20120831Avista 2012 Natural Gas IRP.pdf

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Avista Corp.
1411 East Mission P.O.Box 3727
Spokane.Washington 99220-0500
Telephone [phone]
Toll Free 800-727-9170
August 31,2012
Jean D.Jewell,Secretary
Idaho Public Utilities Commission
Statehouse Mail
W.472 Washington Street
Boise,Idaho 83720
Dear Ms.Jewell:
RE:Avista Utilities 2012 Natural Gas Integrated Resource Plan (IRP)
Per IPUC’s Integrated Resource Plan Requirements outlined in Case No.U-1500-165,
Order No.22299,Case No.GNR-E-93-1,Order No.24729 and Case No.GNR-E-93-3,
Order No.25260 ,Avista Corporation d/b/a/Avista Utilities,hereby submits for filing an
original,an electronic copy,and 7 copies of its 2012 Natural Gas Integrated Resource
Plan.
The Company submits the IRP to Public Utility Commissions in Idaho,Washington and
Oregon every two years as required by state regulation.The Company has a statutory
obligation to provide reliable natural gas service to customers at rates,terms and
conditions that are fair,just,reasonable and sufficient.The IRP,by identif’ing and
evaluating various resource options and establishing a plan of action for resource
decisions,is a significant component in meeting this obligation.
The 2012 Plan highlights the following:
•Our philosophy is to reliably provide natural gas to our customer with an
appropriate balance of price stability and prudent cost using our portfolio of
purchase contracts,storage and firm pipeline capacity rights;
•The Company forecasts sufficient natural gas resources well into the future with
resource needs not occurring until 2028 in Oregon and 2030 in Washington and
Idaho;
•t ,.“
•The major change from the 2009 IRP is that customer growth has slowed and it is
not anticipated to rebound in the near term and also use per customer has
declined;
•The price of natural gas has dropped significantly since our last IRP.Robust
North American supplies lead by shale gas developments coupled with lackluster
demand due to the economy has pushed prices down to levels not seen in the last
decade.These low prices,while good for our customers,challenge the cost-
effectiveness of DSM at the program level.Since the drafting of this document,
Avista has filed in Washington and Idaho to suspend natural gas DSM programs
and will soon be making a similar filing in Oregon.
•As forecasted demand is relatively flat,we will monitor actual demand for signs
of increased growth which could accelerate resource needs.
Please direct any questions regarding this report to Kelly Irvine at [phone].
Sincerely,
Linda Gervais
Manager,Regulatory Policy
State and Federal Regulation
Avista Utilities
509-495-4975
linda.gervaisavistacorp.com
cc:Mr.Sterling
Ms.Kathleen McHugh
Mr.Maff Elam
2012 NATURAL GAS
vu -6 -li-O
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INTEGRATED RESOURCE PLAI
AUGUST 31,2012
417ws TAwww.avistautilities.com
2012 AvI5TA NATURAL GAS IRP
II TABLE OF CONTENTS
Executive Summary Chapter 1
Introduction 2
Demand Forecasts 3
Demand-Side Resources 4
Supply-Side Resources 5
Integrated Resource Portfolio 6
Alternate Scenarios,Portfolios,Stochastic Analysis 7
Distribution Planning 8
Action Plan 9
Glossary of Terms and Acronyms 10
Note:Appendices provided under separate cover.
2012 AVISTA NATURAL GAS IRP
II SAFE HARBOR STATEMENT
This document contains forward-looking statements,including statements regarding our current expectations
for future financial performance and cash flows,capital expenditures,financing plans,our current plans or
objectives for future operations and other factors,which may affect the company in the future.Such
statements are subject to a variety of risks,uncertainties and other factors,most of which are beyond our
control and many of which could have significant impact on our operations,results of operations,financial
condition or cash flows and could cause actual results to differ materially from those anticipated in such
statements.
For a further discussion of these factors and other important factors please refer to the Company’s reports
filed with the Securities and Exchange Commission,which are available on our website at
www.avistacorp.com.The forward-looking statements contained in this document speak only as of the date
hereof.We undertake no obligation to update any forward-looking statement or statements to reflect events or
circumstances that occur after the date on which such statement is made or to reflect the occurrence of
unanticipated events.New factors emerge from time to time,and it is not possible for management to predict
all of such factors,nor can it assess the impact of each such factor on our business or the extent to which any
such factor,or combination of factors,may cause actual results to differ materially from those contained in
any forward-looking statement.
2012 AvI5TA NATURAL GAS IRP
II 2012 IRP KEY MESSAGES
ii Avista has a diversified portfolio of existing natural gas supply resources including owned
and contracted storage,firm capacity rights on six pipelines and purchase contracts from
several different supply basins.Our philosophy is to reliably provide natural gas to
customers with an appropriate balance of price stability and prudent cost.
ii Avista’s 2012 Integrated Resource Plan (IRP)forecasts lower demand for all service
territories than our previous plans.These reductions are driven by lower growth rates and
declining use-per-customer in our service territories than originally anticipated driven
primarily by the recession.
ii Additional resource needs do not occur until well into the future.In Oregon,the first
resource deficits occur in 2029 and in Washington and Idaho in 2030.Demand growth
averages 1.3 percent per year in the respective jurisdictions.Customer accounts are expected
to grow at an annual average rate of 1.6 percent and 1.7 percent,respectively.Our plan
indicates incremental pipeline transportation capacity is the preferred resource to meet the
identified needs.
ii An important risk with the identified future resource deficits is the relatively flat slope of
forecasted demand growth.Implied in this outlook is existing resources will be sufficient to
meet demand for most of the 20 year planning horizon.However,should demand growth
accelerate,the steepening of the demand curve could quickly accelerate resource shortages
by several years.
ii Other risks evaluated include long term natural gas pricing levels,potential impacts of
carbon legislation and hydraulic fracturing,future availability of existing regional resources,
implication of exporting LNG,alternate weather planning standard,and potential
NGV/CNG demand.
ii Conservation potential is an integral component of our IRP process and a starting point for
the DSM business planning process,as these programs result in multiple benefits including
reduced customers’bills,reduced supply-side resource needs and reduced greenhouse gas
(GHG)emissions.Lower avoided costs have challenged the cost-effectiveness of natural gas
DSM programs,resulting in filings to suspend programs in Washington and Idaho.The
Oregon DSM portfolio is currently under evaluation.
ii The IRP identifies and establishes an Action Plan that continues to guide us toward the risk
adjusted,least-cost method of providing service to our natural gas customers.Included in
this Action Plan are efforts to closely monitor avoided costs and the cost effectiveness of
natural gas DSM,evaluate current price elasticity adjustment,watch LNG export trends,and
perform gate station analysis.
2012 AVISTA NATURAL GAS IRP
II INDEXOFTABLES
Table 1.1 Demand Scenarios Page 1.2
Table 3.1 Geographic Demand Classifications 3.1
Table 3.2 Basic Demand Formula 3.2
Table 3.3 SENDOUT©Demand Formula 3.2
Table 3.4 Demand Sensitivities 3.10
Table 3.5 Demand Scenarios 3.11
Table 4.1 Baseline Forecast Summary 4.3
Table 4.2 Conservation Measures 4.4
Table 4.3 Summary of Cumulative Achievable,Economic and Technical Conservation Potential ----4.5
Table 4.4 Summary of Cumulative Achievable,Economic and Technical Conservation Potential ----4.6
by State and Sector
Table 4.5 Residential Cumulative Achievable Potential by State,Selected Years 4.8
Table 4.6 C&I Cumulative Achievable Potential by Sector by Selected Years 4.9
Table 4.7 Idaho Natural Gas Target (2013-2014)4.10
Table 4.8 Oregon Natural Gas Target (2013-2014)4.10
Table 4.9 Washington Natural Gas Target (2013-2014)4.10
Table 5.1 Firm TransportationlResources Contracted 5.6
Table 5.2 Supply Scenarios 5.13
Table 6.1 Regional Price as a Percent of Henry Hub Price 6.7
Table 6.2 Monthly Price as a Percent of Average Price 6.7
Table 6.3 Peak Day Demand —Served and Unserved 6.14
Table 6.4 Annual,Annual Average and Peak Day Demand Served by DSM 6.18
Table 6.5 Supply-Side Resource Selected in SENDOUT®6.19
Table 7.1 Demand Scenarios 7.1
Table 7.2 Supply Scenarios 7.4
2012 AVISTA NATURAL GAS IRP
II INDEX OF TABLES (CONTINUED)
Table 7.3 Net Present Value of Revenue Requirement (PVRR)by Portfolio 7.5
Table 7.4 Example Monte Carlo Weather Inputs 7.6
Table 8.1 Distribution Planning Capital Projects 8.5
2012 AVISTA NATURAL GAS IRP
II INDEX OF FIGURES
Figure 1.1
Figure 1.2
Figure 1.3
Figure 1.4
Figure 1.5
Figure 1.6
Figure 1.7
Figure 1.8
Figure 1.9
Figure 1.10
Figure 1.11
Figure 1.12
Figure 1.13
Figure 2.1
Figure 2.2
Figure 2.3
Figure 3.1
Figure 3.2
Figure 3.3
Figure 3.4
Figure 3.5
Figure 3.6
Figure 3.7
Average Daily Demand Scenarios Page 1.3
Peak Day Demand Scenarios 1.4
Henry Hub Price Forecasts for IRP 1.5
First-Year Peak Demand Not Met with Existing Resources 1.6
Expected Case WAJID Existing Resources vs.Peak Day Demand 1.7
Expected Case MedfordJRoseburg Existing Resources vs.Peak Day Demand 1.7
Expected Case Klamath Falls Existing Resources vs.Peak Day Demand 1.8
Expected Case La Grande Existing Resources vs.Peak Day Demand 1.8
Flat Demand Risk Example 1.9
Expected Case WA/ID Selected Resources vs.Peak Day Demand 1.10
Expected Case MedfordlRoseburg Selected Resources vs.Peak Day Demand 1.10
Expected Case Kiamath Falls Selected Resources vs.Peak Day Demand 1.11
First-Year Peak Demand Not Met with Existing Resources 1.12
Firm Customer Mix 2.2
Therms by Class 2.3
Customer Demand by Service Territory 2.3
Customer Growth Scenarios Total System 3.3
Example Demand vs.Average Temperature 3.4
Annual Demand —Demand Sensitivities 3.5
Reference Case Assumptions 3.8
Sensitivities,Scenarios,Portfolios 3.9
Demand Sensitivities —Annual Demand —Total System 3.10
Average Daily Demand Scenarios 3.12
2012 AvI5TA NATURAL GAS IRP
II INDEX OF FIGURES (coNTINuED)
Figure 3.8 Peak Day Demand Scenarios Page 3.13
Figure 4.1 Conservation —Potential Energy Forecast 4.7
Figure 5.1 Monthly Index Prices 5.3
Figure 5.2 Direct-Connect Pipelines 5.6
Figure 5.3 Proposed New Pipeline Projects 5.10
Figure 6.1 SENDOUT®Model Diagram 6.2
Figure 6.2 Total System Average Daily Load 6.4
Figure 6.3 Henry Hub Forecasted Price 6.5
Figure 6.4 Low/Medium/High Forecasted Price —Real $per Dth 6.6
Figure 6.5 Low/Medium/High Forecasted Price —Nominal $/Dth 6.6
Figure 6.6 Existing Firm Transportation Resources —WA/ID 6.8
Figure 6.7 Existing Firm Transportation Resources —OR 6.9
Figure 6.8 Average Case —WA/ID Existing Resources vs.Average Day Demand 6.10
Figure 6.9 Average Case —Medford/Roseburg Existing Resources vs.Average Day Demand 6.10
Figure 6.10 Average Case —Klamath Falls Existing Resources vs.Average Day Demand 6.11
Figure 6.11 Average Case —La Grande Existing Resources vs.Average Day Demand 6.11
Figure 6.12 Expected Case —WA/ID Existing Resources vs.Peak Day Demand 6.12
Figure 6.13 Expected Case —Medford/Roseburg Existing Resources vs.Peak Day Demand 6.12
Figure 6.14 Expected Case —Klamath Falls Existing Resources vs.Peak Day Demand 6.13
Figure 6.15 Expected Case —La Grande Existing Resources vs.Peak Day Demand 6.13
Figure 6.16 Avoided Costs 6.17
Figure 6.17 Expected Case -WA/ID Selected Resources vs.Peak Day Demand 6.20
Figure 6.18 Expected Case —Medford/Roseburg Selected Resources vs.Peak Day Demand 6.20
Figure 6.19 Expected Case —Klamath Falls Selected Resources vs.Peak Day Demand 6.21
Figure 6.20 Gate Station Modeling Challenge 6.22
2012 AvI5TA NATURAL GAS IRP
II INDEX OF FIGURES (CONTINUED)
Figure 7.1 Peak Day (FEB 15)2012 IRP Demand Scenarios 7.2
Figure 7.2 Peak Day (DEC 20)2012 IRP Demand Scenarios 7.2
Figure 7.3 First Year Peak Demand Not Met with Existing Resources 7.3
Figure 7.4 Frequency of Peak Day Occurrences —Spokane 7.6
Figure 7.5 Frequency of Peak Day Occurrences —Medford 7.7
Figure 7.6 Frequency of Peak Day Occurrences —Roseburg 7.7
Figure 7.7 Frequency of Peak Day Occurrences —Klamath Falls 7.8
Figure 7.8 Frequency of Peak Day Occurrences —La Grande 7.8
Figure 7.9 Avista IRP Total 20-Year Cost 7.9
2012 AVISTA NATURA1GASRP II
CHAPTER 1 II EXECUTIVE SUMMARY
Avista’s 2012 Natural Gas Integrated Resource Plan (IRP)identifies a strategic natural gas resource
portfolio that meets future customer demand requirements over the next 20 years.While the primary
focus of the IRP is ensuring our ability to meet customer’s needs under peak weather conditions,this
process also provides a methodology for evaluating customer needs under normal or average conditions.
The formal exercise of bringing together customer demand forecasts with comprehensive analyses of
resource options,including supply-side resources and demand-side measures,is valuable to Avista,its
customers,Regulatory Commissions and other stakeholders for long-range planning.
IRP PROCESS AND STAKEHOLDER INVOLVEMENT
The IRP is a coordinated effort by several Avista departments along with input from our Technical
Advisory Committee (TAC),which includes Commission Staff peer utilities,customers and other
stakeholders.This group is a vital component of our IRP process,as it provides a forum for the exchange
of ideas from multiple perspectives,identifies issues and risks and improves analytical methods.Topics
discussed with the TAC include natural gas demand forecasts,demand-side management (DSM),supply-
side resources,computer modeling tools and distribution planning.The end result is an integrated
resource portfolio designed to serve our customers’natural gas needs well into the future while balancing
cost and risk.
PLANNING ENVIRONMENT
Uncertainty is a factor in any forecast,and while there are many uncertainties to consider in this IRP there
is one element that has become clear.Shale gas has changed the landscape for North American supply
and turned the price of natural gas on its head.While shale is not new,the technological improvements
for extraction,the value of natural gas liquids and the amount of gas associated with oil extraction have
significantly impacted the volume and cost of the supply mix.Couple this with declining use-per-
customer and stagnant customer growth due to the prolonged effect of the recession and you have a
supply glut driving prices to lows not seen in the last decade.Even though we are hopeful that low-cost
natural gas will be available for many years to come,there are no guarantees,so we continue to challenge
key assumptions and perform our “what if’analysis in order to cover a broad range of possibilities.
DEMAND FORECASTS
In this IRP,we define eight distinct demand areas,which are structured around the pipeline transportation
and storage resources that serve them.Our demand areas are aggregated into four large service territories
(Washington/Idaho;Medford/Roseburg,Oregon;Klamath Falls,Oregon and La Grande,Oregon)and
then disaggregated by the pipelines that serve them.The Washington/Idaho service territory is
disaggregated into areas that can be served only by Northwest Pipeline (NWP),only by Gas Transmission
Northwest (GTN)and by both pipelines.The Medford service territory is also disaggregated into an area
that can only be served by NWP and GTN.
Avista’s approach to demand forecasting focuses on customer growth and use-per-customer as the base
components of demand.We recognize and have accounted for weather as the most significant direct
demand-influencing factor.We also study other factors that influence demand,including population,
1.2 II CHAPTER 1 II EXECUTIVE SUMMARY
employment trends,age and income demographics,construction trends,conservation technology,new
uses development (e.g.natural gas vehicles)and use-per-customer trends.
Recognizing that customers adjust consumption in response to price,we also analyzed factors that could
influence natural gas prices and demand through price elasticity.These included:
II Supply Trends —Shale gas,Canadian supply availability,and export LNG
Ii Infrastructure Trends —regional pipeline projects,national pipeline projects,and storage
II Regulatory Trends —subsidies,market transparency/speculation,and carbon legislation
II Other Trends —thermal generation,and energy correlations (i.e.oi]Igas,coallgas,liquids/gas)
We developed a historical-based reference case and conducted sensitivity analysis on key demand drivers
by varying assumptions to understand how demand changes.Using this information and incorporating
input from the TAC,we formed several alternate demand scenarios for detailed analysis.Table 1.1
summarizes these scenarios,which do not represent the maximum bounds of possible cases,but frame a
range of potential outcomes.Within this range,we define an Average Case,which represents our demand
forecast for normal planning purposes.Then we define an Expected Case,which we view as the most
likely scenario for peak day planning purposes.
Table 1.1
Demand Scenarios
Average Case
Expected Case
High Growth,Low Price
Low Growth,High Price
Alternate Weather Standard
The IRP process defines the methodology and is the basis for the development of two primary types of
demand forecasts —annual average daily and peak day.First is an evaluation of annual average daily
demand forecasts which are useful for preparing revenue budgets,developing natural gas procurement
plans and preparing purchased gas adjustment filings.Peak day demand forecasts are critical for
determining the adequacy of existing resources or the timing for new resource acquisitions to meet our
customers’natural gas needs in extreme weather conditions.The demand forecasts from the Average and
Expected Cases revealed the following:
ANNUAL AVERAGE DAILY DEMAND —Average day,system-wide core demand is projected to
increase from an average of 96,160 dekatherms per day (Dthlday)in 2012 to 117,660
Dthlday in 2031.This is an annual average growth rate of 1.1 percent and is net of
projected conservation savings from DSM programs.1
PEAK DAY DEMAND —Coincidental peak day,system-wide core demand is projected to
increase from a peak of 365,720 Dthlday in 2013 to 474,670 Dthlday in 2031.Forecasted
non-coincidental peak day demand peaks at 341,850 Dth!day in 2012 and increases to
Appendix 3.9 shows gross demand,DSM savings and net demand.
2O12AVISTANATURALGASIRP II 1.3
440,630 Dthlday in 2031,a 1.3 percent compounded growth rate in peak day
requirements.This is also net of projected conservation savings from DSM programs.
Figure 1.1 shows forecasted average daily demand for the five main demand scenarios modeled over the
planning horizon.
Figure 1.1 Average Daily Demand 2012 IRP Demand Scenarios
Mdth/d (Net of DSM Savings)
160 ——-—————--________________
____________
140 --—---
______
i.O 1çC p1 i -5i’o-’.,.o’
—Average Case -Mix —Expected Case -Coldest on Record -Mix
—Coldest in 20 years -Mix -High Growth &Low Prices -Mix
—LowGrowth &High Prices-Mix
Figure 1.2 shows forecasted system-wide peak day demand for the five main demand scenarios modeled
over the planning horizon.
1.4 II CHAPTER 1 II EXECUTIVE SUMMARY
Figure 1.2 Peak Day (Feb 15)2012 IRP Demand Scenarios
(Net of OSM Savings)
Mdth/d
600
500 --
:::zZ
200
100 --————-—--———
————-.----—---——.--.--.—..—.--—-.-..-—.--.-—--.-—--..—
-0ø -l.O -O iO1 2O1 70D 2o2 c?-2Ø2 2.o2 2o Lo2 20
—Average Case -Mix —Expected Case -Coldest on Record -Mix
—Coldest in 20 years -Mix —High Growth &Low Prices -Mix
—LowGrowth &High Prices-Mix
NATURAL GAS PRICE FORECASTS
Natural gas prices are a fundamental component of integrated resource planning because the cormnodity
price is a significant component of the total cost of a resource option.This affects the avoided cost
threshold for determining cost-effectiveness of conservation measures.The price of natural gas also
influences the consumption of natural gas by customers.A price elasticity adjustment to use per customer
is modeled to reflect customer response to changing natural gas prices.
At the end of our last planning cycle the impacts of shale gas on market prices were just beginning to be
realized.Forecasters anticipated that this resource could have a significant impact on lowering prices over
the long term.However,a faster recovery of customer growth,aggressive carbon legislation in the near
term,and sizeable coal switching creating significant gas-fired demand were also anticipated.These
factors produced price forecasts,while lower than previous forecasts,higher than current trends.Now
more information is known about the costs and volumes produced by shale gas and there appears to be
consensus that production costs will continue to stay low for quite some time.
Although we do not believe we can accurately predict future prices for the 20-year horizon of this IRP,
we have reviewed several price forecasts from credible sources and have selected high,medium and low
price forecasts to represent a reasonable range of pricing possibilities for our analysis.The range of prices
provides necessary variation for addressing uncertainty of future prices.Figure 1.3 depicts the price
forecasts used in our IRP.
2O12AVISTANATURALGASIRP II 1.5
Figure 1.3 —Henry Hub Price Forecasts for IRP
Low/Medium/High Forecasted Price
(ReaI$per 0th)
$/Dth
12
—NPCC Low —-NPCC High —Consultl Blend
10 -
8
2
Blend -NYMEX weighted 50%,40%,30%,20%,10%
-
2o ,o 2O ,,0 7.0 2O ‘2.O o’2 7,o2 2o2 7.o2 2o2’2026 2021 .,_o2 ,o2 20 o35 2o’
Long run statistical analysis shows a consumption response to changes in price.In order to model a
consumption response to these price curves,we utilized an expected elasticity response factor,which was
applied under various scenarios.We will monitor this assumption over the IRP cycle and make any
necessary adjustments.
EXISTING AND POTENTIAL RESOURCES
Avista has a diversified portfolio of natural gas supply resources,including contracts to purchase natural
gas from several supply basins;owned and contracted storage providing flexibility of supply sources;and
firm capacity rights on six pipelines diversifies delivery of supply to our service territory city gates.For
potential resource additions,we also consider incremental pipeline transportation,storage options,
distribution enhancements and various forms of liquefied natural gas storage or service.
In our IRP process,we model aggregated conservation potential that reduce demand if they are cost-
effective over the planning horizon.Based on the projected natural gas prices and the estimated cost of
alternative supply resources,our computer planning model (SENDOUT®)selects conservation savings
for further review and implementation.Utilizing IR.P selected savings as a starting point the operational
business planning process ultimately determines the DSM programs cost-effectiveness.Given current
avoided costs,programs in Washington and Idaho have proven to be cost ineffective and filings were
made to suspend programs in Washington and Idaho.In Oregon we are able to offer limited programs on
a cost-effective basis.We actively promote these measures to our customers as one component of a
comprehensive strategy to arrive at mix of best cost/risk adjusted resources.
1.6 II CHAPTER 1 II EXECUTIVE SUMMARY
RESOURCE NEEDS
In our Average Case demand scenario matched with our existing supply resources scenario,we
determined we are not resource deficient in the 20 year planning horizon.Using our Expected Case
demand scenario,matched with our existing resources supply scenario,we assessed when the first year
peak day demand is not fully served.The results of this portfolio are summarized in Figure 1.4.
In Washington and Idaho,this system first becomes unserved in 2030 in the Expected Case.In Oregon,
the first unserved year is in MedfordlRoseburg in 2029 and 2030 in Kiamath Falls.The La Grande system
does not go unserved at any time during the 20-year planning horizon.
Figures 1.5 through 1.8 illustrate when our peak day demand first goes unserved by service territory for
both this IRP and our prior IRP.These charts compare existing peak day resources to expected peak day
demand by year and show timing and extent of resource deficiencies for the Expected Case.Given this
information,it appears we have ample time to carefully monitor,plan and take action on potential
resource additions.
Figure 1.4 -First-Year Peak Demand Not Met with Existing Resources
Expected Case
2012
WAIID Med[ordlRoseburg Kiamath La Grande
F—--------I
2013
2014
.2015
____
2018 -—
________
E 2019 -—-
2020>-
2021
2022
2023 --—.-
2024
2025 -
2026
2027
2028
-—--——-1
2029
IE
I.----—--I JZZZ
F
_____
2030-—---------—_...
2031 --——---—---—-——---.——___________________
I
2O12AVISTANATURALGASIRP II 1.7
Prior Current
Short Short
--
Figure 1.5 -Expected Case -WMD Existing Resources vs.Peak Day Demand
(Net of DSM)
FEB 15
Prior Short Ciirrnt chnrt
0th
400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
0
Existing GTN Existing NWP Spokane Supply ——Peak Day Demand Prior IRP Peak Day Demand
Figure 1.6 -Expected Case -Medford/Roseburg Existing Resources vs.Peak Day Demand
(Net of DSM)
DEC200th
120,000
100,000
80,000 --
60,000
40,000
20,000
.
0
a)c
Existing NWP Existing GTN —--Peak Day Demand Prior IRP Peak Day Demand
1.8 II CHAPTER1 II EXECUTIVESUMMARY
Dth
Figure 1.7 -Expected Case -Kiamath Falls Existing Resources vs.Peak Day Demand
(Net of DSM)
22,000
20,000
18,000
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
Dth
10,000
9,000
8,000
7,000
6,000
5,000
4,000
3,000
2,000
1,000
0
DEC20
Klamath Lateral Existing GTN —.—Peak Day Demand Prior IRP Peak Day Demand
Current
Prior Short Short
I —
‘EEE’E
,,‘1 ‘‘‘.,,‘l-‘1 ‘‘‘‘-1’‘1 ‘‘‘‘‘.,‘,,,,‘,‘1
Figure 1.8 -Expected Case -La Grande Existing Resources vs.Peak Day Demand
(Net 0fDSM)
FEB 15
‘‘‘‘‘I
Existing NWP —.—Peak Day Demand ——PdorlRP Peak Day Demand
2O12AVISTANATURALGASIRP II 1.9
A critical risk with respect to our identified resource shortages is the slope of forecasted demand growth,
which is almost fiat.This outlook implies that existing resources will be sufficient for quite some time to
meet demand.However,if demand growth accelerates,the steeper demand curve could quickly accelerate
resource shortages by several years.Figure 1.9 concepmally illustrates this risk.In this hypothetical
example,a resource shortage does not occur until year eight in the initial demand case.However,the
shortage dramatically accelerates by five years under the revised demand case to year three.This “flat
demand risk”necessitates close monitoring of accelerating demand as well as careful evaluation of lead
times to acquire the preferred incremental resource.
RESOURCE SELECTIONS
The next step is to determine how to resolve resource deficiencies.For this step,we identified possible
resource options,placed them into the SENDOUT®model and allowed it to select the best costlrisk
incremental resources over the 20-year planning horizon.Figures 1.10 through 1.12 depict the best
cost/risk portfolio selected by SENDOUT®to meet the identified resource shortages.As previously
mentioned,the La Grande service territory does not have resource shortages over our planning horizon in
the Expected Case.
Figure 1.9 Flat Demand Risk Example
Demand
8 -____
____
7
Years 1 2 3 4 5 6 7 8 9 10
Resources —*—Initial Demand —*—Revised Demand
1.10 II CHAPTER1 II EXECUTIVESUMMARY
Dth
400,000
350,000
300,000 --
250,000 --
200,000
150,000 --
100,000 --
50,000
0
Figure 1.10 -Expected Case -WA/ID Selected Resources vs.Peak Day Demand
(Net of DSM)
FEB15
Current Short
,,),
Existing GTN Existing NWP Spokane Supply GTN Ca pacityAdd ——Peak Day Demand
Figure 1.11-Expected Case -Medford/Roseburg Selected Resources vs.Peak Day Demand
0th
120,000
(Net of DSM)
DEC20
Current
Short
0
“r ‘‘(,(A
100,000
80,000
60,000
40,000
20,000
GTN Capacity Add Existing NWP Existing GTN —.—Peak Day Demand
2O12AVISTANATURALGASIRP II 1.11
Current ShortI............4p•T
J Kia math Lateral Existing GTN GTN Capacity Add —.—Peak Day Demand
As indicated in the figures,after DSM savings,the model shows a general preference for incremental
transportation resources from existing pipelines and supply basins to resolve resource shortages.
ALTERNATE DEMAND SCENARIOS
We performed the same SENDOUT®process for three other demand scenarios,which identified first year
unserved dates for each scenario by service territory (Figure 1.13).As expected,the High Growth,Low
Price scenario has the most rapid growth and the earliest first year unserved dated.This “steeper”demand
lessens the “flat demand risk”discussed above,but the earlier unserved dates warrant close monitoring of
demand trends and resource lead times.
Figure 1.12 -Expected Case -Klamath Falls Selected Resources vs.Peak Day Demand
(Net of DSM)
DEC20
Dth
22,000
20,000
18,000
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
112 II CHAPTER1 II EXECUTIVESUMMARY
II ISSUES AND CHALLENGES
Although we are satisfied with the planning,analysis and conclusions reached in this IRP,we recognize
wide spread uncertainty exists requiring diligent monitoring of the following issues and challenges:
CONTINUED ECONOMIC UNCERTAINTY
Whether it is through plummeting home prices,empty retail spaces,unemployment,or lack of consumer
spending,evidence of the struggling economy was seen and felt throughout our service territory and
region.Growth across our service territory has been paltry at best and use-per-customer has continued to
decrease.As the country continues to work through the repercussions of the recession,low to moderate
growth is anticipated in our region for many years to come.
With uncertainty about the timing and magnitude of economic recovery,it is prudent to evaluate
alternative growth scenarios.We sought to capture the variability of recovery through a wide range of
scenarios in our modeling and analysis.Monitoring will be required to see how events unfold and if there
are outcomes we did not consider,requiring adjustment of our analysis and Action Plan.
FIVE DOLLAR GAS FOREVER?
The reality of shale gas has changed the face of North American supply.The abundance of shale along
with lagging demand has created a near term supply glut driving prices to lows not seen in the last decade.
Shale production over the last few years has grown to 25%of total North American production.The
unexpected amounts of gas extracted from shale wells,drilling induced by held-by-production (HBP)
clauses in leases,increasing drilling efficiencies,and the tie in of previously drilled wells caused a
Figure 1.13-First Year Peak Demand Not Met with Existing Resources
Scenario Comparisons
WA/ID Medford/Roseburg Kiamath La Grande
2012
2013
2014
2015
2016
2017
2018
E 2019
,2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
•Expected Case U High Growth &Low Prices
•Low Growth &High Prices fl Cold Day 2Oyr
•Average Case
2012 AvI5TA NATURAL GAS IRP II 1.13
significant increase in production.The excess production was able to be absorbed by the market due to a
couple of colder than normal winters and hotter than normal summers.This year’s warmer than normal
winter highlighted the oversupply sending prices into a freefall.Forecasters anticipate prices to rebound
from current lows;with forecasted prices averaging $5.50 per dekatherm at Hemy Hub over the planning
horizon.
For our customers we hope that the forecaster’s expectations come to fruition,but we are mindful of past
experiences and understand that markets can change quickly and dramatically.To address this
uncertainty,our plan includes high and low price scenarios along with stochastic price analysis to capture
a range of possible pricing outcomes.
EXPORTING LNG
A few short years ago importing LNG was the answer to meet North America’s growing gas demand
needs.Enter shale gas.Now the availability of plentiful amounts of natural gas in North America has
changed LNG dynamics.Import LNG facilities are now switching gears and looking to export low cost
North American gas to the higher priced Asian and European markets.One export terminal has been
approved on the coast of British Columbia and another in the Gulf of Mexico.Many more applications to
export are sitting at FERC for review and the same is true in Canada.In the Northwest,there are two
proposed terminals in Oregon.How many of these terminals actually get approval is yet to be determined.
However,exporting has the potential to alter the price and flows of natural gas across all regions in North
America.
NATURAL GAS VEHICLES (NGV)
High oil prices have heightened the desire to reduce reliance on foreign oil.Aided by efforts to reduce
emissions and the low cost ofnatural gas interest in natural gas vehicles has once again been rekindled.
The transportation sector is the nation’s largest consumer of foreign oil therefore changing the nation’s
vehicle fleet will be essential in achieving this goal.
Historically,NGV market penetration of a meaningful size has been challenging due to the lack of
infrastructure and prices higher than competing alternatives.Now,lower anticipated long term natural
gas prices have improved the economics and investments are being made to build out the infrastructure.
Most forecasters believe the largest market will be long haul trucking followed by repetitive route fleets
(e.g.public transportation,school busses,and refuse trucks)and that widespread adoptionlconversion will
not be immediate.
Analysis and evaluation of Avista’s role in the NGV initiative is underway.Future IRP’s will contain the
results of this analysis and include our assessment of the potential demand and our level of participation
in this market segment.For this IRP we have included in our High Growth scenario additional demand
from the NGV market.
II ACTION PLAN
Our 2013-2014 Action Plan outlines activities identified by our IRP team,with advice from management
and TAC members,for development and inclusion in this IRP.The purpose of these action items is to
position Avista to provide the best costlrisk resource portfolio and to support and improve IRP planning.
The Action Plan identifies needed supply and demand side resources and also highlights key analysis that
needs to be completed in the near term.It also highlights essential ongoing planning initiatives and gas
industry trends Avista will be monitoring as a part of its routine planning processes.
1.14 II CHAPTER1 II EXECUTIVESUMMARY
The analysis indicates there is no near term needs to acquire additional supply side resources to meet
customer demand.However,Avista will perform its gate station analysis to assess if individual gate
station deficiencies exist and discuss findings and potential solutions with Commission Staff.We will
continue to coordinate the analytic efforts between Gas Supply,Gas Engineering and the interstate
pipelines to conduct this analysis and if deficiencies are identified seek least-cost solutions.
Avista also believes in the pursuit of cost-effective demand-side solutions,but recognizes the challenges
ofthe current low cost environment.IRP modeling versus operational business planning are different.
Within the IRP,Washington and Idaho conservation measures are targeted to reduce demand by
approximately 120,000 dekatherms in the first year (2013).In Oregon,conservation measures are targeted
to reduce demand by approximately 24,600 dekatherms in the first year.When these aggregated savings
and resultant avoided costs were incorporated into the business planning process,natural gas
programmatic DSM was cost-ineffective.This resulted in Avista filing to suspend natural gas DSM
programs in Washington and Idaho.An evaluation of Oregon program offerings is currently under
evaluation.
We will monitor natural gas prices a signpost for increasing avoided costs.Should avoided costs increase
we will evaluate our demand side programs for cost-effectiveness and be proactive in submitting to
resume our natural gas demand side management options.
Key ongoing components of the Action Plan include:
II Monitor actual demand for indications of growth exceeding our forecast to respond aggressively
to address potential accelerated resource deficiencies arising from exposure to “flat demand”
risk.This will include providing Commission Staff with IRP demand forecast-to-actual variance
analysis on customer growth and use per customer.This information will be provided in Avista’s
updates to each Commission Staff at least bi-annually.
ii Pursue the possibility of a regional elasticity study through the Northwest Gas Association or
possibly the American Gas Association.
ii Assess potential demand impact from NGV/CNG vehicles and other new uses of natural gas to
Avista.
ii Continue to monitor supply resource trends including the availability and price of natural gas to
the region,exporting LNG,Canadian natural gas supply availability and interprovincial
consumption,as well as pipeline and storage infrastructure availability.
ii Monitor availability of current resource options and assess new resource lead time requirements
relative to when resources are needed to preserve flexibility.
II Regularly meet with Commission Staff members to provide information on market activities and
significant changes in assumptions andlor status of Avista activities related to the IRP or natural
gas procurement practices.
II CONCLUSION
Continued slow growth and the declining use-per-customer resulted in lower demand when compared to
our last IRP.Current IRP analysis indicates no near-term need for the acquisition of additional supply
side resources.While Avista believes adoption of conservation is the best strategy for minimizing costs to
our customers and promoting a cleaner environment,current and forecasted low prices challenge the cost
effectiveness of demand side measures at the program level.The IRP process has many objectives,but
2O12AVISTANATURALGA5RP II 1.15
foremost,is to ensure that proper planning will enable us to continue delivering safe,reliable and
economic natural gas service to our customers well into the future.We are confident this plan delivers on
that objective.
2012 AVISTA NATURAL GAS IRP
CHAPTER 2 II INTRODUCTION
OUR COMPANY
Avista is involved in the production,transmission and distribution of energy as well as other energy-
related businesses.Avista was founded in 1889 as Washington Water Power and has been providing
reliable,efficient and competitively priced energy to customers for over 120 years.
Avista entered the natural gas business with the purchase of Spokane Natural Gas Company in 1958.In
1970 it expanded into natural gas storage with Washington Natural Gas (now Puget Sound Energy)and
El Paso Natural Gas (its interest subsequently purchased by Williams-Northwest Pipeline (NWP))to
develop the Jackson Prairie natural gas underground storage facility in Chehalis,Wash.In 1991 we added
63,000 customers with the acquisition of CP National Corporation’s Oregon and California properties.
Avista subsequently sold the California properties and its 18,000 South Lake Tahoe customers to
Southwest Gas in 2005.Avista currently provides natural gas service to approximately 318,000 customers
in eastern Washington,northern Idaho and several communities in northeast and southwest Oregon.
SERVICE TERRITORIES AND NUMBER OF CUSTOMERS
r
Total Natural Gas Customers
as of Dec.31,2011
318,300
148,100
74,800 95,400
Washington Idaho Oregon Total
Avista manages its natural gas operation through two operating divisions —North and South:
II The North Division covers about 26,000 square miles,primarily in eastern Washington and
northern Idaho.Over 840,000 people live in Avista’s Washingtonlldaho service area.It includes
urban areas,farms,timberlands and the Coeur d’Alene mining district.Spokane is the largest
metropolitan area with a regional population of approximately 450,000 followed by the Lewiston,
Idaho/Clarkston,Wash.and Coeur d’Alene,Idaho.The North Division has about 74 miles of
natural gas distribution mains and 5,000 miles of distribution lines.Natural gas is received at
more than 40 points along interstate pipelines and distributed to over 222,000 customers.
II The South Division serves four counties in southwest Oregon and one county in northeast
Oregon.The combined population of these two areas is over 480,000 residents.The South
Avista Service Territory
—-DNoo,i
:fl dA)n.
.a
2.2 II CHAPTER 2 II INTRODUCTION
Division includes urban areas,farms and timberlands.The Medford,Ashland and Grants Pass
areas,located in Jackson and Josephine Counties,is the largest single area served by Avista in
this division,with a regional population of approximately 280,000 residents.The South Division
consists of about 67 miles of natural gas distribution mains and 2,000 miles of distribution lines.
Natural gas is received at more than 20 points along interstate pipelines and distributed to almost
96,000 residential,commercial and industrial customers.
OUR CUSTOMERS
We provide natural gas services to two customer classifications —“core”and “transportation only.”Core
or retail customers purchase natural gas directly from us with delivery to their home or business under a
bundled rate.Those core customers on firm rate schedules are entitled to receive whatever volume of gas
is needed.There are some core customers who are on interruptible rate schedules.These customers pay a
lesser rate than firm customers since their service can be interrupted.These interruptible customers are
not considered in our peak day IRP planning.
Transportation-only customers purchase natural gas from third parties who deliver their gas to our
distribution system.We then deliver this gas to their business charging a distribution rate only.This
delivery service can be interrupted by Avista following our priority of service tariff.Since our
transportation-only customers purchase their own gas and utilize their own interstate pipeline
transportation contracts they are excluded from this long-term resource planning exercise.
Our core or retail customers are further divided into three categories —residential,commercial and
industrial.Most of our customers are residential,followed by commercial.Relatively few are industrial
accounts (Figure 2.1).
The mix is more balanced between residential and commercial accounts on an annual volume basis
(Figure 2.2).Volume consumed by core industrial customers is not significant to the total,partly because
most industrial customers in our service territories are transportation only customers.
Figure 2.1 Firm Customer Mix
Washington and Idaho Oregon
•Residential •Commercial Industrial •Residential I Commercial Industrial
2O12AVISTANATURALGASIRP II 2.3
Core customer demand is seasonal,especially by our residential accounts in our service territories with
colder winters (Figure 2.3).Industrial demand,which is typically not weather sensitive,has very little
seasonality.However,our La Grande service territory has several agricultural processing facilities,
classified as industrial,that produce a late summer season al demand spike.
Washington and Idaho
Figure 2.2 Therms by Class
•Residential •Commercial Industrial I Residential I Commercial Industrial
3,000,000
2,000,000
1,500,000
1,000,000
500,000
0
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
120,000
100,000
Roseburg
Figure 2.3 Customer Demand by Service Territory
(Dekatherms)
Washington/Idaho Medford
450,000
400,0002,500,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
180,000
160,000
140,000
120,000
100,000
80,000
60,000
40,000
20,000
l.a Grande
80,000 -
60,000
40,000 -
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Klamath Falls
20,000
0 -
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec -I
Jan Peb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
100,000
90,000
80,000
70,000
60,000
50,000
40,000
30.000
20,000
10,000
Jan Feb Mar Apr May Jun Jul Aug Sep Oct •Nov •Dec
Resldential Commerciul Industrial
2.4 II CHAPTER 2 II INTRODUCTION
INTEGRATED RESOURCE PLANNING
In order to ensure that our core fu-m customers are provided with long-term reliable natural gas service at
a competitive price,we undertake a comprehensive analytical process through the IRP.We evaluate,
identify and plan for the acquisition of the best-risk,least-cost portfolio ofexisting and future resources to
meet average daily and peak-day demand delivery requirements over a 20-year planning horizon.
PURPOSE OF THE IRP
This document has several objectives:
II Provides a comprehensive long-range planning tool
II Fully integrates forecasted requirements with existing and potential resources
II Determines the most cost-effective,risk-adjusted means for meeting demand requirements
II Responds to Washington,Idaho and Oregon rules and orders
AVISTA’S IRP PROCESS
The IRP process considers:
II Customer growth and usage
U Weather planning standard
II DSM opportunities
II Existing and potential supply-side resource options
II Current and potential legislationlregulation
II Risk
PUBLIC PARTICIPATION
Members of Avista’s TAC play a key role and have a significant impact in development of the IRP.TAC
members include Commission Staff,peer utilities,public interest groups,customers,academics,
government agencies and other interested parties.A list of TAC members is in Appendix 1.1 TAC
members provide important input on modeling,planning assumptions and the general direction of the
process.
Avista sponsored four TAC meetings to facilitate stakeholder involvement in the 2012 IRP.The first
meeting convened on Jan.17,2012 and the last meeting was held on April 17,2012.A broad spectrum of
stakeholders was represented at each meeting.The meetings focused on specific planning topics,
reviewed the status and progress of planning activities and solicited input on the IRP development.A
draft of this IRP was provided to TAC members on May 25,2012.We gained valuable input from the
interaction and communication with TAC members and express our sincere thanks and appreciation for
their contributions and participation.
Preparation of the IRP is a coordinated endeavor by several departments within Avista with involvement
and guidance from management.We are grateful for these efforts and contributions.
2O12AVISTANATURALGASIRP II 2.5
REGULATORY REQUIREMENTS
Avista submits an IRP to the public utility conimissions in Washington,Idaho and Oregon every two
years as required by state regulation.’We will file our IRP with all three Commissions on or before Aug.
31,2012.We have a statutory obligation to provide reliable natural gas service to customers at rates,
terms and conditions that are fair,just,reasonable and sufficient.We regard the IRP as a means for
identifying and evaluating potential resource options and as a process to establish an Action Plan for
resource decisions.Ongoing investigation,analysis and research may cause us to determine that
alternative resources are more cost effective than resources selected in this IRP.We will continue to
review and refine our understanding of resource options and will act to secure these risk-adjusted,least-
cost options when appropriate.
PLANNING MODEL
Consistent with prior IRPs is the use of SENDOUT®,the computer planning model we use to perform
comprehensive and effective natural gas supply planning and analysis.SENDOUT®is a linear
programming-based model that is widely used in the industry to solve natural gas supply,storage and
transportation optimization problems.This model uses present value revenue requirement (PVRR)
methodology to perform least-cost optimization based on daily,monthly,seasonal and annual
assumptions related to:
II Customer growth and customer natural gas usage to form demand forecasts
II Existing and potential transportation and storage options
II Existing and potential natural gas supply availability and pricing
II Revenue requirements on all new asset additions
II Weather assumptions
II Demand-side management
We have also incorporated the Monte Carlo simulation module within SENDOUT®to simulate weather
and price uncertainty.The module uses Monte Carlo functionality to generate simulations of weather and
price to provide a probability distribution of results from which decisions can be made.Some examples of
the types of analysis Monte Carlo simulation provides include:
II Price and weather probability distributions
II Probability distributions of costs (i.e.system costs,storage costs,commodity costs)
II Resource mix (optimally sizing a contract or asset level of various and competing resources)
These computer-based planning tools were used to develop our 20-year best cost/risk resource portfolio
plan to serve customers.
1 in Washington the IRP requirements are outlined in WAC 480-90-238 entitled “Integrated Resource Planning.”
in Idaho the IRP requirements are outlined in Case No.GNR-G-93-2,Order No.25342.In Oregon the IRP
requirements are outlined in Order Nos.07-002,07-047 and 08-339.Appendix 2.2 provides details of these
requirements and how they are met.
2.6 II CHAPTER 2 II INTRODUCTION
PLANNING ENVIRONMENT
Although we prepare and publish an IRP biannually,the process is ongoing,taking into account new
information and developments.In “normal”circumstances,the process can become complex as
underlying assumptions evolve and impact previously completed analyses.Every planning cycle has
challenges and uncertainties;this cycle was no different.The demand for natural gas has undergone
extraordinary changes due to recessionary impacts.Residential,commercial and industrial demand has
flattened.Renewable portfolio standards and the announcement of coal plant retirements have increased
the need for future gas-fired generation and natural gas vehicles are once again in vogue.The supply
picture has also undergone a makeover.The “Shale Gale”—in its infancy during the last planning cycle —
has since grown up.While there continues to be questions about how vast the resource base is,its
environmental impacts and how much can continue to be produced at these pricing levels,it has proved to
be a “game changer.”
II IRP PLANNING STRATEGY
Planning for an uncertain future requires robust analysis that encompasses a wide range of possibilities.
We have determined our approach needs to:
ii Recognize historical trends may be fundamentally altered
II Critically review all assumptions
II Stress test assumptions via sensitivity analysis
ii Pursue a spectrum of possible scenarios
ii Develop a flexible analytical framework to accommodate changes
II Maintain a long-term perspective
With these objectives in mind we believe we have developed a strong strategy encompassing all required
planning criteria that allowed us to produce a complete IRP that effectively analyzes risks and resource
options,which sufficiently ensure our customers will receive safe and reliable energy delivery services
well into the future with the best-risk,lease-cost,long-term solutions.
2012 AvI5TA NATURAL GAS IRP
CHAPTER 3 II DEMAND FORECASTS
OVERVIEW
The integrated resource planning process begins with the development of forecasted demand.
Understanding and analyzing key demand drivers and their potential impact on our forecasts is vital to the
planning process.Utilization ofhistorical data provides a reliable baseline,however it is important to
remember that past trends may not be indicative of future trends.The permanent long term effects of the
recession will not be fully realized for many years.This uncertainty leads us to consider a range of
scenarios to evaluate and prepare for a broad spectrum of outcomes.
DEMAND AREAS
Eight demand areas,structured around the pipeline transportation resources that serve them,were defined
with the SENDOUT®computer model (Table 3.1).These demand areas are aggregated into four service
territories and further summarized into two divisions for presentation throughout this IRP.
Table 3.1 Geographic Demand Classifications
Demand Service
Area Territory Division
Spokane NWP Washington/Idaho North
Spokane GTN Washington/Idaho North
Spokane Both Washington/Idaho North
Medford NWP Medford/Roseburg South
Medford GTN Medford/Ros eburg South
Roseburg Medford/Roseburg South
Kiamath Falls Kiamath Falls South
La Grande L.a Grande South
DEMAND FORECAST METHODOI.OGY
Avista uses the IRP process to develop two types of demand forecasts —“annual”and “peak day.”Annual
average demand forecasts are useful for several purposes,including preparing revenue budgets,
developing natural gas procurement plans and preparing purchased gas adjustment filings.Peak day
demand forecasts are critical for determining the adequacy of existing resources or the timing for
acquiring new resources to meet our customers’natural gas needs in extreme weather conditions
throughout the planning period.
In general,if existing resources are sufficient to meet peak day demand,they will be sufficient to meet
annual average day demand.Developing annual average demand first and evaluating it against existing
resources is an important step in understanding the performance of the portfolio under normal
circumstances.It also facilitates synchronization of modeling processes and assumptions for all planning
purposes.
3.2 II CHAPTER3 II DEMANDFORECASTS
Peak weather analysis aids in assessing not only resource adequacy but differences,if any,in resource
utilization.For example,storage may be dispatched differently under peak weather scenarios.
DEMAND MODELING EQUATION
Because natural gas demand can vary widely from day to day,especially in winter months when heating
demand is at its highest,developing daily demand forecasts is essential.In its most basic form,demand is
a function of customer base usage (non-weather sensitive usage)plus customer weather sensitive usage.
This can be expressed by the following general formula:
Table 3.2 Basic Demand Formula
#of customers x Daily base usage I customer
Plus
#of customers x Daily weather sensitive usage /customer
More specifically,SENDOUT®requires inputs as expressed in the below format to compute daily
demand in dekatherms (Dth):
Table 3.3 SENDOUT®Demand Formula
#of customers x Daily Dth base usage I customer
Plus
#of customers x Daily Dth weather sensitive usage I customer x #of daiy degree days
This calculation is performed by SENDOUT®for each day for each customer class and each demand
area.The base and weather sensitive usage (heating degree day usage)factors are customer demand
coefficients developed outside the SENDOUT®model and capture a variety of demand usage
assumptions.This is discussed in more detail in the Use-per-Customer Forecast section below.The
number of daily degree days is simply heating degree days (HDDs),which are further discussed in the
Weather Forecast section later in this chapter.
CUSTOMER FORECASTS
Avista’s customer base is segregated into three categories:residential,commercial and industrial.For
each of the customer categories we develop our customer forecasts by starting with national economic
forecasts and then drilling down into regional economies.Population growth expectations and
employment are key drivers in regional economic forecasts and are useful in estimating natural gas
customers.We contract with Global Insight,Inc.for long-term regional economic forecasts.A description
of the Global Insight forecasts is found in our customer forecasts detail in Appendix 3.1.We combine this
data with local knowledge about sub-regional construction activity,age and other demographic trends and
historical data to develop our 20-year customer forecasts.
The annual growth for each state is allocated so that the total equals the sum of the parts.These forecasts
are used by the distribution engineering group for optimizing decisions within these geographic sub-areas
2O12AVISTANATURALGASIRP II 3.3
and facilitating integrated forecasting and planning within Avista (see further discussion in Chapter 8 —
Distribution Planning).
Forecasting customer growth is an inexact science so it is important to consider alternative forecasts.Two
alternative growth forecasts were developed for consideration in this IRP.In past IRPs we have used 25
years of historical growth rates to derive our low and high growth sensitivities.This historical look back
gave us growth assumptions of 50%greater than expected and 50%lower than expected for our high and
low growth sensitivities.Utilizing historical data provided some comfort with the reasonableness of these
growth forecasts.
However,recent events have impacted our economy and there is much uncertainty about when and how
much recovery will occur.The past may not be indicative of future behaviors.Growth experienced in the
last couple of years is low.In examining recent trends and comparing to history the range of growth
seems asymmetric.To this end we utilized forecasted information from the Washington State Office of
Financial Management (OFM)to prepare the high and low growth sensitivities.The OFM forecasts the
potential for growth rates 40%below and 60%above current growth rates.These three customer growth
forecasts are shown in Figure 3.1.Detailed customer count data by region and class for all three scenarios
is in Appendix.3.2.
USE-PER-CUSTOMER FORECAST
The goal for a use-per-customer forecast is to develop base and weather sensitive demand coefficients
that can be combined and applied to HDD weather parameters to reflect average use per customer.This
produces a very reliable forecast because of the high correlation between usage and temperature as
depicted in the example scatter plot in Figure 3.2.
Average Annual
Customers
600,000
Figure 3.1 Customer Growth Scenarios
Total System
500,000
400,000 -
300,000
-‘
200,000
100,000
0
1 rJ Cfl N 00 01 C ,1 rJ m if,‘.D N 00 C -1 iNiNININININ(N (N IN IN IN m cfl enCCCCCC000C00CCC0C0CCCCIN(N (N (N (N (N (N IN IN IN IN (N IN IN IN IN (N (N IN IN IN IN
Expected Low Growth High Growth
3.4 II CHAPTER3 II DEMANDFORECASTS
The first step in developing demand coefficients was gathering daily historical gas flow data for all of our
city gates.Our preference to use city gate data over revenue data is due to the tight correlation between
weather and demand.Our revenue system does not capture data on a daily basis and therefore,makes a
statistical analysis with tight correlations virtually impossible.We do reconcile city gate flow data to
revenue data to ensure that we are properly capturing total demand.
The historical city gate data was gathered,segregated by service territory/temperature zone and then by
month.In our last IRP we used three years of historical data to derive our use per customer coefficients.
Continuing with our theme of challenging each assumption we looked at varying the number of years of
historical data.We analyzed five years,three years and two years of use per customer.We decided that
two years was not necessarily indicative of future use per customer behavior nor does it incorporate
enough data points to make a comprehensive long term analysis.Five years incorporated some years of
higher use per customer,which may overstate use due to current recessionary impacts and conservation
savings.Three years seemed to strike the right balance between historical and contemporaneous customer
usage patterns.Figure 3.3 illustrates the annual demand differences between the three year and five year
use per customer with normal and peak weather conditions.
Figure 3.2 -Example Demand vs.AverageTemperature
WA/ID Residential 0th
250,000
200,000
150,000
100,000
50,000
0
100 80 60 40 20 0 -20
Farenheit
2O12AVISTANATURALGASiRP II 3.5
To calculate base usage,three years of July and August data was used to derive coefficients.Average
usage in these months divided by average number of customers provides the base usage coefficient input
into SENDOUT®.This calculation is done for each area and customer class based on customer billing
data demand ratios.
To derive weather sensitive demand coefficients,for each monthly data subset,we removed base demand
from the total and plotted usage by HDD in a scatter plot chart to visually verif’correlation.We then
applied linear regression to the data by month to capture the linear relationship of usage to HDD.The
slopes of the resulting lines are the monthly weather sensitive demand coefficients input into
SENDOUT®.Again,this calculation is done by area and by customer class using allocations based on
customer billing data demand ratios.
In extreme weather conditions,demand can sometimes begin to flatten out relative to the linear
relationships at less extreme temperatures.This occurs,for example,when appliances such as furnaces
reach maximum output and do not consume any more natural gas regardless of how much colder
temperatures get.We sought to capture this phenomenon through development of super peak coefficients.
The methodology for deriving super peak coefficients was exactly the same as deriving weather sensitive
demand coefficients except,instead of forming data subsets by month,a dataset was created using
temperature (specifically HDD’s greater than 65).The line slope from the regression on this data was
typically flatter relative to the other monthly weather sensitive demand coefficients.One inherent
drawback to this methodology is the lack of sufficient data points to develop a strong linear relationship.
Mdth/d
50,000 -
Figure 3.3 -Annual Demand -Demand Sensitivities
3-Year Use per Customer vs.5-Year Use per Customer
Total System
5,000
10,000
35,000
30,000 -—----———--—----——-———-—-—--—-..—---------—--
25,000 -•--—---——--———-—--------———----——.-—-—---—-—---——-----.--—---—.--
_____
--—
20,000 -————--——--—--——--—---—--——-----—----—--—--—--—-——--———-——---
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
—Reference Case -3 Yr -Normal Weather
5 Yr -Normal Weather
—3 Yr -Coldest on Record
5 Yr -Coldest on Record
3.6 II CHAPTER3 II DEMAND FORECASTS
More years of data can help,but the older data becomes less and less relevant to current demand
relationships.We will continue to test this theory and monitor trends.
As a final step,to check coefficient reasonableness,we applied the coefficients to actual customer count
and weather data to backcast demand.This was compared to actual demand with satisfactory results.The
regression calculations and coefficients can be found in Appendix 3.3.
WEATHER FORECAST
The last input in the demand modeling equation is weather (specifically HDDs).We obtain the most
current 30 years of daily weather data from the National Oceanic Atmospheric Administration (NOAA),
convert it to HDDs and compute an average for each day to develop our weather forecast.For Oregon we
use four weather stations,corresponding to the areas where natural gas services are provided.HDD
weather patterns between these areas are uncorrelated.For the eastern Washington and northern Idaho
portions of our service area weather data for the Spokane Airport is used,as HDD weather patterns within
that region are correlated.
The NOAA 30-year average weather (adjusted for global warming —see below)serves as the base
weather forecast that is used to prepare the annual average demand forecast.In preparing the peak day
demand forecast we adjust average weather to reflect a five-day cold weather event.This consists of
adjusting the middle day of the five-day cold weather event to the coldest temperature on record for a
service territory,as well as adjusting the two days either side of the coldest day to temperatures slightly
warmer than the coldest day.For our Washingtonlldaho and La Grande service territories,we model this
event on and around February 15 each year.For our southwestern Oregon service territories (Medford,
Roseburg,Klamath Falls)we model this event on and around December 20 each year.
The following describes specific details on the coldest days on record for each service territory:
ii On Dec.30,1968,the Washington/Idaho service area experienced the coldest day on record,
an 82 HDD for Spokane.This is equal to an average daily temperature of-17 degrees
Fahrenheit.Only one 82 HDD has been experienced in the last 40 years for this area;
however,within that same time period,80,79 and 74 HDD events occurred on Dec.29,
1968,Dec.31,1978,and January 5,2004,respectively.
ii On Dec.9,1972,Medford experienced the coldest day on record,a 61 HDD.This is equal to
an average daily temperature of 4 degrees Fahrenheit.Medford has experienced only one 61
HDD in the last 40 years;however,it has also experienced 59 and 58 HDD events on Dec.8,
1972,and Dec.21,1990,respectively.
ii The other three areas in Oregon have similar weather data.For Klamath Falls,a 72 HDD
occurred on Dec.21,1990,in La Grande a 74 IIDD occurred on Dec.23,1983,and a 55
HDD occurred in Roseburg on Dec.22,1990.As with Washington/Idaho and Medford,these
days are used as the peak day weather standard for modeling purposes.
Utilizing a peak planning standard of the coldest temperature on record may seem aggressive given we
are using,in some cases,a temperature experienced only once.Given the potential impacts of an extreme
weather event on our customers’personal safety and property damage to customer appliances and
company infrastructure,we believe it is a prudent planning standard.
2O12AVISTANATURALGASIRP II 3.7
We do analyze an alternate planning standard using the coldest temperature in the last twenty years For
our Washingtonlldaho service area we use a 74 HDD,which is equal to an average daily temperature of -
9 degrees Fahrenheit.In Medford the coldest in twenty year is a 54 HDD,equivalent to a temperature of
11 degrees Fahrenheit.In Roseburg the coldest in twenty year is a 48 HDD,equivalent to a temperature of
17 degrees Fahrenheit.In Klamath Falls the coldest in twenty is a 64 HDD,equivalent to a temperature
of 1 degree Fahrenheit.In La Grande the coldest in twenty years is a 68 HDD,equivalent to a
temperature of -3 degrees Fahrenheit.
These HDDs by area,class and by day entered into SENDOUT®can be found in Appendix 3.4.
GLOBAL WARMING
Consistent with past IRPs,we adjusted the NOAA weather data to incorporate estimates for global
warming in developing our HDD forecasts.This was based on extensive analysis of historical weather
data in each of the areas we serve.Adjustments were applied to daily NOAA normal weather data and
include a phase-in over the first ten years of our planning horizon.The effect of the adjustments,all else
equal,results in declining annual demand over time.Appendix 3.5 summarizes our historical analysis and
adjustment factors.
The analysis identified a gradual warming trend in the historical data;however we were unable to discern
any definitive evidence to support a peak day warming trend.We continue to search but have be
unsuccessful in finding supporting studies or analysis on the topic and,after discussion with our TAC,
determined we would not make warming trend adjustments to our peak day weather events in our HDD
forecast.Therefore,our modeling and analysis with respect to peak day planning is unaffected by global
warming.Additional information on this topic is in Appendix 3.5.
DEVELOPING A REFERENCE CASE
To adjust for uncertainty,we developed a dynamic demand forecasting methodology that is flexible to
changing assumptions.To understand how various alternative assumptions influence forecasted demand
we needed a reference point for comparative analysis.For this we define a reference case demand forecast
(Figure 3.4).We stress that this case is not intended to reflect anything other than a simple assumption
start point.
3.8 II CHAPTER3 II DEMAND FORECASTS
DYNAMIC DEMAND METHODOLOGY
The dynamic demand planning strategy critically examines a wide range of potential outcomes.The
approach developed consists of:
ii Identifying key demand drivers behind natural gas consumption
ii Performing sensitivity analysis on each demand driver
ii Combining demand drivers under various scenarios to develop alternative potential outcomes
for forecasted demand
ii Matching demand scenarios with supply scenarios to identify unserved demand
Figure 3.5 represents our methodology of starting with sensitivities,progressing to scenarios,and
ultimately creating portfolios.
State I Residential I Commerical I Industrial
1.00%
0.40%
0.74%
Figure 3.4-Reference Case Assumptions
1.Customer Annual Average Growth Rates
Washington 1.50%1.60%
Idaho 2.00%1.70%
Oregon 1.70%1.30%
2.Use Per Customer Coefficients
Flat Across All Classes
3-year Average Use per Customer per HDD by Area/Class
3.Weather
30-year Normal -NOAA (1981-2010)
Global Warming Adjustment
4.Elasticity
None
5.Demand Side Management
None
2O12AvIsTANATuRALGA5IRP II 3.9
Supp
SENSITIVITY ANALYSIS
In analyzing demand drivers,we grouped them into two categories based on:
II DEMAND INFLUENCING FACTORS —Factors that directly influence the volume of natural gas
consumed by our core customers
Ii PRICE INFLUENCING FACTORS —Factors that,through price elasticity response,indirectly
influence the volume of natural gas consumed by our core customers
Once factors were identified,we developed sensitivities which we define as focused analysis of a specific
natural gas demand driver and its impact on forecasted demand relative to our Reference Case when the
underlying input assumptions are modified
Sensitivity assumptions reflect incremental adjustments we estimate are not captured in the underlying
Reference Case forecast.We analyzed 14 demand sensitivities to determine the resultant effect relative to
the reference case.Table 3.4 lists these sensitivities.More detailed information about these sensitivities
can be found in Appendix 3.6.
Demand
Portfolios
3.10 II CHAPTER3 II DEMANDFQRECASTS
Table 3.4-Dennd Sensitivities
Figure 3.6 shows the annual demand from each of the sensitivities we modeled.
40,000
35,000
High Price
Low Price
Carbon Adder
Following our testing of the various sensitivities we grouped them into meaningful combinations of
demand drivers to develop demand forecasts representing scenarios.Table 3.5 identifies the scenarios we
developed.Our Average Demand Case is representative of what we would consider for normal planning
purposes,such as corporate budgeting,procurement planning,and PGA!General Rate Cases.The
Scenario Influence Weather Growth Use per Customer Price Curve Carbon Adder LNG Adder DSM CNGINGV Elasticity
Reference Case Direct Normal Expected 3 year Expected No No No No No
Reference Case plus Peak Direct Peak Expected 3 year Expected No No No No NoWeather
High Growth Case Direct Peak High 3 year Expected No No No No No
Low Growth Case Direct Peak Low 3 year Expected No No No No No
Alternate Use per Customer Direct Peak Expected 5 year Expected No No No No No
CNG!NGV Case Direct Peak Expected 3 year Expected No No No Yes No
DSM Direct Normal Expected 3 year Expected No No No No No
Peak plus DSM Direct Peak Expected 3 year Expected No No Yes No No
Alternate Weather Planning Direct Coldest in 20 Expected 3 year Expected No No Yes No NoStandard
Expected Elasticity Indirect Peak Expected 3 year Expected No No No No Yes
Low Price Indirect Peak Expected 3 year Low No No No No No
High Price Indirect Peak Expected 3 year High No No No No No
Carbon Legislation Indirect Peak Expected 3 year Expected Yes No No No No
Exported LNG Indirect Peak Expected 3 year Expected No Yes No No No
Figure 3.6 -2012 Demand Sensitivities
Mdth Annual Demand -Total System
60,000 ---—---—-
-—-——-———---——-—-—-———ReferenceCase
55,000
50,000
45,000
30,000
—Reference plus Coldest on
Record
—Low Growth
—High Growth
—‘Alt.UPC (5 Yr)
—Coldest in 20
CNG-NGV
—DSM -Coldest on Record
DSM -Normal
—Expected Elasticity
25,000
20,000 —------——-—--———----—---
i_O iO 1_07.0 .i.O2 2026 207-s’2o
SCENARIO ANALYSIS
Exported LNG
2O12AVISTANATURALGASIRP II 3.11
Expected Case reflects the demand forecast we believe is most likely given peak weather conditions.The
High Growth/Low Price and Low Growth/High Price represent a forecasted range of possibilities for
customer growth and future prices.The Alternate Weather Standard utilizes the coldest day in the last
twenty years.Each of these scenarios helps provide us with sufficient “what if’analysis given the volatile
nature of many key assumptions including weather and price.Appendix 3.6 lists the specific assumptions
within the scenarios while Appendix 3.7 contains a detailed description of each scenario.
Table 3.5
Demand Scenarios
Average Demand
Expected Demand -Peak
High Growth/Low Price
Low Growth/High Price
Alternate Weather Standard
PRICE ELASTICITY
Historic natural gas price volatility has created challenges in projecting future natural gas prices.Now that
shale gas has fundamentally altered the market for natural gas historic analysis may not be indicative of
future behavior.Some believe price volatility will decrease due to the widespread availability of natural
gas while others feel volatility could become greater as shale production profiles are much less
predictable than conventional gas production.We acknowledge changing price levels influence usage so
we incorporate a price elasticity of demand factor into our modeling assumptions to allow use per
customer to vary into the future as our natural gas price forecast changes.
Price elasticity is usually expressed as a numerical factor that defines the relationship of a consumer’s
consumption change in response to price change.Typically,the factor is a negative number as consumers
normally reduce their consumption in response to higher prices or will increase their consumption in
response to lower prices.For example,a price elasticity factor of negative 0.13 means a 10%price
increase will prompt a 1.3%consumption decrease and a 10%price decrease will prompt a 1.3%
consumption increase.
We noted complex relationships influence price elasticity and given the new economic environment,we
question whether current behavior will be considered normal or if customers will return historic usage
patterns.
AGA PRICE ELASTICITY STUDY
From our participation in the 2007 AGA long-run price elasticity study,we received regional elasticity
factors which compared favorably to our past estimates.Based on this corroboration we used a factor of
negative .13 as our expected case factor to adjust use per customer coefficients.
In our last IRP we modeled a high and low price elasticity assumption due to the uncertainty in how our
customers would respond to their evolving economic conditions.Utilizing the high elasticity assumption
resulted in significant curtailment of demand which was much greater than historical experience.
Alternatively low elasticity resulted in no meaningful reduction in demand.Our recent usage data
indicates that even with declines in the retail rate for natural gas,use-per-customer continues to decline.
3.12 II CHAPTER 3 II DEMAND FORECASTS
This is likely driven by a confluence of factors including high unemployment,increased investments in
energy efficiency measures,building code improvements,behavioral changes and overall heightened
focus of consumers’household budgets.
Based on our analysis of data since our 2009 IRP we find that the expected elasticity factor is a
reasonable assumption and have decide to forgo utilizing a high or low elastic response in this IRP.
RESULTS
During 2012,our Average Case demand forecast indicates we will serve an average of 327,300 core
natural gas customers with 33,200,000 dekathenns of natural gas.By 2031,we project 448,100 core
natural gas customers with an annual demand of over 42,200,000 dekatherms.In Washington/Idaho,the
number of customers is projected to increase at an average annual rate of 1.6 percent with demand
growing at a compounded average annual rate of 1.3 percent.In Oregon,the number of customers is
projected to increase at an average annual rate of 1 .7percent,with demand growing 1.3 percent per year.
During 2012 our Expected Case demand forecast indicates we will serve an average of 327,300 core
natural gas customers with 34,700,000 dekatherms of natural gas.By 2031 we project 448,100 core
natural gas customers with an annual demand of over 43,744,000 dekatherms.
Figure 3.7 shows system forecasted demand for the demand scenarios on an average daily basis for each
year’.
Appendix 3.9 shows gross demand,DSM savings,and net demand.
Mdth/d
150
140
130
120
110
100
90
80
__________
—.
2012 AVISTA NATURAL GAS IRP II 3.13
Figure 3.7 Average Daily Demand 2012 IRP Demand Scenarios
(Net of DSM Savings)
—Average Case -Mix
Coldest in 20 years -Mix
—LowGrowth &High Prices-Mix
—‘Expected Case -Coldest on Record -Mix
—--‘High Growth &Low Prices -Mix
Figure 3.8 shows system forecasted demand for the Expected,High and Low Demand cases on a peak
day basis for each year relative to the Average case average daily winter demand.Detailed data for all
demand scenarios is in Appendix 3.8.
70 -----—----——--------—-—------——--
60 --—-----—--—--—-----—-------———-----—------—---—------——-—---———--—-
iO iO iO’%0 i,O 7Ø)0 ‘o i3 ,,,o 2,O’l ...1 Ø ,i9 ,.O
3.14 II CHAPTER 3 II DEMAND FORECASTS
Figure 3.8 -PEAK DAY (FEB 15)2012 IRP Demand Scenarios
Mdth/d (Net of DSM Savings)
600
200
100 -—_____
___________
-—-
__________-
iO iç i.O i.O iO’i.O 7.O-i.S i.O2 cS 1.O’-iO iO
—Average Case -Mix —‘——Expected Case -Coldest on Record -Mix
Coldest in 20 years-Mix —‘High Growth &Low Prices-Mix
—LowGrowth &High Prices-Mix
The purpose of the IRP is to balance forecasted demand with existing and new supply alternatives.Since
new supply sources include conservation resources,which act as a demand reduction,the demand
forecasts prepared and described in this section include existing efficiency standards and normal market
acceptance levels.The methodology for modeling demand side management initiatives is described in
Chapter 4 -Demand-Side Resources.
ALTERNATIVE FORECASTING METHODOLOGIES
There are many forecasting methods available and used throughout different industries..We strive to use
methods that enhance forecast accuracy,facilitate meaningful variance analysis and allow for modeling
flexibility to incorporate differing assumptions.We believe our statistical methodology to be sound and
provide us with a robust range of demand considerations.Our methodology allows for us to vary the
results of our statistical inputs by considering both qualitative and quantitative factors.These factors can
be derived from data or surveys of market information,fundamental forecasters,and industry experts.We
are always open to new methods of forecasting demand and we continually assess which,if any,
alternative methodologies to include in our dynamic demand forecasting methodology.
II ACTION ITEM
Demand forecasting is a critical component,careful evaluation of the current methodology and sufficient
scenario planning is essential.The change in demand over recent years has been dramatic causing a
heightened focus on variance analysis and trend monitoring.Current techniques have provided sound
forecasts with appropriate variance capabilities.In the near term we have identified three key issues to
investigate and monitor.
2012 AVISTA NATURAL GAS IRP II 3.15
PRICE ELASTICITY
Our price elasticity analysis raised several issues.First,we noted the AGA factors were derived from
annual demand data.This was satisfactory for our annual demand forecasting,but this raised a question
whether the factors were applicable to peak demand analysis.We also use the same factors for residential
and conirnercial customer classes even though the AGA factors were derived from residential customer
data only.
We also noted that price signals to core customers are lagged and they are often insulated from volatile
prices due to their exposure to tariff rates versus wholesale prices.
During our planning cycle we realized the effects of the recession and our demand forecast once again is
lower than previous IRPs.Natural gas prices are at lows not seen in the last decade.Prices throughout this
forecast are intended to increase,albeit moderately.The question still remains,how much more can/will
customers curtail?
An action item from our last IRP had us make an inquiry to the AGA for an updated study.The AGA
declined due to budget constraints.For the upcoming IRP cycle,we will consider working with a third-
party,such as the NWGA,to conduct a price elasticity study and assess interest of other utilities in
pursuing a regional study.
FLAT DEMAND RISK
Demand once again has “flattened”when compared to previous IRPs.The flattening of demand is due to
many factors including moderate forecasted customer growth over the 20-year planning horizon
(especially when compared to previous IRP customer forecasts)and declining use per customer due to
behavioral changes driven by challenging economic conditions,increased investments in energy
efficiency measures and enhanced building codes improving the efficiency of homes.The reduced
demand pushes the need for resources out further into the future which is a good thing for customers,as
no new investments in resources will be necessary in the foreseeable future.However,should there be a
significant rebound in demand our resource needs become more imminent.We need continued visibility
into our demand trends in order to identify signposts of accelerated recovery or changing usage behavior.
NATURAL GAS VEHICLE POTENTIAL
Robust availability of natural gas at economic prices has stimulated investments in NGV infrastructure.
How much market penetration occurs nationally and regionally remains uncertain.Analysis and
evaluation of our role in the NGV initiative is underway.We have included a scenario where NOV
demand is served by Avista.
II CONCLUSION
Through our dynamic demand modeling process,we have considered a wide range ofpotential demand
impacts ofboth changing natural gas prices and a changing economy.The result of those considerations is
a reasonable array of outcomes with respect to core consumption of natural gas.While we recognize that
the actual level of demand is dependent on a variety of factors,reviewing a range of potential outcomes
allows us to plan more effectively as economic or pricing conditions change.
2012 AvI5TA NATURAL GAS IRP II
CHAPTER 4 II DEMAND-SIDE RESOURCES
OVERVIEW
Avista has been offering natural gas Demand-Side Management (DSM)to its residential,commercial and
industrial customers since 2001 These programs result in multiple benefits including,but not limited to,
reductions in customers’energy bills,reductions in natural gas supply-side resource needs and reductions in
Green House Gas (GHG)emissions.These benefits make acquiring cost-effective demand-side efficiencies an
appealing resource alternative which Avista believes is the best strategy for minimizing energy service costs to
our customers while promoting a cleaner environment.
in response to the Washington Transportation and Utilities Commission (UTC)staff request of an
independent,external Conservation Potential Assessment (CPA)pursuant to the Company’s next IRP,Avista
issued a Request for Proposal (RFP)for a CPA.Consequently,in preparation for this IRP,Global Energy
Partners,an EnerNOC Company,was selected to conduct a CPA to forecast the 20-year DSM potential for
Avista’s natural gas service territory within Washington,Idaho,and Oregon.The DSM potential that was
generated for Avista’s service territory was then evaluated in SENDOUT®as a resource on par with other
supply-side resources.
The SENDOUT®model understands that investments made in DSM are a long-term resource decision.Within
SENDOUT®the aggregated potential and costs by region and class are tested against supply side resources.
The model also understands that some potential may not be cost-effective in the initial forecast years;however
the total cost over the life of the measure,coupled with the cumulative therms savings,is economic.Due to
this modeling nuance,SENDOUT®typically selects most of the DSM potential.
The changing natural gas supply picture and lower prices have resulted in the decline of natural gas avoided
costs.While this is good news for customers,these lower avoided costs add new challenges to offering a
comprehensive natural gas DSM portfolio.The Company’s 2012 DSM Business Plan forecasted non-cost-
effective natural gas using the avoided costs from the 2009 Natural Gas IRP.A subsequent study done in
February 2012 entitled “Review of Prospects and Strategies for the 2012 Avista Regular Income Natural Gas
DSM Portfolio”projected that,with substantial modifications,the natural gas DSM portfolio could potentially
be marginally cost-effective using a presumed 25 percent reduction in avoided cost.
Avista’s originally anticipated assumption of 25 percent lower natural gas avoided costs was replaced with
current IRP avoided costs which is a decrease of approximately 50 percent.Given these avoided costs,the
Company’s business planning projections indicate that the natural gas DSM portfolio will not be cost-
effective.Evaluation of a number of scenarios to include additional adders for carbon/green house gases,
distribution capacity adders,various allocations and categorizations of non-incentive utility cost,realization
rates and net-to-gross ratios,as well as,evaluating the portfolio on a gross (including all program participants)
rather than net (including only participants who adopted the measure as a result of the program)did not change
the projected unfavorable portfolio cost-effectiveness.
‘The Company operated natural gas DSM programs from 1995-1997 until natural gas avoided costs declined to the point at which
natural gas DSM programs became cost-ineffective.At that time,the natural gas DSM TariffRider,Schedule 191,was reduced to $0
until the avoided costs increased and natural gas programs could again be offered.In 2001 Schedule 191 rider amount was increased
and natural gas DSM programs were again implemented.The Company has had uninterrupted natural gas DSM since 2001.
4.2 II CHAPTER4 II DEMAND-SIDE MANAGEMENT
CPA METHODOLOGY
Prior to the development ofpotential estimates,Global developed a baseline end-use forecast to quantify the
use of natural gas by end use,in the base year,and projections of consumption in the future in the absence of
utility programs and naturally occurring conservation.The end-use forecast includes the relatively certain
impacts of codes and standards that will unfold over the study timeframe.All such mandates that were defined
as of January 2011 are included in the baseline.The baseline forecast is the foundation for the analysis of
savings from future DSM efforts,as well as,the metric against which potential savings are measured.
Inputs to the baseline forecast include current economic growth forecasts (e.g.customer growth,income
growth),natural gas price forecasts,trends in fuel shares and equipment saturations developed by Global,
existing and approved changes to building codes and equipment standards,and Avista’s internally developed
sales forecasts.
According to the natural gas CPA completed for Avista,the residential sector natural gas consumption for all
end uses and technologies increases,mainly due to the projected 1.7 percent annual growth in the number of
households,but also due to the slight increase in the average home size.Other heating,which includes unit
wall heaters and miscellaneous loads,have a relatively high growth rate compared to other loads.However,at
the end of the 20-year planning period,these loads represent only a small part of overall use.
For the commercial and industrial (C&I)sectors,natural gas use continues to grow slowly over the 20-year
planning horizon as new C&I construction increases the overall square footage in the commercial sector.In
addition,existing buildings are renovated to incorporate additional amenities such as full-scale kitchens.
Growth in the HVAC and water heating end uses is moderate.Food preparation,though a small percentage of
total usage,grows at a higher rate than other end uses.Consumption by miscellaneous equipment and process
heating are also projected to increase.
Table 4.1 illustrates the system-wide baseline forecast and how natural gas use across all sectors is expected to
increase by 28 percent during the 20-year planning horizon,for an average annual growth of 1.1 percent.
Overall,the forecast for the next 20 years grows steadily,dominated by growth in the residential sector.
Further,growth is forecasted to be highest in Idaho followed by Oregon.
2O12AvIsTANATuRALGAsIRP II 4.3
Table 4.1 Baseline Forecast Summary (1000 therms)
Sm.Commercial 50,693 50,130 50,530 51,271 52,378 53,494 55,120 9%0.4%
Lg.Commercial 71,176 69,274 69,647 70,392 71,667 73,191 75,295 6%0.2%
Industrial 5,141 5,026 5,067 5,156 5,274 5,409 5,560 8%0.3%
Total 315,906 320,503 322,693 330,932 349,097 373,385 405,250 28%1.1%
Washington 167,021 168,616 169,523 173,064 180,908 191,260 205,302 23%0.9%
Idaho 72,017 73,767 74,426 76,910 82,427 89,742 99,277 38%1.4%
Oregon 76,867 78,120 78,744 80,958 85,762 92,383 100,671 31%1.2%
Total 315,906 320,503 322,693 330,932 349,097 373,385 405,250 28%1.1%
The next step in the study is the development of the three types of potential:technical,economic and
achievable.Technical potential is the theoretical upper limit of conservation potential.This assumes that all
customers replace equipment with the most efficient option available regardless of cost,as well as,the
adoption of every available non-equipment measure,where applicable.Economic potential represents the
adoption of cost-effective conservation measures based on the Total Resource Cost (TRC)test and assumes
that customers purchase the most cost-effective and applicable measure.Finally,achievable potential takes
into account market maturity,customer preferences for energy efficiency technologies and expected program
participation.Achievable potential establishes a realistic target for conservation savings that a utility can
expect to achieve through its programs.
DSM measures that achieve generally uniform year round energy savings,independent of weather are
considered base load measures.Examples include high efficiency water heaters,cooking equipment and front
load clothes washers.Weather sensitive measures are those which are influenced by heating degree day factors
and include higher efficiency furnaces,ceiling/wall/floor insulation,weather stripping,insulated windows,
duct work improvements (tighter sealing to reduce leaks)and ventilation heat recovery systems (capturing
chimney heat).Weather sensitive measures are desirable in resource planning,as they save the most energy
during the coldest periods,thus displacing the more expensive peaking or seasonal supply resources.Weather
sensitive measures are often referred to as “winter measures”and are typically valued using a higher avoided
cost (due to sun-u-ner to winter pricing differentials)while base load measures often called “annual measures”
are valued at a lower avoided cost.
Conservation measures are offered to residential,non-residential and low-income2 customers.Conservation
measures offered to residential customers are classified as prescriptive,meaning they have a standardized
therm savings which can be generalized across the customer class and all customers receive the same financial
incentive for the same measures.Low income customers receive a more holistic,customized approach through
Residential 188,894 196,073 197,449 204,112 219,778 241,292 269,274 43%1.5%
2 For purposes of tables,figures and targets,low income is a subset of residential class.
4.4 II CHAPTER 4 II DEMAND-SIDE MANAGEMENT
a handful of Community Action Agency partnerships.Non-residential customers have access to prescriptive
and site-specific conservation measures.Site-specific measures are customized to the facility and have cost
and therm savings that are unique to the individual facility.
Finally,some conservation measures in Oregon are required by law and are therefore designated “mandatory”
or “must take”measures in the modeling tool,which means they are offered to customers without regard to
their current cost-effectiveness relative to the utility’s supply resources.An example of a mandated measure is
a walk-through energy audit,which would not be accompanied by energy savings unless a customer chooses
to participate in a program.In addition,a customer may choose to delay participating in a program for many
years.In these cases,the audit would be non-cost effective since there is no savings benefit to offset the cost of
the audit.
See Table 4.2 for Residential and C&I Measures evaluated in this study for all three states.
POTENTIAL RESULTS
Table 4.2 Conservation Measures
The technical potential reflects the adoption of all DSM measures regardless ofcost effectiveness and
represents the upper limit on savings.Over the 20 years considered by the CPA,technical potential reaches
38.9 percent of the baseline end-use forecast.
Economic potential applies the TRC test to measures identified within the technical potential and reflect the
adoption of DSM measures that are cost-effective.By the end of the 20-year timeframe this represents 14.6
percent of the baseline energy forecast.The significant difference between the technical and economic
potential reflects the lower natural gas avoided costs resulting from shale gas,as well as,the influence of
Residential Measures C&I Measures
Furnace —Maintenance
Boiler —Pipe Insulation
Insulation —Ducting
Insulation —Infiltration Control
Insulation —Ceiling
Insulation —Wall Cavity
Insulation —Attic Hatch
Insulation —Foundation (new only)
Ducting —Repair and Sealing
Doors —Storm and Thermal
Windows —ENERGY STAR
Thermostat —Clock/Programmable
Water Heating —Faucet Aerators
Water Heating —Low Flow Showerheads
Water Heating —Pipe Insulation
Water Heating —Tank Blanket/Insulation
Water Heating—Thermostat Setback
Water Heating—Timer
Water Heating —Hot Water Saver
Water Heating —Drain Water Heat Recovery (new only)
Home Energy Management System
Advanced new Construction Designs (new only)
ENERGY STAR Homes (new only)
Furnace —Maintenance
Boiler —Maintenance
Boiler —Hot Water Reset
Boiler —High Efficiency Hot Water Circulation
Space Heating —Heat Recovery Ventilator
Insulation —Ducting
Insulation —Ceiling
Insulation —Wall Cavity
Ducting —Repair and Sealing
Windows —High Efficiency
Energy Management System
Thermostat —Clock/Programmable
Water Heating —Faucet Aerators
Water Heating —Pipe Insulation
Water Heating —Tank Blanket/Insulation
Water Heating —Hot Water Saver
Advanced New Construction Designs (new only)
Comprehensive Commissioning
Process —Boiler Hot Water Reset (industrial only)
2O1ZAVISTANATURALGASIRP II 4.5
Avista ‘s long-running history of operating DSM programs that have already achieved much of the cost-
effective conservation.Consequently,the remaining conservation measures are becoming incrementally more
expensive on a per-therm basis and many,therefore,do not pass the cost-effectiveness screen based on current
avoided costs.
Finally,achievable potential across the residential,commercial and industrial sectors is 12.9 percent of the
baseline energy forecast by the end of 2032.
For the Oregon service territory,it should be noted that both economic and achievable potential include
residential weatherization measures that are mandated by Oregon legislation to be provided regardless of cost
effectiveness and other factors.Many of these measures did not pass the TRC benefit-cost ratio analysis but
were nevertheless included in economic and achievable potential.
Tables 4.3 and 4.4 summarize cumulative conservation for each potential type for selected years across the 20-
year CPA and IRP horizon.Initially,the large commercial sector provides a relatively higher percentage of the
achievable savings compared with its share of sales,but over time,this situation reverses so that the residential
sector’s share of savings is the greatest,due to growth in residential customer count.For more specific detail,
please refer to the natural gas CPA provided in Appendix 4.1.
Table 4.3 Summary of Cumulative Achievable,Economic and Technical Conservation Potential
2013 2014 2017 2022 2027 2032
Baseline Forecast (1000 thm)
320,503 322,693 330,932 349,097 373,385 405,250
Cumulative Natural Gas Savings (1000 thm)
Achievable 1,546 3,738 12,794 28,216 41,349 52,381
Economic 1,797 4,333 14,785 31,757 45,809 58,965
Technical 7,623 15,844 46,189 91,655 131,422 157,520
Cumulative Natural Gas Savings (%of Baseline)
Achievable 0.5%1.2%3.9%8.1%11.1%12.9%
Economic 0.6%1.3%4.5%9.1%12.3%14.6%
Technical 2.4%4.9%14.0%26.3%35.2%38.9%
4.6 II CHAPTER 4 II DEMAND-SIDE MANAGEMENT
Furthermore,overall potential is presented first by state and then for each sector in the following table.
Table 4.4 Summary of Cumulative Achievable,Economic and Technical Conservation Potential
and
Idaho 364 821 2,734 5,601 8,758 11,914
Oregon 289 715 3,136 7,251 10,706 13,559
Total 1,546 3,738 12,794 28,216 41,349 52,381
Residential 515 1,567 6,507 14,903 22,278 29,960
Small Commercial 206 469 1,588 3,557 5,709 7,018
Large Commercial 801 1,654 4,548 9,436 13,007 15,027
Industrial 25 49 151 319 354 377
Total 1,546 3,738 12,794 28,216 41,349 52,381
Figure 4.1 below illustrates the potential forecasts compared with the end-use baseline forecast that was
projected to occur in the absence of utility DSM programs.The dotted black line depicts the 2010 usage level.
By the end of the 20-year period,achievable potential (indicated by the blue line)offsets 60 percent of the
growth in the baseline forecast.
Washington 893 2,203 6,923 15,364 21,885 26,909
2O12AVISTANATURALGASIRP II 4.7
Figure 4.1 -Conservation
Potential Energy Forecast (1000 therm)
450,000
400,000 -_____________________________________________________________
350,000 -
______________________—-
I ::::_...E
D 200000U,
—Baseline
150,000 -——--———----—Achievable -—
—Economic
100,000 --———-—-——-.--—:—.—Technical ——
-----2010 Use
50,000-———-.--.--.-.-.----—.———-.——---—-.————---..-.—---—.—.————
-.—---..-—.—..--.-—.-.-...—--...—-..-,...—.—-.—-,-——.
00 43
POTENTIAL RESULTS —RESIDENTIAL
Single-family homes represent 79 percent of Avista’s residential natural gas customers,but accounts for 84
percent of the sector’s consumption in the study base year 2010.While Oregon represents only about one-
quarter of the baseline forecast,it makes up between 28 and 35 percent ofthe achievable potential savings.
This is due to the inclusion of the legislatively mandated weatherization and insulation measures within
Oregon’s achievable potential.
Table 4.5 provides a distribution of achievable potential by state for the residential sector.
4.8 II CHAPTER 4 II DEMAND-SIDE MANAGEMENT
Table 4.5 Residential Cumulative Achievable Potential by State,Selected Years
2013 2014 2017 2022 2027 2032
Baseline Forecast (1000 thm)
Washington 100,894 101,415 104,274 110,964 119,962 132,043
Idaho 46,065 46,424 48,209 52,647 58,832 67,038
Oregon 49,114 49,609 51,629 56,167 62,498 70,193
Total 196,073 197,449 204,112 219,778 241,292 269,274
Natural Gas Savings (1000 thm)
Washington 237 838 3,017 7,268 10,634 13,894
Idaho 121 306 1,248 2,337 4,002 6,246
Oregon 156 422 2,242 5,298 7,642 9,819
Total 515 1,567 6,507 14,903 22,278 29,960
%of Total Residential Savings
Washington 46.2%53.5%46.4%48.8%47.7%46.4%
Idaho 23.6%19.6%19.2%15.7%18.0%20.8%
Oregon 30.3%26.9%34.5%35.5%34.3%32.8%
The bulk of the residential potential exists primarily with space heating followed by water heating
applications.Appliances and miscellaneous contribute a small percentage ofpotential.Based on measure-by-
measure finding of the potential study,the greatest sources of residential achievable potential across all three
states are:
ii Shell measures and insulation
ii Thermostats and home energy monitoring systems
ii Water-saving devices such as low-flow showerheads and faucet aerators
ii Water heater tank blankets and pipe insulation
POTENTIAL RESULTS —COMMERCIAL AND INDUSTRIAL
The baseline forecast for the C&1 sector grows steadily during the forecast period as the region begins to
recover from the economic downturn.Consequently,energy efficiency opportunities are significant for this
sector.However,similar to the residential sector,many conservation opportunities do not pass the TRC
economic screen given the low natural gas avoided costs.
The large commercial sector provides the greatest opportunities for savings.Although potential as a
percentage of baseline use varies from one sector to the next,results do not vary greatly among the three
states.See Table 4.6 for achievable potential by sector for selected years.
2O12AvI5TANATuRALGA5IRP II 4.9
Table 4.6 C&l Cumulative Achievable Potential by Selected Years
2013 2014 2017 2022 2027 2032
Baseline Forecast (1000 thm)
Small Commercial 50,130 50,530 51,271 52,378 53,494 55,120
Large Commercial 69,274 69,467 70,392 71,667 73,191 75,295
Industrial 5,026 5,067 5,156 5,274 5,409 5,560
Total 124,429 125,244 126,819 129,319 132,094 135,976
Natural Gas Savings (1000 thm)
Small Commercial 206 469 1,588 3,557 5,709 7,018
Large Commercial 801 1,654 4,548 9,436 13,007 15,027
Industrial 25 49 151 319 354 377
Total 1,031 2,172 6,287 13,312 19,071 22,422
%of Total C&l Savings
Small Commercial 20.0%21.6%25.3%26.7%29.9%31.3%
Large Commercial 77.6%76.2%72.3%70.9%68.2%67.0%
Industrial 2.4%2.2%2.4%2.4%1.9%1.7%
Similar to Residential,the bulk of the C&I potential exists within space heating and water heating applications.
Food preparation,process and miscellaneous represents a smaller proportion of potential.Primary sources of
commercial achievable savings are:
ii Energy management systems and programmable thermostats
ii Boiler operating measures such as maintenance
ii Hot water reset and efficient circulation
ii Equipment upgrades for furnaces,boilers and unit heaters
ii Food service equipment
SENDOUT®MODELING METHODOLOGY
The SENDOUT®model understands that investments made in DSM are a long-term resource decision.The
model also understands that some programs may not be cost-effective in the initial forecast years;however the
total cost over the life of the measure,coupled with the cumulative therms savings,is economic.Due to this
modeling nuance,SENDOUT®typically selects most of the DSM potential.
While the IRP process evaluates demand-side and supply-side resources for a 20-year planning horizon,the
process also results in a starting point for the two year operational business plan and goal for natural gas DSM.
The business plan sets targets specific to each state and sector —residential and C&J.The following three
tables provide the 2013-2014 CPA identified DSM opportunity for Idaho,Oregon and Washington,
respectively.
4.10 II CHAPTER 4 II DEMAND-SIDE MANAGEMENT
Table 4.7 Idaho Natural Gas Target (2013-2014)
Incremental Annual Savings
(1000 therm)2013 2014
Residential 121 185
Commercial &Industrial 246 271
Total 364 456
Table 4.8 Oregon Natural Gas Target (2013-2014)
Incremental Annual Savings
(1000 therm)2013 2014
Residential 156 266
Commercial &Industrial 133 160
Total 289 426
Table 4.9 Washington Natural Gas Target (2013-2014)
Incremental Annual Savings
(1000 therm)2013 2014
Residential 237 601
Commercial &Industrial 655 709
Total 893 1,310
There are substantial methodological differences between the Global Energy Partners CPA and Avista’s
operational business planning process.These include how measures are aggregated into programs offerings
and evaluated,how non-incentive infrastructure costs are treated,and how specific the results are to Avista’s
service territory and program offerings.The CPA provides substantial guidance in evaluating the entire
spectrum of efficiency options and illustrating trends in equipment and technologies,however the business
planning process is a reflection of the likely results of actual DSM operations.
Key analytical differences between the CPA and the business planning process include the ‘splintering’of
measures into numerous scenarios (by building type,replace-before-burnout vs.replace-on-burnout,by
jurisdiction,etc.).These splintered measures may pass and generate the expectation of the cost-effective
acquisition of resources,but if the measures are not collectively cost-effective when aggregated into a program
that can be operationally delivered,there are no realistic prospects for achieving these projections.
Additionally there are differences in non-incentive utility cost levels driven by program design approaches and
how these costs are distributed.Fundamentally these differences are driven by the use of an independent third
party packaged model intended to provide general guidance regarding resource acquisition economics versus a
utility-specific business planning approach incorporating operational details,program-specific assumptions
and indexed to past actual results.These differences can lead to different results under many conditions,
especially under challenging cost-effectiveness scenarios.
2O12AvIsTANATuLGAsIRP II 4.11
THE BUSINESS PLANNING PROCESS AND CONSERVATION GOALS
Each fall,Avista develops a DSM business plan where CPA-identified measure applications are re-cast into
operational DSM programs and goals are developed.For example,a CPA could identify that 3-pan and 5-pan
commercial cookware would be cost-effective while 4-pans may not.However,programmatically,since the
4-pan cookware is such a small slice of the market,the program would ultimately incent all of these non
residential cookware options.As explained above,the ‘splintered’approach utilized in the evaluation of
natural gas efficiency options within the CPA can lead to substantially different results than can be
operationally achieved.Under those circumstances Avista has found that the business planning process is
more indicative of what is operationally achievable.
Evaluation ofthe Washington/Idaho natural gas portfolio using these latest avoided costs have not resulted in
any scenarios where Washington!Idaho natural gas programs are cost-effective,on either a gross or net basis.
Consequently,Avista has filed in both states for an indefinite suspension of its Washington/Idaho natural gas
DSM programs.
The Company has history of suspending natural gas DSM when avoided costs have decreased rendering
programs cost-ineffective.Since Washington and Idaho electric DSM portfolio continues to be cost-effective
and operate,it is fairly easy for the Company to ramp up the natural gas programs again should there be a
change in the natural gas avoided costs.Avista’s natural gas DSM programs were suspended in 1997 due to
decreased avoided costs and were reinstated when avoided costs increased three years later.The Company will
continue to monitor Weighted Average Cost of Gas (WACOG)as a proxy to determine changes in avoided
costs.
The Oregon natural gas DSM portfolio is undergoing portfolio evaluation.This evaluation will incorporate the
continuation of mandated audit services,as well as,any programs which can be redesigned to meet the
required criteria.Additional review of appropriate methodologies will occur to include discussions of the
appropriate discount rate and base case.This work is being expedited in recognition of the need to implement
program redesigns or suspensions in a responsible manner and timeline.
While the lower natural gas avoided costs can be viewed as disappointing news for DSM,the good news for
customers translates to lower retail rates.In addition,some electric efficiency programs such as fuel
conversions become even more cost-effective and there may be potential for increases in customer incentives
to enhance participation in these programs and encourage customers to make the appropriate fuel choice.
Avista continues to support energy efficiency efforts where cost-effectiveness allows.
ENVIRONMENTAL EXTERNALITIES
The impact of utilizing energy on the environment continues to be a subject of societal concern and debate.If
there are impacts that cannot be repaired naturally within a reasonable period of time,damage cost to the
environment occurs for which society will have to pay in some future undetermined form.The question of who
pays,how much and when payment should be made,are complicated issues.This longstanding debate is trying
4.12 II CHAPTER 4 II DEMAND-SIDE MANAGEMENT
to be addressed through a variety of public policy initiatives and legislation.Regulatory guidelines in Oregon3
advocate specific analysis in the IRP process to better understand these issues.Avista included an evaluation
of the impacts of environmental externalities in the context of this evolving legislative environment.Appendix
4.2 discusses the analysis.
DEMAND RESPONSE
Demand response is a peak demand management concept where customers adjust the timing of their energy
consumption away from consumption peaks in exchange for lower rates.Implementation strategies encompass
a number of activities including real-time pricing,time-of-use rates,critical-peak pricing,demand buyback,
interruptible rates and direct-load controls.When effectively implemented,acquisition of costly supply
resources can be deferred.
Demand response works best when it is a quick solution to an immediate problem.When demand peaks,
system operators need the ability to either quickly notify customers to curtail consumption or do it themselves
via control systems to physically manage/restrict gas flow to increase distribution system pressures.
This mechanism exists with respect to our interruptible transportation-only customers,which make up
approximately one third of Avista’s total annual throughput.However,because we do not purchase supply for
these customers,they do not represent an incremental supply resource alternative.Only core customers with
high winter consumption profiles would provide an incremental supply resource using demand response
curtailment strategies.Unfortunately,we currently have very few core customers with a complying
consumption profile.As a result,we believe that all customers who can manage their operations on
interruptible service are currently served on an interruptible basis,leaving little opportunity to reduce peak
loads through expanded interruptible service.
While little demand response opportunity exists on our natural gas system,we continue to monitor the
progress of other natural gas utilities and their efforts of peak load shifting to offset hourly and/or daily flow
constraints.Whereas electric demand response technologies have been in place for over two decades,major
differences exist between electric and natural gas supply/delivery systems.The economics of the timing of
natural gas usage are much more forgiving than electric due to underground storage and line packing.
Furthermore,natural gas curtailment is not an option since a natural gas company cannot restart service
without a technician on-site to ensure all pilots are properly lit for safety reasons.
At times natural gas providers may find implementing a demand response program helpful in offsetting or
postponing a pipeline upgrade or in price balancing.However,mandatory participation in the affected areas
would be vital to fund the necessary investment in enabling technologies.
II CONCLUSION
By encouraging customers to change their demand for natural gas,Avista can displace the need to purchase
additional natural gas supplies,displace or delay contracting for incremental pipeline capacity and possibly
displace or delay the need for upgrades to our distribution system.This IRP process provides the utility with
the necessary resource analysis to evaluate demand-side resource options on par with supply-side resources,
Oregon IRP regulations require that a 10%cost advantage accrues to DSM resources relative to supply resources for environmental
externalities costs.Appendix 4 describes our analysis.
2O12AVISTANATURALGASIRP II 4.13
periodically review and update DSM operations and finally,develop and implement improved natural gas
energy efficiency programs.
The completion of the IRP analysis is not the end point,but rather the midpoint of a much larger evaluation of
the DSM natural gas resource portfolio.The IRP analysis presented has generally indicated a conservation
potential for a future DSM program design and delivery.However,differences in modeling methodologies
require further evaluation through Avista’s annual business planning process in order to facilitate the
development of a cost-effective program portfolio to be incorporated into overall DSM operations.
Even though applications to suspend gas DSM have been filed,Avista is committed to closely monitoring
proxies for the natural gas avoided cost and returning the natural gas DSM programs to our menu of offerings
if commodity costs and efficiency technologies or program delivery options change in such a manner as to
make these programs cost-effective under the Total Resource Cost test.This monitoring will be performed on
an ongoing basis in addition to our regularly scheduled annual DSM business plans and the biennial IRP
process.
2012 AvisrA NATURAL GAS IRP
CHAPTER 5 H SUPPLY-SIDE RESOURCES
OVERVIEW
We have analyzed a range ofanticipated future demand scenarios and a variety ofpossible conservation
measures to reduce demand.This chapter discusses possible supply options to meet net demand.Our
objective is to reliably provide natural gas to customers with an appropriate balance of price stability and
prudent cost while navigating continuously changing market conditions.To achieve this,we evaluate a
variety of supply-side resources and attempt to build a supply portfolio that is appropriately diversified.The
resource acquisition and commodity procurement programs resulting from our evaluation consider physical
and financial risks,market-related risks and procurement execution risks and identif’the methods we deploy
to mitigate these risks.
We manage our natural gas procurement and related activities on a system-wide basis.We have a number of
regional supply options available to serve our core customers.These include firm and non-firm supplies,firm
and interruptible transportation on six interstate pipelines and storage.Because Avista’s core customers span
three states,the diversity of delivery points and demand requirements adds to the options available to meet
customers’needs.The utilization of these components varies depending on demand and operating conditions.
In this chapter,we discuss the available regional commodity resources and our procurement plan strategies,
the regional pipeline resource options available to deliver the commodity to our customers,and the storage
resource options available which provide additional supply diversity,enhanced reliability,favorable price
opportunities and flexibility to meet a varied demand profile.Beyond these traditional supply-side resources
we discuss non-traditional resources which are also considered.
COMMODITY RESOURCES
SUPPLY BASINS
Avista is fortunate to be located in relatively close proximity to the two largest natural gas producing regions
in North America —the Western Canadian Sedimentary Basin (WCSB),which is located primarily in the
Canadian provinces of Alberta and British Columbia,and the Rocky Mountain (Rockies)gas basin,located
primarily in Wyoming,Utah and Colorado.Avista sources virtually all of its natural gas supplies from these
two basins.
The WCSB and Rockies gas basins used to have limited pipeline export potential,which has historically
resulted in lower regional natural gas prices when compared to other parts of the country.Over the last
decade,however,several large pipelines have been completed (or capacities of existing pipelines increased)
connecting the WCSB and Rockies gas basins to the Southwest,Midwest and Northeast sections of the
continent.This has at times diminished the discounted price advantage the Region has enjoyed.Furthermore,
the prolific amounts of shale gas located across North America (particularly in the East)have and will
continue to change the flow dynamics.Forecasts show a continued price advantage for the region in both the
WCSB and Rockies basins as the need for these supplies to move East diminishes.
1ncreased availability of North American natural gas has prompted a change in the LNG landscape.More
supply than demand has changed the plans of many LNG import facilities.Now owners of these facilities are
looking to switch from importing to exporting gas in order to capture better pricing in the Asian and European
5.2 II CHAPTER5 II SUPPLYSIDERESOURCES
markets.Regionally,Kitimat LNG has received authorization to export natural gas offthe coast of British
Columbia.Two proposed import LNG facilities in Oregon have petitioned FERC to become export facilities.
While there is much uncertainty about how many facilities actually get built the bigger question is how
regional markets will be impacted by potential exports.
REGIONAL.MARKET HUBS
Extending out from the two primary basins are numerous regional market hubs where natural gas is traded.
These typically are located at pipeline interconnects.Avista is located near and transacts at most of the Pacific
Northwest regional market hubs,enabling flexible access to a diversity of supply points.These supply points
include:
ii AECO —The AECO-C/Nova Inventory Transfer market center is a major connection region to long-
distance transportation systems,which take gas to points throughout Canada and the United States.
Alberta has historically produced 90%of Canad&s natural gas and is the source of most Canadian
natural gas exports to the U.S.representing volume that accounts for approximately 13%ofU.S.
natural gas requirements.
ii ROCKIES —This pricing “point”actually represents several locations on the southern end of the NWP
system in the Rocky Mountain region.The system draws on Rocky Mountain gas-producing areas
clustered in areas of Colorado,Utah,and Wyoming.
II SUMAS/HUNTINGDON —This pricing point at Sumas,Wash.,is on the U.S./Canadian border where
the northern end of the NWP system connects with Spectra Energy’s Westcoast Pipeline,and is
predominantly Canadian gas coming south from Northern British Columbia.
ii MALIN —this pricing point is at Malin,Ore.on the California/Oregon border where the pipelines of
TransCanada Gas Transmission Northwest (GTN)and Pacific Gas &Electric Co.connect.
II STATION 2 —Located at the center of the Spectra Energy/Westcoast Pipeline system connecting to
northern British Columbia production.
II STANFIELD —Located near the Washington/Oregon border at the intersection of the NWP and GTN
pipelines
ii KINGSGATE —Located at the U.S./Canadian (Idaho)border where the GTN pipeline connects with
the TransCanada Foothills pipeline.
Given the ability to transport natural gas to other portions of North America natural gas pricing is often
compared to the Henry Hub price for natural gas.Henry Hub is a natural gas trading point located in
Louisiana is widely recognized as the primary natural gas pricing point in the U.S.and is also the trading
point used in NYMEX futures contracts.
Figure 5.1 shows historic natural gas prices for first-of-month index physical purchases at AECO,Sumas,
Rockies and Henry Hub.The figure illustrates there is usually a tight relationship among the various
locations;however,there have been periods where one or more price points have disconnected.In winter
2000-200 1 Sumas rallied on a combination of the Western energy crisis and unusually cold local weather
conditions.In fall of 2005 hurricanes Katrina and Rita disrupted significant Gulf of Mexico regional
production causing the Henry Hub to spike disproportionately to Northwest hubs.Since 2007 increased
production in the Rocky Mountain basin has exceeded the takeaway pipeline capacity forcing concessions on
Rockies prices pending completion of major phases of the Rockies Express pipeline project.This significant
project —completed in late summer 2009 —enables substantial volumes to reach Midwestern and
2012 Avista Natural Gas IRP II 5.3
Northeastern demand centers.Consequently,Rockies prices have resumed tighter tracking with Henry Hub
prices.As prices have declined the pricing differentials among the basins have tightened.
Natural gas prices among the Northwest regional supply points typically move together as well;however,the
basis differential can change depending on market or operational factors.This includes differences in weather
patterns,pipeline constraints at different locations and the ability to shift supplies to higher-priced delivery
points in the U.S.or Canada.By monitoring these price shifts we are often able to purchase at the lowest-
priced trading hubs on a given day,subject to operational and contractual constraints.
Liquidity is generally sufficient in the day-markets at most northwest supply points.AECO continues to be
the most liquid supply point,especially for longer-term transactions.Sumas has historically been the least
liquid of the four major supply points (AECO,Rockies,Sumas,Maim).This illiquidity contributes to
generally higher relative prices in the high demand winter months.
Procurement of natural gas is done via contracts.There are a number of contract specifics that vary from
transaction-to-transaction,and many of those terms or conditions impact commodity pricing.Some of the
agreed-upon terms and conditions include:
II FIRM VS.NON-FIRM —Most term contracts specify that supplies are firm except for force majeure
conditions.In the case of non-firm supplies the standard provision is that they may be cut for reasons
other than force majeure conditions.
II FIXED VS.FLOATING PRICING —The agreed-upon price for the delivered gas may be fixed or based
upon a daily or monthly index.
II PHYSICAL VS.FINANCIAL —Certain counterparties,such as banking institutions,may not trade
physical natural gas but are still active in the natural gas markets.Rather than managing physical
$16.00
$14.00
Figure 5.1 -Monthly Index Prices
$12.00
$10.00
$8.00
$6.00
$4.00
$2.00
$0.00
rrr.
—-o o c a -i -i -1 r.J c-.J m m u u ‘.D ‘.D LD r—N.CO CO C O 0 0 rI ,-1 ,1aa,o C C a a a a C C a C C a C C a a C a a a 0 a a a —i .-i -ia,a,0 0 0 C 0 0 0 0 0 C C C 0 0 0 0 0 0 0 C 0 0 0 0 0 0 0 0 0.-,-4 ,1 g-.J r.J rJ rj r.4 r4 r.J r’J NJ NJ NJ NJ NJ NJ NJ NJ NJ NJ NJ NJ NJ NJ NJ NJ NJ NJ NJ—.-.—-.-—.—-.--——.-.-....-—-....-.--———....-..-.-.,.1 ,-(-l ,1 -I ,l -1 -l -.-I ,-4 ,1 -i -1 -4 -i -1 .-l ri -I ,1 .1 ,1 -l 1—-.---..-.—-—.-..—-.-—.——.—-.--.--.-...--.--,..—--.——.—.—.—.-.—1 1,0 -i t NJ N.NJ Lfl 0 rfl CO -1 1,0 -1 a,NJ N NJ U)a m CO -1 1,0 -i O NJ N NJ_1 .-.-1 -‘-l
—Henry Hub —AECO —Rockies —Sumas
5.4 II CHAPTER5 II SUPPLYSIDERESOURCES
supplies,those counterparties choose to transact financially rather than physically.Financial
transactions provide another way for Avista to financially hedge price.
II LOAD FACTORNARIABLE TAKE —Some contracts have fixed reservation charges assessed during
each of the winter months,while others have minimum daily or monthly take requirements.
Depending on the specific provisions,the resulting commodity price will contain a discount or
premium compared to standard terms.
ii LIQUIDATED DAMAGES —Most contracts contain provisions for symmetrical penalties for failure to
take or supply natural gas.
For this IRP,the SENDOUT®model assumes the natural gas is purchased as a firm,physical,fixed-price
contract regardless of when the contract is executed and what type of contract it is.However,in reality,we
pursue a variety of contractual terms and conditions in order to capture the most value from each transaction.
AVISTA’S PROCUREMENT PLAN
We cannot accurately predict future natural gas prices but market conditions and experience help shape our
overall approach.Avista has designed a natural gas procurement plan process that seeks to competitively
acquire natural gas supplies while reducing exposure to short-term price volatility.Our procurement strategy
includes hedging,storage utilization and index purchases.Although the specific provisions of the
procurement plan will change as a result of ongoing analysis and experience,the following principles guide
Avista’s development of its procurement plan:
Avista employs a time,location and counterparty diversified hedging strategy.It is appropriate to hedge
over a period of time and we establish hedge periods within which portions of future demand are physically
and/or fmancially hedged.The hedges may not be completed at the lowest possible price but they will protect
our customers from price volatility.With access to multiple supply basins,when we transact we seek the
lowest priced basin.Furthermore,we transact with a range of counterparties.
Avista establishes a disciplined but flexible hedging approach.In addition to establishing hedge periods
within which hedges are to be completed we also set upper and lower pricing points.In a rising market this
reduces Avista’s exposure to extreme price spikes.In a declining market this encourages capturing the benefit
associated with lower prices.
Avista regularly reviews its procurement plan in light of changing market conditions and opportunities.
Avista’s plan is open to change in response to ongoing review of the assumptions that led to the procurement
plan.Although we establish various targets in the initial plan design,policies provide flexibility to exercise
judgment to revise/adjust targets in response to changing conditions.
A number of tools are utilized to help mitigate financial risks.Avista purchases gas in the spot market as well
as the forward market.Spot purchases are made on a day for the next day or weekend.Forward purchases are
made on a day for a designated future delivery period.Many of these tools are financial instruments or
derivatives that can be utilized to provide fixed prices or dampen price volatility.We continue to evaluate
how to manage daily demand volatility,whether through option tools available from counterparties or through
access to additional storage capacity and/or transportation.
2012 Avista Natural Gas IRP II 5.5
TRANSPORTATION RESOURCES
Although proximity to the liquid hubs is important from a cost perspective those supplies are only as reliable
or firm as the pipeline transportation from the hubs to Avista’s service territories.Capturing favorable price
differentials and mitigating price and operational risk can also be realized by holding multiple pipeline
transport options.Consequently,we have contracted for a sufficient amount of diversified firm pipeline
capacity from various receipt and delivery points (including out of storage facilities)so that firm deliveries
will meet peak day demand.We believe the combination of finn transportation rights to our service territory,
storage facilities and access to liquid supply basins will ensure peak supplies are available to our core
customers.
The major pipelines servicing our region are as follows:
II WILLIAMS -NORTHWEST PIPELINE (NWP)
A natural gas transmission pipeline serving the Pacific Northwest moving natural gas from the
US/Canadian border in Washington and from the Rocky Mtn.region of the US.
ii TRANSCANADA GAS TRANSMISSION NORTHWEST (GTN)
A natural gas transmission pipeline originating at Kingsgate,Idaho (Canadian/U.S.border)and
terminating at the California/Oregon border close to MaIm,Ore.
ii TRANSCANADA ALBERTA SYSTEM
A natural gas gathering and transmission pipeline in Alberta Canada that delivers natural gas into the
TransCanada Foothills pipeline at the Alberta/British Columbia border.
ii TRANSCANADA FOOTHILLS SYSTEM
A natural gas transmission pipeline that delivers natural gas between the Alberta,British Columbia
border and the Canadian/U.S.border at Kingsgate,Idaho.
i TRANSCANADA TUSCARORA GAS TRANSMISSION
A natural gas transmission pipeline originating at MaIm,Ore and terminating at Wadsworth,Nev.
II SPECTRA ENERGY -WESTCOAST PIPELINE
A natural gas transmission pipeline originating at Fort Nelson,British Columbia and terminating at
the Canadian/U.S.border at Huntington,British Columbia/Sumas,Wash.
ii EL PASO NATURAL GAS—RUBY PIPELiNE
A natural gas transmission pipeline bringing supplies from the Rocky Mountain region of the U.S.to
interconnections near Malin,Ore.Ruby Pipeline began operating in July 2011.
Avista has contracts with all of the above pipelines (with the exception of Ruby Pipeline)for firm
transportation to serve our core customers.Table 5.1 details the firm transportation/resource services
contracted by Avista.These contracts are of different vintages,thus different expiration dates;however,all
have the right to be renewed by Avista.This gives Avista and its customers the knowledge that Avista will
have available capacity to meet existing core demand now and in the future.
5.6 II CHAPTER5 II SUPPLYSIDERESOURCES
Avista defines two categories of interstate pipeline capacity.“Direct-connect”pipelines deliver supplies
directly to our local distribution system from production areas,storage facilities or interconnections with
other pipelines.“Upstream”pipelines deliver natural gas to the direct-connect pipelines from remote
production areas,market centers and out of area storage facilities.Figure 5.2 illustrates the direct-connect
pipeline network relative to our supply sources and service territories 1.
1 Avista has a small amount of pipeline capacity with TransCanada Tuscarora Gas Transmission,a natural gas transmission pipeline
originating at Malin,Oregon,to service a small number of Oregon customers near the southern border of the state.
Table 5.1
Firm TransportationlResources Contracte d*
Dth/Day
Avista Avista
North South
Firm Transportation Winter Summer Winter Summer
NWP TF-1 157,869 157,869 42,699 42,699
GTN T-1 100,605 75,782 42,260 20,640
NWPTF-2 91,200 2,623
Total 349,674 233,651 87,582 63,339
Firm Storage Resources -Max Deliverability
Jackson Prairie
(Owned and
Contracted)346,667 54,623
Total 346,667 54,623
*Represents original contract amounts after releases expire.
2012 Avista Natural Gas IRP II 5.7
Supply-side resource decisions focus on where to purchase natural gas and how to deliver it to customers.
Each LDC has distinctive service territories and geography relative to supply sources and pipeline
infrastructure.Solutions that deliver supply to service territories among regional LDCs are similar but are
rarely generic —instead they are almost always unique.
The NWP system for the most part is a fully contracted system.With the exception of La Grande our service
territories lie at the end of various NWP pipeline laterals.Washington/Idaho is served via the Spokane,Coeur
d’Alene and Lewiston laterals while Roseburg and Medford are served by the Grants Pass lateral.Capacity
expansions on each ofthese laterals are lengthy and costly endeavors which Avista would likely bear most of
the incremental costs.
The GIN system,on the other hand,currently has ample unsubscribed capacity.This pipeline runs directly
through or lies in close proximity to most of our service territories.Mileage based rates and backhaul
potential provide attractive options for securing incremental resource needs.
Peak day planning aside,both pipelines provide an array of options to flexibly manage daily operations.Our
two largest service territories are directly served by both pipelines providing diversification and risk
management with respect to supply source,price and reliability.The NWP system (a bi-directional,fixed
reservation fee-based pipeline)provides direct access to Rockies and British Columbian supply and facilitates
excellent optionality for storage facility management.The Stanfield interconnect of the two lines is also
geographically well situated to our service territories.
The rates we use in our planning model start with filed rates that are currently in effect (See Appendix 5.1).
Forecasting future pipeline rates is challenging.Our assumptions for future rate changes are the result of
market information on comparable pipeline projects,prior rate case experience and informal discussions.It is
generally assumed that the pipelines will file to recover costs at rates equal to the GDP with adjustments made
for specific project conditions.
NWP and GIN also offer interruptible transportation services.The level of service of interruptible
transportation is subject to curtailment when pipeline capacity constraints limit the amount of natural gas that
may be moved.Although the commodity cost per dekatherm transported is the same as firm transportation,
there are no demand or reservation charges in these transportation contracts.As the marketplace for release of
transportation capacity by the pipeline companies and other third parties has become more prevalent,the use
of interruptible transportation services has diminished.We do not rely on interruptible capacity to meet peak
day core demand requirements.
Avista’s transportation acquisition strategy is to contract for firm transportation to serve core customers
should a peak day occur in the near-term planning horizon.Since contracts for pipeline capacity are often
lengthy in tenor and core customer demand needs can vary over time determining the appropriate level of firm
transportation is a complex analysis of many factors.The analysis includes the projected number of firm
customers and their expected annual and peak day demand,opportunities for future pipeline or storage
expansions and relative costs between pipelines and their upstream supplies.This analysis is done on an
annual basis as well as through the TRP.Active management of underutilized capacity through the capacity
release market and engaging in optimization transactions offsets some of the transportation costs.Timely
analysis is also important in order to maintain an appropriate time cushion to allow for required lead times
should the need for securing new capacity arise.
5.8 II CHAPTER5 II SUPPLYSIDERESOURCES
STORAGE RESOURCES
Storage is a valuable strategic resource that enables improved management of a highly seasonal and varied
demand profile.Storage benefits include:
ii Flexibility to serve peak period needs
ii Access to typically lower cost off-peak supplies
ii Reduced need for higher cost annual firm transportation
ii Improved utilization of existing firm transportation via off-season storage injections
ii Additional supply point diversity
While there are a number of different storage facilities available to the region,Avista’s existing storage
resources consist solely of ownership and leasehold rights at the Jackson Prairie storage facility.
JACKSON PRAIRIE STORAGE
Avista is one-third owner,with NWP and Puget Sound Energy (PSE)in the Jackson Prairie storage project for
the benefit of its core customers in all three states.Jackson Prairie Storage is an underground reservoir facility
located near Chehalis,Wash.approximately 30 miles south of Olympia,Wash.The total working gas
capacity of the facility is approximately 25 Bcf.Avista’s current share of this capacity for core customers is
approximately 8.5 Bcf and includes 398,667 Dth of daily deliverability rights.
Outside of Avista’s ownership rights,we have leased an additional 95,565 Dth of Jackson Prairie capacity
with 2,623 Dth of deliverability from NWP to serve Oregon customers.
INCREMENTAL SUPPLY-SIDE RESOURCE OPTIONS
Our existing portfolio of supply-side resources provides a good mix of assets to manage demand requirements
for an average day and peak day events.But in anticipation of growing and changing demand requirements,
we monitor the following potential resource options to meet future requirements.
SYSTEM ENHANCEMENTS
Within the context of the IRP,distribution planning plays a role but is not the primary focus.Distribution
works hand in hand with supply to ensure that customer demand is met on both and average day and a peak
day.There are modifications,enhancements,or upgrades that occur on the distribution system that are
routine projects enhancing reliability of our system.However,in certain instances,Avista can facilitate
additional peak and base load-serving capabilities through a modification or upgrade of our distribution
facilities.These projects would enable more takeaway capacity from the interstate pipelines.These
opportunities are geographically specific and require case-by-case study.Costs of these types of
enhancements are included in the context of the IRP.A more detailed description of system enhancements
(including both routine and non-routine)can be found in Chapter 8.
CAPACITY RELEASE RECALL
As discussed earlier,pipeline transportation that is not utilized to serve core customer demand can be released
to other parties or optimized through daily or term transactions.Released capacity is generally marketed
through a competitive bidding process and can be done on a short-term (month-to-month)or long-term basis.
2012 Avista Natural Gas IRP II 5.9
We actively participate in the capacity release market and have both short-term and long-term capacity
releases.
We assess the need to recall capacity or extend a release of capacity on an on-going basis.The IRP process
also helps evaluate if or when we need to recall some or all of our long-term releases.
EXISTING AVAILABLE CAPACITY
In some instances there is currently available capacity on existing pipelines.NWP’s mainline is currently
fully subscribed;however GTN mainline has available capacity.There is some uncertainty about the future
capacity availability as the demand needs of utilities and end-users vary across the region.We do model
access to the GTN forward-haul and backhaul capacity as an option to meet our future demand needs.
GTN BACKHAULS
GTN backhaul services have always been available on a relatively reliable basis via displacement.However,
the interconnection with the Ruby Pipeline has enabled GTN the physical capability to provide this service
with minor modifications to their system.Effective in April 2012 the GTN system offers long-term firm
backhaul services.Fees for utilizing this service will be provided under the existing Firm Rate Schedule
(FTS-1)and currently no fuel charges will be assessed.Additional requests for firm backhaul service may
necessitate the need for additional facilities and compression (i.e.fuel).
This service has the potential to be a particularly interesting solution for our Oregon customers.For example,
Avista can purchase supplies at Maim,Ore.and transport those supplies to our service territory at either
Klamath Falls or Medford.Maim-based natural gas supplies typically price at a premium to AECO supplies
but are generally less expensive than the cost of forward-haul transporting those traditional supplies and
paying the associated demand charges.The GTN system is a mileage-based system so we pay only a fraction
of the forward rate if it is transporting supplies from Malin to Medford and Kiamath Falls.The GTN system is
approximately 612 miles long and the distance from Maim to the Medford lateral is only about 12 miles.
NEW PIPELINE TRANSPORTATION
Additional firm pipeline transportation resources are viable and attractive resource options.However,
determining the appropriate level,supply source and associated pipeline path,costs and timing and
determining whether or not existing resources will be available at the appropriate time,make this resource
difficult to analyze.Firm pipeline capacity provides several advantages;it provides the ability to receive firm
supplies at the production basin,it provides for base-load demand and it can be a low-cost option given
optimization and capacity release opportunities.Pipeline capacity also has several drawbacks,including
typically long-dated contract requirements,limited need in the summer months (many pipelines require
annual contracts)and limited availability and/or inconvenient sizing/timing relative to resource need.
Pipeline expansions are typically more expensive than existing pipeline capacity and often require long-term
annual contracts.Even though expansions may be more expensive than existing capacity,this approach may
still provide the best option to us given that some of the other options discussed in this section require
matching pipeline transportation anyway.Expansions may also provide reliability or access to supply that
cannot otherwise be obtained through existing pipelines.
Several specific projects have been proposed for the region.The following summaries describe these projects
while Figure 5.3 illustrates their location:
5.10 II CHAPTER5 II SUPPLYSIDERESOURCES
II SUMAS i-S EXPANSION
NWP continues to explore options to expand its service from Sumas,WA to markets along the 1-5
corridor.Looping sections of 36-inch diameter pipeline with the existing pipeline and additional
compression at existing compressor stations can add incremental capacity.Actual miles of pipe and
incremental compression will determine the amount of capacity created,but can be scaled to meet
market demand.
ii BLUE BRIDGE/PALOMAR EXPANSION
NWP has begun working with Palomar Gas Transmission (a partnership between NW Natural and
TransCanada)to develop the Cascade (eastern)section of the previously proposed Palomar in
conjunction with an expansion of NWP’s existing system.The proposed 106-mile,30-inch-diameter
pipeline would extend from TransCanada’s GTN’s mainline,to NW Natural’s system near Molalla,
Ore.It would be a bi-directional pipeline with an initial capacity ofup to 300 MMcf/d expandable up
to 750 MMcf/d.
ii KINGSVALE-OLIVER REINFORCEMENT EXPANSION
Fortis,British Columbia and Spectra Energy are considering a 100-mile,24-inch expansion project
from Kingsvale to Oliver,British Columbia to expand service to the Pacific Northwest and California
markets.Removing constraints will allow expansion of Spectra’s T-South enhanced service offering,
which provides shippers the options of delivering to Sumas or the Kingsgate market.Expansion of
the bi-directional Southern Crossing system would increase capacity at Sumas during peak demand
periods.Initial capacity from the Spectra system to Kingsgate would be 300 MMcf/d,expandable to
450 MMcf/d.Expanded east-to-west flow will increase delivery of supply to Sumas by an additional
150 MMcf/d.
2012 Avista Natural Gas IRP II 5.11
Avista is supportive of proposals that bring supply diversity and reliability to the region.We actively engage
in discussions and analysis of the potential impact to Avista of each regional proposal from a demand serving
and reliability/supply diversity perspective.None of the above projects provide direct delivery connection to
any of our service territories.For Avista to consider them to be a viable incremental resource to meet demand
needs would require combining with additional capacity on existing pipeline resources.Given this situation
we did not model these specific projects.However we do model a generic NWP expansion that extends
beyond the proposed 1-5 expansion to Avista’s service territories.
IN-GROUND STORAGE
In-ground storage provides many advantages when gas from storage can be delivered to Avista’s service
territory city-gates.It can enable deliveries of natural gas to customers during cold weather events when they
need it most.It also facilitates potentially lower cost supply for our customers by capturing peak/non-peak
pricing differentials and potential arbitrage opportunities within individual months.Although additional
storage can be a valuable resource,without deliverability to Avista’s service territory,this storage cannot be
considered an incremental firm peak serving resource.
JACKSON PRAIRIE
Jackson Prairie is a potential resource for expansion opportunities.Any future storage expansion capacity
does not include transportation and therefore cannot be considered an incremental peak day resource.
However,we will continue to look for exchange and transportation release opportunities that could fully
utilize these additional resource options.Even without deliverability,we believe it can make financial sense to
utilize Jackson Prairie capacity to optimize time spreads within the natural gas market and provide net
revenue offsets to customer gas costs.There are no current plans for immediate expansion of Jackson Prairie.
Should those plans materialize Avista would evaluate its cost-effectiveness within the context of future IRP’s.
OTHER IN-GROTJTD STORAGE
Other regional storage facilities exist and may be cost-effective.Additional capacity at Northwest Natural’s
Mist facility,capacity at one of the Alberta area storage facilities,Questar’s Clay Basin facility in northeast
Utah,Ryckman Creek in Uinta County,Wyoming,and northern California storage are all possibilities.Again,
transportation to and from these facilities to Avista’s service territories continues to be the largest impediment
to contracting for these options.Northern California storage opportunities may be able to overcome this
hurdle by using backhaul transportation for deliveries to some of the Washingtonfldaho and Oregon
customers.Another issue is whether sellers of storage capacity will offer multi-year contracts or contracts
with beginning dates during the timeframes that we may need these incremental resources.
SATELLITE LNG
Satellite LNG is another storage option that could be constructed within Avista’s service territories and is
ideal for meeting peak day or cold weather events.Satellite LNG uses natural gas that is trucked to the
facilities in liquid form rather than liquefying on site.Locating the facility in the service area would avoid
interstate pipeline transportation and related charges.Permitting issues notwithstanding,facilities could be
located in optimal locations within the distribution system.
Estimates for this type of resource are somewhat varied because of sizing and location issues.For our
modeling,we have used estimates from other facilities constructed in the area and believe these to be
reasonable estimates for planning purposes.We will continue to monitor and refine the costs of developing
satellite LNG while remaining mindful of lead time requirements and environmental issues.
5.12 II CHAPTER5 II SUPPLYSIDERESOURCES
PLYMOUTH LNG
NWP owns and operates an LNG storage facility located at Plymouth,Washington,which provides a gas
liquefaction,storage,and vaporization service under its LS-1 and LS-2F tariffs.An example ratio of injection
and withdrawal rates are such that it can take more than 200 days to fill to capacity,but only 3-5 days to
empty.As such,the resource is best suited for needle-peak demands.Incremental transportation capacity to
our service territories would have to be obtained in order for it to be a truly effective peaking resource.
This peaking resource is fully contracted and not available for contracting at this time.Given this situation,
this option is not being modeled in SENDOUT®for this IRP.However,due to the fact that many of the
current capacity holders are on one-year rolling evergreen contracts,it is possible that this option will again
become viable in the future.
COMPANY OWNED LIQUEFACTION LNG
Instead of leasing LNG capacity from Plymouth,Avista could construct a liquefaction LNG facility within
our service area.Doing so could use excess transportation during off-peak periods to fill the facility but avoid
tying up transportation during peak weather events.Additional annual pipeline charges could probably be
avoided.
Construction would be dependent on regulatory and environmental approval as well as cost-effectiveness
requirements.Preliminary estimates of the construction,environmental,right of way,legal,operating and
maintenance,required lead times,and inventory costs indicate company-owned LNG facilities have
significant development risks.Due to these risks we did not include this resource in our modeling,
recognizing this type of project is highly complex and there are many risk considerations that require
evaluation and monitoring.
BIOGAS
Biogas typically refers to a gas produced by the biological breakdown of organic matter in the absence of
oxygen.One type of biogas is produced by anaerobic digestion or fennentation of biodegradable materials
such as biomass,manure or sewage,municipal waste,green waste and energy crops.This type of biogas
comprises primarily methane and carbon dioxide.
Biogas is a renewable fuel so it sometimes attracts renewable energy subsidies in some parts of the world.We
are not aware of any current subsidies but future stimulus or energy policies could lead to some form of
financial incentives at a later time.
Biogas projects are inherently individualized,making reasonable and reliable cost estimates difficult to
obtain.Project sponsorship has many complex issues and the more likely participation in such a project is as a
long-term contracted purchaser.We did not consider biogas as a resource in this planning cycle but remain
receptive to such projects as they are proposed.
SUPPLY SCENARIOS
For this IRP we modeled three supply scenarios.Table 5.2 lists the supply scenarios and Appendix 5.2
provides the details on what is included in each of these scenarios.Additional detail about the results of these
supply scenarios modeled is included in Chapters 6 and 7.
2012 Avista Natural Gas IRP II 5.13
Table 5.2
Supply Scenarios
Existing Resources
Existing +Expected Available
GTN Fully Subscribed
II EXISTING RESOURCES
Represents all resources currently owned or contracted by Avista.
II EXISTING +EXPECTED AVAILABLE
Existing resources plus supply resource options expected to be available when resource needs are
identified.This includes:currently available forward and backhaul GTN,capacity release recalls,
NWP expansions and satellite LNG.
ii GTN FULLY SUBSCRIBED
Availability of GTN capacity is unavailable due to significant contracting driven by increased
demand.
SUPPLY ISSUES
The importance of shale gas in the North American supply mix has fundamentally altered current and the
outlook of future natural gas prices and infrastructure.While it appears certain that North American supply is
in good shape there are issues that can impact the cost and availability.
II HYDRAULIC FRACTURING
“Fracking”has become the bad word of the natural gas and oil industry.Improvements in hydraulic
fracturing (HF),a sixty-year-old technique used to extract oil and natural gas from shale rock
formations,has enabled access to previously uneconomic resources.However,the process does not
come without its challenges.Movies and articles in the national newspapers have further fueled a
movement to cease this drilling practice.There is worry that HF is contaminating aquifers,
increasing air pollution,and most recently causing earthquakes.The wide spread publicity generated
interest in the production process and caused some states to issue bans or moratoriums on drilling
until further research was conducted.
To that end many levels of government,industry,and universities have or are engaged in conducting
studies to better understand the actual and potential impacts of HF.Industry has been working to
refute these claims by focusing on ensuring companies use “best practices”for well drilling,
disclosing the fluids used in the HF processing,and implementing “green completions”for wells.
The state governments are participating in independent audits of their regulations to ensure that
proper oversight is in place.The EPA is engaged in a study and will issue a report in late 2012 to
determine the effects of HF on water and air.Finally,the United States Geological Survey (USGS)
has begun to study the correlation between seismic activity and HF.The outcome of these audits,
studies,and further research could greatly impact both the cost and availability of natural gas and oil.
ii LNG -EXPORT IS THE NEW IMPORT
A few short years ago,North America was going to be reliant on importing LNG in order to fill the
supply and demand gap and the gas market was heading to a more global pricing structure.Now wide
5.14 II CHAPTER5 II SUPPLYSIDE RESOURCES
spread shale availability and low production costs have upended the US importing LNG industry.
Europe and Asia have prices that are more favorable so in an effort to maximize margins many import
facilities have petitioned to become exporters.
On a national level,in April 2012 Sabine Pass LNG was granted the authority by FERC to export 2.2
Bcf/d.Sabine Pass LNG is the first in the US to be granted permission,however there are many more
in the queue.Regionally,two proposed LNG terminals in Oregon,Jordan Cove LNG and Oregon
LNG are looking to export.In Canada,the National Energy Board (NEB)granted Kitimat LNG in
British Columbia a twenty year license to export LNG to serve international markets.When and
where this happens,how many,what volume and how our natural gas prices are affected are
continuing to be debated.
II GREEN TURNS TO BLUE
The desire to reduce reliance on fossil fuels,improve the carbon footprint,and lessen our need for
foreign oil sparked a flurry of legislative activity.State mandated renewable portfolio standards
(RPS),carbon taxes or cap and trade programs,and natural gas vehicles (NGV)became common
news.
RPS mandates required electric utilities to “green up”their portfolios.In many cases,this means
reducing reliance on coal and investing in renewable sources of energy such as wind,solar,and
nuclear.Wind and solar in particular became the resource of choice for most utilities,unfortunately
these are intermittent and would require reliable and controllable backup.Additional gas fired power
generation will be necessary to support the renewable fleet.
Helping to encourage the change to cleaner and greener energy was the concept of a carbon tax.This
would provide a means to make the cost of renewable on par with less expensive fossil fuels.There
were many different plans proposed on how to implement the additional costs.However,rapid
adoption of such legislation did not occur.As the depth of the recession began to be felt,legislators
realized burdening afready strapped taxpayers would be detrimental to an already fragile economy.
The economy is still healing,but that does not change the importance of reducing our carbon
footprint.There continues to be discussion about a carbon tax.The timing and magnitude of the tax
has been pushed out many years and is at a much lower level than originally proposed.
With oil prices surging and driving high gasoline prices,many are looking to reduce the nation’s need
for foreign oil.This push has renewed investments in NGV infrastructure.T.Boone Pickens and
Clean Energy are often in the headlines discussing how NOV can play an important role in the energy
and transportation future.Much of the transportation focus has been on long haul trucks and fleet
vehicles such as refuse trucks and public transportation.The cost to convert these vehicles is
significant,however many are making the switch.
II PIPELINE AVAILABiLITY
The pipeline infrastructure of the Northwest is sparse when compared to the Gulf or East Coast.As
we move closer and closer to a more renewable energy future demand for natural gas via gas-fired
generation will increase.Pipeline capacity is the link between gas and power.LDCs will have to
compete with power generators for pipeline capacity.The new mix could alter current pipeline
operations and the potential availability of infrastructure to the region.
2012 Avista Natural Gas IRP II 5.15
MARKET-RELATED RISKS AND RISK MANAGEMENT
While risk management can be defined in a variety ofways,the integrated resource plan focuses on two areas
of risk:the fmancial risk under which the cost to supply customers will be unreasonably high or unreasonably
volatile,and the physical risk that there may not be enough natural gas resources (either the transportation
capacity or the commodity)to serve core customers.
Avista has a Risk Management Policy that describes the policies and procedures associated with financial and
physical risk management.The Risk Management Policy addresses,among other things,issues related to
management oversight and responsibilities,internal reporting requirements,documentation and transaction
tracking,and credit risk.
There are two internal organizations that assist in the establishment,reporting and review of Avista’s business
activities as they relate to management ofnatural gas business risks:
ii The Risk Management Committee consists of several corporate officers and senior-level
management.The committee establishes the Risk Management Policy and monitors compliance.
They receive regular reports on natural gas activity and meet regularly to discuss market conditions,
hedging activity and other natural gas-related matters.
ii The Strategic Oversight Group exists to coordinate natural gas matters among internal natural gas-
related stakeholders and to serve as a reference/sounding board for strategic decisions,including
hedges,made by the Natural Gas Supply department.Members include representatives from the
Accounting,Regulatory,Credit,Power Resources and Risk Management departments.While the
Natural Gas Supply department is responsible for implementing hedge transactions,the Group
provides input and advice.
II ACTION ITEMS
With no immediate need to acquire incremental supply side resources to meet peak day demands Avista’s
focus in the near term will include the following:
ii Continue to monitor supply resource trends including the availability and price of natural gas to the
regions,exporting LNG,Canadian natural gas imports,regional plans for gas fired generation and its
affect on pipeline availability,as well as future regional pipeline and storage infrastructure plans.
ii We will also monitor new resource lead time requirements relative to when resources are needed to
preserve resource option flexibility.
II CONCLUSION
Avista is committed to providing reliable supplies of natural gas to its customers.We procure these supplies
with a diversified plan that seeks to competitively acquire natural gas supplies while reducing exposure to
short-term price volatility through a strategy that includes hedging,storage utilization and index purchases.
We have long-term contracts for firm pipeline transportation capacity from many supply points and also own
and lease firm natural gas storage capacity sufficient to serve customer demand during peak weather events
and throughout the year.
2012 Avism NATURALGASIRP II
CHAPTER 6—INTEGRATED RESOURCE PORTFOLIO
OVERVIEW
This chapter combines all previously discussed IRP components and the model used to determine resource
deficiencies during the 20-year planning horizon.This chapter also provides an analysis of potential resource
options and displays the model-selected best cost/risk resource options to meet resource deficiencies.
The foundation for integrated resource planning is the demand planning criteria used for developing demand
forecasts.Avista currently uses the “coldest day on record”as its weather planning standard for determining
peak-day demand.This is consistent with our past IRPs and is more fully described in Chapter 3 —Demand
Forecasts.We utilize historic peak and average weather data for each demand region for this IRP.We plan to
serve our expected peak day in each demand region with firm resources.Firm resources include natural gas
supplies,pipeline transportation and storage resources.In addition to planning for peak requirements,we also
plan for non-peak periods such as winter,shoulder and summer demand.Our modeling process includes
running an optimization for every day of the 20-year planning period.
It is assumed that on a peak day all interruptible customers have left the system in order to provide service to
firm customers.Avista does not make firm commitments to serve interruptible customers.Therefore,our IRP
analysis of demand-serving capabilities only focuses on the residential,commercial and firm industrial
classes.
Our supply forecasts are increased between 1.0 percent and 3.0 percent on both an annual and peak-day basis
to account for additional supplies that are purchased primarily for pipeline compressor station fuel.The
percentage of additional supply that must be purchased is governed through FERC and National Energy
Board approved tariffs.
SENDOUT®PLANNING MODEL
The SENDOUT®Gas Planning System from Ventyx is used to perform integrated resource optimization.The
SENDOUT®model was purchased in April 1992 and has been used in preparing all IRPs since then.Avista
has a long-term maintenance agreement with Ventyx that allows us to receive software updates and
enhancements.These enhancements include software corrections and improvements brought on by industry
change.
SENDOUT®is a linear programming model widely used to solve natural gas supply and transportation
optimization questions.Linear programming is a proven technique used to solve minimization/maximization
problems.SENDOUT®looks at the complete problem at one time within the study horizon,while taking into
account physical limitations and contractual constraints
The software analyzes thousands of variables and evaluates possible solutions to generate a least cost
solution.The model uses the following variables:
ii Demand data,such as customer count forecasts and demand coefficients by customer
type (e.g.residential,commercial and industrial)
ii Weather data —minimum,maximum and average temperatures
ii Existing and potential transportation data which describes to the model the network for
the physical movement of the natural gas and associated pipeline costs
6.2 II CHAPTER 6 II INTEGRATED RESOURCE PORTFOLIO
ii Existing and potential supply options including supply basins,revenue requirements as
the key cost metric for all asset additions,and prices
ii Natural gas storage options with injectionlwithdrawal rates,capacities and costs
ii DSM potential
Figure 6.1 is a SENDOUT®network diagram of our demand centers and resources.This diagram illustrates
Avista’s current transportation and storage assets,flow paths and constraint points.
FIGuRE 6.1 SENDOUT®MODEL DIAGRAM
The SENDOUT®model also provides a flexible tool to analyze potential scenarios such as:
ii Pipeline capacity needs and capacity releases
ii Effects of different weather patterns upon demand
ii Effects of natural gas price increases upon total natural gas costs
ii Storage optimization studies
ii Resource mix analysis for DSM
ii Weather pattern testing and analysis
ii Transportation cost analysis
2O12AVISTANATURALGASIRP II 6.3
ii Avoided cost calculations
ii Short-term planning comparisons
SENDOUT®also includes Monte Carlo capabilities,which facilitates price and demand uncertainty modeling
and detailed portfolio optimization techniques to produce probability distributions.More information and
analytical results are located in Chapter 7 —Alternate Scenarios,Portfolios and Stochastic Analysis.
RESOURCE INTEGRATION
We have defined the planning methodologies,described the modeling tools and identified the existing and
potential resources.The following summarizes the comprehensive analysis of bringing demand forecasting
and existing and potential supply and demand-side resources together to form our 20-year,risk adjusted least-
cost plan.
DEMAND FORECASTING
Avista’s demand forecasting approach is described in detail in the Chapter 3 -Demand Forecasts.
We forecast demand in the SENDOUT®model in eight service areas given the existence of distinct weather
and demand patterns for each area and pipeline infrastructure dynamics.The SENDOUT®areas are
Washingtonlldaho (disaggregated into three sub-areas because of pipeline flow limitations),Medford
(disaggregated into two sub-areas because ofpipeline flow limitations)and Roseburg,Klamath Falls and La
Grande.In addition to area distinction,we also model demand by customer class within each area.The
relevant customer classes in Avista’s service territories are residential,commercial and firm industrial
customers.
Customer demand reflects a highly weather-sensitive component.Avista’s customer demand is not only
highly seasonable but also highly variable.Figure 6.2 captures this variability showing our monthly system-
wide average demand,minimum demand day observed in each month,and maximum demand day observed
in each month,and our winter projected peak day demand for the first year of our Expected Case forecast as
determined in SENDOUT®.
6.4 II CHAPTER 6 II INTEGRATED RESOURCE PORTFOLIO
NATURAL GAS PRICE FORECASTS
Natural gas prices are a fundamental component of the IRP.The commodity price is a significant component
of the total cost of a resource option.This in turn affects the avoided cost threshold for determining cost-
effectiveness of conservation measures.We also recognize the price of natural gas influences consumption,so
we include price elasticity analysis in our demand evaluation (see Chapter 3 —Demand Forecasts).
The natural gas price outlook has changed dramatically in recent years in response to several influential
events and trends affecting the industry.The recession,shale gas production and potential climate change
legislation encouraging natural gas-fired power generation to replace coal burning power plants.Due to the
rapidly changing environment and uncertainty in predicting future events and trends,modeling a range of
forecasts is necessary.
Many additional factors influence natural gas pricing and volatility,such as regional supply/demand issues,
weather conditions,hurricanes/storms,storage levels,gas-fired generation,infrastructure disruptions and
infrastructure additions (e.g.new pipelines,LNG terminals).
Even though we continually monitor these factors,we cannot accurately predict future prices for the 20-year
horizon of this IRP.We have reviewed several price forecasts from credible sources.Figure 6.3 depicts the
price forecasts we considered in our analyses.
Figure 6.2 Total System Average Daily Load
Dth/Day (Average/Mininum/Maximum)
350,000
300,000
250,000
200,000
150,000
100,000
50,000
7,7,7,\“•7,7,7,
(OC
Average Load —.—Minimum Load ——Maximum Load Peak Day
2O12AVISTANATURALGASIRP II 6.5
Selecting the price curves can be more art than science.With assistance and concurrence of the TAC we
selected high,expected and low price curves to consider possible outcomes and the impact on resource
planning.The price curves we have selected have variation and provide reasonable upper and lower bounds,
which is consistent with our theme of stretching modeling assumptions to address uncertainty in the planning
environment.These curves are shown in real dollars in Figure 6.4 and nominal dollars in Figure 6.5.
Additionally,stochastic modeling of natural gas prices is also completed.The results from that analysis are
shown in Chapter 7 —Alternate Scenarios,Portfolios,and Stochastic Analysis.
Figure 6.3 Henry Hub Forecasted Price
$/Dth (Real $per Dth)
12
10-
8 --—-—_____
__________
6----——
4
2-
—Consultant 1 —Consultant 2
0 -----.—-——---—------—.—---—----—----------—.——---—----.--—----——------———
2O 20 2O6 2O 202.0 2022 2o2 2026 2o2 2c 2032 2o3
AEO —NPCC Low —NPCC Medium NPCC High NYMEX 9FEB
6.6 II CHAPTER 6 II INTEGRATED RESOURCE PORTFOLIO
Figure 6.4 Low/Medium/High Forecasted Price
$/Dth (Real$perDth)
$12.00
$10.00
$8.00 -______________________________________________
______________
::::
$2.00 —-—---——_________
_______________________
$---..--.--.--..-——
__________
..-——-—-.--
_________________________________
—
20 $3 20 20’2.0’’20”20’20 2020 2022 202 2o2 2o2 2o2’2021 202 2o0
NPCC Low NPCC High —Consulti Blend
Figure 6.5 Low/Medium/High Forecasted Price
$/Dth (Nominal $per Dth)
$16.00 ----—---.——----———__._
_______________
$14.00 --—---.--------------—--.-.—------------.----.———.—------——--------—--
$12.00 .-.---—---—--—--
_______
—
E
_________________
$200 ---
_____________________
—--.-—---.----..-
$---------..--------
------------.----..--.---.--.---.----
202 20 20 20 20 201 20 20 2020 202 2022 2023 202 202’2026 2021 202S 20 2030 203
—NPCC Low NPCC High —Consulti Blend
2012AvsTANATuRALGAslRP II 6.7
Each of the price forecasts above are for Henry Hub,which is located in Louisiana just onshore from the Gulf
ofMexico.Henry Hub is widely recognized as the most important pricing point in the U.S.because of its
proximity to a large portion of U.S.natural gas production and the sheer volume traded in the daily or spot
market as well as the forward markets via the New York Mercantile Exchange’s (NYMEX)futures contracts.
Consequently,all other trading points tend to be priced off of the Henry Hub.
The primary physical supply points at Sumas,AECO,and the Rockies (and other secondary regional market
hubs)ultimately determine Avista’s costs.Prices at these points typically trade at a discount or negative basis
differential to Henry Hub primarily because of their relative close proximity to the two largest natural gas
basins in North America (the WCSB and the Rockies).
Table 6.1 shows the Pacific Northwest regional prices from our consultants,historic averages,and the prior
IRP as a percent of Henry Hub price along with historical comparisons.
Table 6.1 Regional Price as a Percent of Henry Hub Price
AECO Sumas Rockies Maim Stanfield
Consultanti
Forecast Average 88.60%89.90%90.80%92.30%91.40%
Consultant2
Forecast Average 86.20%92.50%92.80%94.10%92.60%
Historic Cash
Three-Year Average 89.90%95.50%88.10%97.00%95.60%
Prior IRP 92.70%95.20%85.60%94.10%93.70%
This IRP used monthly prices for modeling purposes because of our heavily winter-weighted demand profile.
Table 6.2 depicts the monthly price shape we used in this IRP.A slight change to the shape of the pricing
curve has occurred since the last IRP.Driven primarily by supply availability,the forecasted differential
between winter and summer pricing has come in to some extent when compared to historic data.
Table 6.2 Monthly Price as a Percent of Average Price
Jan Feb Mar Apr May Jun
Consulti 101%101%98%98%98%100%
Consult2 103%102%99%98%99%101%
Historic First of Month Index
Three-Year Average 130%113%101%94%96%96%
Prior IRP 107%108%103%93%93%94%
Jul Aug Sep Oct Nov Dec
Consulti 102%103%100%100%100%102%
Consult2 101%101%97%97%98%104%
Historic First of Month Index
Three-Year Average 104%100%84%93%92%97%
Prior IRP 94%94%95%96%101%106%
6.8 II CHAPTER 6 II INTEGRATED RESOURCE PORTFOLIO
Consistent with our selection for Henry Hub prices,we selected Consultant l’s forecast of regional prices and
monthly shape.Appendix 6.1 contains detailed monthly price data behind the summary table information
discussed above.
TRANSPORTATION AND STORAGE
Valuing natural gas supplies is a critical first step in resource integration.Equally important is capturing all
costs to deliver the gas to the customer.Daily capacity of our existing transportation resources (described in
Chapter 5 —Supply-Side Resources)is represented by the firm resource duration curves depicted in Figures
6.6 and 6.7.
Figure 6.6 Existing Firm Transportation Resources
MDth WA/ID
500
450
400
350
300
250
200
150
100
50
0
1 31 61 91 121 151 181 211 241 271 301 331 361
Day of Year
2O12AVISTANATURALGASIRP II 6.9
Current rates for capacity are in Appendix 5.1.Forecasting future pipeline rates can be a challenge as we need
to estimate the amount and timing of rate changes.Our estimates and timing of future rate increases are based
on knowledge obtained from industry discussions and participation in various pipeline rate cases.This IRP
assumes that pipelines will file to recover costs at rates equal to increases in GDP (see Appendix 6.2 —
General Assumptions).
DEMAND-SIDE MANAGEMENT
Chapter 4—Demand-side Resources describes the methodology used to identify conservation potential and
the interactive process deployed in SENDOUT®that computes avoided cost thresholds for determining cost
effectiveness of conservation measures on an equivalent basis with supply-side resources.
PRELIMINARY RESULTS
After incorporating the above data into the SENDOUT®model,we then generate an assessment of demand
compared to existing resources for several scenarios.The demand results from these cases are discussed in
Chapter 3 —Demand Forecasts,with additional details supported in the Appendices 3.1 through 3.10.
Figures 6.8 through 6.11 graphically represent summaries of Average Case demand compared to existing
resources.This demand is net of DSM savings and shows the adequacy of our resources under normal
weather conditions.For this case,current resources meet our demand needs over the planning horizon.
Figure 6.7 Existing Firm Transportation ResourcesMDthOR
200
180
160
140
120
100
80
60
40
20
0
1 31 61 91 121 151 181 211 241 271 301 331 361
Day of Year
6.10 II CHAPTER 6 II INTEGRATED RESOURCE PORTFOLIO
Figure 6.8 Average Case -WA/ID Existing Resources vs.Average Day Demand
Dth (Net of DSM)
February400,000
350,000
300,000 ---
250,000 -
200,000 -
150,000 -
100,000 -
50,000 -
0
9,‘o 9,o “,,,
Existing GTN Existing NWP Spokane Supply —4—Average Day Demand
Figure 6.9 Average Case -Medford/Roseburg Existing Resources vs.Average Day Demand
Dth (Net of DSM)
December
120,000
100,000
80,000
60,000
40,000
20,000
0
I ———————————_——————_I
IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII!PII!!I
IiiiiiIIIIIIIIIIIIIII
[HIll II U HIll HUll
9,,,0 ‘\‘b °i N-9,o 0)
Existing NWP Existing GTN —4—Average Day Demand
2O12AvISTANATuRALGA5IRP II 6.11
Figures 6.12 through 6.15 graphically represent summaries of Expected Case peak day demand compared to
existing resources,as well as demand comparisons to our prior IRP.This demand is net of DSM savings.This
comparison shows by service territory the amount and timing of deficits over the planning horizon.
Figure 6.10 Average Case -Klamath Falls Existing Resources vs.Average Day Demand
(Net of DSM)Dth December
22,000
20,000
18,000
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
‘,“i,(0 0Q C)C (0
,
Kiamath Lateral Exisiting GTN ——Average Day Demand
Figure 6.11 Average Case -La Grande Existing Resources vs.Average Day Demand
(Net of DSM)
Dth Febraury
10,000
9,000
8,000
7,000
6,000
5,000
4,000 ••S S •.
____
3,000
2,000
1,000
0 I I I I I I I I I I I I
I,,
Existing NWP —.—Average Day Demand
6.12 II CHAPTER 6 II INTEGRATED RESOURCE PORTFOLIO
Figure 6.12 Expected Case -WA/ID Existing Resources vs.Peak Day Demand
(Net of DSM)
Dth FEB15
400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
0
Existing GTN Existing NWP 1 Spokane Supply —--Peak Day Demand —o-—Prior IRP Peak Day Demand
Figure 6.13 Expected Case -Medford/Roseburg Existing Resources vs.Peak Day Demand
Dth (Net of DSM)
DEC20
120,000
Prior Short Current Short
100,000
80,000
60,000 ::
40,000 .
20,000
0
Existing NWP Existing GTN ——Peak Day Demand —a--Prior IRP Peak Day Demand
2O12AvIsTANATuRALGA5IRP II 6.13
.PriorShort Current—
Short
-—-——-——--r -.--—--—---
.--—-——-—-—-——-----r ---
These charts show that when resource shortages occur they are well into the future.In the Expected Case for
Washington and Idaho,the system first becomes unserved in 2030.In Oregon,the first unserved year is in
MedfordlRoseburg in 2029 followed by Klamath Falls in 2030.The La Grande service territory does not go
unserved at any time during the 20-year planning horizon.This surplus resource situation provides ample time
to carefully monitor,plan and act on potential resource additions.
I-
Figure 6.14 Expected Case -Kiamath Falls Existing Resources vs.Peak Day Demand
Dth (Net of DSM)
22,000 DEC 20
20,000
18,000
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0 I I I I —I I I I I 1 —I
c .‘.“,.<,(o ‘.
f ,9 ###
Kiamath Lateral Existing GTN ——Peak Day Demand Prior IRP Peak Day Demand
Figure 6.15 Expected Case -La Grande Existing Resources vs.Peak Day Demand
Dth (Net of DSM)
FEB 15
10,000
9,000
8,000
7,000
6,000
5,000
4,000
3,000
2,000
1,000
0
Existing NWP —I-—Peak Day Demand —Prior IRP Peak Day Demand
6.14 II CHAPTER 6 II INTEGRATED RESOURCE PORTFOLIO
However,an important risk with respect to identified capacity shortages is the slope of forecasted demand
growth which is almost flat.However,if demand accelerates the need for additional resources will also
accelerate by several years.This “flat demand risk”necessitates close monitoring of signs of accelerating
demand and careful evaluation of lead times to acquire preferred incremental resources.
Table 6.3 quantifies the forecasted total demand (net of DSM savings)and unserved demand from the above
charts,identifying the amount of deficiencies by region and growth in deficiencies over time.The next step is
to determine the best risk/least cost resources to satisfy these deficiencies.
Table 6.3 Peak Day Demand —Served and Unserved (MDthId)
Before Resource Additions &Net of DSM Savings
Gas Grande Grande
Case Year Served Unserved
Expected 2012 7.23
Expected 2013 7.31
Expected 2014 7.20
Expected 2015 7.23
Expected 2016 7.29
Expected 2017 7.36
Expected 2018 7.42
Expected 2019 7.46
Expected 2020 7.50
Expected 2021 7.56
Expected 2022 7.58
Expected 2023 7.61
Expected 2024 7.64
Expected 2025 7.67
Expected 2026 7.70
Expected 2027 7.73
Expected 2028 7.76
Expected 2029 7.80
Expected 2030 7.83
Expected 2031 7.86
La La La LaGrande WA)lD
Grande %of Peak WA/ID WA/ID WA/ID %of Peak
________
Total Day Served Served Unserved Total Day Served
7.23 100%253.37 -253.37 100%
7.31 100%257.65 -257.65 100%
7.20 100%255.77 -255.77 100%
7.23 100%258.58 -258.58 100%
7.29 100%262.92 -262.92 100%
7.36 100%267.56 -267.56 100%
7.42 100%272.04 -272.04 100%
7.46 100%275.59 -275.59 100%
7.50 100%279.39 -279.39 100%
7.56 100%283.59 -283.59 100%
7.58 100%286.78 -286.78 100%
7.61 100%289.92 -289.92 100%
7.64 100%293.46 -293.46 100%
7.67 100%296.78 -296.78 100%
7.70 100%300.44 -300.44 100%
7.73 100%303.38 -303.38 100%
7.76 100%306.66 -306.66 100%
7.80 100%309.85 -309.85 100%
7.83 100%311.74 1.25 312.99 100%
7.86 100%311.74 4.38 316.12 98.6%
Kiamath Medford/
Kiamath Klamath Kiamath Falls %of Medford/Medford/Medford/Roseburg %
Gas Falls Falls Falls Peak Day Roseburg Roseburg Roseburg of Peak Day
Case Year Served Unserved Total Served Served Unserved Total Served
Expected 2012 12.69 -12.69 100%67.91 -67.91 100%
Expected 2013 12.83 -12.83 100%68.59 -68.59 100%
Expected 2014 12.68 -12.68 100%67.90 -67.90 100%
Expected 2015 12.79 -12.79 100%68.66 -68.66 100%
Expected 2016 13.00 -13.00 100%69.98 -69.98 100%
Expected 2017 13.21 -13.21 100%71.41 -71.41 100%
Expected 2018 13.40 -13.40 100%72.81 -72.81 100%
Expected 2019 13.55 -13.55 100%73.94 -73.94 100%
Expected 2020 13.70 -13.70 100%75.13 -75.13 100%
Expected 2021 13.88 -13.88 100%76.42 -76.42 100%
Expected 2022 14.01 -14.01 100%77.53 -77.53 100%
Expected 2023 14.13 -14.13 100%78.49 -78.49 100%
Expected 2024 14.27 -14.27 100%79.60 -79.60 100%
Expected 2025 14.40 -14.40 100%80.65 -80.65 100%
Expected 2026 14.54 -14.54 100%81.80 -81.80 100%
Expected 2027 14.65 -14.65 100%82.76 -82.76 100%
Expected 2028 14.78 -14.78 100%83.79 -83.79 100%
Expected 2029 14.91 -14.91 100%84.09 0.60 84.69 99.3%
Expected 2030 15.00 0.02 15.02 99.9%84.08 1.46 85.54 98.3%
Expected 2031 15.00 0.14 15.14 99.1%84.09 2.41 86.50 97.2%
2O12AvIsTANATuRALGA5IRP II 6.15
NEW RESOURCE OPTIONS
When existing resources are not sufficient to meet expected demand,there are many considerations that are
important in determining the appropriateness of potential resources.
RESOURCE COST
Resource cost is the primary consideration when evaluating resource options although other factors mentioned
below also influence resource decisions.We have found that newly constructed resources are typically more
expensive than existing resources but existing resources are in shorter supply.Newly constructed resources
provided by a third party,such as a pipeline,may require a significant contractual commitment.Newly
constructed resources are often less expensive per unit if a larger facility is constructed,because of economies
of scale.
LEAD TIME REQUIREMENTS
New resource options can take from one to five or more years to put in service.Open season processes,
planning and permitting,environmental review,design,construction and testing are some of the aspects
contributing to lead time requirements for new physical facilities.Recalls of released pipeline capacity
typically require advance notice of up to a year.Even DSM programs require significant time from program
development and rollout to the point when natural gas savings are realized.
PEAK VERSUS BASE LOAD
Our planning efforts include the ability to serve a peak day as well as all other demand periods.Avista’s core
loads are considerably higher in the winter than the summer.Due to the winter-peaking nature of Avista’s
demand,resources that cost-effectively serve the winter without an associated summer commitment may be
preferable.Alternatively,it is possible that the costs of a winter-only resource may exceed the cost of annual
resources after capacity release or optimization opportunities are considered.
RESOURCE USEFULNESS
It is paramount that an available resource effectively delivers natural gas to the intended geographical region.
Given Avista’s unique service territories it is often impossible to deliver resources from a resource option
such as storage without acquiring additional pipeline transportation.Pairing together resources increases the
cost.Other key factors that can contribute to the usefulness of a resource are viability and reliability.If the
potential resource is either not available currently (e.g.,new technology)or not reliable on a peak day (e.g.,
firm)then may not be considered as an option for meeting unserved demand.
“LUMPINESS”OF RESOURCE OPTIONS
Newly constructed resource options are often “lumpy.”This means that new resources may only be available
in larger-than-needed quantities and only available every few years.This lumpiness of resources is driven by
the cost dynamics of new construction,the fact that lower unit costs are available with larger expansions and
the economics of expansion of existing pipelines or the construction of new resources dictate additions
infrequently.Lumpiness provides a cushion for future growth.Given the economies of scale for pipeline
construction,we are afforded the opportunity to secure resources to serve future demand increases.
COMPETITION
LDCs,end-users and marketers all compete for regional resources.The Northwest has been particularly
efficient in the utilization of existing resources,which means the system is neither overbuilt nor under built.
6.16 II CHAPTER 6 II INTEGRATED RESOURCE PORTFOLIO
Currently,the region is able to sufficiently handle the demand needs of varying parties.However,the future
needs vary and regional LDCs may find they are competing with each other and other parties in order to
secure firm resources for customers.
RISKS AND UNCERTAINTIES
Investigation,identification and assessment of risks and uncertainties are critical considerations when
evaluating supply resource options.For example,resource costs determinations are subject to various degrees
of estimation,partly influenced by the expected timeframe of the resource need and degree of rigor
determining estimates or estimation difficulties because of the uniqueness of a resource.Lead times can have
varying degrees of certainty ranging from securing currently available transport (high certainty)to building in
service territory underground storage (low certainty).
RESOURCE SELECTION
After identifying supply-side resource options and evaluating them based on the above considerations,we
entered these supply-side scenarios (see Table 5.2)along with conservation measures (see Chapter 4 -
Demand-side Resources)into the SENDOUT®model for it to select the least cost approach to meeting
resource deficiencies.SENDOUT®compares demand-side and supply-side resources (see Appendix 6.3 for a
list of supply-side resource options)using PVRR analysis to determine which resource is the best risk
adjusted/least cost resource.
DEMAND-SIDE RESOURCES
AVOIDED COST
The SENDOUT®model determined avoided cost figures represent the unit cost to serve the next unit of
demand with a supply-side resource option during a given period.If a conservation measure’s total resource
cost is less than this avoided cost,it will cost effectively reduce customer demand and Avista can “avoid”
possible commodity,storage,transportation and other supply resource costs.
SENDOUT®calculates marginal cost data by day,month and year for each demand area.A summarized
graphical depiction of avoided annual and winter costs for the Washington/Idaho and Oregon areas is in
Figure 6.16.The detailed data is presented in Appendix 6.4.The avoided costs do not include environmental
externality adders to monetarily recognize adverse environmental impacts.Appendix 4.2 discusses this
concept more fully and includes specific requirements required in our Oregon service territory.
2O12AVISTANATURALGASIRP II 6.17
$/Dth
$6.00
$5.00
$4.00
$3.00
$2.00
Figure 6.16 Avoided Costs
Includes Commodity and Tansp.Cost,exiudes Env.Externalies
2010$/Dth
$1.00 ——---——-----—---——----—--—
_____
$0.00 -—-—-----—-—--.--—----——--—----——-—-------—-.-.—-——----
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
SELECTED MEASURES
‘WA/ID Annual -2012 —OR Annual -2012 —WA/ID Winter -2012 —OR Winter -2012
Using the above avoided cost thresholds;SENDOUT®selected all DSM potential.Table 6.4 details the
potential DSM savings in each region from the selected conservation potential for our Expected Case.
6.18 II CHAPTER 6 II INTEGRATED RESOURCE PORTFOLIO
Table 6.4 Annual,Annual Average and Peak Day Demand Served by DSM
Daily
Daily Peak Day Annual Medfordi Peak Day
Annual Daily Peak Day Annual LaGrande LaGrande Medtordl Roseburg Medfordl
Kiamath KJamathDSM KiamathOSM La&ande DSM DSM i,seburg DSM Roseburg
Case Gas Year OSM (0th)(0th/day)(0th/day)DSM (0th)(0th/day)(Dthlday)OSM (0th)(Dthlday)DSM (Dthlday)
Expected 2012 3.804 0.010 0.041 1.125 0.003 0.017 17.318 0.047 0.218
Expected 2013 9 197 0.025 0.085 3.762 0.010 0.036 39691 0.109 0.456
Expected 2014 17.066 0.047 0.152 7.479 0.020 0.064 73.108 0.200 0.797
Expected 2015 28448 0.078 0.249 12.841 0.035 0.104 121 001 0.332 1.295
Expected 2016 43.646 0.120 0.377 19.585 0.054 0.157 184.206 0.505 1.938
Expected 2017 61 501 0.168 0.530 27.493 0.075 0.221 258.310 0.708 2.703
Expected 2018 80.223 0.220 0.690 35.789 0.098 0.286 336.087 0.921 3.517
Expected 2019 98.644 0.270 0.853 43.949 0.120 0.354 412.643 1.131 4.334
Expected 2020 117.151 0.321 1.015 52.118 0.143 0.421 489.317 1.341 5.158
Expected 2021 127 102 0 348 1.111 56567 0.155 0.460 531.201 1,455 5.649
Expected 2022 137.231 0.376 1.205 61.086 0.167 0.499 573.753 1.572 6.132
Expected 2023 148.183 0.406 1.308 65.943 0.181 0.542 619.449 1.697 6.663
Expected 2024 162.586 0.445 1.442 72.437 0.198 0.597 680.881 1.865 7.362
Expected 2025 175.765 0482 1.567 78308 0.215 0.651 736.135 2.017 8025
Expected 2026 189.001 0.518 1.691 84.187 0.231 0.701 791.406 2.168 8.633
Expected 2027 200.574 0550 1.788 89.385 0.245 0.743 840.303 2.302 9160
Expected 2028 212.097 0.581 1.881 94.588 0.259 0.783 889.359 2.437 9.620
Expected 2029 221.425 0.607 1.962 98.711 0.270 0.817 927.903 2.542 10.060
Expected 2030 231.638 0.635 2.050 103.227 0.283 0.853 970.169 2.658 10.492
Expected 2031 242,347 0.664 2.141 107.971 0.296 0.890 1,014.565 2.780 10.937
Annual Peak Day
Annual Daily Peak Day Annual Daily Peak Day Total Daily Total Total
Oregon Oregon DSM Oregon DSM WAIID WA/ID DSM WAIIDDSM System DSM System DSM System DSM
Case Gas Year OSM (0th)(Dthlday)(0th/day)DSM (0th)(0th/day)(0th/day)(0th)(0th/day)(Dthlday)
Expected 2012 22.247 0.061 0.275 116.058 0.318 1.198 138.305 0.379 1.474
Expected 2013 52.650 0.144 0.577 244.960 0.671 2.432 297 610 0.815 3.009
Expected 2014 97.653 0.268 1.013 425.533 1.166 4.149 523.186 1.433 5.162
Expected 2015 162.291 0.445 1.64.8 631.464 1.730 5.994 793.755 2.175 7.642
Expected 2016 247.438 0.678 2.472 869.181 2.381 7.975 1,116.619 3.059 10.447
Expected 2017 347.304 0952 3.454 1,102.398 3.020 10.193 1,449 702 3972 13647
Expected 2018 452.098 1.239 4.493 1,333.820 3.654 12.440 1,785.918 4.893 16.934
Expected 2019 555.236 1.521 5.540 1,570 968 4304 14837 2,126.204 5825 20.377
Expected 2020 658.587 1.804 6.594 1,818,742 4.983 17.303 2,477.328 6.787 23.897
Expected 2021 714.870 1 959 7.220 2,060 492 5645 19892 2.775.361 7.604 27.112
Expected 2022 772.070 2.115 7.836 2,260.822 6.194 21.888 3,032.892 8.309 29.724
Expected 2023 833.575 2.284 8.513 2,453.430 6.722 23.941 3.287.005 9.005 32.454
Expected 2024 915.904 2.509 9.402 2,661.143 7.291 25.837 3,577.047 9.800 35.240
Expected 2025 990.208 2.713 10243 2,855 741 7.824 27887 3,845 949 10537 38.130
Expected 2026 1,064.594 2.917 11.025 3,052.666 8.363 29.847 4,117.260 11.280 40.872
Expected 2027 1,130.262 3.097 11692 3,251.635 8.909 31865 4,381898 12005 43.556
Expected 2028 1,196.045 3.277 12.284 3,469.294 9.505 33.928 4,665.338 12.782 46.212
Expected 2029 1,248.039 3.419 12.839 3,617.612 9.911 35500 4,865.651 13.331 48339
Expected 2030 1,305.035 3.575 13.395 3,779.664 10.355 36.994 5,084.699 13.931 50.390
Expected 2031 1.364 884 3.739 13.968 3.928 219 10.762 38.536 5.293.102 14.502 52.504
DSM ACQUISITION GOALS
The avoided cost established in SENDOUT®,the demand-side potential selected and the resulting calculated
therm savings is the basis for determining DSM acquisition goals and subsequent program implementation
planning.While the model selected essentially all DSM potential,the subsequent business planning process
yielded different results.Chapter 4 —Demand-Side Resources has additional details on this process.
2O12AVISTANATURALGASIRP II 6.19
SUPPLY-SIDE RESOURCES
SENDOUT®considered all options entered into the model,determined when and what resources were needed
and rejected options that were determined to not be cost effective.These selected resources represent the least
cost solution,within given constraints,to serve anticipated customer requirements.Table 6.5 shows the
SENDOUT®selected supply-side resources for the Expected Case.
Table 6.5 Supply Side Resource Selected in SENDOUT®
Case Additional Resources Jurisdiction Size Cost/Rates Availability Notes
Expected Case
GTN Capacity WA/ID 25,000 GTN rate Currently Currently available unsubscribed capacity.
Dth/d
GTN Medford l.ateral Expansion OR 10,000 GTN rate 2014 Additional compression to allow more gas to flow
Dth/d from GTN mainline to the lateral.
MaIm Backhaul OR 10,000 GTN rate Currently Backhaul capacity is provided by tarrif.In order to
Dth/d facilitate additional deliveries to our OR properties
an expansion of the Medford Lateral is necessary.
Klamath Falls Lateral Purchase OR 15,000 NetBookValue 12/31/2012 PurchaseoftheNWP Klamath Falls Lateral.This was
Dth/d the perferred resource identified in the 2009 IRP.
GTN Capacity OR 2,000 GIN rate Currently Currently available unsubscribed capacity.
Dth/d
With additional research and investigation,we may later determine that alternative resources are more cost
effective than those resources selected in this IRP.Since resource additions are not anticipated until late in the
planning horizon,we will continue to review and refine knowledge of resource options and will act to secure
these best cost/risk options when necessary or advantageous.
RESOURCE SELECTION RESULTS
Figures 6.17 through 6.19 summarize modeling results when comparing regional peak day demand against
existing and incremental resources for the Expected Case over the 20-year planning period.
6.20 II CHAPTER 6 II INTEGRATED RESOURCE PORTFOLIO
Dth
400,000 -
350,000 -—
300,000 -—
Figure 6.17-Expected Case -WA/ID Selected Resources vs.Peak Day Demand
(Net of DSM)
FEB15
Current Short
250,000 -—
200,000
150,000
100,000
50,000
0 iii IIIIiIIIIIiiii1 ii
0 ‘00
Existing GTN Existing NWP Spokane Supply GTN Capacity Add —.—Peak Day Demand
-tI
t’
I I
Figure 6.18-Expected Case -Medford/Roseburg Selected Resources vs.Peak Day Demand
(Net of DSM)
DEC20Dth
120,000
100,000
80,000
60,000
40,000
20,000
0
Current
Short
GTN Capacity Add Existing NWP ExistingGTN —.—Peak Day Demand
2O12AvI5TANATuRALGAsIRP II 6.21
Current
Short
—-,—-•—.1 —I —
As indicated in the figures,after DSM savings the model shows a general preference for incremental
transportation resources from existing pipelines and supply basins to resolve capacity deficiencies.
RESOURCE UTILIZATION
Our primary purpose is to meet our customer’s demand needs in a cost effective manner.As the
analysis indicates,we have ample resources to meet highly variable demand under multiple scenarios,
including peak weather events,for the foreseeable future.With primary needs addressed,utilization
of excess resource capacity is considered.There are many short term and long term opportunities to
utilize and capture value for our customers using these resources.Each year a comprehensive
evaluation of our demand forecasts and existing resource portfolio are reviewed.The following are
some examples of how resources can be utilized:
ii Serving interruptible demand
II Storage injections
ii Storage optimization
ii Capacity releases —short-term and long-term
ii Basin optimization
ii Transportation optimization
Dth
Figure 6.19-Expected Case -Kiamath Falls Selected Resourcesvs.Peak Day Demand
(Netof DSM)
DEC 2022000
20,000
18,000
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
Kiamath Lateral Existing GTN GTN Capacity Add ——Peak Day Demand
ii Intra and/or inter-seasonal optimization
6.22 II CHAPTER 6 II INTEGRATED RESOURCE PORTFOLIO
GATE STATION ANALYSIS
In previous IRP’s we identified a risk associated with our aggregated methodology for supply and demand
forecasting.Our forecasting methodology is consistent with operational practices which aggregate capacity at
individual points for scheduling/nomination purposes.Typically,the amount of natural gas that can flow from
a contract demand (CD)(i.e.receipt/supply quantity)is fixed and the amount that can be delivered (i.e.
maximum daily delivery obligation (MDDO)or delivery quantity)to various gate stations is greater.(See
Figure 6.20)However,aggregation could mask deficiencies at individual gate stations.
Figure 6.20 —Gate Station Modeling Challenge
In order to address this concern,a gate by gate analysis was developed outside of SENDOUT®.The analysis
involved coordination between Gas Supply,Gas Engineering,and intrastate pipeline personnel.Utilizing
historical gate station flow data and demand forecasting methodologies detailed in our IRP,forecasted peak
day gate station demand was calculated.This demand was then compared to contracted and operational
capacities at each gate station.
If forecasted demand exceeded contracted and/or operational capacities further analysis is completed.The
additional analysis would involve assessing the most economic way to address the gate deficiency.This
could involve a gate station expansion,re-assigning MDDO’s,targeted DSM,or distribution system
enhancements.
For example,the analysis identified a gate station on NWP’s Coeur d’Alene Lateral where forecasted peak
day demand exceeded both the gate station MDDO’s and physical capacity.Working together with all
parties,numerous solutions were examined.Current analysis indicates the optimal solution is to take
advantage of a pre-existing plan to build a new gate station at Chase Road off of GTN’s mainline (See
Chapter 8 for further details).The project originally was designed to alleviate capacity constraints at GTN’s
Rathdrum gate,however,the new gate’s location allows for the potential to displace gas on the NWP Coeur
d’Alene Lateral.
II ACTION ITEM
With no immediate need to acquire incremental supply side resources to meet peak day demands Avista’s
focus in the near term will include the following:
Contract Demand:10,000
Supply (Receipt Quantity)
MDDO’s:11,000
Gate Station (Delivery
Quantity)
Demand:8,000
Behind the Gate
10,000
II
II
I’I
2O12AVISTANATURALGASIRP II 6.23
ii Continuing to coordinate analytic efforts between Gas Supply,Gas Engineering,and the
intrastate pipelines to perform gate station analysis and if deficiencies are identified seek
least cost solutions.
II CONCLUSION
The integrated resource portfolio analysis process summarized in this chapter was first performed on our
Average Case and then on the Expected Case demand scenario.We have chosen to utilize the Expected Case
for our peak operational planning activities because this case is the most likely outcome given our experience,
industry knowledge and our understanding of future natural gas markets.This case provides for reasonable
demand growth given current expectations of natural gas prices over the planning horizon.If realized,this
case is at a level that allows us to be well protected against resource shortages and does not over commit to
additional long-term resources.
We fully recognize that there are numerous other potential outcomes.The process described in this chapter
was applied to alternate demand and supply resource scenarios,which is covered in the Chapter 7 —Alternate
Scenarios,Portfolios and Stochastic Analysis.
2012 AVISTA NATURAL GAS IRP II
CHAPTER 7 II ALTERNATE SCENARIOS,PORTFOLIOS AND
STOCHASTIC ANALYSIS
OVERVIEW
The integrated resource portfolio analysis process described in Chapter 6 was applied to several alternate
demand and supply resource scenarios to develop a sufficient range of possible alternate portfolios.This
deterministic modeling approach considered a host ofunderlying assumptions which were vetted with
significant discussion and recommendations from our TAC to develop a consensus number of cases to model
and analyze.
We also performed stochastic modeling for estimating probability distributions of potential outcomes by
allowing for random variation in natural gas prices and weather based on fluctuations observed in historical
data.This statistical analysis,in conjunction with our deterministic analysis,enabled us to statistically
quantify the risk from a reliability and cost perspective related to resource portfolios under varying price and
weather environments.
ALTERNATE DEMAND SCENARIOS
As discussed in the Demand Forecasting section,we have identified several alternate scenarios for detailed
analysis to capture a wide range of possible outcomes over the planning horizon.These scenarios are
summarized in Table 7.1 and are described in detail in the Chapter 3 -Demand Forecasts and Appendices 3.6
and 3.7.These alternate scenarios consider different demand influencing factors as well as price elasticity
effects for various price influencing factors.
Table 7.1
Demand Scenarios
Average Case
Expected Case
High Growth/Low Price
Low Growth/High Price
Alternate Weather Standard
Demand profiles over the planning horizon for each of the alternate scenarios shown in Figures 7.1 and 7.2
reflect the two winter peaks we model for the different service territories (Dec.20 and Feb.15).
7.2 I I CHAPTER 7 II ALTERNATE SCENARIOS,PORTFOLIOS AND STOCHASTIC ANALYSIS
Figure 7.1 Peak Day (FEB 15)2012 IRP Demand Scenarios
Mdth/d (Net of OSM Savings)
600
500 -_____________
________________________________________________________________
400
—
300 ——---—---—---—--
200 -—-——---——-—----—--—-—-—————--——-—
100
0 ----——--—-————-
_____
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
—Average Case -Mix —Expected Case -Coldest on Record -Mix
—Coldest in 20 years-Mix -High Growth &Low Prices -Mix
—Low Growth &High Prices-Mix
Figure 7.2 Peak Day (DEC20)2012 IRP Demand Scenarios
Mdth/d (l.etofDSM 5avings
--.—-—_—.——-————--———-————----———————--———-————---.
::
—---.--—---—---n-----------•,--
:i ::is D14 ::IE ::16 :r ::1 ::i 2:2:::i :::::::t :3:4 ::z :::s :::‘:::s :3:s :::
—ersgesse -.11 —!-Dece se -c[:es:cr eccr:
—2c!e:ir23 ers-’
e ‘.
2O12AVISTANATURALGASIRP II 7.3
As in the Expected Case,we modeled in SENDOUT®the same resource integration and optimization process
described in this section for each of the other five demand scenarios (see Appendix 3.7 for a complete listing
of all portfolios considered).This identified first year unserved dates for each scenario by service territory
(Figure 7.3).
Figure 7.3 -First Year Peak Demand Not Met with Existing Resources
Scenario Comparisons
As anticipated,our High Growth,Low Price scenario has the most rapid growth and the earliest first year
unserved dates.This scenario includes customer growth rates 60%higher than the Expected Case,
incremental demand driven by NGV/CNG vehicles,and no adjustment for price elasticity.Even with these
aggressive assumptions,resource shortages do not occur until late in the planning horizon.
ii 2020 in Washington/Idaho
ii 2020 in Medford/Roseburg
ii 2018 in Kiamath
ii 2026 in La Grande
This “steeper”demand highlights the “fiat demand risk”discussed earlier.The likelihood of this scenarios
occurrence is remote;however any potential for accelerated unserved dates warrants close monitoring of
demand trends and resource lead times.
WA/ID Medford/Roseburg Kiamath La Grande
2012
2013
2014
2015
2016
2017
2018
2019
2020
>2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
U Expected Case U High Growth &Low Prices •Low Growth &High Prices D Cold Day 2Oyr •Average Case
The remaining scenarios do not identify any resource deficiencies in the planning horizon.
7.4 II CHAPTER 7 II ALTERNATE SCENARIOS,PORTFOLIOS AND STOCHASTIC ANALYSIS
Detailed information on certain selected scenarios is included in the following appendices:
ii Demand and Selected Resources graphs by service territory (High Growth Case only)—Appendix 7.1
ii Peak Day Demand,Served and Unserved table (all cases)—Appendix 7.2
ii Avoided cost curve detail and graphs for High Growth and Low Growth cases —Appendix 6.4
ALTERNATE SUPPLY SCENARIOS
We identified many supply-side resources which could be considered to meet resource deficiencies should
they occur.Chapter 6 details available supply-side resource options that were considered for this IRP.The list
includes resources we considered but did not input into SENDOUT®because of various restrictions.
For example,contracted city gate deliveries in the form of a structured purchase transaction could be a viable
and desirable option to meet peak conditions.However,the market-based price and other terms are difficult to
reliably determine until a formal agreement is negotiated.Exchange agreements also have market-based terms
and are hard to reliably model especially when the resource is not needed in the near term.
Exported LNG was also a considered primarily as a price influencing factor.However,if one of the proposed
export LNG terminals in Oregon were to be approved and a pipeline was to be built to supply that facility it
potentially could bring supply through Avista’s service territory.This scenario is interesting however;there is
much uncertainty about export LNG.New pipeline builds are expensive and there are currently existing
pipeline options that would be more cost effective.We will continue to monitor this situation and will
consider inclusion of this supply scenario for future IRPs.
For our Washington/Idaho and Medford/Roseburg service territories unsubscribed firm capacity on GTN
and/or firm backhaul plus lateral expansion is a preferred resource selection from our existing resources plus
currently available supply scenario for most demand scenarios.However,assumptions on future availability
could change over time.Therefore,we ran an additional alternate supply-side scenario with changed
assumptions on GTN capacity as per Table 7.2.
Table 7.2
Supply Scenarios
Existing Resources
Existing +Expected Available
GTN Fully Subscribed
In our alternate supply scenario we assumed increased need for GTN capacity.This could be driven by power
generators who require firm transportation to fuel combustion turbines or significant investments made by the
transportation industry for fueling long haul trucks.The increased contracting leads to GTN becoming fully
subscribed.The result of this scenario using our Expected Case demand profile is that in Washington and
Idaho and Oregon recalls of existing capacity and satellite LNG is selected as the preferred resource portfolio.
(Figures detailing the resources selected based on this scenario are included in Appendix 7.1.)
PORTFOLIO SELECTION
The alternate demand scenarios and supply scenarios are matched together to form portfolios.Each of these
unique portfolios is run through SENDOUT®where the supply resources and demand-side resources are
2O12AVISTANATURALGAS(RP II 7.5
compared and selected on a least cost basis.Once the resources are determined,a net present value of the
revenue requirement (PVRR)is calculated.
In the Expected Case,the Expected Demand with Existing Resources plus Expected Available portfolio has
the lowest PVRR and was therefore selected as our preferred portfolio.In this portfolio,the supply-side
resources selected to meet unserved demand include the acquisition of currently available pipeline capacity on
GTN,additional compression and capacity on the GTN Medford Lateral.These resources are the least
cost/risk adjusted options currently available to meet peak day demand.
Table 7.3 summarizes the PVRR of all the portfolios considered.Each of these portfolios is based on unique
assumptions and therefore a simple comparison of PVRR cannot be made.
Table 7.3 Net Present Value of Revenue Requirement (PVRR)by Portfolio
Unserved
Portfolio Demand PVRR in (000’s)
Average Case Average Demand with Existing Resources (before resource additions)No $5,826,401
Expected Case
Expected Demand with Existing Resources (before resource additions)Yes $5,902,214
Expected Demand with Existing Resources plus Expected Available No $5,972,641
Expected Demand with GTN Fully Subscribed No $6,245,354
AdditionalDemand Scenarios
High Growth,Low Price Demand with Existing Resources Yes $6,315,432
High Growth,Low Price Demand with Existing Resource plus Expected Available No $6,645,781
High Growth,Low Price Demand with GTN Fully Subscribed No $6,954,112
Alternate Weather Standard Demand with Existing Resources No $5,888,614
Low Growth,High Price with Existing Resources No $8,281,177
STOCHASTIC ANALYSIS’
The scenario (deterministic)analysis described earlier in this document represents specific “what if’
situations based on predetermined assumptions including price and weather.These two factors are an integral
part of scenario analysis.To better understand a particular portfolio’s response to price and weather,we
applied stochastic analysis to generate a wide variety of price and weather events.
Deterministic analysis is a valuable tool for selecting the optimal portfolio.The model selects resources to
meet peak weather conditions in each of the 20 years.However,due to the recurrence of design conditions in
each of the 20 years,total system costs over the planning horizon can be overstated because of annual
recurrence of design conditions and the recurrence of price increases in the forward price curve.As a result,
deterministic analysis does not provide a comprehensive look at future events.This type of analysis is only
one piece of the puzzle.Utilizing Monte Carlo simulation in conjunction with deterministic analysis provides
a more complete picture of how the portfolio performs under multiple weather and price profiles.
For this IRP,Monte Carlo analysis was employed in two ways.The first was to test our weather planning
standard and the second was to assess the risk related to costs of our Expected portfolio under varying price
environments.
SENDOUT uses Monte Carlo simulation to support stochastic analysis,which is a mathematical technique for
evaluating risk and uncertainty.Monte Carlo simulation is a statistical modeling method used to imitate the many future
possibilities that exist with a real-life system.
7.6 II CHAPTER 7 II ALTERNATE SCENARIOS,PORTFOLIOS AND STOCHASTICANALYSIS
WEATHER
In order to evaluate weather and its effect on our portfolio we derived 200 simulations (draws)through the
use of SENDOUT®’s Monte Carlo capabilities.Unlike deterministic scenarios or sensitivities the draws have
more variability from month-to-month and year-to-year.In the model,random monthly total HDD draw
values (subject to Monte Carlo parameters —see Table 7.4)are distributed on a daily basis for a month in
history with similar HDD totals.The resulting draws provide a weather pattern with variability in the total
HDD values,as well as variability in the shape ofthe weather pattern.This provides more robust basis for
stress testing the deterministic analysis.
Table 7.4 Example of Monte Carlo Weather Inputs
Spokane
Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
HDD Mean 895 1152 1145 913 781 546 331 143 37 37 191 544
HDDStdDev 132 141 159 115 85 73 72 52 28 28 77 70
HDD Max 1361 1,506 1,681 1,204 953 694 471 248 151 97 343 677
HDD Mm 699 918 897 716 598 392 192 61 -1 54 361
Avista models five weather areas:Spokane,Medford,Roseburg,Klamath Falls and La Grande.From the
simulation data we were able to assess the frequency that the peak day occurs in each area.The stochastic
analysis shows that in over 200 twenty-year simulations,while still remote,peak day (or more)does occur
with enough frequency to maintain our current planning standard for this IRP though this topic remains a
subject of continued analysis.For example,in our Medford weather pattern over the 200 twenty-year draws
(i.e.4000 years,HDDs at or above peak weather (61 HDD)occur 128 times.This equates to a peak day
occurrence once every 31 years (4000 simulation years divided by 128 occurrences).The Spokane area has
the least occurrences of peak day (or more)occurrences in our simulations while La Grande has the most
occurrences.This is primarily due to the frequency in which each region’s peak day HDD occurs within the
historical data as well as near peak day HDDs.See Figures 7.9 through 7.13 for the number of peak day
occurrences for a weather area.
Figure 7.4 -Frequency of Peak Day Occurrences
Spokane
3
C,,
I I I I I I II I I I I I I I I
1 10 19 28 37 46 55 64 73 82 91100109118127136145154163172181 190199
Draws
2O12AVISTANATURALGASIRP N 7.7
3 —-.--—----
U,wC.)
52
i u ii u
_
Figure 7.5-Frequency of Peak Day Occurrences
Medford
1 10 19 28 37 46 55 64 73 82 91 100 109 118 127 136 145 154 163 172 181 190 199
Draws
Figure 7.6 -Frequency of Peak Day Occurrences
Roseburg
3
U,
C.)
I
C.)C.)0
C)0
IC
0 I -I I I I I II I I I I I I I II [7----
1 10 19 28 37 46 55 64 73 82 91 100 109 118 127 136 145 154 163 172 181 190 199
Draws
7.8 II CHAPTER 7 II ALTERNATE SCENARIOS,PORTFOLIOS AND STOCHASTIC ANALYSIS
d MN I ii[
PRICE
7
003C.)
035
C.)C.)
04
>IcII3Ic’z03
-I2
1 1111’j11 •iIái1h iIiiihij Ii I4
1 10 19 28 37 46 55 64 73 82 91 100109118127136145154163172181 190199
While weather is an important driver for IRP planning price is also important.As seen in recent years,there
can be significant price volatility that can affect the portfolio.In deterministic modeling a single price curve
for each scenario is used to perform analysis.There is risk,however,that the price curve used in the scenario
will not reflect actual results.
5
Figure 7.7 -Frequency of Peak Day Occurrences
Kiamath Falls
4U,03C.)
03
C.)
10 19 28 37 46 55 64 73 82 91 100 109 118 127 136 145 154 163 172 181 190 199
Draws
8
Figure 7.8 -Frequency of Peak Day Occurrences
LaGrande
Draws
2O12AVISTANATURALGASIRP II 7.9
Through Monte Carlo simulation we are able to test our portfolio and quantify the risk to our customers when
prices do not materialize as forecasted.We performed a simulation of 200 draws,varying prices,to
investigate whether the Expected Case total portfolio costs from our deterministic analysis is within the range
of occurrences in our stochastic analysis.Figure 7.9 shows a histogram of the total portfolio cost of all 200
draws plus the Expected Case results.This histogram depicts the frequency and the total cost of the portfolio
among all the draws,the mean ofthe draws,the standard deviation of the total costs and the total costs from
the Expected Case.The figure confirms that our Expected Case total portfolio cost is within an acceptable
range of total portfolio costs based on 200 unique pricing scenarios.
Performing stochastic analysis on two key variables of weather and price in our demand analysis provided a
statistically supported approach to evaluate and confirm the findings reached from our scenario analysis with
respect to adequacy and reasonableness of our weather planning standard and our selected natural gas price
forecast.This alternative analytical perspective provides us better confidence in our conclusions and helps us
stress test our assumption,thereby mitigating analytical risks.
REGULATORY REQUIREMENTS
IRP regulatory requirements in Washington,Oregon and Idaho call for several key components.The
completed plan must demonstrate that we have:
ii Examined a range of demand forecasts
ii Examined feasible means of meeting demand with both supply-side and demand-side resources
25
Figure 7.9
AvistalRPTotal 20-Year Cost
90th 95th
20
Mean
Average:5.545
StdDev:0.070
Mm:5.393
90%percenti’e:5.637
95%percentHe:5.663
15
1
C
0
IU.
0.9
10
0.8
0.7
5
0.6
0.5
a)
•1
E
0
0.4
0.3
0.2
$Billions •
0.1
0
ii Treated supply-side and demand-side resources equally
7.10 II CHAPTER 7 II ALTERNATE SCENARIOS,PORTFOLIOS AND STOCHASTIC ANALYSIS
ii Described our long-term plan for meeting expected demand growth
ii Described our plan for resource acquisitions between planning cycles
ii Taken planning uncertainties into consideration
ii Involved the public in the planning process
ii We have addressed the applicable requirements throughout this document.Appendix 2.2 lists the
specific requirements and guidelines of each jurisdiction and describes our compliance in detail
We are also required to consider risks and uncertainties throughout our planning and analysis.Our approach
in addressing this requirement was to identify factors that could cause significant deviation from our Expected
Case planning conclusions.We employed dynamic demand analytical methods and incorporated sensitivity
analysis on various demand drivers that impacted demand forecast assumptions.From this,we created 15
demand sensitivities and modeled five demand scenario alternatives,which incorporated differing customer
growth,use per customer,weather and price elasticity assumptions.We developed three supply scenarios to
consider various risks of resource uncertainties.This resulted in nine distinct portfolios analyzed within
SENDOUT®.
We performed analysis on our peak day weather planning standard,performing sensitivity on HDDs and
modeling an alternate weather planning standard using coldest day in 20 years.We supplemented this analysis
with stochastic analysis running Monte Carlo simulations in SENDOUT®.We also used simulations from
SENDOUT®to analyze price uncertainty and the effect on total portfolio cost.
We examined risk factors and uncertainties that could impact expectations and assumptions with respect to
DSM programs and supply-side scenarios.From this,we developed three supply-side scenarios and included
potential DSM savings for evaluation.
This investigation,identification and assessment ofrisks and uncertainties in our IRP process should
reasonably mitigate surprise outcomes.
II CONCLUSION
The High Growth and Low Growth Case demand analysis provides a sufficient range for evaluating possible
demand trajectories relative to our Expected Case.Based on this analysis we feel comfortable that we have
sufficient time to plan for forecasted resource needs.Even under a very extreme growth scenario our first
forecasted deficiency does not occur until 2018.The analysis shows a preference to meet the forecasted
demand needs with the purchase of existing incremental pipeline capacity.We recognize that many things
could happen between now and when our resource needs occur,therefore we will carefully monitor our
demand trends and continually updated and evaluate all demand side and supply side alternatives.
2012 AvI5TA NATURAL GAS IRP II
CHAPTER 8 II DISTRIBUTION PLANNING
OVERVIEW
Avista’s integrated resource planning encompasses evaluation of safe,economical and reliable full-path
delivery ofnatural gas from basin to burner tip.Securing adequate natural gas supply and ensuring sufficient
pipeline transportation capacity to our city gates become secondary issues if the distribution system behind
the city gates is not adequately planned and becomes severely constrained.An important part of the planning
process is to forecast future local demand growth,determine potential areas of distribution system constraints,
analyze possible solutions and estimate costs for eliminating constraints.
Analyzing our resource needs to this point has focused on ensuring adequate capacity to our city gates,
especially during a peak event (i.e.“Is there adequate volume for a peak day?”).Distribution planning focuses
on “Is there adequate pressure during a peak hour?”Despite this altered perspective distribution planning
shares many ofthe same goals,objectives,risks and solutions.
Avista’s natural gas distribution system consists of approximately 5,400 miles of distribution main pipelines
in Washington,3,000 miles in Idaho and 3,500 miles in Oregon as well as numerous regulator stations,
service distribution lines,monitoring and metering devices,and other equipment.Currently,there are no
storage facilities or compression systems within our distribution system.System pressure is maintained by
pressure regulating stations that utilize pipeline pressures from the interstate transportation pipelines before
natural gas enters our distribution networks.
DISTRIBUTION SYSTEM PLANNING
Avista conducts two primary types of evaluations in its distribution system planning efforts to determine the
need for resource additions including distribution system reinforcements and expansions.Reinforcements are
upgrades in existing infrastructure or new system additions that increase system capacity,reliability and
safety.Expansions are new system additions to accommodate new demand.Collectively we refer to these as
distribution enhancements.
Ongoing evaluations of each distribution network in our four primary service territories are conducted to
identify strategies for addressing local distribution requirements resulting from customer growth.Customer
growth assessments are made based on many factors including our IRP demand forecasts1,monitoring of gate
station flows and other system metering,ongoing communication with construction staff and local area
management regarding new service requests,field personnel discussion and inquiries from major developers.
Additionally,Avista regularly conducts integrity assessments of its distribution systems.This type of ongoing
system evaluation can also indicate distribution upgrading requirements,but as a result of system
maintenance needs rather than customer and load growth.In some cases,however,the timing for system
integrity upgrades can coincide with growth related expansion requirements.
Distribution Planning forecasts customer growth rates by town code to generate local demand growth projections in its forecasting
model consistent with the broader IRP customer forecasting methodology facilitating consistent integrated planning efforts.A town
code is an unincorporated area within a county or a municipality within a county.
8.2 II CHAPTERS II DISTRIBUTION PLANNING
These planning efforts provide a long-term planning and strategy outlook and are integrated into our capital
planning and budgeting process which incorporates planning for other types of distribution capital
expenditures and infrastructure upgrades.
NETWORK DESIGN FUNDAMENTALS
Natural gas distribution networks rely on pressure differentials to flow gas from one place to another.When
pressures are the same on both ends of a pipe the gas does not move.When gas is removed from a point on
the network the pressure at that point drops lower than the pressure upstream in the network.Gas then moves
from the higher pressure in the network to the point of removal attempting to equalize the pressure throughout
the network.If gas removed is not sufficiently replaced by new gas entering the network the pressure
differential will decrease,flow will stall and the network could run out of pressure.Therefore,it is important
to design a distribution network so that the intake pressure (from gate stations and/or regulator stations)
within the network is high enough to maintain an adequate pressure differential when gas leaves the network.
Not all gas flows equally throughout a network.Certain points within the network can constrain flow and thus
restrict overall network capacity.Network constraints can occur over time as demand requirements on the
network evolve.Anticipating these demand requirements,identifying potential constraints and forming cost-
effective solutions with sufficient lead times without overbuilding infrastructure are the key challenges in
network design.
COMPUTER MODELING
Developing and maintaining effective network design is significantly aided by computer modeling to perform
network demand studies.Demand studies have evolved with technology in the past decade to become a
highly technical and powerful means for analyzing the operation of a distribution system.Using a pipeline
fluid flow formula a specified parameter of each pipe element can be simultaneously solved.A variety of
pipeline equations exist,each tailored to a specific flow behavior.Through years ofresearch these equations
have been refined to the point where modeling solutions produced closely resemble actual system behavior.
Avista conducts network load studies using GL Noble Denton’s SynerGEE®4.6.0 software.This computer-
based modeling tool runs on a Windows operating system and allows users to analyze and interpret solutions
graphically.Appendix 8.1 describes in detail our computer modeling methodology while Appendix 8.2
provides an example load study presentation including graphical interface and output examples.
DETERMINING PEAK DEMAND
For ease of maintenance and operation,safety to the public,reliable service and cost considerations,
distribution networks operate at a relatively low pressure.Avista operates its distribution networks at a
maximum operating pressure of 60 pounds per square inch (psig).Since distribution systems operate at
pressure through relatively small diameter pipes there is essentially no line-pack capability for managing
hourly demand fluctuations.
Core demand typically has a morning peaking period between 6 a.m.and 10 a.m.and an evening peaking
period between 5 p.m.and 9 pm.The peak hour demand for these customers can be as much as 50%above
the hourly average of the daily demand.Because of the importance of responding to hourly peaking in the
2O12AvIsTANATuIALGAsIRP II 8.3
distribution system,planning capacity requirements for our distribution systems are based on peak hour
demand2.Included in Appendix 8.1 is the detailed methodology we use for determining peak demand.
DISTRIBUTION SYSTEM ENHANCEMENTS
Computer-aided demand studies facilitate modeling numerous “what if’demand forecasting scenarios,
constraint identification and corresponding optimum combination of pipe modification and pressure
modification solutions to maintain adequate pressures throughout the network over time.
Distribution system enhancements do not reduce demand nor do they create additional supply.However,they
can increase the overall capacity of a distribution pipeline system while utilizing existing gate station supply
points.The three broad categories of distribution enhancement solutions are pipelines,regulators and
compression.
PIPELINES
Pipeline solutions consist of looping,upsizing and uprating.
II PIPELINE LOOPING is the most common method of increasing capacity within an existing
distribution system.It involves constructing new pipe parallel to an existing pipeline that has,or may
become,a constraint point.Constraint points inhibit pressure capacities downstream of the constraint
creating inadequate pressure during periods of high demand.When the parallel line is connected to
the system this second alternative path allows natural gas flow to bypass the original constraint point
and bolster downstream pressure capacities.The feasibility of looping a pipeline is primarily
dependent upon the location where the pipeline will be constructed.Installing gas pipelines through
private easements,residential areas,existing asphalt and steep or rocky terrain can greatly increase
the cost to amounts that are unjustifiable so that other alternative solutions offer a more cost effective
solution.
II PIPELINE UPSIZING is simply replacing existing pipe with a larger size pipe.The increased pipe
capacity relative to surface area of the pipe results in less friction and therefore a lower pressure drop.
This option is usually pursued when there is damaged pipe or pipe integrity issues exist.If the
existing pipe is otherwise in satisfactory condition looping is usually pursued,allowing the existing
pipe to remain in use.
II PIPELINE UPRATING involves increasing the maximum allowable operating pressure of an existing
pipeline.This enhancement can be a quick and relatively inexpensive method of increasing capacity
in the existing distribution system before constructing more costly additional system facilities.
However,safety considerations and pipe regulations may prohibit feasibility or lengthen the time
before completion of this option.Also,increasing line pressure may produce leaks and other pipeline
damage creating unanticipated costly repairs.
REGUI.ATORS
Regulators or regulator stations are used to reduce pipeline pressure at various stages within the distribution.
The primary purpose of regulation is to provide a specified and constant outlet pressure before gas continues
its downstream travel to a city’s distribution system,customer’s property or gas appliance.Regulators also
ensure that flow requirements are met at a desired pressure regardless of fluctuations upstream of the
regulator.Regulators can be found at city gate stations,district regulators stations,farm taps and customer
services.
2 This method differs from the approach that we use for broader IRP peak demand planning which focuses on peak day requirements
to the city gate.
8.4 II CHAPTER 8 II DISTRIBUTION PLANNING
COMPRESSION
Compressor stations present a capacity enhancing option for pipelines with significant gas flow and the ability
to operate at higher pressures.For pipelines experiencing a relatively high and constant flow of gas a single,
large volume compressor can be installed in the optimal position along the pipeline to boost downstream
pressure.However,this type of compressor configuration will not function effectively if the flow in the
pipeline has high variability.
A second option is the installation of multiple,smaller compressors located close together or strategically
placed in different locations along a pipeline.Multiple compressors accommodate a large flow range and the
use of smaller and very reliable compressors.These smaller compressor stations are well suited for areas
where gas demand is growing at a relatively slow and steady pace so that purchasing and installing these less
expensive compressors can be done over time allowing a pipeline to serve growing customer demand for
many years into the future.
Compressors can be a cost effective,feasible option to resolving constraint points;however,regulatory and
environmental approvals to install a station along with engineering and construction time can be a significant
deterrent.Also,adding compressor stations within a distribution system typically involves considerable
capital expenditure.Based on our detailed knowledge of our distribution system,we do not currently envision
or have any foreseeable plans to add compressors to our distribution network.
CONSERVATION RESOURCES
Included in our evaluation of distribution system constraints is consideration of targeted conservation
resources that could reduce or delay distribution system enhancements.We are mindful;however,that the
consumer is still the ultimate decision-maker regarding the purchase of a conservation measure.Because of
this we attempt to influence these decisions but we do not depend on estimates ofpeak day demand
reductions from conservation to eliminate near-term distribution system constraint areas.Over longer-term
planning we do recognize that targeted conservation programs provide a cumulative benefit that offsets
potential constraint areas and may be an effective strategy.
PLANNING RESULTS
Table 8.1 summarizes the cost ofmajor distribution system enhancement projects which address future
growth-related system constraints as well as system integrity issues and the anticipated timing of
expenditures.These proposed projects are preliminary estimates of timing and costs of reinforcement
solutions.The scope and needs of these projects can evolve over time with new information requiring
ongoing reassessment.Actual solutions may be different due to differences in actual growth patterns and/or
construction conditions from those assumed in the initial assessment.
The following discussion provides further information on our key near-term projects:
3203 -EAST MEDFORD REINFORCEMENT —Observed local growth and our IRP indicate increased gas
deliveries will likely be needed from the TransCanada Pipeline source at Phoenix Road Gate Station in
southeast Medford.To facilitate distribution receipt of the increased gas volumes,a new HP gas line
encircling Medford to the east and tying into an existing high-pressure feeder in White City will improve
delivery capacity and provide a much needed reinforcement in the East Medford area which is forecasting
higher growth.
2O12AVISTANATURALGASIRP II 8.5
3237—U.S.2 NORTH SPOKANE REINFORCEMENT —This project will reinforce the area north of Spokane
along U.S.Highway 2.This mixed-use area with residential,commercial and industrial demand experiences
low pressure at unpredictable times given varied demand profiles of the diverse customer base.Completion of
this reinforcement will improve pressures in the U.S.2 north Kaiser area.Approximately 8,000 feet of HP
steel will be installed in a newly established easement along U.S.Highway 2.
3296 —CHASE RD GATE STATION,POST FALLS,ID —This gate station will allow Avista to split the large
load at the Rathdrum Gate Station.Approximately 18,000 feet of high-pressure line will be built to connect
Chase Rd Gate Station to the existing high pressure.This gate station will also give Avista the opportunity to
feed the growing the Post Falls and Coeur d’Alene areas from the north.
Table 8.1 Distribution Planning Capital Projects
Estimated Budget and rifling
Refit Title State 2012 2013 2014 2015 Beyond 2015 Total
3000 Gas Reinfrc-MinorBlanket ALL 800,002 1.050,000 1,050,000 1,050,000 1,050,000 5,000,002
3001 Rep DeterioratingGas Systetm (Non-Aklyl-A)ALL 800,006 1.000,000 1,000,000 1,000,000 1000,000 4800,006
3002 Reg Rellable -Blanket ALL 400,006 500,000 500,000 500,000 500,000 2400,006
3003 Gas Replc-St&Hwy ALL 2,200,007 2,250,000 2,250,000 2,250,000 2,250,000 11,200,007
3004 CathPmt-MinorBlanket ALL 500,003 500,000 500,000 500,000 500,000 2,500,003
3005 Gas DistNon-RevBlanket ALL 3,823,013 3,937,703 4,055,834 4,177,510 4,302,835 20,296,8953006OverbulklPipeReplacementALL500,002 500,000 500,000 500,000 500,000 2,500,002
3007 Isolated Steel Pipe Replacement.Various locations ALL 1,095,004 990,000 1000,000 1,000,000 1,000,000 5,085,0043117GasTelemetmyALL370,801 100,000 100,000 570,801
3296 Upgrade -YZ Odorrs,Various Locations (6ea.)ALL 150,000 150,0003246ChaseRdGateStation.Post Falls,ID ID 2,100,000 2,164,000 4.264,000
3275 Upgrade -Coeur dAlene East Tap Upgrade,Coeur d’Alene,ID ID
3279 Reinlbrcemenl -HP Main Extension southfrom CDA East Gate,CDA ID ID
3292 Reinflarcement -Sprit lake HP Main,AtholID ID
3297 Hwy95 Relocation,CDA ID ID 3,000,000 3,000,000
3298 Old Hwy 95 Relocation,CDA ID ID 1,250,000 1,250,000
TBD Post Falls HP Extension ID 2,000,000 3,000,000 3,000,000 8,000,000
0 3203 EastMedlbrd OR 550,000 4,100,000 4,650,0003242ReinforceTalentORGateStation&Piping OR
3257 Oakland Bridge Bore and Relocation,Oakland OR OR 181,000 181.000
3274 Reinthrce,ent,Loop the existing 6”HP from Tolo to White City OR
3112 Re-RteKettleFallsFeed&GateStation WA
3237 US2 N Spo Gas HP Reinfbrce(Kaiser Prop)WA 1,300,000 1,300,000
3245 Cheney 8’HP Feeder Project WA
3264 Appleway to Henry Reinthrcetent,Spokane Valley WA WA
0 Details ofprojectdescrthed in IRP 14,819,842 13,177,703 18,169,834 12,927,510 13,052,835 72,147,724
II CONCLUSION
Avista’s goal is to maintain its distribution systems reliably and cost effectively to deliver natural gas to every
customer.This goal can be achieved with computer modeling,which increases the reliability ofthe
distribution system by identif’ing specific areas within the system that may require changes.
The ability to meet our goal of reliable cost effective gas delivery is also enhanced through the recent
integration of customer growth forecasting at the town code level and localized distribution planning enabling
coordinated targeting of distribution projects that are responsive to detailed customer growth patterns.
2012 NATURAL GAS IRP
CHAPTER 9 II ACTION PLAN
2010-2011 ACTION PLAN REVIEW
The 2010-2011 Action Plan focused on the following areas:
II Integrated Resource Portfolio
II Demand Forecasting
II Demand-Side Management
II Supply-Side Resources
A discussion of the specific action items and the plan results follows.
II ACTION ITEM
Monitor actual demand closely for indications of faster growth exceeding our forecasted growth to
respond aggressively to address potential accelerated resource deficiencies arising from our exposure to
“flat demand”risk.This includes researching and refining the evaluation of resource alternatives,
including implementation risk factors and timelines,updated cost estimates and feasibility assessments
targeting options for the service territories with nearer-term unserved demand exposure.
II RESULTS
We continue to monitor demand and compare actual results to IRP forecasted demand.Trends so far
indicate slower than anticipated customer growth arid continued declines in weather normalized use-per-
customer,which has delayed the need for resource acquisitions.
II ACTION ITEM
Analyze actual use-per-customer data and DSM program results for indications of price elasticity
response trends that may have been influenced by evolving economic conditions.Investigate
contemporary analytical sources for information on natural gas price elasticity.Explore persuading the
AGA to update their analytical work andlor consider hiring a third-party price elasticity study including
assessing interest of other utilities in pursuing a regional project.
II RESULTS
As part of our reconciliation of forecasted demand to actual demand we analyze weather normalized use —
per customer.While rates have remained relatively stable over the last few years,customers have
decreased their overall usage.Trying economic times,successful adoption of demand-side management
initiatives and appliance and building code efficiencies have contributed to the lower use per customer.
Long run price elasticity does not change much over time;however we did approach the AGA to update
their analytic work.Like man,the AGA was managing a tight budget and did not have the dollars to
undertake an updated study.
9.2 II CHAPTER 9 II ACTION PLAN
II ACTION ITEM
Continue our pursuit of cost effective demand-side solutions to reduce demand.In Washington and Idaho
conservation measures are targeted to reduce demand by approximately 2,193,000 therms in the first year.
In Oregon conservation measures are targeted to reduce demand by approximately 303,000 therms in
the first year.These goals represent increases of 54 percent in Washington and Idaho and 1 percent in
Oregon from our prior 2007 IRP.
II RESULTS
Avista actively pursues cost-effective demand-side management solutions to reduce demand.In 2010 and
2011 Washington and Idaho conservation measures reduced demand by approximately 1,850,000 therms
and 1,730,000 therms.In Oregon demand was reduced by 312,000 therms and 313,000 therms.
II ACTION ITEM
Research and engage a conservation consultant to perform an updated assessment of conservation
technical and achievable potential in our service territories prior to the next IRP.
II RESULTS
Global Energy Partners performed a conservation potential assessment for Avista’s natural gas and
electric demand-side management programs.Results from this analysis were used in the 2012 Natural
Gas IRP and a copy of the assessment is included in Appendix 4.1.
II ACTION ITEM
Continue to monitor the discussion around diminishing Canadian gas exports looking for signals that
indicate increased risk of disrupted supply over the 20-year planning horizon.Since much of our supply
comes from Canadian natural gas exports the notion that this supply could diminish significantly remains
a concern.
II RESULTS
During the 2009 IRP supplies available for import into the United States were showing signs of decline.
Since then the supply picture for North America has changed dramatically.The widespread availability of
shale gas throughout the U.S.and Canada has greatly reduced the concern that supplies will diminish.
II ACTION ITEM
Explore and evaluate alternative and additional forecasting methodologies for potential inclusion in our
next IRP.Methodologies to be evaluated include statistical,non-statistical,quantitative,qualitative and
terrain overview approaches.
II RESULTS
We continue to believe our forecasting methodology is sound,cost effective and adequate;however we
have explored several alternative forecasting methodologies for possible consideration in our IRP
planning.Our methodology allows the ability to vary the results of our statistical inputs by considering
both qualitative and quantitative factors.These factors can be derived from data or surveys of market
2O12AvI5TANATuRALGA5IRP II 9.3
information,fundamental forecasters,and industry experts.We are always open to new methods of
forecasting demand and are assessing which,if any,alternative methodologies to include in future IRPs.
II ACTION ITEM
Meet regularly with Commission Staff members to provide information on market activities,
material changes to risk management programs,and significant changes in assumptions andlor
status of company activity related to the IRP or procurement practices.
II RESULTS
We have met and will continue to meet no less than biannually with Commission Staff members to
provide updates on market fundamentals,procurement planning initiatives,changes to risk management
programs,and significant changes of assumptions related to the IRP.
2013-2014 ACTION PLAN
Since our 2009 IRP customer growth has slowed and it is not anticipated to rebound in the near term.We
have also seen use per customer reductions as customers have become more household budget conscience,
changed usage behavior,and over the last few years have invested in conservation measures.These factors
have reduced overall and peak day demand when compared to our 2009 IRP.
Based on the analysis conducted for the 2012 IRP,under our Expected Case,we do not anticipate the need to
acquire additional supply side resources in the next two to three years.Furthermore,even our most
aggressive High Growth/Low Price scenario did not indicate supply side needs within the next few years.
The Average,Alternate Planning Standard,and Low Growth/High Price scenarios do not indicate any
resource deficiencies within the planning horizon.We will actively monitor our demand looking for
indications of deviations away from our Expected Case.
The demand forecast was not the only thing that changed dramatically.The price of natural gas has dropped
significantly since our last IRP.Robust North American supplies lead by shale gas developments coupled
with lackluster demand due to the economy has pushed prices down to levels not seen in the last decade.
These low prices,while good for our customers,challenge the cost-effectiveness of DSM at the program
level.Since the drafting of this document,Avista has filed in Washington and Idaho to suspend natural gas
DSM programs and is currently evaluating programs in Oregon.
Over the next two to three years,Avista will be watching natural gas prices as a sign post for the cost-
effectiveness of DSM programs.Should prices move significantly Avista will again be proactive in seeking
to reinstate a full complement of our natural gas DSM programs.
Continued enhancement of our gate station analysis will also be completed to assess if there are individual
gate station deficiencies that are masked by our aggregated IRP analysis.Should any deficiencies be
identified we will discuss findings and potential solutions with Commission Staff.We will continue to
coordinate analytic efforts between Gas Supply,Gas Engineering,and the intrastate pipelines to perform gate
station analysis and if deficiencies are identified seek least cost solutions.
II ONGOING ACTION ITEMS
ii Monitor actual demand for indications of growth exceeding our forecast to respond aggressively to
address potential accelerated resource deficiencies arising from exposure to “flat demand”risk.This
will include providing commission staff with IRP demand forecast to actual variance analysis on
9.4 II CHAPTER 9 II ACTION PLAN
customer growth and use per customer.This information will be provided in Avista’s updates to each
commission staff at least biannually.
II Pursue the possibility of a regional elasticity study through the Northwest Gas Association or
possibly the American Gas Association.
II Assess potential demand impact from NGV/CNG vehicles and other new uses of natural gas to
Avista.
II Continue to monitor supply resource trends including the availability and price of natural gas to the
regions,exporting LNG,Canadian natural gas imports and interprovincial consumption,regional
plans for gas-fired generation and its affect on pipeline availability,as well as regional pipeline and
storage infrastructure plans.
ii Monitor new resource lead time requirements relative to when resources are needed to preserve
resource option flexibility.
II Regularly meet with Commission Staff members to provide information on market activities and
significant changes in assumptions and/or status of Avista activities related to the IRP or natural gas
procurement practices.
2012 AvI5TA NATURAL GAS IRP II
CHAPTER 10 II GLOSSARY OF TERMS AND ACRONYMS
ACHIEVABLE POTENTIAL
Represents a realistic assessment of expected energy savings recognizing and accounting for economic and
other constraints that preclude full installation of every identified conservation measure.
AGA
American Gas Association
ANNUAL MEASURES
Conservation measures that achieve generally uniform year round energy savings independent of weather
temperature changes.Annual measures are also often called base load measures.
AVISTA
The regulated Operating Division of Avista Corp.;separated into north (Washington and Idaho)and south
(Oregon)regions;Avista Utilities generates,transmits and distributes electricity in addition to the
transmission and distribution ofnatural gas.
BACKHAUL
A transaction where gas is transported the opposite direction of normal flow on a unidirectional pipeline.
BASE LOAD
As applied to natural gas,a given demand for natural gas that remains fairly constant over a period of time,
usually not temperature sensitive.
BASE LOAD MEASURES
Conservation measures that achieve generally uniform year round energy savings independent of weather
temperature changes.Base load measures are also often called annual measures.
BASIS DIFFERENTIAL
The difference in price between any two natural gas pricing points or time periods.One of the more common
references to basis differential is the pricing difference between Henry Hub and any other pricing point in the
continent.
BRITISH THERMAL UNIT (BTU)
The amount of heat required to raise the temperature of one pound of pure water one degree Fahrenheit under
stated conditions of pressure and temperature;a therm (see below)of natural gas has an energy value of
100,000 BTUs and is approximately equivalent to 100 cubic feet of natural gas.
CD
Contract Demand
C&I
Commercial and Industrial
CITY GATE (ALSO KNOWN AS GATE STATION OR PIPELINE DELIVERY POINT)
The point at which natural gas deliveries transfer from the interstate pipelines to Avista’s distribution system.
10.2 II CHAPTER 10 II GLOSSARY OF TERMS AND ACRONYMS
CNG
Compressed Natural Gas
COMPRESSION
Increasing the pressure of natural gas in a pipeline by means of a mechanically driven compressor station to
increase flow capacity.
CONSERVATION MEASURES
Installations of appliances,products or facility upgrades that result in energy savings.
CONTRACT DEMAND (CD)
The maximum daily,monthly,seasonal or annual quantities of natural gas,which the supplier agrees to
furnish,or the pipeline agrees to transport,and for which the buyer or shipper agrees to pay a demand charge.
CORE LOAD
Firm delivery requirements of Avista,which are comprised of residential,commercial and firm industrial
customers.
COST EFFECTIVENESS
The determination of whether the present value of the therm savings for any given conservation measure is
greater than the cost to achieve the savings.
CPA
Conservation Potential Assessment
CPI
Consumer Price Index,as calculated and published by the U.S.Department of Labor,Bureau of Labor
Statistics
CUBIC FOOT (CF)
A measure of natural gas required to fill a volume ofone cubic foot under stated conditions of temperature,
pressure and water vapor;one cubic foot of natural gas has the energy value of approximately 1,000 BTUs
and 100 cubic feet of natural gas equates to one therm (see below).
CURTAILMENT
A restriction or interruption of natural gas supplies or deliveries;may be caused by production shortages,
pipeline capacity or operational constraints or a combination of operational factors.
DEKATHERM
Unit of measurement for natural gas;a dekatherm is 10 therms,which is one thousand cubic feet (volume)or
one million BTUs (energy).
DEMAND-SIDE MANAGEMENT (DSM)
The activity pursued by an energy utility to influence its customers to reduce their energy consumption or
change their patterns of energy use away from peak consumption periods.
2O12AVISTANATURALGASIRP II 10.3
DEMAND-SIDE RESOURCES
Energy resources obtained through assisting customers to reduce their “demand”or use of natural gas.Also
represents the aggregate energy savings attained from installation of conservation measures.
DSM
Demand-Side Management
DTH
Unit of measurement for natural gas;a dekatherm is 10 therms,which is one thousand cubic feet (volume)or
one million BTUs (energy).
EIA
Energy Information Administration
EXTERNAL ENERGY EFFICIENCY BOARD
Also known as the “Triple-E”board,this non-binding external oversight group was established in 1999 to
provide Avista with input on DSM issues.
EXTERNALITIES
Cost and benefits that are not reflected in the price paid for goods or services.
FEDERAL ENERGY REGULATORY COMMISSION (FERC)
The government agency charged with the regulation and oversight of interstate natural gas pipelines,
wholesale electric rates and hydroelectric licensing;the FERC regulates the interstate pipelines with which
Avista does business and determines rates charged in interstate transactions.
FERC
Federal Energy Regulatory Commission
FIRM SERVICE
Service offered to customers under schedules or contracts that anticipate no interruptions;the highest quality
of service offered to customers.
FORCE MAJEURE
An unexpected event or occurrence not within the control ofthe parties to a contract,which alters the
application of the terms of a contract;sometimes referred to as “an act of God;”examples include severe
weather,war,strikes,pipeline failure and other similar events.
FORWARD PRICE
The future price for a quantity of natural gas to be delivered at a specified time.
GAS TRANSMISSION NORTHWEST (GTN)
A subsidiary of TransCanada Pipeline which owns and operates a natural gas pipeline that runs from the
Canada/USA border to the OregonlCalifornia border.One of the six natural gas pipelines Avista transacts
with directly.
10.4 II CHAPTER 10 II GLOSSARY OF TERMS AND ACRONYMS
GEOGRAPHIC INFORMATION SYSTEM (GIS)
A system of computer software,hardware and spatially referenced data that allows information to be modeled
and analyzed geographically.
GHG
Greenhouse Gas
GLOBAL INSIGHT,INC.
A national economic forecasting company.
GTN
Gas Transmission Northwest
HEATING DEGREE DAY (HDD)
A measure of the coldness of the weather experienced,based on the extent to which the daily average
temperature falls below 65 degrees Fahrenheit;a daily average temperature represents the sum of the high and
low readings divided by two.
HENRY HUB
The physical location found in Louisiana that is widely recognized as the most important pricing point in the
United States.It is also the trading hub for the New York Mercantile Exchange (NYIVIEX).
HP
High Pressure
INJECTION
The process of putting natural gas into a storage facility;also called liquefaction when the storage facility is a
liquefied natural gas plant.
INTEGRITY MANAGEMENT PLAN
A federally regulated program that requires companies to evaluate the integrity of their natural gas pipelines
based on population density.The program requires companies to identify high consequence areas,assess the
risk of a pipeline failure in the identified areas and provide appropriate mitigation measures when necessary.
INTERRUPTIBLE SERVICE
A service of lower priority than firm service offered to customers under schedules or contracts that anticipate
and permit interruptions on short notice;the interruption happens when the demand of all firm customers
exceeds the capability of the system to continue deliveries to all of those customers.
IPUC
Idaho Public Utilities Commission
IRP
Integrated Resource Plan;the document that explains Avista’s plans and preparations to maintain sufficient
resources to meet customer needs at a reasonable price.
2O12AVISTANATURALGASIRP II 10.5
JACKSON PRAIRIE
An underground storage project jointly owned by Avista Corp.,Puget Sound Energy,and NWP;the project is
a naturally occurring aquifer near Chehalis,Washington,which is located some 1,800 feet beneath the surface
and capped with a very thick layer of dense shale.
LIQUEFACTION
Any process in which natural gas is converted from the gaseous to the liquid state;for natural gas,this process
is accomplished through lowering the temperature of the natural gas (see LNG).
LIQUEFIED NATURAL GAS (LNG)
Natural gas that has been liquefied by reducing its temperature to minus 260 degrees Fahrenheit at
atmospheric pressure.
LINEAR PROGRAMMING
A mathematical method of solving problems by means of linear functions where the multiple variables
involved are subject to constraints;this method is utilized in the SENDOUT®Gas Model.
LOAD DURATION CURVE
An array of daily send outs observed that is sorted from highest send out day to lowest to demonstrate both
the peak requirements and the number of days it persists.
LOAD FACTOR
The average load of a customer,a group of customers,or an entire system,divided by the maximum load;can
be calculated over any time period.
LoCAL DISTRIBUTION COMPANY (LDC)
A utility that purchases natural gas for resale to end-use customers andlor delivers custome?s natural gas or
electhcity to end users facilities.
LOOPING
The construction of a second pipeline parallel to an existing pipeline over the whole or any part of its length,
thus increasing the capacity of that section of the system.
MCF
A unit of volume equal to a thousand cubic feet.
MDDO
Maximum Daily Delivery Obligation
MDQ
Maximum Daily Quantity
MMBTU
A unit of heat equal to one million British thermal units (BTUs)or 10 therms.Can be used interchangeably
with Dth.
NATIONAL ENERGY BOARD
The Canadian equivalent to the Federal Energy Regulatory Commission (FERC).
10.6 II CHAPTER 10 II GLOSSARY OF TERMS AND ACRONYMS
NATIONAL OCEANIC ATMOSPHERIC ADMINISTRATION (NOAA)
Publishes the latest weather data;the 30-year weather study included in this IRP is based on this information.
NATURAL GAS
A naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geologic
formations beneath the earth’s surface,often in association with petroleum;the principal constituent is
methane,and it is lighter than air.
NEW YORK MERCANTILE EXCHANGE (NYMEX)
An organization that facilitates the trading of several commodities including natural gas.
NGV
Natural Gas Vehicles
NOAA
National Oceanic and Atmospheric Administration
NoMINAL
Discounting method that includes inflation.
NOMINATION
The scheduling of daily natural gas requirements.
NON-COINCIDENTAL PEAK DEMAND
The demand forecast for a 24-hour period for multiple regions that includes at least one peak day and one
non-peak day.
NoN-FIRM OPEN MARKET SUPPLIES
Natural gas purchased via short-term purchase arrangements;may be used to supplement firm contracts
during times of high demand or to displace other volumes when it is cost-effective to do so;also referred to as
spot market supplies.
NORTHWEST PIPELINE CORPORATION (NWP)
A principal interstate pipeline serving the Pacific Northwest and one of six natural gas pipelines Avista
transacts with directly.NWP is a subsidiary of The Williams Companies and is headquartered in Salt Lake
City,Utah.
NOVA GAS TRANsMIssIoN (NOVA)
See TransCanada Alberta System
NORTHWEST POWER AND CONSERVATION COUNCIL (NPCC)
A regional energy planning and analysis organization headquartered in Portland,Ore.
NPCC
Northwest Power and Conservation Council
NWP
Williams-Northwest Pipeline
2O12AVISTANATURALGASIRP II 10.7
NYMEX
New York Mercantile Exchange
OPUC
Oregon Public Utility Commission
PEAK DAY
The greatest total natural gas demand forecasted in a 24-hour period used as a basis for planning peak
capacity requirements.
PEAK DAY CURTAILMENT
Curtailment imposed on a day-to-day basis during periods of extremely cold weather when demands for
natural gas exceed the maximum daily delivery capability of a pipeline system.
PEAKING CAPACITY
The capability of facilities or equipment normally used to supply incremental natural gas under extreme
demand conditions (i.e.peaks);generally available for a limited number of days at this maximum rate.
PEAKING FACTOR
A ratio of the peak hourly flow and the total daily flow at the city-gate stations used to convert daily loads to
hourly loads.
PRESCRIPTIVE MEASURES
Avista’s DSM tariffs require the application of a formula to determine customer incentives for natural gas-
efficiency projects.For commonly encountered efficiency applications that are relatively uniform in their
characteristics the utility has the option to define a standardized incentive based upon the typical application
of the efficiency measure.This standardized incentive takes the place of a customized calculation for each
individual customer.This streamlining reduces both the utility and customer administrative costs ofprogram
participation and enhances the marketability of the program.
PSIG
Pounds per square inch gauge —a measure of the pressure at which natural gas is delivered.
PVRR
Present Value Revenue Requirement
RATE BASE
The investment value established by a regulatory authority upon which a utility is permitted to cam a
specified rate of return;generally this represents the amount of property used and useful in service to the
public.
REAL
Discounting method that excludes inflation.
RESOURCE STACK
Sources of natural gas infrastructure or supply available to serve Avista’s customers.
10.8 II CHAPTER 10 II GLOSSARY OF TERMS AND ACRONYMS
SEASONAL CAPACITY
Natural gas transportation capacity designed to service in the winter months.
SENDOUT
The amount of natural gas consumed on any given day.
SEN DOUT°
Natural gas planning system from Ventyx;a linear programming model used to solve gas supply and
transportation optimization questions.
SERVICE AREA
Territory in which a utility system is required or has the right to provide natural gas service to ultimate
customers.
SPOT MARKET GAS
Natural gas purchased under short-term agreements as available on the open market;prices are set by market
pressure of supply and demand.
STORAGE
The utilization of facilities for storing natural gas which has been transferred from its original location for the
purposes of serving peak loads,load balancing and the optimization of basis differentials;the facilities are
usually natural geological reservoirs such as depleted oil or natural gas fields or water-bearing sands sealed on
the top by an impermeable cap rock;the facilities may be man-made or natural caverns.LNG storage
facilities generally utilize above ground insulated tanks.
TAC
Technical Advisory Committee
TARIFF
A published volume of regulated rate schedules plus general terms and conditions under which a product or
service will be supplied.
TF-I
NWP’s rate schedule under which Avista moves natural gas supplies on a firm basis.
TF-2
NWP’s rate schedule under which Avista moves natural gas supplies out of storage projects on a firm basis.
TECHNICAL ADVISORY COMMITrEE (TAC)
Industry,customer and regulatory representatives that advise Avista during the IRP planning process.
TECHNICAL POTENTIAL
An estimate of all energy savings that could theoretically be accomplished if every customer that could
potentially install a conservation measure did so without consideration of market barriers such as cost and
customer awareness.
2O12AvIsTANATuRALGAsIRP II 10.9
THERM
A unit of heating value used with natural gas that is equivalent to 100,000 British thermal units (BTU);also
approximately equivalent to 100 cubic feet of natural gas.
ToWN CODE
A town code is an unincorporated area within a county and a municipality within a county served by Avista
natural gas retail services.
TRANSCANADA ALBERTA SYSTEM
Previously known as NOVA Gas Transmission;a natural gas gathering and transmission corporation in
Alberta that delivers natural gas into the TransCanada BC System pipeline at the Alberta/British Columbia
border;one of six natural gas pipelines Avista transacts with directly.
TRANSCANADA BC SYSTEM
Previously known as Alberta Natural Gas;a natural gas transmission corporation of British Columbia that
delivers natural gas between the TransCanada-Alberta System and GTN pipelines that runs from the
Alberta/British Columbia border to the United States border;one of six natural gas pipelines Avista transacts
with directly.
TRANSPORTATION GAS
Natural gas purchased either directly from the producer or through a broker and is used for either system
supply or for specific end-use customers,depending on the transportation arrangements;NWP and GTN
transportation may be firm or interruptible.
TRC
Total Resource Cost
TRIPLE E
External Energy Efficiency Board
TUSCARORA GAS TRANSMISSION COMPANY
Tuscarora is a subsidiary of Sierra Pacific Resources and TransCanada;this natural gas pipeline runs from the
Oregon/California border to Reno,Nevada;one of the six natural gas pipelines Avista transacts with directly;
VAPORIZATION
Any process in which natural gas is converted from the liquid to the gaseous state.
WCSB
Western Canadian Sedimentary Basin
WEIGHTED AVERAGE COST OF GAS (WACOG)
The price paid for a volume of natural gas and associated transportation based on the prices of individual
volumes of natural gas that make up the total quantity supplied over an established time period.
WEATHER NORMALIZATION
The estimation of the average annual temperature in a typical or “normal”year based on examination of
historical weather data;the normal year temperature is used to forecast utility sales revenue under a procedure
called sales normalization.
10.10 II CHAPTER 10 II GLOSSARY OF TERMS AND ACRONYMS
WEATHER SENSrnVE MEASURES
Conservation measures whose energy savings are influenced by weather temperature changes.Weather
sensitive measures are also often referred to as winter measures.
WINTER MEASURES
Conservation measures whose energy savings are influenced by weather temperature changes.Winter
measures are also often referred to as weather sensitive measures.
WITHDRAWAL
The process of removing natural gas from a storage facility,making it available for delivery into the
connected pipelines;vaporization is necessary to make withdrawals from an LNG plant.
WUTC
Washington Utilities and Transportation Commission