200912302009 IRP.pdf

,,.~(,~:. :._",1
1009 nEC 30 AH 9: 53 ~"lIl'STll
Dember 29, 200
Jean D. Jewell, Secreta
Idao Public Utilities Commssion
Statehouse Mail
W. 472 Washigton Street
Boise, Idaho 83720
A VU -G-09-06
De Ms. Jewell:
RE: Avista Utilities 200 Natu Gas Integrte Resour Plan
Per IPUC's Integrted Resource Plan Requiments outled in Case No.U-15~165,
Order No. 22299, Case No.GNR-E-93-1, Order No. 24729 and Case No.GNR-E-93-3,
Order No. 25260 , A vista Corpration dllaJ A vista Utilities, hereby submits for filing an
onginal, an electronic copy and 7 copies of its 2009 Natu Gas Integrated Resoure
Plan.
The Company submits the IR to public utility commssions in Idaho, Washigtn and
Oregon every two year as requir by state reguation. The Company has a statutory
obligation to provide reliable natu gas service to customers at rates, terms and
conditions that are fai, just, reasonable and suffcient. The IR, by identig and
evaluating vanous resource options and establishig a plan of action for resoure
decisions, is a signficant component in meetig this obligation.
The 200 Plan highghts the following:
. Our philosophy is to reliably provide natual gas to our customer with an
appropnate balance of pnce stabilty and prudent cost using our portolio of
purhase contrcts, storage and fi pipelie capacity nghts;
. The Company forecasts suffcient natura gas resources well into the futu with
resource needs not occurg until 2018-2019 in Orgon and 2022-2023 in
Washigton and Idao;
. The major chage frm the 2007 IR is a lower demad foreast dnven by lower
economic grwt in our service terntones;
. We continue our puruit of cost effective demand-side management solutions
establishing a 2010 goal to reuce demand by 2,193,00 therms in Washigton
and Idao and 303,00 therms in Orgon; and
. As forecasted demand is relatively flat, we wil monitor actual demand for signs
of increased growth which could acelerate resource nees.
Pleae dit any questions regardig ths report to Greg Rah at [phone].
Sincerely,~.~
Linda Gervais
Manager, Regulatory Policy
State and Federa Regulation
A vista Utilities
509-495-4975
lida. gervais (g avistacorp.com
c: MattElam
II
Rcr. i.!.' .!&_ .",l'¡/
AVU-G..09..06
December 31,2009
www.avistautilities.com
2909 DEC 30 AM 9: 53
TABLE OF CONTENTS
Executive Summry ............................ ................... ....................................... ................ .................... Page 1.1
Introduction................................................................................................................... ............................. 2.1
Demand Forecasts...................................................................................................................... ................ 3.1
Demand-Side Resources ................. .................. .......................... ............................. ........... ........................ 4.1
Supply-Side Resources ............................................................................................................................... 5.1
Integrated Resource Portfolio..................................................................................................................... 6.1
Alterate Scenarios, Portfolios, Stochastic Analysis........... ....................... ..... ................... .................... ...... 7.1
Distribution Planning........................... ................... ........................... ...................... ................. .................. 8.1
Action Plan.......................................................................................................................... ...................... 9.1
Glossary of Ter and Acronyms.............................................................................................................10.1
Note: Appendices provided under separate cover.
SAFE HARBOR STATEMENT
This document contains forward-lookig statements. Such statements are subject to a variety of
risks, uncertainties and other factors, most of which are beyond the Company's control, and many of
which could have a significant impact on the Company's operations, results of operations and
financial condition, and could cause actual results to differ materially from those anticipated.
For a further discussion ofthese factors and other important factors, please refer to the Company's
reports fied with the Securities and Exchange Commission which are available on our website at
ww.avistacorp.com. The Company undertakes no obligation to update any forward-looking
statement or statements to reflect events or circumstances that occur after the date on which such
statement is made or to reflect the occurence of unanticipated events.
2009 Natural Gas IRP
2009 IRP KEY MESSAGES
· A vista has a diversified portfolio of existing natural gas supply resources including owned
and contracted storage, fi capacity rights on six pipelines and purchase contracts from
several different supply basins. Our philosophy is to reliably provide natural gas to customers
with an appropriate balance of price stability and prudent cost.
· Avista's 2009 Integrated Resource Plan (IRP) forecasts lower demand for all service
terrtories than our 2007 plan. These reductions are driven mainly by lower growth rates in
our service terrtories than originally anticipated as a result ofthe severe economic downturn
during this IRP cycle.
· Additional resource needs do not occur until well into the future. In Oregon, resource deficits
occur in 2018-2019 and in Washington and Idaho in 2022-2023. The deficits are driven
primarily by demand growth averaging 1.4 percent and 1.0 percent per year in the respective
jurisdictions. Customer accounts are expected to grow at an annual average rate of2.5
percent and 2.2 percent, respectively. Our plan indicates incremental pipeline transportation
capacity is the preferred resource to meet the identified needs.
· An important risk with the identified future resource deficits is the relatively flat slope of
forecasted demand growth. Implied in this outlook is existing resources wil be suffcient for
quite some time to meet demand. However, should demand growth accelerate, the steepening
of the demand curve could quickly accelerate resource shortages by several years. This "flat
demand risk" requires that we closely monitor signs of accelerating demand and carefully
evaluate lead times to acquire preferred incremental resources.
· Other risks we evaluated include price elasticity variability, climate change policy
uncertainty, long-term availability of supply, weather planning standard alternatives and cost
escalation risks/lead times when acquiring resources.
· Conservation programs are an integral component of our IRP process, as these programs
result in multiple benefits including reduced customers' bils, reduced supply-side resource
needs and reduced greenhouse gas (GHG) emissions. Avista's long-time commitment to
energy conservation and effciency is founded in the belief that these benefits make acquiring
cost effective conservation resources the single best strategy for minimizing energy service
costs to our customers while promoting a cleaner environment.
· We have identified fist-year conservation goals of2,193,300 therms for our North Division
(Washington and Idaho) and 303,300 therm for our South Division (Oregon).
· The IRP identifies and establishes an Action Plan that continues to guide us toward the risk-
adjusted, least-cost method of providing service to our natural gas customers. Included in this
Action Plan are efforts to improve price elasticity modeling, monitor trends for Canadian
natural gas imports, and goals for demand-side management.
2009 Natural Gas IRP
Table 1.1
Table 3.l
Table 3.2
Table 3.3
Table 3.4
Table 3.5
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 7.1
Table 7.2
Table 7.3
Table 7.4
Table 8.1
INDEX OF TABLES
Alternte Demand Scenarios ................................................ ..................................... .Page 1.2
Geographic Demand Classifications................................................................................... 3.1
Basic Demand Formula...................................................................................................... 3.2
SENDOUT(ß Demand Formula ..........................................................................................3.2
Alternate Demand Scenarios .............................................................................................. 3.9
Price Elasticity Assumptions............................................................................................3.10
SENDOUT(ß DSM Results.. .................................................. ............................................4.6
Results of Achievable Resource Potential............... ................... ............ ........... .................4.7
Anual and Cumulative SENDOUTiI Achievable Potential and Revised GoaL.................. 4.9
DSM Sensitivities Sumry ....................................................................................... .....4.11
Existing Fir Transportation & Storage Resources .............. ... ... ...... ... .... ....... ......... 5.6
Alterte Supply Scenarios........................... ........... ................................... ....5.16
Regional Price as a percent of Henr Hub Price ........ ................ .............. .......... .................6.7
Monthly Price as a percent of Average Price ...................................................................... 6.7
Peak Day Demand - Sered and Unsered.................... ............................................ ....... 6.12
Anual, Anual Average and Peak Day Demand Served by DSM.................................... 6.16
Supply-Side Resources Selected in SENDOUT(ß.............................................................. 6.17
Alternate Demand Scenarios.............................................................................................. 7.l
Alternte Supply Scenarios ............................................................................................... 7.8
Net Present Value of Revenue Requirements (PVR) by Portfolio ....................................7.9
Example Monte Carlo Simulation Weather Inputs ........................ .................. ........ .......... 7.10
Distribution Planning Capital Projects ...............................................................................8.7
2009 Natural Gas IRP
Figue I.l
Figue 1.2
Figue l.3
Figue 1.4
Figue 1.5
Figue 1.6
Figure 1.7
Figue 1.8
Figue 1.9
Figue 1.10
Figue 1.11
Figure I.l2
Figue 1.13
Figue 2.1
Figue 2.2
Figure 2.3
Figure 2.4
Figue 2.5
Figure 2.6
Figue 3.l
Figue 3.2
Figure 3.3
Figue 3.4
Figue 3.5
Figue 3.6
INDEX OF FIGURES
System Wide Average Day Demand..........................................................................Page 1.3
System Wide Peak Day Demand .............. ................. .......................... .............................. 1.4
Henr Hub Price Forecasts for IRP .................................................................................... 1.5
First Year Peak Demand Not Met with Existing Resources ............. ........... .................. ...... 1.6
W A/ID Existing Resources vs. Peak Day Demand............................................................. 1. 7
Medford/Roseburg Existing Resources vs. Peak Day Demand........................................... 1. 7
Klamath Falls Existing Resources vs. Peak Day Demand................................................... 1.8
La Grande Existing Resources vs. Peak Day Demand ........... ................................. ............ 1.8
Flat Demand Risk Example ............................................................................................... 1.9
W A/D Selected Resources vs. Peak Day Demand............................................................. 1.9
MedfordIoseburg Selected Resources vs. Peak Day Demand .......... ........... .................... 1.10
Klamath Falls Selected Resources vs. Peak Day Demand................................................. 1.10
First Year Peak Demand Not Met with Existing Resources - Scenario Comparisons ........ 1.11
Customer Make-up..... ............................. ............... .................................. ................. ........ 2.3
Anual Demand ............................ ................... ..................... ............................ ................ 2.3
Seasonal Demand by Serice Teritory and Customer Class............................................... 2.4
Historical Daily Prices....................................................................................................... 2.7
Customer Count - 2007 IR VS. Actuals - OR ResidentiaL............................................... 2.8
Customer Count - 2007 IR VS. Actuals - OR Commercial............................................... 2.8
Customer Growth Scenarios .............................................................................................. 3.3
Example Daily Demand VS. Temperatue Profile................................................................ 3.4
Average vs. Coldest vs. Warest HDDs - Spokane Weather ............................................. 3.5
Average vs. Coldest vs. Warmest HDDs - Medford Weather ............................................. 3.6
Average vs. Plannng Standard Weather - Spokane Weather ............................................. 3.6
Average vs. Plannng Standard Weather - Medford Weather ............................................. 3.7
2009 Natural Gas IRP
Figue 3.7
Figue 3.8
Figue 3.9
Figue 4.1
Figue 4.2
Figue 4.3
Figue 4.4
Figue 4.5
Figue 5.1
Figue 5.2
Figue 5.3
Figue 6.l
Figure 6.2
Figue 6.3
Figue 6.4
Figue 6.5
Figue 6.6
Figue 6.7
Figure 6.8
Figue 6.9
Figue 6.10
Figue 6.11
Figue 6.12
Figue 6.13
INDEX OF FIGURES (CONTINUED)
Reference Case Assumptions .....................................................................................Page 3.8
System Wide Average Daily Demand ..............................................................................3.1 1
System Feb 15 Peak Day Demand.................................................................................... 3.1 1
DSM Methodology Flowchart............................ .......... ..................................... ........... ......4.3
Conservation Supply Cure - North....... .......................... ................................. .................4.5
Conservation Supply Cure - South...... .................. ............. ..... ................ ......................... 4.5
Cumulative Identified Potential vs. Cumulative Acquired - North Division............. .........4.10
Cumulative Identified Potential vs. Cumulative Acquired - South Division...................... 4.10
Monthly Prices - AECO/SUMAS/ROCKIES/Henry Hub .................................................. 5.3
Direct-Connect Pipelines................................................................................................... 5.7
Proposed New Pipelines ................................................................................................... 5.12
SENDOUT(ß Model Diagram................. ............................... .................... ............ .............6.2
Total System Average Daily Demand ................................................................................6.4
Henry Hub Price Forecasts - 2009 $/Dh ...........................................................................6.5
Henry Hub Price Forecasts for IRP - 2009 $/Dth ...............................................................6.6
Henry Hub Price Forecasts for IRP - Nominal $/Dth .........................................................6.6
Existing Fir Transportation Resources - W AID ......... ................................... ................. 6.8
Existing Fir Transporttion Resources - OR ........................................... ........... ..............6.8
North Division DSM Supply Cure, 1 st year (2010) ........................................................... 6.9
South Division DSM Supply Curve, 1 st year (2010) ........................................................... 6.9
W AID Existing Resources vs. Peak Day Demand........................................................... 6.10
MedfordIoseburg Existing Resources vs. Peak Day Demand......................... ................. 6.10
Klamath Falls Existing Resources vs. Peak Day Demand........... ................. ..................... 6.11
La Grande Existing Resources vs. Peak Day Demand...................................................... 6.11
2009 Natural Gas IRP
Figue 6.14
Figue 6.15
Figue 6.16
Figue 6.17
Figure 6.l8
Figue 6.19
Figue 6.20
Figue 7.1
Figue 7.2
Figure 7.3
Figue 7.4
Figue 7.5
Figue 7.6
Figue 7.7
Figue 7.8
Figue 7.9
Figue 7.10
Figue 7.11
Figue 7.l2
Figue 7.13
Figure 7.14
INDEX OF FIGURES (CONTINUED)
Washington and Idaho Avoided Costs .....................................................................Page 6.15
Oregon Avoided Costs.....................................................................................................6.15
W A/ID Selected Resources vs. Peak Day Demand.................................... ....................... 6.18
MedfordIoseburg Selected Resources vs. Peak Day Demand......................................... 6.18
Klamath Falls Selected Resources vs. Peak Day Demand................................................. 6.19
Load Duration Curve & Resource Stack - W A/ID ...........................................................6.19
Load Duration Curve & Resource Stack - OR.. ........................................ ....................... 6.20
Dec 20 Peak Day Demand by Case.................................................................................... 7.2
Feb 15 Peak Day Demand by Case .................................................................................... 7.2
First Year Peak Demand Not Met with Existing Resources - Scenario Comparisons.......... 7.3
Price Cure Comparison - Initial vs. Updated Forecast..................................................... 7.4
System Wide Peak Day Demand - Initial vs. Updated Forecast Comparison...................... 7.5
W A/D Existing Resources vs. Peak Day Demand - Expected Case, .................... .............. 7.6
Medium Elasticity, Price Update
MedfordIoseburg Existing Resources vs. Peak Day Demand - Expected Case,................. 7.6
Medium Elasticity, Price Update
Klamath Falls Existing Resources vs. Peak Day Demand - Expected Case, ........................7.7
Medium Elasticity, Price Update
Frequency of Peak Day Occurrences - Spokane............................................................... 7.10
Frequency of Peak Day Occurences - Medford ........................ ..... ........... ...................... 7.ll
Frequency of Peak Day Occurrences - Roseburg ............................................................. 7.11
Frequency of Peak Day Occurences - Klamath Falls ...................................................... 7.12
Frequency of Peak Day Occurences - La Grande............................................................ 7.12
Avista IRP Total20-Year Cost ........................................................................................ 7.13
2009 Natural Gas IRP
AGA
DSM
Dth
EIA
FERC
GTN
GHG
HDD
HP
IRP
LNG
Mmbtu
NOAA
NPCC
NWP
NYMEX
Psig
PVRR
TAC
TRC
Triple E
LIST OF ACRONYMS
American Gas Association
Demand-Side Management*
Dekatherm*
Energy Information Administration
Federal Energy Regulatory Commission*
Gas Transmission Northwest*
Greenhouse Gas
Heating Degree Day*
High Pressure
Integrated Resource Plan*
Liquified Natural Gas*
Milion British Thermal Units*
National Oceanic and Atmospheric Administration *
Northwest Power and Conservation Council *
Wiliams - Northwest Pipeline*
New York Mercantile Exchange*
Pounds per Square Inch Gauge*
Present Value Revenue Requirement
Technical Advisory Committee*
Total Resource Cost
Externl Energy Efficiency Board
WCSB Western Canadian Sedimentary Basin
* Glossary contain additional information.
2009 Natural Gas IRP
CHAPTER 1 - EXECUTIVE SUMMARY
A vista's 2009 Natural Gas Integrated Resource Plan (IRP) identifies a strategic natural gas resource
portfolio that meets future customer demand requirements. The formal exercise of bringing together
customer demand forecasts with comprehensive analyses of resource options, including supply-side
resources and demand-side measures, is valuable to A vista, its customers, Regulatory Commissions
and other stakeholders for long-range planning.
The IRP identifies and establishes an Action Plan to steer A vista toward the least-cost method of
providing service to our natual gas customers. There are other factors that must be considered
besides cost within the context of least-cost planning, including an assessment of risks associated
with each alternative as well as environmental and regulatory issues. Actions resulting from the IRP
process represent risk-adjusted, least-cost results, which we refer to as best cost/risk resources.
IRP PROCESS AND STAKEHOLDER INVOLVEMENT
The IRP is a coordinated effort by several Avista departments along with input from our Technical
Advisory Committee (TAC) which includes Commission Staff, peer utilities, customers and other
stakeholders. This group is a vital component of our IRP process, as it provides a forum for idea
exchange that communicates multiple perspectives, identifies issues and risks and improves
analytical methods. Topics discussed include natural gas demand forecasts, demand-side
management (DSM), supply-side resources, computer modeling tools and distribution planning. The
end result is an integrated resource portfolio designed to serve our customers' natual gas needs well
into the future while balancing cost and risk.
PLANNING ENVIRONMENT
This IRP was developed during a two-year period in which an international credit crisis severely
disrupted the United States and global economy. Long-term effects on the natural gas industry are
uncertain, prompting us to consider a wider range of scenarios to evaluate and prepare for a broad
spectrum of potential outcomes. We examined key assumptions and historical trends, questioning
how they might be impacted by the economic environment which is ambiguous, fluid and evolving.
We have sought to perform analysis and modeling that not only looks at "what happened?" but also
asks "what if?" to understand possible outcomes. Over time, as more becomes known about this
uncertain period, some of our scenarios may differ substantially from subsequent actual results.
Nonetheless, the trade-off of examining a broad range of possibilities with stretched assumptions is
preferable to a narrower analysis of more-likely outcomes that could completely miss a less probable
future.
Avista 1.1
Chapter 1 - Executive Summary 2009 Natural Gas IRP
DEMAND FORECASTS
For this IRP, we define eight demand areas, which are structued around the transportation resources
that serve them. These demand areas are aggregated into four service terrtories (Washington/Idaho,
Medford/oseburg, Oregon, Klamath Falls, Oregon and La Grande, Oregon) and further
summarized into two divisions (North and South) for presentation throughout this IRP.
Avista's approach to demand forecasting focuses on customer growth and use per customer as the
base components of demand. We recognize and have accounted for weather as a fundamental
demand-influencing factor as well. We also studied other factors that influence demand including
population, employment trends, age and income demographics, construction trends, conservation
technology, new uses development (e.g. natural gas vehicles) and use per customer trends.
Recognizing customers adjust consumption in response to price, we also analyzed factors that
influence natural gas prices and demand through price elasticity. These included unconventional
natural gas production trends, climate change policies and legislation, Canadian import trends,
potential driling restrictions and alternate price forecasts.
We developed a historical based reference case and conducted sensitivity analysis on key demand
drivers by varying assumptions to understand how demand changes. Using this information and
incorporating input from the T AC, we formed several alternate demand scenarios for detailed
analysis. Table 1.1 summarizes these scenarios, which do not represent the maximum bounds of
possible cases, but frame a broad range of potential outcomes. Within this range, we defie an
Expected Case which we view as the most likely scenario.
Alteat
Expected Case
High Growth, Low Pnce
Low Growth, High Pnce
Green Future
Alternate Weather Standard
Supply Constraints
A vista uses the IRP process to develop two primar types of demand forecasts - annual average
daily and peak day. Annual average daily demand forecasts are useful for preparing revenue budgets,
developing natural gas procurement plans and preparing purchased gas adjustment filings. Peak day
demand forecasts are critical for deterining the adequacy of existing resources or the timing for
new resource acquisitions to meet our customers' natual gas needs in extreme weather conditions.
The demand forecasts from the Expected Case revealed:
1.2 Avista
2009 Natural Gas IRP Chapter 1 - Executive Summary
Annual Average Daily Demand - Average day, system-wide core demand is projected to
increase from an average of96,160 dekatherms per day (Dth/day) in 2009-2010 to 1 17,660
Dth/day in 2028-2029. This is an annual average growth rate of 1.1 percent and is net of
projected conservation savings from DSM programs!.
Peak Day Demand - Coincidental peak day, system-wide core demand is projected to
increase from a peak of365,720 Dth/day in 2009-2010 to 474,670 Dth/day in 2028-2029.
Forecasted non coincidental peak day demand peaks at 341,850 Dth/day in 2009-2010 and
increases to 440,630 Dth/day in 2028-2029, a 1.3 percent compounded growth rate in peak
day requirements. This is also net of projected conservation savings from DSM programs.
Figure 1. I shows forecasted system-wide annual average daily demand for the six main scenarios
modeled over the planning horizon.
Figure 1.1 System Vlde Average Day Demand
(NetofDSM Savings)
160
140 ---120 --
100 --..- I
~ L¡;
:E 80
""~60:i
40
20
---,~~~~~~~~~~~&~~d~Ø~#~~~~~~~~~~~~~~~~~w~~~~~~~~~~~~~~~~~~~~~~~
.. Expe Case -- High Groth, Lo Prices __ Lo Groth, High Priæs
~ Gre Fu1re __ Al1le Weaer Sla -- Suppy Conlrinl
Figure 1.2 shows forecasted system-wide peak day demand for the six main scenarios modeled
over the planning horizon.
i Appendix 3.9 shows gross demand, DSM savings, and net demand.
Avista 1.3
Chapter 1 - Executive Summary 2009 Natural Gas IRP
Figure 1.2 System Wide Peak Day Demand
(NetofDSM Savings)
600
400 f---~---- ....
500
¡;:i.c 300is::
~-=
200
100 , , , ,~ ~ ~~~ ~~~~~~ßg$g$Gßg~!l~ ~~ "'~ ~~ !'"- be~ ~" '0'' ~" 'l" 'I'' ~" "," n;" r:" be" ~" l(" (\:" fl"~~~~~~~~~~~~~~~~~~~~
.. Expe Cas -- High Grolh, Low Prices __ Lo Grolh, High Prices
~ Gre Futre __ Altlni Wæler Slada -- Suppy Conslrnl
NATURAL GAS PRICE FORECASTS
Natural gas prices are a fundamental component of integrated resource planning. The commodity
price is a significant component ofthe total resource cost of a resource option. This affects the
avoided cost threshold for determing cost effectiveness of conservation measures. The price of
natural gas influences the consumption of natual gas by customers, sowe included price elasticity
analysis in our evaluation of demand.
The outlook for natural gas prices has changed dramatically over the recent planning cycle because
of several influential events and trends affecting the natural gas industry. Most notable is the severe
economic recession triggered by the global credit crisis. Other significant influences include
expectations of prolific shale gas production and increased natual gas-fied power generation as
anticipated climate change legislation encourages replacement of coal burning power plants. The
outlook for these and other factors has evolved rapidly in the midst of significant uncertainty
precipitating wide swings and frequent updates to the natural gas price forecasts we monitor.
Although we do not believe we can accurately predict future prices for the 20-year horion of this
IRP, we have reviewed several price forecasts from credible sources and have selected high, medium
and low price forecasts to represent aggressive but reasonable pricing possibilities for our analysis.
Figue 1.3 depicts the price forecasts used in our IRP. Continuing our theme of stretching modeling
assumptions to better prepare for an uncertain environment, the price curves have considerable
variation.
1.4 Avista
2009 Natural Gas IRP Chapter 1 - Executive Summary
Figure 1.3 Henry Hub Price Forecasts for IRP
NYMEX blend first fie years'
2009$/DUi
$16.00
$14.00 ~..$12.00
$10.00 -~-..cë $8.00 ¿~.---...-"".~..
$6.00 ,7r .--
$4.00 I
$2.00
'NYMEX weighled 50%, 40%, 30%, 20%, 10%
$0.00 .-en 0 N '"..10 to ..00 en 0 N N '"..10 to ..00 en 00C;C;C;C;C;C;C;C;C;C;N N N N N N N N N '"0 0 0 0 0 0 0 0 0 0 0 0NNNNNNNNNNNNNNNNNNNNNN
-+Consul --NPCC La -- NPCC High -. Consull1 . June Upd
In modeling a consumption response to these price curves, we developed high, medium and low
price elasticity response factors to be applied under various scenarios. We have assumed a low
response to prices in our Expected Case, partly based on a conservative assumption that tight
economic conditions and declining real estate values may deter many customers from investing in
long-term capital intensive conservation measures in the near term. We wil monitor this assumption
over the next IRP cycle and make any necessary adjustments.
EXISTING AND POTENTIAL RESOURCES
A vista has a diversified portfolio of natural gas supply resources, including contracts to purchase
natural gas from several different supply basins, owned and contracted storage enabling flexibility
and diversity of supply sources, and firm capacity rights on six pipelines enabling delivery of supply
to our service territory city gates. For potential resource additions, we also evaluate incremental
pipeline transportation, storage options, distribution enhancements and various form of liquefied
natural gas storage or service.
In our IRP process, we model a number of conservation measures that reduce demand if they prove
to be cost effective over the planning horizon. Based on the projected natural gas prices and the
estimated cost of alternative supply resources, our computer planning model (SENDOUTiI) selects
measures for further review and implementation. We actively promote these measures to our
customers as one component of a comprehensive strategy to arrive at best cost/risk adjusted
resources.
Avista 1.5
Chapter 1 - Executive Summary 2009 Natural Gas IRP
RESOURCE NEEDS
Using our Expected Case demand scenario matched with our Existing Resources supply scenario, we
ran the case through the SENDOUTiI computer model to determe when the fist year peak day
demand is not fully served. The results of this portfolio are summarized in Figue 1.4.
2009
2010
2011
2012
2013
.. 2014
~ 2015CD
~ 2016
~ 2017
¡¡ 2018
!j 2019
~ 2020
~ 2021
i! 2022
¡¡ 2023
2024
2025
2026
2027
2028
Figure 1.4 First Year Pea Demand Not Met With Existing Resource
Expecæ Case
WNiD Medbrd Klamati La Grande
In the Expected Case for Washington and Idaho, this system first becomes unserved in 2023. In
Oregon, the first unserved year is in MedfordIoseburg in 2018 followed by Klamath Falls in 2021.
The La Grande system does not go unerved at any time during the 20-year planning horizon.
Figures 1.5 through 1.8 provide detailed ilustrations of when our peak day demand first goes
unserved by service terrtory for both this IRP and our prior IRP. These charts compare existing peak
day resources to expected peak day demand by year and show timing and extent of resource
deficiencies for the Expected Case. Given this information, it appears we have ample time to
carefully monitor, plan and take action on potential resource additions.
1.6 Avista
2009 Natural Gas IRP Chapter 1 - Executive Summary
Figure 1.5 WAIID Existing Resources vs. Peak Day Demand
Expecld Case (NetofDSM Savings) Noverrer 10 Oc1ber
400,000
Prior Short Current Short
350,000
300,000
250,000
5 200,000
150,000
100,000
50,000
o~~~~~~~~~~#~~#$#Ø#~~#K~~¥¥KK~KK ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~~
- Exising GTN - Existng TF-1ll Existng TF-2 _ Spokane Supply -- Peak Day Demand -. Prior IRP Peak Day Demand
Figure 1. Medford/Roseburg Existing Resources VS. Peak Day Demand
Expeæd Case (Net of DSM Savings) Noverrer 10 Ocber
120,000
100,000
80,000
,c 60,000Õ
40,000
20,000
0 ~ " ~ ?: '" ~ ~ ~ ~ ~ i; " fl r" '" b ,,'0 ",\ ,,'ò "C!~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~M~~~v~K~~¥¥KK~K ~v ~v ~v ~v ~v ~v ~v ~v ~v ~v~~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~~~
- Existng GTN _ Existng TF-1 ll Exising TF.2 -- Peak Day Demand -. Prior IRP Peak Day Demand
Avista 1.7
Chapter 1 - Executive Summary 2009 Natural Gas IRP
Figure 1. Klamath Falls Existing Resources VS. Peak Day Demand
Expeæd Case (net of DSM Saviigs) Noveimer ti Ocber
22,000
20,000
18,000
16,000
14,000
.. 12,000ë10,000
8,000
6,000
4,000
2,000
o
Prior Short Current Short
~~~~~~~~~~~~~~øø~~~~~~ ~~~ ~~~~ø~~ ~~~ ~~~~~~~~~~~~~~~~~~~~~~~~~
_ Existing GTN _ Exislng TF-1 -- Peak Day Demand -. Prior IRP Peak Day Demand
Figure 1. La Grande Existng Resource vs. Peak Day Demand
Expeæd Case (NetofDSM Savings) Noveimr ti Ocber
14,000
12,000
10,000
8,000..ë
6,00
4,000
2,000
0
Prior Short
~~~~~~~~ ~~~~~~øø~~ ~~#K~if¥~KK~KK ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~~
_ExistingTF-1 -- Peak Day Demand -. Prior IRP Peak Day Demand
A critical risk with respect to our identified resource shortages is the slope of forecasted demand
growth which is almost flat. This outlook imlies that existing resources wil be suffcient for quite
some time to meet demand. However, if demand growth accelerates, the steeper demand curve could
quickly accelerate resource shortages by several years. Figue 1.9 is a conceptual diagram that
ilustrates this risk. In this hypothetical example, a resource shortage does not occur until year eight
in the initial demand case. However, the shortage dramatically accelerates by five years under the
revised demand case to year three. This "flat demand risk" necessitates close monitoring of
accelerating demand as well as careful evaluation of lead times to acquire the preferred incremental
resource.
1.8 Avista
2009 Natural Gas IRP Chapter 1 - Executive Summary
Figure 1. Flat Demand Risk Example
8
7
6
5
"0i:
E 4"'ci
3
2
o
2 3 4 5 6Years 7 8 9 10
_Resources -- Initl Demand .. Revise Demand
RESOURCE SELECTIONS
The next step is to determe how to resolve resource deficiencies. For this step, we identified
possible resource options and placed them into the SENDOUT(ß model to allow it to select the best
cost/risk incremental resources over the 20-year planing horion. Figues 1.10, 1.11 and 1. 12 depict
the best cost/risk portfolio selected by SENDOUT(ß to meet the identified resource shortages. As
previously mentioned, the La Grande service territory does not have resource shortages over our
planning horizon in the Expected Case.
Figure 1.10 WAllO Selected Resources vs. Peak Day Demand
Expeæd Case (NetofDSM Savings) Noverrer b Ocber
400,000
Current Short
50,000
350,000
300,000
250,000
S 200,000
150,000
100,000
o~~~~~~~~~~~&~~d##~~~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~# ~ ~ W ~ ~ ~~~~~~~~~~~~~~~ ~~~~~~
- Existng GTN _ Existng TF-1 !4d Exising TF-2 _ Spokane Supply _ Add'i GTN -- Peak Day Demand
Avista 1.9
Chapter 1 - Executive Summary 2009 Natural Gas I RP
120,000
100,000
80,000
..60,000is
40,000
20,000
Figure 1.11 Medford/Roseburg Selectd Resources vs. Peak Day Demand
Expeæd Case (NetofDSM Savings) Noverrer b Ocber
o
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~, ~ n~ ~ ~ ~ ~ ~~'" ~~ ~~ ~~ ~~ ~" ~'" ~~ ~~ ~" ~rç ~ti ~v ~V Ç)V Ç)V Ç)V Ç)V Ç)V Ç)V~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~gg ~ ~g ~ ~ ~v~ ~ ~ ~ ~ ~rç rç rç rç rç rç "V "V rç rç "V rç rç rç rç rç rç rç rç rç
_ Existng GTN _ Exislng TF-1 I! Exislng TF-2 c: Backaul Mad LatlGTN Corrressn __ Peak Day Demand
22,000
20,000
18,000
16,000
14,000
.. 12,000
is 10,000
8,000
6,000
4,000
2,000
o
Figure 1.12 Klamath Falls Selectd Resource vs. Peak Day Demand
Expectd Case (Net of DSM Savilgs) Noverrer 10 Ockber
Current Short
~~~~~~~~~~#~#~~#ø~~~#¥~K¥¥¥K~¥Kø~~~~~~~~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~~
- Exislng GTN _ Exisng TF-1 c: KF La1eral Purchase -- Peak Day Demand
As indicated in the figues, after DSM savings, the model shows a general preference for
incremental transportation resources from existing pipelines and supply basins to resolve resource
shortages.
ALTERNATE DEMAND SCENARIOS
We performed the same SENDOUTiIprocess for five other demand scenarios, which identified fIrst
year unserved dates for each scenario by service terrtory (Figure 1.13). As expected, the High
Growth, Low Price scenario has the most rapid growth and the earliest fIrst year unserved dates. This
1.10 Avista
2009 Natural Gas IRP Chapter 1 - Executive Summary
"steeper" demand somewhat lessens the "flat demand risk" discussed above, but the earlier unserved
dates warrant close monitoring of demand trends and resource lead times.
Figure 1.13 First Year Peak Demand Not Met with Existing Resource
Scenario COlJarisns
WAiID Medbrd Klari1h La Grande
..
Ic~..c'"EGOC..
~!
¡¡
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
. Expecld Case
. Green Fuure
. High Growli Low Price
. A1erna1e Wea1her Sid
. Low Grow1 High Pric
. Supply Conslainls
Several scenarios indicate no resource deficiencies over the planning horizon due to very slow or
even negative demand growth. A key reason for this is our price elasticity assumptions combined
with price forecasts with steep price increases early in the planning horizon. This perfect storm
combination produces a significant curtailment in total demand early in the forecast. A key question
for these scenarios is whether this early price shock materializes as forecasted and, if so, is demand
permanently curtailed as predicted in the price elastic response assumption. This condition also
warrants close monitorig and comparison to actual results.
ACTION PLAN
Our 2010-2011 Action Plan outlines activities identified by our IRP team, with advice from
management and TAC members, for development and inclusion in the 2011 IRP. The purpose of
these action items is to position A vista to provide the best cost/risk resource portfolio and to support
and improve IRP planning. Key components ofthe Action Plan include:
· Monitor actual demand for indications of growth exceeding our forecast to respond
aggressively to address potential accelerated resource deficiencies arising from exposure to
"flat demand" risk. This includes researching and refining evaluation of resource alternatives,
including implementation risk factors and time lines, updated cost estimates, feasibility
assessments and targeting options for the service territories with nearer term unserved
demand exposure.
· Analyze use per customer data and DSM program results for indications of price elasticity
response trends that may have been influenced by evolving economic conditions. InvestigateAvista 1.11
Chapter 1 - Executive Summary 2009 Natural Gas i RP
contemporary analytical sources for information on natural gas price elasticity. Determine if
the American Gas Association (AGA) wil update its analytical work and/or consider hiring a
third-party price elasticity study and assess interest of other utilities in pursuing a regional
study.
· Continue cost effective demand-side solutions. In Washington and Idaho, conservation
measures are targeted to reduce demand by 2,193,338 therms in the first year (2010). In
Oregon, conservation measures are targeted to reduce demand by 303,300 therms in the fist
year. These goals represent an increase of25 percent in Washington and Idaho and a nominal
decrease ofless than 1 percent in Oregon from the 2010 projected goals in the 2007 IRP.
. Research and engage a conservation consultant to perform an updated assessment of
technical and achievable potential for conservation in our service territories prior to the 2011
IRP.
· Continue to monitor the discussion around diminishing Canadian natural gas imports and
look for signals that indicate increased risk of disrupted supply given much of our supply
comes from Canadian sources.
. Explore and evaluate alterntive and additional forecasting methodologies for potential
inclusion in our next IRP.
. Regularly meet with Commission Staff members to provide information on market activities
and significant changes in assumptions and/or status of A vista activities related to the IRP or
natural gas procurement practices.
ISSUES AND CHALLENGES
Although we are satisfied with the planning, analysis and conclusions reached in this IRP, we
recognize widespread uncertainty results in a heightened risk environment requiring diligent
monitoring ofthe following issues and challenges:
ECONOMIC UNCERTAINTY
The current economic downturn has been dramatic and has impacted near-term trends in economic
activity. The potential influence on natual gas demand, DSM, infrastructure developments,
commodity prices, credit term and procurement practices in such an unsettled environment presents
many forecasting challenges. Historical relationships may be altered or fudamentally changed. For
example, customer changes in natural gas consumption may be driven as much by personal income
changes as by natural gas prices. DSM initiatives could be enthusiastically pursued by more
customers seeking savings on their energy costs while other customers may forego participation due
to personal economic constraints. Tight credit markets, lower regional demand and community
opposition could delay pipeline and other infrastructure projects. Alternatively, lower labor,
materials and interest costs may prompt accelerated infrastructue investment.
In such an uncertain environment, there is more risk of unanticipated outcomes. Although we sought
to capture many of these issues through a wide range of scenarios in our modeling and analysis,
1.12 Avista
2009 Natural Gas IRP Chapter 1 - Executive Summary
monitoring will be required to see how events unfold and ifthere are outcomes we did not consider,
requiring adjustment of our analysis and action.
CLIMATE CHANGE LEGISLATION
Global economic growth earlier in the decade was partly driven by low cost debt and inexpensive
energy. The two are not uncorrelated - robust growth usually depends on both. In hindsight, we now
see this growth was vulnerable. Debt was improperly priced for risk while energy was underpriced
for carbon emissions and other environmental concern. As prices of debt and energy readjust to
reflect these costs, economic growth will face strong headwinds. The emerging political dilemma
wil be how to facilitate this readjustment in a fragile economic climate.
When we initiated our IRP planning and analysis, federal climate change legislation appeared almost
certain to pass with far reaching and long-term implications. We still believe some form of federal
climate change legislation is likely to be enacted though the form, extent and timing continue to be
uncertain. A cap.and trade structure remains the most likely framework for greenhouse gas
legislation. Economic issues aside, this complex structue has numerous design issues that must be
addressed, including emissions target levels, phase in timeframes, allocation of allowances,
availability of offsets, cost mitigation to customers and a host of implementation challenges.
By design, this legislation is meant to substantially alter the energy production and consumption
landscape. Inherent in this new landscape is significant uncertainty in market behavior and
acceptance, which can profoundly impact resource needs. Additional carbon mitigation costs may
slow or reverse end user adoption of natural gas appliances and applications. Direct use initiatives
may stall given significant regional hydro and other renewable electric resources wil not be
burdened with carbon costs. The integration of federal legislation with the regional Western Climate
Initiative also remains uncertain. These example issues pose significant modeling and forecasting
challenges.
To address these challenges, we worked closely with one of our energy industry consultants,
leveraging their monitoring of climate change policy issues and in-depth research to develop our
long-term price forecasts. This includes specific alternative price forecast scenarios that separately
captured influences of potential carbon emissions legislation. We also conferred with and solicited
ideas and feedback from Avista's electric resource planning team and the TAC to develop two
carbon emission reduction sensitivities that were ultimately incorporated in each of our modeled
scenarios. This provided useful findings and a solid base to continue analysis and monitorig
developments in this important sphere going forward.
SEISMIC SUPPLY SHIFTS
The main driver of North American natural gas production growth is now forecast to be
unconventional gas, especially shale gas. Several new shale gas fields have been identified with
many of the wells delivering impressive results. However, the reality is huge future volumes are
being forecast for this resource, yet the long-term estimates for these resources remain relatively
Avista 1.13
Chapter 1 - Executive Summary 2009 Natural Gas I RP
untested and unown. Although we are encouraged by this progress, we wil need to be prudently
wary as well.
Burgeoning supply from international liquefied natual gas projects, which have been at least a half
decade in the making, is just now comig on line. Significant capacity is being added as near-term
global demand is diminished from the prospects of a lingering global recession. This, combined with
the unconventional gas production supply surge, resulted in an unprecedented rapid collapse in
prices. Although beneficial to end users in the near term this dramatic volatility and uncertainty
could cause long-term disruption in production, pipeline and storage capital investment exacerbating
boom/bust cycles in the long term.
CONCLUSION
Lower demand since our last IRP as well as slower forecasted demand in our Expected Case
indicates no near-term need for additional supply-side resources. This wil not diminish our efforts to
encourage customer adoption of cost effective conservation measures consistent with our
longstanding commitment to acquire demand-side resources. The IRP process has many objectives
but foremost is to ensure that proper planning wil enable us to continue delivering safe, reliable and
economic natual gas service to our customers well into the future. We are confident this plan
delivers on that objective.
1.14 Avista
2009 Natural Gas IRP
CHAPTER 2 - INTRODUCTION
OUR COMPANY
Avista is involved in the production, transmission and distribution of energy as well as other energy-
related businesses. Avista was founded in 1889 as Washington Water Power and has been providing
reliable, effcient and competitively priced energy to customers for nearly 120 years.
Avista entered the natural gas business with the purchase of Spokane Natural Gas Company in 1958.
In 1970, we expanded into natural gas storage with Washington Natural Gas (now Puget Sound
Energy) and El Paso Natual Gas (their interest subsequently purchased by Wiliams - Northwest
Pipeline (NWP)) to develop the Jackson Prairie natural gas underground storage facility in Chehalis,
Washington. In 1991, we added 63,000 customers with the acquisition ofCP National Corporation's
Oregon and California properties. Avista subsequently sold the California properties and its 18,000
South Lake Tahoe customers to Southwest Gas in 2005. Avista currently provides natural gas
service to over 314,000 customers in eastern Washington, northern Idaho and several communities
in northeast and southwest Oregon.
SERVICE TERRITORIES AND NUMBER OF CUSTOMERS
. ElSl_
o _GoSl_. ElIl_GoSt_
Natural Gas Customers
as of Dec. 31, 2008
Washington
Idaho
Oregon
Total
145,600
73,250
95,300
314,150
41
-Wi - 01 !i Wa
Avista 2.1
Chapter 2 - Introduction 2009 Natural Gas IRP
A vista manages its natural gas operations through two operating divisions - North and South:
. The North Division covers about 26,000 square miles, primarily in eastern Washington and
northern Idaho. Over 840,000 people live in Avista's Washington/Idaho service area. It
includes urban areas, fars, timberlands and the Coeur d Alene mining district. Spokane is
the largest metropolitan area with a regional population of approximately 450,000 followed
by the Lewiston, Idaho/Clarkston, Washington area and Coeur d Alene, Idaho. The North
Division has about 74 miles of natual gas distribution mains and 5,000 miles of distribution
lines. Natural gas is received at more than 40 points along interstate pipelines and distributed
to over 219,000 residential, commercial and industrial customers.
. The South Division serves four counties in southwest Oregon and one county in northeast
Oregon. The combined population ofthese two areas is over 480,000 residents. The South
Division includes urban areas, farms and timberlands. The Medford, Ashland and Grants
Pass area, located in Jackson and Josephine Counties, is the largest single area served by
A vista in this division, with a regional population of approximately 280,000 residents. The
South Division consists of about 67 miles of natual gas distribution mains and 2,000 miles
of distribution lines. Natual gas is received at more than 20 points along interstate pipelines
and distributed to over 95,000 residentiaL, commercial and industrial customers.
OUR CUSTOMERS
We provide natural gas services to two customer classifications - core and transportation only
customers. Core customers purchase natural gas directly from us with delivery to their home or
business under a bundled rate. This service implicitly obligates A vista to deliver whatever volume is
needed by the customer under fir delivery requirements.
Transportation only customers purchase natural gas from third-parties who deliver their gas to our
distribution system. We then deliver this gas to their business charging a distribution rate only. This
delivery service can be interrpted by us during periods of high demand by our core customers.
Because our transportation only customers purchase their own gas and delivery on our distribution
system is non-fi, we exclude these customers from our long-term resource planning analysis.
Our core or retail customers are fuher divided into three categories - residential, commercial and
industriaL. Most of our customers are residential followed by commercial and relatively few are
industrial accounts (Figue 2.1).
2.2 Avista
2009 Natural Gas I RP Chapter 2 - Introduction
Customer Make Up
Washington and Idaho
5% 1%
Figure 2.1 Customer Make Up
Oregon
5% 1%
94%
- Residential - Commercial - Industrial
94%
- Residential - Commercial - Industrial
The mix is more balanced between residential and commercial accounts on an annual volume basis
(Figure 2.2). Volume consumed by core industrial customers is not significant to the total partly
because most industrial companies in our service terrtories are transportation only customers.
Annual Demand
Washington and Idaho
1%
Figure 2.2
Annual Demand
Oregon
2%
60%60%
- Residential - Commercial - Industrial - Residential - Commercial - Industrial
Core customer demand is seasonal, especially by our residential accounts in our service terrtories
with colder winters (Figue 2.3). Industrial demand, which is typically not weather sensitive, has
very little seasonality. However, our La Grade servce terrtory has several agricultual processing
facilities that produce a late summer seasonal demand spike.
Avista 2.3
Chapter 2 - Introduction 2009 Natural Gas IRP
WAlO
Figure 2.3 Seasonal Demand by ServiceTerritory and Customer Class
2008 Medford
3,400,000
2,900,000
2,400,000
S
1,900,000
1,400,000
900,000
400,000
(100,000)
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Klamath Falls
170,000
150,000
130,000
110,000
90,000S70,000
50,000
30,000
10,000
(10,000)Jan Feb Mar Apr May Jun Jul Au Sep Oc Nov DeI-:~~~~:~~I
INTEGRATED RESOURCE PLANNING
95,000
85,000
75,00
65,000
55,000
S 45,000
35,000
25,000
15,000
5,000
(5,00)Jan Feb Mar Apr May Jun Jul Aug Sep Oc Nov Dec
In order to ensure that our core customers are provided with long-term reliable natural gas service at
an economic price, we undertake a comprehensive analytical process through the integrated resource
plan. We evaluate, identify and plan for the acquisition of the best-risk, least-cost portfolio of
existing and future resources, to meet daily and peak day demand and delivery requirements over a
20-year planning horion.
PURPOSE OF THE IRP
This document has several objectives:
· Provides a comprehensive long-range planning tool;
· Fully integrates forecasted requirements with potential resources;
· Determines the most cost effective, risk-adjusted means for meeting demand requirements;
and
· Responds to Washington, Idaho and Oregon rules and orders.
AVISTA'S IRP PROCESS
The IRP process considers:
. Customer growth and usage;
. Weather planning standard;2.4 Avista
2009 Natural Gas IRP Chapter 2 - Introduction
· DSM opportunities;
· Existing and potential supply-side resource options; and
. Risk.
PUBLIC PARTICIPATION
Members of Avista's TAC playa key role and have a significant Împact in development of the IRP.
TAC members include Commission Staff peer utilities, public interest groups, customers,
academics, governent agencies and other interested parties. A list ofTAC members is in Appendix
1.1. The TAC provides important input on modeling, planning assumptions and the general direction
of the process.
Avista sponsored four TAC meetings to facilitate stakeholder involvement in the 2009 IRP. The first
meeting convened on April 26, 2009 and the last meeting was held on July 16, 2009. A broad
spectrum of stakeholders was represented at each meeting. The meetings focused on specific
planning topics, reviewed the status and progress of planning activities and solicited input on the IRP
development. A draft of this IRP was provided to TAC members on September 4,2009. We gained
valuable input from the interaction and communication with T AC members and express our thanks
and appreciation for their contributions and participation.
Preparation of the IRP is a coordinated endeavor by several deparments within Avista with
involvement and guidance from management. We are grateful for these efforts and contributions.
REGULATORY REQUIREMENTS
Avista submits an IRP to the Public Utility Commissions in Washington, Idaho and Oregon every
two years as required by state regulation!. We intend to file our plan with all three Commissions on
or before December 31, 2009. We have a statutory obligation to provide reliable natual gas service
to customers at rates, terms and conditions that are fair, just, reasonable and sufficient. We regard the
IRP as a means for identifying and evaluating resource options and as a process to establish an
Action Plan for resource decisions. Ongoing investigation, analysis and research may cause us to
determine that alterntive resources are more cost effective than resources selected in this IRP. We
wil continue to review and refine our understanding of resource options and will act to secure these
risk-adjusted, least-cost options when appropriate.
PLANNING MODEL
Consistent with several prior IRPs is SENDOUTiI, the computer planning model we use to perform
comprehensive and effective natural gas supply planning and analysis. This linear programming-
based model is widely used in the industry to solve natural gas supply, storage and transportation
1 hi Washington, IR requirements are outlined in WAC 480-90-238 entitled "hitegrated Resource Planning." hi Idaho, the IR
requirements are outlined in Case No. GNR-G-93-2, Order No. 25342. hi Oregon, the IR requiements are outlined in Order Nos. 07-
002,07-047 and 08-339. Appendix 2. i provides details of these requirements and how they were met.
Avista 2.5
Chapter 2 - Introduction 2009 Natural Gas I RP
optimization problems. This model uses present value revenue requirement (PVRR) methodology to
perform least cost optimization based on daily, monthly, seasonal and annual assumptions related to:
. Customer growth and customer natul gas usage to form demand forecasts;
. Existing and potential transportation and storage options;
. Existing and potential natual gas supply availability and pricing;
. Revenue requirements on all new asset additions;
. Weather assumptions; and
. Demand-side management.
We have also incorporated the Monte Carlo simulation module within SENDOUTiI (formerly called
VectorGas™) to simulate weather and price uncertainty. The module uses Monte Carlo functionality
to generate simulations of weather and price to provide a probability distribution of results from
which decisions can be made. Some examples ofthe types of analysis Monte Carlo simulation
provides include:
. Price and weather probability distributions;
. Probability distributions of costs (i.e. system cost, storage costs, commodity costs); and
· Resource mix (optimally sizing a contract or asset level of various and competing resources).
These computer-based planning tools were used to develop our 20-year best cost/risk resource
portfolio plan to serve customers.
PLANNING ENVIRONMENT
Although we prepare and publish an IRP biannually, the IRP process is ongoing to take into account
new information and developments. In "normal" circumstances, the process can become complex as
underlying assumptions evolve and impact previously completed analyses. The most recent cycle
has been even more challenging because the planning environment has undergone extraordinary
changes to the economic and natural gas industr landscape.
HISTORICAL RECAP
As we completed our 2007 IRP, continued robust global economic activity was pressuring energy
commodity prices upward. Natual gas prices were strained by extremely tight production versus
production capacity conditions and declining production in the Gulf of Mexico and western Canada.
Increased oil sands production consumed an increasing share of western Canada's declining
production exacerbating a declining import trend into the United States. At that time there was much
discussion that imported liquefied natual gas (LNG) was essential to bridging the supply/demand
gap. Higher forecasted prices were predicted to be necessary to lure LNG away from the higher
priced European and Asian markets. Further, fiing climate change policy generally predicted solid
demand growth from increased gas- fired power generation to replace coal burning generation.
2.6 Avista
2009 Natural Gas IRP Chapter 2 - Introduction
Higher prices brought increased investment in natural gas exploration, production and infrastructue.
Emerging successes in existing unconventional gas production, especially shale gas, was a primary
recipient of this increased investment, particularly in the areas of securing land leases and driling
test wells in new and existing plays throughout North America. With the expectation of strong
demand growth came numerous new proposed pipeline projects announced including several to
serve the Pacific Northwest.
Strong energy price increases and tight fundamentals also caught the attention of the investment
community prompting significant interest in energy commodities and investment inflows into the
sector. Prices were bid strongly and by summer 2008, natural gas prices reached all-time highs on a
seasonal basis (Figure 2.4).
Figure 2.4 Historical Daily Prices
AECO
$14.00
$12.00
$10.00
:5 $8.00
~$6.00
$4.00
$2.00
$0.00~~~~&~~~~~~~~ ~ ~ ~ ~~~~~~~~G ~ ~ ~ G ~ G ~ff~ ~ ~~ ~ ~ G ~ ~ ~ G ~ G ~ G~ ~ ~ ~~ ß ~ ~ø~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ w ~ ~"v. "V ";\ ((\ ai\ "V ";\ ((\ ai\ \ ~\ ,,\ ~ ,\\ ~\ ,,\ ~ ,\\ "
However, shifting fundamental factors and a slowing economy increasingly contradicted with this
price strength. In the second half of2008 and into 2009, the global credit crisis led to widespread
economic disruption and energy demand destruction which dramatically reversed energy market
expectations. Energy prices plummeted and uncertainty reigned. Meanwhile, earlier investments in
shale exploration and production began delivering prolific results, leading to several upward
revisions for predicted future supply sources prompting significant downward revisions to forward
price forecasts.
In our own data, we saw a dramatic drop in a key demand metric, customer counts, which began
lagging our 2007 IRP forecast. In Oregon, the counts even fell below our low-case projection,
raising concern about the severity ofthe downtu and questions about our underlying modeling
assumptions (See Figures 2.5 and 2.6).
Avista 2.7
Chapter 2 - Introduction 2009 Natural Gas I RP
Figure 2.5 Customer Count. 2007 IRP VS. Actals
OR Residentil
90,000
89,000
88,000
87,000
86,000
85,000
84,000
83,000
82,000
81,000
80,000
ß~r:s5r;'ò ~r;'ò,'I ~'I iß ~r;o.,~ ~'I(b,,'i
~~..
~'ò ;l'!
cg~ ~r:')'ò~Po§s
~~..
~,~
~o.
C:'l~
Note: y-axis doesrllstrtalzero l: beter show dilrences,
_Low
i: Expele
i: High
-+ Acluals
Figure 2.6 Customer Count. 20071RP vs. Actals
OR Corrcil
11,700
11,600
11,500
11,400
11,300
11,200
11,100
11,000
10,900
10,800
10,700
;l~~r:
.:;~
s5r;'ò ~r;'ò _v~,'/ ~'/ ~~..
~o. ~r;o.,# ~'/')'ò,~
~'ò ;l'!
c!~ ~r:')0.~~o.
cg~
_vr;o.
~~..
No1e: y-axis doesn'lslartalzero to bellr show dilrences.
_Lo
i: Expe
i: High
-+Aclals
IRP PLANNING STRATEGY
Amid this rapidly changing and uncertain environment, we contemplated our IRP planning strategy.
We determined our approach needed to:
· Recognize historical trends may be fundamentally altered;
. Critically review all assumptions;
· Stress test assumptions via sensitivity analysis;
. Pursue a wide spectrum of possible scenarios;2.8 Avista
2009 Natural Gas IRP Chapter 2 - Introduction
· Develop a flexible analytical framework to accommodate changes; and
· Maintain a long-term perspective.
With these objectives in mind, we believe we have developed a sound strategy encompassing all
required planning criteria that allowed us to produce a complete IRP that effectively analyzes risks
and resource options, which sufficiently ensures our customers wil receive safe and reliable energy
delivery services well into the future with the best-risk, least-cost long-term solutions.
Avista 2.9
Chapter 2 - Introduction 2009 Natural Gas I RP
2.10 Avista
2009 Natural Gas IRP
CHAPTER 3 - DEMAND FORECASTS
OVERVIEW
The integrated resource planning process begins with the development of forecasted demand. This
was a challenging time to predict future events including preparing demand forecasts. Although
historical trends normally provide a reliable baseline, they were used with heightened caution given
the dramatic economic disruption we confronted as we prepared and presented this analysis.
The current economic situation is ambiguous, fluid and evolving. Although the economy appears to
be stabilizing, long-term effects on the natural gas industry are uncertain, prompting us to consider a
wide range of scenarios to evaluate and prepare for a broad spectrum of potential outcomes.
DEMAND AREAS
Eight demand areas, structured around the pipeline transportation resources that serve them, were
defied within the SENDOUTQ! computer model (Table 3.1). These demand areas are aggregated
into four service terrtories and fuher summarized into two divisions for presentation throughout
this IRP.
Spokane NWP
Spokane GTN
Spokane Both
Medford NWP
Medford GTN
Roseburg
Klamath Falls
La Grande
gtllIl~DElm~rid Clåss'
SerViCe
Terrto
Washington/Idaho
Washington/Idaho
Washington/Idaho
MedfordIoseburg
Medford/Roseburg
Medford/Roseburg
Klamath Falls
La Grande
North
North
North
South
South
South
South
South
DEMAND FORECAST METHODOLOGY
A vista uses the IRP process to develop two tyes of demand forecasts - annual and peak day.
Anual demand forecasts are useful for several puroses including preparing revenue budgets,
developing natural gas procurement plans and preparing purchased gas adjustment filings. Peak day
demand forecasts are critical for determining the adequacy of existing resources or the timing for
acquiring new resources to meet our customers' natural gas needs in extreme weather conditions
throughout the planning period.
Avista 3.1
Chapter 3 - Demand Forecasts 2009 Natural Gas I RP
DEMAND MODELING EQUATION
Because natural gas demand can vary widely from day to day, especially in winter months when
heating demand is at its highest, developing daily demand forecasts is essentiaL. In its most basic
form, demand is a function of customer base usage plus customer weather sensitive usage. This can
be expressed by the following general formula:
Table 3.2 Basic Demand Formula
# of customers x Daily base usage I customer
Plus
# of customers x Daily weather sensitive usage I customer
More specifically, SENDOUTiI requires inputs as expressed in the below format to compute daily
demand in dekatherms (Dth):
Table 3.3 SENDOUTiI Demand Formula
# of customers x Daily Dth of base usage I customer
Plus
# of customers x Daily Dth of degree day usage I customer x # of daily degree days
This calculation is performed by SENDOUT(ß for each day for each customer class and each demand
area. The base and weather sensitive usage (degree day usage) factors are customer demand
coeffcients developed outside the SENDOUTQ! model and captue a variety of demand usage
assumptions. This is discussed in more detail in the Use per Customer Forecast section below. The
number of daily degree days is simply heating degree days (HDDs), which are further discussed in
the Weather Forecast section later in this chapter.
Customer Forecasts
Avista's customer base is segregated into three categories: residential, commercial and industriaL.
For each ofthe customer categories, we develop our customer forecasts by starting with national
economic forecasts and then driling down into regional economies. Population growth expectations
and employment are key drivers in regional economic forecasts and are useful in estimating natural
gas customers. We contract with Global Insight, Inc. for long-term regional economic forecasts. A
description ofthe Global Insight forecasts is found in our customer forecasts detail in Appendix 3.1.
We combine this data with local knowledge about sub-regional construction activity, age and other
demographic trends and historical data to develop our 20-year customer forecasts.
In response to a previous IRP action item, this IRP incorporates sub-area core customer forecasting
for each municipality and unincorporated county area throughout the three-state service area. This
includes 56 governental subdivisions or "town codes" in Washington, 26 in Idaho and 37 in
Oregon.
3.2 Avista
2009 Natural Gas IRP Chapter 3 - Demand Forecasts
The annual growth for each state is allocated so that the total equals the sum of the parts. These 119
town code forecasts are used by the distribution engineering group for optimizing decisions within
these geographic sub-areas and facilitating integrated forecasting and planning within Avista (see
fuher discussion in Chapter 8 - Distribution Planning).
Forecasting customer growth is an inexact science so it is important to consider alternative forecasts.
Two alternative forecasts were developed for consideration in this IRP. Durig the last 25 years,
customer growth durg five-year periods has ranged between one-half and one-and-a-halftimes the
25-year average customer growth rate. Since both pattern have been observed, Avista has created
low and high customer growth alternatives with these parameters. The three customer growth
forecasts are shown in Figue 3.1. Detailed customer count data, by region and by class, for all three
scenarios, is in Appendix 3.2.
Figure 3.1 Customer Growt Scenarios
700,000
600,000
500,000
l!400,000'"E0i;::300,000(.
200,000
100,000
o
ft ~ P P ~ ~ P ? P ~ ~ ft P fr P 7 ft ~ ft ~ ft~ ~~ ~ ~~ ~ ~~ ~~ ~~ ~ ~~ ~ ~~ ~~
-WABase -OR Base - High Grow1 -Low Grow1
Use per Customer Forecast
The goal for a use per customer forecast is to develop base and weather sensitive demand
coeffcients that can be combined and applied to HDD weather parameters to reflect average use per
customer. This produces a very reliable forecast because ofthe high correlation between usage and
temperature as depicted in the example scatter plot in Figue 3.2.
Avista 3.3
Chapter 3 - Demand Forecasts 2009 Natural Gas i RP
Figure 3.2 . Example Daily Demand vs. Temperature Profile
washingm Idaho
250,000
200,00
î
150,000 ~
~e-..100,000 ~
~
50,000
100 90 80 70 60 50 40 30 20 10 o -10
Temp (Fahrenheit)
The first step in developing demand coeffcients was gathering daily historical gas flow data for all
of our city gates. Three years of data were gathered, segregated by service territory/temperature zone
and then by month. Weather normlized July and August data was used to calculate base demand
coeffcients by dividing total usage by total number of customers. Customer class factors were then
calculated using allocations based on customer biling data demand ratios.
To derive weather sensitive demand coeffcients, for each monthly data subset, we removed base
demand from the total and plotted usage by HDD in a scatter plot chart. We then applied linear
regression to the data to capture the linear relationship of usage to HDD. The slopes ofthe resulting
lines were our monthly weather sensitive demand coeffcients. Again to derive factors by customer
class, we used allocations based on customer biling data demand ratios.
In extreme weather conditions, demand can sometimes begin to flatten out relative to the linear
relationships at less extreme temperatures. This occurs, for example, when appliances such as
furnaces reach maximum output and do not consume any more natural gas regardless of how much
colder temperatures get. We sought to captue this phenomenon through development of super peak
coeffcients.
The methodology for deriving super peak coeffcients was exactly the same as deriving weather
sensitive demand coeffcients except, instead of forming data subsets by month, a dataset was
created using temperature (specifically only very cold temperatures). The line slope from the
regression on this data was tyically flatter relative to the other monthly weather sensitive demand
coeffcients. One inerent drawback to this methodology is the lack of suffcient data points to
develop a strong linear relationship. More years of data can help, but the older data becomes less and
less relevant to curent demand relationships.
3.4 Avista
2009 Natural Gas IRP Chapter 3 - Demand Forecasts
As a final step, to check coefficient reasonableness, we applied the coeffcients to actual customer
count and weather data to backcast demand. This was compared to actual demand with satisfactory
results. The regression calculations and coeffcients can be found in Appendix 3.3.
Weather Forecast
The last input in the demand modeling equation is weather (specifically HDDs). We obtain the most
current 30 years of daily weather data from the National Oceanic Atmospheric Administration
(NOAA), convert it to HDDs and compute an average for each day to develop our weather forecast.
For Oregon, we use four weather stations, corresponding to the areas where natural gas services are
provided. HDD weather patterns between these areas are uncorrelated. For the eastern Washington
and northern Idaho portions of our service area, weather data for the Spokane Airort is used, as
HDD weather pattern within that region are correlated.
Figues 3.3 and 3.4 show NOAA's most recent 30-year average weather data in comparison to the
coldest and warmest planning year in history for the Spokane and Medford areas. Measurements of
historical average weather do not necessarily represent the range of potential futue weather patterns,
including some days that may differ substantially from that average pattern.
Figure 3.3 Average vs. Coldest VS. Warmest HODs
Spokane wea1her
90
80
70
60
14 27 40 53 66 79 92 105 118 131 144 157 170 183 196209222235248261 274 287 300 313 326 339 352 365
January. December
.g 50
Q:i 40
30
20
10
__ 30-year Coldest - 30-year Warmest - Avg - NOAA
Avista 3.5
Chapter 3 - Demand Forecasts 2009 Natural Gas IRP
Figure 3.4 Average vs. Coldest vs. Warmest HODs
Medbrd Wealler
70
10
60
50
'" 40cc:i 30
20
o
1 14 27 40 53 66 79 92 105118131144157 170 183 196 209222235248261 274287300313326339352365
January. Dec
- 30-year Coldest - 30-year Warmest - Avg - NOAA
Figues 3.5 and 3.6 compare the NOAA 30-year average weather with a company-selected
composite of weather months that form a weather year based on average HDDs with the variability
of actual weather.
Figure 3.5 Average vs. Planning Standard Wether
Spokane Welier
90
80
70
60
~ 50c:i 40
30
20
10
o
1 14 27 40 53 66 79 92 105118131 144157170 183196209222235248261 274287300 313326339352365
January. December
- Peak HDDs - Normal HDDs
3.6 Avista
2009 Natural Gas IRP Chapter 3 - Demand Forecsts
Figure 3.6 Average vs. Planning Standard Weather
Medbrd Wealher
70
60
50
'" 40cc
:i 30
10
20
14 27 40 53 66 79 92 105118131 144157170183196 209 222235248261 274287300313326339352365
January. December
- Normal HODs - Peak HODs
The NOAA 30-year average weather (adjusted for global warming-see below) serves as the base
weather forecast that is used to prepare the annual average demand forecast. In preparing the peak
day demand forecast we adjust average weather to reflect a five-day cold weather event. This
consists of adjusting the middle day of the five day cold weather event to the coldest temperature on
record for a service terrtory, as well as adjusting the two days either side ofthe coldest day to
temperatures slightly warmer than the coldest day. For our Washington/Idaho and La Grande service
territories, we model this event on and around February 15 each year. For our southwestern Oregon
service terrtories (Medford, Roseburg, Klamath Falls) we model this event on and around December
20 each year.
The following describes specific details on the coldest days on record for each service territory:
· On Dec. 30, 1968, the Washington/Idaho service area experienced the coldest day on record,
an 82 HDD for Spokane. This is equal to an average daily temperature of -17 degrees
Fahrenheit. Only one 82 HDD has been experienced in the last 40 years for this area;
however, within that same time period, 80 and 79 HDD events occurred on Dec. 29, 1968,
and Dec. 3 1,1978, respectively.
· On Dec. 9, 1972, Medford experienced the coldest day on record, a 61 HDD. This is equal to
an average daily temperature of 4 degrees Fahrenheit. Medford has experienced only one 6 I
HDD in the last 40 years; however, it has also experienced 59 and 58 HDD events on Dec. 8,
1972, and Dec. 2 I, 1990, respectively.
· The other three areas in Oregon have similar weather data. For Klamath Falls, a 72 HDD
occured on Dec. 21, 1990, in La Grande a 74 HDD occurred on Dec. 23, 1983, and a 55
HDD occurred in Roseburg on Dec. 22, 1990. As with Washington/Idaho and Medford, these
days are used as the peak day weather standard for modeling puroses.Avista 3.7
Chapter 3 - Demand Forecasts 2009 Natural Gas IRP
The actual HDDs by area and by day entered into SENDOUTiE can be found in Appendix 3.4.
For this IRP, we adjusted the NOAA weather data to incorporate estimates for global warming in
developing our HDD forecast. This was based on extensive analysis of historical weather data in
each ofthe areas we serve. Adjustments were applied to daily data and include a phase-in over the
first ten years of our planning horizon. The effect ofthe adjustments, all else equal, results in
declining annual demand over time. Appendix 3.5 summarizes our historical analysis and adjustment
factors.
Although our analysis identified a gradual warmg trend in the historical data, we were unable to
discern any definitive evidence to support a peak day warmig trend. We unsuccessfully searched
for potential supporting studies or analysis on the topic and, after discussion with our T AC,
determined we would not make warming trend adjustments to our peak day weather events in our
HDD forecast. Therefore, our modeling and analysis with respect to peak day planning is unaffected
by global warming. Additional information on this topic is in Appendix 3.5.
DEVELOPING A REFERENCE CASE
Significant uncertainty in the planning environment led us to develop a demand forecasting process
that could flexibly adapt to a host of alternative demand forecast assumptions. To understand how
various alternative assumptions influence forecasted demand, we needed a reference point for
comparative analysis. For this we defie a reference case demand forecast (Figure 3.7). We stress
that this case is not intended to reflect anything other than a simple assumption start point.
Figure 3.7 Reference Case Assumptions
1. Customer annual growt rates:
Residential Commercial Industrial
Washington 18%2.1 %1.2%
Idaho 3.0%2.5%0.6%
Oregon 2.7%1.4%0%
2. Use per customer coeffcients - Flat all classes
3. Weather planning standard - coldest day on record
· WAlO 82; Medford 61; Klamath 72; La Grande 74
DYNAMIC DEMAND METHODOLOGY
To address the uncertain planning environment, we identified a demand planning strategy to
critically examine a wide range of potential outcomes. The approach developed consisted of:
· Identifying key demand drivers behind natural gas consumption;
3.8 Avista
2009 Natural Gas IRP Chapter 3 - Demand Forecasts
· Performing sensitivity analysis on each demand driver; and
· Combining demand drivers under various scenarios to develop alternative potential outcomes
for forecasted demand.
In analyzing demand drivers, we grouped them into two categories based on:
· Demand Influencing Factors - Factors that directly influence the volume of natural gas
consumed by our core customers.
· Price Influencing Factors - Factors that, through price elasticity response, indirectly
influence the volume of natural gas consumed by our core customers.
Once factors were identified, we developed sensitivities which we define as focused analysis of a
specific natural gas demand driver and its impact on forecasted demand relative to our Reference
Case when the underlying input assumptions are modified.
Appendix 3.6 schedules the specific sensitivities we identified and the base assumptions we varied to
determine the resultant effect on demand relative to our reference case. Sensitivity assumptions
reflect incremental adjustments we estimate are not captured in the underlying Reference Case
forecast.
Following our testing of the various sensitivities we grouped them into meaningful combinations of
demand drivers to develop demand forecasts representing scenarios. Table 3.4 identifies the
scenarios we developed. Included is an Expected Case reflecting the demand forecast we believe is
most likely. Appendix 3.6 schedules the specific assumptions within the scenarios while Appendix
3.7 contains a detailed description of each scenario.
Expected Case
High Growth, Low Price
Low Growth, High Price
Green Future
Alternate Weather Standard
Supply Constraints
PRICE ELASTICITY
With increased natural gas price volatility, it has become diffcult to project futue natural gas prices.
We acknowledge changing price levels influence usage so we incorporate a price elasticity of
demand factor into our model to allow use per customer to vary into the futue as our natural gas
price forecast changes.
Price elasticity is usually expressed as a numerical factor that defines the relationship of a
consumer's consumption change in response to price change. Typically, the factor is a negative
number as consumers normlly reduce their consumption in response to higher prices or wil
Avista 3.9
Chapter 3 - Demand Forecasts 2009 Natural Gas IRP
increase their consumption in response to lower prices. For example, a price elasticity factor of
negative 0.13 means a 10% price increase wil prompt a 1.3% consumption decrease and a 10%
price decrease wil prompt a 1.3% consumption increase.
We noted complex relationships influence price elasticity and given the challenging economic
environment, we questioned whether curent behavior might differ from historical trends. Working
with the TAC we sought to develop a range of elasticity factors to examine sensitivity of demand to
various price. elasticity assumptions.
AGA PRICE ELASTICITY STUDY
From our participation in the AGA price elasticity study, we received regional elasticity factors
which compared favorably to our past estimates. Based on this corroboration, we used a factor of
negative .13 as our medium case factor to adjust use per customer coeffcients. From this base line
assumption, we varied the factors to come up with a range of price elasticity responses which was
then used in various price influencing demand scenarios (Table 3.5).
Table 3.5 Pnaa Elasticity
Real Price annual
incr wiin 30
Negative .20
Negative .13
No response
nêê'ånnual
incre exce 30
Negative .30
Negative .13
Negative .06
High
Medium
Low
RESULTS
During 2009-10, our Expected Case demand forecast indicates we will serve an average of 317,700
core natural gas customers with 35,099,000 dekatherm of natural gas. By 2028-29, we project
493,600 core natural gas customers with an anual demand of over 42,944,000 dekatherms. In
Washington/Idaho, the number of customers is projected to increase at an average annual rate of2.2
percent with demand growing at a compounded average anual rate of 1.0 percent. In Oregon, the
number of customers is projected to increase at an average annual rate of2.5 percent, with demand
growing 1.4 percent per year.
Figue 3.8 shows system forecasted demand for the Expected, High and Low demand cases on an
average daily basis for each yearl.
1 Appendix 3.9 shows gross demand, DSM savings, and net demand.
3.10 Avista
2009 Natural Gas IRP Chapter 3 - Demand Forecasts
Figure 3.8 System \/de Average Daily Demand
(NetofDSM Savings)
160
140 ---
120 OL__-
::
S 80::
-- ---. .-.100
60
40
20
o i. ,~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ $ ø ~ ø ø # ~ ~g#KK~~¥¥K~KK ~ ~~~ ~ ~ ~ ~~ ~v~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~v~ ~ ~ ~ ~ ~
.. Expeæd Case -- High Grow1 Low Priæ -. Low Grow1 High Priæ
Figure 3.9 shows system forecasted demand for the Expected, High and Low Demand cases on a
peak day basis for each year.
Figure 3.9 System Feb 15 Peak Day Demand
(NetofDSM Savings)
600
~~ 300
.~ --
--~..--500
400
~
200
100
-.~ ~ ~~~~~~~~~$U~$$g$$g~v ~ ~ ~v ~v ~v~v~v~v~v~v ~v ~v ~v ~v ~v ~v ~v ~v ~v~~~~~#~ ~ ~ ~ ~ ~~~~~~~~~
.. Expec1d Case -- High Growt Low Price __ Low Grow1 High Priæ
Detailed data depicting annual and peak day demand data is in Appendix 3.8.
The purpose of the IRP is to balance forecasted demand with existing and new supply alternatives.
Since new supply sources include conservation resources, which act as a demand reduction, the
demand forecasts prepared and described in this section include existing effciency standards and
norml market acceptance levels. The incremental conservation measures modeled are described in
the Demand-Side Resources Chapter.
Avista 3.11
Chapter 3 - Demand Forecasts 2009 Natural Gas IRP
ACTION ITEM
Our price elasticity analysis raised several issues. First, we noted the AGA factors were derived from
annual demand data. This was satisfactory for our anual demand forecasting, but this raised a
question whether the factors were applicable to peak demand analysis. We also use the same factors
for residential and commercial customer classes even though the AGA factors were derived from
residential customer data only.
We also noted that price signals to core customers are lagged and they are often insulated from
volatile prices due to their exposure to tariff rates versus wholesale prices. Finally, we noted that the
period we were analyzing presented a challenging scenario because of the timing of our price
forecasts.
During our planning cycle, prices had reached all-time seasonal highs in summer 2008 but by the
begining of2009, prices had tubled to multi-year lows. This dramatic volatility in the wholesale
market was not necessarily a price signal to core customers who were on more stable tarff rates.
Our medium price forecast captured very low pricing early in the forecast but included a very steep
increase in the second and third years. The medium and high case price elasticity assumptions, when
run through the SENDOUTIR model, resulted in significant curtailment of demand which was much
greater than historical experience.
This curtailment had a cumulative effect and our forecasted demand in some cases took several years
to retur to our current demand. This raised apprehension that the forecasted curailment might not
occur and our modeled demand could be understated. This, in turn, could distort the timing of actual
futue resource deficiencies. On the other hand, the customer response could materialize as modeled,
resulting in an actual significant demand curailment.
We discussed this dilemma with the TAC. We decided to use the low price elasticity assumption for
our Expected Case and monitor closely actual use per customer data and DSM program results for
indications of price elasticity response trends that may have been influenced by evolving economic
conditions.
For the comig IRP cycle, we plan to investigate contemporary analytical sources for information on
natural gas price elasticity and inquire if the AGA wil update its analytical work. We may also
consider hiring a third-party price elasticity study and assess interest of other utilities in pursuing a
regional study.
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 ofthose considerations is a
reasonable range of outcomes with respect to core consumption of natural gas. While we recognize
that the actual level of demand is dependent on a variety of factors, reviewing a range of potential
outcomes allows us to plan more effectively as economic or pricing conditions change.
3.12 Avista
2009 Natural Gas I RP
CHAPTER 4 - DEMAND-SIDE RESOURCES
OVERVIEW
Demand-side management (DSM) is the activity pursued by an energy utility to influence its
customers to reduce their energy consumption or change their pattern of energy use away from peak
consumption periods. This usually includes information campaigns and financial incentives to
persuade customers to adopt conservation measures. Conservation measures are installations of
appliances, products or facility upgrades that result in energy savings. Demand-side resources
represent the aggregate energy savings attained from the installation of conservation measures.
A vista has been offering natural gas DSM programs to its customers periodically since 1995. These
programs result in multiple benefits including reducing customers' bils, reducing supply-side
resource needs and reducing GHG emissions. These benefits make acquiring cost effective demand-
side resources a very attractive resource alternative which we believe is the best strategy for
minimizing energy service costs to our customers while promoting a cleaner environment.
Since our last IRP, energy policy and legislation activity are placing a high level of awareness and
importance on environmental and energy use issues. Spiking energy prices in early 2008 and
subsequent economic challenges in latter 2008 and into 2009 have also led to increased public
awareness and interest in energy saving measures. In response, A vista is committed to provide the
resources to help consumers reduce energy consumption through cost effective conservation
programs.
Avista's DSM organization is split into a North Division (Washington and Idaho), and a South
Division (Oregon). The North Division is one delivery area while the South Division is further
segmented into four delivery areas consistent with our SENDOUTiI modeling.
COST EFFECTIVENESS
Cost effectiveness is a fundamental concept to DSM. In simple term, it is the determination of
whether the present value of the energy savings (net of non-energy benefits) for any given
conservation measure is greater than the cost to achieve the savings. When making this assessment,
it is important to capture all benefits and costs in the evaluation. For example, Avista identifies and
quantifies the non-energy benefits of water conservation in high effciency front loading washing
machines as an offset againt the avoided cost ofthat measure. For the South Division, the presence
of environmental externalities in supply resources relative to conservation measures is quantified and
factored into any comparative cost analysis i. Incremental administrative costs are also evaluated for
possible inclusion in analyzing conservation measure economics.
i Oregon IR regulations require that a 10% cost advantage accres to DSM resources relative to supply resources for envionmental
externalities costs. Appendix 4.4 describes our analysis.
Avista 4.1
Chapter 4 - Demand-Side Resources 2009 Natural Gas IRP
Exceptions to the cost effectiveness rule include conservation measures that are pursued as part of a
broader market transformation effort or measures that are mandated or approved by regulators. In
some cases, bundling measures may justify inclusion of a non-cost effective measure when the
overall bundle of measures is cost effective, otherwise enhancing the non-cost effective measure
with cost effective measures while enticing the customer to install more measures.
TYPES OF CONSERVATION MEASURES
Conservation measures that achieve generally uniform year round energy savings independent of
weather temperature changes are considered base load measures. Examples include high efficiency
water heaters, cooking equipment and front load clothes washers. Measures that are influenced by
weather temperature changes are weather sensitive measures which include higher effciency
furnaces, ceiling/wall/floor inulation, weather stripping, inulated windows, duct work
improvements (tighter sealing to reduce leak) and ventilation heat recovery systems (captuing
"chimney" heat). Weather sensitive measures are desirable in resource planning, as they save the
most energy during the coldest periods thus displacing the more expensive peaking or seasonal
supply resources. Weather sensitive measures are often referred to as winter measures and are valued
using a higher avoided cost while base load measures are often called annual measures and are
valued ata lower avoided cost.
Conservation measures are offered to residentiaL, non-residential and low income customers.
Conservation measures offered to residential customers are classified as prescriptive, meaning they
have a standardized therm savings which can be generalized across the customer class and all
customers receive the same financial incentive for the same measures. Low income customers
receive a more holistic, customized approach through six Community Action Agency partnerships.
Non-residential customers have access to prescriptive and site-specific conservation measures. Site-
specific measures are customized to the facility and have cost and therm savings that are unique to
the individual facility.
Finally, some conservation measures in our South Division are offered based on legislation and are
therefore designated "mandatory" or "must take" measures in our SENDOUT(ß modeling tool, which
means they are offered to customers without regard to their current cost effectiveness relative to the
utility's supply resources. An example of something mandated would be a walk-through energy
audit which would not be accompanied with energy savings unless a customer chooses to participate
in a program. In addition, a customer may choose to delay participating in a program for many years
if they choose to participate at all. In these cases, the audit would be non-cost effective since there is
no savings benefit to offset the cost of the audit.
METHODOLOGY
Avista's methodology for evaluating DSM within our IRP is based on four key concepts:
4.2 Avista
2009 Natural Gas IRP Chapter 4 - Demand-Side Resources
· Provides a comprehensive evaluation of all significant conservation measures that are
curently commercially available and emerging measures that are likely to be available in the
future;
· Evaluates conservation measures in a process that is interactive with supply-side options;
· Maximizes portfolio net total resource value (we strive to get the most for each dollar spent);
and
· Delivers analytical results that are actionable for the DSM implementation planning process2.
The methodology we adopted to fulfill these concepts has four phases:
· Identifying Technical Potential
· Assessing Achievable Potential
. SENDOUT~ Testing
· Conservation Goal Development
The above DSM methodology is summarized in the flowchart in Figure 4.1. Details of each phase
follows.
. Figure 4.1 DSM Methodology Flowchart
DSM Integration within the Natural Gas IRP
Identify potential measure-develop co, energy saings,
NEBs characteristics
Develop technical and
achievable potential
Integrated Resource Plan Process
Business Planning process - outside scope of IRP
Initiate new programs,ContinuelmodifltenninateExisting programs per
Implementation plan
Review existing
business plan &
penonn additional
analysis on progras
Develop ad hoc
agreements per
Implementation plan
Develop a reise
DSM implementation
plan
2 The completion of IR analysis is not the end point but rather the midpoint of a larger reassessment of the DSM resource portfolio.
Appendix 4.1 descrbes the development of our DSM implementation plan and overall DSM operations.
Avista 4.3
Chapter 4 - Demand-Side Resources 2009 Natural Gas I RP
PHASE ONE: IDENTIFYING TECHNICAL POTENTIAL
Technical potential is an estimate of all energy savings that can theoretically be accomplished if
every customer that could potentially install a conservation measure did so without consideration of
market barriers such as cost and customer awareness. For example, the "replace on burnout"
technical potential for high effciency water heaters would quantify total savings assuming every
existing water heater (gas or electric) within a natual gas service terrtory would be replaced with a
high effciency model upon an assumed burout schedule in all cases.
In 2005, Avista contracted with RL W Analytics, a conservation analysis consultant, to
independently identify and analyze the potential energy savings for our Oregon service territories.
Methodology from their study was extrapolated to Washington and Idaho and served as the initial
basis for determining conservation technical potential for all of Avista's natural gas service
territories. The energy savings data for weather-sensitive measures were adjusted to incorporate
local heating degree day data appropriate to each geographic area. A vista DSM engineers, program
implementers and analysts also reviewed the consultant's estimates of incremental measure costs,
measure lives, energy savings and other inputs and assumptions, making adjustments when
knowledge oflocal factors differed from the more generalized assumptions used in the study.
Since 2005, we have made adjustments and updates to incorporate new information regarding
measure costand energy savings, augmenting the study with additional measures not previously
evaluated. A total of 155 residential and 147 non-residential measures were considered for this IRP.
A summary ofthese measures for both divisions are contained in Appendix 4.2.
PHASE TWO: ASSESSING ACHIEVABLE POTENTIAL
Achievable potential represents a more realistic assessment of expected energy savings since it
recognizes and accounts for economic and other constraints that preclude full installation of every
identified conservation measure. Even the most robust information campaigns wil not reach every
eligible customer nor suffciently motivate all affected customers to immediately install every
conservation measure applicable to them.
Unlike other regional utilities that have selected an overall percentage to estimate achievable
potential, Avista analyzes each measure's likely installation rate to establish measure by measure
achievable potentiaL. Engineers and program implementers begin their evaluation with the number of
natural gas customers in that division broken down by the percentage that is single family,
multifamily or manufactured homes. The applications are evaluated based on how many have that
application in their home or facility and/or have access to have it in their home or facility and,
finally, how many of those that would be replaced with a higher effciency option over the standard
option over the 20-year horizon. A summary list oftechnical and achievable potential is included in
Appendix 4.2.
Figures 4.2 and 4.3 show the comparison oftechnical potential and achievable potential for our
North and South Divisions, respectively. For perspective, we indicate a cost effectiveness screen of
$0.50 pertherm based on an approximate commodity cost of$5 per Dth. Around this level, Avista's
4.4 Avista
2009 Natural Gas IRP Chapter 4 - Demand-Side Resources
achievable potential tracks much closer with the technical potential and is similar to other regional
utilities. We fuher discuss the gap in technical versus achievable potential in Appendix 4.1
including our plans to obtain a new external study of technical potential prior to completion ofthe
20111RP.
Figure 4.2 Conservation Supply Curve. North
All Segments, 2010 DSM Polenlil
12,000
10,000
8,000
íñ
~ Ec: ...- .c 6,000,¡ :;_ c:'" '":: Ulc:::4,000c: 0
~ E.
2,000
- Apprximate "currnt marker cost efctiveness screen
JrJ I
,J i
rL ~
U?lo
o 0.5 1.5 2 2.5 3 3.5 4
Levelized Annual Cost ($/therm)*
. Maximum colis $11.89; chart scae 1rnca at $4
Figure 4.3 Conservation Supply Curve. South
AD Segments, 2010 DSM Poæntial
Ul íñ
'" E.~ ~'" -U) ..- c:'" '"
:: Ulc: ::c: 0
~ E.
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
o
o
i
I- Approximate "currnt marker cost effctiveness screen.
I iI~r
;¡~:iri
0.5 1.5 2 2,5 3 3.5 4
Levelized Annual Cost ($/therm)*
. Maximum cot is $9.36; char scale 1rncal at $4
These estimates are preliminary assessments of the best implementation approach for particular
technologies and market segments and the expected growth or decline ofthose markets. These
assessments may require revision based on further development of program plans during the
implementation planning process.
Avista 4.5
Chapter 4 - Demand-Side Resources 2009 Natural Gas IRP
PHASE THREE: SEN DOUT(8 TESTING
In past IRPs, conservation measures were grouped into bundles to facilitate easier data input and
faster system processing within SENDOUTQP. However, this method required a complex process of
manually calculating leve1ized total resource cost (TRC) outside the model based on estimated
avoided costs that had to be checked and adjusted against SENDOUTQP results in an iterative process.
For this IRP, we elected to invest the time to enter each individual conservation measure into
SENDOUTQPto enable more granular and accurate measure selection for DSM resource acquisition.
This effort was no small task considering the exponential proliferation of inputs, as each assumption
for every conservation measure had to be entered by customer class across the eight sub areas we
model in SENDOUTQP. This resulted in significantly more data entry that required managing around
potential system processing constraints but eliminated prepackaging issues and potentially less
accurate "group" measure selection.
Inputs included conservation measure cost, measure life, annual energy savings, non-energy benefits
and discount rate. The model then calculated a levelized TRC for each measure to compare against
the model's avoided cost calculation.
Mandated measures were entered into SENDOU~ as must takes which bypassed system cost
effectiveness testing and were automatically selected as a preferred resource by the modeL. All other
measures were evaluated by SENDOUTQP againt other supply-side resource options.
The demand-side resources selected by SENDOUTQP are summarized in Table 4. I. Note that these
results do not include site-specific measures. These measures are incorporated in the next phase of
the IRP process.
Table 4.1 SENDOU~ DSM Results
(calendar year 2010)
Residential measures
Non-residential measues
Total adopted measures (therms)
North
2,926,761
75,601
3,002,362
South
215,580
110,734
326,314
PHASE FOUR: CONSERVATION GOAL DEVELOPMENT
In this phase, we augment the results of the SENDOUT(ß testing with estimates of resource
acquisition from commercial and industrial site-specific programs to develop a therm acquisition
goaL. These programs can include multiple conservation measures, are inerently individualized and
have unique characteristics that preclude input into SENDOUTQP.
Site-specific programs are designed to be all inclusive so any natural gas effciency options with
measureable therm savings qualify for the program in some fashion. Direct fiancial incentives are
contingent upon minimum project simple-payback criteria in the North Division and a TRC cost
effectiveness test in the South Division based on differing regulation. Generally speaking, all
projects have the potential for receiving technical assistance and many qualify for direct fiancial
4.6 Avista
2009 Natural Gas IRP Chapter 4 - Demand-Side Resources
assistance. Site-specific therm acquisition is estimated by establishing a baseline of historical site-
specific program results modified to reflect past and estimated future growth.
A final adjustment must be made to eliminate the duplication of resource opportnities between the
all-inclusive site-specific programs and the measures accepted within the SENDOUT1Ð modeling.
Some of the measures incorporated into the SENDOUT1Ð model are duplicative of resource
acquisition incorporated into the estimates of site-specific resource acquisition. Based on a review of
the SENDOUT1Ð accepted measures and the expectations of site-specific program targets, we
estimated that all of the South Division and 84 percent ofthe North Division future site-specific
therm acquisition were included in the SENDOUT1Ð analysis.
It is possible that there wil be measures selected in this process that wil subsequently be determined
to be unsuitable for inclusion in Avista's DSM portfolio based on post-IRP analysis, implementation
planning and program planning efforts. It is also possible that programs could be developed for
measures that were rejected by this IRP as a result of this same process. Though the IRP is our best
opportunity to comprehensively re-evaluate the DSM portfolio and its integration into the overall
resource mix at one point in time, it is necessary to incorporate an ongoing implementation planning
process to ensure that the best resource decisions are made.
PRELIMINARY CONSERVATION GOAL
The following therm goals reflect of the results ofthe integrated resource optimization as further
described in Chapter 6 - Integrated Resource Portfolio. See that chapter for the complete results of
the integrated resource optimization including the regional cumulative benefits over the 20-year
planning horizon.
The SENDOUT1Ð results3 and modifications for site-specific programs for the first two years are
summarized in Table 4.2.
Table 4.2 Results of Achievable Resource Potential
Current Year 2010 and 2011
SENDOUT(íaccepted residential programs
SENDOUT(íaccepted non-residential programs
Estimated site-specific acquisition
Less: non-res prescriptive programs duplication
Total North Division
2010
2,926,761
75,601
811,920
(685,440)
3,128,842
2011
2,862,948
77,852
844,397
(712,858)
3,072,339
SENDOUT(íaccepted residential programs
SENDOUT(íaccepted non-residential programs
Total South Division
2010
215,580
110,734
326,314
2011
206,333
118,650
324,983
3 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.
Avista 4.7
Chapter 4 - Demand-Side Resources 2009 Natural Gas I RP
Based on the analytical process described in the above Methodology section, first-year energy
savings goals resulting from the IRP process were approximately 3,128,842 therm in the North
Division and 326,3 14 therms in the South Division. This commitment represents an increase of 98
percent from the 2007 IRP annual resource acquisition for 2010 in the North Division and an
increase of9 percent in the South Division.
Site-specific acquisition included in the above is estimated to be 126,480 therms for the North
Division and is no longer applicable for the South Division as all measures were tested within
SENDOUTIl. These estimates incorporate consideration of the significantly different non-residential
customer bases within our North and South Divisions. Specifically, non-residential customers
within our South Division tend to be smaller-sized retail customers and generally non-industriaL.
However, in spite oftheir limited opportnity to acquire resources through their site-specific
program, existing utility staff has been redeployed to establish and foster relationships with contract
auditors and trade alles in effort to increase participation.
The North Division site-specific program has been a highly successful component ofthe overall
portfolio. However, active and real-time management is necessary to continue to focus on and move
toward new opportnities within this market. As more participation occurs in specific applications
and technologies, program implementers and engineers use results to establish more prescriptive
approaches in order to increase participation without having to add additional infrastructure. This
has proved to be a successful approach to address developing markets and influencing customers
toward them.
The North potential is in excess of the 2010 acquisition goal of 1,755,829 therm developed in the
2007 IRP. The potential increase in the target is the result ofa steep carbon mitigation cost adder4 in
our natural gas price forecast that we model to take effect in 20l5. This large increase in natual gas
prices, correspondingly, significantly increases avoided costs over the planning horizon. A concern
is how to influence customers to implement natural gas efficiency upgrades now based on a price
increase modeled to take effect in 2015 which they may not see or are skeptical of it materializing
that far into the future.
We are resolved to meet all cumulative potential identified in this IRP over the planning cycle, but
wil do so with a gradual ramping up of program activity. We determined it was possible to establish
an approximate 6.5 percent constraint on the anual increase over the first 10 years while
simultaneously achieving this objective in the long ru by the end of the 20- year period. This
increase is in excess of customer growth but ensures that the infrastructue growth can be managed
more carefully and without undue inflation of acquisition costs associated with rapid growth.
For the South Division, the potential is slightly below the 2010 acquisition goal of304,548 therms
from the 2007 IRP. This comes at a time when customers in this service territory are facing state
unemployment rates exceeding 14 percent in some counties. We are resolved to meet all cumulative
4 Adder reflects price impacts to comply with anticipated climate change legislation. Appendices 3.6 and 3.7 has detailed discussion
on our modeling of climate change policy.
4.8 Avista
2009 Natural Gas IRP Chapter 4 - Demand-Side Resources
potential identified in this IRP over the long-term (20-year) planning cycle, but wil do so with a
gradual ramping up of program activity. We determined this to be possible by establishing an
approximate 2.2 percent constraint on the annual increase over the fist five years while
simultaneously achieving this objective in the long ru by the end ofthe 20-year planning horion.
This increase is greater than the projected customer growth but ensures that the infrastructure growth
can be managed more carefully during this economic time.
Application ofthis 6.5 percent annual growth constraint for the North Division and 2.2 percent
annual growth constraint for the South Division results in a summary of annual and cumulative
acquisition and identified DSM potential as listed in Table 4.3
Table 4.3 Annual and Cumulative SENDOUT(ß Achievable Potential and Revised Goal
I North Divison /il South Divison
Achievable Cumulative DSM Cumulative Achievable Cumulative DSM Cumulative
Potential Potential Goal Goal Potential Potential Goal Goal
CY2010 3,128,842 3,128,842 2,193,338 2,193,338 326,314 326,314 303,300 303,300
CY2011 3,072,339 6,201,181 2,336,541 4,529,879 324,983 651,297 309,973 613,273
CY2012 3,010,146 9,211,327 2,489,094 7,018,973 298,759 950,056 316,792 930,065
CY2013 3,000,080 12,211,407 2,651,607 9,670,579 280,458 1,230,514 299,879 1,229,944
CY2014 3,005,777 15,217,184 2,824,730 12,495,310 278,214 1,508,728 278,214 1,508,158
CY2015 2,943,985 18,161,169 3,009,157 15,504,466 275,973 1,784,701 275,973 1,784,130
CY2016 2,864,302 21,025,471 3,205,625 18,710,091 271,604 2,056,305 271,604 2,055,735
CY2017 2,849,376 23,874,847 3,414,920 22,125,011 266,358 2,322,663 266,358 2,322,093
CY2018 2,862,118 26,736,965 3,637,633 25,762,643 262,851 2,585,514 263,041 2,585,134
CY2019 2,900,317 29,637,283 3,874,639 29,637,283 266,715 2,852,229 267,095 2,852,229
CY2020 2,796,582 32,433,864 2,796,582 32,433,865 269,559 3,121,789 269,559 3,121,788
CY2021 2,675,821 35,109,685 2,675,821 35,109,686 257,134 3,378,923 257,134 3,378,922
CY2022 2,690,538 37,800,223 2,690,538 37,800,224 227,802 3,606,725 227,802 3,606,724
CY2023 2,707,941 40,508,164 2,707,941 40,508,165 188,897 3,795,622 188,897 3,795,621
CY2024 2,651,295 43,159,459 2,651,295 43,159,460 154,709 3,950,331 154,709 3,950,330
CY2025 2,621,258 45,780,716 2,621,258 45,780,718 136,043 4,086,374 136,043 4,086,373
CY2026 2,585,548 48,366,264 2,585,548 48,366,266 132,376 4,218,750 132,376 4,218,749CY20272,278,881 50,645,145 2,278,881 50,645,147 135,054 4,353,804 135,054 4,353,803
CY2028 2,034,955 52,680,100 2,034,955 52,680,102 129,141 4,482,945 129,141 4,482,944
CY2029 2,029,521 54,709,621 2,029,521 54,709,623 120,643 4,603,588 120,643 4,603,587
The North Division potential and acquisition identified in Figues 4.4 and 4.5 indicates that we wil
fully acquire identified DSM potential over the 20-year planning cycle within the 6.5 and 2.2 percent
annual ramp-up constraint for North and South, respectively.
Avista 4.9
Chapter 4 - Demand-Side Resources 2009 Natural Gas i RP
35,000
30,000
25,000
'"
Ê..20,000;¡,.'"..'"15,000::0;¡
10,000
5,000
Figure 4.4 Cumulative Identified Potential vs. Cumulative Acquired
Nor1 Division
o
- Cumulatve Polenlal
- Cumulatve Acquisiti
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
3,000
2,500
'"2,000
~;¡,.1,500'"..'"::0;¡
1,000
500
Figure 4.5 Cumulatve Identified Potential vs. Cumulatve Acquired
Souli Divisn
- Cumulatve Polal
- Cumulative Acquisiti
o
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
The IRP resource analysis is, as previously mentioned, the starting point for the implementation
planning process. Appendix 4.1 discusses Avista's DSM programs and how the IRP results wil be
incorporated into DSM operations.
DSM SENSITIVITIES
Avista continues to acknowledge its obligation to acquire all cost effective natural gas-effciency
resources available through utility intervention. Given the rapid changes within the natural gas
market, new efficiency opportnities may arise in the market within the 20-year horizon being
4.10 Avista
2009 Natural Gas IRP Chapter 4 - Demand-Side Resources
analyzed within this process. As we continue to consider and evaluate any developing applications
and/or technologies for inclusion in our portfolio between IRPs, considerable uncertainty remains
regarding customers' response to these programs. Since this is a time of economic uncertainty when
retail gas prices are declining, we face the challenge of how to get customers to respond now to
prices they might not actually see for years to come. Historically, we have seen levels ofless
paricipation as retail prices decline. However, stimulus-related governent incentives could
accelerate participation.
To better understand how demand-side resources may be affected by uncertain economic conditions,
we evaluated two DSM sensitivities based on the following:
· DSM Accelerated - Tax credits, particularly on the residential side, induce a combination of
increasing participation in our programs to some degree, but the greatest impact is in
inducing participating residential customers to stretch to higher levels of effciency in order
to qualify for tax credits as a complement to our existing rebates. Non-residential customers
have far fewer such tax credits available to them, but to a much lesser degree the same
impact occurs in that market. Stimulus funded residential audit programs result in the
acquisition of low-cost/no-cost measures beyond what was assumed in the IRP base case.
· DSM Delayed - Budget constraints restrict customer incentives to less than current levels.
Our program outreach is cut by 50% and staffing is curtailed. The economic recession
continues and due to reduced disposable income, we see a reduction in non-lost-opportty
(deferrable) efficiency measures such as weatherization and a lesser reduction in the
installation of lost-opportunity (furnace, hot water heater, etc.) measures. We also see a
reduction in non-residential energy-efficiency measures due to the lack of discretionary
capital budget within our customers businesses.
The resulting incremental (decremental) savings ofthese sensitivities are summarized in Table 4.4:
Table 4.4 DSM Sensitivities Summary
DSM Accelerated
Cumulative Therms
2010 Therms over 20 Years
DSM Delayed
Cumulative Therms
2010 Therms over 20 Years
Annual Measures
Medford 3,666 65,985
Roseburg 843 15,173
Klamath 1,539 27,697
LaGrande 642 11,560
WAiID 56,311 1,013,598
Winter Measure
Medford 16,330 293,944
Roseburg 3,755 67,586
Klamath 6,854 123,372
LaGrande 2,861 51,494
WAiID 233,720 4,206,960
(444)
(102)
(186)
(78)
(32,584)
(7,986)
(1,837)
(3,353)
(1,400)
(586,512)
(125,057)(2,251,026)
The impact of either sensitivity could be meaningfuL. We wil continue to watch for signs of either
sensitivity developing. However, this uncertainty does not preclude us from pursuing the planned
aggressive ramp-up of natural gas-effciency programs. Additionally, we have, and wil continue to
Avista 4.11
Chapter 4 - Demand-Side Resources 2009 Natural Gas IRP
actively seek, opportities for new or enhanced resource acquisition through the development of
cooperative regional programs.
ENVIRONMENTAL EXTERNALITIES
The impact of utilizing energy on the environment continues to be a subject of societal concern and
debate. Ifthere are impacts that cannot be repaired natually within a reasonable period oftime,
damage cost to the environment occurs for which society wil have to pay in some future
undetermined form. The question of who pays, how much and when payment should be made, are
complicated issues. This debate is begining to be addressed through a variety of public policy
initiatives and legislation. Regulatory guidelines in Oregon advocate specific analysis in the IRP
process to better understand these issues. Avista included an evaluation of the impacts of
environmental externalities in the context of this evolving legislative environment. Appendix 4.4
discusses our analysis.
DEMAND RESPONSE
Demand response is a peak demand management concept where customers adjust the timing of their
energy consumption away from consumption peaks in exchange for lower rates. Implementation
strategies encompass a number of activities including real time pricing, time of use rates, critical
peak pricing, demand buyback, interrptible rates and direct load controls. When effectively
implemented, acquisition of costly supply resources can be deferred.
Demand response works best when it is a quick solution to an immediate problem. When demand
peaks, system operators need the ability to either quickly notify customers to curail consumption or
do it themselves via control systems to physically manage/restrict gas flow to increase distribution
system pressures.
This mechanism exists with respect to our interrptible transportation-only customers, which make
up approximately one third of Avista's total annual throughput. However, because we do not
purchase supply for these customers, they do not represent an incremental supply resource
alternative. Only core customers with high winter consumption profiles would provide an
incremental supply resource using demand response curailment strategies. Unfortnately, we
currently have very few core customers with a complying consumption profile. As a result, we
believe that all customers who can manage their operations on interrptible service are curently
served on an interrptible basis, leaving little opportunity to reduce peak loads through expanded
interrptible service.
While little demand response opportnity exists on our natual gas system, we continue to monitor
the progress of other natural gas utilities and their efforts of peak load shifting to offset hourly and/or
daily flow constraints. Whereas electric demand response technologies have been in place for over
two decades, major differences exist between electric and natual gas supply/delivery systems. The
economics of the timing of natural gas usage are much more forgiving than electric due to
underground storage and line packing. Furthermore, natual gas curailment is not an option since a
4.12 Avista
2009 Natural Gas IRP Chapter 4 - Demand-Side Resources
natural gas company cannot restart service without a technician on-site to ensure all pilots are
properly lit for safety reasons.
At times natual gas providers may find implementing a demand response program helpful in
offsetting or postponig a pipeline upgrade or in price balancing. However, mandatory participation
in the affected areas would be vital to fund the necessary investment in enabling technologies.
One possible demand response program for the residential sector is remotely controllable
thermostats. A vista is curently conducting a pilot project using this technology with Idaho electric
customers. At present this pilot is limited to controlling the thermostat for space heating and cooling
during times of electric peak demand. This pilot wil conclude December 31, 2009 at which time a
draft report wil be compiled for results and what was learned from the program. Preliminary
findings at this time show this technology is not cost effective for Avista for either summer or winter
peak. Future technologies may offer cheaper, more reliable and flexible options for customers and
their fuel providers. However, there are no near-term plans to pursue demand response programs.
CONCLUSION
By prompting customers to change their demand for natural gas, A vista can displace the need to
purchase additional natural gas supplies, displace or delay contracting for incremental pipeline
capacity and possibly displace or delay the need for reinforcements on our distribution system. This
IRP process provides Avista with the necessary resource analysis to evaluate demand-side resource
options alongside supply-side resources, periodically review and update DSM operations and finally,
develop and implement improved natural gas effciency programs.
The completion of IRP analysis is not the end point but rather the midpoint of a larger reassessment
ofthe DSM resource portfolio. The IRP analysis presented has generally indicated a set of cost
effective measures and achievable resource potential for a future DSM resource portfolio. Yet
fuher evaluation is needed to facilitate the development of program plans and to incorporate them
into an updated DSM implementation plan in the overall DSM operations.
Avista 4.13
Chapter 4 - Demand-Side Resources 2009 Natural Gas IRP
4.14 Avista
2009 Natural Gas IRP
CHAPTER 5 - SUPPLY-SIDE RESOURCES
OVERVIEW
We have analyzed a range of anticipated future demand scenarios and a variety of possible
conservation measures to reduce demand. This chapter discusses possible supply options to meet net
demand. Our objective is to reliably provide natural gas to customers with an appropriate balance of
price stability and prudent cost while navigating continuously changing market conditions. To
achieve this, we evaluate a variety of supply-side resources and attempt to build a supply portfolio
that is appropriately diversified. The resource acquisition and commodity procurement programs
resulting from our evaluation consider physical and financial risks, market-related risks and
procurement execution risks and identify the methods we deploy to mitigate these risks.
We manage our natural gas procurement and related activities on a system-wide basis. We have a
number of regional supply options available to serve our core customers. These include fi and
non- firm supplies, firm and interrptible transportation on six interstate pipelines and two storage
projects. Because Avista's core customers span three states, the diversity of delivery points and
demand requirements adds to the options available to meet customers' needs. The utilization ofthese
components varies depending on demand and operating conditions. In this chapter, we discuss the
available regional commodity resources and our procurement plan strategies, the regional pipeline
resource options available to deliver the commodity to our customers, and the storage resource
options available which provide additional supply diversity, enhanced reliability, favorable price
opportunities, and flexibility to meet a varied demand profile. Beyond these traditional supply-side
resources, we discuss non-traditional resources which are also considered.
COMMODITY RESOURCES
SUPPLY BASINS
A vista is fortunate to be located in relatively close proximity to the two largest natural gas producing
regions in North America--the Western Canadian Sedimentary Basin (WCSB), which is located
primarily in the Canadian provinces of Alberta and British Columbia, and the Rocky Mountain gas
basins, located primarily in Wyoming, Utah and Colorado. Avista sources virually all of its natural
gas supplies from these two basins.
The WCSB and Rockies gas basins used to have limited pipeline export potential, which has
historically resulted in lower regional natural gas prices that were discounted to other pars ofthe
country. Over the last decade, however, several large pipelines have been completed (or capacities of
existing pipelines increased) connecting the WCSB and Rockies gas basins to the Southwest, Midwest
and Northeast sections of the continent. This has, at times, diminished the discounted price advantage the
region has enjoyed. Future projects that relieve bottlenecks and pipeline congestion out ofthe basin
enabling gas to flow to higher priced markets could further erode this historically favorable price
advantage. Futue shale production in eastern markets could also reduce or eliminate this advantage.
Avista 5.1
Chapter 5 - Supply-Side Resources 2009 Natural Gas IRP
REGIONAL MARKET HUBS
Extending out from the two primary basins are numerous regional market hubs where natural gas is
traded. These typically are located at pipeline interconnects. A vista is located near and transacts at
most of the Pacific Northwest regional market hubs, enabling flexible access to a diversity of supply
points. These supply points include:
AECO - The AECO-C/Nova Inventory Tranfer market center is a major connection region to
long-distance transportation systems, which take gas to points throughout Canada and the
United States. Alberta has historically produced 90% of Canada's natural gas and is the
source of most Canadian natural gas exports to the United States representing volume that
accounts for approximately 13% of U.S. natural gas requirements.
Rockies - This pricing "point" actually represents several locations on the southern end ofthe
NW system in the Rocky Mountain region. The system draws on Rocky Mountain gas-
producing areas clustered in areas of Colorado, Utah, and Wyoming.
Sumas/Huntingdon - This pricing point at Sumas, Washington, is on the U.S.-Canadian border
where the northern end of the NWP system connects with Spectra Energy's BC Pipeline, and
is predomiantly Canadian gas comig south from Northern British Columbia.
Malin - this pricing point is at Malin, Oregon on the California-Oregon border where the
pipelines of Trans Canada Gas Transmission Northwest (GTN) and Pacific Gas & Electric
Co. connect.
Station 2 - Located at the center ofthe Spectra Energy - BC Pipeline system connecting to
northern British Columbia production.
Stanfield - Located near the Washington/Oregon border at the intersection of the NWP and
GTN pipelines
Kingsgate - Located at the US-Canadian (Idaho) border where the GTN pipeline connects with
the TransCanada Foothils pipeline.
Given the ability to transport natural gas to other portions of North America, natural gas pricing is
often compared to the Henry Hub price for natual gas. Henry Hub is a natual gas trading point
located in Louisiana and is widely recognized as the primary natural gas pricing point in the United
States. Henry Hub is also the trading point used in NYMEX futures contracts.
Figue 5. I shows historic natural gas prices for fist-of-month index physical purchases at AECO,
Sumas, Rockies and Henry Hub. The figue ilustrates there is usually a tight relationship among the
various locations; however, there have been periods where one or more price points have
disconnected. In winter 2000-2001, Sumas rallied on a combination of the western energy crisis and
unusually cold local weather conditions. In fall of2005, hurrcanes Katrina and Rita disrupted
significant Gulf of Mexico regional production causing the Henry Hub to spike disproportionately to
Northwest hubs. Since 2007, increased production in the Rocky Mountain basin has exceeded the
takeaway pipeline capacity forcing concessions on Rockies prices pending completion of major
phases of the Rockies Express pipeline project. This significant project, completed in late summer
5.2 Avista
2009 Natural Gas IRP Chapter 5 - Supply-Side Resources
2009, enables substantial volumes to reach Midwestern and Northeast demand centers.
Consequently, Rockies prices have resumed tighter trackig with Henry Hub prices.
Figure 5.1 Monthly Price
AECO/SumasJRocksiHenry Hub
$16.00
$14.00
$12.00
$10.00
.cÕ $8.00..
$6.00
$4.00
$2.00
$0.00**~~~~~~~~~~~~~~~~ ~~~~# ~# ~ # ~# ~ # ~# ~# ~# ~# ~# ~# ~
.. AECO -. Sumas ~ Rocks __ Henry Hub
Natural gas prices among the Northwest regional supply points typically move together as well;
however, the basis differential can change depending on market or operational factors. This includes
differences in weather patterns, pipeline constraints at different locations and the ability to shift
supplies to higher-priced delivery points in the United States or Canada. By monitoring these price
shifts, we are often able to purchase at the lowest-priced trading hubs on a given day, subject to
operational and contractual constraints.
As mentioned above, Rockies natural gas has tended to trade at a discount to Henry Hub when
production out-paced local demand and takeaway pipeline capacity. Pipeline expansion activity
moving incremental production southwest to California (Kern River pipeline) and east to the
Midwest and Eastern seaboard markets (via the Rockies Express pipeline) has eased the basis
differential between AECO and Sumas prices as well.
Liquidity is generally sufficient in the day-markets at most northwest supply points. AECO
continues to be the most liquid supply point, especially for longer-term transactions. Sumas has
historically been the least liquid of the four major supply points (AECO, Rockies, Sumas, Malin).
This iliquidity contributes to generally higher relative prices in the high demand winter months.
Procurement of natural gas is done via contracts. There are a number of contract specifics that vary
from transaction-to-transaction, and many ofthose terms or conditions impact commodity pricing.
Some ofthe agreed-upon term and conditions include:
Avista 5.3
Chapter 5 - Supply~Side Resources 2009 Natural Gas IRP
Firm vs. Non-Firm - Most term contracts specify that supplies are firm except for force
majeure conditions. In the case of non- fi supplies, the standard provision is that they may
be cut for reasons other than force majeure conditions.
Fixed vs. Floating Pricing - The agreed-upon price for the delivered gas may be fixed or based
upon a daily or monthly index.
Physical vs. Financial - Certain counterparties, such as banking institutions, may not trade
physical natural gas but are stil active in the natural gas markets. Rather than managing
physical supplies, those counterparties choose to transact fiancially rather than physically.
Financial transactions provide another way for A vista to fiancially hedge price.
Load FactorN ariable Take - Some contracts have fied reservation charges assessed during
each of the winter months, while others have minimum daily or monthly take requirements.
Depending on the specific provisions, the resulting commodity price wil contain a discount
or premium compared to standard term.
Liquidated Damages - Most contracts contain provisions for symmetrical penalties for failure
to take or supply natural gas.
For this IRP, the SENDOUTQl model assumes the natual gas is purchased as a fi, physical, fixed-
price contract regardless of when the contract is executed and what type of contract it is. However,
in reality, we pursue a variety of contractual term and conditions in order to capture the most value
from each transaction.
AVISTA'S PROCUREMENT PLAN
We cannot accurately predict future natural gas prices but market conditions and experience help
shape our overall approach. A vista has designed a natural gas procurement plan process that seeks to
competitively acquire natural gas supplies while reducing exposure to short-term price volatility.
Our procurement strategy includes hedging, storage utilization and index purchases. Although the
specific provisions of the procurement plan wil change as a result of ongoing analysis and
experience, the following principles guide Avista's development of its procurement plan:
A vista employs a time, location and counterpart diversified hedging strategy - It is
appropriate to hedge over a period of time, and we establish hedge periods within which
portions of future demand are financially hedged. The hedges may not be completed at the
lowest possible price, but they wil protect our customers from price volatility. Additionally,
we pursue diversified purchases at multiple basinmarket hubs and transact with a range of
counterparties.
A vista establishes a disciplined but flexible hedging approach - In addition to establishing
hedge periods within which hedges are to be completed, we also set upper and lower pricing
points. In a rising maket, this reduces Avista's exposure to extreme price spikes. In a
declining market, this encourages captuing the benefit associated with lower prices.
5.4 Avista
2009 Natural Gas IRP Chapter 5 - Supply-Side Resources
A vista regularly reviews its procurement plan in light of changing market conditions and
opportunities - Avista's plan is open to change in response to ongoing review ofthe
assumptions that led to the procurement plan. Although we establish various targets in the
initial plan design, policies provide flexibility to exercise judgment to revise/adjust targets in
response to changing conditions.
A number of tools are utilized to help mitigate fiancial risks. Avista purchases gas in the spot
market as well as the forward market. Spot purchases are made on a day for the next day or
weekend. Forward purchases are made on a day for a designated futue delivery period. Many of
these tools are financial instruments or derivatives that can be utilized to provide fixed prices or
dampen price volatility. We continue to evaluate how to manage daily demand volatility, whether
through option tools available from counterparties or through access to additional storage capacity
and/or transportation.
TRANSPORTATION RESOURCES
Although proximity to the liquid hubs is important from a cost perspective, those supplie,s are only
as reliable or fim as the pipeline transportation from the hubs to Avista's service territories.
Capturing favorable price differentials and mitigating price and operational risk can also be realized
by holding multiple pipeline transport options. Consequently, we have contracted for a suffcient
amount of diversified firm pipeline capacity from various receipt and delivery points (including out
of storage facilities) so that fim deliveries wil meet peak day demand. We believe the combination
offirm transportation rights to our service territory, storage facilities and access to liquid supply
basins wil ensure peak supplies are available to our core customers.
The major pipelines servicing our region are as follows:
Williams - Northwest Pipeline (NWP) - A natural gas transmission pipeline serving the Pacific
Northwest moving natural gas from the US/Canadian border in Washington and from the
Rocky Mtn. region ofthe US.
TransCanada Gas Transmission Northwest (GTN) - A natural gas transmission pipeline
originating atKingsgate, ID (CanadianlS border) and terminating at the California/Oregon
border close to Malin, OR.
TransCanada Alberta System - A natural gas gathering and transmission pipeline in Alberta
Canada that delivers natural gas into the TransCanada Foothils pipeline at the
Alberta/British Columbia border.
TransCanada BC System - A natural gas transmission pipeline that delivers natural gas
between the Alberta, BC border and the Canadian/US border at Kigsgate, ID.
TransCanada Tuscarora Gas Transmission - A natural gas transmission pipeline originating
at Malin, OR and terminating at Wadsworth, NY.
Spectra Energy - BC Pipeline - A natural gas tranmission pipeline originating at Fort Nelson,
BC and terminating at the CanadianlS border at Huntington, BC/Sumas, W A.
Avista 5.5
Chapter 5 - Supply-Side Resources 2009 Natural Gas IRP
A vista has contracts with each ofthe above pipelines for fir transportation to serve our core
customers. Table 5.1 details the fIrm transportation/resource services contracted by A vista. These
contracts are of different vintages, thus different expiration dates; however, all have the right to be
renewed by Avista. This gives Avista and its customers the knowledge that Avista wil have
available capacity to meet existing core demand now and in the futue.
Table 5.1 . Existing Firm Transportation & Storage Resources
DthIay
Avista Avista
North South
Firm Transportation Winter Summer Winter Summer
NWPTF-1 119,526 119,526 22,562 22,562
GTN T-1 100,605 75,782 42,260 20,640
NWPTF-2 91,200 2,623
Total 311,331 195,308 67,445 43,202
Firm Storage Resources. Deliverabilty
Jackson Prairie 266,667 2,623
MIST 15,000
Total 266667 17623
A vista defines two categories of interstate pipeline capacity. "Direct-connect" pipelines deliver
supplies directly to our local distribution system from production areas, storage facilities or
interconnections with other pipelines. "Upstream" pipelines deliver natual gas to the direct-connect
pipelines from remote production areas, market centers and out of area storage facilities. Figure 5.2
illustrates the direct-connect pipeline network relative to our supply sources and service terrtories 1.
I Avista has a small amount of pipeline capacity with TransCanada Tuscarora Gas Transmission, a natul gas transmission pipeline
originating at Malin, Oregon, to serice a small number of Oregon customers near the southern border of the state.
5.6 Avista
2009 Natural Gas IRP Chapter 5 - Supply-Side Resources
Figure 5.2 Direct-Connect Pipelines
Supply-side resource decisions focus on where to purchase natural gas and how to deliver it to
customers. Each LDC has distinctive service territories and geography relative to supply sources
and pipeline infrastructure. Solutions that deliver supply to service territories among regional LDCs
are similar but are rarely generic-instead they are almost always unique.
The NWP system for the most part is a fully contracted system. With the exception of La Grande,
our service terrtories lie at the end of various NW pipeline laterals. Washington/daho is served via
the Spokane and Lewiston laterals while Roseburg and Medford are served by the Grants Pass
lateraL. Capacity expansions on each of these laterals are lengthy and costly endeavors which Avista
would likely bear most ofthe incremental costs.
The GTN system, on the other hand, currently has ample unsubscribed capacity. This pipeline rus
directly through or lies in close proximity to most of our service territories. Mileage based rates and
backhaul potential provide attractive options for securing incremental resource needs.
Peak day planning aside, both pipelines provide an array of options to flexibly manage daily
operations. Our two largest service territories are directly served by both pipelines providing
diversification and risk management with respect to supply source, price and reliability. The NWP
system (a bi-directional, fixed reservation fee-based pipeline) provides direct access to historically
cheaper Rockies supply and facilitates excellent storage facility management. The Stanfield
interconnect of the two lines is also geographically well situated to our service territories.
The rates we use in our planning model start with filed rates that are currently in effect (See
Appendix 5.1). Forecasting futue pipeline rates is challenging. Our assumptions for future rate
changes are the result of market information on comparable pipeline projects, prior rate case
experience and informal discussions. It is generally assumed that the pipelines wil fie to recover
Avista 5.7
Chapter 5 - Supply-Side Resources 2009 Natural Gas IRP
costs at rates equal to the GDP with adjustments made for specific project conditions. Refiement of
theses assumptions will be done as better information becomes available.
NW and GTN also offer interrptible tranportation service to Avista. The level of service of
interrptible transportation is subject to curailment when pipeline capacity constraints limit the
amount of natural gas that may be moved. Although the commodity cost per dekatherm transported
is the same as firm transportation, there are no demand or reservation charges in these transportation
contracts. As the marketplace for release oftransportation capacity by the pipeline companies and
other third parties has become more prevalent, the use of interrptible transportation services has
diminished. We do not rely on interrptible capacity to meet peak day core demand requirements.
A vista's transportation acquisition strategy is to contract for fim transportation to serve core
customers should a peak day occur in the near-term planning horizon. Too much fir transportation
could keep us from achieving our goal of being a low-cost energy provider. But too little firm
transportation impairs our reliability goal. Determining the appropriate level of fi transportation is
a complex evaluation of many factors, including the projected number of firm customers and their
expected annual and peak day demand, opportities for future pipeline or storage expansions and
relative costs between pipelines and their upstream supplies. It is important to maintain an
appropriate time cushion to allow for required lead times for securig new capacity. Also, the ability
to release capacity can offset some or all ofthe cost of holding underutilized capacity.
STORAGE RESOURCES
Storage is a valuable strategic resource that enables improved management of a highly seasonal and
varied demand profile. Storage benefits include:
. Flexibility to serve peak period needs;
. Access to typically lower cost off-peak supplies;
. Reduced need for higher cost anual fir tranportation;
· Improved utilization of existing fir transportation via off-season storage injections; and
. Additional supply point diversity.
Avista's existing storage resources consist of ownership and leasehold rights in two in-ground
regional storage facilities.
JACKSON PRAIRIE STORAGE
Avista is one-third owner, with NWP and Puget Sound Energy (PSE), in the Jackson Prairie storage
project for the benefit of its core customers in all three states. Jackson Prairie Storage is an
underground reservoir facility located near Chehalis, Washington approximately 30 miles south of
Olympia, Washington. The total working gas capacity of the facility is approximately 25 Bcf.
Avista's curent share of this capacity for core customers is approximately 5.2 Bcfand includes
266,667 Dth of daily deliverability rights.
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2009 Natural Gas IRP Chapter 5 - Supply-Side Resources
In 1999, and again in 2002, Avista participated in capacity expansions of the project with NW and
PSE. It was determined that the additional capacity for core utility customers was not needed at that
time, and the expansion went under the management of Avista Energy, Avista's former non-
regulated energy marketing and trading affliate. In June 2007, Avista Energy sold substantially all
of its energy contracts and ongoing operations to Shell Energy North America (U. S.), L.P. (Shell
Energy). Concurrent with the sales transaction, A vista reacquired the rights to the 2002 expansion
while the 1999 expansion rights were temporarily included in the sale. Shell Energy retains these
rights through April 30, 20 I I. These rights represent approximately 3 Bcf of storage capacity and
100,000 Dth of daily de1iverability.
After this date, we anticipate recalling these storage rights for availability in our utility operations,
and have included it in our SENDOUTiI model as an incremental available storage resource at that
time.
We continue to evaluate our Jackson Prairie capacity and deliverability requirements to determine if
we should opportnistically optimize storage capacity beyond what is able to be delivered to
customers.
Outside of Avista's ownership rights, we have leased an additional 95,565 Dth of Jackson Prairie
capacity with 2,623 Dth of deliverability from NWP to serve Oregon customers.
MIST STORAGE
The Mist storage project is an underground depleted reserve storage project owned by Northwest
Natural Gas and is located near the small community of Mist, Oregon about 60 miles northwest of
Portland, Oregon. The total working gas capacity of the facility is approximately 16 Bc£ For our
Oregon customers, A vista has contracted for service in this storage project which includes rights to
500,000 Dth of capacity with 15,000 Dth of deliverability. This contract expires in April 2011.
INCREMENTAL SUPPLY-SIDE RESOURCE OPTIONS
Our existing portfolio of supply-side resources provides a good mix of assets to manage demand
requirements for peak day events and throughout each year in the near term. But in anticipation of
growing and changing demand requirements, we monitor the following potential resource options to
meet future requirements.
SYSTEM ENHANCEMENTS
In certain instances, A vista can facilitate additional peak and base load-serving capabilities through a
modification or upgrade of our distribution facilities. These opportunities are geographically specific
and require case-by-case study. We have reviewed several enhancements and preliminary fidings
indicate that the following opportunities may be viable:
NWP Klamath Falls Lateral- A vista has the opportty to purchase and operate the NW
Klamath Falls lateral as a high-pressure distribution system. Although we would incur the
Avista 5.9
Chapter 5 - Supply-Side Resources 2009 Natural Gas IRP
capital costs associated with the purchase price, we would be able to terminate curent NW
reservation and fuel charges at Klamath Falls and relocate the transportation contract
deliverability on NWP to areas where additional deliverability is needed. This solution would
facilitate additional deliveries into the Klamath Falls area off ofGTN. If certain terms are
met, this enhancement can likely be completed with less than one year's notice.
Medford System Enhancement - Avista is constructing a high-pressure distribution system
reinforcement off of the GTN Medford lateral. This wil facilitate delivery of incremental
volumes off ofthe GTN system into Medford when needed. This solution also wil allow
existing NWP supply and capacity on the Grants Pass Lateral to be diverted from Medford
back to the Roseburg area. Through this enhancement, potential resource shortages in the
Medford and Roseburg areas can be addressed.
La Grande Distribution System Enhancement- Avista has the option to enhance the
distribution system in the La Grande area with high-pressure distrbution looping from an
adjacent city-gate station such that the distribution system would be reinforced. This solution
would allow additional deliveries off of the NW system to La Grande.
CAPACITY RELEASE RECALL
As discussed earlier, pipeline transportation that is not utilized to serve core customer demand can be
released to other parties or optimized through daily or term transactions. Released capacity is
generally marketed through a competitive bidding process and can be done on a short-term (month-
to-month) or long-term basis. We actively participate in the capacity release market and have both
short-term and long-term capacity releases.
We assess the need to recall capacity or extend a release of capacity on an on-going basis. The IRP
process also helps evaluate if or when we need to recall some or all of our long-term releases.
GTN BACKHAULS
On the GTN system, due to the north-to-south flow dynamics and the large amount of natural gas
flowing that direction, backhauling supply purchases to Avista's service territory can be done on a
relatively reliable basis. For example, A vista can purchase cost effective supplies at Malin, Oregon
and transport those supplies via displacement to our service territory at either Klamath Falls or
Medford. Malin-based natual gas supplies typically price at a premium to AECO supplies but are
generally less expensive than the cost of forward-haul transporting those traditional supplies and
paying the associated demand charges. The GTN system is a mileage-based system so we pay only a
fraction of the forward rate ifit is transporting supplies from Malin to Medford and Klamath Falls.
The GTN system is approximately 612 miles long and the distance from Malin to the Medford
lateral is only about 12 miles. Avista can decrease costs by avoiding fuel charges and full reservation
charges on an annual or seasonal basis and/or by avoiding potentially expensive peaking resources.
Although we are confident in this resource option especially in the near to intermediate term, it is
only available as long as sufficient forward-haul natual gas flow exists. Pipeline capacity at Malin is
over two Bcfwith several high volume subscribers currently flowing substantial daily volumes into
5.10 Avista
2009 Natural Gas IRP Chapter 5 - Supply-Side Resources
California. However, in the future this condition could change if declines in forward-haul volume
occur or requests for backhauls increase, causing net forward-haul volume to be insuffcient to honor
all backhaul requests. Specifically, the proposed Ruby pipeline project (see new pipeline projects
section below) which would interconnect with the GTN system at Malin could decrease forward-
haul volumes if GTN subscribers source significant volumes from the new Ruby pipeline. We
continue to monitor this possibility in conjunction with the Ruby project development.
NEW PIPELINE TRANSPORTATION
Additional firm pipeline transportation resources are viable and attractive resource options.
However, determing the appropriate level, supply source and associated pipeline path, costs and
timing and determining whether or not existing resources wil be available at the appropriate time,
make this resource diffcult to analyze. Firm pipeline capacity provides several advantages; it
provides the ability to receive firm supplies at the production basin, it provides for base-load demand
and it can be a low-cost option given optimization and capacity release opportnities. Pipeline
capacity also has several drawbacks, including typically long-dated contract requirements, limited
need in the summer months (many pipelines require annual contracts) and limited availability and/or
inconvenient sizing/timing relative to resource need.
Some pipelines currently have available pipeline capacity on the mainline portion of their systems.
Unfortately, NWP does not have any available capacity on its mainline or on any ofthe relevant
laterals that serve Avista's requirements. GTN has mainline capacity currently available and may be
able to provide additional service to some Washington/Idaho and Oregon customers without an
expansion. Further, longer-term permanent capacity release options may be available on both
pipelines.
Pipeline expansions are typically more expensive than existing pipeline capacity and often require
long-term annual contracts. Even though expansions may be more expensive than existing capacity,
this approach may stil provide the best option to us given that some of the other options discussed in
this section require matching pipeline transportation anyway.
Several specific projects have been proposed for the region. The following summaries describe these
projects while Figue 5.3 ilustrates their location:
Avista 5.11
Chapter 5 - Supply-Side Resources 2009 Natural Gas IRP
Figure 5.3 Proposed New Pipelines
-.."
-.
" l' ~ !I :j l .
't.""., ...','t
Ruby - Project sponsor El Paso Corporation. The project is expected to include approximately
675 miles of 42-inch natural gas transmission pipeline begining at the Opal Hub in
Wyoming and terminating at interconnects near Malin, Oregon. The project wil have an
initial capacity of up to 1.5 billon cubic feet per day (Bcfìd) and would traverse portions of
four states: Wyoming, Utah, Nevada, and Oregon.
Blue Bridge Pipeline - Northwest Pipeline GP and Puget Sound Energy are jointly proposing
this project, which would include the installation of additional compression horsepower at
existing Northwest Pipeline stations and the construction of up to 120 miles of pipe. The
project is bi-directional and is designed to deliver between 250 and 500 MMcfìd from
Stanfield, Oregon to the 1-5 Corrdor. The project would generally follow Northwest
Pipeline's existing pipeline corridor for the majority of the route.
Inland Pacific Connector - Terasen Gas is proposing to build this 153-mile, 24-inch diameter
pipeline as an extension of its Southern Crossing Pipeline from southern Alberta near
Kigsgate, Idaho, to Huntingdon, BC, near Sumas, Washington. The initial design capacity is
projected to be about 350 MMcfìd.
Palomar Cascade - Palomar Gas Transmission is a partnership between NW Natual and
TransCanada. The proposed 1 lO-mile, 36-inch-diameter pipeline would extend from
TransCanada's GTN system near Madras, Oregon, to NW Natual's system near Molalla,
Oregon. It would be a bi-directional pipeline with an initial capacity of up to 1,000 MMcfìd.
Sunstone - Project partners include Wiliams Gas Pipeline Company, LLC, TransCanada
PipeLine USA Ltd. and Sempra Gas Pipelines and Storage Corp. The proposed 598-mile
pipeline would transport gas from the Rockies to markets in the West and Pacific Northwest.
The pipeline would generally follow existing pipeline and utility corridors from the Opal
Hub in Wyoming through southern Idaho, connecting with TransCanada's GTN system and
5.12 Avista
2009 Natural Gas IRP Chapter 5 - Supply-Side Resources
Wiliams' Northwest Pipeline near Stanfield, Oregon. The developers have suspended
activity on this project due to unfavorable curent market conditions.
None of the above projects provide end delivery to any of our service terrtories. Therefore, to be a
viable peak day incremental resource requires combining with additional pipeline resources. In our
modeling, we utilized available cost and other information to develop more generic pipeline resource
alternatives rather than specifically modeling the various segments.
To accurately assess costs and location feasibility of potential expansion scenarios requires detailed
engineering studies by the pipelines. These studies can be expensive and of limited shelf life for
projects that might be developed well into the future. Consequently, we employ estimates derived
from our knowledge of historical costs, reasonable price escalations, and site specific issues that may
impact a specific scenario. We combine this knowledge with past information from the pipelines to
develop a reasonable basis for our transportation analysis. If and when we determine that additional
transportation capacity is necessary, we wil request thorough estimates from the appropriate
pipeline companies, search the release market for capacity that may include winter-only service, and
seek capacity on constrained segments. These pipeline estimates are costly and wil be prudently
acquired.
IN-GROUND STORAGE
In-ground storage provides many advantages when storage deliveries can be delivered to Avista's
service terrtory city-gates. It can enable deliveries of natural gas to customers during cold weather
events when they need it most. It also facilitates potentially lower cost supply for our customers by
capturing peak/non-peak pricing differentials and potential arbitrage opportities within individual
months. Although additional storage can be a valuable resource, without deliverability to Avista's
service terrtory, this storage cannot be considered an incremental fir peak serving resource.
Jackson Prairie
Jackson Prairie is a potential resource for expansion opportities. The Shell Energy recall discussed
earlier and any future storage expansion capacity does not include transportation and therefore
cannot be considered an incremental peak day resource. However, we wil continue to look for swap
and transportation release opportunties that could fully utilize these additional resource options.
Even without deliverability, we believe it can make financial sense to fully develop/recall Jackson
Prairie capacity to optimize time spreads within the natural gas market and provide net revenue
offsets to customer gas costs.
Other In-Ground Storage
Other regional storage facilities exist and may be cost effective. Additional capacity at Northwest
Natural's Mist facility, capacity at one of the Alberta area storage facilities, Questar's Clay Basin
facility in northeast Utah, and northern California storage are all possibilities. Again, transportation
to and from these facilities to Avista's service terrtories continues to be the largest impediment to
contracting for these options. Northern California storage opportnities may be able to overcome this
hurdle by using backhaul transportation for deliveries to some of the Washington/Idaho and Oregon
Avista 5.13
Chapter 5 - Supply-Side Resources 2009 Natural Gas I RP
customers but fim, reliable delivery on peak days or cold weather events remains an issue. Another
issue is whether sellers of storage capacity wil offer multi-year contracts or contracts with begining
dates durg the timeframes that we may need these incremental resources.
SATELLITE LNG
Satellite LNG is another storage option that could be constructed within A vista's service territories
and is ideal for meeting peak day or cold weather events. Satellite LNG uses natural gas that is
trucked to the facilities in liquid form rather than liquefying on site. Locating the facility in the
service area would avoid interstate pipeline transportation and related charges. Permitting issues
notwithstanding, facilities could be located in optimal locations within the distribution system.
Estimates for this type of resource are somewhat challenging because of sizing and location issues.
For our modeling, we have used estimates from other facilities constructed in the area and believe
these to be reasonable estimates for planning puroses. We wil continue to monitor and refie the
costs of developing satellte LNG while remaining mindful oflead time requirements and
environmental issues.
PLYMOUTH LNG
NWP own and operates an LNG storage facility located at Plymouth, Washington, which provides a
gas liquefaction, storage, and vaporization service under its LS- I and LS-2F tariffs. An example
ratio of injection and withdrawal rates are such that it can take more than 200 days to fill to capacity,
but only 3-5 days to empty. As such, the resource is best suited for needle-peak demands.
Incremental transportation capacity to our service terrtories would have to be obtained in order for it
to be a trly effective peaking resource.
This peaking resource is fully contracted and not available for contracting at this time. Given this
situation, this option is not being modeled in SENDOUTiÊ for this IRP. However, due to the fact that
many ofthe curent capacity holders are on one-year rolling evergreen contracts, it is possible that
this option will again become viable in the future.
COMPANY OWNED LIQUEFACTION LNG
Instead ofleasing LNG capacity from Plymouth, Avista could construct a liquefaction LNG facility
within our service area. Doing so could use excess tranportation during off-peak periods to fill the
facility but avoid tyig up tranportation durg peak weather events. Additional annual pipeline
charges could probably be avoided.
Construction would be dependent on regulatory and environmental approval as well as cost
effectiveness requirements. Preliminary estimates ofthe construction, environmental, right of way,
legal, operating and maintenance, required lead times, and inventory costs indicate company-owned
LNG facilities have significant development risks. We include this resource in our modeling,
recognizing this type of project is highly complex and there are many risk considerations that require
evaluation and monitoring should this resource be selected.
5.14 Avista
2009 Natural Gas IRP Chapter 5 - Supply-Side Resources
IMPORTED LNG
Although burgeoning supply from unconventional gas production in the U.S. is now forecasted to
ease the need for LNG imports to meet domestic demand, there continues to be interest and
discussion nationally regarding LNG regasification terminals (import LNG). Several termals have
been proposed in the U.S., Mexico and Canada with several projects proposed for the Pacific
Northwesr. Not all ofthese terminals wil advance, and it may be possible that none of the Pacific
Northwest projects wil proceed. The siting of import LNG terminals is a difficult endeavor. In order
for a terminal to advance, it wil require economies of scale, the ability to move regasified supplies
to markets, a favorable environmental review and public reception, secure LNG supply, long-term
output/sales agreements and financing. We have participated in several forums on the various
regional projects.
Although the Pacific Northwest may not provide project sponsors with these requirements, the
announcement to construct a pipeline from the proposed Coos Bay LNG facility to Malin, Oregon
remains of interest to Avista. This pipeline may provide gasified LNG to be directly delivered to
Avista's service territory around Roseburg, Medford and Klamath Falls while potentially helping
supply other regions via fuher backhaul or displacement opportnities. We continue to monitor the
progress of this project having participated in their open season and contingently reserving capacity.
We are also monitoring progress of other regional projects noting, however, that they curently do
not provide supply directly to any of our service territories. In particular, we continue to monitor our
regional prices relative to global prices, as these differentials directly affect the securing of
dependable supply which we believe poses a significant challenge for LNG project sponsors.
Some industry experts believe that if additional LNG terals are built and receive incremental
supply, natual gas prices may trend downward or at least become less volatile given the flexibility
and responsiveness of incremental volumes to enter our domestic market. These experts also believe
that it generally does not matter where the LNG terminals are located because the national natual
gas markets are so tightly connected. Even ifthe Pacific Northwest facilities do not proceed, Avista
wil likely benefit from increasing amounts of imported LNG nationally.
For this IRP, we are not making import LNG a resource option available to the modeL. This is
because LNG in the Pacific Northwest is highly speculative, the region is not considered to be a
premium market when compared to other locations in North America, and because it wil take at
least five years before this option would move forward in the Pacific Northwest. Each ofthe price
forecasts we have reviewed make assumptions regarding LNG imports to North America, so LNG
commodity impacts are imbedded in those forecasts. If a termal were to be built regionally, we
believe the approximate supply price would be the nearest market hub price adjusted for delivery
charges to our service terrtories. So to some extent, LNG resources are indirectly captured in our
modeling.
2 The Kitimat LNG project in Kitimat, British Columbia has changed its project scope to become a liquefaction termnal to export
LNG to Asian and other markets.
Avista 5.15
Chapter 5 - Supply-Side Resources 2009 Natural Gas i RP
We wil continue to monitor this option and wil take more forml action if a Pacific Northwest
terminal begins to look promising.
BIOGAS
Biogas typically refers to a gas produced by the biological breakdown of organic matter in the
absence of oxygen. One type ofbiogas is produced by anaerobic digestion or fermentation of
biodegradable materials such as biomass, manure or sewage, municipal waste, green waste and
energy crops. This type ofbiogas comprises primarily methane and carbon dioxide.
Biogas is a renewable fuel so it sometimes attracts renewable energy subsidies in some parts ofthe
world. We are not aware of any current subsidies but future stimulus or energy policies could lead to
some form of financial incentives at a later time.
Biogas projects are inerently individualized, making reasonable and reliable cost estimates diffcult
to obtain. Project sponsorship has many complex issues and the more likely participation in such a
project is as a long-term contracted purchaser. We did not consider biogas as a resource in this
planning cycle but remain receptive to such projects as they are proposed.
SUPPLY SCENARIOS
Forthis IRP we modeled four supply scenarios. Table 5.2 lists the supply scenarios and Appendix
5.2 provides the details on what is included in each of these scenarios. Additional detail about the
results of these supply scenarios modeled is included in Chapters 6 and 7.
maleSup
Existing Resources
Existing + Expected Available
GTN Rate Escalation
GTN Fully Subscribed
Existing Resources - Represents all resources curently owned or contracted by A vista.
Existing + Expected Available - Existing resources plus supply resource options expected to be
available when resource needs are identified. This includes: curently available GTN,
capacity release recalls, NWP expansions, satellite LNG, backhauls combined with increased
lateral compression, liquefaction LNG and Klamath Falls Lateral Purchase.
GTN Rate Escalation - Same resource options as Existing + Expected Available except GTN
subscription rate is doubled.
GTN Fully Subscribed - Same resource options as Existing + Expected Available except GTN
is fully subscribed so there is no incremental GTN capacity available.
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2009 Natural Gas IRP Chapter 5 - Supply-Side Resources
SUPPLY ISSUES
The market for natural gas has undergone dramatic changes over the last several years. Previously,
the commodity market was transitioning from a regionally-based market to a nationally-based, and
perhaps, globally-based market. The economic recession and emerging abundant supply now looks
to interrpt and potentially shift away from that paradigm. Issues likely to playa promient role in
defining the future for natural gas are as follows:
Unconventional Supply - Shale gas and other unconventional sources are changing the industry
in ways not yet fully understood. Although there are several instances of mature and
seasoned wells, most have limited long-term track records. The high natural gas prices pre-
2008 spured technological breakthroughs that have advanced and improved production
methods. Yet as we enter a potentially long-term cycle of lower prices, inovation may be
stifled. Some of the more promising plays are in areas with little or no infrastructure.
Investment in required infrastructure may be stifled as well. Alternatively, lower natural gas
prices may serve as an important catalyst for economic recovery and futue investment.
Climate Change Policies - By design, climate change policy is intended to disrupt the
consumption of fossil fuels. The role of natural gas in this arena is one of inerent
contradiction. In the near term consumption is predicted to increase significantly via gas-
fired power generation replacing coal plants. It is unclear however, whether natual gas has a
long-term role in power generation or wil be marginalized by nuclear, renewables or other
emerging technologies. Economic conditions add fuher uncertainty regarding legislative
enactment and/or delayed implementation.
Supply from Canada - There is an abundance of evidence supporting the assumption that gas
wil continue to be imported from Canada into the United States. However, since much of
our supply comes from the WCSB, the possibility that supply could become significantly
constrained is monitored closely. Oil sands production and royalty structures are two key
factors that wil likely influence this issue. We wil continue to monitor this situation looking
for signals that indicate increased risk of disrupted supply from Canadian exports.
Pipeline rate increases - A sustained economic slow-down could result in excess or
underutilized pipeline capacity in many pars ofthe countr including our region. This excess
capacity may cause capacity holders with expiring contracts to consider relinquishing their
capacity back to the pipelines. Many capacity holders have shown a preference to tum back
transportation contracts where transportation expenses exceed the value of this
transportation. The result ofthis action from a pipeline perspective is to cause affected
pipelines to file rate cases to recover some or all of the lost revenues. Distribution companies
that rely on firm supplies and transportation wil likely 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 this issue.
National pipeline infrastructure - Pipeline capacity out of the supply regions has increased in
volume and delivery points. As a result, natual gas prices in the Pacific Northwest have
become more dependent on demand and prices in regions as far away as the east coast. The
Avista 5.17
Chapter 5 - Supply-Side Resources 2009 Natural Gas IRP
Rockies Express pipeline expansion to the Midwest and Eastern markets is expected to
fuher solidify price correlation with these markets.
The role of LNG in the United States - Projections indicate that, over the long term there wil
stil be a growing gap between North American natual gas production and North American
demand for natual gas. The consensus is that LNG wil supply the gap. Should this occur,
there wil be global price competition for LNG. We have been, and wil continue to be,
involved in discussions about LNG as a potential supply resource.
MARKET-RELATED RISKS AND RISK MANAGEMENT
While risk management can be defined in a variety of ways, the integrated resource plan focuses on
two areas of risk: the financial risk under which the cost to supply customers wil be uneasonably
high or unreasonably volatile, and the physical risk that there may not be enough natural gas
resources (either the transportation capacity or the commodity) to serve core customers.
A vista has a Risk Management Policy that describes the policies and procedures associated with
financial and physical risk management. The Risk Management Policy addresses, among other
things, issues related to management oversight and responsibilities, internal reporting requirements,
documentation and transaction tracking, and credit rik.
There are two internal organizations that assist in the establishment, reporting and review of Avista's
business activities as they relate to management of natual gas business risks:
. The Risk Management Committee consists of several corporate offcers and senior-level
management. The commttee establishes the Risk Management Policy and monitors
compliance. They receive regular reports on natual gas activity and meet regularly to discuss
market conditions, hedging activity and other natural gas-related matters.
· The Strategic Oversight Group exists to coordinate natual gas matters among internal natual
gas-related stakeholders and to serve as a reference/sounding board for strategic decisions,
including hedges, made by the Natual Gas Supply deparment. Members include
representatives from the Accounting, Regulatory, Credit, Power Resources and Risk
Management departments. While the Natual Gas Supply deparment is responsible for
implementing hedge transactions, the Group provides input and advice.
ACTION ITEMS
We wil continue to monitor the supply issues identified in this chapter including shale production
trends, climate change policies, slowing Canadian exports, pipeline constraints in our region,
pipeline expansions moving volumes away from our region, pipeline cost escalations and import
LNG activity.
We wil also monitor new resource lead time requirements relative to when resources are needed to
preserve resource option flexibility.
5.18 Avista
2009 Natural Gas IRP Chapter 5 - Supply-Side Resources
CONCLUSION
Avista is committed to providing reliable supplies of natural gas to its customers. We procure these
supplies with a diversified plan that seeks to competitively acquire natural gas supplies while
reducing exposure to short-term price volatility through a strategy that includes hedging, storage
utilization and index purchases. We have long-term contracts for firm pipeline transportation
capacity from many supply points and also own and lease fim natural gas storage capacity sufficient
to serve customer demand during peak weather events and throughout the year.
Avista 5.19
Chapter 5 - Supply-Side Resources 2009 Natural Gas IRP
5.20 Avista
2009 Natural Gas IRP
CHAPTER 6 - INTEGRATED RESOURCE PORTFOLIO
OVERVIEW
This chapter combines all previously discussed IRP components and the model used to determine
resource deficiencies during the 20-year planning 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 planning criteria used for developing
demand forecasts. A vista currently uses the "coldest day on record" as its weather planning standard
for determning peak day demand. This is consistent with our past IRPs and is more fully described
in Chapter 3 - Demand Forecasts. We utilize historic peak and average weather data for each
demand region for this IRP. We plan to serve our expected peak day in each demand region with
finn resources. Fir resources include natural gas supplies, pipeline transportation and storage
resources. In addition to planning for peak requirements, we also plan for non-peak periods such as
winter, shoulder and summer demand. Our modeling process includes ruing an optimization for
every day ofthe 20-year planning period.
It is assumed that on a peak day all interrptible customers have left the system in order to provide
service to fim customers. A vista does not make firm commitments to serve interrptible customers.
Therefore, our IRP analysis of demand-serving capabilities only focuses on the residential,
commercial and fi industrial classes.
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 primarily for pipeline compressor
station fueL. The percentage of additional supply that must be purchased is governed through FERC
and National Energy Board approved tariffs.
SENDOUTlI PLANNING MODEL
The SENDOUTiI Gas Planning System from Venty is used to perform integrated resource
optimization. The SENDOUTiI model was purchased in April 1992 and has been used in preparing
all IRPs since then. A vista has a long-term maintenance agreement with Ventyx that allows us to
receive software updates and enhancements. These enhancements include software corrections and
improvements brought on by industry change.
SENDOUTiI is a linear programming model widely used to solve natural gas supply and
tranportation optimization questions. Linear programming is a proven technique used to solve
minimiation/maximization problems. SENDOUTiI looks at the complete problem at one time
within the study horion, while taking into account physical limitations and contractual constraints.
The software analyzes thousands of variables and valuates possible solutions to generate a least cost
solution. The model uses the following variables:
Avista 6.1
Chapter 6 - Integrated Resource Portfolio 2009 Natural Gas IRP
. Demand data, such as customer count forecasts and demand coeffcients by customer type
(e.g. residential, commercial and industrial);
. HDD information;
. Existing and potential transportation data which describes to the model the network for the
physical movement ofthe natual gas and associated pipeline costs;
. Existing and potential supply options including supply basins, revenue requirements as the
key cost metric for all asset additions, and prices;
. Natural gas storage options with injection/withdrawal rates, capacities and costs; and
. DSM programs.
Figue 6.1 is a SENDOUTiI network diagram of our demand centers and resources (see also Appendix 6.5).
This diagram ilustrates Avista's curent transporttion and storage assets, flow paths and constraint points.
Figure 6.1 SENDOUTI8 Model Diagram ~
The SENDOUTiI model also provides a flexible tool to analyze potential scenaios such as:
. Pipeline capacity needs and capacity releases;
. Effects of different weather pattern upon demand;
. Effects of natual gas price increases upon total natual gas costs;
. Storage optimization studies;6.2 Avista
2009 Natural Gas IRP Chapter 6 - Integrated Resource Portfolio
. Resource mi analysis for DSM programs;
. Weather pattern testing and analysis;
. Transportation cost analysis;
. Avoided cost calculations; and
. Short-term planning comparisons.
The latest SENDOUTiIversion includes Monte Carlo capabilities, which facilitates price and
demand uncertainty modeling and detailed portfolio optimization techniques to produce probability
distributions. Similar to SENDOUTiI, there are numerous variables entered for Monte Carlo
simulation. The variables required for the Monte Carlo analysis are:
· Expected monthly HDDs by month;
· Standard deviation of monthly HDDs;
. Monthly minimum and maximum HDDs;
. Daily HDD pattern derived from historical data;
. Expected monthly gas price by month;
· Standard deviation of the monthly gas price;
· Monthly minimum and maximum gas price;
· Temperature-to-temperature correlations;
. Price-to-price correlations; and
· Price-to-temperature correlations.
This additional software module enhances Avista's analytical capabilities. More informtion and
analytical results are located in Chapter 7 - Alternate Scenarios, Portfolios and Stochastic Analysis.
RESOURCE INTEGRATION
We have defined the planning methodologies, described the modeling tools and identified the
existing and potential resources. The following summarizes the comprehensive analysis of bringing
demand forecasting and existing and potential supply and demand-side resources together to form
our 20-year, risk adjusted least-cost plan.
DEMAND FORECASTING
Avista's demand forecasting approach is described in detail in the Demand Forecasts chapter.
We forecast demand in the SENDOUTiI model in eight service areas given the existence of distinct
weather and demand patterns for each area and pipeline infrastructure dynamics. The SENDOUTiI
areas are Washington/Idaho (dis aggregated into three sub-areas because of pipeline flow
limitations), Medford (dis aggregated into two sub-areas because ofpipeline flow limitations) and
Avista 6.3
Chapter 6 -Integrated Resource Portolio 2009 Natural Gas I RP
Roseburg, Klamath Falls and La Grande. In addition to area distinction, we also model demand by
customer class within each area. The relevant customer classes in A vista's service terrtories are
residential, commercial and firm industrial customers.
Customer demand reflects a highly weather-sensitive component. Avista's customer demand is not
only highly seasonable but also highly variable. Figue 6.2 captues this variability showing our
monthly system-wide average demand, miimum demand day observed in each month, and
maximum demand day observed in each month, and our winter projected peak day demand for the
first year of our Expected Case forecast as determned in SENDOUTiE.
Figure 6.2 Total System Average Daily Demand
(Average, Minim.m, Maxim.m, and Peak Day)
400,000
350,000
300,000
150,000
250,000
:E.: 200,000c
100,000
50,000
o
Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oc
.. Average -- Minim.m .. Maxim.m x Peak Day
NATURAL GAS PRICE FORECASTS
Natural gas prices are a fundamental component ofthe IRP. The commodity price is a significant
component ofthe total cost of a resource option. This in turn affects the avoided cost threshold for
determining cost-effectiveness of conservation measures. We also recognize the price of natual gas
influences consumption, so we include price elasticity analysis in our demand evaluation (see
Chapter 3 - Demand Forecasts).
The natural gas price outlook has changed dramatically over the recent planning cycle in response to
several influential events and trends affecting the industr. Most notably is the severe economic
recession trigged by the global credit crisis, but two other significant influencers are the surge in
shale gas production expectations and potential climate change legislation encouraging natural gas-
fired power generation to replace coal burning power plants. The outlook for these factors has
evolved rapidly in the midst of an environment of significant uncertainty precipitating wide swings
and frequent updates to the price forecasts we monitor.
6.4 Avista
2009 Natural Gas IRP Chapter 6 - I ntegrated Resource Portfolio
Many additional factors influence natural gas pricing and volatility, such as regional supply/demand
issues, weather conditions, huricanes/storms, storage levels, gas-fired generation, infrastructue
disruptions and infrastructure additions (e.g. new pipelines, LNG terminals).
Even though we continually monitor these factors, we cannot accurately predict future prices for the
20-year horizon ofthis IRP. We have reviewed several price forecasts from credible sources. Figure
6.3 depicts the price forecasts we considered in our analyses.
Figure 6.3 Henry Hub Price Forecasts
2009$/Dlh
16.00
8.00
--~
I..--
"-.=-.y ~'+
~.J - --I
..,..
14.00
12.00
10.00
..isw 6.00
4.00
2.00
0.00
# ~ ~#~ ~~~ ~ ~~~ ~ # ~G#~G ~ ~ ~
__Consult1
-- NPCC Low
-Q Consul12
-- NPCC Medium
--AEO
--NPCCHigh
--NYMEX
-+ Consult - June Updaæ
Some of these forecasts are more plausible than others, but most ofthem are possible. With
assistance and concurrence of the TAC Committee, we selected high, medium and low price cures
to consider possible outcomes and the impact that this volatile and high pricing environment might
have on planning. The price cures we have selected have considerable variation, which is consistent
with our theme of stretching modeling assumptions in an uncertain environment. These curves are
shown in real dollars in Figue 6.4 and nominal dollars in Figue 6.5.
Avista 6.5
Chapter 6 - Integrated Resource Portolio 2009 Natural Gas IRP
Figure 6.4 Henry Hub Price Forecasts for IRP
NYMEX blend Irsfie years'
2009$lDli
16.00 I
14.00 ----12.00 i
10.00 --~....""is 8.00..?--~..
6.00 --~q ---
4.00 I2.00
'NYMEXweighl 50%,40"10,30%,20%,10%
0.00 ,,,,,~ ~. ~ ~ ~ ~ ~ ~ ~ ~ ~ & ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~~ ~ ~ ~ ~~ ~ ~ ~~ ~ ~ ~~ ~ ~ ~ ~~ ~
__Consull1 --NPCCLow --NPCCHigh -- Consull - June Upda1e
Figure 6.5 Hery Hub Price Forecsts for IRP
NYMEX blend Irlve years'
Noral $lDli
22.00 r------
20.00
18.00
16.00
14.00
- ~-.-_.~---!".~~--__ .. I..12.00is..10.00
8.00
6.00
4.00
2.00
0.00
--~---er ~--..~ ~
-~.. --./~
'NYM EX weighE 50% , 40"10 , 30"10 , 20%, 10%, ,. ...
~ ~ ~~~~~ ~~ ~ #~~#~G~~~G~#
__ Consull -- NPCC Low -- NPCC High __ Consull - June Upda1e
Each ofthe price forecasts above are for Henr Hub, which is located in Louisiana just onshore from
the Gulf of Mexico. Henry Hub is widely recognized as the most important pricing point in the U.S.
because of its proximity to a large portion of U.S. natual gas production and the sheer volume
traded in the daily or spot market, as well as the forward markets via the New York Mercantile
Exchange's (NYMEX) futues contracts. Consequently, all other trading points tend to be priced off
of the Henry Hub.
The primary physical supply points at Sumas, Washington, AECO Alberta, Canada, and Opal,
Wyoming in the United States Rockies (and other secondary regional market hubs) ultimately
6.6 Avista
2009 Natural Gas I RP Chapter 6 - Integrated Resource Portfolio
determines A vista's costs. Prices at these points typically trade at a discount or negative basis
differential to Henry Hub primarily because of their relative close proximity to the two largest
natural gas basins in North America (the WCSB and the Rockies).
Table 6.1 shows the Pacific Northwest regional prices from our consultant as a percent of Henry
Hub price along with historical comparisons.
AECO Rockies Sumas Malin Stanfield
Consultant1
92.7%85.6%95.2%94.1%93.7%
Forecast Average
Forward Markets
88.8%84.5%97.1%N/A N/A
Five Yr Average
Prior IRP 86.0%80.5%87.6%N/A N/A
This IRP used monthly prices for modeling purposes because of our heavily winter-weighted
demand profile. Table 6.2 depicts the monthly price shape we used in this IRP and comparisons to
the 2007 IRP.
Jan Feb Mar Apr May Jun
Consult1 107%108%103%93%93%94%
Prior IRP 113%113%110%93%92%93%
Jul Aug Sep Oct Nov Dec
Consult1 95%96%96%97%109%110%
Prior IRP 94%94%95%96%101%106%
Appendix 6.l contains detailed monthly price data behind the summary table information discussed
above.
TRANSPORTATION AND STORAGE
Valuing natural gas supplies is a critical first step in resource integration. Equally important is
capturig all costs to deliver the gas to the customer. Daily capacity of our existing tranportation
resources (described in Chapter 5 - Supply-Side Resources) is represented by the fim resource
duration cures depicted in Figures 6.6 and 6.7.
Avista 6.7
Chapter 6 - Integrated Resource Portolio 2009 Natural Gas IRP
Figure 6.6 Existing Firm Transporttion Resources
Norti Division - WAllO
Figure 6.7 Existing Firm Transporttion Resource
Souti Divisn - OR
Current rates for capacity are in Appendix 5.1. Forecasting future pipeline rates can be a challenge,
as we need to estimate the amount and timing of rate changes. Our estimates and timing of future
rate increases are based on knowledge obtained from industry discussions and participation in
various pipeline rate cases. This IRP assumes that pipelines wil file to recover costs at rates equal to
increases in GDP (see Appendix 6.2 - General Assumptions).
DEMAND-SIDE MANAGEMENT
Chapter 4 - Demand-side Resources describes the methodology used to identify all possible
conservation measures (technical potential), ascertain what level of measures can be reasonably
6.8 Avista
2009 Natural Gas IRP Chapter 6 -Integrated Resource Portfolio
attained (achievable potential) and the interactive process deployed in SENDOUTiI that computes
avoided cost thresholds for determining cost effectiveness of conservation measures on an equivalent
basis with supply-side resources.
This process results in conservation measures data that facilitates construction of natual gas DSM
supply curves. These curves represent the cumulative therms ofthe evaluated measures stacked in
ascending order of levelized TRC. Supply curves for our Expected Case are presented for the two
divisions (Figues 6.8 and 6.9).
Figure 6.8 North Division DSM Supply Curve, 1st Year (2010)
SENDOUT(ß seleæd rrsures only
4
3.5.
¡3GO.c~2.5i;0..2(,IIi-..1.5.~ãi
ã;..
0.5
--
,.
J
i.Jr
-F i.-o
o 500 1,000 1,500 2,000 2,500 3,000 3,500
thousand therm
. Maximum cot is $11.89; chart scae ii at $4
Figure 6.9 South Division DSM Supply Curve, 1st Year (2010)
SENDOUT(ß seleæd rrsures only
4
3.5.
¡3GO.c~e 2.5i;0..(,2IIi-..1.5.~ãi
ã;..
0.5
.-
r'
J
1".
.-o
o 50 100 150 200 250 300 350
thousand therm
. Maximum cot is $9.36; char scle trncle 81$4
Avista 6.9
Chapter 6 -Integrated Resource Portolio 2009 Natural Gas IRP
PRELIMINARY RESULTS
After incorporating the above data into the SENDOUTQ! modei we then generate an assessment of
demand compared to existing resources for several scenarios. The demand results from these cases
are discussed in Chapter 3 - Demand Forecasts, with additional details supported in the Appendices
3.1 through 3.9.
Figures 6.1 0 through 6.13 graphically represent summaries of Expected Case peak day demand
compared to existing resources, as well as demand comparisons to our prior IRP. This demand is net
ofDSM savings. This comparison shows by service territory the amount and timing of deficits over
the planning horizon.
Figure 6.10 WAllO Existing Resource vs. Peak Day Demand
Expeæd Case (Net ofDSM Savings) Noverir b Ocber
400,000
150,000
350,000
300,000
250,000
S 200,000
100,000
50,000
o~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ # ~ß$G$G~#K~N~¥¥¥~KK ~ ~ ~ ~y ~y ~y ~y ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~~
_ Existing GTN _ Existing TF-1 .he, I Exising TF-2 _ Spokane Supply __ Peak Day Demand __ Prior IRP Peak Day Deman
Figure 6.11 Medford/Roseburg Existing Resourc vs. Peak Day Demand
Expeæd Case (NetofDSM Savings) NovelTer b Ocber
120,000
100,000
80,000
..60,000is
40,000
20,000
Prio Short....,
op~ ~~~~ ~~~~~~#~d###~~~vK ~N ~ ¥ ~¥ ~ K K ~ ~ ~~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~v~~~~~~
_ Existing GTN _ Existing TF-1 ."+1 Existing TF-2 -- Peak Day Demand __ Prior IRP Peak Day Demand
6.10 Avista
2009 Natural Gas IRP Chapter 6 -Integrated Resource Portfolio
22,000
20,000
18,000
16,000
14,000
.i 12,000
ì5 10,000
8,000
6,00
4,000
2,000
o
Figure 6.12 Klamath Falls Existing Resources VS. Peak Day Demand
Expeæd Case (netofDSM Savings) Noverrer 10 Ocber
~~~~~~~~~~~$Ø~d#~~#~#K~K¥¥¥¥~KK ~ ~ ~ ~ ~ ~ ~~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~~
_ExistngGTN _ Existing TF-1 -- Peak Day Demand -- Prior IRP Peak Day Demand
14,000
12,000
10,000
8,000.i
ì5
6,000
4,000
2,000
0
Figure 6.13 La Grande Existing Resources VS. Peak Day Demand
Expecld Case (Net of DSM Savings) Noverrer 10 Ocber
Prior Short
~~~~~~~~~~~$Ø~d##~#~~~~~~~~~~~~~~~~~~~~~~~~~~#~~~~~~~~~~~~~~
_ExistngTF-1 -- Peak Day Demand -- Prior IRP Peak Day Demand
These charts show that resource shortages occur well into the future. In the Expected Case for
Washington and Idaho, the system fist becomes unserved in 2023. In Oregon, the fist unserved
year is in MedfordIoseburg in 2018 followed by Klamath Falls in 2021. The La Grande service
territory does not go unserved at any time during the 20-year planning horizon. This surplus resource
situation provides ample time to carefully monitor, plan and act on potential resource additions.
However, an important risk with respect to identified capacity shortages is the slope of forecasted
demand growth which is almost flat. This outlook implies existing resources wil be sufficient for
quite some time to meet demand. However, if demand growth accelerates, increased demand could
Avista 6.11
Chapter 6 - Integrated Resource Portolio 2009 Natural Gas I RP
accelerate resource shortages by several years. This "flat demand risk" necessitates close monitoring
of signs of accelerating demand and careful evaluation of lead times to acquire preferred incremental
resources.
Table 6.3 quantifies the forecasted total demand (net ofDSM savings) and unserved demand from
the above charts, identifying the amount of deficiencies by region and growth in deficiencies over
time. The next step is to determine the best risk/least cost resources to satisfy these deficiencies.
Table 6.3 Peak Day Demand - Served and Unserved (MOth/d)
Before Resource Additions & Net of DSM Savings
201._
2017-201820130~~.'
Expected 2019-2020
i:~~ 202Ct'
Expected 2021-2022~~.20.~3
Expected 2023-2024Ei 20220
Expected 2025-2026Exiieff . 2lal19
Expected 2027-2028Ei Pi Ii .
La Grande La Grande
Served Unserved
7.98
La Grande WAllO WAllO
Unserved
8.43a6l'
8.58
iuis
8.74
8.82
8.90
8:98 .
9.06
8.29
8.38
8.43'":1 c'ãSf
8.588..
8.74
8.82
8.90
8.98
Klamath
Falls
Unserved
Medford!
Roseburg
Medford!
Roseburg
Medford!
Roseburg
Unserved
Klamath
NEW RESOURCE OPTIONS
The following considerations are important in determining the appropriateness of potential
resources:
RESOURCE COST
Resource cost is the primary consideration when evaluating resource options although other factors
mentioned below also influence resource decisions. We have found that newly constructed resources
6.12 Avista
2009 Natural Gas IRP Chapter 6 -Integrated Resource Portfolio
are typically more expensive than existing resources, but existing resources are in shorter supply.
Newly constructed resources provided by a third party, such as a pipeline, may require a significant
contractual commitment. Newly constructed resources are often less expensive per unit if a larger
facility is constrcted, because of economies of scale.
LEAD TIME REQUIREMENTS
New resource options can take from one to five or more years to put in service. Open season
processes, planning and permitting, environmental review, design, construction and testing are some
of the aspects contributing to lead time requirements for new physical facilities. Recalls of
transportation release capacity typically require advance notice of up to a year. Even DSM programs
require significant time from program development and rollout to the point when natural gas savings
are realized.
PEAK VERSUS BASE LOAD
Our planning efforts include the ability to serve a peak day as well as all other demand periods.
Avista's core loads are considerably higher in the winter than the summer. Due to the winter-peaking
nature of Avista's demand, resources that cost-effectively serve the winter without an associated
summer commitment may be preferable. Alternatively, it is possible that the costs of a winter-only
resource may exceed the cost of annual resources after capacity release or optimization opportunities
are considered.
RESOURCE USEFULNESS
It is paramount that an available resource effectively delivers natural gas to the intended
geographical region. Given Avista's unique service terrtories, it is often impossible to deliver
resources from a resource option such as storage without acquiring additional pipeline
transportation.
"LUMPINESS" OF RESOURCE OPTIONS
Newly constructed resource options are often "lumpy." This means that new resources may only be
available in larger than needed quantities and only available every few years. This lumpiness of
resources is driven by the cost dynamics of new construction, the fact that lower unit costs are
available with larger expansions, and the economics of expansion of existing pipelines or the
construction of new resources dictate additions infrequently. Lumpiness provides a cushion for
future growth. Given the economies of scale for pipeline construction, we are afforded the
opportunty to secure resources to serve future demand increases.
RISKS AND UNCERTAINTIES
Investigation, identification and assessment of risks and uncertainties are critical considerations
when evaluating supply resource options. For example, resource costs determinations are subject to
various degrees of estimation, parly influenced by the expected time frame ofthe resource need and
degree of rigor determining estimates or estimation difficulties because of the uniqueness of a
Avista 6.13
Chapter 6 -Integrated Resource Portolio 2009 Natural Gas IRP
resource. Lead times can have varying degrees of certainty ranging from securing curently available
transport (high certainty) to contracting for imported LNG (low certainty).
RESOURCE SELECTION
After identifying supply-side resource options and evaluating them based on the above
considerations, we entered these supply-side scenarios (see Table 5.2) along with conservation
measures (demand-side resources) into the SENDOUTQl model for it to select the least cost approach
to meeting resource deficiencies. This process is described in Chapter 4 - Demand-side Resources in
the Methodology section. SENDOUTQl compares demand-side and supply-side resources using
PVRR analysis to determine which resource is the best risk adjusted/least cost resource. Appendix
4.3 lists the demand-side measures and Appendix 6.3 lists the supply-side resource options.
DEMAND-SIDE RESOURCES
Avoided Cost
The SENDOUTQl model determined avoided cost figues represent the unit cost to serve the next unit
of demand with a supply-side resource option during a given period. If a conservation measure's
total resource cost is less than this avoided cost, it wil cost effectively reduce customer demand and
A vista can "avoid" possible commodity, storage, transportation and other supply resource costs.
Measures that reduce heat-related demand are evaluated againt a winter avoided cost while
measures that reduce non-heat (base load) demand are evaluated againt an annual avoided cost.
SENDOUTQl calculates marginal cost data by day, month and year for each demand area. A
summarized graphical depiction of avoided winter and annual costs for the Washington/Idaho and
Oregon areas is in Figure 6.14 and 6.15. The detailed data is presented in Appendix 6.4. The avoided
costs do not include environmental externality adders to monetarily recognize adverse environmental
impacts. Appendix 4.4 discusses this concept more fully and includes specific requirements required
in our Oregon service territory.
6.14 Avista
2009 Natural Gas IRP Chapter 6 - Integrated Resource Portfolio
Figure 6.14 Washington and Idaho Avoided Costs
Indudes Cormdil & Trans. Costldudes Env. Ext Adder - Novermer b Ocber
2009$/Oli
14.00
12.00
10.00 ~/8.00..7ë..
6.00 "'..
4.00
2.00
0.00
--
~ ~~~~~~~~~gßU~g$g~~g~ ~ ~v ~v ~v ~v ~v ~v XV ~v ~v ~v ~v ~v ~v ~v ~v ~v ~v ~v~~~~~~~~~#~~~~~~~~~~
-+ WAllO Wn1er -- WAllO Annual
Figure 6.15 Oregon Avoided Costs
Indudes Cormdil & Trans. Cost/Excldes Env. Ext Adder - Noverrr b Ocber
2009$1011
14.00
12.00
..-- .~ ::
6.00
..~/'/
--
10.00
.. 8.00
ë..~..-.
4.00
2.00
0.00 ,, .-~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ $ ø~g$g~~g##~N~¥¥¥~K~#~ ~v ~v ~v ~v ~v ~v ~v~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~
-+ OR Wn1er -- OR Annual
Following a small decline in 2013-2014, avoided costs increase rapidly over the next five years
when carbon cost adders from anticipated cap-and-trade legislation is phased in.
Selected Measures
Using the above avoided cost thresholds, SENDOUT(R selected all cost-effective measures and any
mandatory measures. Table 6.4 details anticipated DSM savings in each region from the selected
conservation measures for our Expected Case.
Avista 6.15
Chapter 6 - Integrated Resource Portolio 2009 Natural Gas IRP
Table 6.4 Annual, Annual Average and Peak Day Demand Served by DSMDaily Annual DailyLa Grande Medford/ Medford/DSM DSM
Annual
Oregon DSM
(MDth)
31.879
Daily Peak Day Annual
Oregon DSM Oregon DSM WAIID DSM
(MDth/day) (MDth/day) (MDth)0.087 0.250 301.191d.~~'~¡" ......~.(0.265 0.760 889.351
"~i. O,34.;;j0~\¡ ',1115:41
0.419 1.202 1,460.9130.4951~~jj1 t,t4&70
0.569 1.643 2,018.933.(1.64 1.86 2;lUIIi. 0.716 2.084 2,555.5210.188 2:30 2,81
0.860 2.523 3,099.580;9 2.741 3,t.z
1.003 2.957 3,595.8021.08 3.180 3.84.81
1.104 3.329 4,095.2711.145 .. M9å 4;331.96 .
1.181 . 3.654 4,573.965t~.1~~.81l 4.80tó2
1.252 3.977 4,980.468"'_.f:28at.S?,'.'''~i~;,"
Daily
WAIIDDSM
(MDth/day)
0.825'1.$l
2.430
3.22
4.0034.78
5.5166;2
7.001
7.741
8.469
9.171
9.852
10.63
11.189
11067
12.531
13.15
13.608
14:121
~ Gas Year
Expected 2009-2010/lii ~11ÍAiExpected 2011-2012 96.875:m P1~.':; :&, I ¡.;'Expected 2013-2014 152.967. ~ I !t1!JfF 'lfjiiimrExpected 2015-2016 208.161:&EXct.:~ li' 23.978Expected 2017-2018 261.433~19 287.549'
Expected 2019-2020 314.776" . ., 2020.~_341¡4
EJp~ed 2021-2022 366.203,~_lllr 387.~¡Expected 2023-2024 403.982.. 2ó1.~17~Expected .2025-2026 .431.191.~íd~ ...,lllf'PPExpected 2027-2028 458.202oI'~II!IMt. ::..m!iIF.
:;¡':t
Peak Day
WAIIDDSM
(MDth/day)
3.336~10.008
::~:1;r~
16.680l!m6
23.3512668
30.022
33.35
36.69139.9
43.243
48.519
49.795
53.04
56.295.. ..l!,~62.068!!~"""
Peak DayAnnual Daily Tolal Total
T alai System System DSM System DSM
DSM (MDth) (MDlhlday) (MDth/day)333.070 0.913 3.585;~~;fj~..ljí'~'ol.986.226 2.695 10.7681;3Ol~ :3,56 1.4.~, .1,613.879 4.422 17.8821,92_3l '~.200 "2U~ ,'0
2,227.094 6.085 24.9942,5253;.iiiilf;i." It.2,816.954 7.718 32.1063,112.910 8.~ To; .' .3~l3,414.356 9.329 39.2133,68 1QD'l ( 42.7I
3,962.005 10.855 46.1994,21.62 11.59 49.67
4,499.253 12.293 53.1244;74925 13,012" t;¡0~'
5,005.156 13.713 59.950~~~ 14,37 . 63.36 .'
5,38.669 14.860 66.045~. !o;.í..~411::::&~~~~:.
The list of individual selected measures in the above savings is detailed in Appendix 4.2. Futue
implementation planning efforts wil use these selected measures as a starting point for more detailed
planning efforts but we wil also investigate other measures that may not have been selected by the
SENDOUTQ9 modeL.
DSM Acquisition Goals
The avoided cost established in SENDOUTQ9, the demand-side resources selected and the resulting
calculated therm savings is the basis for determining DSM acquisition goals and subsequent program
implementation planning. The Preliminary Conservation Goal discussion in Chapter 4 - Demand-
side Resources, has additional details on this process.
North Division DSM Goals
Changes in avoided costs, specifically adders taking effect in 2015, have driven the potential
DSM goals identified in this IRP substantially beyond the 2010 goal of 1,755,829 therms
developed in the 2007 IRP. SENDOUTQ9 models escalating avoided costs into the futue which
are generally higher than the current prices actually experienced by our customers. This is parly
due to regulatory lag as well as most customers typically do not explicitly consider higher future
gas prices in their purchasing behavior. So customers are not as incented as the model indicates
6.16 Avista
2009 Natural Gas IRP Chapter 6 - Integrated Resource Portolio
to choose DSM projects in the near term. We compensated for this situation by setting the 20 I 0
DSM acquisition goal at 2,193,338 therms and increasing the DSM goal by 6.5 percent anually.
The 6.5 percent annual growth rate results in the full acquisition of the identified potential over a
10-year planning cycle.
Achievement of a 6.5 percent annual increase in acquisition may result in 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.
South Division DSM Goals
Based on analyses for this IRP, a cost-effective annual acquisition of303,300 first-year thermsis
achievable through utility intervention. The DSM goal originally identified by SENDOUTiI
significantly exceeds our past IRP goals. This coupled with unprecedented state unemployment
and a recessive economy has caused us to constrain the annual ramp-up to 2.2 percent for the
first five years. Overall, the acquisition over the entire 5-year planning cycle wil accomplish
full acquisition.
The identification of this goal does not preclude the addition of other resources that may be
identified as cost-effective during later analysis, nor does it preclude the pursuit of unexpected
resource acquisition opportunities that may occur between IRP cycles.
Other revisions to regulation, infrastructure or DSM operations are likely to be identified in futue
implementation planning efforts. Avista is committed to pursuing a more rapid ramp-up ofDSM
acquisition if it can be achieved without an undue increase in acquisition costs.
SUPPLY-SIDE RESOURCES
SENDOUTiI considered all options entered into the model, determined when and what resources
were needed, and rejected options that were determined to not be cost effective. These selected
resources represent the least cost solution, within given constraints, to serve anticipated customer
requirements. Table 6.5 shows the SENDOUTiI selected supply-side resources for the Expected
Case.
Case I
Table 6.5 Supply Side Resource Selected in SENDOUT\I
Additional Resources Jurisdiction Siz CoslIals Availabllil Noles
Expecte Case
GTN Canacitv WNiD 25,000 Dthld GTNrate 2010 Currentlv available unsubscrbed capacity
GTNCapacity OR 25,000 Dthd GTN rate 2010 Currently available unsubscrbed capacity; requires expansion of
Medrd Lateral
GTN Medford Lateral Expansion OR 25,000 Dthd GTNrate 2011 Additinal compression to allow more gas 10 flow frm GTN mainiine to
the lateral
Klamath Falls Laterai Purchase OR 6,00 Dthd $2.5 millon capital cot November 2010 Agreement with NWPL 10 purchase th Klamath Falls lateral at net
book value. If certin terms are met, can be done with less than one
"eats notice.
Maiin Backaul OR GTNrate 2010 Backhaul capacity is provided by displacement and is available up to
the amount of scheduled forwrdhaul capacity through a specifc point.
In order 10 facilitate additional deliveries 10 our OR propertes an
exnansion of the Medford Laterl is necessarv,
With additional research and investigation, we may later determine that alternative resources are
more cost effective than those resources selected in this IRP. We wil continue to review and refie
Avista 6.17
Chapter 6 -Integrated Resource Portolio 2009 Natural Gas IRP
knowledge of resource options and wil act to secure these best cost/risk options when necessar or
advantageous.
RESOURCE SELECTION RESULTS
Figues 6.16 through 6.18 summarize modeling results when comparing regional peak day demand
against existing and incremental resources for the Expected Case over the 20-year planning period.
400,000
350,000
300,000
250,000
5 200,000
150,000
100,000
50,000
Figure 6.16 WAllO Select Resources vs. Peak Day Demand
Expeæd Case (NetofDSM Savings) Noverrer ti Ocber
o~ ~ ~~ ~ # ~ ~ ~ ~ ~ ~ #~ ø # ~ ~ # ~~ ~ ~ N if # K K ~ K K ~ ~ ~ ~ ~ W ~ ~ ~~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~~
_ Existng GTN _ Existg TF-1 i: Exising TF-2 _ Spokane Supply _ Add'i GTN -- Peak Day Demand
120,000
100,000
80,000
..60,000Õ
40,000
20,000
Figure 6.17 Medord/Roseburg Selectd Resources VS. Peak Day Demand
Expeæd Case (Net ofDSM Savings) Noverier il Ocr
o
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ n~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~v~v~v~v~v~v~v~v~v~v
Pi'V i:'V ",'V ri'V Of'V b('V ':'V fó'V ~~ fó'V af'V Rf'V ",'V n? P;'V b('V ~'V fó'V (\~ Rf'V&~~~~~~~~~~~~~~~~~~~'V 'V 'V 'V 'V 'V 'V 'V 'V 'V 'V 'V 'V 'V 'V 'V 'V 'V 'V 'V
- Exising GTN _ Existing TF-1 ~ Existing TF-2 i: Backaul Med LaVGTN Corrresson-- Peak Day Demand
6.18 Avista
2009 Natural Gas IRP Chapter 6 - Integrated Resource Portfolio
22,000
20,000
18,000
16,000
14,000
.. 12,000
is 10,000
8,00
6,000
4,000
2,000
o
Figure 6.18 Klamath Falls Selectd Resources VS. Peak Day Demand
Expeæd Case (Net ofDSM Savings) Noverier iJ Octber
Current Short
~~~~~~~~~~~&#~d~Ø~~~#K~~¥¥¥K~KK~~~~~~~~~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~~
- Existng GTN _ Existing TF-1 i: KF Lateral Purchase -- Peak Day Demand
As indicated in the figures, after DSM savings, the model shows a general preference for
incremental transportation resources from existing pipelines and supply basins to resolve capacity
deficiencies.
Figures 6.19 and 6.20 show load duration curves and the curent 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 peak day sufficiency and allows the opportunity to compare all demand
days within that year. Although it appears there is excess capacity during non-winter periods, Avista
utilizes this capacity for storage injections and transportation optimization opportities.
..
is 250:i
Figure 6.19 Load Duration Curve & Resource Stack
Expeæd Case (netofDSM) - WAllO
500
450
400
350
300
200
150
100
50
o
29 85 113 141 169 197 225 253 281 309 337 365
Days Available
_S1olneectonPosl2011 i: S10 Injecons 2010 _208-29 _2018-19 _20-10 -CurrResourc
57
Avista 6.19
Chapter 6 -Integrated Resource Portfolio 2009 Natural Gas IRP
Figure 6.20 Load Duration Curve & Resource Stack
Expeæd Case (netofDSM) - OR
200
180
160
Pea Day (M D1)
2010 90
140 2018-19 106
2029 128.i 120ë:i 100
80
60
40
20
0
29 57 85 113 141 169 197 225 253 281 309 337 365
Days Available
- Sbrge Injections Post 2011 c= S1l Injecons 20010 .. 208-29 _ 2018-19 _ 200910 - Currnt Resourc
CONCLUSION
The integrated resource portfolio analysis process summarized in this Chapter was performed on our
Expected Case demand scenario. We have chosen to utilize the Expected Case for our operational
planning activities because this case is the most likely outcome given our experience, industry
knowledge and our understanding of future natual gas markets. This case provides for reasonable
demand growth given curent expectations of natural gas prices over the planning horizon. If
realized, this case is at a level that allows us to be reasonably well protected againt resource
shortages and does not over commit to additional long-term resources.
We fully recognize that there are numerous other potential outcomes. The process described in this
chapter was applied to a host of alternate demand and supply resource scenarios and includes a price
update to our initial Expected Case which is covered in the Chapter 7 - Alternate Scenarios,
Portfolios and Stochastic Analysis.
6.20 Avista
2009 Natural Gas IRP
CHAPTER 7 - ALTERNATE SCENARIOS, PORTFOLIOS AND
STOCHASTIC ANALYSIS
OVERVIEW
The integrated resource portfolio analysis process described in Chapter 6 was applied to several
alternate demand and supply resource scenarios to develop a broad diversity of possible alternate
portfolios. This determiistic modeling approach considered a host of underlying assumptions which
were vetted with significant discussion and recommendations from our T AC to develop a consensus
number of cases to model and analyze.
We also performed stochastic modeling for estimating probability distributions of potential
outcomes by allowing for random variation in natural gas prices and weather based on fluctuations
observed in historical data. This statistical analysis, in conjunction with our deterministic analysis,
enabled us to statistically quantify the risk related to resource portfolios under varying price
environments. We also developed weather probability distributions to complement our analysis of
our weather planning standard.
ALTERNATE DEMAND SCENARIOS
As discussed in the Demand Forecasting section, we have identified several alternate scenarios for
detailed analysis to capture a wide range of possible outcomes over the planning horizon. These
scenarios are summarized in Table 7.1 and are described in detail in the Demand Forecasts Chapter
and Appendices 3.6 and 3.7. These alternate scenarios consider different demand influencing factors
as well as price elasticity effects for various price influencing factors. This broad range of scenarios
is intended to capture most reasonably possible outcomes.
able 7.1De)~a
Expected Case
High Growth, Low Price
Low Growth, High Price
Green Future
Alternate Weather Standard
Supply Constraints
Demand profiles over the planning horizon for each ofthe alternate scenarios shown in Figures 7.1
and 7.2 reflect the two winter peaks we model for the different service territories (Dec. 20 and Feb.
15).
Avista 7.1
Chapter 7 - Alternate Scenarios, Portolios, Stochastic Analysis 2009 Natural Gas I RP
Figure 7.1 Dec 20 Peak Day Demand by Case
(NetofDSM Savings)
500 --~
450 --~I400----
:E.i 350;;~::!~""ii300- ""--..~..
250
i200~~~~~~ ~~~~~~~~øø~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~
-- Expeæd Case
__ Green FuiJre
-- High Grow Low Pric -- Low Growth High Pnce
-+ AInae Weather Siindard -- Supply Conslaints
Figure 7.2 Feb 15 Peak Day Demand by Case
(NetofDSM Savings)
600
550
500
450
:E.i 400;;::
350
300
250
200 ,
----~--- --~..
------
..
- ..-
i
I~ ~ ~~~~~~~~~$H~g$8$ßg~* ~ ~ ~ ~v ~v ~v ~v ~v ~v ~v ~v ~v ~v ~v ~v ~v ~v ~v ~v~~ ~ ~ ~ ~~~~~~~~~~~~~~~
-- Expect Case
__ Green FuiJre
-- High Growt Low Pric
-+ Alrnae Weather Siindard
-- Low Growth High Price
-- Supply Constaints
Noteworthy in these peak demand forecasts are two significant demand decline periods for most
scenarios. The first occurs almost immediately followed by a second decline begining in 2015.
These declines are a direct result of customers reacting to steep increases in natual gas prices as
modeled. The immediate period assumes that prices rise significantly from the curent extremely low
prices as the recession ebbs. We assume that customers respond to this price signal by consuming
less. The price increase in 2015 is a result of significant carbon cost adders for climate change policy
going into effect. Customers again react adversely to this sharp price movement, reducing their
consumption in a second round.
7.2 Avista
2009 Natural Gas IRP Chapter 7 - Alternate Scenarios, Portolios, Stochastic Analysis
As in the Expected Case, we modeled in SENDOUTiI the same resource integration and
optimization process described in this section for each of the other five demand scenarios (see
Appendix 7.1 for a complete listing of all portfolios considered). This identified first year unserved
dates for each scenario by service territory (Figure 7.3).
Figure 7.3 First Year Peak Demand Not Met with Existing Resources
Sænario Corrarisns
WNID Medbrd K1arrlh La Grande
1i:::..i:ca
¡¡C
!
iïii
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
. Expeæd Case
. Green Future
. High Growlh Low Pric
. AJrna1e Weatier Stl
. Low Grow1 High Pric
. Supply Constaints
As expected, our High Growth, Low Price scenario has the most rapid growth and the earliest fist
year unserved dates. Noteworthy is the significant acceleration of fist year unserved dates that result
from this higher growth scenario across all service territories:
· Washington/Idaho - seven years earlier (February 2016);
· Medford/oseburg - three years earlier (December 2015);
. Klamath Falls - five years earlier (December 2016); and
. La Grande - at least six years earlier (February 2022).
This "steeper" demand exemplifies the "flat demand risk" discussed earlier. The potential for
accelerated unserved dates warrants close monitoring of demand trends and resource lead times.
Several scenarios indicate no resource deficiencies over the planning horizon due to very slow or
even negative demand growth. A key reason for this is the price elasticity assumptions combined
with price forecasts with very steep price increases very early in the planning horizon. This "perfect
storm" combination produces a significant curtailment in total demand early in the forecast. A key
question for these scenarios is whether this early price shock materializes as forecasted and, if so, is
demand really permanently curtailed as predicted in the price elastic response assumption. This
condition also warants close monitorig of actual results.
Avista 7.3
Chapter 7 - Alternate Scenarios, Portolios, Stochastic Analysis 2009 Natural Gas i RP
Analyses of alterntive scenarios were extensive. Detailed information on certain selected scenarios
is included in the following appendices:
. Demand and Selected Resources graphs by service terrtory (select cases only) - Appendix
7.2;
. Peak Day Demand, Served and Unserved table (all cases) - Appendix 7.3;
. Load Duration Cure graphs for High Growth and Low Growth cases - Appendix 7.4;
. Avoided cost cure detail and graphs for High Growth and Low Growth cases - Appendix
6.4.
UPDATED PRICE FORECASTS
As discussed in Chapter 3 - Demand Forecasts, a dynamic forward maket and several factors that
influence fundamental price forecasts evolved quickly in the fist half of2009. We noted significant
changes in forward prices and several updates to the forecasts we monitor, including the mid-range
forecast we use in many of our scenarios. This prompted us to update our price forecasts in early
August 2009. Timing restrictions to meet work plan and filing schedules precluded us from updating
all of our prior analyses, limiting our price forecast updates to our Expected Case. A comparison of
the initial price cure and the updated price cure is shown in Figue 7.4.
Figure 7.4 Price Curve Comparison
Initial vs. Updaæd Forecst (indudes carbon adders) - Expeæd Case
2009$/Dth
$14.00
$12.00 ~-+-
$10.00 ../$8.00&.;;is --~------~..~
$6.00 -:J-$4.00 rr
$2.00
$0.00 ,
P.~!'"~~ ~~~~~~~~&"toP; ~~~(\ iò'frs 'f 'f '1 '1 'f 'f 'f 'f 'f 'f 'f 'f'' 'f 'f'1 'f'1 'f'1 'f~ 'f'V 'f'1
__ Initl Forecst -- Updaæd Forecast
After compiling updated prices, we ran three additional scenarios against our Expected Case
assumptions reflecting low, medium and high price.elasticity. The demand forecasts for these three
new scenarios compared to the initial Expected Case scenario (with low price elasticity) is shown in
Figue 7.5.
7.4 Avista
2009 Natural Gas IRP Chapter 7 - Alternate Scenarios, Portolios, Stochastic Analysis
Figure 7.5 System VVde Peak Day Demand (Net of DSM Savings)
Initl vs. Updaed Price Forecst Corrarison . Expeæd Case
SOO
450
400 -
350
:E 300 ....oJ 250ì5::200
150
100
50
,,,.
---
~
~~~~~~~~~~~~~~d#~~~~~¥~K~¥~K~¥K ~ ~# ~ ~ ~ ~ ~ ~~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~ ~~~~~~
-+ Initil Forecast -- Updated Prics Low Elastci -- Updated Prices Medium Elastty __ Updated Prics High Elasl
As anticipated, the Updated Prices, Low Elasticity scenario showed essentially unaffected demand
from the changed price curve. Therefore, we determined there would be no change in the timing of
unserved demand or resource selections made by SENDOUTiI.
In the Updated Prices, High Elasticity scenario, the response to prices resulted in essentially flat
demand over the planning horizon. SENDOUTiI confired our expectation that no region goes
resource deficient durg the planning horizon.
In the Updated Prices, Medium Elasticity scenario, resource deficiencies did occur but several years
later than under the initial Expected Case. The demand scenario was resource optimized in
SENDOUTiI for all jurisdictions which confirmed our expectation that the same resources would be
selected but merely in the later year when the deficit occurred. In W A/ID the shortage was delayed
beyond our planning horizon. Medford/oseburg went resource deficient five years later than
initially forecast to 2022. These results are shown in Figures 7.6 through 7.8.
Avista 7.5
Chapter 7 - Alternate Scenarios, Portolios, Stochastic Analysis 2009 Natural Gas I RP
Figure 7.6 WAllO Existing Reurce vs. Peak Day Demand
Expeæd Case wil Medium Pric Elasi (Net ofDSM Savings) Noverrer b Oåber
400,000
350,000
300,000
250,000
..200,000is
150,000
100,000
50,000
0~~~~~~~~~~#~~~d####~#¥~K~~K¥~¥K ~ ~# ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~ ~~~~~~
_ExistingGTN _ Exising TF-1 i: Existng TF-2 _ Spokane Supply -- Peak Day Demand
Figure 7.7 Medford/Roseburg Existing & Seleced Resource vs. Peak Day Demand
Expeæd Case witi Medium Priæ Elastici (Net ofDSM Savings) Noverrer b Ocber
120,000
Current Short
100,000
80,000
..60,000is
40,000
20,000
0 ~ ~ ~ 0 ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~v ~v ~ ~ ~v ~v ~v ~ ~v ~v~ ~ ~ ~ ~ ~v~v~v~v~v~v~v~v ~v ~v ~v ~v ~v ~v ~v~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~'V~'V~'r~'V~rt~'V~rt
- Existng GTN _ Existng TF-1 r: Existng TF-2 c: Backaul Med LaVGTN Corrresson -- Peak Day Demand
7.6 Avista
2009 Natural Gas IRP Chapter 7 - Alternate Scenarios, Portolios, Stochastic Analysis
Figure 7.8 Klamath Falls Existing & Selected Resources vs. Peak Day Demand
Expeæd Case with Medium Price Elaslci (netofDSM Savings) Noverrer 10 OCber
22,000
20,000
18,000
16,000
14,000
.c 12,000
ë 10,000
8,000
6,00
4,000
2,000
o
Current Short
~~~~~~~~~~~~~~ø####~#K~K¥~¥¥~¥K~~~~~~~~~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~n
_ Exislng GTN _ Existing TF-1 i: KF Lateral Purchase .. Peak Day Demand
ALTERNATE SUPPLY SCENARIOS
The list of identified and available supply-side resource options at Appendix 6.3 is extensive and is
meant to capture resource options we can reasonably count on if selected by SENDOUT~ when
running resource optimizations. The list includes other resources we considered but did not input
into SENDOUT~ because of various restrictions.
For example, contracted city gate deliveries in the form of a structured purchase transaction could be
a viable and desirable option to meet super peak conditions. However, the market-based price and
other term are difficult to reliably determine until a formal agreement is negotiated. Exchange
agreements also have market-based terms and are hard to reliably model especially when the
resource is not needed in the near term.
Another example is Imported LNG. Model assumptions can be reasonably estimated for LNG import
facilities but significant uncertainties outside of model assumptions preclude consideration of these
resources as "fIrm" at this time. (See Appendix 5.2 for detailed information about supply-side
scenarios. )
For our W NID and Medford/Roseburg service territories, unsubscribed fIrm capacity on GTN
and/or backhaul plus lateral expansion is a preferred resource selection from our existing resources
plus curently available supply scenario for most demand scenarios. However, assumptions on future
availability could change over time. Therefore, we ran two additional alternate supply-side scenarios
with changed assumptions on GTN capacity as per Table 7.2.
Avista 7.7
Chapter 7 - Alternate Scenarios, Portolios, Stochastic Analysis 2009 Natural Gas IRP
Table 7.2
A1te~Su plScena~9
Existing Resources
Existing + Expected Available
GTN Rate Escalation
GTN Fully Subscribed
The first scenario we assumed significant decontracting occurs in the futue which leads to much
higher rates. The result of this scenario using our Expected Case demand profile is that, in
Washington and Idaho, Satellte LNG is selected as the preferred resource portfolio. However, in
Medford/Roseburg the model stil favors the backhaul with and expansion of the Medford LateraL.
(Figues detailing the resources selected based on this scenario are included in Appendix 7.2.)
The second scenario assumes GTN or the upstream pipelines are fully subscribed and therefore,
capacity is not an available resource. This scenario resulted in satellte LNG for Washington and
Idaho. However in Medford/Roseburg the model selected an expansion ofthe NW mainline.
Figues detailing the resources selected based on this scenario are included in Appendix 7.2)
PORTFOLIO SELECTION
The alternate demand scenarios and supply scenarios are matched together to form portfolios. Each
ofthese unique portfolios is run through SENDOUTiI where the supply resources and demand-side
resources are compared and selected on a least cost basis. Once the resources are determined, a net
present value ofthe revenue requirement (PVRR) is calculated.
In the Expected case, the Expected Demand with Existing Resources plus Expected Available
portfolio has the lowest PVRR and was therefore selected as our preferred portfolio. In this
portfolio, the supply-side resources selected to meet unerved demand include the acquisition of
currently available pipeline capacity on GTN, additional compression on the GTN Medford Lateral
and the purchase of the Klamath Falls lateraL. These resources are the least cost/risk adjusted
options available to meet peak day demand.
Table7.3 summarizes the PVRR of all the portfolios considered. Each of these portfolios is based
on unique assumptions and therefore a simple comparison ofPVRR cannot be made. Detailed cost
information on all portfolios can be found in Appendix 7.5.
7.8 Avista
2009 Natural Gas IRP Chapter 7 - Alternate Scenarios, Portolios, Stochastic Analysis
Table 7.3 Net Present Value of Revenue Requirement (PVRR) by Portolio
Portolio PVRR in (OOO'sl
$(6,514,895)
$(6,547,705)
$(6,593,845)
$(7,440,510)
$(5,856,847)
$(6,249,435)
$(7,997,147)
$(7,691,204)
$(10,704,833)
$(9,277 ,241)
$(10,814,967)
$(11,782,862)
Expected Case
Expected Demand with Existing Resources (before resource additions)
Expected Demand with Existing Resources plus Expected Available
Expected Demand with GTN Fully Subscribed
Expected Demand with GTN Rate Escalation
Additional Demand Scenarios
Expected Demand with High Elasticity and Existing Resources
Expected Demand with Medium Elasticity and Existing Resources
Alternate Weather Standard Demand with Existing Resources
High Growth, Low Price Demand with Existing Resources
High Growth, Low Price Demand with Existing Resource plus Expected Available
Green Future with Exisiting Resources
Low Growth, High Price with Existing Resources
Suoply Constraints with ExistinQ Resources
STOCHASTIC ANALYSIS 1
The scenario (deterministic) analysis described earlier in this document represents specific "what if'
situations based on predetermed assumptions including price and weather. These two factors are
an integral part of scenario analysis. To better understand a particular portfolio's response to price
and weather, we applied stochastic analysis to generate a wide variety of price and weather events.
Deterministic analysis is a valuable tool for selecting the optimal portfolio. The model selects
resources to meet peak weather conditions in each of the 20 years. However, due to the recurence
of design conditions in each of the 20 years, total system costs over the planning horion can be
overstated because of annual recurence of design conditions and the recurrence of price increases in
the forward price cure. As a result, deterministic analysis does not provide a comprehensive look at
future events. This type of analysis is only one piece of the puzzle. Utilizing Monte Carlo
simulation in conjunction with deterministic analysis provides a more complete picture of how the
portfolio performs under multiple weather and price profiles.
For this IRP, Monte Carlo analysis was employed in two ways. The first was to test our weather
planning standard and the second was to assess the risk related to costs of our Expected portfolio
under varying price environments.
WEATHER
In order to evaluate weather and its effect on our portfolio, we derived 200 simulations (draws)
through the use ofSENDOUTiÊ,s Monte Carlo capabilities. Unlike determistic scenarios or
sensitivities, the draws have more variability from month-to-month and year-to-year. In the modeL,
random monthly total HDD draw values (subject to Monte Carlo parameters - see Table 7.4) are
distributed on a daily basis for a month in history with similar HDD totals. The resulting draws
provide a weather pattern with variabilty in the total HDD values, as well as variability in the shape
of the weather pattern. This provides more robust basis for stress testing the deterministic analysis.
i SENDOUT'" uses Monte Carlo simulation to support stochastic analysis, which is a mathematical technque for evaluating risk and
uncertinty. Monte Carlo simulation is a statistical modeling method used to imitate the many future possibilties that exist with a
real-life system.
Avista 7.9
Chapter 7 - Alternate Scenarios, Portolios, Stochastic Analysis 2009 Natural Gas IRP
Nov Dec
Table 7.4 Example of Monte Carlo Weather Inputs
SpokaneJan Feb Mar Apr May Jun Jul Aug Sep Oct
HDDMean
HDDStd Dev
HDDMax
HDDMin
895 1,152 1,145 913 781 546 331 143 37 37 191 54
132 141 159 115 85 73 72 52 28 28 77 70
1,361 1,506 1,681 1,20 953 694 471 248 151 97 343 677
699 918 897 716 598 392 192 61 -1 54 361
A vista models five weather areas; Spokane, Medford, Roseburg, Klamath Falls and La Grande.
From the simulation data we were able to assess the frequency that the peak day occurs in each area.
The stochastic analysis shows that in over 200 twenty-year simulations, while stil remote, peak day
(or more) does occur with enough frequency to maintain our current planning standard for this IRP,
though this topic remains a subject of continued analysis. For example, in our Medford weather
pattern over the 200 twenty-year draws (i.e. 4000 years), HDDs at or above peak weather (61 HDD)
occurs 128 times. This equates to a peak day occurrence once every 3 I years (4000 simulation years
divided by 128 occurences). The Spokane area has the least occurrences of peak day (or more)
occurrences in our simulations while La Grande has the most occurences. This is primarily due to
the frequency in which each region's peak day HDD occurs within the historical data as well as near
peak day HDDs. See Figues 7.9 through 7.13 for the number of peak day occurrences for a weather
area.
Figure 7.9 Freuency of Peak Day Occurrence
Spkane
3
II~c 2
ig::
8..osC..os..1ii
'õ'"
0 ,,
1 10 19 28 37 46 55 64 73 82 91 100 109 118 127 136 145 154 163 17 181 190 199
Draws
7.10 Avista
2009 Natural Gas i RP Chapter 7 - Alternate Scenarios, Portolios, Stochastic Analysis
Figure 7.10 Frequency of Peak Day Occurrences
Medfbrd
3
5
ê 2::
8
~Q..
:f-o""
o
10 19 28 37 46 55 64 73 82 91 100 109 118 127 136 145 154 163 172 181 190 199
Draws
Figure 7.11 . Frequency of Peak Day Ocurrences
Roseburg
3
:l..i:2
¡g::..8,.OJQ
I
..:ir:1-0""
0 ,,.
1 10 19 28 37 46 55 64 73 82 91 100 109 118 127 136 145 154 163 172 181 190 199
Draws
Avista 7.11
Chapter 7 - Alternate Scenarios, Portolios. Stochastic Analysis 2009 Natural Gas i RP
Figure 7.12 Frequency of Peak Day Occurrences
Klamath Falls
3
Bi: 2
¡g'"
8~o....
if 1
'õ,.
o
1019 28 37 46 55 64 73 82 91 100 109 118 127 136 145 154 163 172 181 190 199
Draws
Figure 7.13 Freuency of Peak Day Occurrnce
LaGrande
7
6
B 5i:
¡g
~ 4
c3~~ 3..if
'õ 2,.
o
10 19 28 37 46 55 64 73 82 91 100 109 118 127 136 145 154 163 172 181 190 199
Draws
PRICE
While weather is an important drver for IRP planning, price is also important. As seen in recent
years, there can be significant price volatility that can affect the portfolio. In determistic modeling,
a single price curve for each scenario is used to pedorm analysis. There is risk, however, that the
price curve used in the scenario wil not reflect actual results.
Through Monte Carlo simulation, we are able to test our portfolio and quantify the risk to our
customers when prices do not materialize as forecasted. We performed a simulation of200 draws,
varying prices, to investigate whether the Expected Case total portfolio costs from our deterministic
7.12 Avista
2009 Natural Gas IRP Chapter 7 - Alternate Scenarios, Portolios, Stochastic Analysis
analysis is within the range of occurrences in our stochastic analysis. Figure 7. 14 shows a histogram
of the total portfolio cost ofa11200 draws, plus the Expected Case results. This histogram depicts the
frequency and the total cost ofthe portfolio among all the draws, the mean ofthe draws, the standard
deviation ofthe total costs, and the total costs from the Expected Case. The figue confirms that our
Expected Case total portfolio cost is within an acceptable range oftotal portfolio costs based on 200
unique pricing scenarios. This provides us comfort that our Expected Case price curve and the
resultant total portfolio cost is adequately statistically supported.
Figure 7.14
Avista IRP Total 20 Year Cost
90th 95th
35 Mean Expected 100%
_ Frequency
.. Cumulative
90%
Average: 8.671
StdDev: 0.051Mn: 8.53330 90% percentile: 8.735
95% percentie: 8.756Ma: 8.826
Expected: 8.685
80%
5%
~Cop8. 756)=5%70%25
~ 20c
GI::trGI
it 15
60%
CI
.~
50%"t3
E:i.040%
,:, 10%~ - -- - - - - - - - - - - - - - - - - - - - - - - - -+
:: ~Cost~8.735)=10%
10 30%
20%
5
10%o , 0%
~O; ~~ ~ ~ ~Cb co" co') ~ 'i~ ~'rf: coCb ,," ,,'):,,~:,,~ -( o.~'ò 0.'PÇ) 0.'P" 0.'P0; _q.~
030 030 ~'ò0 ~'ò0 ~'ò0 ~'ò0 030 030 ~'ò0 ~'ò0 ~'ò0 ~'ò0 ~'ò0 030 ~'ò0 ~'ò0 030 ~v ~v ~v ~v "S
$ Billons
Performing stochastic analysis on two key variables of weather and price in our demand analysis
provided a statistically supported approach to evaluate and confm the fidings reached from our
scenario analysis with respect to adequacy and reasonableness of our weather planning standard and
our selected natural gas price forecast. This alternative analytical perspective provides us better
confidence in our conclusions and helps us stress test our assumption, thereby mitigating analytical
risks.
REGULATORY REQUIREMENTS
IRP regulatory requirements in Washington, Oregon and Idaho call for several key components. The
completed plan must demonstrate that we have:
. Examined a range of demand forecasts;
Avista 7.13
Chapter 7 - Alternate Scenarios, Portfolios, Stochastic Analysis 2009 Natural Gas IRP
. Examined feasible means of meeting demand with both supply-side and demand-side
resources;
. Treated supply-side and demand-side resources equally;
. Described our long-term plan for meeting expected demand growth;
. Described our plan for resource acquisitions between planning cycles;
. Taken planning uncertainties into consideration; and
. Involved the public in the planning process.
We have addressed the applicable requirements throughout this document. Appendix 2.1 lists the
specific requirements and guidelines of each jurisdiction and describes our compliance in detaiL.
We are also required to consider risks and uncertainties throughout our planning and analysis. Our
approach in addressing this requirement was to identify factors that could cause significant deviation
from our Expected Case planning conclusions. We employed dynamic demand analytical methods
and incorporated sensitivity analysis on various demand drivers that impacted demand forecast
assumptions. From this, we created 15 demand sensitivities and modeled 6 demand scenario
alternatives, which incorporated differing customer growth, use per customer, weather and price
elasticity assumptions. We developed four supply scenarios to consider various risks of resource
uncertainties. This resulted in 13 distinct portfolios analyzed within SENDOUTiI.
We performed analysis on our peak day weather planing standard, performing sensitivity on HDDs
and modeling an alternate weather planning standard using coldest day in 20 years. We
supplemented this analysis with stochastic analysis ruing Monte Carlo simulations in
SENDOUTiI. We also used simulations from SENDOUTiI to analyze price uncertainty and the
effect on total portfolio cost.
We examined risk factors and uncertainties that could impact expectations and assumptions with
respect to DSM programs and supply-side scenarios. From this, we developed four supply-side
scenarios and included numerous DSM programs for evaluation.
This investigation, identification and assessment of risks and uncertainties in our IRP process should
reasonably mitigate surprise outcomes.
CONCLUSION
Given the extreme increase and decrease in demand levels over the full planning horizon framed by
the Low Growth and High Growth cases, we believe that we have modeled a suffcient range to
capture all reasonably possible but less likely outcomes from our Expected Case.
Our portfolio and resource analysis indicates several strategies that should be pursued to fully
optimize available resources. The effectiveness of any strategy wil be in the flexibility to take
advantage of maket opportities. These strategies indicate the following:
7.14 Avista
2009 Natural Gas IRP Chapter 7 - Alternate Scenarios, Portolios, Stochastic Analysis
· A total system supply portfolio should be maintained to provide the greatest flexibility for
dispatching resources, while maintaining lower supply costs due to the diverse weather
within our service territory.
· Long-term and short-term capacity releases and recalls should continue to be reviewed
periodically.
We wil continue to monitor demand levels and peak day requirements for signposts (e. g. greater
than or less than expected customer growth or use per customer) that indicate demand levels are
moving toward another case. We believe that through this analysis and monitoring process, and
given that we have suffcient time before potential resource shortages, there is little chance of being
surprised by resource shortages.
Avista 7.15
Chapter 7 - Alternate Scenarios, Portolios, Stochastic Analysis 2009 Natural Gas IRP
7.16 Avista
2009 Natural Gas IRP
CHAPTER 8 - DISTRIBUTION PLANNING
OVERVIEW
Avista's integrated resource planning encompasses evaluation of safe, economical and reliable full-
path delivery of natural gas from basin to burner tip. Securing adequate natural gas supply and
ensuring sufficient pipeline transportation capacity to our city gates become secondary issues if the
distribution system behind the city gates is not adequately planned and becomes severely
constrained. An important part ofthe planning process is to forecast future local demand growth,
determine potential areas of distribution system constraints, analyze possible solutions and estimate
costs for eliminating constraints.
Analyzing our resource needs to this point has focused on ensuring adequate capacity to our city
gates, especially during a peak event (i.e. "Is there adequate volume for a peak day?"). Distribution
planning focuses on "Is there adequate pressure during a peak hour?" Despite this altered
perspective, distribution planning shares many ofthe same goals, objectives, risks and solutions.
A vista's natural gas distribution system consists of approximately 3,400 miles of distribution main
pipelines in Washington, 1,900 miles in Idaho and 2,300 miles in Oregon, as well as numerous
regulator stations, service distribution lines, monitorig and meterig devices, and other equipment.
Currently, there are no storage facilities or compression systems within our distribution system.
System pressure is maintained by pressure regulating stations that utilize pipeline pressures from the
interstate transportation pipelines before natural gas enters our distribution networks.
DISTRIBUTION SYSTEM PLANNING
A vista conducts two primary types of evaluations in its distribution system planning efforts to
determine the need for resource additions, including distribution system reinforcements and
expansions. Reinforcements are upgrades in existing infrastructure or new system additions that
increase system capacity, reliability and safety. Expansions are new system additions to
accommodate new demand. Collectively we refer to these as distribution enhancements.
Ongoing evaluations of each distribution network in our four primary service terrtories are
conducted to identify strategies for addressing local distribution requirements resulting from
customer growth. Customer growth assessments are made based on many factors including our IRP
demand forecasts!, monitoring of gate station flows and other system metering, ongoing
communication with construction staff and local area management regarding new service requests,
field personnel discussion and inquiries from major developers.
1 Distrbution Planning forecasts customer growth rates by town code to generate local demand growth projections in its forecasting
model consistent with the broader IR customer forecasting methodology facilitating consistent integrated planning efforts. A town
code is an unincorporated area within a county or a municipality within a county.
Avista 8.1
Chapter 8 - Distribution Planning 2009 Natural Gas I RP
Additionally, A vista regularly conducts integrity assessments of its distribution systems. This tye of
ongoing system evaluation can also indicate distribution upgrading requirements, but as a result of
system maintenance needs rather than customer and load growth. In some cases, however, the timing
for system integrity upgrades can coincide with growth related expansion requirements.
These planning efforts provide a long-term planning and strategy outlook and are integrated into our
capital planning and budgeting process which incorporates planning for other types of distribution
capital expenditures and infrastructure upgrades.
NETWORK DESIGN FUNDAMENTALS
Natual gas distribution networks rely on pressure differentials to flow gas from one place to
another. When pressures are the same on both ends of a pipe, the gas does not move. When gas is
removed from a point on the network, the pressure at that point drops lower than the pressure
upstream in the network. Gas then moves from the higher pressure in the network to the point of
removal, attempting to equalize the pressure throughout the network. If gas removed is not
sufficiently replaced by new gas enterig the network, the pressure differential wil decrease and
flow wil stall and the network could ru out of pressure. Therefore, it is important to design a
distribution network so that the intake pressure (from gate stations and/or regulator stations) within
the network is high enough to maintain an adequate pressure differential when gas leaves the
network.
Not all gas flows equally throughout a network. Certain points within the network can constrain flow
and thus restrict overall network capacity. Network constraints can occur over time as demand
requirements on the network evolve. Anticipating these demand requirements, identifying potential
constraints and formig cost effective solutions with suffcient lead times without overbuilding
infrastructure are the key challenges in network design.
COMPUTER MODELING
Developing and maintaining effective network design is significantly aided by computer modeling to
perform network demand studies. Demand studies have evolved with technology in the past decade
to become a highly technical and powerful means for analyzing the operation of a distribution
system. Using a pipeline fluid flow formula, a specified parameter of each pipe element can be
simultaneously solved. A variety of pipeline equations exist, each tailored to a specific flow
behavior. Through years of research, these equations have been refied to the point where modeling
solutions produced closely resemble actual system behavior.
Avista conducts network load studies using Advantica's SynerGEEQ\ 4.3.0 software. This computer-
based modeling tool ru on a Windows operating system and allows users to analyze and interpret
solutions graphically. Appendix 8. I describes in detail our computer modeling methodology while
Appendix 8.2 provides an example load study presentation including graphical interface and output
examples.
8.2 Avista
2009 Natural Gas IRP Chapter 8 - Distribution Planning
DETERMINING PEAK DEMAND
For ease of maintenance and operation, safety to the public, reliable service and cost considerations,
distribution networks operate at a relatively low pressure. A vista operates its distribution networks at
a maximum operating pressure of 60 pounds per square inch (psig). Since distribution systems
operate at pressure through relatively small diameter pipes, there is essentially no line-pack
capabilty for managing hourly demand fluctuations.
Core demand typically has a morning peaking period between 6 a.m. and 10 a.m. and an evening
peaking period between 5 p.m. and 9 pm. The peak hour demand for these customers can be as much
as 50% above the hourly average ofthe daily demand. Because ofthe importance of responding to
hourly peaking in the distribution system, planning capacity requirements for our distribution
systems are based on peak hour demand2. Included in Appendix 8. I is the detailed methodology we
use for determining peak demand.
DISTRIBUTION SYSTEM ENHANCEMENTS
Computer-aided demand studies facilitate modeling numerous "what if' demand forecasting
scenarios, constraint identification and corresponding optimum combination of pipe modification
and pressure modification solutions to maintain adequate pressures throughout the network over
time.
Distribution system enhancements do not reduce demand nor do they create additional supply.
However, they can increase the overall capacity of a distribution pipeline system while utilizing
existing gate station supply points. The three broad categories of distribution enhancement solutions
are pipelines, regulators and compression.
PIPELINES
Pipeline solutions consist of looping, upsizing and uprating.
· Pipeline looping is the most common method of increasing capacity within an existing
distribution system. It involves constructing new pipe parallel to an existing pipeline that has,
or may become, a constraint point. Constraint points inibit pressure capacities downstream
of the constraint creating inadequate pressure durig periods of high demand. When the
parallel line is connected to the system, this second alternative path allows natural gas flow to
bypass the original constraint point and bolster downstream pressure capacities. The
feasibility of looping a pipeline is primarily dependant upon the location where the pipeline
wil be constructed. Installing gas pipelines through private easements, residential areas,
existing asphalt, and steep or rocky terrain can greatly increase the cost to amounts that are
unjustifiable so that other alternative solutions offer a more cost effective solution.
2 This method differs from the approach that we use for broader IR peak demand plannng which focuses on peak day requirements
to the city gate.
Avista 8.3
Chapter 8 - Distribution Planning 2009 Natural Gas IRP
. Pipeline upsizing is simply replacing existing pipe with a larger size pipe. The increased pipe
capacity relative to surface area of the pipe results in less friction and therefore a lower
pressure drop. This option is usually pursued when there is damaged pipe or pipe integrity
issues exist. If the existing pipe is otherwise in satisfactory condition, looping is usually
pursued, allowing the existing pipe to remain in use.
. Pipeline uprating involves increasing the maximum allowable operating pressure of an
existing pipeline. This enhancement can be a quick and relatively inexpensive method of
increasing capacity in the existing distribution system before constructing more costly
additional system facilities. However, safety considerations and pipe regulations may
prohibit feasibility or lengthen the time before completion ofthis option. Also, increasing
line pressure may produce leaks and other pipeline damage creating unanticipated costly
repairs.
REGULATORS
Regulators or regulator stations are used to reduce pipeline pressure at various stages within the
distribution. The primary purose of regulation is to provide a specified and constant outlet pressure
before gas continues its downstream travel to a city's distribution system, customer's property, or
gas appliance. Regulators also ensure that flow requirements are met at a desired pressure regardless
of fluctuations upstream of the regulator. Regulators can be found at city gate stations, district
regulators stations, farm taps and customer services.
COMPRESSION
Compressor stations present a capacity enhancing option for pipelines with significant gas flow and
the ability to operate at higher pressures. For pipelines experiencing a relatively high and constant
flow of gas, a single, large volume compressor can be installed in the optimal position along the
pipeline to boost downstream pressure. However, this type of compressor configuration wil not
function effectively if the flow in the pipeline has high variability.
A second option is the installation of multiple, smaller compressors located close together or
strategically placed in different locations along a pipeline. Multiple compressors accommodate a
large flow range and the use of smaller and very reliable compressors. These smaller compressor
stations are well suited for areas where gas demand is growing at a relatively slow and steady pace
so that purchasing and installing these less expensive compressors can be done over time allowing a
pipeline to serve growing customer demand for many years into the future.
Compressors can be a cost effective, feasible option to resolving constraint points; however,
regulatory and environmental approvals to intall a station along with engineering and construction
time can be a significant deterrent. Also, adding compressor stations within a distribution system
typically involves considerable capital expenditure. Based on our detailed knowledge of our
distribution system, we do not curently envision or have any foreseeable plans to add compressors
to our distribution network.
8.4 Avista
2009 Natural Gas IRP Chapter 8 - Distribution Planning
CONSERVATION RESOURCES
Included in our evaluation of distribution system constraints is consideration oftargeted
conservation resources that could reduce or delay distribution system enhancements. We are
mindful, however, that the consumer is stil the ultimate decision-maker regarding the purchase of a
conservation measure. Because ofthis, we attempt to influence these decisions but we do not depend
on estimates of peak day demand reductions from conservation to eliminate near-term distribution
system constraint areas. Over longer-term planning, we do recognize that targeted conservation
programs provide a cumulative benefit that offsets potential constraint areas and may be an effective
strategy.
PLANNING RESULTS
Table 8.1 summarizes the cost of major distribution system enhancement projects which address
futue growth-related system constraints as well as system integrity issues and the anticipated timing
of expenditures. These proposed projects are preliminary estimates oftimig and costs of
reinforcement solutions. The scope and needs of these projects can evolve over time with new
information requiring ongoing reassessment. Actual solutions may be different due to differences in
actual growth pattern and/or construction conditions from those assumed in the initial assessment.
The following discussion provides further information on our key near-term projects:
3203 - East Medford Reinforcement - This project wil install a high-pressure (HP) steel
line from North Phoenix Road, ending in White City. The total length ofthe line wil be
about nie miles. The 2010 project wil install approximately 3000 feet ofHP main into an
open right-of-way in conjunction with road reconstruction by third parties. The remainder of
the project, approximately 14,000 feet wil be completed in the future.
Observed local growth and our IRP indicate increased gas deliveries wil likely be needed
from the TransCanada Pipeline source at Phoenix Road Gate Station in southeast Medford.
To facilitate distribution receipt ofthe increased gas volumes, a new HP gas line encircling
Medford to the east and tying into an existing high-pressure feeder in White City wil
improve delivery capacity and provide a much needed reinforcement in the East Medford
area which is forecasting higher growth.
3204 - Roseburg Reinforcement - This is a three-part project to bring HP gas into the
central and east Roseburg areas. The first phase, completed in 2008, extended HP steel from
an existing main located in south Roseburg to the downtown area. The second phase wil
extend HP pipe to the east side of Roseburg and install a regulator station. The final phase of
the project wil complete the main extension from south Roseburg to Winston where it will
be connected to a new HP source.
The Roseburg distribution system is fed entirely from the west side oftown where Northwest
Pipeline is located. There is curently no HP source located on the east side of town. Curent
Avista 8.5
Chapter 8 - Distribution Planning 2009 Natural Gas IRP
and projected growth is heavy on the east side of Roseburg, causing pressure problems in the
winter months. This project wil ease this problem and position the system for future growth.
The scope of this project was modified in 2008. Due to excessive construction costs to
complete the previously proposed second phase ofthe project, an alternate temporary
solution was implemented. The sequence for completing the final two phases of the project
was changed to fully utilize the 2008 temporar system enhancement while completing the
necessary reinforcement for the east side of Roseburg.
3237 - U.S. 2 North Spokane Reinforcement - This project wil reinforce the area north of
Spokane along U.S. Highway 2. This mixed-use area with residentiaL commercial and
industrial demand experiences low pressure at unpredictable times given varied demand
profies of the diverse customer base. Completion ofthis reinforcement wil improve
pressures in the U.S. 2 north Kaiser area. Approximately 8,000 feet ofHP steel wil be
installed in a newly established easement along U.S. Highway 2.
3240 - Grants Pass Reinforcement - This project will extend approximately two miles of
HP main from near the existing Jones Creek Gate Station to the downtown Grants Pass area.
This project wil provide two benefits to our customers. First, it wil provide for necessary
additional delivery volumes into Grants Pass. Grants Pass high-pressure gas delivery is
constrained by the size ofthe existing distribution main. Secondly, the project wil replace a
section ofHP main that has a number of identified high-consequence areas (HCAs) that must
be mitigated under the PHMSA Integrity Management Regulation.
Contingencies include extension of other HP sources into Grants Pass. The identified
solution is curently the low cost alternative based on length of pipe installed. Installation of
new main as identified allows for a pressure reduction in the existing portion of the HP
transmission main into Grants Pass. Installation ofthe new main avoids integrity
management mitigation costs and reduces the consequences and risks associated with a
pipeline incident.
3269 - Clarkston Reinforcement - This project wil reinforce the southwest area of
Clarkston. The existing HP feeder serving the Clarkston Heights area is capacity constrained
on a peak day. Reinforcement is required to reliably serve the area. The project wil include
the installation of 14,400 feet ofHP steel main from the existing source in Clarkston to
Critchfield Road.
8.6 Avista
2009 Natural Gas IRP Chapter 8 - Distribution Planning
Ref # TITLE Sate Project Type 2010 2011 Total
3112 Re-Route Kettle Falls Feed & Gate Station WA compliance 1,800,000 2,760,000 4,560,000
3245 Cheney HP Feeder Project WA reinforcement 3,600,000 3,600,000
. 3269 Clarkston Reinforcement WA reinforcement 2,000,000 2,000,000
. 3237 US2 N Spokane Reinforcement WA reinforcement 1,200,000 1,200,000
3102 N-S Freeway/Gas WA rod requiremnt 50,000 100,000 100,000 100,000 100,000 450,000
3107 Bridging the Valley WA road requiremnt 50,000 100,000 100,000 100,000 100,000 450,000
3268 Reinforcement - Appleway Bridge Crossing WA reinforcement 275,000 275,000
3273 Relocation, Stevenson Bridge Bore WA enhancement 250,000 250,000
3260 Reinforcement, Install casing and pipe on Bridge Spokane WA reinforcement 100,000 100,000
3274 Reinforcement, Loop existing HP frm Tolo to White City OR reinforcement 6,615,000 6,615,000
. 3204 Roseburg Reinforcement OR reinforcment 1,934,000 3,347,000 5,281,000.3203 East Medford Reinforcement OR reinforcement 600,000 4,100,000 4,700,000
3242 Reinforce Talent OR Gate Station & Piping OR reinforcement 3,600,000 3,600,000
. 3240 Grants Pass Reinforcement OR reinforcement 2,000,000 2,000,000
3277 IMP Pipe Replacements Medford OR compliance 1,500,000 1,500,000
3209 Elgin Line Reinforcement OR reinforcement 1,500,000 1,500,000
3267 Rebuild - Jackie Sl/inston Gate Station, Roseburg OR reinforcement 1,000,000 1,000,000
TBO Reloction - N Ross Ln. (2010 Road Project), Medford OR rod requiremnt 200,000 200,000
3257 Oakland Bridge Bore and Reloction, Oakland OR compliance 180,000 180,000
3227 T ri-City Hwy 99 Road Projec, Roseburg OR road requiremnt 150,000 150,000
3261 Brown Bridge Relocation, Roseburg OR road requiremnt 136,000 136,000
3258 Relocation, Davis Creek, Roseburg OR compliance 125,000 125,000
3213 Altamont & Crosby Road Projec, K Falls OR road requiremnt 100,000 100,000
3278 Relocation - Reg Station, Medford OR compliance 100,000 100,000
3276 Reinforcement, Wolf Lodge Tap, Coeur d'Alene 10 reinforcement 2,700,000 2,700,000
3246 Chase Rd Gate Station, Post Falls 10 reinforcement 2,100,000 2,100,000
3270 Reinforcement - Southeast Coeur d'Alene 10 reinforcment 255,000 285,000 245,000 450,000 1,235,000
TBO Reinforcement - Spirit lake Main, Athol 10 reinforcement 1,000,000 1,000,000
3275 Upgrade - Coeur d'Alene East Tap, Coeur d'Alene 10 reinforcement 700,000 700,000
3279 Reinforcement - Main Exension south from COA East Gate 10 reinforcement 450,000 450,000
TBO Reinforcement - Pack Saddle Area, COA 10 10 reinforcement 170,000 170,000
3271 Rebuild - Reg Station, Sandpoint 10 10 reliability 150,000 150,000
. Details of project described in IRP 8,741,000 6,019,000 7,142,000 7,960,000 18,715,000 48,577,000
CONCLUSION
Avista's goal is to maintain 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
reliability of the distribution system by identifying specific areas within the system that may require
changes.
The ability to meet our goal of reliable cost effective gas delivery is also enhanced through the
recent integration of customer growth forecasting at the town code level and localized distribution
planning enabling coordinated targeting of distribution projects that are responsive to detailed
customer growth patterns.
Avista 8.7
Chapter 8 - Distribution Planning 2009 Natural Gas IRP
8.8 Avista
2009 Natural Gas IRP
CHAPTER 9 - ACTION PLAN
2008.2009 ACTION PLAN REVIEW
The 2008-2009 Action Plan focused on the following areas:
. Integrated Resource Portfolio
. Demand Forecasting
. Demand-Side Management
. Supply-Side Resources
A discussion of the specific action items and the plan results follows:
INTEGRATED RESOURCE PORTFOLIO
Action Item:
We wil refine our specific resource acquisition action plans for Klamath Falls and Medford service
areas that address the projected unserved Expected Case demand in 2011-2012 and 2013-2014,
respectively. We will monitor timelines, milestones, status and progress reporting, ongoing plan risk
assessment and consideration of alternative actions.
For Klamath Falls we wil:
· Reassess the necessary operational steps and timing (curent estimate is six months) to
acquire the Klamath Falls lateral,
. Monitor actual demand trends to forecasted demand to refie a target date for initiating the
purchase ofthe lateraL.
For Medford we wil:
· Commission a pipeline expansion study from GTN to identify specific costs and issues,
. Monitor actual demand trends to forecasted demand to refine the timing of action steps,
· Assess the impacts of project timing from possible changes in our weather planning standard.
Results:
The economic downturn and resultant weak demand delayed the projected unerved demand in all of
our service terrtory regions.
Avista 9.1
Chapter 9 - Action Plan 2009 Natural Gas I RP
Klamath Falls - In 2008, we performed an internal assessment of our standing option to
purchase the Klamath Falls lateral from NWP. This agreement requires relocation of
maximum daily quantities from Klamath Falls to another point (or points) on NW's system
to maintain our total contract demand. We explored numerous possible areas that might
benefit from increased capacity. None are curently constrained and our current assessment
does not indicate a resource need in the near term. We also explored the potential for new
large demand customers with our marketing team which indicated limited near-term
prospects, especially in light ofthe current economic environment. Although purchasing the
lateral benefits our Oregon customers, the lack of actual, anticipated or prospective need for
additional capacity that could fulfill the maximum daily quantities relocation requirement
(either within the Klamath Falls service terrtory or elsewhere on the NWP system) restricts
the purchase of the lateral at this time.
Medford - Demand trends for Medford have tracked to the low end of our IRP forecasts for
some time. We, therefore, have deferred incuring the cost ofa formal pipeline expansion
study given sufficient time exists to monitor actual demand trends which we have updated in
our 2009 IRP.
Action Item:
We wil re-evaluate our current peak day weather standad to ascertain if it stil provides the best
risk-adjusted methodology in evaluating resource plaing.
Results:
In re-evaluating our weather standard we performed the following analyses:
. Sensitivities around one and two HDD weather adjustments
. Monte Carlo simulations to analyze probabilities of encounterig peak weather
. Applied confidence levels to review upper-limit exposure in conjunction with the regressions
performed during our gate station demand and resources work, as well as use per customer
coeffcient development
. Examied important qualitative factors around safety and reliability
While other planning assumptions allow for continuous monitorig for reasonableness and
corrective adjustments over time, peak day weather can occur with no waring which severely limits
any response adjustments. Significant safety risk, propert damage and inconvenience can occur if
actual weather exceeds our peak day weather planning standard. Because there have been limited
recent extreme cold weather events, more uncertainty and potential error exists in predicting cold
weather usage. The recent actual data we do have on very cold weather events indicate instances
when demand has been higher than the projected usage from our regression analysis. Because of
these factors, we are maintaining our curent "coldest day on record" planning standard for our
Expected Case.
9.2 Avista
2009 Natural Gas IRP Chapter 9 - Action Plan
Action Item:
We wil meet regularly with Commission Staff members to provide information on market activities,
material changes to risk management programs, and significant changes in assumptions and/or status
of company activity related to the IRP or procurement practices.
Results:
We have met with Commission Staff several times since our last acknowledged IRP to provide
information on market activities, risk management programs, the IRP and procurement practices.
Schedules permitting, we attempt to meet on a quarerly basis.
DEMAND FORECASTING
Action Item:
We wil further integrate the VectorGas™ module in our SENDOUTiI modeling software to
strengthen our ability to analyze the demand impacts under varying weather and price scenarios as
well as conduct sensitivity analysis to identify, quantify, and manage risk around these demand-
influencing components.
Results:
VectorGas™ (now incorporated into SENDOUTiB has provided statistically-based analysis in
support of our peak day weather standard evaluation. We developed statistical modeling and analysis
of potential price outcomes and the impacts on total portfolio cost and alternate resource selections.
Looking forward for the next IRP, we are also explorig potential applications for simulating
probabilistic weather outcomes in a possible global warming scenario. We continue to review other
applications to employ the VectorGas™ analytical tool in our 2011 IRP.
Action Item:
We wil study ways to further refine our ability to model demand by region. Town code forecasting
was the first step in enhancing our demand forecasting. We now want to explore incorporating these
town code forecasts into regions for analysis in SENDOUTiI, especially within the broad
Washington/Idaho division to investigate potential resource needs that may materialize earlier than
the broader region indicates.
Results:
Town code forecasting continues to be an effective method for developing and monitorig
expectations for customer growth rates providing benefits beyond the IRP, including corporate
budgeting and distribution planning. The use per customer coeffcient is the other key driver in
determining forecasted demand in SENDOUTiI. We have explored several potential methods for
developing sub-regional use per customer coeffcients that enhance predicting reasonable
expectations of forecasted demand while reconciling tightly back to actual results with back casting.
Avista 9.3
Chapter 9 - Action Plan 2009 Natural Gas IRP
We use linear regression on daily observable temperatue/demand data to produce coeffcients.
Allocations of monthly customer demand by class are applied to our gate station data as necessary,
given few customers have daily meterig. Our attempts to build daily town code level coefficients by
customer class from allocations of monthly town code level data have not produced satisfactory
results. It appears that biling period and cutoff issues are magnified when constrcting coefficients
with smaller customer groupings. Consequently, unacceptable distortions arise in backcasting to
actual demand.
We have been more successful in refining our coeffcient development into monthly factors from
broader regional data. Using more data points, this method provides improved captuing of the
seasonal consumption profile. The regressions on the coldest data points from this method were also
used in our reassessment and analysis of our peak day weather standard. Because ofthe superior
backcasting that regional coeffcients provide, we wil forego sub-regional/town code level use per
customer coeffcient development at this time.
DEMAND-SIDE MANAGEMENT
Action Item:
The IRP analysis has indicated a set of cost effective measures and achievable resource potential for
a futue DSM portfolio. We established targets for first-year energy savings goals for 2008 of
1,425,000 therms in Washington/Idaho and 350,000 therms in Oregon. In 2009 the goals for fist-
year energy savings are l,58l,000 therms in Washington/daho and 300,000 therms in Oregon. The
completion of the IRP analysis is the midpoint, not the end point, ofa larger reassessment of the
DSM resource portfolio. Furher evaluation is required to facilitate the development of program
plans and to incorporate them into an updated DSM implementation plan. Following detailed
investigation of the natural gas effciency technologies identified as cost effective resource options,
we wil incorporate these efforts into the larger Heritage Project ramp-up of Avista's energy-
efficiency efforts.
Results:
Washington/Idaho DSM energy savings achieved in 2008 totaled 1,888,061 therms, reflecting an
increase over our initial 2007 IRP goal. Oregon DSM energy savings achieved in 2008 totaled
287,476 therms, a shortfall from our 2008 goal of 350,000 therm. Additional detail around actual-
to-goal results is discussed in Appendix 4.1.
Action Item:
We wil fie our cost effectiveness limits based upon the avoided costs derived from this IRP
process.
9.4 Avista
2009 Natural Gas IRP Chapter 9 - Action Plan
Additionally, we are investigating the applicability of recently completed quantifications of electric
distribution capacity, the customer value of risk reduction and greenhouse gas emissions to
determe if similar quantifications are possible for our natual gas system.
Results:
Cost effectiveness limits were filed on June 9, 2008 with an effective date of July 1,2008.
We reviewed the value components of our electric avoided costs to determine if conceptually there
was applicability to our natural gas customers. We have initiated analysis to assess the potential
value that our customers place on the value of reduced volatility. This work continues. Regarding
quantifying the value customers ascribe to reduced distribution capacity and greenhouse gas
emissions, we concluded quantifications were not reliably determinable.
SUPPLY-SIDE RESOURCES
Action Item:
We wil continue to monitor several issues identified 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
. Large scale LNG activity
Results:
Through our various information sources (retainer services, industry publications, seminars, and
conversations with industry participants) we monitor ongoing developments on the above items. The
following are brief summaries of our curent assessments:
Tight production/productive capacity - The economic downtur has dramatically reversed this
previously very tight situation, producing significant excess capacity. Massive rig count
reduction in response to demand destruction has significant potential to overshoot when demand
stabilizes, triggering a retu to very tight conditions, prompting spikes in prices and volatility.
Pipeline constraints in our region - Several regional pipeline projects were proposed in early
2008. We monitor their progress and assess how they may fit into our resource strategy. We
currently have non-binding participation agreements on some ofthese projects.
Avista 9.5
Chapter 9 - Action Plan 2009 Natural Gas IRP
Pipeline expansions that move volumes away from our region - Rockies Express eastward
expansion has experienced some delays but wil ultimately facilitate more Rockies production to
reach East Coast markets.
Pipeline cost escalations - Much lower steel commodity prices and delayed/cancelled projects
appear to have reversed the cost-escalation trend in the near term.
Large scale LNG activity - Regional proposed projects continue to be challenged by regional
market prices that trade at a discount to other potential markets for LNG as well as complex
environmental issues.
Action Item:
We wil refine our analysis of acquiring or constructing resource alternatives to improve project cost
estimating, assessment of project feasibility issues, deterination of project siting issues and risks,
and improved accuracy of construction/acquisition lead times. Specifically, we wil fuher study
these issues with respect to satellite LNG, company owned LNG, pipeline expansions, distribution
system enhancements and storage facility diversification.
We wil explore creative, non-traditional resource possibilities to address our needle peaking
exposures with emphasis on potential structued trnsactions (e.g. transportation and storage
exchanges) with neighboring utilities and other market participants that leverage existing regional
infrastructure as an alternative to incremental infrastructue additions.
Results:
Given likely deferred resource needs, we have deferred any expenditure for formal cost and project
feasibility studies. We have collected information from publicly available sources and informal
inquiries. We also have gained insights on expansion rates/costs/timelines from our non-binding
participation in various proposed interstate pipeline projects. This information provides useful
proxies for project costs for use in resource modeling.
Although the easing of regional demand correspondingly eases the urgency for needle peaking
solutions in the near term we continue to evaluate the region's participants and their resources for
possible transactions. We have engaged in discussions with a neighboring utility regarding a
potential mutual assistance agreement around transport assets with dialogue continuing. We also
receive and solicit information on various structured product tranactions.
Action Item:
We wil continue to assess methods for captug additional value related to existing storage assets,
including methods of optimizing recently recalled releases while implementing its storage strategy of
providing balanced storage opportities. This includes exploring storage diversification options
including AECO and northern California facilities.
9.6 Avista
2009 Natural Gas IRP Chapter 9 - Action Plan
Results:
We periodically see solicitations for storage leasing. We evaluate the project economics and consider
our resource needs. In some cases, we have placed bids; however, our bids have not been selected.
We have entered into a month-to-month storage agreement at Clay Basin for interrptible service
which facilitates daily/short-term demand balancing for scheduling. Finally, we continue to engage
in intra-seasonal optimization tractions as market pricing conditions warrant to captue value for our
customers.
Action Item:
We wil continue to analyze natural gas procurement practices for strategy-enhancing ideas such as
basis diversification, storage injection/withdrawal timing and structured products.
Results:
Our annual procurement plan development process undertaken each fall provides a comprehensive
assessment of existing and potential new procurement practices and strategies. The result is a
targeted but flexible procurement plan that serves as a base to evaluate changing conditions
throughout the year and modify strategy and actions as necessary.
Action Item:
Since much of our supply comes from Canadian natual gas exports, the notion that this supply could
diminish significantly is of concern. We wil continue to monitor the discussion around diminishing
Canadian gas exports, looking for signals that indicate increased risk of disrupted supply over the
20-year planning horion.
Results:
We utilize multiple information sources to monitor and track developments on declining Canadian
exports including our retainer services, industry news subscriptions, semiars and market pricing
behavior. Historical information from the Energy Informtion Administration indicates a rebound in
export volumes in recent months following a decade low volume in June 2008. Lower oil sands
production in the face of sharp oil price declines is likely a significant factor in this near-term trend
reversaL. Longer term we see the oil/gas price relationship as a primary driver of Canadian domestic
natural gas demand and correspondingly, export volumes. Significant unconventional gas
discoveries in British Columbia have both the potential to reverse export declines with prolific
potential production or accelerate export declines if these volumes are diverted to oil sands
extraction in a high oil price environment.
In our 2009 IRP, we included sensitivity analysis on estimated price implications resulting from a
more severe decline in Canadian exports than included in our base price forecasts. We then included
a price adder in alternate demand scenarios. Additional detail is contained in Chapter 3 and
Appendices 3.6 and 3.7.
Avista 9.7
Chapter 9 - Action Plan 2009 Natural Gas I RP
2010.2011 ACTION PLAN
Key components for our 2010-201 I Action Plan include:
Action Item:
Monitor actual demand closely for indications of faster growth exceeding our forecasted growth to
respond aggressively to address potential accelerated resource deficiencies arising from our exposure
to "flat demand" risk. This includes researching and refining the evaluation of resource alternatives,
including implementation risk factors and timelines, updated cost estimates, and feasibility
assessments, targeting options for the service territories with nearer-term unserved demand
exposure.
Action Item:
Analyze actual use per customer data and DSM program results for indications of price elasticity
response trends that may have been influenced by evolving economic conditions. Investigate
contemporary analytical sources for informtion on natural gas price elasticity. Explore persuading
the AGA to update their analytical work and/or consider hiring a third party price elasticity study
including assessing interest of other utilities in pursuing a regional project.
Action/tern:
Continue our pursuit of cost effective demand-side solutions to reduce demand. In Washington and
Idaho, conservation measures are targeted to reduce demand by approximately 2,193,000 therms in
the first year. In Oregon conservation measures are targeted to reduce demand by approximately
303,000 therms in the fist year. These goals represent increases of 54 percent in Washington and
Idaho and 1 percent in Oregon from our prior 2007 IRP.
Action Item:
Research and engage a conservation consultant to perform an updated assessment of conservation
technical and achievable potential in our service terrtories prior to the next IRP.
Action Item:
As much of our supply comes from Canadian natural gas exports, the notion that this supply could
diminish significantly remains a concern. We wil continue to monitor the discussion around
diminishing Canadian gas exports looking for signals that indicate increased risk of disrupted supply
over the 20-year planning horion.
Action Item:
We believe our forecasting methodology is sound, cost effective and adequate but wil explore and
evaluate alternative and additional forecasting methodologies for potential inclusion in our next IRP.
Methodologies to be evaluated include statistical, non-statistical, quantitative, qualitative and terrain
overview approaches.
9.8 Avista
2009 Natural Gas I RP Chapter 9 - Action Plan
Action Item:
We wil meet regularly with Commission Staff members to provide information on market activities,
material changes to risk management programs, and significant changes in assumptions and/or status
of company activity related to the IRP or procurement practices.
Avista 9.9
Chapter 9 - Action Plan 2009 Natural Gas IRP
9.10 Avista
2009 Natural Gas IRP
CHAPTER 10 - GLOSSARY OF TERMS AND ACRONYMS
Achievable Potential
Represents a realistic assessment of expected energy savings recognizing and accounting for economic and
other constraints that preclude full installation of every identified conservation measure.
Annual Measures
Conservation measures that achieve generally uniform year round energy savings independent of weather
temperatue changes. Anual measures are also often called base load measures.
A vista
The regulated Operating Division of Avista Corp.; separated into north (Washington and Idaho) and south
(Oregon) regions; A vista Utilities generates, transmits and distributes electricity in addition to the
transmission and distribution of natural gas.
Backhaul
A transaction where gas is transported the opposite diection of norml flow on a unidirectional pipeline.
Base Load
As applied to natual gas, agiven demand for natual gas that remains fairly constant over a period of time,
usually not temperatue sensitive.
Base Load Measures
Conservation measures that achieve generally unform year round energy savings independent of weather
temperature changes. Base load measures are also often called annual measures.
Basis Differential
The difference in price between any two natul gas pricing points or time periods. One of the more common
references to basis differential is the pricing difference between Henry Hub and any other pricing point in the
continent.
British Thermal Unit (BTU)
The amount of heat required to raise the temperature of one pound of pure water one degree Fahrenheit under
stated conditions of pressure and temperatue; a therm (see below) of natual gas has an energy value of
100,000 BTUs and is approximately equivalent to 100 cubic feet of natual 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.
Compression
Increasing the pressure of natural gas in a pipeline by means of a mechanically driven compressor station to
increase flow capacity.
Conservation Measures
Installations of appliances, products or facility upgrades that result in energy savings.
Avista 10.1
Chapter 10 - Glossary of Terms and Acronyms 2009 Natural Gas IRP
Contract Demand (CD)
The maximum daily, monthly, seasonal or annual quantities of natual gas, which the supplier agrees to
fush, or the pipeline agrees to transport, and for which the buyer or shipper agrees to pay a demand charge.
Core Load
Fir delivery requirements of Avista, which are comprised of residential, commercial and firm industrial
customers.
Cost Effectiveness
The determination of whether the present value of the ther savings for any given conservation measure is
greater than the cost to achieve the savings.
CPI
Consumer Price Index, as calculated and published by the U. S. Departent of Labor, Bureau of Labor
Statistics
Cubic Foot (cQ
A measure of natural gas required to fill a volume of one cubic foot under stated conditions of temperatue,
pressure and water vapor; one cubic foot of natul gas has the energy value of approximately 1,000 BTUs
and 100 cubic feet of natual gas equates to one therm (see below).
Curtailment
A restriction or interption of natual gas supplies or deliveries; may be caused by production shortages,
pipeline capacity or operational constraints or a combination of operational factors.
Dekatherm
Unit of measurement for natual gas; a dekatherm is 10 therm, which is one thousand cubic feet (volume) or
one million BTUs (energy).
Demand-Side Management (DSM)
The activity pursued by an energy utilty to infuence its customers to reduce their energy consumption or
change their patters of energy use away from peak consumption periods.
Demand-Side Resources
Energy resources obtained through assisting customers to reduce their "demand" or use of natual gas. Also
represents the aggregate energy savings attained from installation of conservation measures.
Dth
Unit of measurement for natural gas; a dekatherm is LO therm, which is one thousand cubic feet (volume) or
one millon BTUs (energy).
External Energy Effciency Board
Also known as the "Triple-E" board, this non-binding exterl oversight group was established in 1999 to
provide A vista with input on DSM issues.
Externaliies
Cost and benefits that are not reflected in the price paid for goods or services.
10.2 Avista
2009 Natural Gas IRP Chapter 10 - Glossary of Terms and Acronyms
Federal Energy Regulatory Commission (FERC)
The government agency charged with the regulation and oversight of interstate natual gas pipelines,
wholesale electric rates and hydroelectric licensing; the FERC regulates the interstate pipelines with which
A vista does business and determines rates charged in interstate transactions.
Firm Service
Service offered to customers under schedules or contracts that anticipate no interptions; the highest quality
of serice offered to customers.
Force Majeure
An unexpected event or occurence not within the control of the parties to a contract, which alters the
application of the terms of a contract; sometimes refered to as "an act of God; " examples include severe
weather, war, strikes, pipeline failure and other similar events.
Forward Price
The future price for a quantity of natual gas to be delivered at a specified time.
Gas Transmission Northwest (GTN)
A subsidiary of TransCanada Pipeline which owns and operates a natual gas pipeline that rus from the
Canada/USA border to the Oregon/Californa border. One of the six natul gas pipelines Avista transacts
with directly.
Geographic Information System (GIS)
A system of computer software, hardware and spatially referenced data that allows information to be modeled
and analyzed geographically.
Global Insight, Inc.
A national economic forecasting company.
Heating Degree Day (HOD)
A measure of the coldness of the weather experienced, based on the extent to which the daily average
temperatue falls below 65 degrees Fahrenheit; a daily average temperatue 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 also the trading hub for the New York Mercantile Exchange (NYMX).
Jnjection
The process of putting natual gas into a storage facility; also called liquefaction when the storage facilty is a
liquefied natural gas plant.
Integrity Management Plan
A federally regulated program that requires companies to evaluate the integrity of their natural gas pipelines
based on population density. The program requires companies to identify high consequence areas, assess the
risk of a pipeline failure in the identified areas and provide appropriate mitigation measures when necessary.
Avista 10.3
Chapter 10 - Glossary of Terms and Acronyms 2009 Natural Gas I RP
Interruptible Service
A service of lower priority than fim serice offered to customers under schedules or contracts that anticipate
and permit interptions on short notice; the interption happens when the demand of all firm customers
exceeds the capability of the system to continue deliveries to all of those customers.
IPUC
Idaho Public Utilities Commssion
IRP
Integrated Resource Plan; the document that explain Avista's plans and preparations to maintain suffcient
resources to meet customer needs at a reasonable price.
Jackson Prairie
An underground storage project jointly owned by A vista Corp., Puget Sound Energy, and NW; the project is
a natually occuring aquifer near Chehalis, Washington, which is located some 1,800 feet beneath the surface
and capped with a very thick layer of dense shale.
Liquefaction
Any process in which natul gas is convered from the gaseous to the liquid state; for natural gas, this process
is accomplished through lowering the temperatue of the natual gas (see LNG).
Liquefied Natural Gas (LNG)
Natual gas that has been liquefied by reducing its temperatue to minus 260 degrees Fahrenheit at
atmospheric pressure.
Linear Programming
A mathematical method of solving problems by means of linear fuctions where the multiple variables
involved are subject to constraints; ths method is utilized in the SENDOUTiI Gas ModeL.
Load Duration Curve
An array of daily send outs observed that is sorted from highest send out day to lowest to demonstrate both
the peak requirements and the number of days it persists.
Load Factor
The average load of a customer, a group of customers, or an entire system, divided by the maximum load; can
be calculated over any time period.
Local Distribution Company (LDC)
A utilty that purchases natual gas for resale to end-use customers and/or delivers customer's natural gas or
electricity to end users' facilities.
Looping
The constrction of a second pipeline parallel to an existing pipeline over the whole or any part of its length,
thus increasing the capacity of that section of the system.
MCF
A unit of volume equal to a thousand cubic feet.
10.4 Avista
2009 Natural Gas I RP Chapter 10 - Glossary of Terms and Acronyms
MDQ
Maximum Daily Quantity.
MMbtu
A unit of heat equal to one milion British thermal unts (BTUs) or 10 therms. Can be used interchangeably
with Dth.
National Energy Board
The Canadian equivalent to the Federal Energy Regulatory Commssion (PERC).
National Oceanic Atmospheric Administration (NOAA)
Publishes the latest weather data; the 30-year weather study included in this IRP is based on this information.
Natural Gas
A natually occuring miture of hydrocarbon and non-hydrocarbon gases found in porous geologic
formations beneath the earth's surface, often in association with petroleum; the principal constituent is
methane, and it is lighter than air.
New York Mercantile Exchange (NYMEX)
An organization that facilitates the trading of several commodities including natual gas.
Nominal
Discounting method that includes inflation.
Nomination
The scheduling of daily natual gas requirements.
Non-Coincidental Peak Demand
The demand forecast for a 24-hour period for multiple regions that includes at least one peak day and one
non-peak day.
Non-Firm Open Market Supplies
Natural gas purchased via short-term purchase arrangements; may be used to supplement firm contracts
during times of high demand or to displace other volumes when it is cost-effective to do so; also referred to as
spot market supplies.
Northwest Pipeline Corporation (NWP)
A principal interstate pipeline serving the Pacific Northwest and one of six natual gas pipelines A vista
transacts with diectly. NW is a subsidiary of The Wiliams Companies and is headquartered in Salt Lake
City, Utah.
NOVA Gas Transmission (NOVA)
See TransCanada Albera System
Northwest Power and Conservation Council (NPCC)
A regional energy planning and analysis organization headquartered in Portland, Ore.
Avista 10.5
Chapter 10 - Glossary of Terms and Acronyms 2009 Natural Gas IRP
OPUC
Public Utilty Commssion of Oregon
Peak Day
The greatest total natual gas demand forecasted in a 24-hour period used as a basis for planning peak
capacity requirements.
Peak Day Curtailment
Curailment imposed on a day-to-day basis during periods of extremely cold weather when demands for
natural gas exceed the maximum daily deliver capabilty of a pipeline system.
Peaking Capacity
The capability of facilities or equipment normally used to supply incremental natual gas under extreme
demand conditions (i.e. peaks); generally available for a limited number of days at this maximum rate.
Peaking Factor
A ratio of the peak hourly flow and the total daily flow at the city-gate stations used to conver daily loads to
hourly loads.
Prescriptive Measures
Avista's DSM tariffs require the application of a formula to deterne customer incentives for natual gas-
effciency projects. For commonly encountered effciency applications that are relatively unform in their
characteristics the utility has the option to define a standardied incentive based upon the typical application
of the efficiency measure. This standardized incentive takes the place of a customied calculation for each
individual customer. This streamlining reduces both the utility and customer admnistrative costs of program
participation and enhances the marketability of the program.
Psig
Pounds per square inch gauge - a measure of the pressure at which natual gas is delivered.
Rate Base
The investment value established by a regulatory authority upon which a utility is permitted to earn a
specified rate of retu; generally this represents the amount of proper used and useful in serice to the
public.
Real
Discounting method that excludes infation.
Resource Stack
Sources of natural gas inastructue or supply available to serve Avista's customers.
Seasonal Capacity
Natual gas transporttion capacity designed to serice in the winter months.
Sendout
The amount of natual gas consumed on any given day.
10.6 Avista
2009 Natural Gas I RP Chapter 10 - Glossary of Terms and Acronyms
SENDOUTI
Natual gas planning system from Ventix; a linear programming model used to solve gas supply and
transporttion optimization questions.
Service Area
Teritory in which a utility system is required or has the right to provide natual gas servce to ultimate
customers.
Spot Market Gas
Natural gas purchased under short-term agreements as available on the open market; prices are set by market
pressure of supply and demand.
Storage
The utilization of facilities for storing natual gas which has been transferred from its original location for the
purposes of serving peak loads, load balancing and the optimization of basis differentials; the facilities are
usually natural geological reservoirs such as depleted oil or natual gas fields or water-bearing sands sealed on
the top by an impermeable cap rock; the facilties may be man-made or natual caverns. LNG storage
facilities generally utilze above ground insulated tank.
Tariff
A published volume of regulated rate schedules plus general terms and conditions under which a product or
service wil be supplied.
TF.I
NW's rate schedule under which A vista moves natural gas supplies on a fim basis.
TF.2
NW's rate schedule under which A vista moves natual gas supplies out of storage projects on a firm basis.
Technical Advisory Committee (TAC)
Industry, customer and regulatory representatives that advise A vista during the IRP planning process.
Technical Potential
An estimate of all energy savings that could theoretically be accomplished if every customer that could
potentially install a conseration measure did so without consideration of market bariers such as cost and
customer awareness.
Therm
A unit of heating value used with natural gas that is equivalentto 100,000 British thermal units (BTU); also
approximately equivalent to 100 cubic feet of natural gas.
Town Code
A town code is an unincorporated area within a county and a municipality within a county sered by A vista
natual gas retail services.
Avista 10.7
Chapter 10 - Glossary of Terms and Acronyms 2009 Natural Gas I RP
TransCanada Alberta System
Previously known as NOVA Gas Transmission; a natual gas gathering and transmission corporation in
Alberta that delivers natual gas into the TransCanada BC System pipeline at the Albertalritish Columbia
border; one of six natural gas pipelines A vista transacts with directly.
TransCanada BC System
Previously known as Albera Natual Gas; a natual gas transmission corporation of British Columbia that
delivers natural gas between the TransCanada-Albert System and GTN pipelines that ru from the
Albertalritish Columbia border to the United States border; one of six natual gas pipelines Avista transacts
with directly.
Transportation Gas
Natual gas purchased either directly from the producer or through a broker and is used for either system
supply or for specific end-use customers, depending on the transportation arrangements; NW and GTN
transporttion may be fim or interptible.
Tuscarora Gas Transmission Company
Tuscarora is a subsidiary of Sierra Pacific Resources and TransCanada; this natual gas pipeline runs from the
Oregon/California border to Reno, Nevada; one of the six natual gas pipelines Avista transacts with directly;
Vaporization
Any process in which natual gas is convered from the liquid to the gaseous state.
Weighted Average Cost of Gas (WACOG)
The price paid for a volume of natural gas and associated transporttion based on the prices of individual
volumes of natual gas that make up the total quantity supplied over an established time period.
Weather Normalization
The estimation of the average annual temperatue in a tyical or "norml" year based on examination of
historical weather data; the normal year temperatue is used to forecast utility sales revenue under a procedure
called sales normalization.
Weather Sensitive Measures
Conservation measures whose energy savings are influenced by weather temperatue changes. Weather
sensitive measures are also often refered to as winter measures.
Winter Measures
Conservation measures whose energy savings are influenced by weather temperatue changes. Winter
measures are also often referred to as weather sensitive measures.
Withdrawal
The process of removing natual gas from a storage facility, making it available for deliver into the
connected pipelines; vaporization is necessary to make withdrawals from an LNG plant.
WUTC
Washington Utilities and Transportation Commssion.
10.8 Avista