200603312006 IRP.pdf

Avista Corp.
1411 East Mission PO Box3727
Spokane, Washington 99220-3727
Telephone [phone]
Toll Free 800-727-9170
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Corp.
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March 30, 2006
Jean D. Jewell, Secretary
Idaho Public Utilities Commission
Statehouse Mail
W. 472 Washington Street
Boise, Idaho 83720
Avu-
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Dear Ms. Jewell:
RE:Avista Utilities 2006 Natural Gas Integrated Resource Plan
Per IPUC's Integrated Resource Plan Requirements outlined in Case No.GNR-93-
Order No. 25342, A vista Corporation d/b/a! A vista Utilities, hereby submits for filing an
original and 7 copies of its 2006 Natural Gas Integrated Resource Plan.
The Company submits the IRP to public utility commissions in Idaho , Washington and
Oregon every two years as required by state regulation. The Company has a statutory
obligation to provide reliable natural gas service to customers at rates, tenns and
conditions that are fair, just, reasonable and sufficient. A vista regards the IRP as a
methodology for identifying and evaluating various resource options and as a process by
which to establish a plan of action for resource decisions.
Please direct any questions regarding this report to Kevin Christie at [phone].
Sincerely,
~,..~
Kelly Norwood
Vice President, State and Federal Regulation
Mr. Harry Hall
; j
TABLE OF CONTENTS
" ,' ," ,,, .., ,:: ' ..,
Section 1: Executive SJilirrlJY~.
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f; 1:);; '. U . . 1.1
Section 2: Natural Gas Demand Forecast. . . . . . . . . .
Section 3: Demand-Side Management. . . . . . . . . . . . 3.
Section 4: Distribution Planning. . . . . . . . . . . . . . . . 4.
Section 5: Supply-Side Resources. . . . . . . . . . . . . . . 5.
Section 6: Integrated Resource Portfolio. . . . . . . . . . 6.
Section 7: Avoided Cost Determination. . . . . . . . . . . 7.
Section8:ActionPlan....................... .
Section9:Glossary..........................
Note: Appendices Provided Under Separate Cover
2006 NATURAL GAS INTEGRATED RESOURCE PLAN
TABLES
Table 2.1 - Demand Coefficients
Table 2.2 - Price-Related Demand Adjustments for Demand Scenarios
Table 2.3 - Demand Scenarios
Table 2.4 - Annual Average Demand Percentage Increases
Table 3.1 - Measure vs. Program Categorization Matrix
Table 3.2 - Geographic Area Characteristics
Table 3.3 - Avista Residential Shell Program Requirements
Table 3.4 - Summary of 2004 Natural Gas Efficiency Program Results
Table 3.5 - Heating Degree-Days by Service District
Table 3.6 - Annual Distribution of Heating Degree-Days
Table 3.7 - WA/ID Rate Schedule 190 Incentive Tiers
Table 3.8 - WA/ID Prescriptive Residential Gas Measures
Table 3.9 - WAIID Community Action Program Contracts
Table 4.1 - Determining a Base Load
Table 4.2 - Determining a Heat Load
Table 4.3 - Determining a Design Peak Hourly Load
Table 4.4 - Capital Reinforcement Projects with Estimated Costs in 2005$
Table 5.1 - Current Maximum Available Firm Transportation/Resources
Table 5.2 - Current Transportation/Storage Rates and Assumptions Rates
Table 6.1 - Oregon Program Preliminary Evaluation Results
Table 6.2 - Results of Oregon SENDOUT"- Tested Programs
Table 6.3 - WA/ID Preliminary Evaluation Results
Table 6.4 - Results ofWA/ID SENDOUT"'Tested Programs
Table 6.5 - Oregon 1st-year Therm Acquisition by Customer Segment
Table 6.6 - Oregon Programs Accepted within the IRP Analysis
Table 6.7 - WA/ID Programs Accepted within the IRP Analysis
Table 6.8 - Basis Differential Assumptions
Table 6.9 - Monthly Pricing Allocation
Table 6.10 - Demand Scenarios
Table 6.11 - Peak Day Demand - Served and Unserved
Table 6.12 - Least Cost Supply-Side Resource Additions Selected by SENDOUT'"
Table 6.13 - Annual and Average Daily Demand Served by Demand-Side Management
2006 NATURAL GAS INTEGRATED RESOURCE PLAN
FIGURES
Figure 1.1 - System-Wide Average Annual Demand
Figure 1.2 - Henry Hub Forward Prices
Figure 1.3 - WA/ID Existing Resources vs. Peak Day Demand
Figure 1.4 - Oregon Existing Resources vs. Peak Day Demand
Figure 1.5 - WAIID Existing & Least Cost Resources vs. Peak Day Demand
Figure 1.6 - Oregon Existing & Least Cost Resources vs. Peak Day Demand
Figure 2.1 - Customer Growth Rate Scenarios
Figure 2.2 - WA/ID Average Annual Demand
Figure 2.3 - Oregon Average Annual Demand
Figure 2.4 - WA/ID Peak Day Demand
Figure 2.5 - Oregon Peak Day Demand
Figure 3.1 - Integration ofDSM within the 2006 Gas IRP
Figure 3.2 - Gas DSM Acquisition
Figure 3.3 - Combined Gas and Electric DSM Acquisition
Figure 3.4 - Portfolio Distribution of Natural Gas Efficiency Therm Acquisition, 2004
Figure 5.1 - January 1995 to February 2006 Monthly Index Nymex/Rockies/Sumasl AECO
Figure 6.1 - SENDOUT'" Model Diagram
Figure 6.2 - WA/ID Historical Monthly Average Demand
Figure 6.3 - Oregon Historical Monthly Average Demand
Figure 6.4 - Average vs. Coldest vs. Warmest - Spokane Weather
Figure 6.5 - Average vs. Coldest vs. Warmest - Medford Weather
Figure 6.6 - NOAA 30-year Average vs. Planning Weather - Spokane Weather
Figure 6.7 - NOAA 30-year Average vs. Planning Weather - Medford Weather
Figure 6.8 - Existing Firm Transportation & Storage Resource Stack - WA/ID
Figure 6.9 - Existing Firm Transportation & Storage Resource Stack - Oregon
Figure 6.10 - Oregon Natural Gas DSM Supply Curve
Figure 6.11 - Oregon Gas DSM Supply Curve
Figure 6.12 - WA/ID Natural Gas DSM Supply Curve
Figure 6.13 - WA/ID Natural Gas DSM Supply Curve
Figure 6.14 - Annual Oregon Acquisition Goals
Figure 6.15 - Henry Hub Forward Price Forecasts
Figure 6.16 - Henry Hub Forward Prices For Avista 2006 IRP
Figure 6.17 - WA/ID Existing Resources vs. Peak Day Demand
Figure 6.18 - Oregon Existing Resources vs. Peak Day Demand
Figure 6.19 - WA/ID Existing & Least Cost Resources vs. Peak Day Demand
Figure 6.20 - Oregon Existing & Least Cost Resources vs. Peak Day Demand
Figure 6.21 - Load Duration Curve & Resource Stack - WA/ID
Figure 6.22 - Load Duration Curve & Resource Stack - Oregon
Figure 7.1 - Natural Gas Avoided Costs
AVISTA'S ELECTRIC AND NATURAL GAS SERVICE AREAS
RETAIL ELECTRIC CUSTOMERS BY STATE RETAIL NATURAL GAS CUSTOMERS BY STATE
Washington: 225 000
Idaho: 113 000
Total Retail Electric Customers: 338 000
Washington: 137 000
Idaho: 68 000
Oregon: 92 000
Total Retail Natural Gas Customers: 297,000
(Data as of December 31, 2005)Electric Service Areas Natural Gas Service Areas
SECTION EXECUTIVE SUMMARY
Avista s Utilities 2006 Natural Gas Integrated
Resource Plan (IRP) identifies a strategic gas-supply
portfolio that meets future demand requirements.
The foundation for integrated resource planning is the
demand planning criteria utilized for the development of
demand forecasts. The formal exercise of bringing
forecasts of customer demand together with
comprehensive analyses of resource options, which
include both supply-side and demand-side measures, is
valuable to the company, its customers and its regulatory
commissions for long-range planning activities.
The company submits an IRP to public utility
commissions in Idaho, Washington and Oregon every two
years as required by state regulation. The company has 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 the IRP as a
methodology for identifying and evaluating various
resource options and as a process by which to establish a
plan of action for resource decisions. Through ongoing
and evolving investigation and research, the company
may determine that alternative resources are more
cost-effective than those resources selected in this IRP.
The company will continue to review and refine its
knowledge of resource options and will act to secure
least-cost options at the appropriate point in time.
The IRP identifies and establishes an action plan that
will steer the company toward the least-cost method of
serving Avista s natural gas customers. There are a
number of factors that must be considered within the
context of least-cost, including an assessment of risks
associated with each alternative. Therefore, actions
resulting from the IRP process represent risk-adjusted
least-cost results.
Avista s management and stakeholders in the
Technical Advisory Committee (TAC) playa key role and
have a significant impact in guiding the plan to its
* in Washington, iRP requirements are outlined in WAC 480-90,238 entitled
Integrated Resource Planning," In Idaho, the iRP requirements are outlined in Case
No,GNR-93-Order No, 25342. in Oregon, the iRP requirements are outiined in
Order No. 89-507.
conclusions. TAC members include customers
commission staff, consumer advocates, academics, utility
peers, governmental agencies and other interested parties.
The TAC provides important input on modeling,
planning assumptions and the general direction of the
planning process.
IRP PROCESS AND STAKEHOLDER INVOLVEMENT
Preparation of the IRP is a coordinated effort by
several departments within the company and includes
input ttom Commission Staff, customers and other
stakeholders. Topics leading to the development of the
IRP include natural gas sales forecasts, demand-side
management, distribution planning, supply-side resources
and computer modeling tools, resulting in an integrated
resource portfolio.
To facilitate stakeholder involvement in the 2006 IRP
the company sponsored six TAC meetings. The first
meeting convened on Oct. 4, 2005 , and the last meeting
was held on Dec. 8, 2005. A broad spectrum of people
were invited to each meeting. The meetings focused on
specific planning topics, reviewed the status and progress
of planning activities and solicited ongoing input on the
IRP development. In addition to the TAC meetings, the
company and the TAC members met via conference call
to discuss natural gas pricing issues. Furthermore, there
were a number of phone and e-mail discussions about
various other topics. Lastly, the company provided a draft
of this IRP to TAC members on Jan. 13, 2006. Avista
received comments on this draft from all interested parties
and has incorporated these comments into the final
version of this IRP. The company gained valuable input
from the TAC interaction and appreciated the positive
contribution of the participants.
MODELING APPROACH
The company applied its SEND OUT'" model (a PC-
based linear programming model widely used to solve
natural gas supply and transportation optimization
questions) to develop the least-cost resource mix for the
Avista Utilities 1 -2006 Naturai Gas Integrated Resource Pian
20-year planning period. This model performs the
least-cost optimization based upon daily, montWy,
cases to review in more detail. These three cases, from
this point forward, are known as the Expected Case
seasonal and annual assumptions related to:
. Customer growth and customer natural gas usage
that ultimately form demand forecasts;
. Existing and potential transportation and storage
(Case #2), the Low Demand Case (Case #6) and the
High Demand Case (Case #7). The Expected Case
revealed:
options;
. Existing and potential natural gas supply
availability and pricing;
. The number of core customers is expected
to increase ttom an average of 314 205 in
2006-2007 to 552 924 in 2025-2026. This is an
. Weather assumptions; and
. Demand-side management opportunities.
annual average growth rate of 4.0 percent.
. Average day core demand, net of model selected
demand-side management measures, is projected
to increase ttom an average of 93 670 Dth/day in
DEMAND AND SCENARIOS 2006-2007 to 160 190 Dth/day in 2025-2026.
The company developed a multi-step approach to
demand forecasting by using a three-by-three matrix
using low, medium and high price scenarios crossed
This is an annual average growth rate of
7 percent.
with low, medium and high customer growth scenarios
to represent a wide range of future end-states. These
. Coincidental peak day core demand, net of
model selected demand-side management
measures, is projected to increase ttom a peak of
scenarios look at the range of possible outcomes over
the planning horizon given the unprecedented price
spikes in the natural gas markets and the uncertainty of
the sustainability of the prices as well as customer
368 530 Dth/day in 2006-2007 to 642 970
Dth/day in 2025-2026. This is a growth rate of
over 3.9 percent in peak day requirements.
impact. From an analytical standpoint, after developing
each scenario, the company then selected three main
Figure 1.1 shows average annual system demand for
the three main scenarios over the planning horizon.
Figure 1.1 - System-Wide Average Annual Demand
(Net of DSM Savings) MDth/d - November to October
250
200
150
100 ..A- - -
-Ac-k-
.,!,-
.or-- ,
........... "/ """
..be
.... ~
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
--
Expected Demand --- Low Demand
"'",
" High Demand
1 ,2006 Natural Gas integrated Resource Plan Avista Utilities
Figure 1.2 - Henry Hub Forward Prices for Avista 2006 lAP
2005$/Dth
13.
12.
11.
10.
------"--
High Price --- Low Price
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
--.I:r- Medium Price
NATURAL GAS PRICE FORECASTS
The market for natural gas supply has undergone
dramatic changes over the last several years, as the
commodity market has transitioned ttom a regionally
based market to a national, and perhaps global, market.
Regional and national natural gas prices have recently
risen to unprecedented levels. The industry in general
and price forecasting organizations in particular, did not
forecast these unprecedented increases. Oil price
increases and the price relationship with natural gas
demand growth, natural gas use for electric generation
hurricane activity and other weather events are believed
to be some of the reasons for these price increases. Given
that these increases were not predicted and that these
price levels have not been witnessed before on a
sustained basis, it is very difficult to determine the length
of the price run-up, as well as the expected impact on
customer loads. Although the company does not believe
that it can accurately predict future prices for the 20-year
horizon of this IRp, it has reviewed a variety of price
forecasts provided by credible sources and has selected
high, medium and low price forecasts to best represent
the realm of reasonable pricing possibilities. Figure 1.
depicts the selected price forecasts.
RESOURCES
Avista has a diversified portfolio of natural gas supply
resources, including owned and contracted storage, firm
capacity rights on six pipelines, and contracts in place to
purchase natural gas ttom several different supply basins.
Avista has modeled a number of conservation measures
or programs that, if cost effective, could further
reduce demand.
In addition to conservation measures as supply
resources, A vista evaluated incremental pipeline
transportation, storage options, distribution
enhancements and various forms of liquefied natural
gas storage or service.
DEMAND-SIDE MANAGEMENT
Avista actively promotes and offers energy-efficiency
programs to all (non-transport) retail electric and natural
gas customers. These demand-side management (DSM)
programs are one component of a comprehensive
strategy to provide customers with a least-cost energy
resource. The IRP is used as an opportunity to evaluate
that resource mix with the intent to refine approaches
to the management of both supply-side and demand-
side management portfolios.
Avista Utilities 2006 Naturai Gas Integrated Resource Pian
Figure 1.3 - WAllO Existing Resources VS. Peak Day Demand
(Net of DSM Savings) Expected Case - November to October
---------
L..----'
Dthld
500,000
450,000
400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Existing GTN
Existing TF-
Existing TF-
Existing Plymouth
-G- WNID Peak Day Demand
Based on the projected natural gas prices and the
estimated cost of alternative supply resources, the
SEND OUT'" model selected certain DSM programs for
further review and implementation. In Oregon
demand-side management measures are targeted to
reduce demand by over 441 000 therms in the first year.
In Washington and Idaho, demand-side measures are
targeted to reduce demand by over 1 062 000 therms in
the first year.
RESOURCE NEEDS
The SEND OUT'" model was run utilizing existing
resources and the demand cases to determine whether
resource deficiencies exist during the planning period.
. In the Expected Case (Case #2) for Washington
and Idaho, the system first becomes capacity
deficient in 2012-2013. Given this timing, Avista
is afforded sufficient time to carefully monitor
plan and take action on potential resource
additions.
. In the Expected Case for Oregon, the system first
becomes capacity deficient in 2010-2011. Given
this timing, Avista is afforded sufficient time to
carefully monitor, plan and take action on
potential resource additions.
Figures 1.3 and 1.4 compare existing peak day
resources to expected peak day demand and show the
timing and extent of resource deficiencies for the
Expected Case.
The company identified possible resource options
and placed those options into the SEND OUT'" model
to allow SEND OUT'" to select the least-cost
incremental resources over the 20-year timettame of the
IRP. Figures 1.5 and 1.6 depict the optimum solution
selected by SEND OUT'" to meet the identified capacity
deficiencies.
As indicated in Figures 1.5 and 1.6, for
Washington/Idaho and Oregon, the model shows a
preference for incremental transportation resources ttom
existing supply basins to resolve capacity deficiencies.
SUMMARY OF KEY FINDINGS AND ACTION ITEMS
The company s 2006-2007 Action Plan outlines
the activities developed by the company s staff with
advice from its management and TAC members.
Avista Utilities2006 Naturai Gas Integrated Resource Plan
Figure 1.4 - Oregon Existing Resources vs. Peak Day Demand
(Net of DSM Savings) Expected Case - November to October
Dthld
200,000
60,000
40,000
---------
180,000
160,000
140,000
120,000
100,000
80,000
20,000
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Malin Supply
Existing GTN
Existing TF-
Existing TF-
Existing Will. Peaking
Existing Plymouth
Oregon Peak Day Demand
These actions, in many instances, have already begun
and will be completed in the next two years.
The purpose of these action items is to position the
of the Action Plan include:
. Avista will explore further separating out and
company to provide the least-cost resource portfolio and
to support and improve IRP planning. Key components
forecasting demand areas. Avista will research
whether it is possible, and whether or not it
would improve upon the forecasting quality, to
Figure 1.5 - WAIID Existing & Least Cost Resources vs. Peak Day Demand
(Net of DSM Savin9s) Expected Case - November to October
Dthld
500,000
----
i--
-----------
450,000
400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Existing GTN
Existing TF-
Existing TF-
Existing Plymouth
Stanfield Supply/Backhaul
TransCanada to WAllO
WAIID Sat. LNG
-- WAllO Peak Day Demand
Avista Utiiities 2006 Naturai Gas integrated Resource Pian 1 ,
Figure 1.4 - Oregon Existing Resources vs. Peak Day Demand
(Net of DSM Savings) Expected Case - November to October
Dth/d
80,000
60,000
40,000
-------. ----------
I--
200 000
180,000
160,000
140,000
120,000
100,000
20,000
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Malin Supply
Existing GTN
Existing TF-
Existing TF-
Existing Will. Peaking
Existing Plymouth
Oregon Peak Day Demand
These actions, in many instances, have already begun
and will be completed in the next two years.
The purpose of these action items is to position the
company to provide the least-cost resource portfolio and
of the Action Plan include:
. Avista will explore further separating out and
forecasting demand areas. Avista will research
to support and improve IRP planning. Key components
whether it is possible, and whether or not it
would improve upon the forecasting quality, to
Figure 1.5 - WA/ID Existing & Least Cost Resources vs. Peak Day Demand
(Net of DSM Savings) Expected Case - November to October
Dth/d
500,000
150,000
100,000
------------ .------
450,000
400,000
350,000
300,000
250,000
200,000
50,000
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Existing GTN
Existing TF-
Existing TF-
Existing Plymouth
Stanfield Supply/Backhaul
TransCanada to WNID
WAIID Sat. LNG
WNID Peak Day Demand
Avista Utilities 2006 Natural Gas integrated Resource Pian
Figure 1.6 - Oregon Existing & Least Cost Resources VS. Peak Day Demand
(Net of DSM Savings) Expected Case - November to October
Dth/d
200,000
40,000
20,000
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
----
L----
180,000
160,000
140,000
120,000
100,000
80,000
60,000
Existing GTN Malin Supply ....,.. Oregon Peak Day Demand
Existing TF-La Grande Dist. Enhance
Existing TF-Klam. Lat. Purchase
Existing Will. Peaking Medford Lateral Expansion
Existing Plymouth Meet Sat. LNG
forecast demand levels in sub-areas beyond the
regional areas discussed in this IRP.
. Avista will assess methods for capturing additional
and price scenarios.
. Avista explicitly recognizes the obligation to
value related to existing storage assets, including
but not limited to recalling some or all of the
achieve all natural gas-efficiency resources
available through the intervention of cost-
current releases.
effective utility programs.
. DSM measures target first-year savings of over
. Avista will further develop its storage strategy
with particular focus on storage opportunities for
Oregon customers and will research non-Jackson
441 000 therms in Oregon and over 1 062 000
therms in Washington and Idaho.
Prairie storage prospects for all customers.
. Avista will meet regularly with Commission Staff
members with the intent to provide information
on market updates, any material changes to risk
management programs, and significant changes in
assumptions and status of company activity
related to the IRP.
. The company will complete its evaluation of
VectorGas . If purchased, the company will
utilize VectorGas~ to strengthen Avista s ability to
analyze the financial impacts under varying load
2006 Natural Gas Integrated Resource Plan Avista Utilities
SECTION 2 - NATURAL GAS DEMAND FORECAST
OVERVIEW
In 2005 , Avista served 297 253 core natural gas
customers with 33 594 800 Dth of natural gas. By the
end of the planning period for this IRp, Avista projects
that it will have over 550 000 core natural gas customers
with an annual demand over 58 000 000 Dth.
In Washington and Idaho, the number of customers is
projected to increase at an average annual rate of 3.
percent per year with demand growing at a projected
rate of 2.8 percent per year. In Oregon, the number of
customers is projected to increase at an average annual
rate of 3.3 percent per year with demand growing at a
projected rate of 3.0 percent per year.
Avista presented its 2005 natural gas forecast to the
Technical Advisory Committee (TAC) in October 2005.
This forecast was completed in July 2005, and it had
assumptions and results that were driven by national and
service-area economic forecasts. Based on discussions
with the TAC about changes in natural gas pricing and
natural gas rate increases in the fall of 2005, Avista
revised use-per-customer assumptions for this IRP.
Avista manages its demand forecast through two
distinct operating divisions - North and South:
. The North Operating Division of Avista covers
about 26 000 square miles, primarily in eastern
Washington and northern Idaho. More than
600 000 people live in Avista s Washington/Idaho
service area. The service territory includes urban
areas, highly productive farm and timberlands, as
well as the Coeur d' Alene mining district.
Spokane is the largest metropolitan area with a
regional population of approximately 450 000
followed by the Lewiston, Idaho, and Clarkston
Wash., areas and Coeur d'Alene, Idaho. The
North Operating Division consists of about
000 miles of natural gas distribution mains.
Natural gas is received at more than 40 points
along the interstate pipelines and distributed to
Avista Utilities 2006 Natural Gas Integrated Resource Pian
more than 200 000 residential, commercial and
industrial customers.
. The South Operating Division of Avista serves
five counties in Oregon. The population of this
area is greater than 400 000. The South
Operating Division includes urban areas and
highly productive farm and timberlands. The
Medford, Ashland and Grants Pass area, located
in Jackson and Josephine Counties, is the largest
single area served by Avista, with a regional
population of around 120 000. The South
Operating Division consists of about 67 miles of
natural gas transmission mains and 2 000 miles of
natural gas distribution mains. Natural gas is
received at more than 20 points along the
interstate pipelines and distributed to more than
000 residential, commercial and industrial
customers.
DEMAND FORECAST METHODOLOGY
For this IRP, the SEND OUT'" model is used to
produce the Avista demand forecast. The key inputs to
the model for the demand forecast are a forecast of the
number of customers, a set of demand coefficients (Dth
consumed per customer per heating degree-day) and a
forecast of heating degree-days. The daily demand
forecasts are calculated as follows:
# of Customers Daily Dth Degree-
Day Customer
# of Daily
Degree-Days
This calculation is performed for each day for each
firm customer class and demand area. The customer
classes are the residential, commercial and firm industrial
classes. The demand areas are Medford, Ore., Roseburg,
Ore., Klamath Falls, Ore., La Grande, Ore. and the
eastern Washington/northern Idaho area. The climate
and the economy in each of these five areas vary
enough to make a meaningful difference in the demand
profiles for these areas. In the two-year action plan
Avista will explore further separating out sub-areas in
these demand areas, particularly in the
Washington/Idaho natural gas service areas.
Due to the volatility of natural gas prices, and based
on lengthy discussions with the TAC, Avista has
incorporated the use of price elasticity when
determining use per customer.
The purpose of the IRP is to balance forecasted
demand with existing supply 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. Incremental
conservation measures modeled are described in
Section 3.
CUSTOMER FORECASTS
The foundation of any demand forecast is the
forecast of the number and types of customers expected
over the planning horizon. The company develops its
customer forecast by reviewing and understanding
national economic forecasts and then drilling down into
regional economics. Population growth expectations and
Avista Utiiities2006 Naturai Gas Integrated Resource Plan
Figure 2.1 - Customer Growth Rate Scenarios
(Number of Customers by Period)
800,000
700,000
600,000
500,000
400,000
300,000
200,000
100,000
~~ ~ -~~~ -~~~ -~~~ -~~
02 03 04 06 07 08 09 11 12 13 14 16 17 18 19 21 22 23
Base Cust. Growth Case - WA/ID
li' Base Cust. Growth Case - OR
employment are the key drivers in understanding
regional economics and ultimately estimating natural gas
customers. The company contracts with Global Insight
Inc. (formerly known as DRI-McGraw Hill) for both its
long-term economic and regional forecasts. A company
narrative description of the Global Insight forecasts can
be found in Appendix 2.1. The company combines this
data, along with company-specific knowledge about
sub-regional construction activity, trends and historical
knowledge to develop the 20-year customer forecast.
Avista acknowledges that forecasting customer
growth is an inexact science and believes it is important
to consider alternatives to this forecast. Therefore
Avista has developed two additional outcomes for
consideration in this IRP. During the last 25 years
customer growth during five-year periods has ranged
between one-half and one-and-a-half times the 25-year
average customer growth rate. Since both patterns have
been observed in the past, Avista has created low
customer growth and high customer growth scenarios
with these parameters. The three customer growth
forecasts are shown in Figure 2.1. Detailed customer
count data, by region and by class, for all three scenarios
can be found in Appendix 2.
High Cust. Growth Case
Low Cust. Growth Case
HEATING DEGREE-DAY DATA
Heating degree-day data is obtained ttom the
National Weather Service. For Oregon, Avista uses four
weather stations as the weather basis, corresponding to
the areas within which natural gas services are provided.
Heating degree-day weather patterns between these
areas are uncorrelated. For the eastern Washington and
northern Idaho portion of Avista s service area, weather
data for the Spokane International Airport are used, as
heating degree-day monthly weather patterns within
that region are correlated. Actual heating degree-day
weather is discussed in more detail in Section 6 and the
actual heating degree-days used in SEND OUT'" can be
found in Appendix 6.
USE PER CUSTOMER
The forecasts of use per customer are based on daily
heating degree-days, which shape customer use with the
seasons' variation. Avista uses multiple regressions to
compute the forecast coefficients by customer classes.
The regression includes a non-heat amount (the
constant in the regression) and two variables for heating
degree-days. The first heating degree-day coefficient is
the shoulder-month estimate. It includes heating degree-
Avista Utilities 2 -2006 Natural Gas Integrated Resource Plan
days for the months of March, April, May,June
September, October and November. Summer heating
degree-days are excluded during the air-conditioning
months. The second heating degree-day coefficient is
the winter-period estimate. This variable includes
degree-days for December January and February only.
These coefficients can be seen in
Table 2.1. The actual regression
calculations producing these coefficients
VALIDATION OF CUSTOMER GROWTH AND
COEFFICIENT INFORMATION
The heating degree-day coefficients are average
responses over a 60-month period. In order to true up
the coefficients to the latest data, a back cast over the
previous 12 months is conducted. Through
SEND OUT"', actual demand data over the previous 12
months was compared to calculated demand based on
actual customers, actual heating degree-days and the
coefficients to ensure accuracy of the demand forecast.
With respect to the customer growth assumptions
residential customer growth is in proportion to
population growth, and commercial customer growth is
in proportion to employment growth. This gives Avista
further comfort that the company-specific forecasts are
aligned with the regional and national economic
forecasts.
DEMAND FORECAST SCENARIOS FOR IRP
Avista acknowledges it has become very difficult to
project (or predict) future natural gas prices and uses a
price elasticity of demand factor to allow use per
customer to vary into the future as natural gas price
forecasts change. Given the unprecedented recent price
spikes in the natural gas commodity markets and the
uncertainty and sustainability of the prices, the company
has created three price response demand forecasts in
Table 2.1 - Demand Coefficients
Residential - WAIID
Commercial - WNID
Industrial - WNID
Residential - Medford
Commercial - Medford
Residential - Roseburg
Commercial - Roseburg
Residential - Klamath Falls
Commercial - Klamath Falls
Residential - La Grande
Commercial - La Grande
can be found in Appendix 2.
The shoulder-month regression
coefficient is about one-half the winter-
period coefficient. This means that, for
example, a shoulder-month heating
degree-day produces about one-third as
many therms per customer as a winter-
period heating degree-day. The
coefficients are estimated separately for
Non-Heat
Dth/CusVDay
0536
3757
1648
0457
3158
0682
4395
0509
0388
0462
2483
Shoulder
DthlCusVHDD
0077
0346
1375
0070
0276
0087
0288
0051
0186
0079
0282
Dec.Jan.Feb.
DthlCusVHDD
0104
0506
1798
0113
0467
0115
0456
0079
0305
0099
0395
each area.(Each coefficief1t above is significant at the 95 percent level)
Avista Utilities2006 Natural Gas Integrated Resource Plan
addition to three customer growth forecasts.
Avista has assumed that its customers' usage responds
to significant changes in their natural gas rates. Through
the concept of price elasticity, if customer rates continue
to rise as they have over the last few years, natural gas
use per customer is expected to decline. Conversely, if
rates drop, use per customer is expected to increase.
Based on company historical trends and other research
and analysis, Avista has estimated price elasticity to be
15 for residential customers and -10 for commercial
customers. Avista estimates income elasticity is +0.
and electricity cross-price elasticity is estimated to be
+0.10. The firm industrial sector is very small, and no
estimates have been determined for this sector. Avista
assumed price elasticity estimates are based on a review
of recent studies and were discussed at the TAC
meetings.
What these price elasticity estimates mean is if the
real (adjusted for inflation) price of natural gas increases
by 10 percent, Avista would expect residential therms
per customer per heating degree-day to decline by 1.5
percent. Similarly, if real personal income per customer
increases by 10 percent, Avista would expect natural
gas consumption would increase by 7.5 percent.
And finally, if real electricity prices increase by 10
percent, Avista would expect natural gas consumption
would increase by 1 percent. The elasticity estimates
assumed are expected to see adjustments over a period
of years, and since Avista s IRP covers 20 years, Avista
treats these elasticity estimates as long-run estimates.
Table 2.2 - Price-Related
Demand Adjustments for Demand Scenarios
Low Price Medium Price High Price
2006 106.30%98.51%95.84%
2007 101.10%104.31%101.84%
2008 101.13%101.11%101.80%
2009 101.12%101.59%101.51%
2010 101.15%100.77%100.55%
2011 100.25%100.29%99.74%
2012 100.26%99.80%99.64%
2013 100.25%99.82%99.62%
2014 100.24%99.83%99.57%
2015 100.24%99.96%99.59%
2016 99.82%99.42%99.61 %
2017 99.83%99.16%99.64%
2018 99.84%99.53%99.64%
2019 99.84%99.57%99.65%
2020 99.83%99.60%99.66%
2021 99.89%99.66%99.66%
2022 99.89%99.67%99.67%
2023 99.89%99.67%99.67%
2024 99.89%99.67%99.67%
2025 99.89%99.68%99.68%
The three customer use demand forecasts developed
by the company were derived utilizing the above
elasticity assumptions and the natural gas price curves
that the company discusses in detail in Section 6 and
that are shown in Figure 6.16. Avista calculated
customer response for each scenario by adjusting the
demand coefficients shown in Table 2.1 for each case.
The price-related coefficient adjustment factors
calculated as described previously are shown in
Table 2.
Table 2.3 - Demand Scenarios
Case #1 - Low natural gas price
adjustment - elasticity (-15)
Case #2 - Medium natural gas
price adjustment - elasticity (-15)
Case #3 - High natural gas price
adjustment - elasticity (-15)
Case #4 - Case #1 with a reduction of
customer growth by 50%
Case #5 - Case #2 with a reduction of
customer growth by 50%
Case #6 - Case #3 with a reduction of
customer growth by 50%
Case #7 - Case #1 with an increase of
customer growth by 50%
Case #8 - Case #2 with an increase of
customer growth by 50%
Case #9 - Case #3 with an increase of
customer growth by 50%
Avista Utilities 2006 Natural Gas Integrated Resource Plan
Figure 2.2 - WA/ID Average Annual Demand
(Net of DSM Savings) MDth/d - November to October
---
200
180
160
140
120
100
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
-+- Case #2 -+- Case #6 Case #7
IRP DEMAND SCENARIOS scenarIos. Table 2.3 shows this in detail.
The top row of the matrix incorporates the highAs described above, Avista has elected to analyze
three customer growth rate scenarios and has also medium and low natural gas price curve adjustments.
As previously discussed, for each of these cases in thiselected to analyze three different customer use rate
scenarios. The result of this approach, when each row, the demand coefficients were adjusted annually
based on the comparison of each of the price curves
selected by the company and the associated elasticity
potential outcome is considered, is that nine total
scenarios are produced. Crossing the high, medium and
low use per customer demand coefficients discussed
above with the high, medium and low customer growth
calculations. For the middle row of the matrix, the
coefficients remain the same as the top row of the
rate scenarios shown in Figure 2., derives these nine matrix but the customer growth rates were adjusted
Figure 2.3 - Oregon Average Annual Demand
(Net of DSM Savings) MDth/d - November to October
.....
.A,
- ~-..........-.. -
-A --A' - --
........-
-A-- -
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
-+- Case #2 --- Case #6 -.... Case #7
2006 Natural Gas integrated Resource Plan Avista Utilities
Figure 2.4 - WAIID Peak Day Demand
(Net of DSM Savings) MDthid - November to October
800
700
600500
....:~~
200
100
: '
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
-+- Case #2 -+- Case #6 --A-- Case #7
of the matrix but the customer growth rates were
adjusted upward by 50 percent.
Figures 2.4 and 2.5 show Washington/Idaho and
Oregon forecasted demand for the highest growth
lowest growth and mid growth cases on a peak day basis
downward by 50 percent. For the bottom row of the
matrix, the coefficients remain the same as the top row
RESULTS
for each year of this IRP.
Looking in more detail, Table 2.4 depicts annual
demand increases by class of customer and area for the
Figures 2.2 and 2.3 show Washington/Idaho and
Oregon forecasted demand for the highest growth
lowest growth and mid-growth cases on an average daily
highest growth, lowest growth and mid growth cases for
this IRP.
basis for each year of this IRP.
Additional detailed data depicting annual and peak
day demand data is attached in Appendix 2.4.
Figure 2.5 - Oregon Peak Day Demand
(Net of DSM Savings) MDthid - November to October
----- -
250
225
200
175
150
125
100
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
-+- Case #2 -+- Case #6 '.!,-- Case #7
Avista Utilities 2006 Natural Gas Integrated Resource Plan
CONCLUSION TWO-YEAR ACTION PLAN
Through the scenario planning process, Avista has
considered the potential demand impacts of both
changing natural gas prices and a changing economy.
The result of those considerations is a reasonable range
of outcomes with respect to core consumption of
natural gas. While Avista recognizes that the actual level
of demand is dependent on a variety of factors
reviewing the range of potential outcomes allows the
company to plan more effectively as economic or
pricing conditions change on a dynamic basis.
In addition to updating the forecast methodology for
the latest actual data (including customer growth rates
and demand coefficients), Avista plans to evaluate sub-
area planning at the city-gate level. The development of
a city-gate forecasting system is a major undertaking,
and Avista will provide periodic progress reports
addressing issues surrounding this project.
Table 2.4 - Annual Average Demand Percentage Increases
11/2006,10/2026
Area
Case #2
Klamath Falls
La Grande
Medford
Medford NWP
Roseburg
OR Sub-total
Spokane
Spokane NWP
WAiID Sub-total
Scenario #2 Total
Residential Commercial Firm Industrial
2.4%
Case #6
Klamath Falls
La Grande
Medford
Medford NWP
Roseburg
OR Sub-total
Spokane
Spokane NWP
WAiID Sub-total
Scenario #6 Total
Case #7
Klamath Falls
La Grande
Medford
Medford NWP
Roseburg
OR Sub-total
Spokane
Spokane NWP
WAiID Sub-total
Scenario #7 Total
2.4%
, .
Avista Utilities2006 Natural Gas Integrated Resource Plan
SECTION 3 - DEMAND-SIDE MANAGEMENT
Avista actively offers energy-efficiency programs to
all (non-transport) retail electric and natural gas
customers. These demand-side management (DSM)
programs are one component of a comprehensive
strategy to provide customers with a least-cost energy
resource. The IRP is used as an opportunity to evaluate
that resource mix with the intent to refine approaches
to the management of both supply-side and demand-
side management portfolios.
The DSM function within Avista is organizationally
split into a North (Washington and Idaho) division
offering both electric and natural gas efficiency
programs and a South (Oregon) division providing
solely natural gas efficiency programs. For purposes of
modeling DSM within the IRP process, the Oregon
division was segmented into five areas and the
Washington/Idaho division was segmented into two
areas consistent with the company s approach to
SEND OUT'" modeling.
The analysis presented as a part of this IRP is the
first step toward identifying cost-effective natural gas
efficiency measures. Immediately following the
completion of this analysis, but outside the scope of this
IRP document, the company will review the existing
DSM portfolio and business plan in light of the results
of this analysis. This process will incorporate
refinements and additional analysis of measures, revisions
to existing and prospective program plans, and
potentially the termination of measures that are
determined not to be cost-effective. Included within
this effort will be a determination of the optimal
approach to each identified cost-effective measure to
include the potential for cooperative acquisition or
market transformation efforts.
It is possible that there will be measures accepted
within this IRP that will subsequently be determined to
be unsuitable for inclusion within the company s DSM
portfolio based on post-IRP analysis, business planning
and program planning efforts. It is also possible that
programs will be developed for measures that were
rejected by this IRP as a result of this same process.
Though the IRP is the company s best opportunity to
complete a comprehensive re-evaluation of the DSM
portfolio and its integration into the overall resource
mix, it is necessary to incorporate an ongoing business
planning process to ensure that the best resource
decisions are made.
Ultimately the company is committed to achieving
Avista Utilities 2006 Natural Gas Integrated Resource Plan
all natural gas-efficiency measures that can be cost-
effectively acquired through utility intervention.
This commitment supersedes any numerical goals
established within the IRP or the company s business
planning efforts.
THE METHODOLOGY
The development of a methodology for
characterizing and evaluating DSM within the IRP was
based on four key requirements. It was determined that
the analysis must:
. Provide a comprehensive evaluation of all
significant natural gas-efficiency options that are
currently commercially available;
. Evaluate those natural gas-efficiency options in
process that is as interactive with supply-side
options as possible;
. Maximize portfolio net total resource value; and
. Deliver analytical results that are meaningful and
actionable for the business planning process to
follow the completion of the IRP analysis.
The methodology that was adopted to fulfill these
requirements divided the process into five key phases:
. Definition phase - Defining and characterizing
potential DSM resource options;
. Preliminary evaluation phase - Performing a
preliminary evaluation of each measure using a
spreadsheet model based on its ability to
contribute to portfolio cost-effectiveness;
. Packaging and optimization phase - Packaging
these measures into marketable DSM programs
by iteratively optimizing these programs and
testing alternative measure packages and
implementation approaches (to include
alternative ramp rates, program outreach, target
marketing, etc.
. Program characterization phase - Dividing
those optimized programs into three
categories for further testing within the
SEND OUT'" model:
. Defining those programs that are certain to
favorably contribute to portfolio net total
resource value as "must take" options within
the IRP model;
. SpecifYing the resource characteristics of
those programs that are of indeterminate
cost-effectiveness and incorporating them
into SEND OUT'" for possible selection
(or rejection) by the model itself; and
Excluding programs that are higWy cost-
ineffective based on preliminary total
resource cost analysis ttom further
consideration within SENDOUT".
. Program technical and acquirable potential -
Determine the size of the resource block
acquirable through the adoption of the measure.
This must be consistent with the non-incentive
utility cost and program packaging effort
previously defined.
Additional analysis, business planning, development
of regional and ad hoc partnerships, and local DSM
program implementation efforts will be triggered by the
findings of this IRP effort. These efforts may modifY
the findings contained within this IRP document based
on improved information and the timely assessment of
opportunities. The nature of the process and the
timelines of these ongoing efforts necessitate their
omission ttom this document. Nevertheless they have
been represented, in simplified form, in the
methodology flowchart contained in Figure 3.
The incorporation of specific DSM resource options
into the SENDOUT'" model will be described as part of
the overall integration of the IRP planning effort.
This will include a compilation of the DSM measures
selected by SEND OUT"', as well as their estimated
therm acquisition and aggregate DSM goals for
Washington/Idaho and Oregon.
3 - 2 Avista Utilities2006 Naturai Gas Integrated Resource Plan
PHASE ONE: CHARACTERIZING THE
DSM MEASURES
Avista retained the services ofRLW Analytics to
provide much of the basic data regarding the cost
energy-efficiency and technical potential characteristics
of the 74 residential and 67 non-residential measures
tested within the IRP. RLW Analytics was able to
leverage previous work that it had performed for the
Energy Trust of Oregon and the Northwest Energy
Efficiency Alliance to develop these estimates.
A summary of the measures that were tested is
contained within Appendix 3.1. Energy efficiency,
incremental cost and other measure characteristics were
generally evaluated in comparison to industry standards
or code minimums, whichever were higher. These
measures were tested under new construction, replace-
on-burnout, replace-before-burnout scenario
assumptions, and sometimes all three, as appropriate.
Each measure tested included an assessment of the
technical resource acquisition potential provided by
RLW Analytics. This estimate assumes that a natural
gas-efficiency measure was installed in all applications
where it would physically function regardless of the
economic viability at that individual site, the likelihood
of achieving the acquisition through utility programs or
the length of time that would be required to reach total
saturation of the market, and the ability of non-utility
trade allies to support the sale and installation of the
measure. Since the assumptions made in reaching the
technical potential are obviously unrealistic, and
sometimes grossly unrealistic, the acquirable potential is
naturally lower than the theoretical technical potential.
The majority of the RLW Analytics work was
specific to Avista s Oregon service territory, though it
was consistent with and in a large part derived from
regional market research performed by the Northwest
Energy Efficiency Alliance. Thus, this raw data provided
a sound foundation for determining the measure
Figure 3.1 -Integration of DSM within the 2006 Gas IRP
Identify
Potential
Measures
Develop Cost
Characteristics
Assess Market
Characteristics &
Past Program
Results
Represented within Integrated Resource Planning Process
Outside the Scope of the Integrated Resource Planning Process
Initiate Regional
Market Transformation
Efforts per Business Plan
Preliminary
Cost-effectiveness
Evaluation
Packaged Into
Marketable
Programs
Re-evaluation of
Cost-effectiveness
by Program
Terminate
Specify as
Must Take
for SENDOUT'"
Characterize for
Interactive
Evaluation within
SENDOUT'"
Initiate New Programs.
Continue, Modify or
Terminate Existing
Programs per
Business Plan
Development of a
Revised DSM
Business Plan Additional Analysis of
Programs as Necessary
Develop Ad Hoc
Agreements per
Business Plan
Review Existing
DSM Business Plan
Avista Utilities 2006 Naturai Gas integrated Resource Plan
characteristics within Avista s Washington/Idaho service
territory as well. This translation began by designating
weather-dependent measures and establishing a default
adjustment to North division energy savings based on
the relative heating degree-days between the weighted
average of the four Oregon divisions (Medford
Klamath, Roseburg and La Grande) as compared to that
of the combined North division (Washington/Idaho)
service territory. This default was then reviewed and
adjusted as necessary based on the characteristics of
Washington/Idaho (e.g. housing stock, end-use measure
performance, differences in customer operations, etc.
Avista DSM engineers, program implementers and
analysts also reviewed incremental measure costs
measure lives, energy savings and other inputs and
assumptions in the evaluation process with the staff of
RLW Analytics and made revisions as necessary.
Great care was taken to ensure that there was symmetric
treatment of the costs and benefits of base case and
high-efficiency scenarios for each measure.
Notably, the potential energy savings per unit does
not include consideration for customer "take-back"
(e.g. increased usage in response to the reduced
incremental cost of end-use as a result of higher
efficiency). The energy savings of individual measures
will again be reviewed within the program planning
phase to determine if there is any need for reducing the
per unit savings to account for interactive effects
between measures.
Program implementation staff estimated incremental
non-incentive utility costs for each measure. Since it was
assumed that there would be a substantial portfolio of
programs passing the total resource cost (TRC) test, the
incremental utility cost was generally low or zero.
This reflects the minimal incremental utility
administrative cost associated with incorporating an
individual DSM measure or program into a pre-existing
portfolio of cost-effective programs. This approach has
been previously presented to the IRP TAC and others as
a "sub- TRC" test in that it excludes one cost element
(fixed non-incentive utility cost) that is typically
included in a full calculation of the TRC test.
Incremental measure cost was based on the customer
cost over and above the assumed base case for new
construction and replacement options. The incremental
measure cost for retrofit (replace-before-burnout)
options were based on the full cost of the measure on
the presumption that there was an existing operational
unit in place at the time of change-out (this being part
of the definition of replace-before-burnout). This
assumption made retrofit measures considerably more
costly than replacement or new construction scenarios.
Consequently the retrofit measures were generally not
cost-effective or, at best, of marginal cost-effectiveness.
Clearly, the replacement and new construction
alternatives would be strongly favored in the preliminary
evaluation and SEND OUT'" modeling phases of this
study. However, this simplification did not adequately
reflect the nature of the majority of retrofit situations.
Typically the replacement of existing operational end-
use equipment occurs when that equipment is nearing
the end of its physical or economic life. For cost-
effectiveness purposes, Avista has traditionally defined
the replacement of equipment that is in "impending
failure" as being a replace-on-burnout situation for
purposes of estimating incremental costs for cost-
effectiveness reporting. The term "impending failure" is
generally defined as equipment that is likely to have less
than one year of remaining useful physical life or
equipment that has reached or exceeded its
economic life.
Discussions in preparation for program design have
often identified the targeting of replacement-shortly-
before-burnout as an attractive market segment given
the greatly reduced likelihood of customer installation of
efficient equipment when the customer is in a water-
out or space heat-out situation. This topic and its
relationship to technical and economic potential therm
acquisition will be revisited at a later point in the
documentation of the IRP analysis and during business
Avista Utilities2006 Natural Gas Integrated Resource Pian
planning and program development.
Avista has traditionally adopted a conservative
approach to the treatment of non-energy benefits or
costs. Those non-energy impacts that are quantifiable in
a reasonably rigorous manner are incorporated into the
analysis as an adjustment to the incremental cost of the
measure. Fundamentally, this assumes that part of the
premium that the customer is purchasing within the
incremental cost of a high-efficiency end-use is for the
acquisition of the non-energy benefit. (An adverse non-
energy impact would be represented as a negative non-
energy benefit). The incremental cost attributable to the
energy-efficiency component of the purchase is only
that which is over the sum of the base case cost and the
net value of the non-energy benefit. Within the set of
measures analyzed for this IRP only the horizontal-axis
washing machine was deemed to have a significant
quantifiable non-energy benefit.
The company did perform a preliminary calculation
of a revealed-preference approach to quantifying the
non-energy benefits of shell measures (insulation and
energy-efficiency windows). This methodology assumes
that any participant payment in excess of the present
value of future reductions in the energy bill is a
minimum valuation of the non-energy benefit.
Performing this analysis on a sample of floor, ceiling and
attic weatherization participants indicated that the
present value of the customers' energy savings was
sufficiently high to offset the total measure cost in the
vast majority of cases. This does not indicate a lack of
non-energy benefits; it simply means that the energy
benefits were sufficiently high to fully offset the measure
cost in most cases, and consequently, the customer was
not forced to 'reveal' a valuation of non-energy benefits.
The company has successfully employed this approach
to quantifying non-energy benefits in the past, however
these evaluations occurred in an era of lower retail
natural gas rates.
PHASE TWO: PERFORMING A PRELIMINARY
EVALUATION
Based on the incremental customer cost, incremental
non-incentive utility cost, incremental annual energy
savings, measure life and the application of a discount
rate consistent with the IRP process, a levelized "sub-
TRC" cost was calculated for each individual measure.
This calculation allowed for the comparison of costs
across different measures with varying measure lives and
was the foundation for the measure and program
selection and portfolio optimization to follow.
This analysis was augmented with estimates of the
full TRC levelized costs (including those that were not
incremental to the program) to provide estimates of
long-term portfolio cost-effectiveness. This information
was used as a diagnostic tool to obtain an understanding
of the magnitude and cost-effectiveness of a portfolio
including fully loaded non-incentive utility costs.
The sub-TRC calculations drove decisions regarding the
incorporation of individual measures into programs or
into the overall portfolio.
This preliminary evaluation was performed within
an Excel spreadsheet model to permit easy manipulation
of the data. This process facilitated the identification of
data elements that were out of the norm or in need
further research, the calculation of a number of different
diagnostic statistics, and the testing of measures and
programs under alternative approaches to program
planning. It also greatly reduced the effort necessary to
reformat the results of each program entered into
SEND OUT"'
PHASE THREE: PROGRAM PACKAGING AND
OPTIMIZATION
It is in this stage that the art of program design and
implementation begins to enter the evaluation process.
The intent is to maximize the netTRC value of each
individual measure and then package these measures
into marketable programs (e., a weatherization
program composed of attic, wall and floor insulation, as
Avista Utiiities 2006 Natural Gas integrated Resource Pian
well as possibly window measures and infiltration
measures). It was therefore necessary to broadly define
customers.
how these programs would be offered to Avista
The measure optimization and subsequent packaging
of measures into programs were necessarily intertwined
in this process. For example, the inclusion of a window
measure as part of a residential shell program may have
the impact of enhancing program throughput, however
the ultimate impact on the program cost-effectiveness
depends on the cost-effectiveness of each individual
measure and its weighting within the program.
Alternative program planning efforts, such as high and
low ramp-rates and large or small outreach investments
were generally defined and evaluated as part of the
program optimization. Using the inputs and diagnostic
statistics previously described in the first two phases
this analysis made it possible to
provide program planners with useful
information regarding program
benefit-to-cost ratios, net total
resource value, as well as TRC and
sub- TRC levelized costs under a
number of different scenarios. This
work is not a substitute for post-IRP
program planning efforts, but it did
allow us to realistically represent the
most likely implementation approach
within the IRP analysis.
To the extent possible, there was
the desire to ensure that generally
cost-effective measures were not
packaged in non-cost-effective
programs (and vice-versa). Table 3.
illustrates the dekatherms of
acquirable potential for individual
measures and programs when
disaggregated into broadly defined
cost-effective, marginally cost-
effective and non-cost-effective
categories. These categories were described as "green
yellow" and "red" respectively in discussions with the
IRP TAc. These terms are also used within Table 3.
The final cost-effectiveness of the portfolio not only
depends on the package of measures within each
program, it also depends on the package of programs in
the overall DSM portfolio. There is arguably a value to
retaining certain "flagship" programs (such as the
residential shell program) to provide a meaningful
anchor program around which other programs (such
residential HVAC efficiency, domestic hot water
measures, etc.) can leverage. Additionally, in the
development of the Oregon DSM portfolio those
measures that were mandated by legislation were
designated as a "must take" option in all scenarios for
purposes of the SEND OUT'" model.
Though the calculations of levelized costs are made
Table 3.1 - Measure vs. Program Categorization Matrix
First-year Thenns achievable by lAP testing category
Oregon residential measures
Must take Green Yellow Red"TOTAL
Green" measures 349 294 109 308,458
Yellow" measures 40,609 544 793 622 108 568
Red" measures 883 810 987 546 995 239
TOTAL 57,840 294 653 603 008,168 1,412 265
Oregon non-residential measures
Must take Green "Yellow Red"TOTAL
Green" measures 301 390 691
Yellow" measures 586 634 270
Red" measures 986 986
TOTAL 52,887 024 036 127 947
Washington/Idaho residential measures
Must take Green Yellow Red"TOTAL
Green" measures 101 125 252 397 940 354,462
Yellow" measures 270,824 165,432 436 256
Red" measures 890,874 890,874
TOTAL 101 125 523 221 057 246 681 593
Washington/Idaho non-residential measures
Must take Green Yellow Red"TOTAL
Green" measures 38,495 992 58,488
Yellow" measures 780 634 2,481
Red" measures 398 398
TOTAL 275 626 74,465 135,367
Green' measures were those with the highest cost-effectiveness
Yellow" measures were considered to be marginaJly cost-effective
Red' measures were deemed to be non-cast-effective
Avista Utilities2006 Natural Gas Integrated Resource Plan
on a reasonably objective basis, there is of necessity a
certain element of subjectivity within the majority of
the packaging and optimization phase. Consequently
much of this process was left to the program planners
who will ultimately be responsible for developing and
fielding the measures and programs selected in the IRP
and future business planning processes.
PHASE FOUR: PROGRAM CHARACTERIZATION
PHASE
The objective of this process was to develop
marketable programs, generally composed of several
measures related by common inttastructure or some
other close tie, and to characterize these programs in a
manner suitable for entry into the SEND OUT'" model.
Each program was split into five geographic segments
(in Oregon) or two geographic segments (in
Washington/Idaho) to be consistent with the modeling
of the natural gas transmission system within
SEND OUT"'. This disaggregation was based on
residential households, non-residential natural gas
throughput and the climatic conditions for each of the
geographic areas. The heating degree-days used for
these purposes are summarized in Table 3.2. These
heating degree-days are consistent with those used for
demand planning in this IRP, discussed in Section 6 and
can be found in Appendix 6.
The levelized costs of a given program are identical
in each of the Spokane and Medford geographic areas
although SEND OUT'" will not necessarily reach the
same accept or reject decision due to differences in
supply-side resource costs.
The five geographic areas within Oregon have a 71
percent range in heating degree-days from the warmest
(Roseburg) to the coldest (Klamath Falls). This results
in significantly different energy savings and cost-
effectiveness levels for weather dependent measures.
The almost certain probability that some DSM
programs would be accepted by SEND OUT'" in some
geographic areas and rejected in others within the same
Table 3.2 - Geographic Area Characteristics
HDDs
Oregon
Klamath Falls
La Grande
Medford
Medford NWP
Roseburg
201
751
786
786
216
Washington/Idaho
Spokane
SNWP
997
997
HDDs = heating degree-days
SNWP = the area w~hin Washington/idaho that can be served only off of NWP,
Spokane = the area within Washington/Idaho outside of the SNWP area,
Medford NWP = the area in Medford that can only be served off of NWP,
Medford = the area in Medford outside of the Medford NWP,
jurisdiction will pose program development difficulties.
Only very rarely has Avista offered programs that were
not available throughout the entire jurisdiction. Though
this issue was discussed with stakeholders as part of the
IRP process, it is generally deferred to the program-
planning phase.
Avista will complete analysis of the prospective cost-
effectiveness of each program in each of the five Oregon
geographic areas as part of the program planning efforts.
This analysis may lead to an improvement in the overall
cost-effectiveness of selected measures through
geographically targeting the program. The distinction
between the two Washington/Idaho geographic areas
(designated SNWP and Spokane) is based on pipeline
delivery areas that are not meaningful in a DSM
program planning sense (but are meaningful to Avista
supply-side planning).
Prior to the development of the methodology used
in this analysis the company had discussions with
utilities experienced in incorporating DSM packages
into the SEND OUT'" model. Based upon those
discussions, it was determined that the SEND OUT'"
model quickly becomes unwieldy if too many DSM
options are submitted for interactive evaluation within
the model. This is particularly true when those DSM
options must be subdivided into seven geographic areas
and evaluated in all nine of the original IRP scenarios.
Avista minimized this problem by identifying several
Avista Utilities 2006 Natural Gas Integrated Resource Pian
categories of DSM programs in a preliminary evaluation
process. These included:
. "
Must take" programs composed of
. Legislatively-mandated Oregon programs
. Programs with sub- TRC levelized costs so
low that acceptance by SENDOUT'" was
virtually guaranteed
. Programs with levelized costs so high that
rejection of the program in all SENDOUT'"
scenarios was virtually assured
. Programs that could not be clearly accepted or
rejected based on the preliminary evaluation
results.
A ranking of measures and programs by sub- TRC
cost-effectiveness was initially completed in the
preliminary evaluation process. This ranking is not
necessarily the precise ranking that SEND OUT'" would
apply for selection since it was composed of programs
with varying annual load profiles. The ranking was
nevertheless suitable for establishing an initial
disaggregation of the optimized programs into the three
categories defined above.
Measures in the "must take" category were
aggregated into base load measures (not dependent upon
heating degree-day levels) and weather sensitive
measures (those that were heating degree-day sensitive)
to establish the annual load profiles necessary for
evaluation within SEND OUT"'. This aggregation and
mandatory acceptance significantly reduced the input
and computational time required to complete the
modeling process without compromising the
final results.
Programs that were clearly not going to be accepted
were eliminated from further consideration and not
entered into SEND OUT"'. This also reduced input and
computational time without compromising the validity
of the final results.
Those programs whose acceptance or rejection by
SEND OUT'" was uncertain were individually entered
into the model with all of the necessary geographic
disaggregations discussed earlier. Indeterminate programs
were defined as programs with sub- TRC levelized cost-
to-benefit ratios between 0.6 and 1.5 when compared
against a levelized avoided cost of $1.00 per thermo
The use of a cost-benefit ratio and a hypothesized
avoided cost was necessary since the programs were
ttequently composed of measures with varying measure
lives. It was believed that this range was sufficiently
broad to fully capture the range of indeterminate
programs in the medium-price IRP scenarios.
At the time that this evaluation was being
performed, it was assumed that all measures would be
implemented through local program delivery.
The opportunity for the development of any of these
measures as regional market transformation programs
was not sufficiently mature at this time to represent
within the IRP analysis. The company is committed to
pursuing all cost-effective measures in the manner that is
most appropriate given the available opportunities
including the potential for cooperative or
regional efforts.
The disaggregation of programs into these categories
is represented in Appendix 3.2. These programs consist
of multiple measures as well as replace-on-burnout
replace-before-burnout and new construction options.
Thus, the same measure may appear in multiple
programs based on these characteristics. This is an
unfortunate but unavoidable level of detail necessary to
ensure that individual measures were not inappropriately
combined with other separable measures with very
different cost-effectiveness characteristics.
PHASE FIVE: TECHNICAL AND ACQUIRABLE
POTENTIALS
At this point in the analysis, the evaluation, ranking
and selection of measures has been independent of the
potential acquisition of each resource. The acquirable
resource available from a selected measure is only
important to the extent that the business planning
Avista Utiiities2006 Natural Gas Integrated Resource Plan
process will need to establish sufficient infrastructure
flexibility to respond to customer demand for the
program. Even this importance is minimized considering
Avista s commitment to funding the acquisition of all
available cost-effective gas-efficiency resources.
Avista will carry forward into the post-IRP business
planning process the intent to establish an inttastructure
sufficient to achieve the level of cost-effective resource
acquisition identified within the IRP. Adjustments will
be made based on differing approaches to program
implementation and actual customer response to the
DSM portfolio. These adjustments will reflect the
company s commitment to delivering all cost-effective
resources achievable through utility programs.
The estimates of the resource potential for each
individual measure were initiated with Oregon division
technical potential provided by RLW Analytics. These
estimates were based on generally available demographic
information, as well as the results of market research
performed for the Energy Trust of Oregon and
Northwest Energy Efficiency Alliance. The Oregon
estimates were reviewed and modified for service
territory-specific information known to the company.
The Oregon technical potential served as a starting
point for the development of Washington/Idaho
technical potentials. A default calculation translating
Oregon technical potential to Washingtoniidaho was
made based on the number of residential customers for
residential measures and non-residential load for non-
residential measures. These default calculations were
then reviewed and modified as necessary by Avista staff
based on service territory-specific market knowledge
particularly in regard to multi-family housing and
industry-specific non-residential measures.
Estimates of the technical potential for a measure
were used as starting points in the development of
realistically acquirable and sustainable resource
acquisition. At this point, earlier questions regarding the
disaggregation of measures into new construction
replace-on-burnout and replace-before-burnout were
revisited. For purposes of developing estimates of
acquirable resources, it was determined that
replacements of equipment very close to the end
their life would be considered to be a replace-on-
burnout scenario.
Acquirable resource potential estimates were based
on the technical potential available, available trade ally
inttastructure, estimated participant economics and
market opportunities to include the ability to leverage
programs being implemented elsewhere within the
region, customer interest and satisfaction with the
technology, placement of the measure within a product
life cycle continuum, and related issues. The subjectivity
involved in this estimate is unavoidable given the nature
of the programs and the market. Given this subjectivity,
Avista has incorporated within the IRP a commitment
to innovatively seek and acquire all cost-effective DSM
resources available to the company and to establish and
maintain the necessary utility inttastructure to do so.
This commitment is elaborated on elsewhere within
this IRP.
All of the previous analysis was focused on the
acquisition of a portfolio of measures that could be
offered on a prescriptive basis. In recent years Avista has
been successful at deriving substantial therm savings
ttom large customers with unique natural gas-efficiency
opportunities captured through the company's site-
specific program. This has been particularly true in the
Washingtoniidaho division, as many Oregon customers
are transport-only customers who do not qualify for
assistance through utility DSM programs.
It is exceptionally difficult to develop estimates of
the potential within this site-specific market for a
number of reasons. The site-specific program was
developed to create an all-inclusive means of capturing
unique projects; however, by definition, unique projects
are difficult to generically categorize and extrapolate.
In recent history both the Oregon and the
Washington/Idaho divisions have substantially exceeded
previously established therm acquisition goals with
Avista Utilities 2006 Naturai Gas Integrated Resource Plan
projects that have either been completed or are
currently underway. It is uncertain whether or not the
enhanced acquisition of these large projects is solely the
result of recent increases in retail rates that will perhaps
subside once a relatively finite inventory of efficiency
opportunities is acquired. Alternatively the same retail
rates could be generating a new tier of economically
attractive efficiency opportunities that are sustainable in
the long-term.
In previous natural gas IRP proceedings, Avista has
expressed a reluctance to assume a long-term
continuation of these recent site-specific acquisition
achievements. As time progresses and the acquisition
level has remained at a highly favorable level, the
company is of the opinion that the market may be able
to sustain these achievements in the long run.
Consequently, within this IRP analysis, Avista has used
recent history as a baseline for future achievements.
Two alternative methodologies for establishing
acquirable therm acquisition targets for the
Washington/Idaho division were undertaken.
The first approach was to review the last three years
(2002 to 2004 inclusive) of non-residential DSM
program acquisition and to remove the prescriptive
measures incorporated elsewhere within the analysis.
This resulted in an estimate of 48 000 first-year
dekatherms acquired on an annual basis. Prior to the
initiation of the IRP process, a different approach was
used to develop 2006 budget and labor requirements.
This second approach identified a 45 800 first-year
dekatherms annual acquisition. Based on this range, an
acquisition of 46 900 first-year dekatherms was
incorporated into SEND OUT'" as a "must take" option
for the Washington/Idaho division.
The nature of Avista s Oregon retail customer
base is fundamentally different ttom that of the
Washington/Idaho division. More of the large
commercial and small industrial customers have already
become natural gas transportation customers in Oregon.
As these customers purchase their own natural gas
supplies, the proportionately smaller number of
industrial customers that do purchase gas through the
utility naturally limits the potential acquisition level.
Avistas previous Oregon goal of 10 000 first-year
dekatherms of annual acquisition is significantly less than
the companys expectation of future potential. However
due to the large size of the individual projects and the
relatively small service territory, it is difficult to develop
a reasonable acquisition target based on recent history.
This difficulty was described to the TAC as a problem
with the "lumpiness" of the historical data.
Consequently, Avista is proposing that the therm
acquisition achievements be based on a five-year moving
average rather than the results of a single year.
Given an analysis of projects underway, as well as
possible opportunities that are being pursued, the
company believes that the acquirable potential for this
program should be increased from 10 000 first-year
dekatherms to 30 000 first-year dekatherms.
The company believes that this increase is obtainable as
a result of the participant economics at current and
expected future retail rates, as well as increased DSM
program outreach efforts to be incorporated into the
2006 DSM business plan. This estimate of 30 000 first-
year dekatherms was entered into SENDOUT'" as a
must take" resource option.
ADVANCE DSM OPTIONS FOR THE SENDOUT~
MODELING PROCESS
This concluded the portion of the analysis that was
necessary to prepare for the integration ofDSM
resource options into the SEND OUT'" modeling
process.
The results of the SEND OUT'" modeling, discussed
in Section 6, is used as an input into a re-evaluation of
the Oregon and Washington/Idaho DSM portfolios and
business plans described later. Though the DSM options
were represented as closely as possible to the manner in
which the program is likely to be offered, additional
revisions and updates to the SEND OUT'" results will
3 ,Avista Utiiities2006 Natural Gas Integrated Resource Plan
undoubtedly occur. The results of this additional
analysis and any modifications will be communicated
within the Oregon DSM Annual Report and the
Washingtoniidaho Triple-E proceedings.
OVERVIEW OF CURRENT OREGON DSM PORTFOLIO
Avista s residential programs are available to
approximately 79 000 customers (Avista Rate Schedule
410) with an annual consumption of 48 million therms.
The commercial programs are available to 10 600 mostly
small-to-medium-sized customers (Avista Rate
Schedules 420 and 424) with an annual consumption of
approximately 76 million therms. The largest segment
of qualified commercial customers use gas for space and
water heat, and cooking with an average consumption
of 2 600 therms each.
The company has offered a mix of mandated and
non-mandated natural gas efficiency programs to
Oregon customers since the late 1970s. Five separate
programs are offered at the present time: residential
space heat efficiency, residential water heater efficiency,
residential shell measures (insulation and windows),
commerciallindustrial natural gas-efficiency and
commercial energy audits. These five programs and
their recent history are described in greater detail.
Residential Space Heat Efficiency
This program offers a direct incentive of $200 to
$250 for residential customers installing a natural gas
furnace, boiler or combination space/water heating
systems with a 90 percent or higher Annual Fuel
Utilization Efficiency (AFUE). The current federal
minimum furnace efficiency is 78 percent.
The company currently applies a 25-year measure
life to residential natural gas furnaces and boilers.
This is toward the high-end of the range of measure life
typically applied by other utilities.
Current program participation is roughly equally
split between the replacement of existing natural gas
appliances (34 percent), new natural gas appliances
(29 percent) and new construction (37 percent).
Retrofit opportunities most ttequently occur upon start-
up at the outset of the heating season.
Residential Water Heat Efficiency
Forty-gallon natural gas water heaters with an
Energy Factor (EF) rating of 60 percent or higher and
50-gallon water heaters with an EF of 62 percent or
higher qualify for a $50 incentive under the company
current program. The current federal minimum
efficiency level is an EF rating of 59 percent for 40-
gallon water heaters and 58 percent for 50-gallon units.
Past program participation data indicates that
approximately 43 percent of participants are new
construction, 24 percent are replacing an existing gas
appliance and 33 percent are replacing an electric
appliance. A 12-year measure life has been applied to
water heaters in the past. That assumption has been
retained for purposes of this analysis and is consistent
with the physical life of the appliances.
Due to the limited availability of high-efficiency
water heaters customers must frequently endure a "
water heat" period of one to five days in order to obtain
a high-efficiency water heater. Water heaters typically do
not fail during a period of time when such a "heat out
situation is tolerable to the customer. The company has
Avista Utilities 2006 Natural Gas integrated Resource Pian
identified this lack of availability as a market barrier in
the past. Informal surveys have indicated that DSM
programs have had some favorable impact on HVAC
dealer stocking patterns, but the improvement has been
modest and seems to have reached a plateau. Large
retailers on the other hand are not stocking qualified
models indicating a regional effort may be necessary.
The analysis culminating in the DSM supply curve
presented in this IRP substantiate that the lack of
availability of high-efficiency water heating equipment is
a major barrier to improvements in market saturation.
The intent of the current program, which carries an
incentive virtually equal to the then-assumed cost
premium, was to encourage dealers to stock the high-
efficiency equipment as a matter of standard practice
secure in the knowledge that the post-incentive
customer cost for the high-efficiency equipment would
be no higher than that of the standard-efficiency
equipment. Though this program has had an impact on
the market, it is clearly insufficient to achieve any
significant transformation.
The need for more rigorous baseline information on
availability, cost premiums and possible program
enhancements to address these market barriers has been
identified as a future deliverable.
Residential Shell Measures
The company is mandated to offer residential shell
audits and provide shell incentives. The program
includes an attic, wall and floor weatherization program
as well as an efficient window component. The cost
associated with the mandated audit is not included in
the TRC costs of this program since it is not an
incremental resource decision.
Though the customer costs of the shell measures are
not notably different across the four service districts in
Oregon, the therm savings are dramatically different.
That difference is driven by the heating degree-days, as
well as the order that the individual shell measures and
space heat efficiency measures are incorporated into the
home. Shell measures receive the greatest savings when
they are adopted in colder climates, when they are the
first shell measure adopted and when they are adopted
prior to HVAC efficiency measures.
For purposes of developing therm savings estimates
for each of the individual shell components, it was
assumed that participants adopted attic insulation, floor
insulation, wall insulation and window improvements in
that order. This order is based on a combination of the
cost-effective potential of the individual shell measures
and a realistic review of customer behavior. Notably
windows are often replaced as "stand-alone" measures
generally driven by non-energy motivations.
The vintage of a home has a significant bearing on
whether a home is identified as a weatherization
opportunity. Building code improvements during the
1980s and 1990s brought many homes in the housing
inventory to an R-value that is consistent with the
current program standards. Consequently homes deemed
to be program opportunities will gradually decrease over
time as these older homes are removed ttom the
housing inventory or retrofitted to meet existing
shell standards.
Table 3.3 shows current residential shell program
standards.
Table 3 - Avista Residential Shell
Program Requirements
Shell Component
Attic insulation
Floor insulation
Wall insulation
Windows
Program Requirement
Shell measure savings are presumed to have a 30-year
life with no degradation, although windows have been
considered a 25-year measure. This is a simplification of
reality in that a certain amount of degradation certainly
does occur, however it is also true that a substantial
portion of the energy savings persist beyond the
specified measure life.
3 -Avista Utiiities2006 Naturai Gas Integrated Resource Plan
Commercial/ Industrial
~atural c;as IJificiency Table 3.4 - Summary of 2004 Natural Gas Efficiency Program Results
This program encompasses
all TRC-cost-effective measures
that can be applied to the
Program Res Shell Res W/H Res 8/H C/I efficiency
Measure life 30 years 15 years 25 years 18 years
Incentive per unit variable $50 $2001$250 variable
TRC cost per unit variable $50 $496 variable
Therm savings per unit variable variable
Annual target therm savings 45,000 600 42,000 10,000
2004 actual therm savings 70,802 858 123 750 693
company s non-residential/non-
transport customers. Any
natural gas efficiency measure
qualifies provided that it passes
a "sub- TRC" calculation. The "sub- TRC" calculation
excludes the allocation of utility fixed costs to individual
projects. Projects that pass the "sub- TRC" test are
enhancements to the TRC cost-effectiveness of the
overall portfolio even though some may be so
marginally cost-effective that they could not bear a share
of fixed utility cost without becoming cost-ineffective.
Measure lives for these projects are individually
calculated. The program life-to-date weighted average
measure life (weighted by the therm savings of each
project) of the program is 18 years.
Historically this program has exhibited a significant
year-to-year variance in therm acquisition. This is the
result of the relative small size of the qualified customer
base and natural gas-efficiency opportunities and the
relative large size of some individual projects.
Customers qualifying for assistance through DSM
programs within the Oregon service territory have a
higher proportion of small commercial customers than is
evident in Avista s Washington/Idaho service territory.
Consequently the technical and realistic savings potential
are disproportionately lower due to the difficulties
associated with acquiring energy savings from the small
commercial customer segment.
MEASUREMENT AND EFFECTIVENESS OF CURRENT
PROGRAMS
The results of the company s DSM programs are
summarized in an Annual DSM Report. The reporting
includes therm acquisition, number of customers
impacted, and the information necessary to substantiate
the TRC and Utility Cost Test (UCT) analysis
contained within the report. Two of these programs
residential water heater natural gas efficiency and
commerciallindustrial natural gas efficiency, have
consistently been cost effective under both the TRC
and UCT test. The mandated residential weatherization
and the residential space-heat natural gas efficiency
programs are not TRC cost effective on a life-to-date
basis, however they are life-to-date UCT cost effective.
A summary of the 2004 program results is contained
in Table 3.4. Results for 2005 operations will be filed as
part of the 2005 DSM Annual Report.
Derivation of Residential Building Characteristics
In order to estimate potential natural gas savings for
the retrofit and replacement sectors, a fundamental
characterization of the residential populations is
required. Residential accounts have been classified
either single family or multifamily homes. Avista
residential audit data and a secondary data source were
used to estimate saturations of natural gas-powered end-
uses and system types. Basic characterizations are used to
estimate applicable populations for residential natural gas
savings measures and the technical potential savings.
The data sources used in this analysis include 2004
Department of Energy Building Energy Data Book
Census 2000, Residential Energy Consumption Survey
(RECS) 2001, GAMA Gas Appliance Database, and
Database of Energy Efficient Resources (DEER)
2001 and 2005, and preliminary data from RLW
residential surveys for the Northwest Energy Alliance.
Characteristics of new construction are detailed by
Avista Utilities 2006 Naturai Gas integrated Resource Plan
Oregon Dwelling Code and the Northwest Energy
Alliance s 2001 Residential New Construction
Baseline study.
Gas measure savings and costs were primarily drawn
ttom the Energy Trust of Oregon, the Database of
Energy Efficient Resources (DEER) 2005 and surveys
that RLW Analytics conducted with local equipment
suppliers and ttom HVAC and plumbing contractors.
Weatherization costs were taken ttom Avista retrofit
program data and were validated against other available
cost data.
DERIVATION OF GAS SAVINGS POTENTIAL FOR
COMMERCIAL ACCOUNTS
In order to determine the energy savings potential
for the commercial sector, a statistical characterization of
the market was necessary. RLW Analytics completed this
analysis through telephone surveys of a random sample
of the population.
Account data, for the entire commercial sector was
provided, including contact information and billing
information from the past year. Addressees with
multiple accounts were aggregated to bring the accounts
to the "site" or building level. The population of sites
was then stratified by usage and a sample design was
created to optimize the precision of the final estimates.
The site contacts for the sample were called and
asked a series of questions about the nature of business
the natural gas equipment used at the facility and
building characteristics. The survey data was entered
into a database along with site annual base and heat load
that was approximated ttom analysis of one year of
monthly site billing data. In most cases, the base load
was extrapolated ttom the billed July/ August usage, and
the heat load was considered to be the remainder.
Schools and other seasonally operated buildings required
individual base load allocation analysis based upon
survey responses.
CLIMATE
The Oregon service territory is subdivided into four
separate service districts primarily based on climatic
differences. These four areas, ttom warmest to coldest
are Roseburg, Medford, La Grande and Klamath Falls.
The heating degree-days used in this IRP (discussed in
Section 6) for the four service districts are shown in
Table 3.
Notably there
is a significant
difference (71
Table 3.5 - Heating Degree-
Days by Service District
Roseburg
Medford
La Grande
Klamath Falls
216
786
751
201
percent) in
heating degree-
days from the
warmest to the
coldest Oregon
district.
Table 3.6 - Annual Distribution
of Heating Degree-Days (HDDs)
To determine
the seasonal
pattern of energy
Month Percent of Annual HDDsJanuary 16.February 12.March 11.April 8.May 4.June 1.July 0.August 0.September 2.1 %October 7.November 13.December 21.
savings of
heating-related
efficiency
measures
(weatherization
and space heating
measures), the monthly heating degree-day patterns of
Medford were ascribed to each service territory s annual
heating degree-day level. This monthly pattern is
represented in Table 3.
PROGRAM DEVELOPMENT
Based on RLW Analytics DSM potential study and
subsequent analysis, there will be a number of new
programs developed. Avista will begin the development
process in advance of the IRP acknowledgement.
A new prescriptive program for commercial
customers will be developed along with the addition of
measures to the existing residential prescriptive program.
Residential weatherization measures and incentives will
Avista Utiiities2006 Natural Gas integrated Resource Plan
also be evaluated to reflect cost effectiveness calculations
and promote additional participation.
Avista will also look at the "best fit" for program
implementation. Implementation options could include
a combined effort between Avista s North and South
divisions, additional staffing, Energy Trust of Oregon
(ETO), trade partners, and if developed, a natural gas
Northwest Energy Efficiency Alliance (NEEA).
Additional avenues for implementation will be evaluated
as they are identified.
OVERVIEW OF THE CURRENT WASHINGTON/IDAHO
DSM PORTFOLIO
Program Overview
Avista offers a portfolio of electric and natural gas
efficiency programs to Washington and Idaho customers.
Electric efficiency programs have been available since
1978. Natural gas efficiency programs have been offered
without interruption since 2001 and periodically prior
to that time based on cost-effective opportunities within
the market.
The company has established a non-binding external
oversight group, the External Energy Efficiency
Triple-) Board to provide guidance for the
implementation ofDSM programs. This board is
Table 3.7 - WAllO Rate Schedule 190 Incentive Tiel"S
Customer Simple Payback
Zero to 17 months
18 to 48 months
49 to 71 months
72 months or more
Incentive per 1 st yr Therm
$0.
$2.
$2.
$3.
Incentives are capped at 50 percent of incremental measure cost in Idaho and 30 percent of
incremental measure cost in Washington,
provided with a quarterly written update, convenes
twice a year, and receives a comprehensive annual
evaluation of acquisition and cost-effectiveness.
Avistas Rate Schedule 190 provides the regulatory
guidelines for the implementation of the natural gas
DSM programs. This tariff prescribes a set of tiered
direct financial incentives, as illustrated in Table 3.
based on the customer simple payback of the measure.
Selected exceptions to these tiered incentives allow
the company sufficient flexibility to respond to
unexpected or unique opportunities. This flexibility
includes an additional set of tiered incentives, permitting
higher incentives for the development of new
technologies and market transformation efforts.
Avista Rate Schedule 190 also establishes an annual
goal of 240 000 first-year therms. This goal was set in
late 2000 as a natural gas efficiency program was being
Figure 3.2 - Gas OSM Acquisition
000,000
800,000
600,000
400,000
200,000
000,000
800,000
600,000
400,000
200,000
2001 2002
-+- Actual Therms --- Therm Goal
2004
2003
2005
2006
90 Months
Avista Utilities 3 -2006 Natural Gas Integrated Resource Plan
reestablished in response to increases in the weighted
average cost of natural gas. After the approval of the
tariff, natural gas commodity costs and retail rates
continued to escalate. Additionally, the 2001 regional
electric crisis resulted in a substantial enhancement to
electric DSM programs. The strong electric efficiency
message and increasing natural gas retail rates prompted
a much larger natural gas efficiency response than was
anticipated when the original Schedule 190 goal was
established.
Despite the unexpected volume of acquisition
through Schedule 190, the company was well positioned
to respond. In the nearly five years since Avista
reinitiated its natural gas DSM programs, the company
has been communicating its uncertainty regarding the
sustainability of this level of acquisition. Given the lack
of historical precedent, it has not been possible to
determine if this is a one-time response to acquire
measures that have become cost-effective at higher retail
rates or if it will be a sustained response for the
foreseeable future. Based on five years of experience and
the analytical results of this IRp, the company is
proceeding on the presumption that this is a sustainable
level of acquisition.
Funding for the natural gas efficiency programs is
derived through a surcharge on retail rates authorized
under Schedule 191. In Washington this surcharge will
fall from an amount equal to 0.96 percent of retail rates
to a 0.50 percent surcharge. The higher surcharge was
necessary to allow for the recovery of a persistent
negative balance within this tariff rider. The negative
balance was accumulated as a result of unexpectedly
high demand for DSM projects during the 2001 and
2002 period. Since over 90 percent of the natural gas
DSM funding was going to direct customer incentives
required under Schedule 190, it was not possible to
address this negative tariff rider through utility cost
efficiency actions.
Natural gas DSM funding within Idaho is also
funded through Schedule 191 surcharges.
This surcharge was set at 0.50 percent when it was
re-initiated in early 2001 and has not been modified.
The tariff rider balance as of November 2005 is negative
(customers owe shareholders) in an amount equal to
months of typical revenue. As in the case of the
Washington tariff rider balance, customer demand since
2001 has exceeded the original 2001 expectations.
Avista s greatly enhanced electric and natural gas
DSM response to the 2001 regional energy crisis
resulted in an aggregate tariff rider balance (both
Figure 3.3 - Combined Gas and Electric DSM Acquisition
000,000
900,000
800,000
700,000
600,000
500,000
400,000
300,000
200,000
100,000 1999
2001
20022000
-+- Dth Equivalent Goal-+- Actual Dth Equivalent
2003 2004 2005 2006
90 Months
Avista Utilities2006 Natural Gas Integrated Resource Pian
jurisdictions, both fuels) of negative (customers owe
shareholders) $12.4 million. Under a business plan
emphasizing utility cost-control and the targeting of
DSM program outreach to cost-effective and lost-
opportunity measure applications, the company was able
to return this tariff rider to a zero balance in August
2005, all while exceeding tariffed BTU acquisition goals
during that period.
In the future, the company plans to pursue an annual
adjustment to DSM tariff rider levels to ensure funding
that is sufficient to fund continuing DSM operations, as
well as to recover or disburse any tariff rider balance
carried into that year. The planned 2006 filing will be
the first of these revisions. Since this is the company
first opportunity to individually fine-tune tariff rider
balances through this mechanism, it may be necessary to
extend the recovery of some negative balances over
more than one year to provide for reasonable stability of
tariff rider levels.
Only those customers contributing to the program
funding through Avista Rate Schedule 191 are eligible
to receive financial incentives. This limits availability to
core customers. Since 2001, Avista has claimed
acquisition credit for one natural gas efficiency project
ttom a transport customer as a result of the project
being tightly interwoven with an electric-efficiency
project that was being evaluated and funded under the
company s electric DSM program.
DSM implementation efforts within Washington and
Figure 3.4 - Portfolio Distribution of Natural Gas
Efficiency Therm Acquisition, 2004
Commercial/Industrial
Idaho are separated into three different portfolios: (1)
the commerciallindustrial portfolio, (2) the residential
portfolio and (3) the limited income residential
portfolio. The approaches to the implementation of
these three portfolios differ significantly in recognition
of the differences in these markets.
Portfolio Overview Commercial/Industrial
This portfolio is characterized by its all-
encompassing approach to this market. Any natural gas
efficiency measure qualifies for assistance through this
portfolio. Incentives are offered based on the previously
described tiered incentive structure applied to each
individual project.
This approach to the market ensures that unique and
unexpected efficiency measures are never excluded from
acquisition through utility programs. The company
restricts the development of prescriptive programs to
measures and applications that are reasonably uniform in
their energy savings and cost characteristics. This has
generally not been found to be the case for even
relatively common natural gas DSM measures. (Several
prescriptive electric DSM programs have been
developed for the commerciallindustrial market).
In 2004 the company acquired 934 239 therms from
this portfolio (87 percent of the total acquisition of all
three portfolios, 389 percent of the total Avista Rate
Schedule 190 tariffed goal) as depicted in Figure 3.4.
Fifty percent of the total non-interactive energy (electric
and natural gas) acquisition within this portfolio is
attributable to therm savings.
Notably several multifamily housing measures are
incorporated within the commerciallindustrial portfolio
due to the non-residential electric and natural gas rate
schedules that many of these customers are billed. Many
of the multifamily measures evaluated as part of this IRP
analysis (e.g. pool and spa water heating efficiencies in
multifamily housing) will be forwarded to the
commerciallindustrial portfolio segment for further
evaluation.
Avista Utilities 2006 Naturai Gas Integrated Resource Pian
Large projects, those resulting in incentives of
$100 000 or larger, are disclosed to the Triple-E board to
provide them with the information necessary to provide
oversight of DSM programs.
Portfolio Overview Residential
Due to the large volume and relatively small size of
individual projects, the residential portfolio is exclusively
composed of prescriptive programs. In 2004 this
portfolio was responsible for the acquisition of 124 865
first-year therms (12 percent of the total portfolio
52 percent of the Schedule 190 tariffed goal). Of the
non-interactive total energy (electric and natural gas)
savings in 2004 ttom this portfolio, 17 percent are
attributable to therm savings.
Incentives available for residential programs are
calculated based on the application of the measure in a
typical residential home. Calculations are made in
accordance with Avista Rate Schedule 190 tiered
incentives with appropriate modifications for potential
differences in application, multiple measure programs
and rounding for purposes of offering a customer and
trade ally-friendly program. The prescriptive residential
programs currently available are outlined in Table 3.
Additional residential incentives are available for the
conversion of space or water heating appliances ttom
electric to natural gas.
Avista has recently undertaken an enhanced outreach
effort for the residential portfolio. This is composed of a
media and print campaign driving customers to a
revised residential online energy audit. This audit tool
will be enhanced to allow the
customer the ability to
automatically input their
forms over the Internet, as well as provide them with
educational energy efficiency messages and tips
appropriate for the season.
This new online outreach, auditing and education
program will be followed up with a measurement and
evaluation effort intended to provide the information
necessary to determine therm (and kWh) acquisition
and cost-effectiveness, as well as management
information necessary for evaluating ongoing
improvements to the program.
Portfolio Overview Limited Income Residential
Avista s Washington and Idaho limited income
programs are implemented in cooperation with six
community action partnership (CAP) agencies. These
CAP agencies are awarded an annual funding contract
specifying the maximum funding amounts and the
conditions for program implementation. Contracts can
be revised with 30 days' notice, a provision that allows
Avista to reallocate funds among the CAP agencies
during the year to maximize their value to the
customer base.
The CAP agencies and 2006 funding levels are
summarized in Table 3.9. These amounts include a
$200 000 increase above calendar year 2005 funding.
The company has approached the limited income
segment with the intent to provide the maximum
flexibility possible. This permits the agencies to respond
to unexpected urgent needs and energy-efficiency
opportunities that may not have been anticipated when
the annual contracts were signed.
Table 3.8 - WAIID Prescriptive Residential Gas Measures
High-efficiency natural gas furnace ($200 for AFUE 90% or better)
High-efficiency natural gas boiler ($200 for AFUE of 85% or better)
High-efficiency natural gas water heater ($25 for EF 0.60 (50 gallon) or 0.62 (40 gallon) or better)
Ceiling insulation (14 cents/SF for an added R-10 or more)
Attic insulation (14 cents/SF for an added R-10 or more)
Floor insulation (14 cents/SF for an added R-10 or more)
Wall insulation (14 cents/SF for an added R-10 or more)
High-efficiency windows (70 cents/SF of window for U-35 or better)$3.
personal usage data to provide
more detailed and accurate
audit results. The website will
ultimately allow customers to
access program information
and incentive application Additional residential incentNes are avaHable for the conver~on of space or water heating appliances from electric to natural gas,
Avista Utiiities2006 Natural Gas Integrated Resource Pian
Table 3.9 - WAllO Community Action Program Contracts
Spokane Neighborhood Action Program (Spokane area)
Community Action Agency (Idaho and Washington)
Pullman Community Action (Whitman County)
Grant County/North Columbia CM (Grant County area)
Northeast Rural Resources
Klickitat CM (Golden dale/Stevenson)
As part of this flexibility, Avista allows the CAP
agencies to expend up to 100 percent of their total
funding on electric efficiency projects or up to 75
percent of their funds on natural gas efficiency projects.
The funding available includes an allowable 15 percent
remuneration to the agency for administrative and
outreach costs. Up to 15 percent of the funds can be
expended for health and human safety measures with an
emphasis on the safe use of energy, and maintenance and
repairs necessary to ensure the longevity of installed
efficiency measures and continued habitability
the home.
The limited income residential segment delivered
277 first-year therms to the overall natural gas DSM
program in 2004 (2 percent of the total acquisition that
year). This therm acquisition represented 42 percent of
the total BTU's acquired by the combined electric and
natural gas programs.
AVISTA DSM COMMITMENT
Avista recognizes its obligation to meet the resource
needs of customers in the most cost-effective manner.
The delivery of natural gas efficiency programs is
anticipated to represent an increasing portion of the
optimal natural gas resource portfolio. The IRP process
is an opportunity for the company to comprehensively
review the natural gas efficiency program portfolio and
make the revisions necessary to meet those
commitments in the years to follow.
This document summarizes a broad evaluation of
applicable natural gas efficiency opportunities and
identifies those worthy of testing against all other
$539 812
$447 772
$83,048
$72 667
$71 107
300
possible resources to assist the company in
making decisions about which of those natural
gas efficiency resources are suitable to carry
forward into program development.
The company solicited comments of key
stakeholders regarding the selection
characterization and testing of natural gas
efficiency opportunities within the IRP process.
Mter much discussion and some revision, the general
consensus of those stakeholders was that this approach
was sufficient to represent natural gas efficiency
opportunities within the IRP.
The company also agrees that it is cost-effective and
appropriate to substantially ramp-up Oregon natural
gas DSM programs, as well as to reconsider the approach
to the implementation of those programs. This analysis
has also established a tentative goal far in excess of
previous commitments represented in Washington and
Idaho Schedule 190 and slightly above recent
acquisition levels.
Complete agreement was not possible regarding the
likely customer reaction to several components of the
enhanced Oregon natural gas DSM portfolio.
The company is concerned that market barriers will
constrain participation. Avista is, and will remain, open
to alternative approaches to overcoming those market
barriers to include enhanced outreach efforts, revised
incentives, and innovative marketing of natural gas
efficiency programs and cooperative arrangements with
other agents in the market, with particular attention to
other natural gas utilities, the Energy Trust of Oregon
and regional market transformation organizations with
an interest in natural gas efficiency.
Additionally, the company is committed to
maintaining a collaborative relationship with all
stakeholders who may contribute to the improvement
natural gas DSM efforts as programs are further
developed and launched. Additional metrics will be
developed to improve the active management of these
programs over time, as well as to provide better
Avista Utiiities 2006 Natural Gas Integrated Resource Pian
benchmarks for determining the regulatory prudence of
these programs.
The company recognizes that this commitment to
acquiring all cost-effective natural gas-efficiency
potential is not limited by the therm acquisition goals
established within this IRP. Avistas implementation of
the results of this planning effort will be sufficiently
flexible to realize those opportunities even if they are
well in excess of expectations. Human and financial
resources will be made available to the extent necessary
to achieve the cost-effective potential without regard to
those goals.
ACTION ITEMS
The completion of the IRP analysis is the midpoint
not the ending point, of a larger reassessment of the
DSM resource portfolio. The IRP analysis presented has
generally indicated a set of cost-effective measures and
acquirable resource potential for a future DSM portfolio.
These results remain in need of further evaluation to
facilitate the development of program plans and to
incorporate them into an updated DSM business plan.
The DSM analysis that occurred during the IRP
process is the launching point for a more detailed
investigation of the natural gas-efficiency technologies
identified as cost-effective resource options.
The company initiated this additional evaluation and
development of programs in January 2006 with the
expectation that program revisions, and the launch of
new programs will occur thereafter. The timing of
partnership arrangements and the seasonality of the
customer adoption of particular measures may influence
the timing of those launches.
The company has explicitly recognized within this
IRP the obligation to achieve all natural gas-efficiency
resources available through the intervention of cost-
effective utility programs. Given the rapid changes
within the natural gas market, there are many new
efficiency opportunities in the market. Considerable
uncertainty remains regarding the customer response to
these programs, however. This uncertainty does not
preclude the company from pursuing the planned
aggressive ramp-up of natural gas-efficiency programs
throughout the service territory. Additionally, the
company has, and will actively seek, opportunities for
new or enhanced resource acquisition through the
development of cooperative regional programs.
One of the results of the IRP process is a 20-year
forecast of monthly avoided costs for each of the seven
geographic areas. The detailed nature of these avoided
costs makes it possible to continue to evaluate measures
and programs as technology and markets change
without the need to await the next IRP process. This is
of value in determining program cost-effectiveness based
on updated inputs, revised program plans and the ability
to determine the value of targeting specific markets.
Avoided cost determination is discussed in detail in
Section 7.
As part of the program planning process, Avista will
calculate all individually-evaluated measures and other
measures, as necessary, for their cost-effectiveness in each
of the individual Oregon divisions as well as within the
Washington/Idaho division.
UPDATING THE PARAMETERS OF THE
OREGON SITE-SPECIFIC COST-EFFECTIVENESS
LITMUS TEST
For the past two years the company has made site-
specific financial incentives available only to those
projects that have passed a sub- TRC cost-effectiveness
test. Upon the OPUC approval of revised avoided costs
this model will be updated and applied to future
projects.
The potential energy savings ttom a programmable
natural gas thermostat program is, in the opinion of the
company, uncertain. Many credible sources have come
to the conclusion that there are no energy savings from
these devices based on the assumption that (a) many
customers adjust non-programmable thermostats to
obtain a degree of control that is equal or superior to
3 - 20 Avista Utilities2006 Natural Gas Integrated Resource Pian
that achievable ttom programmable thermostats;
(b) many customers with programmable thermostats do
not effectively use them as control devices; and (c) the
ramping down of interior temperature when the
thermostat sets back and the make-up heating required
when it ends the set back period causes a loss in much
of the expected efficiency impact.
Avista has past experience with a combined
residential electric and natural gas programmable
thermostat program. Based on an evaluation of these
results and an updated survey of available literature, the
company will reconsider previous conclusions regarding
energy savIngs.
Participation in consideration of regional natural
gas market transformation organization
Based on the company's assessment of natural gas
efficiency programs in all three state jurisdictions, Avista
has come to the tentative conclusion that there is a need
for a regional natural gas efficiency market
transformation organization similar to the Northwest
Energy Efficiency Alliance. Partially based on Avista
actions, the Alliance will be initiating that discussion
in 2006. Avista will be an active participant in that
discussion.
CONCLUSION
This IRP provides Avista the necessary resource
analysis to proceed to the further development and
ultimate implementation of natural gas efficiency
programs. In this process there will be additional
evaluation of measures and programs and consideration
of all alternatives, including, for the Oregon jurisdiction
cooperative arrangements with the ETO. Additionally,
Avista intends to investigate the potential for wider
regional cooperation among natural gas utilities for the
implementation of selected efficiency measures based
upon either a resource acquisition or market
transformation business plan.
Avista Utilities 2006 Natural Gas Integrated Resource Plan
(This page intentionally left blank,
2006 Naturai Gas integrated Resource Plan Avista Utilities
SECTION 4 - DISTRIBUTION PLANNING
The primary goal of distribution system planning is
to design for present needs and to plan for future
expansion to serve demand growth. This allows the
company to satisfy current demand-serving
requirements while taking steps toward meeting future
needs. Distribution system planning identifies potential
problems and areas of the distribution system that
require reinforcement either in the near- or mid-term.
Knowing when and where pressure problems may
occur, the necessary reinforcements can be incorporated
into normal maintenance. Thus, more costly "reactive
and emergency solutions can be avoided.
COMPUTER MODELING
When designing new main extensions, computer
modeling can help determine the optimum size facilities
for present and future needs. Undersized facilities are
costly to replace, and oversized facilities incur
unnecessary expenses to the company and its customers.
THEORY AND APPLICATION OF STUDY
Natural gas network load studies have evolved in
recent years to become a highly technical and useful
means of analyzing the operation of a distribution
system. Using a pipeline fluid flow formula, a specified
parameter of each pipe element can be simultaneously
solved. A variety of pipeline equations exist, each
tailored to a specific flow behavior. Through years of
research, these equations have been refined to the point
where solutions obtained closely represent actual system
behavior.
Avista conducts network load studies using Advantica
Stoners SynerGEE'" 4.13 software. This is a computer-
based modeling tool that runs on a Windows operating
system and allows users to analyze and interpret
solutions graphically.
Avista Utilities 2006 Naturai Gas Integrated Resource Pian
CREATING A MODEL STEADY STATE COMPUTER SIMULATION
To properly study the distribution system, all natural
gas main information is entered (length, pipe roughness
and ID) into the model. "Main" refers to all pipelines
supplying services.
Nodes (points where natural gas enters or leaves the
system) are placed at all pipe intersections, beginnings
and ends of mains, changes in pipe diameter/material
and to identify all large commercial customers.
A model element connects two nodes together.
Therefore, a "to node" and a "ttom node" will represent
an element between those two nodes. Almost all of the
elements in a model are pipes.
In the model, regulators are treated like adjustable
valves in which the downstream pressure is set to a
known value. Although specific regulator types can be
entered for realistic behavior, the "expected" flow
passing through the actual regulator is determined, and
the modeled regulator is forced to accommodate
such flows.
FLUID MECHANICS OF MODEL
Pipe flow equations are used to determine the
relationships between flow, pressure drop, diameter and
pipe length. For all models, the Fundamental Flow
equation (FM) is used due to its demonstrated reliability.
Efficiency factors are used to account for the
equivalent resistance of valves, fittings and angle changes
within the distribution system. Starting with a 95
percent factor, the efficiency can be changed to fine
tune the model to match field results.
Pipe roughness along with flow conditions creates a
ttiction factor for all pipes within a system. Thus, each
pipe may have a unique friction factor, minimizing
computational errors associated with generalized
ttiction values.
All studies are considered "steady state:" all natural
gas entering the distribution system must equal the
natural gas exiting the distribution system at any given
time.
Customer loads are obtained from Avista s customer
billing system and transferred to an algebraic format so
loads can be generated for various conditions.
In the event of a peak day or an extremely cold
weather condition, it will be assumed that all curtailable
loads are interrupted. Therefore, the models will be
conducted with only core loads unless otherwise stated.
DETERMINING NATURAL GAS CUSTOMERS'
MAXIMUM HOURLY USAGE
Determining a Base Load
Base loads are not temperature dependent; they
remain relatively constant regardless of temperature.
A reasonable base load can be calculated ttom customer
billing information. The billing month, which has the
Avista Utiiities2006 Natural Gas Integrated Resource Plan
lowest amount of heating degree-days is usually August.
Usage during this month will reflect nearly all natural
gas loads exclusive of space heating.
By determining the amount of days in the billing
period and applying a "peaking factor," the "peak hourly
base load" of each customer can be estimated as shown
in Table 4.
Table 4.1 - Determining a Base Load
Customer Usage X Days In X 0 0625* - Peak HourlyBilling Period Billing Period Base Load
*Note:The average residential customers peak usage
was found to be 6.25 percent of the total daily load.
This "peaking factor" was estimated by studying the
ratio of the peak hourly flow and the total daily flow at
the pipeline gate stations (result = 6.25 percent of total
daily load) in past years (1994-99). The peaking factor is
periodically discussed with other utilities and has been
shown as consistent with other utilities of similar size.
DETERMINING A HEAT LOAD
A heat load will be proportional to heating degree-
days (HDDs); at 0 HDD, the load will be zero. A heat
load can be reasonably calculated from customer billing
information. The billing month with the greatest
consumption is usually January. This month reflects
maximum space heating loads as well as non-space
heating loads.
Customers usage for January (winter) billing, minus
Table 4.2 - Determining a Heat Load
Customer Usage
Winter Billing
Period
Customer Usage
Summer Billing
Period
Heat Load
Winter Billing
Period
Heat Load Winter Billing
Winter Billing X Period Degree X Design Degree XPeriod Days Days Day
0625*Peak Hourly Heat Load
usage for August (summer) billing, leaves a reasonable
estimate for heat load. This load can be divided by the
amount of HDDs that occurred in January, leaving usage
per HDD. Customer needs can be calculated by
applying the peaking factor, resulting in a "peak hourly
heat load" per HDD. This is shown in Table 4.
DETERMINING A DESIGN PEAK HOURLY LOAD
Adding the hourly base load and hourly heat load
for a design temperature results in the design peak
hourly load for a customer. This estimate reflects
highest system hourly demands, as shown in Table 4.
This method differs ttom the approach that the
company takes for peak day/design day load planning.
The primary reason for this difference is due to the
hourly peak importance in distribution planning, while
IRP resource planning is performed based on peak day
requirements.
Table 4.3 - Determining a Design Peak Hourly Load
Peak Hourly +
Base Load
Peak Hourly
Heat Load
Design Peak
Hourly Load
APPLYING LOADS
Having estimated the peak loads for all customers in
a particular service area, the model can be loaded. The
first step is to assign each load to the respective node or
element.
GENERATING LOADS
Temperature-based and non-temperature-based loads
are established for each node, thus loads can be varied
based on any temperature (HDD). Such a tool is
necessary to evaluate the difference in flow and pressure
due to different weather conditions.
Avista Utilities 2006 Naturai Gas Integrated Resource Plan
GEOGRAPHIC INFORMATION SYSTEM (GIS)
The company is in the process of converting its
natural gas facility maps to GIS. While a GIS can
provide a variety of map products, its power lies in its
analytical capability. A GIS consists of three
components: spatial operations, data association and map
production.
A GIS allows analysts to conduct spatial operations.
A spatial operation is possible if a facility displayed on a
map maintains a relationship to other facilities. Spatial
relationships allow analysts to perform a multitude of
queries, including:
. IdentifY electric customers adjacent to natural gas
mains and who are not currently using natural
gas;
. Display the ratio of customers to length of pipe
in Emergency Operating Procedure zones
(geographical areas defined by the number
customers and their safety in the event of an
emergency); and
. ClassifY high-pressure pipeline proximity criteria.
The second component of a GIS is data association.
Data association allows analysts to model relationships
between facilities displayed on a map to tabular
information residing in a database. Databases store
facility information such as pipe size, pipe material
pressure rating, or related information (e., customer
databases, equipment databases, and work management
systems). Data association allows interactive queries
within a map-like environment.
Finally, a GIS provides a means to create maps of
existing facilities in different scales, projections and
displays. In addition, the results of a comparative or
spatial analysis can be presented pictorially. This allows
users to present abstract analyses in a more intuitive
context.
BUILDING SYNERGEEQI MODELS FROM A GIS
A GIS can provide additional benefits through the
ease of creation and maintenance of load studies. Avista
can create load studies ttom a GIS based on tabular data
(attributes) installed during the mapping process.
MAINTENANCE USING A GIS
A GIS helps maintain the existing distribution
facility by allowing a design to be initiated on a GIS.
Currently, design jobs for the company s natural gas
system are managed through Avistas Work Management
System (WMS). This system is being integrated with
GIS, allowing jobs to be designed directly within a GIS.
Once completed, the as-built information is submitted
to GIS, and the facility is immediately updated. This
eliminates the need to convert physical maps to a GIS at
a later date. Because the facility is updated on GIS, load
studies can remain current by refreshing the analysis.
DEVELOPING A PRESENT CASE LOAD STUDY
In order for any model to have accuracy, a "present
case" model has to be developed that reflects what the
system was doing when downstream pressures and flows
are known. To establish the "present case;' pressure
charts located throughout the distribution are used.
Pressure charts plot pressure (some include
Avista Utilities2006 Naturai Gas Integrated Resource Pian
temperature) versus time over several days. Various
locations recording simultaneously are used to validate
the model. Customer loads on SynerGEE'" are generated
to correspond with the actual temperatures recorded on
the pressure charts. An accurate model's downstream
pressures will match the corresponding location s "field"
pressure chart. To further refine the model's pressures
efficiency factors are fine-tuned.
Since telemetry at the gate stations record hourly
flow, temperature and pressure, such known values are
also used to validate the model. All loads are
representative of the average daily temperature and are
defined as hourly flows. If the load generating method is
truly accurate, all natural gas entering the "actual
system" (physical) equals total natural gas demand solved
by the "simulated" system (model).
DEVELOPING A PEAK CASE LOAD STUDY
Using the calculated peak loads, a model can be
analyzed to identify the behavior during a peak day.
The efficiency factors established in the "present case
are used throughout subsequent models.
ANALYZING RESULTS
Mter a model has been balanced, several features
within the SynerGEE'" model are used to translate
results. Color plots are generated to depict flow
direction, pressure, pipe diameter and gradient with
specific break points. Thus, attributes of a reinforcement
can be queried by visual inspection. When user edits are
completed and the model is re-balanced, pressure
changes can be visually displayed, helping identify
optimum reinforcements.
An optimum reinforcement will have the largest
pressure increase per unit length. Reinforcements can
also be deferred and occasionally eliminated through
load mitigation of DSM efforts.
PLANNING CRITERIA
In most instances, models resulting in node pressures
below 15 psig indicate a likelihood of distribution
failure and therefore necessitate reinforcements.
For most Avista distribution systems, a minimum of
15 psig will ensure deliverability as natural gas exits the
distribution mains and travels through service pipelines
to a customers meter.
Some Avista distribution areas operate at lower
pressures and are assigned a minimum pressure of 5 psig
for model results. Given a lower operating pressure
service pipelines in such areas are sized accordingly to
maintain reliability.
DETERMINING MAXIMUM CAPACITY FOR A
SYSTEM
Using a peak day model, loads can be prorated at
intervals until area pressures drop to 15 psig. At that
point, the total amount of natural gas entering the
system equals the maximum capacity before new
construction is necessary. The difference between
natural gas entering the system in this scenario and a
peak day model is the maximum "additional" capacity
that can be added to the system.
Since the approximate natural gas usage for the
average customer is known, it can be determined how
many new customers can be added to the distribution
system before necessitating system reinforcements.
The above models and procedures are utilized with
new construction proposals or pipe reinforcements to
determine a potential increase in facilities.
FIVE-YEAR FORECASTING
The intent of Avistas load study forecasting is to
predict the system s behavior and what reinforcements
will be necessary within the next five years. Various
Avista personnel provide information to determine
where and why certain areas may experience growth.
By combining information from Avista s demand
forecast, IRP planning efforts, regional growth plans and
Avista Utilities 2006 Naturai Gas Integrated Resource Plan
Table 4.4 - Capital Reinforcement Projects with Estimated Costs in 2005$
Project Description STATE 2005 2006 2007 2008 2009 2010
Bruce Rd. H.P. Reinforcement 050 000
Klamath Falls H.P. Feeder Re-route $40,1 gO $950,000 500 000
Transmission Reinforcement - Medford 194 388 $10 000,000
Diamond Lake Reinforcement 622,472 $1,500,000
Grants Pass South Side Reinforcement $304,556
Eagle pt High Pressure Reinforcement 100,000
Elgin Line H.P. Reinforcement 600 000 700 000
Medford Airport H.P. crossing $1,000,000
Sutherlin 6"$170 000
Merlin Gate Station Rebuild $102,714 $450 000
Dover Gate Station $615,813
Klamath Falls Lateral Acquisition $3,100,000
La Grande/Elgin H.P. Reinforcement 000 000 000,000 000 000
area developments, proposals for pipeline reinforcements
and expansions can be evaluated with SynerGEE"'
A current list of management approved proposed
reinforcement projects for the company is shown in
Table 4.4.
SUMMARY
The company s goal is to maintain its distribution
systems in order to reliably deliver natural gas to every
customer with the most cost-effective investment.
This goal can be better achieved with computer
modeling.
Computer modeling increases the reliability of the
distribution system by identifYing specific areas within
the system that may require changes.
SynerGEE'" models are constantly used to look
different areas within the companys natural gas service
area. Natural gas system planning, construction
budgeting and prioritization are conducted ttom these
analyses. Additionally, pipeline constraints and
improvements are reviewed internally to facilitate supply
and demand optimization.
4 - 6 Avista Utilities2006 Natural Gas Integrated Resource Plan
SECTION 5 - SUPPLY-SIDE RESOURCES
Avista s supply philosophy is to reliably provide
natural gas to its customers with an appropriate balance
of price stability and prudent cost. To that end, Avista
continuously evaluates a variety of supply resources and
attempts to build a portfolio that is appropriately
balanced and diversified to achieve cost effectiveness.
The hedging program resulting from that continuous
evaluation addresses physical and financial risks, both of
which are covered in this section.
This section describes natural gas commodity
resources, transportation arrangements used to connect
those supply resources to Avista s demand regions, and
market-related risks and ways that Avista mitigates
those risks.
COMMODITY RESOURCES
Avista has a number of supply options available to
serve Avistas core customers. These include firm and
non-firm supplies, firm and interruptible transportation
on six interstate pipelines, and two storage projects.
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.
Avista is located near several liquid hubs and supply
basins in western North America, including Alberta and
British Columbia in Canada, and the Rocky Mountain
region in the United States. Avista s unique access to a
diverse group of supply basins, coupled with the
diversity of delivery points, allows the company to
purchase at the lower-priced trading hubs on any given
day, subject to operational and contractual constraints.
The three major supply points near Avista s service
area are Sumas (located north of Seattle at the
US./Canadian border), AECO (northeast of Spokane
in Alberta, Canada) and the Rockies (a number of
natural gas production pools in Wyoming, Utah
Colorado and New Mexico). The price for natural gas
at these three supply points generally moves together.
However the basis differential among the supply points
can change depending on a variety of market or
Avista Utilities 2006 Natural Gas Integrated Resource Pian
operational factors, including differences in weather
patterns, pipeline constraints at different locations and
the agreed-upon terms and conditions include:
. Firm vs. Non-Firm - Most term contracts
the ability to shift supplies to higher-priced delivery
points elsewhere in the United States or Canada. Based
specify that supplies are firm except for force
majeure conditions, and the standard provision for
on market information and analysis, Avista believes
there is sufficient liquidity at the three supply points
daily transactions is that they may be cut for
reasons other than force majeure conditions.
such that there will be as much commodity available as
the company requires to meet demand.
Given the transportability of natural gas to other
. Fixed vs. Floating Pricing - The agreed-upon
price for the delivered gas may be a fixed price
or based upon a daily or monthly index.
portions of North America, natural gas pricing is often
compared to the Henry Hub price for natural gas.
. Physical vs. Financial - Certain counterparties
such as banking institutions, do not trade physical
natural gas but are still active in the natural gas
markets. Rather than managing physical supplies
Henry Hub is a natural gas trading point located in
Louisiana and is widely recognized as the primary
natural gas pricing point in the United States. NYMEX
futures contracts are priced at Henry Hub. Figure 5.
illustrates the tight relationship among the various
locations and shows historic natural gas prices for
those counterparties choose to transact financially
rather than physically. Financial transactions
provide another way for Avista to financially
physical purchases at Henry Hub, AECO, Sumas and
the Rockies.
hedge price.
. Load Factor/Variable Take - Some contracts
Contract Provisions - There are a number of
have fixed reservation charges assessed during
each of the winter months, while others have
contract specifics that vary ttom transaction to
transaction, and many of those terms or conditions have
minimum daily or monthly take requirements.
Depending on the specific provisions, the
resulting commodity price will contain aan impact on the pricing of the commodity. Some of
Figure 5.1 -January 1995 to Freburary 2006 Monthly Index
Nymex/Rockies!Su mas! AECO
Jan. July Jan. July Jan. July Jan. July Jan. July Jan. July Jan. July Jan. July Jan. July Jan. July Jan. July Jan.
~ ~
--- Rockies --- Sumas
--!I.-- AECO Nymex
5 - 2 2006 Natural Gas integrated Resource Pian Avista Utilities
discount or premium when compared to a
standard product.
. Liquidated Damages - Most contracts contain
provisions for symmetrical penalties for failure to
take or supply natural gas according to contract
terms.
For the purposes of this IRp,the SEND OUT'"
model assumes the natural gas is purchased as a firm
physical, fixed-price contract regardless of when the
contract is executed and what type of contract it is.
However, in reality, Avista explores a variety of
contractual terms and conditions in order to capture the
most value ttom each transaction.
STORAGE RESOURCES
The company is one-third owner, with NWP and
Puget Sound Energy (PSE), in the Jackson Prairie
Storage Project for the benefit of its Washington and
Idaho customers. Avista has contracted for service in
this underground natural gas storage project for its
Oregon customers and has contracted for LNG storage
at Plymouth to serve core customers in all three states.
Jackson Prairie Storage is an underground reservoir
project located near NWP's mainline near Chehalis
Wash. Plymouth LNG is a liquefied natural gas storage
facility located near NWP's mainline near
Plymouth, Wash.
Storage is a strategic resource due to the company
low load factor. Storage provides the following benefits:
. Provides invaluable peaking capability;
. Reduces the need for higher cost annual firm
transportation;
. Increases the load factor of existing firm
transportation; and
. Provides access to normally lower cost summer
supplies.
Table 5.1 recaps the current storage resources
by area.
JACKSON PRAIRIE STORAGE PROJECT
In the early 1980s, Avista determined it did not then
need its entire Jackson Prairie storage capacity to meet
firm system requirements. In 1982, Avista released half
of its capacity and deliverability at Jackson Prairie to BC
Hydro. The primary term of the original contract was
set to expire in 1996, with a provision for year-to-year
continuation thereafter. The new contract with Terasen
successor to BC Hydro for natural gas operations, has
been in place since 1996, with recall provisions after
2000. This arrangement retains the storage capacity for
Avista s future use, while providing a return on Avista
investment in the form of rental payments until such
time as the additional capacity is needed. The annual
renewal of this contract is analyzed each year to
determine the appropriateness of continuing this
agreement with Terasen.
In 1990, Avista made a similar, although smaller
release to Cascade Natural Gas Company (Cascade).
As with the Terasen release, this release to Cascade
retains the storage capacity for Avista s future need and is
analyzed each year to determine the appropriateness of
continuing this arrangement. The release of storage
rights includes a similar amount of firm transportation
whereas the Terasen release does not include a
transportation release. In March 2006, Avista notified
Cascade that this release will be terminated pursuant to
the contractual provisions. The recall will be effective
April 30 2007.
In 1999, and again in 2002, Avista participated in
capacity expansions of the Jackson Prairie Storage
Project with NWP and Puget Sound Energy. It was
determined that the additional capacity for core utility
customers was not needed at that time, and it went
under the management of Avista Energy. The company
has an option to take this capacity back as soon as
November 2009.
The 2002 expansion is a phased, ongoing project to
increase the storage capacity of the field. The 2002
expansion has progressed at a slower pace than originally
Avista Utilities 2006 Natural Gas integrated Resource Pian
planned and will be approximately 50 percent complete
in mid-2006. Additionally, the partners in Jackson
Prairie are currently studying the feasibility of
expanding the daily withdrawal capability. The target of
this expansion study is to increase daily deliverability by
300 MMcfd by the fall of 2008.
Avista continues to evaluate its Jackson Prairie
capacity and deliverability requirements to determine
it should continue present releases, call back some or all
capacity, negotiate additional releases or participate in
future expansions of the project.
TRANSPORTATION RESOURCES
Although proximity to the liquid hubs is important
ttom a cost perspective, those supplies are only as reliable
or firm as the pipeline transportation that moves the
supplies from the hubs to Avista s service territory.
Consequently, Avista has contracted for a sufficient
amount of firm pipeline capacity so that
firm deliveries will meet design day
demand. Avista believes the combination of
firm transportation rights to its service
territory, storage facilities and access to
liquid supply basins will ensure peak
supplies are available to its core customers.
The company has many contracts with
NWP and GTN for firm and interruptible
transportation to serve the core customers.
In addition to this capacity, Avista also
contracts for capacity on upstream pipelines
to flow natural gas to NWP and GTN.
Table 5.1 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 the company and its customers
the knowledge that Avista will have
available capacity to meet core load demand
now and in the future.
NWP and GTN also provide interruptible
transportation service to the company. The level of
service of 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 connected with these transportation
contracts. Since the marketplace for capacity release of
transportation capacity has become so prevalent, the use
of interruptible transportation services has diminished.
Avista does not rely on interruptible capacity to meet
design day core demand requirements.
The company's strategy is to contract for firm
transportation to serve core customers should a design
peak day occur in the near-term planning horizon.
Too much firm transportation could keep the company
ttom achieving its goal of being a low-cost energy
Table 5.1 - Current Maximum Available
Firm Transportation/Resources
Dth/Day
Firm Transportation 1/
NWP TF-
GTN T-
NWP TF-2 (JP) 3/
NWP TF-2 (LNG)
Total
Upstream Transportation 1/
Duke
TransCanada Alberta Sys.
TransCanada BC System
Firm Storage Resources 1/
JPSP (SG) 3/
NWP LNG (LS-
Total
Other Peaking Arrangements
Williamette Ind. Agreement 2/
Avista North Avista South
Winter Summer Winter Summer
143 270 143 270 33,731 33,731
100 605 782 260 640
200 654
000 19,200
357,075 219,052 97,845 54,371
914 914 856 856
103,434 565 43,489 658
101 953 084 867 616
127 667 623
000 200
134 667 21,823
000
1/ Contract expiration dates vary but in each instance, other than with the Wolliamette PealOng Agreement, Avista holds a
unilateral evergreen or nght of tirst refusa to retain the capacity indefinately, AJI figures are net of non-recaJlable currently
effective re1eases,
21 This peaking arrangement allows for up to 20 days of delivenes in the Medford area served off of NWP, This contract
expires in 2010, Upon expiration, 12,000 Dthlday of released annual capacity will rerum to Avista under NWP's TF-1 rate
schedule,
3/ Includes JP Storage/Capacity recaJl for 15,000 Dthld of TF-2 transportation and 15,000 Dthld ofdelivenbility from JP
(along with 480 000 Dth of Capacity),
5 - 4 Avista Utilities2006 Natural Gas integrated Resource Pian
Table 5.2 - Current Transportation/Storage Rates and Assumptions
Rates in US$/Dth/Day
Commodity Fuel Rate Rate Change AssumptionsReservation
TransCanada Alberta System Firm Rates-
Postage Stamp Rates
AECo/NIT to ABC
AECo/NIT to ABC Winter Only
1340
1675
TransCanada BC System Firm Rates-
Postage Stamp Rates
ABC to Kingsgate 0550 0030
GTN FTS-1 Rates -
Mileage Based - Representative Example
Kingsgate to Spokane
Kingsgate to Medford
Meford Lateral
0690
2499
5607
0015
0078
DukelWestcoast System Firm Rates -
Postage Stamp Rates
Station 2 to Huntington/Sumas 2650
Williams NWP
Postage Stamp Rates
TF-11/
TF-21/
SGS-2F 2/
LS-1 3/
2776
2776
5137
8918
0319
0319
0189
5569/0.0303
1/1F-t based upon annual dalivery capability, 1F-2 based upon approximately 32 days ofde1ivery capability
21 Not applicable for WNID Customers
31 The commodity rate for LS-t service is for injection and w.hdrawals
41 Fuel retained in-lOnd
00%
00%
Change annually at GDP
Change annually at GDP
00%Change annually at GDP
32%
80%
00%
10% rate increase on 11/06 and GDP thereafter
10% rate increase on 11/06 and GDP thereafter
10% rate increase on 11/06 and GDP thereafter
00%Change annually at GDP
1.77%
1.77%
16%
66%
25.22% rate increase on 11/06 and GDP thereafter
25.22% rate increase on 11/06 and GDP thereafter
25.22% rate increase on 11/06 and GDP thereafter
25.22% rate increase on 11/06 and GDP thereafter
provider, but it is important to maintain an appropriate
time cushion such that Avista allows for required lead
times for new capacity. The ability to release capacity
acts to offset the cost of holding underutilized capacity.
Too little firm transportation impairs the company s goal
of being a reliable energy provider.
Note about the Rate Change Assumptions in Table
2: Forecasting future pipeline rates is difficult, if not
impossible. Avista s assumptions for future rate changes
were the result of market information and concurrence
by members of the TAc. Williams NWP has indicated
to various parties that it intends to file a pipeline rate
case in mid-2006, and it is commonly anticipated that
GTN will also file a rate case in 2006. Beyond those
expectations, it is assumed that the pipelines will file to
recover costs at rates equal to the GDP.
Determining the appropriate level of firm
transportation is a complex evaluation of many factors
including the projected number of firm customers and
their expected demand on an annual and peak day basis
opportunities for future pipeline or storage expansions
and relative costs between pipelines and their
upstream supplies.
MARKET-RELATED RISKS AND RISK MANAGEMENT
While risk management can be defined in a variety
of ways, this IRP focuses on two areas of risk: the
financial risk under which the cost to supply customers
will be unreasonably high or unreasonably volatile, and
the physical risk that there may not be enough natural
gas (either the transportation capacity or the
commodity) to serve Avistas core customers.
Avista has a risk management policy that describes in
more detail the policies and procedures associated with
Avista Utiiities 5, 52006 Naturai Gas Integrated Resource Plan
financial and physical risk management. The risk
management policy addresses, among other things, issues
related to management oversight and responsibilities
internal reporting requirements, documentation and
transaction tracking and credit risk.
Additionally, there are three internal organizations
that assist in the establishment, reporting and review of
Avistas business activities as they relate to management
of natural gas business risks:
. The Risk Management Committee consists of
several corporate officers and other senior-level
management. The Risk Management
Committee receives regular reports on natural gas
activity and meets regularly to discuss market
conditions, hedging activity and other natural
gas-related matters.
. The Strategic Oversight Group (SOG) exists to
coordinate natural gas matters among internal
natural gas-related stakeholders and to serve as a
reference/sounding board for strategic decisions
including hedges, made by the Natural Gas
Supply department. Members include
representatives from the Accounting, Rates and
Risk Management departments. While the
Natural Gas Supply department is responsible for
implementing hedge transactions, the SOG
provides input and advice.
. A Natural Gas Coordination Committee involves
Natural Gas Supply, Demand-Side Management
Natural Gas Engineering, Rates, Accounting,
Natural Gas Operations and customer
representatives to ensure that the various
departments are maintaining lines of
communication and coordinating efforts with
respect to natural gas-related projects.
MARKET FACTORS AND AVISTA'
PROCUREMENT PLAN
Avista cannot predict future natural gas prices.
The company has designed a natural gas procurement
plan that attempts to competitively acquire natural gas
supplies while reducing exposure to short-term volatile
movements in prices. Although the specific provisions
of the procurement plan will change over time as a
result of ongoing analysis and experience, the following
principles reflect Avista s philosophy of its
procurement plan:
. Avista employs a time-diversified approach to
hedging its loads - It is appropriate to hedge
over a period of time, and Avista establishes
windows within which portions of its future
loads are financially hedged. While this means
that the financial hedges may not be completed
at the lowest possible price, it also protects Avista
and its customers ttom price spikes.
. Avista establishes a disciplined approach to
hedging its loads - In addition to establishing
windows within which hedges are to be
completed, there are also upper and lower pricing
points. In a rising market, this reduces the
companys exposure to extreme price spikes. In a
declining market, this encourages the company to
capture the value associated with the lower price.
. Avista regularly reviews its procurement plan
in light of current market conditions and
opportunities - Avista has a dynamic plan with
ongoing review of the assumptions leading to the
procurement plan. For example, Avista
historically hedged seasonal and annual loads up
to one year out. Avista has been conducting
research with respect to multiple-year contracts
and has recently increased the tenor on a portion
of its hedges beyond one year. Another recent
area of focus has been the percentage of load that
is financially hedged. Over the last several years
Avista hedged approximately 50 percent of its
Avista Utilities2006 Naturai Gas integrated Resource Plan
load. More recently, Avista has modified its
procurement plan to increase that percentage in
an effort to reduce the volatility of its portfolio.
A number of tools are available to the company to
help mitigate its financial risks. Many of these tools are
financial instruments or derivatives that can be utilized
to provide fixed prices or dampen price volatility. Avista
will further evaluate how to manage daily load volatility,
whether through option tools available from
counterparties or through access to additional
storage capacity.
Avista believes it can strengthen the analysis leading
to certain hedges and future modifications to its natural
gas procurement plan. Accordingly, staff will be
evaluating the addition of a planning model called
VectorGas~ during the two-year action period for this
plan.VectorGas~ was developed by New Energy
Associates as an addition to the SENDOUT'" model that
facilitates the ability to model price and load
uncertainty. VectorGas~ will allow Avista to model
various hedging strategies and evaluate their different
impacts on cost and volatility of the overall portfolio.
If Avista elects to purchase VectorGas , the product
would likely be implemented in 2006.
EMERGING SUPPLY ISSUES
The market for natural gas has undergone dramatic
changes over the last several years, as the commodity
market has transitioned from a regionally-based market
to a nationally-based, and perhaps globally-based
market. This transition can be attributed to several
reasons, including:
. Growing national pipeline inttastructure -
Pipeline capacity out of the supply regions has
increased, both in volume and delivery points.
As a result, natural gas prices in the Pacific
Northwest have become more dependent on
demand and prices in regions as far away as the
east coast.
. Increasing correlation among natural gas and
oil prices - The relatively recent run-up in
natural gas prices has in some ways mirrored the
sharp increase in crude oil prices over the last
year. This can be explained by fuel switching
capabilities of some industrial consumers in the
United States and the increased presence of non-
utility energy investors that may simply be
trading BTUs.
. The potential of LNG to be the marginal
source of natural gas in the United States -
I -
Several projections indicate that over the next 10
years there will be a growing gap between North
American natural gas production and North
American demand for natural gas. The consensus
is that LNG will supply the gap. Should this
occur, there will naturally be global price
competition for LNG. Avista has been, and will
continue to be, involved in discussions about
LNG as a potential supply resource.
. Pipeline rate increases - There is more pipeline
capacity from supply sources to markets than is
currently needed in many regions in North
America. This excess capacity has caused capacity
holders with expiring contracts to consider
relinquishing this capacity back to the pipelines.
Avista Utilities 2006 Natural Gas integrated Resource Pian
Many capacity holders have shown a preference
to turn-back transportation contracts where
transportation expenses exceed the value of this
transportation. The result of this action from a
pipeline perspective is to cause affected pipelines
to consider filing rate cases to recover some or all
of the lost revenues. Distribution companies that
rely on firm supplies and transportation will
likely continue to hold their transportation
contracts and may end up paying higher
transportation rates depending on the FERC'
approach to this issue.
. Pipeline constraints - Although there now may
, or will be in the future, excess pipeline
capacity in many parts of the country, the market
or delivery portion of most pipelines remains
heavily contracted. This is due to the fact that
end-users such as LDC's and industrial customers
prefer certainty of supply. Avista and other
consumers in the Pacific Northwest continue to
hold all of the NWP capacity and existing lateral
capacity on NWP and GTN. Of particular
concern to Avista is NWP's Grants Pass Lateral in
Western Oregon. This lateral is fully contracted
demand is continuing to grow in the demand
centers along this lateral, and it is not easily or
inexpensively expanded.
2006 Naturai Gas Integrated Resource Pian Avista Utilities
SECTION 6 - INTEGRATED
NATURAL GAS RESOURCE MODELThis section describes how the company brings
together all the previously discussed components that are
part of the IRP process, the model the company utilizes
for this process, and determines if, over the 20-year
planning horizon, the company is resource deficient.
This section also provides an analysis of potential
resource options and displays the model-selected least
cost resource options to serve resource deficiencies.
The foundation for integrated resource planning is
the demand planning criteria utilized for the
development of demand forecasts. Avista believes that
the appropriate planning standard for peak day demand is
the " coldest day on record" standard utilized by many
other natural gas utilities. Given this approach, A vista
utilizes historic peak and average weather data for each
demand region as a basis for this IRP. It is also important
to note that Avista plans to serve this expected peak for
each demand region utilizing only firm resources. These
firm resources include natural gas supplies, pipeline
transportation and storage resources. It is also important
to note that, in addition to planning for peak
requirements, the company also plans for non-peak
periods such as winter, shoulder and summer demand.
The companys modeling process includes running the
optimization 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. The company does not make
firm commitments to serve interruptible customers.
Therefore, the company IRP analysis of demand serving
capabilities only focuses on the residential, commercial
and firm industrial classes. These three customer classes
are collectively referred to as "core" customers.
Avista supply forecasts are 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 fuel for compressor
stations. The percentage of additional supply that must
be purchased is governed through the FERC and
National Energy Board tariff filings of the pipelines.
RESOURCE PORTFOLIO
The natural gas resource optimization model used by
the company is the SEND OUT'" Gas Planning System
ttom New Energy Associates (NEA), a subsidiary of the
Siemens Westinghouse Power Corp. The SEND OUT'"
model was purchased in April 1992 and has been used
in the preparation of all IRPs since then. The company
has a long-term maintenance agreement with NEA that
allows Avista to receive updates to the software as
enhancements are made. These enhancements
encompass software corrections and improvements, and
enhancements to the software brought on by industry
change.
SENDOUT'" is a PC-based linear programming
model widely used to solve natural gas supply and
transportation optimization questions. Linear program-
ming is a proven technique used to solve
minimization/maximization problems. SEND OUT'"
looks at the complete problem at one time within the
study horizon, taking into account physical limitations
and contractual constraints. The software looks at
thousands of variables and evaluates thousands of
possible solutions in order to generate the least-cost
solution. Among the variables required by the
model are:
. Demand data such as customer count forecasts
and demand coefficients by customer type, e.
residential, commercial, industrial;
. Heating degree-day (HDD) weather information;
. Existing and potential transportation data which
describes to the model the network for the
physical movement of the natural gas and
associated pipeline costs;
. Existing and potential supply options, including
supply basins and prices;
. Natural gas storage options with
injection/withdrawal rates, capacities and
costs; and
. Demand-side management programs.
Avista Utiiities 6 -2006 Natural Gas Integrated Resource Plan
The SEND OUT'" model gives the company a
flexible tool with which to analyze a multitude of
potential scenarios such as:
. Resource mix analysis for demand-side
management programs;
. Analysis of pipeline capacity needs and
capacity releases;
. Analysis of transportation costs; and
. Short-term planning comparisons.
. Effects of different weather patterns upon
demand;
The SEND OUT'" model provides the company with
valuable information used as the framework for
. Effects of natural gas price increases upon
total natural gas costs;
developing numerous studies relating to capacity release
storage optimization, peaking supply needs, DSM
. Storage optimization studies;resource mix, avoided cost calculations, and weather
Figure 6.1 - SENDOUT'" Model Diagram
t,f~~y;!
1~~I1E"'.r-.--K~:~ndl
2006 Natural Gas integrated Resource Plan Avista Utilities
pattern testing and analysis. An example of some of the
information used in the model is illustrated in Figure
, which is the SEND OUT'" Model Diagram. This
diagram illustrates the company s current transportation
and storage assets, flow paths and constraint points.
As discussed previously, the company is evaluating
the addition of the VectorGasm software package from
NEA.VectorGasm is an add-on to the SENDOUT'"
model that facilitates the ability to model price and
demand uncertainty through Monte Carlo simulation
and detailed portfolio optimization techniques that
ultimately produces probability distribution information.
This additional software package may enhance Avista
IRP analytical capabilities, and the evaluation will be
completed before the next IRP process commences.
ANALYSIS FRAMEWORK
The approach used to analyze Avista s long-range
natural gas planning options focuses on the sensitivity of
the optimization model to periodic (daily, monthly,
seasonal and/or annual) changes in:
. Assumptions related to customer growth and
customer natural gas usage that ultimately form
demand forecasts;
. Existing and potential transportation and
storage options;
. Existing and potential natural gas supply
availability and pricing;
. Weather assumptions; and
. Demand-side management and avoided cost.
Avista has reviewed and performed rigorous analysis
on each of the aforementioned areas and provides the
following detail.
DEMAND FORECASTING APPROACH
Avista s demand forecasting approach is described in
Section 2.
Avista forecasts demand in the SEND OUT'" model
in five areas due to the existence of distinct weather and
demand patterns for each area. The areas within
SEND OUT'" are Washington/Idaho (further
disaggregated to two sub-areas due to pipeline flow
limitations), Medford (further disaggregated to two sub-
areas due to pipeline flow limitations), Roseburg,
Klamath Falls and La Grande. In addition to area
distinction, Avista also models demand by customer
class within each of these areas. The relevant customer
classes within the Avista service territory for this IRP
are residential, commercial and firm industrial sales. It is
important to note that not all classes of customers
currently exist or are forecasted to exist in each
demand area.
Figures 6.2 and 6.3 show historic non-weather
normalized average demand for core customers by
region for January 1998 through June 2005.
Figure 6.2 - WAIID Historical Monthly Average Demand
(1/98 - 6/05)
Dth/d
140,000
120,000
100,000
80,000
60,000
40,000
20,000
Nov.Dec.Jan.Feb.March April May Sept.Oct.June July Aug.
Avista Utilities 2006 Natural Gas integrated Resource Plan
Figure 6.3 - Oregon Historical Monthly Average Demand
(1/98'6/05)
Dth/d
::::::
20,000 j
17,500
15,000
12,500
000
::::::::--
500
10,000
500
-:S
Nov.Dec.Jan.Feb.March April May June July Aug.Sept.Oct.
--
Klamath Falls
........ Medford
--- La Grande
--
Roseburg
The company uses its SENDOUT'" model to
forecast customer demand and has calibrated the
with customers' price elasticity, Avista believes it is
possible that the current and future high prices will
demand forecasting component of the SEND OUT'"
model through a meticulous back casting process.
A back cast uses the algorithm developed for forecasting
purposes and applies it to known historical data as a
impact natural gas demand in a lasting fashion.
As stated in Section 2, Avista created nine scenarios
means of testing the validity of that algorithm.
As described in Section 2, and given experience
as a three-by-three matrix using low, medium and high
price scenarios crossed with low, medium and high
customer growth scenarios to better explore demand
forecasts for this IRP.
Figure 6.4 - Average vs. Coldest vs. Warmest (84/85 plus 82 HDD, NOAA) Spokane Weather
(November, October)
HDD
100
121 151 181 211 241 271 301 331 361
Days
Coldest Warmest Avg - NOAA
2006 Naturai Gas integrated Resource Plan Avista Utilities
Figure 6.5 - Average vs. Coldest vs. Warmest (63/64 plus 61 HDD, NOAA) Medford Weather
(November - October)
HDD
121 151
Coldest Warmest
WEATHER ASSUMPTIONS
Avista demand reflects a weather dependent
customer base. Therefore, the study of weather becomes
very important in integrated resource planning. The
figures below show core demand compared to actual
HDDs. The analysis in this IRP is based on the weather
data as published by the National Oceanic Atmospheric
Administration (NOAA). This is a 30-year weather
study spanning 1971-2000. Figures 6.4 and 6.5 show the
NOAA 30-year average weather data in comparison to
the coldest and warmest planning year in history for the
181 331 361
Days
211 241 271 301
Avg - NOAA
Spokane and Medford areas. Measurements of historical
average weather do not represent the range of potential
future weather patterns, including days that may differ
substantially ttom that average pattern.
Figures 6.6 and 6.7 compare the NOAA 30-year
average weather with a company-selected composite of
weather months that form a weather year based on
average heating degree-days with the variability of
actual weather.
On Dec. 30, 1968, the North Operating Division
area experienced the coldest day on record, an 82
Figure 6.6 - NOAA 30-year Average vs. Planning Weather (added 82 HDD on Feb. 15) Spokane Weather
(November, October)
HDD
100
121 151
Average - Acutal Average NOAA
181 271 361
Days
301 331211241
Avista Utilities 2006 Naturai Gas Integrated Resource Plan
Figure 6.7 - NOAA 3D-year Average vs. Planning Weather (added 61 HDD on Feb. 15) Medford Weather
(November - October)
HDD
121 151
Average NOAAAverage - Acutal
heating degree-day for Spokane. This is equal to an
average daily temperature of -17 degrees Fahrenheit.
For the purpose of forecasting, this day is used as the
design-day for cold conditions in the Washington/Idaho
service area. Only one 82 heating degree-day has been
experienced in the last 30-plus years for this area;
however, within that same time period, 80 and 79
heating degree day events occurred on Dec. 29 1968
and Dec. 31 1978, respectively.
On Dec. 9 1972, Medford experienced the coldest
day on record, a 61 heating degree-day. This is equal to
an average daily temperature of 4 degrees Fahrenheit.
181 211 241 271 301 331 361
Days
For the purpose of forecasting, this day is used as the
design-day for cold conditions in Medford. Medford has
experienced only one 61 heating degree-day in the last
30-plus years; however, it has also experienced 59 and
58 heating degree day events in the same time period
on Dec. 8 1972, and Dec. 21, 1990, respectively. The
other three areas in Oregon have similar weather data.
For Klamath Falls, a 72 heating degree-day occurred on
Dec. 21 1990, in La Grande a 74 heating degree-day
occurred on Dec. 23, 1983 , and a 55 heating degree-day
occurred in Roseburg on Dec. 22, 1990. As with
Washington/Idaho and Medford, these days are used as
Figure 6.8 - Existing Firm Transportation & Storage Resource Stack
WNiD
MDthld
400
350
300
250
200
150
100
121 151 181 211 241 271 301 331 361
Day of Year
Avista Utilities2006 Naturai Gas Integrated Resource Pian
Figure 6.9 - Existing Firm Transportation & Storage Resource Stack
Oregon (includes Willamette Firm Peaking Arrangement)
MDthid
120
100
121 151
the design-day for modeling purposes.
The actual HDDs, by area and by day, entered into
SENDOUT'" can be found in Appendix 6.
TRANSPORTATION AND STORAGE
Avista s existing transportation and storage resources
are described in Section 5 (summarized in Table 5.
and are represented by the firm resource duration curves
depicted in Figure 6.8 and 6.9. Avista considers these
firm transportation and storage resources as the starting
point for SEND OUT'" infrastructure. When modeling
future transportation and storage rates, the company
modified existing rates for expected rate increases and
then escalated these rates annually at the Global Insight
331 361181301211241271
Day of Year
inflation rate (summarized in Table 5.2). The expected
rate increases are based on industry discussions regarding
yet-to-be-filed interstate pipeline rate cases.
DEMAND-SIDE MANAGEMENT
As discussed in Section 3, the identification and total
resource characterization of available natural gas
efficiency measures completed using the previously
described methodology allows the construction of a
natural gas DSM supply curve. This supply curve is
simply a graphical depiction of the measures in
ascending order of total resource cost. The horizontal
axis indicates the cumulative resource obtainable at or
below that cost.
Figure 6.10 - Oregon Natural Gas DSM Supply Curve
(Non-site-specific programs)
$/Dth
$160.
$140.
$120.
$100.
$80.
$60.
$40.
$20.
$0.
20,000 40,000 60,000 80,000 140,000 180,000100,000 120,000 160,000
Therm Acquisition
Avista Utilities 2006 Naturai Gas Integrated Resource Pian
Figure 6.11 - Oregon Gas DSM Supply Curve
(Up to $30/Dth, non-site-specific programs)
$/Oth
$40.
$35.
$30.
$25.
$20.
$15.
$10.
$5.
$0.
r--
".J
20,000 40,000 000
Therm Acquisition
Two supply curves are presented for each division
(Figures 6.10 through 6.13). Figures 6.10 and 6.12 focus
only on measures available at levelized sub- TRC cost of
$30 per Dth or less to allow for greater detail of this
range of the supply curve.
SELECTED MEASURES
Based on the methodology described Section 3, the
must take" and indeterminate measures were input into
the SEND OUT'" model. The three key price scenarios
(see Figure 6.16) reviewed for resource planning
purposes are discussed later in this section and are based
on a high natural gas price curve, mid natural gas price
curve and low natural gas price curve. The medium
price scenario is the reasonably expected scenario;
however the availability of the acceptance of DSM
measures under alternative price scenarios is useful
information for incorporation into future DSM business
planning efforts.
Tables 6.1 through 6.4 summarize the acceptance
and rejection of all DSM measures evaluated in the IRP
process. These results have been disaggregated into six
geographic areas. (The two Medford geographic areas
had identical resource decisions and therefore were not
separately reported in Table 6.1 or Table 6.2).
As expected, some DSM measures were accepted in
80,000 100,000 120,000 140,000
some geographic areas and rejected in others. This was
particularly true in the case of Oregon given the
significant climatic differences. These cases were
primarily heating degree-day-dependent measures that
were accepted in cold climates and rejected in warmer
climates. For purposes of developing therm acquisition
goals, measure packages that were cost-effective in 50
percent or more of the Oregon service territory were
accepted into the portfolio on a statewide basis.
Application of this approach requires a program to pass
in Medford to be accepted statewide since that district is
over 50 percent of the total jurisdictional usage and
customer base. Post-IRP program planning efforts will
include an assessment of the ability to cost-effectively
offer those measure packages that passed in less than 50
percent of the Oregon service territory through
geographic, climatic or building type target marketing.
In only one occasion was an individually tested
measure accepted in one Washington/Idaho geographic
area and not in the other. In this case, the difference in
the resource selection was not based on climate, which
was identical for these two areas, but it was instead
attributable to the cost of alternative supply-side
resources.
Avista Utilities2006 Naturai Gas integrated Resource Plan
Figure 6.12 - WAllO Natural Gas OSM Supply Curve
(Non,site,specific programs)
$/Dth
$160.
$140.
$120.
$100.
$80.
$60.
$40.
$20.
$0.
50,000 100,000
THERM ACQUISITION GOALS
Avistas fundamental commitment is toward the
acquisition of cost-effective natural gas-efficiency
resources achievable through utility intervention. The
analysis within this IRP has provided the opportunity
for a comprehensive assessment of efficiency
opportunities in an analysis that integrates supply-side
options as well.
OREGON GOALS
Based on the analysis completed within this IRp, the
company believes that a cost-effective annual acquisition
150,000 250,000 300,000200,000
Therm Acquisition
of 441 000 first-year therms is achievable through utility
intervention. This is a significant increase from historical
actual acquisition levels. In order to incorporate a
reasonable ramp rate into the programs and in
recognition of the timing of this analysis, the company is
proposing a calendar year 2006 acquisition goal that is
the midpoint between the 2004 actual acquisition level
and the IRP identified annual acquisition level. In 2007
and thereafter, the annual acquisition goal would be
regarded as the full annual acquisition level that has been
identified as cost-effective within this IRP. Figure 6.
and Table 6.5 represent the annual goal of298 000
Figure 6.13 - WAllO Natural Gas OSM Supply Curve
(up to $30/Dth, non,site-specific programs)
$/Dth
$40.
$35.
$30.
$25.
$20.
$15.
$10.
$5.
$0.
,----f
50,000 100,000 150,000 250,000 300,000200,000
Therm Acquisition
Avista Utiiities 2006 Natural Gas integrated Resource Plan
Table 6.1 - Oregon Program Preliminary Evaluation Results
Program Roseburg Medford LaGrande Klamath Falls
MFH shell pgm Mandated Mandated Mandated Mandated
SFH shell pgm Mandated Mandated Mandated Mandated
Comm dryer pgm Must Take Must Take Must Take Must Take
Energy Star'" cooking pgm Must Take Must Take Must Take Must Take
Comm kiln pgm Must Take Must Take Must Take Must Take
Non,Res Low-Flow Showerhead pgm Must Take Must Take Must Take Must Take
Non-res pool/spa pgm Must Take Must Take Must Take Must Take
Comm shell pgm Must Take Must Take Must Take Must Take
Comm space heat pgm Must Take Must Take Must Take Must Take
Comm pre-rinse sprayer pgm Must Take Must Take Must Take Must Take
Comm water heat pgm Must Take Must Take Must Take Must Take
Res hot water heating pgm Must Take Must Take Must Take Must Take
Res Low-Flow Showerhead pgm Must Take Must Take Must Take Must Take
MFH boiler pgm Must Take Must Take Must Take Must Take
MFH duct insulation pgm Must Take Must Take Must Take Must Take
MFH space heat pgm Must Take Must Take Must Take Must Take
Res pool/spa pgm Must Take Must Take Must Take Must Take
SFH duct insulation pgm Must Take Must Take Must Take Must Take
SFH space heat pgm Must Take Must Take Must Take Must Take
Res programmable thermostat pgm Must Take Must Take Must Take Must Take
Res tankless water heater pgm Must Take Must Take Must Take Must Take
Res resource efficient washing machine pgm Must Take Must Take Must Take Must Take
SFH space heat pgm SENDOUT'"SENDOUT'"SENDOUT"SENDOUT'"
MFH space heat pgm SENDOUT'"SENDOUT'"SENDOUT'"SENDOUT'"
MFH water heating pgm SENDOUT'"SENDOUT'"SENDOUT'"SENDOUT'"
Energy Star'" residential package SENDOUT'"SENDOUT'"SENDOUT"SENDOUT'"
Crematory pgm SENDOUT'"SENDOUT'"SENDOUT'"SENDOUT'"
Res pool/spa pgm SENDOUT'"SENDOUT'"SENDOUT"SENDOUT'"
Res passive solar water heating pgm SENDOUT'"SENDOUT'"SENDOUT'"SENDOUT'"
Comm prescriptive cooking pgm SENDOUT'"SENDOUT'"SENDOUT"SENDOUT'"
Comm cooking pgm Screened Out Screened Out Screened Out Screened Out
Comm dryer pgm Screened Out Screened Out Screened Out Screened Out
Comm kiln pgm Screened Out Screened Out Screened Out Screened Out
Non,Res pool/spa pgm Screened Out Screened Out Screened Out Screened Out
Non-Res passive solar water heating pgm Screened Out Screened Out Screened Out Screened Out
Comm washing machine pgm Screened Out Screened Out Screened Out Screened Out
Non-Res window pgm Screened Out Screened Out Screened Out Screened Out
Res water heating pgm Screened Out Screened Out Screened Out Screened Out
Res door pgm Screened Out Screened Out Screened Out Screened Out
MFH water heating pgm Screened Out Screened Out Screened Out Screened Out
MFH window pgm Screened Out Screened Out Screened Out Screened Out
Res pool/spa pgm Screened Out Screened Out Screened Out Screened Out
SFH water heating pgm Screened Out Screened Out Screened Out Screened Out
SFH window pgm Screened Out Screened Out Screened Out Screened Out
first-year therms in calendar year 2006 and 441 000
therms in 2007 in relation to the 155 000 therms
actually acquired in 2004.
The IRP-identified cost-effective market segments
and the estimated acquirable first-year therm acquisition
are represented in Table 6.
A more detailed identification of measures, including
a breakout of the mandated and "must take
categorizations, are included in Appendix 3.
WASHINGTON/IDAHO GOALS
The current 240 000 annual therm acquisition goal
specified in the companys Schedule 190 filing was
originally developed in late 2000 based on historical
experience in natural gas DSM. The 2001 energy crisis
and subsequent increases in retail natural gas rates
occurred shortly after these tariffs were approved and
very quickly changed the natural gas-efficiency
environment. In the last four years of gas DSM program
6 -Avista Utiiities2006 Naturai Gas Integrated Resource Pian
Table 6.2 - Results of Oregon SENDOUT'"Tested Programs
Program
SFH space heat pgm
MFH space heat pgm
MFH water heating pgm
Energy Star" residential package
Crematory pgm
Res pool/spa pgm
Res passive solar water heating pgm
Comm prescriptive cooking pgm
Program
SFH space heat pgm
MFH space heat pgm
MFH water heating pgm
Energy Star" residential package
Crematory pgm
Res pool/spa pgm
Res passive solar water heating pgm
Comm prescriptive cooking pgm
Program
SFH space heat pgm
MFH space heat pgm
MFH water heating pgm
Energy Star" residential package
Crematory pgm
Res pool/spa pgm
Res passive solar water heating pgm
Comm prescriptive cooking pgm
SENDOUT"-tested (high price scenarios)Roseburg MedfordPass PassFail PassPass PassFail FailPass PassFail FailFail FailFail Fail
SENDOUT"-tested (mid price scenarios)Roseburg MedfordFail PassFail FailFail FailFail FailFail FailFail FailFail FailFail Fail
SENDOUT"-tested (low price scenarios)Roseburg MedfordFail PassFail FailFail FailFail FailFail FailFail FailFail FailFail Fail
Note: Similar measures may be spl~ into multiple programs to create consistent cost-effectiveness characteristics,
Mandated' = Programs legislatively mandated w~hin Oregon
Must Take" = Programs with sufficient cost-effectiveness to be passed in preliminary evaluatiOl1 process,
SENDOU1"" = Programs with indeterminate cost-effectiveness to be indMdually tested in SENOOU1",
Rejected" = Programs w~h cost-effectiveness so low as to be rejected in the pre1iminary evaluation,
Pass" = Those programs indMduaJly tested in SENOOU1" that passed,
Fail" = Those programs individuaJly tested in SENOOlJ1"that failed,
LaGrande
Pass
Pass
Pass
Pass
Pass
Pass
Fail
Fail
LaGrande
Pass
Pass
Fail
Fail
Fail
Fail
Fail
Fail
LaGrande
Fail
Fail
Fail
Fail
Fail
Fail
Fail
Fail
Klamath Falls
Pass
Pass
Pass
Pass
Pass
Pass
Fail
Fail
Klamath Falls
Pass
Pass
Fail
Pass
Fail
Fail
Fail
Fail
Klamath Falls
Fail
Fail
Fail
Fail
Fail
Fail
Fail
Fail
activity (2002 through 2005, excluding the aberrant
2001 energy crisis period), Avista has averaged over
800 000 first-year therm savings per year. The market
has clearly changed for natural gas-efficiency.
Recent events within the market do create a
significant degree of uncertainty in forecasting
achievable results. The company has on several
occasions indicated that it is difficult to determine if the
extraordinary level of acquisition that has been
experienced since 2001 is sustainable. At this point
given five years of sustained acquisition, the assumptions
made within this IRP are that the recent history is
representative of what is obtainable in the future.
This conclusion will lead to a considerable increase in
estimates of acquirable DSM resources.
Based on the measures that were designated as "must
take" and the addition of measure packages that were
individually tested within SEND OUT"', a total
estimated therm acquisition level of 1 062 000 first-year
therms has been identified. Table 6.7 summarizes
these measures.
NATURAL GAS SUPPLY AVAILABILITY AND PRICING
The company attempts to balance the need for both
low cost and low volatility with high reliability in its
natural gas procurement efforts. Section 5 contains a
Avista Utiiities 6 -2006 Natural Gas Integrated Resource Plan
Table 3 - WAIID Preliminary Evaluation Results
Program
Res pool/spa pgm
SFH space heating pgm
Res programmable thermostat pgm
Res programmable thermostat pgm
Carom dryer pgm
Carom Energy Star" cooking pgm
Carom kiln pgm
Carom low-flow showerhead pgm
Carom pool/spa pgm
Carom shell pgm
Carom space heat pgm
Carom pre-rinse sprayer pgm
Res hot water heating pgm
MFH boiler pgm
MFH duct pgm
MFH shell pgm
MFH windows pgm
SFH duct pgm
SFH shell pgm
SFH windows pgm
Carom water heating pgm
MFH furnace pgm
MFH space heating pgm
Res low-flow showerhead pgm
MFH hot water heating pgm
Res pool/spa pgm
Res tankless water heater pgm
Res resource-efficient washing machine pgm
Crematory pgm
Carom prescriptive cooking pgm
Res hot water heating pgm
Res door pgm
Res Energy Star" Package pgm
MFH hot water heating pgm
MFH pipe insulation pgm
Res pool/spa pgm
SFH hot water heating pgm
SFH space heating pgm
SFH pipe insulation pgm
Res passive solar water heating pgm
Carom cooking pgm
Carom dryer pgm
Carom kiln pgm
Carom pool/spa pgm
Carom passive solar water heating pgm
Carom washing machine pgm
Carom window pgm
Spokane
Must Take
Must Take
Must Take
Must Take
Must Take
Must Take
Must Take
Must Take
Must Take
Must Take
Must Take
Must Take
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
SNWP
Must Take
Must Take
Must Take
Must Take
Must Take
Must Take
Must Take
Must Take
Must Take
Must Take
Must Take
Must Take
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
SENDOUT'"
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
Screened Out
description of supply options available to the company.
Regional and national natural gas prices have
recently risen to unprecedented levels. The industry in
general and price forecasting organizations in particular
did not forecast these unprecedented increases. Oil price
increases and a correlation between natural gas and the
price relationship with natural gas, demand growth
stagnating u.S. supply growth, natural gas use for
electric generation, hurricane activity and other weather
events are believed to be some of the reasons for these
price increases. Given that these increases were not
predicted and that these price levels have not been
witnessed before on a sustained basis, it is very difficult
to determine the length of the price run-up, as well as
6 -Avista Utilities2006 Naturai Gas Integrated Resource Plan
Table 6.4 - Results of WAllO SENOOUT"'- Tested Programs
SENDOUT"-tested (high price scenarios)Program Spokane SNWP
Res hot water heating pgm Pass PassMFH boiler pgm Pass PassMFH duct pgm Pass Pass
MFH shell pgm Pass Pass
MFH windows pgm Pass PassSFH duct pgm Pass Pass
SFH shell pgm Pass PassSFH windows pgm Pass Pass
Comm water heating pgm Pass PassMFH furnace pgm Pass Pass
MFH space heating pgm Pass Pass
Res low-flow showerhead pgm Pass Pass
MFH hot water heating pgm Pass PassRes pool/spa pgm Pass Pass
Res tankless water heater pgm Pass Pass
Res resource-efficient washing machine pgm Pass PassCrematory pgm Pass Pass
Comm prescriptive cooking pgm Pass Pass
SENDOUT"-tested (mid price scenarios)Program Spokane SNWP
Res hot water heating pgm Pass PassMFH boiler pgm Pass PassMFH duct pgm Pass PassMFH shell pgm Pass PassMFH windows pgm Pass PassSFH duct pgm Pass Pass
SFH shell pgm Pass PassSFH windows pgm Pass Pass
Comm water heating pgm Pass Pass
MFH furnace pgm Pass PassMFH space heating pgm Fail Pass
Res low-flow showerhead pgm Pass Pass
MFH hot water heating pgm Pass PassRes pool/spa pgm Fail Fail
Res tankless water heater pgm Fail Fail
Res resource-efficient washing machine pgm Pass Pass
Crematory pgm Pass Pass
Comm prescriptive cooking pgm Fail Fail
I -
the expected impact on customer loads. Although the
company does not believe that it can accurately predict
future prices for the 20-year horizon of this IRp, it has
reviewed a variety of price forecasts provided by
least possible. Therefore, Avista, with the assistance and
concurrence of the TAC Committee, selected a high
medium and low price curve as the best way to consider
credible sources.
A number of these price forecasts are
possible outcomes and the impact that this volatile and
high pricing environment might have on planning.
provided in the Figure 6.15.
As Figure 6.15 shows, there are many price
Table 6.5 - Oregon 1 st-year Therm Acquisition
by Customer Segment
forecasts with a large variation in overall price
levels. Although some of these forecasts are
more plausible than others, most of them are at
Year
2004 actual acquisition
2006 acquisition goal
2007 acquisition goal
Residential
140,000
249 000
358,000
Non-Residential
000
49,000
83,000
Total
155 000
298,000
441 000
Avista Utilities 2006 Natural Gas integrated Resource Plan 6 -
Table 6.4 continued - Results of WAllO SENOOU'f0-Tested Programs
SENDOUT"-tested (low price scenarios)Program Spokane SNWP
Res hot water heating pgm Fail FailMFH boiler pgm Pass PassMFH duct pgm Pass PassMFH shell pgm Pass PassMFH windows pgm Pass PassSFH duct pgm Pass PassSFH shell pgm Fail FailSFH windows pgm Fail Fail
Comm water heating pgm Pass PassMFH furnace pgm Pass Pass
MFH space heating pgm Fail Pass
Res low-flow showerhead pgm Fail Fail
MFH hot water heating pgm Fail FailRes pool/spa pgm Fail FailRes tankless water heater pgm Fail Fail
Res resource-efficient washing machine pgm Fail FailCrematory pgm Fail FailComm prescriptive cooking pgm Fail Fail
Note: S;milar measures may be spl~ into multiple programs to create consistent cost-effectiveness charactenstics,
Mandated" = Programs legislatively mandated within OregOl1
Must Take" = Programs wilh sufficient cost-effectiveness to be passed in prelimin8l)l evaluation process,
SENDOUro' = Programs with indeterminate cost-effectiveness to be indMdually tested in SENOOUro,
Rejected' = Programs with cost-effectiveness so low as to be rejected in the prelimin8l)l evatuation,
Pass' = Those programs indMdually tested in SENOOUro that passed,
Fail' = Those programs individuaJly tested in SENDOlfTO that faJled,
Table 6.6 - Oregon Programs Accepted within the IRP Analysis
Multifamily home shell measures
Single-family home shell measures
Residential domestic hot water
Residential low-flow showerheads
Residential tankless water heaters
Horizontal-axis washing machines
Multifamily home high-efficiency boilers
Residential pool and spa measures
Single-family home duct measures
Single-family home HVAC measures
Residential programmable thermostats
Multifamily home duct measures
Multifamily home HVAC measures
Commercial dryers
Commercial Energy Star" cooking measures
Kiln
Non-residential low-flow showerheads
Non-residential pre-rinse sprayers
Non-residential water heating measures
Non-residential pool measures
Non-residential shell measures
Non-residential space heat measures
Single-Family Home HVAC program
Total identified cost-effective measures
(Components may not sum due to rounding to nearest 100 therms)
800
000
8,400
700
200
300
600
10,400
100
180,000
700
100
600
600
100
100
300
200
600
5,400
700
441 100
1 st year therms
1 st year therms
1 st year therms
1st year therms
1 st year therms
1 st year therms
1 st year therms
1st year therms
1 st year therms
1 st year therms
1 st year therms
1 st year therms
1 st year therms
1 st year therms
1 st year therms
1 st year therms
1 st year therms
1 st year therms
1 st year therms
1st year therms
1 st year therms
1 st year therms
1 st year therms
1st year therms
I .
Avista Utilities2006 Natural Gas Integrated Resource Plan
These curves are shown in Figure 6.16.
Each of the forecasts illustrated in Figure 6.16 are at
the Henry Hub. The Henry Hub is found in Louisiana
just onshore from the Gulf of Mexico. It is the physical
location that is widely recognized as the most important
pricing point in the United States because of the sheer
volume traded both on a daily or spot basis, as well as a
forward basis and the proximity to a large portion of
United States production. All other producing and
market area-pricing points tend to be set off of the
Henry Hub as it is the New York Mercantile Exchange
(NYMEX) trading hub for futures contracts. Although
the Henry Hub is certainly relevant to pricing natural
gas in the United States and the Pacific Northwest, the
physical supply points closer to Avistas service territory
are Sumas, Wash., AECO Alberta, Canada, and the u.s.
Rockies. Pricing of these points is set or based upon
Henry Hub, although they typically trade at a significant
Figure 6.14 - Annual Oregon Acquisition Goals
Therms
500,000
450,000
400,000
350,000
300,000
250,000
200,000
150 000
100,000
50,000
2004 Actual 2006 Goal 2007 Goal
Res
. Non-Res
Table 6.7 - WAllO Programs Accepted within the lAP Analysis
Residential pool/spa measures
Single,family home HVAC measures
Residential thermostat measures
Non-residential clothes dryers
Non-residential cooking measures
Kiln
Non-residential low-flow showerheads
Non-residential pre-rinse sprayers
Non-residential pool measures
Non-residential shell measures
Non-residential space heat measures
Non-residential site-specific program
Residential domestic hot water measures
Residential low-flow showerhead measures
Multifamily boiler measures
Multifamily domestic how water measures
Multifamily home duct measures
Multifamily furnace measures
Multifamily HVAC measures
Multifamily shell measures
Multifamily window measures
Single-family home duct program
Single-family home shell program
Single-family home window measures
Horizontal-axis washing machine program
Non-residential water heat program
Crematoria program
Total identified cost-effective measures
000
000
000
000
000
000
16,000
000
000
000
469,000
13,000
000
000
000
000
000
000
000
234 000
000
26,000
20,000
000
062,000
(Components may not sum due to rounding to nearest 1 ,000 therms)
1 st year therms
1 st year therms
1st year therms
1 st year therms
1 st year therms
1st year therms
1 st year therms
1 st year therms
1 st year therms
1 st year therms
1 st year therms
1 st year therms
1st year therms
1 st year therms
1st year therms
1 st year therms
1 st year therms
1st year therrns
1 st year therms
1 st year therms
1 st year therms
1st year therms
1 st year therms
1st year therms
1 st year therms
1 st year therms
1 st year therms
1st year therms
Avista Utiiities 6 -2006 Naturai Gas integrated Resource Pian
13.
12.
11.
10.
Figure 6.15 - Henry Hub Forward Price Forecasts
2005$/Dth
- - - - - - -- - - - - - - - - - - - - - -, - - - - - - - ---
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
uuu 7/1/05 Forwards -+- Consultant 2 - - - NPCC - High
-+- 10/31/05 Forwards --- CEC EIA AEO '
-b- Consultant 1 NPCC - Med NPCC - Low
discount. This discount is commonly referred to as the
basis differential. Some of the reasons for the basis
differential are a more favorable supply/demand balance
in the West, better physical proximity to these supplies
pricing points, Avista needed to estimate the basis
differential between Henry Hub and the pricing points
on which the company relies. As discussed at the TAC
meetings, the company believes that an average of the
most recent differentials is an appropriate approach to
estimate basis differentials. This is because the company
and distance ttom the very large demand centers in the
eastern United States.
Since most price forecasters do not forecast regional
13.
12.
11.
10.
believes that recent history better represents the current
Figure 6.16 - Henry Hub Forward Prices for Avista 20061RP
2005$/Dth
- -----A
...
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
--- High Price --- Low Price -A- Medium Price
6 -Avista Utiiities2006 Natural Gas Integrated Resource Plan
structure of the natural gas market. This structure may
change in the future, particularly out of the u.s.
Rockies producing region; however, at this point in
time, it is the best predictor of what future differentials
may look like. Therefore, Avista has adopted Table 6.
showing the percentage of Henry Hub, for AECO,
Sumas and the Rockies pricing points. Avista calculated
these percentages by comparing the actual monthly
index prices ttom November 2003 through October
2005. The beginning date for this comparison was
chosen because there were a number of pipeline
expansions that went into service in 2003 , and Avista felt
it appropriate to select a date, beginning with the winter
heating season, after those potentially basis altering
expansions went into service.
Each of the price forecasts provides annual (not
monthly) prices by year. For modeling purposes, given
Avistas heavily winter-weighted demand profile, it is
more accurate for the company to break these annual
figures down to monthly figures. As discussed with the
TAC, Avista believes that utilizing available forward
price differentials, by month, is an appropriate way to
compute monthly prices. Table 6.9 depicts the monthly
shape that the company is applying to the annual prices
in the price curves. Avista calculated these percentages
by taking the average of the monthly forward prices
available on July 1 2005. The reason the company
chose July 1 is that the company felt it appropriate to
attempt to avoid the potentially skewed forward prices
in the aftermath of the 2005 hurricane activity and
associated price run-up.
Appendix 6.1 displays the detailed monthly price
data as calculated by the company when the Henry Hub
price forecasts are incorporated with the basis
and seasonal factor adjustments
discussed above.
Table 6.8 - Basis Differential Assumptions
Pricing Point
Percentage
AECO
85.
Sumas
86.4%
Rockies
85.
markets and the uncertainty of the sustainability of the
prices, as well as the customer impact, the company has
created nine scenarios to better look at the range of
possible outcomes over the planning horizon. These
nine scenarios were developed by crossing the high
medium and low price curves depicted in Figure 6.
with the high, medium and low customer growth
scenarios discussed in Section 2 (Figure 2.1).
This effort produced the three-by-three matrix
shown in Table 6.10.
The top row of the matrix incorporates the high
medium and low price curves. For each of these cases in
this row, the heat coefficient was adjusted annually based
upon the comparison of each of the price curves
selected by the company. The calculation of these
coefficients is discussed in Section 2 and can be seen in
Appendix 2.3. For the middle row of the matrix, the
coefficients remain the same as the top row of the
matrix but the customer growth rates were adjusted by
decreasing the customer growth rate by 50 percent.
For the bottom row of the matrix, the coefficients
remain the same as the top row of the matrix but the
customer growth rates were adjusted by increasing the
customer growth rate by 50 percent. The customer
growth rate figures are further discussed in Section 2
and can be seen in Figure 2.1 and Appendix 2.
Therefore, Case #6 has the lowest demand because it
has the highest price and associated demand coefficients
Table 6.9 - Monthly Pricing Allocation
January February March April May June
DEMAND FORECASTS AND SENSITIVITIES 111%111%109%96%94%95%
As discussed in Section 2, given the July August September October November December
unprecedented price spikes in the natural gas 95%96%95%96%100%104%
Avista Utiiities 6 -2006 Naturai Gas Integrated Resource Plan
Table 6.10- Demand Scenarios
Case #1 - Low natural gas price
adjustment - elasticity (-15)
Case #2 - Medium natural gas
price adjustment - elasticity (-15)
Case #3 - High natural gas price
adjustment - elasticity (-15)
Case #4 - Case #1 with a reduction of
customer growth by 50%
Case #5 - Case #2 with a reduction of
customer growth by 50%
Case #6 - Case #3 with a reduction of
customer growth by 50%
Case #7 - Case #1 with an increase of
customer growth by 50%
Case #8 - Case #2 with an increase of
customer growth by 50%
and the lowest customer growth rates. Case #7 has the
highest demand because it has the lowest price and
associated demand coefficients and the highest customer
growth rates. All other cases fall in between these
bookends.
PRELIMINARY RESULTS
Avista generated results ttom SEND OUT'" utilizing
these nine cases and existing transportation and storage
resources. The purpose of this initial exercise is to first
determine if Avista has sufficient resources to meet peak
day requirements in all scenarios. The second purpose
of this exercise is to determine, in scenarios where the
company has insufficient resources, as well as where
when and how much of a deficiency exists.
From an analytical standpoint, after creating and
running each scenario, the company then honed the
group down to three main cases to review in more
detail. These cases are the highest customer growth and
demand level case (#7), the lowest customer growth and
demand level case (#6), and the middle demand and
customer growth case (#2). Case #2 is known as the
Expected Case, Case # 6 is known as the Low Demand
Case and Case #7 is known as the High Demand Case.
The demand results of these cases are further discussed
in Section 2 and additional details of these cases can be
seen in Appendix 2.4. The company believes that these
cases best explore the realm of reasonable possible
outcomes while at the same time minimizing the
number of cases the company analyzes all the way
Case #9 - Case #3 with an increase of
customer growth by 50%
through the conclusion of this IRP process.
Figures 6.17 and 6.18 graphically represent a
regional summary of Expected Case peak day demand
compared to existing resources. This comparison shows
on a regional bases, when and how much the company
is deficient over the planning horizon. Similar figures for
the Low and High Demand cases can be found in
Appendix 6.
It is important to note that this summarized or
rolled-up approach can "mask" regional deficiencies.
Therefore, the company prepared Table 6.11 to provide
more detail. Table 6.11 identifies when the company
first becomes resource constrained and the amount
that deficiency by demand region on that region
design day. This table further shows the growth in
deficiencies over time. Similar figures for the Low and
High Demand cases can be found in Appendix 6.
Each case depicts at least one deficiency in at least
one demand area sometime during the planning
horizon. Given that the company does not anticipate
resource shortages until at least the 200812009 heating
season in the most robust case, and given that the mid
case is not deficient until the 201012011 heating season
Avista is afforded sufficient time to carefully monitor
plan and take action on potential resource additions.
That being said, for purposes of the IRP process, the
company attempted to identify all reasonable resource
options given current information and placed these
options in the SEND OUT'" model in order to allow the
model to pick the least cost incremental resources.
6 ,Avista Utiiities2006 Naturai Gas Integrated Resource Plan
Figure 6.17 - WA/ID Existing Resources vs. Peak Day Demand
(Net of DSM Savings) Expected Case - November to October
Dth/d
500,000
450,000
200,000
150,000
~-------e
-------!------------
400,000
350,000
300,000
250,000
100,000
50,000
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Existing GTN
Existing TF-
Existing TF-
Existing Plymouth
WAIID Peak Day Demand
NEW RESOURCE OPTIONS CONSIDERATIONS
When researching options, the company determined
that the following considerations are important when
Resource Cost
evaluating the appropriateness of potential resources.
The company strives for the least-cost resource
portfolio, so resource cost is the primary consideration
, .
when evaluating resource options. It is important to
note that the other considerations mentioned below
Figure 6.18 - Oregon Existing Resources vs. Peak Day Demand
(Net of DSM Savings) Expected Case - November to October
Dthld
200,000
40,000
20,000
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
---
180,000
160,000
140,000
120,000
100,000
80,000
60,000
Malin Supply
Existing GTN
Existing TF-
Existing TF-
II Existing Will. Peaking
Existing Plymouth
--0- Oregon Peak Day Demand
Avista Utiiities 2006 Naturai Gas Integrated Resource Pian 6 -
influence resource decisions. Avista has found that it is the larger the total facility constructed is.
often true that newly constructed resources are more
expensive than existing resources, but existing resources Peak Versus Base Load
As previously stated, Avista s planning efforts includeare in shorter supply. Newly constructed resources
provided by a third party such as a pipeline may require
a significant commitment for contract length. The
company believes that newly constructed resources by a
third party are often less expensive per unit cost given
the ability to serve a design or peak day as well as all
other demand periods. The company s core loads are
considerably higher in the winter than the summer.
Due to the winter-peaking nature of Avistas demand
Table 6.11 - Peak Day Demand - Served and Unserved (MOth/d)
Before Resource Additions & Net of DSM Savings
La Grande La Grande La Grande WAiID WAiID WAiID
Case Gas Year Served Unserved Total Served Unserved Total
2006-2007 274.274.
2007-2008 295.295.
2008-2009 310.310.
2009-2010 326,326.
2010-2011 341.341.
2011-2012 354.354.
2012-2013 10.10.357.366.
2013-2014 10.10.373.377 .
2014-2015 10.10.43 373.14.387.
2015-2016 10.10.386.11.398.
2016-2017 10.0.49 10.387.19.407.
2017-2018 10.10.386.46 27.414.
2018-2019 10.11.385.37.422.49
2019-2020 10.11.384.46.430.
2020-2021 10.11.383.54.438.
2021,2022 10.11.47 382.62.445.
2022-2023 10.11.382.70.453.
2023-2024 10.11.382.77.55 460.
2024-2025 10.11.382.85.468.
2025-2026 10.11.382.85.468.
Medford Medford Medford
Klamath Falls Klamath Falls Klamath Falls Roseburg Roseburg Roseburg
Case Gas Year Served Unserved Total Served Unserved Total
2006-2007 12.12.73.73.
2007-2008 13.13.79.79.
2008-2009 14.14.83.43 83.43
2009,2010 14.77 14.77 88.88.
2010-2011 15.15.87.91.
2011-2012 15.15.87.95.
2012-2013 15.15.87.11.98.
2013-2014 15.16.87.14.101.
2014-2015 15.1.45 16.48 87.17.47 104.
2015-2016 15.16.87.21.108.
2016-2017 15.17.87.24.111.
2017-2018 15.17.49 87.27.114.41
2018-2019 15.17.87.30.117.
2019,2020 15.18.87.33.121.
2020-2021 15.18.87.37.124.49
2021-2022 15.18.87.40.127.
2022-2023 15.19.87.44.131.
2023-2024 15.19.87.47.40 134.
2024-2025 15.20.87.50.138.
2025-2026 15.20.87.54.142.
6 - 20 2006 Naturai Gas Integrated Resource Plan Avista Utiiities
resources that cost-effectively serve the winter without
an associated summer commitment may be preferable.
It is important to remember that 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.
Lead- Time Requirements
New resource options can take anywhere from a
year to more than four years to put in service. Open
season processes, planning and permitting, environmental
review, design, construction and testing are just some of
the many aspects that contribute to lead-time
requirements associated with new physical facilities.
Recalls of storage or transportation release capacity
typically require advance notice of up to two years.
Even DSM programs require a significant amount of
time from program rollout to the point in time at which
natural gas savings are realized.
Resource Usefulness
It is paramount that an available resource effectively
delivers natural gas to the intended geographical region.
Given Avista s unique service territories, it is often
impossible to deliver resources ttom a resource option
such as storage without acquiring additional pipeline
transportation to deliver storage volumes.
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, the
fact that lower unit costs are available with larger
expansions, and the economics of expansion of existing
pipelines or the construction of new resources dictate
additions only every few years. This lumpiness does
provide a cushion for future growth. Given the
economies of scale for pipeline construction costs, the
company is afforded the opportunity to assure that
resources are in place for future increases in demand.
OPTIONS REVIEWED
The following narrative summarizes the company
research and analysis on a number of demand serving
options. Actual supply-side resources placed into the
SEND OUT'" model are detailed in Appendix 6.4.
Demand-Side Management
As part of the IRP process, a comprehensive
assessment was made of potentially cost-effective
demand-side management opportunities. This
assessment resulted in the conclusion that there
significant additional resource potential beyond Oregon
historical acquisitions and the goals specified in the
tariffs governing the Washington and Idaho natural gas
DSM programs. The SEND OUT'" model, through the
evaluation of all the measures described in Section 3
selects the lowest cost resource, whether that resource is
a supply- or demand-side resource. In instances where
cost-effective DSM resources are available, these
resources will be selected before more expensive
supply-side resources.
Avista System Enhancements
In certain instances, through a modification or
upgrade of Avista s facilities, the company can facilitate
additional peak and base load-serving capabilities.
These opportunities are geographically specific and
require case-by-case study. Avista has begun preliminary
review of several of these enhancements and although
this review hasn t been finalized, preliminary findings
indicate that the following opportunities may
be beneficial.
. NWP Klamath Falls Lateral - Avista has the
opportunity to purchase and operate the NWP
Klamath Falls lateral as a high-pressure
distribution system. While incurring the capital
cost associated with the purchase price, Avista
Avista Utilities 6 - 212006 Natural Gas Integrated Resource Plan
will be able to avoid current NWP transportation
charges at Klamath Falls and relocate the
transportation contract deliverability on NWP to
areas where additional deliverability is needed.
This solution would also facilitate additional
deliveries into the Klamath Falls area off of
GTN. The potential transaction is subject to a
number of terms and conditions that have not yet
been satisfied.
. Medford System Enhancement - Avista may be
able to construct a high-pressure distribution
reinforcement from the GTN system off of the
Medford lateral to deliver additional quantities of
natural gas off of GTN to Medford. This
solution would also allow existing supply and
capacity to be diverted from Medford on the
NWP Grants Pass Lateral to the Roseburg area.
Through this enhancement, potential resource
shortages in the Medford and Roseburg areas can
be addressed. The company is likely to proceed
with the change, whether needed for demand-
serving purposes or not, due to the recently
enacted Office of Pipeline Safety Integrity
Management rules. Avista is required by these
rules to assess and manage potential risks of
transmission pipeline rupture in areas of high
consequence; i.e. areas of dense population or
gathering places with regular use. The above
option currently appears to be the companys best
option in dealing with Medford-area high
consequence area Issues.
. La Grande Distribution System Enhancement
- Avista has the option to enhance the
distribution system in the La Grande area with
high-pressure distribution looping ttom an
adjacent city-gate station such that the
distribution system would be reinforced.
This solution would allow additional deliveries
off of the NWP system to La Grande.
Utilization of Backhauls
On the GTN system, due to the north-to-south
flow dynamics and the large amount of natural gas
flowing that direction, backhauling supply purchases to
Avistas service territory can be done on a firm basis.
For example, Avista can purchase cost-effective supplies
at Malin, Ore., and transport those supplies to Avista
service territory at either Klamath Falls or Medford.
Malin-based natural gas supplies typically price at a small
premium to AECO, Rockies and Sumas supplies and are
generally less expensive than the cost of both
transporting those traditional supplies and paying the
associated reservation charges. The GTN system is a
mileage-based system, and therefore Avista only pays a
ttaction of the forward rate if it is transporting supplies
ttom Malin to Medford and Klamath Falls. The GTN
system is approximately 612 miles long and the distance
ttom Malin to the Medford lateral is only about 12
miles. Thus, Avista can decrease costs by avoiding
paying full reservation charges on an annual or seasonal
basis and/or by avoiding potentially expensive
peaking resources.
Storage
Storage allows the company to deliver natural gas
supply when needed most. Storage provides many
advantages when storage deliveries can be made to
Avistas city-gate points. Storage also allows the company
to take advantage of summer/winter pricing
differentials, as well as provide the company with
arbitrage opportunities within individual months.
The latter advantages do not offer peak load serving
capabilities although they certainly allow the company
to offset natural gas supply expenses with these
revenues. Although storage can be a valuable resource
without deliverability to Avista s service territory, storage
cannot be considered a firm peak serving resource.
Storage resources are limited in the Pacific
Northwest; however, there are a number of options
available to the company.
Avista Utiiities2006 Natural Gas integrated Resource Plan
existing services and expansion opportunities.
For Washington and Idaho customers, the
Avista currently holds LNG needle peaking
capacity contracts with NWP for both
Washington/Idaho customers as well as Oregon
. Jackson Prairie - As discussed in Section 5
Jackson Prairie is a tremendous resource for both
company has provided notice of its intent to
recall storage capacity and associated NWP
customers. Although this is a valuable peaking
resource, it is fairly costly per unit delivered.
transportation capacity ttom Cascade Natural Gas
Company. The company will retake possession of
this capacity on April 30 2007.
This recall will further facilitate peak and
Furthermore, this resource is fully contracted and
not available for contracting at this time. Given
this situation, this option is not being modeled
within SENDOUT'" for this IRP.
winter deliveries at no cost for the storage and
very little cost for the transportation in addition
Due to the fact that many of the current
capacity holders are on one-year rolling
to providing ratepayers with the opportunity to
capture current arbitrage opportunities that far
evergreen contracts, it is possible that this option
will again become viable in the future. In order
the future expansion capacity discussed in Section
5 do not include transportation and therefore
for this option to become a preferred resource
transportation to and from Plymouth will need
to be acquired.
. Other Storage - Other regional storage
facilities exist and may be cost-effective.
Northwest Natural's Mist facility in Northwest
exceed the release revenues that Avista is
currently receiving ttom Cascade.
The remaining storage release to Terasen and
cannot directly serve system demand. However
the company will continue to look for swap and
Oregon, Alberta area storage, Questar s Clay
Basin facility in Northeast Utah and Northern
transportation release opportunities to fully
utilize these additional resources. Even without
California storage are all possibilities. Again
transportation to and from these facilities to
Avista s service territory continues to be thedeliverability, it may make financial sense in the
future for the company to fully develop/recall
Jackson Prairie capacity to optimize time spreads
within the natural gas market.
largest impediment to contracting for these
options. Currently the most attractive non-
For Oregon customers, transportation from
Jackson Prairie and rate base issues continue to
be the main reasons that more storage is not
Jackson Prairie resource that the company
reviewed is storage potential in Northern
California. This concept needs to be further
analyzed, although it appears that through
available for peak and winter load requirements.
It may be possible that some of the Jackson
Prairie expansion capacity could be allocated to
backhaul transportation, deliveries could be made
to some of the Washington/Idaho and Oregon
Oregon in the future, and the company will
continue to assess that opportunity. Further
customers. Storage capacity is currently available
in Northern California, as well as transport
through the acquisition of cost effective pipeline
capacity to the various Oregon demand centers
capacity to and from these locations.
Unfortunately, current sellers of storage
Oregon customers may have the ability to benefit
from storage resources for peak needs.
capacity in Northern California are not offering
multi-year contracts or contracts with beginning
. Plymouth LNG - As mentioned previously,
dates during the timeframes that the company
may need these incremental resources.
Avista Utilities 2006 Naturai Gas integrated Resource Plan
Company-Owned Liquefied Natural Gas Storage
LNG facilities could be constructed within the
companys service area. By locating within the Avista
service area and not on the interstate pipelines, Avista
could avoid annual pipeline charges. Such construction
would be dependent on regulatory and environmental
approval, as well as cost effectiveness requirements.
Preliminary estimates of the construction
environmental, right of way, legal, operating and
maintenance, and inventory costs for a needle-peaking
resource indicate that company-owned LNG facilities
do not appear to be cost effective. Although the
company is not modeling this option at this time, Avista
will continue to seek cost effective opportunities
utilizing this resource option.
Satellite LNG
Company-owned satellite liquefied natural gas
storage is another option. Satellite LNG facilities could
be constructed within the company's service area.
Unlike LNG facilities described earlier, satellite LNG
uses natural gas that is trucked to the facilities in liquid
form rather than liquefying on site. By locating within
the Avista service area and not on the interstate
pipelines, Avista could avoid annual pipeline charges.
Estimates for this type of needle-peaking resource
look interesting, and the company will continue to
monitor and evaluate the cost and benefit of satellite
LNG as new supply increments are needed.
Propane-Air
Propane-air facilities are yet another option.
Propane-air and natural gas interchangeability concerns
may limit the cost-effective application of a propane-air
system to individual industrial customer facilities or to
metropolitan areas. Interchangeability concerns about
the blending of too great a concentration of propane-air
with natural gas can pose service, maintenance and
safety problems. Avista has had experience with
propane-air systems in the Medford, Ore., service area
for peaking in the past, however the company does not
operate a propane-air plant at this time.
Pipeline Transportation
Additional firm pipeline transportation resources are
very viable resource options for the company.
Determining the appropriate level, supply source and
associated pipeline path, costs and timing, as well as
determining whether or not existing resources will be
available at the appropriate time make this resource very
difficult to analyze. Firm pipeline capacity provides
several advantages: it provides the ability to receive firm
supplies at the production basin; it is generally a low-
cost option given optimization and capacity release
opportunities; and it provides for base-load demand.
Pipeline capacity also has several drawbacks, including
typically long-dated contract requirements, limited need
in the summer months (many pipelines require annual
contracts) and limited availability.
As discussed in Section 5, many pipelines currently
have available pipeline capacity on the mainline portion
of their systems. Unfortunately, NWP does not have any
available capacity on its mainline or on any of the
relevant laterals that serve Avistas requirements. GTN
has mainline capacity currently available and may be
able to provide additional service to some
Washington/Idaho and Oregon customers without an
expansion. Further, longer-term permanent capacity
release options may be available on both pipelines.
Pipeline expansions can be more expensive than
existing pipeline capacity and often require long-term
annual contracts. Even though expansions may be more
expensive than existing capacity, this approach may still
provide the best option to the company given that most
of the other options discussed in this section require
pipeline transportation anyway.
Avista has dated information ttom the pipelines for a
number of expansion scenarios and locations. This
information was used as a basis for the transportation
analysis. If and when Avista determines that additional
6 - 24 Avista Utilities2006 Natural Gas Integrated Resource Plan
transportation capacity is necessary, the company will
request thorough estimates from the appropriate pipeline
companies, search the release market for capacity that
may include winter-only service, and seek capacity on
constrained segments.
Large-scale LNG
There has been a considerable amount of national
discussion regarding LNG gasification terminals.
At today s natural gas prices, LNG can be competitively
transported, stored and marketed. To date, at least 60
terminals have been proposed in the u.S., Mexico and
Canada with seven or more terminals proposed for
Washington, Oregon and British Columbia. Obviously,
not all of these terminals will advance, and it may be
possible that none of the Pacific Northwest terminals
will proceed. The siting of LNG terminals is a difficult
endeavor. In order for a terminal to advance, it will
require economies of scale, the ability to move regasified
supplies to markets, a favorable environmental review
and public reception, secure LNG supply, long-term
output/sales agreements and financing. Although the
Pacific Northwest may not provide sponsors with these
requirements, the recent announcement by PG&E
Corporation, NWP and Fort Chicago Energy Partners
to construct a pipeline from the proposed Coos Bay
LNG facility to Malin, Ore., is certainly encouraging.
This pipeline, assuming it and the LNG facility are built
may allow LNG to be directly delivered to Avista
service territory around Roseburg, Medford and
Klamath Falls.
Industry experts believe that if additional LNG
terminals are built and receive incremental supply,
natural gas prices may trend downward or at least
become less volatile. These experts also believe that it
generally does not matter where the LNG terminals are
located because the national natural gas markets are so
tightly connected. Therefore, if the Pacific Northwest
facilities do not proceed, Avista will likely benefit ttom
increasing amounts of imported LNG.
For this IRP, Avista is not making LNG available to
the model in any case other than the most robust
demand case. This is because LNG in the Pacific
Northwest is highly speculative, the region is not
considered to be as premium of a market as other
locations in North America and because it will take at
least four years before it is known if this option would
move forward in the Pacific Northwest. Each of the
price forecasts the company has reviewed make
assumptions regarding increasing LNG imports to North
America so LNG commodity impacts are imbedded in
those forecasts.
Avista will continue to monitor this intriguing
option and will take action if a Pacific Northwest
terminal begins to look promising.
RESULTS - PORTFOLIO INTEGRATION
Mter performing the preliminary analysis, the
company focused on the question of how to cost
effectively solve resource constraints for the Expected
High, and Low Demand cases (#2, 6 & 7). In order to
answer this question, the company entered the new
resource options as described above, and detailed in
Appendix 6.4, into the SENDOUT'" model and allowed
the model to pick the least-cost approach to meeting
resource deficiencies.
Figures 6.19 and 6.20 summarize the results of this
modeling effort by comparing regional peak day
demand against existing and incremental resources for
the Expected Case over the 20-year period of the plan.
Companion figures similar to Figures 6.19 and 6.20 are
available in Appendix 6.5.
Figures 6.21 and 6.22 show the load duration curves
as well as the resource stacks for Case #2 for three
different yearly intervals. These graphics are useful to
review because an entire year of demand is compared to
the resource stack for that same year. This enables a
review of not just peak day sufficiency but also allows
the opportunity to compare all demand days within that
year. Similar figures for the High and Low Demand
Avista Utiiities 2006 Naturai Gas integrated Resource Plan
Figure 6.19 - WAIID Existing & Least Cost Resources vs. Peak Day Demand
(Net of DSM Savings) Expected Case - November to October
Dthld
500,000
250,000
200,000
I--
1---
--------
450,000
400,000
350,000
300,000
150,000
100,000
50,000
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Existing GTN
Existing TF-
Existing TF-
Existing Plymouth
Stanfield Supply/Backhaul
TransCanada to WAiID
WAIID Sat. LNG
-0- WAiID Peak Day Demand
Figure 6.20 - Oregon Existing & Least Cost Resources vs. Peak Day Demand
(Net of DSM Savings) Expected Case - November to October
Dthld
200,000
40,000
20,000
------
180,000
160,000
140,000
120,000
100,000
80,000
60,000
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Existing GTN Malin Supply '-&- Oregon Peak Day Demand
Existing TF-La Grande Dist. Enhance
Existing TF-Klam. Lat. Purchase
Existing Will. Peaking Medford Lateral Expansion
Existing Plymouth Med. Sat. LNG
2006 Natural Gas integrated Resource Plan Avista Utilities
cases can be found in Appendix 6.
SEND OUT'" considered all options entered into the
program and determined when and what resources were
needed. SEND OUT'" also rejected options that were
not cost effective. These selected resources represent the
least-cost solution, within given constraints, to serve
anticipated customer requirements. Table 6.12 shows
the SEND OUT'" selected supply-side resources for the
Expected Case. The High and Low Demand case
selections can be found in Appendix 6.7. Table 6.
shows the SEND OUT'" selected DSM savings for the
Expected Case. The High and Low Demand case DSM
savings can be found in Appendix 6.
Through ongoing and evolving investigation and
research, the company may determine that alternative
resources are more cost effective than those resources
selected in this IRP. The company will continue to
review and refine its knowledge of resource options and
will act to secure these least-cost options at the
appropriate point in time.
Avista has chosen to utilize the mid demand case
(Case #2) as the most likely or "Expected Case" for its
planning activities. Avista believes that this is the most
likely outcome given company experience, industry
knowledge and the company s understanding of future
gas markets. This case provides for reasonable demand
growth given current expectations of natural gas prices
over the planning horizon. The company believes this
case, if realized, is at a level that allows the company to
be reasonably well protected against resource shortages
and at the same time does not over commit to
additional long-term resources. Further, given the
extreme increase and decrease in demand levels over the
full planning horizon for the Low Demand Case and
the High Demand Case, the company believes that these
cases, although possible, are less likely.
Avista will continue to diligently monitor demand
levels and peak day requirements for "signposts" that
indicate that demand levels are moving toward one of
these other cases. Avista believes that through this
monitoring process, and given that the company has
sufficient time before potential resource shortages, there
is little chance of being surprised by resource shortages.
Avista s portfolio and resource analysis indicates
Figure 6.21 - Load Duration Cul'Ve & Resource Stack (with DSM) Average! Actual Weather with Design Day
Expected Case - WA/ID
MDth
500
450
400 '350 '
300
250
200
150
100
121 151
Current Resources2006/2007
2015/2016
2025/2026
181 301 361
Days
331211241271
2015 Resources
-- 2025 Resources
Avista Utilities 6 - 272006 Naturai Gas integrated Resource Pian
Figure 6.22 - Load Duration Curve & Resource Stack (with DSM) Average/Actual Weather with Design Day
Expected Case - Oregon
MOth
200
180
160
140
120
100
121 151 181 211 241 271 301 331 361
Days
2006/2007
2015/2016
2025/2026
Current Resources
2015 Resources
2025 Resources
several strategies that should be pursued in order to fully
optimize available resources. The effectiveness of any
existing storage asset value, including but not
limited to recalling some or all of the current
strategy will be in the flexibility to take advantage of
market opportunities. These strategies indicate that:
releases;
. Seeking low-cost peaking resources that do not
. Because of the diverse weather within Avista
service territory, a total system supply portfolio
should be maintained to provide the greatest
flexibility for dispatching resources while
maintaining lower supply costs;
require annual commitments;
. Investigating acquisition of winter capacity
releases from third-party providers;
. Furthering the company s understanding of
. Avista will continue to benefit from pursuing
diversification of its firm transportation sources
satellite LNG options;
. Researching low-cost transportation options to
via GTN and NWP. Flexibility is again the key
to being able to cost-effectively utilize the lowest
marry with storage assets to enable better
utilization of the whole portfolio;
. Investigating the potential to balance Avista
priced delivered supply; and
. Capacity releases, both long-term and short-
storage portfolio among its various
jurisdictions/ service territories;
term, should continue to be reviewed . Researching Northern California storage
opportunities; andperiodically.
The company has also identified a number of
resource areas that merit additional review prior to the
. Continuing to analyze natural gas procurement
practices.
next IRP. These areas include but are not limited to:
. Assessing methods for capturing additional
2006 Natural Gas Integrated Resource Pian Avista Utilities
Table 6.12 - Least Cost Supply-Side Resource Additions Selected by SENDOUT"'
Case 2 - Expected Case
Item #Region
Washington/ldaho
WAIID
WAIID
WAIID
WAIID
WAIID
WAIID
WAIID
Oregon
Klamath Falls
Klamath Falls
Medford/Roseburg
Medford/Roseburg
La Grande
Medford/Roseburg
Medford/Roseburg
Type Quantity Dth/d Timing Rates/Charges
Transportation 22 000 November 2012 $4.7 MM Capital Cost Plus Commodity
and NWP Transportation Rate
Notes: WNiD area expansions to facilITate the deiNery in and around Spokane, Lewiston, etc, from GTN into NWP
Transportation TransCanada and GTN Transportation
Rates Plus Commodity
000 November 2012
Note.. Provides delivery to Item #1
Transportation 25,000 November 2016 $5.0 MM Capital Cost Plus Commodity
and NWP Transportation Rate
Notes: WNiD area expansions to facilITate the delNery in and around Spokane, Lewiston, etc, from GTN into NWP
Transportation 000 November 2016 TransCanada and GTN Transportation
Rates Plus Commodity
Notes: Provides delivery to Item #3
Satellite LNG 000 November 2020 $10MM Capital Cost/$1.5MM
Annual Expense Plus Commodity
Transportation 000 November 2022 $5.0 MM Capital Cost Plus Commodity
and NWP Transportation Rate
Noles: WNiD area expansions to facilITate the delivery in and around Spokane, Lewiston, etc, from GTN into NWP
Transportation November 2022 TransCanada and GTN Transportation
Rates Plus Commodity
000
Notes: Provides delivery to Item #6
Purchase n/a November 2006 $3MM Capital Cost
Notes: Purchase of NWP Klamath pipeline segment. Transportation and fuel cost savings more than offset the revenue requirement and capitaJ cost of
the investment. Payoff is approximately 3 years
Reclassification November 2006 No Incremental Charges000
Notes: Companion to Item #8, Ownership of lateraJ aJlows Avista to operate this lateraJ as distribution transmission system which provides aproximately
000 Dthld incrementaJ capacity
Distribution Enhancement $11 MM Capital Cost/$1.3MM Annual
Revenue Requirement
n/a November 2007
Notes: Companion item to Item #11 and 13 below
Transportation 20 000 November 2010 GTN's Med. Lat. Rate
Notes: GTN expansion of the Medford lateraL Assumed cment lateraJ rates, escalated for inftation, for expansion, Item #10 above required to facilitate this option,
Distribution Enhancement $3MM Capital Cost/$.360MM Annual
Revenue Requirement
000 November 2013
Transportation 20,000 November 2014 GTN's Med. Lat. Rate
Notes: GTN expansion of the Medlord LateraJ, Assumed cuITenl lateraJ rates, escalated forinftation, for expansion, Item #10 above required to facilifatethis option,
Satellite LNG $10MM Capital Cost/$1.5MM Annual
Expense Plus Commodity
000 November 2020
Avista Utilities 2006 Naturai Gas integrated Resource Plan
Table 6.13 - Annual and Average Daily Demand Served by Demand-Side Management
Actual peak day DSM is greater than annual average DSM
Annual Daily Annual Daily Annual Daily Annual Daily
Case Gas Year Klamath Klamath La Grande La Grande Medford Medford Roseburg Roseburg
DSM (MOth)DSM (MDthlday)DSM (MOth)DSM (MDthlday)DSM (MOth)DSM (MDthlday)DSM (MOth)DSM (MDthlday)
2006-2007 991 027 280 012 24.781 068 933 016
2007-2008 20.043 055 586 024 49.768 136 11.903 033
2008-2009 29.972 082 12.841 035 74.342 204 17.799 049
2009-2010 39.963 109 17.121 047 99.122 272 23.732 065
2010-2011 49.953 137 21.402 059 123.903 339 29.665 081
2011,2012 60.129 165 25.757 071 149.304 409 35.708 098
2012-2013 69.934 192 29.962 082 173.464 0.475 41.531 114
2013-2014 79.925 219 34.243 094 198.245 543 47.464 130
2014-2015 89.916 246 38.523 106 223.026 611 53.397 146
2015-2016 100.214 275 42.928 118 248.840 682 59.513 163
2016-2017 100.872 276 45.431 124 271,991 745 65.678 180
2017-2018 100.259 275 45.142 124 269.794 739 65.103 178
2018-2019 99.646 273 44.853 123 267.597 733 64.529 177
2019-2020 98.970 271 44.530 122 265.653 728 63.951 175
2020-2021 97.684 268 43.948 120 261.452 716 62.976 173
2021-2022 95.132 261 43.460 119 252.750 692 60.728 166
2022-2023 92.581 254 42.973 118 244.048 669 58.480 160
2023-2024 90.289 247 42.599 117 236.314 647 56.391 154
2024-2025 87.037 238 41.801 115 225.549 618 53.727 147
2025-2026 79.393 218 39.059 107 204.712 561 48.678 133
Annual Daily Annual Daily Annual Daily
Case Gas Year Oregon Oregon WAIID WAIID Total System Total System
DSM (MOth)DSM (MDthlday)DSM (MOth)DSM (MDthlday)DSM (MOth)DSM (MDthldey)
2006-2007 44.105.038 288 150.0.41
2007-2008 90.210.723 577 301.
2008-2009 134.315.115 863 450.
2009-2010 179.420.153 151 600.
2010-2011 224.525.192 1.439 750.
2011-2012 270.621.538 703 892.2.45
2012-2013 314.712.033 951 026.
2013-2014 359.804.429 204 164.
2014-2015 404.896.826 2.457 1 ,301 .
2015-2016 451.49 992.248 718 1,443.
2016-2017 483.089.136 984 573.
2017-2018 480.087.088 978 567,
2018-2019 476.082.768 966 559.
2019-2020 473.1 ,077.291 951 1 ,550.
2020-2021 466.065.283 919 531.
2021-2022 452.054.580 889 506.
2022-2023 438.045.926 866 1,484.
2023,2024 425.1 ,040.305 850 1 ,465.
2024-2025 408.017.861 789 1 ,425.
2025-2026 371.998.575 736 370.42
2006 Naturai Gas Integrated Resource Plan Avista Utilities
SECTION 7 - AVOIDED COST DETERMINATION
Avista s avoided cost estimates represent the marginal
cost of natural gas usage incremental to the forecasted
demand. In other words, avoided cost is the unit cost to
serve the next unit of demand during any given period
of time. If demand-side management measures reduce
customer demand, the company is able to "avoid"
certain commodity and transportation costs.
METHODOLOGY
To develop avoided cost figures associated with the
reduction of natural gas usage, a demand forecast
existing and future supply-side resources, and demand-
side resources are required. Avista utilizes the
SEND OUT'" model data used throughout this IRP to
produce its avoided cost figures. In particular, the
company assumes the Expected Case (Case #2) as the
appropriate data set.
SEND OUT'" functionality provides for marginal cost
data by day, month and year for each demand area.
This marginal cost data includes the cost of the next
unit of supply and the associated transportation charges
to move this unit.
AVOIDED COST DETERMINATIONS
Avista has summarized the SEND OUT'" calculated
avoided cost data in Appendix 7.1. This has been
divided into annual and winter costs and is averaged
accordingly. Winter season costs are most appropriate
when considering heat-related avoided costs. Annual
costs are most appropriate when considering non-heat
(base load) related avoided costs.
Note that Appendix 7.1 displays avoided cost figures
for each of the demand regions discussed in this IRP.
Also note that figures are stated in nominal dollars per
dekatherm and are not discounted.
A graphical depiction of the avoided costs for the
Medford and Washington/Idaho areas for annual and
winter-only dekatherm usage is represented in Figure
1. These avoided costs exclude consideration of
environmental externality adders.
ENVIRONMENTAL COSTS AND EXTERNALITIES
(OREGON JURISDICTION ONLY)
The methodology employed to develop the avoided
costs associated with the reduction of natural gas usage
has been based upon the monetary value associated with
Figure 7.1 - Natural Gas Avoided Costs - $/Dth
Includes Commodity & Trans. Costs/Excludes Env. Ext. Adder - November to October
10.
~ ~ ~ ~
~O ~1 ~2 ~3 ~4 ~5 ~6 ~7 ~8 ~9
~ ~ ~ ~ ~ ~ ~
-+- Medford annual
--&- Medford Winter
-+- WA/ID Annual
-- WA/ID Winter
Avista Utilities 2006 Natural Gas integrated Resource Pian
commodity and transportation costs only. These avoided
cost streams do not include a valuation of the
environmental externality costs related to the gathering,
transmission, distribution or end-use of natural gas.
Per traditional economic theory and industry
practice, an environmental externality factor is typically
added to the monetary avoided cost when there is an
opportunity to displace traditional supply-side resources
with an alternative resource lacking this adverse
environmental impact. Per the requirements established
within UM 424 (see excerpt below) a 10 percent
conservation cost advantage environmental externality
factor must be added to the above stream of avoided
costs when evaluating natural gas-efficiency options.
UM 424 , SECTION 9
base our decision in part on the conclusion by the
Northwest Power Planning Council in 1987 that the 10
percent cost advantage should be continued. The Council
identified a number of conservation bemftts not then
quantified in its analysis, including the elimination offish
and wildlife impacts and other environmental iffects of
displaced generating resources, load stability and
predictability, flexibility to adapt to changing circumstances
and increased customer comfort. believe these beniftts
are not fully recognized in utility planning and resource
decisions, so electric and gas utilities should continue to
apply the 10 percent conservation cost advantage.
In compliance with this clear directive, the company
will incorporate this 10 percent environmental
externality "adder" into our assessment of the cost-
effectiveness of existing and proposed demand-side
management programs. Additionally our assessment of
prospective demand-side management opportunities will
be based upon an avoided cost stream that includes the
same consideration of environmental externalities.
When appropriate these evaluations and resource
decisions will be based upon program impacts, markets
and environmental impacts that are as geographically
specific as possible.
Avistas natural gas DSM business planning process
will continue to incorporate full consideration of the
required environmental externality factor.
7 - 2 Avista Utilities2006 Natural Gas Integrated Resource Plan
SECTION 8 - ACTION PLAN
AVISTA UTILITIES 2003 ACTION PLAN REVIEW
The 2003 action plan focused on six key areas:
. Sales Forecasting
. Modeling/Forecasting
. Supply/Capacity
. Demand-Side Management
. Distribution Planning
. Public Involvement
SALES FORECASTING
Action Item:
Avista will continue to track the price elasticity
customer use responses over the action plan period to
validate or modify the lag structure.
Results:
Price elasticity response rates were tracked during
the action plan period. Despite dramatic reductions in
usage after the 2001 energy crisis, elasticity response
rates have returned to pre-2001 levels. This was
discussed at the Oct. 4, 2005 TAC meeting.
MODELING/DAILY FORECASTING
Action Item:
Avista will continue to use the SEND OUT'" Gas
Planning Model and the Nostradamus'" Forecasting
Model to evaluate capacity requirements, storage
requirements, supply requirements, monthly guidance
for Natural Gas Supply, etc.
Results:
Avista utilized and continues to utilize these tools for
the above-mentioned purposes since the 2003 IRP was
filed. The company employs these models on a regular
basis and has refined them to meet changing business
needs on a proactive basis.
SUPPLY /CAPACITY
Action Item:
Avista will continue to monitor Avista Energy as part
of the "bench marking" agreement. Avista will continue
to supply the State Commission Staffs with quarterly
reports as stipulated in the "bench marking" agreement.
Avista will also continue to analyze the need for
additional interstate pipeline capacity and to evaluate the
renewal of transportation contracts as they expire.
Results:
The "Benchmark Mechanism" expired on
March 31 2005.
DEMAND-SIDE MANAGEMENT
Action Item:
Within the company s Washington and Idaho service
territory, the company will work toward achieving
available cost-effective natural gas efficiency
opportunities while simultaneously bringing the tariff
rider balance back to zero in a timely manner. Toward
these ends Avista has identified the following action
items for these two jurisdictions:
. Continue to target low-cost/no-cost and lost
opportunity measures in the
commercial/industrial segments.
. Evaluate the rotation of programs contained
within the residential portfolio to create a sense
of urgency on the part of customers and dealer
infrastructure.
. Leverage regional and local electric efficiency
programs to realize natural gas-efficiency
opportunities.
Within the Oregon jurisdiction the company has
identified the following action items:
. Evaluate the impact of the space and water
heating natural gas efficiency programs, to
include an evaluation of the market
transformation effects.
Avista Utilities 2006 Naturai Gas Integrated Resource Pian
. Avista will continuously reevaluate the company
approach to meeting mandated residential
weatherization, commercial audit and commercial
incentive program responsibilities. The company
will work with external stakeholder groups to
meet common objectives and optimize
implementation.
Results:
Within the North Division, the company committed
to the acquisition of cost-effective natural gas efficiency
opportunities while simultaneously returning the DSM
tariff rider balance back to zero. Since that commitment
Avista has exceeded achieved acquisition levels up to
and exceeding four times the goal specified within
Avista Rate Schedule 190. The aggregate tariff rider
balance was successfully returned to zero in August
2005, although the Idaho natural gas tariff rider balance
retains a negative balance. The company is currently
executing a business plan that incorporates periodic
revisions to tariff rider levels to maintain a near-zero
balance in all tariff riders while providing the necessary
funding for the substantial increase in the acquisition
goals specified within this IRP.
The company also committed to an evaluation of
space and water heating appliance efficiency programs.
Based on a review of engineering calculations and
revisions to the baseline standard efficiency the per unit
savings claims were updated for purposes of calculating
program cost-effectiveness.
Additional commitments were made to continue the
continuous reevaluation of the optimal approach to
meeting the companys responsibilities for mandated
residential and commercial programs. This work has
and will continue to be, an ongoing effort. To date, this
program has included establishing a dialogue with the
Energy Trust of Oregon regarding the potential for
cooperative programs.
DISTRIBUTION PLANNING
Action Item:
Avista will continue to use the Stoner Workstation in
activities of distribution planning and continue to
integrate the GIS system into the planning functions.
Results:
Avista continues to improve its GIS system through
the conversion of each service territory s facility and
mapping records. After conversion, distribution models
can be generated using standardized load study practices
resulting in consistency and accuracy.
PUBLIC INVOLVEMENT
Action Item:
Avista will continue to participate in the energy
planning efforts of other organizations in the
Northwest, as well as any national studies that may
occur. This includes but is not limited to studies being
performed under the guidance of the American
Gas Association, the Northwest Gas Association and
the FERc.
Avista will also look to other utilities in the
northwest to find better ways to get active, meaningful
participation in the TAc.
Results:
Avista is active with the Northwest Gas Association
American Gas Association, Western Energy Institute and
the Northwest Power and Conservation Council as well
as with many other industry organizations. Avista
participation allows for the sharing of best practices and
the enhancement of valuable relationships with industry
participants and stakeholders.
Avista Utilities2006 Naturai Gas Integrated Resource Plan
AVISTA UTILITIES 2006-2007 ACTION PLAN
The 2006 action plan is focused on the following
key areas:
. Sales Forecasting
. Supply/Capacity
. Forecasting
. Demand-Side Management
. Distribution Planning
SALES FORECASTING
Action Items:
During 2006, the company will update customer
forecasting models, incorporating the most recent data.
The dramatic increase in natural gas retail prices will
provide improved information on price elasticity and
weather sensitivity coefficients.
Avista anticipates making two changes to the
forecasting methodology, one in 2006 and the other
2007. The company currently uses county-level
forecasts for eight counties in the three states it serves.
During 2006, Avista will add five counties, two in
Washington and three in Idaho. This will help identifY
differential growth patterns between the core areas
(Spokane and Coeur d'Alene) and the more rural and
resort areas of the service area.
In 2007, utilizing the data and forecasts from these
additional counties, Avista will develop a "gate-station
forecasting system that will allocate the sales and
customer forecast to the various pipeline delivery points
in the service area. Avista anticipates having this system
available so that the company can utilize the results for
the next IRP.
SUPPLY ICAPACITY
Action Items:
Avista will conduct regular meetings with
Commission Staff members with the intent to provide
information on market updates, any material changes to
the hedging program, and significant changes in
assumptions and status of company activity related to
the IRP.
Avista will continue to seek low-cost peaking
resources that do not require annual contractual
commitments and will investigate acquisition of winter
capacity releases from third-party providers.
The company will further its understanding of LNG
opportunities, including satellite and company-owned
LNG resources. Avista will further consider and
evaluate the Coos Bay LNG/Pacific Connector Pipeline
opportunity.
The company will assess methods for capturing
additional value related to existing storage assets
including but not limited to recalling some or all of the
current releases.
Avista will further develop its storage strategy with
particular focus on storage opportunities for Oregon
customers and will research non-Jackson Prairie storage
prospects for all customers.
FORECASTING
Action Item:
The company will complete its evaluation of
VectorGas . If purchased, the company will utilize
VectorGas~ to strengthen Avista s ability to analyze the
financial impacts under varying load and price scenarios.
DEMAND-SIDE MANAGEMENT
Action Item:
The DSM analysis that occurred during the IRP
process is the launching point for a more detailed
investigation of the natural gas-efficiency technologies
identified as cost-effective resource options.
The company initiated this additional evaluation and
development of programs in January 2006 with the
expectation that program revisions and the launch of
new programs will occur in the spring of that same year.
The company has explicitly recognized within this
IRP the obligation to achieve all natural gas-efficiency
Avista Utilities 2006 Naturai Gas Integrated Resource Pian
resources available through the intervention of cost-
effective utility programs. Given the rapid changes
within the natural gas market, there are many new
efficiency opportunities within the market.
Considerable uncertainty remains regarding the
customer response to these programs. This uncertainty
does not preclude the company ttom pursuing the
planned aggressive ramp-up of natural gas-efficiency
programs. Additionally, the company has and will
actively seek opportunities for new or enhanced
resource acquisition through the development of
cooperative regional programs.
DISTRIBUTION PLANNING
Action Item:
Avista will continue to utilize computer modeling to
facilitate distribution-planning efforts and identify least-
cost opportunities to meet growth and reinforcement
needs. Avista will determine the benefit and feasibility
of using city-gate station forecasts as a method for
improving distribution planning.
8 -2006 Naturai Gas integrated Resource Plan Avista Utiiities
SECTION 9 - GLOSSARY OF TERMS AND ACRONYMS
Avista Corporation (Avista Corp.
An energy company engaged in the generation
transmission and distribution of energy as well as other
energy-related businesses; Avista is located in the Pacific
Northwest with corporate headquarters located in
Spokane, Wash.
Avista Energy
The non-regulated energy marketing and trading
affiliate of Avista Corporation.
Avista Utilities (Also referred to as Avista or
the company)
The regulated operating division of Avista Corp.
separated into North (Washington and Idaho) and South
(Oregon) operating divisions; 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.
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.
Cascade Natural Gas Corporation
A natural gas local distribution company
headquartered in Seattle, Wash., serving customers in
Washington and Oregon.
City-Gate (Also known as gate station or pipeline
delivery point)
The point at which natural gas deliveries transfer
ttom the interstate pipelines to Avista s distribution
system.
Commodity Price
The current price for a supply of natural gas that is
charged for each unit of natural gas supplied
determined by market conditions.
Compression
Increasing the pressure of natural gas in a pipeline by
means of a mechanically driven compressor station to
increase flow capacity.
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.
Avista Utilities 9 -2006 Natural Gas integrated Resource Plan
cpr
Consumer Price Index, as calculated and published
by the US. 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 Resources
Energy resources obtained through assisting
customers to reduce their "demand" or use of
natural gas.
D~a~S~ ~n~~mt ~S~
The activity of implementing demand-side measures
to minimize customers' energy usage in their facilities.
Design Day
A 24-hour period of demand, which is used as a
basis for planning peak natural gas capacity
requirements. For purposes of this plan, the company
calculates design day demand based upon the coldest day
on record for each of several service regions.
Econometric Model
A set of equations developed through regression
analysis and other quantitative techniques, as well as
intuitive judgment that mathematically represents and
forecasts economic relationships.
End User
The ultimate consumer of natural gas; the end user
purchases the natural gas for consumption, not for resale
or transportation purposes.
Externalities
Cost and benefits that are not reflected in the price
paid for goods or services.
Federal Energy Regulatory Commission (FER
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.
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 toa 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 Price
The future price for a quantity of natural gas to be
delivered at a specified time.
Avista Utilities2006 Naturai Gas integrated Resource Plan
Gas Day
A period of 24 consecutive hours commencing at
9 a.m. Central Clock Time (7 a.m. Pacific Clock Time);
this is an industry standard throughout North America.
GasSolutions
A relational database system developed by Avista to
nominate, track and report flows of natural gas.
Gas Transmission Northwest (GTN)
One of the six natural gas pipelines the company
deals with directly; GTN is headquartered in Portland
Ore., and it is a subsidiary of Trans Canada Pipeline;
owns and operates a natural gas pipeline that runs ttom
Canada to the Oregon/ California border.
Geographic Information System (GIS)
A system of computer software, hardware and
spatially referenced data that allows information to be
modeled and analyzed geographically.
Global Insight, Inc.
A national economic forecasting company.
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 found in Louisiana that is
widely recognized as the most important pricing point
in the United States. It is also the trading hub for the
New York Mercantile Exchange (NYMEX).
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 (IMP)
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.
Interruptible Service
A service oflower 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
Integrated Resource Plan (IRP)
The document that explains Avista s plans and
preparations to maintain sufficient resources to meet
customer needs at a reasonable price; also known as a
Least Cost Plan (see LCP).
Jackson Prairie Storage Project UP or JPSP)
An underground 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 some 1 800 feet beneath the
surface and capped with a very thick layer of
dense shale.
Avista Utilities 2006 Naturai Gas integrated Resource Plan
Liquefaction
Any process in which natural gas is converted 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 that has been 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 SEND OUT'" Gas Model.
Load Duration Curve
An array of daily sendouts observed that is sorted
ttom highest sendout day to lowest to demonstrate both
the 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.
Local Distribution Company (LDC)
A utility that purchases natural gas for resale to end-
use customers and/or delivers customers' 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.
LS-
NWP rate schedule covering its LNG service; also
used to refer to the natural gas (as in "LS-l" natural gas).
MCF
A unit of volume equal to a thousand cubic feet.
MDQ
Maximum Daily Quantity.
MMBTU
A unit of heat equal to one million British thermal
units (BTUs) or 10 therms. Can be used interchangeably
with Dth.
National Energy Board (NEB)
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 Energy Associates
The developers of the SEND OUT'" Gas Planning
System, a Siemens Company.
New York Mercantile Exchange (NYMEX)
An organization that facilitates the trading of several
commodities including natural gas.
Avista Utilities2006 Natural Gas Integrated Resource Plan
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 design day
and one non-design day.
Non-Firm Open Market Supplies
Natural gas purchased via short-term purchase
arrangements; may be used to supplement firm contracts
during times of high demand or to displace other
volumes when it is cost-effective to do so; also referred
to as spot market supplies.
Northwest Pipeline Corporation (NWP)
The principal interstate pipeline serving the Pacific
Northwest and one of six natural gas pipelines the
company deals with directly; NWP is Avistas primary
transporter of natural gas; headquartered in Salt Lake
City, Utah, NWP is a subsidiary of The Williams
Companies.
NOVA Gas Transmission (NOVA)
See TransCanada Alberta System
Northwest Power and Conservation Council
(NWPPC)
A regional energy planning and analysis organization
headquartered in Portland, Ore.
OPUC
Public Utility Commission of Oregon
Peak Day
The 24-hour day period of greatest total natural gas
sendout; may be used to represent historical actual or
projected requirements. Sometimes referred to as a
Design Day.
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., 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.
Propane
An alternative hydrocarbon fuel which has a higher
heat value than natural gas (2550 BTUs vs. 1000 BTUs
per cubic foot), however it also has higher safety
concerns including being heavier than air (i., doesn
dissipate) and being more easily ignited.
Propane Air
Propane mixed with air and natural gas to allow
burning in a natural gas system to supplement natural
gas supplies for customers on peak days.
PSI
Pounds per square inch - a measure of the pressure
at which natural gas is delivered (see Delivery Pressure)
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.
Avista Utiiities 9 - 52006 Naturai Gas Integrated Resource Pian
Resource Stack
Sources of natural gas inttastructure or supply
available to serve Avista s customers.
Seasonal Capacity
Natural gas transportation capacity designed to
service in the winter months.
Sendout
The amount of natural gas consumed on any
given day.
SENDOU'J"'!'
Natural gas planning system ttom New Energy
Associates; 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.
SGS
NWP rate schedule covering storage natural gas
ttom Jackson Prairie; also used to refer to storage natural
gas supply.
Shoulder Months
Generally defined as the months of March, April
and May (in the spring) or September and October (in
the fall) when the temperatures are moderate and
customer demand is unpredictable.
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 ttom 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.
Tariff
A published volume of regulated rate schedules plus
general terms and conditions under which a product or
service will be supplied.
TF-
NWP's rate schedule under which Avista moves
natural gas supplies on a firm basis.
TF-
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.
Terasen
A natural gas LDC headquartered in Vancouver
British Columbia, serving customers in Canada.
Formerly known as BC Gas.
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.
Avista Utilities2006 Naturai Gas integrated Resource Pian
TransCanada Alberta System (TCPL-AB)
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 deals with
directly.
TransCanada BC System (TCPL-BC)
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 US border; one
of six natural gas pipelines Avista deals 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.
Tuscarora Gas Transmission Company
One of the six natural gas pipelines the company
deals with directly; Tuscarora is a subsidiary of Sierra
Pacific Resources and TransCanada; this natural gas
pipeline runs ttom the Oregon/California border to
Reno, Nevada.
Vaporiz ation
Any process in which natural gas is converted from
the liquid to the gaseous state.
WACOG
Weighted Average Cost of Gas; 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.
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.
Avista Utilities 9, 72006 Naturai Gas integrated Resource Pian
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2006 Naturai Gas integrated Resource Pian Avista Utilities