high or
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Chapter 4: Supply-Side Resources

volatile, and the physical risk that there may not be enough natural gas resources
(either transportation capacity or the commodity) to serve core customers.
Avista’s Risk Management Policy describes the policies and procedures associated with
financial and physical risk management. The Risk Management Policy addresses
issues related to management oversight and responsibilities, internal reporting
requirements, documentation and transaction tracking, and credit risk.
Two internal organizations assist in the establishment, reporting and review of Avista’s
business activities as they relate to management of natural gas business risks:
 The Risk Management Committee includes corporate officers and senior-level
management. The committee establishes the Risk Management Policy and
monitors compliance. They receive regular reports on natural gas activity and
meet regularly to discuss market conditions, hedging activity and other natural
gas-related matters.
 The Strategic Oversight Group coordinates natural gas matters among internal
natural gas-related stakeholders and serves as a reference/sounding board for
strategic decisions, including hedges, made by the Natural Gas Supply
department. Members include representatives from the Accounting, Regulatory,
Credit, Power Resources, and Risk Management departments. While the Natural
Gas Supply department is responsible for implementing hedge transactions, the
Strategic Oversight Group provides input and advice.

Transportation Resources
Although proximity to liquid market hubs is important from a cost perspective, supplies
are only as reliable as the pipeline transportation from the hubs to Avista’s service
territories. Capturing favorable price differentials and mitigating price and operational
risk can also be realized by holding multiple pipeline transport options. Avista contracts
for a sufficient amount of diversified firm pipeline capacity from various receipt and
delivery points (including storage facilities), so that firm deliveries will meet peak day
demand. This combination of firm transportation rights to Avista’s service territory,
storage facilities and access to liquid supply basins ensure peak supplies are available
to serve core customers.
The major pipelines servicing the region include:
 Williams - Northwest Pipeline (NWP)
A natural gas transmission pipeline serving the Pacific Northwest moving natural
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J. Morehouse, Avista
Schedule 1, P. 70 of 152
Chapter 4: Supply-Side Resources

gas from the U.S./Canadian border in Washington and from the Rocky Mountain
region of the U.S.
 TransCanada Gas Transmission Northwest (GTN): A natural gas transmission
pipeline originating at Kingsgate, Idaho, (Canadian/U.S. border) and terminating
at the California/Oregon border close to Malin, Oregon.
 TransCanada Alberta System: This natural gas gathering and transmission
pipeline in Alberta, Canada, delivers natural gas into the TransCanada Foothills
pipeline at the Alberta/British Columbia border.
 TransCanada Foothills System: This natural gas transmission pipeline delivers
natural gas between the Alberta, British Columbia, border and the Canadian/U.S.
border at Kingsgate, Idaho.
 TransCanada Tuscarora Gas Transmission: This natural gas transmission
pipeline originates at Malin, Oregon, and terminates at Wadsworth, Nevada.
 Spectra Energy - Westcoast Pipeline: This natural gas transmission pipeline
originates at Fort Nelson, British Columbia, and terminates at the Canadian/U.S.
border at Huntington, British Columbia/Sumas, Washington.
 El Paso Natural Gas– Ruby pipeline: This natural gas transmission pipeline
brings supplies from the Rocky Mountain region of the U.S. to interconnections
near Malin, Oregon.
Avista has contracts with all of the above pipelines (with the exception of Ruby Pipeline)
for firm transportation to serve our core customers. Table 4.1 details the firm
transportation/resource services contracted by Avista. These contracts are of different
vintages, thus different expiration dates; however, all have the right to be renewed by
Avista. This gives Avista and its customers the knowledge that Avista will have available
capacity to meet existing core demand now and in the future.

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Table 4.1: Firm Transportation Resources Contracted (Dth/Day)

Avista defines two categories of interstate pipeline capacity. “Direct-connect” pipelines
deliver supplies directly to Avista’s local distribution system from production areas,
storage facilities or interconnections with other pipelines. “Upstream” pipelines deliver
natural gas to the direct-connect pipelines from remote production areas, market
centers and out-of-area storage facilities. Figure 4.2 illustrates the direct-connect
pipeline network relative to Avista’s supply sources and service territories.1

1 Avista has a small amount of pipeline capacity with TransCanada Tuscarora Gas Transmission, a
natural gas transmission pipeline originating at Malin, Oreg., to service a small number of Oregon customers near the southern border of the state.
Firm Transportation/Resources Contracted*
Dth/Day

Firm Transportation Winter Summer Winter Summer
NWP TF-1 157,869 157,869 42,699 42,699
GTN T-1 100,605 75,782 42,260 20,640
NWP TF-2 91,200 2,623
Total 349,674 233,651 87,582 63,339
Firm Storage Resources - Max Deliverability
Jackson Prairie
(Owned and
Contracted)346,667 54,623
Total 346,667 54,623
* Represents original contract amounts after releases expire.
Avista Avista
North South
Table 5.1
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J. Morehouse, Avista
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Chapter 4: Supply-Side Resources

Figure 4.2: Direct-Connect Pipelines

Supply-side resource decisions focus on where to purchase natural gas and how to
deliver it to customers. Each LDC has distinctive service territories and geography
relative to supply sources and pipeline infrastructure. Solutions that deliver supply to
service territories among regional LDCs are similar but are rarely generic.
The NWP system, for the most part, is a fully-contracted system. With the exception of
La Grande, Avista’s service territories lie at the end of NWP pipeline laterals. The
Spokane, Coeur d’Alene and Lewiston laterals serve Washington/Idaho load, and the
Grants Pass lateral serves Roseburg and Medford. Capacity expansions of these
laterals would be lengthy and costly endeavors which Avista would likely bear most of
the incremental costs.
The GTN system currently has ample unsubscribed capacity. This pipeline runs directly
through or near most of Avista’s service territories. Mileage based rates provides an
attractive option for securing incremental resource needs.
Peak day planning aside, both pipelines provide an array of options to flexibly manage
daily operations. The NWP and GTN pipelines directly serve Avista’s two largest service
territories, providing diversification and risk mitigation with respect to supply source,
price and reliability. The NWP system (a bi-directional, fixed reservation fee-based
Roseburg
Medford
Stanfield
Washington / Idaho
SUMAS AECO
ROCKS
La Grande
MALIN
Klamath
Falls Roseburg &
Medford
Stanfield
NWP GTN
Washington/Idaho
LaGrande
JP
Storage
Malin
Klamath
Falls
AECO
Kingsgate
Station 2
Sumas
Rockies
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pipeline) provides direct access to Rockies and British Columbia supply and facilitates
optionality for storage facility management. The Stanfield interconnect of the two lines is
also geographically well situated to Avista’s service territories.
The rates used in the planning model start with filed rates currently in effect (See
Appendix 4.1). Forecasting future pipeline rates is challenging. Assumptions for future
rate changes are the result of market information on comparable pipeline projects, prior
rate case experience, and informal discussions with regional pipeline owners. Pipelines
will file to recover costs at rates equal to the GDP with adjustments made for specific
project conditions.
NWP and GTN also offer interruptible transportation services. Interruptible
transportation is subject to curtailment when pipeline capacity constraints limit the
amount of natural gas that may be moved. Although the commodity cost per dekatherm
transported is the same as firm transportation, there are no demand or reservation
charges in these transportation contracts. As the marketplace for release of
transportation capacity by the pipeline companies and other third parties has become
more prevalent, the use of interruptible transportation services has diminished. Avista
does not rely on interruptible capacity to meet peak day core demand requirements.
Avista's transportation acquisition strategy is to contract for firm transportation to serve
core customers on a peak day in the planning horizon. Since contracts for pipeline
capacity are often lengthy and core customer demand needs can vary over time,
determining the appropriate level of firm transportation is a complex analysis. The
analysis includes the projected number of firm customers and their expected annual and
peak day demand, opportunities for future pipeline or storage expansions, and relative
costs between pipelines and upstream supplies. This analysis is on an annual basis, as
well as through the IRP. Active management of underutilized capacity through the
capacity release market and engaging in optimization transactions offsets some
transportation costs. Timely analysis is also important in order to maintain an
appropriate time cushion to allow for required lead times should the need for securing
new capacity arise (See Chapter 5 for a more detailed description of the management
of underutilized pipeline resources).

Storage Resources
Storage is a valuable strategic resource that enables improved management of a highly
seasonal and varied demand profile. Storage benefits include:
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 Flexibility to serve peak period needs.
 Access to typically lower cost off-peak supplies.
 Reduced need for higher cost annual firm transportation.
 Improved utilization of existing firm transportation via off-season storage
injections.
 Additional supply point diversity.
While there are several storage facilities available to the region, Avista’s existing
storage resources consist solely of ownership and leasehold rights at the Jackson
Prairie Storage facility.

Jackson Prairie Storage
Avista is one-third owner, with NWP and Puget Sound Energy (PSE), of the Jackson
Prairie Storage Project for the benefit of its core customers in all three states. Jackson
Prairie Storage is an underground reservoir facility located near Chehalis, Washington
approximately 30 miles south of Olympia, Washington. The total working gas capacity of
the facility is approximately 25 Bcf. Avista’s current share of this capacity for core
customers is approximately 8.5 Bcf and includes 398,667 Dth of daily deliverability
rights. Besides ownership rights, Avista leased an additional 95,565 Dth of Jackson
Prairie capacity with 2,623 Dth of deliverability from NWP to serve Oregon customers.

Incremental Supply-Side Resource Options
Avista’s existing portfolio of supply-side resources provides a mix of assets to manage
demand requirements for average and peak day events. Avista monitors the following
potential resource options to meet future requirements in anticipation of changing
demand requirements. When considering or selecting a transportation resource, the
appropriate natural gas supply pairs with the transportation resource and the
SENDOUT® model prices the resources accordingly.

System Enhancements
Distribution planning plays a role in the IRP, but is not the primary focus. Distribution
works with supply to meet customer demand on average and peak days. Modifications,
enhancements or upgrades occur on the distribution system that are routine projects,
enhancing system reliability. However, in certain instances, Avista can facilitate
additional peak and base load-serving capabilities through a modification or upgrade of
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distribution facilities. These projects would enable more takeaway capacity from the
interstate pipelines. When resource deficiencies are identified, Gas Supply works with
distribution engineering to assess if the distribution system can facilitate additional take
away. These opportunities are geographically specific and require case-by-case study.
Costs of these types of enhancements are included in the context of the IRP. A more
detailed description of system enhancements (including both routine and non-routine)
are in Chapter 7 – Distribution Planning.

Capacity Release Recall
As discussed earlier, pipeline capacity not utilized to serve core customer demand is
available to sell to other parties or optimized through daily or term transactions.
Released capacity is generally marketed through a competitive bidding process and can
be on a short-term (month-to-month) or long-term basis. Avista actively participates in
the capacity release market with short-term and long-term capacity releases.
Avista assesses the need to recall capacity or extend a release of capacity on an on-
going basis. The IRP process also helps evaluate if or when to recall some or all long-
term releases.

Existing Available Capacity
In some instances, there is currently available capacity on existing pipelines. NWP’s
mainline is fully subscribed; however, GTN mainline has available capacity. There is
some uncertainty about the future capacity availability as the demand needs of utilities
and end-users vary across the region. Avista models access to the GTN capacity as an
option to meet our future demand needs.

GTN Backhauls
The GTN interconnection with the Ruby Pipeline has enabled GTN the physical
capability to provide a limited amount of firm back-haul service from Malin with minor
modifications to their system. Fees for utilizing this service are under the existing Firm
Rate Schedule (FTS-1) and currently include no fuel charges. Additional requests for
back-haul service may require additional facilities and compression (i.e., fuel).
This service can provide an interesting solution for Oregon customers. For example,
Avista can purchase supplies at Malin, Oregon and transport those supplies to Klamath
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Falls or Medford. Malin-based natural gas supplies typically include a higher basis
differential to AECO supplies, but are generally less expensive than the cost of forward-
haul transporting those traditional supplies south and paying the associated demand
charges. The GTN system is a mileage-based system, so Avista pays only a fraction of
the rate if it is transporting supplies from Malin to Medford and Klamath Falls. The GTN
system is approximately 612 miles long and the distance from Malin to the Medford
lateral is only about 12 miles.

New Pipeline Transportation Additional firm pipeline transportation resources are viable and attractive resource
options. However, determining the appropriate level, supply source and associated
pipeline path, costs and timing, and if existing resources will be available at the
appropriate time, make this resource difficult to analyze. Firm pipeline transportation
provides several advantages; it provides the ability to receive firm supplies at the
production basin, it provides for base-load demand, and it can be a low-cost option
given optimization and capacity release opportunities. Pipeline transportation also has
several drawbacks, including typically long-dated contract requirements, limited need in
the summer months (many pipelines require annual contracts), and limited availability
and/or inconvenient sizing/timing relative to resource need.
Pipeline expansions are typically more expensive than existing pipeline capacity and
often require long-term contracts. Even though expansions may be more expensive
than existing capacity, this approach may still provide the best option given that some of
the other options discussed in this section require matching pipeline transportation.
Expansions may also provide reliability or access to supply that cannot be obtained
through existing pipelines.
Several specific projects have been proposed for the region. The following summaries
describe these projects while Figure 4.3 illustrates their location.

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Figure 4.3: Proposed Pipeline Locations



 NWP Washington Expansion
NWP continues to explore options to expand service from Sumas, Wash., to
markets along the Interstate-5 corridor. Looping sections of 36-inch diameter
pipeline with the existing pipeline and additional compression at existing
compressor stations can add incremental capacity. Actual miles of pipe and
incremental compression will determine the amount of capacity created, but it
can scale to meet market demand. This project is currently under FERC review.
 Northwest Market Access Expansion (N-MAX)/Palomar Expansion
NWP began working with Palomar Gas Transmission (a partnership between NW
Natural and TransCanada) to develop the Cascade (eastern) section of the
previously proposed Palomar gas transmission line in conjunction with an
expansion of NWP’s existing system. The proposed 106-mile, 30-inch-diameter
pipeline would extend from TransCanada’s GTN’s mainline to NW Natural’s
Source: Northwest Gas
Association

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system near Molalla, Oregon. It would be a bi-directional pipeline with an initial
capacity of up to 300 MMcf/d expandable up to 750 MMcf/d. In 2011, Palomar
Gas Transmission withdrew its application for this pipeline, yet remains prepared
if natural gas demand rebounds.
 Spectra/FortisBC System Enhancement
FortisBC and Spectra Energy are considering a 100-mile, 24-inch expansion
project from Kingsvale to Oliver, British Columbia, to expand service to the
Pacific Northwest and California markets. Removing constraints will allow
expansion of Spectra’s T-South enhanced service offering, which provides
shippers the options of delivering to Sumas or the Kingsgate market. Expanding
the bi-directional Southern Crossing system would increase capacity at Sumas
during peak demand periods. Initial capacity from the Spectra system to
Kingsgate would be 300 MMcf/d, expandable to 450 MMcf/d. Expanded east-to-
west flow will increase delivery of supply to Sumas by an additional 150 MMcf/d.
Currently, there is no plan to construct this pipeline, but it would be available if
demand was sufficient.
Avista supports proposals that bring supply diversity and reliability to the region. Avista
engages in discussions and analysis of the potential impact of each regional proposal
from a demand serving and reliability/supply diversity perspective. None of the above
projects provides direct delivery connection to any of the service territories. For Avista to
consider them a viable incremental resource to meet demand needs would require
combining them with additional capacity on existing pipeline resources. Given this
situation, Avista did not model these specific projects. However, the IRP considers a
generic expansion that represents a new pipeline build to Avista’s service territories.

In-Ground Storage
In-ground storage provides advantages when gas from storage can be delivered to
Avista’s service territory city-gates. It enables deliveries of natural gas to customers
during peak cold weather events. It also facilitates potentially lower-cost supply for
customers by capturing peak/non-peak pricing differentials and potential arbitrage
opportunities within individual months. Although additional storage can be a valuable
resource, without deliverability to Avista’s service territory, this storage cannot be an
incremental firm peak serving resource.

Jackson Prairie
Jackson Prairie is a potential resource for expansion opportunities. Any future storage
expansion capacity does not include transportation and therefore cannot be considered
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an incremental peak day resource. However, Avista will continue to look for exchange
and transportation release opportunities that could fully utilize these additional resource
options. When an opportunity presents itself, Avista assesses if it makes sense from a
financial impact to customers, as well as reliability. Even without deliverability, it can
make financial sense to utilize Jackson Prairie capacity to optimize time spreads within
the natural gas market and provide net revenue offsets to customer gas costs. There
are no current plans for immediate expansion of Jackson Prairie.

Other In-Ground Storage
Other regional storage facilities exist and may be cost effective. Additional capacity at
Northwest Natural’s Mist facility, capacity at one of the Alberta area storage facilities,
Questar’s Clay Basin facility in northeast Utah, Ryckman Creek in Uinta County, Wyo.,
and northern California storage are all possibilities. Transportation to and from these
facilities to Avista’s service territories continues to be the largest impediment to these
options. Avista will continue to look for exchange and transportation release
opportunities while monitoring daily metrics of load, transport and market environment.

LNG and CNG
LNG is another resource option in Avista’s service territories and is suited for meeting
peak day or cold weather events. Satellite LNG uses natural gas that is trucked to the
facilities in liquid form from an offsite liquefaction facility. Alternatively, small-scale
liquefaction and storage may also be an effective resource option if gas supply during
non-peak times is sufficient to build adequate inventory for peak events. Permitting
issues notwithstanding, facilities could be located in optimal locations within the
distribution system.
CNG is another resource option for meeting demand peaks and is operationally similar
to LNG. Natural gas could be compressed offsite and delivered to a distribution supply
point or compressed locally at the distribution supply point if sufficient natural gas
supply and power for compression is available during non-peak times.
LNG and CNG supply resource options for LDCs are becoming more attractive as the
market for LNG and CNG as alternative transportation fuels develops. The combined
demand for peaking and transportation fuels can increase the volume and utilization of
these resource assets thus lowering unit costs for the benefit of both market segments.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 80 of 152
Chapter 4: Supply-Side Resources

Estimates for LNG and CNG resources vary because of sizing and location issues. This
IRP uses estimates from other facilities constructed in the area and from informal
conversations with experts in the industry. Avista will monitor and refine the costs of
developing LNG and CNG resources while considering lead time requirements and
environmental issues.

Plymouth LNG
NWP owns and operates an LNG storage facility at Plymouth, Wash., which provides
gas liquefaction, storage and vaporization service under its LS-1 and LS-2F tariffs. An
example ratio of injection and withdrawal rates show that it can take more than 200
days to fill to capacity, but only 3-5 days to empty. As such, the resource is best suited
for needle-peak demands. Incremental transportation capacity to Avista’s service
territories would have to be obtained in order for it to be an effective peaking resource.
This peaking resource is fully contracted and not available at this time. Given this
situation, this option is not modeled in SENDOUT® for this IRP. However, because
many of the current capacity holders are on one-year rolling evergreen contracts, it is
possible this option will become viable in the future. As with other storage options, firm
transportation from the facility would be required.

Avista-Owned Liquefaction LNG
Avista could construct a liquefaction LNG facility in the service area. Doing so could use
excess transportation during off-peak periods to fill the facility, avoid tying up
transportation during peak weather events, and it may avoid additional annual pipeline
charges.
Construction would depend on regulatory and environmental approval as well as cost-
effectiveness requirements. Preliminary estimates of the construction, environmental,
right-of-way, legal, operating and maintenance, required lead times, and inventory costs
indicate company-owned LNG facilities have significant development risks. Due to these
risks, Avista did not include this resource in the IRP modeling.

Biogas Biogas typically refers to a gas produced by the biological breakdown of organic matter
in the absence of oxygen. Biogas can be produced by anaerobic digestion or
fermentation of biodegradable materials such as biomass, manure or sewage, municipal
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 81 of 152

Chapter 4: Supply-Side Resources

waste, green waste, and energy crops. This type of biogas is primarily methane and
carbon dioxide.
Biogas is a renewable fuel, so it may qualify for renewable energy subsidies. Avista is
not aware of any current subsidies, but future stimulus or energy policies could lead to
some form of financial incentives.
Biogas projects are unique, so reliable cost estimates are difficult to obtain. Project
sponsorship has many complex issues, and the more likely participation in such a
project is as a long-term contracted purchaser. Avista did not consider biogas as a
resource in this planning cycle, since they are small and insignificant compared to
demand, but remains receptive to such projects as they are proposed.

Supply Scenarios
This IRP includes two supply scenarios. Table 4.2 lists the supply scenarios and
Appendix 4.2 provides the details on what is included in each of these scenarios.
Additional details about the results of the supply scenarios are in Chapters 5 and 6.

Table 4.2: Supply Scenarios

 Existing Resources: This scenario represents all resources currently owned or
contracted by Avista.
 Existing + Expected Available: In this scenario, existing resources plus supply
resource options expected to be available when resource needs are identified.
This includes currently available south and north bound GTN, capacity release
recalls, NWP expansions and satellite LNG.

Supply Issues
The abundance and accessibility of shale gas has fundamentally altered North
American natural gas supply and the outlook for future natural gas prices. Even though
Table 5.2
Supply Scenarios 
Existing Resources
Existing + Expected Available
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J. Morehouse, Avista
Schedule 1, P. 82 of 152
Chapter 4: Supply-Side Resources

the supply is available and the technology exists to access it, there are issues that can
affect the cost and availability of natural gas.
Hydraulic Fracturing
Improvements in hydraulic fracturing, a 60-year-old technique used to extract oil and
natural gas from shale rock formations, coupled with horizontal drilling has enabled
access to previously uneconomic resources. However, the process does not come
without challenges. The publicity caused by movies, documentaries and articles in
national newspapers about “fracking” has plagued the natural gas and oil industry.
There is worry that hydraulic fracturing is contaminating aquifers, increasing air pollution
and causing earthquakes. The wide-spread publicity generated interest in the
production process and caused some states to issue bans or moratoriums on drilling
until further research was conducted.
Government, industry and universities engaged in studies to understand the actual and
potential impacts of hydraulic fracturing. Industry has been working to refute these
claims by focusing on ensuring companies use best practices for well drilling, disclosing
the fluids used in the hydraulic fracturing processing, and implementing “green
completions” for wells. State governments are participating in independent audits of
their regulations to ensure that proper oversight is in place. The outcome of these
audits, studies and research could greatly affect the cost and availability of natural gas
and oil.
Pipeline Availability
The Pacific Northwest has efficiently utilized its relatively sparse network of pipeline
infrastructure to meet the regions needs. As the amount of renewable energy increases,
future demand for natural gas-fired generation will increase. Pipeline capacity is the link
between natural gas and power.
Adding additional pressure to existing pipeline resources is the announcement of three
methanol plants in the region. The plants use large amounts of natural gas as a
feedstock for creating methanol, which is used to make other chemicals and as a fuel.
LDCs will have to compete with power generators, LNG exporters and other large end
users for limited pipeline capacity. The new mix could alter current pipeline operations
and the potential availability of infrastructure to the region.

Action Items
Without resource deficiencies or a need to acquire incremental supply-side resources to
meet peak day demands, Avista’s focus will only include normal activities in the near
term, including:
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 83 of 152

Chapter 4: Supply-Side Resources

 Continue to monitor supply resource trends including the availability and price of
natural gas to the region, exporting LNG (specifically on the Oregon coast)
Canadian natural gas imports, regional plans for natural gas-fired generation and
its affect on pipeline availability, and regional pipeline and storage infrastructure
plans
 Avista will also monitor new resource lead-time requirements relative to when
resources are needed to preserve resource option flexibility

Conclusion
Avista is committed to providing reliable supplies of natural gas to its customers. Avista
procures supplies with a diversified plan that seeks to acquire natural gas supplies while
reducing exposure to short-term price volatility through a strategy that includes hedging,
storage utilization and index purchases. The supply mix includes long-term contracts for
firm pipeline transportation capacity from many supply points and ownership and
leasing of firm natural gas storage capacity sufficient to serve customer demand during
peak weather events and throughout the year.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 84 of 152
Chapter 5: Integrated Resource Portfolio

5: Integrated Resource Portfolio

Overview
This chapter combines the previously discussed IRP components and the model used
to determine resource deficiencies during the 20-year planning horizon. Although not
the case in this IRP, this chapter also provides an analysis of potential resource options
to meet resource deficiencies when they exist.
The foundation for integrated resource planning is the criteria used for developing
demand forecasts. Avista uses the coldest day on record as its weather-planning
standard for determining peak-day demand. This is consistent with past IRPs and as
described in Chapter 2  Demand Forecasts. This IRP utilizes coldest day on record
and average weather data for each demand region for this IRP. Avista plans to serve
expected peak day in each demand region with firm resources. Firm resources include
natural gas supplies, firm pipeline transportation and storage resources. In addition to
peak requirements, Avista also plans for non-peak periods such as winter, shoulder and
summer demand. The modeling process includes running a daily optimization for every
day of the 20-year planning period.
It is assumed that on a peak day all interruptible customers have left the system in order
to provide service to firm customers. Avista does not make firm commitments to serve
interruptible customers. Therefore, our IRP analysis of demand-serving capabilities only
focuses on the residential, commercial and firm industrial classes. It is Avista’s belief
that using coldest day on record weather criteria, a blended price curve developed by
industry experts, and an academically backed customer forecast all work together to
develop stringent planning criteria.
Forecasted demand represents the amount of natural gas supply needed. In order to
deliver the forecasted demand, the supply forecast needs to be increased between 1.0
percent and 3.0 percent on both an annual and peak-day basis to account for additional
supplies that are purchased primarily for pipeline compressor station fuel. The 1.0
percent to 3.0 percent, known as fuel, varies depending on the pipeline. The FERC and
National Energy Board approved tariffs govern the percentage of required additional
fuel supply.

SENDOUT® Planning Model
The SENDOUT® Gas Planning System from Ventyx performs integrated resource
optimization. The SENDOUT® model was purchased in April 1992 and has been used
in preparing all IRPs since then. Avista has a long-term maintenance agreement with
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 85 of 152
Chapter 5: Integrated Resource Portfolio

Ventyx for software updates and enhancements. Enhancements include software
corrections and improvements brought on by industry needs.
SENDOUT® is a linear programming model widely used to solve natural gas supply and
transportation optimization questions. Linear programming is a proven technique used
to solve minimization/maximization problems. SENDOUT® analyzes the complete
problem at one time within the study horizon, while accounting for physical limitations
and contractual constraints.
The software analyzes thousands of variables and evaluates possible solutions to
generate a least cost solution. The model uses the following variables:
 Demand data, such as customer count forecasts and demand
coefficients by customer type (e.g., residential, commercial and
industrial).
 Weather data, including minimum, maximum and average
temperatures.
 Existing and potential transportation data which describes the network
for physical movement of natural gas and associated pipeline costs.
 Existing and potential supply options including supply basins, revenue
requirements as the key cost metric for all asset additions and prices.
 Natural gas storage options with injection/withdrawal rates, capacities
and costs.
 DSM potential.
Figure 5.1 is a SENDOUT® network diagram of Avista’s demand centers and
resources. This diagram illustrates current transportation and storage assets, flow paths
and constraint points.

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 86 of 152
Chapter 5: Integrated Resource Portfolio

Figure 5.1 SENDOUT® Model Diagram

The SENDOUT® model also provides a flexible tool to analyze potential scenarios such
as:
 Pipeline capacity needs and capacity releases.
 Effects of different weather patterns upon demand.
 Effects of natural gas price increases upon total natural gas costs.
 Storage optimization studies.
 Resource mix analysis for DSM.
 Weather pattern testing and analysis.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 87 of 152
Chapter 5: Integrated Resource Portfolio

 Transportation cost analysis.
 Avoided cost calculations.
 Short-term planning comparisons.
SENDOUT® also includes Monte Carlo capabilities, which facilitates price and demand
uncertainty modeling and detailed portfolio optimization techniques to produce
probability distributions. More information and analytical results are located in Chapter 6
– Alternate Scenarios, Portfolios and Stochastic Analysis.
Resource Integration
This IRP defines the planning methodologies, describes the modeling tools and
identifies existing and potential resources. The following summarizes the
comprehensive analysis bringing demand forecasting and existing and potential supply
and demand-side resources together to form the 20-year, least-cost plan.

Demand Forecasting
Chapter 2 - Demand Forecasts describes Avista’s demand forecasting approach.
Avista forecasts demand in the SENDOUT® model in eight service areas given the
existence of distinct weather and demand patterns for each area and pipeline
infrastructure dynamics. The SENDOUT® areas are Washington/Idaho (disaggregated
into three sub-areas because of pipeline flow limitations); Medford (disaggregated into
two sub-areas because of pipeline flow limitations); and Roseburg, Klamath Falls and
La Grande. In addition to area distinction, Avista also models demand by customer
class within each area. The relevant customer classes are residential, commercial and
firm industrial customers.
Customer demand is highly weather-sensitive. Avista’s customer demand is not only
highly seasonable, but also highly variable. Figure 5.2 captures this variability showing
monthly system-wide average demand, minimum demand day observed by month,
maximum demand day observed in each month, and winter projected peak day demand
for the first year of the Expected Case forecast as determined in SENDOUT®.

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 88 of 152
Chapter 5: Integrated Resource Portfolio

Figure 5.2: Total System Average Daily Load (Average, Minimum, Maximum)

Natural Gas Price Forecasts
Natural gas prices are a fundamental component of the IRP. The commodity price is a
significant component of the total cost of a resource option. This affects the avoided
cost threshold for determining cost-effectiveness of conservation measures. The price
of natural gas influences consumption, so price elasticity is part of the demand
evaluation (see Chapter 2 – Demand Forecasts).
The natural gas price outlook has changed dramatically in recent years in response to
several influential events and trends affecting the industry. The recent recession, shale
gas production, green house gas issues, and renewable energy standards creating the
potential for more natural gas-fired generation impact the natural gas outlook. Due to
the rapidly changing environment and uncertainty in predicting future events and trends,
modeling a range of forecasts is necessary.
Many additional factors influence natural gas pricing and volatility, such as regional
supply/demand issues, weather conditions, hurricanes/storms, storage levels, natural
gas-fired generation, infrastructure disruptions, and infrastructure additions (e.g. new
pipelines and LNG terminals).
Even though Avista continually monitors these factors, we cannot accurately predict
future prices for the 20-year horizon of this IRP. This IRP reviewed several price
forecasts from credible sources. Figure 5.3 depicts the price forecasts considered in the
IRP analyses.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 89 of 152
Chapter 5: Integrated Resource Portfolio

Figure 5.3: Henry Hub Forecasted Price (Real $/Dth)

Selecting the price curves can be more art than science. With the assistance of the
TAC, Avista selected high, expected and low price curves to consider possible
outcomes and their impact on resource planning. The expected curve was a 50 / 50
blended price derived from consulting services subscriptions with the high and low
bounding the expected curve with industry experts’ opinions. The selected price curves
have variation and provide reasonable upper and lower bounds, consistent with
stretching modeling assumptions to address uncertainty in the planning environment.
These curves are in real dollars in Figure 5.4 and nominal dollars in Figure 5.5.
Additionally, stochastic modeling of natural gas prices is also completed. The results
from that analysis are in Chapter 6 – Alternate Scenarios, Portfolios and Stochastic
Analysis.

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 90 of 152
Chapter 5: Integrated Resource Portfolio

Figure 5.4 Henry Hub Forecasts for IRP Low/ Medium/ High Forecasted Price – Real $/Dth

Figure 5.5: Low / Medium / High Forecasted Price – Nominal $/Dth

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 91 of 152
Chapter 5: Integrated Resource Portfolio

Each of the price forecasts above are for Henry Hub, which is located in Louisiana just
onshore from the Gulf of Mexico. Henry Hub is recognized as the most important pricing
point in the U.S. because of its proximity to a large portion of U.S. natural gas
production and the sheer volume traded in the daily or spot market, as well as the
forward markets via the New York Mercantile Exchange’s (NYMEX) futures contracts.
Consequently, all other trading points tend to be priced off of the Henry Hub.
The primary physical supply points at Sumas, AECO and the Rockies (and other
secondary regional market hubs) determine Avista’s costs. Prices at these points
typically trade at a discount, or negative basis differential, to Henry Hub because of their
proximity to the two largest natural gas basins in North America (the WCSB and the
Rockies).
Table 5.1 shows the Pacific Northwest regional prices from the consultants, historic
averages and the prior IRP as a percent of Henry Hub price, along with three-year
historical comparisons.

Table 5.1: Regional Price as a Percent of Henry Hub Price

Consultant1
Forecast Average
91.9% 101.4% 99.2% 105.3% 102.7%
Consultant2
Forecast Average
84.9% 93.6% 91.6% 97.3% 94.8%
Historic Cash
Three-Year
Average
87.4% 98.4% 116.4% 99.2% 97.5%
2012 IRP 88.60% 89.90% 90.80% 92.30% 91.40%

This IRP used monthly prices for modeling purposes because of Avista’s winter-
weighted demand profile. Table 5.2 depicts the monthly price shape used in this IRP. A
slight change to the shape of the pricing curve occurred since the last IRP. Driven
primarily by supply availability, the forecasted differential between winter and summer
pricing has come in to some extent when compared to historic data.

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 92 of 152
Chapter 5: Integrated Resource Portfolio

Table 5.2: Monthly Price as a Percent of Average Price

Avista selected a blend of Consultant 1 and Consultant 2’s forecast of regional prices
and monthly shapes. Appendix 5.1 contains detailed monthly price data behind the
summary table information discussed above.
Transportation and Storage
Valuing natural gas supplies is a critical first step in resource integration. Equally
important is capturing all costs to deliver the natural gas to customers. Daily capacity of
existing transportation resources (described in Chapter 4 – Supply-Side Resources) is
represented by the firm resource duration curves depicted in Figures 5.6 and 5.7.

Jan Feb Mar Apr May Jun
Consult 1 101% 102% 102% 99% 99% 99%
Consult 2 104% 104% 97% 96% 97% 98%
Prior IRP 101% 101% 98% 98% 98% 100%
Jul Aug Sep Oct Nov Dec
Consult 1 99% 100% 101% 100% 100% 100%
Consult 2 99% 100% 99% 99% 102% 106%
Prior IRP 102% 103% 100% 100% 100% 102%
Table 6.2 Monthly Price as a Percent of Average Price
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 93 of 152
Chapter 5: Integrated Resource Portfolio

Figure 5.6: Existing Firm Transportation Resources – Washington/Idaho

Figure 5.7: Existing Firm Transportation Resources – Oregon

0
50
100
150
200
250
300
350
400
450
500
1 31 61 91 121 151 181 211 241 271 301 331 361
MDth
Day of Year
0
20
40
60
80
100
120
140
160
180
200
1 31 61 91 121 151 181 211 241 271 301 331 361
MDth
Day of Year
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J. Morehouse, Avista
Schedule 1, P. 94 of 152
Chapter 5: Integrated Resource Portfolio

Current rates for capacity are in Appendix 5.1. Forecasting future pipeline rates can be
a challenge because of the need to estimate the amount and timing of rate changes.
Avista’s estimates and timing of future pipeline rate increases are based on knowledge
obtained from industry discussions and participation in various pipeline rate cases. This
IRP assumes that pipelines will file to recover costs at rates equal to increases in GDP
(see Appendix 5.2 – General Assumptions).

Demand-Side Management Chapter 3 – Demand-Side Resources describes the methodology used to identify
conservation potential and the interactive process that utilizes avoided cost thresholds
for determining the cost effectiveness of conservation measures on an equivalent basis
with supply-side resources.

Preliminary Results
After incorporating the above data into the SENDOUT® model, Avista generated an
assessment of demand compared to existing resources for several scenarios. Chapter 2
– Demand Forecasts discusses the demand results from these cases, with additional
details in Appendices 2.1 through 2.10.
Figures 5.8 through 5.11 provide graphic summaries of Average Case demand
compared to existing resources. This demand is net of DSM savings and shows the
adequacy of Avista’s resources under normal weather conditions. For this case, current
resources meet demand needs over the planning horizon.

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 95 of 152
Chapter 5: Integrated Resource Portfolio

Figure 5.8: Average Case – Washington/Idaho Existing Resources vs. Peak Day Demand
– February 15th

Figure 5.9: Average Case – Medford / Roseburg Existing Resources vs. Peak Day
Demand – December 20th

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 96 of 152
Chapter 5: Integrated Resource Portfolio

Figure 5.10: Average Case – Klamath Falls Existing Resources vs. Peak Day Demand –
December 20th

Figure 5.11: Average Case – La Grande Existing Resources vs. Peak Day Demand –
February 15th

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 97 of 152
Chapter 5: Integrated Resource Portfolio

Figures 5.12 through 5.15 provide graphic summaries of Expected Case peak day
demand compared to existing resources, as well as demand comparisons to the 2012
IRP. This demand is net of DSM savings. For this case, existing resources meet peak
day demand needs over the planning horizon. This surplus resource situation provides
ample time to carefully monitor, plan and act on potential resource additions.

Figure 5.12: Expected Case – Washington/Idaho Existing Resources vs. Peak Day
Demand – February 15th

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 98 of 152
Chapter 5: Integrated Resource Portfolio

Figure 5.13: Expected Case – Medford / Roseburg Existing Resources vs. Peak Day
Demand – December 20th

Figure 5.14: Expected Case – Klamath Falls Existing Resources vs. Peak Day Demand –
December 20th

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 99 of 152
Chapter 5: Integrated Resource Portfolio

Figure 5.15: Expected Case – La Grande Existing Resources vs. Peak Day Demand –
February 15th

If demand grows faster than expected, the need for new resources will come earlier.
“Flat demand risk” requires close monitoring for signs of increasing demand and
evaluation of lead times to acquire preferred incremental resources. Monitoring of “flat
demand risk” includes a reconciliation of forecasted demand to actual demand on a
monthly basis. This reconciliation helps identify customer growth trends and use-per-
customer trends. If they meaningfully differ compared to forecasted trends, Avista will
assess the impacts on planning from procurement and resource sufficiency standing.
Table 5.3 quantifies the forecasted total demand net of DSM savings and un-served
demand from the above charts.

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 100 of 152
Chapter 5: Integrated Resource Portfolio

Table 5.3: Peak Day Demand – Served and Unserved (MDth/d)

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 101 of 152
Chapter 5: Integrated Resource Portfolio

New Resource Options
When existing resources are not sufficient to meet expected demand, there are many
important considerations in determining the appropriateness of potential resources.
Interruptible customers’ transportation may be cut, as needed, when existing resources
are not sufficient to meet firm customers demand.

Resource Cost
Resource cost is the primary consideration when evaluating resource options, although
other factors mentioned below also influence resource decisions. Newly constructed
resources are typically more expensive than existing resources, but existing resources
are in shorter supply. Newly constructed resources provided by a third party, such as a
pipeline, may require a significant contractual commitment. Newly constructed
resources are often less expensive per unit, if a larger facility is constructed, because of
economies of scale.

Lead Time Requirements
New resource options can take from one to five or more years to put in service. Open
season processes, planning and permitting, environmental review, design, construction,
and testing are some of the aspects contributing to lead time requirements for new
facilities. Recalls of released pipeline capacity typically require advance notice of up to
one year. Even DSM programs can require significant time from program development
and rollout to the realization of natural gas savings.

Peak versus Base Load
Avista’s planning efforts include the ability to serve firm natural loads on a peak day, as
well as all other demand periods. Avista’s core loads are considerably higher in the
winter than the summer. Due to the winter-peaking nature of Avista’s demand,
resources that cost-effectively serve the winter without an associated summer
commitment may be preferable. Alternatively, it is possible that the costs of a winter-
only resource may exceed the cost of annual resources after capacity release or
optimization opportunities are considered.

Resource Usefulness
Available resource must effectively deliver natural gas to the intended region. Given
Avista’s unique service territories, it is often impossible to deliver resources from a
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 102 of 152
Chapter 5: Integrated Resource Portfolio

resource option such as storage without acquiring additional pipeline transportation.
Pairing resources increases cost. Other key factors that can contribute to the usefulness
of a resource are viability and reliability. If the potential resource is either not available
currently (e.g., new technology) or not reliable on a peak day (e.g., firm), they may not
be considered as an option for meeting unserved demand.

“Lumpiness” of Resource Options
Newly constructed resource options are often “lumpy.” This means that new resources
may only be available in larger-than-needed quantities and only available every few
years. This lumpiness of resources is driven by the cost dynamics of new construction,
where lower unit costs are available with larger expansions and the economics of
expansion of existing pipelines or the construction of new resources dictate additions
infrequently. Lumpiness provides a cushion for future growth. Economies of scale for
pipeline construction afford the opportunity to secure resources to serve future demand
increases.

Competition
LDCs, end-users and marketers compete for regional resources. The Northwest has
been efficient in the utilization of existing resources and has an appropriately sized
system. Currently, the region can accommodate the regional demand needs. However,
future needs vary, and regional LDCs may find they are competing with each other and
other parties to secure firm resources for customers.

Risks and Uncertainties
Investigation, identification, and assessment of risks and uncertainties are critical
considerations when evaluating supply resource options. For example, resource costs
are subject to degrees of estimation, partly influenced by the expected timeframe of the
resource need and rigor determining estimates, or estimation difficulties because of the
uniqueness of a resource. Lead times can have varying degrees of certainty ranging
from securing currently available transport (high certainty) to building underground
storage (low certainty).

Resource Selection
After identifying supply-side resource options and evaluating them based on the above
considerations, Avista entered the supply-side scenarios (see Table 5.2) and
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 103 of 152
Chapter 5: Integrated Resource Portfolio

conservation measures (see Chapter 3 – Demand-Side Resources) into the
SENDOUT® model for it to select the least cost approach to meeting resource
deficiencies, if they exist. SENDOUT® compares demand-side and supply-side
resources (see Appendix 5.3 for a list of supply-side resource options) using PVRR
analysis to determine which resource is a best option/least cost resource.

Demand-Side Resources

Integration by Price
As described in Chapter 3, the model runs without future DSM programs. This
preliminary run provides an avoided cost curve for EnerNOC. EnerNOC then evaluates
the cost effectiveness of DSM programs against the initial avoided cost curve using the
appropriate resource cost tests. The therm savings and associated program costs are
incorporated into the SENDOUT® model. After incorporation, the avoided costs are re-
evaluated. This process continues until the change in avoided cost curve is immaterial.

Avoided Cost
The SENDOUT® model determined avoided-cost figures represent the unit cost to
serve the next unit of demand with a supply-side resource option during a given period.
If a conservation measure’s total resource cost (for Idaho and Oregon), or utility cost
(for Washington), is less than this avoided cost, it will be cost effective to reduce
customer demand and Avista can avoid commodity, storage, transportation and other
supply resource costs.
SENDOUT® calculates marginal cost data by day, month and year for each demand
area. A summary graphical depiction of avoided annual and winter costs for the
Washington/Idaho and Oregon areas is in Figure 5.16. The detailed data is in Appendix
5.4. Other than the carbon tax adder embedded in the expected price curve, avoided
costs do not include additional environmental externality adders for adverse
environmental impacts. Appendix 3.2 discusses this concept more fully and includes
specific requirements required in the Oregon service territory.

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 104 of 152
Chapter 5: Integrated Resource Portfolio

Figure 5.16: Avoided Cost (Includes Commodity & Transport Cost – 2012 $/Dth)

DSM Potential
Using the avoided cost thresholds, EnerNOC selected all potential cost effective DSM.
Table 5.4 shows potential DSM savings in each region from the selected conservation
potential for the Expected Case. The DSM potential includes anticipated annual
acquisition and is cumulative.

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 105 of 152
Chapter 5: Integrated Resource Portfolio

Table 5.4: Annual and Average Daily Demand Served by DSM

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 106 of 152
Chapter 5: Integrated Resource Portfolio

DSM Acquisition Goals The avoided cost established in SENDOUT®, the DSM potential selected, and the
amount of therm savings is the basis for determining DSM acquisition goals and
subsequent program implementation planning. Chapter 3 – Demand-Side Resources
has additional details on this process.

Supply-Side Resources
SENDOUT® considers all options entered into the model, determines when and what
resources are needed, and which options are cost effective. Selected resources
represent the best cost/risk solution, within given constraints, to serve anticipated
customer requirements. Since the Expected Case has no resource additions in the
planning horizon, Avista will continue to review and refine knowledge of resource
options and will act to secure best cost/risk options when necessary or advantageous.

Resource Utilization
Avista’s plans to meet firm customers’ demand requirements in a cost-effective manner.
This goal encompasses a range of activities from meeting peak day requirements in the
winter to acting as a responsible steward of resources during periods of lower resource
utilization. As the analysis presented in this IRP indicates, Avista has ample resources
to meet highly variable demand under multiple scenarios, including peak weather
events.
Avista acquired the majority of its upstream pipeline capacity during the deregulation or
“unbundling” of the natural gas industry. Pipelines were required to allocate capacity
and costs to their existing customers as they transitioned to transportation only service
providers. The FERC allowed a rate structure for pipelines to recover costs through a
Straight Fixed Variable rate design. This structure is based on a higher reservation
charge to cover pipeline costs whether gas is transported or not, and a much smaller
variable charge which is incurred only when gas is transported. An additional fuel
charge is assessed to account for the compressors required to move the gas to
customers. Avista maintains enough firm capacity to meet peak day requirements under
the Expected Case in this IRP. This requires pipeline capacity contracts at levels in
excess of the average and above minimum load requirements. Given this load profile
and the Straight Fixed Variable rate design, Avista incurs ongoing pipeline costs during
non-peak periods.
Avista chooses to have an active, hands-on management of resources to mitigate
upstream pipeline and commodity costs for customers when the capacity is not utilized
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 107 of 152
Chapter 5: Integrated Resource Portfolio

for system load requirements. This management simultaneously deploys multiple long
and short-term strategies to meet firm demand requirements in a cost effective manner.
The resource strategies addressed are:
 Pipeline contract terms.
 Pipeline capacity.
 Storage.
 Commodity and transport optimization.
 Combination of available resources.

Pipeline Contract Terms
Pipeline costs are incurred whether the capacity is utilized or not. Winter demand must
be satisfied and peak days must be met. Ideally, capacity could be contracted from
pipelines for the time and days it is required. Unfortunately, this is not how pipelines are
contracted or built. Long-term agreements at fixed volumes are the usual requirements
for building or acquiring firm transport. This assures the pipeline of long-term,
reasonable cost recovery.
Avista has negotiated and contracted for several seasonal transportation agreements.
These agreements allow volumes to increase during the demand intensive winter
months and decrease over the lower demand summer period. This is a preferred
contracting strategy because it eliminates costs when demand is low. Avista refers to
this as a front line strategy because it attempts to mitigate costs prior to contracting the
resource. Not all pipelines offer this option. Avista seeks this type of arrangement when
available. Avista currently has some seasonal transportation contracts on TransCanada
GTN, TransCanada BC and TransCanada Alberta. These pipelines match up to move
natural gas from Alberta (AECO) to Avista’s service territories. Avista also contracted for
TF2 on NWP. This is a storage specific contract and matches up to some of the
Jackson Prairie storage capacity. TF2 is a firm service and allows for contracting a daily
amount of transportation for a specified number of days rather than a daily amount on
an annual basis as is usually required. For example, one of the TF2 agreements allows
Avista to transport 91,200 Dth/day for 31 days. This is a more cost effective strategy for
storage transport than contracting for an annual amount. Through NWP’s tariff, Avista
maintains an option to increase and decrease the number of days this transportation
option is available. More days correspond to more costs, so balancing storage,
transport and demand is important to ensure an optimal blend of cost and reliability.

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 108 of 152
Chapter 5: Integrated Resource Portfolio

Pipeline Capacity After contracting for pipeline capacity, its management and utilization determine the
actual costs. The worst-case economic scenario is to do nothing and simply incur the
costs associated with this transport contract over a long term to meet current and future
peak demand requirements. Avista develops strategies to ensure this does not happen
on a regular basis.

Capacity Release Through the pipeline unbundling of transportation, the FERC establishes rules and
procedures to ensure a fair market developed to manage pipeline capacity as a
commodity. This evolved into the capacity release market and is governed by FERC
regulations through individual pipelines. The pipelines implement the FERC’s posting
requirements to ensure a transparent and fair market is maintained for the capacity. All
capacity releases are posted on the pipelines Bulletin Boards and, depending on the
terms, may be subject to bidding in an open market. This provides the transparency
sought by FERC in establishing the release requirements. Avista utilizes the capacity
release market to manage both long-term and short-term transportation capacity.
For capacity under contract that may exceed current demand, Avista seeks other
parties that may need it and arranges for capacity releases to transfer rights, obligations
and costs. This shifts all or a portion of the costs away from customers to a third party
until it is needed to meet customers’ demand.
There are many variables in determining the value of transportation. Certain pipeline
paths are more valuable and this can vary by year, season, month and day. The term,
volume and conditions precedent also contribute to the value recoverable through a
capacity release. For example, a release of winter capacity to a third party may allow for
full cost recovery; while a release for the same period that allows Avista to recall the
capacity for up to 10 days during the winter may not be as valuable to the third party,
but of high value to us. Avista may be willing to offer a discount to retain the recall rights
during high demand periods. This turns a seasonal-for-annual cost into a peaking-only
cost. These are market terms and conditions that are negotiated to determine the value
or discount required by both parties.
Avista has several long-term releases, some extending through 2025 providing full
recovery of all the pipeline costs. These releases maintain Avista’s long-term rights to
the transportation capacity without incurring the costs of waiting until demand increases.
As the end of these release terms near, Avista surveys the market against the IRP to
determine if these contracts should be reclaimed or released, and for what duration.
Avista has releases to third parties that terminate in 2016. Results of this IRP show that
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 109 of 152
Chapter 5: Integrated Resource Portfolio

this capacity is not needed in 2016 as originally anticipated, and Avista is negotiating
new terms and conditions to continue full cost recovery until it is required. Through this
process, Avista retains the rights to vintage capacity without incurring the costs or
having to participate in future pipeline expansions that will cost more than current
capacity.
On a shorter term, excess capacity not fully utilized on a seasonal, monthly or daily
basis can also be released. Market conditions often dictate less than full cost recovery
for shorter-term requirements. Mitigating some costs for an unutilized, but required
resource reduces costs to our customers.

Segmentation
Through a process called segmentation, Avista creates new firm pipeline capacity for
the service territory. This doubles some of the capacity volumes at no additional cost to
customers. With increased firm capacity, Avista can continue some long-term releases,
or even reduce some contract levels, if the release market does not provide adequate
recovery.

Storage
As a one-third owner of the Jackson Prairie Storage facility, Avista holds an equal share
of capacity (space available to store gas) and delivery (the amount of natural gas that
can be withdrawn on a daily basis).
Storage allows lower summer-priced gas to be stored and used in the winter during high
demand or peak day events. Similar to transportation, unneeded capacity and delivery
can be optimized by selling into a higher priced market. This allows Avista to manage
storage capacity and delivery to meet growing peak day requirements when needed.
The injection of gas into storage during the summer utilizes existing pipeline transport
and helps increase the utilization factor of pipeline agreements. Avista employs several
storage optimization strategies to mitigate costs. Revenue from this activity flows
through the annual PGA/Deferral process.

Commodity and Transportation Optimization Another strategy to mitigate transportation costs is to participate in the daily market to
assess if unutilized capacity has value. Avista seeks daily opportunities to purchase
gas, transport it on existing unutilized capacity, and sell it into a higher priced market to
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 110 of 152
Chapter 5: Integrated Resource Portfolio

capture the cost of the gas purchased and recover some pipeline charges. The recovery
is market dependent and may or may not recover all pipeline costs, but mitigates
pipeline costs to customers.

Combination of Resources
Unutilized resources like supply, transportation, storage and capacity can combine to
create products that capture more value than the individual pieces. Avista has
structured long-term arrangements with other utilities that allow available resources
utilization and provide products that no individual component can satisfy. These
products provide more cost recovery of the fixed charges incurred for the resources.

Resource Utilization Summary
As determined through the IRP modeling of demand and existing resources, new
resources under the Expected Case are not required. Avista manages the existing
resources to mitigate the costs incurred by customers until the resource is required to
meet demand. The recovery of costs is often market based with rules governed by the
FERC. Avista is recovering full costs on some resources and partial costs on others.
The management of long and short-term resources ensures the goal to meet firm
customer demand in a reliable and cost-effective manner.

Gate Station Analysis
Avista identified a risk associated with the aggregated methodology for supply and
demand forecasting in previous IRPs. The forecasting methodology is consistent with
operational practices which aggregate capacity at individual points for
scheduling/nomination purposes. Typically, the amount of natural gas that can flow from
a contract demand (i.e., receipt/supply quantity) is fixed and the deliverable amount
(i.e., maximum daily delivery obligation or delivery quantity) to gate stations is greater.
(See Figure 5.17) However, aggregation could mask deficiencies at individual gate
stations.

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 111 of 152
Chapter 5: Integrated Resource Portfolio

Figure 5.17: Gate Station Modeling Challenge

To address this concern, a gate-by-gate analysis was developed outside of
SENDOUT®. The analysis involved coordination between Gas Supply, Gas Engineering
and intrastate pipeline personnel. Utilizing historical gate station flow data and demand
forecasting methodologies detailed in the IRP, forecasted peak-day gate station
demand was calculated. This demand was compared to contracted and operational
capacities at each gate station.
If forecasted demand exceeded contracted and/or operational capacities, further
analysis was completed. The additional analysis involved assessing the economic way
to address the gate deficiency. This could involve a gate station expansion, re-assigning
maximum daily delivery obligations, targeted DSM, or distribution system
enhancements.
For example, analysis in the last IRP identified a gate station on NWP’s Coeur d’Alene
Lateral where forecasted peak day demand exceeded the gate station maximum daily
delivery obligation and the physical capacity. Numerous solutions were examined with
all parties. The analysis indicated the optimal solution is a pre-existing plan to build a
new gate station at Chase Road off GTN’s mainline. The project originally was designed
to alleviate capacity constraints at GTN’s Rathdrum gate; however, the new gate’s
location could displace natural gas on the NWP Coeur d’Alene Lateral.
Avista is working on the gate station analysis on NWP’s system serving Oregon
customers. Any deficiencies identified will be communicated to Commission Staff with
proposed least cost solutions. After the analysis of the NWP gates is complete, Avista
will analyze the GTN system gates.
10,000
2000
Contract Demand: 10,000
Supply (Receipt Quantity)
MDDO’s: 11,000
Gate Station (Delivery
Quantity)
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Demand: 8,000
Behind the Gate
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 112 of 152
Chapter 5: Integrated Resource Portfolio

Action Items With no resource deficiencies in the planning horizon, there are no specific and
measurable near-term action items for gate station analysis.

Conclusion
The IRP portfolio analysis summarized in this chapter was performed on the Average
Case and then on the Expected Case demand scenario. Although the results show no
resource deficiencies during the 20-year forecasted term, Avista has chosen to utilize
the Expected Case for peak operational planning activities because this case is the
most likely outcome given experience, industry knowledge and understanding of future
natural gas markets. This case provides reasonable demand growth given current
expectations of natural gas prices over the planning horizon. If realized, this case allows
Avista protection against resource shortages and does not over commit to additional
long-term resources.
Avista recognizes that there are other potential outcomes. The process described in this
chapter applies to the alternate demand and supply resource scenarios covered in
Chapter 6 – Alternate Scenarios, Portfolios and Stochastic Analysis.

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 113 of 152
Chapter 5: Integrated Resource Portfolio

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 114 of 152
Chapter 6: Alternate Scenario, Portfolios and Stochastic Analysis

6: Alternate Scenarios, Portfolios and Stochastic
Analysis

Overview
Avista applied the IRP analysis in Chapter 5 to several alternate demand and supply
resource scenarios to develop a range of alternate portfolios. This deterministic
modeling approach considered different underlying assumptions vetted with the TAC
members to develop a consensus about the number of cases to model.
Avista also performed stochastic modeling for estimating probability distributions of
potential outcomes by allowing for random variation in natural gas prices and weather
based on fluctuations in historical data. This statistical analysis, in conjunction with the
deterministic analysis, enabled statistical quantification of risk from reliability and cost
perspectives related to resource portfolios under varying price and weather
environments.

Alternate Demand Scenarios
As discussed in the Demand Forecasting section, Avista identified alternate scenarios
for detailed analysis to capture a range of possible outcomes over the planning horizon.
Table 6.1 summarizes these scenarios and Chapter 2 – Demand Forecasts and
Appendices 2.6 and 2.7 describes them in more detail. The scenarios consider different
demand influencing factors and price elasticity effects for various price influencing
factors.

Table 6.1: Scenarios

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 115 of 152
Chapter 6: Alternate Scenario, Portfolios and Stochastic Analysis
Demand profiles over the planning horizon for each of the scenarios shown in Figures
6.1 and 6.2 reflect the two winter peaks modeled for the different service territories
(Dec. 20 and Feb. 15).

Figure 6.1 Peak Day (Feb 15) – 2014 IRP Demand Scenarios

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 116 of 152
Chapter 6: Alternate Scenario, Portfolios and Stochastic Analysis

Figure 6.2 Peak Day (Dec 20) – 2014 IRP Demand Scenarios

As in the Expected Case, Avista used SENDOUT® to model the same resource
integration and optimization process described in this section for each of the five
demand scenarios (see Appendix 2.7 for a complete listing of portfolios considered).
This identified first year unserved dates for each scenario by service territory (Figure
6.3).

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Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 117 of 152
Chapter 6: Alternate Scenario, Portfolios and Stochastic Analysis
Figure 6.3: First Year Peak Demand Not Met with Existing Resources

As anticipated, the High Growth, Low Price scenario has the most rapid growth and the
earliest first year unserved dates. This scenario includes customer growth rates higher
than the Expected Case, incremental demand driven by emerging markets and no
adjustment for price elasticity. Even with aggressive assumptions, resource shortages
do not occur until late in the planning horizon.
 2029 in Washington/Idaho.
 2029 in Medford/Roseburg.
Steeper demand highlights the flat demand risk discussed earlier. The likelihood of this
scenario occurring is remote due to a yearly recurrence of coldest day on record
weather paired with a much steeper growth of customer population; however, any
potential for accelerated unserved dates warrants close monitoring of demand trends
and resource lead times as described in the Ongoing Activities section of Chapter 8 –
2014
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Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 118 of 152
Chapter 6: Alternate Scenario, Portfolios and Stochastic Analysis

Action Items. The remaining scenarios do not identify resource deficiencies in the
planning horizon.
Due to their importance and connection with the IRP process, additional detailed
information on certain selected scenarios is included in the following appendices:
 Demand and Existing Resources graphs by service territory (High Growth Case
only) – Appendix 6.1.
 Peak Day Demand, Served and Unserved table (all cases) – Appendix 6.2.
 Avoided cost curve detail and graphs for High Growth and Low Growth cases –
Appendix 6.4.

Alternate Supply Resources
Avista identified supply-side resources that could meet resource deficiencies. Table 6.2
shows available supply-side scenarios considered for this IRP. There are many other
options; however, Avista excluded them from SENDOUT® modeling for this IRP given
the lack of need in the near term and the speculative nature of many of these resources.
For example, contracted city gate deliveries in the form of a structured purchase
transaction could meet peak conditions. However, the market-based price and other
terms are difficult to reliably determine until a formal agreement is negotiated. Exchange
agreements also have market-based terms and are hard to reliably model when the
resource need is later in the planning horizon.
Many of the potential resources are not yet commercially available or well tested
technically making them speculative. Resources such as coal-bed methane, LNG
imports and absorbed natural gas (ANG) would fall into this category. Avista will
continue to monitor all resources and assess their appropriateness for inclusion in future
IRPs as described in Chapter 8 – Ongoing Activities.
One resource which will be closely observed is exported LNG. While Avista considered
LNG exports, it was primarily as a price-influencing factor. However, if one of the
proposed export LNG terminals in Oregon were approved and a pipeline was to be built
to supply that facility, it potentially could bring supply through Avista’s service territory.
However, there is much uncertainty about export LNG because new pipelines are
expensive and there are currently existing pipeline options that are more cost effective.
Avista will monitor (Chapter 8 – Ongoing Activities) this situation through industry
publications and daily operations to consider inclusion of this supply scenario for future
IRPs.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 119 of 152
Chapter 6: Alternate Scenario, Portfolios and Stochastic Analysis
Table 6.2: Supply Scenarios

Portfolio Evaluation
There is no resource deficiency identified in the planning period and the existing
resource portfolio is adequate to meet forecasted demand. The alternate demand
scenarios and supply scenarios are matched together to form portfolios. This creates
bounds for analyzing the expected case by creating a high and low for customer count,
weather and pricing. Each portfolio runs through SENDOUT® where the supply
resources and demand-side resources are compared and selected on a least cost
basis. Supply resources include AECO, Sumas, Malin, Rockies, Stanfield trading hubs
and Jackson Prairie storage. Once resources are determined, a net present value of the
revenue requirement (PVRR) is calculated.
Table 6.3 summarizes the PVRR of the portfolios considered. Each portfolio is based on
unique assumptions and therefore a simple comparison of PVRR cannot be made.

Table 6.3: Net Present Value of Revenue Requirement (PVRR) by Portfolio

Stochastic Analysis1
The scenario (deterministic) analysis described earlier in this document represents
specific what if situations based on predetermined assumptions, including price and
weather. These factors are an integral part of scenario analysis. To understand a

1 SENDOUT® uses Monte Carlo simulation to support stochastic analysis, which is a mathematical
technique for evaluating risk and uncertainty. Monte Carlo simulation is a statistical modeling method used to imitate future possibilities that exist with a real-life system.
Portfolio
Unserved
Demand PVRR in (000's)
Average Case Average Demand with Existing Resources (before resource additions)No 4,463,055$
Expected Demand with Existing Resources (before resource additions)No 4,717,654$
High Growth, Low Price Demand with Existing Resources Yes 4,491,462$
Alternate Weather Standard Demand with Existing Resources No 4,557,367$
Low Growth, High Price with Existing Resources No 5,455,336$
Table 7.3 Net Present Value of Revenue Requirement (PVRR) by Portfolio
Expected Case
Additional Demand Scenarios
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 120 of 152
Chapter 6: Alternate Scenario, Portfolios and Stochastic Analysis

particular portfolio’s response to price and weather, Avista applied stochastic analysis to
generate a variety of price and weather events.
Deterministic analysis is a valuable tool for selecting an optimal portfolio. The model
selects resources to meet peak weather conditions in each of the 20 years. However,
due to the recurrence of design conditions in each of the 20 years, total system costs
over the planning horizon can be overstated because of annual recurrence of design
conditions and the recurrence of price increases in the forward price curve. As a result,
deterministic analysis does not provide a comprehensive look at future events. Utilizing
Monte Carlo simulation in conjunction with deterministic analysis provides a more
complete picture of portfolio performance under multiple weather and price profiles.
This IRP employs stochastic analysis in two ways. The first tested the weather-planning
standard and the second assessed risk related to costs of our Expected case (existing
portfolio) under varying price environments. The Monte Carlo simulation in SENDOUT®
can vary index price and weather simultaneously. This simulates the effects each have
on one another.

Weather In order to evaluate weather and its effect on the portfolio, Avista derived 200
simulations (draws) through SENDOUT®’s stochastic capabilities. Unlike deterministic
scenarios or sensitivities, the draws have more variability from month-to-month and
year-to-year. In the model, random monthly total HDD draw values (subject to Monte
Carlo parameters – see Table 6.4) are distributed on a daily basis for a month in history
with similar HDD totals. The resulting draws provide a weather pattern with variability in
the total HDD values, as well as variability in the shape of the weather pattern. This
provides a more robust basis for stress testing the deterministic analysis.

Table 6.4: Example of Monte Carlo Weather Inputs – Spokane

Avista models five weather areas: Spokane, Medford, Roseburg, Klamath Falls and La
Grande. Avista assessed the frequency that the peak day occurs in each area from the
Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
HDD Mean 895 1,152 1,145 913 781 546 331 143 37 37 191 544
HDD Std Dev 132 141 159 115 85 73 72 52 28 28 77 70
HDD Max 1,361 1,506 1,681 1,204 953 694 471 248 151 97 343 677
HDD Min 699 918 897 716 598 392 192 61 - 1 54 361
Table 7.4 Example of Monte Carlo Weather Inputs
Spokane
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 121 of 152
Chapter 6: Alternate Scenario, Portfolios and Stochastic Analysis
simulation data. The stochastic analysis shows that in over 200, 20-year simulations,
peak day (or more) occurs with enough frequency to maintain the current planning
standard for this IRP. This topic remains a subject of continued analysis. For example,
the Medford weather pattern over the 200 20-year draws (i.e., 4,000 years). HDDs at or
above peak weather (61 HDDs) occur 128 times. This equates to a peak day
occurrence once every 31 years (4,000 simulation years divided by 128 occurrences).
The Spokane area has the least occurrences of peak day (or more) occurrences and La
Grande has the most occurrences. This is primarily due to the frequency in which each
region’s peak day HDD occurs within the historical data, as well as near peak day
HDDs. See Figures 6.4 through 6.8 for the number of peak day occurrences by weather
area.

Figure 6.4: Frequency of Peak Day Occurrences – Spokane

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Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 122 of 152
Chapter 6: Alternate Scenario, Portfolios and Stochastic Analysis

Figure 6.5: Frequency of Peak Day Occurrences – Medford

Figure 6.6: Frequency of Peak Day Occurrences – Roseburg

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Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 123 of 152
Chapter 6: Alternate Scenario, Portfolios and Stochastic Analysis
Figure 6.7: Frequency of Peak Day Occurrences – Klamath Falls

Figure 6.8: Frequency of Peak Day Occurrences – La Grande

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Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 124 of 152
Chapter 6: Alternate Scenario, Portfolios and Stochastic Analysis

Price While weather is an important driver for the IRP, price is also important. As seen in
recent years, significant price volatility can affect the portfolio. In deterministic modeling,
a single price curve for each scenario is used for analysis. There is risk that the price
curve in the scenario will not reflect actual results.
Avista used Monte Carlo simulation to test the portfolio and quantify the risk to
customers when prices do not materialize as forecast. Avista performed a simulation of
200 draws, varying prices, to investigate whether the Expected Case total portfolio costs
from the deterministic analysis is within the range of occurrences in the stochastic
analysis. Figure 6.9 shows a histogram of the total portfolio cost of all 200 draws, plus
the Expected Case results. This histogram depicts the frequency and the total cost of
the portfolio among all the draws, the mean of the draws, the standard deviation of the
total costs, and the total costs from the Expected Case. The figure confirms that
Expected Case total portfolio cost is within an acceptable range of total portfolio costs
based on 200 unique pricing scenarios.

Figure 6.9: 2014 IRP Total 20-Year Cost

0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
-
10
20
30
40
50
60
4.980 5.000 5.130 5.140 5.150 5.160 5.170 5.180 5.190 5.200 5.210 5.220 5.230 5.244
Cu
m
u
l
a
t
i
v
e
Fr
e
q
u
e
n
c
y
$ Billions
Frequency
Cumulative

Mean 90th Percentile 95th Percentile
5%
P(Cost>5.225)=5%
10%
P(Cost>5.220)=10%
Average: 5.191StdDev: 0.025Min: 5.11890% percentile: 5.22095% percentile: 5.225Max: 5.244Expected: 8.685
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 125 of 152
Chapter 6: Alternate Scenario, Portfolios and Stochastic Analysis
Performing stochastic analysis on weather and price in the demand analysis provided a
statistical approach to evaluate and confirm the findings in the scenario analysis with
respect to adequacy and reasonableness of the weather-planning standard and the
natural gas price forecast. This analytical perspective provides more confidence in the
conclusions and stress tests the robustness of the selected portfolio of resources,
thereby mitigating analytical risks.

Regulatory Requirements
IRP regulatory requirements in Idaho, Oregon and Washington call for several key
components. The completed plan must demonstrate that the IRP:
 Examines a range of demand forecasts.
 Examines feasible means of meeting demand with both supply-side and
demand-side resources.
 Treats supply-side and demand-side resources equally.
 Describes the long-term plan for meeting expected demand growth.
 Describes the plan for resource acquisitions between planning cycles.
 Takes planning uncertainties into consideration.
 Involves the public in the planning process.
Avista addressed the applicable requirements throughout this document. Appendix 1.2
lists the specific requirements and guidelines of each jurisdiction and describes Avista’s
compliance.
The IRP is also required to consider risks and uncertainties throughout the planning and
analysis. Avista’s approach in addressing this requirement was to identify factors that
could cause significant deviation from the Expected Case planning conclusions. This
included dynamic demand analytical methods and sensitivity analysis on demand
drivers that impacted demand forecast assumptions. From this, Avista created 17
demand sensitivities and modeled five demand scenario alternatives, which
incorporated different customer growth, use-per-customer, weather, and price elasticity
assumptions.
Avista analyzed peak day weather planning standard, performing sensitivity on HDDs
and modeling an alternate weather-planning standard using the coldest day in 20 years.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 126 of 152
Chapter 6: Alternate Scenario, Portfolios and Stochastic Analysis

Stochastic analysis using Monte Carlo simulations in SENDOUT® supplemented this
analysis. Avista also used simulations from SENDOUT® to analyze price uncertainty
and the effect on total portfolio cost.
Avista examined risk factors and uncertainties that could affect expectations and
assumptions with respect to DSM programs and supply-side scenarios. From this,
Avista assessed the expected available supply-side resources and potential DSM
savings for evaluation.
The investigation, identification, and assessment of risks and uncertainties in our IRP
process should reasonably mitigate surprise outcomes.
Conclusion
The High Growth and Low Growth Case demand analyses provide a range for
evaluating demand trajectories relative to the Expected Case. Based on this analysis
there appears to be sufficient time to plan for forecasted resource needs. Even under an
extreme growth scenario, the first forecasted deficiency does not occur until 2029. Many
things could happen between now and when the first resource needs occur, so Avista
we will carefully monitor (Chapter 8 – Action Items) demand trends through reconciling
and comparing forecast to actual customer counts and continually update and evaluate
all demand-side and supply-side alternatives.

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 127 of 152
Chapter 6: Alternate Scenario, Portfolios and Stochastic Analysis

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 128 of 152
Chapter 7: Distribution Planning
7: Distribution Planning

Overview
Avista’s integrated resource planning encompasses evaluation of safe, economical and
reliable full-path delivery of natural gas from basin to the customer meter. Securing
adequate natural gas supply and ensuring sufficient pipeline transportation capacity to
city gates become secondary issues if distribution system growth behind the city gates
becomes severely constrained. Important parts of the planning process include
forecasting local demand growth, determining potential distribution system constraints,
analyzing possible solutions, and estimating costs for eliminating constraints.
Analyzing resource needs to this point has focused on ensuring adequate capacity to
the city gates, especially during a peak event. Distribution planning focuses on
determining if there will be adequate pressure during a peak hour. Despite this altered
perspective, distribution planning shares many of the same goals, objectives, risks and
solutions as resource planning.
Avista’s natural gas distribution system consists of approximately 3,000 miles of
distribution main pipelines in Idaho, 3,500 miles in Oregon and 5,400 miles in
Washington, as well as numerous regulator stations, service distribution lines,
monitoring and metering devices, and other equipment. Currently, there are no storage
facilities or compression systems within Avista’s distribution system. Pressure regulating
stations that utilize pipeline pressures from the interstate transportation pipelines before
natural gas enters our distribution networks maintains system pressure.

Distribution System Planning
Avista conducts two primary types of evaluations in its distribution system planning
efforts to determine the need for resource additions, including distribution system
reinforcements and expansions. Reinforcements are upgrades to existing infrastructure,
or new system additions, which increase system capacity, reliability and safety.
Expansions are new system additions to accommodate new demand. Collectively,
these are distribution enhancements.
Ongoing evaluations of each distribution network in the four primary service territories
identify strategies for addressing local distribution requirements resulting from customer
growth. Customer growth assessments are made based on factors including IRP
demand forecasts, monitoring gate station flows and other system metering, ongoing
communication about new service requests, field personnel discussion, and inquiries
from major developers.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 129 of 152
Chapter 7: Distribution Planning
Additionally, Avista regularly conducts integrity assessments of its distribution systems.
Ongoing system evaluation can also indicate distribution-upgrading requirements for
system maintenance needs rather than customer and load growth. In some cases, the
timing for system integrity upgrades coincides with growth-related expansion
requirements.
These planning efforts provide a long-term planning and strategy outlook and integrate
into the capital planning and budgeting process, which incorporates planning for other
types of distribution capital expenditures and infrastructure upgrades.

Network Design Fundamentals
Natural gas distribution networks rely on pressure differentials to flow natural gas from
one place to another. When pressures are the same on both ends of a pipe, the natural
gas does not move. When natural gas is removed from a point on the network, the
pressure at that point drops below the pressure upstream in the network and moves
from the higher pressure area in the network to the point of removal to equalize
pressure throughout the network. If the amount of natural gas removed is not replaced,
the pressure differential decreases, flow stalls and the network could run out of
pressure. Therefore, it is important to design a distribution network so that intake
pressure (from gate stations and/or regulator stations) within the network is high enough
to maintain an adequate pressure differential when natural gas leaves the network.
Not all natural gas flows equally throughout a network. Certain points within the network
constrain flow and restrict overall network capacity. Network constraints can occur as
demand requirements evolve. Anticipating these demand requirements, identifying
potential constraints and forming cost-effective solutions with sufficient lead times
without overbuilding infrastructure are the key challenges in network design.

Computer Modeling
Developing and maintaining effective network design is aided by computer modeling for
network demand studies. Demand studies have evolved with technology in the past
decade to become a highly technical and powerful means of analyzing distribution
system performance. Using a pipeline fluid flow formula, a specified parameter for each
pipe element can be simultaneously solved. Many pipeline equations exist, each
tailored to a specific flow behavior. Through years of research, these equations have
been refined to the point where modeling solutions produced closely resemble actual
system behavior.
Avista conducts network load studies using GL Noble Denton’s SynerGEE® software.
This computer-based modeling tool allows users to analyze and interpret solutions
graphically. Appendix 7.1 describes the computer modeling methodology while
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 130 of 152
Chapter 7: Distribution Planning
Appendix 7.2 provides an example load study including graphical interface and output
examples.

Determining Peak Demand
Avista’s distribution network is comprised of high pressure (90-500 psig) and
intermediate pressure (5-60 psig) mains. Avista operates its intermediate networks at a
relatively low maximum pressure of 60 psig or less for ease of maintenance and
operation, public safety, reliable service, and cost considerations. Since the majority of
distribution systems operate through relatively small diameter pipes, there is essentially
no line-pack capability for managing hourly demand fluctuations.
Core demand typically has a morning peaking period between 6 a.m. and 10 a.m. and
an evening peaking period between 5 p.m. and 9 p.m. The peak hour demand for these
customers can be as much as 50 percent above the hourly average of daily demand.
Because of the importance of responding to hourly peaking in the distribution system,
planning capacity requirements for distribution systems uses peak hour demand.1
Appendix 7.1 shows the methodology Avista uses for determining peak demand.

Distribution System Enhancements
Computer-aided demand studies facilitate modeling numerous demand forecasting
scenarios, constraint identification and corresponding optimum combination of pipe
modification, and pressure modification solutions to maintain adequate pressures
throughout the network.
Distribution system enhancements do not reduce demand nor do they create additional
supply. Enhancements can increase the overall capacity of a distribution pipeline
system while utilizing existing gate station supply points. The three broad categories of
distribution enhancement solutions are pipelines, regulators and compression.

Pipelines
Pipeline solutions consist of looping, upsizing and uprating. Pipeline looping is the most
common method of increasing capacity in an existing distribution system. It involves
constructing new pipe parallel to an existing pipeline that has, or may become, a
constraint point. Constraint points inhibit flow capacities downstream of the constraint
creating inadequate pressures during periods of high demand. When the parallel line
connects to the system, this alternative path allows natural gas flow to bypass the
original constraint and bolsters downstream pressures. Looping can also involve

1 This method differs from the approach that Avista uses for IRP peak demand planning, which focuses on peak day requirements to the city gate.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 131 of 152
Chapter 7: Distribution Planning
connecting previously unconnected mains. The feasibility of looping a pipeline depends
upon the location where the pipeline will be constructed. Installing gas pipelines through
private easements, residential areas, existing asphalt, and steep or rocky terrain can
greatly increase the cost to a point where alternative solutions are more cost effective.
Pipeline upsizing involves replacing existing pipe with a larger size pipe. The increased
pipe capacity relative to surface area results in less friction, and therefore a lower
pressure drop. This option is usually pursued when there is damaged pipe or pipe
integrity issues exist. If the existing pipe is otherwise in satisfactory condition, looping
augments existing pipe, which remains in use.
Pipeline uprating increases the maximum allowable operating pressure of an existing
pipeline. This enhancement can be a quick and relatively inexpensive method of
increasing capacity in the existing distribution system before constructing more costly
additional facilities. However, safety considerations and pipe regulations may prohibit
feasibility or lengthen the time before completion of this option. Also, increasing line
pressure may produce leaks and other pipeline damage creating costly repairs. A
thorough review is conducted to ensure integrity before pressure is increased.

Regulators
Regulators, or regulator stations, reduce pipeline pressure at various stages in the
distribution system. Regulation provides a specified and constant outlet pressure before
natural gas continues its downstream travel to a city’s distribution system, customer’s
property or gas appliance. Regulators also ensure that flow requirements are met at a
desired pressure regardless of pressure fluctuations upstream of the regulator.
Regulators are at city gate stations, district regulators stations, farm taps and customer
services.

Compression
Compressor stations present a capacity enhancing option for pipelines with significant
natural gas flow and the ability to operate at higher pressures. For pipelines
experiencing a relatively high and constant flow of natural gas, a large volume
compressor installation along the pipeline boosts downstream pressure.
A second option is the installation of smaller compressors located close together or
strategically placed along a pipeline. Multiple compressors accommodate a large flow
range and use smaller and very reliable compressors. These smaller compressor
stations are well suited for areas where gas demand is growing at a relatively slow and
steady pace, so that purchasing and installing these less expensive compressors over
time allows a pipeline to serve growing customer demand for into the future.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 132 of 152
Chapter 7: Distribution Planning
Compressors can be a cost effective option to resolving system constraints; however,
regulatory and environmental approvals to install a station, along with engineering and
construction time can be a significant deterrent. Adding compressor stations typically
involves considerable capital expenditure. Based on Avista’s detailed knowledge of the
distribution system, there are no foreseeable plans to add compressors to the
distribution network.

Conservation Resources
Included in the evaluation of distribution system constraints is the 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 longer-term, targeted
conservation programs provide a cumulative benefit that offsets potential constraint
areas and may be an effective strategy.

Planning Results
Table 7.1 summarizes the cost of major distribution system enhancements addressing
growth-related system constraints, system integrity issues and the timing of these
expenditures. These projects are preliminary estimates of timing and costs of major
reinforcement solutions. The scope and needs of these projects generally evolves with
new information requiring ongoing reassessment. Actual solutions may differ due to
differences in actual growth patterns and/or construction conditions from the initial
assessment.
The following discussion provides information about key near-term projects:
East Medford Reinforcement: Previous IRP and distribution planning analysis
identified a near-term resource deficiency driven by forecasted local growth. Increased
natural gas deliveries from the TransCanada Pipeline source at Phoenix Road Gate
Station in southeast Medford will remedy this deficiency. To facilitate distribution receipt
of the increased natural gas volumes, a new high-pressure (HP) line encircling Medford
to the east and tying into an existing high-pressure line in White City will improve
delivery capacity and provide reinforcement in the East Medford area.
This has been a multi-phase project spanning several years. As forecasted, needs have
changed over time, and with no immediate resource need, completing the final phase of
the project has been delayed. Other factors may drive completion of the project
including reliability needs, flexibility of natural gas supply management and optimizing
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 133 of 152
Chapter 7: Distribution Planning
synergies of other construction projects to reduce project cost. Avista will continue to
evaluate forecasts and assess the most appropriate timing for completion of this project.
U.S. Highway 2 North Spokane Reinforcement: This project will reinforce the area
north of Spokane along U.S. Highway 2. This mixed-use area experiences low
pressure during winter at unpredictable times given demand profiles of the diverse
customer base. Completion of this reinforcement will improve pressures in the U.S. 2
North Kaiser area. Approximately 8,000 feet of HP steel gas main will be installed in a
newly established easement along U.S. Highway 2.
Chase Road Gate Station, Post Falls, Idaho: This gate station will allow Avista to split
the large load at the Rathdrum Gate Station. Approximately 18,000 feet of new HP line
will connect the Chase Road Gate Station to the existing HP line. This gate station will
give Avista the opportunity to feed the growing Post Falls and Coeur d’Alene areas from
the north.

Table 7.1 Distribution Planning Capital Projects

2015 2016 2017 2018
Pr
o
j
e
c
t
s

*East Medford
Reinforcement $0 $0 $0 $5,000,000
Goldendale HP $3,500,000 $0 $0 $0
NSC Greene ST
HP $0 $0 $0 $1,500,000
Rathdrum Prairie
HP Gas
Reinforcement $100,000 $4,900,000 $5,000,000 $0
*Reinforcement,
Hwy 2 Kaiser $1,300,000 $0 $0 $0
Spokane St
Bridge Gas $1,000,000 $0 $0 $0
*Details of project described in IRP

Table 7.2 shows city gate stations identified as over utilized or under capacity.
Estimated cost, year and the plan to remediate the capacity concern are shown.

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 134 of 152
Chapter 7: Distribution Planning
Table 7.2 City Gate Station Upgrades
Location Gate Stn Project to Remediate Cost Year
Athol, ID Athol #219 TBD - 2019+
Genesee, ID Genesee #320 TBD - 2019+
Rathdrum, ID *Chase Rd
Chase Rd Gate Stn &
Hayden Ave HP Main $5.4M 2014
CDA (East),
ID CDA East #221
Rathdrum Prairie HP
Gas Reinforcement $10M 2016-17 Post Falls, ID McGuire #213
CDA (West),
ID
Post Falls &
CDA West
Colton, WA Colton #316 TBD - 2019+
Sutherlin, OR Sutherlin #2626 TBD - 2019+
La Grande,
OR
La Grande
#815 & Union
#817 Union HP Connector $3M 2019+
*Details of project described in IRP

CONCLUSION
Avista’s goal is to maintain its distribution systems reliably and cost effectively to deliver
natural gas to every customer. This goal relies on computer modeling to increase the
capacity and reliability of the distribution system by identifying specific areas that may
require changes.
The ability to meet the goal of reliable and cost effective gas delivery is enhanced
through localized distribution planning, which enables coordinated targeting of
distribution projects responsive to customer growth patterns.

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 135 of 152
Chapter 7: Distribution Planning

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 136 of 152
Chapter 8: Action Plan

8: Action Plan

2013-2014 Action Plan Review

Action Item
Avista will monitor actual demand for indications of deviations away from the Expected
Case.
Results
Forecast to actual analysis reveals that the modeling techniques are producing
forecasts that track actual demand. Recent natural gas demand does not show
significant deviation away from expected results.

Action Item
Continued enhancement of the gate station analysis will assess if the aggregated IRP
analysis masks any individual gate station deficiencies. Any deficiencies identified and
potential solutions will be discussed with Commission Staff. Avista will continue to
coordinate analytic efforts between Gas Supply, Gas Engineering and the intrastate
pipelines to perform gate station analysis and seek least cost solutions for any identified
deficiencies.
Results
Avista is completing the gate analysis in Oregon on the NWP system. Any deficiencies
will be communicated along with solutions for rectifying the deficiencies to Commission
Staff. The gates along the GTN system will be reviewed next.

Action Item
Avista filed in Idaho, Oregon and Washington to suspend natural gas DSM programs
due to the low avoided costs in the 2012 IRP. Over the next two to three years, Avista
will review natural gas prices as a signpost for the cost-effectiveness of DSM programs.
If natural gas prices increase enough, Avista will seek to reinstate a full complement of
natural gas DSM programs.
Results
Idaho approved the filing, and natural gas DSM programs were suspended. In Oregon,
DSM programs will continue for a two-year period. During that time, Avista will evaluate
program costs and develop a separate program for low-income participants. In
Washington, DSM programs were also allowed to continue for a limited period and the
test for evaluating cost effectiveness was changed from the total resource cost to the
utility cost test.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 137 of 152
Chapter 8: Action Plan

Action Item Pursue the possibility of a regional elasticity study through the NGA or the AGA.
Results
Price elasticity theory predicts that energy consumers will reduce consumption as prices
rise. The amount of a response is debatable. Avista has reviewed historic research on
price elasticity. The analysis shows a wide range of results from statistically significant
to statistically insignificant and even positive in some cases.
Avista contacted the NGA and they are still willing to help facilitate a process if a
regional price elasticity study moves forward. At this time, Avista is assessing the costs
and benefits of such an undertaking. A regional natural gas price elasticity study will
commence if enough interest develops in the project.

2015-2016 Action Plan
The recent recession significantly affected the expected long-term customer growth in
Avista’s service territory. This natural gas demand reduction has created no resource
needs in the Expected Case within the 20-year planning horizon. Scenario analysis
shows that even in the most robust growth case, Avista will not have a resource
deficiency until very late in the 20-year forecast.
With no immediate resource needs, Avista can evaluate current resources and potential
future resources. Avista will continue to optimize underutilized resource to recover value
for customers and reduce their costs until resources are required to meet changing
demand needs.
Avista remains committed to offering cost-effective conservation measures as a way for
customers to reduce their energy bills and promote a cleaner environment. Like the
2012 IRP, the low price of natural gas has reduced the amount of cost-effective DSM
measures. Based on the latest CPA, incorporating the lower avoided costs, Avista
estimates 22,800 Dth of first year savings in Idaho, 16,100 Dth of savings in Oregon
and 128,700 Dth of savings in Washington. .
Avista will comply with Commission findings to try to increase the cost effectiveness of
DSM measures by reducing administration and audit costs, analyzing non-natural gas
benefits and increasing measure lives. Avista will monitor natural gas prices as signpost
for increasing avoided costs. If avoided costs increase, Avista will evaluate DSM
programs for cost effectiveness and submit to resume natural gas DSM options.
Complete the gate station analysis to assess resource deficiencies masked by
aggregated IRP analysis. Any identified deficiencies and potential solutions will be
discussed with Commission Staff. Avista will continue to coordinate analytic efforts
between Gas Supply, Gas Engineering and the intrastate pipelines to perform gate
station analysis and develop least cost solutions should deficiencies exist.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 138 of 152
Chapter 8: Action Plan

Ongoing Activities
 Monitor actual demand for indications of growth exceeding the forecast to
respond aggressively to address accelerated resource deficiencies arising from
flat demand risk. This will include providing Commission Staff with IRP demand
forecast to actual variance analysis on customer growth and use-per-customer.
Avista will provide this information in updates to Commission Staff at least
biannually.
 Continue to monitor supply resource trends, including the availability and price of
natural gas to the regions, LNG exports, Canadian natural gas imports and
interprovincial consumption trends, regional plans for natural gas-fired
generation, and its affect on pipeline availability, as well as regional pipeline and
storage infrastructure plans.
 Monitor new resource lead-time requirements relative to resource need to
preserve resource option flexibility.
 Regularly meet with Commission Staff members to provide information on market
activities and significant changes in assumptions and/or status of Avista’s
activities related to the IRP and natural gas procurement practices.

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 139 of 152
Chapter 8: Action Plan

Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 140 of 152
Chapter 9: Glossary of Terms and Acronyms

9: Glossary of Terms and Acronyms

Achievable Potential
Represents a realistic assessment of expected energy savings, recognizing and
accounting for economic and other constraints that preclude full installation of every
identified conservation measure.
AGA
American Gas Association
Annual Measures
Conservation measures that achieve generally uniform year-round energy savings
independent of weather temperature changes. Annual measures are also often called
base load measures.
Average Case
Represents Avista’s demand forecast for normal planning purposes. This case uses a 20 year rolling average NOAA weather for the five major areas (Spokane, WA.,
Medford, OR. Klamath Falls, OR, Roseburg, OR. La Grande, OR.).
Avista
The regulated Operating Division of Avista Corp.; separated into north (Washington and
Idaho) and south (Oregon) regions. Avista Utilities generates, transmits and distributes
electricity, in addition to the transmission and distribution of natural gas.
Backhaul
A transaction where gas is transported the opposite direction of normal flow on a
unidirectional pipeline.
Base Load
As applied to natural gas, a given demand for natural gas that remains fairly constant
over a period of time, usually not temperature sensitive.
Base Load Measures
Conservation measures that achieve generally uniform year-round energy savings
independent of weather temperature changes. Base load measures are also often
called annual measures.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 141 of 152
Chapter 9: Glossary of Terms and Acronyms

Basis Differential
The difference in price between any two natural gas pricing points or time periods. One
of the more common references to basis differential is the pricing difference between
Henry Hub and any other pricing point in the continent.
British Thermal Unit (BTU)
The amount of heat required to raise the temperature of one pound of pure water one
degree Fahrenheit under stated conditions of pressure and temperature; a therm (see
below) of natural gas has an energy value of 100,000 BTUs and is approximately
equivalent to 100 cubic feet of natural gas.
Capacity
The sum amount of natural gas transportation contracts or storage available in Avista’s
current portfolio.
CD
Contract Demand
C&I
Commercial and Industrial
City Gate (also known as gate station or pipeline delivery point)
The point at which natural gas deliveries transfer from the interstate pipelines to Avista’s
distribution system.
CNG
Compressed Natural Gas
Compression
Increasing the pressure of natural gas in a pipeline by means of a mechanically-driven
compressor station to increase flow capacity.
Conservation Measures
Installations of appliances, products or facility upgrades that result in energy savings.
Contract Demand (CD)
The maximum daily, monthly, seasonal or annual quantities of natural gas, which the
supplier agrees to furnish, or the pipeline agrees to transport, and for which the buyer or
shipper agrees to pay a demand charge.
Core Load
Firm delivery requirements of Avista, which are comprised of residential, commercial
and firm industrial customers.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 142 of 152
Chapter 9: Glossary of Terms and Acronyms

Cost Effectiveness
The determination of whether the present value of the therm savings for any given
conservation measure is greater than the cost to achieve the savings.
CPA
Conservation Potential Assessment
CPI
Consumer Price Index, as calculated and published by the U.S. Department of Labor,
Bureau of Labor Statistics
Cubic Foot (cf)
A measure of natural gas required to fill a volume of one cubic foot under stated
conditions of temperature, pressure and water vapor; one cubic foot of natural gas has
the energy value of approximately 1,000 BTUs and 100 cubic feet of natural gas
equates to one therm (see below).
Curtailment
A restriction or interruption of natural gas supplies or deliveries; may be caused by
production shortages, pipeline capacity or operational constraints or a combination of
operational factors.
Dekatherm (Dth)
Unit of measurement for natural gas; a dekatherm is 10 therms, which is one thousand
cubic feet (volume) or one million BTUs (energy).
Demand-Side Management (DSM)
The activity pursued by an energy utility to influence its customers to reduce their
energy consumption or change their patterns of energy use away from peak
consumption periods.
Demand-Side Resources
Energy resources obtained through assisting customers to reduce their "demand" or
use of natural gas. Also represents the aggregate energy savings attained from
installation of conservation measures.
DSM
Demand-Side Management
Dth
Unit of measurement for natural gas; a dekatherm is 10 therms, which is one thousand
cubic feet (volume) or one million BTUs (energy).
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 143 of 152
Chapter 9: Glossary of Terms and Acronyms

EIA
Energy Information Administration
Expected Case
The most likely scenario for peak day planning purposes. This case uses a 20 year
rolling average NOAA weather for the five major areas (Spokane, WA., Medford, OR.
Klamath Falls, OR, Roseburg, OR. La Grande, OR.). Combined with this 20 year rolling
average weather is the coldest day on record.
External Energy Efficiency Board
Also known as the "Triple-E" board, this non-binding external oversight group was
established in 1999 to provide Avista with input on DSM issues.
Externalities
Costs and benefits borne by a third party not reflected in the price paid for goods or
services.
Federal Energy Regulatory Commission (FERC)
The government agency charged with the regulation and oversight of interstate natural
gas pipelines, wholesale electric rates and hydroelectric licensing; the FERC regulates
the interstate pipelines with which Avista does business and determines rates charged
in interstate transactions.
FERC
Federal Energy Regulatory Commission
Firm Service
Service offered to customers under schedules or contracts that anticipate no
interruptions; the highest quality of service offered to customers.
Force Majeure
An unexpected event or occurrence not within the control of the parties to a contract,
which alters the application of the terms of a contract; sometimes referred to as "an act
of God;" examples include severe weather, war, strikes, pipeline failure and other
similar events.
Forward Haul
A transaction where gas is transported the normal direction of normal flow on a
unidirectional pipeline.
Forward Market
An over-the-counter marketplace that sets the price of a financial instrument or physical
asset for future delivery.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 144 of 152
Chapter 9: Glossary of Terms and Acronyms

Forward Price
The future price for a quantity of natural gas to be delivered at a specified time.
Gas Transmission Northwest (GTN)
A subsidiary of TransCanada Pipeline which owns and operates a natural gas pipeline
that runs from the Canada/USA border to the Oregon/California border. One of the six
natural gas pipelines Avista transacts with directly.
Geographic Information System (GIS)
A system of computer software, hardware and spatially referenced data that allows
information to be modeled and analyzed geographically.
GHG
Greenhouse Gas
Global Insight, Inc.
A national economic forecasting company.
GTN
Gas Transmission Northwest
Heating Degree Day (HDD)
A measure of the coldness of the weather experienced, based on the extent to which
the daily average temperature falls below 65 degrees Fahrenheit; a daily average
temperature represents the sum of the high and low readings divided by two.
Henry Hub
The physical location in Louisiana that is widely recognized as the most important
natural gas pricing point in the U.S., as well as the trading hub for the New York
Mercantile Exchange (NYMEX).
HP
High Pressure
Injection
The process of putting natural gas into a storage facility; also called liquefaction when
the storage facility is a liquefied natural gas plant.
Integrity Management Plan
A federally regulated program that requires companies to evaluate the integrity of their
natural gas pipelines based on population density. The program requires companies to
identify high consequence areas, assess the risk of a pipeline failure in the identified
areas and provide appropriate mitigation measures when necessary.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 145 of 152
Chapter 9: Glossary of Terms and Acronyms

Interruptible Service
A service of lower priority than firm service offered to customers under schedules or
contracts that anticipate and permit interruptions on short notice. The interruption
happens when the demand of all firm customers exceeds the capability of the system to
continue deliveries to all of those customers.
IPUC
Idaho Public Utilities Commission
IRP
Integrated Resource Plan; the document that explains Avista’s plans and preparations
to maintain sufficient resources to meet customers’ natural gas needs at a reasonable
price.
Jackson Prairie
An underground natural gas storage project jointly owned by Avista Corp., Puget Sound
Energy and NWP. The project is a naturally occurring aquifer near Chehalis, Wash.,
which is located about 1,800 feet beneath the surface and capped with a thick layer of
dense shale.
Liquefaction
Any process converting natural gas from the gaseous to the liquid state. For natural
gas, this process is accomplished through lowering the temperature of the natural gas
(see LNG).
Liquefied Natural Gas (LNG)
Natural gas liquefied by reducing its temperature to minus 260 degrees Fahrenheit at
atmospheric pressure.
Linear Programming
A mathematical method of solving problems by means of linear functions where the
multiple variables involved are subject to constraints; this method is utilized in the
SENDOUT® Gas Model.
Load Duration Curve
An array of daily send outs observed, sorted from highest send out day to lowest to
demonstrate peak requirements and the number of days it persists.
Load Factor
The average load of a customer, a group of customers or an entire system, divided by
the maximum load; can be calculated over any time period.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 146 of 152
Chapter 9: Glossary of Terms and Acronyms

Local Distribution Company (LDC)
A utility that purchases natural gas for resale to end-use customers and/or delivers
customer's natural gas or electricity to end users' facilities.
Looping
The construction of a second pipeline parallel to an existing pipeline over the whole or
any part of its length, thus increasing the capacity of that section of the system.
MCF
A unit of volume equal to a thousand cubic feet.
MDDO
Maximum Daily Delivery Obligation
MDQ
Maximum Daily Quantity
MMbtu
A unit of heat equal to one million British thermal units (BTUs) or 10 therms. Used
interchangeably with Dth.
National Energy Board
The Canadian equivalent to the Federal Energy Regulatory Commission (FERC).
National Oceanic Atmospheric Administration (NOAA)
Publishes the latest weather data; the 30-year weather study included in this IRP is
based on this information.
Natural Gas
A naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in
porous geologic formations beneath the earth's surface, often in association with
petroleum; the principal constituent is methane and it is lighter than air.
New York Mercantile Exchange (NYMEX)
An organization that facilitates the trading of several commodities, including natural gas.
NGV
Natural Gas Vehicles
NOAA
National Oceanic and Atmospheric Administration
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 147 of 152
Chapter 9: Glossary of Terms and Acronyms

Nominal
Discounting method that includes inflation.
Nomination
The scheduling of daily natural gas requirements.
Non-Coincidental Peak Demand
The demand forecast for a 24-hour period for multiple regions that includes at least one
peak day and one non-peak day.
Non-Firm Open Market Supplies
Natural gas purchased via short-term purchase arrangements. May supplement firm
contracts during times of high demand or to displace other volumes when cost-effective.
Also referred to as spot market supplies.
Northwest Pipeline Corporation (NWP)
A principal interstate pipeline serving the Pacific Northwest and one of six natural gas
pipelines Avista transacts with directly. NWP is a subsidiary of The Williams
Companies, headquartered in Salt Lake City, Utah.
NOVA Gas Transmission (NOVA)
See TransCanada Alberta System
Northwest Power and Conservation Council (NPCC)
A regional energy planning and analysis organization headquartered in Portland, Ore.
NPCC
Northwest Power and Conservation Council
NWP
Williams-Northwest Pipeline
NYMEX
New York Mercantile Exchange
OPUC
Oregon Public Utility Commission
Peak Day
The greatest total natural gas demand forecasted in a 24-hour period used as a basis
for planning peak capacity requirements.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 148 of 152
Chapter 9: Glossary of Terms and Acronyms

Peak Day Curtailment
Curtailment imposed on a day-to-day basis during periods of extremely cold weather
when demands for natural gas exceed the maximum daily delivery capability of a
pipeline system.
Peaking Capacity
The capability of facilities or equipment normally used to supply incremental natural gas
under extreme demand conditions (i.e. peaks); generally available for a limited number
of days at this maximum rate.
Peaking Factor
A ratio of the peak hourly flow and the total daily flow at the city-gate stations used to
convert daily loads to hourly loads.
Prescriptive Measures
Avista's DSM tariffs require the application of a formula to determine customer
incentives for natural gas-efficiency projects. For commonly encountered efficiency
applications that are relatively uniform in their characteristics, the utility has the option to
define a standardized incentive based upon the typical application of the efficiency
measure. This standardized incentive takes the place of a customized calculation for
each individual customer. This streamlining reduces both the utility and customer
administrative costs of program participation and enhances the marketability of the
program.
Psig
Pounds per square inch gauge  a measure of the pressure at which natural gas is
delivered.
PVRR
Present Value Revenue Requirement
Rate Base
The investment value established by a regulatory authority upon which a utility is
permitted to earn a specified rate of return; generally this represents the amount of
property used and useful in service to the public.
Real
Discounting method that excludes inflation.
Resource Stack
Sources of natural gas infrastructure or supply available to serve Avista’s customers.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 149 of 152
Chapter 9: Glossary of Terms and Acronyms

Seasonal Capacity
Natural gas transportation capacity designed to service in the winter months.
Sendout
The amount of natural gas consumed on any given day.
SENDOUT®
Natural gas planning system from Ventyx; a linear programming model used to solve
gas supply and transportation optimization questions.
Service Area
Territory in which a utility system is required or has the right to provide natural gas
service to ultimate customers.
Spot Market Gas
Natural gas purchased under short-term agreements as available on the open market;
prices are set by market pressure of supply and demand.
Storage
The utilization of facilities for storing natural gas which has been transferred from its
original location for the purposes of serving peak loads, load balancing and the
optimization of basis differentials; the facilities are usually natural geological reservoirs
such as depleted oil or natural gas fields or water-bearing sands sealed on the top by
an impermeable cap rock; the facilities may be man-made or natural caverns. LNG
storage facilities generally utilize above ground insulated tanks.
TAC
Technical Advisory Committee
Tariff
A published volume of regulated rate schedules, plus general terms and conditions
under which a product or service will be supplied.
TF-I
NWP's rate schedule under which Avista moves natural gas supplies on a firm basis.
TF-2
NWP's rate schedule under which Avista moves natural gas supplies out of storage
projects on a firm basis.
Technical Advisory Committee (TAC)
Industry, customer and regulatory representatives that advise Avista during the IRP
planning process.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 150 of 152
Chapter 9: Glossary of Terms and Acronyms

Technical Potential
An estimate of all energy savings that could theoretically be accomplished if every
customer who could potentially install a conservation measure did so without
consideration of market barriers such as cost and customer awareness.
Therm
A unit of heating value used with natural gas that is equivalent to 100,000 British
thermal units (BTU); also approximately equivalent to 100 cubic feet of natural gas.
Town Code
A town code is an unincorporated area within a county and a municipality within a
county served by Avista natural gas retail services.
TransCanada Alberta System
Previously known as NOVA Gas Transmission; a natural gas gathering and
transmission corporation in Alberta that delivers natural gas into the TransCanada BC
System pipeline at the Alberta/British Columbia border; one of six natural gas pipelines
Avista transacts with directly.
TransCanada BC System
Previously known as Alberta Natural Gas; a natural gas transmission corporation of
British Columbia that delivers natural gas between the TransCanada-Alberta System
and GTN pipelines that runs from the Alberta/British Columbia border to the United
States border; one of six natural gas pipelines Avista transacts with directly.
Transportation Gas
Natural gas purchased either directly from the producer or through a broker and is used
for either system supply or for specific end-use customers, depending on the
transportation arrangements; NWP and GTN transportation may be firm or interruptible.
TRC
Total Resource Cost
Triple E
External Energy Efficiency Board
Tuscarora Gas Transmission Company
Tuscarora is a subsidiary of Sierra Pacific Resources and TransCanada; this natural
gas pipeline runs from the Oregon/California border to Reno, Nev.; one of the six
natural gas pipelines Avista transacts with directly;
Vaporization
Any process in which natural gas is converted from the liquid to the gaseous state.
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 151 of 152
Chapter 9: Glossary of Terms and Acronyms

WCSB
Western Canadian Sedimentary Basin
Weighted Average Cost of Gas (WACOG)
The price paid for a volume of natural gas and associated transportation based on the
prices of individual volumes of natural gas that make up the total quantity supplied over
an established time period.
Weather Normalization
The estimation of the average annual temperature in a typical or "normal" year based
on examination of historical weather data; the normal year temperature is used to
forecast utility sales revenue under a procedure called sales normalization.
Weather Sensitive Measures
Conservation measures whose energy savings are influenced by weather temperature
changes. Weather sensitive measures are also often referred to as winter measures.
Winter Measures
Conservation measures whose energy savings are influenced by weather temperature
changes. Winter measures are also often referred to as weather sensitive measures.
Withdrawal
The process of removing natural gas from a storage facility, making it available for
delivery into the connected pipelines; vaporization is necessary to make withdrawals
from an LNG plant.
WUTC
Washington Utilities and Transportation Commission
Exhibit No. 7 Case No. AVU-G-15-01
J. Morehouse, Avista
Schedule 1, P. 152 of 152