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2009 AUG 31 AM 9:,uflllSTlie
August 28, 200 IDAHO PU8UC
UTILITIES COMMISSION
Jean D. Jewell, Secreta
Idao Public Utilities Commssion
Statehouse Mail
W. 472 Washigton Strt
Boise, Idaho 83720 7\vu-E-09-69
De Ms. Jewell:
RE: A vista Utilities 200 Electrc Integrate Resoure Plan
Per IPUC's Integrated Resour Plan Requirments outled in Case No.U-1500165,
Orer No. 22299, Case No.GNR-E-93-1, Orer No. 24729 and Case No.GNR-E-93-3,
Order No. 25260 , A vista Corpration d//a! A vista Utilities, hereby submits for filig an
origial, an electronic copy and 7 copies of its 200 Electrc Integrte Resour Plan.
The Company submits the IR to public utility commssions in Idao and Washington
every two year as reuied by state regulation. A vista regar the IR as a methodology
for identiyig and evaluating varous resource options and as a proess by which to
establish a plan of action for resource decisions. Paper use and pritig costs have ben
reuce by puttg supportng documents on our web site at
ww.avistautities.comlresoureslplanslelectrc.asp.
The 200 Plan is notable for the following:
. The Company is currntly long on energy unti 2018 and capacity until 2015;
. The Prferred Resource Strtegy (PRS) includes 350 MW of wind, 5 MW of
hydro upgres, 5 MW of distrbution effciencies, 750 MW of CCCT, and 339
MW of conservation acquisitions between 2010 and 2029;
. 150 MW of wind power by 2012 to tae advantage of renewable energy ta
incentives, diversify our fuel mi, and meet renewable portolio stada; and
. 26 percnt of futue load grwt is met by new conservation.
Pleae dit any questions regarding ths report to Clint Kalich at (509) 495-4532.
Sincerely,~~~
Linda Gervais
Manager, Regulatory Policy
State and Federa Reguation
c: Mr. Rick Sterling
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SPCIAL THNKS TO OUR TALENTED VENDORS FROM
THE SPOKAE AREA WH PRODUCED THIS IRP:
Ross Printing Company
Thinkng Cap Design
Printed on recycled paper. *
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TABLE OF CONTENTS
Executive Summary
Introduction and Stakeholder Involvement 1-1
Loads and Resources 2-1
Energy Effciency 3-1
Environmental Policy 4-1
Transmission and Distnbution 5-1
Generation Resource Options 6-1
Market Analysis 7-1
Preferred Resource Strategy 8-1
Action Items 9-1
SAFE HARBOR STATEMENT
This document contains forward-looking statements. Such
statements are subject to a variety of risks, uncertainties
and other factors, most of which are beyond the company's
control, and many of which could have a significant impact on
the company's operations, results of operations and financial
condition, and could cause actual results to difer materially
from those anticipated.
For a further discussion of these factors and other important
factors, please refer to our reports filed with the Securities and
Exchange Commission which are available on our website at
ww.avistacorp.com. The company undertakes no obligation
to update any forward-looking statement or statements to
reflect events or circumstances that occur after the date on
which such statement is made or to reflec the occurrence of
unanticipated events.
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TABLE OF TABLES
Table 1:
Table 2:
Table 3:
Table 1.1:
Table 1.2:
Table 1.3:
Table 2.1:
Table 2.2:
Table 2.3:
Table 2.4:
Table 2.5:
Table 2.6:
Table 2.7:
Table 3.1:
Table 6.1:
Table 6.2:
Table 6.3:
Table 6.4:
Table 6.5:
Table 6.6:
Table 6.7:
Table 6.8:
Table 6.9:
Table 6.10:
Table 6.11:
Table 6.12:
Table 6.13:
Table 6.14:
Table 6.15:
Table 6.16:
Table 6.17:
Table 6.18:
Table 6.19:
Table 6.20:
Table 6.21:
Table 6.22:
Table 6.23:
Table 6.24:
Net Position Forecast
2009 Preferred Resource Strategy
2007 Preferred Resource Strategy
TAC Participants
TAC Meeting Dates and Agenda Items
Washington IRP Rules and Requirements
Global Insight National Long Range Forecast Assumptions
Company-Owned Hydro Resources
Company-Owned Thermal Resources
Large Congtractual Rights and Obligations
Washington State RPS Detail (aMW)
Winter Capacity Position (MW) - Plan for Position Excluding Maintenance
Summer Capacity Position (MW) - Plan for Position Excluding Maintenance
Current Avista Energy Effciency Programs
CCCT (Water Cooled) Levelized Costs per MWh
CCCT with Carbon Sequestration Levelized Costs per MWh
Frame SCCT Levelized Costs per MWh
LMS 100 Levelized Costs per MWh
Wind Capital and Fixed O&M Costs
Columbia Basin Wind Project Levelized Costs per MWh
Small Scale Project Levelized Costs per MWh
Offshore Wind Project Levelized Costs per MWh
Coal Capital Costs (2009$)
Ultra Critical Pulverized Coal Project Levelized Cost per MWh
IGCC Coal Project Levelized Cost per MWh
IGCC with Carbon Sequestration Coal Project Levelized Cost ($/MWh)
Hydro Upgrade Project Characteristics
Hydro Upgrade Nominal Levelized Costs per MWh
Hydro Upgrade 2009$ Levelized Costs per MWh
Solar Nominal Levelized Cost ($/MWh)
Solar 2009$ Levelized Cost ($/MWh)
Biomass Capital Costs
Biomass Nominal Levelized Costs per MWh
Biomass 2009 Dollar Levelized Cost per MWh
Geothermal Levelized Costs per MWh
TidallWave Levelized Costs per MWh
Small Cogeneration Levelized Costs per MWh
Nuclear Levelized Costs per MWh
viii
ix
1-2
1-3
1-6
2-4
2-17
2-19
2-21
2-26
2-27
2-28
3-10
6-4
6-5
6-6
6-6
6-7
6-8
6-8
6-8
6-9
6-10
6-10
6-10
6-11
6-12
6-12
6-13
6-14
6-15
6-15
6-15
6-16
6-17
6-17
6-18
TABLE OF TABLES (continued)
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Table 6.25:Hydrokinetics Levelized Costs per MWh 6-18 r'Table 6.26:Pumped Storage Levelized Costs per MWh 6-19
Table 6.27:Large Scale Hydro Levelized costs per MWh 6-19
Table 6.28:Resource Analysis Summary for Preferred Resources Strategy Analysis 6-21
Table 6.29:Resource Analysis Summary for Other Resources Options 6-22
Table 7.1:AURORAxMP Zones 7-3 F"
Table 7.2:20- Year Annual Average Peak & Energy Load Growth Rates 7;"3
Table 7.3:Western Interconnec Transmission Upgrades Included in Analysis 7-4
Table 7.4:New Resources Available to Meet Resource Deficits 7-7
Table 7.5:Natural Gas Price Basin Differentials from Henry Hub (Nominal Dollars)7-9 r
Table 7.6:Monthly Price Differentials for Malin 7-9
Table 7.7:Western Interconnect Coal Prices (2009$)7-10 r
Table 7.8:Northwest Hydro Capacity Factors 7-11 t
Table 7.9:Western Interconnect Wind Capacity Factors 7-11
Table 7.10:Stochastic Study Correlation Matrx 7-14
Table 7.11:EPA Carbon Study (Nominal Price per ShorUon)7-15
Table 7.12:Ten Co Særi Ba on Wo Maen an EPA Stie (Nominal Pii pe Sho Ton)_7-15 (;
Table 7.13:January through June Area Correlations 7-20
Table 7.14:July through December Area Correlations 7-20
Table 7.15:Area Load Coeffcient of Determination (Std Dev/Mean)7-21
Table 7.16:Area Load Coeffcient of Determination (Std Dev/Mean)7-21
Table 7.17:Annual Mid-Columbia Electric Prices ($/MWh)7-28
Table 7.18:Main and Mid-Columbia Forecast Results (Nominal Levelized)7-43 t~Table 7.19:Main and Mid-Columbia Forecast Results (2009 Dollars Levelized)7-43
Table 8.1:2009 Preferred Resource Strategy 8-8
L'Table 8.2:2007 Preferred Resource Strategy 8-9 j
Table 8.3:Levelized Avoided Costs ($/MWh)8-16
Table 8.4:PRS Rate Base Additions for Capital Expenditures 8-18 rJ
Table 8.5:Unconstrained Carbon Scenario - Least Cost Portolio 8-23
Table 8.6:Portolio Cost and Risk Comparison 8-23
Table 8.7:Low Load Growh Resource Strategy Changes to PRS 8-25
Table 8.8:High Load Growth Resource Strategy Changes to PRS 8-25
Table 8.9:Large Hydro Upgrade Resource Strategy Modifications 8-27
Table 8.10:Portolio Cost and Risk Comparison 8-29
Table 8.11: Other Renewables Available - Changes to PRS 8-29
Table 8.12:Annual Load & Resources (aMW)8-31
Table 8.13:Loads & Resources at Winter Peak (MW)8-32
Table 8.14:Loads & Resources at Summer Peak (MW)8-33
TABLE OF FIGURES
Figure 1:
Figure 2:
Figure 3:
Figure 4:
Figure 5:
Figure 6:
Figure 7:
Figure 8:
Figure 9:
Figure 10:
Figure 2.1:
Figure 2.2:
Figure 2.3:
Figure 2.4:
Figure 2.5:
Figure 2.6:
Figure 2.7:
Figure 2.8:
Figure 2.9:
Figure 2.10:
Figure 2.11 :
Figure 2.12:
Figure 2.13:
Figure 2.15:
Figure 2.16:
Figure 2.17:
Figure 3.1:
Figure 3.2:
Figure 3.3:
Figure 4.1:
Figure 5.1:
Figure 5.2:
Figure 5.3:
Figure 6.1:
Figure 7.1:
Figure 7.2:
Figure 7.3:
Figure 7.4:
Load Resource Balance Winter Capacity
Load Resource Balance-Energy
Effcient Frontier
Annual Flat Mid-Columbia Prices
Annual Average Henry Hub Natural Gas Price
Cumulative Conservation Acquisitions
Forecast of Conservation Acquisition
ii
ii
iv
v
vi
vii
vii
viii
Estimated Price of CO2 Credits for 20091RP
Avista Owned and Controlled Resource's Greenhouse Gas Emissions
Avista's Service Territory
Population Change for Spokane, Kootenai and Bonner Counties
Total Population for Spokane, Kootenai and Bonner Counties
Three-County Population Age 65 and Over
Three-County Job Change
Three-County Non-Farm Jobs
Avista Annual Average Customer Forecast
Household Size Index
Annual Use per Customer
Avista's Retail Sales Forecast
Annual Net Native Load
Calendar Year Peak Demand
Electric Load Forecast Scenarios
Winter Capacity Position
Summer Capacity Position
Annual Average Position
Historical Conservation Acquisition
Forecast of Conservation Acquisition
Supply of Evaluated Conservation Measures (Levelized TRC Cost)
Price of Carbon Dioxide Credits
Avista Transmission System
Levelized Cost of Feeder Upgrades
Estimated Feeder Supply Curve
CCCT Output Per 100 MW of Nameplate Capacity
NERC Interconnection Map
Renewable Resource Additions to Meet RPS
Northwest Peak Load/Resource Balance
Total Western Interconnect Capacity Deficits
x
x
2-2
2-3
2-3
2-5
2-5
2-6
2-7
2-10
2-11
2-12
2-13
2-14
2-15
2-24
2-25
2-25
3-2
3-11
3-12
4-11
5-2
5-12
5-12
6-4
7-2
7-5
7-6
7-7
TABLE OF FIGURES (continued)
Figure 7.5:Henry Hub Natural Gas Price Forecast 7-8 fe,
Figure 7.6:Price of Carbon Credits 7-13 l
Figure 7.7:Cost of Carbon Credits 7-13
Figure 7.8:Distribution of Annual Average Carbon Prices for 2012 7-16 r
Figure 7.9:Distribution of Annual Natural Gas Prices for 2012 7-17
Figure 7.10:Henry Hub Natural Gas Distributions 7-17 ('
Figure 7.11:Random Draws from the Henry Hub Price Distribution 7-18
Figure 7.12:Random Draws Load Forecast with Year 2009 at 100 7-19
Figure 7.13:Distribution of Avista's Hydro Generation 7-23
Figure 7.14:Wind Ouput Distribution 7-24 r
Figure 7.15:Base Case New Resource Selection 7-26
Figure 7.16:Annual Flat Mid-Columbia Electric Prices 7-27
Figure 7.17:Selected Mid-Columbia Annual Flat Price Duration Curves 7-27
Figure 7.18:Western States Greenhouse Gas Emissions 7-29
Figure 7.19:Base Case Wetern Interconnect Resource Energy 7-30
Figure 7.20:Unconstrained Carbon Emissions Resource Selection 7-31
Figure 7.21 :Mid-Columbia Prices Comparison with and without Carbon Legislation 7-32 ( ,
Figure 7.22:Western U.S. Carbon Emissions Comparison 7-33
Figure 7.23:Unconstrained Carbon Scenario Resource Dispatch 7-33 (è
Figure 7.24:Western Interconnect Fuel Cost Comparison 7-34
Figure 7.25:Henry Hub Prices for High and Low Natural Gas Price Scenarios 7-35
Figure 7.26:Greenhouse Gas Prices for High and Low Natural Gas Price Scenarios 7-36
Figure 7.27:High Natural Gas Prices Scenario Resource Selection 7-36
Figure 7.28:Low Natural Gas Prices Scenario Resource Selection 7-37
Figure 7.29:Mid-Columbia Electric Price Forecast 7-38
Figure 7.30:Resource Dispatch - High Gas Price Scenario 7-38
Figure 7.31:Resource Dispatch - Low Gas Price Scenario 7-39
Figure 7.32:Solar Saturation Scenario Resource Selection 7-40
Figure 7.33:Western Interconnect Carbon Emissions Comparison 7-41
Figure 7.34:Resource Dispatch - Solar Saturation Scenario 7-41
Figure 8.1:Resource Acquisition History 8-2
Figure 8.2:Effcient Frontier Curve 8-4 L,
Figure 8.3:Effcient Frontier in a Constrained Environment 8-5
Figure 8.4:Physical Resource Positions 8-6
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Figure 8.5:REC Requirement vs. Qualifying RECs for Washington State RPS 8-7
Figure 8.6:Energy Effciency Annual Expected Acquisition 8-10
Figure 8.7:Annual Average Load and Resource Balance 8-11
Figure 8.8:Winter Peak Load and Resource Balance 8-12
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TABLE OF FIGURES (continued)
Figure 8.9:
Figure 8.10:
Figure 8.11 :
Figure 8.12:
Figure 8.13:
Figure 8.14:
Figure 8.15:
Figure 8.16:
Figure 8.17:
Figure 8.18:
Figure 8.19:
Figure 8.20:
Summer Peak Load and Resource Balance
Avista Owned and Controlled Resource's Greenhouse Gas Emissions
Base Case Effcient Frontier
Avoided Costs for Conservation
Effcient Frontier Portolios 2029 New Resources
Power Supply Expense
Power Supply Cost Sensitivities
Carbon Related Power Supply Expense
Effcient Frontier Comparison
High & Low Load Growth Cost Comparison
Effcient Frontier Base Case vs. Other Renewables Available
Real Power Supply Expected Cost Growth Index (2010 = 100)
8-13
8-14
8-15
8-16
8-17
8-19
8-20
8-21
8-22
8-26
8-28
8-30
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LIST OF ACRONYMS AND KEY TERMS
2009 IRP INTRODUCTION
Avista has a long tradition of innovation as a provider of clean, renewable energy. The 2009 Integrated Resource
Plan (IRP) continues that tradition as it looks into the future needs of our customers. The IRP analyzes and
outlines a strategy to meet projected demand through energy effciency and a careful mix of new renewables and
traditional resources.
The plan includes economic growth forecasts for the Avista service territory. Electricity sales growt is expected
to occur at a rate of 1.7 percent over the next two decades. Avista projects that it wil have suffcient resources to
meet growh until 2018 when new energy supplies wil need to be brought online.
Avista expects to add increasing amounts of new renewables to its generation portolio in the coming years. This
is partly due to active and pending state and federal regulations. Regardless of legislation, Avista believes that
renewables represent viable energy sources that reduce the need for fossil fuels and diversify our resource mix.
New renewable energy sources like wind and solar power currently are more expensive to build than traditional
energy resources. An added challenge is they are intermittent resources, meaning that the wind doesn't always
blow and the sun doesn't always shine. Customers except high reliabilty so utilties wil stil need energy resources
like natural gas and hydropower to keep the lights on. This presents a challenge to resource planners who must
consider realiabilty as well as rate and environmental impacts.
The IRP is updated every two years and looks 20 years into the future. This plan is developed by Avista's professional
energy analysts using sophisticated modeling tools and input from interested community stakeholders.
Each IRP is a thoroughly researched and data driven document to guide responsible resource planning for the
company. The plan's Preferred Resource Strategy (PRS) section covers our projected resource acquisitions over
the next 20 years.
Some highlights of the PRS include:
· 150 MW of wind power by 2012 to take advantage of renewable energy tax incentives, diversify our fuel
mix, and meet renewable portolio standards.
· An additional 200 MW of wind power over the IRP timeframe.
· 26 percent of future load growth is met by new conservation.
· Construction of 750 MW of clean-burning natural gas-fired generation facilties.
· Avista does not plan to add any coal-fired generation to its resource mix.
· Aggressive energy effciency measures are expected to save 226 aMW of cumulative energy over the
next 20 years.
· 5 MW of hydro upgrades are planned for the Little Falls and Upper Falls hydro projecs.
· Large hydro upgrades wil be studied as alternative new renewable resources for the 2011 IRP.
· Transmission upgrades wil be needed to add new generation and Avista wil continue to participate in
regional efforts to expand the region's transmission system.
This document is mostly technical in nature. The IRP has an Executive Summary and chapter highlights at the
beginning of each section to help guide the reader.
Avista expects to begin developing the 2011 IRP in early 2010. Stakeholder involvement is encouraged and
interested parties may contact John Lyons at 509-495-8515 or john.lyons~avistacorp.com for more information
on participating in the IRP procss.
Executive Summary
Executive Summary
Avista's 2009 Integrated Resource Plan (IRP) guides the utility's resource acquisition
strategy over the next two years and the overall direction of resource procurements for
the remainder of the 20-year planning horizon. The IRP provides a snapshot of the
Company's resources and loads, and provides
guidance regarding resource needs and
acquisitions. The Preferred Resource Strategy
(PRS) is a mix of renewable resources,
conservation, upgrades at existing facilities,
and new gas-fired generation.
The PRS balances low cost, reliable service,
reasonable future rate volatility, and renewable
resource requirements. Avista's management
and stakeholders from the Technical Advisory
Committee (TAC) playa key role in guiding the
development of the IRP. TAC members
include customers, commission staff,
consumer advocates, academics, utility peers,
government agencies, and other interested
parties. The TAC provides significant input on
modeling, resource assumptions, and the
general direction of the planning process.
Noxon Rapids Upgrade CrewResource Needs
Plant upgrades and conservation measures are integral to Avista's resource strategy,
but are ultimately inadequate to meet all future load growth. Annual energy deficits
begin in 2018, with loads plus a planning margin exceeding resource capabilty by 27
aMW. Energy deficits rise to 126 aMW in 2022 and 527 aMW in 2029. The Company
wil be short 45 MW of capacity in 2015. In 2022 and 2029, capacity deficits rise to 139
MW and 667 MW, respectively. Table 1 presents Avista's net load position for the first
10 years of the study.
Table 1: Net Position Forecast
Increasing deficits are a result of forecasted 1.7 percent energy and capacity load
growth through 2029. Expirations of long-term contracts also increase deficiencies.
Figures 1 and 2 provide graphical representations of the Company's load and resource
balance. The forecasted load in each year includes the one-in-two peak forecast plus
planning and operating reserve obligations. The forecast would be higher without past
conservation acquisitions.
Avista Corp 2009 Electric IRP
Executive Summary
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Executive Summary
Modeling and Results
Avista used a multi-step approach to develop its PRS. The process began with the
identification and quantification of potential new resources to serve future demand
across the West. A Western Interconnect-wide study was performed to understand the
impact of regional markets on the Northwest electricity marketplace. Avista's existing
resource stack was combined with the present transmission grid to simulate hourly
operations for the Western Interconnect from 2010 to 2029.
Cost-effective new resources and transmission were added as necessary to meet
growing loads. Monte Carlo-style analysis varied hydro, wind, load, forced outages,
greenhouse gas emissions, and gas price data over 250 iterations of potential future
conditions. The simulation results were used to estimate the Mid-Columbia electric
market, and the iterations collectively formed the Base Case for this IRP.
Estimated market prices were used to analyze potential conservation initiatives and
available supply-side resources to meet forecasted resource requirements. Each new
resource option was valued against the Mid-Columbia market to identify the future value
of each asset to the Company, as well as its inherent risk measured in year-to-year
power supply cost volatility. Future market values and risk were compared with the
capital and fixed operation and maintenance costs that would be incurred. Avista's
Preferred Resource Strategy Linear Programming Model (PRiSM) assisted in selecting
the PRS for serving future load. The PRS selection was based on forecasted energy
and capacity needs, resource values, state mandated renewable portolio standards,
and limiting power supply expense variabilty.
Portolio scenarios were used to identify tipping points that would change the PRS
under alternative conditions beyond the Base Case. The scenarios identified changes to
underlying assumptions that could alter the PRS, such as chang.es to load growth,
capital costs, hydro upgrades, the emergence of other small renewable projects and
nuclear revivaL.
The preferred resource portolio must address two key challenges that include the
mitigation of future costs and risk given a set of environmental constraints. An effcient
frontier helps determine trade offs between risk and cost. This approach is similar to
finding the optimal mix of risk and return when developing a personal investment
portfolio. As expected returns increase, so do risks; whereas reducing risk reduces
overall returns. Finding the PRS is similar to the investots dilemma, but the trade-off is
future costs against power supply cost variation. Figure 3 presents the change in cost
and risk from the PRS on the Effcient Frontier.
Avista Corp 2009 Electric IRP iii
Executive Summary
Figure 3: Effcient Frontier
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2010-2020 NPVof power supply costs (Rillons)
Electricity and Natural Gas Market Price Forecasts
Figure 4 shows the Company's electricity price forecast developed for the 2009 IRP.
The Mid-Columbia market price is expected to average $79.56 per MWh in 2009 dollars
over the next 20 years; the average nominal price is $93.74 per MWh. Spreads between
on- and off-peak prices are $14.34 per MWh in 2010 and $32.71 per MWh in 2029.
Stochastic prices are higher than deterministic prices, as the stochastic model accounts
for carbon, hydro, natural gas, forced outage and wind energy risks.
iv Avista Corp2009 Electric IRP
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Electricity prices are highly correlated with natural gas prices because natural gas-fired
generation is the marginal resource in the Western Interconnect. Base Case natural gas
prices at Henry Hub are shown in Figure 5. The levelized Henry Hub nominal price is
expected to be $9.05 per Dth over the next 20 years and the real 2009 dollar levelized
cost is $7.67. The natural gas forecast is derived from a combination of sources in the
near term including the New York Mercantile Exchange, the Energy Information
Administration, Wood Mackenzie and other consultants. Longer term prices rely on the
forecast from Wood Mackenzie. The forecast includes a price adder of $0.50 per Dth
in 2013 and $1.00 per Dth after 2018 (2009 dollars) to account for the increase in
demand of natural gas due to a shift from coal to natural gas-fired generation.
Avista Corp v2009 Electric IRP
f.,Executive Summary ¡:.
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Figure 5: Annual Average Henry Hub Natural Gas Price l.
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Energy Efficiency
Avista's energy effciency efforts provide conservation programs and education for
residential, commercial, industrial and low income customers. Programs fall into
prescriptive and site-specific classifications. Prescriptive programs offer cash incentives
for standardized products, such as compact fluorescent light bulbs. These programs are
directed towards residential and small commercial customers. Site-specific programs
provide cash incentives for any cost-effective energy savings measure with a payback
greater than one year. Site-specific programs require customized services for
commercial and industrial customers because many applications need to be tailored to
each customer's premises and processes.
Figure 6 shows how conservation has decreased the Company's energy requirements f
by 138.5 aMW since programs began in the late 1970s. 109 aMW of effciency projects .
acquired over the past 18 years are stil online.
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vi 200 Electric IRP Avista Corp (,
Executive Summary
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Figure 6: Cumulative Conservation Acquisitions
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Approximately 3,000 effciency measures were evaluated for the 2009 IRP. The PRS
includes 10.4 aMW (7.5 aMW local and 2.9 aMW regional) of conservation are expected
to be obtained in 2010. Figure 7 shows the projected levels of local and regional
conservation over the next 20 years.
Figure 7: Forecast of Conservation Acquisition
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16 . Local (Avista)
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Avista Corp vii2009 Electric IRP
Executive Summary
Preferred Resource Strategy
The PRS is developed after careful consideration of information gathered over the IRP
process. The PRS is reviewed and critiqued by management and the TAC. The 2009
plan relies on a combination of conservation, distribution system upgrades, wind, hydro
upgrades, and gas-fired combined-cycle combustion turbines. It also identifies
transmission projects to improve system reliability and to access generation resources
necessary to comply with renewable portolio standards. Figure 8 ilustrates the
Company's PRS.
Figure 8:
1,600
1,400
1,200
800
. Distibution Effciencies
. Hydro Upgrades
CCCT
.Wind
Conservationi 1,000l
I 600
400
200
0 0 ~N C"''10 CD ~OC 0)~~N C"~10 ~~OC 0)~~~'f 'f 'f ~'f ~~N N N N N N0000000~~0 0 ~~0 ~0 0 ~0 0NNNNNNNNNNNNNN
Table 2: 2009 Preferred Resource Strategy
By the
End of Nameplate Energy
Resource Year (MW)(aMW)
NWWind 2012 150.0 48.0
Distribution Efficiencies 2010-2015 5.0 2.7
Little Falls Unit UPQrades 2013-2016 3.0 0.9
NWWind 2019 150.0 50.0
CCCT 2019 250.0 225.0
Upper Falls 2020 2.0 1.0
NWWind 2022 50.0 17.0
CCCT 2024 250.0 225.0
CCCT 2027 250.0 225.0
Conservation All Years 339.0 226.0
Total 1,449.0 1,020.6
viii 2009 Electric IRP Avista Corp
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Executive Summary
The PRS resources, shown in nameplate capability, are shown in tabular format in
Table 2 for the 2009 PRS and Table 3 for the 2007 PRS.
Table 3: 2007 Preferred Resource Strategy
By the End Nameplate Energy
Resource of Year (MW)(aMW)
Non-Wind Renewable 2011 20.0 18.0
Non-Wind Renewable 2012 10.0 9.0
NWWind 2013 100.0 33.0
Non-Wind Renewable 2013 5.0 4.5
Share of CCCT 2014 75.0 67.5
NWWind 2015 100.0 33.0
NWWind 2016 100.0 33.0
Non-Wind Renewable 2019 10.0 9.0
Non-Wind Renewable 2020 10.0 9.0
Non-Wind Renewable 2021 5.0 4.5
Share of CCCT1 2019 297.0 267.3
Share of CCCT 2027 305.0 274.5
Conservation All Years 331.5 221.0
Total 1,368.5 983.3
The 2009 IRP requires just over $1.0 billon in net present value of new capital
investments over the next 20 years.
Carbon Emissions
Carbon emission costs have been included jn the Base Case since the 2007 IRP.
Carbon, or C02, cost estimates are from a national market study by Wood Mackenzie.
Figure 8 shows projected CO2 emissions prices. Figure 9 shows the projected carbon
emissions for existing and new generation assets. These estimates do not include
emissions from market and contract purchases, and C02 emissions are not reduced for
wholesale sales. The white area of Figure 10 indicates estimated emission levels
without legislative action.
Avista Corp 2009 Electric IRP ix
Executive Summary
$120
$100
c:S $801:0.stI $60..
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Figure 9: Estimated Price of CO2 Credits for 2009 IRP
r-
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Figure 10: Avista Owned and Controlled Resource's Greenhouse Gas Emissions
(
5.0
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4.0
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Action Items
The Company's 2009 Action Plan outlines activities and studies to be developed and L..,
presented in the 2011 Integrated Resource Plan. The Action Plan was developed using
input from the Company's management team and the TAC. Action Item categories
include resource additions and analysis, demand side management, environmental
policy, modeling and forecasting enhancements, and transmission planning.
x Avista Corp200 Electnc IRP
Chapter 1 - Introduction and Stakeholder Involvement
1. Introduction and Stakeholder Involvement
Avista Utilities submits a biennial Integrated Resource Plan (IRP) to the Idaho and
Washington public utility commissions. 1 The 2009 IRP is Avista's eleventh plan
identifying and describing its Preferred Resource Strategy (PRS) for meetiñg customer's
future requirements while balancing cost and risk measures.
The Company is statutorily obligated to provide reliable electric service to customers at
rates, terms, and conditions that are "just, fair, reasonable and suffcient." We assess
resource acquisition strategies and business plans to acquire resources to meet
resource adequacy requirements and optimize the value of our current resource
portolio. Avista uses the IRP as a resource evaluation tool, rather than a plan for
acquiring a particular asset. The 2009 IRP refines our process for the evaluation of
resource decisions, requests for proposals and other acquisition efforts.
IRP Process
Avista actively sought input from a variety of constituents through the Technical
Advisory Committee (TAC). The TAC included Commission Staff, customers,
academics, government agencies, consultants, utilities and other interested parties. The
Company sponsored six TAC meetings for the 2009 IRP. The TAC process began on
May 14, 2008 and the final meeting to present the results of the 2009 IRP occurred on
June 24, 2009. Over 70 people were invited to each meeting. Each TAC meeting
covered different aspects of the 2009 IRP planning activities and solicited contributions
and assessments regarding modeling assumptions, modeling processes, and results.
Agendas and presentations are in Appendix A and on Avista's web site located at
ww.avistautilities.com/inside/resources/irp/electric.
Stakeholder Participation
The IRP process provides substantial opportunities for stakeholders to participate in
Avista's resource planning activities. The Company utilzes three main stakeholder
groups for the public involvement component of the IRP. The main group involves
stakeholders with expertise in various aspects of utility planning to provide input
concerning the studies, resource data, modeling efforts and critical review of the
modeling results. This group includes Commission Staff, planners from other utilties,
academics, and consultants. The second group includes parties involved with a specific
aspect of the IRP. Examples of this group include environmental groups such as the
Northwest Energy Coalition and government agencies. The third area of public
involvement includes delegates from and participation in regional planning efforts, such
as the Northwest Power and Conservation Council and the Western Electricity
Coordinating CounciL.
1 Washington LRP requirements are conf.ned in WAC 480-100-251 Least Cost Planning. .Idaho IRP
requirements are 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 Corp 2009 Electric IRP 1-1
Chapter 1 - Introduction and Stakeholder Involvement
Public Process
The 2009 I RP is developed and written with the aid of a public process. All of the 2009
TAC presentations are available for review at the Company's website. The entire 2009
IRP, its appendices, and previous IRPs are available at Avista's web site.
Technical Advisory Committee
Avista's IRP is developed with significant amounts of public input and involvement. The
Company had six TAC meetings supplemented with phone and email contact to r
develop this plan. Some of the topics included in the 2009 TAC series were: resource
options, conservation, modeling, fuel price forecasts, load forecasts, market drivers and
environmental issues.
The T AC mailng list includes over 70 individuals from 46 different organizations. The
Company greatly appreciates all of the time and effort expended by the participants in r
the TAC process and looks forward to their continued involvement in the 2011 IRP.
Avista wishes to acknowledge the contributions of the TAC participants in Table 1.1.
Table 1.1: TAC Participants
Participant Organization
Andy Ford Washinoton State University
Robin Toth Greater Spokane Inc.
Dave Van Hersett Resource Development Associates
Mike Connelly Idaho Forest Group
John Daauisto Gonzaoa University
Lea Daeschel Washinoton Attorney General's Offce
Deborah Reynolds Washinoton Utilitv and Transportation Commission
Steve Johnson Washinoton Utilitv and Transportation Commission
David Niohtinoale Washinoton Utilitv and Transportation Commission
Vanda Novak Washinoton Utilitv and Transportation Commission
Carrie Dolwick Northwest Eneroy Coalition
Kirsten Wilson Washinoton State General Administration
Rick Sterlino Idaho Public Utilities Commission
Chuck Murray Community Trade and Economic Development
Tom Noll Idaho Power
Maurv Galbraith Northwest Power and Conservation Council
Vilamour Gamponia Puaet Sound Enerav
Mike Kersh Inland Empire Paper
i
Table 1.2 provides a list of TAC meeting dates and agenda items covered in eachmeeting. b~
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1-2 2009 Electric IRP Avista Corp
Chapter 1 - Introduction and Stakeholder Involvement
Table 1.2: TAC Meeting Dates and Agenda Items
Meeting Date Agenda Items
TAC 1 - May 14, 2008 .Load and Resource Balance Update.Climate Change Update.Renewable Acquisitions.Loss of Load Probability Analysis.2009 IRP Topic Discussions - Work Plan
and Analyical Process Changes
TAC 2 - August 27, 2008 .Risk Assumptions/PRiSM.Resource Assumptions.Scenarios and Futures.Demand Side Management
TAC 3 - October 22,2008 .Load Forecast.Natural Gas Price Forecast.Electric Price Forecast.Legislative Update
TAC 4 - January 28, 2009 .2008 Peak Load Event.Natural Gas and Electric Price Update.Resource Assumptions.Transmission.Draft Preferred Resource Strateav
TAC 5 - March 25, 2009 .Conservation.Preferred Resource Strategy.Scenarios and Futures
.2009 IRP Topics
TAC 6 - June 24, 2009 .Presentation of the 2009 PRS.20091RP Action Items
Issue Specific Public Involvement Activities
Besides TAC meetings, Avista also sponsors and participates in several other
collaborative processes involving a range of public interests.
External Energy Efficiency (ItTriple E'? Board
The Triple E Board began in 1995 for stakeholders and public groups to gather and
discus conservation efforts. The Triple E Group grew out of the DSM Issues group,
which was influential in developing the country's first distribution surcharge for
conservation acquisition for Avista.
FERC Hydro Relicensing - Clark Fork River Projects
Over 50 stakeholder groups participated in the Clark Fork hydro-relicensing process
beginning in 1993. This led to the first all-part settlement filed with a Federal Energy
Regulatory Commission (FERC) relicensing application, and eventual issuance of a 45-
year FERC operating license effective March 1, 2001. The nationally recognized Living
License concept was a result of this process. This collaborative process continues in the
implementafton phase of the Living License with stakeholders participating in various
protection, mitigation and enhancement measures.
Avista Corp 2009 Electric IRP 1-3
Chapter 1 - Introduction and Stakeholder Involvement
FERC Hydro Relicensing - Spokane River Projects
The Company has utilzed a hydro relicensing process for the Spokane River Projects
similar to the process used for relicensing the Clark Fork Projects. Avista was issued a
50-year license for the Spokane River Projects by FERC in June 2009. Approximately
100 stakeholder groups participated in this collaborative effort.
Low Income Rate Assistance Program (LIRAP)
L1RAP progress is shared with several community action agencies in the Company's
Washington service territory through regular meetings. The program began in 2001 and
has quarterly meetings to review administrative issues and needs.
Regional Planning
The Pacific Northwest's generation and transmission system is operated in a
coordinated fashion. Avista participates in many organization's planning processes.
Information from this participation is used to supplement the Company's IRP process.
Some organizations Avista participates in are:
. Western Electricity Coordinating Council
. Northwest Power and Conservation Council
. Northwest Power Pool
. Pacific Northwest Utilties Conference Committee
. ColumbiaGrid
. Northwest Transmission Assessment Committee
. Seams Steering Group - Western Interconnection
. North American Electric Reliability Council
Future Public Involvement
Avista actively solicits input from interested parties to enhance the integrated resource
planning process. Advice wil be requested from members of the Technical Advisory
Committee on a wide variety of resource planning issues. We wil continue to work on
expanding the diversity of the members on the TAC, and wil strive to maintain the TAC
meetings as an open public process.
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2009 IRP Outline
The 2009 IRP consists of nine chapters plus an executive summary. A series of
technical appendices supplement this report. Li
Executive Summary
This chapter summarizes results and highlights of the 2009 IRP.
Chapter 1: Introduction and Stakeholder Involvement
This chapter introduces the IRP and provides details concerning public participation and
involvement in the integrated resource planning process. L..
1-4 Avista Corp2009 Electric IRP
Chapter 1 - Introduction and Stakeholder Involvement
Chapter 2: Loads and Resources
The first half of this chapter covers Avista's load forecast and relevant local economic
forecasts. The last half describes Company-owned generating resources, major
contractual rights and obligations, capacity and energy tabulations and reserve issues.
Chapter 3: Energy Efficiency
This chapter discusses Avista's energy effciency programs. It provides an overview of
the programs, descriptions of conservation measures, analysis of conservation
measures for the IRP and the conservation results for the 2009 IRP.
Chapter 4: Environmental Policy
This chapter focuses on modeling efforts and issues surrounding greenhouse gas
emissions and state and federal environmental regulations.
Chapter 5: Transmission and Distribution Planning
This chapter discusses Avista's distribution and transmission systems, as well as
regional transmission planning issues. Transmission cost studies used in IRP modeling
efforts are also covered.
Chapter 6: Generation Resource Options
This chapter covers costs and operating characteristics of generation resource types
modeled for the 2009 IRP.
Chapter 7: Market Analysis
This chapter covers the analysis ofwhoJesale markets for the 2009 IRP.
Chapter 8: Preferred Resource Strategy
This chapter provides details about Avista's 2009 PRS. It compares the PRS to a
variety of theoretical portolios under stochastic and scenario-based analyses.
Chapter 9: Action Items
This chapter provides an overview of progress made on Action Items from the 2007 IRP
and presents details about Action Items for the 2009 IRP.
Avista Corp 2009 Electric IRP 1-5
Chapter 1 - Introduction and Stakeholder Involvement
Regulatory Requirements
The IRP process for Washington has several requirements that must be met and r'
documented under Washington Administrative Code (WAC). Table 1.3 provides the
applicable WACs and indicates the chapter where each rule or requirement is met.
Table 1.3 Washington IRP Rules and Requirements
Rule and Requirement Plan Citation
WAC 480-100-238(4) - Work Work plan submitted to the WUTC on August 29,
plan filed no later than 12 months 2008, See Appendix B
before next IRP due date. Work
plan outlines content of IRP.
Work plan outlines method for
assessino potential resources.
WAC 480-100-238(5) - Work Appendix B
plan outlines timing and extent of
public participation.
WAC 480-100-238(2)(a) - Plan Chapter 6- Generation Resource Options
describes mix of energy supply
resources.
WAC 480-100-238(2)(a) - Plan Chapter 3- Energy Effciency
describes conservation supplv.
WAC 480-1 00-238(2)(a) - Plan Chapter 2- Loads & Resources
addresses supply in terms of
current and future needs of utility
ratepavers.
WAC 480-100-238(2)(b) - Plan Chapter 8- Preferred Resource Strategy
uses lowest reasonable cost
(LRC) analysis to select mix of
resources.
WAC 480-100-238(2)(b) - LRC Chapter 8- Preferred Resource Strategy
analysis considers resource
costs.
WAC 480-100-238(2)(b) - LRC Chapter 4- Environmental Policy
analysis considers market-Chapter 7- Market Analysis
volatility risks.Chaoter 8- Preferred Resource Strateov
WAC 480-100-238 (2)(b) - LRC Chapter 3- Energy Effciency
analysis considers demand side
uncertainties.
WAC 480-1 00-238(2)(b) - LRC Chapter 6- Generation Resource Options
analysis considers resource Chapter 7- Market Analysis
dispatchability .
WAC 480-1 00-238(2)(b) - LRC Chapter 7- Market Analysis
analysis considers resource Chapter 8- Preferred Resource Strategy
effect on system operation.
1-6 2009 Electric IRP Avista Corp
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Chapter 1 - Introduction and Stakeholder Involvement
WAC 480-100-238(2)(b) - LRC Chapter 4- Environmental Policy
analysis considers risks imposed Chapter 6- Generation Resource Options
on ratepayers.Chapter 7- Market Analysis
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(b) - LRC Chapter 2- Loads & Resources
analysis considers public policies Chapter 4- Environmental Policy
regarding resource preference Chapter 8- Preferred Resource Strategy
adopted by Washington state or
federal government.
WAC 480-1 00-238(2)(b) - LRC Chapter 4- Environmental Policy
analysis considers cost of risks Chapter 8- Preferred Resource Strategy
associated with environmental
effects including emissions of
carbon dioxide.
WAC 480-100-238(2)(c) - Plan Chapter 3- Energy Effciency
defines conservation as any Chapter 8- Preferred Resource Strategy
reduction in electric power
consumption that results from
increases in the effciency of
energy use, production, or
distribution.
WAC 480-1 00-238(3)(a) - Plan Chapter 2- Loads and Resources
includes a range of forecasts of Chapter 8- Preferred Resource Strategy
future demand.
WAC 480-100-238(3)(a) - Plan Chapter 2- Loads and Resources
develops forecasts using Chapter 5- Transmission & Distribution
methods that examine the effect Chapter 8- Preferred Resource Strategy
of economic forces on the
consumption of electricity.
WAC 480-100-238-(3)(a) - Plan Chapter 2- Loads and Resources
develops forecasts using Chapter 3- Energy Efficiency
methods that address changes in Chapter 5- Transmission & Distribution
the number, type and effciency of
end-uses.
WAC 480-100-238(3)(b) - Plan Chapter 3- Energy Effciency
includes an assessment of Chapter 5- Transmission & Distribution
commercially available
conservation, including load
management.
WAC 480-100-238(3)(b) - Plan Chapter 3- Energy Effciency
includes an assessment of Chapter 5- Transmission & Distribution
currently employed and new
policies and programs needed to
obtain the conservation
improvements.
Avista. Corp 2009 Electric IRP 1-7
Chapter 1 - Introduction and Stakeholder Involvement
WAC 480-1 00-238(3)(c) - Plan Chapter 6- Generator Resource Options
includes an assessment of a wide Chapter 8- Preferred Resource Strategy
range of conventional and
commercially available
non conventional generating
technoloQies.
WAC 480-1 00-238(3)(d) - Plan Chapter 5- Transmission & Distribution
includes an assessment of
transmission system capabilty
and reliability (as allowed by
current law).
WAC 480-100-238(3)(e) - Plan Chapter 3- Energy Efficiency
includes a comparative Chapter 5- Transmission & Distribution
evaluation of energy supply
resources (including transmission
and distribution) and
improvements in conservation
usina LRC.
WAC-480-1 00-238(3)(f) -Chapter 3- Energy Effciency
Demand forecasts and resource Chapter 5- Transmission & Distribution
evaluations are integrated into Chapter 6- Generator Resource Options
the long range plan for resource Chapter 8- Preferred Resource Strategy
aCCluisition.
WAC 480-100-238(3)(g) - Plan Chapter 9- Action Items
includes a two-year action plan
that implements the long range
plan.
WAC 480-100-238(3)(h) - Plan Chapter 9- Action Items
includes a progress report on the
implementation of the previously
filed plan.
WAC 480-100-238(5) - Plan Chapter 1- Introduction and Stakeholder
includes description of Involvement
consultation with commission
staff. (Description not reCluired)
WAC 480-100-238(5) - Plan Appendix B
includes description of work plan.
(Description not reCluired)
1-8 Avista Corp2009 Electric IRP
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Chapter 2 - Loads and Resources
2. Loads and Resources
Introduction and Highlights
Loads and resources represent two key components of the Integrated Resource Plan
(IRP). The first half of this chapter summarizes customer and load forecasts for our
service territory. This includes forecast ranges, load scenarios and an overview of
recent enhancements to our forecasting models and processes. The second half of the
chapter covers resource requirements, including descriptions of Company-owned and
operated resources, as well as long-term contracts.
Section Highlights
· Weak economic growth is expected through 2011 in Avista's service territory.
· Historic conservation acquisitions are included in the load forecast; higher
acquisition levels anticipated in this IRP reduce the load forecast further.
· Annual electricity sales growth from 2010-2020 averages 1.7 percent over the
next decade (199 aMW) and 1.7 percent over the entire 20-year forecast.
· Peak loads are expected to grow at a 1.7 percent annual rate over the next 10
years (312 MW) and 1.7 percent over the 20-year forecast.
· Energy deficits begin in 2018; absent conservation deficits would begin in 2016.
· Renewable portolio standard deficiencies are the driver of near-term
resource need.
Economic Conditions in the
Electric Service Territory
Avista serves a wide area of eastern
Washington and northern Idaho. This area
is geographically and economically diverse.
Avista serves most of the urbanized and
suburban areas in 24 counties. Figure 2.1
is a map of the Company's electric and
natural gas service territories. The orange
areas are electric and yellow areas are Avista's Plug-In Hybrid Sun Car
natural gas service territories.
The economy of the Inland Northwest has transformed over the past 20 years, from a
natural resource-based manufacturing to diversified light manufacturing and services.
Much of the mountainous area of the region is owned by the Federal government and
managed by the United States Forest Service. Timber harvest reductions on public
lands have closed many local sawmils. Two pulp and paper plants served by Avista
have access to large forest land holdings; but they continue to face stiff domestic and
international competition for their products.
Avista Corp 2009 Electric IRP 2-1
Chapter 2 - Loads and Resources
Figure 2.1: Avista's Service Territory
Employment grows during periods of economic expansion and contracts during
recessions. Our service territory experienced large scale unemployment during two
national recessions in the 1980s. Avista's service territory was mostly bypassed by the
1991/92 national recession, but was not as fortunate during the 2001 recession. The
current recession is expected to end by 2011. Effects of recessions and economic
growth are best ilustrated by employment for the three principal counties in Avista's
electric service territory: Bonner, Kootenai and Spokane. Regional employment data is
provided later in this chapter.
Population often is more stable than employment during times of economic change;
however, population contracts during severe economic downturns as people leave in
search of employment opportunities. Over the past 25 years, 1987 was the only year
the region experienced a net loss in population. Figure 2.2 details actual and projected
annual population changes in Bonner, Kootenai, and Spokane counties from 1990 to
2030. Figure 2.3 shows total population in these three counties for the same period.
2-2 2009 Electric IRP AvistaCorp
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Chapter 2 - Loads and Resources
Figure 2.2: Population Change for Spokane, Kootenai and Bonner Counties
16
10
14
. Spokane County
. Kootenai County
r i Bonner County
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Figure 2.3: Total Population for Spokane, Kootenai and Bonner Counties ·
-tnooo-coi:.!::c.oc.
s
.s
1,000
900
800
700
600
500
400
300
200
100
o
. Spokane County
. Kootenai County
ii Bonner County
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Avista Corp 2009 Electric IRP 2-3
Chapter 2 - Loads and Resources
People, Jobs and Customers
Avista acquires national and county-level employment and population forecasts from
Global Insight, Inc. Global Insight is an internationally recognized economic forecasting
consulting firm used by various agencies in Washington and Idaho. The data
encompasses the three principal counties which comprise over 80 percent of our
service area economy, namely, Spokane County in Washington; and Kootenai and
Bonner counties in Idaho. The national forecast for this IRP was prepared in March
2008; county-level estimates were completed in June 2008 and the load forecast was
completed in July 2008.
The forecast and underlying assumptions used in this IRP were presented at the Third
Technical Advisory Committee (TAC) meeting for Avista's 2009 Integrated Resource
Plan on October 22, 2009. Key forecasts assumptions are shown in Table 2.1.
Table 2.1: Global Insight National Long Range Forecast Assumptions
Assumption Range Assumption Range
Gross Domestic Product 1.9%-3.2%Housina Starts (miL.)1.5-1.8lvear
Consumer Price Index 3.5%-1.7%Job Growth 0.9%/vear
West Texas Crude 2000$$30-$50 Worker Productivity 2%
Fed Funds Rate 4%-8%Consumer Sentiment 90
Unemplovment Rate 4.3%-4.9%
Looking forward, the national economy slows after recovering from the present
recession, setting the stage for regional economic performance in Avista's electric
service area. As shown in the charts above, population growth rebounds after slow
growth from 1997 to 2002. Population growth is expected to resume its recent trend
after 2010.
Regional population growth is supported by retiree immigration, representing between
10 and 20 percent of overall population growth. Figure 2.4 presents the population
history and forecast for individuals 65 years and over in the three-county area. Between
1990 and 2010 this segment averages a compound growth rate of 2.6 percent in
Bonner County, 4.1 percent in Kootenai County and 1.0 percent in Spokane County.
The age group represents 14.2 percent of the overall population in 2010. The forecast
predicts growth of 3.1 percent, 4.0 percent, and 2.8 percent, respectively, pushing the
overall contribution of this age group to 20.2 percent in 2030.
2-4 Avista Corp200 Electric IRP
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Chapter 2 - Loads and Resources
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Figure 2.4: Three-County Population Age 65 and Over
. Spokane County
. Kootenai County
i ¡ Bonner County
o N ~ cø~ 0 N ~cø ~ 0 N ~cø ~ 0 N~ cø ~ 0~ ~ ~ ~~ 0 0 00 0 _ _ __ _ N NN N N M~ ~ ~ ~~ 0 0 00 0 0 0 00 0 0 00 0 0 0-----NNNNNNNNNNNNNNNN
Employment growth often drives population growth. Figure 2.5 shows historical
employment trends from 1990 and anticipated growth through 2030.
12
10
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Figure 2.5: Three-County Job Change
. Spokane County
. Kootenai County
ii Bonner County
o N~cø ~ON ~cø~ ON~cø ~ON ~cø~ 0~ ~~~ ~oo 000 ____ _NN NNN M~ ~ ~ ~ ~ 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0- --- -NN NNN NNNN NNN NNN N
Avista Corp 2-52009 Electric IRP
Chapter 2 - Loads and Resources
Overall non-farm wage and salary employment over the past 20 years averaged 2.8
percent for Bonner County, 5.1 percent for Kootenai County and 2.1 percent for
Spokane County. Figure 2.6 provides additional non-farm employment data. Over the
forecast horizon growth rates are predicted at 1.4 percent, 2.8 percent, and 1.4 percent,
respectively. As indicated in the following chart, annual employment growth is expected
to be approximately 6,200 new jobs.
Figure 2.6: Three-County Non-Farm Jobs
450
400
350
. Spokane County
. Kootenai County
i I Bonner County-t/
g 300Q-
t/ 250.co'-
E
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200
150
100
50
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Customer growth projections follow from baseline economic forecasts. The Company
tracks four key customer classes-residential, commercial, industrial and street lighting.
Residential customer forecasts are driven by population. Commercial forecasts rely
heavily on employment and lagged residential growth trends. Industrial customer growth
is correlated with employment growth. Employment statistics have the greatest
probability of near term changes as we emerge from the present recession. Street
lighting trends with population growth.
Avista forecasts sales by rate schedule. The overall customer forecast is a compilation
of the various rate schedules of our served states. For example, the residential class
forecast is comprised of separate forecasts prepared for rate schedules 1, 12, 22 and
32 for Washington and Idaho. See Figure 2.7 for Avista's annual average customer
forecast levels.
2-6 2009 Electric IRP Avista Corp
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Chapter 2 - Loads and Resources
Figure 2.7: Avista Annual Average Customer Forecast
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Avista served 311,807 residential customers, 39,154 commercial customers, 1,393
industrial customers and 433 street lighting customers for a total of 352,786 retail
customers in 2008. This is an increase from 340,652 retail customers in 2006. The 2029
forecast predicts 443,278 residential, 56,849 commercial, 1,654 industrial and 644
street lighting customers for a grand total of 502,425 retail customers. The 20-year
compound growth rate averages 1.7 percent.
Weather Forecasts
The baseline electricity sales forecast is based on 30-year normal temperatures
recorded at the Spokane International Airport weather station, as tabulated by the
National Weather Service from 1971 through 2000. Daily values go back as far as 1890.
There are several other weather stations with historical records in the Company's
electric service area; however data is available for a much shorter duration. Sales
forecasts are prepared using monthly data because more granular load information is
not available. The Company finds high correlations between the Spokane International
Airport and other weather stations in its service territory. It uses heating degree days to
measure cold weather and cooling degree days to measure hot weather in its retail
sales forecast.
In response to questions from the TAC, the Company has implemented estimates of the
impacts of climate change in its retail load forecast. Ample evidence of cooling and
warming trends exists in the 115-year record. The recent trend has been a warming
climate compared to the 30-year normaL. Trends in heating and cooling degree days for
Spokane are roughly equal to the scientic community's predictions for this geographic
Avista Corp 2009 Electric IRP 2-7
Chapter 2 - Loads and Resources
area, implying a one degree warming every 25 years. Incorporating the warming trend
finds that in 20 years summer load would be approximately 26 aMW higher than the 30 r. ",
year average weather case. In the winter, loads would be approximately 40 aMW lower
in 2029, for a net impact of a 14 aMW load decrease. The Company wil continue to
study these data trends in its two year Action Plan and report findings in the 2011 IRP.
Price Elasticity
Price elasticity is a central economic concept for projecting electricity demand. Price
elasticity of demand is the ratio of the percentage change in the quantity demanded of a
good or service to a percentage change in its price. Elasticity measures the
responsiveness of buyers to changes in electricity prices. A consumer who is sensitive
to price changes has a relatively elastic demand profile. A customer who is
unresponsive to price changes has a relatively inelastic demand profile. During the r. .
2000-01 energy crisis, customers showed increased sensitivity, or price elasticity of
demand, by reducing their overall electricity usage in response to price increases.
Cross-price elasticity, is the ratio of the percentage change in the quantity demanded of
one good to a percentage change in the price of another good. A positive coeffcient
indicates that the two products are substitutes; a negative coefficient indicates they are
complementary goods. Substitute goods are replacements for one another. As the price l..........,'
of the first good increases relative to the price of the second good, consumers shift their L
consumption to the second good. Complementary goods are used together; increases
in the price of one good result in a decrease in demand for the second good along with
the first. The principal cross price elasticity impact on electricity demand is the
substitutability of natural gas in some applications, including water and space heating.
Income elasticity of demand is the ratio of the percentage change in the quantity
demanded of one good to a percentage change in consumer income. Income elasticity
measures the responsiveness of consumer purchases to income changes. Two impacts
affect electricity demand. The first is affordability. As incomes rise, a consumer's ability
to pay for goods and services increases. The second income-related impact is the
amount and number of customers using equipment within their homes and businesses.
As incomes rise, consumers are more likely to purchase more electricity-consuming
equipment, live in larger dwellngs and use electrical equipment more often.
The correlation between retail electricity prices and the commodity cost of natural gas
has increased in recent years. We estimate customer class price elasticity in our
computation of electricity and natural gas demand. Residential customer price elasticity
is estimated at negative 0.15. Commercial customer price elasticity is estimated at L;
negative 0.10. The cross-price elasticity of natural gas and electricity is estimated to be
positive 0.05. Income elasticity is estimated at positive 0.75, meaning electricity is more
affordable as incomes rise.
2-8 Avista Corp2009 Electric IRP
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Chapter 2 - Loads and Resources
Retail Price Forecast
The retail sales forecast is based on retail prices increasing an average of 10 percent
annually from 2010 to 2018, followed by increases at the tate of inflation thereafter.
Approximately one third of the rate rise is assumed to be driven by carbon-related
legislation, assuming that future federal carbon legislation does not provide for any rate
mitigation. The remaining two-thirds of rate rise is for capital additions and higher fuel
costs.
Conservation
It is diffcult to separate the interrelated impacts of rising electricity and natural gas
prices, rising incomes and conservation programs. Avista collects data on total demand
and must derive the impacts associated with consumption changes. The Company has
offered conservation programs since 1978. The impact of conservation on electricity
usage is fully embedded in the historical data; therefore, we concluded that existing
conservation levels (7.5 aMW) are embedded in the forecast. Where conservation
acquisition decreases from this level, retail load obligations would increase. As this IRP
forecasts growing conservation acquisition, this growth reduces retail load obligations
from the forecast.
Use Per Customer Projections
The database used to project usage per customer uses monthly electricity sales and the
number of customers by rate schedule, customer class, and state from 1997 to 2008.
Historical data is weather-normalized to remove the impact of heating and cooling
degree day deviations from expected normal values, as discussed above. Retail electric
price increase assumptions are applied to price elasticity estimates to estimate price-
induced reductions in electrical use per customer.
The Company included a forecast of personal residential electric vehicles in the Base
Case. These vehicles are a combination of plug-in hybrids and electric-only and
represent a proportional share from the Northwest Power and Conservation Council's
estimates available in mid-2008. Avista's share by 2030 is expected to be 85,000 plug-
in hybrid cars, increasing residential load about 1.3% from 2010 to 2030.
The residential use per customer trend over the long term is flat, consistent with
embedded conservation, warming temperatures and price elasticity offset by electric
vehicles. The number of occupants per household is also decreasing over time. Figure
2.8 shows the number of persons per household over the next 20 years.
Avista Corp 2009 Electric IRP 2-9
Chapter 2 - Loads and Resources
105
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Residential customers tend to be homogeneous relative to dwellng size. Commercial
customers are heterogeneous, ranging from small customers with varying electricity
intensity per square foot of floor space to big box retailers with generally higher
intensities. The addition of new large commercial customers, specifically universities
and hospitals, can greatly skew average use per average customer statistics. Customer
usage is ilustrated in Figure 2.9.
Estimates for residential use per customer across all schedules are relatively smooth.
Commercial usage per customer is forecast to increase for several years due to
additional buildings either built or anticipated to be built by existing very large
customers, such as Washington State University and Sacred Heart HospitaL. Expected
additions for very large customers are included in the forecast through 2015, and no
additions are included in the forecast after 2015. We wil include publicly-announced
long lead time buildings in the load forecast in future IRPs.
2-10 200 Electric IRP Avista Corp
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Figure 2.9: Annual Use per Customer
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Retail Electricity Sales Forecast
Between 1997 and 2008 the region was affected by major economic changes, not the
least of which was a marked increase in wholesale and retail electricity prices. The
energy crisis of 2000-01 included the implementation of widespread, permanent
conservation efforts by our customers. In 2004, rising retail electricity rates further
reinforced conservation efforts. Several large industrial facilities served by the Company
closed permanently during the 2001-02 economic recession. Recently the economy has
entered a significant recession.
Retail electricity consumption rose from 8.2 billon kWh in 1999 to over 8.9 billon kWh in
2008. This increase was in spite of the combined impacts of higher prices and
decreased electricity demand during the energy crisis. The forecasted average annual
increase in retail sales over the 2009 to 2029 period is 1.8 percent.
The sales forecast takes a "bottom up" approach, summing forecasts of the number of
customers and usage per customer to produce a retail sales forecast. Individual
forecasts for our largest industrial customers (Schedule 25) include planned or
announced production increases or decreases. Lumber and wood products industries
have slowed down from very high production levels, which is consistent with the decline
in housing starts at the national level and the current recession. The load forecasts for
these sectors were reduced to account for decreased production levels. Anticipated
sales to aerospace and aeronautical equipment suppliers have increased and local
plants have announced plans to hire more workers and increase their output.
Avista Corp 2009 Electric IRP 2-11
Chapter 2 - loads and Resources
Actual, not weather corrected, retail electricity sales to Avista customers in 2008 were
8.93 billon kWh. Heating degree days in 2008 were 103 percent of normal, almost F'
completely offset in terms of energy use by 121 percent of normal cooling degree days. l
The forecast for 2030 is 12.85 billon kWh, representing a 1.7 percent compounded
increase in retail sales. See Figure 2.10. Degree days in 2030 are forecast to be 87
percent of the 1971-2000 thirty year normal for heating and 149 percent for cooling.
Figure 2.10: Avista's Retail Sales Forecast
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Load Forecast
Load forecasts are derived from retail sales. Retail sales in kilowatt hours are converted tIl
into average megawatt hours using a regression model to ensure monthly load shapes
conform to history. The Company's load forecast is termed its native load. Native load is
net of line losses across the Avista transmission system.
Native load growth is shown in Figure 2.11. Note the significant drop in 2001 during the
energy crisis. Loads from 1997 to 2008 are not weather normalized. Annual growth is
expected to be 1.7 percent over the next twenty years. The 2005 and 2007 IRP load
forecasts are presented for comparison purposes. Loads are moderately lower in the Lil
2009 IRP compared with the 2007 IRP due to the cumulative impact of additional
conservation measures from the 2007 IRP being incorporated in this forecast.
2-12 200 Electric IRP Avista Corp
Chapter 2 - Loads and Resources
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Peak Demand Forecast
The peak demand forecast in each year represents the most likely value for that year. It
does not represent the extreme peak demand. The most likely peak demand has a 50
percent chance of being exceeded in any year. The peak forecast is produced by
running a regression between actual peak demand and net native load. The peak
demand forecast is in Figure 2.12. Peak loads are expected to grow at 1.7 percent
between 2009 and 2019 (223 MW) and 1.7 percent over the entire 20-year forecast.
Avista Corp 2009 Electric IRP 2-13
Chapter 2 - Loads and Resources
2,600
2,400
2,200
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Figure 2.12: Calendar Year Peak Demand
Winter
-Summer
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Historical data are influenced by extreme weather events. The comparatively low 1999
peak demand figure was the result of a warmer-than-average winter peak day; the peak
in 2006 was the result of a below-average winter peak day. The 1999 and 2006 peak
demand values ilustrate why relying on compound growth rates for the peak demand
forecast is an oversimplification and why the Company plans to own or control enough
generation assets and contracts to meet peak demand during weather events.
Avista has witnessed significant summer load growth as air conditioning penetration has
risen in its service territory. That said, Avista expects to remain a winter-peaking utilty in
the foreseeable future. It is possible that very mild winter weather and extremely hot
summertime temperatures could result in our summer peak load exceeding our
wintertime demand level in a given year. This wil be an anomaly. The 2007 IRP
provided an ilustration of this trend into the future.
Figure 2.13 shows the high and low load growth scenarios compared to the base load
forecast. The high load growth scenario projects 2.6 percent load growth over the 20
year forecast. The low load forecast assumes 0.6 percent load growth over the next 20
years.
2-14 200 Electric IRP Avista Corp
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Avista Resources and Contracts
The Company relies on a diversified portolio of generating assets to meet customer
loads. Avista owns and operates eight hydroelectric projects located on the Spokane
and Clark Fork Rivers. Its thermal assets include partial ownership of two coal-fired
units in Montana, four natural gas-fired projects within its service territory, another
natural gas-fired project in Oregon and a biomass plant near Kettle Falls, Washington.
Spokane River Hydroelectric Projects
Avista owns and operates six hydroelectric projects on the Spokane River. These
projects received a new 50-year FERC operating license in June 2009. The following
section includes a short description of the Spokane River projects with the maximum
capacity and nameplate ratings for each plant. The maximum capacity of a generating
unit is the total amount of electricity a plant can safely generate. This is often higher
than the nameplate rating. The nameplate, or installed capacity is the plant's capacity
as rated by the manufacturer.
Post Falls
The upper most hydro facilty on the Spokane River is Post Falls, located at its Idaho
namesake near the Washingtonlldaho border. The project began operation in 1906 and
maintains lake elevation during the summer for Lake Coeur d'Alene. The project has six
units, with the last added in 1980. The project is capable of producing 18.0 MW and has
a 14.75 MW nameplate rating. Avista is studying the potential to replace the
Avista Corp 2-152009 Electric IRP
Chapter 2 - Loads and Resources
powerhouse with two larger units to increase energy production at the plant, and
another option to increase generation by upgrading Unit 6.
Upper Falls
The Upper Falls project began generating in 1922 in downtown Spokane and is within
the city's Riverfront Park. This project is comprised of a single 10.0 MW unit with a
10.26 MW maximum capacity rating. Rewinding the generator and replacing the runner
is evaluated in this IRP; the upgrade would increase generation by approximately 2.0
MW.
Monroe Street
The Monroe Street facility was the Company's first generating unit. It started service in
1890 near what is now Riverfront Park. Rebuilt in 1992, the single generating unit has a
15.0 MW maximum capacity and a 14.8 MW nameplate rating. In year's past a second
powerhouse at Monroe Street was evaluated. As part of the Company's efforts to
increase renewable generation, this option wil be studied further.
Nine Mile
The Nine Mile project was built by a private developer in 1908 near Nine Mile Falls,
Washington, nine miles northwest of Spokane. The Company purchased it in 1925 from
the Spokane & Eastern Railway. Its four units have a 17.6 MW maximum capacity1 and
a 26.4 MW nameplate rating. Currently Unit 1 provides no generation and Unit 2 is
limited to half load. These units wil be replaced and are expected to be online by 2012
and 2013. A rubber dam wil be added to the facilty, replacing f1ashboards, to take
advantage of high flows. The total incremental capacity is 8.8 MW and an additional 4.4
aMW of renewable energy from its former operational capabilty.
Long Lake
The Long Lake project is located northwest of Spokane and maintains Lake Spokane,
also known as Long Lake. The facilty was the highest spilway dam with the largest
turbines in the world when it was completed in 1915. The plant was upgraded with new
runners in the 1990s, adding 2.2 aMW of renewable energy. The project's four units
provide 88.0 MW of combined capacity and have an 81.6 MW nameplate rating. This
IRP evaluates two additional upgrades at the project, either an additional 24 MW unit in
the existing powerhouse or the development of a second powerhouse with a 60 MW
generator.
Little Falls
The Little Falls project was completed in 1910 near Ford, Washington, and is Avista's
furthest downstream hydro facility on the Spokane River. The facilty was recently
upgraded to generate an additional 0.6 aMW of renewable energy with a runner
replacement on Unit 4. The facility's four units generate 35.2 MW of maximum capacity
and have a 32.0 MW nameplate rating. Generator rewinds at each of these units were
included at as resource options in this IRP for a total potential of 4.0 MW of additional
capacity and 1.3 aMW of energy.
1 This is the de-rated capacity considering the outage of unit 1 and de-rate of unit 2
2-16 2009 Electric IRP Avista Corp
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Clark Fork River Hydroelectric Project
The Clark Fork River Projectincludes hydroelectric projects near Clark Fork, Idaho, and
Noxon, Montana, 70 miles south of the Canadian border. The plants are operated under
a FERC license through 2046.
Cabinet Gorge
The Cabinet Gorge plant started generating power in 1952 with two units. The plant was
expanded with two additional generators in the following year. The current maximum
capacity of the plant is 270.5 MW; it has a nameplate rating of 265.2 MW. Upgrades at
this project began with the replacement of Unit 1 in 1994. Unit 3 was upgraded in 2001
and Unit 2 was upgraded in 2004. Unit 4, received a $6 millon turbine upgrade in 2007,
increasing its generating capacity from 55 MW to 64 MW, and adding 2.1 aMW of
renewable energy. The Company is evaluating the addition of a fifth unit at the project.
This addition would add 50 to 60 MW of capacity and up to 10.2 aMW of renewable
energy.
Noxon Rapids
The Noxon Rapids project includes four generators installed between 1959 and 1960,
and a fifth unit added in 1977. The current plant configuration has a maximum capacity
of 541.0 MW and a generator nameplate rating of 480.6 MW. The project's units are
currently being upgraded. The Unit 1 upgrade was completed in April 2009 and the
remaining units wil be replaced over the next three years. The upgrades are expected
to add 30 MW of capacity and 6 aMW of qualified renewable energy to the Company's
resource portolio.
Total Hydroelectric Generation
In total, our hydroelectric plants are capable of generating as much as 986 MW. Table
2.2 summarizes the Company's hydro projects. This table also includes the average
annual energy output of each facility based on the 70-year hydrologic record.
Table 2.2: Company-Owned Hydro Resources
Nameplate Maximum Expected
River Start Capacity Capability Energy
Project Name System Location Date (MW)(MW)(aMW)
Monroe Street Spokane Spokane, WA 1890 14.8 15.0 11.6
Post Falls Spokane Post Falls, 10 1906 14.7 18.0 9.8
Nine Mile Spokane Nine Mile Falls, WA 1925 26.4 17.6 13.3
Little Falls Spokane Ford, WA 1910 32.0 35.2 23.7
Long Lake Spokane Ford, WA 1915 81.6 88.0 58.4
Upper Falls Spokane Spokane, WA 1922 10.3 10.0 8.6
Cabinet Gorge Clark Fork Clark Fork, 10 1952 265.2 270.5 123.8
Noxon Rapids Clark Fork Noxon, MT 1959 541.0 480.6 197.1
Total 986.0 934.9 446.3
Avista Corp 2009 Electric IRP 2-17
Chapter 2 - Loads and Resources
Thermal Resources
Avista owns seven thermal assets located across the Northwest. Each thermal plant is
expected to continue to be available through the 20-year duration of the 2009 IRP. The
Company's thermal resources provide dependable low-cost energy to serve base loads
and provide peak load serving capabilities. A summary of Avista's thermal resources is
shown in Table 2.3.
Colstrip
The Colstrip plant, located in Eastern Montana, consists of four coal-fired steam plants
owned by a group of utilities. PPL Montana operates the facilities. Avista owns 15
percent of Units 3 and 4. Unit 3 was completed in 1984 and Unit 4 was finished in 1986.
The Company's share of each Colstnp unit has a maximum net capacity of 111.0 MW
and a nameplate rating of 123.5 MW. Capital improvements to both units were
completed in 2006 and 2007 to improve effciency i reliability and generation capacity.
The upgrades included new high-pressure steam turbine rotors and a conversion from
analog to digital control systems. These capital improvements increased the Company's
share of generation by 4.2 MW at each unit without any additional fuel consumption.
Rathdrum
Rathdrum is a two-unit simple-cycle combustion turbine. The gas-fired plant is located
near Rathdrum, Idaho. It entered service in 1995 and has a maximum capacity of 180.0
MW in the winter and 126.0 MW in the summer. The nameplate rating is 166.5 MW.
Northeast
The Northeast plant, located in northeast Spokane, is a two-unit aero-derivative simple-
cycle plant completed in 1978. The plant is capable of burning natural gas or fuel oil, but
current air permits prevent the use of fuel oiL. The combined maximum capacity of the
units is 68.0 MW in the winter and 42.0 MW in the summer, with a nameplate rating of
61.2 MW. Northeast is primanly used for reserve capacity to protect against reliability
concerns and market aberrations.
Boulder Park
The Boulder Park project was completed in Spokane Valley in 2002. The site uses six
natural gas-fired internal combustion engines to produce a combined maximum capacity
and nameplate rating of 24.6 MW.
Coyote Springs 2
Coyote Springs 2 is a natural gas-fired combined cycle combustion turbine located near
Boardman, Oregon. The plant began service in 2003. The maximum capacity is 280.6
MW in the winter and 226.5 MW in the summer and the duct burner provides the unit
with an additional capability of up to 20.4 MW. The nameplate rating for this plant is
287.3 MW.
Kettle Falls and Kettle Falls CT
The Kettle Falls biomass facilty was completed in 1983 near Kettle Falls, Washington
and is one of the largest biomass plants in North America. The open-loop biomass
steam plant is fueled by waste wood products from area mills and forest slash, but can
2-18 Avista Corp200 Electric IRP
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Chapter 2 - Loads and Resources
also run on natural gas. A gas-fired CT was
added to the facility in 2002. The CT burns
natural gas and sends exhaust heat to the
wood facilities boiler to increase wood fuel
effciency.
The wood portion of the plant has a
maximum capacity of 50.0 MW and a
nameplate rating is 50.7 MW; typically the
plant operates between 45 and 47 MW due to
fuel quality issues. The plant's capacity
increases to 56.0 MW when operated in
combined-cycle mode with the CT. The CT
produces 5.2 MW of peaking capability in theKettle Falls Generation Station summer and 7.8 MW in the winter. The CT
resource has limited operations in winter when the gas pipeline is constrained. Avista is
evaluating upgrading the capacity of the pipeline, This IRP also evaluates the addition
of a wood gasifier to the project so that the CT can use less natural gas and generate
more renewable energy.
Table 2.3: Company-Owned Thermal Resources
Winter Summer
Maximum Maximum Nameplate
Start Capacity Capacity Capacity
Project Name Location Fuel Type Date (MW)(MW)(MW)
Colstrip 3 (15%)Colstrip, MT Coal 1984 111.0 111.0 123.5
Colstrip 4 (15%)Colstrip, MT Coal 1986 111.0 111.0 123.5
Rathdrum Rathdrum, 10 Gas 1995 180.0 126.0 166.5
Northeast Spokane, WA Gas 1978 68.0 42.0 61.2
Boulder Park Spokane, WA Gas 2002 24.6 24.6 24.6
Coyote Sprinos 2 Boardman, OR Gas 2003 301.0 246.9 287.3
Kettle Falls2 Kettle Falls, WA Wood/Gas 1983 50.0 50.0 50.7
Kettle Falls CT Kettle Falls, WA Gas 2002 7.8 5.2 7.2
Total 853.4 716.7 844.5
Power Purchase and Sale Contracts
The Company utilzes several power supply purchase and sale arrangements to meet
some load requirements. This chapter describes some of the larger contracts in effect
during the scope of the 2009 IRP. Contracts can provide many benefits including
environmentally low-impact and low-cost hydro and wind power. A 2010 annual
summary of Avista's large contracts is in Table 2.4.
2 Assumes combined cycle mode; when not in this mode the operational capacity is between 45-47 MW
depending upon fuel quality.
Avista Corp 2009 Electric IRP 2-19
Chapter 2 - Loads and Resources
Bonnevile Power Administration - WNP-3 Settlement
Avista (then Washington Water Power) signed settlement agreements with Bonnevile
Power Administration (BPA) and Energy Northwest (formerly the Washington Public
Power Supply System or WPPSS) on September 17, 1985, ending construction delay
claims against both parties. The settlement provides an energy exchange through June
30, 2019, with an agreement to reimburse the Company for certain WPPSS -
Washington Nuclear Plant NO.3 (WNP-3) preservation costs and an irrevocable offer of
WNP-3 capability for acquisition under the Regional Power Act.
The energy exchange portion of the settlement contains two basic provisions. The first
provision provides approximately 42 aMW of energy to the Company from BPA through
2019, subject to a contract minimum of 5.8 millon megawatt-hours. Avista is obligated
to pay BPA operating and maintenance costs associated with the energy exchange as
determined by a formula that ranges from $16 to $29 per megawatt-hour in 1987 year
constant dollars.
The second provision provides BPA approximately 32 aMW of return energy at a cost
equal to the actual operating cost of the Company's highest-cost resource. A further
discussion of this obligation, and how Avista plans to account for it, is covered under the
Planning Margin heading of this chapter.
Mid-Columbia Hydroelectric Contracts
During the 1950s and 1960s, public utilty districts (PUDs) in central Washington
developed hydroelectric projects on the Columbia River. Each plant was oversized
compared to the loads then served by the PUDs. Long-term contracts were signed with
public, municipal and investor-owned utilties throughout the Northwest to assist with
project financing and to ensure a market for the surplus power.
The Company entered into long-term contracts for the output of four of these projects
"at cost." The contracts provide energy, capacity and reserve capabilties; in 2010
contracts wil provide approximately 164 MW of capacity and 85 aMW of energy. Over
the next 20 years, the Wells (2018) and Rocky Reach (2011) contracts wil expire.
Avista may be able to extend these contracts; however, it has no assurance today that
extensions wil be offered. Due to this uncertainty, the IRP does not include these
contracts beyond their expiration dates.
Avista renewed its contract with Grant PUD in 2005 for power from the Priest Rapids
project. The contract term wil equal the term in the forthcoming Priest Rapids and
Wanapum dam FERC licenses in 2052.
Lancaster
Avista acquired the output rights to the Lancaster combined-cycle generating station as
part of the sale of Avista Energy to Shell in 2007. Lancaster is also known as the
Rathdrum Generating Station, but the plant is referred to as Lancaster in this IRP to
remove confusion with the Rathdrum CT. The project is under a tolling Power Purchase
Agreement (PPA) with Energy Investors Funds (80 percent owner) and Goldman Sachs
(20 percent owner) through October 2026. Avista has the right to dispatch the plant and
'".
2-20 2009 Electric IRP Avista Corp
L~
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Chapter 2 - Loads and Resources
is responsible for providing fuel, energy, and capacity payments. The 2007 IRP showed
that the Lancaster project was a lower cost acquisition than a greenfield site and was
also lower in cost than recent CCCT transactions in the Northwest.
Table 2.4: Large Contractual Rights and Obligations
2010
Winter Summer Annual
Capacity Capacity Energy
Contract Type End Date (MW)(MW)(aMW)
Canadian Entitlement Sale n/a 6.3 6.3 3.6
Douglas Settlement Purchase Sep-2018 2.5 3.9 3.7
Forward Market Purchase Dec-2010 100.0 100.0 100.0
Grant Displacement Purchase Sep-2011 17.4 19.6 22.0
Lancaster Purchase Oct-2026 281.0 264.0 237.8
Nichols Pumpina Sale n/a 6.8 6.8 6.8
PGE Capacity Exchange Dec-2016 150.0 150.0 0.0
Potlatch PURPA Dec-2011 75.0 75.0 47.6
Rockv Reach Purchase Oct-2011 34.5 34.0 20.3
Stateline Purchase Dec-2011 0.0 0.0 8.3
Stimson Lumber PURPA Sep-2011 4.2 4.4 4.2
Upriver (net load)PURPA Dec-2011 8.2 -1.3 6.1
Wanapum/Priest Rapids Purchase Mar-2052 67.6 66.6 34.8
Wells Purchase AUÇ.-2018 26.1 25.9 14.7
WNP-3 Purchase/Sale Jun-2019 89.3 0.0 42.3
Reserve Margins
Planning reserves accommodate situations when loads exceed and/or resources are
below expectations due to adverse weather, forced outages, poor water conditions or
other contingencies. There are disagreements within the industry on adequate reserve
margin levels. Many stem from system differences, such as resource mix, system size,
and transmission interconnections. For example, a hydro-based utility generally has a
higher capacity to energy ratio than a thermal-based utilty.
Reserve margins, on average, increase customer rates when compared to resource
portolios without reserves, due to carrying additional cost of generation. Reserve
resources have the physical capabilty to generate electricity, but high operating costs
limit economic dispatch and the potential to create revenues to offset capital
investments.
Avista Planning Margin
Avista retains two types of planning margins-capacity and energy. Capacity planning is
a traditional planning metric for many utilities to ensure they can meet peak loads at
times of system strain. Energy planning is used for utilties with resources that have an
unpredictable fuel source, such as wind and hydro, but also to cover load variance. For
capacity planning, Avista reseryes are not directly based on unit size or resource type.
Avista Corp 2009 Electric IRP 2-21
Chapter 2 - Loads and Resources
Planning reserves are set at a level equal to 15 percent planning reserve margin during
the Company's peak load hour.
For energy planning, resources must be adequate to meet customer requirements.
Extreme weather conditions can change monthly energy obligations by up to 30
percent. If generation capability does not meet high load variations, customers and the
utilty are exposed to increased short term market volatility. In addition to load variance,
Avista also uses a planning margin for its hydro generation. Unlike weather, hydro is not
normally distributed due to river regulation by the hydroelectric projects.
There is a difference of regional opinion concerning the proper method for establishing
a resource planning margin. Many utilities in the Northwest base their capacity planning
on critical water using the 1936/37 hydro year as the critical time period. The critical
water year of 1936/37 is poor on an annual basis, but it is not necessarily critical month-
to-month. The utilty could build resources to reach the 99 percent confidence level, and
could significantly decrease the frequency of market purchases, but this strategy
requires approximately 200 MW of additional generation capabilty. Additional capital
expenditures to support this level of reliabilty would put upward pressure on retail rates.
Analysis of historical data indicates that an optimal criterion is the use of a 90 percent
confidence interval based on the monthly variabilty of load and the 10th percentile of
monthly historical hydro energy. This results in a 10 percent chance of load exceeding
the planning criteria for each month. In other words, there is a 10 percent chance that
the Company would need to purchase energy from the market in any given month.
Additional variability is inherent in Avista's WNP-3 contract with SPA. The contract
includes a return energy provision that can equal 32 aMW annually. The contract would
be exercised under adverse conditions, such as low hydroelectric generation or high
loads. The contract was last exercised in 2001. Energy planning margin is increased by
32 aMW to account for the WNP-3 obligation through its expiration in 2019. The total
capacity planning margin and energy margin adds 267 MW of required capacity and
227 aMW of energy in 2010.
Other Planning Methods
Parallel to planning margins is a gray area between energy and capacity planning.
Sustained peaking and Loss of Load Probabilty (LOLP) metrics can be used to further
evaluate system constraints. Avista has actively participated in the Northwest Power
and Conservation Council's Resource Adequacy committees over the past few years.
This effort has used LOLP and sustained capacity analyses to evaluate the Northwest's
resource position over extended timeframes. Preliminary work indicates that the
Northwest should carry approximately a 25 percent planning margin in the wintertime
and a 17 percent planning margin in the summertime. These levels are much higher
than the 12 to 15 percent levels recommended in other markets, primarily due to the
Northwest's heavier reliance on hydroelectric generation. Given the uncertainties
surrounding higher planning margins, Avista wil not adopt the NPCC metrics in this
planning cycle. The Company wil continue to participate in the regional process and wil
use the results for future resource planning.
2-22 200 Electric IRP Avista Corp
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Chapter 2 - Loads and Resources
Sustained peaking capacity is a tabulation of loads and resources over a period
exceeding the traditional one-hour definition. It is also. a measure of reliabilty and
recognizes that peak loads do not stress the system for just one hour. The difference
from traditional one hour peak analysis is a look at multiple days versus one hour. The
analysis also considers hydro system impacts by freezing temperatures and hydro
reservoir depletion.
LOLP has only recently gained attention in the Northwest. The industry standard is a 5.0
percent acceptable loss of load. Avista has created a tool to evaluate LOLP, but there is
stil significant uncertainty surrounding how much energy from the wholesale market
would be available to Avista at a time of regional peak loads. At the first TAC meeting,
an early analysis was shown for 2009 and included many scenarios. The results of this
study indicated for the 2009 planning year the LOLP is 2.1 percent in the winter and 3.8
percent in the summer, but this includes a market availability of 300 MW. If only 200
MW of on-peak market is available, the LOLP increases to 7.4 percent in the winter and
12.1 percent in the summer. Additional studies are required for this analysis. The goal
for the LOLP tool is to ensure the Preferred Resource Strategy adds resources
adequate to meet reliabilty criteria, but the critical assumption is the amount of energy
available from the market. The Northwest Power and Conservation Council is studying
this problem, and Avista wil use the results from that process.
Washington State Renewable Portolio Standard
In the November 2006 general election, Washington State voters approved Citizens
Initiative 937. The initiative requires utilties with more than 25,000 customers to source
3 percent of their energy from qualified renewables by 2012,9 percent by 2016, and 15
percent by 2020. Utilities also must acquire all cost effective conservation and energy
effciency measures. Even though Avista does not require new resources to meet
forecasted loads through 2017, this new law requires Avista to acquire qualified
renewable generation or Renewable Energy Certificates (REC) resources it otherwise
would not need to meet the initiative's renewable goals.
Avista wil meet or exceed its renewable requirement goals between 2012 and 2015
with a recent REC purchase and qualified hydroelectric upgrades. The Company plans
to acquire resources to ensure that it is not forced to make REC purchases in a strained
market in nine of 10 years due to lower-than-expected wind and hydro generation
levels. See Table 2.5.
Resource Requirements
The differences between loads and resources ilustrate potential needs the Company
must address through future resource acquisitions. Avista regularly develops a 20-year
forecast of peak capacity loads and resources. Peak load is the maximum one-hour
obligation, including operating reserves, on the expected average coldest day in
January and the average hottest day in August. Peak resource capabilty is the
maximum one hour generation capability of Company resources, including net contract
contribution, at the time of the one-hour system peak, and excludes resource that are
on maintenance during peak load periods.
Avista Corp 2009 Electric IRP 2-23
Chapter 2 - Loads and Resources
Avista is surplus capacity through 2014. It then carries a modest deficit until the
Portland General Exchange contract expires in 2016. Avista is then capacity surplus in
2019. Deficits grow after 2018 as peaking requirements increase with load growth, and
as the Company's resource base declines with the expiration of market purchases and
Mid-Columbia hydroelectric project contracts. Winter and summer capacity positions are
shown in Figures 2.15 and 2.16, respectively. Tabular views of this data are in Table 2.6
and Table 2.7.
In addition to balancing capacity, Avista procures enough resources to meet its energy
obligations. The energy position includes resources at their full capabilty during normal
weather conditions in each month. It includes generation maintenance schedules and
loads based on expected normal temperatures. The first deficit . year for energy
(including the planning margin) is 2018. Quarterly deficits begin in the fourth quarter of
2014. A graphical representation of Avista's positions is shown in Figure 2.17; a tabular
version of the data is shown Table 2.8. Each of these charts includes conservation
levels per the 2007 IRP. In Chapter 8, conservation levels are updated to reflect 2009
IRP levels.
Figure 2.15: Winter Capacity Position
3,000
2,500
2,000ll;as 1,500a
CD
E 1,000
500
0 0 -N M ~It cø ..00 en 0 -N M ~It cø ..00 en----------N N N N N N N N N N00000000000000000000NNNNNNNNNNNNNNNNNNNN
2-24 Avista Corp2009 Bectric IRP
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3,000
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Figure 2.16: Summer Capacity Position
500
o O-NM~~~~~~O_NM~~~~~~-------___NNNNNNNNNN00000000000000000000NNNNNNNNNNNNNNNNNNNN
Figure 2.17: Annual Average Position
500 Hydro _ Base Thermal Contracts
_ Peakers Load Load wI ContoO-NM~~~~~~O_NM~~~~~~------____NNNNNNNNNN00000000000000000000NNNNNNNNNNNNN~NNNNNN
~~~~,
Avista Corp 2009 Electric IRP 2-25
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Chapter 3 - Energy Efficiency
3. Energy Efficiency
Introduction
Avista's energy effciency programs provide a wide
range of conservation options and education for
residential, commercial, industrial and low income
customers. Programs fall into prescriptive and site-
specific classifications. Prescriptive programs offer
cash incentives for standardized products, such as
compact fluorescent light bulbs and high effciency
appliances. These programs are primarily directed
towards residential and small commercial
customers. Site-specific programs provide cash
incentives for any cost-effective energy savings
measure with a payback greater than one year.
These site-specific programs require customized
services for commercial and industrial customers
because many applications need to be tailored to
the unique characteristics of customer's premises
and processes. Energy efficient window replacement at Avista's
headquarters in Spokane, Washington
Chapter Highlights
· Conservation additions provide 26 percent of new supplies through 2020.
· 20091RP includes 0.3 aMW (3.3 perænt) more conservation than the 20071RP.
· Avista has offered conservation programs for over 30 years.
· The Company has acquired 138.5 aMW of electric effciency in the past three
decades; an estimated 109 aMW continue to reduce customer loads.
· The Company is prepared to quickly respond to another energy crisis with
effciency measures.
· Approximately 3,000 effciency measures were evaluated for the 2009 IRP.
· 7.5 aMW of local and 2.9 aMW of regional conservation are expected in 2010.
Avista has continuously offered electric effciency programs since 1978. Some of
Avista's most notable effciency achievements include the Energy Exchanger programs,
which converted over 20,000 homes from electric to natural gas space or water heating
from 1992 to 1994; pioneering the country's first system benefit charge for energy
effciency in 1995; and the immediate conservation response during the 2001 Western
energy crisis which tripled annual energy savings at only twice the cost in half the time
during a period of high wholesale market prices. The Company's conservation programs
provide savings that regularly meet or exceed its regional share of energy effciency
savings as outlined by the Northwest Power and Conservation Council (NPCC). Figure
3.1 ilustrates Avista's tiistorical electricity conservation acquisitions.
Avista Corp 2009 Electric IRP 3-1
Chapter 3 - Energy Effciency
Figure 3.1: Historical Conservation Acquisition
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Avista has acquired 138.5 aMW of cumulative electricity effciency resources over the
last 30-years; of the 138.5 aMW total, 109 aMW acquired during the last 18 years is
assumed to stil be online and providing resource value today. Northwest Energy
Effciency Alliance's (NEEA's) cumulative conservation estimates are based on an 18-
year average weighted measure life.
All conservation measures and programs have been examined based on surrogate
generation costs in this IRP. New savings targets have been established and the
Company is planning a significant ramp-up of energy effciency activity in the coming
years.
Avista is also expanding the breadth of its energy effciency activities to include demand
response initiatives and is analyzing the potential for transmission and distribution
effciency measures. More details about transmission and distribution effciency projects
can be found in the Transmission and Distribution chapter of this IRP. Our demand
response pilot is stil in process, so there is not enough data to currently determine if
Avista wil continue demand response initiatives, and they were not included in this IRP.
The results of the demand response pilot wil be addressed in detail in the 2011 IRP.
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Chapter 3 - Energy Efficiency
Cooperative Regional Market Transformation Programs
Avista is a funding and fully participating member of NEEA, www.nwalliance.org. NEEA
is funded by regional investor-owned and public utilities to acquire electric effciency
measures that are best achieved through broad market transformation efforts. These
programs reach beyond individual service territories and consequently require regional
cooperation to succeed.
Past NEEA funding has been $20 milion shared throughout the region. Avista's four
percent annual portion of NEEA funding has been $800,000. The Northwest funding
utilties have been discussing increasing this amount by 50 percent or more and
reapportioning member shares to reflect current retail load. Avista's share would be
increased from 4.0 percent to 5.41 percent. This increase in our regional funding share
would increase our savings acquisition by 30% or more. NEEA has proven to be a cost-
effective component of regional resource acquisition. Avista has and continues to
leverage NEEA ventures when cost-effective enhancements can be achieved.
Attributing regionally acquired conservation savings to individual utilties is diffcult. To
ensure that resources are not double-counted at regional and local levels, NEEA has
excluded all energy for which local utility rebates have been granted. This allows the
summation of local and regional acquisitions to determine the total impact in a market.
Avista has typically applied our funding share of slightly less than four percent to
NEEA's annual claim of energy savings. It was assumed that historic acquisitions would
remain flat at the most recent level because there are no reliable 20-year estimates of
regional program acquisitions. This assumption is speculative and dependent on the
opportunities for regional market transformation during this period. It is consistent with
the recent history of NEEA funding.
Program Funding
Avista changed its approach to conservation cost-recovery in 1995 from the traditional
capitalization of the investments to cost-recovery through a non-bypassable public
benefits surcharge (the tariff rider). Avista currently manages four separate tariff riders
for Washington electric, Idaho electric, Washington natural gas and Idaho natural gas
investments. Based upon the demand for funds and incoming tariff rider revenues, this
balance can be positive or negative at any particular point in time.
The aggregate tariff rider balances were returned to a zero balance in 2005 from a
$12.4 millon deficit in the aftermath of the 2001 Western energy crisis. Recent demand
for conservation services has exceeded tariff rider revenues. The most recent projection
forecasts a $3.6 millon negative balance in the Washington electric DSM tariff rider by
the end of 2009. The Idaho electric tariff balance is projected to be just below $4.0
millon with schedule 91 increases effective August 1,2009.
Energy Independence Act
Washington's Energy Indpendence Act, established under Initiative 937 (1-937), and
codified under RCW 19.285, requires utilties with over 25,000 customers to obtain a
fixed percentage of their electricity from qualifying renewable resOurces. The mandates
are three percent of retail load in Washington by 2012, nine percent by 2016 and 15
percent by 2020. As experienC&nas shown in other jurisdictions, these requirements
AvistaCorp 2009 Electric IRP 3-3
Chapter 3 - Energy Efficiency
could be changed by the state legislature in the future. In addition to its RPS, 1-937 also
requires utilities with over 25,000 customers to acquire all cost-effective and achievable
energy conservation. The methodology for identifying the conservation target must be
consistent with the methods used by the Northwest Power and Conservation Council
(NPCC) in its power plans. Avista's methodology for identifying its conservation target is
consistent with the NPCC Sixth Power Plan methodology to the extent possible given
the timing of the two processes (this IRP was completed prior to the completion of the
Sixth Power Plan). The conservation inputs for this IRP process leveraged the NPCC
work. To the extent that significant changes are incorporated into the Sixth Power Plan
after the completion of this IRP, it is Avista's intent to reserve the opportunity to
substitute our share of the regional conservation potential ultimately defined by the Sixth
Power Plan, on a year-by-year basis, for the conservation targets identified in this IRP.
The first performance period for the Washington energy effciency target wil be 2010-
2011. Washington regulations require the Company to file its biennial conservation
target on or before January 31, 2010. Avista's report, as required by WAC 480-109
(3)(c), wil "describe the technologies, data collection, processes, procedures and
assumptions the utility used to develop these figures. This report must describe and
support any changes in assumptions or methodologies used in the Utilty's most recent
IRP or the Conservation Council's (NPCCi Power Plan." WAC 480-109 requires
approval, approval with modifications or rejection by the WUTC of the Company's
targets. Avista's filing wil follow, and this IRP wil be consistent with, the NPCC's Sixth
Power Plan. The Company's report will include traditional conservation efforts (possibly
exclusive of electric to natural gas conversions), non-programmatic adoption of energy
effciency measures consistent with the Sixth Power Plan and distribution effciency
measures which would include savings on the utility and customer sides of the meter.
Since distribution effciencies count toward our goal, meeting plan requirements with the
least net cost to ratepayers wil involve interdepartmental coordination of efforts and
development of new processes.
American Recovery and Reinvestment Act of 2009
Portions of the American Recovery and Reinvestment Act of 2009 (ARRA) provide
economic stimulus funding for energy conservation, including residential audits,
weatherization and smart grid development. Avista is working with local governments to
field residential audits funded by a combination of our energy effciency tariff rider, local
government Energy Effciency Conservation Block Grant (EECBG) funds, State Energy
Program funds and the customer. The most recent iteration of these analyses calls for a
"mid-level" audit that includes the installation of low-cost measures such as CFL's, door
sweeps, water tank blankets, low-flow showerheads, furnace filter replacements,
refrigerator and coil cleaning and several infiltration reduction measures. The audit is a
$325 direct investment including about $160 in low-cost direct-install measures and
$165 in auditor labor cost. The Company anticipates some program administrative labor
needs on the back-end and estimates this to be the equivalent of about 2.9 full-time
employees.
3-4 Avista Corp2009 Electric IRP
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Chapter 3 - Energy Efficiency
The Company currently estimates that customers wil pay $150, with the remainder of
the $325 incremental audit cost being spli between the tariff rider and local government
EECBG funds. The full cost of back office labor wil also be funded by the tariff rider. If a
local government chooses to not provide EECBG funds, customers will be responsible
for paying the total cost of the audit. This enables Avista to offer this service throughout
our Washington and Idaho jurisdictions, regardless of how different local governments
choose to use their EECBG funds.
The ARRA economic stimulus funding low income weatherization wil be allocated
directly to regional community action agencies, as they already have the infrastructure
necessary to distribute these funds to low income customers. Therefore, Avista will not
be involved in administering programs funded under this portion of the ARRA. Low
income populations served by the economic stimulus funding wil not be counted
towards our conservation goals since the Company is not contributing to the acquisition
process.
Avista may participate in a regional smart grid demonstration project. The project scope
would include distribution automation, distributed generation, energy storage, advanced
metering infrastructure (AMI), softare and support and demand response. The
application deadline for this project is August 26, 2009.
Electricity Efficiency in the 2009 IRP
Avista has reviewed its effciency options to ensure it is evaluating all alternatives in an
effort to delay building additional generation industry infrastructure. The Heritage Project
began during the 2007 IRP evaluation and "roadmaps" for several key areas were
developed and followed. The road maps included: energy effciency, demand response,
transmission and distribution, and analytics.
Energy Effciency
The Company has completed a comprehensive assessment of industry best practices in
energy effciency and enhanced its program offerings. As a result of this process, the
Company launched rebate programs for residential fireplace dampers, non-residential
prescriptive side-stream filtration, prescriptive energy/heat recovery ventilation,
prescriptive demand control ventilation, prescriptive steam trap maintenance, retro-
commissioning, as well as offering CFL coupons and community outreach and
education on low cost and no cost ways to save energy. In addition, the Company has
an on-going Facilties Model Program focusing on energy effciency while maintaining
and upgrading our facilities. Several projects at Avista's facilities, such as HVAC control
upgrades, variable frequency drives (VFDs) on fan motors, and upgrades to the
economizer cooling were estimated to save the Company 270,000 kWh and nearly
20,000 therms per year. The Company continues to assess the implementation of cost-
effective energy effciency upgrades where appropriate.
Load Management
While Avista faces higher market prices during peak demand periods, our costs are very
different from other parts of the country. Technology costs continue to..,decline while
technological improvements continue to develop making integration with our system a
Avista Corp 2009 Electric IRP 3-5
Chapter 3 - Energy Effciency
possibility. Since the Load Management Roadmap was developed, a program manager
was added to evaluate load management. As part of this effort, a two year pilot of end-
use control technology as well as customer acceptance was launched. This pilot wil be
completed on December 31, 2009. The Company wil report on the pilot results in the
20111RP.
Analytics
Identification of cost-effective energy effciency through traditional conservation or
distribution efficiencies, as well as demand response, is dependent upon a technically
sound and transparent analytical approach. Representatives from several departments
developed concepts for resource evaluation of six resource value categones. Four of
these values are part of a total avoided cost of energy usage while the remaining two
values represent reductions in system coincident peak. Components included in the
avoided cost of energy are commodity cost of energy, avoidance of carbon emissions,
reducing retail rate volatilty, and transmission and distribution system loss reduction.
The value of system coincident peak capacity includes deferring future investments in
generation capacity and transmission and distribution.
Transmission and Distribution
Avista completed a comprehensive assessment of the available cost-effective electric
effciency opportunities. This is always a factor in the completion of alllRP efforts given,
but it is significantly increased. Further evaluation of these effciency opportunities
continue past the IRP processes. Avista evaluates energy-effciency potential for the
IRP in a manner that can augment the conservation business planning process and
ultimately lead to appropriate revisions in effciency acquisition operations.
Consistency between the IRP Evaluation and Conservation Operations
Avista evaluates energy-effciency potential for the IRP in a manner that can augment
the conservation business planning process and ultimately lead to appropriate revisions
in conservation acquisition operations.
Avista utilizes the IRP process to comprehensively reevaluate the conservation market.
This assessment evaluates individual technologies (generally prescriptive programs)
where possible as well as program potential when a technology approach is infeasible.
The evaluation assesses resource characteristics and constructs a conservation supply
curve using the levelized total resource cost (TRC) and acquirable resource potential for
each technology. Cost-effective technologies, compared to the defined avoided cost,
are incorporated into the IRP acquisition target.
Further detailed program evaluation is applied when technologies in the program cannot
be defined to permit their individual evaluation. This is the case in the Company's
comprehensive limited income program, a portion of the non-residential site specific
programs and the cooperative regional programs. The target acquisition for these
programs is based on the modification of the historical baseline for known or likely
changes in the market. This includes but is not necessanly limited to modifying the
baseline for pnce elasticity and load growth.
3-6 2009 Electric IRP Avista Corp
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Chapter 3 - Energy Effciency
Evaluation of Efficiency Technology Opportunities
The Regional Technical Forum (RTF) periodically surveys Pacific Northwest utilities and
evaluates the amount of remaining conservation potential in the region. The Company
used the results of these efforts as the starting point for evaluating different types of
conservation technologies. Approximately 3,000 effciency concepts were evaluated by
Avista's staff using a six-stage review process. The process began with concepts using
easily obtained data and moved toward more technically rigorous analyses. Measures
that ranked poorly on the initial review did not receive further consideration. The
individual phases of the analytical process are as follows.
Defining: Refinement and redefinition of the concept list to eliminate duplicative
concepts and develop common definitions.
Qualitative ranking: The refined concepts were ranked based on a qualitative
feasibility assessment. Concepts determined to not be acquirable through utility
intervention were eliminated from further consideration.
Defining cost characteristics: Concepts with a reasonable potential for incorporation
in the conservation portolio were evaluated based on preliminary assessments of cost-
effectiveness. This step required estimates of incremental customer cost, non-energy
benefits, energy savings and measure life to develop a TRC levelized cost. Concepts
were sorted based upon these cost characteristics.
Defining resource potential: Acquirable potentials for concepts specific to Avista's
customers were estimated for the remaining concepts. These acquirable potentials
came from an evaluation of technical and economic potential adjusted for utilty
intervention limitations to address barriers to customer adoption regardless of the
economics.
Identifying load profiles: The value of capacity contribution (transmission, distribution
and generation) is also included for evaluation of the total avoided cost. The Company
based the avoided cost of energy on a 20-year, 8,760-hour avoided cost matrix. A 70-
year avoided cost projection was also developed to account for the longevity of some
measures. This avoided cost structure made it necessary to develop an 8,760-hour load
profile for each evaluated measure. Avista uses thirt-three residential and non-
residential load profiles in this part of the exercise. Appendix C contains a list of the load
profiles used in this analysis.
Calculating TRC cost-effectiveness: A full TRC cost-effectiveness evaluation was
performed on the remaining 706 residential and 2,484 non-residential concepts. The
following section provides a more detailed explanation of the review of these concepts.
A summary list of concepts reaching the evaluation stage is included in Appendix D.
Evaluation of TRC Cost-Effectiveness for Finalist Concepts
The construction of the TRC cost for each measure was based on the incremental
customer cost. Non-energy benefits were considered, but none of the evaluated
measures had a large enough non-energy benefit to materially change the final cost-
effectiveness evaluation.
Estimating the TRC values is an intrinsically quantitative process. This requi~~d a
. .. ~present value calculation of the avoided energy and capacity cost over the measu~re.life
Avista Corp 2009 Electric IRP 3-7
Chapter 3 - Energy Effciency
for each concept. The avoided cost of energy was based upon an application of the
mèasure's 8,760-hour load profile to the 8,760-hour avoided cost structure.
For purposes of measure evaluation, it was appropriate to focus upon deferring a
summer space-cooling-driven load. The 3,190 evaluated concepts had significant
differences in their impact upon system coincident load and these differences were not
always apparent based upon the general pattern of the measure load shape. To
determine the expected impact upon the deemed space cooling-driven system peak
load the 3,190 concepts and 33 load shapes (including a flat load option) were
categorized into three groups.
Zero impact: Measures that would not have any impact on a summer space-cooling-
driven peak received a zero valuation regardless of their load profile. This includes
measures such as residential space-heating effciencies.
Non-Drivers: Measures that were not related to space cooling but would potentially
contribute to system load during a space cooling-driven peak received a capacity
valuation based upon the average demand of their specific load profile during eight hour
summer peak load period. The eight peak hours were 1 pm to 8 pm, weekdays only,
between June 15 and September 15. These measures include commercial lighting and
residential appliances.
Drivers: Measures that would drive a space cooling peak received a capacity valuation
based on the maximum hourly demand identified in their 8,760-hour load profile. This
includes measures such as residential and non-residential air conditioning effciency.
A TRC ratio was developed after the TRC cost and benefit calculations were completed.
Even though this analysis limits the identification of future DSM acquisition to measures
that fully pass the TRC cost-effectiveness test, the Company plans on evaluating all
measures with a benefit-to-cost ratio of 0.75 or higher in order to provide a fair
evaluation of the marginally failng measures.
Having identified TRC cost-effective measures, the next step determined the annual
acquisition of the identified potentiaL. This completed the evaluation of those concepts
that were suitable for review by groups of technology types within the IRP. These
results are revisited following the explanation of the programmatically reviewed
elements of the DSM portolio.
Evaluation of Comprehensive Program Elements
The all-inclusive nature of Avista's non-residential site specific and limited income
portolios make it infeasible to generically evaluate the entire spectrum of possible
efficiency measures. Nevertheless, it is necessary to develop estimates for the potential
of these markets in order to establish a meaningful business planning process. Unique
effciency measures could not be generically evaluated as individual technologies. In
place of this approach, the Company established a historical baseline level of
acquisition and modified it to incorporate the impact of known or likely changes in the
market.
The Company's limited income portolio is all-inclusive for qualifying effciency
measures. The portolio is implemented in cooperation with community action agencies
that are given wide latitude in their approach to distributing. program funds. No changes
3-8 Avista Corp200 Electric IRP
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were expected in the abilty of agency infrastructure to deliver these programs, and
there were not any known market or technology changes that would cause a significant
change in the ability to obtain effciency resources from this segment. It was determined
that a historical baseline would be the most appropriate starting point for estimating
future throughput. The economic stimulus funding from the ARRA for low income
weatherization was unknown at the time this analysis was completed. There may be
material increases in the low income population served by the economic stimulus
funding. Analysis funding impacts wil be treated as an Action Item for reporting in the
2011 IRP. This historical baseline was modified for load growth and retail price elasticity
based upon assumptions consistent with the forecasts available at the time. This
resulted in a forecast of limited income acquisition for incorporation into the final
conservation forecast.
Although some of the measures incorporated into the site-specific program were
specifically evaluated, a large portion of non-residential acquisition comes from
measures which could not be generically evaluated. As with the limited income
program, the historical baseline was modified for anticipated load growth and retail price
elasticity to develop a forecast. Unlike the limited income program, it was necessary to
separate the specifically evaluated measures from the historical baseline, and then
combine the two again as part of the final expected conservation acquisition. This
process is illustrated in a flowchart in Appendix E.
Technical Potential
Every five years, the NPCC develops a regional Power Plan that evaluates technically
available conservation potentiaL. This amount is reduced to reflect the fraction of
measures that can never be practically achieved, even if the measures were free and
cost-effective. The Council believes this practically achievable conservation potential
can reach penetration levels of 85 percent over the next twenty years.
The Sixth Power Plan is currently being drafted and wil not be completed until after
submission of the 2009 IRP, however, the Council's most recent draft plan estimates
Avista's portion of the regional target to be 329 aMW for the twenty year period. This is
an early estimate but should be within 10 to 15 percent of the final regional technical
potential per the Council's Sixth Power Plan.
The Company's last external study on our energy savings potential was done in 2005.
As an action item, Avista is committing to updating our estimates through another third-
party savings potential study. We anticipate this study wil cover all states and fuels
intended to be used in the preparation of the 2011 IRP.
The Council only provides targets at a higher, utilty leveL. Our measures along with their
acquirable potential are ilustrated in Appendix F.
Avista Corp 2009 Electric IRP 3-9
Chapter 3 - Energy Efficiency
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Compilation of the Final DSM Resource Estimates f'
The following conservation targets were developed by summing individually evaluated
concepts and the evaluated programs over a 20-year period. The first two years of the r '
targets are detailed in Table 3.1. Transmission and Distribution effciency improvements t
are covered in Chapter 5.
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Table 3.1: Current Avista Energy Efficiency Programs
Portfolio 2010 Target 2011 Target
Limited Income Residential 1,977,099 2,056,183
Residential 20,518,584 21,339,327
Prescriptive Non-Residential 18,211,396 18,939,852
Site-Specific Non-Residential 24,936,765 25,934,236
Total Local Acquisition (kWh)65,643,844 68,269,598
Local 7.5 7.8
ReQional 2.9 2.9
Total before Distribution Effciencies (aMW)10.4 10.7
Estimated NPCC Sixth Plan Goal (aMW)11.2 12.4
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A graphical representation of the annual conservation targets for the full 20-year horizon
is ilustrated in Figure 3.3. A flat annual 2.94 aMW estimate of Avista's share of regional
resource acquisition (Avista's pro-rated share of NEEA's annual savings) is included in
the estimate. In the absence of reliable 20-year estimates of regional program
acquisition, it was assumed that historic acquisition levels would remain flat at their
most recent anticipated leveL. This assumption is speculative and dependent on the
opportunities for regional market transformation during this period, but is consistent with
the recent history of flat NEA funding.
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3-10 2009 Electric IRP Avista Corp
Chapter 3 - Energy Efficiency
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. Regional (NEE)
. Local (Avista)
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A measure-by-measure stacking of the 845 evaluated concepts, in ascending order of
levelized TRC, leads to a traditional upward-sloping supply curve for this component of
the conservation target, as ilustrated in Figure 3.3. Supply curves for 2010 and 2011
have been shown to represent the two years before the next IRP. The rightward shift of
the supply curve over time is a consequence of the assumption that lower cost
measures will be less available in subsequent years due to early adoption thereby
causing movement up the supply curve.
Since there is a gap in the cost of energy effciency measures, the measures with a very
high total resource cost cause a rapid sloping of the supply curve. Therefore, measures
with a total resouræ cost in excess of $0.50 per kwh have not been included in Figure 3.3
Avista Corp 200 Electric IRP 3-11
Chapter 3 - Energy Effciency
Figure 3.3: Supply of Evaluated Conservation Measures (Levelized TRC Cost)
0.50
0.45
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annual GWH acquisition
Integrating IRP Results into the Business Planning Process
The IRP evaluation process provides a high-level estimate of cost-effective
conservation acquisition. Avista uses the results of the IRP evaluation to establish a
budget for conservation measures, determine the size and skil sets necessary for future
conservation operations, and identify general target markets for programs. However, the
results are not detailed enough to become an operational conservation business plan.
The results of the IRP analysis establish baseline goals for continued development and
enhancement of Avista's conservation programs. The near-term conservation business
planning is summarized by portolio in the following sections.
Residential Portolio
A review of residential program concepts and sensitivity to key assumptions indicate
that more detailed assumptions based on actual program plans and target markets may
improve the cost-effectiveness of many of the residential concepts that marginally failed
in this analysis. To account for this marginal failure rate, all concepts with TRC benefit-
to-cost ratios of 0.75 or better are evaluated as part of the business planning process.
Over 62 percent (443 out of 706) of the evaluated residential concepts met the criteria.
Measures unavailable for the IRP evaluation wil be inserted into a reevaluation
process for possible inclusion in the Business Plan.
Limited Income Residential Portolio
Avista is committed to maintaining stable funding and maintaining program flexibilty for
limited income conservation programs. There are six local community action partner
(CAP) agencies the Company funds to deliver limited income weatherization and energy
effciency programs. Five of the funded agencies offer electric effciency measures. CAP
agency funding is currently set at $1,972,000 millon per year ($490,OOO'to Idaho and
3-12 Avista Corp2009 Electric IRP
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Chapter 3 - Energy Efficiency
$1,482,000 to Washington). Limited income programs include infiltration, insulation,
Energy Star approved windows, doors and refrigerators, space and water heating
upgrades, and electric to natural gas space and water heating conversions. CAP
agencies can offer other cost-effective programs with Avista's approval. These
programs require periodic updates because of changes in fuel focus and target
measures. The Company is quantifying potential impacts of the three-year Northwest
Sustainable Energy for Economic Development project.
Non-Residential Portolio
There is suffcient uncertainty and potential. for improvement in evaluated non-
residential program concepts to warrant regular reevaluations to ensure they retain a
minimum TRC cost-to-benefi ratio of 0.75 based on refined program planning
assumptions. Ninety four percent (2,337) of the 2,484 non-residential concepts
evaluated for the IRP meet the TRC criteria. The programs wil be reviewed for target
marketing, the creation of a prescriptive program, or for targeting under a site-specific
program.
All electric-effciency measures with a simple payback exceeding one year automatically
qualify for the non-residential portfolio. The IRP provides account executives, program
managers and end-use engineers with valuable information regarding potentially cost-
effective target markets. However, the unique and specific characteristics of a
customer's facilty override any high-level program prioritization.
Demand Response
The Idaho Public Utilities Commission approved a residential demand response pilot
launched in July 2007. Smart thermostats and direct control unit (DCU) switches for
water heaters, as well as compressors for heat pumps or air conditioners, were selected
for this pilot. Seventy-two customers participated in the Sandpoint and Moscow area
projects. Two demand response events were called during 2008 and three demand
response events were called during the winter of 2008-2009. This pilot is scheduled to
continue through December 31, 2009. The Company anticipates calling two to three
additional summer events and two to three more winter events before the end of this
pilot. Test results were not available in time for the 2009 IRP.
Summary
The IRP evaluation process assists the Company in developing a conservation
business plan and meeting regulatory requirements. Avista uses this opportunity for
comprehensive evaluation as an integral part of the ongoing management of Avista's
conservation portolio. The acquisition targets provide valuable information for future
budgetary, staffng and resource planning needs. However, numerical targets do not
displace the Company's fundamental obligation to pursue a resource strategy that best
meets customer needs under a continually changing environment. The effciency targets
established in this IRP planning process may be modified as necessary to meet these
evolving obligations.
Avista Corp 2009 Electric IRP 3-13
Chapter 4 - Environmental Policy
4. Environmental Policy
Environmental policy often means different things to different stakeholders. The 2007
IRP included a chapter on emissions that focused on legislation and regulations
concerning sulfur dioxide, nitrogen oxide, mercury, and carbon dioxide (C02); including
modeling assumptions used for each emission type. With the exception of CO2, current
regulatory environment diminishes the need for a specific discussion of other emissions
in this chapter. Current Washington laws, specifically an emissions performance
standard, effectively forbid the addition of new coal plants in the Preferred Resource
Strategy, and mercury controls have been added to the Company's coal projects
located in Colstrip, Montana. This chapter is dedicated to a discussion of the two most
important areas of environmentally related legislation: renewable portolio standards
and the regulation of greenhouse gases.
Environmental Concerns
Greenhouse gas emissions present a resource planning challenge because of
continuously evolving legislative developments resulting in ever-changing projections of
the scope and costs of a carbon allocation market. If environmental concerns were the
only issue faced by utilities, resource planning would be reduced to choosing the
required amount and type of renewable generating technology to use. However, utilty
planning is compoonded by the need to maintain system reliability, acquire least cost
resources, mitigate price volatility, meet renewable generation requirements and satisfy
future greenhouse gas emissions constraints. Each generating resource also has
distinctive operating characteristics, cost structures and environmental challenges.
Traditional generation technologies are financially and operationally well understood.
For example, coal~fired units have high capital costs, long lead times, and relatively low
and stable fuel costs. They are diffcult to site because of state laws, local opposition
and environmental issues ranging from mercury to greenhouse gas emissions. There
are also problems with the remote locations of coal mines or the high cost of
transporting coaL. Natural gas-fired plants have relatively low capi1al costs, can be
located closer to load centers than coal plants, can be constructed in a relatively short
time frame, and have much lower emission levels than traditional coal-fired
technologies, but they are affected by high fuel price volatility.
Chapter Highlights
· Avista supports national greenhouse gas legislation that is workable, cost
effective, fair, protects the economy, supports technological innovation, and
addresses emissions from developing nations.
· The Company is a member of the Clean Energy Group.
. The Company is gaining experience in trading carbon credits through its
membership in the Chicago Climate Exchange.
· Avista's Climate Change Committee monitors emissions legislation and
issues.
· Avista participates in the annual Carbon Disclosure Project.
Avista Corp 2009 Electric IRP 4-1
Chapter 4 - Environmental Policy
Renewable energy technologies such as
wind, biomass, and solar have different
challenges. Renewable resources are
attractive because they have low or no
fuel costs and low or no emissions. But,
they provide limited on-peak capacity,
present integration challenges and have
high upfront capital costs. Similar to coal
plants, renewable resource projects are
usually located where their fuel source is
Newly installed solar panels at Avista's headquarers most abundant. Remote locations may
in Spokane, Washington require significant investment in
transmission interconnection and capacity expansion, as well as resolution of possible
wildlife and aesthetic concerns. Unlike coal or natural gas-fired plants, the fuel for non-
biomass renewable resources cannot be transported from one location to another to
better utilze existing transmission facilities or minimize opposition to project
development. Biomass facilties can be particularly challenged because of their
dependence on the health of the forest products industry and access to biomass
materials located in publicly-owned forests.
Furthermore, the long-term economic viability of renewable resources is uncertain for at
least two important reasons. First, federal investment and production tax credits are
scheduled to expire within the planning horizon of this IRP and their continuation cannot
be relied upon in light of the impact such subsidies have on the finances of the federal
government and the relative maturity of wind technology development. Second, the cost
of renewable technologies is affected by many relatively unpredictable factors, including
renewable portolio standard mandates, material prices and currency exchange rates.
There is stil a great deal of uncertainty regarding greenhouse gas emissions regulation.
There continues to be strong regional and national support for addressing climate
change. Since the publication of the 2007 IRP, many changes in the approach and
potential for actual greenhouse gas emissions regulation have occurred, including:
· Diferent and changing federal legislative proposals: Lieberman-Warner, Dingell-
Boucher, and now Waxman-Markey;
· Leadership changes at the federal level leading to a determination to address
climate change. The election of President Obama and the commitment of
Congressional leaders to enact climate change legislation in the near-term.
· Passage of H.R. 2454, the American Clean Energy and Security Act;
· Joining RPS and greenhouse gas issues under the Waxman-Markey legislation;
and
· Developments in climate change legislation in jurisdictions such as Washington
and Oregon.
4-2 2009 Electric IRP Avista Corp
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Chapter 4 - Environmental Policy
Climate Change Policy Efforts
Avista's Climate Change Committee (CCC) was chartered as an internal clearinghouse
for all matters related to climate change. In regards to climate change, the CCC:
· Anticipates and evaluates strategic needs and opportunities relating to climate
change;
· Analyzes the company-wide implications of various trends and proposals;
· Develops recommendations on positions and action plans; and
· Facilitates internal and external communications regarding climate change
issues.
The core team of the CCC includes members from Environmental Affairs, Government
Relations, Corporate Communications, Engineering, Energy Solutions, and Resource
Planning. Other areas of the Company are invited as needed. The monthly meetings for
this group include work divided into immediate and long term concerns. The immediate
concerns include reviewing and analyzing state and federal legislation, reviewing
corporate climate change policy, and responding to internal and external data requests.
Longer term issues involve emissions tracking and certification, providing
recommendations for greenhouse gas reduction goals and activities, evaluating the
merits of different reduction programs, actively participating in the development of
legislation, and benchmarking climate change policies and activities against other
organizations.
Avista has maintained its membership in the Clean Energy Group which includes
Calpine, Entergy, Exelon, Florida Power and Light, Pacific Gas & Electric and Public
Service Energy Group. This group collectively evaluates and supports different
greenhouse gas legislation such as H.R. 2454, the American Clean Energy and
Security Act of 2009, submitted by Congressmen Henry A. Waxman and Edward J.
Markey and narrowly passed in June 2009. This legislation aims to combine RPS,
greenhouse gas and energy effciency issues under a single bil. Avista also participates
in hydro and biomass issues through its membership in national hydroelectric and
biomass associations.
Avista's Position on Climate Change Legislation
Avista expects comprehensive federal greenhouse gas legislation to be enacted within
the next two to three years. This is slightly longer than projected in the 2007 IRP,
primarily because of issues involving the current recession taking up legislative time.
The current lack of definitive legislation makes for an uncertain environment as Avista
plans to meet future customer loads. Avista does not have a preferred form of
greenhouse gas legislation at this time, but supports federal legislation that is:
· Workable and cost effective;
· Fair;
· Protective of the economy and consumers;
· Supportive of technological i"novation; and
· Includes emissions froir'developing nations.
Avista Corp 2009 Electric IRP 4-3
Chapter 4 - Environmental Policy
Workable and cost effective legislation would be carefully crafted to produce actual
greenhouse gas reductions through a single system, as opposed to competing, if not
conflicting, state, regional and federal systems. The legislation also needs to be fair in
that its impacts must be equitably distributed across all sectors of the economy based
on relative contribution to greenhouse gas emissions. Protecting the economy and
consumers is of utmost importance. The legislation cannot be so onerous that it stalls
the economy or fails to have any sort of adjustment mechanism in case the market
solution fails causing allowance or offset prices to escalate at unmanageable rates.
Supporting a wide variety of technological innovations should be a key component of
any greenhouse gas reduction legislation because innovation can help contain costs,
as well as provide a potential boost to the economy through an increased
manufacturing base. Climate change legislation must involve developing nations with
increasing greenhouse gas emissions; legislation should include strategies for working
with other nations directly or through international bodies to control global emissions.
Greenhouse Gas Concerns for Resource Planning
Resource planning, in the context of greenhouse gas emissions regulation, raises
concerns about the balance between the Company's obligations for environmental
stewardship and cost implications for our customers. Consideration must be given to the
cost effectiveness of resource decisions as well as the need to mitigate the financial
impact of emissions risks.
Complying with greenhouse gas emission regulations, particularly in the form of a. cap
and trade mechanism, involves two actions: ensuring the Company maintains suffcient
allowances and/or offsets to correspond with its emissions during a compliance period,
and undertaking measures to reduce the Company's future emissions. Effectuating
emission reductions on a utility-wide basis can entail any and all of the following:
· Increasing effciency of existing fossil-fueled generation resources;
· Reducing emissions from existing fossil-fueled generation through fuel
displacement including co-firing with biomass or biofuels;
· Permanently decreasing output from existing fossil-fueled resources and
substituting them with lower emitting resources;
· Decommissioning or divesting fossil-fueled generation and substituting lower
emitting resources;
· Reducing exposure to market purchases of fossil-fueled generation, particularly
during periods of diminished hydropower production, by establishing larger
reserves based on lower emitting technologies; and
· Increasing investments in energy effciency measures.
With the exception of increasing Avista's commitment to energy effciency, the cost and
risks of the other actions listed above cannot be adequately, let alone fully, evaluated
until uncertainty about the nature of greenhouse gas emission regulations is resolved;
that is, after a regulatory regime has been implemented and the economic effects of its
4-4 Avista Corp L,2009 Electric IRP
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Chapter 4 - Environmental Policy
interacting components can be modeled. A specific reduction strategy as part of an IRP
may be forthcoming when greater regulatory clarity and more precise modeling
parameters exist. In the meantime, the model for this IRP internalizes a carbon price
proxy based on the Wood Mackenzie forecast based on the November 2008 discussion
draft legislation sponsored by Representatives John Dingell and Rick Boucher. The
2009 IRP focuses on the costs and mitigation of carbon dioxide since it is the most
prevalent and primary greenhouse gas emitted from fossil-fueled generation sources.
Emissions Legislation
Several themes have emerged from various climate change legislative proposals that
have been considered since publication of the 2007 IRP. These include:
· Settling of scientific questions about human contributions to climate change; it is
viewed as a largely anthropogenic or human-developed phenomenon.
· A consensus view that regulation should be applied on an economy-wide basis,
rather than one or two sectors at a time.
· Technology wil be a key component to reducing overall greenhouse gas
emissions, particularly in the electric sector. Significant investment in carbon
capture and sequestration technology wil be needed since coal wil continue to
be an important part of the U.S. generation fleet into the foreseeable future.
· Developing countries must be involved in reducing global emissions as
greenhouse gas emissions generally increase with economic growth.
· The longer federal legislation takes to enact, the higher the probability of that
inconsistent state and regional regulatory schemes may be implemented. A
patchwork of regulation may obstruct the operation of businesses serving
multiple jurisdictions by causing market disruptions and increasing the
uncertainty of how federal and disparate state and regional regulatory systems
might interact.
These themes all point towards a need to develop national greenhouse gas legislation
in a timely manner to ensure the best environmental and economic outcomes. The
current version of the Waxman-Markey bil importantly acknowledges these multi-
jurisdiction problems by temporarily superseding state and regional cap and trade
regulation over emissions covered under federal law between 2012 and 2017.
Federal Emissions and Renewables Legislation
The U.S. House of Representatives passed H.R. 2454, the American Clean Energy and
Security Act by Waxman and Markey on June 26, 2009. Among its many components,
this bil establishes greenhouse gas reduction goals, creates a national cap-and-trade
program, and outlines a national RPS. Some of the bill's details include:
· RPS goals start at six percent in 2012 and increase to 20 percent by 2020.
· Recognizes hydroelectric effciency upgrades and additions effectuated since
January 1, 1992 as qualifying against the renewable energy standard.
Avista Corp 2009 Electric IRP 4-5
Chapter 4 - Environmental Policy
· Removes existing hydroelectric power generation, excluding upgrades made
after January 1, 1992, from the load base against which the renewable energy
standard is applied.
· Allows electric utilities to make $25 per MWh alternative compliance payments,
adjusted for inflation starting in 2010, in lieu of acquiring new renewable
resources or renewable energy certificates (REC).
· Permits REC trading, and banking of RECs for three years.
· Greenhouse gas reduction goals of 3 percent below 2005 levels by 2012, 17
percent by 2020, 42 percent by 2030 and 83 percent by 2005.
· Proposes to administratively allocate allowances to electric utilties from 2011
through 2028, with 50 percent of them being allocated on the basis of a utility's
share of emissions associated with retail sales and 50 percent being allocated
based on a utility's annual average electricity deliveries.
· Calculates a utility's average annual emissions based upon data from 2006
through 2008, or any three consecutive calendar years between 1999 and 2008,
as may be selected by the utility.
· Allows banking and borrowing of emission allowances.
· Allows for some forms of carbon offsets.
· Establishes mechanisms for containing costs and for regulating allowance and
derivative markets.
Jeff Bingaman is also developing a federal RPS bil that is working its way through the
Senate. The Bingaman bil sets a 15 percent renewable energy goal by 2021 and allows
electric utilities to meet up to four percent of their RPS goals with energy effciency. The
bil also creates an off ramp provision exempting a utilty from the RPS if their retail
rates would increase by four or more percent in any given year for complying with the
law.
Avista's main concerns with the potential federal climate change legislation concerns
the compliance costs, which centers primarily, though not exclusively, on the method of
allocating allowances and the amount of allowances the Company may be required to
purchase through auction. Avista favors the adoption of a compromise advocated by the
Edison Electric Institute, which allows for half of the allowances allocated to electric
utilities to be load based and half of the allowances to be emissions based. This is a
more equitable compromise than allocation based solely on historic emissions, which
could provide a windfall for non-utilty generators for their past greenhouse gas
emissions and effectively penalizes past use of renewable energy. Administrative or
direct allocation, at least in the beginning of the program, is also favored because it wil
mitigate compliance cost impacts on customers while the allowance markets and
emissions reductions technologies are developed.
State Level Emissions Legislation
The failure of the federal government to enact greenhouse gas emission regulations
during the current decade has encouraged many states to develop their own climate
4-6 Avista Corp2009 Electric IRP
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Chapter 4 - Environmental Policy
change laws and regulations. Climate change legislation can take many forms, including
comprehensive regulation in the form of a cap and trade system, and complementary
policies, such as renewable portolio standards, energy effciency standards, and
emission performance standards. All of these standards are included for Washington,
but not necessarily in other jurisdictions where Avista operates. Individual state actions
can produce a patchwork of competing rules and regulations for utilities to follow, which
may be particularly problematic for multi-jurisdictional utilities such as Avista. There are
currently 23 states plus the District of Columbia with active renewable portolio
standards.
One of the more notable state level greenhouse gas initiatives outside of the Pacific
Northwest is the Regional Greenhouse Gas Initiative (RGGI) agreement between ten
northeastern and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland,
Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and Vermont)
to implement a cap and trade program for carbon dioxide emissions from power plants.
The District of Columbia, Pennsylvania, and some Canadian Provinces are also
participating as RGGI observers. RGGl's cap and trade regulations have been effective
since January, 2009.
The Western Regional Climate Action Initiative, otherwise known as the Western
Climate Initiative (WCI), began with a February 26, 2007 agreement to reduce
greenhouse gas emissions through a regional reduction goal and market-based trading
system. This group includes Arizona, British Columbia, California, Manitoba, Montana,
New Mexico, Oregon, Utah, Quebec and Washington. In September 2008, the WCI
released a set of Final Design recommendations for a regional cap and trade regulatory
system to cover 90 percent of the societal greenhouse gas emissions within the region
by 2015. The WCI is presently proceeding to finish its Work Plan, which completes
details necessary to implement its proposed cap and trade system. The WCI has also
recently initiated a process to identify and evaluate complementary policies that can be
adopted region-wide to further ensure that greenhouse gas reduction goals are met. In
addition, the WCI has formally submitted comments to Congress regarding the content
of the Waxman-Markey bil. There have also been a number of regional municipalities
participating in the U.S. Mayors Climate Protection Agreement to reduce GHG
emissions to seven percent below 1990 levels by 2012.
It is important to acknowledge that a federal cap and trade program, such as that
envisioned by the Waxman-Markey legislation, wil not operate in isolation. Members of
the Western Climate Initiative, such as Washington, Oregon, and Montana, are likely to
- as some of them have already - pursue complementary policies to regulate emission
sources that are covered under cap and trade regulation, as well as those that wil not
be regulated under a cap and trade program. The Waxman-Markey bil in its current
form ilustrates this potentiality. Even though the federal legislation would preclude
states from implementing their own cap and trade regulations between 2012 and 2017,
it would not prevent states from imposing any different form of regulations on the
covered sources before, during or after that time frame, or from administering and
augmenting federal cap and trade regulations after 2017.
Avista Corp 2009 Electric IRP 4-7
Chapter 4 ~ Environmental Policy
The adoption of greenhouse gas emission reduction goals, and any associated
regulations by Washington, could directly impact the Company's generation assets in
the state, which are largely comprised of the Kettle Falls Generating Station, the
Northeast Combustion turbines and the Boulder Park peaking facilities. Oregon's
greenhouse gas reduction goals and potential future regulations can be applied to the
Coyote Springs 2 project.
Idaho Emissions legislation
Idaho is not a member of WCI and does not regulate greenhouse gases or have an
RPS. However, the state is actively trying to promote the development of local
renewable energy.
Montana Emissions legislation
The Montana Global Warming Solutions Act (House Bil 753) was submitted in late 2006
to establish greenhouse gas reductions goals to be achieved by 2020. This legislation
did not leave committee. Montana now has a non-statutory goal of reducing greenhouse
gas emissions to 1990 levels by 2020. In 2007, the Legislature passed House Bil 25,
requiring new coal-fired facilties built in the state to sequester 50 percent of their
emissions. Montana's renewable portolio standard law, which was enacted through
Senate Bil 415 in 2005, does not apply to Avista because the Company does not seive
retail load in Montana. While involved in the Western Climate Initiative, Montana did not
consider any legislation during the 2009 Legislative Session to authorize its participation
in and implementation of the regional cap and trade system designed by the WCI.
Oregon Emissions legislation
The State of Oregon has been actively developing legislation concerning greenhouse
gases and renewable portolio standards. Oregon's climate change legislation began in
December 2004 when the Oregon Strategy for Greenhouse Gas Reduction called for
the development of a detailed GHG report by the end of 2007. That year, the
Legislature enacted House Bil 3543 callng for reductions of greenhouse gas emissions
to 10 percent below 1990 levels by 2020 and 75 percent below 1990 levels by 2050.
These reduction goals are in addition to a 1997 regulation requiring fossil-fueled
generation developers to offset the project's C02 emissions exceeding 83 percent of the
emissions of a state-of-the-art gas-fired CCCT by paýing into the Climate Trust of
Oregon. Senate Bil 838 requires large electric utilties to generate 25 percent of annual
electricity sales with qualified renewable resources by 2025. Shorter term goals include
five percent by 2011, 15 percent by 2015 and 20 percent by 2020. Governor Ted
Kulongoski introduced Senate Bil 80 during the 2009 Legislative Session to authorize
the state's implementation of cap and trade regulations either in isolation or as part of a
regional program. This legislation failed. Oregon continues to be an active member of
WCI.
Washington Emissions legislation
The State of Washington has enacted several measures affecting fossil-fueled
generation and the diversification of generation resources. A law was enacted in 2004
that requires new fossil-fueled thermal electric generating facilities of more that 25 MW
generation capacity to mitigate C02 emissions through a. plan including: third party
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Chapter 4 - Environmental Policy
mitigation, purchased carbon credits or cogeneration. Washington's Energy
Independence Act (1-937), passed in the November 2006 election, established a
requirement for utilities with over 25,000 customers to use qualified renewable energy
or renewable energy certificates to serve three percent of retail load by 2012, nine
percent by 2016 and 15 percent by 2020. Failure to meet the RPS requirements results
in a fine. The initiative also requires utilities to acquire all cost effective conservation and
energy effciency measures.
Senate Bil 5840 was brought forward in 2009 to update 1-937, qualify existing biomass
generation (e.g., Kettle Falls) as an eligible renewable resource, and adjust the
renewable energy standards, but it failed to obtain the needed votes after emerging
from Conference Committee in the closing days of the Legislative Session. The
renewable requirement begins in 2012.
Avista is projected to meet or exceed its renewable requirements between 2012 and
2015 through a combination of hydro upgrades and REC purchases. The Company
could bank RECs acquired from the Stateline Wind contract in 2011 for 2012, but these
RECs are allocated for its Buck-a-Block program. The 2009 IRP has been developed so
that the 1-937 RPS goals wil be achieved by the Company.
In 2007 the Legislature passed Senate Bil 6001. It prohibits electric utilities from
entering into financial commitments beyond five years for fossil-fueled generation where
C02 emissions exceed 1,100 pounds per MWh. In 2013 the emissions performance
standard wil be lowered every five years to reflect the emissions profile of the latest
commercially available CCCT. The emissions performance standard effectively
prevents utilities from developing new coal-fired generation or expanding the generation
capacity of existing coal-fired generation, unless they can sequester emissions from the
facility. The Legislature amended Senate Bil 6001 in 2009 to prohibit contractual
commitments where more than 12 percent of the total power supplied under the
contract comes from unspecified sources.
Governor Christine Gregoire signed Executive Order 07-02 in February 2007 which
established the following GHG emissions goals:
,
· 1990 levels by 2020;
· 25 percent below 1990 levels by 2035;
· 50 percent below 1990 levels by 2050 or 75 percent below expected emissions in
2050;
· Increase clean energy jobs to 25,000 by 2020; and
· Reduce statewide fuel imports by 20 percent.
The goals of this Executive Order were later codified into law when the Legislature
enacted Senate Bil 6001 in 2007. Taking the next step to achieve the State's
greenhouse gas reduction goals, the governor introduced legislation (Senate Bil 5735
and House Bil 1819) during the 2009 Legislative Session to authorize the Department
of Ecology to adopt rules, consistent from recommendations from the Western Climate
Initiative,' enabling the state to administer and enforce a regional cap and trade
program. When that legislation failed, Governor Gregoire signed Executive Order 09-05
Avista Corp 2009 Electric IRP 4-9
Chapter 4 - Environmental Policy
directing the Department of Ecology to develop emission reduction "strategies and
actions", including complementary policies, to meet Washington's 2020 emission
reduction target by October 1, 2010. This directive wil require the agency to provide
"each facility that the Department of Ecology believes is responsible for the emission of
25,000 metric tons or more of carbon dioxide equivalent each year in Washington with"
an estimate of each facilit's baseline emissions and to designate "each facility's
proportionate share of greenhouse gas emission" reductions necessary to achieve the
state's 2020 emission reduction goal. The department is also asked, by December 1,
2009, to develop emission benchmarks by industry sector for facilties the Department
of Ecology believes wil be covered by a federal or regional cap and trade program; the
state may advocate the use of these emission benchmarks in any federal or regional
cap and trade program as an appropriate basis for the distribution of emission
allowances. The department must submit recommendations regarding its industry
benchmarks and their appropriate use to the Governor by July 1, 2011.
Washington Renewable Portolio Standard (1-937)
National RPS legislation is being developed through Waxman and Markey's American
Clean Energy Security Act of 2009 (HR 2454) and Senator Bingaman's draft RPS bilL.
The proposed federal RPS level ranges between 10 and 25 percent with several target
years. Federal legislation is expected to include a hydro netting provision, which
excludes loads served by hydropower energy from the RPS requirement. Federal
legislation conceptually - and significantly -- differs from 1-937, in particular with respect
to hydro-netting. The absence of hydro-netting makes the Washington RPS more
stringent than proposed federal requirements. National legislation may count existing
biomass resources, including Kettle Falls, against the renewable energy standard, as
well as power from upgrades to hydropower facilities that were effectuated before 1999
(the date established in 1-937 to determine resource eligibilty). Treatment of renewable
resources in federal legislation would not allow the Company to use RECs from
federally-eligible resources to comply with 1-937, but Avista would be able to make REC
sales from certain facilities into a national market and perhaps individual state markets
governed by their own RPS requirements.
Emissions Measurement and Modeling
Greenhouse gas tracking is an important part of the IRP modeling process because
emissions legislation is one of the greatest fundamental risks facing the electricity
marketplace today. Reducing CO2 emissions from power plants wil fundamentally alter
the resource mix as society moves towards a carbon constrained future. Though there
are no federal laws regulating carbon emissions presently, carbon costs stil need to be
projected for planning purposes because expectations for carbon regulation can change
resource decisions.
This IRP uses a Wood Mackenzie carbon price forecast. Wood Mackenzie based its
carbon price forecast on November 2008 legislation sponsored by Representatives
Dingell and Boucher. Even though the Dingell-Boucher bil is no longer being
considered for federal greenhouse gas legislation, it does provide a reasonable proxy
for the current Waxman-Markey bilL. Wood Mackenzie balanced its macro-economic
models by identifying a carbon price forecast to meet national. greenhouse gas
reduction goals. Figure 4.1 shows the carbon price forecast for this IRP. The 2009 IRP
4-10 2009 Electric IRP Avista Corp
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assumes carbon wil have a cost starting in 2012. The levelized cost of carbon is $46.14
(nominal) and $33.37 (2009 dollars). Natural gas prices greatly affect carbon offset
values. Therefore, when natural gas prices rise or fall, the IRP assumes carbon costs
wil change to balance the relative competitiveness of gas and coaL.
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Figure 4.1: Price of Carbon Dioxide Credits
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Avista Corp 4-112009 Electric IRP
Chapter 5 - Transmission and Distribution
5. Transmission and Distribution
Introduction
This section of the Integrated Resource Plan
(IRP) provides an overview of Avista's
transmission system, recently completed and
planned upgrades, transmission planning
issues, and estimated costs and issues
involved with integrating potential resources
into the transmission system.
Coordinating transmission system operations
and planning activities among regional
transmission providers is necessary to
maintain reliable and economic service for
Avista's customers. Transmission providers
and interested stakeholders continue to
implement changes in the region's approach
to planning, constructing and operating the
transmission system under new rules
promulgated by the Federal Energy
Regulatory Commission (FERC) and under
state and local siting agencies. This section
was developed in full compliance with
Avista's FERC Standards of Conduct
governing communications between Avista
merchant and transmission functions.
"----~
lìf¡
I ~L
'i '\t
Transmison upgrade work
Chapter Highlights
· Avista recently completed a $130 millon transmission improvement project.
· The Company has over 2,200 miles of high voltage transmission.
· Avista is actively involved in regional transmission planning efforts.
· The costs of transmission upgrades are included in the 2009 Preferred
Resource Strategy.
Avista's Transmission System
Avista owns and operates approximately 685 miles of 230 kilovolt (kV) and 1,527 miles
of 115 kV transmission lines. Avista also owns an 11 percent interest in 495 miles of the
500 kV line between Colstrip and Townsend, Montana. The transmission system
includes switching stations and high-voltage substations with transformers, monitoring
and metering devices, and other system operation-related equipment. The system
transfers power from Avista's generation resources to its retail load centers. The
Company also has network interconnections with the following utilties:
Avista Corp 5-12009 Electric IRP
Chapter 5 - Transmission and Distribution
· Bonnevile Power Administration
(BPA)
· Chelan County PUD
· Grant County PUD
· Idaho Power Company
· NorthWestern Energy
· PacifiCorp
· Pend Oreile County PUD
Figure 5.1: Avista transmission system
'-"'..
MONTANA
WASHINGTON
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l ..-...__..118.) '.
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e.:",,,. rf--... """, 11p_l'll.~"... ./"------"
L.....Dn51iVÀ-230k\I-r.
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In addition to providing enhanced transmission system reliabilty, network
interconnections serve as points of receipt for power from generating facilties outside
Avista's service area. These interconnections also provide for the interchange of power
with entities within and outside of the Pacific Northwest, including the integration of long
and short-term contract resources. Avista also has interconnections with several
government-owned and cooperative utilties at transmission and distribution voltage
levels, representing non-network radial points of delivery for service to wholesale loads.
Transmission Changes since the 2007 IRP
Avista has completed a multi-year $130 millon transmission upgrade project. Much of
this construction was completed prior to 2007 and was documented in the 2007 IRP.
Since the 2007 IRP the Company completed 60 miles of new 230 kV transmission
between its Benewah and Shawnee substations to increase capacity between the north
and south portions of its system. The project provides a second 230 kV transmission
line between Avista's northern and southern load service areas, significantly improving
reliabilty. Energized in December, 2007, Avista installed a new 200 megavolt- ampere-
reactive (MVAR) 230 kV capacitor bank at the Benewah station in October of 2008, and
installed a new 125 MVA 230/115 kV transformer in November of.2008. This work,
5-2 200 Electric IRP Avista Corp
Chapter 5 - Transmission and Distribution
known as the West of Hatwai reinforcement, was part of a joint transmission project
between Avista and BPA.
Future Upgrades and Interconnections
Station Upgrades
Several station upgrades are planned for the next 10 years. The final scope of station
upgrades has not yet been determined, but four of the Company's 230 kV station
upgrades (Noxon, Moscow, Westside and Pine Creek) are slotted for completion within
the next five to 10 years. A number of 115 kV capacitor banks wil also be installed at
various substations throughout the Avista transmission system.
South Spokane 230 kV Reinforcement
Recent transmission studies indicate the need for an additional 230 kV line to the south
and west of Spokane. Avista currently has no 230 kV source southwest of the Spokane
area and relies on its 115 kV system for load service as well as bulk power flow through
the area. The project scope is currently being defined; however, preliminary studies
indicate the need for the following projects:
· New 230/115 kV station near Garden Springs;
· Tap the Benewah-Boulder 230 kV line southwest of the Libert Lake area and
construct a new 230 kV switching station (for later development of a 230/115 kV
substation );
· Connection of the Liberty Lake 230 kV station with the Garden Springs 230 kV
station;
· New 230 kV line from Garden Springs to Westside; and
· Origination and termination of the 115 kV lines from the Spokane 230/115 kV line.
The final scope for the South Spokane 230 kV Reinforcement project is scheduled for
completion by the end of 2009. Its energization date is expected to be 2018, with staged
in-service dates beginning in 2014.
Canada to California Transmission Project and Devils Gap Interconnection
One of the primary projects under review at the Transmission Coordination Work Group
(TCWG, see below) is a new transmission line involving four major projects.
· 500 kV HVAC facilties from Selkirk in southeast British Columbia to the
proposed Northeast Oregon (NEO) Station, with an intermediate interconnection
with Avista at a new Devils Gap Substation near Spokane;
· 500 kV HVDC facilties from NEO Station to Collnsvile Substation in the San
Francisco Bay Area, with a possible third terminal at Cottonwood Area
Substation in northern California (DC Segment);
· Volta9,e support at the interconnecting substations; and
· Remedial actions for project outages.
'~"~fi
Avista Corp 2009 Electric IRP 5-3
Chapter 5 - Transmission and Distribution
The proposed north-to-south rating for the two-segment project is 3,000 MW. It wil
improve system reliability in the Western Interconnection, as well as provide access to
significant renewable resources. Its target operating date is December 2015. Avista
joins Pacific Gas and Electric, PacifiCorp and the British Columbia Transmission
Corporation in this project.
The Avista Devils Gap Interconnection project is comprised of a 500 MW bi-directional
500/230 kV interconnection and 230 kV transmission into the Spokane area 230 kV
grid. It (plus additional transmission in the area around the proposed NEO substation)
would provide additional transmission Avista could use to integrate Coyote Springs 2
generation. The Project wil allow Avista to enhance its access to incremental renewable
resources in the Pacific Northwest, Canada and, at times, the southwestern U.S.
Immediate and future environmental and resource needs of Avista and other Western
Interconnected utilities wil be aided by this Project.
Avista's goal is to also provide market participants with beneficial opportunities to use its
facilities. Through its participation in TCWG meetings Avista makes all project
information available to group members, including resource developers, load serving
entities, energy marketers and independent transmission owners.
Regional Transmission System
BPA operates over 15,000 miles of transmission facilties throughout the Pacific
Northwest. BPA's system represents a large portion of the region's high voltage (230 kV
or higher) transmission grid. Avista uses the BPA transmission system to transfer output
from its remote generation sources to Avista's transmission system, including its
Colstrip units, Coyote Springs 2 and its Washington Public Power Supply System
Washington Nuclear Plant NO.3 settlement contract. Avista also contracts with BPA for
Network Integration Transmission Service to transfer power to 10 delivery points on the
BPA system to serve portions of the Company's retail load.
Avista participates in regional and BPA-specific forums to coordinate system reliability
issues and manage BPA transmission costs. We participate in BPA transmission and
power rate case processes, and in BPA's Business Practices Technical Forum, to
ensure charges remain reasonable and support system reliabilty and access. Avista
also works with BPA and other regional utilties to coordinate major transmission facilty
outages.
Future generation resource development wil require construction of new transmission
assets. BPA recently received $3.5 bilion in additional borrowing authority through the
American Recovery and Reinvestment Act of 2009. Increased borrowing capabilty
enhances BPA's abilty to construct new transmission projects. One recent example is
the 79-mile long 500 kV McNary-John Day upgrade. This $200 millon project had been
on hold since 2002 because of BPA's inabilty to finance the project.
5-4 2009 Electric IRP Avista Corp
Chapter 5 - Transmission and Distribution
FERC Planning Requirements and Processes
FERC provides guidance to regional and local area transmission planning. The
following section describes several requirements and processes important to Avista's
transmission planning function.
Attchment K
On December 7, 2007, Avista submitted a revised Attachment K to its Open Access
Transmission Tariff (OAn). The revisions to the prior Attachment K met nine
transmission planning principles proposed in FERC Order 890. The principles made the
planning process more open to interested stakeholders and formalized coordination
between interconnected utilities. In its Attachment K process, Avista established three
levels of planning on the local, sub-regional and regional levels.
At the local level, Avista develops a two-year Local Planning Process culminating with
the production of a Local Planning Report (in coordination with Avista's five- and ten-
year Transmission Plans). Avista encourages participation of interconnected neighbors,
transmission customers and other stakeholders in the local planning process. The
Company uses ColumbiaGrid to coordinate planning with sub-regional groups.
Regionally, Avista participates in several WECC processes and groups, including
various Regional Review processes, Transmission Expansion Planning Policy
Committee, Planning Coordination Committee and the newly formed Transmission
Coordination Work Group (TCWG). Participation in these efforts supports regional
coordination of Avista's transmission projects.
Avista submitted a modified Attachment K to FERC on October 15, 2008 to correct
deficiencies in its 2007 filing. The Attachment K revisions included clarifications that did
not change the substance of the original filing.
Western Electricity Coordinating Council
The Western Electricity Coordinating Council (WECC) coordinates and promotes
electric system reliabilty in the Western Interconnection. WECC also supports effcient
and competitive power markets, assures open and non-discriminatory transmission
access among members, provides a forum for resolving transmission access or
capacity ownership disputes, and provides an environment for coordinating operating
and planning activities as set forth in WECC Bylaws. Avista participates in WECC's
Planning, Operations, and Market Interface committees, as well as various sub groups
and other processes such as the TCWG.
Northwest Power Pool
The Pacific Northwest has a long history of coordinated transmission planning through
Northwest Power Pool (NWPP) workgroups. The NWPP was formed in 1942 when the
federal government directed utilities to coordinate operations in support of wartime
production. NWPP activities are determined by committees including the Operating
Committee, the PNCA Coordinating Group and the Transmission Planning Committee
(TPC). The TPC, formed in 1990, provides a forum for addressing northwest electric..... planning issues and concerns, including a structured interface with outside
stakeholders.
Avista Corp 2009 Electric IRP 5-5
Chapter 5 - Transmission and Distribution
The NWPP serves as a Northwest electricity industry reliability forum. It helps
coordinate present and future industry restructuring. NWPP promotes member
cooperation to achieve reliable system operation, coordinate power system planning
and assist transmission planning in the Northwest Interconnected area. NWPP
membership is voluntary and includes major generating utilities serving the
Northwestern U.S., British Columbia and Alberta. Smaller, principally non-generating
utilities, participate indirectly through their member systems.
ColumbiaGrid
ColumbiaGrid was formed on March 31, 2006 to develop sub-regional transmission
plans, assess transmission alternatives (including non-wires alternatives), provide a
decision-making forum, and a cost-allocation methodology for new transmission
projects. This group was formed in response to a number of FERC initiatives. Avista
joined ColumbiaGrid in early 2007. Other members include BPA, Chelan County PUD,
Grant County PUD, Puget Sound Energy, Seattle City Light and Tacoma Power.
Though not a member, Snohomish PUD participates in a number of functional
agreements. These agreements are used to help different organizations and groups
determine areas of transmission work and establish agreements to carry out the plans.
Transmission Coordination Work Group
The TCWG is a joint effort of Avista, BPA, Idaho Power, Pacific Gas and Electric,
PacifiCorp, Portland General Electric, Sea Breeze Pacific-RTS and TransCanada to
coordinate transmission project developments expected to interconnect at or near the
proposed NEO station near Boardman, Oregon. These projects are following the WECC
Regional Planning and Project Rating Guidelines. Detailed information on NEO and the
projects that could be integrated at NEO may be found at ww.nwpp.org/tcwg .
Avista Transmission Reliabilty and Operations
Avista plans and operates its transmission system pursuant to applicable criteria
established by the North American Electric Reliabilty Corporation (NERC), WECC and
the NWPP. Through involvement in WECC and NWPP standing committees and sub-
committees, Avista participates in the development of new and revised criteria, and
coordinates planning and operation of its transmission system with neighboring
systems. Mandatory reliabilty standards promulgated through FERC and NERC,
subject Avista to periodic penormance audits through these regional organizations.
Portions of Avista's transmission system are fully subscribed for transferring power
output of Company generation resources to its retail load centers. Transmission
capacity that is not reserved and scheduled to move power to satisfy long-term (greater
than one year) obligations is marketed on a short-term basis and may be used by Avista
for short-term resource optimization or third parties seeking short-term transmission
service pursuant to FERC requirements under Orders 888,889 and 890.
Transmission Construction Costs
An essential part of the IRP is estimating transmission costs to integrate new generation
resources. ConstructiQQ,~quality estimates were only made for three projects proposed in
the IRP. The other options identified in this IRP are based on engineering judgment.
5-6 2009 Electric IRP Avista Corp
Chapter 5 - Transmission and Distribution
There is an inverse relationship between transmission project size and the certainty of
the estimates. A 50 MW resource can be integrated in many places on the Company's
system for a moderate cost compared to its overall installation cost. There are fewer
options available for locating a 500 MW plant on Avista's system. Larger (750 and 1,000
MW) plants have even fewer location options. Each would require participation in
FERC's Generation Interconnection Process as well as coordination through the
regional processes described above. These processes would be completed to
determine impacts on Avista and other systems' transmission grid before a final plant
placement decision.
Estimating Transmission and Integration Costs
The following sections provide an overview of Avista's estimated resource integration
costs for the 2009 IRP. Integration points were roughly divided into locations where
interconnection study work has been completed and additional points where new
resources might be interconnected. Rigorous analyses have not been completed for off-
system alternatives because of the breadth of study needed for those estimates. Limited
study work has been completed except for projects with existing generation
interconnection requests to Avista's transmission group. Completing transmission
studies without detailed project parameters is nearly impossible. Approximate worst-
case estimates have been assigned based on engineering judgment for neighboring
system impacts. Generation interconnection costs are listed for locations within Avista's
transmission system. Internal cost estimates are in 2009 dollars and are based on
engineering judgment with a 50 percent margin for error. Construction timelines are
defined from the beginning of the permitting process to line energization.
Integration of Resources External to the Avista System
Avista's load serving entity function (Avista-LSE) is required to submit generation
interconnection and transmission service requests on third part transmission systems.
The third party determines transmission system integration and wheeling service costs
for delivering new resource power to Avista's system. Construction cost estimates are
based on $2 milion per mile of new 500 kV lines, $700,000 per mile of 230 kV lines and
$350,000 per mile of 115 kV lines.
Eastern Montana Resources
A regional study sponsored by the NWPP and Northwest Transmission Assessment
Committee (NTAC) found that enhancement of existing 500 kV and 230 kV facilities
would be required to integrate additional generation from Montana. Power transfer from
eastern Montana to the Northwest is affected by several constraints. A more detailed
study effort focusing on relieving constraints from central and eastern Montana is
underway as a joint effort by Avista, SPA, NorthWestern Energy, PacifiCorp and Puget
Sound Energy. The study is scheduled for completion in 2010 to identify transmission
constraints and engineering-level construction cost estimates to fix the constraints.
Avista Corp 2009 Electric IRP 5-7
Chapter 5 - Transmission and Distribution
Integration of Resources on the Avista Transmission System
Avista~LSE has requested three generator interconnection studies: one near Reardan,
Washington, a second near Grangevile, Idaho, and a third in Garfeld County,
Washington. Each interconnection study request is discussed below.
Reardan, Washington
Avista-LSE submitted a generator interconnection request to Avista Transmission for a
65 MW wind project located south of Reardan, Washington, and has requested a study
of interconnection to Avista's 115 kV Devil's Gap - Lind line. The point of
interconnection is located approximately six miles south of the Reardan Substation on
the Gaffney - Reardan segment of the line. Initial studies indicate that construction of a
new 115 kV transmission line into the Spokane area wil be required to accommodate
the full project output. Preliminary cost estimates of interconnecting a wind project at
Reardan are under $15 milion; however, not all costs associated with the upgrade wil
be directly assigned to the project because some upgrades are needed whether or nor
the project is completed.
Avista-LSE wil submit a transmission service request to determine any required system
reinforcements necessary to enable the proposed project to be a designated network
resource serving native load under FERC OA TT requirements.
Grangevile, Idaho
Avista-LSE submitted a generator interconnection request to Avista Transmission in
2008 for a proposed 120 MW wind project located near Grangevile, Idaho. The
transmission line from the project to the point of interconnection is approximately 10
miles. Studies indicate the project is feasible based on the preliminary analysis;
however the work also identified thermal violations under certain contingency
conditions. The total estimated cost of interconnecting this project at the Grangevile
Substation, without mitigating the reactive power consumption of the transmission
system, is estimated to be $12.9 milion including reconductoring the local transmission
lines. The cost estimate does not include constructing a radial 115 kV interconnection
transmission line from the project to the point of interconnection at the Grangevile
substation.
Ganield County, Washington
Avista-LSE submitted a generator interconnection request for a 200 MW wind project
located approximately three miles east of the Columbia/Garfeld (Washington) county
line in Garfeld County. The project, locted near Pomeroy, Washington, would
interconnect to the existing Dry Creek~Talbot 230 kV line via a double-bus, double-
breaker (six breaker station) configured station. The approximate interconnection cost is
$4 millon.
Lancaster Integration
Avista is eyaluating various alternatives for a new transmission interconnection with
SPA in the Spokane Valley. One interconnection is at SPA's Lancaster Substation. This
interconnection mlght allow Avista to eliminate or offset some SPA wheeling charges for
moving the Lancaster combustion turbine project to Avista's system. Avista is working
5-8 200 Electric IRP Avista Corp
Chapter 5 - Transmission and Distribution
with BPA to determine what form the interconnection should take. Preliminary studies
indicate that Avista could expand existing BPA facilties, construct an interconnection to
BPA facilities, and build a loop-in to the Avista Boulder-Rathdrum 230 kV line.
This project could benefit Avista and BPA by increasing system reliabilty, decreasing
losses and delaying the need for additional transformation at the BPA Bell Substation.
The proposed plan of service might represent the best option for service from Avista's
sole perspective. Additional studies indicate that looping the Boulder-Rathdrum 230 kV
line into the Lancaster Substation may allow more transfer capability across the
combined transmission infrastructure of Avista and BPA. The preliminary study results
are expected by the end of the third quarter of 2009. Construction could be completed
by the end of 2010.
Other Potential Resources
2009 IRP resources could be located on Avista's or another organizations transmission
grid. The following section provides details concerning generic potential resources,
Generator interconnection and transmission service requests would be required to
integrate any new generation resource.
CCCT with Duct Burner
A 150 to 250 MW CCCT could be integrated into Avista's 230 kV grid at several
locations. The best locations from a transmission siting perspective are near the existing
Rathdrum and Lancaster units near Rathdrum, Idaho or near the Benewah 230/115 kV
station near Benewah, Idaho
Small Cogeneration (0(5 MW)
Small cogeneration plants are likely to be near large industrial loads. Because of the
unique nature of these installations, detailed studies must be run to determine
integration costs. These costs cannot be estimated until a generator interconnection
request is made.
Hybrid SCCT (lMS 100)
As with the CCCT, a 100 MW SCCT could be integrated into the Avista 230 kV gnd in
several locations. The best locations from a transmission siting perspective are near the
existing Rathdrum and Lancaster units near Rathdrum, Idaho, or near the Benewah
230/115 kV station near Benewah, Idaho.
Coal
It is unlikely that a coal-fired facility (traditional or gasification) would be built in Avista's
service territory, especially with Washington's emissions performance standards. If a
coal plant is developed, it would probably be integrated on a third party transmission
system.
Geothermal
There are no known geothermal resources in Avista's service territory, so this resource
type would require an interconnection request on another system. The most likely areas
for this type of generation for Avista are located in Nevada or Oregon. Significant
Avista Corp 2009 Electric IRP 5-9
Chapter 5 - Transmission and Distribution
transmission constraints exist between these states and Avista's system, increasing the
cost of integrating a geothermal resource.
Nuclear
Direct integration of nuclear power into Avista's transmission system is unlikely because
of the significant cost, siting and waste issues associated with this resource. If this type
of resource were constructed, regional studies as well as generator interconnection and
transmission service requests on the transmission provider would be required.
Hydro Upgrades
Spokane River Upgrades
The transmission system serving the Spokane River projects plant is robust so small
upgrades could be integrated with minimal system impacts. Larger upgrade options,
including a second powerhouse at Monroe Street or a Post Falls rebuild, could require
significant upgrades. Generator interconnection and transmission service requests
would be necessary prior to wOïk being initiated.
Clark Fork Hydro Upgrades
The Clark Fork area transmission system consists of Avista and SPA 230 kV lines
integrating Western Montana hydro projects. These include the federally-operated Libby
and Hungry Horse projects and Avista's Clark Fork Projects (Cabinet Gorge and Noxon
Rapids). Avista coordinates operation of the Clark Fork projects with SPA to maintain
system reliabilty in the Western Montana area. Additional transmission upgrades are
not anticipated to integrate the planned Clark Fork upgrades. However, the addition of
new units to the Clark Fork project may require transmission upgrades.
Distribution Efficiencies
Avista delivers electrical energy from generators to the customer's meter through a
network of conductors (links) and stations (nodes). The network system is operated at
various voltages to reduce current losses across the system dependent upon the
distance the energy must travel. A common rule to determine effcient energy delivery is
one kV per mile. For example, 115 kV power systems commonly transfer energy over a
distance of up to 115 miles while 13 kV power systems generally limit delivery of energy
to 13 miles.
Avista's energy delivery systems are categorized into two classes: transmission and
distribution. Avista's transmission system operates at nominal voltages of 230 kVand
115 kV. Distribution is operated at a range of voltages between 4.16 kV and 34.5 kV.
Avista's distribution system is typically operated at a nominal voltage of 13.2 kV in its
. urban service centers. In addition to voltages, the transmission system is designed and
operated distinctly from the distribution system. For example, the transmission system is
a network linking multiple sources with multiple loads while the distribution system is
configured in radial feeders which link a single source to multiple loads.
5-10 2009 Electric IRP Avista Corp
Chapter 5 - Transmission and Distribution
System Efficiencies Team
Avista's System Effciencies Team of operational, engineering and planning staff
developed a plan to evaluate potential energy savings from transmission and
distribution (T&D) system upgrades. The first phase summarized energy savings from
distribution feeder upgrades. The second phase, beginning in the summer of 2009,
combines transmission system topologies with "right sizing" distribution feeders to
reduce system losses, improve system reliabilty and meet future load growth.
Distribution Feeders
The System Effciencies Team evaluated energy losses across Avista's distribution
system. Avista's distribution system consists of approximately 330 feeders covering
30,000 square miles. The distribution feeders range in length from 3 to 73 miles.
The System Effciencies Team evaluated several effciency programs across urban and
rural distribution feeders. The programs consisted of the following system
enhancements:
· Conductor losses;
· Distribution Transformers;
· Secondary Districts; and
· VAR compensation.
The energy loss, capital investment and O&M cost reductions resulting from individual
effciency programs were combined on a per-feeder basis. This approach provided a
means to rank and compare energy savings and net resource cost for each feeder.
Economic Analysis
Economic analysis determined the net resource costs to upgrade each feeder for the
four program areas listed above. The net resource cost determines the avoided cost of
a new energy resource levelized over the asset's life-cycle expressed in dollars per
megawatt (MW). This economic value is calculated by estimating the capital investment,
energy savings, and avoidance of O&M and interim capital investments resulting from
feeder upgrades. The economic analysis methodology and assumptions are more fully
described in the Avista Distribution System Effciencies Program document in Appendix G.
The O&M avoided costs for upgrades were determined by modeling existing feeders in
the Availabilty Workbench Program. This program is an expected value model
combining a weighted average time an~ material cost of equipment failure with the
probability of failure. The distribution feeder's conductor, transformers and ancilary
equipment were used to determine the failure model for each feeder. Customer,
material and labor costs incurred by outages from equipment failure are the economic
parameters used to measure the economic risk of a failure. The results were calibrated
to the expected value model using industry indexes and Avista's actual outage history.
A sensitivity analysis determined the variability of net resource values of different
projected O&M. time horizons, since O&M avoided costs are based on expected
outcomes. Figure 5.2 iIustFates the levelized cost of feeder upgrades.
Avista Corp 2009 Electric IRP 5-11
Chapter 5 - Transmission and Distribution
lvt 100 - - - - - -- - - - - - - - - - - - - - - - - - - - - - - - - - - - - --
200
150
§
¡
'õ
~
-50
Q
Figure 5.2: Levelized Cost of Feeder Upgrades
-40 year -15 year
-10 year -5 year
o
50 ----------
~~ . 8.. N ~~~~fa ~8..~..fa..
quantity of feeders
Distribution feeders wjth the highest potential for effciency gains were included in the
IRP analysis. The five selected feeders are estimated to reduce system losses by 2.7
aMW. Figure 5.3 shows the projected feeder upgrade supply curve of potential for loss
reduction. If all feeders under $100 per MWh using the 40 year levelized cost method
were upgraded, nearly 13 aMW could be saved and between 20 and 25 MW of peak
savings could be realized.
200
150-
í
100
i.50-
§0
~
'õ -50~
-100
-150
Figure 5.3: Estimated Feeder Supply Curve
-5 Year Avoided Cost
-40 Year Avoided Cost
2.0 12.0 14.0 16.04.0 6.0 8.0 10.0
aMW of savings
5-12 2009 Electric IRP Avista Corp
Chapter 5 - Transmission and Distribution
Operational Considerations
By implementing feeder effciency programs, voltage drop across feeders wil decrease
and wil provide an opportunity to deploy a Conservation Voltage Reduction (CVR)
program. Although CVR was not evaluated in the system effciencies program, previous
studies suggest additional energy savings can be achieved by lowering the voltage.
Also, with the implementation of "smart grid" technology, voltage can be regulated to
follow the time-varying load profile along the feeder more accurately. The energy
savings associated with CVR can be challenging to forecast since it is dependent upon
system configuration and varying load characteristics. However, a study conducted by
the Northwest Energy Effciency Allance in January 2008 determined a general
guideline of 0.7 percent reduction in energy consumption with a 1 percent change in
voltage.
Transmission Topologies and Distribution Feeder Sizing
After completion of the distribution analysis, a second-phase analysis wil incorporate
transmission topology, station locations and load growth. Avista's power grid was
designed and built to adhere to reliability and capacity guidelines for the least first cost.
This approach was reasonable considering the low cost of electrical energy at the time
the system was constructed. With the increasing cost of energy, a life cycle economic
analysis is warranted to evaluate power system losses corresponding to various power
grid configurations.
The comprehensive analysis wil review several transmission topologies to determine
the most effcient configuration to move bulk power through and by Avista's balancing
area. The transmission topologies wil consider the effciency between star network, hub
and loop, southern loop and southern source. Avista's load service wil be incorporated
in this analysis by determining ideal substation placement and feeder sizes as well as
forecasted load growth. The comprehensive analysis wil evaluate many of the items
listed below.
· Develop performance criteria to determine system measures;
· Develop base case to measure existing system performance;
· Develop methodology to determine a full build out load case;
· Identify transmission topologies to be evaluated;
· Identify guidelines for placing substations;
· Identify guidelines for distribution feeder sizes; and
· Bound the analysis to ensure the system remains reliable, compliant and
operationally flexible.
Avista Corp 2009 Electric IRP 5-13
Chapter 5 - Transmission and Distribution
Summary
Avista's transmission system consists of over 2,200 miles of high voltage transmission
lines. Transmission system planning utilzes various local, sub-region and regional
processes providing opportunities for stakeholder input into system expansions and
upgrades. The system can integrate small amounts of generation in many areas for
moderate integration costs; these costs tend to escalate rapidly as generation project
size increases. Planning and initial cost estimates have been developed for three wind
projects on the Avista system. Integration costs for the interconnection of customer-
owned generation wil be developed after a complete generation interconnection
request has been submitted and ac~pted by Avista's Transmission Department.
l,
¡
5-14 2009 Electric IRP Avista Corp
I.
I
Chapter 6 - Generation Resource Options
6. Generation Resource Options
Introduction
There are many generating options to meet future resource deficits. Avista can upgrade
existing resources, build new facilties or contract with other energy companies for
future delivery. This section describes the resources considered to meet future resource
needs. Most of the new resources described in this chapter are generic. Actual size,
cost and operating characteristics may differ due to siting or engineering requirements.
This chapter also includes some resource options specific to Avista, including the
Reardan wind site and hydro upgrades to our Spokane and Clark Fork River Projects.
The costs and characteristics of these resources are based on preliminary studies.
Chapter Highlights
· Only resources with well-defined costs and characteristics were considered in
the PRS analysis; other resources were studied in sensitivities.
· Renewable resource economics include federal tax incentives.
· Small hydro upgrades and wood-fired upgrades were considered in this IRP..
Assumptions
For the Preferred Resource Strategy (PRS) analysis, Avista only considers
commercially-available resources with well-known cost, availability and generation
profiles. These resources include gas-fired combined cycle combustion turbines (CCCT)
and simple cycle combustion turbines (SCCT), large scale wind, and small hydro
upgrades to the Spokane River Projects. Several other resource options described later
in the chapter were not included the PRS analysis, but were modeled as sensitivities to
understand potential impacts to the PRS.
Levelized costs referred to throughout this section are assumed to be at the generation
busbar. The nominal discount rate used in the analyses is 7.08 percent; the real
discount rate is 5.09 percent. Nominal levelized costs were computed by discounting
nominal cash flows at the nominal interest rate. Real levelized costs were computed by
discounting real 2009 dollar cash flows at the real discount rate.
Renewable resources eligible for either the federal investment tax credit 1 (ITC) or
production tax credit (PTC) are assumed to use the highest-value credit. The levelized
costs shown in this chapter are based on maximum available energy for each year
instead of expected generation. For example, wind generation assumes 33 percent
availability, CCCT generation assumes 90 percent availabilty and SCCT generation
1 Avista may not be able to take advantage of the full 30 percent tax credit in a single year. The utilty may
need to find a tax investor or spread the tax credit over multiple years. The Company may be eligible for
treasury credits for projects with construction dates beginning before January 1, 2011.
Avista Corp 2009 Electric IRP 6-1
Chapter 6 - Generation Resource Options
assumes 92 percent availability. The following are definitions of the levelized cost items
used in this chapter:
· Capital Recovery and Taxes: includes depreciation, return on capital, income
taxes, property taxes, insurance, and miscellaneous charges such as
uncollectible accounts and state taxes for each of these items pertaining to
generation asset investment.
· Interconnection Capital Recovery includes depreciation, return on capital,
income taxes, property taxes, insurance, and miscellaneous charges such as
uncollectible accounts and state taxes for each of these items pertaining to
transmission asset investments needed to interconnect the generator.
· Allowance for Funds Used During Construction (AFUDC): the cost of money for
construction payments before the utilty is allowed to recover prudently invested
costs.
· Variable Operations and Maintenance (O&M): Costs per MWh related to
incremental generation.
· Fixed O&M: Costs related to plant
operation such as labor, parts, and other
maintenance services (pipeline capacity
costs are included for CCCT resources)
that are not based on generation levels.
· CO2 Emissions Adder: Cost of carbon
dioxide (greenhouse gas) emissions
based on Wood Mackenzie forecast.
· NOx and 502: Cost of nitrous oxide and
sulfur dioxide emissions based on the
Wood Mackenzie forecast.
· Fuel Costs: The cost of fuels such as
natural gas, coal or wood per the
effciency of the generator. Further details
on fuel prices are included in the Market
Analysis chapter.
· Excise Taxes and Other Overheads:
Includes miscellaneous charges for non-
capital expenses. Noxon Rapids turbine upgrade
Tables at the end of this chapter (Table 6.28 and Table 6.29) show incremental
capacity, heat rates, generation and transmission capital cost estimates before AFUDC,
fixed O&M, variable costs, peak creditl and levelized costs. All costs shown in this
section are in 2009 dollars unless otherwise noted.
2 Peak credit is the amount of capacity a resource contributes at system peak.
6-2 2009 Electric IRP Avista Corp
Chapter 6 - Generation Resource Options
Gas-Fired Combined Cycle Combustion Turbine (CCCT)
The gas-fired CCCT plants were the Northwest resource of choice earlier this decade.
The technology provides a reliable source of both capacity and energy for a relatively
inexpensive upfront investment. The main disadvantage is generation cost volatilty due
to reliance on natural gas. The Company's 2007 IRP discussed the potential for buying
long-term fixed price contracts or supplies to reduce the price volatility and risk
associated with this technology.
CCCTs were modeled using one-on-one (1x1) configurations with both water- and air-
cooling technologies. This configuration consists of a single gas turbine, a single heat
recovery steam generator (HRSG) and a duct burner to gain generation from the
HRSG. These plants are 250 MW to 300 MW each. Plants can be constructed with two
gas turbines and one HRSG (2x1 configuration) up to 600 MW. For modeling purposes,
250 MW and 400 MW plant sizes were included as resource options. Capital cost
estimates were based on General Electric (GE) 7FA machine technology. O&M costs
were based on engineering estimates from the Company's experience with Coyote
Spring 2.
The heat rate modeled for a water-cooled CCCT resource is 6,750 BtulkWh in 2009.
The CCCT heat rate falls by 0.5 percent annually to reflect anticipated technological
improvements. The plants include seven percent of rated capacity as duct firing at a
heat rate of 8,500 Btu/kWh. Forced outage rates are estimated at 5.0 percent per year
and 18 days of maintenance are assumed. Cold startup costs are $35/MWh plus 6.6
Dth per MW per start.
CCCT plants are modeled to back down to 55 percent of nameplate capacity and ramp
from zero to full load in five hours. Carbon emissions are 117 pounds per Dth of fueL.
The maximum capabilty of each plant is highly dependent on ambient temperature and
plant elevation. Figure 6.1 ilustrates the average capacity by month for a water-cooled
CCCT located in Rathdrum, Idaho, compared to the same technology at other locations.
The air-cooled technology is shown for ilustrative purposes and would be an alternative
configuration if an adequate water supply is unavailable. Air-cooled technologies
provide less capacity during warmer periods of the year. The figure ilustrates how
combined cycle capacity is greatly affected by site elevation. (Rosalia-2,238 feet,
Rathdrum-2,211 feet, Lewiston-745 feet and Boardman-298 feet).
Avista Corp 2009 Electric IRP 6-3
Chapter 6 - Generation Resource Options
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Figure 6.1: CCCT Output Per 100 MW of Nameplate Capacity
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90
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The capital cost for a CCCT with AFUDC is estimated to be $1,553 per kW. Fixed O&M
costs are expected to be $11 per kW-year. Table 6.1 is the levelized cost for a CCCT
resource in both nominal and 2009 dollars.
Table 6.1: CCCT (Water Cooled) Levelized Costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 20.91 15.49
Interconnection capital recovery 0.76 0.64
AFUDC 2.60 2.21
Variable O&M 3.88 3.29
Fixed O&M 4.00 3.39
CO2 emissions adder 15.25 12.94
NOx and 802 emission adder 0.15 0.13
Fuel costs 59.29 50.28
Excise taxes and other overheads 3.57 3.04
Total Cost 110.41 91.40
It is possible to sequester 90 percent of the carbon emissions from a gas-fired resource.
A cost adder of $1,374 per kW was added for sequestration, for a total cost of $2,907
per kW including AFUDC. The fixed O&M is expected to increase to $18.70 per kW-
year. The levelized cost for this resource option is shown in Table 6.2.
6-4 2009 Electrc IRP Avista Corp
Chapter 6 - Generation Resource Options
Table 6.2: CCCT with Carbon Sequestration Levelized Costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 43.70 32.38
Interconnection capital recovery 0.57 0.48
AFUDC 7.51 6.37
Variable O&M 5.69 4.83
Fixed O&M 5.86 4.97
CO2 emissions adder 1.98 1.68
NOx & 802 emission adder 0.00 0.00
Fuel costs 75.51 64.20
Excise taxes and other overheads 3.86 3.28
Total Cost 144.68 118.18
Gas-Fired Simple Cycle Combustion Turbine (SCCT)
Gas-fired combustion turbines provide low-cost capacity and are capable of providing
energy as needed. Technology advances allow some SCCTs the ability to start and
ramp quickly, enabling them to provide regulation services and reserves for varying
loads and intermittent resources such as wind.
Two SCCT options were modeled in the IRP: Frame (GE 7EA) and hybrid aero-
derivative (GE LMS 100). The LMS 100 ramps up quickly and has a lower heat rate and
lower start-up costs than the 7EA model, but its capital costs are significantly higher.
O&M costs are based on engineering and NPCC estimates. The frame machine is
modeled in 60 MW increments and the LMS 100 in 100 MW increments.
Heat rates for SCCT plants are 8,400 Btu/kWh (LMS100) and 10,200 Btu/kWh (7EA) in
2009, decreasing by 0.5 percent per year (real) to reflect anticipated technological
improvements. Forced outage rates are estimated at five percent per year, with no
maintenance outages (approximately 10 days per year) because it is assumed to occur
in months when these plants do not typically operate. Cold startup costs are $15 per
MW per start for the frame machine and one Dth per MW for the LMS 100. The
maximum capabilities of these plants are highly dependent on ambient temperature,
and use the same monthly capacity shape as CCCT plants.
The capital cost for a 2009 SCCT with AFUDC is estimated to be $676 per kW for the
frame and $1,342 per kW for the LMS 100. Fixed O&M costs are modeled at $4 per kW-
year for each resource. Tables 6.3 and 6.4 show the levelized cost per MWh for each
resource. The LMS 100 can provide regulation for load and wind; reserves were valued
at $84 per kW-year in the PRS analysis.
Avista Corp 2009 Electric IRP 6-5
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Chapter 6 - Generation Resource Options
Table 6.3: Frame SCCT Levelized Costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 9.27 6.87
Interconnection capital recovery 0.74 0.63
AFUDC 0.43 0.36
Variable O&M 5.90 5.00
Fixed O&M 0.58 0.49
CO2 emissions adder 23.04 19.55
NOx & 802 emission adder 0.23 0.19
Fuel costs 90.09 76.40
Excise taxes and other overheads 5.19 4.40
Total Cost 135.47 113.90
Table 6.4: LMS 100 Levelized Costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 19.31 14.31
Interconnection capital recovery 0.74 0.63
AFUDC 0.89 0.75
Variable O&M 6.49 5.50
Fixed O&M 0.58 0.49
CO2 emissions adder 18.97 16.10
NOx & 802 emission adder 0.19 0.16
Fuel costs 74.19 62.92
Excise taxes and other overheads 4.35 3.69
Total Cost 125.71 104.55
Wind
Concerns over the environmental impact of carbon-based generation technologies have
increased demand for wind generation. Governments are promoting wind generation
through tax credits, renewable portolio standards and climate change legislation. The
2009 American Recovery and Reinvestment Act extended the PTC for wind through
January 1, 2013 and provided an option for owners to select a 30 percent ITC instead.
Several wind resource locations were studied for this IRP:
· Reardan (up to 50 MW);
· Columbia Basin (50 MW increments);
· Montana (25 MW increments);
· Small scale (less than 1 MW); and
· Offshore (75 MW increments).
Reardan and Columbia Basin locations were the only wind resources considered for the
PRS analysis. Other resource locations wil be considered if projects are submitted in
response to competitive solicitations.
6-6 2009 Electric IRP Avista Corp
Chapter 6 - Generation Resource Options
Transmission is an issue for many wind projects. Projects often are not close to
transmission, or when they are the existing lines are fully subscribed. New transmission
must often be constructed. For IRP analyses, transmission costs are assumed to be:
· Reardan: Avista transmission system requiring $15 millon in network and project
transmission improvements.
· Columbia Basin (Tier 1 and Tier 2): SPA wheei3 and $100 per kW for local
interconnection.
· Montana: Northwestern wheei4 and $50 per kW for local interconnection.
· Small Scale: Avista distribution system and $100 per kW for distribution
interconnection and a 10 percent adder for saved transmission and distribution
losses.
· Offshore: SPA wheel and $36 per kW for local interconnection (assumes
economies of scale).
Wind resources benefit from having no emissions and no fuel costs, but are
disadvantaged by not being dispatchable, and being capital and labor intensive. The
costs for capital and fixed O&M, and capacity factors are shown in Table 6.5. Capacity
factors are expected (P50) values for each location. A statistical method, based on
regional wind studies, was used to derive a range of capacity factors depending on the
wind regime in each year (see stochastic modeling assumptions for more details). Using
these expected capacity factors and the capital and operating costs, levelized costs are
ilustrated in Tables 6.6, 6.7 and 6.8. The cost of integrating wind generation is not
shown, but is expected to change over time depending upon the amount of wind
resources on the Avista system. The PRS analysis used a cost of $3.50 per MWh for
integration services.
Table 6.5: Wind Capital and Fixed O&M Costs
Capital 2009$Fixed O&M
(includes ($ per kW-Capacity
Location AFUDC)year)Factor
,0
Columbia Basin (Tier 1 )2,262 50 33.0%
Columbia Basin (Tier 2)2,262 50 26.4%
Montana 2,262 50 37.0%
Small Scale 3,343 50 20.0%
Off Shore 5,573 95 45.0%
Reardan 2183 45 300o/
3 $18 per kW-year and losses are 1.9 percent. Tier 2 wind has a 20 percent lower capacity factor than
Tier 1 wind.4 $40.80 per kW-year and losses are 4.0 percent
5 Costs for the Reardan Wind Project are generic base on prices at the time of modeling. Actual costs wil
vary depending on turbine and balance of plant costs at time of construction. Reardan is assumed to be
slightly less expensive than Columbia Basin projects, due to the lack of signifcant transmission upgrade
. cots, no third part development fees and the proximity of the project to Avista's operations center.":i;F
Avista Corp 2009 Electric IRP 6-7
Chapter 6 - Generation Resource Options
Table 6.6: Columbia Basin Wind Project Levelized Costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 56.63 48.01
Interconnection capital recovery 4.40 3.73
AFUDC 4.60 3.90
Variable O&M 3.54 3.00
Fixed O&M 20.79 17.63
CO2 emissions adder 0.00 0.00
NOx & 802 emissions adder 0.00 0.00
Fuel costs 0.00 0.00
Integration 4.05 3.50
Excise taxes and other overheads 1.05 0.89
Total Cost 95.06 80.66
Table 6.7: Small Scale Project Levelized Costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 125.01 105.97
Interconnection capital recovery 0.00 0.00
AFUDC 10.14 8.60
Variable O&M 3.54 3.00
Fixed O&M 30.60 25.94
CO2 emissions adder 0.00 0.00
NOx and 802 emission adder 0.00 0.00
Fuel costs 0.00 0.00
Integration 4.05 3.50
Excise taxes and other overheads 1.48 1.25
Total Cost 174.82 148.27
Table 6.8: Offshore Wind Project LevelizedCosts per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 103.83 88.02
Interconnection capital recovery 1.16 0.99
AFUDC 11.16 9.46
Variable O&M 5.90 5.00
Fixed O&M 28.97 24.57
CO2 emissions adder 0.00 0.00
NOx and 802 emissions adder 0.00 0.00
Fuel costs 0.00 0.00
Integration 4.05 3.50
Excise taxes and other overheads 1.51 1.28
Total Cost 156.58 132.81
6-8 2009 Electric IRP Avista Corp
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Chapter 6 - Generation Resource Options
Coal
Pulverized and integrated gasification combined cycle (IGCC) coal plants were included
as resource options for the IRP. Pulverized coal options included sub-critical, super-
critical, ultra-critical and circulating fluidized bed (CFB) technologies. These different
technologies have different boiler temperatures and pressures, resulting in different
capital cost and operating effciencies. The ultra-critical plant was modeled for sensitivity
analysis.
IGCC plants gasify coal, thereby lowering carbon emissions and removing toxic
substances before combustion. This technology has the potential to sequester 90
percent of carbon emissions, effectively reducing C02 emissions from 205 pounds per
MMBtu to 20.5 pounds per MMBtu.
The Washington State legislature passed Senate Bil 6001 in 2007, effectively
prohibiting local electric utilities from developing coal-fired facilties that do not
sequester emissions. A coal facility could legally be constructed to serve Idaho loads,
where no emissions performance standard exists, but Avista is not considering a
pulverized coal facilty for the 2009 IRP and believes such a facility is unlikely to be
approved. IGCC facilties were modeled in 200 MW increments in thePRS analysis
beginning in 2022 for IGCC plants without sequestration and 2025 for an IGCC plants
with sequestration.
Capital and fixed O&M costs, and heat rates, are shown in Table 6.9. Levelized costs
per MWh are shown in Tables 6.10, 6.11 and 6.12. IGCC resources currently may
qualify for the federal PTC; but the levelized costs in the tables below do not reflect the
incentive as it is expected to expire before an IGCC resource could be built in 2022.
IGCC coal plants are assumed to be located in Montana with transmission provided by
upgrades to Northwestern's system.
Table 6.9: Coal Capital Costs (2009$)
Capital Cost
($/kW includes Fixed O&M Heat Rate
Technology AFUDC)($/kWNr)(btu/kWh)
Ultra Critical Pulverized Coal $3,594 $38 8,825
IGCC $4,305 $41 8,130
IGCC with Sequestration $6,013 $50 9,595
Avista Corp 2009 Electric IRP 6-9
Chapter 6 - Generation Resource Options
Table 6.10: Ultra Critical Pulverized Coal Project Levelized Cost per MWh r -
Item Nominal $Real 2009$
Capital recovery and taxes 49.96 37.02
Interconnection capital recovery 0.60 0.57
AFUDC 9.29 7.87
Variable O&M 1.53 1.30
Fixed O&M 5.98 5.07
CO2 emissions adder 34.92 29.63
NOx and S02 emission adder 1.30 1.26
Fuel costs 11.37 9.64
Excise taxes and other overheads 2.39 2.03
Total Cost 117.34 94.32
Table 6.11: IGCC Coal Project Levelized Cost per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 59.95 44.42
Interconnection capital recovery 0.60 0.51
AFUDC 11.14 9.45
Variable O&M 4.72 4.00
Fixed O&M 6.45 5.47
CO2 emissions adder 32.17 27.30
NOx and S02 emission adder 0.59 0.54
Fuel costs 10.47 8.88
Excise taxes and other overheads 2.36 2.00
Total Cost 128.45 102.56
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Table 6.12: IGCC with Carbon Sequestration Coal Project Levelized Cost ($/MWh)
Item Nominal $Real 2009$
Capital recovery and taxes 84.71 62.77
Interconnection capital recovery 0.61 0.51
AFUDC 15.75 13.35
Variable O&M 5.19 4.40
Fixed O&M 7.94 6.73
CO2 emissions adder 3.80 3.22
NOx and S02 emission adder 0.18 0.15
Fuel costs 12.36 10.48
Excise taxes and other overheads 1.28 1.08
Total Cost 131.82 102.70
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6-10 2009 Electric IRP Avista Corp
Chapter 6 - Generation Resource Options
Hydroelectric Project Upgrades
Avista has a long history of owning, maintaining and operating hydroelectric projects.
We continue to programmatically upgrade many of our hydroelectnc facilities. Our latest
hydro upgrades add 7 MW at Noxon Rapids Unit 1 and 17 MW at Cabinet Gorge Unit 4.
The Company is planning to upgrade units 2, 3 and 4 at Noxon Rapids (2010, 2011 and
2012 respectively), and units 1 and 2 at Nine Mile in 2012.
Avista designed and studied other larger potential upgrades at Long Lake and Cabinet
Gorge. These upgrades were too costly in previous studies, but increasing market
prices, growing capacity needs, renewable energy incentives and carbon emission
costs may make these resources financially more attractive now. Upgrade options
include a second powerhouse at Long Lake, a fifth unit at Long Lake and Cabinet Gorge
Unit 5. These upgrades are not included as PRS options, but they were evaluated for
sensitivity analysis. See Table 6.13 for more information on these hydro upgrades.
Avista engineers also developed preliminary plans to replace the powerhouse at Post
Falls, doubling its capacity. These large hydro upgrade options have attracted attention
during this IRP cycle and wil be further studied between now and the 2011 IRP. The
estimated levelized costs of hydro upgrades are included in Table 6.14 and Table 6.15.
Table 6.13: Hydro Upgrade Project Characteristics
Little Falls Unit 1 2,787 2014 1.0 32%
Little Falls Unit 2 1,929 2015 1.0 32%
Little Falls Unit 3 3,430 2016 1.0 32%
Little Falls Unit 4 1,393 2017 1.0 32%
Post Falls Unit 6 5,359 2018 0.2 32%
U er Falls 3,870 2019 2.0 49%
Lon Lake Unit 5 2,882 2020 24.0 34%
Lon Lake 2nd Powerhouse 2,454 2020 60.0 30%
Cabinet Gor e Unit 5 1,660 2015 60.0 17%
Avista Corp 2009 Electric IRP 6-11
Chapter 6 - Generation Resource Options
Table 6.14: Hydro Upgrade Nominal Levelized Costs per MWh
Generation Transmission
Capital Capital
Recovery &Recovery &Fixed Total
Project Taxes Taxes AFUDC O&M Cost
Little Falls Unit 1 81.07 0.00 5.82 0.00 86.89
Little Falls Unit 2 56.13 0.00 4.03 0.00 60.16
Little Falls Unit 3 99.78 0.00 7.16 0.00 106.94
Little Falls Unit 4 40.54 0.00 2.91 0.00 43.45
Post Falls Unit 6 155.91 0.00 11.19 0.00 167.10
Upper Falls 71.27 0.00 7.54 0.00 78.81
Long Lake Unit 5 63.58 14.38 10.93 0.40 89.29
Long Lake 2nd Powerhouse 66.52 6.51 10.56 0.90 84.49
Cabinet Gorge Unit 5 83.15 0.00 14.29 1.58 99.02
Table 6.15: Hydro Upgrade 2009$ Levelized Costs per MWh
Generation Transmission
Capital Capital
Recovery &Recovery &Fixed Total
Project Taxes Taxes AFUDC O&M Cost
Little Falls Unit 1 68.72 0.00 4.93 0.00 73.66
Little Falls Unit 2 47.58 0.00 3.42 0.00 50.99
Little Falls Unit 3 84.58 0.00 6.07 0.00 90.66
Little Falls Unit 4 34.36 0.00 2.47 0.00 36.83
Post Falls Unit 6 132.16 0.00 9.49 0.00 141.65
Upper Falls 60.42 0.00 6.39 0.00 66.80
LonQ Lake Unit 5 53.90 12.19 9.26 0.34 75.71
LonQ Lake 2nd PH 56.39 5.52 8.95 0.76 71.65
Cabinet GorQe Unit 5 70.49 0.00 12.12 1.34 84.00
Other Resource Options
A thorough IRP considers resources that may not be commercially or economically
ready for utilty-scale development. This is particularly true for some emerging
technologies that are attractive from an environmental perspective. These resources are
analyzed to ensure that the Company does not overlook resource options with changing
economic characteristics. Avista analyzed solar, tidal (wave), biomass, geothermal, co-
generation, nuclear, pumped storage, hydrokinetics and large scale hydro.
Solar
Solar technology has advanced in the last several years with help from renewable
portolio standards, the federal ITC and state incentives. Solar stil struggles
economically against other resources because of its low capacity factor and high capital
cost. To its credit, solar provides predictable on-peak generation that complements the
loads of summer-peaking utilities.
6-12 2009 Electric IRP Avista Corp
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Chapter 6 - Generation Resource Options
The Northwest is not a prime location for photovoltaic solar relative to the Southwest. A
well placed utiliy scale photovoltaic system located in the Pacific Northwest would
achieve a capacity factor of less than 20 percent. Three solar technologies were studied
for this IRP: utility scale photovoltaic, solar-thermal, and roof-top photovoltaic. Each
option has certain advantages. Utility scale photovoltaic can be optimally located for the
best solar radiation, solar thermal has the ability to produce a higher capacity factor (up
to 30 percent) and store energy for several hours, and roof-top solar is located at the
source of the load reducing system losses. Capital costs, including AFUDC, for these
technologies are expected to be:
· Utilty Scale Photovoltaic: $7,900 per kW;
· Solar or Concentrating Thermal: $4,541 per kW; and
· RoofTop Solar: $8,283 per kW.
The levelized costs of these resources, including federal incentives,6 are shown in
Tables 6.16 and 6.17.
Table 6.16: Solar Nominal Levelized Cost ($/MWh)
Utility Scale Solar Roof-Top
Item Photovoltaic Thermal Solar
Capital recovery and taxes 312.51 130.82 444.46
Interconnection capital recovery 0.00 4.86 0.00
AFUDC 11.06 12.84 15.73
Variable O&M 0.00 0.00 0.00
Fixed O&M 19.58 29.73 24.48
CO2 emissions adder 0.00 0.00 0.00
NOx and 802 emissions adder 0.00 0.00 0.00
Fuel costs 0.00 0.00 0.00
Excise taxes and other overheads 0.85 1.29 1.06
Total Cost 344.00 179.54 485.73
6 Washington has small renewable energy incentives for up to $2,000 per year, depending upon location
of manufacturing, through June of 2014. These incentives are not included in this analysis.
Avista Corp 2009 Electric IRP 6-13
Chapter 6 - Generation Resour.ce Options
Table 6.17: Solar 2009$ Levelized Cost ($/MWh)
Utility Scale Solar Roof-Top
Item Photovoltaic Thermal Solar
Capital recovery and taxes 264.93 110.90 376.79
Interconnection capital recovery 0.00 4.11 0.00
AFUDC 9.38 10.88 13.34
Variable O&M 0.00 0.00 0.00
Fixed O&M 16.60 25.21 20.76
CO2 emissions adder 0.00 0.00 0.00
NOx and 802 emissions adder 0.00 0.00 0.00
Fuel costs 0.00 0.00 0.00
Excise taxes and other overheads 0.72 1.09 0.90
Total Cost 291.63 152.20 411.78
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Biomass and Wood Generation
Avista is an industry leader in biomass generation. In 1983, the Company built one of
the largest biomass generation facilties in North America, the 50 MW Kettle Falls
Generating Station. Eastern Washington and Northern Idaho have the potential for new
biomass facilities. As part of the 2007 IRP Action Plan to study biomass potential, the
Company targeted its biomass focus on wood generation. Several unique options were r .evaluated for this IRP. l
The first option is to use the utility's existing steam turbine capacity at Coyote Spring 2
by augmenting with wood; this option is the CCCT Wood Boiler and would require new
facilities at Coyote Springs 2 for wood handling. It would also require fuel deliveries from
locations remote from the plant, increasing its fuel costs. This option could add 10 MW
of capacity to Coyote Springs 2 when the gas-fired portion of the plant is online.
A second option is to add a wood gasifier to the Kettle Falls Combustion Turbine. It
would utilize existing facilties and infrastructure, and increase winter peak generating
capacity7 by 7.8 MW. The IRP analysis also includes generic biomass resources,
including a new large biomass generation facility using wood gasification technology
and generic biomass resources fueled with manure, landfill gas, wood, and other bio-
waste fuels, including open- and closed-loop technologies. Assumed capital and
operating costs are shown in Table 6.18. The levelized costs are shown in Table 6.19
and Table 6.20. The costs include production tax credits that were extended through
January 1, 2014; closed loop technologies reæive double the federal credits. No fuel
costs were included for non-wood biomass resources because the fuel cost wil depend
on the type of fuel souræ. For example, a digester resource located at a dairy wil have
free fueL.
7 The Kettle Falls CT is currently unavailable for winter peak generation due to limited fuel transportation.
Increasing fuel capacity to the northern service area'is currently being examined.
6-14 Avista Corp2009 Electric IRP
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Chapter 6 - Generation Resource Options
Table 6.18: Biomass Capital Costs
Capital Cost Fixed(2009$)
(includes O&MProjectAFUDC)($/kWfYr)
CCCT Wood Boiler 2,745 121
KFCT Wood Gasifier 4,645 85
Wood Gasifer Combined Cycle 3,476 85
Biomass Open-Loop 5,406 85
Biomass Closed-Loop 8,649 150
Table 6.19: Biomass Nominal Levelized Costs per MWh
CCCT KFCT Wood Biomass Biomass
Wood Wood Gasifier Open-Closed-
Item Boiler Gasifier CC Loop Loop
Capital recovery and taxes 24.67 43.03 32.49 48.16 77.07
Interconnection capital recovery 0.00 0.00 0.28 0.28 0.28
AFUDC 2.42 2.30 1.73 3.91 6.25
Variable O&M 7.08 9.08 9.08 3.54 11.79
Fixed O&M 18.09 12.68 12.68 12.40 21.89
CO2 emissions adder 0.00 0.00 0.00 0.00 0.00
NOx and S02 emission adder 2.12 0.00 0.00 0.00 0.00
Fuel costs 82.50 40.46 40.46 0.00 0.00
Excise taxes and other overheads 4.75 2.69 2.69 0.69 1.46
Total Cost 141.63 110.24 99.41 68.98 118.74
Table 6.20: Biomass 2009 Dollar Levelized Cost per MWh
CCCT KFCT Wood Biomass Biomass
Wood Wood Gasifier Open-Closed-
Item Boiler Gasifier CC Loop Loop
Capital recovery and taxes 20.91 36.48 27.55 40.83 65.33
Interconnection capital recovery 0.00 0.00 0.24 0.24 0.24
AFUDC 2.05 1.95 1.47 3.31 5.30
Variable O&M 6.00 7.70 7.70 3.00 10.00
Fixed O&M 15.34 10.75 10.75 10.52 18.56
CO2 emissions adder 0.00 0.00 0.00 0.00 0.00
NOx and S02 emission adder 1.83 0.00 0.00 0.00 0.00
Fuel costs 69.95 34.31 34.31 0.00 0.00
Excise taxes and other overheads 4.03 2.28 2.28 0.59 1.24
Total Cost 120.12 93.47 84.30 58.48 100.66
Avista Corp 2009 Electric IRP 6-15
Chapter 6 - Generation Resource Options
Geothermal
Northwest utilities have developed increased interest in geothermal energy over the
past two years. Geothermal energy provides a stable renewable source that can provide
capacity and energy with minimal carbon dioxide emissions (zero to 200 pounds per
MWh). The federal government has also extended production tax credits to this
technology through January 1, 2014. Geothermal energy is disadvantaged by a risky
development process involving driling several thousand feet below the earth's crust;
each hole can cost over $3 milion. Capital costs are assumed to be $5,698 per kW,
including AFUDC, with fixed operating costs of $75 per kW-year. Table 6.21 presents
the levelized cost for geothermal generation. Geothermal costs appear attractive once a
viable location has been found, but the risk capital required to find a viable site is
significant and cannot be underestimated. The values below do not account for dry-hole
costs.
Table 6.21: Geothermal Levelized Costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 49.05 41.58
Interconnection capital recovery 0.28 0.24
AFUDC 6.85 5.81
Variable O&M 5.90 5.00
Fixed O&M 11.14 9.45
CO2 emissions adder 1.93 1.64
NOx and 802 emission adder 0.00 0.00
Fuel costs 0.00 0.00
Excise taxes and other overheads 0.82 0.70
Total Cost 75.97 64.41
Tidal and Wave
Tidal and wave power are in the early stages of development. It has varying generation,
but is more predictable than wind. Questions remain surrounding corrosion, bio-fouling
by barnacles and other marine organisms, environmental issues and siting concerns.
Depending upon its application, tidal power can generate in two time periods daily, but
the generation pattern follows the lunar cycle. A 30 percent capacity factor was
assumed for the i RP analysis.
Given its early development stage, tidal power was not considered for the PRS. The
costs of tidal power are uncertain at this time and were estimated using a variety of
sources and engineering estimates. Capital costs including AFUDC are expected to be
$10,389 per kW. Costs presented in Table 6.22 are estimated costs for an experimental
project.
6-16 Avista Corp200 Electric IRP
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Chapter 6 - Generation Resource Options
Table 6.22: TidallWave Levelized Costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 305.57 259.04
Interconnection capital recovery 0.00 0.00
AFUDC 11.90 10.09
Variable O&M 0.00 0.00
Fixed O&M 448.74 379.52
CO2 emissions adder 0.00 0.00
NOx & 802 emission adder 0.00 0.00
Fuel costs 0.00 0.00
Excise taxes and other overheads 19.42 16.47
Total 785.63 665.12
Small Cogeneration
Avista has few industrial customers capable of developing a cogeneration project. If an
interested customer was inclined to proceed, it could provide benefits including reduced
transmission and distribution losses, shared fuel/capital/emissions costs, and credit
towards Washington's 1-937 targets. This resource was excluded from the PRS,
because Avista is not aware of any cogeneration plans by its customers. If a customer
wanted to pursue this resource, Avista would consider it along with other generation
options. The expected levelized costs for cogeneration are shown in Table 6.23.
Table 6.23: Small Cogeneration Levelized Costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 28.09 20.81
Interconnection capital recovery 0.00 0.00
AFUDC 1.29 1.10
Variable O&M 5.90 5.00
Fixed O&M 2.43 2.06
CO2 emissions adder 12.87 10.92
NOx and 802 emission adder 0.13 0.11
Fuel costs 49.18 41.70
Excise taxes and other overheads 3.05 2.59
Total 102.94 84.29
Nuclear
Nuclear plants are not currently considered a viable resource option for Avista given the
uncertainty of their economics, the apparent lack of political support for the technology
in the region. Like coal plants, nuclear resources need to be studied because other
utilties in the Western Interconnect may be able to incorporate nuclear power into their
resource mixes. The viability of nuclear power could change as national policy priorities
focus attention on de-carbonizing the nation's energy supply. Nuclear capital costs are
diffcult to forecast, as no new nuclear facility has been built in the United States since
the 1980s, so costs were obtained from industry studies and plant license proposals.
Capital cost sensitivity analyses were performed to compensate for the diffculties
Avista Corp 2009 Electric IRP 6-17
Chapter 6 - Generation Resource Options
obtaining reliable capital costs for nuclear plants. The starting point for capital costs was
$7,168 per kW, including AFUDC. Levelized costs are shown in Table 6.24.
Table 6.24: Nuclear Levelized costs per MWh r'
Item Nominal $Real 2009$
Capital recovery and taxes 91.79 77.81
Interconnection capital recovery 0.60 0.51
AFUDC 27.23 23.09
Variable O&M 0.65 0.55
Fixed O&M 15.29 12.96
CO2 emissions adder 0.00 0.00
NOx and 802 emission adder 0.00 0.00
Fuel costs 12.06 10.22
Excise taxes and other overheads 0.55 0.47
Total 148.17 125.61
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Hydrokinetics projects consist of small turbines placed in rivers that generate based on
the amount of water flow in the system. Avista has identified potential locations for this
technology and has developed preliminary cost estimates shown in Table 6.25. Capital
costs for this low-impact hydro resource is expected to be $4,212 per kW including
AFUDC and fixed O&M is $3 per kW-year.
Table 6.25: Hydrokinetics Levelized costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 138.89 117.75
Interconnection capital recovery 0.00 0.00
AFUDC 7.38 6.25
Variable O&M 0.00 0.00
Fixed O&M 1.53 1.30
CO2 emissions adder 0.00 0.00
NOx and 802 emission adder 0.00 0.00
Fuel costs 0.00 0.00
Excise taxes and other overheads 0.07 0.06
Total Cost 147.87 125.35
Pumped Storage
Increasing wind generation levels in the Northwest has renewed interest in pumped
storage. Few studies have been conducted for the Northwest market. The most likely
storage options are water or battery technologies. Either option faces significant re-
charging penalties ilustrated by the high variable O&M charge. The expected capital
cost is $4,151 per kW, including AFUDC, with $5 per kW-year for fixed O&M. Levelized
costs estimates are shown in Table 6.26. The reserve value, estimated to be $84 per
kW-year is not shown in the table.
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6-18 2009 Electric IRP Avista Corp
Chapter 6 - Generation Resource Options
Table 6.26: Pumped Storage Levelized costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 90.71 88.61
Interconnection capital recovery 2.59 2.20
AFUDC 16.86 14.29
Variable O&M 92.86 78.76
Fixed O&M 1.22 1.04
CO2 emissions adder 0.00 0.00
NOx and S02 emissions adder 0.00 0.00
Fuel costs 0.00 0.00
Excise taxes and other overheads 4.07 3.45
Total 208.31 188.35
Large Scale Hydro
New large hydro projects are not likely to be built in the Pacific Northwest because of
environmental and cost hurdles. British Columbia has projects in the design phases.
Avista may be able to contract with a Canadian firm for delivery of this energy.
However, the resource was not considered for the PRS analyses because of the
uncertainty surrounding large hydro, and the lack of transmission from British Columbia
to Avista's service territory. The expected capital costs, including AFUDC, are estimated
at $5,273 per kW; fixed O&M is estimated at $2 per kW-year. The levelized cost
analysis shown in Table 6.27 includes BPA and British Columbia Transmission
Corporation transmission wheels.
Table 6.27: Large Scale Hydro Levelized costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 232.4t 197.01
Interconnection capital recovery 1.86 1.58
AFUDC 39.95 39.09
Variable O&M 0.00 0.00
Fixed O&M 0.98 0.83
CO2 emissions adder 0.00 0.00
NOx and S02 emission adder 0.00 0.00
Fuel costs 0.00 0.00
Excise taxes and other overheads 0.04 0.04
Total 275.24 238.54
Avista Corp 2009 Electric IRP 6-19
Chapter 6 - Generation Resource Options
Summary
Avista has several resource alternatives to select from for this IRP. Each provides
different benefits, costs and risks. This IRP identifies relevant characteristics and
chooses a set of resources that are actionable, meet customets energy and capacity
needs, balances renewable requirements and keeps customer costs minimized. Table
6.28 is a summary of resource costs and plant characteristics used in the PRS
analyses. All other resources are shown in Table 6.29. The PRS chapter discusses
resource choices and provides "tipping-point" analyses to explain how resource costs
would need to change to be included in the PRS. (Note: capital costs do not include
AFUDC.)
6-20 Avista Corp2009 Electric IRP
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Chapter 7 - Market Analysis
7. Market Analysis
Introduction
This section discusses the market environment that Avista expects to face in the future.
The analytical foundation for the 2009 IRP is a fundamentals-based electricity model of
the entire Western Interconnect. The market analysis compares potential resource
options on their value in the wholesale marketplace, rather than on overall costs.
Resource net market values are used in the Preferred Resource Strategy (PRS)
analyses. Understanding market conditions in the different geographic areas of the
Western Interconnect is important, because regional markets are highly correlated
because of large transmission linkages between load centers. This IRP builds on prior
analytical work by maintaining the relationships between the various sub-markets within
the Western Interconnect and the changing value of company-owned and contracted-for
resources. The backbone of the analysis is AURORAmp, an electric market model that
dispatches resources to loads across the Western Interconnect with given fuel prices,
hydro conditions, and transmission and resource constraints. The model's primary
outputs are electricity prices at key market hubs (e.g., Mid-Columbia), resource dispatch
costs and values and greenhouse gas emissions.
Chapter Highlights
. Mid-Columbia electricity and Malin natural gas prices are 27 and 20 percent
higher than the 2007 IRP, primarily due to carbon legislation impacts.
. Mid-Columbia electricity prices are expected to average $79.56 per megawatt-
hour (Ievelized) over the next 20 years.
. Mid-Columbia electricity prices are forecast to be one-third higher, than they
otherwise would be, due to projected carbon legislation.
. Average Malin natural gas prices are expected to be $7.36 per decatherm
(Ievelized) over the next 20 years.
. Gas-fired resources continue to serve most new loads and take the place of
coal generation to reduce greenhouse gas emissions
. Society's mandates to acquire new renewable resources help reduce carbon
emmisions, but force utilties to invest in twice as much generation infrastructure.
. New environment-driven investment, combined with higher market prices wil
lead to higher retail rates, absent federal initiatives to limit rate increases.
. Carbon legislation is expected to increase 2Q-year cost (NPV, 2009 dollars) for
electricity generation by $25.7 billon (10 percent) in the Western Interconnect.
Marketplace
AURORAmp is a modeling tool used to simulate the Western Interconnect. The
Western Interconnect includes the states west of the Rocky Mountains, the Canadian
provinces of British Columbia and Alberta and the Baja region of Mexico as shown in
Figure 7.1. The modeled area has an installed resource base of approximately 200,000
MW, and an average load of approximately half that leveL.
Avista Corp 2009 Electric IRP 7-1
Chapter 7 - Market Analysis
Figure 7.1: NERC Interconnection Map
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systems except by eight inverter stations. The Western Interconnect follows operation
and reliabilty guidelines administered by the Western Electricity Coordinating Council
(WECC).
The Western Interconnect electnc system is divided into 16 AURORAmp modeling
zones based on load concentrations and transmission constraints. Atter extensive
study, Avista found that the Northwest is best modeled as a single zone. The single
zone more accurately dispatches resources relative to splitting the Northwest into (L;
multiple areas. The regional topology in this IRP differs from the previous plan by
reverting to a single zone.
Fundamentals-based electncity models range in their abilities to emulate power system
operations. Some account for every bus and transmission line while others utilze
regions or zones. An IRP requires regional price and plant dispatch information. The
specific zones modeled are descnbed in Table 7.1.
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7-2 2009 Electric IRP Avista Corp
Chapter 7 - Market Analysis
Table 7.1: AURORAXMP Zones
Northwest- ORIWAIID/MT Southern Idaho
Eastern Montana Wyoming
Northern California Southern California
Central California Arizona
Colorado New Mexico
British Columbia Alberta
North Nevada South Nevada
Utah Baja, Mexico
Western Interconnect Loads
A load forecastwas developed for each area of the Western Interconnect. Avista relied
on external sources to quantify load growth across the west. These sources included
the integrated resource plans for Northwest utilties and Wood Mackenzie for the
remaining areas. Carbon legislation and associated price increases are expected to
reduce loads over time from their present trajectory. Wood Mackenzie forecasts loads to
be one percent lower in 2020 and 4.6 percent lower in 2026 compared to projected
loads without carbon legislation.
Specific regional load growth levels are presented in Table 7.2. Overall Western
Interconnect loads are forecast to rise by an average level of 1.6 percent over the next
20 years, from 106,727 aMW in 2010 to 146,579 aMW in 2029. A planning margin was
added to the load forecast to account for unplanned events. Regional planning margins
are assumed to be 25 percent in the winter in the Northwest, 17 percent for California,
and 15 percent for all other zones. Higher Northwest planning margins are needed to
account for hydroelectric variability. Additional details about planning margins are in the
Loads and Resources chapter.
Table 7.2: 20-Year Annual Average Peak & Energy Load Growth Rates
Northwest Areas Growth Rate Other Areas Growth Rate
Eastern Oregon 0.01%California 1.51%
Eastern WAlNorth Idaho 1.39%Baja, Mexico 1.51%
Northwest Washington 1.69%Arizona 1.97%
Seattle Metro Area 1.69%South Nevada 1.97%
Portland Metro Area 1.74%North Nevada 2.18%
SW Washincton 1.69%New Mexico 1.83%
Western Oregon 0.01%Colorado 1.48%
Central Washington 2.53%Wvoming 3.59%
South Idaho 1.31%Utah 1.91%
Western Montana 0.61%Alberta 2.00%
British Columbia 1.26%Eastern Montana 0.61%
Avista Corp 2009 Electric IRP 7-3
Chapter 7 - Market Analysis
Transmission
Several regional transmission projects have been announced in the last two years.
Many of these projects wil move renewable resources to load centers for renewable
portolio standards (RPS) obligations. The AURORAxmp model was updated to reflect
the 26,600 MW of transmission upgrades shown in Table 7.3. The transmission
expansion represents the most likely upgrades at the time the price forecast was
developed (Dec 2008). Transmission upgrades within AURORAmp zones were not
included in the model, as they do not impact power transactions between zones.
Table 7.3: Western Interconnect Transmission Upgrades Included in Analysis
Year Capacity
Project From To Available MW
Canada - PNW Project British Columbia Northwest 2018 3,000
PNW - California Project Northwest California 2018 3,500
Eastern Nevada Intertie North Nevada South Nevada 2015 1,600
Colstrip Transmission Montana Northwest 2012 500
Gateway South Utah Nevada 2014 600
Gateway South Wvomino Utah 2015 3,000
Gateway Central Idaho Utah 2016 1,500
Sunzia/Navaio Transmission Arizona New Mexico 2013 3,000
Wyomino- Colorado Intertie Wvomino Colorado 2013 900
Gateway South Wvomino Utah 2015 3,000
Gateway West Wyomino Idaho 2016 3,000
Heminoway to Boardman Idaho Northwest 2015 1,500
Heminoway to Captain Jack Idaho Southern Orecon 2015 1,500
Total 26,600
Regional Renewable Portolio Standards
In an effort to curb greenhouse gas emissions and diversify energy sources, many
states have created RPS requirements. RPS legislation requires utilities to meet a
portion of their load with qualified renewable resources. Each state defines RPS
obligations differently. AURORAmp does not have the abilty to target RPS levels, so
RPS requirements were input into the model to ensure that renewable resource levels
satisfy state laws.
Wind, the predominant renewable resource, does not add capacity to the electric
system. Wind plants are not likely to be able to recover all of their life-cycle costs from
the wholesale electricity marketplace. Renewable resource portolios to meet Western
Interconnect RPS obligations were developed by the Northwest Power and
Conservation Council (NPCC); these percentages were applied to estimated RPS
shortalls in each state. California has the most aggressive RPS goal (33 percent by
2020). The 2009 IRP adopts the NPCC resource mix assumptions. Figure 7.2 ilustrates
projected renewable resource additions to the Western Interconnect. Renewable
resources were manually added only to meet RPS requirements, not exceed it.
7-4 Avista Corp200 Electric IRP
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Chapter 7 - Market Analysis
AURORAmp could have added additional renewable resources where they were found
to be economical as part of its optimization routine, but it did not.
Figure 7.2 ilustrates the difference between nameplate capacity and the delivered
energy of the RPS additions. Most renewable energy requirements are met by wind,
with a smaller contribution from solar. Geothermal, biomass and hydro resources fill
remaining RPS needs. The renewable resource choices differ by state consistent with
their respective laws. The Southwest wil meet requirements with solar and wind; the
Northwest wil use wind and hydro; and the Rocky Mountain states wll predominately
use wind to meet RPS needs.
Figure 7.2: Renewable Resource Additions to Meet RPS
60
50
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_ Geothermal
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_Wind
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Resource Deficits
Assumptions are made on when, where and how many of each new resource type wil
be added to meet peak demand in order to forecast electricity market prices. New
renewable resources meet energy needs, but add a much smaller level of capacity to
the system so that each megawatt of additional wind requires an additional resource to
provide dependable capacity. In tine with the NPCC assumptions, wind is assumed to
provide five percent of its nameplate capacity to meet regional peak demand periods in
the IRP price forecast analysis.
The Northwest historically has depended on hydro system flexibilty to meet peak
demand, but new wind regulation obligations and increased fisheries obligations have
constrained the system. The hydro system can flex for a few hours during a cold day,
but may not have the energy to meet a cold or hot weather event lasting several days.
AURORAmp adds resources to meet one hour system peaks. To simulate a sustained
Avista Corp 2009 Electric IRP 7-5
Chapter 7 - Market Analysis
peaking event exceeding one hour, the amount of hydro available to meet system peaks
was decreased by approximately one-third. Figure 7.3 ilustrates the Northwest resource
shortalL. Blue bars represent the capacity contributions of hydro, thermal and other
resources. The black line represents forecasted winter peak load plus net firm transfers f"
from outside the region (net load). The red line is the net load with a 25 percent
planning margin. Based on these assumptions, the Northwest region is deficit beginning
in 2015; individual utility needs may differ. Avista's resource position was described in
Chapter Two.
Figure 7.3: Northwest Peak Load/Resource Balance
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-Peak Load
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Outside the Northwest, resources and loads are more closely aligned with deficits in
some areas beginning in 2010. Figure 7.4 sums capacity deficits for the entire Western
Interconnect; nearly 10 gigawatts (GW) of capacity are needed in 2010, 38 GW are
needed in 2020 and 62 GW are needed in 2029.l~
7-6 200 Electric IRP Avista Corp
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New Resource Options
The resource deficits shown in Figure 7.4 must be met by resources with dependable
capacity, including gas-fired CCCT or SCCT, coal IGCC, coal with carbon
sequestration, solar, nuclear and traditional pulverized coal plants. Table 7.4 shows
resource options available to fill deficits in different regions.
Table 7.4: New Resources Available to Meet Resource Deficits
IGCC
CCCTI Pulv.IGCC Coal wI
Region SCCT Wind Solar Nuclear Coal Coal CO2 Seq.
Northwest Unlimited Tier 2 Unlimited 2022 n/a n/a 2025
California Unlimited Tier 2 Unlimited n/a n/a n/a 2025
Desert SW Unlimited Tier 2 Unlimited 2022 n/a n/a 2025
Rocky Mountains Unlimited Tier 1 Unlimited 2022 n/a 2015 2025
Canada Unlimited Tier 1 Unlimited 2022 2015 2015 2025
Fuel Prices and Conditions
Some of the most important drivers of resource costs and values are fuel and
availabilty. Some resources, including geothermal and biomass, have limited fuel
options or sources, while coal and natural gas have more fuel sources. Hydro and wind
use free fuel sources, but are highly dependent on weather.
Avista Corp 2009 Electric IRP 7-7
Chapter 7 - Market Analysis
r- .
Natural Gas
The fuel of choice for new base load and peaking resources continues to be natural
gas. The largest drawback to natural gas is its high price volatility. Avista used forward
market prices and a combination of independent sources including the Energy
Information Administration (EIA), the New York Mercantile Exchange and Wood
Mackenzie through 2011. Wood Mackenzie prices were used from 2013 through 2029.
2012 prices used the average of 2011 and 2013.
The natural gas price forecast was completed in December 2008. It was adjusted for the
expected impacts of carbon legislation. Such legislation wil cause the demand for
natural gas to increase as generation shifts from coaL. The increase is estimated to be
$0.50 per Dth in 2013 and $1.00 per Dth after 2018 (2009 dollars).
Economic recovery should absorb exæss productive capacity for natural gas and increase
overall demand growth by 2014. Carbon legislation also wil spur incremental demand for a
multi-year cycle of gas-fired generation construction. This increased demand, combined
with low investments in drillng in prior years, should push priæs higher. The Frontier Gas
Pipeline (1 bcfd) from Alberta to Chicago should also be operational by the end of the next
decade. Figure 7.5 shows the priæ forecst for Henry Hub; the levelized nominal price is
$9.05 per Dth and the reallevelized cost is $7.67 per Dth.
14.0
13.0
12.0
:S 11.0c..10.0CDc.
CD 9.0Co'Cc.8.0
7.0
6.0
5.0
Figure 7.5: Henry Hub Natural Gas Price Forecast
-Nominal
-+2009 Dollars
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Prices differences across North America depend on demand at various trading hubs
and the pipeline constraints between trading hubs. Many pipeline projects have been
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7-8
IL ,2009 Electric IRP Avista Com
Chapter 7 - Market Analysis
announced to access cheaper gas supplies located in the Rocky Mountains. Table 7.5
presents western gas basin differentials from Henry Hub and the) levelized price of gas
at each basin. Prices converge as new pipelines are built and new sources of gas come
online. To ilustrate the seasonality of natural gas prices, the monthly Malin price shape
is provided in Table 7.6 for select years.
Table 7.5: Natural Gas Price Basin Differentials from Henry Hub (Nominal Dollars)
Nominal 2009$
Levelized Levelized
Basin 2010 2015 2020 2025 Cost Costs
Henrv Hub $9.05 $7.67
Opal -2.46 -0.61 -0.68 -0.58 $8.11 $6.88
San Juan -0.26 -0.10 -0.08 0.39 $9.08 $7.70
Southern CA -0.32 -0.15 -0.19 1.42 $9.11 $7.73
Malin -0.51 -0.24 -0.32 -0.49 $8.64 $7.33
Sumas -0.51 -0.20 -0.26 -0.36 $8.70 $7.38
AECO -0.61 -0.31 -0.42 -0.67 $8.54 $7.24
Table 7.6: Monthly Price Differentials for Malin
Month 2010 2015 2020 2025
Jan 103.7%99.8%105.0%106.9%
Feb 104.7%104.9%109.4%107.6%
Mar 100.7%103.7%104.6%101.8%
Apr 92.3%90.6%94.7%g3.4%
May 92.5%94.2%95.4%94.1%
Jun 94.1%93.6%96.0%94.8%
Jul 95.0%96.4%97.8%95.9%
Aua 95.9%97.1%97.8%96.4%
Sep 97.5%97.7%95.2%97.4%
Oct 98.1%98.8%95.3%97.6%
Nov 112.6%111.0%104.1%106.7%
Dec 113.0%112.0%104.7%107.4%
Coal
Coal transportation prices for existing facilties are based on estimates contained in the
AURORAmp database. For new projects, coal mine costs are based on data provided
by the EIA for Wyoming mine-mouth coaL. Transportation costs were added based on
assumed transportation rates and each existing or proposed plant's distance from the
coal supply source. The IRP includes three representative coal plant delivery distances
for all new plants: mine mouth, short haul (250 miles) and long haul (1,000 miles). Coal
details are in Table 7.7.
Avista Corp 2009 Electric IRP 7-9
Chapter 7 - Market Analysis
Table 7.7: Western Interconnect Coal Prices (2009$)
Coal type $/MMBtu $/short ton
Mine mouth $0.73 $12.41
Short haul $1.26 $21.34
Long haul $2.83 $48.11
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Avista has operated the Kettle Falls wood-fired generator for 25 years. When Kettle
Falls was constructed, hog fuel was a waste product from area sawmils at low or no
cost. The future price and availability of hog fuel are critical to understanding the viability
of new wood-fired facilities. Hog fuel costs for new plants are forecasted for two
locations. The first is fuel in Avista's service territory, forecast at $30 per ton or $3.30
per MMBtu in real 2009 dollars. The second fuel forecast is for the Boardman, Oregon
area for a Coyote Spring 2 wood addition, where the price is estimated to be $60 per
ton or $6.60 per MMBtu (2009$). Hog fuel availabilty is highly dependent on lumber
demand. The Kettle Falls plant had surplus fuel in the mid-2000s, but the plant has
struggled to find enough economically priced fuel over the past two years.
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Hydro
The Northwest and British Columbia have substantial hydroelectric generation capacity.
A favorable characteristic of hydro power is its ability to provide short periods of near-
instantaneous generation. This characteristic is particularly valuable for meeting peak
load demands, following general intra-day load trends, shaping energy for sale during
higher-valued peak hours and integrating wind generation. The key drawback to hydro
is its lack of predictable energy on a year-to-year or seasonal basis. Hydro is
constrained by weather patterns and subsequent stream flows. The amount of energy
available at a particular plant depends on river system characteristics.
The IRP uses the Northwest Power Pool's (NWPP) 2007-08 Headwater Benefit Study to
model regional hydro availability. The NWPP study provides energy levels for each
hydroelectric plant by month from 1928 to 1999. British Columbia plants are modeledusing data from the Canadian government. r-;
Many of the analyses in this IRP use an average of the 70-year hydroelectric record;
whereas stochastic studies randomly draw from the 70-year record (see Risk Analysis
later in this chapter). Hydroelectric plants are divided into geographic regions and
represented as a single plant in each zone. The Company models its own projects
individually to provide greater detail about its resources. Table 7.8 shows average
assumed hydro capacity factors for the Northwest hydroelectric plants.
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7-10 2009 Electric IRP Avista Corp
Chapter 7 - Market Analysis
Table 7.8: Northwest Hydro Capacity Factors
Annual Average
Area Capacity Factor
Eastern Oregon 42%
Eastern WAlNorth Idaho 43%
Northwest Washington 40%
Portland Metro Area 41%
SW Washington 38%
Western Oregon 31%
Central Washington 46%
South Idaho 44%
Western Montana 42%
British Columbia 64%
AURORAmp represents hydroelectric plants using annual and monthly capacity
factors, minimum and maximum generation levels, and sustained peaking generation
capabilities. The model's objective, subject to constraints, is to move hydroelectric
generation into peak hours to follow daily load changes. This objective maximizes the
value of the system consistent with actual operations. .
Wind and Solar
As additional wind and solar capacity is added to the electric system to satisfy
renewable portolio standards, there wil be significant competition for higher quality
wind and solar sites. The capacity factors in Table 7.9 present average generation for
the entire area, not specific projects. The Rocky Mountain area is the best location for
wind generation and the desert Southwest is best for solar generation.
Table 7.9: Western Interconnect Wind Capacity Factors
Solar Wind
Wind CF CF Solar
Area CF (%)(%)Area (%)CF (%)
Montana 37.36 19.63 Colorado 34.32 25.23
Canada 36.29 16.82 New Mexico 33.09 25.23
Wyoming 36.13 19.63 South Nevada 33.05 28.04
South Idaho 34.91 22.43 Northwest 32.77 19.63
Utah 34.85 22.43 South California 31.20 25.23
Arizona 32.39 25.23 North California 28.97 19.63
North Nevada 34.56 22.43 Baja, Mexico 31.20 28.04
Greenhouse Gas Emissions
Greenhouse gas or C02 legislation is one the greatest fundamental risks facing the
electricity marketplace today. Reducing CO2 emissions from power plants wil change
the resource mix over time as society moves away from traditional resources and shifts
to an increased reliance on renewable resources. There is currently no federal
regiiation of carbon emissions, but national legislation is expected to pass in the next
Avista Corp 2009 Electric IRP 7-11
Chapter 7 - Market Analysis
few years. In the interim, several western states and provinces are promoting the
Western Climate Initiative to develop a multi-jurisdictional greenhouse gas reduction
program. Whether or not a federal system wil ultimately supersede these efforts is not
known.
The Wood Mackenzie carbon price forecast was used in this IRP. Wood Mackenzie
considered this forecast as it developed its other commodity price forecasts. Carbon
prices ultimately wil depend on greenhouse gas reduction goals, the supply and cost of
allowances and offsets, and the price of natural gas. The only way to greatly reduce
power plant carbon emissions is to price carbon at a level high enough to greatly reduce
the dispatch of coal-fired plants.
Wood Mackenzie based its carbon price forecast on November 2008 legislation
sponsored by Representatives Dingell and Boucher. Their macro-economic models
were balanced by identifying a carbon price forecast adequate to meet federal emission
goals. The analysis included new nuclear and carbon sequestration resources to meet
future load growth in the 2020's. Figure 7.6 shows the carbon price forecast. The IRP
assumes carbon wil have a cost starting in 2012. The price trajectory increases greatly
in 2018 as the next major step in carbon reduction goals begins. The 20-year levelized
cost of carbon is $46.14 (nominal) and $33.37 (2009 dollars). When natural gas prices
rise or fall, the cost of carbon is expected to change to balance the relative
competitiveness of gas and coaL.
The only way to reduce carbon emissions from electric generation below existing levels
under a cap-and-trade model is to increase carbon prices to a level making the marginal
cost of a coal plant higher than a natural gas-fired resource. For example, a natural gas
plant facing a $7.50 per Dth natural gas price wil require a carbon price of
approximately $60 per short ton to make its dispatch attractive relative to a coal plant
with $1.00 per MMBtu fuel. Figure 7.7 ilustrates carbon price levels that would be
necessary at various natural gas and coal prices to allow natural gas generation to
displace coaL. The crossover points between the "dashed" coal and "solid" natural gas
marginal cost estimates represent the price of carbon that makes the two resources
equal in dispatch cost.
7-12 Avista Corp2009 Electric IRP
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Chapter 7 - Market Analysis
$120
$100
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c $160
.s $140
1.o
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..CD $100c.
~ $80'¡:
~ $60o
of $40
cuCJ $20
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Figure 7.6: Price of Carbon Credits
..Nominal
-.2009 Dollars
O"lN C"~an c..-co 0)0 "INC" ~anc. ..coO)"I"I"I"I"I"I"I"I"I"INNNNNNNNNN00000000000000000000NNNNNNNNNNNNNNNNNNNN
Figure 7.7: Cost of Carbon Credits
- - . Coal- $1.00
~ Coal- $3.00
CCCT- $7.50 Gas
CCCT- $5.00 Gas
CCCT- $10.00 Gas
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - ~ - - - ~- -
....
~..- ~ - - - - - - -------- - - - -- - - - -~ -- - - - -- ---ø .-.,...,..
~ - ~_: :~::-:: ::: - ~ -~. ~~. ::.~~-è C -..-..--.,
--"t--.,----..- -01....-.,- ~.,.,
01
.,-- - - -.- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - --.,
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Avista Corp 2009 Electric IRP 7-13
Chapter 7 - Market Analysis
Risk Analysis
Base assumptions in this chapter were modeled stochastically to reflect that we do not
know what future conditions wil actually be. All Base Case assumptions discussed
earlier in this chapter represent expected values, not their expected ranges over time.
Some market drivers are correlated. For example, higher natural gas prices wil likely
require higher carbon prices to ensure that carbon reduction goals are met. The
increased costs wil cause a subsequent load decrease and affect other fuel prices
(e.g., hog fuel price might increase as generators chose to burn more of this fuel to
avoid higher carbon prices). Table 7.10 ilustrates correlations between variables in the
IRP. The relationships between variables were developed to show expected levels of
cause and effect, not on the results of statistical analysis. Market data does not exist for
many of these relationships, so Avista made the assumptions shown in Table 7.10.
Table 7.10: Stochastic Study Correlation Matrix
Natural New Hog
Gas GHG Coal Fuel Load
Prices Prices Prices Prices Growth
Gas Prices 1
GHG Prices 0.50 1
New Coal Prices -0.25 1
Hog Fuel Prices 0.50 0.50 1
Load Growth -0.25 -0.25 -0.5 1
Wind, hydro and forced outages are not necessarily correlated to other market drivers.
The stochastic study portion of the IRP includes 250 combinations of these variables;
500 combinations were studied, but no difference in the mean and standard deviation of
the results was found.
Greenhouse (GHG) Prices
Without established federal legislation, and no formal rules for western carbon markets,
the expected price of GHG emissions is diffcult to determine without macroeconomic
models capable of determining financial impacts outside of the electric industry. Even
with rules in place, carbon prices wil be determined based on the tradeoff and
interaction between natural gas and coal prices. The lack of certainty means that a
range of potential prices needs to be modeled. This IRP utilized ten EPA scenarios as
possible legislative outcomes. The EPA scenarios were developed for the Lieberman-
Warner bil, the leading federal greenhouse gas legislation at the time the modeling for
this IRP was developed. Each scenario was given a weighting (see Table 7.11) by
members of Avista's Climate Change Committee. For the scholastic price forecast, the
assigned weight wil be the probabilty of a certain base price leveL.
7-14 Avista Corp2009 Electric IRP
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Chapter 7 - Market Analysis
Table 7.11: EPA Carbon Study (Nominal Price per Shorton)
Study Weight 2012 2020 2025
ADAGE 10%28.60 50.89 72.40
IGEM 3%40.50 70.15 98.04
ADAGE - Low Inti Action 15%26.20 48.14 66.36
IGEM Unlimited Offsets 10%8.70 20.63 28.66
IGEM with No Offsets 2%80.80 134.79 190.04
ADAGE Scenario 6 3%39.70 67.39 95.02
ADAGE Scenario 7 2%57.20 94.90 132.73
Alt. Ref. ADAGE 35%21.00 38.51 54.30
Alt. Ref. IGEM 5%35.00 61.89 85.97
1766 ADAGE 15%10.20 20.63 28.66
Weighted Average 100%23.46 42.76 59.91
The EPA and Wood Mackenzie studies differ in many aspects, but the major difference
between the two is their assumed natural gas price forecast. To adjust for these
differences, 10 price scenarios were developed for the stochastic portion of the i RP.
See Table 7.12 for the 10 base carbon scenarios modeled for this I RP.
Table 7.12: Ten Cost Scenarios Based on Wood Mackenzie and EPA Studies
(Nominal Price per Short Ton)
Scenario Weight 2012 2020 2025
1 10%8.01 68.28 96.89
2 3%11.31 94.12 131.21
3 15%7.32 64.59 88.82
4 10%2.42 27.68 38.35
5 2%22.56 180.86 254.34
6 3%11.09 90.43 127.17
7 2%15.97 127.34 177.63
8 35%5.86 51.67 72.67
9 5%9.77 83.05 115.06
10 15%2.85 27.68 38.35
Weighted Average 100%6.55 57.37 80.18
The carbon price is determined in a two-step process. The first step draws the carbon
price regime; the second step adjusts natural gas pnces and other variables. The
adjustment keeps prices correlated so the market effect is consistent. See Figure 7.8 for
the carbon price distribution for the 250 iterations in 2012. Carbon prices range from $1
to $35 per short ton, with an average of $6.55 per short ton. The standard deviations of
carbon prices in 2012, 2014, 2016 and beyond are 50 percent, 25 percent and ten
percent respectively.
The correlation between carbon and natural gas is likely to be high because gas-fired
resources set the marginal pnce of electricity in most markets. A 50-percent correlation
between carbon and natural gas is used for this IRP. A gO-percent correl.ation scenario
Avista Corp 2009 Electric IRP 7-15
Chapter 7 - Market Analysis
found no material impact on the results. The method for obtaining carbon prices and
their correlation to other market drivers wil be an ongoing IRP process task.
14%
12%
tic 10%0:¡
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Figure 7.8: Distribution of Annual Average Carbon Prices for 2012 r '
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Natural Gas
Natural gas prices are highly volatile. Daily prices at AECO were as high as $12.92 and
as low as $0.78 per Dth between 2002 and 2009. To represent future natural gas price
uncertainty, volatility is modeled to increase over the study horizon. The standard
deviation is set to 35 percent in 2012, 40 percent in 2015, 45 percent in 2020 and 50
percent in 2025 in a lognormal distribution. Prices wil be determined by the
development and timing of new gas supplies and changes in demand. The IRP risk
analysis is an attempt to capture the range of potential outcomes in this uncertain
future. The 2012 distribution for average prices is in Figure 7.9. Mean prices in 2012 are
expected to be $6.76 per Dth and the median level is $6.24 per Dth. The lognormal
distribution skews prices upward. The 95 percent confidence level is $11.56 per Dth and
the TailVar90, or average of the highest 10 percent of the iterations, is $12.37 per Dth.
Figure 7.10 ilustrates the range of gas prices. The gas prices discussed earlier in this
section are shown as white diamonds. The red lines represent median values from the
stochastic draws and bars represent the 80 percent confidence interval band. The
triangles are the 95 percent confidence level prices. The range of prices increase as
time goes on, consistent with the standard deviation assumptions discussed above.
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l_~7-16 200 Electric IRP Avista Corp
Chapter 7 - Market Analysis
12%
Figure 7.9: Distribution of Annual Average Natural Gas Prices for 2012
2%
1 00/0 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -t/co;: 8%
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aa a aa a aa Q It a(Ø 00 en -N ~.,..(l (l (l -----(l (l (l (l (l
price per Dth
Q
aa
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Figure 7.10: Henry Hub Natural Gas Distributions
$35 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
$30 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
:S $25c..
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$10 lilt!$5 - -- -- ~ --
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Avista Corp 2009 Electric IRP 7-17
Chapter 7 - Market Analysis
High carbon prices generally lead to higher natural gas prices due to the 50 percent
assumed correlation between the two variables. In the later half of the study horizon,
extremely high carbon and natural gas prices are possible due to the vast uncertainty of
future price levels. In past IRPs, the year-to-year prices of a draw were correlated, but
Avista no longer believes there is enough statistical evidence to support this assumption.
Figure 7.11 shows the randomness of annual prices from one year to the next.
100
90
80
705c 60..
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CD.g 40
c.
30
20
10
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Figure 7.11: Random Draws from the Henry Hub Price Distribution
Load
Load variability is driven by several factors. The largest driver is weather because
extreme weather variations can move loads up or down compared to overall expected
levels. The recent economic downturn has decreased electric demand relative to the
long-term average, while earlier economic expansions increased loads. Loads are
modeled to increase at the levels discussed earlier in the chapter, but the risk analysis
varied economic and weather conditions. The economic adjustments are inversely
correlated to natural gas and carbon prices using a lag function. This means that if
carbon prices were high in the previous year, then the probability of lower loads is likely
the following year (25 percent probabilty) due to price elasticity responses.
The standard deviation for load growth is estimated at 50 percent. If a load area was
forecast to have a 2 percent average annual load growth rate, the load in any given year
would be between one and three percent at one standard deviation; two-thirds of all
random draws should fall within this range. Figure 7.12 ilustrates the annual load
growth trajectory for the Western Interconnect in 10 selected iterations.
7-18 200 Electric IRP Avista Corp
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Chapter 7 - Market Analysis
145
140
135!
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cv 110
105
100
Figure 7.12: Random Draws Load Forecast with Year 2009 at 100
en Q _ C' C" ~ It CD to 00 en Q _ C' C" ~ It CD to 00 enQ - - - - - - - _ _ _ C' C' C' C' C' C' C' C' C' C'QQQQQQQQQQQQQQQQQQQQQC' C' C' C' C' C' C' C' C' C' C' C' C' C' C' C' C' C' C' C' C'
The Western Interconnect has many diverse areas and economies. The long-term load-
growth correlation between each area is assumed to be 20 percent. Low correlation
means each area within the Western Interconnect acts in a relatively independent
manner. As with many risk assumptions, the Company wil continue to assess the
correlations and variation for major drivers of the electricity market. A study of historical
weather-adjusted load growth wil be examined for Western Interconnect areas for the
next IRP.
The method Avista adopted for its 2003 IRP continues to be used to reflect weather
patterns across the Western Interconnect. FERC Form 714 data was collected for 2002
to 2007. Correlations between Northwest and other Western Interconnect load areas
were calculated and represented as stochastic weather adjustments to the load modeL.
Correlating area loads avoids oversimplifying the Western Interconnect load picture.
Absent correlations, stochastic models would offset load changes in one zone with load
changes in another, thereby virtually eliminating the possibility of modeling the West-
wide load excursions we witness in today's marketplace. Given the high degree of
interdependency across the Western Interconnect (e.g., the Northwest and California),
this additional accuracy is crucial for understanding variation in wholesale electricity
market prices and the value of resources used to meet such variation (Le., peaking
generation). For example, without regional correlation the volatilty would be measured,
but would not adequately represent heat waves and cold snaps occurring across the
Western Interconnect.
Tables 7.13 and 7.14 ilustrate the correlations used in the I RP. The correlation statistics
are relative to the Northwest load area (Oregon, Washington, and North Idaho).
Avista Corp 7-192009 Electric IRP
Chapter 7 - Market Analysis
"NotSig" indicates no statistically valid correlation was found in the evaluated data. "Mix"
"indicates the relationship was not consistent across time and was not used in this
analysis. Tables 7.15 and 7.16 provide the coeffcient of determination (standard
deviation divided by the average) values for each zone. The weather adjustments are
fairly consistent for each area, except for shoulder months where loads diverge from
one another.
Table 7.13: January through June Area Correlations
Jan Feb Mar Apr May Jun
Alberta 0.674 0.631 0.494 0.679 0.593 0.771
Avista 0.934 0.886 0.848 0.706 0.819 0.691
Arizona 0.236 0.162 0.077 Mix Not Sia 0.312
Baia 0.530 0.584 Mix 0.076 Mix 0.692
British Columbia 0.753 0.765 0.763 0.693 0.552 0.552
Colorado 0.653 00425 Not Sia 00402 00493 0.503
Idaho South 0.847 0.743 0.797 0.075 0.237 0.585
Montana 0.831 0.836 0.655 0.338 0.533 0.726
New Mexico 0.570 0.413 0.349 00469 0.737 0.622
Nevada North 0.690 0.725 0.658 0.683 0.685 0.830
Nevada South 0.785 0.779 0.075 Mix 0.242 0.726
California South 00499 0.334 Mix Mix Not Sia 0.164
Utah 00482 Not Sia 0.259 Mix 0.077 0.425
Wvomina 00486 Not Sia 0.167 Mix Not SiQ 0.386
California North 0.750 0.728 0.603 Mix 0.327 0.543
(
Table 7.14: July through December Area Correlations
Jul Aug Sep Oct Nov Dec
Albert 0.767 0.777 0.821 0.733 0.673 0.786
Avista 0.909 0.776 0.594 0.873 0.909 0.878
Arizona 0.368 Not Sia Mix Mix Not SiQ Not SiQ
Baja 0.689 0.757 Mix Mix 0.072 00456
British Columbia 0.677 Mix 0.247 0.666 0.743 0.732
Colorado 0.505 0.686 0.663 0.672 0.694 0.774
Idaho South 0.747 0.760 Mix 00426 0.873 0.870
Montana 0.782 0.673 0.635 0.775 0.882 0.833
New Mexico 0.596 Mix 0.664 0.525 00420 0.689
Nevada North 0.780 0.818 0.626 0.447 0.756 0.793
Nevada South 0.689 0.608 0.418 Mix 0.543 0.821
California South 00487 0.249 Mix Mix Not SiQ Mix
Utah 00400 Mix 0.243 0.161 0.076 Not SiQ
Wvomina 0.240 Mix Mix Mix 0.072 Not SiQ
California North 0.707 0.503 Mix Mix 0.560 0.764
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7-20 200 Electric IRP Avista Corp
Chapter 7 - Market Analysis
Table 7.15: Area Load Coefficient of Determination (Std Dev/Mean)
Jan Feb Mar Apr May Jun
Alberta 2.8%2.4%3.0%2.9%2.7%3.6%
Arizona 5.8%4.7%4.3%6.4%11.0%7.6%
Avista 6.7%5.8%6.3%5.4%5.5%6.9%
Baja 9.5%7.9%8.5%9.2%10.5%7.6%
British Columbia 5.4%3.8%5.0%4.9%4.3%4.1%
California North 5.3%5.5%5.4%6.0%8.6%9.4%
Colorado 5.2%5.4%5.5%5.2%6.6%7.6%
Idaho South 5.2%5.9%6.8%6.0%10.3%10.9%
Montana 5.0%4.7%4.7%4.5%4.7%5.8%
Nevada North 2.8%2.8%3.2%3.3%4.9%5.0%
Nevada South 4.2%3.7%3.8%6.6%13.8%9.2%
New Mexico 4.6%4.4%4.3%4.6%6.8%5.9%
Oregon Washington Idaho 7.0%5.6%6.3%5.4%5.0%5.1%
Southern California 6.7%6.4%6.6%7.4%9.0%8.1%
Utah 4.9%5.3%5.3%5.0%6.7%8.1%
Wyoming 5.0%5.4%5.3%5.0%6.5%8.2%
Table 7.16: Area Load Coeffcient of Determination (Std Dev/Mean)
Jul Aug Sep Oct Nov Dec
Alberta 3.5%3.2%2.7%2.9%2.5%3.0%
Arizona 7.3%7.1%10.5%10.4%4.9%6.1%
Avista 7.8%6.8%5.7%5.9%6.7%5.7%
Baja 6.4%6.3%11.6%9.9%7.6%10.2%
British Columbia 4.8%4.4%4.4%5.2%5.9%4.6%
California North 9.5%8.0%'!.O%6.0%5.9%5.8%
Colorado 7.2%7.3%7.3%5.2%5.5%5.6%
Idaho South 6.2%6.9%9.8%4.5%6.6%6.1%
Montana 5.9%5.4%4.2%4.5%5.4%4.4%
Nevada North 5.0%4.4%5.0%2.9%3.4%3.5%
Nevada South 7.1%7.2%12.7%8.5%4.0%4.3%
New Mexico 5.9%5.4%5.8%5.3%5.0%5.2%
Oregon Washington Idaho 6.3%5.1%4.8%5.7%7.0%5.8%
Southern California 8.8%8.0%10.4%7.6%7.4%6.8%
Utah 5.7%5.6%7.2%4.5%5.4%5.4%
Wyoming 5.8%5.6%7.0%4.5%5.4%5.5%
Avista Corp 2009 Electric IRP 7-21
Chapter 7 - Market Analysis
Coal Prices
Coal prices are not modeled stochastically for existing plants. Coal prices are typically
contractually based for long time periods. As coal project contracts expire and plants
begin to rely on new fuel sources, prices change with coal supply and demand and
transportation. Coal prices were modeled stochastically using a 10 percent standard
deviation for new coal projects options considered in Avista's PRS Analysis. Prices are
inversely correlated to carbon, as higher carbon prices are expected to decrease coal
demand. It is possible that increased international demand for U.S. domestic coal wil
cause prices to increase. Lower coal demand could reduce the number of suppliers and
cause prices to increase. Transportation cost increases arising from factors besides
carbon reduction also could raise the cost of coaL.
Wood/Hog Fuel
The price of wood, or hog fuel, is modeled stochastically for new resource options
available to the PRS. Avista's experience with woody biomass generation indicates
consistent price increases for a fuel that used to be free. The price and availabilty of
hog fuel varies with the economy. The IRP stochastic analysis assumes a standard
deviation of 10 percent. Further demand for wood residues wil increase with aggressive
greenhouse gas and renewable portolio standard legislation. These environmental
concerns wil encourage more woody-biomass generation or the co-firing of existing
coal and other boiler-fired plants with wood pellets. The correlation between wood and r,
carbon prices is therefore assumed to be 50 percent. Hog fuel is also correlated 50
percent to natural gas prices because most commercial wood residue is displacing
natural gas.
Hydro
The hydro risk analysis uses the 70-year record (1928 to 1999) from the 2008-09
Headwater Benefis Study completed by the Northwest Power Pool. Each water year is
drawn randomly for each iteration of the stochastic analysis. Hydro is not correlated to
any other variable in this study. Some preliminary studies indicate that there might be
modest correlation between hydroelectric and wind generation over a calendar year or
certain seasons. However, Avista is not aware of any comprehensive study of
correlation between the two resources. This relationship wil be studied as more wind
data becomes available. Figure 7.13 shows the distribution of annual hydro capacity
factors for Avista's hydro fleet over the 70-year record. Expected hydro output is 538
aMW and median output is 543 aMW.
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7-22 200 Electric IRP Avista Corp
Chapter 7 - Market Analysis
Figure 7.13: Distribution of Avista's Hydro Generation
18%
16%
~14%.s
.sa.c 12%~
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CD 10%::0 8%....0 6%-c
CD
~4%
CD
Co 2%
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-.!-:- - - - - - - - - - - - - - -c
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-~- - - - - - - - - - - - - --
ii
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-~ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
~
-CD - - -
~
350 400 450 500 550 600 650 700 750
average megawatt
Wind
Wind is one of the most volatile generating resources available to utilities. Storage,
apart from some integration with hydro, is not a financially viable option based on
current technologies. This makes it necessary to capture wind volatilty in the power
supply model to determine its impacts on the overall market, as well as the value of any
wind project acquisition. Accurately modeling wind resources requires hourly generation
shapes. Variabilty is modeled similar to how AURORAmp models hydroelectric
resources for regional analyses. A single wind generation shape is developed for each
area. This generation shape is smoother than individual plant characteristics, but closely
represents how a large number of wind farms across a geographical area would operate
together.
This simplified wind methodology works well for forecasting electricity prices across a
large market, but does not represent well the volatility of specific wind resources the
Company might select. A different wind shape was used for each Avista resource option
in each of the 250 stochastic iterations. This analysis used historical wind speed data
for potential wind sites at Reardan, Washington, the Columbia Basin and Montana.
The first step in developing the wind randomization model was to create a distribution of
hourly output. Figure 7.14 shows the distribution for a Northwest wind site. In this
example, generation is zero for 13 percent of the on-peak hours and zero for 6 percent
of the off-peak hours. The resource is near full output only 5 percent of the time. The
second step links next-hour generation to present generation levels. The next hour has
Avista Corp 2009 Electric IRP 7-23
Chapter 7 - Market Analysis
a 95 percent probability of being within two percent of the last hour's generation leveL.
The model also correlates wind locations: Reardan is 75 percent correlated to
Northwest resources and Montana is 25 percent correlated to Northwest wind
resources.
Figure 7.14: Wind Output Distribution
100%
80%
-On.Peak
-Off.Peak
..Su
.e
~u
caa.
cau
60%
40%
20%
0%
';~~';';~~~';~~0 0 0 0 0 0 00QQQQ00QQQQ-N C"e In CD ..00 en Q-
percent of time
( ,
Forced Outages
Forced outages at CCCT, coal and nuclear plants were included in the risk analysis.
The forced outage logic in the AURORAxmp algorithm is based on a mean time to
repair and a forced outage rate. The model randomly forces a unit out of service and
brings it back online at different intervals throughout the year based on its mean time to
repair. Operating performance varies from iteration to iteration.
Market Forecast
An optimal resource portolio must account for the extrinsic value inherent in the
resource choices. The 2009 IRP simulation was conducted by comparing each
resource's expected hourly output at a forecasted Mid-Columbia hourly price. This
exercise was repeated for 250 iterations of Monte Carlo-style stochastic analysis. L
Resources generating during on-peak hours generally contribute higher margins tO~-;j
Avista's resource portolio than resources with intermediate and unpredictable output.
(.Assumptions used to develop the electricity price forecast were discussed earlier in this
chapter. In general, hourly electricity price is set by the operating cost of the marginal
unit in the Northwest or the economic cost to move power into or out of the Northwest. L..:
To create an electricity market price projection, a forecast of available future resources
must be determined. The IRP uses regional planning margins to set minimum capacity
7-24 2009 Electric IRP Avista Corp L:
Chapter 7 - Market Analysis
requirements, instead of using the summation of capacity needs of each utilty in the
region. Western regions can have resource surpluses even where some individual
utilities may be in a deficit situation. This imbalance can be due to ownership of regional
generation by independent power producers or differences in planning methodologies
used by the deficit utilities.
AURORAmp assigns market values to each resource alternative available to the
Preferred Resource Strategy (PRS), but it does not select PRS resources. Several
market price forecasts are used to determine the value and volatility of a resource
portolio. As Avista does not know what will happen in the future with any degree of
certainty, it relies on risk analysis to help determine an optimal resource strategy. Risk
analysis uses several market price forecasts with different assumptions than the Base
Case or changes the underlying statistics of a study. These alternate cases are split into
stochastic and deterministic studies.
A stochastic study uses Monte Carlo analysis to quantify variabilty in future market
prices. These analyses include 250 iterations of varying gas prices, loads, hydro,
thermal outages, wind shapes and emissions prices. Two stochastic studies were
developed for this IRP, one with and one without carbon legislation. The remaining
studies were deterministic scenario analyses.
Resource Selection
New resource options were discussed earlier in this chapter, along with the amount of
capacity necessary to meet capacity targets. New resources for the Western
Interconnect wil primarily be natural gas-fired. Renewable resources added to meet
renewable portolio standards help fill system energy needs, but fail to provide
equivalent capacity for system reliabilty. Figure 7.15 shows the new resources selected
to meet capacity needs and RPS requirements for the Western Interconnect. The model
retires a number of coal and high heat rate natural gas plants for economic reasons.
Using the same scale, the amount of potential energy is shown in the black line with
diamonds. In 2020, 78 GW of nameplate capacity is added, but only 48 GW of energy is
available from these resources. Mandates to acquire new renewable resources help
reduce carbon emissions, but force utilities to invest in more infrastructure.
The Northwest is expected to need new capacity in 2015, as described earlier in this
chapter. The predominant resource selected after renewables to meet Northwest loads
is combined cycle combustion turbines. 8,100 MW of CCCT are forecast to be added in
the Northwest between 2015 and 2029.
Avista Corp 2009 Electric IRP 7-25
Chapter 7 - Market Analysis
130
115
100
85
l!70;ft 55.~
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40
25
10
(5)
Figure 7.15: Base Case New Resource Selection
Geothermal_Hydro_Solar
CCCT_ Coal- retire_Oil- retire
_Biomass_WindCoal Seq
SCCTly",,'1 NG- retire
~Energy (aGW)
Mid-Columbia Price Forecast
The Mid-Columbia electricity trading hub is Avista's primary trading hub. The Western
Interconnect also has trading hubs on the California/Oregon Border (COB), Four
Corners, Palo Verde, SP15 (southern California), NP15 (northern California) and Mead.
The Mid-Columbia market is usually the least cost market because of low-cost hydro
generation, though other markets can be less expensive when Rocky Mountain area
gas prices are low.
Two studies were conducted for the Base Case. The first is a deterministic market view
using expected levels for key assumptions discussed in the first part of this chapter. The
second is a risk or stochastic study with 250 unique scenarios based on different
underlining assumptions for gas prices, load, carbon prices, wind, hydro, forced outages
and others. Each of these studies simulates the entire Western Interconnect between
2010 and 2029 for each hour. The analysis used 25 CPUs linked to a SQL server to
simulate the market, creating over 26.5 GB of data requiring 1,500 hours of computing
time.
Average prices from the stochastic study do not match deterministic or median prices.
Lognormal natural gas prices with carbon penalties affect prices in a lognormal way,
with more up-side than down-side price variabilty. Figure 7.16 compares stochastic
market price results to the deterministic Base Case scenario. The price distributions are
shown in Figure 7.17 for selected years: the horizontal axis is the percent of time,
indicating 10 percent of the iteration's annual flat prices were above $75 per MWh in
2010 and 50 percent of the time prices were over $48 per MWh.
7-26 200 Electric IRP Avista Corp
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Chapter 7 - Market Analysis
180
160
140
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120
100..(IQ.80
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..(I 150Q.
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Figure 7.16: Annual Flat Mid-Columbia Electric Prices
--Deterministic
--Stochastic- Mean
-+Stochastic- Median
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ N M ~ ~ ~o ~ ~ ~oooooooooooo~~oo 000N N N N N N N N N N N N ~, ~, N N N N N N
Figure 7.17: Selected Mid-Columbia Annual Flat Price Duration Curves
300
250 -2010 -2014
-2017 -2020
50 - - - - - - - - - - - - - - - - - - - - - - - -
o
~oo ~oo'l
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percent of iterations
Annual on- and off-peak prices are presented in Table 7.17, along with levelized costs
for deterministic and stochastic analyses. The Mid-Columbia market price is expected to
average $79.56 per MWh in 2009 dollars over the next 20 years and the average
nominal price is $93.74 per MWh. Spreads between on- and off-peak prices are $14.34
per MWh in 2010 and $32.71 per MWh in 2029.
Avista Corp 2009 Electric IRP 7-27
Chapter 7 - Market Analysis
Table 7.17: Annual Mid-Columbia Electric Prices ($/MWh)
Deterministic Stochastic Mean
Year On Off Flat On Off Flat
Peak Peak Peak Peak
2010 53.86 40.08 47.96 55.44 41.10 49.29
2011 54.40 40.35 48.38 56.70 42.10 50.44
2012 59.09 45.83 53.39 62.56 48.49 56.51
2013 63.62 50.37 57.95 68.92 54.34 62.68
2014 71.19 56.95 65.09 76.76 60.98 70.00
2015 80.72 65.87 74.36 86.94 70.07 79.71
2016 90.50 74.69 83.73 97.00 78.71 89.17
2017 95.46 78.86 88.32 103.78 84.00 95.27
2018 107.32 91.28 100.45 119.24 97.01 109.72
2019 112.00 95.68 105.01 126.03 102.86 116.10
2020 114.88 98.22 107.75 128.40 104.45 118.15
2021 116.16 99.70 109.11 129.17 105.09 118.86
2022 117.84 101.50 110.84 131.07 106.60 120.59
2023 123.03 106.01 115.71 138.34 112.73 127.33
2024 128.07 110.46 120.53 142.84 116.61 131.61
2025 132.85 114.43 124.97 152.13 123.83 140.01
2026 137.71 119.03 129.71 158.82 129.10 146.09
2027 143.78 124.25 135.42 161.94 131.58 148.94
2028 148.88 128.60 140.16 166.20 135.23 152.89
2029 153.78 133.09 144.92 175.56 142.85 161.55
Nominal Levelized 93.10 77.39 86.36 102.41 82.17 93.74
2009$ Levelized 79.01 65.68 73.30 86.92 69.75 79.56 l ,
Greenhouse Gas Emissions Levels
Greenhouse gas levels are expected to increase over the study period where no carbon
legislation is enacted that would affect the Western Interconnect. The carbon costs
discussed earlier in this chapter provide price signals to encourage greenhouse gas
emission reductions following proposed legislation at the end of 2008. The prices were
based on a Wood Mackenzie study including the entire U.S. electrical system. Figure
7.18 shows emissions across the Western Interconnect. Emissions are expected to
quickly fall to 2005 levels, and then more toward 1990 levels by the end of the study.
The Wood Mackenzie study assumed carbon offsets would help meet Western
Interconnect carbon reduction goals. Carbon prices would need to be significantly
higher to reduce the Western Interconnect to 1990 emissions levels without the offset
assumptions. The Wood Mackenzie study found that the Eastern Interconnect wil lower l~.i
emissions at twice the level as the West, but that the West would reduce it emissions by
a higher percentage.
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7.28 2009 Electric IRP Avista Corp
Chapter 7 - Market Analysis
350
330
310-
~ 290
~
E 270
-; 250c
.e 230t:
,g 210
l/190
170
150
Figure 7.18: Western States Greenhouse Gas Emissions
$$.*i .~----*.. -----------*"~---------------------------------------~-*.-**.il.~-
------------------------------------------------------------------
------------------------------------------------------..-
----------------------------------------------------
------------------------_.-------------.--------------------
----------------------------------------------ÃGHGEmissons
2005 Levels ------------------------------------------------1990 Levels ----------------------------------------------
Q~NMe~Ø~~~Q~NMe~Ø~~~~~~~~~~~~~NNNNNNNNNNQQQQQQQQQQQQQQQQQQQQNNNNNNNNNNNNNNNNNNNN
Resource Dispatch
State-level RPS and carbon legislation wil change resource dispatch decisions and
affect future power supply expenses. Figure 7.19 ilustrates that natural gas is expected
to be 27 percent of power generation in 2010, 32 percent in 2020 and 44 percent in
2029. Coal decreases from 29 percent of Western Interconnect generation in 2010 to 16
percent in 2029. Non-hydro based renewables increase from 10 percent in 2010 to 25
percent in 2029. The reduction in coal generation is offset by new renewable
generation, but load growth will primarily be met by natural gas-fired resources.
Public policy changes to encourage renewable energy development and reduce
greenhouse gas emissions wil change the electric marketplace. Policy changes are
likely to move the electric generation fleet toward its most volatile contributor-natural
gas. These policies wil displace low-cost and dependable coal-fired generation with
higher cost renewables and gas-fired generation having lower capacity factors (wind)
and higher marginal costs (natural gas). Regulated utilities are expected to recover
stranded coal costs, requiring society to pay for duplicative resources as renewable and
natural gas resources are buil to satisfy RPS and emissions performance standards.
Wholesale prices wil increase with the effects of the changing resource dispatch driven
by carbon emission limitations. New environment-driven investment, combined with
higher market prices, wil lead to higher retail rates absent federal action.
Avista Corp 2009 Electric IRP 7-29
Chapter 7 - Market Analysis
Figure 7.19: Base Case Western Interconnect Resource Energy
.~ '1100% 200
80%160
~~60%~~120 n:
CD .2'c 0'CD..(l040%80 C)~n:i.0 (l;;n:
20%400% 0O~N~~~~~~~O~N~~~~~~~~~~~~~~~~~NNNNNNNNNN r00000000000000000000 lNNNNNNNNNNNNNNNNNNNN
Scenario Analysis
This section evaluates the market with specific changes in individual assumptions. The
unconstrained carbon emissions scenario is modeled stochastically and
deterministically. It is modeled stochastically because it is used in the PRS analysis to
determine the total cost of carbon legislation. The high gas price, low gas price and
solar saturation scenarios are provided to show the impact of significant market
changes on electricity and carbon prices. Market scenarios were used in prior IRPs to
stress test the PRS against different market scenarios. Since the PRS accounts for a
range of possible outcomes in its risk analysis, the market scenario analysis section has
been limited in this i RP.
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7-30 2009 Electric IRP Avista Corp L.,
Chapter 7 - Market Analysis
Unconstrained Carbon Emissions
The unconstrained carbon emissions scenario quantifies the projected cost of
greenhouse gas legislation. The scenario is first studied deterministically, then
stochastically, with 250 iterations of varying natural gas prices, loads, wind, forced
outages and hydro conditions. The assumptions are similar to the Base Case with a few
notable exceptions. First, the natural gas price forecast is lower because of less
demand for natural gas caused by the continued use of coal-fired generation. Without
carbon legislation, gas prices are expected to be $0.80 per Dth lower, an 8.6 percent
decrease. The resources selected for this scenario are shown in Figure 7.20. The
primary difference between this scenario's resource selection and the Base Case is the
reduction in new natural gas resources and an increase in new coal resources. New
coal resources totaled 11,000 MW over the 20-year study; an equivalent amount of
CCCTs were removed from the portfolio. A few additional peaking resources were
developed in this scenario.
130
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Figure 7.20: Unconstrained Carbon Emissions Resource Selection
Geothermal_Hydro_Coal
CCCT_ Coal- retire_ Oil- retire
_Biomass_Wind_Solar
SCCT~NG-retire
..Energy (aGW)
10
(5)Q - N M 'l U) (Ø .. co en Q _ N M 'l U) (Ø .. co en__________NNNNNNNNNNQQQQQQQQQQQQQQQQQQQQNNNNNNNNNNNNNNNNNNNN
Mid-Columbia market prices would be lower absent carbon legislation. The deterministic
analysis found prices would be $22.43 per MWh lower on a nominallevelized basis over
the forecast horizon; the stochastic analysis found prices would be $25.52 per MWh
(32 percent) lower. Prices are lower without carbon penalties because fuel and dispatch
costs for natural gas-fired plants are lower. A comparison of the two forecasts is shown
in Figure 7.21.
Avista Corp 2009 Electric IRP 7-31
Chapter 7 - Market Analysis
Figure 7.21: Mid-Columbia Prices Comparison with and without Carbon Legislation
180
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-"..-.Unconstined Carbn Emisson&- Stochastc
Q-NMe~~~~~Q_NMe~~~~~------____NNNNNNNNNNQQQQQQQQQQQQQQQQQQQQNNNNNNNNNNNNNNNNNNNN
Figure 7.22 ilustrates the difference between carbon emissions with and without the
carbon adder included in the Base Case. Carbon emissions would be 11 percent higher
in 2020 and 40 percent higher in 2029 without the Base Case carbon adder. The
increased emissions are caused by higher dispatch levels for coal-fired resources
(Figure 7.23) relative to the Base Case. Carbon emission impacts on coal plants could
increase overall fuel costs across the Western Interconnect by 16.3 percent or $42.5
billon in present value terms (2009 dollars). Annual cost increases are shown in Figure
7.24. Carbon legislation adds $328 milion in present value term (2009 dollars) over the
study period for operations, but reduces capital and other non-O&M costs by $17.1
billon. In total, carbon legislation on a 20 year net present value calculation wil
increase costs by $25.7 billon (10 percent).f:i
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7-32 2009 Electric IRP Avista Corp
Chapter 7 - Market Analysis
Figure 7.22: Western U.S. Carbon Emissions Comparison
450
400 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - ---
U)c
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300U)cS
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200 ..GHG Emissons - - -- -- --- - - - - - - - - - - - - - - -- - - - - - - -- -- - - - - - ---
--No GHG Reductions
150 0 ..N CO "l It CD ..co en 0 ..N CO "l It CD ..co en....................N N N N N N ('('('('0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0('('N N ('('('('('N ('('('('N N ('('('('
Figure 7.23: Unconstrained Carbon Scenrio Resource Dispatch
100%200
80%160
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Avista Corp 2009 Electric IRP 7-33
Chapter 7 - Market Analysis
Figure 7.24: Western Interconnect Fuel Cost Comparison
$45
$40
f $35.!
Õ $30"0
en
g $25N-
1; $20ou
ei $152
$10
. Base Case Difference
. Unconstained Carbon
r
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High and Low Natural Gas Prices (1
The High and Low Natural Gas Price scenarios ilustrate the range in Mid-Columbia
electricity prices for different ranges of natural gas prices. These scenarios also keep
carbon emissions at the same level as the Base Case; therefore, a carbon price can be
derived if gas prices change from the Base Case assumptions. Figure 7.25 shows
natural gas prices used for these analyses at the Henry Hub. The monthly and basin
differential prices remain the same as the Base Case. The objective of the Low Natural
Gas Price scenario is to maintain the real price level at the 2010 level throughout the r-'
study and only allow nominal prices to increase with inflation. The levelized price is LJ
$7.50 per Dth (nominal) and $6.36 per Dth (2009 dollars) in this scenario. The High
Natural Gas Price scenario uses a Wood Mackenzie price forecast from the summer of
2008. Prices in this scenario did not include the current recession and subsequent
market effects as well as including lower levels of unconventional gas supplies. The
levelized price is $12.17 per Dth (nominal) and $10.33 per Dth (2009 dollars) for the
High Natural Gas Price scenario.
7-34 2009 Electric IRP Avista Corp
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Chapter 7 - Market Analysis
Figure 7.25: Henry Hub Prices for High and Low Natural Gas Price Scenarios
$25
$20
~Base Case
-"Low Gas Prices
-High Gas Prices
.c-
~ $15
CDc.
CDu'C $10c.
..... ..... .:;:. .:..:.~..: ..:. .:..:.:
. . . .
$5
$0 O-NM~~~~~~O_NM~~~~~~------____NNNNNNNNNN00000000000000000000NNNNNNNNNNNNNNNNNNNN
As discussed throughout this chapter, carbon prices are dependent on natural gas
prices. The objective of the High and Low Gas Price scenarios is to keep carbon
emissions at the samè level as in the Base Case. To achieve these levels, the carbon
emission prices shown in Figure 7.26 were used. The nominal levelized greenhouse
gas price was $47.12 per short ton for the High Gas Price scenario. It was $24.12 for
the Low Gas Price scenario compared to the Base Case of $38.61 per short ton. The
real carbon prices in 2009 dollars are $40.06 (Base Case), $20.49 (Low Gas) and
$32.83 (High Gas) per short ton respectively.
The new resources selected by AURORAmp in the High and Low Natural Gas Price
scenarios do not differ greatly from the Base Case. This is mostly due to RPS
assumptions remaining the same between all cases and because traditional coal is not
an option for most U.S. utilities in the Western Interconnect; therefore, the model uses a
mix of gas, nuclear, sequestered coal, and low capacity factor wind or solar resources.
The High Gas Price scenario is displayed in Figure 7.27. The model in this case
selected more carbon sequestration than in the Base Case and added nuclear
generation to the resource mix. The model also retired three gigawatts of natural gas
and one gigawatt of coal-fired generation.
New resources for the Low Gas Price scenario are shown in Figure 7.28. In the Low
Gas Price environment, the model selected only new gas-fired resources in addition to
the RPS resources. The model retired four gigawatts of older natural gas and two
gigawatts of coal-fired plants.
Avista Corp 2009 Electric IRP 7-35
Chapter 7 - Market Analysis
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iFigure 7.26: Greenhouse Gas Prices for High and Low Natural Gas Price Scenarios
$140
$120
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.s $100
1:
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$20
-+Base Case
-+Low Gas Pnces
-High Gas Pnces
$0 0 ..N CO .10 CD ..GO en 0 ..N CO .10 CD ..GO en....................N N N N N N N N N N00000000000000000000
(N N N N N N N N N N N N N N N N N N N N
Figure 7.27: High Natural Gas Prices Scenario Resource Selection
130
115
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85
~70~to 55.2lat
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Geothermal_Hydro_Solar
Nuclear
SCCT1'0"\1 NG- retire
-+Energy (aGW)
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7-36 200 Electric IRP Avista Corp
Chapter 7 - Market Analysis
130
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Figure 7.28: Low Natural Gas Prices Scenario Resource Selection
Geothermal_Hydro_SolarNuclear
SCCT~NG- retire
..Energy (aGW)
_BiomaS$_Wind~Coal Seq
CCCT_ Coal- retire_Oil- retire
orNQN
As expected, Mid-Columbia electricity prices are higher in the High Gas Price scenario
than in the Base Case or the Low Gas Price scenarios. The nominal levelized price for
the High Gas Price scenario is $102.61 per MWh. The Low Gas Price scenario is
$67.48 per MWh, compared to $86.36 per MWh in the Base Case. Prices are $87.10,
$57.24 and $73.30 per MWh in 2009 dollars, respectively. These prices are graphically
presented in Figure 7.29. Market prices follow natural gas prices because of the high
correlation between these two variables.
The High Gas Price scenario lowers the contribution of natural gas in the Western
Interconnect fuel mix and adds coal sequestration and nuclear projects beginning in
2020 (see Figure 7.30). The Low Gas Price scenario has a similar dispatch as the Base
Case; it includes an increase in natural gas-fired resources (see Figure 7.31). The
contribution from traditional coal-fired resources shrinks to lower carbon emissions in
both scenarios.
Avista Corp 2009 Electric IRP 7-37
Chapter 7 - Market Analysis
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7-38 2009 Electric IRP Avista Corp
Chapter 7 - Market Analysis
Figure 7.31: Resource Dispatch- Low Gas Price Scenario
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Solar Saturation
It is helpful to use the IRP process to identify and understand potential market changes,
rather than only focus on what is or is not included in the Company's PRS. Solar has
caught the attention of many utility planners, government offcials and customers
because of positive environmental characteristics, potential line loss reductions through
distributed energy, free fuel and high correlations with on-peak load. Solar has many
upside potentials, but is stil financially prohibitive because of its high capital costs and
limited generation. The Solar Saturation scenario was developed to understand the
market reaction to a significant decrease in the price of photovoltaic solar. Natural gas,
carbon prices and load remain the same in this scenario. The only change is an 80-
percent reduction in installed photovoltaic solar costs. The scenario is not used for the
PRS, but is included to identify how market prices and greenhouse gas emissions would
be impacted by a significant decrease in photovoltaic solar costs.
If photovoltaic solar became 80 percent less expensive, the amount of solar added
above and beyond the RPS levels is 75 GW, for a total of 90 GW of solar capacity by
2029 (Figure 7.32). Even with the added solar, it only contributes 23,000 aMW of
energy due to the low capacity factor. Solar is not an ideal fit to meet winter peak in
northern areas (5 percent winter capacity contribution in northern states) so another
technology must be used or additional solar must be added to compensate for the lower
winter capacity.
Avista Corp 2009 Electric IRP 7-39
Chapter 7 - Market Analysis
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Figure 7.32: Solar Saturation Scenario Resource Selection
Geothermal_Hydro_Solar
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Adding 75 GW of solar did not have a significant impact on Mid-Columbia market prices.
There was only a reduction of $3.50 per MWh (4 percent) levelized (nominal), though
second and third quarters (high solar months in the Northwest) had lower on-peak
power prices than in the Base Case. Prices did not change because the marginal cost
of power was stil set by gas-fired resources and because solar does not produce power
at night. More solar would need to be added and a low-cost storage technology
identified to effectively lower market prices. Greenhouse gas emissions were reduced
by 10 percent from the Base Case (see Figure 7.33) in this scenario.
More solar generation reduces the Western Interconnect's carbon footprint. Carbon
reduction is primary driven by a decrease in natural gas-fired generation. Coal energy
increased by 1,000 aMW over the Base Case while natural gas-fired production fell by
18,000 aMW in this scenario (see Figure 7.34). The increase in coal generation was
from existing plants operating in off peak hours to compensate for the lack of night time
solar generation, while the reduction in natural gas-fired generation is a result of
decreased need due to the influx of solar resources to serve on-peak load. This study
ilustrates that market prices in the Northwest wil not radically change in spite of a large
amount of new solar generation being added to the system, but greenhouse gas
emissions wil fall along with natural gas prices.
7-40 2009 Electnc IRP Avista Corp
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Chapter 7 - Market Analysis
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Figure 7.33: Western Interconnect Carbon Emissions Comparison
-ABase Case
-2005 Levels
-1990 Levels
-Solar Saturation
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Avista Corp 2009 Electric IRP 7A1
Chapter 7 - Market Analysis
Market Analysis Summary
Market analysis is a key component of the IRP. The market is where the Company
balances its load and resource positions. Without a firm understanding of the
marketplace and how it is affected by public policy, it is diffcult to provide a
comprehensive examination of potential resource being evaluated by Avista and the
utility industry. A summary of key drivers for the 2009 IRP market forecast are
presented in Table 7.18 and Table 7.19. These tables present 10- and 20-year levelized
costs in nominal and 2009 dollars. The 2007 IRP forecasts are included for comparison.
Price expectations have increased since the 2007 IRP. The 10-year Malin natural gas
price forecast increased 20 percent, and the Mid-Columbia electric price forecast
increased 27 percent from the 2007 IRP. Large increases are the result of carbon
mitigation costs. Without greenhouse gas legislation, Malin natural gas and Mid-
Columbia electric prices would only have increased seven percent from the previous
IRP forecasts.
New legislation and regulations impacting the electric system are on the horizon. It does
not matter if the intent is to decrease greenhouse gas emissions, make generation
greener, promote energy independence or affect reliability-power costs wil increase
because new capacity and transmission resources are needed to replace aging
resources and meet new load growth. Carbon and RPS legislation wil diversify fuel
supplies, but wil also increase demand for cleaner burning natural gas.
7-42 2000 EIAr.rir. IRP Avista Com
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Avista Corp 2009 Electric IRP 7-43
Chapter 8 - Preferred Resoure Strategy
8. Preferred Resource Strategy
Introduction
This chapter summarizes the 2009
Integrated Resources Plan's (IRP)
Preferred Resource Strategy (PRS), along
with its potential cost and risks. It details theplanning and resource decision
methodologies; describes the strategy,
climate change ramifications and how the
PRS might evolve if base forecasts of future
conditions are incorrect.
The 2009 PRS is the least-cost achievable Site of the Proposed Reardan Wind Project
plan accounting for climate change and fuel
supply and cost risks. The major change from the 2007 PRS is a greater reliance on wind
to meet renewable portolio standards (RPS), rather than a combination of wind and other
renewables. More wind was selected because it is the only renewable resource available
in quantities large enough to affect utilty planning. It also is more actionable and
controllable by the utilty, allowing for less reliance on third-part developers that might or
might not respond to utilty request for proposal (RFP) efforts. It is likely that the 2009
PRS wil change as new information becomes available on cost, resource options and
legislative actions. However, the strategy contained in this chapter is based on the best
information available at this time.
Chapter Highlights
· Avista's physical energy nees begin in 2018 and capacity needs begin in 2015.
· The first supply-side acquisition is 150 MW of wind by the end of 2012.
· Conservation additions provide 26 percent of new supplies through 2020.
· A 250 MW natural gas-fired combined cycle project is required by 2020, but
could be required as soon as 2015.
· Large hydro upgrades could change the PRS if further study determines them
to be economically viable.
Supply-Side Resource Acquisition History
Avista sold its 210 MW share of the Centralia coal plant in 2001 and replaced its
generation with natural gas-fired projects (see Figure 8.1). After the Centralia sale,
Avista acquired 32 MW of gas-fired peaking capacity and 287 MW of intermediate load
gas-fired capacity. In addition to gas, Avista contracted for 35 MW of wind capacity from
Stateline and added 35.5 MW of new capacity through upgrades to its hydro fleet.
Avista wil gain control of the output for the 270 MW Lancaster Generating Facility
(Rathdrum GS) on January 1, 2010. Avista also expects to upgrade its Nine Mile Falls
and Noxon Rapids hydro facilties over the next five years.
Avista Corp 200 Electric IRP 8-1
Chapter 8 - Preferred Resoure Strategy
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Resource Selection Process
Avista uses several decision support systems to develop its resource strategy. The PRS
is based on results from the PRiSM modeL. The model's objective function is to meet
resource deficits while accounting for overall cost, risk and other constraints. This
method replaces the traditional hand-picked portolio comparison approach. The
AURORAmp model, discussed in the Market Analysis chapter, calculates the operating
margin (value) of Avista's existing resource portolio and each resource option in each
of the 250 potential future outcomes. Then the PRiSM model uses these values
combined with capital and fixed operating costs to select the best resource mix to meet
capacity, energy, RPS and other requirements.
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PRiSM
Avista staff developed the PRiSM model in 2002 to help select the PRS. The PRiSM
model uses a linear programming routine to support complex decision making with
single or multiple objectives. Linear programs provide optimal values for variables using
given system constraints.
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8-2 2009 Electric IRP Avista Corp
Chapter 8 - Preferred Resoure Strategy
Overview of the PRiSM Model
PRiSM has six basic inputs:
1. Load deficits (energy and capacity);
2. RPS standards;
3. Avista's existing portolio's costs (load and resources) and operating margins
(resources);
4. Fixed operating costs, return on capital, interest and taxes for each resource
option;
5. Generation levels for existing resources and new resource options; and
6. Carbon emission levels for existing resources and new resource options.
PRiSM uses these inputs to develop an optimal resource mix over time at varying levels
of cost and consummate risk leveL. It weights the first 10 years more heavily than the
outer years to recognize the importance of near-term decisions on today's utilty
interests (Le., customers and shareholders). A simplified view of the linear programming
objective function formula is provided below.
PRiSM Objective Function
Minimize: (X1 * NPVZ01D-Z019) + (Xz * NPVZ01D-ZOZ9) + (~ * NPVZ010-Z059)
Where: X1 = Weight of net costs over the first 10 years;
Xz = Weight of net costs over 20 years ofthe plan;
X3 = Weight of net costs over the next 50 years; and
NPV is the net present value of total cost (existing resource marginal
costs, all future resource fixed and variable costs, and all future
conservation costs and the net short-term market sales/purchases).
Subject to: Capacity needs;
Energy needs;
Washington RPS;
Resource limitations;
Resource availability; and
Risk tolerance
The hypothetical resource set is used to develop an Effcient Frontier. The 2009 IRP
Effcient Frontier captures the optimal resource selection, given constraints at each level
of cost and risk. Figure 8.2 ilustrates the Effcient Frontier. The optimal point on the
curve depends on the level of risk Avista and its customers can accept. As discussed in
the 2007 IRP, utility-scale resource options are limited because of environmental
legislation. Two portfolio planning assumptions from the 2007 IRP are not continued for
this plan: RPS requirements can no longer be met entirely with utility purchases of
renewable energy certificates (RECs), and long-term fixed-price natural gas is not
available to the portolio. The loss of these options further limits resource choices
compared with the 2007 IRP. Avista does not expect it wil be able to acquire suffcient
RECs at a reasonable price to meet the RPS, and REC purchases expose the
Company to potential volatility that asset ownership would not. For resource planning
Avista Corp 2009 Electric IRP 8-3
Chapter 8 - Preferred Resoure Strategy
purposes, REC purchases are an option, but not in excess of 45,000 per year. Work
since the 2007 IRP have found that long-term fixed-price natural gas contracts consume
inordinate amounts of Company capitaL.
Figure 8.2: Effcient Frontier Curve
Least Cost
.ifI.¡:
(
Least Risk
cost
Constraints
As discussed earlier in this chapter, constraints are necessary to solve for the optimal
resource strategy. Some constraints are physical and others are societaL. The major
resource constraints are: capacity and energy needs, and Washington's RPS and
emissions penormance standard (S8 6001).!i
The PRiSM model is limited by resource type and size. It can select from combined-
and simple-cycle natural gas-fired combustion turbines, wind and small hydro upgrades.
Sequestered coal plants are available beginning in 2023. A new enhancement to
PRiSM for the 2009 IRP cycle ensures it selects resources in minimum block sizes
rather than mathematically optimal increments. This change better reflects how Avista
actually acquires resources. It also emulates how the Company manages lumpy
resource additions and that resource positions are not penectly balanced with load each
year. PRiSM is allowed to model Avista's portolio to be as much as 50 MW short or 200
MW long in any given planning year.
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Washington's RPS fundamentally changed how Avista plans to meet future loads.
Historically an Effcient Frontier was created with the least-cost strategy on one end and
the least-risk strategy on the other. Next, management decided where they warited to
be on the continuums, based on risk appetite. Recent least-cost strategies typically
8-4 200 Electric IRP Avista Corp
Chapter 8 - Preferred Resoure Strategy
consisted of gas-fired resources. Portolios with less risk replaced some of the gas-fired
resources with wind, other renewables and coaL. Past IRPs identified strategies that
included these risk-reduction resources. For ilustration, these strategies are
represented on the Effcient Frontier as a red dot in Figure 8.3. Washington laws
requiring the acquisition of renewable generation, or RECs, and the near-ban on new
coal-fired facilities, removes the lowest-cost portion of the effcient frontier, ilustrated in
blue in Figure 8.3. The added constraints greatly reduce the Company's ability to
reduce future costs. The 2009 IRP is therefore based on the least-cost strategy that stil
complies with state laws, rather than a portolio selected on a full vetting of cost and
risk.
Figure 8.3: Efficient Frontier in a Constrained Environment
Least Cost
~ø.C
Least Risk
cost
Resource Shortges
Avista has adequate resources to meet annual physical energy and capacity needs until
2015. See Figure 8.4. The graphic accounts for energy effciency and conservation
program impacts on the portfolio. Absent these effciency gains, our position would be
deficit sooner. The first capacity deficit is short-lived because a 150 MW exchange
contract ends in 2016. Avista plans to address the 2015-2016 capacity deficit with
market purchases as 2015 approaches.
The Company's resource portfolio has 226 MW of natural gas-fired peaking plants
available to serve winter loads. For long-term planning these resources are assumed to
generate energy at their full capabilities. Operationally, the resouræs often wil be
displaced with less expensive purchases from the wholesale marketplace. On an annual
Avista Corp 2009 Electric IRP 8-5
Chapter 8 - Preferred Resoure Strategy
average basis our loads and resources fall out of balance in 2018 for energy; the first
quarterly energy deficit is in the fourth quarter of 2014.
PRiSM selects new resources to fill capacity and energy deficits, although the model
might over- or under-build for economic reasons. Because of its greater capacity need,
and the fact that wind acquisitions do not provide capacity commensurate with their
energy production, Avista wil retain large energy surpluses.
Figure 8.4: Physical Resource Positions
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Planning Criteria
Avista uses several risk mitigation methods to manage energy and capacity positions.
For capacity, peak load is reflected at the higher of the median coldest or hottest daily
temperature on record in the Spokane area. Resources are netted against peak load at
their expected capacities at the time of system peak; long-term contracts are also netted
in the calculation. A 15 percent planning margin is added to load to represent extreme
weather and resource forced outages. The NPCC suggests Northwest planning margin
levels of 25 percent for winter and 17 percent for summer. Avista staff has evaluated
several methods to determine whether it has adequate reserves, including a sustained
peak analysis and loss of load probability calculations. Its evaluations indicated that a
15 percent planning margin is adequate for planning purposes.
L,. ..~~..:
Avista uses a similar method for energy planning. Load levels use historic temperatures
and include an adjustment for extreme weather, set at a 90 percent confidence level
(single-tail). Thermal resources include forced outage rates and planning maintenance
L
8-6 2009 Electric IRP Avista Corp
Chapter 8 - Preferred Resoure Strategy
downtimes. The largest adjustment is to hydro energy, where water levels are set on a
monthly basis to a level exceeded in nine out of 10 years.
Renewable Portolio Standards (1-937)
Washington voters approved Initiative 937, the Energy Independence Act, in the
November 2006 general election. The initiative requires utilities with over 25,000
customers to meet three percent of load from qualified renewables by 2012, nine
percent by 2016 and 15 percent by 2020. The initiative also requires utilties to acquire
all cost effective conservation and energy effciency measures.
Avista projects it will meet or exceed its renewable requirements between 2012 and
2015 through hydro upgrades and a REC purchase made in 2009, as shown in green in
Figure 8.5. Avista has the ability to bank RECs acquired from the Stateline Wind
contract in 2011 for 2012, but these RECs are sold to customers as part of the Buck-a-
Block program. As part of the REC analysis, Avista included a 10 percent margin so
Avista is not forced to make REC purchases in a strained market when hydroelectric
generation or load varies from its expectation and the Company would potentially be
required to pay a penalty.
The Company wil need its next block of qualifying resources prior to 2016 and another
block wil be required prior to 2020. Assuming Avista meets RPS requirements with
wind, as ilustrated later in this section, it wil requrre 150 MW of nameplate capacity by
2016 and a similar amount by 2020. After 2020, Avista wil continue to acquire
renewable resources to meet load growth as specified in 1-937.
Figure 8.5: REC Requirement vs. Qualifying RECs for Washington State RPS
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Avista Corp 8-72009 Electric IRP
Chapter 8 - Preferred Resoure Strategy
Preferred Resource Strategy
The 2009 PRS consists of hydro upgrades, wind, conservation, distribution effciency
programs and natural gas-combined cycle gas turbines. The first generation resource
acquisition is 150 MW of wind by the end of 2012 to take advantage of federal tax
incentives. Based on expected capital cost growth rates and the likelihood of the tax
credits not being extended beyond 2012, Avista will develop wind projects prior to its
2016 need.
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Avista wil begin rebuilding distribution feeders over the next five years. The PRS
includes five MW of capacity savings and 2.7 aMW of energy savings. More discussion
on this topic is included in the distribution upgrades section of the Transmission and
Distribution chapter.
Avista has committed to upgrades at its Noxon Rapids and Nine Mile Falls projects. The
PRS identified additional cost-effective upgrade opportunities at Little Falls and Upper
F ails. These upgrades provide 5 MW of capacity and 2 aMW of energy qualifying for the
Washington RPS.
The PRiSM model selected its first large capacity addition in 2019, a 250 MW combined
cycle combustion turbine. Another 150 MW of wind capacity is. also needed by the end r j
of 2019 for the 15 percent RPS goal, followed by a 50 MW wind resource in 2022 to
meet additional RPS obligations created by load growth. In 2024 and 2027, another 250
MW natural gas combined-cycle plant is needed to meet a capacity deficit created by
the expiration of the Lancaster tollng agreement. Table 8.1 presents PRS resources.
Table 8.1: 2009 Preferred Resource Strategy
By the
End of Nameplate Energy
Resource Year (MW)(aMW)
NWWind 2012 150.0 48.0
Distribution Effciencies 2010-2015 5.0 2.7
Little Falls Unit Uporades 2013-2016 3.0 0.9
NWWind 2019 150.0 50.0
CCCT 2019 250.0 225.0
Upper Falls 2020 2.0 1.0
NWWind 2022 50.0 17.0
CCCT 2024 250.0 225.0
CCCT 2027 250.0 225.0
Conservation All Years 339.0 226.0
Total 1,449.0 1,020.6
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The 2007 PRS is shown in Table 8.2 for comparison. The major difference between the
2009 and 2007 IRPs is the absence of non-wind renewables and an earlier acquisition
of wind resources in the 2009 plan. The 2014 share of aCCCT plant was removed, due
8-8 2009 Electric IRP Avista Corp
Chapter 8 - Preferred Resoure Strategy
to a lower load forecast and the decision to fill a temporary capacity shortall with market
purchases. The 2009 plan includes 750 MW of natural gas and 350 MW of wind. The
2007 plan included 677 MW of natural gas-fired generation and 300 MW of wind.
Table 8.2: 2007 Preferred Resource Strategy
By the End Nameplate Energy
Resource of Year (MW)(aMW)
Non-Wind Renewable 2011 20.0 18.0
Non-Wind Renewable 2012 10.0 9.0
NWWind 2013 100.0 33.0
Non-Wind Renewable 2013 5.0 4.5
Share of CCCT 2014 75.0 67.5
NWWind 2015 100.0 33.0
NWWind 2016 100.0 33.0
Non-Wind Renewable 2019 10.0 9.0
Non-Wind Renewable 2020 10.0 9.0
Non-Wind Renewable 2021 5.0 4.5
Share of CCCT'2019 297.0 267.3
Share of CCCT 2027 305.0 274.5
Conservation All Years 331.5 221.0
Total 1,368.5 983.3
Energy Efficiency and Conservation
Energy effciency is an integral part of the PRS analytical process. Energy effciency is
also a critical part of the Washington RPS, where utilties are required to obtain all cost
effective conservation. Avista uses internal analysis to develop its avoided energy costs
and compares these figures against an acquirable supply curve of conservation. The
20-year forecast of acquired energy effciency is shown in Figure 8.6. Avista wil acquire
102 aMW of energy effciency over the next 10 years and 226 aMW over 20 years.
These acquisitions wil also reduce the system peak. Effciency gains are expected to
shave 153 MW from the 2020 peak, and 339 MW from the 2029 peak.
Avista Corp 2009 Electric IRP 8~9
Chapter 8 - Preferred Resoure Strategy
Figure 8.6: Energy Efficiency Annual Expected Acquisition
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Reardan
Avista purchased the development rights for the Reardan wind site from Energy
Northwest in 2008. The site is fully permitted for development and has several years of
meteorological data. Reardan is an attractive wind site for Avista because of its close
proximately to Spokane-the site is 23 miles west of downtown Spokane. The site is
expected to deliver a 28 to 32 percent capacity factor depending on the final project
configuration. This wind site is competitive to higher capacity factor sites since the
project does not require any third-part transmission and its proximity to Avista. The site
has the potential to supply 50 to 100 MW of wind generation.
Additional Northwest Wind
Avista anticipates issuing an all-renewables request for proposals (RFP) in 2009. The
RFP wil be for wind projects and other renewable generating facilities with expected
generation up to 50 aMW. If Reardan is found to be cost-effective relative to the RFP,
the total amount of generation acquired from the competitive bidding process wil be
reduced.
Hydro Upgrades
This IRP has analyzed the potential for upgrades on Avista's hydro system. Small
upgrades are included in the PRS analysis, while larger projects are considered as
8-10 Avista Corp2009 Electric IRP
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Chapter 8 - Preferred Resoure Strategy
scenarios since they wil require further engineering work to determine the ultimate cost
of each project. The PRS analysis found four hydro upgrades should be pursued. Little
Falls Units 1, 2 and 4 require generator rewinds and generator shaft replacements. Two
of the units wil also require new runners. The upgrades wil provide 1.0 MW of
additional capacity and 0.32 aMW of energy for each unit. The Upper Falls upgrade wil
include a generator rewind and runner replacement. The upgrade wil add 2.0 MW of
capacity and 1.0 aMW of energy. These hydro upgrades add system capacity and
provide qualified renewable energy.
Loads and Resource Balances
The load forecasts shown in the following charts decrement conservation from the load
forecast by assumed conservation levels identified in the 2007 IRP to show
conservation as a resource. Peak load forecasts are reduced by 1.5 times the average
conservation acquisition leveL. The energy load and resource balance (L&R) forecast
(Figure 8.7) reaches its first deficit in 2016 absent conservation; conservation efforts
delay the deficit two years, until 2018. The PRS additions remove all negative positions
from the L&R position. The CCCT resource included in January 2020 could be brought
online as early as 2015 without any significant impact on the PRS where loads differ
from the present forecast or other factors make the resource attractive prior to that year
(see the end of this chapter for detailed L&R tables).
Figure 8.7: Annual Average Load and Resource Balance
3,500
3,000
~ 2,500;ft
~ 2,000
E
& 1,500
e
~ 1,000ft
500
0
Q "l N C"~10 CD ..co CÐ Q "l N C"~10 CD ..co CÐ"l "l "l "l "l "l "l "l "l "l N N N N N N N N N NQQQQQQQQQQQQQQQQQQQQNNNNNNNNNNNNNNNNNNNN
The first winter peak deficit without conservation occurs in 2014 and the deficit is
delayed to 2015 with conservation (see Figure 8.8). The resource portolio shows
deficits for 2015 and 2016, but returns to a surplus position in 2017 with the expiration
of a 150 MW capacity exchange contract. Avista intends to meet this short-term
deficiency with market purchases rather than acquiring a resource prior to a sustained
Avista Corp 2009 Electric IRP 8-11
Chapter 8 - Preferred Resoure Strategy
long-term need. However, if the Company determines that it cannot depend on the
market during this time period, a capacity resource could be added without a significant
impact on the long-term portolio cost. PRiSM added the first CCCT resource in 2020,
leaving a small short position in 2019 that would be filled with market purchases.
r '
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The summer peak L&R is similar to the winter peak L&R. While peak loads are lower in
summer than winter, hydro and thermal generation capacity is also lower during the
summer. As shown in Figure 8.9, summer resource deficits occur in 2013 without
conservation and in 2014 with conservation measures. The Company plans to fill the
short-term deficit position between 2014 and 2016 with market purchases.
3,500
3,000
2,500
~2,000
~eu
C)1,500(1
E
1,000
500
l
Figure 8.8: Winter Peak Load and Resource Balance
o
0_ NM'l1l CD ""00 cn O_NM 'I ii CD"" oocn__________NNNNNNNNNN00000000000000000000NNNNNNNNNNNNNNNNNNNN
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8-12 2009 Electric IRP Avista Corp
Chapter 8 - Preferred Resoure Strategy
3,500
3,000
2,500
l!2,000;
CGCl 1,500CD
E
1,000
500
Figure 8.9: Summer Peak Load and Resource Balance
o
~ Existing Resources
_ Distbution Effciencies
CCCT
-Load + Planning Margin
Conservation
_ Hydro Upgrades_Wind
Q_NM~~~~~~Q_NM~~~~~~--________NNNNNNNNNNQQQQQQQQQQQQQQQQQQQQNNNNNNNNNNNNNNNNNNNN
Greenhouse Gas Emissions
The Market Analysis chapter discusses how greenhouse gas emissions in the Western
Interconnect wil decrease. Avista's greenhouse gas emissions might not fall due to the
cap and trade market. The projected cap and trade market interaction wil first impact
less effcient carbon emitting facilities before affecting the emissions from more effcient
facilities. This wil affect existing coal resources with high fuel and incremental operation
costs as they wil be replaced with new or underutilized natural gas-fired resources
located closer to west coast load centers. Figure 8.10 shows Avista's expected PRS
greenhouse gas emissions. Emissions wil be near 2010 levels on an annual basis, but
not lower than 2010 levels by the end of 2029. Emissions from current resource portfolio
wil be reduced as Colstrip's output decreases and natural gas facilities increase
generation. The addition of new gas facilities necessary to meet growing loads wil
ultimately contribute to the Company's emission totals. Emissions by 2029 would be 23
percent higher where no carbon legislation is implemented. Avista's carbon intensity is
projected to fall from 0.32 short tons per MWh to 0.24 short tons per MWh by 2029.
Avista Corp 2009 Electric IRP 8-13
Chapter 8 - Preferred Resoure Strategy
Figure 8.10: Avista Owned and Controlled Resource's Greenhouse Gas Emissions
5.0
4.5 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
4.0-t/c 3.5
.2
E 3.0-
t/ 2.5c
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t/
1.0
0.5
0.0
0.40
-----------0.35
0.30
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0.00O_NM~~~~~~O_NM~~~~~~_ _ _ _ __ _ _ _ _ N N N N NN N N N N00000000000000000000N N N N NN N N N N N N N N NN N N N N
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Efficient Frontier Analysis
The backbone of the PRS is the Effcient Frontier analysis. This analysis ilustrates the
relative performance of potential portolios to each other on a cost and risk basis. The
curve created in the analysis represents the least-cost strategy at each level of risk. The
PRS analyses examined the following portolios, as detailed here and in Figure 8.11 :
· Market Only: No conservation measures, deficits are met with spot market
purchases, and capacity and RPS constraints are not met with new resources.
· Capacity Only: No conservation measures or resources are added to meet
capacity needs and RPS requirements are ignored.
· Least Cost without Conservation: Least cost strategy (excluding conservation
measures) meeting capacity and RPS requirements.
· Least Cost: Least cost strategy that includes conservation measures meeting all
capacity and RPS requirements.
· Least Risk: Meets capacity and RPS requirements with the lowest risk.
· Effcient Frontier: A set of intermediate portolios between the least risk and
least cost options.
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The Market Only strategy is the least cost strategy from a long-term financial
perspective, but it has a high risk level. This strategy fails to meet RPS requirements
unless REC purchases are made and does not acquire capacity resources for reliabilty.
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8-14 Avista Corp2009 Electric IRP
Chapter 8 - Preferred Resoure Strategy
The Capacity Only strategy meets reliability needs with CT plant additions, that are
mostly displaced by wholesale market purchases. This strategy does not meet RPS
requirements or relieve volatility, except for tail risk. The Least Cost without
Conservation strategy reduces risks with wind resource additions and selects CCCT
resources rather than CTs; this portolio meets RPS and capacity requirements.
Figure 8.11: Base Case Efficient Frontier
$290
~ $270
o
.
Market Only
Capacity Only.
E $250
caC $230
Eo
.: $210::Q)
:; $190
QN
~ $170
Least CostPRS..
Efcient FrOntie~. Least Risk
Least Cost w/o
Conservation.
$150
3,300
.
3,350 3,400 3,450 3,500 3,550
2010-2020 NPV of power supply costs (millons)
The cost differentials between each portolio quantifies the avoided costs of the
following items:
· Market costs: Market Only portolio.
· Capacity costs: difference between the Market Only and Capacity Only
strategies.
· RPS and risk reduction costs: difference between the Capacity Only and Least
Cost without Conservation strategies.
· Carbon costs: difference between market prices in the Base Case and the
Unconstrained Carbon scenario.
The levelized avoided costs for each item are shown in Table 8.3. The annual avoided
conservation costs are shown in Figure 8.12. Avoided costs are determined by resource
need and Mid-Columbia market prices. The first adder to Mid-Columbia prices is the
Avista Corp 2009 Electric IRP 8-15
Chapter 8 - Preferred Resoure Strategy
carbon adder in 2012, and then capacity and RPS adders are included. The RPS cost-
adder disappears in 2019 and 2025, as a result of the selected resources recovering
their costs from the market rather than rate payers.
Table 8.3: Levelized Avoided Costs ($/MWh)
$180
$160
$140
~ $120
~ $100
CDc.CD $80u'Cc. $60
$40
$20
$0
Nominal 2009 Dollars
Mid-Columbia 68.22 54.37
Carbon 25.52 19.83
Capacity 11.66 9.29
Risk 5.76 4.68
Total 111.15 88.18
Figure 8.12: Avoided Costs for Conservation
o Ca rbon Cost
.RPS
o Capacity
. Mid-Clumbia
o _ N C" . It CD .. co Ø) 0 _ N C" . It CD .. co Ø)--________NNNNNNNNNN00000000000000000000NNNNNNNNNNNNNNNNNNNN
A $111.15 per MWh levelized avoided cost added enough conservation to lower costs
by $65 millon from the least-cost strategy absent this resource; risk is reduced by 14
percent. The Effcient Frontier portolios decrease risk but increase costs. These
portolios add wind resources beyond RPS levels and exchange CCCT plants at the
end of the study for sequestered coal resources. Avista historically selected resources
on the Effcient Frontier, but Washington law requires portolios to include a certain
percentage of qualified renewables, effectively causing utilities to accept less market
risk. The least-cost portolio, with capacity and RPS constraints, was selected over
alternative portolios.
8-16 2009 Electric IRP Avista Corp
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Effcient Frontier Portolios
The Efficient Frontier analysis creates resource portolios for given levels of risk and
cost. Avista's management selected the least cost portfolio because of the significant
risk reductions already present with the inclusion of RPS obligations. Figure 8.13 shows
a range of resource portfolios from the Effcient Frontier. Resource portolios are similar,
but differ in the amount and timing of wind acquisitions.
1,600
1,400
1,200
!1,000
~800as
C)
CD
E 600
400
200
Figure 8.13: Efficient Frontier Portolios 2029 New Resources
Least Risk
Expected Costs
The stochastic market analysis ilustrates a potential range of costs using different
market outcomes. The final discussion covers the range of carbon costs that might be
added to power supply costs, given carbon legislation's potential impact on the natural
gas market, reductions in coal-fired generation dispatch and increases in the dispatch of
natural gas-fired resources.
¡ICCCT
.Wind
.IGCCCoal
. T&O Effciencies
. Hydro Upgrades
. IGCC Coal wI Seq
Capital
The PRS first requires capital in 2010 for distribution feeder upgrades, followed by
needs for wind development. The capital cash flows in Table 8.4 include AFUDC costs
and account for various tax incentives including federal investment tax credits. Costs
are shown for years where capital would be placed in rate base, rather than when
capital is actually expended. The present value of the $2.2 bilion required investment is
just over $1 billon. Avista may not have to supply all of the capital that has been
identified where it chooses to procure resources through power purchase agreements.
Avista Corp 8-17
Least Cost Mid Range +
2009 Electric IRP
Chapter 8 - Preferred Resoure Strategy
Table 8.4: PRS Rate Base Additions for Capital Expenditures
(Milions of Dollars)
Year Investment Year Investment
2010 4.9 2020 942.1
2011 5.0 2021 10.6
2012 5.1 2022 0.0
2013 278.1 2023 163.3
2014 7.7 2024 0.0
2015 2.3 2025 542.0
2016 0.0 2026 0.0
2017 1.7 2027 571.6
2018 0.0 2028 0.0
2019 0.0 2029 0.0
2010-2019 Total 304.8 2020-2029 Totals 2,229.6
Annual Power Supply Expenses and Volatilty
The PRS analyses track fuel, variable O&M, emissions and market transaction costs for
the existing resource portolio. These costs are captured for each of the 250 iterations of
the Base Case risk analysis. In addition to existing portolio costs, new resource capital,
fuel, O&M, emissions and other costs are tracked to provide a range in potential costs
to serve future loads. Figure 8.14 shows expected PRS costs modeled through 2020 as
the black line. Costs are expected to be $180 millon in 2010. The 80 percent
confidence interval, shown in blue, ranges between $130 and $233 millon. The black
diamonds represent the TailVar 90 risk level, or the top 10 percent of the worst
outcomes; this 2010 cost is $270 millon, 50 percent higher than the expected value. As
natural gas and greenhouse gas prices increase, power supply costs also increase.
Price uncertainty increases with time and the confidence interval band expands. The
2020 reduction in variability is created by the addition of wind and CCCT resources to
Avista's portolio.
8-18 Avista Corp200 Electric IRP
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Chapter 8 - Preferred Resoure Strategy
Figure 8.14: Power Supply Expense
$1,200
- 80%CL Low
-Expectd Cost
. Tail Var 90
- 80%CL High
-tiC
~ $1,000
E-
$800CDtiC
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$600
$400
$200
$-o"loN
"l"loN
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C""loN
~"loN
It"loN
CD"loN
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00"loN
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oNoN
Natural Gas Price Risk
The Market Analysis chapter showed the high and low natural gas price forecasts. The
750 MW of PRS gas-fired resources exposes Avista tg natural gas price risk. This
section uses natural gas price forecast scenarios to calculate the range in expected
costs resulting from the PRS. Figure 8.15 shows the total portolio cost range using
different natural gas points in comparison to the deterministic and stochastic Base
Cases. The low gas price scenario reduces expected costs 20 percent and the high gas
price scenario increases costs 15 percent. Using stochastic model results, rather than
deterministic scenarios, ilustrates risk exposure to the wholesale market. The 80
percent confidence interval in Figure 8.15 shows variability due to drivers besides
natural gas. The range in costs is logarithmic, meaning there is the potential for
extremely high costs but that there is not a commensurate cost reduction where gas
prices are low. For example, at the 80 percent confidence level, costs range between 30
percent lower and 40 percent higher than the mean values.
Avista Corp 2009 Electric IRP 8-19
Chapter 8 - Preferred Resoure Strategy
80% CL (High End)
High Gas Price Forecast
Base Case. Deterministic
Base Case. Stochastic
Low Gas Price Forecast
80% CL (Low End)
Figure 8.15: Power Supply Cost Sensitivities
2009 dollars (bilions)
$0.0 $8.0 $10.0$4.0 $6.0$2.0
0%80% 100% 120% 140%20%40% 60%
percent change from Base Case (2029 costs)
Greenhouse Gas Costs
Avista anticipates federal greenhouse gas laws within the next three years; therefore
carbon cost estimates are included in the IRP Base Case. Carbon cost estimates rely
on Wood Mackenzie's forecast from the end of 2008. These prices ilustrate possible
market and opportunity costs of carbon legislation, but ignore the potential for any free
carbon allocations. The PRS analysis assumes all carbon credits are auctioned, rather
than administratively allocated to utilties. This assumption does not affect the resource
strategy because it analyzes the opportunity costs of trading credits for resource
decision making. The ultimate number of credits granted versus auctioned to utilities is
unknown at this time, and wil affect Avista's system costs and rates. The costs shown
in Figure 8.16 ilustrate the range of potential annual carbon costs associated with future
portolio operations.
Most of the overall carbon costs are a result of decreased Colstrip generation and
increased natural gas and electricity market prices. Low cost coal-fired plants are traded
for higher-cost natural gas-fired resources. The cost of gas resources is higher than it
would be absent carbon legislation because of increased demand for gas-fired
resources. These additional costs represent up to 30 percent of total power supply
expenses in the Base Case. The costs were calculated by taking the difference in cost
between the Base Case against the same resource portolio in a market without carbon
legislation.
8-20 200 Electric IRP Avista Corp
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Chapter 8 - Preferred Resoure Strategy
-
Figure 8.16: Carbon Related Power Supply Expense
400
50
0 (:-N C""I It cø ..co en (:-N C""I It cø ..co en----------N N N N N N N N N N(:(:(:(:(:(:(:(:(:(:(:(:(:(:(:(:(:(:(:(:N N N N N N N N N N N N N N N N N N N N
-100% Allocation
- -80% Allocation
-40% Allocation
-0% Allocation
350-
~ 300
~
E 250-
f 200
~
.g 150
en(:~ 100
Carbon Legislation Impact
The PRS would not differ substantially absent carbon legislation because of
Washington's RPS and emissions performance standards on new base load resources.
Avista's carbon emissions would be higher, as Colstrip generation would remain at
current levels, and the cost and risk to Avista's customers would be lower. This is
ilustrated by the Effcient Frontier analysis in Figure 8.17. The green curve on the upper
right of the chart is the Base Case Effcient Frontier with the red dot representing the
PRS. The blue curve in the lower left corner of Figure 8.17 represents the Effcient
Frontier without carbon legislation; the curve is less risky and less costly than the Base
Case. The red dot on this curve ilustrates the non-carbon constrained PRS. A major
difference between the resource selections in this scenario is that the least-cost portolio
includes gas-fired peaking plants, rather than combined cycle resources.
Avista Corp 2009 Electric IRP 8-21
Chapter 8 - Preferred Resoure Strategy
Figure 8.17: Efficient Frontier Comparison
$300
l $250 - - - - - - - - - - - - \ - - -
E-
( 1
( 1L ,I
~ $200
:stIoN
~ $150 . - - - ~- - - - - _. - - - - - - - - -- - - - - - - - - -- -------- - - - - - - - - - - - - --
$100
$2,500 $2,700 $2,900 $3,100 $3,300 $3,500
2010.2020 NPV (millons)
$3,700
The least cost portolio in this scenano is very similar to the PRS, except 750 MW of
combined cycle projects is exchanged for 800 MW of LMS 100 simple-cycle generators
and one of the Little Falls hydro upgrades is dropped (see Table 8.5). The CCCT is the
least cost resource in a carbon constrained world because of its low heat rate and the
need for additional base load generation to replace coaL. But without carbon constraints,
the strategy relies instead on gas peaking plants that ultimately are displaced by market
purchases.
The PRS in an unconstrained carbon market would decrease expected costs 24
percent, to $807 milion present value, as well as decrease annual power supply cost
variation by 30 percent. Table 8.6 summarizes the cost and risk comparison among the
PRS and the least cost scenario in an Unconstrained Carbon market. The least cost
portolio in the Unconstrained Carbon scenario decreases cost and increases risk. The
strategy has lower carbon emissions from Avista's resources because the strategy uses
peaking plants to meet capacity and buys energy from the market, meaning Avista wil
not directly emit as much greenhouse gas.
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8-22 2009 Electric IRP Avista Corp
Chapter 8 - Preferred Resoure Strategy
Table 8.5: Unconstrained Carbon Scenario- Least Cost Portolio
By the End Nameplate Energy
Resource of Year (MW)(aMW)
NWWind 2012 100.0 48.0
Distribution Effciencies 2010-2015 5.0 2.7
Little Falls 4 2016 1.0 0.3
NWWind 2019 150.0 50.0
SCCT 2019 200.0 180.0
Little Falls 2 2021 1.0 0.3
Little Falls 1 2022 1.0 0.3
NWWind 2022 50.0 17.0
SCCT 2022 100.0 90.0
SCCT 2025 100.0 90.0
SCCT 2026 300.0 270.0
SCCT 2028 100.0 90.0
Total 1,159.0 838.6
Table 8.6: Portolio Cost and Risk Comparison
Base Case UC Least Cost
PRS UC PRS Strategy
2010-2020 Cost NPV $3,430 $2,623 $2,610
2020 Expected Cost $909 $634 $609
2020 Stdev $277 $169 $179
2020 Stdev/Cost 30.5%26.7%29.4%
2010-2020 Capital $1,247 $1,247 $1,101
2020 CO2 Emissions (OOO's)3,311 4,016 3,575
2029 CO2 Emissions (OOO's)3,286 4,041 2,928
Portolio Scenarios
In many resource plans, a PRS is presented with a comparison to other portfolios to
ilustrate cost and risk trade-offs. Avista wants to extend the portolio analysis beyond
simple portolio comparisons for this IRP by focusing on how the portolio would change
if assumptions changed. This piOvides an array of stiategies fOi fundamentally diffeient
futures instead of a single strategy. This section identifies assumptions that could alter
the PRS, such as changes to load growth, capital costs, hydro upgrades, the
emergence of other small renewable projects and a nuclear revivaL.
The 2007 IRP pushed wind resources out to 2013 due to the federal production tax
credit and other renewable resource expectations. Due to the lack of sizeable non-wind
renewables and extension of federal tax credits the 2009 IRP suggests that these
resources be developed sooner to take advantage of tax savings. Exact online dates
will depend on results from a competitive bidding process for wind and other
renewables, expected to be released in 2009. The timing of these resources could
change depending on capital costs determined in the RFP.
Avista Corp 2009 Electric IRP 8-23
Chapter 8 - Preferred Resoure Strategy
Wind Capital Costs Sensitivity
Avista owns the rights and permits to build the Reardan wind project, but has not
secured turbines or completed engineering for the site. Most wind projects in this
position today could be completed by the end of 2010 or 2011. The PRiSM model
selects this resource to be online by the end of 2012 with an estimated cost of $2,183
per kW (2009 dollars with AFUDC). There are certain tax advantages for beginning
project development in 2010, such as taking advantage of the investment tax credit.
This analysis determines the tipping point where lower capital costs would allow earlier
wind development. The PRiSM model was re-run while lowering the capital cost of wind
projects until the model changed resource timing. The Reardan project was selected to
be online by the end of 2010 with an all-in capital cost as high as $1,832 per kW (2009
dollars).
CCCT Capital Cost Sensitivity
The Unconstrained Carbon Market future would lead Avista to consider adding simple
cycle CTs to the PRS mix to lower costs, but in the carbon constrained world, CCCT
resources have lower net costs. Since CCCT acquisition in the PRS does not occur until
the end of the next decade, the cost of this resource may change and the cost
relationship to a simple cycle CT might also change. This sensitivity analysis determines
the maximum CCCT cost that would allow the least cost strategy to select a SCCT over
a CCCT. The Base Case CCCT cost is $1,533 per kW (2009 dollars with AFUDC), but if
the cost were to increase five percent to $1,611 per kW (2009 dollars), the least cost
strategy would change to a SCCT.
CCCT in 2015
The PRS does not meet temporary resource deficits in 2015 or 2016 and wil require
market purchases to maintain a 15 percent planning margin. The return of capacity from
the expiration of the Portland General Exchange contract corrects this deficit. If Avista
acquired a combined cycle resource by 2015, costs to meet the earlier obligations
would increase 10-year present value costs by $102 milion or 2.3 percent and reduce
power supply risk between 2015 and 2019 by 5.7 percent. The decision to acquire this
resource earlier wil depend on the Company's expectation that the market has the
capacity to meet regional peak load. Other scenarios that could impact this decision are
dramatic changes in the load forecast, the availability of a suffcient amount of
economically viable renewable resources with on-peak capacity contributions, or
attractive pricing on a new CCCT.
Load Forecast Alternatives
Loads wil probably differ from the current forecast because of the recession and the
greater Spokane area could grow faster with future development activity after the
economy recovers. This sensitivity analysis studies the impact to the PRS if loads grow
faster or slower than the Base Case estimate. Faster load growth wil increase the need
for capital and slower load growth wil slow the need for increased capitaL. This analysis
focuses on understanding the changes in timing of resource decisions. The Base Case
forecast is for a 1.7 percent growth rate. The Low Load scenario cuts the growth rate by
one percentage point to 0.7 percent and the High Growth case increases by one
8-24 2009 Electric IRP Avista Corp
Chapter 8 - Preferred Resoure Strategy
percentage point to 2.7 percent. Table 8.7 shows the resource strategy adjusted for
lower growth rates. The lower load growth projection would not change near-term
resource acquisitions, but would eliminate the need for some wind and gas-fired
resources, as shown in the Modification to Strategy column. Table 8.8 shows the
resource strategy with higher growth rates. The amount of near-term wind would
increase by 50 MW and additional peaking resources would be acquired by 2011 to
compensate for higher growth rates. In later years of the study, additional gas-fired and
wind resources would be needed to meet peak load growth and RPS requirements. This
analysis indicates that lower load growth would not change near-term resource
decisions.
Table 8.7: Low Load Growth Resource Strategy Changes to PRS
By the End Nameplate Energy Modification to
Resource of Year (MW)(aMW)Strategy
NWWind 2012 100.0 48.0 No ChanQe
Distribution Efficiencies 2010-2015 5.0 2.7 No ChanQe
Little Falls Unit Upgrades 2013-2016 3.0 0.9 No Change
NWWind 2019 100.0 33.0 Reduced from 150 MW
CCCT Removed 250 MW
Upper Falls 2020 2.0 1.0 Delayed to 2028
NWWind Removed 50 MW
CCCT 2024 250.0 225.0 Delayed to 2025
CCCT Removed 250 MW
SCCT 2027 100.0 92.3 Added 100 MW
Total 560.0 402.9
Table 8.8: High Load Growth Resource Strategy Changes to PRS
By the End Nameplate Energy Modification to
Resource of Year (MW)(aMW)Strategy
NWWind 2012 200.0 64.5 Increased from 150 MW
Simple Cycle 2011 60.0 92.3 60 MWAdded
Distribution Efficiencies 2010-2015 5.0 2.7 No Change
Little Falls Unit Upgrades 2013-2016 3.0 0.9 No Change
Simple Cycle 2013 100.0 92.3 100 MWAdded
Simple Cycle 2017 100.0 92.2 100 MWAdded
NWWind 2019 200.0 66.0 Increased from 150 MW
CCCT 2020 250.0 225.0 Delayed from 2019
Simple Cycle 2019 100.0 92.2 100 MWAdded
Upper Falls 2020 2.0 1.0 No Change
NWWind 2022 50.0 17.0 No Change
CCCT 2024 250.0 225.0 No ChanQe
CCCT 2027 250.0 225.0 No ChanQe
Total 1,570.0 1,196.1
Avista Corp 2009 Electric IRP 8-25
Chapter 8 - Preferred Resoure Strategy
The estimated cost for these portolios is shown in Figure 8.18. The bars show the net
present value of costs between 2010 and 2020 (left axis), and the yellow line represents
the nominal capital expenditure for these resources (right axis).
Figure 8.18: High & Low Load Growth Cost Comparison
$3.6 $1.8
_ Expectd Cost (NPV 2010-20)
$3.5 ~Capital Expense (2010-2020)$1.5 --IntI-c -
~$3.4 -----~$1.2
.9
.c.Q
I
--(l-tI ii0$3.3 $0.9 c
Co (l
"0 C.)(.!CI
Co $3.2 $0.6 t'CI
Co :!
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$3.1 $0.3 u
$3.0 $0.0
Low Load Base Case High Load
Large Hydro Facilty Scenarios
Renewable portolio standards, capacity needs, and higher electricity market prices are
drawing attention to upgrades at Avista's larger hydroelectric developments. Several
projects were studied over 20 years ago, but they were not financially feasible at this
time. Avista is reevaluating these projects to determine if there are market and
environmental benefits making them cost effective today. The large hydro upgrades
analyzed for this IRP are Cabinet Gorge Unit 5 (60 MW), Long Lake Unit 5 (24 MW) and
Long Lake second power house (60 MW). Other possible hydro upgrades include a new
powerhouse at Post Falls and a second powerhouse at Monroe Street. If studies
determine these resources are economically viable, then the resource strategy wil
change because these resources add peak capacity as well as qualified renewable
energy. Table 8.9 illustrates potential changes to the PRS under the large hydro
upgrade scenario. These upgrades cannot be completed prior to the middle of the next
decade, so they wil not change near-term resource acquisition plans.
8-26 2009 Electric IRP Avista Corp
Chapter 8 - Preferred Resoure Strategy
Table 8.9: Large Hydro Upgrade Resource Strategy Modifications
By the End Nameplate Energy Modification to
Resource of Year (MW)(aMW)Strategy
Distribution Effciencies 2010-2015 5.0 2.7 No Change
Little Falls Unit Upgrades 2013-2016 3.0 0.9 No Change
Cabinet Gorge 5 2014 60.0 10.2 60 MWAdded
Long Lake 2 Powerhouse 2019 60.0 18.0 60 MWAdded
NWWind 2019 100.0 33.0 Reduced from 150
MW
CCCT 2019 250.0 225.0 No Change
NWWind 2022 50.0 17.0 No Change
Delayed from 2024
CCCT 2026 400.0 360.0 and upgraded from
250MW
CCCT Removed 250 MW
Upper Falls 2029 2.0 1.0 Delaved from 2020
Totals 1,030.0 715.8
NWWlnd 2012 1000 480 No Chan e
Capital cost sensitivities were performed to determine capital cost limits needed to
select large hydro upgrades for the PRS. The analysis found that although higher in
cost, a second power house at Long Lake is more favorable than a new Unit 5 at the
plant because of the higher capacity value of that option. Both projects could be built at
Long Lake to provide system capacity.
An initial review found that costs would need to be under $2,628 per kW, including
transmission upgrades and AFUDC, for the Long Lake second powerhouse to be
selected in the least cost resource strategy. The Cabinet Gorge Unit 5 upgrade would
need to be under $1,289 per kW, including AFUDC. Avista might pursue these
upgrades at higher capital cost levels, depending on the value placed on reducing total
dissolved gas and reduced market exposure.
Small Renewable Resources Scenario
The PRS in the 2005 and 2007 IRPs included small renewable resources. None were
included for the 2009 IRP. Small renewable resources often have unique project
characteristics that wil affect project costs. This scenario ilustrates changes in the PRS
if these resources were included in the Effcient Frontier analysis. As Avista solicits 150
MW of wind, it wil include requests for other renewable resources in the RFP and give
resources with dependable capacity more economic benefit in subsequent bidding
analysis. Figure 8.19 presents the Effcient Frontier with the addition of small renewable
resources. If non-wind renewables are available to Avista at the prices shown in the
resource options chapter, these resources could modestly reduce Avista's costs and
risks. Costs are lower because of a reduction in the quantity of resources needed
because non-wind renewable resources provide capacity. For example, a 25 MW wind
project is not credited with any reliable capacity in this analysis, so it must be backed up
Avista Corp 2009 Electric IRP 8-27
Chapter 8 - Preferred Resoure Strategy
with a resource that provides capacity. A 25 MW renewable resource with capacity does
not require another resource to provide back-up capacity. But these small renewable
resources are not risk free. The owner might cease production at some point in the
contract term. Biomass facilties often require an industrial waste product as fuel, so a
downturn in the industry reduces fuel availability. Geothermal resources are interesting
to Avista because of the potential for low cost and stable base load power, but
availability has been questioned recently by the NPCC and only one geothermal
resource has been built in the Northwest in recent years.
Figure 8.19: Efficient Frontier Base Case vs. Other Renewables Available
$300
$280-rnc
~$260
.e-
:.$240
CDli
rn $2200N0N
$200
$180
$3,300
.
...
$3,400 $3,500 $3,600 $3,700 $3,800
2010-2020 NPV (millons)
$3,900
Where Avista is able to acquire non-wind renewables, its resource portfolio strategy wil
emit fewer greenhouse gases (see Table 8.10). The PRS changes under the small
renewable resource scenario are shown in Table 8.11. The strategy reduces wind
capacity by 100 MW and trades 100 MW of CCCT for SCCT (the cause for increased
risk).
8-28 2009 Electric IRP Avista Corp
r- -.
¡
r
L_i
L
Chapter 8 - Preferred Resoure Strategy
Table 8.10: Portolio Cost and Risk Comparison
Base Case Non-Wind Renewable
PRS Least Cost
2010-2020 Cost NPV $3,430 $3,393
2020 Expected Cost $909 $875
2020 Standard Deviation $277 $288
2020 Standard Deviation/Cost 30.5%30.9%
2010-2020 Capital $1,247 $840
2020 CO2 Emissions ('OOOs 3,311 2,771
2029 CO2 Emissions ('OOOs 3,286 3,145
Table 8.11: Other Renewables Available- Changes to PRS
By the End Nameplate Energy Modification to
Resource of Year (MW)(aMW)Strategy
Biomass/Geothermal 2011 10.0 9.1 10 MWAdded
Reardan Wind 2012 50.0 15.0 No Change
NWWind 2012 50.0 17.0 Reduced from 100 MW
Biomass/Geothermal 2012 5.0 4.5 5 MWAdded
Biomass/Geothermal 2013 5.0 4.5 5 MWAdded
Distribution Effciencies 2010-2015 5.0 2.7 No Change
Little Falls Unit Upgrades 2013-2016 3.0 0.9 No Change
Wood Biomass 2017 5.0 4.5 5 MWAdded
KFCT Wood Conversion 2019 7.0 0.0 Capacity/Energy
Neutral RECs Added
NWWind 2019 100.0 33.0 Reduced by 50 MW
Simple Cycle CT 2019 100.0 92.3 100 MWAdded
CCCT 2020 250.0 225.0 Delayed from 2019
Upper Falls 2020 2.0 1.0 No Change
NWWind 2023 50.0 17.0 Delayed from 2022
CCCT 2026 400.0 360.0 Delayed from 2024 and
changed to 400 MW
CCCT 250 MW in 2027
Removed
Total 1,042.0 786.5
Nuclear
Nuclear resources were not included as a PRS option, but were studied as a resource
scenario. This resource intrigues planners because of stable operating costs, base-load
capability, and a lack of greenhouse gas emissions. However, nuclear power has high
capital costs, and projected capital and operating costs are speculative since no U.S.
project has been completed in over 20 years. Long lead times require significant capital
to be at risk during construction, forcing higher AFDUC costs. If nuclear was an option
in the PRS analysis after 2020 at $5,500 per kW (2009 dollars before AFUDC), the
project would not be selected as least cost, but would lower power supply cost variation.
At $3,800 per kW, a 250 MW nuclear project would be selected as a least cost resource
Avista Corp 2009 Electric IRP 8-29
Chapter 8 - Preferred Resoure Strategy
after 2020. Avista wil continue to monitor and investigate nuclear development as
projects are announced and developed.
Summary
The IRP is a continual effort to select cost- and risk-minimizing resources that
complement existing resources and to help management and policy-makers make
informed decisions for ratepayers. The PRS includes a combination of conservation, f-
distribution effciency, hydro upgrades, wind and combined-cycle combustion turbines.
The resource strategy identified in this report will change as new information becomes
available, but Avista focuses on near-term acquisitions where changes are less likely.
Avista wil study large hydro upgrades on the Clark Fork and Spokane rivers to add
system capacity and help meet renewable RPS requirements. Figure 8.20 shows power
supply costs in 2019 are 38 percent higher in real terms absent carbon legislation, but r
up to 95 percent higher with carbon legislation. Power supply costs grow 2.9 percent in
real terms absent carbon legislation and 4.7 percent with carbon legislation.
Figure 8.20: Real Power Supply Expected Cost Growth Index (2010 = 100)
300
250
..Base Case
-No C02 Cost
_Actual
150
g..
II 200o..
~
~
~100
~o
50 - - - - - .- .
o
~ ~i I I
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fa ~ ~
e CD.. ..
fa fa ~ ~~
fa
o N.. ..
fa fa
f'
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The black line includes historical plant operations, maintenance, depreciation, return on
capital, taxes, fuel costs, and net market purchases and sales. It does not include L,
conservation spending, transmission, distribution, or other A&G costs. The red and blue
forecasts include historical costs escalating at the average historical rate and future fuel L
costs for existing resources and all costs for new resources such as operations and .,j
maintenance, taxes, depreciation and return. The lines also include incremental
conservation amounts, net market purchases and sales, and carbon costs assuming
100 percent auction.
8-30 2009 Electric IRP Avista Corp
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Chapter 9 - Action Items
9. Action Items
The Integrated Resource Plan (IRP) is an ongoing and iterative process balancing
regular publication with pursuing the best long-term resource strategy. The biennial
publication date provides opportunities for ongoing improvements to modeling and
forecasting procedures and tools, as well as additional research into changing market
variables and technologies. This section provides an overview of the progress made on
the 2007 IRP Action Plan, while the 2009 Action Plan provides details about issues and
improvements developed or raised during this planning cycle, but deferred for treatment
in the 2011 IRP.
Summary of the 2007 IRP Action Plan
The 2007 IRP Action Items were separated into five categories: renewable energy,
demand side management, emissions, modeling and forecasting enhancements, and
transmission planning.
Renewable Energy
· Continue studying wind potential in the Company's service territory, possibly
including the placement of anemometers at the most promising wind sites.
· Commission a study of Montana wind resources strategically located near existing
Company transmission assets
· Learn more about non-wind renewable resources to satisfy renewable portfolio
standards and decrease the Company's carbon footprint.
Avista has actively studied wind development since the publication of the 2007 IRP. The
Company purchased the rights to develop a large wind project located at Reardan,
Washington in May 2008. The site is being developed as described in the PRS chapter.
Met towers were placed at several areas in our service territory to measure wind
potentiaL. This wind development work is an ongoing project.
Preliminary work concerning a Montana wind study was done. Transmission limitations
for power coming west and the potential for such projects to not qualify toward the
Washington RPS made continued work on Montana wind projects less attractive than
previously thought. Montana wind wil be reevaluated as RPS laws change, and as
transmission upgrades are made.
Additional studies regarding non-wind renewable energy sources continued throughout
this planning cycle. More details about non-wind renewables are included in the
Generation Resource Options and Preferred Resource Strategy chapters. Avista's
upcoming request for proposals (RFP) for wind and other renewables wil provide
further details for the availabilty and cost of non-renewable resources.
Avista Corp 2009 Electric IRP 9-1
Chapter 9 - Action Items
Demand Side Management
· Update processes and protocols for integrating energy efficiency programs into the
IRP to improve and streamline the process.
· Study and quantify transmission and distribution effciency concepts.
· Determine potential impacts and costs of load management options reviewed as part
of the Heritage Project.
· Develop and quantify the long-term impacts of the newly signed contractual
relationship with the Northwest Sustainable Energy for Economic Development
organization.
The integration of DSM resources into the IRP is an ongoing process. Progress made
on updating the processes and protocols for integrating energy effciency programs into
the i RP process can be found in the Energy Effciency chapter. Transmission and
distribution effciency improvements have also been studied for this IRP. Details about
the results of these studies can be found in the Transmission and Distribution chapter.
Five megawatts of distribution feeder peak savings are included in the PRS for the 2009
IRP. Updates on the results of the Heritage Project and the Northwest Sustainable
Energy for Economic Development organization are also included in the Energy
Effciency chapter.
Emissions
· Continue to evaluate the implications of new rules and regulations affecting power
plant operations, most notably greenhouse gases.
· Continue to evaluate the merits of various carbon quantification methods and
emissions markets.
Avista's Climate Change Committee and the Resource Planning team have been
actively analyzing state and federal greenhouse gas legislation since the publication of
the 2007 IRP. This work wil continue until final rules are established for the Washington
legislation and federal laws are passed. Then the focus wil shift towards mitigating the
cost of climate change to minimize the impact on our customers. Carbon quantification
has been done based on the World Resources Initiative - World Business Council for
Sustainable Development (WRI-WBCSD) greenhouse gas (GHG) inventory protocol as
part of the push to get ready for state and federal GHG reporting mandates.' These
inventories have also been used for Avista's participation in the Chicago Climate
Exchange and the Carbon Disclosure Project. Details about the work done since the
2007 IRP may be found in the Environmental Policy chapter.
Modeling and Forecasting Enhancements
· Study the potential for fixing natural gas prices through financial instruments, coal
gasification, investments in gas fields or other means.
· Continue studying the effcient frontier modeling approach to identify more and better
uses for its information.
· Further enhance and refine the PRiSM modeL.
9-2 2009 Electric IRP Avista Corp
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Chapter 9 - Action Items
· Continue to study the impact of climate change on the load forecast.
· Monitor the following conditions relevant to the load forecast: large commercial load
additions, Shoshone county mining developments and market penetration of electric
cars.
As explained earlier in the IRP, more studies were done regarding several fixed natural
gas opportunities including coal gasification, investment in gas fields or through financial
instruments. The common theme from all of the studies was that the capital or credit
costs would be too high for Avista to effectively participate in any projects or long-term
contracts.
There have been several improvements to the Effcient Frontier and PRiSM modeling
approaches, including solving for minimum acquirable resource sizes, and including
emissions accounting. Projected impacts from climate change and electric car market
penetration have been included in the Company's load forecast, as discussed in the
Loads and Resources chapter. Details about changes to relevant load conditions are
also included in the Loads and Resources chapter.
Transmission Planning
· Work to maintain/retain existing transmission rights on the Company's transmission
systef1, under applicable FERC policies, for transmission service to bundled retail
native load.
· Continue involvement in SPA transmission practice processes and rate proceedings
to minimize costs of integrating existing resources outside of the Company's service
area.
· Continue participation in regional and sub-regional efforts to establish new regional
transmission structures (ColumbiaGrid and other forums) to faciltate long-term
expansion of the regional transmission system.
· Evaluate costs to integrate new resources across Avista's service territory and from
regions outside of the Northwest.
Transmission planning Action Items are ongoing issues that wil be revisited as items in
the 2009 Action Plan. Details about progress made towards the maintenance of existing
transmission rights, involvement in SPA processes, participation in regional
transmission processes, and the evaluation of integrating different resources in the IRP
can be found in the Transmission and Distribution chapter.
2009 IRP Action Plan
The Company's 2009 Preferred Resource Strategy provides direction and guidance for
the type, timing and size of future resource acquisitions. The 2009 IRP Action Plan
provides an overview of activities planned for inclusion in the 2011 IRP. Progress and
results for each of the Action Plan items wil be monitored and reported to the Technical
Advisory Committee and in Avista's 2011 IRP. The Action Plan was developed using
input from Commission Staff, the Company's management team and the Technical
Advisory Committee.
Avista Corp 2009 Electric IRP 9-3
Chapter 9 - Action Items
Resource Additions and Analysis
· Continue to explore the potential for wind and non-renewable resources.
· Issue an RFP for the Reardan wind site, and up to 100 MW of wind or other
renewables in 2009.
· Finish studies regarding costs and environmental benefits of the large hydro
upgrades at Cabinet Gorge, Long Lake, Post Falls and Monroe Street.
· Study potential locations for the natural gas-fired resource identified to be online
between 2015 and 2020.
· Continue participation in regional IRP processes, and where agreeable find resource
opportunities to meet resource requirements on a collaborative basis.
Energy Effciency
· Pursue American Reinvestment and Recovery Act of 2009 funding for income
weatherization.
· Analyze and report on results of the July 2007 through December 2009 demand
response pilot in Moscow and Sandpoint.
· Have an external part do an updated study on technical, economic, achievable
potential for energy effciency in Avista's service territory.
· Study and quantify transmission and distribution effciency concepts as they apply
toward meeting Washington RPS goals.
· Update processes and protocols for conservation measurement, evaluation and
verification.
· Determine potential impacts and costs of load management options.
Environmental Policy
· Continue to study the potential impact of state and federal climate change
legislation.
· Continue and report on the work of Avista's Climate Change Committee.
Modeling and Forecasting Enhancements
· Refine cost driver relationships in the stochastic modeL.
· Continue to refine PRiSM by developing a resource retirement capability, adding the
abilty to solve for other risk measurements and by adding more resource options.
· Continue developing Loss of Load Probability and Sustained Peaking analysis for
inclusion in the IRP process, and confirm appropriateness of the 15 percent capacity
planning margin assumed for this IRP.
· Continue studying the impacts of climate change on the load forecast.
· Stay load growth trends and their correlation to weather patterns.
9-4 Avista Corp2009 Electric IRP
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Chapter 9 - Action Items
Transmission Planning
· Work to maintain/retain existing transmission rights on the Company's transmission
system, under applicable FERC policies, for transmission service to bundled retail
native load.
· Continue involvement in SPA transmission practice processes and rate proceedings
to minimize costs of integrating existing resources outside of the Company's service
area.
· Continue participation in regional and sub-regional efforts to establish new regional
transmission structures (ColumbiaGrid and other forums) to facilitate long-term
expansion of the regional transmission system.
· Evaluate costs to integrate new resources across Avista's service territory and from
regions outside of the Northwest.
· Study and implement distribution feeder rebuild projects to reduce system losses.
· Study transmission reconfigurations to economically reduce system losses.
Avista corp 2009 Electric IRP 9-5
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Chapter 9 - Action Items i_J
Production Credits
Clint Kalich, Manager of
Resource Plannin & Anal sis
James Gall, Senior Power
Su I Anal st
John Lyons, Power Supply
Anal st
Randy Barcus, Chief Corporate
Economist
Lori Hermanson, Partnership
Solutions Mana er
John Gibson, Senior
Effciencies En ineer
Project Manager clint.kalich~avistacorp.com
Modeling and Analysis james.gall~avistacorp.com
/Author
Research/Author/Editor john.lyons~avistacorp.com
Load Forecast randy.barcus~avistacorp.com
Conservation lori. hermanson~avistacorp.com
Transmission & john.gibson~avistacorp.com
Distribution
Other Contributors
Jon Powell, Partnershio Solutions Manaoer Bob Laffert, Director of Power Supply
Greg Rahn, Manaaer of Natural Gas Plan nino Scott Waples, Chief System Planner
Kelly Irvine, Natural Gas Analvst Tracy Rolstad, Senior Plan nina Enoineer II
Thomas Dempsey, Manager of Generation Steve Silkworth, Manager of Wholesale
Joint Projects Marketino and Contracts
9-6 2009 Electric IRP Avista Corp
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