200912302008IRP Appendices.pdf

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December 31,2009
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2009 Natural Gas IRP - APPENDICIES
AVISTA CORPORATION RECEI !"'.~ ¡;...~
2009 NATURAL GAS 2069 DEC 30 AM 9: 54
INTEGRATED RESOURCE PLAN, _ lOAtH) ::5.12";;',
APPENDICIES J i ILlTlbS CUMM1SSIOi\J
TABLE OF CONTENTS
Appendix 1.1 TAC Members ............... ......... ........................ ......................................................Page 1
Appendix 1.2 Work Plan .................................... ............................ .................................................... 5
Appendix 2.1 IRP Regulatory Guidelines ......... ............................................................................... 11
Appendix 2.2 Comments & Responses to 2009 DRAFT IRP ......... .... ............................................. 29
Appendix 3.1 Customer Forecasts..................................................................................................... 45
Appendix 3.2 Customer Forecasts Data ............................................................................................57
Appendix 3.3 Demand Coefficients .................................................................................................. 71
Appendix 3.4 Heating Degree Day (HDD) Data...............................................................................85
Appendix 3.5 Global Waring Summary and Graphs......................................................................91
Appendix 3.6 Alternate Demand Scenarios Summary of Assumptions.......................................... 107
Appendix 3.7 Alternate Demand Scenarios Descriptions............................................................... 1 13
Appendix 3.8 Anual and Peak Day Demand Data ........................................................................123
Appendix 3.9 Anual Demand by Region Before and After DSM................................................. 131
Appendix 3.10 Detail Demand Data.................................................................................................141
Appendix 4.1 DSM Implementation and Operations ...................................................................... 159
Appendix 4.2 Conservation Measures Detail ......................................... ......................................... 171
Appendix 4.3 SENDOU~ selected Conservation Measures ......................................................... 179
Appendix 4.4 Environmental Externalities......................................................................................223
Appendix 5.1 Curent Transportation Rates.................................................................................... 229
2009 Natural Gas IRP - APPENDICIES
Appendix 5.2 Alternate Supply Scenarios Summary of Assumptions ............................................233
Appendix 6.1 Monthly Price Data...................................................................................................237
Appendix 6.2 General Assumptions ........... ..................... ......................................... ....................... 251
Appendix 6.3 Supply Side Resource Options ................................ .... ...................................... ....... 259
Appendix 6.4 Avoided Cost DetaiL........................................................................................... ..... 265
Appendix 6.5 SENDOU~ Model Diagram ............................................................. ...................... 283
Appendix 7.1 Sensitivities, Scenarios, Simulations and Portfolios List ..................... .................... 287
Appendix 7.2 Demand and Expected Resource Graphs ............................................................. .... 291
Appendix 7.3 Peak Day Demand Served and Unserved Table ....................................................... 299
Appendix 7.4 Load Duration Cure Graphs (High and Low Growth Cases) ................................ .307
Appendix 7.5 Total Cost By Portfolio..................... ................... ..................................................... 31 1
Appendix 8.1 Distrbution System Modeling..................................................................................319
2009 Natural Gas IRP - APPENDICIES
APPENDIX 1.1
TAC MEMBERS
Appendix 1.1
20091RP TAC Member List
Bob Jenks
Bruce Folsom
Carrie Dolwick
Chau Lau
Dan Kirschner
Dave Allred
Dave Sloan
David Nightingale
Deborah Reynolds
Greg Rahn
Gurvinder Singh
Inara Scott
Joe Ross
Jon Powell
Kelly Irvine
Ken Ross
Kerry Shroy
Ken Zimmerman
Kevin Christie
Lea Daischel
Linda Gervais
Lisa Gorsuch
Lori Hermanson
Lynn Kittilson
Mark Sellers-Vaughn
Matt Elam
Megan Clark
Paula Pyron
Randy Barcus
Rich Cowan
Steven Johnson
Steven Simmons
Terrence Browne
Terri Carlock
Terry Morlan
Vonda Novak
Name Organization
Oregon CUB
Avista
NW Energy
Cascade Natural Gas Company
Northwest Gas Association
Northwest Pipeline
Gas Transmission Northwest
WUTC
WUTc
Avista
Puget Sound Energy
Northwest Natural
Gas Transmission Northwest
Avista
Avista
Terasen Gas
Avista
OPUC
Avista
Washington Attorney General's Office
Avista
OPUC
Avista
OPUC
Cascade Natural Gas Company
IPUC
Northwest Gas Association
Northwest Industrial Gas Users
Avista
Gas Transmission Northwest
WUTC
Northwest Natural
Avista
IPUC
Northwest Power and Conservation Coucil
WUTC
3
2009 Natural Gas IRP - APPENDlclES
APPENDIX 1.2
WORK PLAN
5
.J~JII'STA.
A vita Corpration 20 Natu Gas Intete Resurce Pl
Work Plan
IRWork Pl Requirements
Section 480-90238 (4), of the natu ga Integrte Resour Plan ("IR") rules. speif
reuiments for the IR Work Plan:
Not latr than twelve month prior to the due date of a pla. the utity must provìde a
work plan for inorm commssìon revìew. The work plan must outle the content
of the ìntegrte resour plan to be develope by the utity and the metod for
assesìng potential reur.
Addtionaly. Section 480-90238 (5) of the WAC sta:
The work pla must outle the tig and extent of public pacipaton.
Overvew
Ths Work Pla outles.the pro Avìsta wil follow to complet its 200 Nat Gas
IR by Deember 31. 200. Avista use a public proess to obta tehncal experte
and gudacethughout th plang period vì Techncal Advìsory Commtt (l AC)
meetigs. The TAC provìde ìnput ìnto ths work plan and wi be provìdìg ìnput ìnto
asumptions, scnaros. and modelig tehnques.Pr
The 200 IR prs wi be simar to th use to prouce the prevìously publish
plan. Avìsta wil use SENOUTtl (a PC bas liea progrng model widely use
to solve na gas supply and trporttion option questions) to develop the risk
adjuste leat-cost resou mi for the 20 yea plang peod.
For ths plan. A vìsta ìnteds to ìncorprate acon plan ìtems identied ìn th 200
Nat Gas IR ìncludìg regìona demad modelig, weaer stada evaluation,
Canadan nat gas import monìtorlg, and anyze (usìng SENUTtl and
VecorGasTM restic alteve. situations ìn whìch the compay may have to opera
durg the next 20 yea. VectoiG™ ìs the Monte calo. risk assessment elemet of
SENUTCi whìch evaluats the cost and reliabilty impac of maket price and demd
volatty.
7
Th plan wil contiue to ìnclude demad analysìs. detaed demand sìde maagement
progr analysìs and avoìded cost dermation. distrbution plang. exìstig and
potential supply-side reour anysìs and reure ìntegron. Furer detas about
Avìsta's proess for determg the risk adjuste leat-cot reur mi ìs shownìn
Exbìt 1.
Tiel
The followìg is Avìsta's TEATI 200 Nat Ga IR tielie:
· Deber 29, 20 - Work Plan fied with wuc
· Apri throug July 20 - Technca Advìsory Commttee meetigs (exac
meeg dats subject to c1ue). Meeg topìcs wil ìnclude:
· Demad Foret & Demad-Side Maement- Apr 28
· Dìstrbution Plang & SupplylItrct - May 19
· SENUT~ Prliminary Output Results and Potential Cas Discussion-
June 16
· SENUT~ and VectorG™ reults - July 16
· September I, 20 - Dra of IR docent to TAC
· Ocber 30,20 - Comments on dr due bak to A vìsta
· November 6, 20 - TAC fial review meetig (n necsar)
. Deber 31, 20 - File finalize IR doent
8
Ga Staonforg
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reew
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2009 Natural Gas IRP - APPENDlclES
APPENDIX 2.1
IRP REGULATORY GUIDELINES
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2009 Natural Gas IRP - APPENDICIES
APPENDIX 3.1
CUSTOMER FORECASTS
45
2009 Natural Gas IRP
APPENDIX 3.1 - CUSTOMER FORECASTS
OVERVIEW
Avista presented their 2009 Natural Gas Demand Forecast to the Techncal Advisory Commttee (TAC) in
April 2009. What follows in narrative is the process of preparing the base customer growth forecast. The first
step is a framework forecast of the national economy, followed by regional economic forecasts consistent
with the national outlook. The employment and population forecasts are the key drivers for the natual gas
customer forecast.
NATIONAL ECONOMIC OUTLOOK
A vista has contracted for national economic forecasts with Global Insight, Inc. for over two decades. The
Spring 2008 twenty-five year long term forecast was used as the basis for the 2009 effort; the Spring 2009
county forecast update took into account the depth of the curent recession but was largely unchanged after
the anticipated economic recovery. The following narative has Avista remarks and Global Insight forecasts
(used with permssion) which are consistent with the presentation at the TAC in April 2009, with a focus on
the near term national outlook.
The U.S. Gross Domestic Product is expected to rebound to levels in 2010 to the 2.5 to 3.0 percent range after
the severe recession in 2008 and 2009. Longer term the rate settles in at 2.6 percent.
REGIONAL ECONOMIC OUTLOOK
A vista serves natual gas in eastern Washington, northern Idaho, and in portions of five counties in Oregon.
The principal county in Washington is Spokane, while in Idaho there are two counties; Kootenai and Bonner
are barometers of service area growth. Kootenai County includes Coeur d Alene, Post Falls, Hayden and a
host of smaller municipalities and Bonner County is anchored by Sandpoint. The primary cities in Spokane
County are the City of Spokane, City of Spokane Valley and Libert Lake. In Oregon, the counties (principal
city) of Jackson (Medford), Josephine (Grants Pass), Douglas (Roseburg), Klamath (Klamath Falls) and
Union (La Grande) round out the service terrtory. The map below shows the breadth of the service area.
..au ....~'
š:-;==::::'æ==~--.-
Avista 3.1.147
Appendix 3.1 - Customer Forecasts 2009 Natural Gas IRP
Global Insight, Inc. has been providing county-level forecasts to A vista for several years. These forecasts are
consistent with and driven by their national forecast.
The economic concepts provided are forecast forward for 30 years. We report below forecast data ending in
the year 2030, the twenty-year horizon IRP horizon.
Overall, the results of the economic forecasts suggest the following impacts on Avista's customer growth:
Near term the weakness in constrction wil be mirrored with slow customer growth, while longer term,
underlying employment and population growt wil drve customer growth.
The following table indicates a listing of 21 counties served with natual gas by A vista. We purchased
economic forecasts for the 15 principal counties.
Table of Counties Served (All or Portions)
Washington
Adams*
Asotin
Franklin*
Grant*
Klickitat*
Lincoln*
Skamania*
Spokane
Stevens
Whitman
Idaho
Benewah
Bonner
Boundary
Latah
NezPerc
Shosone
Oregon
Douglas
Jackson
Josephine
Klamath
Union
*Did not purchase economic data, few customers served
The charts that follow are the actul employment, population, population age 65 and over, number of
households and personal income forecasts used to produce the natural gas customer forecasts by state, by
customer class (residential, commercial and industrial) and by rate schedule (firm - small, medium and large-
sized customers).
Although the forecasts are prepared in detail by county, the chars aggregate the data by State.
3.1.2 Avista
48
2009 Natural Gas IRP Appendix 3.1 - Customer Forecasts
The first pair of charts is Non-Farm Employment. Durng the last decade, fairly consistent growth in jobs was
observed except during recession periods in 2000-01 and at the present time.
The twenty year average compounded growth rate in jobs for Idaho Counties was 2.6 percent from 1990-
2010, and is forecast to be 2.1 percent for the périod 2010-2030. Washington Counties were 1.7 percent from
1990-2010, and is forecast to be 1.4 percent for the period 2010-2030. And Oregon Counties were 0.9 percent
from 1990-2010, and is forecast to be 1.2 percent for the period 2010-2030.
Idaho & Washington Non-farm Employment
500 ~~-
Actual Forecast
450
400
350
300
250
200
150
I
100
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!0
i '"'"~'":g '"'"~'"co '"'"~'"co '"'"~'"co '"'"g:'"'"'"'"'"'"'"-----'"'"'"'"'"..
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'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"-----'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"
I_IdahO Countie Emp..Totl Nonfrm (Thusands)DWashington Countles Emp.-Totl Nonfarm (Thousands)
I
Oregon Non-farm Employment
250
Actual Forst
200
I
150 i
100
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'"'"~'"co '"'"~'"co ~~:i '"co '"'"~'"co '"'"'"'"'"'"'"'"'"'"'"--'"'"'"'"'"..~~~'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"--'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"
I
. Douglas Emp..Total Nonfrm (Thousands). Jackson Emp..Total Nonfarm (Thousands)
I
o Josephine Emp.-Total Nonfarm (Thousands)o Klamath Emp..Totl Nonfrm (Thousands)
. Union Emp.-Total Nonfarm (Thusands)
Avista 3.1.3
49
Appendix 3.1 - Customer Forecasts 2009 Natural Gas IRP
Next is resident population. The twenty year average compounded growth rate in population for Idaho
Counties was 2.2 percent from 1990-2010, and is forecast to be 1.5 percent for the period 2010-2030.
Washington Counties were 1.3 percent from 1990-2010, and is forecast to be 1.0 percent for the period 2010-
2030. And Oregon Counties were 1.1 percent from 1990-2010, and is forecast to be 1.0 percent for the period
2010-2030.
Idaho & Washington Service Area Population
1,200 'c~---
L
1,000
800 "PI l
~600 l
400
i
200 Ii
0 ..'"..co co ..'"..co co ..'":i ~:2 ..'"..co co ..'"!'"'"'"Q ........--N N N N N '"~~~~Q ..........Q Q Q Q Q ....Q Q ..N N N N N N N '"N N N N N N N N
I
· WhRm'~!l!ErStevens R Gusands)_Asotin R: =,rc: 0 o::tlaLah Re n u ds)
Oregon Service Area Population
700
j
600
500
400 i
300
200 j
100 .
0 ..N ..co co ..N ..co co ~~:i ~:2 ..N ..co co ..'"'"'"'"'"Q ........N N N N N '"~~:!~~Q Q ........Q Q Q Q Q Q Q Q Q QNNNNNNNNNNNNNNNN
I · Douglas Resident Population (Thousands)
. Jackson Resident Population (Thousands)
I
o Josephine Resident Population (Thousands)IJ Klamath Resident Population (Thousands)
. Union Resident Population (Thousands)
3.1.4 Avista
50
2009 Natural Gas IRP Appendix 3.1 - Customer Forecasts
The next pair of charts is persons 65 years and over. The twenty year average compounded growth rate in
persons 65 and over for Idaho Counties was 3.1 percent from 1990-2010, and is forecast to be 3.1 percent for
the period 2010-2030. Washington Counties were 1.8 percent from 1990-2010, and is forecast to be 2.9
percent for the period 2010-2030. And Oregon Counties were 2.4 percent from 1990-2010, and is forecast to
be 2.8 percent for the period 2010-2030.
Idaho & Washington Population Age 65 & Over
250
200 iI
I
iI150i
~C~.~0.c..100
I
50
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0 i
'"N ;¡cø GO '"N ..cø GO ~~:i ~~'"N ..cø GO l''"'"'"'"'"'"'"'"'"N N N N N~'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"'".- .- .- .-N N N N N N N N N N N N N N N N
~daho Counti.. Pop, Ag 65 and Older (Thousands)DWashington Counties Pop, Ag 65 and Older (Thousands) I
I
Oregon Population Age 65 and Over
200
180
160
140
120
100
80
60
40 i
I
20 i
0
'"N ..cø GO '"N ..cø GO ~N :i cø :!'"N ..cø GO '"'"'"'"'"'"'"'"'"'"'"~~N N N N N '"~~~~~'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"'"N N N N N N N N N N N N N N N N
I · Douglas Pop, Age 65 and Older (Thousnds)
. Jactson Pop, Age 65 and Older (Tousands)
I
o Josephine Pop, Ag 65 and Older (Tousands)IJ Klati Pop, Age 65 and Older (Thousands)
. Union Pop, Ag 6S and Older (Thousands)
Avista 3.1.5
51
Appendix 3.1 - Customer Forecasts 2009 Natural Gas IRP
The next economic variable used in the preparation of Avista's forecast is number of resident households in
the service area. The household growth rate for Idaho Counties was 2.6 percent from 1990-2010, and is
forecast to be 1.6 percent for the period 2010-2030. Washington Counties were 1.4 percent from 1990-2010,
and is forecast to be 1.1 percent for the period 2010-2030. And Oregon Counties were 1.5 percent from 1990-
2010, and is forecast to be 1.2 percent for the period 2010-2030.
Idaho & Washington Households
500
450
400
350
300
250
200
150
100
50
0 I
....;i '":l ......'"CI ~~;!~:!......'"CI ..'"'"'"......................'"~~'"~................................--................................L I . Idaho Countie Households (Tousands)OWashlngtn Counties Households (Tousands)I
Oregon Households
300.00
250.00
200.00
150.00
i
100.00
I 50.00
I
0.00 ......'"CI ....;i '"CI ....;!~:!......'"CI ..'"'"'"'"'"........--............~~~~'"................................-................................
I · Douglas Households (Thousands)
. Jackson Households (Thousands)o Josphine Housholds (Thousands) I
o Klamat Houseolds (Thousands). Union Hou..hoda (Thousnds)
3.1.6 Avista
52
2009 Natural Gas IRP Appendix 3.1 - Customer Forecasts
REFERENCE CASE FORECASTS OF CUSTOMERS SERVED
Reference case customer forecasts for residential customers are consistent with our economic forecasts. The
relationship has been changing over the last decade, and the forecasts take into account the most recent trends.
As shown on the next figue, the number of residential customers per household grew rapidly between 1997
and 2001, while it has slowed durng the present economic downtu. About half of the growth between 1997
and 2001 was due to fuel switching of existing homes from other heating sources to natual gas. Although
fuel switching continues to occur, today it represents only 15 percent of customer additions.
To produce the customer forecast, we look at recent trends in housing constrction and the likelihood those
homes will be served with natual gas. For example, in Washington, the number of single family homes being
constructed has declined, with apartent dwellngs taking a larger market share. Multi-family housing has
traditionally been served with electricity only, limiting the number of available dwellings for natural gas
service.
However, in the areas outside of the urban core of Spokane, including the rest of Washington, much ofIdaho
and Oregon, housing constrction activity has maintained very high levels of single family homes, whether
detached-style homes on individual lots or attached-style homes, like duplexes, townomes, or
condominiums. This market is traditionally served with natural gas water and space heat, and many of these
homes now are being built with natual gas clothes drers, gas ranges and ovens and natural gas fire places.
Because growth management laws are in place in all of Avista's natual gas service areas, we assume these
constrction trends in the urban growth areas wil be served with natural gas, and do not anticipate any
switching to electrcity. We have an effort under way to encourage multi~family builders, who tyically are
building apartents for rental puroses, to include natural gas appliances, but this forecast does not assume
this effort wil lead to a change in constrction practices. We wil continue to monitor activity in the multi-
family housing segment.
The forecast assumes that the trends of the last five years continue into the future, adjusted for the shar
building cycle presently under way and based on the household forecasts provided by Global Insight. The
next char shows the number of residential customers per household. The reason this ratio is increasing in the
forecast period is because the ratio of homes being added is higher than the curent ratio. This is largely
driven by the assumption of nearly 100 percent of new homes having at least one natual gas servce. Also,
outside of the Medford and Spokane metropolitan areas, the multi-family construction market is very small.
The only exception would be in Pullman and Moscow where growth in unversity enrollments is leading to
apartment construction activity in those special areas. To a lesser extent, La Grande, Klamath Falls, and
Ashland are seeing student growt-drven apartent constrction, but to a small extent.
Avista 3.1.7
53
Appendix 3.1 - Customer Forecasts 2009 Natural Gas IRP
Residential Customers per Household Trends by State
80%,-~..--....~~~~~~~
r/..~~---~~~
75%
70%
65%
60%
55%
50%
45%
40%
35%
30%= ¡ I g g g 8 g g § ggg ~ ~ ~ ~; ~ &~ ~ &m fi š Š š š B S ~;;_ _ _ N N N N N N N N NN N N N N N N N N N N N N N N N N N N ~~ ~~ .~
1-. Washington -- Oregon ..Idaho I
The residential customer forecast is the product of the customers-per-household forecast and the household
forecast from Global Insight.
Residential Customers Served
Average Duñng the Year-All Residential Customers are Core Load
500,000
I
450,000 I
400,000
350,000
l!300,000
..E 250,000~::U 200,000
150,000
100,000
1t
i
50,000
0
g¡
oo ..co
fi ~~;i :g ..r-oo ..co ....;!....r-oo ..co ¡;~..š ....r-oo ..S:i :i ~~~~g ¡;¡;¡¡l!l!l!l!S S l!---l'l'....l'..l'~ .~l'l'l'..l'l'........ ........
I_washington .Oreon . Idaho I
Core commercial customers served are based on job forecasts for each county, as well as the number of
residential customers. The figue below shows ratio of non-farm workers per commercial customer. The
previous ten years show declines in numbers of workers early in the period, followed by a buildup until
recently. This build up is due to an increase in the number of big-box retail stores, which have moved from
the very large metro areas into the smaller metro areas served by Avista. We believe that build out is largely
complete. We do not anticipate new large mall-tye complexes wil be built in to any great extent. Therefore,
in a few more years we expect the number of workers will again begin to decline as smaller shops and strip-
mall developments fill into the neighborhood developments. We have taken into account the known shopping
areas that have been either permtted or have a high probability of being built in the near term forecast. As
3.1.8 Avista
54
2009 Natural Gas IRP Appendix 3.1 - Customer Forecasts
shown in the char, although declines are forecast, they are very modest and reflect the particular
characteristics of the existing mix of commercial developments in each state.
Non-Farm Employment per Commercial Customer Trends by State
20
~..'"'-~~~.~-----\--~
\.\----~--~'- --
~~i ----
19
18
17
16
15
14
13
12
i;::..g ~i:s ....g lõ l!g ~t!.......,..~....¡;i:i:è'....l:ii gi lõ;~..~~~~~N N N~~~~..~..~~..~~~~~~~~~~........~~N N N N N N N N N N N N N
I-+ Washington -"Oreon ..Idaho I
The commercial customer forecast is based on job forecasts multiplied times the forecasted ratio of workers
per customer as described above.
Core Commercial Customers Served
Average During the Year
60,000
50,000
40,000
I!"e 30,000.s
III
.."(J
20,000
10,000
0 ~~~O~N~.~~~~~O NM.~~~~mOrNM.~~~mmommmoooooooooo ~ ~_r___NNNNNNNNNNM~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 2 2 2 2 ~ ~ 2 2 2 ~ 2 2 2 ~ 2 ~ 2. ~. 2 ~ 2 ~ 2
I_waShingtn .Oregon . Idaho I
Core industral customers served are based on manufactung job forecasts for each county. The number of
manufactung workers is expected to be growing slowly over the forecast period, leading to little change in
the number of core firm industrial customers.
Avista 3.1.9
55
Appendix 3.1 - Customer Forecasts 2009 Natural Gas IRP
Core Industrial Customers Served
Average During the Year
350
300
250
l!200..
E
~"150U
100
50
0
:;!co g g ~~I :g ~~i ~
0 N ....'"..r-..co 0 ii N
~
..
~~~~~~~~l're re ¡;re ¡;¡;¡;¡;¡;¡;2 s 2NNNNNNNNNNN
I_washingtn .Oreon . Idaho I
3.1.10 Avista
56
2009 Natural Gas IRP - APPENDlclES
APPENDIX 3.2
CUSTOMER FORECASTS DATA
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2009 Natural Gas IRP - APPENDlclES
APPENDIX 3.3
DEMAND COEFFICIENTS
71
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Appendix 3.3 - WAllO Base Coeffcient Calculation
A A t 10 db Ci~erage c ua ernan )y ass
Month
Year Data 7 8 Grand Total
2005 Average of Res Demand 11,098 10,607 10,852
Average of Com Demand 7,729 8,406 8,067
AveraQe of Ind Demand 991 1,001 996
2006 Average of Res Demand 9,988 10,513 10,250
Average of Com Demand 6,956 8,331 7,643
AveraQe of Ind Demand 892 992 942
2007 Average of Res Demand 10,032 10,433 10,232
Average of Com Demand 6,987 8,267 7,627
Average of Ind Demand 896 984 940
2008 Average of Res Demand 10,684 10,495 10,590
Average of Com Demand 7,441 8,317 7,879
AveraQe of Ind Demand 954 990 972
Total Average of Res Demand 10,450 10,512 10,481
Total AveraQe of Com Demand 7,278 8,330 7,804
Total Average of Ind Demand 933 992 962
A A tiC t C tb CI~erage c ua us orner oun )~ass
Month
Year Data 7 8 Grand Total
2005 Average of Res Cust 179,140 179,447 179,294
Average of Com Cust 20,450 20,427 20,439
Average of Ind Cust 263 260 262
2006 Average of Res Cust 185,182 185,455 185,319
Average of Com Cust 20,748 20,856 20,802
Averaoe of Ind Cust 246 242 244
2007 Average of Res Cust 189,577 190,087 189,832
Average of Com Cust 21,291 21,336 21,314
AveraQe of Ind Cust 244 241 243
2008 Average of Res Cust 193,667 193,643 193,655
Average of Com Cust 21,847 21,815 21,831
Average of Ind Cust 239 240 240
Total Averaoe of Res Cust 186,892 187,158 187,025
Total Averaoe of Com Cust 21,084 21,109 21,096
Total AveraQe of Ind Cust 248 246 247
Base Coefficients
(Actual Average Demand/Customer Count)
.0;056042 Res Base Usage
-0.36998 Com Base Usage-
3.898256100 Base Usage
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Appendix 3.3 . Medford Base Coeffcient Calculation
A A tiD db CiMeragec ua ernan )y ass
Month
Year Data 7 8 Grand Total
2005 Average of Res Demand 2,422 2,367 2,395
Average of Com Demand 2,136 2,219 2,178
Average of Ind Demand 8 7 8
2006 Average of Res Demand 2,245 2,306 2,276
Average of Com Demand 1,979 2,163 2,071
Average of Ind Demand 8 7 7
2007 Average of Res Demand 2,319 2,285 2,302
Average of Com Demand 2,044 2,142 2,093
Average of Ind Demand 8 7 7
2008 Average of Res Demand 2,300 2,688 2,494
Average of Com Demand 2,027 2,520 2,274
Average of Ind Demand 8 8 8
Total Average of Res Demand 2,321 2,412 2,366
Total Average of Com Demand 2,047 2,261 2,154
Total Average of Ind Demand 8 7 8
A A tiC t C b CIMeragec ua us orner ount )y ass
Month
Year Data 7 8 Grand Total
2005 Average of Res Customer 47,286 47,191 47,239
Average of Com Customer 6,085 6,094 6,090
Average of Ind Customer ---
2006 Average of Res Customer 48,666 48,531 48,599
Average of Com Customer 6,225 6,229 6,227
Average of Ind Customer ---
2007 Average of Res Customer 49,448 49,391 49,420
Average of Com Customer 6,356 6,352 6,354
AveraQe of Ind Customer 9 9 9
2008 Average of Res Customer 49,930 49,734 49,832
Average of Com Customer 6,395 6,391 6,393
Average of Ind Customer 10 10 10
Total Average of Res Customer 48,833 48,712 48,772
Total Average of Com Customer 6,265 6,267 6,266
Total AveraQe of Ind Customer 5 5 5
Base Coefficients
(Actual Average Demand/Customer Count)
.0.0485-2 Res Base Usage
0.343742 Com Base Usage
1.613195lnôBase Usag
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Appendix 3.3 . Roseburg Base Coeffcient Calculation
A A 10 db CI"erage ctua ernan .)y ass
Month
Year Data 7 8 Grand Total
2005 Average of Res Demand 859 849 854
Average of Com Demand 910 1,040 975
Average of Ind Demand 32 46 39
2006 Average of Res Demand 702 611 657
Average of Com Demand 744 748 746
Averaçie of Ind Demand 26 33 29
2007 Average of Res Demand 634 619 627
Average of Com Demand 672 757 715
Average of Ind Demand 24 33 28
2008 Average of Res Demand 632 585 609
Average of Com Demand 670 716 693
Averaçie of Ind Demand 23 31 27
Total Average of Res Demand 707 666 686
Total Average of Com Demand 749 815 782
Total Average of Ind Demand 26 36 31
A A tiC t C tb Ci"erage c ua us orner oun )y ass
Month
Year Data 7 8 Grand Total
2005 Average of Res Customer 12,311 12,257 12,284
Average of Com Customer 2,093 2,093 2,093
Averaçie of Ind Customer 2 2 2
2006 Average of Res Customer 12,570 12,511 12,541
Average of Com Customer 2,128 2,112 2,120
Average of Ind Customer 3 4 4
2007 Average of Res Customer 12,900 12,777 12,839
Average of Com Customer 2,126 2,105 2,116
Averaçie of Ind Customer 2 1 2
2008 Average of Res Customer 12,942 12,885 12,914
Average of Com Customer 2,116 2,106 2,111
Averaçie of Ind Customer .2 2 2
Total Averaae of Res Customer 12,681 12,608 12,644
Total Averaae of Com Customer 2,116 2,104 2,110
Total Averaae of Ind Customer 2 2 2
Base Coefficients
(Actual Average Demand/Customer Count)
0;054292 Res Base Usage
0;37003 Com Base Usage
13.78076100 Base Usage ..
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Appendix 3.3 - Klamath Falls Base Coeffcient Calculation
A A 10 b Cveragectuaemand)y lass
Month I
Year Data 7 8 Grand Total
2005 Average of Res Demand 752 674 713
Average of Com Demand 632 682 657
Average of Ind Demand 9 12 11
2006 Average of Res Demand 541 533 537
Average of Com Demand 455 539 497
Average of Ind Demand 7 10 8
2007 Average of Res Demand 576 540 558
Average of Com Demand 484 547 515
Averaçie of Ind Demand 7 10 8
2008 Average of Res Demand 494 508 501
Average of Com Demand 416 514 465
Average of Ind Demand 6 9 8
Total Average of Res Demand 591 564 577
Total Average of Com Demand 497 570 534
Total Average of Ind Demand 7 10 9
A A C Cveragectualustomerount by Class
Month I
Year Data 7 8 Grand Total
2005 Average of Res Customer 12,977 12,855 12,916
Average of Com Customer 1,576 1,566 1,571
Average of Ind Customer ---
2006 Average of Res Customer 13,240 13,135 13,188
Average of Com Customer 1,582 1,576 1,579
Averaçie of Ind Customer ---
2007 Average of Res Customer 13,675 13,610 13,643
Average of Com Customer 1,605 1,598 1,602
Average of Ind Customer 5 5 5
2008 Average of Res Customer 13,703 13,576 13,640
Average of Com Customer 1,603 1,590 1,597
Averaçie of Ind Customer 5 5 5
Total Averaçie of Res Customer 13,399 13,294 13,346
Total Average of Com Customer 1,592 1,583 1,587
Total Average of Ind Customer 3 3 3
Base Coefficients
(Actual Average Demand/Customer Count)
'0:043256 Res Base Usage
0.336197 Com Base Usage
3.5153591nd Base Usage
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Appendix 3.3 - LaGrande Base Coeffcient Calculation
A A 10 db Ci~erage ctua eman y ass
Month
Year Data 7 Grand Total
2005 Average of Res Demand 368 368
Average of Com Demand 224 224
Averaoe of Ind Demand 17 17
2006 Average of Res Demand 360 360
Average of Com Demand 219 219
Average of Ind Demand 17 17
2007 Average of Res Demand 360 360
Average of Com Demand 219 219
Average of Ind Demand 17 17
2008 Average of Res Demand 365 365
Average of Com Demand 222 222
Average of Ind Demand 17 17
Total Average of Res Demand 364 364
Total Averaoe of Com Demand 221 221
Total Average of Ind Demand 17 17
A A i C t C b Ci~erage ctua us omer ount )y ass
Month
Year Data 7 Grand Total
2005 Average of Res Customers 6,475 6,475
Average of Com Customers 949 949
Average of Ind Customers 3 3
2006 Average of Res Customers 6,163 6,163
Average of Com Customers 873 873
Average of Ind Customers 2 2
2007 Average of Res Customers 6,259 6,259
Average of Com Customers 868 868
Averaoe of Ind Customers 1 1
2008 Average of Res Customers 6,351 6,351
Average of Com Customers 880 880
Average of Ind Customers 1 1
Total Average of Res Customers 6,312 6,312
Total Averaae of Com Customers 893 893
Total Averaoe of Ind Customers 2 2
Base Coefficients
(Actual Average Demand/Customer Count)
0:057597 Res Base Usage
0.247762Com Base Usage
9.5829061nd Base Usage
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2009 Natural Gas IRP - APPENDlclES
APPENDIX 3.4
HEATING DEGREE DAY (HDD) DATA
85
Appendix 3.4 - Heating Degree Day Data Monthly Totals
87
Appendix 3.4 - Heating Degree Day Data Monthly Totals
88
Appendix 3.4 . Heating Degree Days by Day (Includes Peak Weather Event and Additional Wintr Storm)
89
18
Appendix 3.4 . Heating Degree Days by Day (Includes Peak Weather Event and Additional Winter Stonn)
2
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90
2009 Natural Gas IRP - APPENDlclES
APPENDIX 3.5
GLOBAL WARMING SUMMARY AND GRAPHS
91
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2007 --
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
l
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95.6%
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93.9%
93.7%
93.4%
93.2%
93.0%
92.7%
92.5%
92.2%
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co
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2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
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2009 Natural Gas IRP - APPENDlclES
APPENDIX 3.6
ALTERNATE DEMAND SCENARIOS SUMMARY
OF ASSUMPTIONS
107
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2009 Natural Gas IRP - APPENDICIES
APPENDIX 3.7
ALTERNATE DEMAND SCENARIOS DESCRIPTIONS
113
Appendix 3.7
Avista 2009 Natural Gas IRP Demand Forecast
Sensitivities and Scenarios Update
A. Definitions
Dynamic Demand Methodology - Avista's demand forecasting approach wherein we 1)
identify key demand drivers behind natural gas consumption, 2) perform sensitivity
analysis on each demand drver, and 3) combine demand drvers under various scenarios
to develop alternative potential outcomes for forecasted demand.
Demand Influencing Factors - Factors that directly influence the volume of natual gas
consumed by our core customers.
Price Influencing Factors - Factors that, through price elasticity response, indirectly
influence the volume of natural gas consumed by our core customers.
Reference Case - A baseline point of reference that captues the basic inputs for
determining a demand forecast in SENDOUT which includes number of customers, use
per customer, daily weather temperatues and natual gas prices.
Sensitivities - Focused analysis of a specific natural gas demand drver and its impact on
forecasted demand relative to the Reference Case when underlying input assumptions are
modified.
Scenarios - Combination of natual gas demand drvers that make up a demand forecast.
B. Reference Case Input Assumptions
Customer growth rates reflect roll up of underlying county level growth rate analysis
utilizing Global Insights forecast data (see Tables & Graphs, Figure 1 below). Initial
use per customer is based on historical analysis of last three years data. Peak Day
weather reflects coldest average daily temperature experienced over available weather
data. Natual gas price curve derived from independent consultant forecast (Wood
Mackinzie, an industr information & analysis consultant) with first five years modified
to include blend of recent market prices (Nymex forward prices). The resulting real price
forecast (2009$) is included in Figure 2.
115
C. Sensitivities
The following Sensitivities were performed on identified demand drvers against the
reference case for consideration in Scenaro development. Note that Sensitivity
assumptions reflect incremental adjustments we estimate are not captued in the
underlying reference case forecast.
Low & High Customer Growth - In our low customer growth Sensitivity, annual
customer growth rates under perform the reference rate of growth by 50% over our 20
year planing horizon while annual customer growth rates exceed the reference rate by
50% in our high growth Sensitivity (Figure 1).
Coldest Day 20yrs Weather Standard - Peak Day weather temperatue reduced to
coldest average daily temperatue (HDDs) experienced in the most recent 20 years in
each region. Note this sensitivity only affects our W A/ID, Medford and Roseburg
service regions as Klamath Falls and La Grande have experienced a coldest day on record
within the last 20 years.
Low & High Prices - To captue a wide band of alternative prices forecasts, we use the
Northwest Power and Conservation Council's "very low" and "very high" natual gas
price forecast scenarios with first five years modified to include blend of recent market
prices (Nymex forward prices) consistent with our Expected price forecast (Figure 2).
Expected, Low, and High Elasticity - For our expected elasticity Sensitivity, we
incorporate reduced consumption in response to higher natual gas prices utilizing a price
elasticity study prepared by the American Gas Association. We then consider a lower
response rate to the study as well as a higher response. We also consider a wider band of
response in especially volatile prices defined as annual price increases exceeding 30%
(Figure 3).
Carbon Mitigation 1 - Utilizes carbon cost adders quantified by independent analysis
from Wood Mackenzie. They identify both an adder reflecting carbon allowances as well
as an adder to capture the effect of increased natual gas demand as more gas tubines
come online to replace coal plants and back up wind generation. The allowance adder
escalates from $5/ton in 2012 to $67/ton by 2030 while the increased demand adder
climbs from $.50/mmbtu to $1.00 over our planing horizon (Figure 4).
Carbon Mitigation 2 - Recognizing significant uncertinty exists regarding the amount,
scope, and timing of carbon regulation, we utilize a second alternate range of cost adders
to develop a high carbon cost case. We escalate an allowance adder from $37 /ton in
2012 to $ 140/ton by 2030 as forecasted in a Pacific Northwest electrc utility's integrated
resource plan. The increased demand adder is consistent with our Carbon Mitigation 1
case.
Canadian Imports Decline - Beginning in 2015, we apply an estimate of$.20/mmbtu
incremental adder each year to regional natual gas prices to captue upward price
116
pressure because of decreased Canadian imports more severe than generally anticipated.
The cumulative cost adder by the end of our planning horizon is $3.00/mmbtu. After
discussion with the TAC, we dropped further analysis of our initial most severe imports
decline case of $.50/mmbtu incremental each year as we concluded this type of price
increase would support several supply responses (including frontier gas pipelines) which
would curail such a long term price increase.
Driling Constraints -This price adder estimates the impact from increased costs to
comply with potential increased environmental regulations. Significant uncertainty exists
regarding potential costs, impacts on production and timing of more stringent regulation.
Also, it is very diffcult to ascertain to what degree these types of costs are already
captued in forward market prices and various price forecasts. In light of this challenge,
we have assumed a $.30/mmbtu adder in each year from 2012 to 2030 for this Sensitivity
recognizing the wide range of actual outcomes.
*****
Following are other Sensitivities we evaluated:
Compressed Natural Gas (CNG) Vehicles - CNG vehicles assumed to produce a 15%
cumulative incremental demand over our 20 year planning horizon. Our assumption
utilized market consumption estimates from an independent analysis on CNG vehicle
viability. The analysis indicates significant challenges exist to widespread adoption but
did provide a scenario for significant market penetration (10% in 10 years). Although we
concur significant system demand from CNG vehicle purchases in our service terrtories
is unlikely at this time, we were motivated to ru this sensitivity to learn how our system
would respond to an emerging application that would grow significant new natual gas
demand. This sensitivity, although instrctive on understanding underlying incremental
change in demand, is not currently used in any Scenario.
lHDD Lower Weather Standard - Peak Day weather temperatue is reduced by 1
heating degree (Fahrenheit) in each service region. This sensitivity, although instructive
on understanding underlying incremental change in demand, is not used in any Scenario.
Northern Migration - Economic and water issues in south western states spur increased
migration to Pacific Northwest states. After discussion, it was determined that the High
Customer Growth sensitivity would likely encompass this sensitivity's demand impacts
therefore we did not pursue further analysis.
Stagnant Growth - Current economic conditions spur much slower and possibly
negative customer growth rates for an extended period with a retu to trend rates at some
point. It was noted that we have not experienced widespread negative growth in our
actual recent data. Our significant residential customer base has historically been very
stable and not prone to extreme boom or bust cycles in four of our five service regions.
Medford/Roseburg would appear most vulnerable to a severe impact though a sustained
negative growth trend appears remote. Also noted were the very low long term growth
117
rates in our Low Customer Growth sensitivity. After discussion, it was determined that
the Low Customer Growth sensitivity would likely encompass this sensitivity's demand
impacts therefore we did not pursue fuher analysis.
Global Warming - Adjust the regional peak day weather temperatues lower to account
for global warming. Although we have developed analysis supporting adjustment to
historical average daily temperatues for our forecasted average daily temperatues, we
searched unsuccessfully for information that would provide a basis for adjusting peak day
temperatures. Our data does suggest more volatile temperatures recently but is
inconclusive on a trend of lower (or higher) peak temperatues. One TAC member
provided information from a study that could not conclude global warming influenced
peak day temperatues. Another TAC member offered reliable assessments of global
waring applied to specific service regions would be challenging given local weather
dynamics and conjectued overall global warming weather dynamics might produce
possible peak day cooling trends for regions situated in transition areas. After discussion
and feedback, we determined that a reliable basis for global warming temperatue
adjustment is too uncertain. We also believe the Atlernate Weather Standard
sensitivity may encompass many possible demand impacts for this sensitivity therefore
we did not pursue fuher analysis.
*****
The following two DSM Sensitivities were also conducted:
DSM Accelerated - Federal stimulus fuded residential audit programs and tax credits in
combination with our program rebates induce increased conservation in 2010 beyond
what is assumed in the IRP base case.
DSM Delayed - A combination of reduced customer disposable income from the
economic recession and a freeze in customer incentives due to A vista budget constraints
result in a reduction in energy-effciency measures from what is assumed in the IR base
case.
D. Scenarios
After identifying the above demand drvers and analyzing the various Sensitivities, we
have developed the following demand forecast Scenarios:
Expected Case - This Scenario we believe represents the most likely demand forecast
modeled. We assume service terrtory customer growth rates consistent with the reference
case, a weather standard of coldest day on record in each service terrtory, our middle
range natual gas price forecast (Consultant #1), low price elasticity, and the C02 cost
adders from our Carbon Mitigation 1 (CMl) Sensitivity. The Scenario does not include
incremental cost adders for declining Canadian imports or drlling restrictions beyond
what is incorporated in the selected price forecast.
118
High Growth, Low Price - This Scenario models a rapid retu to robust growth in part
spured on by low energy prices. We assume customer growth rates 50% higher than the
reference case, coldest day on record weather standard, our low natural gas price forecast,
low price elasticity, and C02 adders from CMI. The Scenario does not include
incremental cost adders for declining Canadian imports or drillng restrctions beyond
what is incorporated in the selected price forecast.
Low Growth, High Price - This Scenario models an extended period of slow economic
growth in part resulting from high energy prices. We assume customer growth rates 50%
lower than the reference case, coldest day on record weather standard, our high natural
gas price forecast, high price elasticity, and C02 adders from our Carbon Mitigation I
Sensitivity (CMI). The Scenario also includes a incremental cost adder for drlling
restrictions.
Green Future - This Scenario models a moderate retu to economic growth consistent
with our Expected Case while striving for environmentally friendly objectives. We
assume service territory customer growth rates consistent with the reference case, a
weather standard of coldest day on record in each service terrtory, and our middle range
natual gas price forecast but with price adjustments including the C02 cost adders from
CM2, and drlling restrictions. We also assume our high elasticity response to rising
prices.
Alternate Weather Standard - This Scenario models all the same assumptions as the
Expected Case Scenario except for the change in the weather planning standard from
coldest day on record to coldest day in 20 years for each service terrtory. As noted in the
Sensitivity analysis, this change does not affect the Klamath Falls and La Grande service
terrtories which have each experienced their coldest day on record within the last 20
years.
Supply Constraints - This Scenario models an extended period of slow economic
growth in part resulting from high energy prices. We assume customer growth rates 50%
lower than the reference case, coldest day on record weather standard, our high natural
gas price forecast, medium price elasticity, and C02 adders from our Carbon Mitigation
I Sensitivity (CMI). The Scenario also includes incremental cost adders for declining
Canadian imports and drilling restrictions.
119
E. Tables & Graphs
Figue 1 - Customer Growth Rates
Customer Growth Rates
Residential
Residential
Residential
Residential
Residential
Commercial
Commercial
Commercial
Commercial
Commercial
WAIID
Medford
Roseburg
Klamath
La Grande
WAIID
Medford
Roseburg
Klamath
La Grande
Reference
Case
2.2%
2.6%
3.6%
1.9%
1.4%
2.3%
1.2%
2.1%
1.9%
0.6%
50%
Increase
in Cust
Growth
Rates
Low Cust High Cust
Growth Growth
50%
Decrease
in Cust
Growth
Rates
$16.00
Figue 2 - Henr Hub Natual Gas Price Forecasts (2009$)
$1400
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Figue 3 - Price Elasticity Factors
Real Price annual increase Real Price annual increase
within 30%exceeds 30%
High Negative .20 Negative .30
Expected Negative .13 Negative .13
Low No response Negative .10
120
Figue 4 -Carbon Cost Adders (Carbon Mitigation 1)
$5.00
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121
2009 Natural Gas IRP - APPENDICIES
APPENDIX 3.8
ANNUAL AND PEAK DAY DEMAND DATA
123
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2009 Natural Gas IRP - APPENDICIES
APPENDIX 3.9
ANNUAL DEMAND BY REGION BEFORE AND AFTER DSM
131
Appendix 3.9 . Annual Demand by Region Before and After DSM
Expected Case (in Mdth)
Annual Oemand Before and After OSM
WAllO
--=
,
~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~y ~y ~ ~ ~y ~v ~v ~v ~v ~v ~v ~v ~v ~v ~v~~~~0~~0~~~~~~~~~0~~# ~~~~~~~~#~#~~####~#
- Wa/ld: Daily Calculated Demand -Wa/ld: Daily Calculated Demand After DSM
Annual Oemand Before and After OSM
Medford
8,000
7,000
6,000
5,000...."a 4,000:i
3,000
2,000
1,000
,
~ ~~~ ~ ~ ~ ~ ~ ~ d ~## ~ ø # ~ # #~~~~0~00~~~~~~~~00~~# ~ ~~ ~ ~ ~ ~~ ~ ~ # ~~ # # # #~ #
- Medford: Daily Calculated Demand - Medford: Daily Calculated Demand After DSM
133
2,500
2,000
.i 1,500.."a~
1,000
500
Annual Demand Before and After DSM
Roseburg
~~~~~ø~~~~#~~~~##~#~~~~~~~~~y~~~~~~~~~~~# ~ ~ ~~ ~ ~~ ~ # ~ # # # # # # # # #
- Roseburg: Daily Calculated Demand - Roseburg: Daily Calculated Demand After DSM
2,000
1,800
1,600
1,400
.i 1,200.."a 1,000~
800
600
400
200
Annual Demand Before and After DSM
Klamath Falls
~ ~ ~~~ø~~#~d~~#~##~#~Pi'V (i",t; '-",t; -v'V 'I'V ~'V "'? 1ó'V '\~ 'I? o? (i'V '-'V 'V'V 'I'V ~'V ~'V 1ó'V ~~ %'V# ~ ~ ~ ~# ~# ~ # ~ # # # # # # # # #
- Klam Falls: Annual Calculated Demand -Klam Annual Calculated Demand After
134
J:.."a:i
Annual Demand Before and After DSM
LaGrande
900
800
700
600
500
400
300
200
100
o
--
,~~~~~~~~ ~~ #~##~##~ ##~~~~~~~0~~~~~~~~~0~~# ~ ~ ~ ~ ~ ~ ~ ~ ~ # # # # # # # # # #
- La Grande: Daily Calculated Demand by Area/Class
-- La Grande: Daily Calculated Demand After DSM by
135
Appendix 3.9 - Annual Demand by Region Before and After DSM
Expected Case (in Mdth)
Gas Year
2009-2010
2010-2011
2011-2012
2012-2013
2013-2014
2014-2015
2015-2016
2016-2017
2017-2018
2018-2019
2019-2020
2020-2021
2021-2022
2022-2023
2023-2024
2024-2025
2025-2026
2026-2027
2027-2028
2028-2029
Wa/ld: Daily Calculated
Demand
26,526.09
26,584.84
26,953.24
27,425.32
28,010.01
28,619.71
28,707.45
29,155.37
29,678.37
30,234.41
30,871.50
31,479.93
32,108.14
32,753.61
33,439.72
34,049.31
34,738.22
35,364.51
36,030.35
36,641.75
Wa/ld: Daily Calculated
Demand After DSM
26,224.90
25,977.00
26,053.00
26,235.81
26,531.25
26,851.68
26,663.92
26,839.97
27,091.79
27,374.74
27,734.31
28,091.83
28,468.23
28,861.41
29,293.84
29,664.20
30,107.15
30,503.32
30,986.56
31,418.51
Wa/ld: Daily DSM
301.19
607.84
900.24
1,189.51
1,478.76
1,768.03
2,043.53
2,315.40
2,586.58
2,859.67
3,137.19
3,388.09
3,639.91
3,892.20
4,145.88
4,385.11
4,631.06
4,861.19
5,043.79
5,223.24
136
% of Demand Served by
DSM
1.14%
2.29%
3.34%
4.34%
5.28%
6.18%
7.12%
7.94%
8.72%
9.46%
10.16%
10.76%
11.34%
11.88%
12.40%
12.88%
13.33%
13.75%
14.00%
14.25%
Appendix 3.9 - Annual Demand by Region Before and After DSM
Expected Case (in Mdth)
Gas Year
2009-2010
2010-2011
2011-2012
2012-2013
2013-2014
2014-2015
2015-2016
2016-2017
2017-2018
2018-2019
2019-2020
2020-2021
2021-2022
2022-2023
2023-2024
2024-2025
2025-2026
2026-2027
2027-2028
2028-2029
Medford: Daily
Calculated Demand
5,271.99
5,247.21
5,320.58
5,421.21
5,535.29
5,649.16
5,686.18
5,785.45
5,875.10
5,949.31
6,064.50
6,172.34
6,271.86
6,387.46
6,503.17
6,605.08
6,705.73
6,813.68
6,925.88
7,010.80
Medford: Daily
Calculated Demand After
DSM
5,254.79
5,210.47
5,266.05
5,350.71
5,448.89
5,547.09
5,568.65
5,652.81
5,727.54
5,787.15
5,886.91
5,979.65
6,065.46
6,169.20
6,275.20
6,369.13
6,462.26
6,562.38
6,666.57
6,744.67
137
Medford: DSM
17.19
36.74
54.53
70.49
86.40
102.07
117.53
132.64
147.56
162.16
177.60
192.69
206.40
218.25
227.97
235.95
243.48
251.29
259.30
266.12
% of Demand Served by
DSM
0.33%
0.70%
1.02%
1.30%
1.56%
1.81%
2.07%
2.29%
2.51%
2.73%
2.93%
3.12%
3.29%
3.42%
3.51%
3.57%
3.63%
3.69%
3.74%
3.80%
Appendix 3.9 - Annual Demand by Region Before and After DSM
Expected Case (in Mdth)
Gas Year
2009-2010
2010-2011
2011-2012
2012-2013
2013-2014
2014-2015
2015-2016
2016-2017
2017-2018
2018-2019
2019-2020
2020-2021
2021-2022
2022-2023
2023-2024
2024-2025
2025-2026
2026-2027
2027-2028
2028-2029
Roseburg: Daily
Calculated Demand
1,491.78
1,495.81
1,540.63
1,590.67
1,642.17
1,696.96
1,730.65
1,778.11
1,820.37
1,864.07
1,912.12
1,959.32
2,007.29
2,058.62
2,112.05
2,153.90
2,199.00
2,234.05
2,277.19
2,316.90
Roseburg: Daily
Calculated Demand After
DSM
1,487.33
1,486.30
1,526.74
1,572.84
1,620.42
1,671.32
1,701.12
1,744.82
1,783.45
1,823.47
1,867.80
1,911.33
1,955.88
2,004.47
2,055.76
2,095.99
2,139.49
2,173.29
2,214.90
2,253.26
Roseburg: DSM
4.45
9.51
13.90
17.83
21.75
25.64
29.52
33.29
36.93
40.61
44.32
47.99
51.40
54.15
56.29
57.92
59.51
60.76
62.29
63.64
138
% of Demand Served by
DSM
0.30%
0.64%
0.90%
1.12%
1.32%
1.51%
1.71%
1.87%
2.03%
2.18%
2.32%
2.45%
2.56%
2.63%
2.67%
2.69%
2.71%
2.72%
2.74%
2.75%
Appendix 3.9 - Annual Demand by Region Before and After DSM
Expected Case (in Mdth)
Gas Year
2009-2010
2010-2011
2011-2012
2012-2013
2013-2014
2014-2015
2015-2016
2016-2017
2017-2018
2018-2019
2019-2020
2020-2021
2021-2022
2022-2023
2023-2024
2024-2025
2025-2026
2026-2027
2027-2028
2028-2029
Klam Falls: Annual
Calculated Demand
1/359.40
1/371.15
1,408.49
1,438.98
1,461.01
1,487.71
1,495.26
1/519.82
1/545.07
1/568.48
1/596.44
1/622.72
1/651.38
1/680.05
1/710.30
1/737.00
1/764.65
1/793.10
1/821.72
1/847.82
Klam Falls: Annual
Calculated Demand After
DSM
1/352.83
1/358.02
1/388.79
1,413.54
1,429.92
1,450.87
1,452.66
1,471.57
1,491.15
1/508.98
1/531.23
1/551.91
1/575.11
1/599.35
1/625.95
1/649.52
1/674.21
1/699.65
1/725.30
1/748.52
139
Klam Falls: DSM
6.57
13.14
19.70
25.43
31.09
36.84
42.60
48.25
53.92
59.50
65.21
70.81
76.28
80.71
84.34
87.48
90.44
93.44
96.43
99.30
% of Demand Served by
DSM
0.48%
0.96%
1.40%
1.77%
2.13%
2.48%
2.85%
3.17%
3.49%
3.79%
4.08%
4.36%
4.62%
4.80%
4.93%
5.04%
5.13%
5.21%
5.29%
5.37%
Appendix 3.9 - Annual Demand by Region Before and After DSM
Expected Case (in Mdth)
Gas Year
2009-2010
2010-2011
2011-2012
2012-2013
2013-2014
2014-2015
2015-2016
2016-2017
2017-2018
2018-2019
2019-2020
2020-2021
2021-2022
2022-2023
2023-2024
2024-2025
.2025-2026
2026-2027
2027-2028
2028-2029
Calculated Demand by
Area/Class
785.67
770.51
772.46
773.43
774.29
772.97
763.70
762.77
761.41
760.07
765.55
771.21
778.37
785.61
792.38
798.33
804.52
811.30
819.23
823.31
Calculated Demand After
DSM by Area/Class
782.49
764.25
763.16
761.45
759.65
755.79
743.95
740.57
736.82
733.14
736.10
739.28
744.06
749.37
754.62
759.27
764.26
769.80
776.44
779.44
La Grande: DSM
3.17
6.26
9.30
11.99
14.63
17.18
19.75
22.20
24.58
26.93
29.44
31.92
34.32
36.24
37.76
39.06
40.26
41.50
42.79
43.87
140
% of Demand served by
DSM
0.40%
0.81%
1.20%
1.55%
1.89%
2.22%
2.59%
2.91%
3.23%
3.54%
3.85%
4.14%
4.41%
4.61%
4.77%
4.89%
5.00%
5.12%
5.22%
5.33%
2009 Natural Gas IRP - APPENDICIES
APPENDIX 3.10
DETAIL DEMAND DATA
141
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2009 Natural Gas IRP - APPENDICIES
APPENDIX 4.1
DSM IMPLEMENTATION AND OPERATIONS
159
2009 Natural Gas IRP
APPENDIX 4.1- DSM IMPLEMENTATION & OPERATIONS
AVISTA DSM COMMITMENT
A vista recognizes our obligation to meet the resource needs of customers in the most cost-effective
manner. The delivery of conservation programs is anticipated to represent an increasing portion of
the optimal resource portfolio. The IRP process is an opportnity to comprehensively review the
conservation program portfolio and make necessary revisions to daily DSM operations and longer-
term implementation plans in order to meet those commitments in the years to follow.
This document summarizes a broad evaluation of applicable conservation measures and identifies
those worthy of testing against all other supply-side resources to assist us in making decisions about
which measures would be suitable to carr forward into program development and implementation.
Through our TAC process we solicited comments from key stakeholders regarding the selection,
characterization and testing of conservation measures within the IRP process. After much discussion
and some revision, the general consensus ofthose stakeholders was that this approach was suffcient
to represent conservation opportunities within the IRP.
There are concerns about our South Division due to the economic condition and high levels of
unemployment that could constrain participation. We remain open to alternative approaches to
overcoming those market barriers to include enhanced outreach efforts, revised incentives, and
inovative marketing of conservation programs and cooperative arrangements with other agents in
the market, with particular attention to other natual gas utilities, the Energy Trust of Oregon and
regional market transformation efforts with an interest in natural gas efficiency.
Additionally, we are committed to maintaining a collaborative relationship with all stakeholders who
may contribute to the improvement ofDSM efforts as programs are fuher developed and launched.
We continue to improve the management of these programs through development of additional
metrics, improved reporting and benchmarking for determining the regulatory prudence of these
programs.
A vista recognizes that acquiring all cost-effective conservation potential is not limited by the therm
acquisition goals established in this IRP. The implementation ofthe results ofthis planning wil be
sufficiently flexible to realize opportities even if they are well in excess of expectations. Human
and fmancial resources wil be made available to the extent necessary to achieve the cost-effective
potential without regard to those goals.
TECHNICAL AND ACHIEVABLE POTENTIAL
In 2005, Avista contracted with RLW Analytics, a conservation consultant, to independently identify
and analyze the potential energy savings for our Oregon service terrtories. The methodology from
this study was extrapolated to Washington and Idaho and served as the initial basis for determining
Avista 4.1.1
161
Appendix 4.1 - DSM Implementation & Operations 2009 Natural Gas IRP
conservation technical potential for all of Avista's natual gas service terrtories. The energy savings
data for weather-sensitive measures were adjusted to incorporate local HDD data appropriate to each
geographic area. A vista DSM engineers, program implementers and analysts also reviewed the RL W
estimates of incremental measure costs, measure lives, energy savigs, 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 cost and energy savings, and have augmented the
study with additional measures not previously evaluated.
Figures 4.1.1 and 4.1.2 depict supply cures for technical and achievable potential for our North and
South divisions.
12,000
10,000
8,000íi
~ Ec '".~ ;6,00t/ .._ cos os'" '"c '"4,000c 0c( É.
2,000
Figure 4.1.1 Conservation Supply Curve. North
AI 5egrrts, 2010 DSM Poænlal
- Approx ¡mat 'currnt market cost e1tiveness scre
I
I~J
,J iL~i?i i
i
io
o 0.5 3 3.5 41.5 2 2.5
Levelized Annual Cost ($/therm)'
. Maximum cot is $11.89; chart scale 1rnca at $4
4.1.2 Avista
162
2009 Natural Gas IRP Appendix 4.1 - DSM Implementation & Operations
Figure 4.1.2 Conservation Supply Curve. South
All Segments, 2010 DSM Polential
4,000
3,500
3,00
",'"2,50
go E
.5 CD:: .c 2,000.. -tn ..- c.. ..'" '"1,500c '"c 0
c( E.
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- Approximat "current marker cost effctiveness screen
fI~i
I I
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r i
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o 0.5 1.5 2 2.5 3 3.5 4
Levelized Annual Cost ($lthenn)*
. Maximum cot is $9.36; chrt scale In at $4
Avista's achievable potential as a percentage oftechnical potential appears to be lower than other
regional utilities. However, our actual per customer savings acquired compare favorably with other
regional utilities. Unlike other regional utilities that have selected an overall percentage oftheir
technical potential 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 customers in a division broken down by the
estimated percentage that is single family, multifamily or manufactured homes. The applications are
evaluated based on how many have or could have access to an application in their home or facility
and, fmally, how many applications would be replaced with a higher efficiency option over the
standard option over the twenty year horizon. This methodology used to develop achievable
potential tracks with our actual results and is comparable with other regional utilities.
For perspective, we indicate a cost effectiveness screen of$0.50 per therm based on an approximate
curent market commodity cost of$5 per Dth. Around this level, Avista's achievable potential tracks
much closer with the technical potential and is similar to other regional utilities.
We have tried to identify differences that create the large gap between our achievable potential and
RL W's technical potentiaL. We did not identify every difference but we did make changes to
technical potential that we could support and document. Some examples were:
· The pre-rinse sprayer program was a one-time, non-recuring, non-residential program where
A vista pursued intallations of sprayers in all existing applications. Since these sprayers are
now code, the savings wil not recur. Therefore, we removed savings associated with pre-
rinse sprayers from the RL W technical potentiaL.
· The same technical potential was listed for all water heater applications, so it appears that
RLW failed to consider the mutually exclusivity ofthe various types of water heaters. AAvista 4.1.3
163
Appendix 4.1 - DSM Implementation & Operations 2009 Natural Gas IRP
single- family residential customer typically only has one water heater application in their
home. However, RLW included that same customer in the technical potential for tanked,
tankless, and passive solar water heaters. We think this same issue may exist for other
measures but we could not verify this, so an adjustment was made only to the water heaters
technical potentiaL.
. In the past, Oregon Staff has generally disapproved faucet aerators and low-flow
showerheads as viable measures with demonstrable savings, so we removed the savings
associated with these two measures.
. RLW included nearly 3,000 units of thermal vent dampers in a multi-family application.
Based on our market knowledge, we felt this number ofthe entire population was
overestimated and was more realistic at 1,000 units. This resulted in a decrease in technical
potential of 54,000 therms.
While this is not a complete list of potential differences with RLW's estimate of technical potential,
this concern should be resolved with a new external study of technical potential which we intend to
pursue prior to completion of the 2011 IRP.
The following sections discuss Avista's DSM progrms and how the IRP results are incorporated
into DSM operations.
SOUTH DIVISION DSM PORTFOLIO
Avista's residential measures are available to approximately 84,000 customers (Avista Rate
Schedule 410) with an annual consumption of 50.5 millon therms. The commercial measures are
available to nearly 11,200 mostly small-to-medium-sized customers (Avista Rate Schedules 420 and
424) with an annual consumption of approximately 32.3 millon therms. The largest segment of
qualified non-residential customers use natual gas for space, water heating and cooking with an
average consumption of nearly 2,900 therm each.
The measures offer a mix of both curently cost effective and market transformation measures which
are expected to be cost-effective over time. The combined residential and non-residential therm goal
for 2010 is 326,314 and 324,314 for 2011. Details on individual measures such as measure life,
levelìzed TRC, unit goal, and therm goal can be found in Appendix 4.2.
RESIDENTIAL SEGMENT
Avista's residential program consists of site specific and prescriptive measures and includes a mix of
curently cost effective measures and market tranformtion measures which are expected to be cost-
effective. The 2010 residential therm goal is 215,580 and 206,333 in 2011.
Avista's residential site specific program is primarily focused on cost effective shell measures.
Changes made to the program in early 2007 include: higher incentive levels, removal ofall non cost
effective measures and requiring window upgrades to be included with at least one other major
4.1.4 Avista
164
2009 Natural Gas I RP Appendix 4.1 - DSM Implementation & Operations
measure. We wil consider additional enhancements as they are identified to increase program
participation.
We also offer prescriptive incentives such as tankless water heaters, high-effciency direct vent space
heaters, external chimney dampers, programmable thermostats, high effciency forced air funaces
and high efficiency tank water heaters.
In the majority of cases, tank water heaters are replaced on "bum out" with the high effciency
models costing, on average, $120 more than standard effciency models. Product availability has
gotten better, but continues to be an issue going forward. We believe that to affect the incremental
cost and maintain availability, that high efficiency tank water heaters should be retained as a "market
transformation" program in 2010 and 2011.
We also believe building a strong trade ally network is the best way to promote the acceptance of
higher effciency equipment. Our trade allies currently include HV AC dealers, plumbers, retailers,
manufactuers, distributors along with builders and developers. A vista has also established
relationships with groups such as the home builders association and landlord associations throughout
its service terrtory.
NON-RESIDENTIAL SEGMENT
Prior to 2007, our non-residential measures were site-specific offerings only. In early 2007, Avista
added several cost effective prescriptive measures such as high-efficiency space heating equipment,
Energy Star gas fryers, Energy Star three pan gas steam cookers and high-efficiency gas rack ovens.
The non-residential therm acquisition goal for 2010 is 110,734 and 118,650 for 2011. Avista also
expects to add new prescriptive measures in 2009. Measures being considered include cost effective
shell measures and additional commercial kitchen measures. Measures with low achievable
potential, technologies new to the marketplace or where natural gas is used for process wil continue
to be evaluated on a site specific basis.
We believe that by adding additional prescriptive measures, the program wil be accessible by a
greater number of customers, wil be easier to manage at less cost and wil result in higher
participation levels in the small to medium sized customer segments. Measures not included in the
prescriptive program wil continue to be evaluated on a site specific basis.
A vista plans to increase efforts to identify cost effective, site specific opportunties with our larger
non-residential customers. Resources wil be reallocated to support this initiative.
In addition, we wil continue to look for opportunities to work cooperatively with the E TO where
site specific effciency projects are identified. We wil also work closely with local land-use planners
and energy consultants on new non-residential projects to influence energy efficiency decisions
during the design phase.
MEASURE DEVELOPMENT
Avista 4.1.5
165
Appendix 4.1 - DSM Implementation & Operations 2009 Natural Gas IRP
A vista wil continue to look at the "best fit" for program implementation. Implementation options
could include a combined effort between Avista's North and South divisions, additional staffing,
Energy Trust of Oregon (ETO), trade partners, and if developed, regional transformation efforts
through a natural gas Northwest Energy Effciency Allance (NEEA).
NORTH DIVISION DSM PORTFOLIO
Conservation measures have been offered to Washington and Idaho customers without interrption
since 2001 and periodically prior to that time.
A non-binding external oversight group, the External Energy Effciency ("Triple-E") Board, has
been established to provide guidance for the implementation ofDSM measures. This board is
provided with monthly and quarerly updates, convenes twice a year and receives a comprehensive
annual evaluation of acquisition and cost-effectiveness.
Avista's Rate Schedule 190 provides the regulatory guidelines for the implementation of DSM
measures. This tariff prescribes a set oftiered, direct fiancial incentives, as ilustrated in Table
4.1.1, based on the customer simple payback ofthe measure.
Table 4.1.1 - Natural Gas Effciency Measures Incentive Levels
Simple Pay-back Period
1 to 2 years
2 to 4 years
4 to 6 years
Over 6 vears
Incentive Level
($/first year therm)
$2.00
$2.50
$3.00
$3.50
Exceptions to these tiered incentives allow us flexibility to respond to unexpected or unique
opportnìties. This flexibility includes an additional set of tiered incentives, permitting higher
incentives for the development of new technologies and market transformtion efforts.
The original 2001 Schedule 190 tariff established an annual goal of240,000 first-year therms.
Almost immediately upon launch of the renewed gas-effciency program, commodity-driven
escalations in retail rates during the 2001 Western energy crisis drove acquisition well beyond these
levels. Initial concerns that this higher level of acquisition may be unsustainable proved to be
unfounded. A reassessment ofthe market in the 2007 Gas IRP process resulted in the establishment
ofa 1,425,070 annual therm goal for 2008 and 1,581,828 for 2009. The 2008 goal has proven to be
achievable. Whether or not the 2009 goal is achievable remains to be seen as customers react within
a struggling. economy.
Begining in 2015, carbon mitigation and other cost adders we model lead to significantly increased
avoided cost in later years. The corresponding increased measure selection by our model results in
preliminary 2010 and 201 1 savings goals which wil be a challenge. Current declining retail rates
for our customers make it diffcult to influence them to react to forecasted price increases. Alternate
scenarios modeled without the adders result in goals more inline with historical IRP goals.
4.1.6 Avista
166
2009 Natural Gas IRP Appendix 4.1 - DSM Implementation & Operations
It is possible that detailed implementation planning wil result in the recommendation for revisions
to the incentive levels, caps and applicable markets, and technologies as par of an overall strategy to
meet the commitments made for increased long-term resource acquisition identified within this IRP.
Our conservation offerings within our North Division are accompanied by a mix of electric
measures. In 2008 the natural gas share ofthe total BTU savings from the overall portfolio was 88
percent. This share shifts over time depending on resource opportities, retail rates, technical
advancements and customer interest. DSM implementation efforts within the North Division are
fuher subdivided into three different portfolios; (1) the non-residential portfolio, (2) the residential
portfolio and (3) the low-income residential portfolio. The approaches to the implementation of these
three portfolios differ significantly in recognition of the differences in these market segments.
NON-RESIDENTIAL. SEGMENT
While the non-residential portfolio has access to prescriptive measures, it is mainly characteried by
its non-prescriptive approach to this market which provides incentives for any cost-effective project.
Financial incentives are offered for projects based on the tiered incentive structure described above.
This approach ensures that the unique operating characteristics of commercial and industrial
customers are recognized. Prescriptive programs are limited to measures and applications with
standard energy savings and cost characteristics or where a standardized approach can be developed.
To simplify programs for our customers and trade alles and maximize program participation, we
have been shifting towards more prescriptive non-residential programs.
In 2008, Avista acquired 1,036,424 therms from this portfolio (55 percent ofthe total acquisition of
all three segments). Fifty-four percent ofthe total non-interactive energy (electric and natural gas)
acquisition is attributable to therm saving within this segment.
Large projects, those resulting in incentives of$100,000 or larger, are disclosed to the Triple-E
board to provide them with the information necessary to provide oversight ofDSM programs.
RESIDENTIAL SEGMENT
Due to the large volume and relatively small size of individual projects, the residential portfolio is
exclusively composed of prescriptive programs. In 2008 this portfolio was responsible for the
acquisition of749,199 first-year therms (40% of the total acquisition of all three segments). Of the
non-interactive total energy (electric and natual gas) savings in 2008 from this portfolio, 39 percent
are attibutable to therm savings ofthis segment.
Incentives available for residential programs are calculated based on the application of the measure
in a typical residential home or, in some cases, based on deemed savings. Calculations are made in
accordance with A vista Rate Schedule 190 tiered incentives with appropriate modifications for
potential differences in application, multiple measure programs and rounding for purposes of
offering a customer and trade ally- friendly program. The prescriptive residential programs curently
available are natural gas fuaces/boilers, high effciency water heaters, tankless water heaters,
ceiling/attic insulation, floor/wall insulation, windows, and rooftop dampers.
Avista 4.1.7
167
Appendix 4.1 - DSM Implementation & Operations 2009 Natural Gas IRP
Notably, several multifamily housing measures are incorporated within the residential segment due
to the non-residential electric and natural gas rate schedules that many ofthese customers are biled.
Many of the multifamily measures evaluated as par ofthis IRP analysis (e.g. pool and spa water
heating effciencies in multifamily housing) wil be forwarded to the residential segment
implementation team for further evaluation.
A vista is continuing an outreach effort targeted at residential customers within our service terrtory
through involvement at area community events. The outreach effort is geared toward improving
conservation by providing continuing educational messages regarding behavioral effects on energy
use as well as encouraging customers to participate in programs that improve the effciency of key
natual gas appliances or shell measures.
In addition, we continue our multi-channel, multi-year educational outreach effort, known as Every
Little Bit. Included in this effort is an website, ww.everylittlebit.com. which provides a one-stop
shop for energy effciency information and tips, available rebates, latest information on renewable
energy, as well as an interactive audit tool where customers can audit their home's energy effciency
and gain insight on improvements that can be made.
LOW-INCOME RESIDENTIAL SEGMENT
Avista's north division low income programs are implemented in cooperation with six community
action partnership (CAP) agencies. These CAP agencies are awarded an anual funding contract
specifying the maximum funding amounts and the conditions for program implementation. Contracts
can be revised on 30 days' notice, a provision that allows A vista flexibility to reallocate funds
among the CAP agencies during the year to maximize their value to the customer base.
The CAP agencies and 2008/2009 funding levels are summarized in Table 4.1.2.
Table 4.1.2 - 2008/2009 Low Income Funding Levels
Community Action Partner
Lewiston CAP
North Columbia CAe (Moses Lake)
Rural Resources CA (Colvile)
SNAP (Spokane)
Whitman County CAe (Pullman)
WGAP (White Salmon)
2008 Budget 2009 Budget
$480,937 $660,000
97,316 125,000
81,990 105,000
722,919 950,000
95,758 125,000
3,080 7,000
$1,482,000 $1,972,000
The distribution of funding for the low income segment has been approached with the intent to
provide the maximum flexibility possible. This permits the agencies to respond to unexpected urgent
needs and energy-efficiency opportunties that may not have been anticipated when the annual
contracts were signed.
As part of this flexibility, the CAP agencies are permitted to expend their contractual funding on
either electric or natual gas-effciency measures. The funding available includes an allowable 15
percent remuneration to the agency for administrative and outreach costs. Up to 15 percent ofthe
4.1.8 Avista
168
2009 Natural Gas IRP Appendix 4.1 - DSM Implementation & Operations
funds can be expended for health and human safety measures with an emphasis on the safe use of
energy, and maintenance and repairs necessary to ensure the longevity of installed efficiency
measures and continued habitability ofthe home.
The low income residential segment delivered 102,438 fist-year therms to the overall natural gas
DSM program in 2008. This therm acquisition represented 5 percent ofthe total BTUs acquired by
the combined electric and natual gas programs.
PROGRAM FUNDING
,
Avista's approach to conservation cost-recovery is through a public purose surcharge on our
customer's energy bil (the tariff rider). We curently manage separate tariff riders for Washington
and Idaho natural gas investments. Based upon the demand for funds and incoming tariff rider
contributions, this balance can be positive (shareholders owe customers) or negative (customers owe
shareholders) at any particular point in time.
The aggregate natual gas tariff rider balance for the north division is a negative (customer owes
shareholders) $4,047,415 as ofJuly 30,2009. Recent demand for conservation services has
exceeded tariff rider revenue. Therefore, we recently requested increases to Schedule 191, the most
recent of which went into effect in Idaho on August 1,2009. The most recent projection forecasts a
positive (shareholders owe customers) $74 thousand balance in the Washington natural gas DSM
tariffrider and just below $21 thousand positive in the Idaho natural gas tariff balance by year end
2010.
Funding for the natual gas efficiency programs is derived through a surcharge on retail rates
authoried under Schedule 191. The recent increases to the Washington and Idaho natual gas
surcharges were necessary to eliminate a persistent imbalance of tariff rider contributions and natural
gas program expenditues. This imbalance tends to grow. durng the periods of increasing
commodity costs and we continue to see higher than budgeted demand in program incentives. For
example, in 2008 natural gas tariff rider contributions were over $4.3 milion while we paid
customers nearly $5.1 millon in natural gas incentives, making incentives 117% of tariff rider
contributions collected. Prior to consideration of infrastructue and other implementation costs, this
puts A vista in a situation of a negative balance.
Only those customers contributing to the program funding through A vista Rate Schedule 191 are
eligible to receive fiancial incentives. This limits availability to core natural gas customers.
Periodically we claim the acquisition of natual gas savings from transport customers if those
efficiencies result from involvement in a project that is tightly interwoven with an electric-efficiency
project that was being evaluated and funded under the company's electric DSM program.
COOPERATIVE REGIONAL PROGRAMS
A vista has and remains interested in testing the viability of a regional market transformation
approach to the acquisition of natural gas-efficiency potentiaL. This model has proven to be
Avista 4.1.9
169
Appendix 4.1 - DSM Implementation & Operations 2009 Natural Gas IRP
successful within Northwest electric markets as evidenced by the success of the Northwest Energy
Effciency Allance (NEEA). Though recent efforts at parnering with NEEA and establishing
limited ad hoc regional efforts on the natural gas side have been unsuccessful, we will continue to
seek alliances with other Northwest utilities to advance this concept.
CONCLUSION
We have explicitly recognized within this IRP our obligation to achieve all natual gas-effciency
resources available through utility intervention of cost-effective programs. Given the rapid changes
within the natural gas market, many new effciency opportunities may arise in the market. The
Company wil continue to consider and evaluate any developing technologies for inclusion in our
programs between IRPs. Considerable uncertainty remains regarding the customer response to these
programs, since this is a time of economic uncertainty at a time when retail gas prices are declining.
Historically, we have seen less paricipation as prices decline. 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 actively seek, opportunities for new or enhanced
resource acquisition through the development of cooperative regional programs.
One of the results ofthe IRP process is a 20-year forecast of avoided costs for each ofthe eight
geographic areas. The detailed natue ofthese avoided costs makes it possible to continue to evaluate
measures and applications as technology and markets change without the need to await the next IRP
process. This is of value in determing program cost effectiveness based upon updated inputs,
revised program plans and the ability to determine the value of targeting specific markets. Avoided
cost determination is discussed in detail in Chapter 6 - Integrated Resource Portfolio.
The completion ofthe IRP analysis is the midpoint, not the ending point, of a larger reassessment of
the DSM resource portfolio. The IRP analysis presented has generally indicated a set of cost
effective measures and achievable resource potential for a future DSM portfolio. These results
remain in need of further evaluation to facilitate the development of program plans and to
incorporate them into an updated DSM implementation plan for use in daily DSM operations.
4.1.10 Avista
170
2009 Natural Gas IRP - APPENDICIES
APPENDIX 4.2
CONSERVATION MEASURES DETAIL
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2009 Natural Gas IRP - APPENDICIES
APPENDIX 4.3
SENDOUTCI SELECTED CONSERVATION MEASURES
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222
2009 Natural Gas IRP - APPENDICIES
APPENDIX 4.4
ENVIRONMENTAL EXTERNALITIES
223
2009 Natural Gas IRP
APPENDIX 4.4 - ENVIRONMENTAL EXTERNALITIES
(OREGON JURISDICTION ONLY)
OVERVIEW
The methodology for determining avoided costs from reduced incremental natual gas usage considers
commodity and variable transportation costs only. These avoided cost streams do not include environmental
externality costs related to the gathering, transmission, distrbution or end-use of natual gas.
Per traditional economic theory and industry practice, an environmental externality factor is tyically added to
the avoided cost when there is an opportity to displace traditional supply-side resources with an alternative
resource with no adverse environmental impact.
REGULATORY GUIDANCE
The Oregon Public Utility Commssion (OPUC) issued Order 93-965 (UM-424) to address how utilities
should consider the impact of environmental externalities in planning for futue energy resources. The Order
required analysis on the potential natural gas cost impacts from emitting carbon dioxide (C02) and nitric-
oxide (NOx).
The OPUC's Order No. 07-002 in Docket UM 1056 (Investigation Into Integrated Resource Planning)
established the following guideline for the treatment of environmental costs used by energy utilities that
evaluate demand-side and supply-side energy choices:
UM 1056, Guideline 8 - Environmental Costs
"Utilities should include, in their base-case analyses, the regulatory compliance costs they expect for
carbon dioxide (COiJ, nitrogen oxides (NOx), sulfur oxides (SOiJ, and mercury (Hg) emissions.
Utilties should analyze the range of potential C02 regulatory costs in Order No. 93-695,from $0-
$40 (1990$). In additon, utilities should perform sensitivity analysis on a range of reasonably
possible cost adders for nitrogen oxides (NOx), sulfur dioxide (S02), and mercury (Hg), if applicable.
In June 2008, the OPUC issued Order 08-338 (UM1302) which revised UM1056, Guideline 8. The revised
guideline requires the utility should constrct a base case portfolio to reflect what it considers to be the most
likely regulatory compliance future for the various emissions. Additionally the guideline requires the utility to
develop several compliance scenarios ranging from the present C02 regulatory level to the upper reaches of
credible proposals and each scenario should include a time profie of C02 costs. The utility is also required to
include a "trigger point" analysis in which the utility must determne at what level of carbon costs its selection
of portfolio resources would be significantly different.
ANALYSIS
Unlike electrc utilties, environmental cost issues rarely impact a natual gas utility's supply-side resource
options. This is because the only supply-side energy resource is natual gas. The utility canot choose
between say "dirty" coal-fired generation and "clean" wind energy sources. The supply-side implication of
environmental externalities generally relates to combustion of fuel to move or compress natul gas. Avista's
direct gas distribution system infrastructue relies solely on the upstream line pressure of the interstate
Avista 4.4.1
225
Appendix 4.4 - Environmental Externalities 2009 Natural Gas IRP
pipeline transporttion network to distribute natual gas to its customers and thus does not directly combust
fuels that result in any CO2, NOx, S02, or Hg emissions.
Upstream gas system infrastructue (pipelines, storage facilities, and gathering systems), however, do produce
CO2 emissions via compressors used to pressurze and move natual gas. Accessing CO2 emissions data on
these upstream activities to perform detailed meaningful analysis is challenging but increasingly important
given building momentum around legislative developments regarding GHG legislation and the movement
towards the creation of carbon cap and trade markets. A vista believes the cap and trade proposals being
contemplated are the likely form of environmental externality cost capture versus a carbon tax framework.
Under either structure, Avista believes the cost pass though mechanisms for upstream gas system
infrastrctue will not make a difference in supply-side resource selection although the amount of cost pass
through could differ widely.
Table 4.2.1 sumarizes a range of environmental cost adders we believe captue several compliance futues
including our expected scenario and upper reaches of credible proposals. The C02 cost adders reflect
outlooks we obtained from one of our consultants, and following discussion and feedback from the T AC,
have been incorporated into each of our six demad scenarios at various assumption levels.
The guidelines also call for a trigger point analysis that reflects a "turng point" at which an alternate
resource portfolio would be selected at different carbon cost adders levels. Because natual gas is the only
supply resource applicable to LDC's any alternate resource portfolio selection would be a result of delivery
methods of natual gas to customers. Conceptully, there could be differing levels of cost adders applicable to
pipeline transported supply versus in service terrtory LNG storage gas. From a practical standpoint however,
the differences in these relative cost adders would be very minor and would not change supply-side resource
selection regardless of various carbon cost adder levels. We do acknowledge there is influence on the level of
demand-side measures that could be cost effective. This alternate demand-side resource portfolio selection is
captued in our overall process of comparing demand-side and supply-side resources described in Chapter 4-
Demand-Side Resources.
CONSERVATON COST ADVANTAGE
For this IRP, we also incorporated a 10 percent environmental externality factor into our assessment of the
cost-effectiveness of existing demand-side management programs. Our assessment of prospective demand-
side management opportunities is based on an avoided cost stream that includes this 10 percent factor.
Environmental externalities were evaluated in the IR by adding the cost per therm equivalent of the
externality cost values to supply-side resources as described in OPUC Order No. 93-965. Avista found that
the environmental cost adders had no impact on the company's supply-side choices, although they did impact
the level of demand-side measures that could be cost-effective to acquire.
REGULATORY FILING
Avista wil fie revised cost-effectiveness limits (CELs) based upon the updated avoided costs available from
this IRP process within the prescribed regulatory timetable. We anticipate this wil occur in early 2010.
4.4.2 Avista
226
2009 Natural Gas IRP Appendix 4.4 - Environmental Externalities
Table 4.2.1 Enviornmental Externalities Cost Adder Analysis (2009$)
2015 2020 2025 2030
~$/100 $1,750 $1,237 $1,205 $1,119
c )($/Ib $0.88 $0.62 $0.60 $0.56..0 Ibs/iherm 0.008 0.008 0.008 0.008cz"..NOxAdder....$/ther $0.01 $0.00 $0.00 $0.00õi..$/100 $12.58 $16.69 $21.0 $27.19ii
~$/lb $0.0063 $0.0083 $0.0107 $0.0136..'".,0 lbs/iher 11.6 11.64 11.64 11.64..()(J..C02 Adder
~$/ther $0.0 $0.10 $0.12 $0.16..ii J! Total Adders)(w ~ $/therm $0.08 $0.10 $0.13 $0.16
2015 2020 2025 2030
$/100 $1,343 $1,140 $1,137 $1,268
)($/Ib $0.67 $0.57 $0.57 $0.63¡0 Ibs/iherm O.OO!0.008 0.008 0.008..zc NOxAdderc$/ther $0.01 $0.00 $0.00 $0.01..:3..$/100 $21.00 $46.00 $58.00 $71.00.,..$/lb $0.0105 $0.0230 $0.0290 $0.0355(J..'"
.!0 lbs/iherm 11.6 11.6 11.6 11.64u()..C02 Adder ii
il $/ther $0.12 $0.27 $0.34 $0.41
J! Total Adders
~ $/therm $0.13 $0.27 $0.34 $0.42
2015 2020 2025 2030
$/100 $1,343 $1,140 $1,137 $1,268
)($/Ib $0.67 $0.57 $0.57 $0.630Ibs/iherm 0.00!0.008 0.008 0.008z
NOxAdderf$/iher $0.01 $0.00 $0.00 $0.01.:"$/100 $46.45 $67.03 $96.74 $139.60IIc$/lb $0.0232 $0.0335 $0.0484 $0.0698..f '"0 lbs/therm 11.6 11.6'11.6'11.6'Cl ()
C02 Adder
$/iher $0.27 $0.39 $0.56 $0.81
J! Total Adders
~ $/therm $0.28 $0.39 $0.57 $0.82
2015 2020 2025 2030
$/100 $7,001 $4,947 $4,821 $4,475
~$/Ib $3.50 $2.47 $2.41 $2.24z)(
~0 Ibs/iherm 0.008 0.008 0.008 0.00z..NOxAdder.!$/ther $0.0 $0.02 $0.02 $0.02..
X $/100 $12.58 $16.69 $21.0 $27.19~$/lb $0.0063 $0.0083 $0.0107 $0.0136...,'"
11.64 11.6'..0 lbs/iherm 11.64 11.6(J ()..CO2 Adder.!u $/therm $0.0 $0.10 $0.12 $0.16..ii)(l Total Addersw
$/therm $0.10 $0.12 $0.14 $0.18
2015 2020 2025 2030
$/100 $5,373 $4,560 $4,547 $5,070)($/lb $2.69 $2.28 $2.27 $2.540z)(
~0 Ibs/iherm 0.008 0.008 0.008 0.008z
¡NOxAdder..$/ther $0.02 $0.02 $0.02 $0.02cc$/100 $21.00 $46.00 $58.00 $71.00..:3 $/lb $0.0105 $0.0230 $0.0290 $0.0355...,'"11.6'..0 lbs/iherm 11.64 11.64 11.6(J ()..C02 Adder.!u $/ther $0.12 $0.27 $0.34 $0.41&il l Total Adders
$/therm $0.14 $0.29 $0.36 $0.43
2015 2020 2025 2030
$/lon $5,373 $4,560 $4,547 $5,070
$/lb $2.69 $2.28 $2.27 $2.54)(
O.OO!0 Ibs/iherm 0.008 0.008 0.008)(z0 NOxAdderz
~$/therm $0.02 $0.02 $0.02 $0.02
f $/100 $46.45 $67.03 $96.74 $139.60
.g $/Ib $0.0232 $0.0335 $0.0484 $0.0698II'"C 0 lbs/therm 11.6'11.64 11.64 11.6'..()f CO2 AdderCl
$/therm $0.27 $0.39 $0.56 $0.81
l Total Adders
$/therm $0.29 $0.41 $0.58 $0.83
Avista
227
4.4.3
2009 Natural Gas IRP - APPENDICIES
APPENDIX 5.1
CURRENT TRANSPORTATION RATES
229
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2009 Natural Gas IRP - APPENDICIES
APPENDIX 5.2
ALTERNATE SUPPLY SCENARIOS SUMMARY OF
ASSUMPTIONS
233
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2009 Natural Gas IRP - APPENDICIES
APPENDIX 6.1
MONTHLY PRICE DATA
237
Appendix 6.1 . Monthly Price Data by Basin
2009$Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
Expected Case AECo 2009-2010 $ 4.33 $ 4.85 $ 4.97 $ 5.05 $ 4.99 $ 4.75 $ 4.65 $ 4.78 $ 4.80 $ 4.89 $ 4.90 $ 5.09~)_Âl~¡¡~'~.!,~",..-' $_ $'.~5.~$ ."5¡~i¡'lll'l,.&1a $ ,&.O$~~f$;_RJilii"$'i..Expected Case AECo 2011-2012 $ 5.46 $ 5.63 $ 5.73 $ 5.73 $ 5.42 $ 5.17 $ 5.17 $ 5.22 $ 5.22 $ 5.24 $ 5.22 $ 5.371I' rAE~2(,~'13' $.' .lf~l6..iiiJJ~;' .~~i;"~"'l.;~a $llill_rRiil5.5 .lij¡f_f%f'Mt~
Expected Case AECo 2013-2014 $ 5.11 $ 5.19 $ 5.25 $ 5.27 $ 5.06 $ 4.94 $ 5.01 $ 5.04 $ 5.06 $ 5.07 $ 5.03 $ 5.16~\~.. 2Of4'Jii~_\§Jö'li.;'.4,~\W;l)\!!JêO..L~M' ...t;l6_~\\1 . 7.2t¿.' 7.~lU"IlW'i
Exected Case AECo 2015-2016 $ 7.83 $ 7.97 $ 8.39 $ 8.42 $ 8.24 $ 8.13 $ 8.20 $ 8.27 $ 8.27 $ 8.29 $ 8.28 $ 8.37~ti~;ø.\!!räi!. ~.17.~~L.1l $ i.1~l"f'8.80 $J!.Ø...I!l?'"'" $ §::t", $;.!Li8.~'l;t~i.iLli;.¡_\Expected Case AECo 2017-2018 $ 9.40 $ 9.47 $ 10.34 $ 10.36 $ 10.03 $ 9.83 $ 9.78 $ 9.86 $ 9.85 $ 9.91 $ 9.89 $ 10.08
lIed~;ii,~'" $' i_$"~$ .för83Li61a!~.~,~t $ 1().3iLL_.~ $.iq.41'tf~Expected Case AECo 2019-2020 $ 10.91 $ 11.06 $ 11.22 $ 11.25 $ 10.71 $ 10.58 $ 10.56 $ 10.58 $ 10.61 $ 10.65 $ 10.34 $ 10.41~a tii~ÇQ¿02o.~t~'$ 1q.~~'1'.~f1..13 1i.""O.59 ¡~+~,~().66;;~,1l:z îl ".jl~Expected Case AECo 2021-2022 $ 10.91 $ 10.98 $ 11.14 $ 11.17 $ 10.91 $ 10.60 $ 10.61 $ 10.66 $ 10.61 $ 10.66 $ 10.67 $ 10.78~~_P~;3"',.12~i~f~ $ 11.1:~¡.11.12 $ 10.;ii_j1 $ 10.ll $ fO.~lò.ll 11~¡11'"j"'ExpectedCase AECo 2023-2024 $ 11.10 $ 11.18 $ 11.19 $ 11.16 $ 10.74 $ 10.61 $ 10.62 $ 10.65 $ 10.63 $ 10.68 $ 10.70 $ 10.71~~øCjii~; $'Ei$;~_ $fl3.$11.~1q,~.J~l).77 $ 10.7l~¡i_~~ $ 1().6Zl'ff~..tl);8IExpected Case AECo 2025-2026 $ 11.14 $ 11.29 $ 11.46 $ 11.45 $ 11.16 $ 10.97 $ 10.98 $ 10.99 $ 10.98 $ 11.02 $ 11.03 $ 11.06~:~AEC(_~262~;i $ _$ 11.~~ 11.~1.7111...I'l#.16 $ 1t:DI;21J1.27.lf.31:lr~' (.~ExpectedCase AECo 2027-2028 $ 11.55 $ 11.66 $ 11.88 $ 11.91 $ 11.51 $ 11.37 $ 11.40 $ 11.40 $ 11.45 $ 11.50 $ 11.55 $ 11.67~;"J~IU.11L,"~; .'f#Ã76 $.1~.$ 0(.;$12.11 -'13 S 11.55 ¡i"..;¡t;$ftøU~0'11.ll;; ..i.1;i.8';Exected Case AECo 2029-2030 $ 11.84 $ 11.84
Expected Case Malin 2009-2010 $ 4.67 $ 5.19 $ 5.32 $ 5.40 $ 5.26 $ 5.03 $ 4.91 $ 5.08 $ 5.13 $ 5.24 $ 5.24 $ 5.41~_~~1()~~n"i. $ __ S'~i¡; $.~I~!1iirJI~t $ 5,Ø;7~"'l~"frY!!.11 'l.;
Expected Case Malin 2011-2012 $ 5.74 $ 5.92 $ 6.00 $ 6.00 $ 5.65 $ 5.41 $ 5.40 $ 5.46 $ 5.48 $ 5.51 $ 5.49 $ 5.63II~M~_i! 201-' ....~.$Ä_r ";~~ SIJ:6 . ~i196' s 5.71l1_~'!¡¡5.7.l 5.61 .. .¡r 1M$' ~:~Expected Case Malin 2013-2014 $ 5.36 $ 5.45 $ 5.48 $ 5.51 $ 5.22 $ 5.14 $ 5.22 $ 5.24 $ 5.28 $ 5.31 $ 5.27 $ 5.40ExÇall~ íI15i\_6.33¡~!r.._s $ 1.~J4Q S7i~Z~r~1S.z.il . '''.~l 1,!.llæ;Z~.l $'WExpected Case Malin 2015-2016 $ 8.04 $ 8.18 $ 8.59 $ 8.62 $ 8.37 $ 8.30 $ 8.37 $ 8.44 $ 8.49 $ 8.51 $ 8.51 $ 8.58~~~, Mal.iLLi2l'l7 $. ..'~ $1!11ßl $ ~iaI a.Q5$ s~~ $ 6.11_)~n1 $ !lJlII1"$!$.Ø~.J."~U.lExpected Case Malin 2017-2018 $ 9.61 $ 9.69 $ 10.54 $ 10.57 $ 10.17 $ 10.01 $ 9.99 $ 10.05 $ 10.08 $ 10.16 $ 10.14 $ 10.31i~ M8!! 201ll~ie )_5'$Y1q.~'111,9! $ilR'JLlt"ig,l' S 1Ó,~i.1.\~!t53,.1()3$!Jf.~~;.$1~ExpectedCase Malin 2019-2020 $ 11.14 $ 11.28 $ 11.39 $ 11.44 $ 10.87 $ 10.76 $ 10.76 $ 10.78 $ 10.86 $ 10.89 $ 10.60 $ 10.64~fI__i.'~..~!f.O?..S.~,$ 1l'B.11.31 .glö $ 10.78'T$ '~"."$.'(li.l1~ìI";Ält).9f)."_le,ieExpectedCase Malin 2021-2022 $ 11.12 $ 11.20 $ 11.30 $ 11.34 $ 11.04 $ 10.78 $ 10.79 $ 10.84 $ 10.84 $ 10.89 $ 10.90 $ 10.98Ex~!:.I~20 . '11._~1.46..""!'Ì.59.$.¡!iiIåH$ 11.~¡1_$11.00 $.J;iO?l"!.;;!'$i.t,~!$ 10;9l.~Expected Case Malin 2023-2024 $ 11.42 $ 11.52 $ 11.46 $ 11.45 $ 11.00 $ 10.87 $ 10.90 $ 10.92 $ 10.98 $ 11.03 $ 11.07 $ 11.07lii4li;;;;18§"4. ~'" ~~~. .11.~S~lM?"r~!g~¡~!it\..11.ô9JL.$'11.14i"S;~'1!ExpectedCase Malin 2025-2026 $ 11.49 $ 11.64 $ 11.79 $ 11.80 $ 11.44 $ 11.27 $ 11.29 $ 11.30 $ 11.34 $ 11.38 $ 11.40 $ 11.42
~~;~?i~~S¡lli74 .. 1". 12.11I"~2.05 _1'$11,48 $ 1f~~$;11._f11,lI~1.67 lr!£!JI5ExpectedCase Malin 2027-2028 $ 11.91 $ 12.03 $ 12.20 $ 12.24 $ 11.79 $ 11.66 $ 11.72 $ 11.73 $ 11.80 $ 11.85 $ 11.91 $ 12.04~ç~ ..LJ~~ $li-.E..i.$1Žo=-$ 12.46!.~.01 ;$z!,ilß4 $ 11.90 $!_"""$12.ø$~J~!!'!'l2~Expected Case Malin 2029-2030 $ 12.20 $ 12.20
Expected Case Rockies 2009-2010 $ 4.42 $ 4.92 $ 5.05 $ 5.17 $ 4.99 $ 4.75 $ 4.70 $ 4.70 $ 4.78 $ 4.88 $ 4.94 $ 5.16~ti!~1~"o,""i!~~'$5,_ 5.IlYt" ~""ltRr'rl~!5.o1 $ 'jJ.~¡;¡¡~.Ø1l' lJ'El1'!lJRlI .
Exected Case Rockies 2011-2012 $ 5.60 $ 5.73 $ 5.84 $ 5.84 $ 5.46 $ 5.23 $ 5.25 $ 5.15 $ 5.22 $ 5.24 $ 5.21 $ 5.41~ C~es..IØ.~~!15.!I..$fíl;2l;!$6.25 S 5.66 $!J!\!~~.!~.'9 $ 5"~ $..¡~!&I ;$.0$ ...
Expected Case Rockies 2013-2014 $ 5.06 $ 5.10 $ 5.15 $ 5.19 $ 4.89 $ 4.84 $ 4.93 $ 4.83 $ 4.91 $ 4.93 $ 4.88 $ 5.03~~R~1f'"()l5 $ _llZ\i! $! i:~ $7.45 .j!1.~9i. $ 7.04;1.~!.! ""$ .7.09 $ t.()~. .$.J!lli)
Expected Case Rockies 2015-2016 $ 7.60 $ 7.73 $ 8.13 $ 8.16 $ 7.88 $ 7.84 $ 7.93 $ 7.86 $ 7.94 $ 7.95 $ 7.95 $ 8.04~.~2916-~líi_. 8.60" 8:91':JJ;$lI~~L..,"6.5:l;;~"3'M.1l~::"II.1I1", $ 11" I~Expected Case Rockies 2017-2018 $ 9.13 $ 9.16 $ 10.03 $ 10.06 $ 9.68 $ 9.57 $ 9.58 $ 9.51 $ 9.58 $ 9.64 $ 9.62 $ 9.83~Ça¡~s1l19""0.32l"~~iQl;$K~ $,!-19.23 $ 10.04 ~fi;$10.oq!$ 10.1f'1~.~$l",21'
Expected Case Rockies 2019-2020 $ 10.60 $ 10.71 $ 10.87 $ 10.91 $ 10.34 $ 10.29 $ 10.30 $ 10.19 $ 10.27 $ 10.31 $ 10.01 $ 10.10~;Ç~¡~"'¿021 $1Q.4~50 '.61 $1nil~.;f$" 10.40 $~_lfO.20 $ 10.09 S10.16i$1~;10.Q( '$~"'.
Expected Case Rockies 2021-2022 $ 10.41 $ 10.44 $ 10.58 $ 10.62 $ 10.33 $ 10.11 $ 10.14 $ 10.06 $ 10.08 $ 10.12 $ 10.14 $ 10.26
~. ~. 20.~ ;~¡";1íÒ.66 $l(10.83 $1_ 1Q,~$ fO_.I.t~JiiLL"~Ø.31 $ 1~fi$'!~jp.4~Expected Case Rockies 2023-2024 $ 10.74 $ 10.80 $ 10.91 $ 10.94 $ 10.56 $ 10.42 $ 10.47 $ 10.35 $ 10.40 $ 10.45 $ 10.49 $ 10.54
.~ ~..zæ5""Ø.83:"S fö:93 ,,1I,q¿ '_~;$ 10.80 $10~;.lIi.J().521Jfl10.56 ...$i~!l~~l10;~t!ExectedCase Rockies 2025-2026 $ 10.98 $ 11.10 $ 11.25 $ 11.27 $ 10.97 $ 10.77 $ 10.81 $ 10.66 $ 10.72 $ 10.75 $ 10.76 $ 10.82~C~îlf!R~ ~....l.1.15 $'1il$ 1t_1111.46_~$ 10.93$ 1Ö,~P$'1Q._;$t~ro.98M~.l\I
Expected Case Rockies 2027-2028 $ 11.24 $ 11.32 $ 11.52 $ 11.55 $ 11.20 $ 11.03 $ 11.09 $ 10.95 $ 11.06 $ 11.09 $ 11.15 $ 11.33;ø'~R~,\\¡._2(2l." $" .'.:4iP:47 .$~ St1¿iìf;'l'Ì1.35 .i;~lH.21'$Tm~ $.'l1:20.... Si~n.tt $;t_
Expected Case Rockies 2029-2030 $ 11.48 $ 11.48
239
Appendix 6.1 . Monthly Price Data by Basin
2009$Scenario Index Gas Year Nov Dec Jan Feb Mar Apr
Expected Case Stanfield 2009-2010 $ 4.53 $ 5.04 $ 5.17 $ 5.25 $ 5.14 $ 4.90,~~X~~~~10.2lf1f¡'(5.5& l" &:. $,.\t1!' S' '5'1 . IAS I' &:llf
Expected Case Stanfield 2011-2012 $ 5.62 $ 5.79 $ 5.88 $ 5.88 $ 5.55 $ 5.29~ê~ S~12.2(,~Efsl'5.69 $ 5.81 $ aM S iU9 $ 5.86 $ 5.62
Expected Case Stanfield 2013-2014 $ 5.25 $ 5.33 $ 5.38 $ 5.41 $ 5.15 $ 5.04~êd ca/ii m14i2(~'*_.~ ,. ,$ 6.35 . 7.66 $ 1.73 '..ì'l; 1.25
Expected Case Stanfield 2015-2016 $ 7.95 $ 8.09 $ 8.50 $ 8.53 $ 8.31 $ 8.22~¿.~~iad;2016.:?i1 J.89 $ 6.¡&_9.29 $ 9.28 $'8.$9 $ 8.78
Expected Case Stanfield 2017-2018 $ 9.52 $ 9.59 $ 10.45 $ 10.48 $ 10.11 $ 9.92'~~201i¡2t M~i¡,$ .lørBMO.9:.i tl1n;93 $10.65 $ .10.40
Expected Case Stanfield 2019-2020 $ 11.04 $ 11.18 $ 11.32 $ 11.36 $ 10.80 $ 10.67
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Expected Case Stanfield 2021-2022 $ 11.03 $ 11.10 $ 11.23 $ 11.27 $ 10.97 $ 10.69
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Expected Case Stanfeld 2023-2024 $ 11.28 $ 11.36 $ 11.34 $ 11.32 $ 10.88 $ 10.74
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ExpectedCase Stanfield 2025-2026 $ 11.33 $ 11.48 $ 11.64 $ 11.64 $ 11.31 $ 11.13
.~ itnfld ~$,11.$$ l 11:72 S1UltS 11.90 $' 11.9' $ 1t.4
ExpectedCase Stanfeld 2027-2028 $ 11.75 $ 11.86 $ 12.05 $ 12.09 $ 11.66 $ 11.52
i;~litL~.ti~20l\t'll,96 $ 12.08 $ 12.2é $ 12.30 $ 11.88 $ 11.71
Expected Case Stanfeld 2029-2030 $ 12.03 $ 12.03
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$ 8.29 $ 8.35 $ 8.38 $ 8.39 $ 8.39 $ 8.48$ 8.111 $ 8ilji $ à89 f$~r_ìiã.9ll'j%.
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$ 10.71 $ 10.75 $ 10.72 $ 10.77 $ 10.79$ 10.91 $,g,!I;t~""r~1U
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Expected Case Sumas 2009-2010 $ 4.63 $ 5.15 $ 5.28 $ 5.36 $ 5.23 $ 4.86 $ 4.64 $ 4.75 $ 4.78 $ 4.88 $ 4.91 $ 5.19
~~ . si'Hiæïìt~;(tb§;1Ø.)i'''ll'is.81 $' '6..' $~(;!.1~0~";ILS;~~¡1¡~I"!Jii(;llli'f;¡~tî;Sd if.. tl.is' $5.~1Expected Case Sumas 2011-2012 $ 5.71 $ 5.88 $ 5.99 $ 6.00 $ 5.63 $ 5.30 $ 5.18 $ 5.21 $ 5.22 $ 5.25 $ 5.24 $ 5,44
.~.Glift:t W~~t~l_li15.~~i;;l5 l ø,t;$"'f'§$;~61 $15.lJ1;;J';¡Jl:M~_l,;¡'5~l);¡liiS
Expected Case Sumas 2013-2014 $ 5.34 $ 5.43 $ 5.48 $ 5.51 $ - 5.21 $ 5.04 $ 5.03 $ 5.05 $ 5.07 $ 5.09 $ 5.07 $ 5.22~d~\= (~ii$(;tl'.._¡~j'1.1!'f~i;'I.iJ¡Ij.?;~ ~~_.l II $;i1;~i~1Expected Case Sumas 2015-2016 $ 8.02 $ 8.17 $ 8.59 $ 8.62 $ 8.37 $ 8.22 $ 8.24 $ 8.30 $ 8.30 $ 8.32 $ 8.34 $ 8.452 ~!JlÌif ~_,$8.91¡~_:. 9.3Ø $~~£I~¡ $: 8.78 1'~__;I.~;.¡.II~lr¡~;$ $ R.4 $'(1..)'
Expected Case Sumas 2017-2018 $ 9.60 $ 9.67 $ 10.54 $ 10.58 $ 10.17 $ 9.92 $ 9.82 $ 9.88 $ 9.88 $ 9.95 $ 9.95 $ 10.16
_fillæi£tSas ~ll:~l; $ 10.83 $1Ö:92 $ 11.4 $' n.o4 l 10.71 $ 10;39 $10.:. $ 1O¡ál1?l';fö:i4'?$'i(l.48 $10.45 $10.83
Expectep Case S~,'Tas 2019-2020 $ 11.12 $ 11.27 $ 11.43 $ 11.48 $ 10.87 $ 10.67 $ 10.61 ,$ 10.63 $ 10.65 $ 10.70 $ 10.3 $ 10.51ex~as 202021 $11.01 $ 11.14 $ 11.0 $ 11,35 $ 11.06 $ 10.69 $ 10.61 $ 10.8 $10.10 $ 10.7~t;.~.ExpectedCase Sumas 2021-2022 $ 11.13 $ 11.20 $ 11.37 $ 11.42 $ 11.04 $ 10.69 $ 10.67 $ 10.71 $ 10.66 $ 10.72 $ 10.75 $ 10.88
~i..U;§'iini~ 2022-20$¡ff,32 $ 11.46 $ 11.64 $ 11.69 $ 11.25 $ 10.97 $ 10.90 $ 10.90 $ 10.92 $ 10.841~(i1lExpectedCase Sumas 2023-2024 $ 11.38 $ 11.48 $ 11.50 $ 11.46 $ 10.92 $ 10.68 $ 10.64 $ 10.65 $ 10.64 $ 10.70 $ 10.74 $ 10.77~3i(:åse ~4-205 $,..1~.31 $ 11.43 $ 11.62 $ 11.71 $ 11.11 $ 10.86 $ 10.80 $ l11.sf $ 10.80 $10.~~;¡lt¡,n.m
ExpectedCase Sumas 2025-2026 $ 11.48 $ 11.63 $ 11.79 $ 11.80 $ 11.35 $ 11.07 $ 11.01 $ 11.01 $ 11.01 $ 11.05 $ 11.08 $ 11.14
~Glse tS~ 2026.207 ;;_~.71 $ 11.85 $ 12.06 $ 12.06 $ 11.48 $ 11.28 $ 11.26 $ 11.16 $ 11.22 $ 11.2E~¡II\ìlljW$Ø)*l~11,.ExpectedCase Sumas 2027-2028 $ 11.87 $ 11.99 $ 12.20 $ 12.24 $ 11.65 $ 11.48 $ 11.44 $ 11.35 $ 11.41 $ 11.46 $ 11.62 $ 11.76
Ê~CI~;!~'!Øl2g;~;;1n. $1~i:m1J_~~ $12.46 $ 11.92 $ 11.61 $ 11.62 $ 11.55 $ 11;58 $11;~l1.7'4$11;.
Expected Case Sumas 2029-2030 $ 11.93 $ 11.93
240
Appendix 6.1 - Monthly Price Data by Basin
2009$Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep OCt
Updated Expected AECo 2009-2010 $ 3.91 $ 4.43 $ 4.57 $ 4.56 $ 4.52 $ 4.33 $ 4.23 $ 4.34 $ 4.35 $ 4.41 $ 4.41 $ 4.58~d~2ò()201.1i4,tl l~Ul'ä.l~~,"l tm;ii:7$. $ i:'tl $ 4.l '$"d4".~ $4~%'~f,*jf.
Updated Expected AECo 2011-2012 $ 5.09 $ 5.24 $ 5.32 $ 5.32 $ 5.19 $ 4.93 $ 4.90 $ 4.95 $ 4.94 $ 4.97 $ 5.01 $ 5.14~ Aí 2012.~$:i~_';i¡'j,44 $ ~'.¡;~îÆ:4:~ $ 5:1l î 5.2 $5,00 $ 5,04 $..-:n:B.
Updated Expected.AECo ......2013-2014 $ 4.62. $~;69.. $4.85 $4;87 $ 4.66 $ 4..55 $ 4.55 $ 4.56 $ 4.52 $ 4.54 $ 4.57 $ 4.68"latll it ~')i;B14;2Å1B1 $.~i';.1l.57 $.,~l.37 $ ..2 $ 6.26 $ 6.27 .~~;, 6.2 f;dé.aq~_Updated Expected AECo 2015-2016 $ 6.75 $ 6.83 $ 6.84 $ 6.86 $ 6.69 $ 6.55 $ 6.55 $ 6.58 $ 6.55 $ 6.58 $ 6.61 $ 6.73
~'~~"~rmi..l!~id7.t'''$ 7.16~'f 6.70 $ .!!~6.M."t~a $_¡¡¡ii~miil;.
Updated Expected AECo 2017-2018 $ 7.07 $ 7.15 $ 7.18 $ 7.21 $ 6.65 $ 6.51 $ 6.48 $ 6.51 $ 6.48 $ 6.52 $ 6.55 $ 6.68~J)'?~cn_l~ ,_if' 1.0tdIJ;Z.,g§dii$'1.9Ø.idf $.~~ll~6.e¡'¡d_:n'6:68' $ tBtæl$ID
Updated Expected AECo 2019-2020 $ 7.16 $ 7.24 $ 7.26 $ 7.28 $ 7.04 $ 6.89 $ 6.87 $ 6.89 $ 6.86 $ 6.88 $ 6.92 $ 7.04,~~~i.. .~~1 $ 1~i.$dd~43 '.~'7.52 $;_~if $1I$?i"'~:~6'$?"f~ild_;~)1:~
Updated Expected AECo 2021-2022 $ 7.66 $ 7.74 $ 7.85 $ 7.88 $ 7.23 $ 7.03 $ 7.02 $ 7.05 $ 7.02 $ 7.05 $ 7.09 $ 7.20_~ a ~.~!~d$ 1,~e4 _.$ 1.63 $_l"7.Oldd~ $d_1.(ldd.' n.N' f.$Jj
Updated Expected AECo 2023-2024 $ 7.11 $ 7.17 $ 7.50 $ 7.45 $ 6.43 $ 6.33 $ 6.33 $ 6.36 $ 6.36 $ 6.39 $ 6.42 $ 6.53
~Il.t~ "-"$ ii.~1 $..._ $ 6.91 ..Me $ ..ii.6.55\_dl)~'_ i.:~;id"lr""
Updated Expected AECo 2025-2026 $ 7.06 $ 7.14 $ 7.08 $ 7.11 $ 6.87 $ 6.75 $ 6.75 $ 6.77 $ 6.74 $ 6.77 $ 6.80 $ 6.91_~¡ La 7_1 $_r7.3Qr...'I.S $ 7Jl6'.ll~.9 .....~ .;..~~~... $'1 lI'i'$$.ø.d$d1.~Updated Expected AECo 2027-2028 $ 7.36 $ 7.43 $ 7.37 $ 7.41 $ 7.05 $ 6.96 $ 6.96 $ 7.00 $ 6.97 $ 7.00 $ 7.04 $ 7.14~êo .,.5".'"1' $,_7.S+~'1.46 $. 7.~9¡¡.¡i)7~t_"fi..lli~3$;1 '~'''$'''"''.ill'.~,
Updated Expected AECo 2029-2030 $ 7.23 $ 7.23
Updated Expeft~d Rockies 2009-2010 $ 4.00 $ 4.50 $ 4.65 $ 4.68 $ 4.53 $ 4.33 $ 4.27 $ 4.26 $ 4.34 $ 4.39 $ 4.44 $ 4.65~ ¡~. dr~ lli4.ìl'i$'iIIl" Uf.-.l 5.04 $ 4.'1_'¡~'.1f.~ 'il'.f1â t4:~"\;lllf;'"'¡¡_
Updated Expected Rockies "ì011-20t2 $' 5.23 $5.34 $ 5.42' $ 5.44 $ 5.23 $ 4.99 $ 4.98 $ 4.87 $ 4.95 $ 4.97 $ 4.99 $ 5.18
l.i£ .~2ö~!¡iíi)13!.g¡i".5.30 'iI$ .5:l~Ä$ 5.21 $ 5.02 $("5.2$'4.92 $ 4.96 $ 5JlO $._~~~~ ~~ ~~4 $ ~ $ ~ $ ~ $ ~ $ ~ $ ~ $ ~ $ ~ $ ~ $ ~ $ ~ $ ~'li£_ 2014-20l_t 5.42$1~~;~ $ *.§l3~;1, 6.05 $ ßJ1 $ 11.96 $$.01 $ 6.01 $" 6:ó;ilF~löî
Updated Expected Rockies 2015-2016 $ 6.52 $ 6.58 $ 6.57 $ 6.61 $ 6.33 $ 6.26 $ 6.28 $ 6.17 $ '6.22 $ 6.24 $ 6.28 $ 6.40_lS~¡H . lili? ~201Ll6.si~ ~&l.~ $¡iø:~T"¡ä.31 $~jl$ ö~_lfft $ &"_'i',;;".
Updated Expected Rockies 2017-2018 $ 6.80 $ 6.84 $ 6.87 $ 6.91 $ 6.30 $ 6.25 $ 6.28 $ 6.17 $ 6.22 $ 6.25 $ 6.28 $ 6.42~"~F ;$ 0~4~$ 6.76 S.¡If,M $ 6.~~ I_Uj'.,;l¡fil 1i'4lI'Ftfll
Updated Expected Rockies 2019-2020 $ 6.85 $ 6.90 $ 6.91 $ 6.94 $ 6.67 $ 6.60 $ 6.61 $ 6.49 $ 6.52 $ 6.55 $ 6.58 $ 6.72~~~~1 $;'-i1'.02~'1.lj""$7,10 tE;Ö.8S $ '.öJI &.75.JlIi~..' __
UpdatEld E!'pec\ed Rockies 2021:2022 $ 7.16. $ 7.20 $ 7.29 $ 7.33 $ 6.65 $ 6.54 $ 6.55 $ 6.44 $ 6.48 $ 6.51 $ 6.56 $ 6.69Upd ~.' ~.20 ~$ 7.oI 6,99 $ 7m_"il.68.i¡..IIU~d$ I _7¡';$í!.~jl;6:M
Updated Expected Rockies 2023-2024 $ 6.75 $ 6.79 $ 7.22 $ 7.24 $ 6.25 $ 6.15 $ 6.18 $ 6.07 $ 6.13 $ 6.16 $ 6.21 $ 6.36
uida~. ~4.2025;~ $ 6,_,ö".~ $ ,_ 6I1iillji;mlJl~$._+p $ 6.~1.:$;;IMiö
Updated Expecìed" Rockies 2025-2026 ""$ 6.90 $ 6.95 $ 6.88 $ 6.92 $ 6.68 $ 6.55 $ 6.59 $ 6.44 $ 6.48 $ 6.51 $ 6.54 $ 6.68UPd~R~2027 ~ $ 7.~~";t$ 7;31";~~6.tirt_Ii._"j~$;~ $~.~=.~ted Bt~;'l::~~,i~~ l;:~~¡~.;~ ;.:g:y,~".~",l.ii.~~:~,~i'~::;y~..."~i:;
Updated Expected Rockies 2029-2030 $ 6.88 $ 6.88 '". d, 8£, "" " .,' '" ""
241
Appendix 6.1 - Monthly Price Data by Basin
2009$Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
Updated Expected Stanfield 2009-2010 $ 4.11 $ 4.63 $ 4.77 $ 4.77 $ 4.67 $ 4.47 $ 4.36 $ 4.50 $ 4.53 $ 4.58 $ 4.59 $ 4.75
lJ .'lf/Y~2Ó1o-2l1t'$J:(ll"f;~rl''(~;''j_''''l:-lltfj"l.,'. '4.-1l,l.lIldli'.i' ~.'l.~0l~+:$i;'~'l
Upd~ted Expe!;t~d Stanfield. 2011-2012 $ 5.25 $ 5.39 $ 5.47 $ 5.47 $ 5.32 $ 5.06 $ 5.03 $ 5.08 $ 5.07 $ 5.11 $ 5.14 $ 5.28~ ~: 2Ø12"2O$!~~ . $..!.4O$'lf.llJ.",,6l l' 5;4 $'6:t7'. lít4': t5.1& $'."'t:7"'l"i£~hS&~25 $/5;~
Updated Expected Stanfield 2013-2014 $ 4.76 $ 4.83 $ 4.97 $ 5.01 $ 4.75 $ 4.64 $ 4.65 $ 4.66 $ 4.63 $ 4.66 $ 4.69 $ 4.81
~~ JIl' 2014:?9Jli $ 5.68 $ 5.1e $ 8.. $ e.7' $ 6.45 $ 8.34$ 6.3& $' 6.36 $~~~._,-(l'$"6:54~~~~ ~~ ~~6 $ ~ $ ~ $ ~ $ ~ $ ~ $ ~ $ ~ $ ~ $ ~ $ ~ $ ~ $ ~O~~~1I 2016:?9t1 $ 7.17 $ 1:i $ 727 $ 7.31 S 6.79 $ 6,68 $ 6.68 $ 6.70 $ir~l;l'r;ll;1f0;:S1'l.15 $ 6.8~
Updated Expected Stanfield 2017-2Ó18 $ 7.19 $ 7.27 $ 7.29 $ 7.33 $ 6.73 $ 6.60 $ 6.59 $ 6.61 $ 6.59 $ 6.63 $ 6.67 $ 6.80
lJ¡)îllll'¡;x~;~ 201~~ft!!.. $ 7.12 $ 721 $ n5 S 7.19 $ 6,90 $ 6,78 $ 6.6 $ 6.17$&,7§''$/ll,nil.~!!,~ $ 6.91
Updated Expected Stanfield 2019-2020 $ 7.29 $ 7.37 $ 7.36 $ 7.39 $ 7.13 $ 6.98 $ 6.97 $ 6.99 $ 6.98 $ 7.00 $ 7.05 $ 7.16U~~!Re 202~JJil'i~ $ 7.66 S 7.58 $ 7.62$,;_,~~~JI.7~~i:7,~7 $ t.~r::$/~_ll%f' Ii
Updated Expected Stanfield 2021-2022 $ 7.78 $ 7.86 $ 7.94 $ 7.97 $ 7.29 $ 7.12 $ 7.12 $ 7.14 $ 7.13 $ 7.16 $ 7.21 $ 7.31
~i tt'¥l ; ,'t:6t, S.7,7Ilr.-.Y1'.72 :$.~~l1;1i;.¡¡ FFpp¡¡¡l¡¡7Jl:~ft
Updated Expected Stanfield 2023-2024 $ 7.29 $ 7.35 $ 7.65 $ 7.62 $ 6.57 $ 6.47 $ 6.47 $ 6.51 $ 6.54 $ 6.57 $ 6.61 $ 6.721I~1 SIrll&W:iddddi' T~,;:l. 't$7,oe,_~;31 $ 6.$$$6.1 l~t"I.__.~~"9'
Updated Expected Stanfield 2025-2026 $ 7.25 $ 7.33 $ 7.26 $ 7.30 $ 7.02 $ 6.91 $ 6.92 $ 6.93 $ 6.92 $ 6.95 $ 7.01 $ 7.11IIEX--illI ! .~.$ 1.41'1,._ $ 7.7Š_t1;; $ 7.01$,7.03 $o1,MI~J~J¡~:.
Updated Expected Stanfield 2027-2028 $ 7.55 $ 7.63 $ 7.55 $ 7.58 $ 7.21 $ 7.11 $ 7.13 $ 7.17 $ 7.14 $ 7.18 $ 7.22 $ 7.341I~ II"' F~ $ 7.ff$';'I1.. $7.68~iê1' $ 7.24'$'7.2 $ .i.~~;¿;f~:$;¡t~,
Updated Expected Stanfield 2029-2030 $ 7.42 $ 7.42
Updated Expected Sumas 2009-2010 $ 4.22 $ 4.73 $ 4.88 $ 4.88 $ 4.77 $ 4.43 $ 4.22 $ 4.31 $ 4.34 $ 4.40 $ 4.42 $ 4.68
II II ;~ii2O'l' S25.1l".-l'C.'llf&:4fl' q~~~"'d$ži"l ii_iF '1:'y- ll.1l lilj~td'l\'4:6f':i$'''~JÜl:~
Updated Expected Sumas 2011-2012 $ 5.34 $ 5.49 $ 5.58 $ 5.59 $ 5.40 $ 5.06 $ 4.92 $ 4.94 $ 4.94 $ 4.97 $ 5.03 $ 5.21
lI~l ~ii"'2O2.æf3 $ $.1 $5.l if !S.6l'$ 5.11 $ It47 $ 1S.17 .. 6.ô4 $ 6.l16 $~~~J'kj5.~j".~i$l~
Updated Expected Sumas 2013-2014 $ 4.85 $ 4.92 $ 5.08 $ 5.11 $ 4.81 $ 4.64 $ 4.57 $ 4.57 $ 4.54 $ 4.56 $ 4.61 $ 4.74\Q~ Sumas 2014-2015 $ 5.n $ 5.8 $ 8.19 $ 6.82 $ 6.5 $ 6,34 $ 6:29,$'6.9 $ 6~,¡¡ì,s~$;~ii35 $'6:.m
Updated Expected Sumas 2015-2016 $ 6.94 $ 7.02 $ 7.04 $ 7.07 $ 6.82 $ 6.64 $ 6.59 $ 6.60 $ 6.58 $ 6.61 $ 6.67 $ 6.81
l&al.~ sî. 2016'2017 $ 7.2 $ 7.3 $ 7.37 $7,41 $ 8.84 $ 6.67 $ 6.63 $ 6.63 $ 6.60$,6.63$'~ll $6~Updated Expected Sumas 2017-2018 $ 7.27 $ 7.35 $ 7.38 $ 7.42 $ 6.79 $ 6.60 $ 6.52 $ 6.54 $ 6..,52......,,$..,1'.,6;5.5.$ 661 .$~7~
1.'EXed,_ 201~~l' $ 721 $ 7.2 $ 7~~$ 7.31 $ 6.96 $ 6.75 $ 6.71 $ 8.71 $ 8.&~~;~ikill¡~78 .,dlíí~Updated Expected Sumas 2019-2020 $ 7.38 $ 7.45 $ 7.48 $ 7.52 $ 7.19 $ 6.98 $ 6.92 $ 6.93 $ 6.91 $ 6.93 $ 7.00 $ 7.14l,alJ:ícl ¥~~1 n'7~r' $ 1.65 $~.:S 1.74 $ 't~t'J;~i?r~¡;~J't'.2?'t$ 7.23 $~ .. e
Updated Expected Sumas 2021-2022 $ 7.88 $ 7.96 $ 8.08 $ 8.13 $ 7.36 $ 7.12 $ 7.08 $ 7.09 $ 7.07 $ 7.11 $ 7.17 $ 7.301I~¡i i~ä.i¡¡l 7.16 $r~_JL$ 7.84 $7.41$ 7.17 $'1.11ld~~" 7 Wi
Updated Expected Sumas 2023-2024 $ 7.39 $ 7.47 $ 7.80 $ 7.75 $ 6.61 $ 6.40 $ 6.34 $ 6.36 $ 6.37 $ 6.41 $ 6.46 $ 6.59, ~" ;;~~. 7.15 $j7~¡$ 7.23 $ 6,85 $6.63$.it~"¡l_I.._¡¡ l~i;
Updated E~p~~t~d Sumas 2025-2026 $ 7.40 $ 7.48 $ 7.41 $ 7.45 $ 7.06 $ 6.85 $ 6.79 $ 6.79 $ 6.77 $ 6.80 $ 6.86 $ 6.99
~.~'l\~;f~~l 7.5 $'t,n,'DIr$:7.9 $ 7.11 $ 6.lt$6~j$j~íll,;~,"l"¡~¿ lL
Updated Expected Sumas 2027-2028 $ 7.68 $ 7.75 $ 7.70 $ 7.73 $ 7.20 $ 7.07 $ 7.00 $ 6.95 $ 6.93 $ 6.96 $ 7.10 $ 7.23
J *fi; Sullål¡'.,i'~2t$ 7.81 $7;él$jll $1.84 $7.41 $ t:i$"7.14$~.;lV'1lfll'llifÆ;lhi1_~~
Updated Expected Sumas 2029-2030 $ 7.32 $ 7.32
242
Appendix 6.1 . Monthly Price Data by Basin
2009$Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
High Growh Low Price AECo 2009.2010 $ 5.44 $ 5.80 $ 5.49 $ 5.53 $ 5.44 $ 4.79 $ 4.84 $ 4.92 $ 4.99 $ 5.07 $ 5.08 $ 5.13~~~(j2ói::~l.!).~!'y~i.9ll~ $.....!l..l!\\~'i..d~.-2l."M*'¥f.ãl;
High Growth Low Price AECo 2011-2012 $ 5.76 $ 5.89 $ 5.76 $ 5.78 $ 5.63 $ 4.92 $ 4.91 $ 4.98 $ 5.04 $ 5.09 $ 5.13 $ 5.17liGi344i lib ~d~1t~~ "!.~;~8ö' .. 6;1lJ~15 \'i~i..1-8l.2 '~.mMì"!fll:ll¥"'i.I$7S:II
High Growth Low Price AECo 2013.2014 $ 5.30 $ 5.32 $ 5.09 $ 5.12 $ 4.98 $ 4.39 $ 4.38 $ 4.44 $ 4.47 $ 4.49 $ 4.50 $ 4.53;!lhGr9li~ N/JllltF 2(l4¿?l'I.iJL"!II!rt\l_r¡ $ø¡a_.\¡~~i$ 6_6,1~mr_~r'8~' .. &,
High Growth Low Price AECo 2015-2016 $ 6.92 $ 7.07 $ 7.17 $ 7.22 $ 7.12 $ 6.44 $ 6.44 $ 6.42 $ 6.53 $ 6.51 $ 6.56 $ 6.63
Hi ¡1r~ ".li ~Lli~!l;~fêtmt..i~1J;06 $ . G..:¥ $ G.~.l.$. .6.41 $ 6.42 $ G~IM4f_
High Growth Low Price AECo 2017-2018 $ 7.13 $ 7.16 $ 7.73 $ 7.76 $ 7.60 $ 7.01 $ 7.04 $ 7.05 $ 7.09 $ 7.09 $ 7.08 $ 7.11
~f'l.-~$?;'i$ 7.'i__dU$ 7.ll"$ 7.53 $ 6.95 $ t¡.96 $..6.98 $ 6:ìl $,i_;'$\". IJ
High Growth Low Price AECo 2019.2020 $ 7.69 $ 7.73 $ 7.60 $ 7.63 $ 7.55 $ 6.87 $ 6.89 $ 6.92 $ 6.98 $ 6.96 $ 7.03 $ 7.12~Lo~Co,~II~' $ 't,.ll:~$ 7'_J1.8ö $ 7.82 $ 7.15 (~~9Øi~; $ 7,~i'ili;it__ft'"iR too'"
High Growth Low Price AECo 2021-2022 $ 7.61 $ 7.65 $ 7.65 $ 7.67 $ 7.49 $ 6.94 $ 6.97 $ 7.00 $ 7.03 $ 7.04 $ 7.08 $ 7.12~;~~~$o~~i._ $ tl" 7.?ii'il7.~i$7.78 $ 7.64 $ 1.() ri¡;i1.08 $7.j~¡fl;rl:"'1~1 ,.High Growth Low Price AECo 2023-2024 $ 7.88 $ 7.90 $ 8.02 $ 8.00 $ 7.84 $ 7.24 $ 7.27 $ 7.32 $ 7.34 $ 7.35 $ 7.41 $ 7.47flîgGr..!\~PrfJ AB 20_ $ ..øm U4.12 $._l(19 $'fi1¡íH~$ 7.4 $ 7.44 $ 7.48 $ t.!)t.rU¡¡"'~!r.
High Growth Low Price AECo 2025.2026 $ 8.28 $ 8.23 $ 8.36 $ 8.35 $ 8.19 $ 7.59 $ 7.62 $ 7.66 $ 7.68 $ 7.68 $ 7.73 $ 7.79Hlgh~ Alr~20?1 ':l'. lItp $'" 8.52",;i~JA\5'~.ll;U $ 7._.7.Øi""~$ 7_.'1.ll:
High Growth Low Price AECo 2027-2028 $ 8.55 $ 8.56 $ 8.71 $ 8.76 $ 8.60 $ 8.01 $ 8.02 $ 8.06 $ 8.07 $ 8.11 $ 8.11 $ 8.16m~ ~d;,._.~;~il $d"~§,$ 8.91iJf$\lj._iir;19 $a.;lf~~\'m~ $ 8_;i.1$;"II,
High Growth Low Price AECo 2029-2030 $ 7.25 $ 7.61
High Growt Low Price Malin 2009-2010 $ 5.57 $ 5.93 $ 5.59 $ 5.84 $ 5.54 $ 4.86 $ 4.90 $ 4.98 $ 5.06 $ 5.16 $ 5.15 $ 5.21~liPl.~¥k' ~1o:20~ 5.91",.~(ir05" 'ØI $ $:".1\14 $¡i~.. 5. '$:'~ $.8.33 l lJ!6~I;"~
High Growth Low Price Malin 2011-2012 $ 5.86 $ 5.99 $ 5.86 $ 5.88 $ 5.62 $ 4.97 $ 4.94 $ 5.01 $ 5.08 $ 5.14 $ 5.18 $ 5.23~~f. "''''21~ $ ~91 "* 8.1~17 'd,I?~J 5.29, $ 5.30 $ 5.31. ,$. s.4ò'l'l'll.4Ø'lw;t..High Growth Low~Price Malin" 2013:2014' $ 5.43 $ 5.45 $ 4.99 $ 5.02 $ 4.81 $ 4.38 $ 4.34 $ 4.46 $ 4.49 $ 4.52 $ 4.53 $ 4.58
HlGr iim .~' 2O~ ;..1'"5.~i li' i~im13S~l!$ 6.1l$ 6.06$"~~~~ø:29q$ 6.29 $ 6;1. ~ 6..
High Growth Low Price Malin 2015-2016 $ 7.06 $ 7.15 $ 6.99 $ 7.42 $ 6.71 $ 6.27 $ 6.27 $ 6.45 $ 6.57 $ 6.56 $ 6.62 $ 6.72HihGíPl:" ~j~$'_7.53/;¡_1;6.99 $~?3 $ 6.23 $ 8.31 $ 6.28 $ 6.41 $ 6~'4",~
High Growth Low Price Malin 2017-2018 $ 7.17 $ 7.17 $ 7.51 $ 7.55 $ 7.29 $ 6.90 $ 6.94 $ 6.94 $ 7.08 $ 7.09 $ 7.08 $ 7.13HlGr"R f.';al32019~;'.illl~ $ '.¿t: 7.8â~f"7._":41 $ .~$ ..9!i'1lfaì $ 611?tJ.97 $7,,la.
High Growth Low Price Malin 2019-2020 $ 7.89 $ 7.92 $ 7.49 $ 7.52 $ 7.52 $ 6.80 $ 6.81 $ 6.86 $ 6.95 $ 6.92 $ 7.02 $ 7.15li~lO~í Main..~2021~~7.95 $7."~ 8.01 $ 8.aI~$ 7.71 $ii $~~&.91 $ 8.94 ~":$ 6.91;Í;l'
High Growth Low Price Malin 2021.2022 $ 7.74 $ 7.82 $ 7.73 $ 7.76 $ 7.59 $ 6.79 $ 6.79 $ 6.81 $ 6.85 $ 6.87 $ 6.95 $ 7.02Ii.Gro lo. MaI~2.2023' $ 1~Ìl.., $;~) 7.82 $ 1;8 $ 7,73 i1B ;1I' $ 6.lt:~.lfÆ::B96 t~_17
High Growth Low Price Malin 2023.2024 $ 8.06 $ 8.14 $ 8.13 $ 8.10 $ 7.94 $ 7.04 $ 7.06 $ 7.12 $ 7.15 $ 7.16 $ 7.28 $ 7.42
.lIlliviI'ì:Ó\..!f.. .iI~24-_ $~8:40 $ 8.3:l;¡nl.30 $ B.07 -:"$ 7.19 $ 7.21 $ 7.26 $ 7.28 $ 7.32 l"M:l~::
ïi1~~~c=.:'~ : ~:; : ::~;~ 1.¡~t~:~t.t;:~ : ;:~Ltl:;J.Jii :';:~~f\t~~High Growth Low Price Malin 2027-2028 $ 8.84 $ 8.82 $ 8.86 $ 8.89 $ 8.77 $ 7.80 $ 7.82 $ 7.85 $ 7.85 $ 7.91 $ 7.99 $ 8.12'fgh~ Mi' 2028~~~K l;IQ1. $ 9.08 !l,¿e.Ol¡~~l 8.1l8.01..J¡_lIl,- iilJ.
High Growth Low Price Malin 2029.2030 $ 8.32 $ 8.32
High Growth Low Price Rockies 2009.2010 $ 4.21 $ 4.62 $ 4.32 $ 4.39 $ 4.19 $ 2.46 $ 2.51 $ 2.59 $ 2.68 $ 2.75 $ 2.75 $ 2.831i~~2~!.1I1IHO-201J1'UO..~' 4,91 $l.'. 'l.~:~ ..~:Ø'; .0~.' 1'.l.""l'($."iI~.
High Growth Low Price Rockies 2011.2012 $ 5.77 $ 5.90 $ 5.77 $5.80 d $ 5.55 $ 4.92 $ 4.91 $ 4.94 $ 5.00 $"5:03 $ 5.03 $ 5.07~~.~ "i'21~~ $ 5;~"f'6.~$¿.f1i $ !i~'.~:15 $,;$.15 $ 5.ge $5.22 $ 5.26 $ $.2Tnffl'~
High Growth Low Price Rockies 2013.2014 $ 5.04 $ 5.05 $ 4.81 $ 4.84 $ 4.57 $ 4.17 $ 4.15 $ 4.17 $ 4.16 $ 4.18 $ 4.18 $ 4.211i~~RC 1!14-20_ $~4$._f$ G.55 $:mt$ ~t~d1!1"'!I;d$5'~ ..¡¡,~
High GroWih'LowPricè Rockies 2015-2016" $ 6.6"D $ 6.73 $ 6.81 $ 6.84 $ 6.55 $ 6.10 $ 6.15 $ 6.14 $ 6.18 $ 6.16 $ 6.18 $ 6.24ll Grì.O!i ~?ò1B.7 .'-,6.85$ .l!.l1; $. G.83 $ 6.$6. $ 6.10'1,'6.17 Üff~¡$'~~'l;dllid
High Growth Low Price Rockies 2017-2018 $ 6.79 $ 6.81 $ 7.38 $ 7.41 $ 7.17 $ 6.74 $ 6.79 $ 6.80 $ 6.83 $ 6.84 $ 6.82 $ 6.84Hi~ RlI\ ~ih201~_h$;~!4:l.'.....$.!,~:~ '$'ffl~!J$"';lr;,~il5$".G.ßf&.~~~ri&\~I' &li~.
High Growth Low Price Rockies 2019-2020 $ 7.30 $ 7.35 $ 7.24 $ 7.28 $ 7.18 $ 6.65 $ 6.69 $ 6.72 $ 6.75 $ 6.77 $ 6.82 $ 6.87ll~1, f'LLJ.RQces.lli!1 _0:$ 7.4lJLII"1$1.5!. $ 7.34 $ G.79 $ 6.83 $ 8.5 $ 8.7 $ 6...l?s~ii $ 6..
High Growth Low Price Rockies 2021-2022 $ 7.49 $ 7.59 $ 7.65 $ 7.69 $ 7.45 $ 6.91 $ 6.95 $ 6.98 $ 7.02 $ 7.04 $ 7.07 $ 7.12
~t.~¿R~23/;1!',"IlT4 $ 7.~Øc,$ 7.å6" "$ 7.72 $ 7.09 $1i::r+$1.16 $ 7.2 $ 7~!l''t:2e ...'t.
High Growth Low Price Rockies 2023-2024 $ 7.98 $ 8.01 $ 8.11 $ 8.10 $ 7.92 $ 7.32 $ 7.35 $ 7.39 $ 7.42 $ 7.44 $ 7.48 $ 7.56~Lo~kis/~_$ 8.16' $Pä.~,_:lB.~f-i'Ó .~1".~ $..~'1;.,iS $ 7.59 $ f.ft' $7.66 $7.7';
High Growth Low Price Rockies 2025-2026 $ 8.38 $ 8.34 $ 8.47 $ 8.45 $ 8.26 $ 7.67 $ 7.70 $ 7.73 $ 7.76 $ 7.76 $ 7.79 $ 7.83ll'Gró";,!l"TRl!!dIIl~20"t¡, $a,jl.,r;'$.~¡13 $ M~.¥$ 7.et~'l\l~1Ji¡".p' $i¥~~'High Growth Low Price Rockies 2027-2028 $ 8.66 $ 8.71 $ 8.82 $ 8.85 $ $ 8.17 $ 8.18 $ 8.22 $ 8.25 $ 8.31HigGr%1 Ii R~4.202.$~..'~~" 9.02 $_ $ ~l;.i_=a,yi 4.
High Growt Low Price Rockies 2029.2030 $ 6.78 $ 7.13
243
Appendix 6.1 . Monthly Price Data by Basin
200$Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep OC
High Growth Low Price Stanfeld 2009-2010 $ 5.51 $ 5.88 $ 5.54 $ 5.58 $ 5.49 $ 4.82 $ 4.86 $ 4.94 $ 5.02 $ 5.09 $ 5.10 $ 5.17/;g!Gt..~~ ~í"il~)J. 00 $ &',ll'''().'Cl'.-'lIt '$HUII) $!t.8-tltoIF' 5.10 $ 5.1~"'d$;37
High Growth Low Price Stanfeld 2011-2012 $ 5.80 $ 5.93 $ 5.80 $ 5.82 $ 5.68 $ 4.92 $ 4.90 $ 4.97 $ 5.03 $ 5.08 $ 5.13 $ 5.17Hlg!~""lfÖf3o/~,'..5.l!5'8;22 $ 6.20 $ 6.05 '.!;;~ $ 5.25 S5.~:;:¡i'::s:~'"~äi
High Growth Low Price 'Stanfeld 2013-2014 x $ 5.37' $ 5.38 $ 5.15 $ 5.18 $ 5.05 $ 4.37 $ 4.30 $ 4.41 $ 4.44 $ 4.46 $ 4.48 $ 4.52f1~"i:nce ~ø 2Ói~~1J_l§17 $ 5.a4 $ 6.8' $$.93 $ 6.87 $ 6.1 $ 6.11 $llll E&.B:~;$";$tiLlii_
High Growth Low Price Stanfeld 2015-2016 $ 7.01 $ 7.17 $ 7.27 $ 7.33 $ 7.25 $ 6.44 $ 6.42 $ 6.39 $ 6.51 $ 6.49 $ 6.55 $ 6.65
_~ i.fl S~'2ai~.îll;38 $ 7A4 $ 7~ $ 7;42 $ 7.19 $ 6.35 $ 6.37 $&_l:ø.~\\J;~~r~
High Growth Low Price Stanfeld 2017-2018 $ 7.23 $ 7.24 $ 7.82 $ 7.85 $ 7.71 $ 6.95 $ 6.96 $ 6.96 $ 7.01 $ 7.01 $ 7.00 $ 7.05~Pr St ?Qi/l~!ii~~1.l¡.7.85 $ 7.s-. '.ttå $ 7.77 S 7.64 $ 6.88 $ 6.86 $ 8.~~''lUIIIlIlE1JJi.
High Growth Low Price Stanfield 2019-2020 $ 7.78 $ 7.81 $ 7.69 $ 7.72 $ 7.67 $ 6.76 $ 6.76 $ 6.79 $ 6.87 $ 6.83 $ 6.93 $ 7.06f1ßrol;QWPrlci ;:~r~201" 1-7:85 $ 7.84;C" 7.90 $ 7.92 $ 7.61 $ 8.M $ 6.82$,6.ö3 $ 6.86 S 6.~' £$
High Growth Low Price Stanfield 2021-2022 $ 7.64 $ 7.72 $ 7.63 $ 7.65 $ 7.49 $ 6.70 $ 6.71 $ 6.74 $ 6.77 $ 6.78 $ 6.86 $ 6.93HiQtGt.l9wPr~eld 20-20:~!:tn $ 7.~'l7.71 $ 7.13"" 7.62$6."I.íHl.:l\?'~l~ $ 6.ll"I;t'*,U ..
High Growth Low Price Stanfield 2023-2024 $ 7.95 $ 7.99 $ 8.02 $ 7.99 $ 7.83 $ 6.95 $ 6.98 $ 7.04 $ 7.06 $ 7.07 $ 7.19 $ 7.30
HighG_LOP!~I_.lf 204-20 "'5$ 8.20 $ &:2& "$, 8.21 So8-i~"~21 1_l~$i:9 $ 7i~. I ì3
High Growth Low Price Stanfield 2025-2026 $ 8.44 $ 8.33 $ 8.39 $ 8.36 $ 8.20 $ 7.26 $ 7.29 $ 7.33 $ 7.34 $ 7.35 $ 7.47 $ 7.59l-igGt I-iw ~eI 2020 $ 8.48 $ 8.46 $ 8.54 S 8;ii.2C~$.!t~~17.55 $ it. ! ".6
High Growth Low Price Stanfield 2027-2028 $ 8.67 $ 8.65 $ 8.73 $ 8.77 $ 8.65 $ 7.70 $ 7.70 $ 7.74 $ 7.74 $ 7.79 $ 7.85 $ 7.95Hig~~nfid 202029 0 $ 8.6 $' 8.M $ 8.f¡ $;$.97 $ 8.85$ 7.!I,JJ~:ì~1 II !11B~.e $7.8 SIl,g$.-
High Growh Low Price Stanfield 2029-2030 $ 8.15 $ 8.15
High Growth Low Price Sumas 2009-2010 $ 5.65 $ 6.01 $ 5.70 $ 5.75 $ 5.54 $ 4.88 $ 4.84 $ 4.89 $ 4.98 $ 5.06 $ 5.11 $ 5.22~(.r:~_IIII_' 0' $'"'ìl2~~"l'_1 =S&,2£I\iit5.1~.:$ !l'I.¡~~HighGr~ =. ~Wi012~:.~~..~:~ : '~~.~tdt,~.: ;:~.~j. ~:~,,~,s;'~ 1~:~ :$~~
High Growth Low Price Sumas 2013-2014 $ 5.51 $ 5.53 $ 5.30 $ 5.33 $ 5.09 $ 4.46 $ 4.40 $ 4.43 $ 4.47 $ 4.50 $ 4.54 $ 4.61
~, 11I~f4~l~li¿ $'.tmlUilllr.&3 $"7.00 $6,9t~_ ~.;If.2''JLlz_ $~.~!~
High Growth Low Price Sumas 2015-2016 $ 7.15 $ 7.29 $ 7.37 $ 7.41 $ 7.25 $ 6.54 $ 6.49 $ 6.46 $ 6.58 $ 6.57 $ 6.62 $ 6.75~~'Y:~:2Ól$.207 $ 7.sff 7.51 $ 7.52 $1.6 $ 7.21 $' 6.5f¡1liy~,__4i $ '6.46 "iøa.. $' °6.$'. . $'i~
High Growh Low Price Sumas 2017-2018 $ 7.39 $ 7.41 $ 7.99 $ 8.02 $ 7.76 $ 7.13 $ 7.10 $ 7.10 $ 7.15 $ 7.16 $ 7.15 $ 7.24~ S~' 2018-2019 $ 8.08 $ 8.05 $ 7;6 $ 7.95 $ 7.71 $ 7.08 $ 7.03 $ 7.04 $ 7.05 $7:.04 $ 7.09 $"?~\¡
High Growth Low Price Sumas 2019-2020 $ 7.97 $ 8.00 $ 7.88 $ 7.91 $ 7.72 $ 7.00 $ 6.95 $ 6.97 $ 7.05 $ 7.03 $ 7.14 $ 7.26di1:G'-.i.WPr ~"20201 $ 8.DO $ 8.1 $ 8.07 $ 8.10 $ 7.80 $ 7.10 $7.04 $' 7.06 $ 7.09 $' 7.0$..l\,Zi~.S 7..
High Growth Low Price Sumas 2021-2022 $ 7.97 $ 8.02 $ 8.09 $ 8.12 $ 7.78 $ 7.07 $ 7.04 $ 7.07 $ 7.10 $ 7.11 $ 7.17 $ 7.36~Prce Su 202-20 $ 8.10 $ 8.10 $ 8.17 $ 8.20 $ 8.01 $ 7.32 $ 7.20 $ 7.22$7.267'ylii~r_1 _¡¡i,ti
High Growth Low Price Sumas 2023-2024 $ 8.27 $ 8.29 $ 8.41 $ 8.40 $ 8.21 $ 7.51 $ 7.43 $ 7.46 $ 7.48 $ 7.50 $ 7.57 $ 7.77ØiGt"t.!"JiY..~~, ~20 $ M3 $lf.ll $8.67 $ 8.66 $ 8.36 $ 7.66 $ 7.9 $ 7.~i;$i'M!l.o$ 7.68 il\t'Jt~_.
HighGrmvh LOWPric~.Sumas,.,2025-2026.$ 8.7,$ 8.71 $,8;84 $ 8.83 $ 8.56 $ 7.88 $ 7.76 $ 7.80 $ 7.82 $ 7.83 $ 7.92 $ 8.09Hlg!l.~~2027J~¡1 $ 8'''13197 $ 9.00 $ 8.79 $'ß"~1$ 8.03 $ 8.~.$1~.1n .$."8,1"ÎJl'~$;.
High Growth Low Price Sumas 2027-2028 $ 9.05 $ 9.05 $ 9.16 $ 9.19 $ 8.98 $ 8.30 $ 8.22 $ 8.23 $ 8.24 $ 8.29 $ 8.33 $ 8.48.~~ 20220__g~ $ll,,~:..~.3""zf"9:3ièr$ 9.17 $8Ji. $ 8.42 $:~II ~;~:;tk.~.
High Growth Low Price Sumas 2029-2030 $ 7.38 $ 7.76
244
Appendix 6.1 - Monthly Price Data by Basin
2009$Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
Low Growth High Price AECo 2009-2010 $ 6.92 $ 7.30 $ 7.66 $ 7.71 $ 7.51 $ 6.87 $ 6.94 $ 7.03 $ 7.14 $ 7.22 $ 7.21 $ 7.26~~ ~'20f¡¡~.tj1~?ítAG$l~. $~~.ltr4 $ &.47 '._'~~(l¡Ct.l. f't~JLE i.ml_
LowGr0wt~HighPrice AECo 2011-2012 $ 9.02 $ 9.19 $ 10.19 $ 10.24 $ 9.91 $ 9.21 $ 9.24 $ 9.33 $ 9.44 $ 9.51 $ 9.50 $ 9.53~ce.0.~ 2Q1I~~,$H;dtl):64"~il80~$ 1l~.$'.~.2S $ 10.29 ,l:J~$lI;"'-''10~.5
Low Growth High Price AECo 2013-2014 $ 11.00 $ 11.07 $ 10.99 $ 11.06 $ 10.67 $ 10.08 $ 10.13 $ 10.22 $ 10.31 $ 10.37 $ 10.31 $ 10.34.GrPi¡~~'íi' ¡_~Ø_i?'$.dUl' 13.61$:"mi.ii;H~.$1~,68 .12.16$12.~lf .$ti.Ø"lIdfl
Low Growth High Price AECo 2015-2016 $ 13.68 $ 13.90 $ 14.17 $ 14.27 $ 13.86 $ 13.19 $ 13.26 $ 13.29 $ 13.46 $ 13.49 $ 13.46 $ 13.52Y1~~r_C9, 'H~j7\_¡,~1$f~ $ 14.í(14.62Y%¡..~é$ 111":.13!íi $ 13.5 $ '1~13.~JJiéJ~.&žl_
Low GrowthHigh Pric~ A~Co.. 2017-2018 $14.47 $ 14.57 $ 15.29. $ 15.36 $ 14.87 $ 14.28 $ 14.39. $ 14.45. $ 14.57 $14;62 J 14:52 $ 14.53~1-iilill~_~8-201.~"'15.37.ci~S:47$y~~f'$1~jj.06 $ 14.49$, 14.51¡¡'$'~;'f4.7lj $!!1~~LowGrowth Hii¡h Pri?e..~EC? .' 2019-2020 .' $ 15.57 $ .15.69.$ 15.71 $ 15.79.$ 15..35 ..J 14.67 $ 14.77$14.86 $ 15.01 $15;P3 $ 15.02 $ 15;09
1toW~ .PØú,y,,,~. 20-~ $ l~JIi;.9!'.~ $ i.E $ ,~mJ:.$ 14.87 $1.~.!!"i1".~15 $ Y11!.13 $ 15,-..0&
Low Gr?wthHii¡h Price. AEG? .,2021-2022 $.15.87 $16.90 $15.94 $ 1.6;02 $)5.47 $ 14:9~$ 15:03 $ 15.12$.15.24.$ 15.30 $15.24 $15.26.~i-.~t AFCo,20~ $ìt~ 16...l6.15"_t22t~"t $ 1~'~pI15:~7:J. $ 15.51$,J~.1S.5t
Low"rowth High Price AECo. 2023-2024 $ 16.33.. $ 16.4.. $ 16.51 $ 16.55 $ 16.01. $ 1M2 $ 15.53. $ 15.64 $ .15.75 $ 15.81. $ 15.78$ 15.82'.J()G_rilg~CÔ~2Ó_¡16.63' $;1!!i77"$ '16.6l¡t:;$.16.ll~; $ 1ii;~. $ 15.80'"115.91 $f~1!JJ,t'ìt6:00'$_
Low Growth High Price AECo 2025-2026 $ 16.95 $ 16.99 $ 17.41 $ 17.45 $ 16.88 $ 16.29 $ 16.40 $ 16.51 $ 16.63 $ 16.68 $ 16.63 $ 16.67
"~ Higli.';' ~.?~$ 1di"l.'ITr,p.$,'1Ö:öc,¡il!18&!J"TT.5f' $.16.93 $17.04$. ìI ..;;&r$17.:35.:i,fl,,'t-~2~
Low Growt~Hii¡h Pri?~ AECo .., 2027-2028., $ 18.09 $ .18.20.. $ 18;65 $ 18.76.$ 18;15. $ 17.56 $ 17.68 $..17.78 $ 17.90 $ .18.00 $ 17.90 $ 17:92~~ AF~ 202S;~ $ ilB18.81JlBI',:3 $ 1_$ ""~2$ 18..22 $.Jll~,¡j¡\Ig:J:5 $1$.68 $ 1(1..~,59
Low Growth High Price AECo 2029-2030 $ 18.59 $ 18.59
Low Growt High Price Malin 2009-2010 $ 7.04 $ 7.42 $ 7.76 $ 7.82 $ 7.61 $ 6.94 $ 7.00 $ 7.10 $ 7.20 $ 7.31 $ 7.28 $ 7.34lb\1l~Mii~1ö!;íf"), '~~'$ &.1Ii 8.8/Ù.IU!IIII¡lli $ ~~:æ11:!I,f?JI$ $,Øl~R aIB1":
Low Growth Hii¡h Price M~lin. 2011-2012 $ 9.13 $ 929 $ 10.29 $ 10.34 $ 9.90 $ 9.25 $ 9.27 $ 9.37 $ 9.48 $ 9.55 $ 9.55 $ 9.59.df._l'~!!?'Ml~12-201:i_$ 10.76ßil92$~$ 11r~W10.&i!;.~.25 $ 10.31 $. iô.;l'ti~l_¡$_l.10:!l_'
Low Growth High Price Malin 2013-2014 $ 11.13 $ 11.20 $ 10.89 $ 10.96 $ 10.50 $ 10.07 $ 10.09 $ 10.24 $ 10.33 $ 10.39 $ 10.35 $ 10.39.GI'PØ+¡~n,"201:ißßj\'\12.~46I~ $ 1.3~ $J~2.~$ 12.59 $12.nrV;'$'12.9oj~$12.~.'"
Low Growt High Price Malin 2015-2016 $ 13.83 $ 13.98 $ 14.00 $ 14.47 $ 13.46 $ 13.02 $ 13.08 $ 13.31 $ 13.51 $ 13.53 $ 13.52 $ 13.61Y1GI'P~:In_?017;¡¡._U.47ß¡"'t".l!Tí~ $ 14:32$:.~J1~g_,. $ .13.41 $ 13.62"IBI5;68. .$".)¡~,i$ 1_LOIvGro~hHigh~~c~Mali~.2017-2018 .$ 14..W $ 14.58$15.07$ 15.15 $ .14.56 $ 14.18 $ 14.29 $ 14.34 $ 14.56. $ .14.61 .....~. 14.52 $.14.56.LO'df~£"~L;~19 £~a." $ 15;...15.71~.4l£+J21,4:ji $ 1.,~4.62 $..1~V4.73 'fil=.l~
L?'Y Growth High Price Malin 2019-2020$ 15.77$15.88$ 15.60 $15,67 $ .15.31 $ 14.60 $ 14.70 $. 14.89..$ .14.97 $..14.9?..$ .15.00 $ 15.12~ HiQ~ Mi~o-~;$ 16.1.?i"fi.16.20$ 16~1 $lj~6_1!).60.$ 14.82 $" 14.116 $. 1...~\~t_C,I~t,l.14.99 ,_
Low Growth High Price Malin 2021-2022 $ 16.00 $ 16.17 $ 16.03 $ 16.10 $ 15.56 $ 14.77 $ 14.85 $ 14.93 $ 15.06 $ 15.12 $ 15.11 $ 15.17toW~F''",,~:W'V'20-2ii\ ..$.16.~';36..$_l1 $ 1llll'$ 1§,Mßt4.92 $ 15.3 $15.jg;ß$;J~~ $1I/\$15.37..'IPi£
Low Growth High Price Malin 2023-2024 $ 16.52 $ 16.68 $ 16.63 $ 16.65 $ 16.11 $ 15.22 $ 15.32 $ 15.44 $ 15.55 $ 15.62 $ 15.65 $ 15.77LoGlilg~in;~4'~'.$.1.Q~17.ØI~.94 $¡r.l91."._$15.47 $'.15.~illli'5.6!iV$.1Mi5.1l $ .15.~jX'I.¡.'"
L0'YGrowt~HighPriceMalin2025-2026. $ 17.27 $ 17.25 $ 17.55 $ 17.57 $17.,91 $ 16.05 $,)..6.16 $16.27$..16.38 $ 16.45 $ 16A8$. 16.61~JMH~ Mi~?O~$1ì'.ì'5 . $ 17.'" 18.15,_.g~.69 $ 16,7~'im(l~6.93.¿~\17.15 $~£$_
Low Growth High Price Malin 2027-2028 $ 18.38 $ 18.46 $ 18.80 $ 18.89 $ 18.32 $ 17.36 $ 17.4 $ 17.57 $ 17.69 $ 17.80 $ 17.78 $ 17.88
!D Hiii_ MII 208-~1 $i~LJ~11l1f~ $ 19.4Í-'1ílll\\18.98 $1¡j.02'1~1&.f:4l'ri$~($18.48'lltm;llí.S6
Low Growth High Price Malin 2029-2030 $ 18.56 $ 18.56
Low Growth High Price Rockies 2009-2010 $ 5.69 $ 6.11 $ 6.49 $ 6.58 $ 6.27 $ 4.53 $ 4.61 $ 4.71 $ 4.82 $ 4.91 $ 4.88 $ 4.95~~~\~~"'~1".."~;'alf:".$d\'.'$i."1$ "f:~t~vll'l);tt '.~'lf"_s:il
LowGrowth~ighPrice,R?CkieS.2011:2012 . .... $9:03 $ 9-0. $10.21,. $ .10.26 $ 9.84 $ 9.20 $ 9.24 $ 9.29 $ 9.39 $ 9.44 $ 9.40 $ 9.43
.i~~.r;~.,~2013\_Ô.52 $~$ 11.17:-'"18 $ 10;68 $1.~O.24 $JQ..~'.$10.31¡& dt$i:J.4lg
Low Growth Hii¡h Price. Rockies 2013-2014 $ 10.74 $ 10.81 $ 10.72 $ 10.78 $ 10.26 $ 9.86 $ 9.89 $ 9.95 $ 10.01 $ 10.05 $ 10.00 $ 10.02~~ ~ 201+~ $ 11~\ßi$\1_;$.13.~,~J-12.78 $12.34 '$'¡12.4(,~r~T1.2,~$'12.66 $;1å"8''-'
Low Growth High Price Rockies 2015-2016 $ 13.36 $ 13.56 $ 13.82 $ 13.89 $ 13.29 $ 12.85 $ 12.96 $ 13.00 $ 13.12 $ 13.14 $ 1308 $ 13.13~~ ~. 201!1 $\,'_¡i.$"1~.~14.$ 13.51 $'i-m11 $.13.2' $"1I$ 3~~~1~$':iI.
Low Growth High Price Rockies 2017-2018 $ 14.12 $ 14.22 $ 14.94 $ 15.01 $ 14.44 $ 14.02 $ 14.14 $ 14.20 $ 14.31 $ 14.36 $ 14.26 $ 14.27LoGi' Pn~ell~2Ql~~\~IS.0~~1~ i.:r$ 15~ $l~~ $ .14.29 $ 14;36 $ 14.44$~'$ 14.:1¡,i;;$ 14,¡
L?'YGr?wthHigh Price Rockies 2019-2020. $ .1.~..18 $ 15.31 $ 15.35 $15.4$ 14.9e $ 14.46 $14.57 $14.66 $ 14.78 $ 14.85 $ 14.80 $ 14.83~ HIQ' Ró~I~':1fi $.lS!~?$ 15.fl5.71$.80¡¡\\.~' $. 14.68$1tj4:~lIj4.8 5. .ill5.04 $14.~i-$t_
Low Growth High Price Rockies.2021-20,22 $ 15.75 $ 15.93 $ 15.95 $ 16.04 $ 1542 $ 14.89 $15.01 $15..09 $ 15.23 $ 15:30 $1~.23 $ 15.27~ Hi~' R~i2022,~t $ 1fl,9l.llij$ 1ll~$~ 16.2~"";;Btl_¡'!15.79 $ 15.17$115.~¡!~$r;tS:~!Ì~~i5;¡; $ iM4.l_~
Low.Growth High Price Rockies 2923-2024 $ 16.3 $ 16.55 $16.61 $..16.65 $ 16.09$ 15.49 $ 15.61 $ 15.71 $ 15,83 $ 15.89 $.15'85. $ .15.91
."G~i~s ~_1"ì'. $ 1iB116.95 $ 16.34 ;B.p $'íi:ll $_~"O $ 1~1~¡~;16._116.19
Low Growt High Price Rockies 2025-2026 $ 17.05 $ 17.10 $ 17.51 $ 17.55 $ 16.95 $ 16.37 $ 16.48 $ 16.58 $ 16.70 $ 16.76 $ 16.69 $ 16.72
~ I3I'PØ '"les '..~'¡...G.$¡~íL$fWll 1l1a? $ 17.jj8;¡..:~ii~~f~~,Ø $ 17.46 511!_11.43
L?Iv.GrowtHighPrice Rocki~~ 2027-2028 .... $ 18.20 $ 18.36 $18.76 $18.85 $18;21 $ 17.66,.$17:80 $ 17.90$.,18.01; $18.11 $ 18.03 $18.07
~~t ~;.;.~ v"' ~$ 19.~fjM4 l:ø $",,1lÍ!1:$ 13.32.¡~18.M;ãìlllll.19 $ 1ll:"îI
Low Growh High Price Rockies 2029-2030 $ 18.74 $ 18.74
245
Appendix 6.1 - Monthly Price Dat by Basin
2009$~~ ~ ~~ ~ ~ ~ ~ ~ . - ~ ~ - - ~
Low Growth High Pnee Stanfield 2009-2010 $ 6,99 $ 7,37 $ 7,1 $ 7,77 $ 7,56 $ 6,89 $ 6,96 $ 7,06 $ 7.16 $ 7.25 $ 7.23 $ 7.29~l(l~11,i~,;;",\'_~~')I:"'$' .aii.$".....,'.... T:Jj~¡~' ' 'IIJJi!,~ ft"ê:():klt$'~'
Low Growth High Pnee Stanfield 2011-2012 $ 9.06 $ 9.23 $ 10.23 $ 10.28 $ 9.96 $ 9.20 $ 9.22 $ 9.32 $ 9.43 $ 9.50 $ 9.50 $ 9.54
II Ii ."i~f' $tElId 2011-2013 'l10.6ê $'1Oß$'$1UtJ $11'J7 $11.1 $1Ö.:l1 $ 10.2 $ 10,§7'$10:4a?'fll I I 11'5$
LowGrowthHighPnee Stanfield 2013-2014 $ 11.06 $ 11.13 $ 11.05 $ 11.12 $ 10.73 $ 10.06 $ 10.05 $ 10.19 $ 10.28 $ 10.34 $ 10.29 $ 10.33IIM_ Stifiel 2014-2O~:~j$ 12.2 $. 12.3 l 13.61 $ 13.6 $. 13.3l $' 1:66 $ 12.M $'12'74' $ 1t.86 $ J' 112:ii
Low Growth High Pnee Stanfield 2015-2016 $ 13.77 $ 14.00 $ 14.28 $ 14.38 $ 14.00 $ 13.19 $ 13.23 $ 13.25 $ 13.44 $ 13.46 $ 13.45 $ 13.53~M~,s¡¡eI 2016-2017 $ 14.44 $ 14.$ $ 14.11 $ 14.7! $1420 $ 13:31 $ 13.46 $13.47 $ 13.55 J~__l~,(l
Low Growth High Pnce Stanfield 2017-2018 $ 14.56 $ 14.66 $ 15.38 $ 15.45 $ 14.98 $ 14.22 $ 14.31 $ 14.37 $ 14.49 $ 14.54 $ 14.45 $ 14.48_;l~~ Steld 2018-2019 $ 15.46 $ 15.56 $ 15.61 $ 15.64 $ 15.17 $ 14.41 $ 14.41 $ 14.54 $ 14.62. $Kj~
Low Growth High Pnce Stanfield 2019-2020 $ 15.66 $ 15.78 $ 15.80 $ 15.88 $ 15.47 $ 14.56 $ 14.64 $ 14.73 $ 14.89 $ 14.90 $ 14.92 $ 15.03~(;róA:lig~eld 20201 $ 16.01 $ 16.09 $ 16.11 $ 16.17 $ 15.49 $ 14.73 $ 14.79 $t1.4.86 $:1~~~~.$.l.14.93 $'llfffiSKs'f_
Low Growth High Pnce Stanfield 2021-2022 $ 15.90 $ 16.06 $ 15.92 $ 16.00 $ 15.46 $ 14.68 $ 14.77 $ 14.86 $ 14.98 $ 15.03 $ 15.03 $ 15.08~1!tSlafield gp~ $i6.1~.$d.i~'s $1S'l9J'~ÄII~Ii~LtJJ;'4.!1 $ 15.04:$Is~~\'$j1_tî.lì~§;$!'_;,
Low Growth High Pnce Stanfield 2023-2024 $ 16.40 $ 16.54 $ 16.51 $ 16.54 $ 16.00 $ 15.13 $ 15.24 $ 15.35 $ 15.47 $ 15.53 $ 15.56 $ 15.65
'n-GI'Wl¡=Igi;Æ _,= I!ll?5'" Mil .i_iw.~'~\~~38i~'$15.49! "$1-.II.I~.lji5.êö$ :f~Ø'1'::!$_
Low Growt High Price Stanfield 2025-2026 $ 17.11 $ 17.09 $ 17.43 $ 17.45 $ 16.89 $ 15.95 $ 16.07 $ 16.18 $ 16.29 $ 16.35 $ 16.37 $ 16.4
\. GI H~ p7 .;iil r~iJ_ 'I;1l.1\!,¡.;$i~17¡ß.f.$ ..16,n4$iAA' WiIl)7.3 $1EJ.91$_
Low Growt High Price Stanfield 2027-2028 $ 18.21 $ 18.29 $ 18.67 $ 18.77 $ 18.20 $ 17.26 $ 17.36 $ 17.46 $ 17.57 $ 17.68 $ 17.63 $ 17.72
l.~~LZi it!a!.;';:¡¿liiia1J~1I12 nã....'~; $ JØ'.Qa .$1,Ji'¡¡¡nJi~j;;8;;l $,18'3f $/:_
Low Growt High Pnce Stanfield 2029-2030 $ 18.39 $ 18.39
Low Growth High Price Sumas 2009-2010 $ 7.12 $ 7.51 $ 7.87 $ 7.93 $ 7.62 $ 6.95 $ 6.94 $ 7.01 $ 7.12 $ 7.21 $ 7.24 $ 7.34
.. II_~ Sunil~l :i~$-i Ö:ífT'J\'"r.~TJ:~1¥r"'li~tJ_i'a:1~'~f~:"~'J,.f:9.$.__'.1 iii
Low Growth High Priee Sumas 2011-2012 $ 9.21 $ 9.39 $ 10.39 $ 10.4 $ 10.02 $ 9.30 $ 9.25 $ 9.31 $ 9.43 $ 9.51 $ 9.54 $ 9.63t..illRlQf'~_l!.:æ3 . $ fo.lU l'l'l-í,".iB!lH':5 $1't;OOl1Ø.llJiil'¡¡Æ 1I"li.1õ.~ $1n:~~q,
Low Growth High Pnee Sumas 2013-2014 $ 11.21 $ 11.28 $ 11.20 $ 11.27 $ 10.78 $ 10.15 $ 10.15 $ 10.21 $ 10.32 $ 10.37 $ 10.36 $ 10.42
l.~ flii~~!i 2014-15 $ 12".41 $ f2.5 $ 13.75 $ 13.8 $ 13~31 $ 12.69 $12:71 $12.11 l. 12.92 $1_äiI:l.Q!
Low Growth High Pnee Sumas 2015-2016 $ 13.91 $ 14.12 $ 14.38 $ 14.45 $ 14.00 $ 13.29 $ 13.31 $ 13.32 $ 13.52 $ 13.54 $ 13.53 $ 13.64
IIHig Pr Sliås 2016-2017 $ 14.56 $ 14.0 $ 14.8 $ 14.8 $ 14.22 $ 13.52 $13.56 $ 13.59 $ 13.67 $ '.¡Z II 1.;'78Low Growth High Pnee Sumas 2017-2018 $ 14.73 $ 14.83 $ 15.55 $ 15.62 $ 15.03 $ 14.40 $ 14.45 $ 14.50 $ 14.62 $ 14.68 $ 14.60 $ 14.67
. Ihl-ff~ "Surns 2018-201~/' $ 15.67 $ 15.74 $ 15.78 $ 15.83 $ 1524 $ 14.62 $14.64 $ 14.71 $ 14.79 $ 11t1111..í4.\l1t
Low Growth High Pnee Sumas 2019-2020 $ 15.85 $ 15.96 $ 15.99 $ 16.07 $ 15.52 $ 14.80 $ 14.83 $ 14.91 $ 15.07 $ 15.10 $ 15.12 $ 15.23
~1-~¡¡:li£s_~J¡J'. $ 16.1a,,~$j!¿l~ $ 1627 $ 16.3$ $ 15.fl:$i1S:Øg!W~~1ìî~.Q9$ 15.Z1$ 15t~5'.
Low Growth High Pnce Sumas 2021-2022 $ 16.23 $ 16.36 $ 16.38 $ 16.46 $ 15.76 $ 15.05 $ 15.10 $ 15.19 $ 15.31 $ 15.36 $ 15.34 $ 15.51
~.!i.I'_i~LL~:. $.l¡r~ $,"1~t.1S.e,J.;$JM~¡¡ì.1I~j1il:ri..5:~.44,¡Z.ß~:i.'.!$.sn/:\~¡¡U(JJ$~_
Low Growth High Pnce Sumas 2023-2024 $ 16.72 $ 16.84 $ 16.91 $ 16.95 $ 16.38 $ 15.69 $ 15.69 $ 15.78 $ 15.89 $ 15.95 $ 15.93 $ 16.12_~ IHi: $W1ii r.a::$ .i?-0å"$'11.2 $\(_1111 r I S7"~fl:1I¡;9öl'¡1ll,05' '$.'l6.1f!:&ìl~:4l"ì¡Z.':_
Low Growth High Pnce Sumas 2025-2026 $ 17.44 $ 17.4 $ 17.88 $ 17.93 $ 17.25 $ 16.58 $ 16.55 $ 16.65 $ 16.77 $ 16.83 $ 16.82 $ 16.98lO~. . r"¡,;i:?n;ll'~B¡.~,.1~.Q $ 18;5$1elnn~LJ$1T,11.24 $ .1i.~:$:ì~~l_~
Low Growth High Pnce Sumas 2027-2028 $ 18.59 $ 18.69 $ 19.10 $ 19.19 $ 18.52 $ 17.86 $ 17.88 $ 17.96 $ 18.07 $ 18.18 $ 18.12 $ 18.24,lO~P; ~~_l~(~'$"'''l1!l18'~~'li18.55 $18.(l,¡L.il_~I"'?~¡'",'_Low Growth High Pnce Sumas 2029-2030 $ 18.92 $ 18.92
246
Appendix 6.1 . Monthly Price Data by Basin
2009$Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep OCt
Green Future AECo 2009-2010 $ 4.33 $ 4.85 $ 4.97 $ 5.05 $ 4.99 $ 4.75 $ 4.65 $ 4.78 $ 4.80 $ 4.89 $ 4.90 $ 5.09~_i,w~~10i~'f~í~'''$ "$ mB, 5.9_~.,(5.~;._l;.f;9§.d~~l!;;_Yi.$'/s.,~Green Future AECo 2011.2012 $ 5.46 $ 5.63 $ 6.03 $ 6.03 $ 5.72 $ 5.47 $ 5.47 $ 5.52 $ 5.52 $ 5.54 $ 5.52 $ 5.67~""¿~?;2q.12'~AØ""'~$ ..ll~ '$lldii'øir. $.5.1!~~;i5.~8.è9..~;~Green Future AECo 2013-2014 $ 5.41 $ 5.49 $ 5.55 $ 5.57 $ 5.36 $ 5.24 $ 5.31 $ 5.34 $ 5.36 $ 5.37 $ 5.33 $ 5.46.Gii:ii~T~15 .;0i_.~6.5d'!) 9.4l~ $;.~~$ .'IM.-g'l';(!\ $"'IIfl.'_Green Future AECo 2015.2016 $ 9.76 $ 9.90 $ 10.13 $ 10.16 $ 9.98 $ 9.87 $ 9.94 $ 10.01 $ 10.01 $ 10.03 $ 10.02 $ 10.11
.ín!~'!" .Aì~. . JI"'6-201t,~O,~.~it. $ 1Q_$ 1.1illl.03 i""ì).5ed.~l;lj~"~.~. $;1~;1lJ.~;/l IiGreen Future AECo 2017-2018 $ 11.27 $ 11.34 $ 11.83 $ 11.85 $ 11.52 $ 11.32 $ 11.28 $ 11.35 $ 11.34 $ 11.41 $ 11.38 $ 11.57'~,~,. 20i~ $ j,~~;~ ØI $ 1~~íl:21 $ 1:t~t95 $ 11.9Ikd~12.~.07lt" ~2;19";Green Future AECo 2019-2020 $ 12.55 $ 12.70 $ 13.02 $ 13.05 $ 12.52 $ 12.38 $ 12.36 $ 12.39 $ 12.41 $ 12.45 $ 12.15 $ 12.22G~'" l"~'"~~; $lI$'l~¿)$1a:0!);/.$13.if.$J2.~t;~t12.5î $.1~1 $ 12.~-.'$12.;i_
Green Future AECo 2021-2022 $ 12.89 $ 12.96 $ 13.32 $ 13.35 $ 13.08 $ 12.78 $ 12.79 $ 12.84 $ 12.79 $ 12.84 $ 12.85 $ 12.95~~IJL'ÄÈCç~22:~t $. ;1~~ $JB $.,..\'$ 13.86 _~.'g1 $ 13.~n;f13.24. ..$.,l~¡~;$¡l~ft $ 1SJit~.24Green Future AECo 2023-2024 $ 13.49 $ 13.56 $ 13.81 $ 13.77 $ 13.36 $ 13.23 $ 13.24 $ 13.27 $ 13.25 $ 13.30 $ 13.32 $ 13.33
IIF";~;fA!~'ø~tl1_;j3 .:18 $",~ $ 13.8l?;"i$);;~"Y$13.65 $;i4~t)l1~l" 13.lKLJ' PI);1.Green Future AECo 2025.2026 $ 14.01 $ 14.16 $ 14.61 $ 14.60 $ 14.31 $ 14.11 $ 14.12 $ 14.13 $ 14.13 $ 14.17 $ 14.17 $ 14.21~FuíAì§it !~27_5:_l4.61'(S',l5.18.i~& $ 1~.~;,$14.~$~l.j:;¡l",~;$ 14J~'$ '1.Green Future AECo 2027.2028 $ 15.00 $ 15.11 $ 15.66 $ 15.69 $ 15.29 $ 15.15 $ 15.18 $ 15.18 $ 15.23 $ 15.28 $ 15.33 $ 15.451I~);AE~~~,~S.54 $4~~$ ..ilí'f'''ä.25 ,¡Lt;;1S:ør';f';'5~1'2 $ 15.t.¥"'l('1.;~1§.t9 . $15~~~qGreen Future AECo 2029-2030 $ 15.98 $ 15.98
Green Futre Malin 2009-2010 $ 4.67 $ 5.19 $ 5.32 $ 5.40 $ 5.26 $ 5.03 $ 4.91 $ 5.08 $ 5.13 $ 5.24 $ 5.24 $ 5.41
~ :~.)1o.2lt.".;$_;$ ~. $.l!~ S.9l,Ì1I".:.;$ !I:atV,__, '~~cd_¡l¡~. _Green Future Malin 2011-2012 $ 5.74 $ 5.92 $ 6.30 $ 6.30 $ 5.95 $ 5.71 $ 5.70 $ 5.76 $ 5.78 $ 5.81 $ 5.79 $ 5.93
'~áI' .'~2012.~$ 6.1() $ _$III$" 6.éQ";~5 $ 6.0"(;;~$iMllf¡Ji 6.11.,i_ll$6.1~_f~~ ~ ~~4 $ ~ $ ~ $ ~ $ ~ $ ~ $ ~ $ ~ $ ~ $ ~ $ ~ $ ~ $ ~.~JlrIIJ_'4'~$_~~lt l 'f(6I'$ 9.~'"r 9.41;..$ 9.27 $9.~$ 9.45~¡j~_Green Futre Malin 2015-2016 $ 9.96 $ 10.11 $ 10.33 $ 10.36 $ 10.11 $ 10.04 $ 10.12 $ 10.19 $ 10.23 $ 10.25 $ 10.25 $ 10.32
Gr~~ "~BI _~2ò1j ".lj,0_;10.~¡11.2e¡~;24' $îii,,$,r5$ 1n._t~th.'~ $"1llU .$'t_
Green Future Malin 2017.2018 $ 11.48 $ 11.55 $ 12.03 $ 12.07 $ 11.66 $ 11.50 $ 11.48 $ 11.54 $ 11.58 $ 11.65 $ 11.63 $ 11.81
lIuil" Mai 2ò1~~1l~~~:34$~'"$;,~~ $7¿12:e4,~$12.35$d12.11114 $ 12. 18"J71~727..$j¡~.31 $ .12,fl~42Green Future Malin 2019.2020 $ 12.78 $ 12.93 $ 13.20 $ 13.25 $ 12.67 $ 12.57 $ 12.56 $ 12.59 $ 12.66 $ 12.69 $ 12.40 $ 12.45
II F.i.I¡'l~1I1Jo~1¡V'1'B2 ;~ _124 $,1. $ 13.04 $';.'. $ 12.!1..,',J2,il1 $ 12"._i2.~ $¡~,Green Futre Malin 2021-2022 $ 13.10 $ 13.18 $ 13.48 $ 13.52 $ 13.22 $ 12.95 $ 12.97 $ 13.02 $ 13.01 $ 13.06 $ 13.08 $ 13.16Gr~..i~"_22:202 $ .i.$ 13,~~t$ 13.llil,'1"$ "1~.j)lf¡$1'~~r6;$¡l;M1~~40 $. t~.,t(Ä,.$ 131"0;13;3$;.~
Green Fut~re ...... Mali~... 2023-2024 ". $13.81 $13.90.. $.14.07.$ 14.07.. $ 13.62 $ 13.49. $ 13.52 $ 13.54. $ 13.60 $ 13.65. $ 13.69$ 13.69~:¡Z;MI~y 294:~ 13..9(,£ l~$1.~.i$ 14.58_'2 $ 13.~W!~ $1S,~14.01 .,Öl $.i~,!Ir..d~Green Future Malin 2025.2026 $ 14.36 $ 14.52 $ 14.94 $ 14.94 $ 14.59 $ 14.42 $ 14.44 $ 14.45 $ 14.49 $ 14.53 $ 14.55 $ 14.57
_liF~..JLlt.-.~7'lfJ~'.,Ø9~Ó3" &:51 $,iæs$ 1S.0! ;.,li~$14.99 $.1~~i¡"'S.øi¡'15.12,_' nj5.30~;Green Futre Malin 2027.2028 $ 15.36 $ 15.48 $ 15.98 $ 16.01 $ 15.57 $ 15.44 $ 15.49 $ 15.51 $ 15.58 $ 15.63 $ 15.69 $ 15.82~ll~; .~20,~5,~¡16.()t..16.~59 .fit. _¡¡ $ 16.~~ $ 1~'rd $ 1.Green Future Malin 2029-2030 $ 16.34 $ 16.34
Green Future Rockies 2009-2010 $ 4.42 $ 4.92 $ 5.05 $ 5.17 $ 4:99,$ 4.75 $ 4.70 $ 4.70 $ 4.78 $ 4.88 $ 4.94 $ 5.16
"\"'RJ6-¡'.II.,"f011;7:io;¡l~;1.~"l~.5....ilJL.f $" ~ .' 5.~;;~il''~Iì;. Lpii~.
Green Future Rockies 2011-2012 $ 5.60 $ 5.73 $ 6.14 $ 6.14 $ 5.76 $ 5.53 $ 5.55 $ 5.45 $ 5.52 $ 5.54 $ 5.51 $ 5.71
¡~lf'~ R~_t2.2013hJIIII§.á§" 5.0011 6.5Ó;~ $~~~¿¿.!i.'l;$~Wi_;S 5;~._fi.;~
Green Future Rockies 2013-2014 $ 5.36 $ 5.40 $ 5.45 $ 5.49 $ 5.19 $ 5.14 $ 5.23 $ 5.13 $ 5.21 $ 5.23 $ 5.18 $ 5.33~i. ~." 2()~,.&.zt $;~ $.. $9.37;dI.01 $ 8.8t1 ~1'lt8.é1$ ..8.00_æ $' i. 8.~..~
Green Future Rockies 2015-2016 $ 9.52 $ 9.65 $ 9.87 $ 9.90 $ 9.63 $ 9.58 $ 9.67 $ 9.61 $ 9.68 $ 9.69 $ 9.69 $ 9.78
IIFlli".7R~41I1B17;;ii$j~8~$4' .,1' $!J~ $" 10.37$;_'$10.40..$ 1jj:3ö'5"""10'~Q.~$t~!M¡ê~
Green Future Rockies 2017-2018 $ 11.00 $ 11.03 $ 11.52 $ 11.56 $ 11.17 $ 11.06 $ 11.07 $ 11.00 $ 11.08 $ 11.14 $ 11.11 $ 11.32
~~.d~1s.2(1f( $I~. $H.8t.\$12.t~~j¡t$ ti-!'3d\l~!1;S. $11.68;$~""~144 $ 11.7!) $1111~1:1~ $~Green Future Rockies 2019.2020 $ 12.24 $ 12.35 $ 12.67 $ 12.71 $ 12.15 $ 12.09 $ 12.10 $ 11.99 $ 12.07 $ 12.12 $ 11.81 $ 11.90~/F~\"~.!~fi $'12.;11 $"-$flg.$ 12.aaJ1llÆf!;1;S8 $ 12.16"IIIIIFd$12.~.$12.14t_~ $11..9$ . $iø"
Gree~ Future .. Rockies 2021.2022. $ 12.39 $ 1~.42 $ 12;75 $ 12.80$ ..12.51 \ $1.2.28 $ 12,31.$ 12,.23$12.25.5 .12.30.$ 12.31$ ,12.44~£¡¡"d~ies ~ë2i!t'd' $12t~f2~ ~\13;l2.$íJ~,26'f12.91;!..i,7:~ $ 12.7t,,~~;11g¡jldí$ 12.~iæØ.12.~
Green Future Rockies 2023-2024 $ 13.12 $ 13.18 $ 13.53 $ 13.56 $ 13.18 $ 13.04 $ 13.09 $ 12.97 $ 13.02 $ 13.07 $ 13.11 $ 13.16
'~'!"R~24'2tf!n'-$;1I$13.5$$13.9,'!i_7J_7~~6T-$1S.~J.¡~~t~9 $ 13..d$.1311¡¡l.J3;5Ó $"1_Green Future Rockies 2025.2026 $ 13.85 $ 13.97 $ 14.40 $ 14.42 $ 14.12 $ 13.92 $ 13.96 $ 13.81 $ 13.87 $ 13.90 $ 13.91 $ 13.97~.i.Øe lJ.Jl~~0$14.00 $tfl1$ .tIl7d$ 14.91\d~ $ 14.38~.~t.!1'4:2l¡dl"'Jl4.39 . '-"$ M.47 $,1_Green Future Rockies 2027.2028 $ 14.69 $ 14.77 $ 15.30 $ 15.33 $ 14.97 $ 14.81 $ 14.87 $ 14.72 $ 14.84 $ 14.87 $ 14.93 $ 15.11
1I!~uí~ 't~9 $g!9dit5 &;80 $~$ 15.49 $l~;"tS:35 $15.23+.$ 1~,~.37$11$_S;~0Green Future Rockies 2029-2030 $ 15.62 $ 15.62
247
Appendix 6.1 . Monthly Price Data by Basin
2009$Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oc
Green Future Stanfield 2009-2010 $ 4.53 $ 5.04 $ 5.17 $ 5.25 $ 5.14 $ 4.90 $ 4.79 $ 4.94 $ 4.97 $ 5.07 $ 5.08 $ 5.26!~,,r"Stek_"r~.~s!'f""llf77l 5i75 $&:11 l¡,l~. $l'18' $' ~¡'¡_,Ia.ìl¡¡.~l,.fcd,26't&:nr'\.1I
Green Future Stanfeld 2011-2012 $ 5.62 $ 5.79 $ 6.18 $ 6.18 $ 5.85 $ 5.59 $ 5.59 $ 5.65 $ 5.65 $ 5.68 $ 5.66 $ 5.81~reeFl !:S~~'!!$!S~!.$~,\~il.6,64' $' '$.69 ,.lfis' 8 5;92 $ 5.91/'.... ¡ ":l 8 6.01ld,'llØl!
Green Future Stanfield 2013-2014 $ 5.55 $ 5.63 $ 5.68 $ 5.71 $ 5.45 $ 5.34 $ 5.42 $ 5.44 $ 5.46 $ 5.49 $ 5.45 $ 5.58GrFl!!ci'¡'tJ~'5 $'!'l~;$.f6_9.58 $ 9.115 $ 9.34 $ 9.18$9:24 $ !~.~' $' 9.~"t' .9.41
Green Future Stanfield 2015-2016 $ 9.87 $ 10.01 $ 10.25 $ 10.27 $ 10.05 $ 9.96 $ 10.03 $ 10.09 $ 10.12 $ 10.13 $ 10.14 $ 10.22
~reni:~ .. $Øl".$i.ì1ØI~~!'!1'l.16 $ 11.15 $ 10.75 $ 10.65 $ 10.ßa $10.7~l!d~~iø'~1
Green Future Stanfield 2017-2018 $ 11.39 $ 11.46 $ 11.94 $ 11.97 $ 11.60 $ 11.41 $ 11.38 $ 11.44 $ 11.45 $ 11.52 $ 11.51 $ 11.69
Gr(~Ii..19 $ '.~i4' $ 1i,3 $12.56 $ 12.51 $ 12.29 $ 12.04 $.12.05 $.12.08 ..$f12!1fifk~ll¡#~~::U
Green Future Stanfield 2019-2020 $ 12.68 $ 12.82 $ 13.12 $ 13.16 $ 12.61 $ 12.48 $ 12.47 $ 12.49 $ 12.53 $ 12.57 $ 12.28 $ 12.34
.~tF LLStnfel "'~~~1,l~ $12.85 $13.16 $ 13.21 $ 12.98 $ 12.67 '$i'~ii,g.i71!_¡ ;(1
Green Future Stanfield 2021-2022 $ 13.01 $ 13.08 $ 13.41 $ 13.44 $ 13.15 $ 12.87 $ 12.88 $ 12.93 $ 12.90 $ 12.94 $ 12.97 $ 13.06
,MA li(t~£k?¡;?2.2023'R_;ï.41 8 13.54 813.90 813.95 $ 13.58 8 13.34 ,~""7;;''lt1'3:l''''$j3?!t7 ..Green Future Stanfeld 2023-2024 $ 13.66 $ 13.75 $ 13.96 $ 13.94 $ 13.50 $ 13.36 $ 13.38 $ 13.41 $ 13.43 $ 13.48 $ 13.52 $ 13.52I .a¡;!~'fr~24-20i;~3.80 813.2 $ 14.35 $ 14.,4 $ 13.99 $ 13.79 'i?il'~....ci"'.~~a..,,$13.¡La A.A!Green Future Stanfeld 2025-2026 $ 14.21 $ 14.36 $ 14.79 $ 14.79 $ 14.46 $ 14.27 $ 14.29 $ 14.30 $ 14.31 $ 14.35 $ 14.37 $ 14.40Gr~g0! S~~ ¡i0,£lI14.73 $ 14.87 $ 15.36 $ 15.35 lH~,94 $ 14.79 $ 14.84 $¡'lS _ifl'r.j4.98'S'J!13
Green Future Stanfield 2027-2028 $ 15.20 $ 15.31 $ 15.83 $ 15.87 $ 15.44 $ 15.30 $ 15.34 $ 15.35 $ 15.40 $ 15.45 $ 15.52 $ 15.65GreF,~,,'j,!Úi~~ "$1.~T4 $ 15:8116.~.!m~'~~~r~.t5.84¡B_¡;;$,JS.9l~___l,.16.16
Green Future Stanfeld 2029-2030 $ 16.16 $ 16.16
Green Future Sumas 2009-2010 $ 4.63 $ 5.15 $ 5.28 $ 5.36 $ 5.23 $ 4.86 $ 4.64 $ 4.75 $ 4.78 $ 4.88 $ 4.91 $ 5.19~~' . '~""$.1Ø"~f'!:il.~~'l)r_i¡¡:fji.k.~§t ,'!!$:l~¡ ¡¡.~. 'l.',l.s,.!£,~~ø;. D"'~;~
Green Future Sumas 2011-2012 $ 5.71 $ 5.88 $ 6.29 $ 6.30 $ 5.93 $ 5.60 $ 5.48 $ 5.51 $ 5.52 $ 5.55 $ 5.54 $ 5.74~ *~2'¡:¡C! 6.10 $.....6;:11 U~ ...~si~.Fi..' $9fllitS.8P""iS"~Bi~~Y5 PP¡.§.l1fîGreen Future Sumas 2013-2014 $ 5.64 $ 5.73: $ 5.7il $5:81 $ 5.51 $ 5:;i $ 5.33'" f 5.35 $ . 5:3l $ d 5:39 $ 5.37 $ 5.52G~~!f'~"'2Ó15 S 6.61 $ 6:73' UlJ S 9.76 $ 9.40 $9.18 81Üi $gi21 8ii,as,!,sÄsø. IUfl4~Green Future Sumas 2015-2016 $ 9.95 $ 10.09 $ 10.34 $ 10.36 $ 10.11 $ 9.96 $ 9.98 $ 10.04 $ 10.05 $ 10.06 $ 10.08 $ 10.19
~ Sun~!l!¡, 2018-2017 $ 10.71 $ 10.81' $ 11.26 $ 11.24 $ 10.80 $ 10.65 $ 10.63 $ 10.84 $ 16.68' tS10.~~1-~'$'lÔ:jlIGreen Future Sumas 2017-2018 $ 11.47 $ 11.54 $ 12.03 $ 12.07 $ 11.66 $ 11.41 $ 11.32 $ 11.37 $ 11.38 $ 11.45 $ 11.44 $ 11.66~è Suìnas.' 2018-2019 $ 12.32 $ 12.42 $ 12.66 $ 12.66 $ 12.35 $ 12.03 $ 12.00 $ 12.02 $ 12.07 $ .'2.ll\':~.'12,pg $ 1_
Green Future Sumas 2019-2020 $ 12.77 $ 12.91 $ 13.24 $ 13.29 $. 12.67 $ 12.47 $ 12.41 $ 12.43 $ 12.46 $ 12.50 $ 12.23 $ 12.31!~e!¡:~¡ 20201 $ 12.81 $ 12.94 $ 13.29 $ 13.33 $ 13.04 $ 12.67 $ 12.65 $ 12.66 $ 12.66 $ 12.?!:i._ij$ 1..
Green Future Sumas 2021-2022 $ 13.11 $ 13.18 $ 13.55 $ 13.60 $ 13.21 $ 12.87 $ 12.85 $ 12.88 $ 12.84 $ 12.89 $ 12.93 $ 1305~e$!Jas 2022.2023 $13.50 $ 13.63 $ 14.03 $ 14.07 $ 13.84 $ 13.35 $ 13.29 $ 13.29 $ 13.31 $13\23 $ 13.1é $ 1_Green Future Sumas 2023-2024 $ 13.76 $ 13.87 $ 14.12 $ 14.07 $ 13.54 $ 13.30 $ 13.25 $ 13.26 $ 13.26 $ 13.31 $ 13.36 $ 13.391l~¡~ 2024;?~j~~iÖ5 $.14''W.ik~JL$ 14.04 $ 13.73 $ 13.68 $ Ja,~:,!:tJ3.lì7 $ij.~~71$13t5 $1'_Green Future Sumas 2025-2026 $ 14.36 $ 14.50 $ 14.94 $ 14.94 $ 14.50 $ 14.22 $ 14.16 $ 14.16 $ 14.15 $ 14.20 $ 14.23 $ 14.28ll~i'i.¡~SLl!!~£!1 20_1 lBi~~.c6$.15;OO $\iia, i .1~.~$1~.;¡$d14.71 $ 14.61;$14.&7: .li2l1't:!W $ 1_Green Future Sumas 2027-2028 $ 15.32 $ 15.44 $ 15.98 $ 16.02 $ 15.43 $ 15.26 $ 15.22 $ 15.13 $ 15.19 $ 15.24 $ 15.39 $ 15.54
~i!~~f$Cia=i.fll~Ä,iiØ!~$':11Uj6i" $1s;MÎ $15.76 .$15.6l(~~¡~~'i;l,,1-S.88 ..Green Future Sumas 2029-2030 $ 16.06 $ 16.06
248
Appendix 6.1 - Monthly Price Data by Basin
2009$Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
Supply Constrained AECo 2009-2010 $ 6.60 $ 7.01 $ 7.34 $ 7.38 $ 7.16 $ 6.96 $ 6.90 $ 7.04 $ 7.09 $ 7.15 $ 7.13 $ 7.27~~~~2l1f;i:..t1(tl'rr__"Alt S8'."_'ii'~¡' 'tMJJiJJtrf St.l C1Ji,_
Supply Constrained AECo 2011-2012 $ 8.80 $ 9.01 $ 9.34 $ 9.36 $ 8.93 $ 8.65 $ 8.66 $ 8.74 $ 8.81 $ 8.85 $ 8.80 $ 8.90~_n.~2012.2~9.64.l~ r$r'0.29,21~%tl!J34~~nnîo $ 9.11 $ .9.67 $.9.75 $ 9.80 ¡l¡ïl;~ $ ..~~.
Supply Constrained AECo 2013-2014 $ 9.92 $ 10.06 $ 9.98 $ 10.04 $ 9.59 $ 9.44 $ 9.50 $ 9.56 $ 9.60 $ 9.64 $ 9.56 $ 9.64~ 20t~$ "._1.5';$ 1~.tiJLl'.12.81 $ 12.28 $ 1~;.'!$',CJ12.19.~ $ ."¡'~j_Z;,,!;ØI '.12.3
Supply Constrained AECo 2015-2016 $ 13.02 $ 13.18 $ 13.4 $ 13.52 $ 13.00 $ 12.84 $ 12.91 $ 12.98 $ 13.03 $ 13.10 $ 13.00 $ 13.10
~'!l 2016f~;t6 $+~;t~'$ 14.()_l;~ $ 13.55 $ 13.38 $ 13.46 $13.51 $ 13.60$,j¡1~.6!;lt~81In_Supply Constrained AECo 2017-2018 $ 14.32 $ 14.47 $ 15.20 $ 15.25 $ 14.73 $ 14.54 $ 14.59 $ 14.67 $ 14.71 $ 14.77 $ 14.69 $ 14.80~ . +;~9;' $~+' 15,B!$A~6l ,.l~ $J5~". .15,'-.Q8LL"I ¡iUrßifß.:ig¿'&$/'.
Supply Constrained AECo 2019-2020 $ 15.94 $ 16.10 $ 16.13 $ 16.19 $ 15.61 $ 15.42 $ 15.46 $ 15.53 $ 15.61 $ 15.69 $ 15.55 $ 15.71IlÌJ ~ AECo~.2021_3 $1_.$~16.5í"ll1f~6~ê;~i!f~3.$ 16.i:f. $ 16j(llß;':iajl6 $ $"_ $ 16/2_
Supply Constrained AECo 2021-2022 $ 16.95 $ 17.12 $ 17.13 $ 17.19 $ 16.66 $ 16.42 $ 16.50 $ 16.57 $ 16.61 $ 16.69 $ 16.62 $ 16.74Ißfl(~; AI§pJl2.20~W.461~"1!;fJJì $ 17.ti~r¡f6:8tr;$'6:9f $ 1Ø;~'l"$'f7.07 l;~! $ 16.:\1 .
Supply Constrained AECo 2023-2024 $ 17.68 $ 17.85 $ 17.71 $ 17.71 $ 17.06 $ 16.92 $ 17.00 $ 17.08 $ 17.13 $ 17.20 $ 17.13 $ 17.21~~;¡. 2Ö4.~ 17.89!í1I "~'( . $18.20 $ 17.54 $ 17.3l"',"~!47' $ f~' $ 17.si1;~ . $1tl ;lt;~
Supply Constrained AECo 2025-2026 $ 18.37 $ 18.55 $ 18.88 $ 18.96 $ 18.32 $ 18.16 $ 18.25 $ 18.31 $ 18.36 $ 18.4 $ 18.35 $ 18.47S~1¡~2026.2i_ lJ.,17$W;37' . $19.75I.\1~;t!! $ 19.11 $ 18.95 $ 19.06 $' 19.12 $ 19.19TqJ9~"'$'¡"lt1jj;3
Supply Constrained AECo 2027-2028 $ 20.01 $ 20.19 $ 20.58 $ 20.66 $ 19.94 $ 19.79 $ 19.90 $ 19.98 $ 20.05 $ 20.14 $ 20.07 $ 20.16~a(lÎ.I.;;¡~i7 202!l~.!'2.9Q.l;ilf.07 '$ 21.4lllf;llf $ 20.84 $ 20.66 $ 20.77 l~~.87 $ 2(,j.~.;;.tgg~!#~~Supply Constrained AECo 2029-2030 $ 21.02 $ 21.02
Supply Constrained Rockies 2009-2010 $ 6.69 $ 7.08 $ 7.42 $ 7.50 $ 7.17 $ 6.96 $ 6.95 $ 6.96 $ 7.07 $ 7.14 $ 7.16 $ 7.33
~;i¡__ :imm;$8:~!"JIO '1; ".8i-1l1i"l.6 S8.f"$ t.lIfdt.81f't.lll $ um"LJrf.ll"'l¡1'J(_~~Supply Constrained Rgckies201.1-2012 ..... $ ,8.94 $~;12 $ 9.~~ $9;~? $ 8.98 $ 8.72 $ 8.74 $ 8.66 $ 8.81 $ 8.85 $ 8.79 $ 8.93
,SijP ii' il~. ~ .1g.66$j,i;l3' $ 1j:~1¡æ $ 9.8 $ 9,j¡ $ i!,!l.l.j.J,,9.60 $!1.n'~'"d~iZl'bdt,.iI~
Supply Constrained Rockies 2013-2014 $ 9.87 $ 9.97 $ 9.88 $ 9.96 $ 9.43 $ 9.35 $ 9.42 $ 9.35 $ 9.45 $ 9.50 $ 9.42 $ 9.52~~ed ~'~1l\;d$'~1:2Z.~1!J;~$. 12:11 S 12Jj~~'rm1 $Ø_!~T:R~';_£S,t!l._
Supply Constrained Rockies 2015-2016 $ 12.79 $ 12.93 $ 13.20 $ 13.27 $ 12.65 $ 12.54 $ 12.64 $ 12.57 $ 12.70 $ 12.76 $ 12.67 $ 12.77~:~'~f~'13.5l~~' 13.83$ 1l~'k$,-,1~7 $~13c~:l~j $.I"riftt.,.¡_
Supply Constrained Rockies 2017-2018 $ 14.04 $ 14.17 $ 14.89 $ 14.96 $ 14.38 $ 14.29 $ 14.39 $ 14.32 $ 14.4 $ 14.50 $ 14.42 $ 14.55~_~f8.2t~1$ 15.2_!3 ~. $ 15.40 ;*',~l~fl¡~;~lJlM!II¡' 1~"'~flf.84 $\t;_rt~3_
Supply Constrained Rockies 2019-2020 $ 15.63 $ 15.76 $ 15.77 $ 15.85 $ 15.24 $ 15.13 $ 15.20 $ 15.13 $ 15.27 $ 15.36 $ 15.22 $ 15.40
S~, .~fj202Q~j1.~.05~~.$t~l $ 1$.25~:ft1.f¡,l!~lf 15.52 $ 15.60 $ 15.54 $ 15.67 $ flU'" $1lJì"~
Supply Constrained Rockies 2021-2022 $ 16.45 $ 16.58 $ 16.57 $ 16.64 $ 16.09 $ 15.93 $ 16.02 $ 15.97 $ 16.07 $ 16.15 $ 16.08 $ 16.22Suæ iljR~.2022-2~.f#i_f $ 17.l)~:'7.04L.i.t.l",lle2F!lt 111.~l1U9$flJ3f $1ll;Sl'\Jljf$.50 $ 11l\t't$1$."
Supply Constrained Rockies 2023-2024 $ 17.32 $ 17.47 $ 17.43 $ 17.50 $ 16.88 $ 16.74 $ 16.85 $ 16.79 $ 16.91 $ 16.97 $ 16.92 $ 17.04
Ißflrm: R~jjÍi9t4:2~' t£l3 $ 1'tlB$ 17.~j.$:!i;1l.6 $ 17..1 17.3Z;~;;.26 !$¡ù~j7...3,:.u&1..¡¡iJh 17.'8
Supply Constrained Rockies 2025-2026 $ 18.21 $ 18.36 $ 18.68 $ 18.77 $ 18.14 $ 17.96 $ 18.09 $ 17.99 $ 18.10 $ 18.18 $ 18.09 $ 18.23IPpPy~ Roc~2027 ;~ $ 1_ $ 19..fLL:' ,fU9 liÍlmtl 18.l~.7..;JJlJSj":1á",~~ 19.00
SupplyConstrai~ed Rockies 2027-2028 ..$ 1~:69 $ 19.84 $ 20.22 $ 20.30 $ 19.63 $ 19.46 $ 19.59 $ 19.53 $ 19.66 $ 19.73 $ 19.67 $ 19.81
i:"'ppy~ R~ZIi.2029 i¡'i\,ø.55 $~ $21.()~ $" 20.47 .$:gq:~L';$ 29.~;&~!I~;:;~.~~i¥Wi~;,J ZO.66Supply Constrained Rockies 2029-2030 $ 20.66 $ 20.66
249
Appendix 6.1 - Monthly Price Data by Basin
2009$Scenario Index Gas Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
Supply Constrained Stanfield 2009-2010 $ 6.79 $ 7.21 $ 7.54 $ 7.59 $ 7.32 $ 7.11 $ 7.04 $ 7.20 $ 7.26 $ 7.33 $ 7.31 $ 7.44
~~ ....' !i'III"i! /,.....$... f......._;...aw$f:dl;.'J,,\~..l/ 1:9& . S.- ":9f'l!,t¡tlld*~".'IJ¡lfi $. .._ILJll1\~"l~
Supply Constrained Stanfield 2011-2012 . $ 8.96 $ 9.17 $ 9.48 $ 9.50 $ 9.06 $ 8.78 $ 8.79 $ 8.86 $ 8.94 $ 8.99 $ 8.94 $ 9.03~Qqìl I.LJæiØ~2,~~1,~hl 9.'T s Ut S.M"S 10Al$i'1fJ.01 S 9.75 $ 9.7Si!J"IT''l $ 9'.93 $lB'iS 9.ef/.¡ik~,
Supply Constrained Stanfield 2013.2014 . $ 10.06 $ 10.20 $ 10.11 $ 10.17 $ 9.68 $ 9.54 $ 9.60 $ 9.66 $ 9.70 $ 9.76 $ 9.68 $ 9.77
!ili~?dstnfie~lf. 'f'11.48 $ 11.64 ,., 12.~- S 12.93 S 12.36 $ 12.22 $ 12.29f;:ir~;; $ 12.40 .Ii~: $ t~_.Supply Constrained Stanfield 2015-2016 $ 13.13 $ 13.29 $ 13.58 $ 13.64 $ 13.07 $ 12.93 $ 13.00 $ 13.06 $ 13.13 $ 13.20 $ 13.12 $ 13.20~IY Con~~17t¡Mi~~~ 14.04 $ 14.fe$ 14.21. &l 1~.~S:'~:-ltj$ 13.56/~lii~~1 $ 13.70; '\,1l78 $ 13.lI;.~13;1fi¡Supply Constrained Stanfield 2017.2018 $ 14.43 $ 14.59 $ 15.31 $ 15.37 $ 14.81 $ 14.64 $ 14.70 $ 14.76 $ 14.81 $ 14.88 $ 14.81 $ 14.92Suppl CcII_~nfi~18-2019 $1I¡f$ 15.2 "S.J¡15.711 $t.tKädil 15.22 $ 15.()"'4,j¡t()S'c1~!:lc~~30 $ 1S:~;$;'15.37Supply Constrained Stanfield 2019.2020 $ 16.07 $ 16.23 $ 16.22 $ 16.30 $ 15.70 $ 15.51 $ 15.56 $ 15.63 $ 15.73 $ 15.81 $ 15.68 $ 15.84SuC~¡¡.ìiJf ~~2021 ;$; ~l$ 16.6Qi.;_$ 16.2 *â1!i~;$ 16.'-ìsLæ.S4 ~._~~'Supply Constrained Stanfield 2021.2022 $ 17.07 $ 17.25 $ 17.22 $ 17.29 $ 16.73 $ 16.51 $ 16.59 $ 16.66 $ 16.72 $ 16.80 $ 16.73 $ 16.84
sul§ I !! Stfi202"~mr.5r ''i1i'''17.nli'I'Sff.8t s 17.18 $ 16.~r6:~:/ltM. il iì~l, tJ:.f.Supply Constrained Stanfield 2023-2024 $ 17.86 $ 18.04 $ 17.86 $ 17.87 $ 17.20 $ 17.06 $ 17.15 $ 17.23 $ 17.31 $ 17.38 $ 17.33 $ 17.40Su.¡~,~.~ 20~ II Ifj;O$ S1ì!_d~/1a.36 $ 17.68 $ 17.~~/f~'n.n~J'.llfii1limal; fl~i:$~Supply Constrained Stanfield 2025"2026 $ 18.57 $ 18.74 $ 19.07 $ 19.15 $ 18.48 $ 18.32 $ 18.42 $ 18.48 $ 18.54 $ 18.63 $ 18.55 $ 18.66
~'_zliel ~19.36 S 19.6' $.19.93"$'/19,7 l 19.2 $ 19.10 $ 19.2fl1Y.~'I~ll'~i$d1-,eM'i,$~tSupply Constrained Stanfield 2027-2028 $ 20.20 $ 20.38 $ 20.76 $ 20.84 $ 20.09 $ 19.95 $ 20.06 $ 20.15 $ 20.22 $ 20.31 $ 20.26 $ 20.36
~tiel 20&-~.l 21.10 $ 2127 . 21.1 $ 21.77 . 20.91 . 20;82 $20.93 $,iÍt"l1tjlr'~l;:O.9 $g_1.ÓÎ)~Supply Constrained Stanfield 2029-2030 $ 21.21 $ 21.21
Supply Constrained Sumas 2009-2010 $ 6.90 $ 7.31 $ 7.65 $ 7.70 $ 7.41 $ 7.07 $ 6.89 $ 7.01 $ 7.07 $ 7.14 $ 7.13 $ 7.37~~¡~!ir_" l3-'8.'!'l.l!$1'$' M'Fl'8,1ö'~";:l f:lll1ßd "(1,81' $ . 7.90 $7.l! $.1." '
Supply Constrained Sumas 2011-2012 $ 9.05 $ 9.27 $ 9.59 $ 9.63 $ 9.14 $ 8.79 $ 8.68 $ 8.72 $ 8.81 $ 8.85 $ 8.82 $ 8.97
"'p,~ '!if'§ S .ílJ.'lliJJl..Ol'llfl'tO.5o $ 10.~.JJi~~!z$,."~;7~l;i,i:.68 t"",ll5 '¡"0,11,l?00i,$'LJiJ:ÖŠ $1'Il4Jæ\t
Supply Constrained Sumas 2013.2014 $ 10.15 $ 10.29 $ 10.22 $ 10.28 $ 9.75 $ 9.54 $ 9.52 $ 9.56 $ 9.61 $ 9.66 $ 9.60 $ 9.71,SuCô~d~'.+015;$ -1,t'1?,'$P12.92l¡~;¡'(~;43 $ 122i "ii.j~_1 __:43 $lí'~0~,12.42~.~~as 2æi:~~; :ijC1 $ 13'ì. ~¡:~. :~i_~'ißiA~ = ~~:4~~.~ K~;~.~lt~~:;Ø;.3.07 ! 1~t~~
Supply Constrained Sumas 2017-2018 $ 14.52 $ 14.68 $ 15.40 $ 15.47 $ 14.87 $ 14.63 $ 14.63 $ 14.69 $ 14.74 $ 14.81 $ 14.75 $ 14.88.~~ $~10!'2ó1S.2W~$i;i'5.1!:f"~;_ 15.$8. $ 1S:llr $ 15.26 $ 15.3 $ '1i¡:ó5 $ 15.11;I~$t,~~.2;l J~
Supply Constrained Sumas 2019-2020 $ 16.16 $ 16.32 $ 16.34 $ 16.42 $ 15.76 $ 15.51 $ 15.51 $ 15.57 $ 15.66 $ 15.74 $ 15.64 $ 15.81~ec" sumøl 202ö2Ot0/l\ír~$ 111.65 $ 16.81 $ 16.82 . 16.90 $ 16.33 . 16.03 $ 16.tJ $ 16.13,$ .ts~:.;Ii:!lî1l ii'd...Supply Constrained Sumas 2021.2022 $ 17.17 $ 17.34 $ 17.36 $ 17.44 $ 16.79 $ 16.51 $ 16.55 $ 16.62' $ 16.66 $ 16.74 $ 16.70 $ 16.84sùi~Çgtr~ 20-2023$ 17.68 $ 17.8 $ 17.8 $ 17.93 $ 11.2 . 16.96 . 16.97 $ 17.01 $17:1'2: $111t'1.oo.$.k_~
Supply Constrained Sumas 2023-2024 $ 17.96 $ 18.16 $ 18.02 $ 18.01 $ 17.24 $ 16.99 $ 17.02 $ 17.08 $ 17.14 $ 17.21 $ 17.17 $ 17.26§\Î~~ 204-2025.' $ 18.21 $ 18.3 $ 18.40 $ 18.5 . 17.73 $ 17.48 $ 17.50 $ 17.56 $ 17.60 $ 1~$'11',gllllllli.
Supply Constrained Sumas 2025-2026 $ 18.72 $ 18.89 $ 19.22 $ 19.30 $ 18.51 $ 18.26 $ 18.29 $ 18.34 $ 18.39 $ 18.47 $ 18.41 $ 18.55~ S~; 2020 $ 19.50 $ 19.70 $ 20.08 $ 20.12 $ 19.25 $ 19.04 $ 19.09 $ 19.7 $ 19.14 $J9.22 $ 19.~li,__
Supply Constrained Sumas 2027-2028 $ 20.33 $ 20.51 $ 20.91 $ 20.99 $ 20.08 $ 19.90 $ 19.94 $ 19.93 $ 20.01 $ 20.10 $ 20.13 $ 20.24~eòns!~~¡:g~'2029 $ 21.24 $ 21.41 $ 21.1l $ 21.92 $ 21.04 $ 20.78 $ 2O.81i\*,$.1~ $ 20.88 l¡~r$~æ_~tSupply Constrained Sumas 2029.2030 $ 21.11 $ 21.11
250
2009 Natural Gas IRP - APPENDICIES
APPENDIX 6.2
GENERAL ASSUMPTIONS
251
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Appendix 6.2 - Weighted Average Cost of Capital
OREGON
AVISTA CORPORATION
Capital Structure and Overall Rate of Return
Cost of Capital as of Percent of
March 31, 2009 Amount Total Capital Cost Component
LI Debt 45.00%6.40%2.88%
Trust Preferred Securities 5.00%6.57%0.33%
Common Equity 50.00%10.00%5.00%
TOTAL 100.00%8.21%
WASHINGTON
AVISTA CORPORATION
Capital Structure and Overall Rate of Return
Agreed-upon
Cost of Capital Percent of
Total Capital Cost Component
LIT Debt 52.06%6.84%3.56%
Trust Preferred Securities 0.00%
Common Equity 47.94%10.20%4.89%
TOTAL 100.00%8.45%
IDAHO
AVISTA CORPORATION
Capital Structure and Overall Rate of Return
Agreed-upon
Cost of Capital Percent of
Amount Total Capital Cost Component
LI Debt (1)53.70%6.51%3.50%
Trust Preferred Securities 0.00%
Preferred Stock 0.00%
Common Equity 46.30%10.20%4.72%
TOTAL 100.00%8.22%
8.32%1System Weighted Average Cost of Capital*
GOP price deflator 2009 1.79%
RealWACC 6.42%
Tax rate 35%
Real after tax WACC "4.U%l
*Weighting based on net rate base as of 4/30109
254
Authorized Rates of Return
Washington Electric
General Case Settlement in 2008 (UE-0804 i 6)
effective 11112009
ProForma
Capital ProForma Weighted
Component Strctue Cost Cost
LIT Debt (1)53.70%6.51%3.50%
PrefTrust 0.00%
Common 46.30%10.20%4.72%
Total 100.00%8.22%
(1) includes shorHenn debt
Idaho Electric
Case Decided in 2008-AVU-E-08-01
effective 10/112008
Component
LIT Debt
PrefTrust
PrefStock
Common
Total
Capital
Strctue
52.06%
ProForma
Weighted
Cost
3.56%
0.00%
0.00%
4.89%
8.45%
ProForma
Cost
6.84%
47.94%
100.00%
10.20%
(excludes short-tenn debt)
Washington Gas
General Case Settlement in 2008 (UG-080417)
effctive 1/1/2009
ProForma
Capital ProForma Weighted
Component Structue Cost Cost
LIT Debt (1)53.70%6.51%3.50%
PrefTrust 0.00%
Common 46.30%10.20%4.72%
Total 100.00%8.22%
(l includes short-tenn debt
Idaho Gas
Case Decided in 2008-A VU-G-08-01
effective 10/1/2008
Component
LIT Debt
PrefTrust
PrefStock
Common
Total
(excludes short-term debt)
Capital
Structue
52.06%
47.94%
100.00%
ProForma
Cost
6.84%
ProForma
Weighted
Cost
3.56%
0.00%
0.00%
4.89%
8.45%
10.20%
Oregon Gas
General Case Settlement in 2007 (vG-18i)
effective 4/112008
Component
LIT Debt
PrefTrust
Common
Total
(excludes short-tenn debt)
255
Capital
Structue
45.00%
5.00%
50.00%
100.00%
ProForma
Cost
6.40%
6.57%
10.00%
ProForma
Weighted
Cost
2.88%
0.33%
5.00%
8.21%
ESCALTION/INFLATION FORECASTS
Implicit Price Deflators - U. S. Average 3/31/2009
Source: Randy Barcus. Finance--Analysis, Budget & Forecasting
Discount Rate: Levelizing is Not Applicable to Escalation Rates
E1 E2 E3 E4
Gross Personal Power Consumer
Domestic Consumption Equipment Price
Year Product Expenditures Investment Index-Urban
(% change)(% change)(% change)(% change)
1996 1.9 2.2 1.6 2.9
1997 1.7 1.7 2.1 2.3
1998 1.1 0.9 1.9 1.5
1999 1.4 1.7 1.6 2.2
2000 2.2 2.5 4.1 3.4
2001 2.4 2.1 2.8 2.8
2002 1.7 1.4 2.7 1.6
2003 2.1 2.0 2.3 2.3
2004 2.9 2.6 8.4 2.7
2005 3.3 2.9 9.4 3.4
2006 3.2 2.8 6.1 3.2
2007 2.7 2.6 5.0 2.9
2008 2.2 3.3 7.7 3.8
2009 0.9 -1.0 1.6 -1.9
2010 0.8 1.4 -1.8 1.7
2011 1.3 1.8 1.6 2.2
2012 1.4 1.7 2.3 2.3
2013 1.9 2.2 3.2 2.6
2014 2.2 2.1 3.5 2.4
2015 2.1 2.1 3.2 2.4
2016 2.1 2.1 3.0 2.5
2017 2.0 2.1 3.0 2.4
2018 2.0 2.1 3.0 2.4
2019 2.0 2.0 2.8 2.3
2020 2.0 1.9 2.8 2.1
2021 1.9 1.7 2.8 1.7
2022 1.9 1.8 2.6 2.0
2023 1.9 1.9 2.7 2.2
2024 1.9 1.9 2.7 2.1
2025 1.8 1.8 2.6 2.1
2026 1.8 1.9 2.6 2.1
2027 1.8 1.9 2.7 2.1
2028 1.9 1.9 2.7 2.2
2029 1.9 1.9 2.7 2.1
2030 1.9 1.9 2.7 2.2
2031 1.9 1.9 2.8 2.2
2032 1.9 1.9 2.8 2.2
2033 1.8 1.9 2.7 2.2
2034 1.8 1.9 2.7 2.2
2035 1.8 1.9 2.7 2.2
2036 1.8 1.9 2.7 2.2
2037 1.9 1.9 2.8 2.2
2038 1.9 2.0 2.8 2.2
2008-2038 Avg.1.8 1.9 2.7 2.1
5 Year Avg. 1.3 1.4 2.3 1.6
10 Year Avg. 1.7 1.8 2.7 2.0
20 Year Avg. 1.8 1.8 2.7 2.1
25 Year Avg. 1.8 1.9 2.7 2.1
30 Year Avg. 1.8 1.9 2.7 2.1
Std. Dev.1.0 1.0 1.5 1.0
0.5 0.6 1.8 0.8
E1 Applies to inflation of all good & services produced & consumed in the U.S.
E2 Applies to inflation of goods & services consumed by individuals.
E3 Applies to inflation of non-residential power equipment
E4 For all urban consumers, applies to inflation of a fixed market basket of typical
goods & services.
Reference:Globallnsights Review of the U.S. Economy First Quarter 2009
256
COST OF CAPITAL
Source: Paul Kimball, Treasury Department
Projected Long-Term Cost of Capital -- Avista Utilties
for Net Present Value Analysis
Target
Capital
Structure
Component
Cost
4/10/2009
Net
Present Value
Debt
Common Equity
Weighted Cost of Capital
50%
50%
7.60%
11.25%
3.80%
5.63%
9.43%
Authorized Cost of Capital -- Avista Utilties
for Revenue Requirements Analysis
Washington Elec/Gas Decided 2008
Authorized
Capital
Structure
Component
Cost
Component
Return
Debt
Common Equity
Rate of Return
53.70%
46.30%
6.51%
10.20%
3.50%
4.72%
8.22%
Authorized Cost of Capital -- Avista Utilties
for Revenue Requirements Analysis
Idaho Elec/Gas Decided 2008 AVU-08-1
Authorized
Capital
Structure
Component
Cost
Component
Return
Debt
Common Equity
Rate of Return
52.06%
47.94%
6.84%
10.20%
3.56%
4.89%
8.45%
257
2009 Natural Gas IRP - APPENDICIES
APPENDIX 6.3
SUPPLY SIDE RESOURCE OPTIONS
259
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2009 Natural Gas IRP - APPENDICIES
APPENDIX 6.5
SENDOUTQj MODEL DIAGRAM
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2009 Natural Gas IRP - APPENDICIES
APPENDIX 7.1
SENSITIVIES, SCNEARIOS, SIMULATIONS, AND PORTFOLIOS
LIST
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2009 Natural Gas IRP - APPENDICIES
APPENDIX 7.2
DEMAND AND EXPECTED RESOURCE GRAPHS
291
450,000
400,000
350,000
UI 300,000
i
i
250,000
200,000
150,000
100,000
50,000
Appendix 7.2 WAIID selected Resources VS. Peak Day Demand
(Net of DSM Savings) High Growth & Low Pnce Case - November to October
OJrr~hort ~I---I- I-::I- 1=-I- I-
~ t:
- i-- I-- I-
t: t:
I- I--I-
-I-::-I- t-
I-i-I-
::lF= I-
. -..-I- t-- I--I- t-
~
I--I- I--I-- I- -
I-- I- t-I- I-I- I--I--I- t-- r- i-1--1-1--1-1- -I-I--I-I-'-r--'-'---i---i -- --- --1--------1------- --1-----
o ~~~#~~~$~~#$##d##~##~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~
_ÐdstingGTN _ExislingTF-1 ~ExistingTF-2 _SpokaneSupply _Add'IGTN _Cap ReI Recall ~PeakDayDemand
140,000
120,000
100,000
",
E
iGIQ
80,000
60,000
40,000
20,000
_ Exsting GTN
Appendix 7.2 Medford/Roseburg selected Resources VS. Peak Day Demand
(Net of DSM Savings) . High Growth & Low Pnce Case - November to October
OJrrent Short-
-= ~1-1--1-1- -1-1-~ I-
I- I-
_ i-
::I- I---t: i.-'-
~ t-- i-
- -
- :: i--i- l-
I- I-'--I- I--I- I-- I- I--
- - --. --- --- -- - ---
- - - - -- - --'--------1---- --------o -,,-~~~#~~~$ ~~#$##d##~ ##~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~# ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ # # ~v # # ~ # # #
_ Exsting TF-1 "'ExilingTF-2 _Add'IGTN ~PeakDayDemand
293
22,000
20,000
18,000
16,000
II 14,000
E
.!
~
i!
12,000
10,000
8,00
6,000
4,000
2,000
_ Exsting GTN
Appendix 7.2 Klamath Falls Selected Resources VS. Peak Day Demand
(Net of DSM SalAngs) High Growth & Low Price Case - NOlomber to October
Qirrent Sh _,l
i- - I-f- '- -.I- -i- - I-
i-
=
_ f=--I-- ~-- Co
f- -- I--1-. - -- --
- Co -I- -- Co -I- - -- --'---- -- Co --I- ------- -- Co --- --I- - -- -~---Co-- -- -1--- --------Co-- -- -1--- --------i--- -- -1--- ----o ,~~#~~~~~#~#&##~### ~ ~~ ¿ ~ ~ ~ ~ ~ ø ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~~~~~~#########
_ExstingTF-1 c: KF Lateral Purchase -4. Peak Day Demand
Appendix 7.2 LaGrande Selected Resources VS. Peak Day Demand
(Net of DSM SalAngs) High Growth & Low Price Case. NOlomber to October
12,000
10,000
8,000
II
E
.!
~GlQ
6,000
--=--1---- I-----
---
--- I-- I-= t:= I-
=== - F= ==--- I-- I----- I-- I-- i--
- ""-1-- --1--1-- --I--I--i--
4,000 - - - I- - I- - i- - I- - - - I- - I- - i- -
2,000 - - - I- - I- - i- - I- - - - i- - I- - Co -
o ~~#~~~~~#~#&##~#####~ ¿ ~ ~ ~ ~ ~ ø ~ ~ ~ ~ ~~~ ~ ~ ~ ~ ~ ~
i:"- i:~ i:" i:" i:" i:~ i:" i:~ i:" .." -," i:rç i:'l ~v i:'l i:'V i:'V i:rç i:'l i:'Vrç rç rç rç rç rç rç rç rç 'v 'v rç rç rç rç rç rç rç rç rç
_ExistingTF-1 "-Peak Day Demand
294
Appendix 7.2 WAllO Selected Resources VS. Peak Day Demand
(Net of DSM Salongs) Expected Case with GTN Rate Double - Noi.mber to October
400,000
350,000
OJrre~hort
rJ 250,000
EQl
i
- f-= ~,=l
f- f- -I- I- -f- f- -
~ l:
300,000 .- I--.'- f-
200,000 - f- --1--1-1--I - f-
f- f- -- f-
150,000 - f- --I--f-I--
100,000 - r- i-- f- I- - I--- I-
50,000 - I- i---1----- -o -,#~~~~~~~~~~&#~~### ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ¿ ~ ~ ~ ~ ~ ~ ~~~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ##~######
_ Exting GTN _ Exsting TF-1 _ExistingTF-2 _ Spokane Supply _Sat LNG __Peak Day Demand
Appendix 7.2 Medford/Roseburg Selected Resources vs. Peak Day Demand
(Net of DSM Salongs) Expected Case with GTN Rate Double - Noi.mber to October
o ,
,Ç) " ,,'\ ~ ~ ~ ~ ~ 'ò Q) ~ " ~'1, r! ~ ~ n~ n'\ iò nO)~ ~ ~' ~ ~ ~ ~ ~ ~ ~ ~ ~ ~v ~ ~ ~ Ç)V Ç)V ~ Ç)V~ ~ ~ n~ ~ ~ ~ ~ A~ ~ ~ ~ ~ ~ ~ ~ ~ ~ A~ ~~ '" " "V ~ '" ~ ~ ~ ~ ~ ~ ~ :v ~~ ro ro ro ~ ~~~~~~~~~~~~~~~~~~~~~
_ Exting GTN _ Exsting TF-1 _ Exsting TF-2 _Add'IGTN -ePeak DayDemand
295
22,000
20,000
18,000
16,000
II 14,000
E
~..u
2l
12,000
10,000
8,000
6,000
4,000
2,000
Appendix 7.2 Klamath Falls Selected Resources VS. Peak Day Demand
(Net of DSM Sa\lngs) Expected Case with GTN Rate Double - NO\ember to October
Current Short
-- 'f-- .-
_ Exsting GTN
..- f----====----
= t:- f-- f-
= =---- - -
- -- f-----f--- - f----I--.'- - f--------- f-- f------f-- - ---1--1--- --I--1...-- I--- --f--i-- ---i----f--- --f--f-- ----f----I--
o ~~##~~~~#~#6##~######~~~N~~~~KK ~ ~# ~ ~ ~ ~ ~#~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ##~ #####~
_EitingTF-1 r: KF laeral Purchase -"Peak Day Demand
10,000
9,000
8,000
Appendix 7.2 LaGrande Selected Resources VS. Peak Day Demand
(Net of DSM Sa\lngs) Expected Cae with GTN Rate Double - NO\ember to October
-;= ,.=
6,000
5,000
4,000
--f--f--f-
=-F===t==r=
- f-_ f-- I-
---f-f-I-
- f-- f-- f-== F
-=- --- I-
7,000 - - - f- - f- - f- - I- - I- - f- - f- - ~ -- --f- -f--f- -I--I--f- -f------ --f- -f--f- -f- -f--f- -f----
3,000 - f- - f- - f- - f- - f- - f- - - - f- - - -
- --f- -f--f- -f- -f--~ -f----
2,000 - f- - f- - f- - f- - f- - f- - - - f- - - -
1,000 - f- - - - f- - - - f- - f- - - - f- - - -
o ~~##~~~~ #~#6##~### ~ ~~~ ~~~ ~~~~~~~ ~~~~ ~~~~~# ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ # # ~v# # # # # #
_ExistingTF-1 __ Peak Day Demand
II
E
.!
1ãuCDQ
296
Appendix 7.2 WAIID Selected Resources VS. Peak Day Demand
(Net of DSM Sa'Ãngs) Expected Case with GlN Unavailable - Noiember to October
400,000
350,000
OJrrent Shortr-
-If-
- ~- '-b
- t-- f--1-- -.300,000 f-I-I-
II 250,000
EGI
i
f- --f- --f-I--f--- - I-
200,000
¡¡If-t--t- --f-I--f--f-f- f- - t- I-
150,000 f-t--f- --f-I--f--f-f-t---I-
100,000 f- t- - f- I- - f- I- - f- I- -- I-
50,000 - ~ --f--'-i--- -
o
~",,'ì "- b- ': ~ ~ 'ò a¡ i: "_'1. r! b- ~n~n'\ n'òP.~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~v ~v ~v ~v~ ~ ~ n~ ~ ~ 3 ~ .~ ~ Of~ ~ ~ ~ ~ ~ ~ ~ .~ ~~ ~ " "V ~ ~ ~ ~ ~ ~ ~ W ~ :v W ~ ro ~ ~ W~~~~~~~~~~~~~~~~~~~~
_ExistingGTN _ExistingTF-1 i: Exting TF-2 _ Spokane Supply _Sat LNG __ Peak Day Demand
Appendix 7.2 Medford/Roseburg Selected Resources VS. Peak Day Demand
(Net of DSM Sa'Ãngs) Expected Case with GlN Unavailable - Noiember to October
140,000 () "'Ant ~hort
120,000 - f- -- f- -
80,000 f- t- -t- I- -f- t- -t= l:=~ i.--I- i-.-- f- ::100,000 - f- t-
II
E
.!'luGIQ
f- I-~ t- t--t- I-
60,000 t- I--f- I--f- t-- f- f--f- I-
40,000 - '--- f-
I I-- --- --- ~
-- f--- --- I-
20,000 - --- '-0, ,~~~~~~#~ #~#&##d### ##~~~~~~~~~~~~~~~~~~~~# ~ ~ ~ ~~ ~ ~ ~ ~ ~ ###~#####
_ExistingGTN _ExistingTF-1 _E)(stingTF-2 _ NWP Exansion __ Peak Day Demand
297
22,000
20,000
18,000
16,000
ti 14,000
E
£
BCIQ
12,000
10,000
8,000
6,000
4,000
2,000
Appendix 7.2 Klamath Falls Selected Resources VS. Peak Day Demand
(Net of DSM Savings) Expected Case with GlN Unavailable - NOlÆmber to October
OJrren Short
I-- I- -
_ Exsting GTN
-
----
1=== 1=
f- -----
= ~- I-= 1=--.. I-- --
- I--I-- I--I-- I-- -
- -
--- I-I-- I-- I--I-- I---- I-- I---- I-- --I-- I---- I-- I--I-- I-I-- I-- --- - -I- -I- - I- - I-I- -i..f- - - --1-----I- -I- -I- -I- -1--o ,~~#~~#~~~~#~##d#### ~~~~~~~~~~~~~~~~~~~~~#~~~~~#~~~###~######
_ExlingTF-1 c: KF Lateral Purchase .. P aak Day Demand
10,000
9,000
8,00
ti
E
1!
'ãCIQ
7,000
6,00
5,000
4,000
Appendix 7.2 LaGrande Selected Resources VS. Peak Day Demand
(Net of DSM Savings) Expected Case with GlN Unavailable - NOlÆmber to October
-1--1--=-f--I-
==t==c:
- I-- I-- f-- f-- I-- I-= ~
- --
== 1=- f-
=
"= I= - F=----f--I--f---- I-- f-- -- f-----f--I- -f--- -I- -f--~ -f-----f--I- -f--- -I- -f--- -f----
3,000 - f- - -- - f- - - - '- - f- - - - f- - - -
-f--I- -f--- -- -f--- -f----
2,000 - f- - ~ ~ f- - - - - - f- - - - f- - - -
1,000 - f- - I- ~ f- - - - - - f- - - - f- - - -o ~~~#~~#~~ ~~#~##d ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~# ~ ~~~~~#~~~~~#~~~###~ ######
_EicstingTF-1 ..Peak Day Demand
298
2009 Natural Gas IRP - APPENDICIES
APPENDIX 7.3
PEAK DAY DEMAND SERVED AND UNSERVED TABLES
299
Appendix 7.3 - Peak Day Demand - Served and Unserved (MOth/d)
Before Resource Additions & Net of DSM Savings
La Grande
Unserved
La Grande
Total
7.88
WAllO
Served
279.38
WAllO
Unserved WAllO Total
279.38
. '"314.0$ .
314.04
. 31'í:04
314.04
314.04
314.04
Klamath
Gas Year Falls Served2009-2010 12.58
Klamath
Falls
Unserved
Medford!
Roseburg
Served
70.11
70.34 LÄ.ù0j"¡,
72.20
Medford!
Roseburg
Unserved
Medford!
Roseburg
Total
70.11
301
Appendix 7.3 - Peak Day Demand - Served and Unserved (MOth/d)
Before Resource Additions & Net of DSM Savings
Case
Low Demand-=l~..
Low Demand
Gas Year
2009-2010201d;m' I
2011-2012
Low
Low
Case
Low Demand
Gas Year
2009-2010
Low.¿. l...n.;mà~2(2021,');;.G""~;..;;",~\".::..lr.'J\,¡f~V '.Low Demand 2021-2022
èmand '.: 202-2023 .
Low Demand 2023-2024~nd
Low Demand
Low
La Grande
Served
7.86
1,'S"
7.57
La Grande
Unserved
WAID
Served
274.71
WAIID
Unserved
La Grande
Total
7.86
WAIID Total
274.71
. '1'21
7.23
.7;23'
7.25
7.37
1.39
7.40
1.42'
Klamath
Falls Served
12.58
Klamath
Falls
Unserved
Medford!
Roseburg
Served
70.10
Medford!
Roseburg
Unserved
Medford!
Roseburg
Total
70.10
Klamath
Falls Total
12.58
12;64.;¡
12.22
70.98
12.2t.
12.29
12.20
12.29
12.31'
12.45
72.53
75.34
302
Appendix 7.3 - Peak Day Demand - Served and Unserved (MOth/d)
Before Resource Additions & Net of DSM Savings
La Grande
Case Gas Year ServedGreen Future 2009-2010 7.98
La Grande
Unserved
La Grande
Total
7.98
WAllO
Served
274.58
WAllO
Unserved WAllO Total
274.58
KlamathCase Gas Year Falls Served
Green Future 2009-2010 12.71
Klamath
Falls
Unserved
Klamath
Falls Total
12.71
Medford!
Roseburg
Served
70.44
Medford!
Roseburg
Unserved
Medford!
Roseburg
Total
70.44
303
Appendix 7.3 - Peak Day Demand - Served and Unserved (MOth/d)
Before Resource Additions & Net of DSM Savings
Case Gas Year
Alt Weather Std 2009-2010A1tWe~~blo'2011
Alt Weather Std 2011-2012
'~ì+:~E t !"'~;2O~:llS: .
Alt Weather Std 2013-2014
Alt Weather Std
Alt Weather
;HI6l"Y~at~LStd . S:i9-2027Alt Weather Std 2027-2028.~8-2d
Case
Alt Weather Std
Gas Year
2009-2010
Alt Std
Alt
La Grande La Grande
SeNed UnseNed
7.98
1:äE
7.95
IlM!"
8.12
. 1'1£63:
8.71." 8;1l .'
8.87
8.95
9.03
~c ¡.:
Klamath
Falls SeNed
12.71
Klamath
Falls
UnseNed
13.23
13.58
1:-:S2'
13.80
fl-M.....
14.27
La Grande
Total
7.98
7.86
7.95
1305
8.12
8.56
8.63
8.71
8.19
8.87
8.95
9.03
9.11
Klamath
Falls Total
12.71
;'l~rEi:
12.90
13':23
13.58
13.82
13.80
'l4Jî4
14.27
tali..
304
WAlO
SeNed
252.68
WAllO
UnseNed
28l;~ .
293.79
300JI2
311.77
313JJ6
Medford!
Roseburg
SeNed
67.86
6T?tt
68.40'/51
72.53
Medford!
Roseburg
UnseNed
WAllO Total
252.68
Appendix 7.3. Peak Day Demand. Served and Unserved (MOth/d)
Before Resource Additions & Net of DSM Savings
Case
Supply Constrained'S~Il~'..~Clll!l&fä"
Supply Constrained'$ i6ttiì ~13 ~,~
Supply Constrained' 2013-2014 '. . '
iiI CoMl ,..-201~
Supply Constrained 2015-2016
.iù~ 2016-2017
Supply Constrained 2017-2018" ~~-d,;;b¡!¡M".8_~":~U.",."lÇ,¡~~. . ~~.
Supply Constrained 2019-2020..~;..~.._k~O ""l! "B. '~YVUl""_~'" -~~F.i~
Supply Constrained 2021-2022. ~'&""Iy ,.~~:m"2:202~ r¡.?!:.~.~~:~,. ~\t
Supply Constrained 2023-2024~~ F..2024-~'
Supply Constrained 2025-2026¡znšli ¡i 11-"2027 'bi~' '
Supply Constrained 2027-2028S~ppl~in41111~~4 ...
Gas Year
2009-2010
La Grande
Served
7.98
La Grande
Unserved
La Grande
Total
7.98
WAlO WNIO
Served Unserved
274.58
249.Ø4t'Y"'t'fT'
249.06
WNIOTotal
274.58
.M5
7.30
270.80
Klamath
Falls
Unserved
Klamath
Falls Total
12.71
Medfordl
Roseburg
Served
70.44
Medfordl
Roseburg
UnservedCase Gas Year
Supply Constrained 2009-2010~~:iÒ"'1'.~.'...", ',' ~~.,::,,~~\!';FJj';
Constrained 2011-2012
305
2009 Natural Gas IRP - APPENDICIES
APPENDIX 7.4
LOAD DURATION CURVE GRAPHS (HIGH AND LOW GROWTH
CASES)
307
Appendix 7.4 Load Duration Curve & Resource Sta
(Dermnd shown netofDSM)
High Case - WAIID
500
450 Peak Day (MDt)
2009-10 279
2018-19 341
2028-29 430400
350
300
is 250::
200
150
100
50
29 57 85 113 141 169 197 225 309 337 365
Days Available
- SlJrage Inejeclns Post2011 = SlJrage Injectns 2009-10 _ 2028-29 _ 2018-19 _ 2009-10 - Current Resurces
253 281
Appendix 7.5 Load Duration Curve & Resurce Stack
(Dermnd shown netofDSM)
High Case- OR
200
180
Peak Day (MDIh)
2009-10 891602018-19 119
2028-29 153
140
..120
ì5::
100
80
60
40
20
29 57 85 113 141 169 197 225 253 281 309 337 365
Days Available
- Slrage Injectns Post2011 = SlJrage Injecns 2009-10 _ 2028-29 _ 2018-19 _ 2009-10 - Current Resourcs
309
Appedix 7.4 Loa Duraon Curve & Resource Stack
(Demand shown net ofDSM)
Low Case - WAllO
500
450 Peak Day (MDti)
2009-10 275
2018-19 244
2028.29 246400
350
300
.c
~ 250
200
150
100
50
29 57 85 309 337 365
Days Available
_ Slrage Inejens Pos2011 = Slrage Injens 2010 _ 2009-10 _ 2028-29 _ 2018-19 - Current Resouræs
113 141 169 197 225 253 281
Appendix 7.4 Load Duraon Curv & Reurc Sta
(Demand shown netofDSM)
Low Case. OR
200
180
Péak Day (MDti)
2009-10 891602018-19 87
2028-29 95
140
.c 120
ë::
100
80
60
40
20
29 57 85 113 141 169 197 225 281 309 337 365
Days Available
253
- Sl:age Injens Pos2011 = Sl:rage Injeclns 2009-10 _ 2009-10 _ 208-29 _ 2018-19 - Current Resuræs
310
2009 Natural Gas IRP - APPENDICIES
APPENDIX 7.5
TOTAL COST BY PORTFOLIO
311
Appendix 7.5 - Net Present Value of Revenue Requirement (NPVRR) by Portolio
Portfolio
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 Expected Elasticity and Existing Resources
Coldest in 20 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 Prices with Restricted Capacity
Supply Constrained with Existing Resources
313
NPVRR in (OOO's)
$
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(6,514,895)
(6,547,705)
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(7,997,147)
(7,691,204)
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2009 Natural Gas IRP - APPENDICIES
APPENDIX 8.1
DISTRIBUTION SYSTEM MODELING
319
2009 Natural Gas IRP
APPENDIX 8.1 - DISTRIBUTION SYSTEM MODELING
OVERVIEW
The primary goal of distribution system planning is to design for present needs and to plan for future
expansion to serve demand growth. This allows A vista to satisfy curent demand-serving
requirements while taking steps toward meeting futue needs. Distribution system planning identifies
potential problems and areas of the distribution system that require reinforcement. By knowing when
and where pressure problems may occur, the necessary reinforcements can be incorporated into
normal maintenance. Thus, more costly reactive and emergency solutions can be avoided.
COMPUTER MODELING
When designing new main extensions, computer modeling can help determine the optimum size
facilities for present and future needs. Undersized facilities are costly to replace, and oversized
facilities incur unnecessary expenses to A vista and its customers.
THEORY AND APPLICATION OF STUDY
Natural gas network load studies have evolved in the last decade to become a highly technical and
useful means of analyzing the operation ofa 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 refmed to the point where solutions obtained closely represent actual system
behavior.
Avista conducts network load studies using Advantica's SynerGEEiI 4.3.0 software. This computer-
based modeling tool rus on a Windows operating system and allows users to analyze and interpret
solutions graphically.
CREATING A MODEL
To properly study the distribution system, all naturl gas main information is entered (length, pipe
roughness and ID) into the modeL. "Main" refers to all pipelines supplying services.
Nodes (points where natural gas enters or leaves the system) are placed at all pipe intersections,
beginings and ends of mains, changes in pipe diameter/material and to identify all large customers.
A model element connects two nodes together. Therefore, a "to node" and a "from node" wil
represent an element between those two nodes. Almost all of the elements in a model are pipes.
Regulators are treated like adjustable valves in which the downstream pressure is set to a known
value. Although specific regulator types can be entered for realistic behavior, the expected flow
passing through the actual regulator is determed and the modeled regulator is forced to
accommodate such flows.
Avista 8.1.1
321
Appendix 8.1 - Distribution System Modeling 2009 Natural Gas I RP
FLUID MECHANICS OF THE MODEL
Pipe flow equations are used to determine the relationships between flow, pressure drop, diameter
and pipe length. For all models, the Fundamental Flow equation (FM) is used due to its
demonstrated reliability.
Effciency factors are used to account for the equivalent resistance of valves, fittings and angle
changes within the distribution system. Starting with a 95 percent factor, the efficiency can be
changed to fie tune the model to match field results.
Pipe roughess along with flow conditions creates a friction factor for all pipes within a system.
Thus, each pipe may have a unique friction factor, minimizing computational errors associated with
generalized friction values.
LOAD DATA
All studies are considered steady state; all natual gas entering the distribution system must equal the
natural gas exiting the distribution system at any given time.
Customer loads are obtained from Avista's customer biling system and converted to an algebraic
formt so loads can be generated for various conditions.
In the event of a peak day or an extremely cold weather condition, it is assumed that all curtailable
loads are interrpted. Therefore, the models wil be conducted with only core loads.
DETERMINING NATURAL GAS CUSTOMERS' MAXIMUM HOURLY USAGE
Determining a Base Load
Base loads are not temperatue dependent; they remain relatively constant regardless oftemperatue.
A reasonable base load can be calculated from customer biling information. The biling month,
which has the lowest amount of heating degree days is usually August. Usage during this month wil
reflect nearly all natural gas loads exclusive of space heating.
By determing the amount of days in the biling period and applying a peaking factor, the peak
hourly base load of each customer can be estimated as shown in Table 1:
Table 1 . Determining Base Load
Customer Usage
Summer Billng Period
1
X Days in Biling X 0.0625* =Period
Peak Hourly
Base Load
The average residential customer's peak usage was found to be 6.25 percent of the total daily load. This peaking factor was estimated by studying the
ratio of the peak hourly flow and the total daily flow at the pipeline gate stations in past years. The peaking factor is periodically discussed with other
utilities and has been consistent with other utilities of similar size.
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Determining Heat Load
A heat load wil be proportional to heating degree-days (HDDs); at 0 HDD, the load wil be zero. A
heat load can be reasonably calculated from customer biling information. The biling month with
the greatest consumption is usually January. This month reflects maximum space heating as well as
non-space heating loads.
Customers' usage for January (winter) biling, minus usage for August (summer) biling, leaves a
reasonable estimate for heat load. This load can be divided by the amount ofHDDs that occured in
January, leaving usage per HDD. Customer needs can be calculated by applying the peaking factor,
resulting in a peak hourly heat load per HDD. This is shown in Table 2:
Table 2 - Determining Heat Load
1 Customer Usage
Winter Biling -
Period
Customer usageJ
Summer Biling X
Period
1
Winter Biling
Period Degree
Days
X Peak HODs X 0.0625* = Peak HourlyHeat Load
Determining Design Peak Hourly Load
The design peak hourly load for a customer is estimated by adding the hourly base load and the
hourly heat load for a design temperature. This estimate reflects highest system hourly demands, as
shown in Table 3:
Table 3 - Determining Peak Hourly Load
Peak Hourly Base +Load
Peak Hourly
Heat Load =Peak Hourly
Load
This method differs from the approach that we use for IRP peak day load planning. The primary
reason for this difference is due to the importance of responding to hourly peaking in the distribution
system, while IRP resource planning focuses on peak day requirements to the city gate.
APPLYING LOADS
Having estimated the peak loads for all customers in a particular service area, the model can be
loaded. The first step is to assign each load to the respective node or element.
GENERATING LOADS
Temperature-based and non-temperatue-based loads are established for each node or element, thus
loads can be varied based on any temperature (HDD). Such a tool is necessar to evaluate the
difference in flow and pressure due to different weather conditions.
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GEOGRAPHIC INFORMATION SYSTEM (GIS)
We have recently converted our natual gas facility maps to GIS. While the GIS can provide a
variety of map products, its power lies in its analytical capability. A GIS consists ofthree
components: spatial operations, data association and map representation.
A GIS allows analysts to conduct spatial operations (relating a feature or facility to another
geographically). A spatial operation is possible if a facilty displayed on a map maintains a
relationship to other facilities. Spatial relationships allow analysts to perform a multitude of queries,
including:
. identify electric customers adjacent to natural gas mains who are not currently using natural
gas;
· display the ratio of customers to length of pipe in Emergency Operating Procedure zones
(geographical areas defied by the number of customers and their safety in the event of an
emergency); and
. classify high-pressure pipeline proximity criteria.
The second component of the GIS is data association. This allows analysts to model relationships
between facilities displayed on a map to tabular informtion in a database. Databases store facility
information such as pipe size, pipe materiaL pressure rating, or related information (e.g., customer
databases, equipment databases and work management systems). Data association allows interactive
queries within a map-like environment.
Finally, the GIS provides a means to create maps of existing facilities in different scales, projections
and displays. In addition, the results of a comparative or spatial analysis can be presented pictorially.
This allows users to present abstract analyses in a more intuitive context.
BUILDING SynerGEElI MODELS FROM A GIS
The GIS can provide additional benefits through the ease of creation and maintenance of load
studies. Avista can create load studies from the GIS based on tabular data (attrbutes) installed
during the mapping process.
MAINTENANCE USING A GIS
The GIS helps maintain the existing distribution facilty by allowing a design to be initiated on a
GIS. Currently, design jobs for the company's natual gas system are managed through Avista's
Facility Management (AFM) tool. This system is being integrated with GIS, allowing jobs to be
designed directly within a GIS. Once completed, the as-built information is submitted to GIS and the
facility is immediately updated. This eliminates the need to convert physical maps to a GIS at a later
date. Because the facility is updated on GIS, load studies can remain curent by refreshing the
analysis.
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DEVELOPING A PRESENT CASE LOAD STUDY
In order for any model to have accuracy, a present case model has to be developed that reflects what
the system was doing when downstream pressures and flows are known. To establish the present
case, pressure charts located throughout the distribution system are used.
Pressure charts plot pressure (some include temperature) versus time over several days. Various
locations recording simultaneously are used to validate the modeL. Customer loads on SynerGEE(j
are generated to correspond with actual temperatures recorded on the pressure charts. An accurate
model's downstream pressures wil match the corresponding location's field pressure chart.
Effciency factors are fine-tuned to fuher refie the model's pressures.
Since telemetry at the gate stations record hourly flow, temperature and pressure, these values are
used to validate the modeL. All loads are representative ofthe average daily temperature and are
defmed as hourly flows. If the load generating method is truly accurate, all natual gas enterig the
actual system (physical) equals total natural gas demand solved by the simulated system (model).
DEVELOPING A PEAK CASE LOAD STUDY
Using the calculated peak loads, a model can be analyzed to identify the behavior during a peak day.
The efficiency factors established in the present case are used throughout subsequent models.
ANALYZING RESULTS
After a modelhas been balanced, several features within the SynerGEE(j model are used to translate
results. Color plots are generated to depict flow direction, pressure, pipe diameter and gradient with
specific break points. Reinforcements can be indentified by visual inspection. When user edits are
completed and the model is re-balanced, pressure changes can be visually displayed, helping identify
optimum reinforcements.
An optimum reinforcement wil have the largest pressure increase per unit length. Reinforcements
can also be deferred and occasionally eliminated through load mitigation ofDSM efforts.
PLANNING CRITERIA
In most instances, models resulting in node pressures below 15 psig indicate a likelihood of
distribution low pressure and therefore necessitate reinforcements. For most Avista distribution
systems, a minimum of 15 psig wil ensure deliverability as natual gas exits the distribution mains
and travels through service pipelines to a customer's meter. Some Avista distribution areas operate
at lower pressures and are assigned a minimum pressure of 5 psig for model results. Given a lower
operating pressure, service pipelines in such areas are sized accordingly to maintain reliability.
DETERMINING MAXIMUM CAPACITY FOR A SYSTEM
Using a peak day model, loads can be prorated at intervals until area pressures drop to 15 psig. At
that point, the total amount of natural gas entering the system equals the maximum capacity before
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new construction is necessary. The difference between natual gas entering the system in this
scenario and a peak day model is the maximum additional capacity that can be added to the system.
Since the approximate natual gas usage for the average customer is known it can be determined
how many new customers can be added to the distribution system before necessitating system
reinforcements. The above models and procedures are utilized with new construction proposals or
pipe reinforcements to determine a potential increase in facilities.
FIVE. YEAR FORECASTING
The intent of our load study forecasting is to predict the system's behavior and reinforcements
necessary within the next five years. Various A vista personnel provide information to determine
where and why certain areas may experience growth.
By combining information from Avista's demand forecast, IRP planning efforts, regional growth
plans and area developments, proposals for pipeline reinforcements and expansions can be evaluated
with SynerGEEiI.
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