200712282007 IRP.pdf

II: 20
~~~'V'ST4'
Corp.
AVU-G-07-04
ell, Secretar
lic Utilities Commssion
ouse Mail
72 Washington Street
oise, Idaho 83720
Dear Ms. Jewell:
RE: A vista Utities 2007 Natural Gas Integrated Resource Plan
Per IPUC's Integrated Resource Plan Requirements outlined in Case No.U-1500-165,
Order No. 22299, Case No.GNR-E-93-1, Order No. 24729 and Case No.GNR-E-93-3,
Order No. 25260 , Avista Corporation d1/aJ Avista Utilities, hereby submits for filing an
original, an electronic copy and 7 copies of its 2007 Natural Gas Integrated Resource
Plan.
The Company submits the IR to public utility commssions 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 fai, just, reasonable and suffcient. The IRP, by identifying and
lvaIuating varous resource options and establishing a plan of action for resource
decisions, is a significant component in meeting this obligation.
The 2007 Plan is notable for the following:
. The Company's peak day resource deficits in Oregon begin in 2011-2012 and in
Washington and Idaho in 2014-2015;
· Deficits are drven priarly by customer and demand growth;
. Lower forecasted demand is the primar change from the 2006 IRP;
. Estimated DSM energy savings goals are 1,425,000 therms in Washington and
Idaho and 350,000 therms in Oregon;
Prntig costs have ben reuce by puttng supportng documents on our web site at
http; IIwww.ayistautilties.com/i nsjde/transm ission/i rp/gasl
Pleae dit any questions regarng ths report to Grg Rah at [phone].
Sincerely, - .ir~
Senior Reguatory Analyst, State and Federa Reguation
c; Brian Laspery
A VU-G-07-04
..
Printed on recycled paper. *
...........................................
C\
COVER PHOTOS
- Avista's investment in natural gas growth crosses the Palouse region of Southeast Washington, serving
Washington State University
- Key components of natural gas effciency include a gas cooktop, a programmable thermostat and a gas
fireplace.
SPECIAL THANKS TO OUR TALENTED VENDORS. FROM
THE SPOKANE AREA WHO PRODUCED THIS IRP;
Ross Printing Company
Thinking Cap Design
.....TABLE OF CONTENTS..Executive Summ 1.1..Demand Forecast 2.1..Demad-Side Management 3.1.Distribution Planning 4.1..Supply-Side Resources 5.1..Integrated Resource Portfolio 6.1.Avoided Cost 7.1..Action Plan 8.1..Glossary 9.1......................
SAFE HARBOR STATEMENT
...........................................
This document contains forward-looking statements. Such statements
are subject to a variety of risks, uncertaities and other factors, most of
which are beyond the company's control, and may of which could have
a signcant impact on the company's operations, results of operations
and financial condition, and could cause actual results to dier materialy
from those anticipated.
For a further discussion of these factors and other important factors,
please refer to our reports fied with the Securities and Exchage
Commssion which are avaiable on our website at ww.avistacorp.com.
The company undertakes no obligation to update any forwrd-looking
statement or statements to reflect events or circumstances that occur afer
the date on which such statement is made or to reflect the occurrence of
unanticipated events.
.....Table 1.1:.Table 2.1:.Table 2.2:.Table 2.3:.Table 2.4:.Table 3.1:.Table 3.2:.Table 3.3:.Table 3.4:.Table 3.5:.Table 3.6:
Table 3.7:.Table 3.8:.Table 3.9:.Table 3.10:.Table 3.11:.Table 3.12:.Table 3.13:.Table 4.1:.Table 4.2:.Table 4.3:.Table 4.4:
Table 5.1:.Table 5.2:.Table 6.1:.Table 6.2:.Table 6.3:.Table 6.4:.Table 6.5:.Table 6.6:.Table 6.7:..........
INDEX OF TABLES
Demand Scenarios
SENDOUTiI Demand Calculation
Demand Coeffcients
Demand Scenarios
Annual Average Demand Percentage Increases
Heating Degree-Days by Delivery Area
Program Categorization Matrix WA/ID
Program Categorization Matrix OR
SENDOUTi DSM Results
Results of Acquirable Resource Potential
Annual and Cumulative DSM Acquisition and Potential
Avista Residential Shell Program Requirements
Summary of 2006 Natural Gas Effciency Program Results
Annual Heating Degree-Days by Servce District
Annual Distribution of Heating Degree-Days
WA/ID Rate Schedule 190 Incentive Tiers
WA/ID Prescriptive Residential Gas Measures
WA/ID Community Action Program Contracts
Determining Base Load
Determining Heat Load
Determining Peak Hourly Load
Capital Reinforcement Projects with Estimated Costs in 2006$
Current Available Firm Transportation Resources
Current Transportation/Storage Rates and Assumptions Rates
Planning Standard Review
Basis Differential Assumptions
MontWy Pricing Alocation
Demand Scenarios
Peak Day Demand - Served and Unserved
Least Cost Supply-Side Resource Additions Selected by SENDOUTiI
Annual Demand, Annual Average Demand and Peak Day Demand Served by DSM
1.2
2.2
2.4
2.5
2.8
3.4
3.5
3.6
3.6
3.8
3.9
3.13
3.13
3.14
3.15
3.16
3.17
3.18
4.3
4.3
4.3
4.6
5.4
5.5
6.7
6.12
6.13
6.13
6.16
6.20
6.21
.
INDEX OF FIGURES ...
Figure 1.1:System Wide Peak Day Demand 1.3 .
Figure 1.2:Henry Hub Forward Prices 1.4 .
Figure 1.3:WA/ID Existing Resources vs. Peak Day Demand 1.5 .
Figure 1.4:OR Existing Resources vs. Peak Day Demand 1.5 .
Figure 1.5:WA/ID Existing & Best Cost/Risk Resources vs. Peak Day Demand 1.6 .
Figure 1.6:OR Existing & Best Cost/Risk Resources vs. Peak Day Demand 1.6 .
Figure 2.1:Customer Growth Scenarios 2.3 .
Figure 2.2:WA/ID Actual Average Daily Demand vs. Forecasted Average Daily Demand 2.6 .
Figure 2.3:OR Actual Average Daiy Demand vs. Forecasted Average Daily Demand 2.6 .
Figure 2.4:WA/ID Peak Day Demand 2.7 .Figure 2.5:Oregon Peak Day Demand 2.7
Figure 3.1:Integration of DSM within the IRP 3.2 .
Figure 3.2:Cumulative Identified Potential vs. Cumulative Acquired WA/ID 3.10 .
Figure 3.3:Cumulative Identified Potential vs. Cumulative Acquired OR 3.10 .
Figure 3.4:Annual Acquisition - WA/ID 3.11 .
Figure 3.5:Annual Acquisition - OR 3.11 .
Figure 5.1:January 1996 to July 2007 Monthly Index 5.2 .
Figure 5.2:Jackson Prairie Storage Capacity and Deliverabilty 5.3 .
Figure 6.1:SENDOUTiI Model Diagram 6.2 .
Figure 6.2:WA/ID Historical Monthly Average Demand 6.4 .
Figure 6.3:OR Historical Monthly Average Demand 6.4 .Figure 6.4:Average vs. Coldest vs. Warmest Spokane Weather 6.5 .Figure 6.5:Average vs. Coldest vs. Warmest Medford Weather 6.5
Figure 6.6:NOAA 30-year Average vs. Planning Weather Spokane Weather 6.6 .
Figure 6.7:NOAA 30-year Average vs. Planning Weather Medford Weather 6.6 .
Figure 6.8:Existing Firm Transportation & Storage Resource Stack WA/ID 6.8 .
Figure 6.9:Existing Firm Transportation & Storage Resource Stack OR 6.8 .
Figure 6.10:WA/ID DSM Supply Curve 6.9 .
Figure 6.11:OR DSM Supply Curve 6.9 .
Figure 6.12:Henry Hub Forward Prices 2006 IRP vs. Current Forecasts 6.11 .
Figure 6.13:Henry Hub Forward Prices for Avista 2007 IRP Nominal $/Dth 6.11 .
Figure 6.14:Henry Hub Forward Prices for Avista 2007 IRP 2007$/Dth 6.12 .
Figure 6.15:Avista IRP Total 20 Year Cost 6.14 .Figure 6.16:WA/ID Existing Resources vs. Peak Day Demand 6.15 .Figure 6.17:OR Existing Resources vs. Peak Day Demand 6.15
Figure 6.18:WA/ID Existing & Best Cost/Risk Resources vs. Peak Day Demand 6.18 .
Figure 6.19:OR Existing & Best Cost/Risk Resources vs. Peak Day Demand 6.18 .
Figure 6.20:Load Duration Curve & Resource Stack Expected Case - WA/ID 6.19 .
Figure 6.21:Load Duration Curve & Resource Stack Expected Case - OR 6.19 .
Figure 7.1:Natural Gas Avoided Costs 7.1 ...
...........................................
2007 IRP KEY MESSAGES
· In our Expected Case,Avista has suffcient natural
gas resources in Oregon unti2011-2012 and in
Washington and Idao unti2014-2015. Peak day
resource deficits begin in these years and are driven
primarily by projected average demand growt of
2 percent per year and average natural gas customer
growth of 2.4 percent.
· To meet our near term resource deficits in Oregon,
we have identified preferred solutions. For the
Klamth Fals servce territory we intend to purchase
the Klamath Fals Lateral from Northwest Pipelie
(NW) enabling us to meet demand in our Expected
Case throughout the planng horizon. For the
Medford servce territory, ongoing distribution system
enhancements combined with expansion of Gas
TransITssion Northwest's (GTN's) Medford Lateral
should also meet long term demand in our Expected
Case.
· Avista has a diversifed portfolio of natural ga
resources, including owned and contracted storage,
firm capacity rights on five pipelines and commodity
purchase contracts frm several different supply basins.
Our phiosophy is to reliably provide natural gas to
customers with an appropriate balce of price stabilty
and prudent cost. Avista plans to meet the identified
resource deficits with demad-side maagement
measures and firm resources, including distribution
system enhancements and pipeline transportation
capacity.
. The major change from the 2006 IRP to the 2007
IRP is the lower demad forecast. This reduction was
driven mainly by a lower econoITC growth rate and
lower use per customer than previously forecasted in
our service territories.
· There are may risks to consider over the planng
horizon. Some of the modeled and non-modeled
risks analyzed include price elasticity growth rates,
lead-ties and cost overruns on resource construction,
legislation on environmenta externalties, availability
of supply and weather.
· Demad-Side Management efforts include a review
and implementation of customer program, including
residential space and water heatig effciency wal,
floor and window audits and replacement program,
and commercial and industrial natural gas effciency
program, among others. Avista has implemented
an energy effciency initiative caled the "Heritage
Project." It builds on the company's long-time
commtment to energy conservation and effciency,
introducing new products and servces to increase
customer's energy savings.
· The maket for natural ga supply has dramticaly
chaged over the last several years as the commodity
market has transitioned from a regionaly-based maket
to a national or perhaps global market. The elevated
prices and increased volatity have infuenced the way
we plan in the short-term and in the long-term. Our
natural gas procurement plan seeks to competitively
acquire natural gas supplies whie reducing exposure
to short-term price volatility using a number of tools
such as financial hedging and storage.
· The Integrated Resource Plan identifies and establishes
an action pla that wi steer the company toward the
risk adjusted, least-cost method of providing service
to our natural gas customers. Included in this action
plan are efforts to improve modeling, evaluation of
our planning standard, further research into supply-
side resource options and goals for demad-side
maagement.
AVISTA'S ELECTRIC AND NATURAL GAS SERVICE AREAS
AS OF DECEMBER 31,200:
RETAIL ELECTRIC CUSTOMERS BY STATE RETAIL NATURAL GAS CUSTOMERS BY STATE
Washington: 140,900Idaho: 69,800Oregon: 93,900
Total Natural Gas: 304,600
Washington:
Idaho:
227,700
117,700
345,400Total Electric:
Electric Service Areas Natural Gas Service Areas
...........................................
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Chapter 1 - Executive Summary
1. EXECUTIVE SUMMARY
Avista's 2007 Natural Gas Integrated Resource Plan
(IRP) identifies a strategic natural gas resource portfolio
that meets future demad requirements. The foundation
for integrated resource plang is the demand planning
criteria utized for the development of demad forecasts.
The forma exercise of bringing together forecasts of
customer demand with comprehensive anayses of
resource options, including supply-side and demand-side
measures, is valuable to the company, its customers and
regulatory commssions for long-range plang.
Avista submits an IRP to the public utility commssions
in Idao, Washington and Oregon every two years
as required by state reguation 1. The company has
a statutory obligation to provide reliable natural ga
servce to customers at rates, terms and conditions that
are fair,just, reasonable and suffcient. We regard the
IRP as a means for identing and evaluating various
resource options and as a process to establish a plan of
action for resource decisions. Through ongoing and
evolving investigation and research, we may determine
that alternative resources are more cost-effective than
those resources selected in this IRP. We will continue
to review and refine our knowledge of resource options
and wi act to secure these least-cost options when
appropriate.
The IRP identifies and establishes an action plan to steer
the company toward the least-cost method of providing
service to our natural gas customers. There are a number
of factors that must be considered within the context
ofleast-cost, including an assessment of risks associated
with each alternative. Therefore, actions resulting from
the IRP process represent risk-adjusted, least-cost results,
which we refer to as best cost/risk resources.
Avista's maagement and stakeholders in the Techncal
Advisory Commttee (TAC) playa key role and have a
signcant impact in guiding the plan to its conclusions.
TAC members include customers, Commssion
Staff, consumer advocates, academics, utity peers,
governmental agencies and other interested parties (a list
ofTAC members is in Appendi 1.1). TheTAC provides
important input on modeling, plannig assumptions and
the general direction of the plannng process.
IRP PROCESS AND STAKEHOLDER
INVOLVEMENT
Preparation of the IRP is a coordiated effort by
several departments withn the company and includes
input from Commssion Staf, customers and other
stakeholders. Topics leading to the development of the
IRP include natural gas sales forecasts, demand-side
management, distribution planng, supply-side resources
and computer modeling tools, resulting in an integrated
resource portfolio.
1 In Washington, IRP requirements are outlined in WAC 480-90-238 entided "Integrated Resource Plannng." In Idao, the IRP require-
ments are oudined in Case No.GNR-G-93-2, Order No. 25342. In Oregon, the IRP requirements are outlned in Order No. 89-507,
07-002 and UM1056. Chapter 6 of this document details these requirements.
AvistaCorp 2007 Natura Gas IRP 1.1
Chapter 1 - Executive Summary
To faciltate stakeholder involvement in the 2007 IRP
the company sponsored fourTAC meetings. The first
meetig convened on May 2, 2007, and the last meeting
was held on Aug. 14, 2007. A broad spectrum of people
was 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. A draft of this IRP was provided to
TAC members on Sept. 6, 2007. We gained valuable
input from the TAC interaction and appreciate the
positive contribution of the participants.
MODELING APPROACH
We applied our SENDOUTiI model (a linear
programng model widely used to solve natural gas
supply and transportation optimization questions)
to develop the best cost! risk resource mi for the
20-year planng period. Using a present value revenue
requirement (PVR) methodology this model performs
least-cost optization based on day, monthly, seasonal
and annual assumptions related to:
· customer growth and customer natural gas usage
to form demand forecasts;
· existing and potential transportation and storage
options;
· existing and potential natural gas supply avaiabilty
and pricing;
· revenue requirements on al new asset additions;
· weather assumptions; and
· demad-side management.
Additionaly, we have incorporatedVectorGas™, a
module withn SENDOUTiI, to simulate weather and
price uncertainty. VectorGas™ generates "draws" which
are single data sets (heating degree-days for weather and!
or prices), which can be optized in SENDOUTiI to
provide a probabilty distribution of results from which
decisions can be made. Some exaples of the analyses
VectorGas™ provides include:
· probabilty distributions of price and weather;
· probabilty distributions of costs (i.e. system cost,
storage costs and commodity costs);
· resource mi (optiy sizing a contract or asset
level for various and competing resources); and
· hedging percentages.
DEMAND AND SCENARIOS
Our approach to demand forecasting focuses on
customer growth and use per customer as the base
components of demad. We considered various factors
that infuence these components, includig population
and employment trends, age and income demographics,
natural ga prices, price elasticity and use per customer
trends. We used this information to develop low; medium
and high customer growth scenarios crossed with low,
medium and high price scenarios. Based on input from
the TAC, three main cases were selected for further
review; Table 1.1 summizes the three cases, including
the customer growth and price elasticity assumptions
included in the scenarios. Throughout this document
these three cases are referenced as the Expected Case, the
High Demand Case and the Low Demad Case. The
high and low cases do not represent the maum or
minimum bounds of possible cases, but frame a broad
range of liely demand scenarios that could occur.
Table 1.1 - Demand Scenarios
High Demand Case - High Expected Case - Base demand Low Demand Case - Low
demand and low price scenario.and mid pnce scenario. Static use demand and high price scenario.
50% increase in customer growth per customer over the planning 50% decrease in customer growth
and a price elasticity adjustment to horizon.and a price elasticity adjustment to
demand coeffcients (-.13).demand coeffcients (-.13).
1.2 AvistaCorp2007 Natural Gas IRP
...........................................
...........................................
Chapter 1 - Executive Summary
The demand forecast from the Expected Case revealed:
· The number of system-wide core customers is
expected to increase from an average of315,200
in 2007-2008 to 494,900 in 2026-2027. This is an
annual average growth rate of 2.4 percent.
· Average day, system-wide core demand, net
of model-selected demand-side magement
measures, is projected to increase from an average
of 95,400 Dekatherms per day (Dth/day) in
2007-2008 to 139,500 Dth/day in 2026-2027.
This is an annual average growt rate of 2 percent.
· Coincidental peak day, system-wide core demand,
net of model-selected demad-side maagement
measures, is projected to increase from a peak of
361,900 Dth/day in 2007-2008 to 535,700 Dthl
day in 2026-2027. This is a growth rate of over
2.1 percent in peak day requirements.
Detais of the demand forecast for our High and Low
Demand cases can be found in Appendi 2.4
Figure 1.1 shows forecasted system-wide average peak
day demad per year for the three man scenarios over
the planning horizon.
NATURAL GAS PRICE FORECASTS
The natural gas market has dramaticaly changed over the
last several years as it has tranitioned from a regional to a
national or perhaps global market. Regiona and national
natural gas prices since 2005 have experienced increased
volatity. Demand growt, natural ga use for electric
generation, hurricane activity and other weather events
are believed to be some of the reasons for the increased
price volatility Additionaly, the continuing trend of
heightened oil price volatity from geopolitical and
global supply I demad issues remas an infuence. The
industr has also observed higher natural ga price levels
since 2005. This new price level stems from the tight
production and productive capacity balance, as well as
the increasing costs of natural gas production. Although
we do not believe that we can accurately predict future
prices for the 20-year horizon of this IRp, we have
reviewed several price forecasts from credible sources, and
we have selected high, medium and low price forecasts
to represent reasonable pricing possibilties. Figure 1.2
depicts the selected price forecasts.
Figure 1.1 . System Wide Peak Day Demand
(Net of DSM Savings)
.-
-Â
---...--
--~-~-
700
600
500
i: 400
~
:: 300
200
100
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I-+ Expected Demand _ Low Demand ~ High Demand I
AvistaCorp 1.32007 Natural Gas IRP
Chapter 1 - Executive Summary
Figure 1.2 . Henry Hub Forward Prices
2007$/Dth
$12.00
$11.00
$10.00
$9.00
$8.00
$7.00
§ $6.00
$5.00
$4.00
$3.00
$2.00
$1.00
$0.00 ~~~~~~~~~~ ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~
1-- Low-AEO/Consultant 2 -+ Medium-NymexlConsultant 1 -- High-Nymex I
-"-_.,-..-
_.._.---~-_...._-_.,~_...._-~---_.._.._._--_._-_.----~..~~---:.--~
.-
--~------~---_._--_._----,._._----
---_._-----.
RESOURCES SENDOUTil model selected certain DSM measures for
further review and implementation.Avista has a diversifed portfolio of natural gas supply
resources, including owned and contracted storage,
firm capacity rights on five pipelies and contracts to
purchase natural ga from several dierent supply basins.
In our IRP process we model a number of conservation
measures or programs that reduce demand if they
prove to be cost effective. We also model incremental
pipeline transportation, storage options, distribution
enhancements and various forms of liquefied natural ga
(LNG) storage or servce.
RESOURCE NEEDS
The SENDOUTil model was run utizing existing
resources and the three demand cases to determie if
resource deficiencies exist during the planning period.
In the Expected Case for Washington and Idao, the first
deficiency is in 2014-2015. Given this timing, we have
suffcient time to carefully monitor, plan and take action
on potential resource additions. We also plan to define
and analyze sub-regions within this broad region for
potential resource needs that may materiale earlier than
2014-2015.
DEMAND-SIDE MANAGEMENT
Avista actively promotes and offers energy-effciency
program to our natural gas customers. These demad-
side management (DSM) programs are one component
of a comprehensive strategy to provide our customers
with a best cost/risk energy resource. The IRP is an
opportunity to evaluate this resource mi to refine
approaches to the maagement of both supply-side and
demad-side management resources.
In the Expected Case for Oregon, the first capacity
deficiency is in Klamth Fals in 2011-2012. The other
Oregon areas become capacity deficient in 2013-2014.
Given ths ting, we are actively assessing our Action
Plan around potential resource additions.
Based on the projected natural gas prices and the
estimated cost of alternative supply resources, the
1.4 2007 Natural Gas IRP AvistaCorp
...........................................
...........................................
Chapter 1 - Executive Summary
400,000
350,000
300,000
250,000
=200,000c
150,000
100,000
50,000
Figure 1.3 . WAIID Existing Resources VS. Peak Day Demand
(Net of DSM Savings) Expected Case - November through October
-..-
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_ Existing GTN _Existing TF-1 _ Existing TF-2 -+ Peak Day Demand
200,000
180,000
160,000
140,000
120,000
5 100,000
80,000
60,000
40,000
20,000
0
Figure 1.4 . OR Existing Resources VS. Peak Day Demand
(Net of DSM Savings) Expected Case - November through October
--
=----------------¡-f-f-f-f-----------------f-I-I-
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- Existing GTN _ Existing TF-1 _ Existing TF.2 _Existing Wil Peaking _ Backhaul Mad Lat -+Peak Day Demand
Figures 1.3 and 1.4 compare existing peak day resources
to expected peak day demad and show the ting and
extent of resource deficiencies for the Expected Case.
We identified possible resource options and placed those
options into the SENDOUTiI model to select the best
cost/risk incrementa resources over the 20~year planning
horizon.
AvistaCorp 1.52007 Natural Gas IRP
Chapter 1 - Executive Summary
Figure 1.5 - WAIID Existing & Best Cost/Risk Resources vs. Peak Day Demand
(Net of DSM Savings) Expected Case - November through October
400,000
350,000
300,000
250,000
ts 200,000
150,000
100,000
50,000
0
!
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~Peak Day Demand
Figure 1.6 . OR Existing & Best Cost/Risk Resources vs. Peak Day Demand
(Net of DSM Savings) Expected Case - November through October
200,000
180,000
160,000
140,000
120,000
s:100,000is
80,000
60,000
40,000
20,000
0
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Figures 1.5 and 1.6 depict the best cost/risk portfolio
selected by SENDOUTiI to meet the identified capacity
deficiencies.
As indicated in Figures 1.5 and 1.6, for Washington/
Idaho and Oregon, afer DSM savings the model shows
a general preference for incremental transportation
resources from existing supply basins to resolve capacity
deficiencies.
1.6 2007 Natural Gas IRP AvistaCorp
...........................................
...........................................
Chapter 1 - Executive Summary
SUMMARY OF KEY FINDINGS AND
ACTION ITEMS
Our 2008-2009 Action Plan outlnes the activities
developed by our sta with advice from management and
TAC members. These actions, in many instances, have
aleady begun and will be completed in the next two
years. The purpose of these action items is to position
the company to provide the best cost/risk resource
portfolio, and to support and improve IRP plannng.
Key components of the Action Plan include:
· Refine our specific resource acquisition action
plans for Klamath Fal and Medford servce areas
that address the projected unserved demand in
2011-2012 and 2013-2014, respectively. For
the Klath Fal service territory we intend
to purchase the Klamth Fal Lateral. For
the Medford servce territory our ongoing
distribution system enhancements combined
with an expansion of the Medford Lateral is our
planned resource solution.
· Research and refine the evaluation of resource
alternatives, including implementation risk
factors and tielines, updated cost estites, and
feasibilty assessments, targeting options for the
servce territories with nearer term unserved
demand exposure.
· Explore non-traditional resources to address our
needle-peakng requirements. This review wi
emphasize potential strctured transactions with
neighboring utities and other market participants
that leverage existing regional inastructure as an
alternative to incremental infastructure additions.
· Reevaluate our current peak day weather planning
standard to ascertain if it sti provides the best
risk-adjusted methodology for resource planning.
· Continue our pursuit of cost effective demad-
side solutions to reduce demand. In Oregon
demand-side measures are targeted to reduce
demand by 350,000 therms in the first year. In
Washigton and Idao, demad-side measures
are targeted to reduce demad by over 1,425,000
therms in the first year.
. Define and analyze sub regions within the
Washington/Idao region for potential resource
needs that may materialze earlier than the broader
region indicates.
· Integrate the VectorGas ™ module in our
SENDOU'r modelig softare to strengthen
our abilty to analyze demand impacts under
varng weather and price scenarios as well as
conduct sensitivity analysis to identify quantifY
and maage risk around these demand influencing
components.
· Continue to assess methods for capturing
additional value related to existing storage assets,
including methods of optizing recently recaled
capacity
AvistaCorp 1.72007 Natural Gas IRP
...........................................
Chapter 2 - Demand Forecast
2. DEMAND FORECAST
OVERVIEW and it had assumptions and results that were driven by
national and servce area economic forecasts. Based on
discussions with the TAC about impacts from natural gas
rate increases on use per customer trends, we revised use
per customer assumptions downward for this IRP
Avista served an average of299,300 core natural gas
customers (firm, non transportation customers) with
31,887,000 Dth of natural gas in 2006. By 2026,
Avista projects that it will have approxitely 500,000
core natural gas customers with an annual demand
of over 53,700,000 Dth. In Washington, the number
of customers is projected to increase at an average
annual rate of 2 percent, with demad growing at 1.9
percent per year. In Oregon, the number of customers
is projected to increase at an average annual rate of
2.5 percent, with demad growing at 2.3 percent per
year. In Idao, the number of customers is projected
to increase at an average annual rate of 3 percent, with
demad growig at 3 percent per year.
Avista manages its demad forecast through two distinct
operating divisions - North and South:
· The North Operating Division covers about
26,000 square mies, primrily in eastern
Washigton and northern Idaho. More than
840,000 people live in Avista's Washington/Idaho
servce area. It includes urban areas, farm and
tiberlands, as well as the Coeur d Alene mining
district. Spokane is the largest metropolitan area
with a regional population of approxitely
450,000, followed by the Lewiston, Idaho/
Clarkston, Wash. area and Coeur d Alene, Idaho.
We presented our natural ga forecast to the TAC in
May 2007. This forecast was completed in April 2007,
Avista Corp 2007 Natural Gas IRP 2.1
Chapter 2 - Demand Forecast
The North Operating Division consists of about
74 mies of natural gas transmission mans and
5,000 miles of natural ga distribution mans.
Natural gas is received at more than 40 points
along interstate pipelines and distributed to more
tha 210,000 residential, commercial and industrial
customers.
· The South Operatig Division serves five counties
in Oregon. The population of ths area is over
480,000. The South Operating Division includes
urban areas, farms and timberlands. The Medford,
Ashld and Grants Pass area, located in Jackson
and Josephine Counties, is the largest single
area in Oregon served by Avista, with a regional
population of approximately 280,000. The South
Operating Division consists of about 67 mies of
natural gas transmission mans and 2,000 mies
of natural gas distribution mans. Natural gas is
received at more than 20 points along interstate
pipelines and distributed to more than 90,000
residential, commercial and industrial customers.
DEMAND FORECAST METHODOLOGY
For this IRp, we used our SENDOUTiI model to
produce forecasted demad. The key demand forecast
inputs are forecasts of the number of customers, demand
coeffcients and heating degree-days. The day demand
forecasts are calculated per the formula in Table 2.1.
This calculation is performed daily for each firm
customer class and demand area. The customer classes
are residential, commercial and firm industrial. The
demad areas are Medford, Roseburg, Klamth Fals,
La Grande, Ore. and the eastern Washington/northern
Idao area. The climate and economy in each of these
five areas vary enough to mae a meaningf dierence
in the demad profùes for these areas.
Due to the volatity in natural ga prices, and based on
discussions with the TAC, we have incorporated price
elasticity when determining use per customer. Avista
participated in a national price elasticity study conducted
by the American Gas Association (AGA). The AGA
provided jurisdiction-specific price elasticity estites to
local distribution companies, and we have incorporated
these estimates into our analysis. For the Expected Case
there is no adjustment made for price elasticity, as this
case assumes no change in use per customer over the
planing horizon. For our High and Low Demand
cases a price elasticity factor of negative 0.13 was used to
adjust the demad coeffcients2.
The purpose of the IRP is to balance forecasted demand
with existing and new supply alternatives. Since new
supply sources include conservation resources, which act
as a demand reduction, the demand forecasts described
in this chapter include existig effciency standards
and norma market acceptance levels. Incremental
Table 2.1 - SENDOU-r Demand Calculation
# of Customers x Daily Dth I Base
Usage I Customer
Plus
# of Customers X Daily Dth I Degree-
Day I Customer X # of Daily
Degree-Days
2 This mean that if natural gas prices increase by 10 percent, we would expect customer demand to decrease 1.3 percent (al other factors
being equal). Similarly, a 10 percent decrease in natural gas prices would stimulate a 1.3 percent increase in natural gas consumption.
2.2 2007 Natural Gas IRP AvistaCorp
...........................................
...........................................
Chapter 2 - Demand Forecast
conservation measures modeled are described in the
Demand-Side Management chapter.
CUSTOMER FORECASTS
The foundation of any demand forecast is based on
the number and tyes of customers expected over
the planning horizon. We developed our customer
forecast by startng with national economic forecasts
and then drilng down into regional economies.
Population growt expectations and employment are
the key drivers in regional economies and in ultimately
estimating natura gas customers. Avista contracts with
Global Insight, Inc. for long-term regional economic
forecasts. A description of the Global Insight forecasts
is found in Appendix 2.1. We combined this data, along
with company-specifc knowledge about sub-regional
construction activity trends and historical data to develop
the 20-year customer forecast.
Forecasting customer growth is an inexact science, so it
is important to consider alternatives to this forecast. We
developed two additional outcomes for consideration
in this IRP. During the last 25 years, customer growth
during five-year periods has ranged between one-hal
and one-and-a-hal ties the 25-year average customer
growt rate. Since both patterns have been observed
in the past,Avista has created low 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
al three scenarios can be found in Appendi 2.2.
SUB-AREA FORECASTING AND PLANNING
In response to an action item in our previous IRP we
have incorporated sub-area core customer forecasting
for each municipality and unincorporated county
throughout the three-state servce area. This includes
56 governmental subdivisions (caled "town codes") in
Washington, 26 governmental subdivisions in Idaho and
37 governmenta subdivisions in Oregon.
The anual growth for each state is alocated so that the
total equals the sum of the parts. These 119 separate
town code forecasts are used by the gas distribution
engineering group for optizing decisions within these
geographic sub-areas facilitating integrated forecasting
Figure 2.1 - Customer Growth Scenarios
(Number of Customers by Year)
700,000
600,000
500,000f
~ 400,000
.s~ 300,000u
200,000
100,000
od~~~~~~~~~~~~~ ~~~~~~~~~~~~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
1- WAIID Base tlfllfJfflOR Base - Low Cust. Growth Case - High Cust. Growth Case 1
AvistaCorp 2.32007 Natural Gas IRP
Chapter 2 - Demand Forecast
and planning within the company (see further discussion
in Chapter 4-Distribution Planning).
HEATING DEGREE-DAY DATA
Heatig degree-day data is obtained from the National
Oceanic and Atmospheric Admnistraion (NOAA)
30-year weather study spanning 1971-2000. For Oregon,
Avista uses four weather stations, corresponding to the
areas where natural gas servces are provided. Heating
degree-day weather patterns between these areas are
uncorrelated. For the eastern Washington and northern
Idaho portions of Avista's servce area, weather data
for the Spokane Aiport 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 Chapter 6-Integrated
Resource Portfolio and the actual heating degree-days
used in SENDOUT~ are found in Appendi 6.1.
USE PER CUSTOMER
Use per customer forecasts are based on daiy heating
degree-days, which shape customer use with the seasons'
variation. We use multiple regressions to compute
coeffcients by customer classes. The regression includes
a non-:heat amount (the constant in the regression
often referred to as base-load) and three variables for
heating degree-days. The first heating degree-day
coeffcient is the shoulder-month estimate. This includes
heating degree-days for the months of April, May,June,
September and October. Sumer heating degree-days
are excluded during the air-conditioning months. The
second heatig degree-day coeffcient is the winter-
period estite. This variable includes degree-days for
December,Januar and Februar The third variable
is for March and November. We have found that the
November and March months are more sensitive to
heating degree-days tha the shoulder months, but less
sensitive than the December through February period.
The regression calculations producing these coeffcients
can be found in Appendi 2.3.
The shoulder-month regression coeffcient is about
one-hal the winter-period coeffcient. This means that
a shoulder-month heating degree-day produces about
one-hal as many therms per customer as a winter-
period heating degree-day. The coeffcients are estimated
separately for each area.
Table 2.2 - Demand Coefficients
Residential - WAllO
Commercial - WAllO
Industrial- WAllO
Residential - Medford
Commercial - Medford
Industrial - Medford
Residential - Roseburg
Commercial- Roseburg
Industrial - Roseburg
Residential - Klamath Falls
Commercial - Klamath Falls
Industrial- Klamath Falls
Residential - La Grande
Commericial - La Grande
Industrial - La Grande
Non-Heat
Dth/CustlDay
0.0488
0.3456
7.0856
0.0442
0.3412
0.0346
0.0465
0.3637
15.5022
0.0318
0.3488
0.0892
0.0299
0.2623
56.0680
(Each coeffcient is significant at the 95 percent level)
Shoulder
Dth/CustlDay
0.0059
0.0297
0.0734
0.0073
0.0348
0.0583
0.0077
0.0387
0.4377
0.0041
0.0217
0.0285
0.0057
0.0257
n/a
Nov. & Mar.
Dth/CustlDay
0.0091
0.0458
0.1130
0.0101
0.0483
0.0809
0.0099
0.0499
0.5648
0.0067
0.0355
0.0466
0.0102
0.0455
n/a
Dec..Jan.-Feb.
Dth/CustlDay
0.0104
0.0543
0.1497
0.0117
0.0475
0.0807
0.0117
0.0512
0.4248
0.0084
0.0372
0.0548
0.0122
0.0508
n/a
2.4 AvistaCorp2007 Natural Gas IRP
...........................................
...........................................
Chapter 2 - Demand Forecast
VALIDATION OF COEFFICIENT AND
CUSTOMER GROWTH INFORMATION
The regression-derived heating degree-day coeffcients
are average responses derived over a forecasted 60-month
period. These coeffcients are compared to recalbrated
coeffcients which are derived from a backcast of
actual demad over the previous 12 months. These
recalbrated coeffcients (see Table 2.2) are input into the
SENDOUTiI model to produce a demand forecast. This
demand forecast is compared to the regression coeffcient
derived forecast for reasonableness.
With respect to the customer growth assumptions,
residential customer growt is proportional to population
growt, and commercial customer growt is proportional
to employment growth. This ensures that the company-
specifc customer forecasts are algned with the regional
and national economic forecasts.
DEMAND FORECAST
Increased natural gas price volatility has made it more
diffcult to project (or predict) future natura gas prices.
We acknowledge changing price levels infuence usage,
so we incorporated a price elasticity of demand factor
into our model to alow use per customer to vary as our
natural gas price forecast changes (See Table 2.3). From
our participation in the American Gas Association's price
elasticity study, we received regional elasticity factors
which compared favorably to our past estites. Based
on this corroboration, we used a factor of negative 0.13
in our process.
This means that if natural gas prices increase by 10
percent, we would expect customer demad to decrease
1.3 percent (al other factors being equal). Simlarly, a
10 percent decrease in natural gas prices would stiulate
a 1.3 percent increase in gas consumption. (The price-
related elasticity factors are calculated for the High
and Low Demad scenarios by indexing the prices to
2007 and applying the negative 0.13 to the percentage)
We calculated customer response for each scenario by
adjusting the demand coeffcients shown in Table 2.2 by
the specific price-related elasticity factors. The High and
Low Demand forecasts utize the elaticity assumption
and the natural gas price curves discussed in Chapter 6,
Figure 6.14
DEMAND SCENARIOS
Our approach to demand forecasting focuses on
customer growth and use per customer as the base
components of demad. Other factors that infuence
these components were considered, such as population
and employment trends, age and income demographics,
natura gas prices, price elasticity and use per customer
trends. Three main cases were selected for further
analysis. Table 2.3 summrizes the thee cases, including
the customer growth and price elaticity assumptions.
The High and Low Demand cases do not represent the
mamum and minium bounds of possible cases, but
frame a broad range of scenaios that could occur.
Table 2.3 - Demand Scenarios
High Demand Case - High Expected Case - Base demand Low Demand Case - Low
demand and low price scenario.and mid price scenario. Static use demand and high price scenario.
50% increase in customer growth per customer over the planning 50% decrease in customer growth
and a price elasticity adjustment to horizon.and a price elasticity adjustment to
demand coeffcients (-.13).demand coeffcients (-.13).
AvistaCorp 2.52007 Natural Gas IRP
Chapter 2 - Demand Forecast
Figure 2.2 . WAIID Actual Average Daily Demand vs. Forecasted Average Daily Demand
(Net of DSM Savings)
140
---,.---~-
.
~......~-
..-.-
~.---~-~--~--~"---
120
100
~::
80
60
40
20
o# # # # # # ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ # $ # #g~¿ #~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~#~ #####~###~~~##~#######
1-- Low Demand -+ Expected Demand -. High Demand I
Figure 2.3 . OR Actual Average Daily Demand vs. Forecasted Average Daily Demand
(Net of DSM Savings)
~::
50
45
40
35
30
25
20
15
10
5
--~~~..-~----
~ -..----
_._.~-~--"-"'--.-
# # # # # # ~ ~ ~~ ~ ~ ~ ~ ~ ~ # $ ## d # # #~ ~~~~~~~~~~ ~~~~~~~~~~ ~~~# # # # # # ~ ~ # # # ~ ~ ~ # # ~ #######
1__ Low Demand -+ Expected Demand -. High Demand 1
RESULTS
Figures 2.2 and 2.3 show Washington/Idaho and Oregon
historical and forecasted demand for the Expected, Low
and High Demad cases on an average day basis for each
year.
Figures 2.4 and 2.5 show Washington/Idaho and Oregon
forecasted demad for the Expected, Low and High
Demand cases on a peak day basis for each year.
2.6 2007 Natural Gas IRP AvistaCorp
...........................................
...........................................
Chapter 2 - Demand Forecast
500
450
400
350
300
~250:¡:E 200
150
100
50
Figure 2.4 - WAIID Peak Day Demand
(Net of DSM Savings)
.-.i---_..._--.-~.i-::.-..--&.-~--
# # ~ ~ ~ # ~ # ~ ~ ~ ~ # ~ # #g #gff,,~ !1~ Pf~ rf~ "'~ ~~ "5~ ~~ l,:? t(~ ~~ q? O:~ rf~ "'~ n? f'" ~~ f;" (("~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ #######
j-+ Expected Demand __ Low Demand ~ High Demand I
200
180
160
140
120
~ 100
:E 80
60
40
20
Figure 2.5 . OR Peak Day Demand
(Net of DSM Savings)
.------
-'f--.-..---
# # ~ ~ ~ # ~ # ~ ~ ~ ~ # ~ # gß ß?~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~" ,J"~" N"~"~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ # # ~v# # # #
I-+ Expected Demand -- Low Demand ~ High Demand j
Table 2.4 depicts anual average demad percentage
increases by class of customer and area for the Expected,
Low and High Demad cases for the 20-year planning
period.
Additiona detaied data depicting annual and peak day
demand data is in Appendix 2.4.
AvistaCorp 2.72007 Natural Gas IRP
Chapter 2 - Demand Forecast
Table 2.4 - Annual Average Demand Percentage Increases
November 2007 through October 2028
ResidentialArea
Expected Case
Klamath Falls
La Grande
Medford
Medford NWP
Roseburg
OR Sub-total
Spokane Both
Spokane GTN
Spokane NWP
WAllO Sub-total
Expected Case Total
Low Demand Case
Klamath Falls
La Grande
Medford
Medford NWP
Roseburg
OR Sub-total
Spokane Both
Spokane GTN
Spokane NWP
WAllO Sub-total
Low Demand Case Total
High Demand Case
Klamath Falls
La Grande
Medford
Medford NWP
Roseburg
OR Sub-total
Spokane Both
Spokane GTN
Spokane NWP
WAllO Sub-total
High Demand Case Total
2.38%
1.43%
3.57%
2.60%
2.60%
2.52%
2.37%
2.37%
2.37%
2.37%
2.44%
1.32%
0.76%
2.08%
1.46%
1.46%
1.42%
1.33%
1.33%
1.33%
1.33%
1.37%
3.26%
2.03%
4.74%
3.72%
3.72%
3.50%
3.23%
3.23%
3.23%
3.23%
3.36%
Commercial Firm Industrial Total
1.37%0.00%1.82%
0.47%0.00%0.87%
1.63%0.00%2.01%
1.34%nfa 2.01%
1.34%nfa 2.60%
1.23%0.00%1.99%
2.26%1.16%2.03%
2.26%1.16%2.04%
2.26%1.16%2.04%
2.26%1.16%2.04%
1.74%0.58%2.02%
0.73%0.00%0.76%
0.24%0.00%0.23%
0.88%0.00%0.91%
0.72%nfa 0.91%
0.72%nfa 1.29%
0.66%0.00%0.89%
1.26%0.64%0.83%
1.26%0.64%0.84%
1.26%0.64%0.84%
1.26%0.64%0.83%
0.96%0.32%0.85%
1.94%0.00%2.56%
0.69%0.00%1.17%
2.28%0.00%2.79%
2.05%nfa 2.80%
2.05%nfa 3.53%
1.80%0.00%2.74%
3.08%1.60%2.87%
3.08%1.60%2.87%
3.08%1.60%2.87%
3.08%1.60%2.87%
2.44%0.80%2.84%
ACTION ITEMS
The above approach to forecasting demand uses a
determistic modeling methodology. Although it
provides a reasonable basis for developing demad cases,
we are alo exaning the capabilties ofVectorGas TM, a
Monte Carlo simulation module of our SENDOUTI\
modeling softare which facilitates modeling of price
and weather uncertainty. We intend to use this tool
to refine our forecasting capability with a focus on
developing sensitivity anysis to identify, quantify and
manage risk around price and weather as determiants of
natural gas demad. Chapter 6 discusses VectorGas™ in
more deta, including preliminary alternative modeling
results.
We wi also study ways to further refine our abilty to
model demand by region. Town code forecasting was the
first step in enhancing our demad forecasting. We now
want to explore incorporating these town code forecasts
into regions for analysis in SENDOUTI\ especialy
within the Washington/Idaho division to investigate
potential resource needs that may materiale earlier than
the broader region indicates.
2.8 AvistaCorp2007 Natural Gas IRP
...........................................
...........................................
Chapter 2 - Demand Forecast
CONCLUSION
Through the scenario planning process, we have
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. Whe we recognze that the actual level of demand
is dependent on a variety of factors, reviewing a range of
potential outcomes alows us to plan more effectively as
economic or pricing conditions change.
AvistaCorp 2007 Natural Gas IRP 2.9
...........................................
3.DEMAND-SIDE MANAGEMENT
Chapter 3 - Demand-Side Management
OVERVIEW METHODOLOGY
Avista's DSM function is organizationaly split into a
North division (Washington and Idaho), and a South
division (Oregon). The Oregon division is segmented
into four delivery areas while the Washington/
Idaho division is one delivery area consistent with
SENDOUTiI modeling requirements.
The anaysis in this IRP is the first step in identifyng
cost-effective natural gas effciency measures. Following
this analysis we will review the DSM portolio and
incorporate refinements and additional analysis of
measures, revisions to existig and prospective program
plans, and the potential termination of measures that are
determined to be no longer cost-effective. This process
includes a determiation of the opti approach to each
identified cost-effective measure to include the potential
for cooperative acquisition or market transformation
efforts.
It is possible that there wi be measures selected in
this IRP tht wi subsequently be determied to be
unsuitable in the company's DSM portfolio based on
post-IRP analysis, implementation plannng and program
plannng efforts. It is also possible that programs could
be developed for measures rejected by this IRP as a
result of the same process. Though the IRP is our best
opportunity to comprehensively reevaluate the DSM
portfolio and its integration into the overal resource mi,
it is necessar to incorporate an ongoing implementation
plannng process to make the best resource decisions.
Avista is commtted to achieving al natura gas-
effciency measures that can be cost-effectively acquired
through intervention. This commtment supersedes
any numerical goals established within the IRP or the
company's implementation planning efforts.
The development of a methodology for evaluating DSM
within the IRP was based on four key requirements. The
analysis must:
· provide a comprehensive evaluation of al
signficant natural gas-effciency options that are
commercialy avaiable;
. evaluate natura gas-effciency options in an
interactive process with supply-side options;
· maze portolio net total resource value;
· deliver meanngf and actionable analytcal results
for the DSM implementation planng process.
The methodology adopted to fulfil these requirements
has four phases:
· Measure identification and characterization
- We first identied al existing DSM program,
measures considered in previous IRPs, and other
concepts evaluated or considered in the last two
years;
· Preliminar evauation - We then calculated
the levelized total resource cost of each measure
(including non-energy benefits as offsets
to measure cost), ranked the measures, and
categorized them as follows:
· Oregon-madated residential measures ("must
take" measures);
· Clearly cost-effective measures ("green"
measures);
· Clearly non-cost-effective measures ("red"
measures);
· Al remaning measures ("yellow" measures).
· SENDOUT'I testing - The "must take" and
"green" measures were loaded into SENDOUT'I
as madatory programs to be automaticaly
selected. "Yellow" measures were input and
evaluated by SENDOUTil against other supply-
side resource options. We also input into
SENDOUTil an indexed estiate of unique
AvistaCorp 3.12007 Natural Gas IRP
Chapter 3 - Demand-Side Management
measures (predominately achieved through
a customized application of the site-specific
program) that cannot be characterized for testing
withn SENDOUTiI. Finaly, "red" measures are
excluded from SENDOUTiI analysis.
. Acquisition goal development - In the last
phase, we augmented the results ofSENDOUTiI
with estimates of resource acquisition that cannot
be characterized and modeled in SENDOUTiI.
The final result is the resource acquisition
level used in implementation plannng efforts.
Additional analysis, implementation planning,
development of regional and ad hoc partnerships,
and local DSM program implementation efforts
are initiated from the findings in this IRP. These
efforts may modify the findings contaned in this
IRP based on improved information and the
tiely assessment ofDSM opportunities.
The DSM methodology is summrized in the flowchar
in Figure 3.1. Details of each phase follows.
PHASE ONE; MEASURE IDENTIFICATION
AND CHARACTERIZATION
We updated previous IRP research, provided by RLW
Analytcs, with new information regarding measure cost
and energy savings and augmented that measure list with
additional measures not previously evaluated. A total
of 43 residential and 47 non-residential measures were
tested for ths IRP This represents an expansion of the
number of measures tested from the 2006 IRP given
that each of these measures was generaly unique, rather
tha defined as new constrction, replacement-before-
burnout or replacement-afer-burnout.
A summry of the measures that were tested is contaned
in Appendix 6.9. Energy effciency, incremental cost and
Figure 3.1 - Integration of DSM within the IRP
Develop energ
savings & NEB's
Asses market
charactñsics
& past program
reults
REPRESENTED WITHIN THE IRP PROCESS
OUTSIDE OF THE SCOPE OF THE IRP PROCESS
Initiate reional market
trnsfrmtion efrt
Develop ad hoc
ag..ments
. Identifing measure to portolios
. Index to historic acquisition as appropriate
. Manually modif programs as appropriate
Review existing DSM
Implementation plan
Initiate new programs.
Continue, modif or
terminate exiting programs
3.2 AvistaCorp2007 Natural Gas IRP
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Chapter 3 - Demand-Side Management
other measure characteristics were generaly evaluated
in comparison to industr standards or code miums,
whichever was higher.
Each tested measure included an assessment of the
acquirable resource potential. These estimates were
based on early projections of the best implementation
approach for parcular technologies, maket segments
and the expected growth of those makets. These
projections could require signcant revision based on
further development of these program plans during the
implementation planng process, and on opportunities
created by interactions and packaging options created by
the mi of program included in the final analysis.
The energy savings data for weather-sensitive measures
were adjusted for the four Oregon delivery areas
(Medford, Klamth, Roseburg and La Grande) and the
one delivery area in the North division (Washington/
Idaho) servce territory based on heating degree-day data
appropriate to each geographic area.
Avista DSM engineers, program implementers and
analysts developed estites of incremental measure
costs, measure lives, energy savings, and other inputs and
assumptions in the evaluation process. Great care was
taen to ensure symetric treatment of the costs and
benefits of base case and high-effciency scenarios for
each measure given that resource selection is known to
be highly sensitive to errors in these assumptions.
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 effciency). The energy
savings of individual measures wi be reviewed again in
the program plang phase to determne if there is any
need for reducing the per-unit savings to account for
interactive effects between measures.
Program implementation staf estimated incremental
non-incentive utity costs for each measure. Since it
was assumed that there would be a substantial portolio
of measures passing the total resource cost (TRC)
test, the incremental utility cost was generaly low or
zero. This reflects the incremental utity admnistrative
cost associated with incorporating an individual DSM
measure or program into a pre-existing portfolio of cost-
AvistaCorp 3.32007 Natural Gas IRP
Chapter 3 - Demand-Side Management
effective program. This approach has been previously
presented to the TAC and others as a "sub- TRC" test, as
it excludes one cost element (fixed non-incentive utity
cost) that is tyicaly 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. Replacement
measures were evaluated based on the assumption that
the existing equipment was in a state of immnent failure
(within one year of a physical faiure that would render
the equipment uneconomic to repair).
Discussions in preparation for program design often
identied the targetig of replacement-shortly-before-
burnout as an attactive maket segment given the greatly
reduced likeliood of customer instalation of effcient
equipment when the customer is without water or space
heating. This topic and its relationship to techncal and
economic potential therm acquisition wi be revisited
later in the IRp, and during implementation planng
and program development.
Climatic dierences between delivery areas was one of
the key elements applied to leverage the measurement
and evaluation efforts among the two divisions and
eight delivery areas. The estimated savings of weather-
dependent effciency measures are generaly dependent
on the heating degree-days of each delivery area (see
Table 3.1), though they are also infuenced by the end-
use inventory, floor stock vintage and prevang energy
codes.
Table 3.1 . Heating Degree-Days by Delivery Area
ANNUAL HODs
Oregon
Klamath Falls
LaGrande
Meford
Roseburg
Washington/Idaho
Spokane
7,135
6,654
4,766
4,240
7,097
HDDs: Heating degree-days
We have traditionaly 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 were incorporated into the analysis as
an adjustment to the incremental cost of the measure.
This assumes that part of the premium that the customer
is purchasing in the incremental cost of a high-effciency
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-effciency 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.
Non-energy benefits reduce the cost associated with
the energy-effciency investment. Within the set of
measures analyzed for this IRP the primary quantifiable
non-energy benefits were from measures with signcant
water savings.
PHASE TWO; PRELIMINARY EVALUATION
Based on the incrementa customer cost, incremental
non-incentive utity 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 measure. Detaied
information on each program can be found in Appendi
6.10. This calculation alowed for the comparison of
costs across measures with varyng measure lives, and was
the foundation for the measure and program selection
and portfolio optimization.
This analysis was supplemented with estimates of the
full TRC levelized costs (including those that were not
incremental to the program) to provide estites of
long-term portfolio cost-effectiveness. This information
was used as a diagnostic tool to understand 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 overal
portfolio.
AvistaCorp2007 Natural Gas IRP3.4
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Chapter 3 - Demand-Side Management
This preliminar evaluation used a spreadsheet model to
permit easy data manipulation. This process identified
data elements that were out of the norm or in need of
further research, the calculation of a number of different
diagnostic statistics and testing measures and program
under alternative approaches to program plannng. It also
reduced the effort necessary to reformat the results of
each program entered into SENDOUTiI.
In the final analysis, a levelized TRC was calculated for
each measure. This became the most critical element
in determining the future treatment of the measure in
the IRP anysis. Those measures which were either
mandated in Oregon or were so clearly cost-effective
that they were certai to be adopted by SENDOUTi
were labeled and manualy incorporated into the modeL.
Those annual load shape measures (e.g. residential water
heating-tye load shapes) with a levelized TRC oUO.50
or less were considered clearly cost-effective or "green"
in our color-coding methodology. Winter load shape
measures (e.g. residential space heating-tye load shapes)
with a levelized TRC of$0.60 or less were considered
"green" in the methodology
In contrast with the "green" and "must take" resource
options that were maualy included into the resource
selection, there were also measures that were so clearly
cost-ineffective that further analysis was unnecessar
Those anual load shape measures with a levelized TRC
oU1.00 or more ($1.20 or more for winter load shape
measures) were excluded from further consideration.
These have been characterized as the "red" program.
The avoided cost levels established for this categorization
ofDSM measures was based on a combination of past
avoided cost levels and expectations of the avoided cost
level to be developed through SENDOUTiI modeling.
This is a subjective process. Retrospective errors in the
avoided cost bandwidths used in this categorization
wi be corrected in the more detaied and actionable
assessment during the DSM implementation process
immediately following the completion of the IRP.
The manual inclusion or omission of measures is
necessar to lit the number of options incorporated
in the linear programng process performed by
SENDOUTiI. Each additional resource option adds
exponentialy to the model's calculation tie. Given that
each DSM measure needs to be subdivided into eight
delivery areas for the model, the wholesale inclusion
of al of the original DSM options would have made
the SENDOUTi analysis an exceptionaly diffcult or
perhaps impossible task.
Forty-two measures were designted as "green" and
maualy incorporated into the final SENDOUTiI
Washington/Idaho portfolio. An additional 21 "yellow"
measures were individualy tested, al of which were
accepted by SENDOUTiI in 200712008 and beyond.
The remaning 27 "red" measures were excluded from
further consideration.
Table 3.2 summizes the madated or tested measures
for Washington/Idao. Therms have been adjusted
upward for customer load growth prior to being entered
into SENDOUTiI.
Table 3.2 - Program Categorization Matrix WAllO
Mandated
"Green" measures
"Yellow" measures
"Red" measures
Residential
Measures
o
15
13
15
Residential
Therms
o
581,968
471,773
NA
Non-residential
Measures
o
27
8
12
Non-residential
Therms
o
70,088
4,658
NA
Mandated
"Green" measures
"Yellow" measures
"Red" measures
There were four mandated residential measures in
Oregon and an additional 42 "green" measures manualy
incorporated into the portfolio. These measures include
pre-rinse sprayers, a measure which is currently being
AvistaCorp 3.52007 Natural Gas IRP
Chapter 3 - Demand-Side Management
pursued with a known goal and impendig sunset date,
which necessitated an adjustment to the SENDOU~
results to establish a meanngf goal. Fifeen measures
were designted "yellow" for explicit testing within
SENDOUTil. Nine measures passed in al delivery areas,
five passed in some delivery areas and one failed in al
delivery areas in 200712008. The remaning 19 "red"
measures were not tested in SENDOUTil. Table 3.3
summrizes the mandated or tested measures for Oregon.
Table 3.3 - Program Categorization Matrix OR
Mandated
"Green" measures
"Yellow" measures
"Red" measures
Residential
Measures
4
13
6
10
Residential
Therms
18,510
82,380
14,922
NA
Non.residential
Measures
o
29
9
9
Non-residential
Therms
o
94,070
2,461
NA
Mandated
"Green" measures
"Yellow" measures
"Red" measures
Passing and many non-passing measures are reviewed in
the DSM implementation process. The development of
measure packages, improved information and refinement
of implementation plans can infuence the cost-
effectiveness of measures.
PHASE THREE; SENDOUTG TESTING
Based on the preceding measure chaacteriation and
categorization, the process of preparing the data for
SENDOUTil testing consisted of:
1. collpsing al "madated" and "green" measure
categorizations into two line items for winter and
annual load shape measures;
2. specifyng al "yellow" categorized measures for
SENDOUTil;
3. translating al measures to be incorporated into
SENDOUTil (including those included on a
"must take" basis) into the units appropriate for
the modeL.
This process is more chalenging than the summry
indicates. The DSM modules of resource planning
linear program are notable for their lack of user-
friendlness and marginal technical support. Errors in
unit specifcation or documentation of the program can
easily result in meaningless results for the entire resource
integration effort.
To minize the potential for errors in this process we
performed prelimina testing of the model by running
SENDOUTil using measures with known results. Two
"green" and two "red" measures from each division were
incorporated in test runs. As expected, the two "green"
measures were accepted by the model and the two
"red" measures were rejected. In addition to providing
confidence that the measures were being correcdy
specified this also confirmed that the avoided cost break-
points used to distinguish" green", "yellow" and "red"
categorizations were withi reason.
The SENDOUTil-accepted DSM resources are
summized in table 3.4. The results do not include the
existing pre-rinse sprayer program or non-residential site-
specific measures that were unable to be characterized
for input into SENDOUTil. These measures are
incorporated in the next phase of the IRP process,
along with other adjustments, to develop anual therm
acquisition goals.
Table 3.4 . SENDOUTI DSM Results
(calendar year 2008)
WAllO
1,106,912
75,792
1,182,704
Oregon
123,491
26,498
149,989
Total adopted measures
Adopted non-residential measures
Total adopted measures
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Chapter 3 - Demand-Side Management
PHASE FOUR; ACQUISITION GOAL DEVELOPMENT
This final phase is critical to translating SENDOUTQ
results into a product that can be used for calendar
years 2008 and 2009 detaied DSM implementation
plannng, as well as for longer-term and higher-level
business planning over a 10-year horizon. Additions
and modifications to the raw SENDOUTQJ results are
required for several reasons.
The greatest modification necessar is the addition to
SENDOUTQJ results of resource acquisition expected
for measures that could not be characterized within
SENDOUTQJ. This consists primrily of non-residential
measures pursued through the site-specific programs
of both divisions. Site-specifc program have been
designed to be al-inclusive, so any natural gas-effciency
measure qualifes for the progra in some fashion.
Direct finacial incentives are contigent upon minimum
project simple-payback criteria in the North division
and a TRC cost-effectiveness test in the South division.
Generaly speakng, al projects have the potential for
receiving technical assistance and may qualfy for direct
fInancial assistance.
The site-specific program acquisition was addressed by
establishing a historical baseline for site-specifc program
results and modifyng those results for past and future
growth. These throughput expectations were based on
the forecast embedded in the SENDOUTQJ assumptions.
Initial review indicated that the dierences in growth
between delivery areas and customer segment (residential
vs. non-residential) were suffciently imaterial to justi
the use of a single 2.8 percent customer growth rate
assumption.
Based on ths approach, we expect site-specific
acquisition of903,000 therms in the North division and
56,800 therms in the South division. These estimates
incorporate consideration of the significantly different
nature of our Oregon non-residential customer base;
that the retai customers in Oregon are smaer-sized
companes and generaly non-industrial. We are in
the process of enhancing our Oregon infrastrctures
capabilty to acquire resources through the site-specific
program by redeploying existing utility staff, establishig
relationships with outside energy auditors, the Energy
Trust of Oregon and trade aly networks.
The North division site-specific program has been a
highly successful component of the overal portfolio.
There is relatively little abilty to enhance ths capabilty,
though active and real-tie management is necessar to
shift the focus toward new opportnities in this market.
The expected therm acquisition is based on a thee-year
(2004 though 2006 inclusive) historical level adjusted for
customer growth.
A final adjustment must be made to the non-residential
sector to elinate the duplication of resource
opportunities between the al-inclusive site-specific
program and the measures accepted in the SENDOUTQJ
modeling. Both divisions permit and pursue acquisition
of al cost-effective, non-residential measures through
the appropriate program. Thus, some of the measures
incorporated into the SENDOUTQJ model, either
on a "must take" or an explicitly tested maer, are
duplicative of resource acquisition incorporated into the
estimates of site-specific resource acquisition. Based on
a review of the SENDOUTQJ accepted measures and
the expectations of site-specific program targets, we
estimated that 5 percent of the Oregon and 20 percent
of the Washigton/Idaho future site-specifc therm
acquisition were included in the SENDOUTQJ analysis.
These amounts are subjective, to the extent that they
involve projectig the future site-specifc program target
makets and success within those markets. Ultimately
an adjustment in the amounts indicated above was
made to the overal non-residential throughput of each
jurisdiction to avoid double-counting non-residential
opportunities.
AvistaCorp 3.72007 Natural Gas IRP
Chapter 3 - Demand-Side Management
As noted in Table 3.4, pre-rinse sprayers were removed
from the SENDOUTI) results due to the pre-
existing program for that measure in both divisions.
Implementation of both programs has been outsourced,
and it provides the opportunity to exchange a lower-
effciency sprayer head with the code-complying higher-
effciency replacement. This has been designed as a
two-year program to accelerate the retirement of sprayers
that are not in compliance with new code standards. The
North division program is scheduled to end in 2007 and
was not tested in SENDOUTI). The Oregon program
terminates in 2008 and was tested and accepted in
SENDOUTI) but removed from the results for separte
treatment to ensure that the program termination dates
align with the calendar year goals to be established as part
of ths IRP.
There has been no attempt to adjust either division for
price elaticity This is because the lack of precedent
for increases in retai rates of the magntude we have
seen, the complicated lag effects and the effect of both
of these on the inventory of cost-effective effciency
opportunities in the market mae it virtualy impossible
to develop any adjustment that can be applied with
confdence. Additionaly, there is inadequate evidence to
determie with any certainty the effects of retai prices
on the throughput ofDSM programs versus simple
reductions in consumption of non-utility sponsored
effciency measures.
The results of the SENDOUTI) model required a
minor revision to translate into the calendar year
implementation planning and budgeting cycle used
for DSM operations. Additionay, a customer growt
rate consistent with that applied in the IRP was used
to adjust historical numbers to reflect current potential
and to increase future potentials of program that were
outside the scope ofSENDOUTi (e.g. the site-specifc
progra).
An application of the SENDOUTI) results and
modifications for site-specific and pre-rinse sprayer
program for the first two years (the years prior to the
next IRP opportunity to revisit DSM potentials) are
summized in Table 3.5.
Table 3.5 . Results of Acquirable Resource Potential
(CY 2008 and CY 2009)
SENDOUT(8accepted residential programs
SENDOUT(8accepted non-residential programs
Estimated site-specific acquisition
Adjustment for non-res program duplication
Estimated pre-rinse sprayer acquisition
TOTAL
SENDOUT(8accepted residential programs
SENDOUTcI-accepted non-residential programs
Estimated site-specifc acquisition
Adjustment for non-res program duplication
Estimated pre-rinse sprayer acquistion
Enhanced commercial! industrial delivery
TOTAL
WAllO
CY2008
1,106,912
75,792
902,837
-60,634
o
2,024,908
WAllO
CY2009
1,176,325
77,914
928,116
-62,331
o
2,120,024
Oregon
CY2008
123,491
26,498
56,808
-2,650
70,400
75,000
349,548
Oregon
CY2009
140,381
27,240
58,399
-2,724
o
75,000
298,295
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Chapter 3 - Demand-Side Management
The Washington/Idaho potential is in excess of the
current acquisition goal of 1,062,000 therms developed
in the 2006 IRP It is also substantialy above the recent
acquisition history of 1,111,000 therms per year (based
on the 2004-2006 acquisition, inclusively). The potential
increase in costs associated with such a lage increase in
infastructure necessary to accommodate the 84 percent
increase from previous acquisition to meet ths identied
potential is concerning. Consequently, we have resolved
to meet al cumulative potential identified in this IRP
over the long-term (10-year) plannng cycle with a
gradual ramping of program activity. We determined
it was possible to establish an 11 percent constraint on
the annual increase whie simultaneously achieving
this objective. This increase is in excess of customer
growth but ensures that the infastructure growth can be
managed more carefully and without undue infation of
acquisition costs associated with rapid growt.
Application of this 11 percent annual growth constraint
results in a summ of annual and cumulative
acquisition and identified DSM potential as listed in
Table 3.6.
,
Table 3.6 . Annual and Cumulative DSM Acquisition and Potential
Washington ¡Idaho
Calendar DSM Cumulative DSM CumulativeYearPotentialPotentialGoalGoalCY20082,024,908 2,047,645 1,425,070 1,425,070CY20092,120,024 4,144,932 1,581,828 3,006,898CY20102,179,385 6,324,317 1,755,829 4,762,727CY 2011 2,240,408 8,564,724 1,948,970 6,711,698CY20122,303,139 10,867,863 2,163,357 8,875,055CY20132,367,627 13,235,490 2,401,326 11,276,381CY20142,433,921 15,669,411 2,665,472 13,941,853CY20152,502,070 18,171,481 2,958,674 16,900,527CY20162,572,128 20,743,609 3,284,128 20,184,655CY20172,644,148 23,387,757 3,203,102 23,387,757
Oregon
Calendar DSM Cumulative DSM CumulativeYearPotentialPotentialGoalGoalCY2008349,548 349,548 349,548 349,548CY2009298,295 647,843 298,295 647,843CY2010304,548 952,391 304,548 952,391CY2011310,975 1,263,366 310,975 1,263,366CY2012317,582 1,580,948 317,582 1,580,948CY2013324,375 1,905,323 324,375 1,905,323CY2014331,357 2,236,680 331,357 2,236,680CY2015338,535 2,575,215 338,535 2,575,215CY2016345,914 2,921,129 345,914 2,921,129CY2017353,500 3,274,629 353,500 3,274,629
AvistaCorp 2007 Natural Gas IRP 3.9
Chapter 3 - Demand-Side Management
Figure 3.2 . Cumulative Identified Potential vs. Cumulative Acquired
WAIID Therms/year
25,000,000
20,000,000
~CD.ci-
15,000,000
10,000,000 ---
5,000,000
o
2007 2013 2014 2015 2016 2017 201820112012200820092010
I-Cumulative acquisition - - Cumulative potential I
Figure 3.3 . Cumulative Identified Potential vs. Cumulative Acquired
OR Therms/year
3,500,000
3,000,000
2,500,000
2,000,000II
ËCD.ci-1,500,000
1,000,000
500,000
0
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
I-Cumuiative acquisition - - Cumulative potential I
The Washigton/Idao potential and acquisition
identified in Figure 3.2 indicates that we wi fully
acquire identied DSM potential over the 10-year
planning cycle withi the 11 percent annual ramp-up
constraint.
The anual ramp-up constraint was not a factor in the
Oregon jurisdiction. The full identified potential is being
acquired in each year of the long-term planning cycle
(see figure 3.3).
3.10 2007 Natural Gas IRP AvistaCorp
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Chapter 3 - Demand-Side Management
3,500,000
3,000,000
2,500,000
2,000,000
1,500,000
1,000,000
500,000
Figure 3.4 - Annual Acquisition - WAllO
(Therms)
.. ....-
o
2002 2004 2006 2008 2010 2012 2014 2016 2018
I-OSM Actual. . . OSM intermediate -OSM goal I
300,000
250,000
200,000
150,000
100,000
50,000
Figure 3.5 - Annual Acquisition - OR
(Therms)
"
-Â ,",-,/\ .,,'
"
'"
o
2002 2004 2006 2008 2010 2012 2014 2016 2018
I-OSM Actual. . . OSM intermediate -OSM goal I
Figure 3.4 shows historical, current and projected
Washington and Idaho DSM therm acquisitions. The
chart ilustrates the gradual ramp-up ofDSM activity
for the first nine years of the planning cycle. In the
tenth year, the cumulative acquisition catches up to the
cumulative identied potential of the projection.
The ilustration in Figure 3.5 shows historical, current
and projected Oregon DSM therm acquisitions. The
acquisitions are somewhat choppy primaily because of
the start up and sunset of the pre-rinse sprayer program
(a 70,400 therm annual impact) in 2007 through 2008
AvistaCorp 3.112007 Natural Gas IRP
Chapter 3 - Demand-Side Management
followed by the gradual growth of acquisition to match
the identified potential of each year.
The IRP resource analysis is, as previously mentioned,
the starting point for the implementation planning
process. The following discussion of Avista's DSM
program and how the IRP results will be incorporated
into DSM operations is a preview of the effort that wi
immediately follow the completion of the 2007 IRP.
THE HERITAGE PROJECT
Based on the expected need for future electric
generation resources and the growig potential for both
electric and natural ga effciency opportunities,Avista
launched a wholesale ramp-up ofDSM activity in late
2006. Although ths ramp-up, known as the Heritage
Project, initialy had an electric-effciency focus the
opportunities for leveraging ths implementation plan for
natural gas-effciency purposes has not been overlooked.
As a consequence the project has been expanded to
cover al three jurisdictions served by Avista.
The Heritage Project signficantly increased the
infastructure capabilties and outreach efforts of Avista's
DSM effort. In the year since the launch of ths effort
the company has successfully:
· incorporated electric transmission and distribution
effciencies into the portfolio of opportunities;
· launched a combined long-term customer
outreach plan to communicate natural gas and
electric-effciency messages;
· augmented the residential portfolio with additiona
measures offered on a short-term basis; and
· improved rural delivery efforts by launching a
rotating geographic saturation implementation
program.
These additional efforts overlay a core organzational
strcture that has a proven history of delivering cost-
effective energy-effciency resources.
OREGON DSM PORTFOLIO
Avista's residential measures are available to approxitely
79,000 customers (A vista Rate Schedule 410) with
an anual consumption of 48 mion therms. The
commercial measures are avaiable to 10,600 mostly
sma-to-medium-sized customers (A vista Rate
Schedules 420 and 424) with an anual consumption of
approximately 76 mion therms. The largest segment of
qualfied commercial customers use natural gas for space,
water heating and cooking with an average consumption
of 2,600 therms each.
The measures offer a mi of currently cost effective
measures and market transformation measures which are
expected to be cost-effective over tie. The combined
residential and commercial therm goal for 2008 is
349,547 and 298,296 for 2009. Detais on individual
measures such as measure life, levelized TRC, unit goal
and therm goal can be found in Appendi 6.10.
RESIDENTIAL MEASURES
Our residential measures consist of site specific and
prescriptive proposals. The residential portfolio is a
mi of currently cost effective measures and maket
transformation measures which are expected to be cost-
effective over tie. The residential therm goal is 123,491
in 2008 and 140,381 in 2009.
3.12 AvistaCorp2007 Natural Gas IRP
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Chapter 3 - Demand-Side Management
Our residential site specific program is primarily focused
on cost effective shell measures. Changes made to the
program in early 2007 include higher incentive levels,
removal of al non cost effective measures, and requiring
window upgrades to be included with at least one other
major measure. Additional changes to this program
wi be considered in 2008. Table 3.7 shows current
residential shell program requirements.
Table 3.7 - Avista Residential Shell
Program Requirements
Shell Component
Attic Insulation
Floor Insulation
Wall Insulation
Windows
Program Requirement
R-38
R-19
R-11
U-35
We wi survey customers who received a home
energy audit, but did not follow through on any
recommendations. The information from this survey wi
be used to evaluate current incentive levels, messaging
on collateral material and frequency of customer contact.
We will alo increase our contract audit staf and support
staf to faciltate additional customer participation.
In addition to the site specifc program, we offer
several prescriptive incentives. In early 2007, we added
taness water heaters, high-effciency direct vent space
heaters, external chiey dampers, and programble
thermostats to our list of prescriptive measures. Existing
measures include high effciency forced air furnaces and
tan water heaters.
Measures currently not offered that are cost effective
based on SENDOUTiI results, will be evaluated
further to determie their viabilty for inclusion in
our prescriptive offerings. With the exception of high
effciency tank water heaters, al current measures are
cost effective in the SENDOUTiI modeL.
In the majority of cases, water heaters are replaced on
"burn out" with the high effciency models costing
about $120 more than standad effciency models.
Product avaibilty is also an issue in this situation. For
ths reason, we feel that in order to afect the incremental
cost and maintain avaibilty, high effciency tank water
heaters should be retaied as a market transformation
program in 2008 and 2009.
We believe that building a strong trade aly network
is the best way to promote the acceptance of high-
effciency gas equipment. Our trde ales include
HVAC dealers, plumbers, retailers, maufacturers,
distributors, builders and developers. We have increased
stafng levels to meet our trade aly objectives and wi
continue to monitor program activity to ensure adequate
resources.
We also partner with the Energy Trust of Oregon
(ETO) in several market transformation programs.
These programs include Energy Star new construction,
Energy Star manufactured homes and high-effciency
washing machines. We wi continue to evaluate these
program anualy to determine their effectiveness and
appropriateness for our rate payers.
COMMERCIAL MEASURES
Prior to 2007, our commercial measures were site-
specific offerings only. In early 2007, we added several
cost effective prescriptive measures. Those measures
Table 3.8 - Summary of 2006 Natural Gas Efficiency Program Results
Program
Measure life
Incentive per unit
TRC cost per unit
Therm savings per unit
Annual target therm savings
2006 actual therm savings
Res Shell
30 years
variable
variable
variable
62,500
70,802
Res Shell
15 years
$50
$50
27
8,397
6,858
ResS/H
25 years
$200
$496
64.4
180,450
123,750
CII effciency
18 years
variable
variable
variable
99,818
14,693
AvistaCorp 3.132007 Natural Gas IRP
Chapter 3 - Demand-Side Management
include: high-effciency space heating equipment, Energy
Starl) gas frers, three pan gas steam cookers and high-
effciency gas rack ovens.
The commercial therm acquisition goal for 2008 is
155,656 for site specifc and prescriptive measures, plus
70,400 therms from the pre-rinse sprayer program for a
total of226,056 therms. With the scheduled completion
of the pre-rinse sprayer offering in 2008, the goal for
2009 is 157,915 therms.
We developed the pre-rinse sprayer offering, with
implementation servces provided by Lockheed Mati,
with the goal of instalng 400 sprayer units in 2007
and 400 more units in 2008. The measure offers the
customer the option to have a code-complying unit
directly instaled into their facilty in return for the
retirement of a non complying unit. This approach
to accelerating retirement of the units that are not in
compliance with current code was one of the most cost-
effective resources identied in the 2006 IRP.
We also expect to add a number of new prescriptive
measures in 2008. Measures under consideration
include cost effective shell measures, tank and tankess
high-effciency water heaters, as well as other measures
found to be cost effective and appropriate for inclusion
as prescriptive measures. Measures with low acquirable
potential, technologies new to the marketplace or where
natural gas is used for process, wi be evaluated on a site
specifc basis.
We believe that by addig additiona prescriptive
measures, the program wi be more accessible to
customers and easier to maage with less cost. It is
anticipated that this wi result in higher participation
levels in the smal to medium sized customer segments.
Measures not included in the prescriptive program will
be evaluated on a site specifc basis.
As a result, we wi increase our efforts to identify cost
effective, site specific opportunities with our larger
commercial customers. We wi realocate resources
toward this initiative.
In addition, we wi look at the viabilty of a maket
transformation program for commercial kitchens. Initial
indications point to cost and avaiability as factors in the
decision not to instal Energy Star appliances. Dependig
on the prelinary evaluation scheduled for early 2008,
a commercial kitchen program could be launched in the
second or third quarter.
We will also continue to look for opportunities to
work cooperatively with the ETO where site specifc
effciency projects, with gas and electric savings potential,
are identified. We wi also work closely with local land-
use planners and energy consultants on new commercial
projects in order to infuence energy effciency decisions
during the design phase.
CLIMATE
The Oregon servce territory is subdivided into four
separate servce districts primaily based on climatic
differences. These four areas, from warmest to coldest,
are Roseburg, Medford, La Grande and Klth Fals.
The anual heating degree-days used in this IRP
(discussed in Chapter 6) for the four servce districts are
shown in Table 3.9.
Table 3.9 - Annual Heating Degree-Days
by Service District
Roseburg
Medford
LaGrande
Klamath Falls
4,240
4,766
6,654
7,135
There is a signcant difference (71 percent) in heatig
degree-days from the warmest to the coldest Oregon
district.
3.14 AvistaCorp2007 Natural Gas IRP
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Chapter 3 - Demand-Side Management
To determine the seasonal pattern of energy savings of
heating-related effciency measures (weatherization and
space heating measures), the monthly heating degree-
day patterns of Medford were ascribed to each servce
territory's anual heating degree-day level. This monthly
pattern is represented in Figure 3.10.
Table 3.10 -Annual Distribution of Heating
Degree Days (HDDs)
Month
January
February
March
April
May
June
July
August
September
October
November
December
Percent of Annual HODs
16.9%
12.9%
11.6%
8.5%
4.6%
1.5%
0.2%
0.3%
2.1%
7.0%
13.5%
21.1%
MEASURE DEVELOPMENT
Based on the results of the 2004 natural ga IRP we
launched a commercial cooking measure and a short-
term 2007-2008 measure to accelerate the replacement
of pre-rinse sprayheads. Additionaly a residential top-
mounted fireplace damper measure has been launched as
a result of opportunities identified afer the previous IRP
was completed.
We wi also look at the best fit for program
implementation. Implementation options could include
a combined effort between Avista's North and South
divisions, additional stafng, Energy Trust of Oregon
(ETO), trade partners, and if developed, a gas Northwest
Energy Effciency Aliance (NEEA). Additional avenues
for implementation wi be evaluated as they are
identified.
There are presently no near-term plans to expand the
Oregon DSM portfolio to include demad-response
program. An Idaho electric demand-response pilot
project is currently underway to test the techncal
abilty and residential customer acceptance of remotely
controllable thermostats. At present ths pilot is lited
to contrllng the thermostat for space cooling load
during times of electric peak load. If this is successfu,
there is the possibilty that the capabilities of the
thermostat could be expanded to address space heating
peak as well, assumig that the value of avoiding or
deferring natural ga distribution capacity warrants such
an expansion. Given the seasonal nature of the testing
of ths program, such an expansion is likely to be several
years in the future.
IMPACT OF EVIRONMENTAL COSTS ON OREGON DSM
MEASURES
To the extent tht natural gas-effciency measures reduce
overal end-use demand, there wi be reductions in
emissions resulting from the compression needed for
transmission as well as at the end-use itself. Of al the
emissions, carbon dioxide could have the greatest impact
on the company. A national carbon ta or green house
ga cap-and-trade system would be the most liely
mechansm for passing through the costs of emissions.
If a carbon ta were imposed, more DSM resources
would become cost-effective. A carbon tax at the $8
per ton level would add $0.07 cents per therm to supply
side resources. A $40 per ton tax adds approxitely
$0.35 cents per thermo At this level, maginal non-cost-
effective measures could become cost-effective.
WASHINGTON/IDAHO DSM PORTFOLIO
Avista offers a portfolio of electric and natural ga
effciency measures to Washington and Idao customers.
Electric effciency measures have been avaiable since
1978. Natural gas effciency measures have been offered
without interruption since 2001 and periodicaly prior
to that time based on cost-effective opportunities within
the market.
AvistaCorp 3.152007 Natural Gas IRP
Chapter 3 - Demand-Side Management
A non-binding external oversight group, the External
Energy Effciency ("Triple-E") Board, was established
to provide guidance for the implementation ofDSM
measures. This board is provided with a quarterly
written update, convenes twce a year and receives a
comprehensive annual evaluation ofDSM acquisition
and cost-effectiveness.
Avista's Rate Schedule 190 provides the regulatory
guidelines for the implementation of the natural gas
DSM measures. This taif prescribes a set of tiered,
diect financial incentives, as ilustrated in Table 3.11,
based on the customer simple payback of the measure.
Table 3.11 - WAllO Rate Schedule
190 Incentive Tiers
Customer Simple Payback
Zero to 17 months
18 to 48 months
49 to 71 months
72 months or more
Incentive per 1st yr Therm
$0.00
$2.00
$2.50
$3.00
Incentives are capped at 50 percent of incremental measure cost in
Idaho and 30 percent of incremental measure cost in Washington.
Selected exceptions to these tiered incentives alow the
company flexibilty to respond to unexpected or unique
opportunities. This flexibilty includes an additional
set of tiered incentives, permittg higher incentives
for the development of new technologies and maket
transformation efforts.
The original 2001 Schedule 190 tarif established
an anual goal of 240,000 first-year therms. Alost
immediately upon launch of the renewed gas-effciency
program, commodity-driven escalations in retail rates and
spilover effects from an emergency electric-effciency
response during the 2001 Western energy crisis drove
acquisition well beyond these levels. Initial concerns
that this higher level of acquisition may be unsustainable
proved to be unfounded. A reassessment of the maket in
the 2006 Gas IRP process resulted in the establishment
of a 1,062,000 annual therm goal. This goal has proven
to be maginay achievable in the years following the
2001 energy crisis.
It is likely that detaied business planning wi result in
recommendations for revisions to the incentive levels,
caps and applicable makets, and technologies as part of
an overal strategy to meet the commtments made for
increased long-term resource acquisition identied in
this IRP
Fundig for the natural gas effciency programs is derived
through a surcharge on retai rates authorized under
Schedule 191. This surcharge was increased from an
amount equal to approxitely 0.50 percent of retail
rates to 1.50 percent of retai rates in 2006. The increase
was necessar to eliminate a persistent imbalance of tariff
rider revenues and natural ga program expenditures;
an imbalance that bega with the 2001 crisis and grew
during the period of increasing commodity costs. For
the majority of ths period, over 90 percent of the ga
DSM funding was going directly to customer incentives
required under Schedule 190.
Only those customers contributing to the program
funding though Avista Rate Schedule 191 are eligible
to receive financial incentives. This limits avaiabilty
to core natural ga customers. Periodicaly we clai
the acquisition of natural gas savings from transport
customers if those effciencies result from involvement
in a project that is tightly interwoven with an electric-
effciency project that was being evaluated and funded
under the company's electric DSM program.
Our energy-effciency offerings within Washington and
Idaho are a closely related mi of electric and natural
ga measures. In 2006, the natural gas share of the total
BTU savings from the overal portfolio was 42 percent.
This share shifts depending on resource opportnities,
retail rates, technical advancements and customer interest.
DSM implementation effort in Washington and Idaho
3.16 AvistaCorp2007 Natural Gas IRP
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Chapter 3 - Demand-Side Management
are further subdivided into three different portfolios; (1)
the commercial/industrial portfolio, (2) the residential
portfolio and (3) the limited income residential portfolio.
The approaches to the implementation of these three
portolios dier signficantly in recogntion of the
differences in these makets.
COMMERCIALINDUSTRIAL PORTFOLIO
This portfolio is characterized by its al-encompassing
approach to this maket. Any natural gas effciency
measure quales 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 maket ensures that unique and
unexpected effciency measures are never excluded from
acquisition though utity program. The company
restricts the development of prescriptive program to
measures and applications that are reasonably uniorm
in their energy savings and cost characteristics. This
has generaly not been found to be the case for even
relatively common natural gas DSM measures. (Several
prescriptive electric DSM program have been developed
for the commercial/industrial maket).
In 2006, the company acquired 695,535 therms from
ths portolio (60 percent of the total acquisition of al
three portfolios). Twenty-five percent of the total non-
interactive energy (electric and natural gas) acquisition
within ths portfolio is attributable to therm savings.
Severa multifamy housing measures are incorporated
in the commercial/industrial portfolio due to the
non-residential electric and natural gas rate schedules
that many of these customers are biled. Many of the
multifamy measures evaluated as part of this IRP
analysis (e.g. pool and spa water heating effciencies
in multiamy housing) will be forwarded to the
commercial/industrial portfolio segment for further
evaluation.
Large projects, resulting in incentives of$100,000 or
larger, are disclosed to the Triple-E board to provide
them with the information necessar to provide
oversight ofDSM program.
RESIDENTIAL PORTFOLIO
Due to the large volume and relatively sma size of
individual projects, the residential portfolio is exclusively
composed of prescriptive program. In 2006, ths
portfolio was responsible for the acquisition of 382,355
first-year therms (7 percent of the total portfolio). Of
the non-interactive total energy (electric and natural
gas) savings in 2006 from this portfolio, 14 percent are
attributable to therm savings.
Incentives for residential programs are calculated based
on the application of the measure in a tyical residential
home. Calculations are made in accordace with Avista
Rate Schedule 190 tiered incentives with appropriate
modifications for potential dierences in application,
multiple measure program and rounding for purposes of
offering a customer and trade aly-friendly program. The
prescriptive residential programs currently available are
outlned in Table 3.12.
Table 3.12. WAllO Prescriptive Residential Gas Measures
High-effciency natural gas furnace ($200 for AFUE 90% or better)
High-effciency natural gas boiler ($200 for AFUE of 85% or better)
High-effciency 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 R10 or more)
Attc 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-effciency windows (70 cents/SF of window for U-.35 or better)
Avista Corp 3.172007 Natural Gas IRP
Chapter 3 - Demand-Side Management
Avista is continuing an outreach effort targeted for
residential customers. The outreach effort is geared
toward improvig residential natural gas-effciency by
providing a continuing educational message regardig
behavioral effects on energy use as well as driving
customers to improve the effciency of key natural gas
appliances.
This new online outreach, auditing and education
program wi 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 program improvements.
LIMITED-INCOME RESIDENTIAL PORTFOLIO
Avista's Washington and Idao limited income programs
are implemented in cooperation with six community
action parnership (CAP) agencies. These CAP agencies
are awarded an annual funding contract specifng the
mamum funding amounts and the conditions for
program implementation. Contracts can be revised on
30 days' notice, a provision that alows Avista to realocate
funds among the CAP agencies during the year to
mamize their value to the customer base.
The CAP agencies and 2006 funding levels are
summarized in Table 3.13. These amounts include a
$200,000 increase above calendar year 2005 funding.
The distribution of funding for the lited income
segment is intended to provide the mamum flexibilty
possible. This permits agencies to respond to unexpected
urgent needs and energy-effciency opportunities that
may not have been anticipated when the annual contracts
were signed.
As part of this flexibilty the CAP agencies are permitted
to expend their contractual funding on either electric or
natural gas-effciency measures. The funding avaiable
includes an alowable 15 percent remuneration to the
agency for admnistrative 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 necessar to
ensure the longevity of instaled effciency measures and
continued habitabilty of the home.
The lited income residential segment delivered 78,729
first-year therms to the overal natural gas DSM program
in 2006. This therm acquisition represented 3 percent of
the total BTUs acquired by the combined electric and
natural ga progras.
AVISTA DSM COMMITMENT
We recognize our obligation to meet the resource needs
of customers in the most cost-effective manner. The
delivery of natural gas effciency program is anticipated
to represent an increasing portion of the optima
natural gas resource portfolio. The IRP process is an
opportunity to comprehensively review the natural gas
effciency progra portolio and mae the revisions
necessary to meet those commtments in the future.
This document summrizes a broad evaluation of
applicable natural gas effciency opportunities and
Table 3.13 . 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 (Goldendale/Stevenson)
$539,812
$447,772
$83,048
$72,667
$71,107
$2,330
3.18 AvistaCorp2007 Natural Gas IRP
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Chapter 3 - Demand-Side Management
identifies those worthy of testing against al other possible
resources to assist us in mang decisions about which of
those natural gas effciency resources are suitable to carry
forward into program development.
We solicited comments from key stakeholders regading
the selection, characterization and testing of natural gas
effciency opportnities within the IRP process. Afer
much discussion and some revision, the general consensus
of those stakeholders was that this approach was suffcient
to represent natural gas effciency opportunities within
the IRP.
We also agreed that it is cost-effective and appropriate to
substantialy ramp-up Oregon natural ga DSM program,
as well as reconsider the approach to the implementation
of those program. This analysis has also established a
tentative goal far in excess of previous commtments
represented in Washington and Idaho Schedule 190 and
slightly above recent acquisition levels.
Complete agreement was not possible regarding the
liely customer reaction to several components of the
enhanced Oregon natural gas DSM portfolio. There is
concern that market barriers wi constrai participation.
We reman open to alternative approaches to overcomig
those market barriers to include enhanced outreach
efforts, revised incentives, innovative marketing of natural
gas effciency program and cooperative arrangements
with other agents in the market, with partcular attention
to other natural gas utities, the Energy Trust of Oregon
and regional maket transformation organizations with an
interest in natural gas effciency.
We are commtted to maintainig a collaborative
relationship with al stakeholders who may contribute to
the improvement of natural ga DSM efforts as programs
are further developed and launched. Additional metrics
wi be developed to improve the active management
of these program over time, as well as to provide better
benchmaks for determining the regulatory prudence of
these program.
We recognze that this commtment to acquiring al cost-
effective natural gas-effciency potential is not limited by
the therm acquisition goals established within this IRP
The implementation of the results of this planing effort
wi be suffciently flexible to realze those opportunities
even if they are in excess of expectations. Huma and
financial resources wi be made avaiable to the extent
necessary to achieve the cost-effective potential without
regard to those goals.
UPDATING AVOIDED COSTS FOR
APPLICATION TO DSM
Upon recogntion of this IRp, we wi mae the
necessar modifications to the avoided costs to be applied
to DSM projects and submit the appropriate fing for
review. This revision wi afect the cost-effectiveness
analysis used withn the business planng process, the
calculation of cost-effectiveness with the DSM Annual
Report and the TRC anysis performed on individual
non-residential site-specifc projects.
COOPERATIVE REGIONAL PROGRAMS
Avista has and remains interested in testing the viability
of a regional maket transformation approach to the
acquisition of natural gas-effciency potential. This
model has proven successful in Northwest electric
markets as evidenced by the success of the Northwest
Energy Effciency Alance (NEEA) over the past 11
years. We believe that this approach wi be particularly
successfu in residential markets. Though recent efforts
at partnering with NEEA and establishing limited ad
hoc regional efforts have been unsuccessful, we wi
continue to seek aliances with other Northwest utities
to advance this concept.
AvistaCorp 3.192007 Natural Gas IRP
Chapter 3 - Demand-Side Management
ACTION ITEMS
The completion of the IRP analysis is the midpoint,
not the end point, of a larger reassessment of the DSM
resource portfolio. The IRP analysis presented indicates
a set of cost-effective measures and acquirable resource
potential for a future DSM portfolio. Further evaluation
is required to facilitate the development of program plans
and to incorporate them into a DSM implementation
plan. Following detaied investigation of the natural
gas-effciency technologies identied as cost-effective,
we wi incorporate these programs into our Heritage
Project ramp-up of energy-effciency efforts.
Based on the analytcal process described in this
chapter, we estimate first-year energy savings goals
of approximately 350,000 therms in Oregon. In the
WA/ID servce territory we estimate first-year energy
savings goals of approximately 1,425,000 therms. This
commtment represents a 34 percent increase in annual
resource acquisition which wi require a signcant
ramp-up in DSM efforts. In the Washington and Idao
jurisdictions, it is likely that revisions to Schedule 190
wi be necessary if we are to achieve the acquisition
commtment. The DSM implementation planng
process will address the specifcs of how we can
aggressively increase acquisition without incurring undue
increases in costs attributable to the rapid ramp-up.
As part of the implementation planng process, we
wi calculate al individualy-evaluated measures and
other measures for their cost-effectiveness in each of
the individual Oregon subdivisions as well as within the
Washington/Idaho division.
We recognize the obligation to achieve al natural ga-
effciency resources available through the intervention
of cost-effective utility program. There are many
new effciency opportunities in the market, however,
considerable uncertainty remains regading the customer
response to these program. This uncertainty does not
preclude us from pursuing the planed aggressive ramp-
up of natural gas-effciency programs. Additionaly, we
have, and will actively seek, opportunities for new or
enhced resource acquisition though the development
of cooperative regional program.
One of the results of the IRP process is a 20-year forecast
of monthly avoided costs for each of our geographic
areas. The detailed nature of these avoided costs maes it
possible to continue to evaluate measures and program
as technology and makets change before the next IRP
process. This is of value in determining program cost-
effectiveness based on updated inputs, revised program
plans and the abilty to determine the value of targeting
specific markets. Avoided cost determiation is discussed
3.20 AvistaCorp2007 Natural Gas IRP
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Chapter 3 - Demand-Side Management
in detai in Chapter 7. We wi file our cost-effectiveness
limits (CELs) based upon the avoided costs derived frm
this IRP process.
Additionay, we are investigating the applicabilty
of recently completed quantications of electric
distribution capacity the customer value of risk reduction
and greenhouse gas emissions to determine if simar
quantications are possible for our natural gas system.
CONCLUSION
This IRP provides Avista the necessar resource
analysis to proceed to the further development and
implementation of natural gas effciency program.
Avista's 2006 natural gas IRP identied a goal of 441,000
therms in Oregon based on information avaiable at
that time. Current evaluations of energy savings frm
high-effciency natural gas furnaces are signficantly
lower than previous assumptions, which, when applied
to the 2006 IRP goal, would reduce the previous goal
to 390,000 therms. The 2007 IRP has identied an
acquirable potential that is 10 percent lower than the
previous IRP This decrease in the estite of acquirable
potential does not dinish the company's continuing
commtment to address the unique issues inherent in
our Oregon servce territory through an increased focus
on the non-residential sector. These enhancements wi
include additional utilty infrastructure, partnerships with
the Energy Trust of Oregon and continuing our work on
developing regional market transformation collboration.
AvistaCorp 3.212007 Natural Gas IRP
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4.DISTRIBUTION PLANNING
Chapter 4 - Distribution Planning
OVERVIEW COMPUTER MODELING
The primry goal of distribution system planning is to
design for present needs and to pla for future expanion
to serve demad growth. This alows the company
to satisfy current demand-servng requirements while
takng steps toward meeting future needs. Distribution
system plag identifies potential problems and areas
of the distribution system that require reinorcement. By
knowing when and where pressure problems may occur,
the necessar reinforcements can be incorporated into
norma maintenance. Thus, more costly "reactive" and
emergency solutions can be avoided.
An action item from the 2006 IRP was to explore a
gate station forecasting system to determine projected
customer growth in smaer geographic areas. Our
evaluation produced a system that utizes town codes as
the forecasting unit. A town code is an unincorporated
area within a county or a municipalty within a county
served by Avista. Distribution Planning has incorporated
town code growth rates to generate area-specifc
load growth for each distribution forecast model thus
integrating plannng efforts.
When designing new man extensions, computer
modeling can help determine the optimum size facilties
for present and future needs. Undersized facilities are
costly to replace and oversized facilties incur unnecessary
expenses to the company and its customers.
THEORY AND APPLICATION OF STUDY
Natural gas network load studies have evolved in the last
decade to become a highy techncal and usefu 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 taored to a specifc 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's
SynerGEEiI softare. This computer-based modeling
tool alows users to anayze and interpret solutions
graphicaly.
Avista Corp 4.12007 Natural Gas IRP
Chapter 4 - Distribution Planning
CREATING A MODEL
To properly study the distribution system, al natural gas
man information is entered Qength, pipe roughness and
diameter) into the modeL. "Main" refers to al pipelies
supplying servces.
Nodes (points where natural gas enters or leaves the
system) are placed at al pipe intersections, beginnings
and ends of mains, changes in pipe diameter/material and
to identify al large commercial and industrial customers.
A model element connects two nodes together.
Therefore, a "to node" and a "from node" wi represent
an element between those two nodes. Alost al of the
elements in a model are pipes.
Regulators are treated lie adjustable valves in which the
downstream pressure is set to a known value. Although
specific reguator tyes can be entered for realstic
behavior, the expected flow passing through the actual
regulator is determined and the modeled regulator is
forced to accommodate such flows.
FLUID MECHANICS OF THE MODEL
Pipe flow equations are used to determine the
relationships between flow, pressure drop, diameter
and pipe length. For al models, the fundamental flow
equation is used due to its demonstrated reliability.
Effciency 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 effciency can be changed to fine tune the model to
match field results.
Pipe roughness, along with flow conditions, creates
a friction factor for al pipes within a system. Each
pipe may have a unique friction factor, minimiing
computational errors associated with generalzed friction
values.
LOAD DATA
Al studies are considered steady state, meaning al natural
gas entering the distribution system must equal the
natural gas exiting the distribution system at any given
tie.
Customer loads are obtained from Avista's customer
bilng system and converted 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 is assumed that al curtaiable loads are
interrupted. Therefore, the models are conducted with
only core loads.
DETERMINING MAXIMUM HOURLY USAGE
Determining Base Load
Base loads are not temperature dependent; they
reman relatively constant regardless of temperature. A
reasonable base load can be calculated from customer
billg information. The bilng month, which has the
lowest amount of heating degree-days is usualy August.
Usage during this month wi reflect nearly al natural gas
loads exclusive of space heating.
By determig the amount of days in the bilng period
and applying a peakng factor, the peak hourly base load
of each customer can be estited as shown in Table 4.1.
Determining Heat Load
A heat load wi be proportional to heating degree-
days (HDDs); at zero HDD, the load wi be zero. Heat
load can be reasonably calculated from customer bilg
information. The billng month with the greatest
consumption is usualy January. This month reflects
mamum space heating as well as non-space heating
loads.
4.2 AvistaCorp2007 Natural Gas IRP
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Chapter 4 - Distribution Planning
Table 4.1 - Determining Base Load
Customer Usage
Summer Billng Period
1
X Days in Biling X 0.06251 =Period
Peak Hourly
Base Load
Table 4.2 - Determining Heat Load
1
Winter Biling
Period Degre X
Days1 Customer Usage
Winter Biling -
Period
Customer usagel
Summer Billng X
Period
PeakHDDs X 0.06251 = Peak HourlyHeat Load
Customers' usage for January (winter) bilng, minus
usage for August (summer) bilg, leaves a reasonable
estimate for heat load. This load can be divided by the
number of HDDs that occurred in January leaving usage
per HDD. Customer needs can be calculated by applying
the peakng factor, resulting in a peak hourly heat load
per HDD. This is shown in Table 4.2.
Determining Peak Hourly Load
The peak hourly load for a customer is estimated by
adding the hourly base load and the hourly heat load for
a peak temperature. This estimate reflects highest system
hourly demads, as shown in Table 4.3.
This method differs from the approach that we use for
IRP peak day load plannng. The prima reason for
this difference is the importance of responding to hourly
peakng in the distribution system, while IRP resource
planning focuses on peak day requirements to the
citygate.
APPLYING LOADS
Havig estimated the peak loads for al customers in a
partcul service area, the model can be loaded. The
first step is to assign each load to the respective node or
element.
GENERATING LOADS
Temperature-based and non-temperature-based loads
are established for each node or element, so loads can
be varied based on any temperature (HDD). This is
necessary to evaluate the difference in flow and pressure
due to different weather conditions.
GEOGRAPHIC INFORMATION SYSTEM (GIS)
We recently converted our natural gas facilty maps to
GIS. Whe a GIS can provide a variety of map products,
its power lies in its analytcal capabilty. A GIS consists of
three components: spatial operations, data association and
map production.
Table 4.3 - Determining Peak Hourly Load
Peak Hourly Base +
Load
Peak Hourly
Heat Load =Peak Hourly
Load
lThe average residential customer's peak usage was found to be 6.25 percent of the total daiy 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 tota daily load) in past
years (1994-99). The peaking factor is periodicaly discussed with other utilties and has been consistent with other utities of simir size.
AvistaCorp 2007 Natural Gas IRP 4.3
Chapter 4 - Distribution Planning
A GIS alows analysts to conduct spatial operations. A
spatial operation is possible if a facilty displayed on a
map mantains a relationship to other facilties. Spatial
relationships alow analysts to perform a multitude of
queries, including:
· identi electric customers adjacent to natural gas
mains who are not currendy using natural gas;
· display the ratio of customers to length of pipe
in Emergency Operating Procedure zones
(geographical areas defined by the number of
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. This
alows anysts to model relationships between fadlities
displayed on a map to tabular information in a database.
Databases store facilty information such as pipe size,
pipe material, pressure rating or related information
(e.g., customer databases, equipment databases and work
maagement systems). Data association alows interactive
queries within a map-lie environment.
Finaly, 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 anysis
can be presented pictorialy. This alows users to present
abstract analyses in a more intuitive context.
BUILDING SynerGEEe MODELS FROM A GIS
A GIS can provide additional benefits through the ease
of creation and mantenance ofload studies. Avista can
create load studies from a GIS based on tabular data
(attibutes) instaled during the mapping process.
MAINTENANCE USING A GIS
A GIS helps maintain the existing distribution facility
by alowig a design to be initiated on a GIS. Currendy,
design jobs for the company's natural gas system are
managed through Avista's Facilty Management (AFM)
tool. This system is being integrated with GIS, alowing
jobs to be designed direcdy withn a GIS. Once
completed, the information is submitted to GIS and the
facilty is imediately updated. This eliminates the need
to convert physical maps to a GIS at a later date. Because
the facilty is updated on GIS, load studies can reman
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 system are used.
Pressure charts plot pressure (some include temperature)
versus tie over several days. Various locations recordig
simultaneously are used to valdate the modeL. Customer
loads on SynerGEEiI are generated to correspond with
actual temperatures recorded on the pressure charts. An
accurate model's downstream pressures wi match the
corresponding location's field pressure chart. Effciency
factors are fine-tuned to further refine the model's
pressures.
Since telemetr at the gate stations record hourly flow,
temperature and pressure, these values are used to valdate
the modeL. Al loads are representative of the average
daly temperature and are defined as hourly flows. If
the load generating method is accurate, al natural gas
entering the actual system (physical) equals total natural
ga demand solved by the simulated system (model).
DEVELOPING A PEAK CASE LOAD STUDY
Using calculated peak loads, a model can be analyzed
to identif the behavior during a peak day. The
effciency factors established in the present case are used
throughout subsequent models.
4.4 AvistaCorp2007 Natural Gas IRP
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Chapter 4 - Distribution Planning
ANALYZING RESULTS
Afer a model has been balanced, several features within
the SynerGEEiI model are used to translate results. Color
plots are generated to depict flow direction, pressure,
pipe diameter and gradient with specific break points.
Attibutes of reinforcement can be queried by visual
inspection. When user edits are completed and the
model is rebalced, pressure changes can be visualy
displayed, helping identifY optimum reinforcements.
An optimum reinforcement will have the largest pressure
increase per unit length. Reinforcements can also be
deferred and occasionaly elinated through load
mitigation ofDSM efforts.
PLANNING CRITERIA
In most instances, models resulting in node pressures
below 15 psig (pounds per square inch) indicate a
likelihood of distribution low pressure and therefore
necessitate reinorcements. For most Avista distribution
systems, a mium of 15 psig wi ensure deliverability
as natural gas exits the distribution mans and travels
through servce pipelines to a customer's meter. Some
Avista distribution areas operate at lower pressures and
are assigned a minium pressure of 5 psig for model
results. Given a lower operating pressure, service
pipelines in such areas are sized accordingly to maintai
reliability
DETERMINING MAXIMUM CAPACITY FOR A SYSTEM
Using a peak day model, loads can be prorated at
intervals unti area pressures drop to 15 psig. At that
point, the total amount of natural gas entering the system
equals the mamum capacity before new constrction
is necessar. The difference between natural gas entering
the system in this scenario and a peak day model is the
maum 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 may new
customers can be added to the distribution system before
necessitating system reinforcements. The above models
and procedures are utized with new construction
proposals or pipe reinforcements to determine a potential
increase in facilties.
Avista Corp 4.52007 Natural Gas IRP
Chapter 4 - Distribution Planning
Table 4.4 . Capital Reinforcement Projects with Estimated Costs in 2006$
Project Description State 2007 2008 2009 2010 2011
East Medford OR $5,799,667 $5,000,000 $6,000,000
Glendale Gas Conv OR $1,420,002
Diamond Lake Reinforcement OR $1,300,087 $1,700,000 $2,100,000
Merlin Gate Station Rebuild OR $472,821
Grants Pass South Side Reinforcement OR $304,845 $250,000
Gekelar Road, LaGrande OR $150,285
N-S Freeway/Gas WA $150,000 $75,000 $50,000 $50,000 $50,000
Bridging the Valley WA $50,000 $100,000 $100,000 $100,000 $100,000
Reinforce Gate Station Post Falls-Chase Rd ID $1,500,000
Re-Rte Kettle Falls HP Feeder & Gate Station WA $1,300,000 $2,600,000 $2,300,000
Qualchan Reinforcement, Spokane WA $1,200,000
HP Reinforcement, Sutherlin OR $800,000
Bonners Ferry 4" PE Reinforcement ID $250,000
Reinforcement, Woolard Rd-Yale Rd, Spokane WA $250,000
Altamont & Crosby Road Project, Klamath Falls OR $225,000 $100,000 $100,000
Umpqua River Crossing Fairgrounds, Roseberg OR $150,000
Reinforce Barker Rd Bridge Crossing, Spokane WA $150,000
Relocation 6" HP (g Larson Creek, Medford OR $130,000
US2 N Spo Gas HP Reinforce (Kaiser Prop)WA $100,000
Rebuild J St Reg Station, Roseburg OR $100,000
Grants Pass 8" HP Reinforce Project OR $2,000,000
Elgin Line HP Reinforcement OR $1,600,000
Relocation, Davis Creek, Roseburg OR $125,000
Reinforce Talent Gate Station & Piping OR $50,000 $2,500,000
Cheney 8" HP Feeder Project WA $3,600,000
Reinforce Country Vista to Appleway 6" PE WA $250,000
Reinforce Barker Rd Looping WA $100,000
IMP Pipe Replacements, 2012 Commitment OR $830,000
TotalWA $200,000 $3,175,000 $2,750,000 $6,400,000 $150,000
TotallD $0 $1,750,000 $0 $0 $0
Total OR $9,447,707 $8,355,000 $11,975,000 $2,600,000 $830,000
FIVE-YEAR FORECASTING CONCLUSION
Load study forecastig is done to predict the system's
behavior and reinforcements necessar withi the next
five years. Various Avista personnel provide information
to determine where and why certain areas may
experience growth.
The company's goal is to mantai its distribution
systems to reliably and cost effectively deliver natural
gas to every customer. This goal can be achieved with
computer modeling, which increases the reliabilty of the
distribution system by identing specific areas within
the system that may require changes.
By combining information from Avista's demand forecast,
IRP planng efforts, regional growth plans and area
developments, proposals for pipeline reinforcements and
expansions can be evaluated with SynerGEEiI. A current
list of maagement approved proposed reinforcement
projects for the company is shown in Table 4.4.
The abilty to meet our goal of reliable and cost-
effective ga delivery is also enhanced through the recent
integration of customer growt forecasting at the town
code level and localized distribution planing. This
enables coordinated targeting of distribution projects that
are responsive to detailed customer growth patterns.
4.6 2007 Natural Gas IRP AvistaCorp
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Chapter 5 - Supply-Side Resources
5. SUPPLY-SIDE RESOURCES
production pools in ~oming, Utah, Colorado and
New Mexico). The prices for natural gas at these three
supply points generaly move together. However the
basis dierential among the supply points can change
depending on maket or operationa factors, including
differences in weather patterns, pipelie constraints and
the abilty to shift supplies to higher-priced delivery
points in the United States or Canada. Based on maket
information and analysis, we believe there is suffcient
liquidity at these three supply points to meet future
demand.
OVERVIEW
Avista's supply philosophy is to reliably provide natural
gas to customers with an appropriate balce of price
stabilty and prudent cost. To that end, we continuously
evaluate a variety of supply resources and attempt to
build a portfolio that is appropriately balanced and
diversifed to maage risk and achieve cost effectiveness.
These include firm and non-firm supplies, firm and
interruptible transportation on five interstate pipelines
and various storage options. The hedging program
resultig from that continuous evaluation addresses
physical and financial risks, both of which are covered in
this chapter.
This chapter describes natural gas commodity and
storage resources, transportation arrangements used
to connect those supply resources to Avista's demad
regions, and market-related risks and ways that mitigate
those risks.
COMMODITY RESOURCES
We have a number of supply options avaiable to serve
our core customers. Because Avista's core customers span
three states, the diversity of delivery points and demad
requirements adds to the options avaiable to meet
customers' needs. The utization of these components
varies depending on demad 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, alows the company to purchase at
lower-priced trading hubs on a given day, subject to
operational and contractual constraints.
The three major supply points near our servce area are
Sumas Oocated north of Seattle at the u.S.lCanadian
border),AECO (northeast of Spokane in Alberta,
Canada) and the Rockies (a number of natural gas
Given the abilty to transport natural ga to other parts
of North America, natural gas pricing is often compared
to the Henry Hub price for natural gas. Henr Hub
is a natural gas trading point located in Louisian and
is widely recognzed as the primary natural gas pricing
point in the United States. NYMEX futures contracts
are priced at Henr Hub. Figure 5.1 ilustrates the tight
relationship among the various locations and shows
historic natural ga prices for physical purchases at Henr
Hub,AECO, Suma and the Rockies.
Procurement of natural ga is tyicaly done via contracts.
There are a number of contract specifics that var from
transaction to transaction, and many of those terms or
conditions impact commodity pricing. Some of the
agreed-upon terms and conditions include:
· Firm vs. Non-Firm - Most term contracts
specify that supplies are firm except for force
majeure conditions. In the case of non-firm
supplies the standard provision is that they may
be cut for reasons other than force majeure
conditions.
· Fixed vs. Floatig Pricing - The agreed-upon
price for the delivered gas may be fixed or based
upon a daiy or monthy index.
· Physical vs. Financial - Certain counterparties,
such as bankng institutions, may not trade physical
natural gas but are stil active in the natural gas
markets. Rather than managing physical supplies,
AvistaCorp 5.12007 Natural Gas IRP
Chapter 5 - Supply-Side Resources
16.00
14.00
12.00
10.00
.c-8.00Q-
6.00
4.00
2.00
0.00
Figure 5.1 . January 1996 to July 2007 Monthly Index
NymexlRockies/Sumas/AECO
~~~ ~ ~~~~~~~~~~~~dddddd~ ~# ## ## ## ## ## ## ## ## ## ## ## #
I-Sumas -US Rockies -AECO -Nymex I
those counterpartes choose to transact financialy
rather than physicaly. Financial transactions
provide another way for Avista to financialy hedge
price.
· Load Factor/Variable Take - Some contracts
have fixed reservation charges assessed during each
of the winter months, whie others have minium
day or monthly take requirements. Dependig
on the specifc provisions, the resultig commodity
price will contain a discount or premium
compared to a standard product.
· Liquidated Damages - Most contracts contain
provisions for symetrical penalties for faiure to
take or supply natural ga according to contract
terms.
For this IRp, the SENDOUTiI model assumes the
natural gas is purchased as a firm, physical, fixed-price
contract regardless of when the contract is executed
and what tye of contract it is. However, in realty we
explore a variety of contractual terms and conditions in
order to capture the most value from each transaction.
STORAGE RESOURCES
The company is one-third owner, with NW and Puget
Sound Energy (PSE), in the Jackson Prairie Storage
Project Oackson Prairie) for the benefit of its core
customers in al three states. Avista has also contracted
for servce in the Mist underground natural ga storage
project for its Oregon customers. Jackson Prairie is an
underground reservoir project located near NW's main
line near Chehals, Wash. Mist is an underground natura
gas storage facility located in Mist, Ore., near Portld,
Ore.
Storage is a strategic resource due to the company's low
load factor. Storage provides the following benefits:
· invaluable peakng capability;
· reduces the need for higher cost annual firm
tranportation;
· storage injections increase the load factor of
existing firm transportation; and
· provides access to normay lower-cost summer
supplies.
5.2 AvistaCorp2007 Natural Gas IRP
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Chapter 5 - Supply-Side Resources
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, the company
released hal of its capacity and deliverabilty at Jackson
Prairie to BC Hydro. The prima term of the original
contract was set to expire in 1996, with a provision for
year-to-year continuation thereafer. The new contract
with Terasen, successor to BC Hydro for natural ga
operations, has been in place since 1996, with recal
provisions afer 2000. In April 2006,Avista notied
Terasen that ths release wi be terminated pursuant to
the contractual provisions. The recal wi be effective
April 30, 2008. The recaled Terasen capacity does not
include transportation.
In 1999 and agan in 2002,Avista participated in capacity
expansions of Jackson Prairie with NW and Puget
Sound Energy. It was determied that the additional
capacity for core utility customers was not needed at that
tie, and the expansion went under the management of
Avista EnergyAvista's non-regulated energy maketing
and trading afate. InJune 2007,Avista Energy sold
substantialy al of its energy contracts and ongoing
operations to Shell Energy North America, (U.S.), L.P.
The sale included Avista Energy's contractual rights
to Jackson Prairie through April 30,2011. Afer this
date, we anticipate recalng these storage rights for use
in our utiity operations, and have included it in our
SENDOUTil model as an incremental storage resource
at that time.
The 2002 expansion has been a phased, ongoing project
to increase the storage capacity of the field. Begining in
July 2007, concurrent with the Avista Energy/Shell sales
tranaction,Avista took over the rights to the ongoing
2002 expansion and wi utilize this incrementa storage
capacity. This phase of the expansion is expected to be
completed in the fal of 2008. Additionaly, the partners
in Jackson Prairie are currently expanding the daiy
withdrawal capabilty The target of this expansion is to
increase Avista's alocation of daily deliverabilty by 100
MMcf/day by November 2008.
Figure 5.2 - Jackson Prairie Storage Capacity and Deliverability
Existing and Future Volumes
Capacity
10.0
9.0
8.0
7.0
6.0
i:5.0II
4.0
3.0
2.0
1.0
0.0
Existing JP Capacity Future JP Capacity
. Current AVIsta
II Capcity Expansion
II Cascde Recall i: Terasen Recall
.Avista Energy Capacit
Deliverabilty
450
400
350
300
f 250
Q 200:i
150
100
50
o
Existing JP Deliverabilty Future JP Deliverabilit
. Currnt AVIsta IlCascade Recall
i: Terasen Recll ii Deliverabilty Expansion
.Avista Energy Deliverabilty
AvistaCorp 5.32007 Natural Gas IRP
Chapter 5 - Supply-Side Resources
The Shell-held rights, the capacity expansion and the
delivery expansion represent signficant incremental
future storage-related assets (see figure 5.2). In spring
2007 we discussed a pla for alocation of these rights
with the Washington, Oregon and Idaho Commssions
Staf recommending an alocation of75 percent/25
percent between our Washington and Idaho customers
and our Oregon customers, respectively. The
recommendation was supported in al three jurisdictions.
We continue to evaluate our Jackson Prairie capacity and
deliverability requirements to determine if we should
negotiate new releases or opportunisticaly optimize
excess storage capacity beyond the benefit currently
being captured.
TRANSPORTATION RESOURCES
Although proxity to the liquid hubs is important
from a cost perspective, those supplies are only as
reliable or firm as the pipeline transportation from
the hubs to Avista's servce territory. Consequently,
we have contracted for a suffcient amount of firm
pipeline capacity so that firm deliveries wi meet peak
day demand. We believe the combination of firm
transportation rights to our servce territory storage
facilties and access to liquid supply basins wi ensure
peak supplies are avaiable to our core customers.
The company has may contracts with Northwest
Pipeline Corporation (NW) and Gas Transmission
Northwest (GTN) for firm and interruptible
transportation to serve our core customers. In addition
to this capacityAvista also contracts for capacity on
upstream pipelines to flow natural ga to NW and
GTN. Table 5.1 detai the firm transportation/resource
servces contracted by the company. These contracts
are of different vintages, with dierent expiration dates.
However, al have the right to be renewed by Avista. This
gives the company and its customers the knowledge that
Avista wi have avaiable capacity to meet existing core
demand now and in the future.
NW and GTN also provide interruptible transportation
servce to the company. The level of servce of
interruptible transportation is subject to curtailment
when pipeline capacity constraints limit the amount
of natural ga that may be moved. Although the
commodity cost per Dth transported is the same as
firm transportation, there are no demad or reservation
charges connected with these transportation
contracts. Since the marketplace for capacity release of
transportation capacity ha become so prevalent, the use
of interruptible transportation servces has dinished.
We do not rely on interruptible capacity to meet peak
day core demand requirements.
Table 5.1 - Current Available Firm Transporttion Resources
Dth/Day
Firm Transportation
NWP TF-1
GTN T-1
NWP TF-2 (JPSP)
Total
Firm Storage Delivery Capacity
JPSP (SGS-1)
MIST
Total
Avista North
Winter Summer
111,599 111,599
100,605 75,782
91,200
303,404 187,381
Avista South
Winter Summer
30,638 30,638
42,260 20,640
2,623
75,521 51,278
127,667 2,623
15,000
17,623127,667
"Firm Storage Delivery Capacity utilzes the Firm Transporttion capacity.
5.4 2007 Natural Gas IRP AvistaCorp
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Chapter 5 - Supply-Side Resources
Table 5.2 - Current Transportation/Storage Rates and Assumptions
Rates in US$/Dth/Day
Reservation
TransCanada Alberta System Firm Rates -
Postage Stamp RatesAECo/NITto ABC 0.1230
AECo/NIT to ABC Winter Only 0.1538
TransCanada BC System Firm Rates -
Postage Stamp RatesABC to Kingsgate 0.0640
GTN FTS-1 Rates 4/ -
Mileage Based - Representative Example
Kingsgate to Spokane
Kingsgate to Medford
Meford Lateral
0.1166
0.4190
0.5481
Specta EnerglWestcoast System Firm Rates -
Postage Stamp Rates
Station 2 to Huntington/Sumas 0.3560
WillamsNWP
Postage Stamp Rates
TF-1 1/
TF-21/
SG8-2F 21
0.3798
0.3798
0.4718
Commodity Fuel Rate 31 Rate Change Assumptions
0.00% Changes every three years
0.00% Changes every three years
1.00% Changes every three years
0.0040
0.0222
0.38%
2.10%
0.00%
Changes every five years
Changes every fie years
Changes every five years
1.30% Changes every three years
0.03000
0.03000
0.01703
1.82%
1.82%
0.52%
Changes every five years
Changes every five years
Changes every five years
1/ TF-1 base upon annual delivery capabilty. TF-2 based upon approximately 32 days of delivery capabilit
2J Not applicable for WAllO customers
3/ Fuel retained in-ind
4/ GTN rates are the full filed rates. The GTN rate case was setted Oct. 31, 2007.
Forecasting future pipeline rates is diffcult, if not
impossible. Our assumptions for future rate changes
were the result of maket information and concurrence
byTAC members. GTN fùed a rate case in late 2006.
The rates in Table 5.2 reflect the rates as fùed. Since the
drafng of ths document, settlement on the GTN rate
case has been reached. The settlement was fied with
the Federal Energy Regulatory Commssion (FERC)
on Oct. 31, 2007, but is not yet approved. Beyond this
assumption, it is assumed that the pipelines wi fùe to
recover costs at rates equal to the GDP.
The company's strategy is to contract for firm
transportation to serve core customers should a peak
day occur in the near-term planning horizon. Too
much firm transportation could keep the company
from achievig its goal of being a low-cost energy
provider. But too little firm transportation impairs the
company's reliabilty goal. Determing the appropriate
level of firm transportation is a complex evaluation of
many factors, including the projected number of firm
customers and their expected demad on an arual
and peak day basis, opportunities for future pipeline or
storage expansions, and relative costs between pipelines
and their upstream supplies. It is important to mantai
an appropriate time cushion, to alow for required lead
times for securing new capacity. Also, the abilty to
release capacity offsets the cost of holding underutized
capacity.
MARKET-RELATED RISKS AND RISK
MANAGEMENT
Whe risk maagement can be defined in a variety of
ways, the 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
AvistaCorp 5.52007 Natural Gas IRP
Chapter 5 - Supply-Side Resources
physical risk that there may not be enough natural gas
(either the transportation capacity or the commodity) to
serve core customers.
Avista has a Risk Magement Policy that describes
in more deta the policies and procedures associated
with financial and physical risk maagement. The Risk
Management Policy addresses, among other things,
maagement oversight and responsibilities, interna
reportig requirements, documentation, transaction
tracking and credit risk.
There are three interna organizations tht assist in the
establishment, reporting and review of Avista's business
activities related to maagement of natural gas business
risks:
· The Risk Management Commttee consists
of several corporate offcers and senior-level
management. The commttee establishes the Risk
Mangement Policy and monitors compliance.
They receive regula reports on natural gas activity
and meet regularly to discuss maket conditions,
hedging activity and other related matters.
· The Strategic Oversight Group (SO G) exists to
coordinate natural gas matters among internal
natural ga-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. Whe the Natural Gas
Supply department is responsible for implementig
hedge tranactions, the SOG provides input and
advice.
· The Natural Gas Coordination Commttee
involves Natural Gas Supply, Demand-Side
Management, Natura Gas Engineering, Rates,
Accounting and Natural Gas Operations to ensure
that the various departments are mantaining lines
of communication and coordinating natural gas-
related projects.
MARKET FACTORS AND AVISTA'S
PROCUREMENT PLAN
We cannot accurately predict future natural ga prices.
The company has designed a natural ga procurement
plan that attempts to competitively acquire natural
gas supplies whie reducing exposure to short-term
price volatilty. Although the specific provisions of the
procurement plan wi change as a result of ongoing
analysis and experience, the following principles reflect
Avista's procurement plan philosophy:
· Avista employs a diversifed approach to
hedging - It is appropriate to hedge over a
period of tie, and we establish hedge periods
within which portions of our future loads are
fInancialy hedged. The finacial hedges may not
be completed at the lowest possible price, but wi
insulate customers from price spikes. Additionaly,
we diversify the basins we purchae at and the
counterparties we purchae from.
· Avista establishes a disciplined but flexible
approach to hedging - In addition to
establishing hedge periods within which hedges
are to be completed, there are alo upper- and
lower- pricing points. In a rising market, this
reduces the company's exposure to exteme price
spikes. In a declining maket, ths encourages the
company to capture the value associated with
lower prices.
· Avista reguarly reviews its procurement
plan in light of current market conditions
and opportunities - Avista has a dynamc plan
with ongoing review of the assumptions leading
. to the procurement plan. Although we establish
various targets in the initial plan design, policies
provide flexibilty to exercise judgment to revise/
adjust targets in response to changing conditions.
A number of tools are available to help mitigate financial
risks. Many of these tools are financial instrments or
derivatives that can be utied to provide fixed prices or
5.6 AvistaCorp2007 Natural Gas IRP
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Chapter 5 - Supply-Side Resources
dampen price volatilty We contiue to evaluate how
to maage day load volatity, whether through option
tools avaiable from counterparties or through access to
additional storage capacity and/or transportation.
We believe we can strengthen the analysis leading to
certn hedges and future modifications to our natural
gas procurement pla. VectorGas™ wi facilitate the
ability to model price and demand uncertainty and
model various hedging strategies and evaluate the
impacts on cost and volatility of the overal portfolio.
SUPPLY-SIDE OPTIONS
SYSTEM ENHANCEMENTS
In certai instances, the company can faciltate additiona
peak and base load-serving capabilties through a
modication or upgrade of our facilties. These
opportunities are geographicaly specific and require
case-by-case study. We have begun a review of several
enhancements and preliminar findings indicate that the
following opportunities are viable.
. NWP Klamath Falls Lateral
Avista has the opportnity to purchase and operate
the NW Klamath Fals lateral as a high-pressure
distribution system. Although we would incur the
capital cost associated with the purchase price, we
would be able to avoid current NWP reservation
and fuel charges at Klamath Fal and relocate the
tranportation contract deliverabilty on NW
to areas where additiona deliverabilty is needed
whie reducing fuel charges. This solution would
alo faciltate additional deliveries into the Klath
Fals area off of GTN. This enhancement can
likely be completed within six months.
· Medford System Enhancement
Avista is constrcting 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 wi alow existing supply and capacity to
be diverted from Medford on the NW Grants
Pass Lateral to the Roseburg area. Through ths
enhancement, we can address potential resource
shortages in the Medford and Roseburg areas.
· La Grande Oistnbuton System Enhancement
Avista has the option to enhance the distribution
system in the La Grande area with high-pressure
distribution looping from an adjacent citygate
station such that the distribution system would be
reinforced. This solution would alow additional
deliveries off of the NW system to La Grande.
EXISTING STORAGE
Storage alows the company to deliver natural gas supply
when needed most. Storage alo alows the company to
take advantage of summer/winter pricing differentials, as
well as provide the company with arbitrage opportunities
withn individual months. The latter advantages do
not offer peak load servng capabilties although they
certainly alow the company to offset natural gas supply
expenses with these revenues. Although additiona
storage can be a valuable resource, without deliverabilty
to Avista's servce territory, this storage canot be
considered an incremental firm peak-servng resource.
Storage resources are limited in the Pacifc Northwest;
however, there are a number of options avaible.
· Jackson Prairie
As discussed in the Storage Resources section,
Jackson Prairie is a tremendous resource for
existing servces and expansion opportunities.
Recently recaled capacity wi faciltate peak and
winter deliveries at no cost for the storage and
very litte cost for the transportation in addition
AvistaCorp 5.72007 Natural Gas IRP
Chapter 5 - Supply-Side Resources
to providing ratepayers with the opportunity to
capture current arbitrage opportunities that exceed
the release revenues that Avista was receiving.
The storage recal and future expansion capacity
discussed earlier do not include incremental
transportation to our servce territory and
therefore cannot be considered an incremental
peak day resource. However, we wi continue
to look for swap and transportation release
opportunities to fully utize these additional
resources. Even without deliverabilty, we believe
it maes financial sense to fully develop/recal
JP capacity to optie tie spreads within the
natural gas maket and provide net revenue offets
to customer gas costs.
As discussed earlier in this chapter, plans cal for
some of the JP expansion capacity to be alocated
to Oregon customers. This expansion does not
currently have transportation so this storage is not
currently avaiable for incremental peak resource
needs. It is, however, a supply replacement on
peak day as well as an arbitrage opportunity
Oregon customers may have the abilty to benefit
from storage resources for incrementa peak needs
if future cost-effective pipeline capacity can be
acquired.
· Mist
Avista has also recently added a sma amount of
storage capacity for its Oregon customers through
a three-year storage capacity agreement at the Mist
Storage Facilty in northwest Oregon.
· Plymout LNG
Avista released its rights to Plymouth LNG in
part because of the JP capacity release recals. This
peakng resource was costly per unit delivered and
is fully contracted and not avaiable for contracting
at this time. Given ths situation, this option is not
being modeled in SENDOUT\l for this IRP.
However, due to the fact that many of the
current capacity holders are on one-year rollng
evergreen contracts, it is possible that this option
wi again become viable in the future. In order
for this option to become a preferred resource,
transportation to and from Plymouth wi need to
be acquired.
· Oter Strage
Other regional storage facilties exist and may be
cost-effective. Additional capacity at Northwest
Natural's Mist facilty, capacity at Alberta area
storage, Questar's Clay Basin facilty in Northeast
Uta, and Northern Calfornia storage are
al possibilties. Again, transportation to and
from these facilties to Avista's servce territory
continues to be the largest impediment to
contracting for these options. An attractive non-
Jackson Prairie resource that we are reviewing is
storage potential in Northern Calornia. This
concept needs to be further analyzed, although
it appears that through backhaul transportation,
deliveries could be made to some of the
Washington/Idao and Oregon customers.
Storage capacity is periodicaly avaible in
Northern Calfornia as well as transport capacity
to and from these locations. Unfortunately,
current sellers of storage capacity in Northern
Calfornia are not offering multi-year contracts
or contracts with beginning dates during the
timeframes that the company may need these
incremental resources.
5.8 AvistaCorp2007 Natural Gas IRP
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Chapter 5 - Supply-Side Resources
PIPELINE TRANSPORTATION
Additiona firm pipeline transportation resources are
viable resource options for the company. Determining
the appropriate level, supply source and associated
pipelie path, costs and ting as well as determining
whether or not existing resources wi be avaiable at the
appropriate tie mae this resource dicult to analyze.
Firm pipeline capacity provides several advantages:
it provides the ability to receive firm supplies at the
production basin, it is generaly a low-cost option given
optization and capacity release opportunities, and it
provides for base-load demand. Pipeline capacity alo has
several drawbacks, including tyicaly long-dated contract
requirements, limited need in the summer months (may
pipelines require annual contracts) and limited avaiabilty
Many pipelines currently have avaiable pipeline capacity
on the manlne portion of their systems. Unfortunately,
NW does not have any avaible capacity on its
manlne or on any of the relevant lateral that serve
Avista's servce territories. GTN has mainlne capacity
currently available and may be able to provide additional
servce to some Washington/Idaho and Oregon
customers without an expanion. Further, longer-term
permanent capacity release options may be avaiable on
both pipelines.
Following are three specific options that provide Avista
with flexible existig transportation resources:
· Capacity Release Recall
Avista's pipeline transportation that is not utized
to serve load can be released to other parties or
optimized through buy/sell transactions. Released
capacity is maketed through a competitive
biddig process and can be done on a short-term
(month-to-month) or long-term basis. We actively
participate in the capacity release maket and have
a may short-term and several long-term capacity
releases.
We assess the need to recal capacity or extend a
release of capacity on an on-going basis. The IRP
process also helps evaluate if or when we need to
recal some or al of our long-term releases.
· Willamett Peaking Arrangement
We currently have some transportation capacity
contingently released to Wilamette Industries.
As part of this agreement we have the abilty to
cal on this capacity and an associated amount of
supply. This contract expires Oct. 31,2010 and
mayor may not be renewed.
· Utlization of Backhauls
On the GTN system, due to the north-to-south
flow dynamcs and the large amount of natural
gas flowing that direction, backhauling supply
purchases to Avista's servce territory can be
done on a firm basis. For example,Avista can
purchase cost-effective supplies at Maln, Ore. and
transport those supplies to our servce territory
at either Klamath Fals or Medford. Maln-based
natural gas supplies tyicaly price at a premium
to AECO supplies but are generaly less expensive
than the cost of forward haul transportation
from traditional supply sources and payig the
associated reservation charges. The GTN system is
a mieage-based system so we only pay a fraction
of the forward rate if it is transporting supplies
from Maln to Medford and Klamth Fals. The
GTN system is approximately 612 mies long and
the distance from Maln to the Medford lateral is
only about 12 mies. Avista can decrease costs by
avoiding fuel charges and full reservation charges
on an annual or seasonal basis and/or by avoiding
potentialy expensive peakng resources.
Pipeline expansions can be more expensive thn existing
pipeline capacity and often require long-term anual
contracts. Even though expansions may be more
AvistaCorp 5.92007 Natural Gas IRP
Chapter 5 - Supply-Side Resources
expensive than existig capacity this approach may sti
provide the best option to the company given that most
of the other options discussed in this section require
pipeline transportation anyway.
To accurately assess costs and location, feasibilty
of potential expansion scenarios requires detailed
engineering studies by the pipelines. These studies can
be expensive and of limited shelflife for projects that
might be developed well into the future. Consequently,
we employ estites derived from our knowledge of
historical costs, reasonable price escalations and site
specific issues that may impact a specifc scenario. We
combine this knowledge with past information from
the pipelines to develop a reasonable basis for our
transportation anaysis. If and when we determine that
additional transportation capacity is necessar we will
request thorough estimates from the appropriate pipeline
companies, search the release market for capacity that
may include winter-only servce and seek capacity on
constrained segments. These estimates are costly and will
be prudently acquired.
SATELLITE LNG
Company-owned satellte LNG storage is another option
that could be constructed withn the company's servce
area. Unle LNG facilties described earlier, satellte
LNG uses natural gas that is trucked to the facilties in
liquid form rather than liquefYg on site. By locating
withn the Avista servce area and not on the interstate
pipelines,Avista could avoid incremental anual pipeline
charges.
Estimates for this tye of peakng resource look
interesting. The company will continue to monitor and
evaluate the cost and benefit of satellte LNG as new
supply increments whie remaning midfl oflead time
requirements and environmental issues.
COMPANY-OWNED LNG
LNG facilties could be constructed withi the
company's servce area. By locating within the Avista
servce area and not on the interstate pipelines,Avista
could avoid anual pipeline charges. Such constrction
would be dependent on regulatory and environmental
approval as well as cost effectiveness requirements.
Prelinary estimates of the constrction, envionmental,
right of way, legal, operating and maintenance, required
lead ties, and inventory costs indicate company-
owned LNG facilties are not cost effective at this time.
Although the company is not modeling this option, we
wi continue to monitor cost effective company-owned
LNG storage opportunities.
LARGE-SCALE LNG
There has been considerable national discussion
regading LNG gasifcation terminals. At today's natural
ga prices, LNG can be competitively transported,
stored and marketed. Numerous terminals have been
proposed in the U.S., Mexico and Canada with seven
termials proposed for Washington, Oregon and British
Columbia. Not al of these terminals wi advance, and
it may be possible that none of the Pacifc Northwest
terminals wi proceed. The siting of LNG terminals is
a diffcult endeavor. In order for a termial to advance,
it wi require economies of scale, the abilty to move
regasified supplies to markets, a favorable envionmental
review; favorable public reception, secure LNG supply,
long-term output/sales agreements and financing. We
have participated in several forums on various regional
projects.
Although the Pacific Northwest may not provide
sponsors with these requirements, the announcement to
constrct a pipeline from the proposed Coos Bay LNG
facilty to Maln, Ore., is encouraging. This pipeline may
alow LNG to be diectly delivered to Avista's service
5.10 AvistaCorp2007 Natural Gas IRP
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Chapter 5 - Supply-Side Resources
territory around Roseburg, Medford and Klamth
Fals whie potentialy helping supply other regions via
further backhaul or displacement opportunities. We
are also. monitoring the Bradford Landing/Palomor
pipelie project. We have participated in the open
seasons of the Coos Bay LNG and Bradwood Landing/
Palomar projects in our region contingently reservng
capacity We continue to monitor developments in this
area including the securing of dependable supply which
we believe poses a signcant chalenge for the project
sponsors.
Industry experts believe that if additional LNG terminals
are built and receive incrementa supply, natural gas prices
may trend downward or at least become less volatile.
These experts also believe that it generaly does not
matter where the LNG terminals are located because
the national natural gas makets are so tightly connected.
Even if the Pacific Northwest facilities do not proceed,
Avista wi likely benefit from increasing amounts of
imported LNG nationaly.
For ths IRp, we are not making large-scale LNG
avaiable to the modeL. This is because LNG in the
Pacifc Northwest is highy speculative, the region is not
considered to be as premium a maket as other locations
in North America, and because it will tae at least five
years before this option would move forward in the
Pacific Northwest. Each of the price forecasts we have
reviewed make assumptions regarding increasing LNG
imports to North America, so LNG commodity impacts
are imbedded in those forecasts.
We wi continue to monitor this option and wi take
action if a Pacific Northwest terminal begins to look
promising.
SUPPLY ISSUES
The market for natural ga has undergone dramtic
changes over the last several years, as the commodity
market has transitioned from a regionaly-based market
to a nationay-based, and perhaps globaly-based, maket.
This transition can be attributed to several reasons,
including:
· Supply/Demand Balance - The balance
between production and productive capacity has
become tight. The balanced market has increased
gas price volatity. Additionaly, the cost of
production has increased. These production costs
keep the maket at a price level that is much
higher than historicalleve1s
· Imports from Canada - There is an abundance
of evidence supporting the assumption that ga
wi continue to be imported from Canada into
the United States. Recently, however, some
literature contends supply imports from Canada
wi diminish greatly or even disappear over the
20-year planng horizon. Since much of our
supply comes from the WCSB, the notion that
supply could disappear is of concern. We wi
continue to monitor this situation for sign that
indicate increased risk of disrupted supply from
Canadian exports.
· Pipeline constraints - Although there now may
be, or wi be in the future, excess pipeline capacity
in many parts of the countr, the maket or
delivery portion of most pipelines remans heaviy
contracted. This is because LDCs and end users
such as industrial customers prefer supply certainty.
Avista and other consumers in the Pacific
Northwest continue to hold al of the NW
capacity and existing lateral capacity on NW and
GTN. Of particular concern to Avista is NW's
Grats Pass Lateral in western Oregon. This lateral
is fully contracted, demad is continuing to grow
in the demand centers along ths latera, and it
is not easily or inexpensively expanded. We also
intend to further anayze how this fu contracted
capacity situation might afect the Spokae lateral
or other laterals.
AvistaCorp 5.112007 Natural Gas IRP
Chapter 5 - Supply-Side Resources
· Pipeline rate increases - There is more pipeline
capacity from supply sources to makets than
is currently needed in many regions in North
America. This excess capacity has caused capacity
holders with expiring contracts to consider
relinquishig this capacity back to the pipelines.
Many capacity holders have shown a preference
for 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 afected pipelines
to file rate cases to recover some or al of the
lost revenues. Distribution companies that rely
on firm supplies and transportation wi liely
continue to hold or may be locked into their long
term transportation contracts and may end up
paying higher transportation rates depending on
the FERC's approach to ths issue.
· Growing national pipeline infrastructure -
Pipeline capacity out of the supply regions ha
increased in volume and delivery points. As a
result, natural ga prices in the Pacific Northwest
have become more dependent on demand and
prices in regions as far away as the east coast.
The Rockies Express pipeline expansion to
the Midwest and Eastern markets is expected
to further solidi price correlation with these
markets.
· The potential of LNG to be the marginal
source of natural gas in the United States -
Several projections indicate that over the next 10
years there wi be a growing gap between North
American natural gas production and North
American demand for natural ga. The consensus
is that LNG will fil the gap. Should this occur,
there will be global price competition for LNG.
We have been, and wi contiue to be, involved
in discussions about LNG as a potential supply
resource.
ACTION ITEMS
We wi continue to monitor several issues identified
in this chapter with respect to commodity storage, and
supply resources. These include:
· tight production/productive capacity;
· pipelie constraits in our region;
· pipeline expansions that move volumes away from
our region;
· pipeline cost escaltions; and
· large scale LNG activity
We wi alo refine our analysis of acquiring or
constrcting resource alternatives to improve project
cost estimating, assessment of project feasibilty issues,
determination of project siting issues and risks, and
increased accuracy of constrction/acquisition lead
times. Specificaly, we will further study these issues with
respect to satellte LNG, company owned LNG, pipeline
expansions, distribution system enhancements and
storage facilty diversification.
We wi explore creative, non traditiona resource
possibilties to address our needle peakg exposures
with emphasis on potential structured transactions (e.g.
transportation and storage exchanges) with neighboring
utilities and other market parcipants that leverage
existing regional infrastructure as an alternative to
incrementa infrastructure additions.
We wi continue to assess methods for capturing
additional value related to existing storage assets,
including methods of optimiing recently recaled
releases whie implementing its storage strategy of
providing balanced storage opportunities. This includes
exploring storage diversifcation options including
AECO and Northern Calornia facilities.
We wi contiue to analyze natural ga procurement
practices for strategy enhancing ideas such as basis
diversifcation, storage injection/withdrawal ting and
strctured products.
5.12 AvistaCorp2007 Natural Gas IRP
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Chapter 5 - Supply-Side Resources
There is an abundance of evidence supporting the
assumption that gas wi contiue to be imported from
Canada into the United States. However, recently some
literature contends supply imports from Canada wi
dinish greatly or even disappear over the 20 year
planng horizon. Since much of our supply comes from
the WCSB, the notion that supply could disappear is
of concern. We will continue to monitor this situation
looking for signals that indicate increased risk of
disrupted supply from Canadian exports.
CONCLUSION
Avista is commtted to ongoing exploration of supply-
side resources that meet our phiosophy of providing
reliable natural gas servce to our customers whie
balncing price stabilty and prudent costs. We are
mindfl that each resource option has unique risks that
also must be evaluated in context of a total resource
cost which in some cases eliminates them from current
modeling consideration. Nonetheless, we are satisfied
that the currently viable resource mi options fulfil our
supply-side resource analysis objectives.
AvistaCorp 2007 Natural Gas IRP 5.13
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Chapter 6 - Integrated Resouræ Portolio
6. INTEGRATED RESOURCE PORTFOLIO
OVERVIEW
This chapter combines al the previously discussed
components of the IRP and the model used for this
process to determine if the company is resource deficient
during the 20-year plannng horizon. This chapter
also provides an analysis of potential resource options
and displays the model-selected best cost/risk resource
options to meet resource deficiencies.
The foundation for integrated resource planning is the
demand planng criteria utized for the development
of demand forecasts. Avista currently uses the "coldest
day on record" as its planning standard for determining
peak day demad. This is consistent with many other
natural gas companes and our past IRPs. We intend
to reevaluate ths standard in the coming months to
ascertain if a revision might be appropriate. Many
important analytcal and judgmental considerations
wi need to be assessed, including probability studies,
reliabilty and safety implications and potential liability.
Currently, we utize historic peak and average weather
data for each demand region for ths IRP It is also
important to note that due to our duty to serve, we plan
to serve this expected peak for each demad region
with firm resources. These firm resources include DSM,
natural ga supplies, pipeline transportation and storage
resources. In addition to planng for peak requirements,
we also pla for non-peak periods such as winter,
shoulder and summer demand. Our modeling process
includes runnig the optization every day of the
20-year planng period.
It is assumed that on a peak day al interruptible
customers have left the system in order to provide
service to firm customers. The company does not mae
firm commtments to serve interruptible customers.
Therefore, our IRP analysis of demand-servg
capabilities only focuses on the residential, commercial
and firm industrial classes. These three customer classes
are collectively referred to as core customers.
Our 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
primrily for pipeline compressor station fueL. The
percentage of additional supply that must be purchased
AvistaCorp 6.12007 Natural Gas IRP
Chapter 6 - Integrated Resource Portolio
is governed through FERC and National Energy Board
tarif fings of the pipelines.
NATURAL GAS RESOURCE MODEL
The natural ga resource optimiation model we use
is the SENDOUTiI Gas Planning System from New
Energy Associates (NEA). The SENDOUTiI model was
purchased in April 1992 and has been used in preparing
al IRPs since that time. The company has a long-
term mantenance agreement with NEA that alows
us to receive updates to the software as enhancements
are made. These enhancements encompass softare
corrections and improvements, and enhancements
brought on by industry change.
SENDOUTiI is a linear programmng model widely
used to solve natural gas supply and transportation
optimization questions. Linear programng is a proven
technique used to solve minimization/mamization
problems. SENDOUTiI looks at the complete problem
at one time within the study horizon, takng 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:
· demad data such as customer count forecasts
and demand coeffcients by customer tye (e.g.
residential, commercial and industrial);
· heating degree-day (HDD) information;
· existing and potential transportation data
which describes to the model the network for
the physical movement of the natural ga and
associated pipeline costs;
· existing and potential supply options including
supply basins, revenue requirements as the key cost
metric for al asset additions, and prices;
· natural ga storage options with injection/
Figure 6.1 - SENDOU~ Model Diagram
6.2 2007 Natural Gas IRP AvistaCorp
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Chapter 6 - Integrated Resource Portolio
withdrawal rates, capacities and costs; and
· demad-side management programs.
An exaple of some of the information used in
the model is ilustrated in Figure 6.1, which is the
SENDOUTiI Model Diagram. This diagram ilustrates
Avista's current tranportation and storage assets, flow
paths and constraint points.
The SENDOUTiI model also provides a flexible tool to
analyze numerous potential scenarios such as:
· pipeline capacity needs and capacity releases;
· effects of different weather patterns on demad;
· effects of natural gas price increases on total
natural gas costs;
· storage optization studies;
· resource mi analysis for demad-side
magement programs;
· weather pattern testing and analysis;
· anysis of transportation costs;
· avoided cost calculations; and
· short-term planng comparisons.
The latest version ofSENDOUTiI, released inJuly 2007,
includes VectorGas ™ which facilitates the abilty to
model price and weather uncertainty through Monte
Carlo simulation and detaied portfolio optimization
techniques that wi ultimately produce probabilty
distribution information. Simiar to SENDOUTiI, there
are numerous variables that are entered into VectorGas™.
Among the variables required to perform the Monte
Carlo analysis are:
· expected monthy heating degree-days by month;
· standard deviation of the monthly heatig degree-
days;
· monthly minimum and maum heating degree-
days;
· daly HDD pattern (derived from historical data);
· expected monthy ga price by month;
· standad deviation of the monthly gas price;
· monthly minium and mamum gas price;
· temperature-to-price correlations;
· price-to-price correlations; and
· daiy price to temperature coeffcients.
This additiona softare module enhances Avista's
analytcal capabilities, and we have just begun to explore
its capabilities.
ANALYSIS FRAMEWORK
The approach used to analyze Avista's long-range natural
gas planning options focuses on the sensitivity of the
optimiation model to periodic (daiy, monthly, seasonal
and/ or annual) changes in:
· assumptions related to customer growt and
customer natural gas usage that ultimately form
demad forecasts;
· existig and potential transportation and storage
options;
· existing and potential natural gas supply avaiabilty
and pricing;
· weather assumptions; and
· demand-side management and avoided cost.
We have reviewed and performed rigorous anysis on
each of the aforementioned areas.
DEMAND FORECASTING APPROACH
Avista's demand forecasting approach is described in the
Demad Forecast chapter.
We forecasted demand in the SENDOUTiI model
in five areas due to the existence of distinct weather
and demand patterns for each area. The areas
withi SENDOUTiI are Washington/Idaho (further
disaggregated to three sub-areas due to pipeline flow
limitations), Medford (further disaggregated to two
sub-areas due to pipeline flow limitations), Roseburg,
Klamth Fals and La Grande. In addition to area
distinction, we also modeled demand by customer class
AvistaCorp 6.32007 Natural Gas IRP
Chapter 6 - Integrated Resource Portolio
Figure 6.2 . WAllO Historical Monthly Average Demand
(April 2003 - April 2007)
140,000
120,000
100,000
80,0003:.c-Q 60,000
40,000
20,000
0
November January March May July September
Figure 6.3 . OR Historical Monthly Average Demand
(April 2003 - April 2007)
30,000
25,000
20,000
~15,000is
10,000
5,000
~/ ~~~~--::s ~
o
November July SeptemberJanuaryMarchMay
I-Klamath Falls -LaGrande -Medford -Roseburg I
in each of these areas. The relevant customer classes in
the Avista servce territory for this IRP are residential,
commercial and firm industrial sales. Not al classes of
customers currendy exist or are forecasted to exist in
each demad area.
The SENDOUTil model is used to forecast customer
demad, and we have calbrated the demad forecasting
component of the SENDOUTil model though a
meticulous backcasting process. A backcast uses the
algorithm developed for forecasting purposes and applies
it to known historical data as a means of testing the
valdity of that algorith.Figures 6.2 and 6.3 show historic non-weather
normazed average monthy demand for core customers
by region for April 2003 through April 2007.As described in the Demand Forecast chapter, and given
experience with customers' price elaticity we believe
6.4 2007 Natural Gas IRP AvistaCorp
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Chapter 6 - Integrated Resource Portolio
Figure 6.4 - Average vs. Coldest vs. Warmest (84/85 plus 82 HOD, NOAA)
Spokane Weather
80
70
60
Q 50
!i 40
30
20
10
o
1 331 361316191121211241271301151181
Days November. October
-Coldest -Avg-NOAA-Warmest
Figure 6.5 - Average vs. Coldest vs. Warmest (63/64 plus 61 HOD, NOAA)
Medford Weather
60
50
40Q
!i 30
20
10
31 331 3616191241271301121151181211
Days November - October
-Coldest -Avg-NOAA-Warmest
that it is possible that current and future high prices wi
continue to impact natural gas demand.
WEATHER ASSUMPTIONS
As stated in Chapter 2, we developed three scenarios
using low, medium and high customer growth crossed
with a price elasticity factor to capture the inverse
relationship between price and demad to build our
three demand scenarios for ths IRP
Avista's customer demand reflects a weather dependent
customer base, so weather is very importt in integrated
resource plag. The analysis in this IRP is based on
weather data published by the National Oceanic and
Atmospheric Admnistration (NOAA). This is a 30-year
weather study spang 1971-2000. Figures 6.4 and 6.5
show NOAA's 30-year average weather data compared to
AvistaCorp 2007 Natural Gas IRP 6.5
Chapter 6 - Integrated Resource Portolio
Figure 6.6 - NOAA 30-year Average vs. Planning Weather (added 82 HOD on Feb. 15)
Spokane Weather
80
70
60
Q 50
~ 40
30
20
10
o
1 31 61 91 121 151 181 211 241 271 301 331 361
Days November - October
-Average - Actual -Average - NOAA
Figure 6.7 - NOAA 30-year Average vs. Planning Weather (added 61 HOD on Feb. 15)
Medford Weather
60 --------------------------
50 ---------------------
Q 40
~ 30
20
10
31 61 91 121 151 331 361181211241271301
Days November - October
- Average - Actual -Average - NOAA
the coldest and warmest historical planng year for the
Spokane and Medford areas. Measurements of historical
average weather do not necessarily represent the range
of potential future weather patterns, including some days
that may differ substantialy from that average pattern.
average heating degree-days with the variabilty of actual
weather.
On Dec. 30, 1968, the North Operating Division area
experienced the coldest day on record, an 82 heating
degree-day for Spokane. This is equal to an average daly
temperature of -17 degrees Fahrenheit. This day is used
as the peak day for cold conditions in the Washington/
Idao servce area. Only one 82 heating degree-day
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
6.6 2007 Natural Gas IRP AvistaCorp
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Chapter 6 - Integrated Resource Portolio
has been experienced in the last 40 years for this area;
however, within that same tie 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 daiy temperature of 4 degrees Fahrenheit.
This day is used as the peak day for cold conditions in
Medford. Medford has experienced only one 61 heating
degree-day in the last 40 years; however, it has also
experienced 59 and 58 heating degree-day events on
Dec. 8,1972, and Dec. 21,1990, respectively. The other
three areas in Oregon have simar weather data. For
Klamth Fals, 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 the peak day
for modeling purposes.
The actual HDDs by area and by day entered into
SENDOUT~ can be found in Appendi 6.1.
As discussed earlier, we intend to review our peak day
weather plannng standard to consider whether or not
modifications are appropriate. Results and any potential
changes wi be incorporated in our next IRP. However,
one prelinar analysis assessed the relationship between
peak day load and the change in 1 HDD which showed
that the peak day unserved demand is pushed out one
year in each area. Table 6.1 shows the planng stadard
heating degree-days, the peak day volume by area, and
the change between scenarios for the gas year 2011-2012.
This is the first year we have unserved demand, in
one region, in our Expected Case. This information
provides a baselie to understand quantitatively the load
implications on each of our servce areas for further
analysis.
Table 6.1 - Planning Standard Review
2011-2012 Klam Falls LaGrande Medford Roseburg WAllO
Planning Standard HDD 72 74 61 55 82
Peak Day Volume 15.15 10.11 65.44 18.03 291.17
Plus One HDD
Peak Day Volume 15.34 10.24 66.47 18.34 294.48
Change from Standard 0.20 0.13 1.03 0.31 3.31
Plus Two HDD
Peak Day Volume 15.54 10.37 67.46 18.64 297.78
Change from Standard 0.39 0.26 2.02 0.61 6.61
Less One HDD
Peak Day Volume 14.96 9.98 64.48 17.74 287.87
Change from Standard (0.19)(0.13)(0.96)(0.29)(3.30)
Less Two HDD
Peak Day Volume 14.76 9.85 63.49 17.44 284.57
Change from Standard (0.38)(0.26)(1.95)(0.59)(6.60)
*Removing one HDD moves the unserved demand out one year in each area.
AvistaCorp 6.72007 Natural Gas IRP
Chapter 6 - Integrated Resource Portolio
500
450
400
350
l 300:: 250
200
150
100
50
o
Figure 6.8 - Existing Firm Transportation & Storage Resource Stack
WAIID
.--------------
----
-------
31 61 91 121 151 181 211 241 271 301 331 361
Day of Year
Figure 6.9 - Existing Firm Transportation & Storage Resource Stack
OR (includes Wilamette Firm Peaking Arrangement)
91 121 151 181 211 241 271 301 331 361
Day of Year
TRANSPORTATION AND STORAGE
Avista's existing transportation and storage resources
are described in the Supply-Side Resource chapter
(summrized in Table 5.1) and are represented by the
firm resource duration curves depicted in Figures 6.8
and 6.9. We consider these firm transportation and
storage resources as the starting point for SENDOUT'i
infrastructure. When modeling future transportation and
storage rates, we modified existing rates (summized in
Table 5.2) for expected rate increases and then escalted
these rates at the Global Insight inflation rate (see
Appendix 6.1). The expected rate increases are based on
industr discussions regading representative pipeline rate
cases.
DEMAND-SIDE MANAGEMENT
As discussed in the DSM Chapter, the identication
and total resource characterization of avable natural
ga effciency measures alows the construction of a
natural gas DSM supply curve. This supply curve is a
6.8 AvistaCorp2007 Natural Gas IRP
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Chapter 6 - Integrated Resource Portolio
$1.00
$0.90
î $0.80..
i! $0.70!!
.. $0.60
8U $0.50II
¡ :::::
l $0.20
$0.10
$0.00
o
Figure 6.10 - WAllO OSM Supply Curve, 2007/2008
Representing 63 evaluated non-site-specific measures
Excluding 27 "red" measures that failed preliminary evaluation
.r.fT -~-r~
i--Ir--
200,000 400,000 800,000 1,000,000 1,200,000600,000
1st year therms
$1.40
$1.20
î $1.00
...c
~$0.80
1 $0.60~i-i:$0.40l
l $0.20
$0.00
Figure 6.11 - OR OSM Supply Curve, 2007/2008
Representing 63 evaluated non-site-specific measures
Excluding 27 "red" measures that failed preliminary evaluation
--
,--.---------------~---
-----_..fJ~.F-r/J
-$0.20
o 50,000 200,000 250,000100,000 150,000
1 st year therms
graphical depiction of the measures in ascending order
of total resource cost. The horizontal axs indicates the
cumulative resources obtainable at or below that cost.
Supply curves are presented for the two divisions (Figures
6.10 and 6.11). These curves represent the cumulative
therms of the evaluated measures stacked in ascending
order ofTRC cost.
Appendi 6.9 of ths document. Future implementation
planning efforts wi use these measures as a starting point
for more detaied planning, but wi also investigate other
measures that may have faied prelinary evaluation
or SENDOUT(I modeling. The implementation plan
will also alow for consideration of improvements to
the program through the definition of tighter target
markets, measure packaging, and clitic and geographic
differentials throughout the servce territory.SELECTED MEASURES
The list of individual selected measures is incorporated in
AvistaCorp 6.92007 Natural Gas IRP
Chapter 6 - Integrated Resource Portolio
The avoided cost developed in this IRP wi be the basis
for the implementation plang effort. This alows for
consideration or modications to measures.
DSM ACQUISITON GOALS
Avista is commtted to acquiring al cost-effective
natural gas-effciency resources achievable through
intervention. This IRP has provided the opportunity for
a comprehensive assessment of effciency opportunities in
an analysis that integrates supply-side options as well.
· Washington/Idaho DSM Goals
Changes in techncal opportunities and avoided
costs have driven the potential identied in this
IRP substantialy beyond the 1,062,000 therm
level developed in the prior IRP The proposal
for constraining annual growt in the goal to an
11 percent increase, to prevent undue increases
in utity acquisition costs, results in a calendar
year 2008 goal of 1,425,000 therms. Continuing
the 11 percent arual growth rate results in the
fu acquisition of the identied potential over a
10-year planning cycle.
Achievement of a persistent 11 percent arual
increase in acquisition is likely to require revisions
to the Schedule 190 tariff governing natural gas
DSM operations. Incentive levels, incentive caps
and applicable measures and markets may need to
be reviewed to support an implementation plan
capable of achieving these long-term goals.
Other revisions to regulation, infastructure
or DSM operations are liely to be identified
in future planning efforts. The company is
commtted to pursuing a more rapid ramp-up of
acquisition if it can be achieved without an undue
increase in utility acquisition costs.
· Oregon DSM Goals
Based on the analysis in this IRP we believe that a
cost-effective annual acquisition of 350,000 first-
year therms is achievable through intervention.
The identification of this goal does not preclude
the addition of other resources that may be
identied as cost-effective during later analysis,
nor does it preclude the pursuit of unexpected
resource acquisition opportnities that may occur
between IRP cycles.
NATURAL GAS SUPPLY AVAILAILITY AND PRICING
We attempt to balce the need for both low cost
and low volatity with high reliabilty in our natural
gas procurement efforts. The chapter on Supply-Side
Resources
describes supply options avaiable to the company.
Regional and national natural ga prices have
experienced increased volatity since 2005. Geopolitical
and global supply/demand issues have continued to
inuence oil price volatity and, consequently, natural ga
prices given their often correlated relationship. Demand
growt, natural gas for electric generation, hurricane
activity and other weather events are believed to be some
of the reasons for the increased gas price volatity. The
industr has also generay observed higher gas price
levels since 2005. This new gas price floor stems from
the tight production and productive capacity balnce, as
well as increasing exploration and production costs.
Many factors infuence natural gas pricing and volatity
in addition to the factors cited above. Exaples
include regional supply/demad issues, local, regional
and national weather, hurricanes/storms or threats of
them, storage levels, fuel needs for gas fired generation,
infastructure disruptions, and infrastrcture additions
(e.g. new pipelines and LNG terminals). Although we
monitor these infuences on an ongoing basis, we do
6.10 AvistaCorp2007 Natural Gas IRP
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Chapter 6 - Integrated Resource Portolio
$12.00
$11.00
$10.00
$9.00
$8.00
.c
~$7.00
$6.00
$5.00 ......
$4.00 .... --....
$3.00
Figure 6.12 - Henry Hub Forward Prices
2006 IRP vs. Current Forecasts
2005$IDth
- - -- -- -- - - - - - -- -- -- - - - - - -- -- - - - ---
$2.00
~ ~ ~ B ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ A ~ n~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~v~v ~v ~ ~v ~v ~v~~~~~~~~~~~~~~~~~~~~~~~
-.2006 High IRP
-- Consultant 1
-l 2006 IRP Medium - - - 2006 IRP Low
-'Consultant 2 -r AEO 2007
X Actual 2006--Nymex
not believe that we can accurately predict future prices
for the 20-year horizon of this IRP We have reviewed
a variety of price forecasts provided by credible sources
and have selected high, medium and low price forecasts
to represent the real of reasonable pricing possibilties.
Figure 6.12 depicts the selected price forecasts.
As Figure 6.12 shows, there are may price forecasts
with a large variation in overal price levels. Although
some of these forecasts are more liely than others, most
of them are plausible. Therefore, with the assistance
and concurrence of the TAC Commttee, we selected
high, medium and low price curves to consider possible
$18.00
$16.00
$14.00
$12.00
.c $10.00
g.. $8.00
$6.00
$4.00
$2.00
$0.00
Figure 6.13 - Henry Hub Forward Prices for Avista 20071RP
Nominal $IDth
2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
I-+ Low-AEO/Consultant 2 - Medium-NymexlConsultant 1 .. High-Nymex I
AvistaCorp 6.112007 Natural Gas IRP
Chapter 6 - Integrated Resource Portolio
$12.00
$11.00
$10.00
$9.00
$8.00
$7.00
25 $6.00~$5.00
$4.00
$3.00
$2.00
$1.00
$0.00
Figure 6.14 - Henry Hub Forward Prices for Avista 20071RP
2007$/Dth
-_._--~-
...
---_.~-~---~--~..Á~~
---
--._---
1-----
~~~~~~~~~~~~~~~~~~~~~~~tt tt ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
-+ Low-AEO/Consultant 2 _ Medium-NymexlConsultant 1 .. High-Nymex
outcomes and the impact that this volatie and high
pricing environment might have on planning. These
curves are shown in nominal dollars in Figure 6.13 and
real dollars in Figure 6.14.
Each of the forecasts ilustrated above are at the Henry
Hub, which is located in Louisiana just onshore from the
Gulf of Mexico. It is the physical location that is widely
recognzed as the most importat pricing point in the
United States because of the sheer volume traded on a
daily and a spot basis, a forward basis and its proximity
to a large porton of United States production. Al other
producing and maket area-pricing points tend to be
set off of the Henr Hub as is the New York Mercantile
Exchange's (NYMEX) trading hub for futures contracts.
Although the Henry Hub infuences natural gas prices in
the United States and the Pacifc Northwest, the physical
supply points Sumas,Wash.,AECO Alberta, Canada, and
the U.S. Rockies ultitely determines Avista's costs.
Pricing of these points is set or based upon Henr Hub,
although they tyicaly trade at a 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, closer physical
proximity to these supplies and longer distance from the
big demad centers in the Eastern United States.
Since most price forecasters do not forecast regiona
pricing points, we estite the basis dierential between
Henry Hub and the pricing points on which the
company relies. As discussed at the TAC meetings, we
believe that an average of the most recent dierentials
is an appropriate estimate of basis differentials, because
recent history better represents the current structure
of the natural ga maket. This structure may change
particularly out of the U.S. Rockies producing region;
however, at this point in tie, it is the best predictor of
future differentials. We have adopted Table 6.2 showing
the percentage of Henr Hub, for AECO, Sumas and
Rockies pricing points. We calculated these percentages
by comparing the actual monthly index prices from
Table 6.2 - Basis Differential Assumptions
Pricing Point
Percentage
AECO
86.0%
Rockies
80.5%
Sumas
87.6%
6.12 AvistaCorp2007 Natura Gas IRP
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Chapter 6 - Integrated Resource Portolio
Table 6.3 . Monthly Pricing Allocation
January February March April May June
113%113%110%93%92%93%
July August September October November December
94%94%95%96%101%106%
November 2003 through June 2007. The beginning
date for this comparison was chosen because of pipeline
expansions that went into servce in 2003, which were
basis altering expansions.
Each price forecast provides annual (not monthy) prices.
For modeling purposes, given Avista's heavily winter-
weighted demad profie, it is more appropriate to
break these annual figures down to monthly figures. As
discussed with the TAC, we believe that utizing avaible
forward price dierentials by month is an appropriate
way to compute monthly prices. Table 6.3 depicts the
monthly shape that we applied to the annual prices in
the price curves.
Appendi 6.1 displays the detaied monthy price data
as calculated when the Henry Hub price forecasts
are incorporated with the basis and seasonal factor
adjustments discussed above.
DEMAND FORECASTS AND SENSITIVITES
As discussed in the Demad Forecast chapter, we have
selected three scenaios for detaied anaysis to capture a
range of possible outcomes over the plang horizon.
These scenarios consider the price elaticity effects
on the high and low customer growth scenarios. The
scenarios are shown in Table 6.4. The customer growth
rate figures are further discussed in the Demad Forecast
chapter and can be found in Figure 2.1 and Appendi
2.2.
Further demand scenarios can be derived byVectorGas™.
By varng the number of heating degree-days by month,
diering demad cases can be created. These scenaios
can then be run thugh SENDOUTil to observe how
unserved demad varies based on weather. A probability
distribution can also be generated showing how likely a
partcular weather event may be.
Table 6.4 - Demand Scenarios
High Demand Case - High Expected Case - Base demand Low Demand Case - Low
demand and low price scenario.and mid price scenario. Static use demand and high price scenario.
50% increase in customer growth per customer over the planning 50% decrease in customer growth
and a price elasticity adjustment to horizon.and a price elasticity adjustment to
demand coeffcients (- .13).demand coeffcients (-.13).
AvistaCorp 6.132007 Natural Gas IRP
Chapter 6 - Integrated Resource Portolio
Figure 6.15 - Avista IRP Total 20 Year Cost
Mean
30
25
Average: 10.621
StdDev: 0.175
Min: 10.247
90% percntile: 10.84
95% percntile: 10.930
Max: 11.163
Expected: 10.769
20 _Frequency
-Cumulative~c
!! 15
eLi
10
5
o
$10.25 $10.34 $10.43 $10.52 $10.61
Expeed 90th 95th
Cas Percntile Percentile
I
I
I
I
I
IIII: 5%,.---------------------------------------------: P(Cost=-10.930)=5%
IIIIIIII
- --"-'-~'1-" --. -- pëC~~~10.84i~1-Õ --- --,......- - - ---IIII.II,IIII.II.
10%
$10.70 $10.80
$ Billons
$10.89 $11.16
100%
90%
80%
70%
60%
50%l~E~u40%
30%
20%
10%
0%
PRELIMINARY RESULTS
Based on our analysis and feedback from the TAC, we
generated results from SENDOUTiI utizing expected,
High and Low Demad cases and existing transportation
and storage resources.
The demad results of these cases are discussed in the
Demand Forecast chapter and additional details of
these cases are in Appendi 2.4. We believe that these
cases explore the real of reasonable outcomes whie
mimig the number of cases analyzed al the way
through the conclusion of this IRP process. As we
further integrate VectorGas™ into our plannng process
we will be able to better understad risks around price
and weather. We wi also be able to determie the
frequency of our chosen resource mi.
$10.98 $11.07
Through our preliminary use ofVectorGas TM a
simulation of 200 draws on price alone revealed that the
Expected Case total portfolio costs are withn the range
of occurances. Figure 6.15 shows a histogram of the
total portfolio cost of al 200 drws, plus the Expected
Case results. This histogram depicts the frequency the
total cost of the portfolio occurred among al the draws,
the mean of the draws, the standard deviation of the
total costs, as well as the total costs from the Expected
Case. The figure shows that our Expected Case is within
an acceptable range of total costs based on 200 unique
pricing scenarios.
2007 Natural Gas IRP6.14 AvistaCorp
...........................................
...........................................
Chapter 6 - Integrated Resource Portolio
400,000
350,000
300,000
250,000
S 200,000
150,000
100,000
Figure 6.16 - WAllO Existing Resources vs. Peak Day Demand
(Net of DSM Savings) Expected Case - November through October
50,000
-....
~¡:,.--:-:-¡:¡o i------------¡.-----~:-:-:-i-i-------------~:-:-:-:-i-i-----------
------:-1--:-i-i-i------_.----------:-:-:-:-f-i-i-i----------
---:-f--f-f-f-i-i-i-----.---------
-[phone]--+-+-+-+-+-+-+-+-+o ## ~~~~~~~~~~gggg§ggg~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~v ~v ~v ~v ~v ~v ~v ~v ~v ~v# ~ # $ ~ ~ ~ $ $ $ ~ $ $ # # ~v~ # # #
_Exting GTN _Existing TF-1 _Existing TF-2 ~Peak Day Demand
200,000
180,000
160,000
140,000
120,000
S 100,000
80,000
60,000
40,000
20,000
0
Figure 6.17 . OR Existing Resources vs. Peak Day Demand
(Net of DSM Savings) Expected Case - November through October
##~~~ ~~~~~~~#~# ~ &###~~~~~~~~~~~~~~~~~~~~#~#$~~ ~$$$~$$##~ ~###
_Existing GTN _Existing TF-1 _Existing TF-2 _Existing Will Peaking _Backhaul Med La! ~Peak Day Demand
Figure 6.16 and 6.17 graphicaly represent a regional
summary of Expected Case peak day demad compared
to existing resources. This comparison shows, on a
regional basis, when and how much the company is
deficient over the planning horizon. Simar figures
for the Low and High Demand cases can be found in
Appendi 6.2.
It is important to note that this summized approach
can mask regional deficiencies. Therefore, we prepared
Avista Corp 6.152007 Natural Gas IRP
Chapter 6 - Integrated Resource Portolio
Table 6.5 to provide servce area detail which identies
when the company first becomes resource constrained
and the amount of that deficiency on that region's peak
day. This table also shows the growth in deficiencies over
time. Simiar figures for the Low and High Demad
cases are in Appendi 6.3.
shortages occurring in our smaer servce areas. Given
that we do not anticipate resource shortges unti at least
the 201012011 heating season in the High Demad case,
and given that the Expected Case is not deficient unti
the 201112012 heatig season, we have suffcient time
to carefully plan and take action on resource additions.
Further, the Low Demad case has no resource
deficiency unti 2019-2020. For this IRp, we attempted
to identi al reasonable resource options, given current
Each case depicts at least one deficiency in at least one
demand area during the planning horizon with the first
Table 6.5 . Peak Day Demand. Served and Unserved (MOth/d)
Before Resource Additions & Net of DSM Savings
Case Gas Year
La Grande
Unserved
WAllO
Unserved
Case
Klamath
Falls
Unserved
Medford/
Roseburg
Unserved
Medford/
Roseburg
WAllO
Total
75.77
6.16 2007 Natural Gas IRP AvistaCorp
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...........................................
Chapter 6 - Integrated Resource Portolio
information, and used the SENDOUTiI model to pick
the least cost incremental resources.
NEW RESOURCE OPTIONS
When researching resource options, the followig
considerations are important in determining the
appropriateness of potential resources.
Resourc Cost
Resource cost is our primry consideration when
evaluating resource options although other considerations
mentioned below also infuence resource decisions. We
have found that newly constructed resources are tyicaly
more expensive than existing resources, but existing
resources are in shorter supply. Newly constrcted
resources provided by a third party such as a pipeline
may require a signcant contractual term commtment.
Newly constructed resources are often less expensive
per unit if a larger facilty is constructed, because of
economies of scale.
Lead- Time Requirements
New resource options can take anywhere from one to as
many as 10 or more years to put in servce. Open season
processes, planning and permitting, envionmental review,
design, constrction and testing are some of the may
aspects that contribute to lead-tie requirements for new
physical facilties. Recals of storage or tranportation
release capacity tyicaly require advance notice of up
to two years. Even DSM program require signficant
tie from program rollout to the point when natural ga
savings are realzed.
Peak versus Base Load
Our planng efforts include the abilty to serve a design
or peak day as well as al other demad periods. The
company's core loads are considerably higher in the
winter than the summer. Due to the winter-peakng
nature of Avista's demand, resources that cost-effectively
serve the winter without an associated summer
commtment may be preferable. It is possible that the
costs of a winter-only resource may exceed the cost of
annual resources afer capacity release or optimiation
opportunities are considered.
Resource Usefulness
It is paramount that an avaiable resource effectively
delivers natural ga to the intended geographical
region. Given Avista's separate servce territories, it is
often impossible to deliver resources from an option
such as storage without acquiring additional pipeline
transportation.
IILumpiness" of Resource Options
Newly constructed resource options are often "lumpy."
This means that new resources may only be avaible in
larger than needed quantities and only avaiable every
few years. This resource lumpiness is driven by the
cost dynamcs of new construction, the fact that lower
unit costs are available with larger expansions, and the
economics of expansion of existig pipelines or the
constrction of new resources dictate additions only
every few years. This lumpiness provides a cushion for
future growth. Given the economy of scale for pipelie
construction costs, we are aforded the opportunity to
assure that resources are in place to serve future increases
in demad.
RESULTS - PORTFOLIO INTEGRATION
Afer identifYng resource options and evaluating them
based on the considerations detaed earlier in this
chapter (i.e. lead-tie, peak vs. base, usefulness, etc.),
we focused on how to cost effectively solve resource
constraints for the Expected, High and Low Demand
cases. In order to answer this question, we entered the
risk assessed resource options as described in Chapters
3 and 5 and further detaied in Appendi 6.4, 6.9 and
6.10 into the SENDOU~ model to pick the least cost
AvistaCorp 6.172007 Natural Gas IRP
Chapter 6 - Integrated Resource Portolio
400,000
350,000
300,000
250,000
S 200,000
150,000
100,000
Figure 6.18 - WAllO Existing & Best Cost/Risk Resources vs. Peak Day Demand
(Net of DSM Savings) Expected Case - November through October
50,000
--_._._....~~_.-1=1==1==I~1=1m7m7-~!!r:¡.-----::~¡.f-f----------------------f-f-f-f----------------f-f-f-f------------------¡-f-f-- -----------------¡-f-f-f---------------f-f-f-f-f----------
-+-+-+-+-+4-4-4-4-4--t -t -t -+-+-+-+-+-+o ~ ~#~~~~~#~~~#&##d###~~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~#~~~$$$~~~$~~#######
=~i~:g/l GR1Jease Recall =~~~x~~1& GTN Cap Purc 1 =~~ni&~~2& GTN cap Purc 2
.. Peak Day Demand
200,000
180,000
160,000
140,000
120,000
S 100,000
80,000
60,000
40,000
20,000
Figure 6.19 - OR Existing & Best Cost/Risk Resources vs. Peak Day Demand
(Net of DSM Savings) Expected Case - November through October
1-----1-~I~IF--""~I::-=- ---::-=- -¡- f- f-~-- ---~--=---------¡-f-f-----------------f-f-f----------------f-f-f-f------------------f-f-f-f-----------------f--f-f------
-t -t -+-+-+-+-+-+-+-+-+4-4-4-4--t -t -t -+o
r:~'ò r:~0, r:..~ r:.... r:..r¡C'? 1/'1 pf'V i:'V -:'1rG~ rGr: rGG 4' rG..
_Existing GTN
_Backhaul Med Lat
_ La Grande Dist Enhance
r:..": r:~ r:.."; r:..'ò r:~ r:..'ò r:..0, r:rG 0-.. r:r¡r¡ é' r:~ r:1' r:r! r:rV~'V ":'V bt'V (,'1 fó'V ~ ~ 'l'V Of'V i:rG -:'1 n:'V f''V bt'V ft'V 1c'V
rG.. rG.. rG'" rG" rG'" rG.. rG'" rG" rG'V rGr¡ rG"v rG"v rG'V rG'" rG'V_Existing TF-1 _Existing TF-2 _ Existing Wil Peaking
_ Klam Lat Puchase InnnnnlCapacily Release Recall _ Mad Lat Expan 1
_Med Lat Expan 2 ""Peak Day Demand
approach to meeting resource deficiencies. SENDOUTQl
compares demand-side and supply-side resources and
determìnes, based on a PVR analysis, which resource is
the least cost.
Figures 6.18 and 6.19 summrize the results of this
modeling effort by comparing regional peak day
demand aganst existing and incremental resources for
the Expected Case over the 20-year period of the plan.
6.18 2007 Natural Gas IRP AvistaCorp
...........................................
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Chapter 6 - Integrated Resource Portolio
500
450
400
350
300
~ 250:i
Figure 6.20 . Load Duration Curve & Resource Stack (with DSM) Average/Actual Weather w/Peak Day
Expected Case - WAIID
200
150
100
50
o
31 61 91 121 151 181 211 241 271 301 331 361
Days."p"Storage Inejections Post 2011 b¡'Storage Injections 'OU081I1I1'17l18 _'07l08 _'27l28
-Current Resources
200
180
160
140
l 120
:I 100
80
60
40
20
o
Figure 6.21 . Load Duration Curve & Resource Stack (with DSM) Average/Actual Weather w/Peak Day
Expected Case - OR
31 61 91 121 151 181 211 241 271 301 331 361
Days
11*!lt4!! Storage Injection Post 2011 rii! Storage Injections '07/08 _ '27l28 .. '17 l18 _ '07l08 - Current Resources I
Companion figures for the High and Low Demand cases
are avaiable in Appendi 6.5.
opportunity to compare al demad days withi that
year. Although it appears that there is excess capacity
during the non-winter periods, the company utizes ths
capacity for storage injections and optimization through
capacity releases and buy/sell opportunities. Simiar
figures for the High and Low Demand cases are in
Appendi 6.6.
Figures 6.20 and 6.21 show the load duration curves
as well as the current resource stack for the Expected
Case. These graphics compare an entire year of demand
to the resource stack for that same year. This enables a
review of not just peak day suffciency but alows the
AvistaCorp 6.192007 Natural Gas IRP
Chapter 6 - Integrated Resource Portolio
Table 6.6 - Least Cost Supply-Side Resource Additions Selected by SENDOUT'
Expected Case
Type
Quantity
Dlh/d Rates/Charges NotesTiming
SENDOUTil considers al resource options (both
demad-side and supply-side) entered into the program,
determines when and what resources are needed, and
rejects options that are not cost effective. These selected
resources represent the least cost solution, within given
constraints, to serve anticipated customer requirements.
Table 6.6 shows the SENDOUTil selected supply-side
resources for the Expected Case. Table 6.7 shows the
SENDOUTil selected DSM savigs for the Expected
Case. The High and Low Demad case duration curves
can be found in Appendi 6.6 whie DSM savings are in
Appendi 6.8.
Through ongoing and evolving investigation and
research, we may determine that alternative resources
are more cost effective than those resources selected in
this IRP. We wi continue to review and refine our
knowledge of resource options and wi act to secure
these best cost/risk options at the appropriate point in
tie.
6.20 2007 Natural Gas IRP AvistaCorp
...........................................
...........................................
Chapter 6 - Integrated Resource Portolio
Table 6.7 -Annual Demand, Annual Average Demand and Peak Day Demand
Served by Demand-Side Management
Dally Peak Day
Annual Daily Peak Day Annual La Daily La Peak Day La Annual Daily Peak Day Annual Roseburg Roseburg
Klamah DSM Klamath DSM Klamath DSM Grande DSM Grande DSM Grande DSM Medford DSM Medford DSM Medford DSM Roseburg DSM DSM
Case Gas Year (Moth) (MDthday) (MDthday) (MDth) (MDtday) (MDth/day) (Moth) (MDth/day) (MDth/day) DSM (MDth) (MDthday) (Moth/day)
Expected ~nn~ ~nno 3.589 1.695 1.030 0.080 3.112 0.009 0.020
Expected 2009-2010 11.112 5.072 1.091 0.250 9.303 0.025
Expected -2012 8.580 8.829 1.152 0.410 15.561 0.043
Expected 5.927 I.UlJU 1.213 0.580 21.708 0.059
Expected 2.318 1.0 1.288 0.760 ry7ry"7
Expected 17.37.091 1.1'1.321 0.900
.pectec 19-2020 42.01.).1 :U.""lJ I.IOU 1.363 1.060 0.250
.pec ec 2021-2022 48.821 0.134 :2.407 1.180 1.394 1.200 0.300
.pec ec 2023-2024 53.570 0.147 :4.424 1.210 155.608 1.426 1.340 0.330
.pec ec 57.956 0.159 26.309 0.230 165.904 0.455 1.480 0.370
E.pec ec 62.673 0.171 28.324 0.250 183.044 0.500 1.620 45.051 0.390
Daily Oregon
DSM
(MDthday
Peak Day
OregonDSM
(MDth/day)
REGULATORY REQUIREMENTS · described our plan for resource acquisitions
between plang cycles;
· taken planning uncertainties into consideration;
and
· involved the public in the plannng process.
IRP reguatory requirements in Washigton, Oregon and
Idao require several key components in our plan. We
must demonstrate we have:
· exaned a range of demad forecasts;
· exaned feasible means of meeting demad
including both supply-side and demand-side Throughout this document, we have addressed the
applicable requirements. Recent ruemaking in Oregon
has provided further guidance. Order UM 1056 outlnes
resources;
· treated supply-side and demand-side resources
equaly;
· described our long term plan for meeting
expected load growth;
AvistaCorp 2007 Natural Gas IRP 6.21
Chapter 6 - Integrated Resource Portolio
13 guidelines where we must demonstrate we have
addressed the following areas:
· Substantive requirements
· Procedural guidelines
· Plan fing, review and updates
· Pla components
· Transmission (Tranportation)
· Conservation
· Demand Response
· Environmental costs
· Direct access loads
· Multi state utities
· Reliabilty
· Distributed generation
· Resource acquisition
Appendi 6.11 lists the specific requirements of the
guidelines and describes our compliance.
One area that warrants specifc discussion is risk and
uncertanty Our approach in addressing this requirement
was to identify the factors that could cause signficant
deviation from our Expected Case planng conclusions.
We employed analytcal methods for each of our load
forecasting assumptions, including use per customer,
weather, customer growth rates and price elasticity
Inadequate consideration or evaluation of these factors
could signcantly impair the planning process and its
effectiveness. We have modeled High and Low Demand
alternatives, incorporated price elasticity considerations,
performed prelinar analysis on our peak weather
planng standard, run simulations in VectorGas™ and
integrated customer growth forecasting in distribution
plang with town code refinements.
Beyond these direct modeling considerations, we also
considered the consequences of insuffcient tielines
for resource acquisition or development, cost overruns
and siting/permitting risks. Infastructure outages were
also identified as a risk area potentialy disrupting plan
execution. We are exploring ways to better integrate
these tyes of uncertainties into our planng process.
ACTION ITEMS
We will refine our specific resource acquisition action
plans for Klamth Fals and Medford servce areas that
address the projected unserved Expected Case demand in
2011-2012 and 2013-2014, respectively. We wi monitor
timelines, miestones, status and progress reporting,
ongoing plan risk assessment and consideration of
alternative actions.
For Klamath Falls we will:
· reassess the necessary operational steps and tig
(current estite six months) to acquire the
Klamth Fals Lateral;
· monitor actual demad trends to forecasted
demad to refine a target date for initiating the
purchase of the latera.
For Medford we will:
. commssion a pipeline expansion study from GTN
to identify specifc costs and issues;
· monitor actual demad trends to forecasted
demand to refine the timing of action plan steps;
· assess the impacts of project tig from possible
changes in our weather planning standard.
We will reevaluate our current peak day weather
plannng standard to ascertain if it sti provides the
best risk-adjusted methodology in evaluating resource
plannng.
We wi meet regularly with Commssion Staf members
to provide information on maket activities, any material
changes to risk management programs, and signficant
changes in assumptions and/or status of company activity
related to the IRP or procurement practices.
6.22 AvistaCorp2007 Natural Gas IRP
...........................................
...........................................
Chapter 6 - Integrated Resource Portolio
CONCLUSION
We have chosen to utie the Expected Case for our
operational plannng activities because this case is the
most liely outcome given company experience, industr
knowledge and our understandig of future ga markets.
This case provides for reasonable demand growt given
current expectations of natural gas prices over the
planng horizon. If realzed, ths case is at a level that
alows us to be reasonably well protected aganst resource
shortages and does not over commt to additional long-
term resources. Given the extreme increase and decrease
in demad levels over the full plannng horizon for the
High and Low Demand cases respectively, we believe that
these cases are possible but less liely.
Our resource analysis indicates several strategies that
should be pursued to fully optimize avaiable resources.
The effectiveness of any strategy wi be in the flexibilty
to take advantage of market opportnities. These
strategies indicate that:
· Because of the diverse weather withi our servce
territory, a total system supply portolio should
be mantaned to provide the greatest flexibilty
for dispatching resources whie mantaining lower
supply costs.
· We wi continue to benefit from pursuing
diversifcation of our firm trsportation sources
via GTN and NW Flexibilty is the key to be
able to cost-effectively utilize the lowest priced
delivered supply.
· Capacity releases and recals, both long-term
and short-term, should continue to be reviewed
periodicaly.
We wi continue to monitor demad levels and peak
day requirements for signposts (e.g. greater than expected
customer growth) that indicate that demand levels are
moving toward another case. We also plan to aggressively
model various potential outcomes around price and
weather usingVectorGas™ to assess demand implications
from these factors. We believe that through this analysis
and monitoring process, and given tht we have sufcient
tie before potential resource shortages, there is little
chance of being surprised by resource shortages.
Avista Corp 6.232007 Natural Gas IRP
...........................................
Chapter 7 - Avoided Cost Determination
7. AVOIDED COST DETERMINATION
Avista's avoided cost estimates represent the marginal
cost of natural gas usage incremental to the forecasted
demad. 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 maagement measures reduce
customer demad, the company is able to "avoid" certai
commodity and transportation costs. This concept is
important to assessing the proper value to demad-side
maagement efforts.
METHODOLOGY
To develop avoided cost figures associated with the
reduction of incremental natural ga usage, a demad
forecast, existing and future supply-side resources and
demand-side resources are required. Avista utizes the
SENDOUTI! model data used throughout this IRP to
produce avoided cost figures. The company assumes the
Expected Case as the appropriate data set for the analysis
of avoided costs.
SENDOUTI! functionalty provides magina cost data
by day, month and year for each demad area. This
marginal cost data includes the cost of the next unit of
supply and the associated tranportation charges to move
this unit.
AVOIDED COST DETERMINATIONS
Avista has summized the SENDOUTI! calculated
avoided cost data in Appendi 7.1, which has been
divided into annual and winter costs and is averaged
accordingly. Winter season costs are most appropriate
when considering heat related avoided costs. Anual
costs are most appropriate when considering non-heat
(base load) related avoided costs.
Note that Appendi 7.1 detais avoided cost figures for
each operating division discussed in this IRP. Also note
that figures are stated in real dollars per Dth.
A graphical depiction of the avoided costs for the
Washington/Idao and Oregon areas for annual and
witer-only Dth usage is represented in Figure 7.1.
These avoided costs exclude environmental externalty
adders.
$11.00
$10.00
$9.00
$8.00
.cÕ $7.00..
$6.00
$5.00
$4.00
Figure 7.1 . Natural Gas Avoided Costs 2007$/Dth
Includes Commodity & Trans. Costs/Excludes Env. Ext. Adder - November through October
-----.~--~~~~--~.--------_._-----_._-~-._----_.~--
$3.00 # # ~ ~ # ~ ~ ~ ~ ~ ~ ~ # & # #ggg¿~ ~ ~ ~ .~ n~ ~ ~ ~ ~ A~ ~ ~ ~ .~ n~ NV .V .V .V~' r:'l r:C! .." ..' ..v "" .. ';J .." ..' ..'0 "J W 0;' o;v Q,J # Q,': Q,":~~~~~~~~~~~~~~~~~~~~
I~WAlID Annual _ORAnnual -'WAIID Winter -*ORWinter I
AvistaCorp 7.12007 Natural Gas IRP
Chapter 7 - Avoided Cost Determination
ENVIRONMENTAL COSTS AND EXERNALITIES
(OREGON JURISDICTION ONLY)
The methodology employed to develop the avoided
costs associated with the reduction of incrementa natural
gas usage have been based upon the monetar value
associated with commodity and tranportation costs only.
These avoided cost streams do not include environmental
externalty costs related to the gathering, tranmission,
distribution or end-use of natural ga.
Per traditiona economic theory and industr practice,
an environmenta externalty factor is tyicaly added to
the monetar avoided cost when there is an opportunity
to displace traditional supply-side resources with an
alternative resource lacking adverse environmental
impact. Per the requirements established by UM 1056
(see excerpt below) environmental compliance cost
adders should be considered when evaluating natural ga
resource options.
UM 1056, Guideline 8 - Environmental Costs
"Utilities should include, in their base-case analyses, the
regulatory compliance costs they expect for carbon dioxide
(CO:¿, nitrogen oxides (NO), sulfur oxides (SO:¿,
and mercury (Hg) emissions. Utilities should analyze
the range of potential CO2 regulatory costs in Order
No. 93-695,jrom $0 - $40 (1990$). In addition,
utilities should peiform sensitivity analysis on a range of
reasonably possible cost adders for nitrogen oxides (NO),
sulfur dioxide (SO:¿, and mercury (Hg), if applicable."
Avista's current direct gas distribution system
infastrcture does not result in any CO2, NOx, S02'
or Hg emissions. Upstream gas system infastrcture
(pipelines, storage facilties, and gathering systems),
however, do produce CO2 emissions via compressors
used to pressurize and move natural gas. Accessing
CO2 emissions data on these upstream activities to
perform detaied meanngfl analysis is chalenging
but increasingly important given building momentum
around legislative developments regarding greenhouse
gas emissions and the movement toward the creation of
carbon cap-and-trade markets. As these markets develop
and mature it may be possible to develop a reasonable
quantification of these values. Given the wide diversity
of scenarios and current lack of information avaible
from al upstream ga system components, it was not
possible to complete a detaied analysis of CO2 emissions
related to upstream natural gas gathering and distribution.
However, we have performed analysis on the pipeline
transportation infrastructure that we rely on to supply
our servce territories.
To the extent that natural gas-effciency programs reduce
overa end-use demad, there will be reductions in CO2
emissions resulting from the compression needed for
transmission as well as at the end-use itself. Of al the
emissions, carbon dioxide could have the greatest impact
on the company. A national carbon tax on greenhouse
ga emittng activities would be the most liely
mechanism for passing through the costs of emissions.
If a carbon tax were to be imposed, more DSM resources
would become cost-effective. A carbon tax at the $8
per ton level would add $0.07 cents per thermo A $40
per ton tax adds approximately $0.35 cents per thermo
At this level, several of the marginal non-cost-effective
measures would become cost-effective.
CONSERVATON COST ADVANTAGE
For this IRp, our natural gas DSM implementation
planng process has incorporated a 10 percent
environmental externalty factor into our assessment
of the cost-effectiveness of existing DSM program.
Additionaly our assessment of prospective DSM
opportunities is based on an avoided cost stream that
includes the same consideration of envionmental
externaities. When appropriate, these evaluations and
resource decisions are based on progra impacts, makets
and envionmental impact that are as geographicaly
specifc as possible.
7.2 AvistaCorp2007 Natural Gas IRP
...........................................
...........................................
Chapter 7 - Avoided Cost Determination
ADDITONAL AVOIDED COST ANALYSIS
Avista wi fùe revised cost-effectiveness limits (CELs)
based upon the updated avoided costs available from
this IRP process. We are planning on investigatig the
applicabilty of recently completed quantications of
electric distribution capacity the customer vaue of risk
reduction and greenhouse gas emissions to determine
if simar quantifications are possible for our natural gas
system. It is possible that this analysis wi result in a
revision to the company's CEL filing in early 2008.
AvistaCorp 2007 Natural Gas IRP 7.3
...........................................
Chapter 8 - Action Plan
8.ACTION PLAN
2006 ACTION PLAN REVIEW counties, two in Washington and three in Idaho. This
wi help identi differential growt patterns between
the core areas (Spokae and Coeur d'Alene) and the
more rural and resort areas of the servce area.
The 2006 action pla foc1lsed on five areas:
· Sales Forecasting
· Supply/Capacity
· Forecasting
· Demad-Side Management
· Distribution Planing
In 2007, utiizing the data and forecasts from these
additional counties, we wi develop a "gate-station"
forecasting system that wi alocate the sales and
customer forecast to the various pipeline delivery points
in the servce area. We anticipate having this system
avaible so that we can utie the results for the next
A discussion of the specific action items and the plan
results follows.
SALES FORECASTING
Action Item:
IRP
During 2006, we wi update customer forecasting
models, incorporating the most recent data. The
dramatic increase in natural gas retai prices wi provide
improved information on price elasticity and weather
sensitivity coeffcients.
Results:
We now purchase economic forecasts for 15 of the
21 counties we serve. We combined ths data with
company-specific knowledge to develop our 20 year
customer forecast. We have also incorporated sub-
area core customer forecasting at the town code level
into our customer forecasting process which is utiized
in distribution system planning thus integrating our
customer forecasting and distribution planig effort.
We anticipate mang two changes to the forecasting
methodology, one in 2006 and the other in 2007. We
currently use county-level forecasts for eight counties in
the three states we serve. During 2006, we wi add five
Avista Corp 2007 Natural Gas IRP 8.1
Chapter 8 - Action Plan
SUPPLY ICAPACITY
Action Item:
We wi conduct regular meetings with Commssion
Staf members to provide information on market updates,
material changes to our hedging program, and significant
changes in assumptions and status of company activity
related to the IRP.
We wi continue to seek low-cost peakng resources that
do not require anual contractual commtments and wi
investigate acquisition of winter capacity releases from
thid-party providers.
We wi further our understading of LNG
opportunities, including satellte and company-owned
LNG resources. We wi consider and evaluate the Coos
Bay LNG/Pacific Connector Pipelie opportunity.
We wi assess methods for capturing additional value
related to existing storage assets, includig but not
limited to recalng some or al of the current releases.
We wi further develop its storage strategy with
particular focus on storage opportunities for Oregon
customers and wi research non-Jackson Prairie storage
prospects for al customers.
Results:
We have reguarly met with Commssion Staf members
as schedules permitted to provide maket updates,
material changes to our hedging program and other
IRP related topics.
Thus far we have not identied any cost effective
avaiable peakng resources. We wi continue to monitor
avaiabilty of winter capacity releases from third party
providers.
Lack of readiy available data on company owned
LNG resource development has precluded us from
signficandy advancing our knowledge on specific
development detais including costs, scalbility, permittng
and timelies. We wi increase our efforts in this area
including inquiries of other neighboring utities that
have developed LNG assets and currendy have them in
their resource portfolio.
With respect to large-scale LNG, we have participated in
several forums, conferences and meetings with sponsors
on the projects contemplated in our region. We have
alo parcipated in the open seasons of two projects in
our region contingendy reserving capacity. We contiue
to monitor developments in this area including the
securing of dependable supply which we believe poses a
signifcant chalenge for project sponsors.
We have recaled our Jackson Praiie storage capacity
with Teresen reganing al this capacity on May 1,2008.
We have identied the current capacity and delivery
expansion activity at Jackson Prairie and an expected
recal of capacity from Avista Energy in 2011 to develop
a storage assets plan that wi alocate these storage assets
between our Washington/Idaho customers and our
Oregon customers on a 75 percent125 percent ratio. In
June 2007, we also acquired term storage capacity rights
in the Mist underground storage project in order to serve
our Oregon customers.
FORECASTING
Action Item:
We wi complete our evaluation ofVectorGas™. If
purchased, we will utie VectorGas ™ to strengthen
Avista's abilty to analyze the financial impacts under
varyng load and price scenarios.
Results:
We have acquired the VectorGas TM module as part of the
SENDOUTiI softare and have begun modeling varng
load and price scenarios.
8.2 AvistaCorp2007 Natural Gas I RP
...........................................
...........................................
Chapter 8 - Action Plan
DEMAND-SIDE MANAGEMENT
Action Item:
The DSM analysis that occurred during the IRP process
is the launching point for a more detaied investigation of
the natural gas-effciency technologies identified as cost-
effective resource options. We initiated this additional
evaluation and development of program in Januar 2006
with the expectation that program revisions and the
launch of new progra wi occur in the spring of that
same year.
We have explicitly recognized within this IRP the
obligation to achieve al natura gas-effciency resources
avaiable though the intervention of cost-effective utity
program. Given the rapid changes within the natural
ga maket, there are may new effciency opportunities
within the market. Considerable uncertainty remas
regarding the customer response to these program. This
uncertainty does not preclude us frm pursuing the
planned aggressive ramp-up of natural gas-effciency
programs. Additionaly, we have and wi actively seek
opportunities for new or enhanced resource acquisition
through the development of cooperative regional
programs.
Results:
We have and wi continue to actively seek opportunities
for developing new DSM programs as well as enhancing
existing offerings. The company is on track to meeting
our long-term goal of acquiring al cost-effective natural
ga resources achievable through utity intervention.
DISTRIBUTION PLANNING
Action Item:
We will continue to utize computer modeling to
faciltate distribution-planing effort and identify least
cost opportunities to meet growth and reinforcement
needs. We wi determine the benefit and feasibilty of
using citygate station forecasts as a method for improving
distribution planing.
Results:
Our evaluation into refining projected customer growth
into smaer geographic areas produced a system that
utizes town code growth rates as the forecasting unit.
These smaer, specific-area growth rates faciltate an
improved integrated planng effort.
AvistaCorp 8.32007 Natural Gas IRP
Chapter 8 - Action Plan
2008-2009 ACTION PLAN
The 2008-2009 action plan is derived from the action
items identied in the following chapters:
CHAPTER 2 - DEMAND FORECAST
Action Item:
We wi further integrate the VectorGas™ module in
our SENDOUTiI modeling softare to strengthen our
abilty to analyze the demad impacts under varyng
weather and price scenarios as well as conduct sensitivity
analysis to identify, quantify and manage risk around
these demad infuencing components.
Action Item:
We wi study ways to further refine our ability to model
demand by region. Town code forecasting was the first
step in enhancing our demad forecasting. We now want
to explore incorporating these town code forecasts into
regions for analysis in SENDOUTiI especialy within the
broad Washington/Idaho division to investigate potential
resource needs that may materialze earlier than the
broader region indicates.
CHAPTER 3 - DEMAND-SIDE MANAGEMENT
Action Item:
The IRP analysis has indicated a set of cost-effective
measures and acquirable resource potential for a future
DSM portfolio. We have established tagets for first-
year energy savings goal for 2008 of 1,425,000 therms
in WA/ID and 350,000 therms in Oregon. In 2009
the goal for first-year energy savings are 1,581,000
therms in WA/ID and 300,000 therms in Oregon. The
completion of the IRP analysis is the midpoint, not the
end point, of a larger reassessment of the DSM resource
portfolio. Further evaluation is required to facilitate the
development of program plans and to incorporate them
into an updated DSM implementation plan. Following
detaied investigation of the natural gas-effciency
technologies identied as cost-effective resource options,
we wi incorporate these efforts into the larger Heritage
Project ramp-up of Avista's energy-effciency efforts.
Action Item:
We wi file our cost-effectiveness limits (CEL's) based
upon the avoided costs derived from this IRP process.
Additionaly, we are investigating the applicabilty
of recently completed quantifcations of electric
distribution capacity, the customer value of risk reduction
and greenhouse ga emissions to determine if simr
quantifications are possible for our natural gas system.
CHAPTER 5 - SUPPLY SIDE RESOURCES
Action Item:
We wi continue to monitor several issues identied
in this chapter with respect to commodity storage and
supply resources. These include:
· tight production/productive capacity;
· pipeline constraints in our region;
· pipeline expansions that move volumes away from
our region;
· pipeline cost escalations; and
· lage scale LNG activity.
Action Item:
We wi refine our analysis of acquiring or constructing
resource alternatives to improve project cost estimatig,
assessment of project feasibility issues, determination of
project siting issues and risks, and improved accuracy of
constrction/acquisition lead times. Specificaly, we wi
further study these issues with respect to satellte LNG,
company owned LNG, pipeline expansions, distribution
system enhancements and storage facility diversification.
We wi explore creative, non-traditional resource
possibilties to address our needle peakng exposures
with emphasis on potential structured trnsactions (e.g.
transportation and storage exchanges) with neighboring
utilities and other maket partcipants that leverage
existing regional infrastructure as an alternative to
incrementa inastructure additions.
8.4 AvistaCorp2007 Natural Gas IRP
...........................................
...........................................
Chapter 8 - Action Plan
Action Item:
We wi contiue to assess methods for capturing
additional value related to existing storage assets,
including methods of optimizing recently recaled
releases whie implementing its storage strategy of
providing balanced storage opportunities. This includes
exploring storage diversification options including
AECO and Northern Calornia facilties.
Action Item:
We wi contiue to analyze natural ga procurement
practices for strategy enhancing ideas such as basis
diversification, storage injection/withdrawal ting and
structured products.
Action Item:
Since much of our supply comes from Candian natural
gas exports, the notion that this supply could diminish
signficantly is of concern. We wi continue to monitor
the discussion around dinishig Canadian gas exports
looking for signals that indicate increased risk of
disrupted supply over the 20-year plannng horizon.
CHAPTER 6 - INTEGRATED RESOURCE PORTFOLIO
Action Item:
We wi refine our specific resource acquisition action
plas for Klth Fals and Medford servce areas that
address the projected unserved Expected Case demad in
2011-2012 and 2013-2014, respectively. We wi monitor
tielines, miestones, status and progress reporting,
ongoing plan risk assessment and consideration of
alternative actions.
For Klamath Falls we will:
· reassess the necessary operational steps and timing
(current estimate six months) to acquire the
Klth Fals Lateral; and
· monitor actual demad trends to forecasted
demand to refine a target date for initiating the
purchase of the lateral.
For Medford we will:
· commssion a pipeline expansion study from GTN
to identi specifc costs and issues;
· monitor actual demad trends to forecasted
demad to refine the ting of action steps; and
· assess the impacts of project ting from possible
changes in our weather planning standard.
Acton Item:
We wi reevaluate our current peak day weather standard
to ascertain if it sti provides the best risk-adjusted
methodology in evaluating resource planning.
Action Item:
We will meet regularly with Commssion Staf members
to provide information on maket activities, material
changes to risk management programs, and signficant
changes in assumptions and/or status of company activity
related to the IRP or procurement practices.
AvistaCorp 8.52007 Natural Gas IRP
...........................................
Chapter 9 - Glossary of Terms and Acronyms
9. GLOSSARY OF TERMS AND ACRONYMS
Backhaul
A transaction where ga is transported the opposite
direction of norma flow on a unidirectional pipeline.
Base Load
As applied to natural gas, a given demad for natura gas
that remas fairly constant over a period of time, usualy
not temperature sensitive.
Basis Difrential
The difference in price between any two natural ga
pricing points or time periods. One of the more
common references to basis dierential is the pricing
difference between Henr Hub and any other pricing
point in the contient.
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 approxitely equivalent to 100 cubic feet
of natural gas.
City gate
(Also known as gate station or pipeline delivery point)
The point at which natural gas deliveries transfer from
the interstate pipelines to Avista's distribution system.
Commodity Price
The current price for a supply of natural gas that
is charged for each unit of natural gas supplied as
determined by market conditions.
Compression
Increasing the pressure of natural gas in a pipeline by
means of a mechanicaly driven compressor station to
increase flow capacity.
Core Load
Firm delivery requirements of Avista, which are
comprised of residential, commercial and firm industrial
customer demad.
Curtailment
A restriction or interruption of natural gas supplies or
deliveries; it may be caused by production shortages,
pipeline capacity or operationa 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 mion BTUs (energy).
Demand-Side Resources
Energy resources obtaied through assisting customers to
reduce their "demad" or use of natural gas.
Demand-Side Management (DSM)
The activity of implementing demad-side measures to
minie customers' energy usage in their facilties.
End User
The ultimate consumer of natural gas; the end user
purchases the natural ga for consumption, not for resale
or transportation purposes.
External Energy Effciency Board
Also known as the "Triple-E" board, this non-binding
external oversight group was established in 1999 to
provide Avista with input on demad-side maagement
issues.
Externalities
Cost and benefits that are not reflected in the price paid
for goods or servces.
Federal Energy Regulatory Commission (FERC)
The government agency charged with the reguation and
oversight of interstate natura 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 (Firm Service)
Servce offered to customers under schedules or contracts
that anticipate no interruptions; the highest qualty of
service offered to customers.
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Chapter 9 - Glossary of Terms and Acronyms
Force Majeure
An unexpected event or occurrence not withn the
control of the parties to a contract, which alters the
application of the terms of a contract; sometimes referred
to as "an act of God;" exaples include severe weather,
war, strikes, pipelie faiure and other simiar events.
Forward Price
The future price for a quantity of natural ga to be
delivered at a specifed tie.
Gas Transmission Northwest (GTN
One of the five natural ga pipelines the company deal
with directly; GTN is headquartered in Portland, Ore.,
and it is a subsidiar ofTransCanada Pipeline; owns and
operates a natural gas pipeline that runs from Canda to
the Oregon/Calfornia border.
Geographic Information System (GIS)
A system of computer softare, hardware and spatialy
referenced data that alows information to be modeled
and analyzed geographicaly.
Global Insight, Inc.
A national economic forecasting company.
Heating Degree-Day (HD)
A measure of the coldness of the weather experienced,
based on the extent to which the daily average
temperature fals below 65 degrees Fahenheit; a day
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
recognzed as the most important pricing point in the
United States. It is alo the trading hub for the New
York Mercantie Exchange (NYMEX).
Injection
The process of putting natural gas into a storage facility
Integrated Resource Plan (IRP)
The document that explains Avista's plans and
preparations to mantai suffcient resources to meet
customer needs at a reasonable price at acceptable risk.
Integrity Management Plan (IMP)
A federaly regulated program that requires companes to
evaluate the integrity of their natural gas pipelines based
on population density. The program requires companes
to identi high consequence areas, assess the risk of
a pipeline failure in the identified areas and provide
appropriate mitigation measures when necessary.
Interptible (Interruptible Servce)
A servce oflower priority than firm servce offered
to customers under schedules or contracts that
anticipate and permit interruptions on short notice;
the interruption happens when the demand of al
firm customers exceeds the capabilty of the system to
continue deliveries to al of those customers.
IPUC
Idao Public Utities Commssion
Jackson Prairie Storage Project (J or JPSP)
An underground storage project jointly owned by Avista
Corp., Puget Sound Energy, and NW; the project is a
naturaly occurring aquifer near Chehals, Washington,
which is located some 1,800 feet below ground and
capped with a very thick layer of dense shae.
Liqueaction
Any process in which natural ga is converted from the
gaseous to the liquid state; for natural gas, this process is
accomplished though lowering the temperature of the
natural gas (see LNG).
Liquefed Natural Gas (LG)
Natural ga that ha 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 constraits; this method is utized in the
SENDOUT~ Gas ModeL.
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Chapter 9 - Glossary of Terms and Acronyms
Load Duration Curve
An array of daily sendouts observed that is sorted from
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 mamum load; can be
calculated over any time period.
Local Distribution Company (IC)
A utity that purchases natural gas for resale to end-
use customers and/or delivers customer's natural gas or
electricity to end users' facilties.
Looping
The construction of a second pipeline paralel to an
existing pipeline over the whole or any part of its lengt,
thus increasing the capacity of that section of the system.
MMcf
A unit of volume equal to a mion cubic feet.
MDQ
Maxum Daily Quantity
MMTU
A unit of heat equal to one mion British therma units
(BTUs) or 10 therms. Can be used interchangeably with
Dth.
National Energy Board
The Canadian equivalent to the Federal Energy
Regulatory Commssion (FERC).
National Oceanic Atmospheric Administration (NOAA)
Publishes weather data; the 30-year weather study
included in this IRP is based on ths information.
Natural Gas
A naturaly occurring mire 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 SENDOUTiI Gas Planning
System.
New York Mercantile Exchange (NEX)
An orgazation that faciltates the trding of several
commodities including natural gas.
Northwest Pipeline Corporation (NWP)
The principal interstate pipeline servng the Pacifc
Northwest and one of six natural gas pipelies the
company deal with directly; NW is Avista's prima
transporter of natural ga; headquartered in Salt Lake
City, Uta, NW is a subsidiary ofThe Wilam
Companies.
NOVA Gas 1ransmission (NOVA)
See TransCanada Alberta System
Northwest Power and Conseration Council (NWPPC)
A regional energy planning and analysis organization
headquartered in Portlad, Ore.
OPUC
Public Utity Commssion of Oregon
Peak 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, Avista calculates peak day demad
based on the coldest day on record.
Peaking Capacity
The capabilty of facilties or equipment normay used
to supply incremental natural gas under exteme demad
conditions (i.e., peaks); generaly avaible for a limited
number of days.
Peaking Factor
A ratio of the peak hourly flow and the total daiy flow
at the citygate stations used to convert daiy loads to
hourly loads.
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Chapter 9 - Glossary of Terms and Acronyms
Prescriptive Measures
Effciency applications that are relatively uniform in
their characteristics, in which the utity has the option
to define a stadadized incentive based upon the tyical
application of the effciency measure. This standadized
prescriptive incentive takes the place of a customized
calculation.
PSIG
Pounds per square inch (guage) - a measure of the
pressure at which natural gas is delivered, someties
referred to as PSI.
Puget Sound Energy
A natural gas local distribution company headquartered
in Bellevue, Washington, servng customers in Western
and Central Washington.
Resource Stack
Sources of natural gas infastrcture or supply avaible to
serve Avista's customers.
Seasonal Capacity
Natural gas trsportation capacity designed to servce in
the winter months.
Sendout
The amount of natural ga consumed on any given day.
SENDOU~
Natural gas planng system from New Energy
Associates; a linear programg model used to solve ga
supply and transportation optimization questions.
Servce Area
Geographic territory in which a utility provides natural
gas servce to customers.
Shoulder Months
Generaly defined as the months of March, April and
May (in the spring) or September and October (in the
fal) when the temperatures are moderate and customer
demand is variable.
Storage
The utization of facilties for storing natural gas which
has been transferred from its original location for the
purposes of servng peak loads, load balancing and the
optization of time spreads; the facilties are usualy
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 facilties may be ma-
made or natural caverns. LNG storage facilties generaly
utie above ground insulated tank.
Tarif
Published reguated rate schedules includig general
terms and conditions under which a product or service
wi be supplied.
TF-l
NW's rate schedule under which Avista moves natural
ga supplies on a firm basis.
TF-2
NW's rate schedule under which Avista moves natural
gas supplies out of storage projects on a firm basis.
1èchnical Advisory Committee (TAG)
Industr, customer and regulatory representatives that
advise Avista during the IRP planning process.
Terasen
A natural gas LDC headquartered in Vancouver, British
Columbia, servng 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 therma units (BTU); also
approximately equivalent to 100 cubic feet of natural gas.
Tow Code
A town code is an unicorporated area within a county
or a municipalty withn a county.
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Chapter 9 - Glossary of Terms and Acronyms
TransCanadaAlberta System (TCPL-AB)
Previously known as NOVA Gas Tranmission; a natura
gas gathering and transmission corporation in Alberta
that delivers natural gas into the TransCanada BC System
pipelie at the Alberta/British Columbia border; one of
five natural gas pipelies Avista deals with directly.
TransCanada BC System (TCPL-BC)
Previously known as Alberta Natural Gas; a natural
ga transmission corporation of British Columbia that
delivers natura gas between the TransCanada-Alberta
System and GTN pipelines that runs from the Alberta/
British Columbia border to the US border; one of five
natural gas pipelines Avista deals with directly.
Vaporization
Any process in which natural gas is converted from the
liquid to the gaseous state.
~ctorGasTM
A module withn SENDOUTil that faciltates the abilty
to model price and weather uncertainty through Monte
Carlo simulation and detailed portfolio optimization
techniques.
J#ather Normalized
The estimation of the average annual temperature in
a tyical or "norma" year based on exanation of
historical weather data; the norma year temperature is
used to forecast utity sales revenue under a procedure
caled sales normalation.
Withdrawal
The process of removing natural gas from a storage
facilty mang it avaiable for delivery into the
connected pipelines; vaporization is necessar to mae
withdrawals from an LNG plant.
WUTC
Washigton Utities and Transportation Commssion.
AvistaCorp 9.52007 Natural Gas IRP