200908312009 Color IRP.pdf

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RECEIVE. ~n.
2009 AUG 31 AM 9: ,u.1I1STAQ§
August 28, 200 IDAHO PUBLIC
UTILITIES COMMISSION
Jea D. Jewell, Secreta
Idaho Public Utilities Commssion
Statehouse Mail
W. 472 Washington Strt
Boise, Idaho 83720 7\Vu-E-D9-69
De Ms. Jewell:
RE: A vista Utities 200 Electrc Integrte Resoure Plan
Per IPUC's Integrated Resour Plan Requirments outled in Case No.U-1500165,
Orer No. 22299, Case No.GNR-E-93-1, Order No. 24729 and Case No.GNR-E-93-3,
Order No. 25260 , A vista Corpration dIlaJ A vista Utities, hereby submits for fig an
ongial, an electronic copy and 7 copies of its 200 Electrc Integrte Resource Plan.
The Company submits the IR to public utility commssions in Idao and Washington
every two year as reuired by state regulation. A vista regar the IR as a methodology
for identiying and evaluating vanous resource options and as a proess by which to
establish a plan of action for resource decisions. Paper use and pnntig 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 Resoure Strtegy (PRS) includes 350 MWof wind, 5 MW of
hydro upgrdes, 5 MW of distrbution effciencies, 750 MW of CCCT, and 339
MW of conservation acuisitions 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 percent of futue load grwt is met by new conservation.
Pleae diect any questions regarng ths report to Clit Kach at [phone].
Sincerely,.~~~
Linda Gervais
Manager, Reguatory Policy
State and Federa Regulation
c: Mr. Rick Sterling
2009 Electric Integrated Resource Plan
August 31, 2009
AC-0910 IRP Cover.indd 1 8/5/09 5:03:12 PM
Special thankS to our talented vendorS from
the Spokane area who produced thiS irp:
Ross Printing Company
Thinking Cap Design
Printed on recycled paper.
Table of ConTenTs
Executive Summary i
Introduction and Stakeholder Involvement 1-1
Loads and Resources 2-1
Energy Efficiency 3-1
Environmental Policy 4-1
Transmission and Distribution 5-1
Generation Resource Options 6-1
Market Analysis 7-1
Preferred Resource Strategy 8-1
Action Items 9-1
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 differ 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
www.avistacorp.com. The company undertakes no obligation
to update any forward-looking statement or statements to
reflect events or circumstances that occur after the date on
which such statement is made or to reflect the occurrence of
unanticipated events.
Safe Harbor Statement
Table 1: Net Position Forecast ______________________________________________________ i
Table 2: 2009 Preferred Resource Strategy __________________________________________ viii
Table 3: 2007 Preferred Resource Strategy ___________________________________________ ix
Table 1.1: TAC Participants ________________________________________________________1-2
Table 1.2: TAC Meeting Dates and Agenda Items _______________________________________1-3
Table 1.3: Washington IRP Rules and Requirements ____________________________________1-6
Table 2.1: Global Insight National Long Range Forecast Assumptions _______________________2-4
Table 2.2: Company-Owned Hydro Resources ________________________________________2-17
Table 2.3: Company-Owned Thermal Resources ______________________________________2-19
Table 2.4: Large Congtractual Rights and Obligations __________________________________2-21
Table 2.5: Washington State RPS Detail (aMW) _______________________________________2-26
Table 2.6: Winter Capacity Position (MW) - Plan for Position Excluding Maintenance __________2-27
Table 2.7: Summer Capacity Position (MW) - Plan for Position Excluding Maintenance ________2-28
Table 3.1: Current Avista Energy Efficiency Programs __________________________________3-10
Table 6.1: CCCT (Water Cooled) Levelized Costs per MWh _______________________________6-4
Table 6.2: CCCT with Carbon Sequestration Levelized Costs per MWh ______________________6-5
Table 6.3: Frame SCCT Levelized Costs per MWh ______________________________________6-6
Table 6.4: LMS 100 Levelized Costs per MWh _________________________________________6-6
Table 6.5: Wind Capital and Fixed O&M Costs _________________________________________6-7
Table 6.6: Columbia Basin Wind Project Levelized Costs per MWh _________________________6-8
Table 6.7: Small Scale Project Levelized Costs per MWh _________________________________6-8
Table 6.8: Offshore Wind Project Levelized Costs per MWh _______________________________6-8
Table 6.9: Coal Capital Costs (2009$) _______________________________________________6-9
Table 6.10: Ultra Critical Pulverized Coal Project Levelized Cost per MWh ___________________6-10
Table 6.11: IGCC Coal Project Levelized Cost per MWh _________________________________6-10
Table 6.12: IGCC with Carbon Sequestration Coal Project Levelized Cost ($/MWh) ____________6-10
Table 6.13: Hydro Upgrade Project Characteristics______________________________________ 6-11
Table 6.14: Hydro Upgrade Nominal Levelized Costs per MWh ____________________________6-12
Table 6.15: Hydro Upgrade 2009$ Levelized Costs per MWh______________________________6-12
Table 6.16: Solar Nominal Levelized Cost ($/MWh) _____________________________________6-13
Table 6.17: Solar 2009$ Levelized Cost ($/MWh) _______________________________________6-14
Table 6.18: Biomass Capital Costs __________________________________________________6-15
Table 6.19: Biomass Nominal Levelized Costs per MWh _________________________________6-15
Table 6.20: Biomass 2009 Dollar Levelized Cost per MWh________________________________6-15
Table 6.21: Geothermal Levelized Costs per MWh ______________________________________6-16
Table 6.22: Tidal/Wave Levelized Costs per MWh ______________________________________6-17
Table 6.23: Small Cogeneration Levelized Costs per MWh _______________________________6-17
Table 6.24: Nuclear Levelized Costs per MWh _________________________________________6-18
Table of T ables
Table 6.25: Hydrokinetics Levelized Costs per MWh ____________________________________6-18
Table 6.26: Pumped Storage Levelized Costs per MWh __________________________________6-19
Table 6.27: Large Scale Hydro Levelized costs per MWh _________________________________6-19
Table 6.28: Resource Analysis Summary for Preferred Resources Strategy Analysis ___________6-21
Table 6.29: Resource Analysis Summary for Other Resources Options ______________________6-22
Table 7.1: AURORAXMP Zones ______________________________________________________7-3
Table 7.2: 20-Year Annual Average Peak & Energy Load Growth Rates _____________________7-3
Table 7.3: Western Interconnect Transmission Upgrades Included in Analysis ________________7-4
Table 7.4: New Resources Available to Meet Resource Deficits ____________________________7-7
Table 7.5: Natural Gas Price Basin Differentials from Henry Hub (Nominal Dollars) ____________7-9
Table 7.6: Monthly Price Differentials for Malin _________________________________________7-9
Table 7.7: Western Interconnect Coal Prices (2009$) ___________________________________7-10
Table 7.8: Northwest Hydro Capacity Factors _________________________________________ 7-11
Table 7.9: Western Interconnect Wind Capacity Factors _________________________________ 7-11
Table 7.10: Stochastic Study Correlation Matrix ________________________________________7-14
Table 7.11: EPA Carbon Study (Nominal Price per Short/Ton) _____________________________7-15
Table 7.12: Ten Cost Scenarios Based on Wood Mackenzie and EPA Studies (Nominal Price per Short 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 Coefficient of Determination (Std Dev/Mean) ________________________7-21
Table 7.16: Area Load Coefficient of Determination (Std Dev/Mean) ________________________7-21
Table 7.17: Annual Mid-Columbia Electric Prices ($/MWh) ________________________________7-28
Table 7.18: Main and Mid-Columbia Forecast Results (Nominal Levelized) ___________________7-43
Table 7.19: Main and Mid-Columbia Forecast Results (2009 Dollars Levelized) _______________7-43
Table 8.1: 2009 Preferred Resource Strategy __________________________________________8-8
Table 8.2: 2007 Preferred Resource Strategy __________________________________________8-9
Table 8.3: Levelized Avoided Costs ($/MWh) _________________________________________8-16
Table 8.4: PRS Rate Base Additions for Capital Expenditures ____________________________8-18
Table 8.5: Unconstrained Carbon Scenario - Least Cost Portfolio _________________________8-23
Table 8.6: Portfolio Cost and Risk Comparison ________________________________________8-23
Table 8.7: Low Load Growth 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: Portfolio 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 T ables (continued)
Figure 1: Load Resource Balance— Winter Capacity ____________________________________ ii
Figure 2: Load Resource Balance—Energy____________________________________________ ii
Figure 3: Efficient Frontier _________________________________________________________ iv
Figure 4: Annual Flat Mid-Columbia Prices ____________________________________________ v
Figure 5: Annual Average Henry Hub Natural Gas Price __________________________________ vi
Figure 6: Cumulative Conservation Acquisitions ________________________________________vii
Figure 7: Forecast of Conservation Acquisition _________________________________________vii
Figure 8: _____________________________________________________________________ viii
Figure 9: Estimated Price of CO2 Credits for 2009 IRP ___________________________________ x
Figure 10: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions _______________ x
Figure 2.1: Avista’s Service Territory __________________________________________________2-2
Figure 2.2: Population Change for Spokane, Kootenai and Bonner Counties __________________2-3
Figure 2.3: Total Population for Spokane, Kootenai and Bonner Counties _____________________2-3
Figure 2.4: Three-County Population Age 65 and Over ___________________________________2-5
Figure 2.5: Three-County Job Change ________________________________________________2-5
Figure 2.6: Three-County Non-Farm Jobs _____________________________________________2-6
Figure 2.7: Avista Annual Average Customer Forecast ___________________________________2-7
Figure 2.8: Household Size Index ___________________________________________________2-10
Figure 2.9: Annual Use per Customer________________________________________________ 2-11
Figure 2.10: Avista’s Retail Sales Forecast ____________________________________________2-12
Figure 2.11: Annual Net Native Load _________________________________________________2-13
Figure 2.12: Calendar Year Peak Demand _____________________________________________2-14
Figure 2.13: Electric Load Forecast Scenarios __________________________________________2-15
Figure 2.15: Winter Capacity Position _________________________________________________2-24
Figure 2.16: Summer Capacity Position _______________________________________________2-25
Figure 2.17: Annual Average Position _________________________________________________2-25
Figure 3.1: Historical Conservation Acquisition __________________________________________3-2
Figure 3.2: Forecast of Conservation Acquisition _______________________________________3-11
Figure 3.3: Supply of Evaluated Conservation Measures (Levelized TRC Cost) _______________3-12
Figure 4.1: Price of Carbon Dioxide Credits ___________________________________________ 4-11
Figure 5.1: Avista Transmission System _______________________________________________5-2
Figure 5.2: Levelized Cost of Feeder Upgrades ________________________________________5-12
Figure 5.3: Estimated Feeder Supply Curve ___________________________________________5-12
Figure 6.1: CCCT Output Per 100 MW of Nameplate Capacity _____________________________6-4
Figure 7.1: NERC Interconnection Map _______________________________________________7-2
Figure 7.2: Renewable Resource Additions to Meet RPS__________________________________7-5
Figure 7.3: Northwest Peak Load/Resource Balance _____________________________________7-6
Figure 7.4: Total Western Interconnect Capacity Deficits __________________________________7-7
Table of figures
Table of figures (continued)
Figure 7.5: Henry Hub Natural Gas Price Forecast ______________________________________7-8
Figure 7.6: Price of Carbon Credits__________________________________________________7-13
Figure 7.7: Cost of Carbon Credits __________________________________________________7-13
Figure 7.8: Distribution of Annual Average Carbon Prices for 2012 _________________________7-16
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
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
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: Efficient Frontier Curve ___________________________________________________8-4
Figure 8.3: Efficient Frontier in a Constrained Environment ________________________________8-5
Figure 8.4: Physical Resource Positions_______________________________________________8-6
Figure 8.5: REC Requirement vs. Qualifying RECs for Washington State RPS _________________8-7
Figure 8.6: Energy Efficiency 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
Figure 8.9: Summer Peak Load and Resource Balance __________________________________8-13
Figure 8.10: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions _____________8-14
Figure 8.11: Base Case Efficient Frontier ______________________________________________8-15
Figure 8.12: Avoided Costs for Conservation ___________________________________________8-16
Figure 8.13: Efficient Frontier Portfolios 2029 New Resources _____________________________8-17
Figure 8.14: Power Supply Expense __________________________________________________8-19
Figure 8.15: Power Supply Cost Sensitivities ___________________________________________8-20
Figure 8.16: Carbon Related Power Supply Expense_____________________________________8-21
Figure 8.17: Efficient Frontier Comparison _____________________________________________8-22
Figure 8.18: High & Low Load Growth Cost Comparison __________________________________8-26
Figure 8.19: Efficient Frontier Base Case vs. Other Renewables Available ____________________8-28
Figure 8.20: Real Power Supply Expected Cost Growth Index (2010 = 100) ___________________8-30
Table of figures (continued)
AARG Annual Average Rate of Growth
AVA Avista
aMW Average Megawatts
BPA Bonneville Power Administration
CCCT Combined-Cycle Combustion
Turbine
CFL Compact Fluorescent Lamp
CO2 Carbon Dioxide
CSA Climate Stewardship Act (also
known as
the McCain-Lieberman Bill)
CVR Controlled Voltage Reduction
Dth decatherm
EF Efficiency
EIA Energy Information Administration
FERC Federal Energy Regulatory
Commission
GE The General Electric Company
GHG Greenhouse Gas
GWh Gigawatt-hour
HRSG Heat Recovery Steam Generator
HVAC Heating, Ventilation and Air
Conditioning (HVAC)
IDP Idaho Power Company
IGCC Integrated Gasification Combined
Cycle
IRP Integrated Resource Plan
IS Information Systems
kV kilo-volt
kW kilowatt
kWh kilowatt-hour
LIRAP Low Income Rate Assistance
Program
LP Linear Programming
Mmbtu Million British Thermal Units,
1 mmbtu = 1 dth of Natural Gas
MW megawatt
MWh megawatt-hour
NCEP National Commission for
Energy Policy
NEB Non-Energy Benefits
Nominal Discounting Method that Includes
Inflation
NPCC Northwest Power and Conservation
Council (formerly Northwest Power
Planning Council)
NPV Net Present Value
NWPP Northwest Power Pool
O&M Operations and Maintenance
OASIS Open Access Same-Time
Information
System
OSU Oregon State University
PC Personal Computer
PGE Portland General Electric
PRS Preferred Resource Strategy
PRiSM Preferred Resource Strategy Line
Programming Model
psig Pounds Per Square Inch Gauge
PTC Production Tax Credit
PUD Public Utility District
PURPA Public Utility Regulatory Policies
Act of 1978
Real Discounting Method that Excludes
Inflation
RPS Renewable Portfolio Standards
RTO Regional Transmission
Organization
SCCT Simple-Cycle Combustion Turbine
TAC Technical Advisory Committee
TIG Transmission Improvements Group
TRC Total Resource Cost
Triple E External Energy Efficiency Board
VFD Variable Frequency Drive
WECC Western Electricity Coordinating
Council
WNP-3 Washington Public Power Supply
System (WPPSS, now Energy
Northwest) – Washington Nuclear
Plant No. 3
LiSt of acronymS and Key termS
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 efficiency and a careful mix of new renewables and
traditional resources.
The plan includes economic growth forecasts for the Avista service territory. Electricity sales growth is expected
to occur at a rate of 1.7 percent over the next two decades. Avista projects that it will have sufficient resources to
meet growth until 2018 when new energy supplies will need to be brought online.
Avista expects to add increasing amounts of new renewables to its generation portfolio 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 reliability so utilities will still 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 portfolio 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 facilities.
• Avista does not plan to add any coal-fired generation to its resource mix.
• Aggressive energy efficiency 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 projects.
• Large hydro upgrades will be studied as alternative new renewable resources for the 2011 IRP.
• Transmission upgrades will be needed to add new generation and Avista will 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 [e-mail] for more information
on participating in the IRP process.
2009 irP introduction
Executive Summary
2009 Electric IRPAvista Corp i
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) play a 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.
Resource 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 capability by 27
aMW. Energy deficits rise to 126 aMW in 2022 and 527 aMW in 2029. The Company
will 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
Net Position 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Energy (aMW) 309 185 123 110 93 59 38 31 -27 -35
Capacity (MW) 293 124 53 31 0 -45 -74 45 11 -46
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 – Public Draft i
Noxon Rapids Upgrade Crew
Executive Summary
2009 Electric IRPii Avista Corp
Executive Summary
Figure 1: Load Resource Balance—Winter Capacity
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Figure 2: Load Resource Balance—Energy
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Avista Corp 2009 Electric IRP – Public Draft ii
Executive Summary
2009 Electric IRPAvista Corp iii
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 portfolio standards,
and limiting power supply expense variability.
Portfolio 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 changes to load growth,
capital costs, hydro upgrades, the emergence of other small renewable projects and
nuclear revival.
The preferred resource portfolio must address two key challenges that include the mitigation of future costs and risk given a set of environmental constraints. An efficient 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 investor’s 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 Efficient Frontier.
Avista Corp 2009 Electric IRP – Public Draft iii
Executive Summary
2009 Electric IRPiv Avista Corp
Executive Summary
Figure 3: Efficient Frontier
$150
$170
$190
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3,300 3,350 3,400 3,450 3,500 3,550
2010-2020 NPV of power supply costs (millions)
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Market Only
Capacity Only
Least Cost w/o
ConservationLeast Cost/PRS
Least RiskEfficient Frontier
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.
Avista Corp 2009 Electric IRP – Public Draft iv
Executive Summary
2009 Electric IRPAvista Corp v
Executive Summary
Figure 4: Annual Flat Mid-Columbia Prices
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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 2009 Electric IRP – Public Draft v
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2009 Electric IRPvi Avista Corp
Executive Summary
Figure 5: Annual Average Henry Hub Natural Gas Price
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Energy Efficiency
Avista’s energy efficiency 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
by 138.5 aMW since programs began in the late 1970s. 109 aMW of efficiency projects acquired over the past 18 years are still online.
Avista Corp 2009 Electric IRP – Public Draft vi
Executive Summary
2009 Electric IRPAvista Corp vii
Executive Summary
Figure 6: Cumulative Conservation Acquisitions
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Approximately 3,000 efficiency 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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Avista Corp 2009 Electric IRP – Public Draft vii
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2009 Electric IRPviii Avista Corp
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 portfolio standards. Figure 8 illustrates the
Company’s PRS.
Figure 8:
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Table 2: 2009 Preferred Resource Strategy
Resource
By the End of
Year
Nameplate
(MW)
Energy
(aMW)
NW Wind 2012 150.0 48.0
Distribution Efficiencies 2010-2015 5.0 2.7
Little Falls Unit Upgrades 2013-2016 3.0 0.9
NW Wind 2019 150.0 50.0
CCCT 2019 250.0 225.0
Upper Falls 2020 2.0 1.0
NW Wind 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
Avista Corp 2009 Electric IRP – Public Draft viii
Executive Summary
2009 Electric IRPAvista Corp ix
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
Resource By the End of Year Nameplate(MW)Energy (aMW)
Non-Wind Renewable 2011 20.0 18.0
Non-Wind Renewable 2012 10.0 9.0
NW Wind 2013 100.0 33.0
Non-Wind Renewable 2013 5.0 4.5
Share of CCCT 2014 75.0 67.5
NW Wind 2015 100.0 33.0
NW Wind 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 billion in net present value of new capital
investments over the next 20 years.
Carbon Emissions
Carbon emission costs have been included in the Base Case since the 2007 IRP.
Carbon, or CO2, 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 CO2 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 – Public Draft ix
Executive Summary
2009 Electric IRPx Avista Corp
Executive Summary
Figure 9: Estimated Price of CO2 Credits for 2009 IRP
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Figure 10: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions
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Action Items
The Company’s 2009 Action Plan outlines activities and studies to be developed and
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.
Avista Corp 2009 Electric IRP – Public Draft x
2009 Electric IRPAvista Corp 1-1
Chapter 1 - Introduction and Stakeholder InvolvementChapter 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 meeting 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 sufficient.” We assess
resource acquisition strategies and business plans to acquire resources to meet
resource adequacy requirements and optimize the value of our current resource
portfolio. 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
www.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 utilizes 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 utilities,
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 IRP requirements are contained 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 – Public Draft 1-1
Executive Summary
Figure 9: Estimated Price of CO2 Credits for 2009 IRP
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Figure 10: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions
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Action Items
The Company’s 2009 Action Plan outlines activities and studies to be developed and
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.
Avista Corp 2009 Electric IRP – Public Draft x
Chapter 1 - Introduction and Stakeholder Involvement
2009 Electric IRP1-2 Avista Corp
Chapter 1- Introduction and Stakeholder Involvement
Public Process
The 2009 IRP 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
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 TAC mailing list includes over 70 individuals from 46 different organizations. The Company greatly appreciates all of the time and effort expended by the participants in
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 Washington State University
Robin Toth Greater Spokane Inc.
Dave Van Hersett Resource Development Associates
Mike Connelly Idaho Forest Group
John Daquisto Gonzaga University
Lea Daeschel Washington Attorney General’s Office
Deborah Reynolds Washington Utility and Transportation Commission
Steve Johnson Washington Utility and Transportation Commission
David Nightingale Washington Utility and Transportation Commission
Vanda Novak Washington Utility and Transportation Commission
Carrie Dolwick Northwest Energy Coalition
Kirsten Wilson Washington State General Administration
Rick Sterling Idaho Public Utilities Commission
Chuck Murray Community Trade and Economic Development
Tom Noll Idaho Power
Maury Galbraith Northwest Power and Conservation Council
Villamour Gamponia Puget Sound Energy
Mike Kersh Inland Empire Paper
Table 1.2 provides a list of TAC meeting dates and agenda items covered in each
meeting.
Avista Corp 2009 Electric IRP – Public Draft 1-2
2009 Electric IRPAvista Corp 1-3
Chapter 1 - Introduction and Stakeholder InvolvementChapter 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 Analytical 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 Strategy
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
• 2009 IRP 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 (“Triple 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-party 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
implementation phase of the Living License with stakeholders participating in various protection, mitigation and enhancement measures.
Avista Corp 2009 Electric IRP – Public Draft 1-3
Chapter 1 - Introduction and Stakeholder Involvement
2009 Electric IRP1-4 Avista Corp
Chapter 1- Introduction and Stakeholder Involvement
FERC Hydro Relicensing – Spokane River Projects
The Company has utilized 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)
LIRAP 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 Utilities 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 will be requested from members of the Technical Advisory
Committee on a wide variety of resource planning issues. We will continue to work on
expanding the diversity of the members on the TAC, and will strive to maintain the TAC
meetings as an open public process.
2009 IRP Outline
The 2009 IRP consists of nine chapters plus an executive summary. A series of
technical appendices supplement this report.
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.
Avista Corp 2009 Electric IRP – Public Draft 1-4
2009 Electric IRPAvista Corp 1-5
Chapter 1 - Introduction and Stakeholder InvolvementChapter 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 efficiency 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 of wholesale 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 portfolios 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 – Public Draft 1-5
Chapter 1 - Introduction and Stakeholder Involvement
2009 Electric IRP1-6 Avista Corp
Chapter 1- Introduction and Stakeholder Involvement
Regulatory Requirements
The IRP process for Washington has several requirements that must be met and
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
plan filed no later than 12 months
before next IRP due date. Work plan outlines content of IRP.
Work plan outlines method for assessing potential resources.
Work plan submitted to the WUTC on August 29,
2008, See Appendix B
WAC 480-100-238(5) – Work
plan outlines timing and extent of public participation.
Appendix B
WAC 480-100-238(2)(a) – Plan describes mix of energy supply
resources.
Chapter 6- Generation Resource Options
WAC 480-100-238(2)(a) – Plan
describes conservation supply.
Chapter 3- Energy Efficiency
WAC 480-100-238(2)(a) – Plan
addresses supply in terms of
current and future needs of utility ratepayers.
Chapter 2- Loads & Resources
WAC 480-100-238(2)(b) – Plan uses lowest reasonable cost
(LRC) analysis to select mix of
resources.
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC
analysis considers resource costs.
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC analysis considers market-
volatility risks.
Chapter 4- Environmental Policy Chapter 7- Market Analysis
Chapter 8- Preferred Resource Strategy
WAC 480-100-238 (2)(b) – LRC
analysis considers demand side
uncertainties.
Chapter 3- Energy Efficiency
WAC 480-100-238(2)(b) – LRC
analysis considers resource dispatchability.
Chapter 6- Generation Resource Options
Chapter 7- Market Analysis
WAC 480-100-238(2)(b) – LRC analysis considers resource
effect on system operation.
Chapter 7- Market Analysis Chapter 8- Preferred Resource Strategy
Avista Corp 2009 Electric IRP – Public Draft 1-6
2009 Electric IRPAvista Corp 1-7
Chapter 1 - Introduction and Stakeholder InvolvementChapter 1- Introduction and Stakeholder Involvement
WAC 480-100-238(2)(b) – LRC analysis considers risks imposed
on ratepayers.
Chapter 4- Environmental Policy Chapter 6- Generation Resource Options
Chapter 7- Market Analysis
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC
analysis considers public policies regarding resource preference
adopted by Washington state or
federal government.
Chapter 2- Loads & Resources
Chapter 4- Environmental Policy Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC
analysis considers cost of risks associated with environmental
effects including emissions of
carbon dioxide.
Chapter 4- Environmental Policy
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(c) – Plan
defines conservation as any reduction in electric power
consumption that results from
increases in the efficiency of energy use, production, or
distribution.
Chapter 3- Energy Efficiency
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(3)(a) – Plan
includes a range of forecasts of
future demand.
Chapter 2- Loads and Resources
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(3)(a) – Plan
develops forecasts using methods that examine the effect
of economic forces on the
consumption of electricity.
Chapter 2- Loads and Resources
Chapter 5- Transmission & Distribution Chapter 8- Preferred Resource Strategy
WAC 480-100-238-(3)(a) – Plan
develops forecasts using methods that address changes in
the number, type and efficiency of
end-uses.
Chapter 2- Loads and Resources
Chapter 3- Energy Efficiency Chapter 5- Transmission & Distribution
WAC 480-100-238(3)(b) – Plan
includes an assessment of commercially available
conservation, including load
management.
Chapter 3- Energy Efficiency
Chapter 5- Transmission & Distribution
WAC 480-100-238(3)(b) – Plan
includes an assessment of currently employed and new
policies and programs needed to
obtain the conservation improvements.
Chapter 3- Energy Efficiency
Chapter 5- Transmission & Distribution
Avista Corp 2009 Electric IRP – Public Draft 1-7
Chapter 1 - Introduction and Stakeholder Involvement
2009 Electric IRP1-8 Avista Corp
Chapter 1- Introduction and Stakeholder Involvement
WAC 480-100-238(3)(c) – Plan includes an assessment of a wide
range of conventional and
commercially available nonconventional generating
technologies.
Chapter 6- Generator Resource OptionsChapter 8- Preferred Resource Strategy
WAC 480-100-238(3)(d) – Plan
includes an assessment of
transmission system capability and reliability (as allowed by
current law).
Chapter 5- Transmission & Distribution
WAC 480-100-238(3)(e) – Plan
includes a comparative
evaluation of energy supply resources (including transmission
and distribution) and
improvements in conservation using LRC.
Chapter 3- Energy Efficiency
Chapter 5- Transmission & Distribution
WAC-480-100-238(3)(f) – Demand forecasts and resource
evaluations are integrated into
the long range plan for resource acquisition.
Chapter 3- Energy Efficiency Chapter 5- Transmission & Distribution
Chapter 6- Generator Resource Options
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(3)(g) – Plan includes a two-year action plan
that implements the long range
plan.
Chapter 9- Action Items
WAC 480-100-238(3)(h) – Plan
includes a progress report on the implementation of the previously
filed plan.
Chapter 9- Action Items
WAC 480-100-238(5) – Plan
includes description of
consultation with commission staff. (Description not required)
Chapter 1- Introduction and Stakeholder
Involvement
WAC 480-100-238(5) – Plan includes description of work plan.
(Description not required)
Appendix B
Avista Corp 2009 Electric IRP – Public Draft 1-8
2009 Electric IRPAvista Corp 2-1
Chapter 2 - Loads and ResourcesChapter 2: Loads & 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 portfolio standard deficiencies are the driver of near-termresource 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
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 sawmills. 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- Public Draft 2-1
Avista’s Plug-In Hybrid Sun Car
Chapter 2 - Loads and Resources
2009 Electric IRP2-2 Avista Corp
Chapter 2: Loads & 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 illustrated 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.
Avista Corp 2009 Electric IRP- Public Draft 2-2
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Figure 2.2: Population Change for Spokane, Kootenai and Bonner Counties
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2009 Electric IRP2-4 Avista Corp
Chapter 2: Loads & 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%Housing Starts (mil.) 1.5-1.8/year
Consumer Price Index 3.5%-1.7%Job Growth 0.9%/year
West Texas Crude 2000$ $30-$50 Worker Productivity 2%
Fed Funds Rate 4%-8%Consumer Sentiment 90
Unemployment 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.
Avista Corp 2009 Electric IRP- Public Draft 2-4
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Chapter 2: Loads & Resources
Figure 2.4: Three-County Population Age 65 and Over
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Employment growth often drives population growth. Figure 2.5 shows historical
employment trends from 1990 and anticipated growth through 2030.
Figure 2.5: Three-County Job Change
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Chapter 2 - Loads and Resources
2009 Electric IRP2-6 Avista Corp
Chapter 2: Loads & 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
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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.
Avista Corp 2009 Electric IRP- Public Draft 2-6
2009 Electric IRPAvista Corp 2-7
Chapter 2 - Loads and ResourcesChapter 2: Loads & 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 scientific community’s predictions for this geographic
Avista Corp 2009 Electric IRP- Public Draft 2-7
Chapter 2 - Loads and Resources
2009 Electric IRP2-8 Avista Corp
Chapter 2: Loads & 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
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 will 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
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 coefficient
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
of the first good increases relative to the price of the second good, consumers shift their
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 dwellings 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
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.
Avista Corp 2009 Electric IRP- Public Draft 2-8
2009 Electric IRPAvista Corp 2-9
Chapter 2 - Loads and ResourcesChapter 2: Loads & 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 rate 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 difficult 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- Public Draft 2-9
Chapter 2 - Loads and Resources
2009 Electric IRP2-10 Avista Corp
Chapter 2: Loads & Resources
Figure 2.8: Household Size Index
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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 illustrated 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 will include publicly-announced
long lead time buildings in the load forecast in future IRPs.
Avista Corp 2009 Electric IRP- Public Draft 2-10
2009 Electric IRPAvista Corp 2-11
Chapter 2 - Loads and ResourcesChapter 2: Loads & Resources
Figure 2.9: Annual Use per Customer
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 billion kWh in 1999 to over 8.9 billion 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- Public Draft 2-11
Chapter 2 - Loads and Resources
2009 Electric IRP2-12 Avista Corp
Chapter 2: Loads & Resources
Actual, not weather corrected, retail electricity sales to Avista customers in 2008 were
8.93 billion kWh. Heating degree days in 2008 were 103 percent of normal, almost
completely offset in terms of energy use by 121 percent of normal cooling degree days.
The forecast for 2030 is 12.85 billion 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
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 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.
Avista Corp 2009 Electric IRP- Public Draft 2-12
2009 Electric IRPAvista Corp 2-13
Chapter 2 - Loads and ResourcesChapter 2: Loads & Resources
Figure 2.11: Annual Net Native Load
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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- Public Draft 2-13
Chapter 2 - Loads and Resources
2009 Electric IRP2-14 Avista Corp
Chapter 2: Loads & Resources
Figure 2.12: Calendar Year Peak Demand
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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 illustrate 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 utility 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 will be an anomaly. The 2007 IRP
provided an illustration 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.
Avista Corp 2009 Electric IRP- Public Draft 2-14
2009 Electric IRPAvista Corp 2-15
Chapter 2 - Loads and ResourcesChapter 2: Loads & Resources
Figure 2.13: Electric Load Forecast Scenarios
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High Growth
Low Growth
Avista Resources and Contracts
The Company relies on a diversified portfolio 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 facility on the Spokane River is Post Falls, located at its Idaho
namesake near the Washington/Idaho 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
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2009 Electric IRP2-16 Avista Corp
Chapter 2: Loads & 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 will 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 will be replaced and are expected to be online by 2012
and 2013. A rubber dam will be added to the facility, replacing flashboards, 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 capability.
Long Lake
The Long Lake project is located northwest of Spokane and maintains Lake Spokane,
also known as Long Lake. The facility was the highest spillway 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 facility 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
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Clark Fork River Hydroelectric Project
The Clark Fork River Project includes 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 million 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 will 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 portfolio.
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
Project Name
River
System Location
Start
Date
NameplateCapacity
(MW)
MaximumCapability
(MW)
ExpectedEnergy
(aMW)
Monroe Street Spokane Spokane, WA 1890 14.8 15.0 11.6
Post Falls Spokane Post Falls, ID 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, ID 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
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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.
ColstripThe 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 Colstrip 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 efficiency, 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 primarily 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 facility 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
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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
efficiency.
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 the
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
Project Name Location Fuel Type
Start
Date
Winter
MaximumCapacity
(MW)
Summer
MaximumCapacity
(MW)
NameplateCapacity
(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, ID 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 Springs 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 utilizes 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.
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Bonneville Power Administration – WNP-3 Settlement Avista (then Washington Water Power) signed settlement agreements with Bonneville
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 million 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 utility 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 utilities 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 capabilities; in 2010 contracts will provide approximately 164 MW of capacity and 85 aMW of energy. Over the next 20 years, the Wells (2018) and Rocky Reach (2011) contracts will expire.
Avista may be able to extend these contracts; however, it has no assurance today that
extensions will 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 will 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
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Chapter 2 - Loads and ResourcesChapter 2: Loads & 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
Contract Type End Date
WinterCapacity (MW)
SummerCapacity (MW)
2010
Annual
Energy (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 Pumping 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
Rocky 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 Aug-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 utility.
Reserve margins, on average, increase customer rates when compared to resource
portfolios without reserves, due to carrying additional cost of generation. Reserve
resources have the physical capability 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 utilities with resources that have an
unpredictable fuel source, such as wind and hydro, but also to cover load variance. For
capacity planning, Avista reserves are not directly based on unit size or resource type.
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2009 Electric IRP2-22 Avista Corp
Chapter 2: Loads & 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 utility 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 utility 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 capability. Additional capital
expenditures to support this level of reliability 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 variability 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 BPA. 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 Probability (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 will not adopt the NPCC metrics in this
planning cycle. The Company will continue to participate in the regional process and will
use the results for future resource planning.
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Chapter 2 - Loads and Resources
Chapter 2: Loads & 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 reliability 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
still 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 reliability 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 will use the results from that process.
Washington State Renewable Portfolio Standard
In the November 2006 general election, Washington State voters approved Citizens
Initiative 937. The initiative requires utilities 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
efficiency 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 will 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 illustrate 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 capability 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- Public Draft 2-23
Chapter 2 - Loads and Resources
2009 Electric IRP2-24 Avista Corp
Chapter 2: Loads & 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 capability 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
0
500
1,000
1,500
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Contracts Peakers
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Avista Corp 2009 Electric IRP- Public Draft 2-24
2009 Electric IRPAvista Corp 2-25
Chapter 2 - Loads and Resources
Chapter 2: Loads & Resources
Avista Corp 2009 Electric IRP- Public Draft 2-25
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Peakers
Hydro
Figure 2.16: Summer Capacity Position
Load
Hydro
Contracts
Figure 2.17: Annual Average Position
Load
Base Thermal
Load w/PM, w/o Maint
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Chapter 2: Loads & 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 capability 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
0
500
1,000
1,500
2,000
2,500
3,000
20
1
0
20
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Hydro Base Thermal
Contracts Peakers
Load Load w/PM, w/o Maint
Avista Corp 2009 Electric IRP- Public Draft 2-24
Chapter 2: Loads & 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 capability 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
0
500
1,000
1,500
2,000
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9
20
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9
me
g
a
w
a
t
t
s
Hydro Base Thermal
Contracts Peakers
Load Load w/PM, w/o Maint
Avista Corp 2009 Electric IRP- Public Draft 2-24
Chapter 2 - Loads and Resources
2009 Electric IRP2-26 Avista Corp
Ch
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26
Ch
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2
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.
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0
.
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.
0

0
.
0

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.
0

0
.
0

0
.
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Lo
n
g

L
a
k
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3
19
9
9
2.
2

2
.
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2
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2

2
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2

2
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2
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2

2
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2
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2
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Li
t
t
l
e

F
a
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s

4
20
0
1
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6

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Ca
b
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t

2
20
0
4
2.
9

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.
9

2
.
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9

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9

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Ca
b
i
n
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t

3
20
0
1
4.
5

4
.
5

4
.
5

4
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4
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4
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4
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Ca
b
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t

4
20
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0

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Ap
p
r
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n
t
i
c
e

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r
e
d
i
t
s
0.
4

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4
Hy
d
r
o

1
0
%

C
h
a
n
c
e

o
f

E
x
c
e
e
d
a
n
c
e
(3
.
5
)

(
3
.
5
)

(
3
.
5
)

(
3
.
5
)

(
3
.
5
)

(
3
.
5
)

(
3
.
5
)

(
3
.
5
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(
3
.
5
)

(
3
.
5
)

(
3
.
5
)

(
3
.
5
)

(
3
.
5
)

(
3
.
5
)

(
3
.
5
)

(
3
.
5
)

(
3
.
5
)
To
t
a
l

Q
u
a
l
i
f
y
i
n
g

R
e
s
o
u
r
c
e
s
16
.
6

1
6
.
6

1
4
.
8

1
4
.
8

1
4
.
8

1
4
.
8

9
.
1

9
.
1

9
.
1

9
.
1

9
.
1

9
.
1

9
.
1

9
.
1

9
.
1

9
.
1

9
.
1
Ne
t

R
E
C

P
o
s
i
t
i
o
n

(
C
o
m
p
l
e
t
e
d
)
16
.
6

1
6
.
6

(
5
.
9
)

(
6
.
3
)

(
6
.
6
)

(
6
.
8
)

(
5
6
.
6
)

(
5
7
.
6
)

(
5
8
.
8
)

(
6
0
.
1
)

(
1
0
8
.
3
)

(
1
1
0
.
2
)

(
1
1
2
.
3
)

(
1
1
4
.
4
)

(
1
1
6
.
4
)

(
1
1
8
.
5
)

(
1
2
0
.
8)
Bu
d
g
e
t
e
d

H
y
d
r
o

U
p
g
r
a
d
e
s
No
x
o
n

1
20
0
9
2.
3
0

2
.
8

2
.
8

2
.
8

2
.
8

2
.
8

2
.
8

2
.
8

2
.
8

2
.
8

2
.
8

2
.
8

2
.
8

2
.
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.
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.
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.
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.
8
No
x
o
n

2
20
1
0
1.
0
0

0
.
6

1
.
2

1
.
2

1
.
2

1
.
2

1
.
2

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.
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.
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1
.
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.
2

1
.
2

1
.
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1
.
2

1
.
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.
2
No
x
o
n

3
20
1
1
1.
3
0

0
.
0

0
.
8

1
.
6

1
.
6

1
.
6

1
.
6

1
.
6

1
.
6

1
.
6

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.
6

1
.
6

1
.
6

1
.
6

1
.
6

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.
6

1
.
6

1
.
6
No
x
o
n

4
20
1
2
1.
2
0

0
.
0

0
.
0

0
.
7

1
.
4

1
.
4

1
.
4

1
.
4

1
.
4

1
.
4

1
.
4

1
.
4

1
.
4

1
.
4

1
.
4

1
.
4

1
.
4

1
.
4
Ni
n
e

M
i
l
e
20
1
2
3.
8
0

0
.
0

0
.
0

2
.
3

4
.
6

4
.
6

4
.
6

4
.
6

4
.
6

4
.
6

4
.
6

4
.
6

4
.
6

4
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6

4
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6

4
.
6

4
.
6

4
.
6
Hy
d
r
o

1
0
%

C
h
a
n
c
e

o
f

E
x
c
e
e
d
a
n
c
e
(1
.
0
)
(1
.
4
)

(
2
.
3
)
(3
.
0
)

(
3
.
0
)

(
3
.
0
)
(3
.
0
)
(3
.
0
)
(3
.
0
)

(
3
.
0
)

(
3
.
0
)
(3
.
0
)
(3
.
0
)
(3
.
0
)

(
3
.
0
)
(3
.
0
)
(3
.
0
)
To
t
a
l

B
u
d
g
e
t
e
d

H
y
d
r
o

U
p
g
r
a
d
e
s
2.
4

3
.
3

6
.
2

8
.
5

8
.
5

8
.
5

8
.
5

8
.
5

8
.
5

8
.
5

8
.
5

8
.
5

8
.
5

8
.
5

8
.
5

8
.
5

8
.
5
Ne
t

R
E
C

P
o
s
t
i
o
n

(
B
u
d
g
e
t
e
d

U
p
g
r
a
d
e
s
)
19
.
0

1
9
.
9

0
.
3

2
.
2

2
.
0

1
.
7

(
4
8
.
1
)

(
4
9
.
1
)

(
5
0
.
3
)

(
5
1
.
6
)

(
9
9
.
8
)

(
1
0
1
.
7
)

(
1
0
3
.
8
)

(
1
0
5
.
9
)

(
1
0
7
.
9
)

(
1
1
0
.
0
)

(
1
1
2
.
3
)
Av
i
s
t
a

C
o
r
p

20
0
9

E
l
e
c
t
r
i
c

I
R
P
-

P
u
b
l
i
c

D
r
a
f
t

26
2009 Electric IRPAvista Corp 2-27
Chapter 2 - Loads and Resources
Ch
a
p
t
e
r

2
:

L
o
a
d
s

&

R
e
s
o
u
r
c
e
s

Ta
b
l
e

2
.
6
:

W
i
n
t
e
r

C
a
p
a
c
i
t
y

P
o
s
i
t
i
o
n

(
M
W
)

-

P
l
a
n

f
o
r

P
o
s
i
t
i
o
n

E
x
c
l
u
d
i
n
g

M
a
i
n
t
e
n
a
n
c
e

20
1
0

2
0
1
1

2
0
1
2

2
0
1
3

2
0
1
4

2
0
1
5

2
0
1
6

2
0
1
7

2
0
1
8

2
0
1
9

2
0
2
0

2
0
2
1

2
0
2
2

2
0
2
3

2
0
2
4

2
0
2
5

2
0
2
6

2
0
2
7

2
0
2
8

2
0
2
9
RE
Q
U
I
R
E
M
E
N
T
S
Na
t
i
v
e

L
o
a
d
-1
,
7
7
9

-
1
,
8
1
2

-
1
,
8
3
9

-
1
,
8
6
2

-
1
,
8
9
3

-
1
,
9
3
7

-
1
,
9
6
7

-
1
,
9
9
8

-
2
,
0
3
3

-
2
,
0
6
2

-
2
,
0
9
1

-
2
,
1
2
4

-
2
,
1
5
4

-
2
,
1
8
5

-
2
,
2
2
2

-
2
,
2
6
1

-
2
,
3
2
0

-
2
,
3
5
2

-
2
,
3
8
7

-
2
,
4
1
9
Co
n
t
r
a
c
t
s

O
b
l
i
g
a
t
i
o
n
s
-2
4
0

-
2
3
9

-
2
3
9

-
2
3
9

-
2
3
9

-
1
6
4

-
1
6
4

-
1
4

-
1
4

-
1
2

-
1
2

-
1
2

-
1
2

-
1
2

-
1
2

-
1
2

-
1
2

-
1
2

-
1
2

-
1
2
To
t
a
l

R
e
q
u
i
r
e
m
e
n
t
s
-2
,
0
1
9

-
2
,
0
5
1

-
2
,
0
7
8

-
2
,
1
0
1

-
2
,
1
3
2

-
2
,
1
0
1

-
2
,
1
3
1

-
2
,
01
2

-
2
,
0
4
6

-
2
,
0
7
4

-
2
,
1
0
3

-
2
,
1
3
6

-
2
,
1
6
6

-
2
,
1
9
7

-
2
,
2
3
4

-
2
,
2
7
3

-
2
,
3
3
1

-
2
,
3
6
4

-
2
,
3
9
8

-
2
,
4
3
1
RE
S
O
U
R
C
E
S
Co
n
t
r
a
c
t
s

R
i
g
h
t
s
65
7

5
5
7

5
3
9

5
3
9

5
3
9

4
6
4

4
6
4

4
6
4

4
6
4

4
6
2

3
7
2

3
7
2

3
7
2

3
7
1

3
7
1

3
7
1

3
7
1

9
0

9
0

9
0
Hy
d
r
o

R
e
s
o
u
r
c
e
s
1,
0
3
0

1
,
0
0
0

9
7
2

9
9
7

9
9
7

9
9
7

9
9
7

9
7
0

9
9
7

9
7
1

9
7
1

9
4
4

9
7
1

9
7
1

9
7
1

9
4
4

9
7
1

9
7
1

9
7
1

9
4
4
Ba
s
e

L
o
a
d

T
h
e
r
m
a
l
s
58
0

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4
Pe
a
k
i
n
g

U
n
i
t
s
22
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6
To
t
a
l

R
e
s
o
u
r
c
e
s
2,
4
9
3

2
,
3
6
6

2
,
3
2
1

2
,
3
4
6

2
,
3
4
6

2
,
2
7
1

2
,
2
7
1

2
,
2
4
4

2
,
2
7
1

2
,
2
4
2

2
,
1
5
3

2
,
1
2
6

2
,
1
5
3

2
,
1
5
2

2
,
1
5
2

2
,
1
2
5

2
,
1
5
2

1
,
8
7
1

1
,
8
7
1

1
,
8
4
4
PE
A
K

P
O
S
I
T
I
O
N
47
4

3
1
5

2
4
2

2
4
6

2
1
4

1
7
0

1
4
1

2
3
2

2
2
5

1
6
9

5
0

-
1
0

-
1
4

-
4
5

-
8
2

-
1
4
8

-
1
8
0

-
4
9
3

-
5
2
8

-
5
8
7
RE
S
E
R
V
E

P
L
A
N
N
I
N
G
Pl
a
n
n
i
n
g

R
e
s
e
r
v
e

M
a
r
g
i
n
-2
6
7

-
2
7
2

-
2
7
6

-
2
7
9

-
2
8
4

-
2
9
1

-
2
9
5

-
3
0
0

-
3
0
5

-
3
0
9

-
3
1
4

-
3
1
9

-
3
2
3

-
3
2
8

-
3
3
3

-
3
3
9

-
3
4
8

-
3
5
3

-
3
5
8

-
3
6
3
Pe
a
k

P
o
s
i
t
i
o
n

W
i
t
h

M
a
i
n
t
.
20
7

4
3

-
3
3

-
3
4

-
7
0

-
1
2
0

-
1
5
4

-
6
7

-
8
0

-
1
4
0

-
2
6
4

-
3
2
8

-
3
3
7

-
3
7
3

-
4
1
6

-
4
8
7

-
5
2
8

-
8
4
6

-
8
8
6

-
9
5
0
PO
S
I
T
I
O
N

E
X
C
L
U
D
I
N
G

M
A
I
N
T
.

3
1
3

1
4
8

7
1

6
6

3
0

-
2
0

-
5
4

6
0

2
0

-
4
0

-
1
6
4

-
2
0
1

-
2
3
7

-
2
7
3

-
3
1
6

-
3
6
0

-
4
2
8

-
7
4
6

-
7
8
6

-
8
2
3
Av
i
s
t
a

C
o
r
p

20
0
9

E
l
e
c
t
r
i
c

I
R
P
-

P
u
b
l
i
c

D
r
a
f
t

27
Ch
a
p
t
e
r

2
:

L
o
a
d
s

&

R
e
s
o
u
r
c
e
s

Ta
b
l
e

2
.
6
:

W
i
n
t
e
r

C
a
p
a
c
i
t
y

P
o
s
i
t
i
o
n

(
M
W
)

-

P
l
a
n

f
o
r

P
o
s
i
t
i
o
n

E
x
c
l
u
d
i
n
g

M
a
i
n
t
e
n
a
n
c
e

20
1
0

2
0
1
1

2
0
1
2

2
0
1
3

2
0
1
4

2
0
1
5

2
0
1
6

2
0
1
7

2
0
1
8

2
0
1
9

2
0
2
0

2
0
2
1

2
0
2
2

2
0
2
3

2
0
2
4

2
0
2
5

2
0
2
6

2
0
2
7

2
0
2
8

2
0
2
9
RE
Q
U
I
R
E
M
E
N
T
S
Na
t
i
v
e

L
o
a
d
-1
,
7
7
9

-
1
,
8
1
2

-
1
,
8
3
9

-
1
,
8
6
2

-
1
,
8
9
3

-
1
,
9
3
7

-
1
,
9
6
7

-
1
,
9
9
8

-
2
,
0
3
3

-
2
,
0
6
2

-
2
,
0
9
1

-
2
,
1
2
4

-
2
,
1
5
4

-
2
,
1
8
5

-
2
,
2
2
2

-
2
,
2
6
1

-
2
,
3
2
0

-
2
,
3
5
2

-
2
,
3
8
7

-
2
,
4
1
9
Co
n
t
r
a
c
t
s

O
b
l
i
g
a
t
i
o
n
s
-2
4
0

-
2
3
9

-
2
3
9

-
2
3
9

-
2
3
9

-
1
6
4

-
1
6
4

-
1
4

-
1
4

-
1
2

-
1
2

-
1
2

-
1
2

-
1
2

-
1
2

-
1
2

-
1
2

-
1
2

-
1
2

-
1
2
To
t
a
l

R
e
q
u
i
r
e
m
e
n
t
s
-2
,
0
1
9

-
2
,
0
5
1

-
2
,
0
7
8

-
2
,
1
0
1

-
2
,
1
3
2

-
2
,
1
0
1

-
2
,
1
3
1

-
2
,
01
2

-
2
,
0
4
6

-
2
,
0
7
4

-
2
,
1
0
3

-
2
,
1
3
6

-
2
,
1
6
6

-
2
,
1
9
7

-
2
,
2
3
4

-
2
,
2
7
3

-
2
,
3
3
1

-
2
,
3
6
4

-
2
,
3
9
8

-
2
,
4
3
1
RE
S
O
U
R
C
E
S
Co
n
t
r
a
c
t
s

R
i
g
h
t
s
65
7

5
5
7

5
3
9

5
3
9

5
3
9

4
6
4

4
6
4

4
6
4

4
6
4

4
6
2

3
7
2

3
7
2

3
7
2

3
7
1

3
7
1

3
7
1

3
7
1

9
0

9
0

9
0
Hy
d
r
o

R
e
s
o
u
r
c
e
s
1,
0
3
0

1
,
0
0
0

9
7
2

9
9
7

9
9
7

9
9
7

9
9
7

9
7
0

9
9
7

9
7
1

9
7
1

9
4
4

9
7
1

9
7
1

9
7
1

9
4
4

9
7
1

9
7
1

9
7
1

9
4
4
Ba
s
e

L
o
a
d

T
h
e
r
m
a
l
s
58
0

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4
Pe
a
k
i
n
g

U
n
i
t
s
22
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6
To
t
a
l

R
e
s
o
u
r
c
e
s
2,
4
9
3

2
,
3
6
6

2
,
3
2
1

2
,
3
4
6

2
,
3
4
6

2
,
2
7
1

2
,
2
7
1

2
,
2
4
4

2
,
2
7
1

2
,
2
4
2

2
,
1
5
3

2
,
1
2
6

2
,
1
5
3

2
,
1
5
2

2
,
1
5
2

2
,
1
2
5

2
,
1
5
2

1
,
8
7
1

1
,
8
7
1

1
,
8
4
4
PE
A
K

P
O
S
I
T
I
O
N
47
4

3
1
5

2
4
2

2
4
6

2
1
4

1
7
0

1
4
1

2
3
2

2
2
5

1
6
9

5
0

-
1
0

-
1
4

-
4
5

-
8
2

-
1
4
8

-
1
8
0

-
4
9
3

-
5
2
8

-
5
8
7
RE
S
E
R
V
E

P
L
A
N
N
I
N
G
Pl
a
n
n
i
n
g

R
e
s
e
r
v
e

M
a
r
g
i
n
-2
6
7

-
2
7
2

-
2
7
6

-
2
7
9

-
2
8
4

-
2
9
1

-
2
9
5

-
3
0
0

-
3
0
5

-
3
0
9

-
3
1
4

-
3
1
9

-
3
2
3

-
3
2
8

-
3
3
3

-
3
3
9

-
3
4
8

-
3
5
3

-
3
5
8

-
3
6
3
Pe
a
k

P
o
s
i
t
i
o
n

W
i
t
h

M
a
i
n
t
.
20
7

4
3

-
3
3

-
3
4

-
7
0

-
1
2
0

-
1
5
4

-
6
7

-
8
0

-
1
4
0

-
2
6
4

-
3
2
8

-
3
3
7

-
3
7
3

-
4
1
6

-
4
8
7

-
5
2
8

-
8
4
6

-
8
8
6

-
9
5
0
PO
S
I
T
I
O
N

E
X
C
L
U
D
I
N
G

M
A
I
N
T
.

3
1
3

1
4
8

7
1

6
6

3
0

-
2
0

-
5
4

6
0

2
0

-
4
0

-
1
6
4

-
2
0
1

-
2
3
7

-
2
7
3

-
3
1
6

-
3
6
0

-
4
2
8

-
7
4
6

-
7
8
6

-
8
2
3
Av
i
s
t
a

C
o
r
p

20
0
9

E
l
e
c
t
r
i
c

I
R
P
-

P
u
b
l
i
c

D
r
a
f
t

27
Chapter 2 - Loads and Resources
2009 Electric IRP2-28 Avista Corp
Ch
a
p
t
e
r

2
:

L
o
a
d
s

&

R
e
s
o
u
r
c
e
s

Ta
b
l
e

2
.
7
:

S
u
m
m
e
r

C
a
p
a
c
i
t
y

P
o
s
i
t
i
o
n

(
M
W
)

-

P
l
a
n

f
o
r

P
o
s
i
t
i
o
n

E
x
c
l
u
d
i
n
g

M
a
i
n
t
e
n
a
n
c
e

20
1
0

2
0
1
1

2
0
1
2

2
0
1
3

2
0
1
4

2
0
1
5

2
0
1
6

2
0
1
7

2
0
1
8

2
0
1
9

2
0
2
0

2
0
2
1

2
0
2
2

2
0
2
3

2
0
2
4

2
0
2
5

2
0
2
6

2
0
2
7

2
0
2
8

2
0
2
9
RE
Q
U
I
R
E
M
E
N
T
S
Na
t
i
v
e

L
o
a
d
-1
,
6
5
9

-
1
,
6
9
5

-
1
,
7
2
0

-
1
,
7
3
9

-
1
,
7
6
6

-
1
,
8
0
5

-
1
,
8
3
0

-
1
,
8
5
8

-
1
,
8
8
7

-
1
,
9
1
2

-
1
,
9
3
8

-
1
,
9
6
6

-
1
,
9
9
3

-
2
,
0
1
9

-
2
,
0
5
1

-
2
,
0
8
5

-
2
,
1
3
6

-
2
,
1
6
4

-
2
,
1
9
4

-
2
,
2
2
2
Co
n
t
r
a
c
t
s

O
b
l
i
g
a
t
i
o
n
s
-2
4
1

-
2
4
0

-
2
4
0

-
2
4
0

-
2
4
0

-
1
6
5

-
1
6
5

-
1
5

-
1
5

-
1
3

-
1
3

-
1
3

-
1
3

-
1
3

-
1
3

-
1
3

-
1
3

-
1
3

-
1
3

-
1
3
To
t
a
l

R
e
q
u
i
r
e
m
e
n
t
s
-1
,
9
0
0

-
1
,
9
3
6

-
1
,
9
6
0

-
1
,
9
7
9

-
2
,
0
0
6

-
1
,
9
7
0

-
1
,
9
9
5

-
1
,
87
2

-
1
,
9
0
2

-
1
,
9
2
5

-
1
,
9
5
1

-
1
,
9
7
9

-
2
,
0
0
6

-
2
,
0
3
2

-
2
,
0
6
4

-
2
,
0
9
8

-
2
,
1
4
9

-
2
,
1
7
7

-
2
,
2
0
7

-
2
,
2
3
5
RE
S
O
U
R
C
E
S
Co
n
t
r
a
c
t
s

R
i
g
h
t
s
54
5

4
4
5

4
2
5

4
2
5

4
2
5

3
5
0

3
5
0

3
5
0

3
5
0

3
4
6

3
4
6

3
4
6

3
4
6

3
4
6

3
4
6

3
4
6

3
4
6

8
2

8
2

8
2
Hy
d
r
o

R
e
s
o
u
r
c
e
s
95
3

9
3
2

1
,
0
2
0

1
,
0
2
8

1
,
0
5
1

1
,
0
2
8

1
,
0
4
9

1
,
0
2
2

1
,
0
2
2

1
,
0
2
1

1
,
0
2
3

9
9
6

9
9
6

9
9
3

1
,
0
2
8

9
9
6

9
9
6

1
,
0
0
2

1
,
0
2
3

9
9
6
Ba
s
e

L
o
a
d

T
h
e
r
m
a
l
s
57
7

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1
Pe
a
k
i
n
g

U
n
i
t
s
20
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0
To
t
a
l

R
e
s
o
u
r
c
e
s
2,
2
7
4

2
,
1
5
8

2
,
2
2
5

2
,
2
3
4

2
,
2
5
7

2
,
1
5
9

2
,
1
8
0

2
,
1
5
2

2
,
1
5
2

2
,
1
4
7

2
,
1
5
0

2
,
1
2
2

2
,
1
2
2

2
,
1
1
9

2
,
1
5
5

2
,
1
2
2

2
,
1
2
2

1
,
8
6
4

1
,
8
8
5

1
,
8
5
8
PE
A
K

P
O
S
I
T
I
O
N
37
4

2
2
2

2
6
6

2
5
5

2
5
1

1
8
9

1
8
4

2
8
0

2
5
0

2
2
2

1
9
8

1
4
3

1
1
6

8
7

9
0

2
4

-
2
7

-
3
1
3

-
3
2
2

-
3
7
7
RE
S
E
R
V
E

P
L
A
N
N
I
N
G
Pla
n
n
i
n
g

R
e
s
e
r
v
e

M
a
r
g
i
n
-2
4
9

-
2
5
4

-
2
5
8

-
2
6
1

-
2
6
5

-
2
7
1

-
2
7
5

-
2
7
9

-
2
8
3

-
2
8
7

-
2
9
1

-
2
9
5

-
2
9
9

-
3
0
3

-
3
0
8

-
3
1
3

-
3
2
0

-
3
2
5

-
3
2
9

-
3
3
3
Pe
a
k

P
o
s
i
t
i
o
n

w
i
t
h

M
a
i
n
t
.
12
5

-
3
3

8

-
6

-
1
4

-
8
2

-
9
0

1

-
3
3

-
6
5

-
9
2

-
1
5
2

-
1
8
2

-
2
1
6

-
2
1
7

-
2
8
9

-
3
4
8

-
6
3
7

-
6
5
1

-
7
1
1
PO
S
I
T
I
O
N

E
X
C
L
U
D
I
N
G

M
A
I
N
T
.

2
9
3

1
2
4

5
3

3
1

0

-
4
5

-
7
4

4
5

1
1

-
4
6

-
7
6

-
1
0
8

-
1
3
9

-
1
6
9

-
2
0
6

-
2
4
5

-
3
0
4

-
6
0
0

-
6
3
4

-
6
6
7
Av
i
s
t
a

C
o
r
p

20
0
9

E
l
e
c
t
r
i
c

I
R
P
-

P
u
b
l
i
c

D
r
a
f
t

28
Ch
a
p
t
e
r

2
:

L
o
a
d
s

&

R
e
s
o
u
r
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29
2009 Electric IRPAvista Corp 3-1
Chapter 3 - Energy EfficiencyChapter 3–Energy Efficiency
3. Energy Efficiency
Introduction
Avista’s energy efficiency 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 efficiency
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.
Chapter Highlights
• Conservation additions provide 26 percent of new supplies through 2020.
• 2009 IRP includes 0.3 aMW (3.3 percent) more conservation than the 2007 IRP.
• Avista has offered conservation programs for over 30 years.
• The Company has acquired 138.5 aMW of electric efficiency 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 efficiency measures.
• Approximately 3,000 efficiency 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 efficiency programs since 1978. Some of
Avista’s most notable efficiency 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
efficiency 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 efficiency
savings as outlined by the Northwest Power and Conservation Council (NPCC). Figure
3.1 illustrates Avista’s historical electricity conservation acquisitions.
Avista Corp 2009 Electric IRP – Public Draft 3-1
Energy efficient window replacement at Avista’s
headquarters in Spokane, Washington
Chapter 3 - Energy Efficiency
2009 Electric IRP3-2 Avista Corp
Chapter 3–Energy Efficiency
Figure 3.1: Historical Conservation Acquisition
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Avista has acquired 138.5 aMW of cumulative electricity efficiency resources over the last 30-years; of the 138.5 aMW total, 109 aMW acquired during the last 18 years is
assumed to still be online and providing resource value today. Northwest Energy
Efficiency 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 efficiency activity in the coming
years.
Avista is also expanding the breadth of its energy efficiency activities to include demand response initiatives and is analyzing the potential for transmission and distribution efficiency measures. More details about transmission and distribution efficiency projects
can be found in the Transmission and Distribution chapter of this IRP. Our demand
response pilot is still in process, so there is not enough data to currently determine if
Avista will continue demand response initiatives, and they were not included in this IRP. The results of the demand response pilot will be addressed in detail in the 2011 IRP.
Avista Corp 2009 Electric IRP – Public Draft 3-2
2009 Electric IRPAvista Corp 3-3
Chapter 3 - Energy EfficiencyChapter 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 efficiency
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 million shared throughout the region. Avista’s four
percent annual portion of NEEA funding has been $800,000. The Northwest funding
utilities 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 utilities is difficult. 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 million 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 million 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
million with schedule 91 increases effective August 1, 2009.
Energy Independence Act
Washington’s Energy Indpendence Act, established under Initiative 937 (I-937), and codified under RCW 19.285, requires utilities 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 experience has shown in other jurisdictions, these requirements
Avista Corp 2009 Electric IRP – Public Draft 3-3
Chapter 3 - Energy Efficiency
2009 Electric IRP3-4 Avista Corp
Chapter 3–Energy Efficiency
could be changed by the state legislature in the future. In addition to its RPS, I-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 efficiency target will 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), will “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 Utility’s most recent
IRP or the Conservation Council’s [NPCC] Power Plan.” WAC 480-109 requires
approval, approval with modifications or rejection by the WUTC of the Company’s
targets. Avista’s filing will follow, and this IRP will 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
efficiency measures consistent with the Sixth Power Plan and distribution efficiency
measures which would include savings on the utility and customer sides of the meter.
Since distribution efficiencies count toward our goal, meeting plan requirements with the least net cost to ratepayers will 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 efficiency tariff rider, local
government Energy Efficiency 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.
Avista Corp 2009 Electric IRP – Public Draft 3-4
2009 Electric IRPAvista Corp 3-5
Chapter 3 - Energy EfficiencyChapter 3–Energy Efficiency
The Company currently estimates that customers will pay $150, with the remainder of the $325 incremental audit cost being split between the tariff rider and local government
EECBG funds. The full cost of back office labor will 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 will 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 will 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), software 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 efficiency 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 roadmaps included: energy efficiency, demand response,
transmission and distribution, and analytics.
Energy Efficiency
The Company has completed a comprehensive assessment of industry best practices in energy efficiency 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 Facilities Model Program focusing on energy efficiency 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 efficiency 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 – Public Draft 3-5
Chapter 3 - Energy Efficiency
2009 Electric IRP3-6 Avista Corp
Chapter 3–Energy Efficiency
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 will be
completed on December 31, 2009. The Company will report on the pilot results in the
2011 IRP.
Analytics
Identification of cost-effective energy efficiency 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 categories. 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 volatility, 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
efficiency opportunities. This is always a factor in the completion of all IRP efforts given,
but it is significantly increased. Further evaluation of these efficiency opportunities
continue past the IRP processes. Avista evaluates energy-efficiency potential for the IRP in a manner that can augment the conservation business planning process and
ultimately lead to appropriate revisions in efficiency acquisition operations.
Consistency between the IRP Evaluation and Conservation Operations
Avista evaluates energy-efficiency 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 necessarily limited to modifying the
baseline for price elasticity and load growth.
Avista Corp 2009 Electric IRP – Public Draft 3-6
2009 Electric IRPAvista Corp 3-7
Chapter 3 - Energy EfficiencyChapter 3–Energy Efficiency
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 efficiency 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 portfolio 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 utility
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 thirty-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 required a
present value calculation of the avoided energy and capacity cost over the measure life
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for each concept. The avoided cost of energy was based upon an application of the measure’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 efficiencies.
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 efficiency.
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 failing 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 portfolio.
Evaluation of Comprehensive Program Elements
The all-inclusive nature of Avista’s non-residential site specific and limited income
portfolios 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 efficiency 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 portfolio is all-inclusive for qualifying efficiency measures. The portfolio is implemented in cooperation with community action agencies
that are given wide latitude in their approach to distributing program funds. No changes
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were expected in the ability 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 efficiency 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 will 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 will 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 will cover all states and fuels
intended to be used in the preparation of the 2011 IRP.
The Council only provides targets at a higher, utility level. Our measures along with their acquirable potential are illustrated in Appendix F.
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Compilation of the Final DSM Resource Estimates
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
targets are detailed in Table 3.1. Transmission and Distribution efficiency improvements
are covered in Chapter 5.
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
Regional 2.9 2.9
Total before Distribution Efficiencies (aMW)10.4 10.7
Estimated NPCC Sixth Plan Goal (aMW) 11.2 12.4
A graphical representation of the annual conservation targets for the full 20-year horizon is illustrated 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 NEAA funding.
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Figure 3.2: Forecast of Conservation Acquisition
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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 illustrated 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 efficiency measures, the measures with a very
high total resource cost cause a rapid sloping of the supply curve. Therefore, measures
with a total resource cost in excess of $0.50 per kwh have not been included in Figure 3.3
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Figure 3.3: Supply of Evaluated Conservation Measures (Levelized TRC Cost)
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 skill 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 portfolio in the following sections.
Residential Portfolio
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 will be inserted into a reevaluation
process for possible inclusion in the Business Plan.
Limited Income Residential Portfolio
Avista is committed to maintaining stable funding and maintaining program flexibility for
limited income conservation programs. There are six local community action partner
(CAP) agencies the Company funds to deliver limited income weatherization and energy efficiency programs. Five of the funded agencies offer electric efficiency measures. CAP agency funding is currently set at $1,972,000 million per year ($490,000 to Idaho and
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$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 Portfolio
There is sufficient uncertainty and potential for improvement in evaluated non-
residential program concepts to warrant regular reevaluations to ensure they retain a
minimum TRC cost-to-benefit 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 will be reviewed for target
marketing, the creation of a prescriptive program, or for targeting under a site-specific
program.
All electric-efficiency 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 facility 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 portfolio. The acquisition targets provide valuable information for future
budgetary, staffing 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 efficiency targets established in this IRP planning process may be modified as necessary to meet these evolving obligations.
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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 (CO2); 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 portfolio 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, utility planning is compounded 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 difficult 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 capital 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.
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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 most abundant. Remote locations may
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 utilize existing transmission facilities or minimize opposition to project
development. Biomass facilities 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 portfolio standard mandates, material prices and currency exchange rates.
There is still 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:
ƒ Different and changing federal legislative proposals: Lieberman-Warner, Dingell-
Boucher, and now Waxman-Markey;
ƒ 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.
ƒ Passage of H.R. 2454, the American Clean Energy and Security Act;
ƒ Joining RPS and greenhouse gas issues under the Waxman-Markey legislation;
and
ƒ Developments in climate change legislation in jurisdictions such as Washington and Oregon.
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Newly installed solar panels at Avista’s headquarters
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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:
ƒ Anticipates and evaluates strategic needs and opportunities relating to climate change;
ƒ Analyzes the company-wide implications of various trends and proposals;
ƒ Develops recommendations on positions and action plans; and
ƒ 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 efficiency issues under a single bill. 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:
ƒ Workable and cost effective;
ƒ Fair;
ƒ Protective of the economy and consumers;
ƒ Supportive of technological innovation; and
ƒ Includes emissions from developing nations.
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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 sufficient 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:
ƒ Increasing efficiency of existing fossil-fueled generation resources;
ƒ Reducing emissions from existing fossil-fueled generation through fuel displacement including co-firing with biomass or biofuels;
ƒ Permanently decreasing output from existing fossil-fueled resources and
substituting them with lower emitting resources;
ƒ Decommissioning or divesting fossil-fueled generation and substituting lower
emitting resources;
ƒ 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
ƒ Increasing investments in energy efficiency measures.
With the exception of increasing Avista’s commitment to energy efficiency, 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
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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:
ƒ Settling of scientific questions about human contributions to climate change; it is viewed as a largely anthropogenic or human-developed phenomenon.
ƒ A consensus view that regulation should be applied on an economy-wide basis,
rather than one or two sectors at a time.
ƒ Technology will be a key component to reducing overall greenhouse gas
emissions, particularly in the electric sector. Significant investment in carbon capture and sequestration technology will be needed since coal will continue to
be an important part of the U.S. generation fleet into the foreseeable future.
ƒ Developing countries must be involved in reducing global emissions as
greenhouse gas emissions generally increase with economic growth.
ƒ 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 bill 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 bill establishes greenhouse gas reduction goals, creates a national cap-and-trade program, and outlines a national RPS. Some of the bill’s details include:
ƒ RPS goals start at six percent in 2012 and increase to 20 percent by 2020.
ƒ Recognizes hydroelectric efficiency upgrades and additions effectuated since
January 1, 1992 as qualifying against the renewable energy standard.
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ƒ Removes existing hydroelectric power generation, excluding upgrades made after January 1, 1992, from the load base against which the renewable energy
standard is applied.
ƒ 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).
ƒ Permits REC trading, and banking of RECs for three years.
ƒ 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.
ƒ Proposes to administratively allocate allowances to electric utilities 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.
ƒ 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.
ƒ Allows banking and borrowing of emission allowances.
ƒ Allows for some forms of carbon offsets.
ƒ Establishes mechanisms for containing costs and for regulating allowance and
derivative markets.
Jeff Bingaman is also developing a federal RPS bill that is working its way through the
Senate. The Bingaman bill 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 efficiency. The
bill also creates an off ramp provision exempting a utility 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-utility 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 will
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
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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 portfolio standards, energy efficiency 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 portfolio
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. RGGI’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 bill. 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, will 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 will not
be regulated under a cap and trade program. The Waxman-Markey bill in its current form illustrates 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.
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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 Bill 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 Bill 25,
requiring new coal-fired facilities built in the state to sequester 50 percent of their emissions. Montana’s renewable portfolio standard law, which was enacted through
Senate Bill 415 in 2005, does not apply to Avista because the Company does not serve
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 portfolio 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 Bill 3543 calling 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 CO2 emissions exceeding 83 percent of the emissions of a state-of-the-art gas-fired CCCT by paying into the Climate Trust of Oregon. Senate Bill 838 requires large electric utilities 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 Bill 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 CO2 emissions through a plan including: third party
Avista Corp 2009 Electric IRP – Public Draft 4-8
2009 Electric IRPAvista Corp 4-9
Chapter 4 - Environmental PolicyChapter 4–Environmental Policy
mitigation, purchased carbon credits or cogeneration. Washington’s Energy Independence Act (I-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 efficiency measures.
Senate Bill 5840 was brought forward in 2009 to update I-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 I-937 RPS goals will be achieved by the Company.
In 2007 the Legislature passed Senate Bill 6001. It prohibits electric utilities from entering into financial commitments beyond five years for fossil-fueled generation where
CO2 emissions exceed 1,100 pounds per MWh. In 2013 the emissions performance
standard will 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 Bill 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:
ƒ 1990 levels by 2020;
ƒ 25 percent below 1990 levels by 2035;
ƒ 50 percent below 1990 levels by 2050 or 75 percent below expected emissions in
2050;
ƒ Increase clean energy jobs to 25,000 by 2020; and
ƒ Reduce statewide fuel imports by 20 percent.
The goals of this Executive Order were later codified into law when the Legislature
enacted Senate Bill 6001 in 2007. Taking the next step to achieve the State’s
greenhouse gas reduction goals, the governor introduced legislation (Senate Bill 5735
and House Bill 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 – Public Draft 4-9
Chapter 4 - Environmental Policy
2009 Electric IRP4-10 Avista Corp
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 will 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 facility’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 facilities the Department
of Ecology believes will 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 Portfolio Standard (I-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 I-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 I-937 to determine resource eligibility). Treatment of renewable resources in federal legislation would not allow the Company to use RECs from
federally-eligible resources to comply with I-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 will 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 still 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 bill 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
Avista Corp 2009 Electric IRP – Public Draft 4-10
2009 Electric IRPAvista Corp 4-11
Chapter 4 - Environmental PolicyChapter 4–Environmental Policy
assumes carbon will 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
will change to balance the relative competitiveness of gas and coal.
Figure 4.1: Price of Carbon Dioxide Credits
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Avista Corp 2009 Electric IRP – Public Draft 4-11
Chapter 5 – Transmission & 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.
Chapter Highlights
• Avista recently completed a $130 million 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 utilities:
Avista Corp 2009 Electric IRP – Public Draft 5-1
2009 Electric IRPAvista Corp 5-1
Chapter 5 - Transmission and DistributionChapter 5 – Transmission & 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.
Chapter Highlights
• Avista recently completed a $130 million 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 utilities:
Avista Corp 2009 Electric IRP – Public Draft 5-1
Transmission upgrade work
Chapter 5 - Transmission and Distribution
2009 Electric IRP5-2 Avista Corp
Chapter 5 – Transmission & Distribution
ƒ Bonneville Power Administration (BPA)
ƒ Chelan County PUD
ƒ Grant County PUD
ƒ Idaho Power Company
ƒ NorthWestern Energy
ƒ PacifiCorp
ƒ Pend Oreille County PUD
Figure 5.1: Avista transmission system
In addition to providing enhanced transmission system reliability, network
interconnections serve as points of receipt for power from generating facilities 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 utilities 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 million 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
reliability. 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,
Avista Corp 2009 Electric IRP – Public Draft 5-2
Chapter 5 – Transmission & 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 will 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:
ƒ New 230/115 kV station near Garden Springs;
ƒ Tap the Benewah-Boulder 230 kV line southwest of the Liberty Lake area and construct a new 230 kV switching station (for later development of a 230/115 kV substation);
ƒ Connection of the Liberty Lake 230 kV station with the Garden Springs 230 kV
station;
ƒ New 230 kV line from Garden Springs to Westside; and
ƒ 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.
ƒ 500 kV HVAC facilities 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;
ƒ 500 kV HVDC facilities from NEO Station to Collinsville Substation in the San
Francisco Bay Area, with a possible third terminal at Cottonwood Area
Substation in northern California (DC Segment);
ƒ Voltage support at the interconnecting substations; and
ƒ Remedial actions for project outages.
Avista Corp 2009 Electric IRP – Public Draft 5-3
2009 Electric IRPAvista Corp 5-3
Chapter 5 - Transmission and DistributionChapter 5 – Transmission & Distribution
ƒ Bonneville Power Administration (BPA)
ƒ Chelan County PUD
ƒ Grant County PUD
ƒ Idaho Power Company
ƒ NorthWestern Energy
ƒ PacifiCorp
ƒ Pend Oreille County PUD
Figure 5.1: Avista transmission system
In addition to providing enhanced transmission system reliability, network
interconnections serve as points of receipt for power from generating facilities 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 utilities 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 million 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
reliability. 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,
Avista Corp 2009 Electric IRP – Public Draft 5-2
Chapter 5 – Transmission & 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 will 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:
ƒ New 230/115 kV station near Garden Springs;
ƒ Tap the Benewah-Boulder 230 kV line southwest of the Liberty Lake area and construct a new 230 kV switching station (for later development of a 230/115 kV substation);
ƒ Connection of the Liberty Lake 230 kV station with the Garden Springs 230 kV
station;
ƒ New 230 kV line from Garden Springs to Westside; and
ƒ 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.
ƒ 500 kV HVAC facilities 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;
ƒ 500 kV HVDC facilities from NEO Station to Collinsville Substation in the San
Francisco Bay Area, with a possible third terminal at Cottonwood Area
Substation in northern California (DC Segment);
ƒ Voltage support at the interconnecting substations; and
ƒ Remedial actions for project outages.
Avista Corp 2009 Electric IRP – Public Draft 5-3
Chapter 5 - Transmission and Distribution
2009 Electric IRP5-4 Avista Corp
Chapter 5 – Transmission & Distribution
The proposed north-to-south rating for the two-segment project is 3,000 MW. It will
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 will 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 will 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 facilities 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 reliability and access. Avista also works with BPA and other regional utilities to coordinate major transmission facility
outages.
Future generation resource development will require construction of new transmission assets. BPA recently received $3.5 billion in additional borrowing authority through the American Recovery and Reinvestment Act of 2009. Increased borrowing capability
enhances BPA’s ability to construct new transmission projects. One recent example is
the 79-mile long 500 kV McNary-John Day upgrade. This $200 million project had been
on hold since 2002 because of BPA’s inability to finance the project.
Avista Corp 2009 Electric IRP – Public Draft 5-4
Chapter 5 – Transmission & 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.
Attachment K
On December 7, 2007, Avista submitted a revised Attachment K to its Open Access
Transmission Tariff (OATT). 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 reliability in the Western Interconnection. WECC also supports efficient 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 – Public Draft 5-5
2009 Electric IRPAvista Corp 5-5
Chapter 5 - Transmission and DistributionChapter 5 – Transmission & Distribution
The proposed north-to-south rating for the two-segment project is 3,000 MW. It will
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 will 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 will 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 facilities 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 reliability and access. Avista also works with BPA and other regional utilities to coordinate major transmission facility
outages.
Future generation resource development will require construction of new transmission assets. BPA recently received $3.5 billion in additional borrowing authority through the American Recovery and Reinvestment Act of 2009. Increased borrowing capability
enhances BPA’s ability to construct new transmission projects. One recent example is
the 79-mile long 500 kV McNary-John Day upgrade. This $200 million project had been
on hold since 2002 because of BPA’s inability to finance the project.
Avista Corp 2009 Electric IRP – Public Draft 5-4
Chapter 5 – Transmission & 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.
Attachment K
On December 7, 2007, Avista submitted a revised Attachment K to its Open Access
Transmission Tariff (OATT). 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 reliability in the Western Interconnection. WECC also supports efficient 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 – Public Draft 5-5
Chapter 5 - Transmission and Distribution
2009 Electric IRP5-6 Avista Corp
Chapter 5 – Transmission & 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 www.nwpp.org/tcwg .
Avista Transmission Reliability and Operations
Avista plans and operates its transmission system pursuant to applicable criteria
established by the North American Electric Reliability 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 reliability standards promulgated through FERC and NERC,
subject Avista to periodic performance 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. Construction-quality estimates were only made for three projects proposed in
the IRP. The other options identified in this IRP are based on engineering judgment.
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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 party 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 million 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, BPA, 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.
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Integration of Resources on the Avista Transmission System
Avista-LSE has requested three generator interconnection studies: one near Reardan,
Washington, a second near Grangeville, Idaho, and a third in Garfield 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 will be required to accommodate
the full project output. Preliminary cost estimates of interconnecting a wind project at
Reardan are under $15 million; however, not all costs associated with the upgrade will be directly assigned to the project because some upgrades are needed whether or nor the project is completed.
Avista-LSE will 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 OATT requirements.
Grangeville, Idaho
Avista-LSE submitted a generator interconnection request to Avista Transmission in
2008 for a proposed 120 MW wind project located near Grangeville, 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 Grangeville
Substation, without mitigating the reactive power consumption of the transmission
system, is estimated to be $12.9 million 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 Grangeville
substation.
Garfield County, Washington
Avista-LSE submitted a generator interconnection request for a 200 MW wind project located approximately three miles east of the Columbia/Garfield (Washington) county line in Garfield County. The project, located 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 million.
Lancaster Integration
Avista is evaluating various alternatives for a new transmission interconnection with
BPA in the Spokane Valley. One interconnection is at BPA’s Lancaster Substation. This
interconnection might allow Avista to eliminate or offset some BPA wheeling charges for
moving the Lancaster combustion turbine project to Avista’s system. Avista is working
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with BPA to determine what form the interconnection should take. Preliminary studies indicate that Avista could expand existing BPA facilities, 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 reliability,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 (<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 grid 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
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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 work being initiated.
Clark Fork Hydro Upgrades
The Clark Fork area transmission system consists of Avista and BPA 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 BPA to maintain system reliability 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 efficient 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 kV and 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.
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System Efficiencies Team
Avista’s System Efficiencies 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 reliability and meet future load growth.
Distribution Feeders
The System Efficiencies 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 Efficiencies Team evaluated several efficiency programs across urban and
rural distribution feeders. The programs consisted of the following system
enhancements:
ƒ Conductor losses;
ƒ Distribution Transformers;
ƒ Secondary Districts; and
ƒ VAR compensation.
The energy loss, capital investment and O&M cost reductions resulting from individual
efficiency 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 Efficiencies Program document in Appendix G.
The O&M avoided costs for upgrades were determined by modeling existing feeders in the Availability Workbench Program. This program is an expected value model
combining a weighted average time and material cost of equipment failure with the
probability of failure. The distribution feeder’s conductor, transformers and ancillary
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 illustrates the levelized cost of feeder upgrades.
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Chapter 5 – Transmission & Distribution
Figure 5.2: Levelized Cost of Feeder Upgrades
-50
0
50
100
150
200
0 25 50 75
10
0
12
5
15
0
17
5
20
0
22
5
25
0
27
5
30
0
av
o
i
d
e
d

c
o
s
t

(
$
/
M
W
h
)
40 year 15 year
10 year 5 year
quantity of feeders
Distribution feeders with the highest potential for efficiency 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.
Figure 5.3: Estimated Feeder Supply Curve
-150
-100
-50
0
50
100
150
200
- 2.0 4.0 6.0 8.0 10.0 12.0 14.0 16.0
av
o
i
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c
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(
$
/
M
W
h
)
5 Year Avoided Cost
40 Year Avoided Cost
aMW of savings
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Chapter 5 - Transmission and DistributionChapter 5 – Transmission & Distribution
Operational Considerations
By implementing feeder efficiency programs, voltage drop across feeders will decrease
and will provide an opportunity to deploy a Conservation Voltage Reduction (CVR)
program. Although CVR was not evaluated in the system efficiencies 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 Efficiency Alliance 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 will 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 will review several transmission topologies to determine
the most efficient configuration to move bulk power through and by Avista’s balancing
area. The transmission topologies will consider the efficiency between star network, hub
and loop, southern loop and southern source. Avista’s load service will be incorporated in this analysis by determining ideal substation placement and feeder sizes as well as
forecasted load growth. The comprehensive analysis will evaluate many of the items
listed below.
ƒ Develop performance criteria to determine system measures;
ƒ Develop base case to measure existing system performance;
ƒ Develop methodology to determine a full build out load case;
ƒ Identify transmission topologies to be evaluated;
ƒ Identify guidelines for placing substations;
ƒ Identify guidelines for distribution feeder sizes; and
ƒ Bound the analysis to ensure the system remains reliable, compliant and
operationally flexible.
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Summary
Avista’s transmission system consists of over 2,200 miles of high voltage transmission
lines. Transmission system planning utilizes 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 will be developed after a complete generation interconnection request has been submitted and accepted by Avista’s Transmission Department.
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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 facilities 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 credit1 (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 availability and SCCT generation
1 Avista may not be able to take advantage of the full 30 percent tax credit in a single year. The utility 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.
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Chapter 6 - Generation Resource OptionsChapter 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 facilities 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 credit1 (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 availability and SCCT generation
1 Avista may not be able to take advantage of the full 30 percent tax credit in a single year. The utility 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.
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Chapter 6 - Generation Resource Options
2009 Electric IRP6-2 Avista Corp
Chapter 6- Generation Resource Options
assumes 92 percent availability. The following are definitions of the levelized cost items used in this chapter:
ƒCapital 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.
ƒInterconnection 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.
ƒAllowance for Funds Used During Construction (AFUDC): the cost of money for
construction payments before the utility is allowed to recover prudently invested
costs.
ƒVariable Operations and Maintenance (O&M): Costs per MWh related to
incremental generation.
ƒFixed 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.
ƒCO2 Emissions Adder: Cost of carbon
dioxide (greenhouse gas) emissions
based on Wood Mackenzie forecast.
ƒNOx and SO2: Cost of nitrous oxide and
sulfur dioxide emissions based on the Wood Mackenzie forecast.
ƒFuel Costs: The cost of fuels such as
natural gas, coal or wood per the
efficiency of the generator. Further details on fuel prices are included in the Market Analysis chapter.
ƒExcise Taxes and Other Overheads:
Includes miscellaneous charges for non-
capital expenses.
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 credit2 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.
Avista Corp 2009 Electric IRP- Public Draft 6-2
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 volatility 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 Btu/kWh 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 capability of each plant is highly dependent on ambient temperature and
plant elevation. Figure 6.1 illustrates 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 illustrative 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 illustrates 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).
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Chapter 6 - Generation Resource OptionsChapter 6- Generation Resource Options
assumes 92 percent availability. The following are definitions of the levelized cost items used in this chapter:
ƒCapital 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.
ƒInterconnection 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.
ƒAllowance for Funds Used During Construction (AFUDC): the cost of money for
construction payments before the utility is allowed to recover prudently invested
costs.
ƒVariable Operations and Maintenance (O&M): Costs per MWh related to
incremental generation.
ƒFixed 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.
ƒCO2 Emissions Adder: Cost of carbon
dioxide (greenhouse gas) emissions
based on Wood Mackenzie forecast.
ƒNOx and SO2: Cost of nitrous oxide and
sulfur dioxide emissions based on the Wood Mackenzie forecast.
ƒFuel Costs: The cost of fuels such as
natural gas, coal or wood per the
efficiency of the generator. Further details on fuel prices are included in the Market Analysis chapter.
ƒExcise Taxes and Other Overheads:
Includes miscellaneous charges for non-
capital expenses.
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 credit2 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.
Avista Corp 2009 Electric IRP- Public Draft 6-2
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 volatility 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 Btu/kWh 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 capability of each plant is highly dependent on ambient temperature and
plant elevation. Figure 6.1 illustrates 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 illustrative 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 illustrates 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- Public Draft 6-3
Chapter 6 - Generation Resource Options
2009 Electric IRP6-4 Avista Corp
Chapter 6- Generation Resource Options
Figure 6.1: CCCT Output Per 100 MW of Nameplate Capacity
80
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Rathdrum, ID (water)
Rathdrum, ID (air)
Rosalia, WA (water)
Boardman, OR (water)
Lewiston, ID (water)
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 SO2 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.
Avista Corp 2009 Electric IRP- Public Draft 6-4
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 & SO2 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- Public Draft 6-5
2009 Electric IRPAvista Corp 6-5
Chapter 6 - Generation Resource OptionsChapter 6- Generation Resource Options
Figure 6.1: CCCT Output Per 100 MW of Nameplate Capacity
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105
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Rathdrum, ID (water)
Rathdrum, ID (air)
Rosalia, WA (water)
Boardman, OR (water)
Lewiston, ID (water)
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
ItemNominal $ Real 2009$
Capital recovery and taxes 20.91 15.49
Interconnection capital recovery 0.76 0.64
AFUDC2.60 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 SO2 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.
Avista Corp 2009 Electric IRP- Public Draft 6-4
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 & SO2 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- Public Draft 6-5
Chapter 6 - Generation Resource Options
2009 Electric IRP6-6 Avista Corp
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 & SO2 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 & SO2 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 portfolio 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:
ƒ Reardan (up to 50 MW);
ƒ Columbia Basin (50 MW increments);
ƒ Montana (25 MW increments);
ƒ Small scale (less than 1 MW); and
ƒ Offshore (75 MW increments).
Reardan and Columbia Basin locations were the only wind resources considered for the
PRS analysis. Other resource locations will be considered if projects are submitted in
response to competitive solicitations.
Avista Corp 2009 Electric IRP- Public Draft 6-6
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:
ƒReardan: Avista transmission system requiring $15 million in network and project
transmission improvements.
ƒColumbia Basin (Tier 1 and Tier 2): BPA wheel3 and $100 per kW for local
interconnection.
ƒMontana: Northwestern wheel4 and $50 per kW for local interconnection.
ƒSmall Scale: Avista distribution system and $100 per kW for distribution
interconnection and a 10 percent adder for saved transmission and distribution losses.
ƒOffshore: BPA 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
illustrated 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 $3.50 per MWh for
integration services.
Table 6.5: Wind Capital and Fixed O&M Costs
Location
Capital 2009$ (includes
AFUDC)
Fixed O&M ($ per kW-
year)
Capacity
Factor
Reardan5 2,183 45 30.0%
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%
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 based on prices at the time of modeling. Actual costs will 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 significant transmission upgrade costs, no third party development fees and the proximity of the project to Avista’s operations center.
Avista Corp 2009 Electric IRP- Public Draft 6-7
2009 Electric IRPAvista Corp 6-7
Chapter 6 - Generation Resource OptionsChapter 6- Generation Resource Options
Table 6.3: Frame SCCT Levelized Costs per MWh
ItemNominal $ Real 2009$
Capital recovery and taxes 9.27 6.87
Interconnection capital recovery 0.74 0.63
AFUDC0.43 0.36
Variable O&M 5.90 5.00
Fixed O&M 0.58 0.49
CO2 emissions adder 23.04 19.55
NOx & SO2 emission adder 0.23 0.19
Fuel costs 90.09 76.40
Excise taxes and other overheads5.19 4.40
Total Cost 135.47 113.90
Table 6.4: LMS 100 Levelized Costs per MWh
ItemNominal $ Real 2009$
Capital recovery and taxes 19.31 14.31
Interconnection capital recovery 0.74 0.63
AFUDC0.89 0.75
Variable O&M 6.49 5.50
Fixed O&M 0.58 0.49
CO2 emissions adder 18.97 16.10
NOx & SO2 emission adder 0.19 0.16
Fuel costs 74.19 62.92
Excise taxes and other overheads4.35 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 portfolio 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:
ƒ Reardan (up to 50 MW);
ƒ Columbia Basin (50 MW increments);
ƒ Montana (25 MW increments);
ƒ Small scale (less than 1 MW); and
ƒ Offshore (75 MW increments).
Reardan and Columbia Basin locations were the only wind resources considered for the
PRS analysis. Other resource locations will be considered if projects are submitted in
response to competitive solicitations.
Avista Corp 2009 Electric IRP- Public Draft 6-6
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:
ƒReardan: Avista transmission system requiring $15 million in network and project
transmission improvements.
ƒColumbia Basin (Tier 1 and Tier 2): BPA wheel3 and $100 per kW for local
interconnection.
ƒMontana: Northwestern wheel4 and $50 per kW for local interconnection.
ƒSmall Scale: Avista distribution system and $100 per kW for distribution
interconnection and a 10 percent adder for saved transmission and distribution losses.
ƒOffshore: BPA 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
illustrated 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 $3.50 per MWh for
integration services.
Table 6.5: Wind Capital and Fixed O&M Costs
Location
Capital 2009$ (includes
AFUDC)
Fixed O&M ($ per kW-
year)
Capacity
Factor
Reardan5 2,183 45 30.0%
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%
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 based on prices at the time of modeling. Actual costs will 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 significant transmission upgrade costs, no third party development fees and the proximity of the project to Avista’s operations center.
Avista Corp 2009 Electric IRP- Public Draft 6-7
Chapter 6 - Generation Resource Options
2009 Electric IRP6-8 Avista Corp
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 & SO2 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 SO2 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 Levelized Costs 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 SO2 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
Avista Corp 2009 Electric IRP- Public Draft 6-8
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 efficiencies. 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 CO2 emissions from 205 pounds per
MMBtu to 20.5 pounds per MMBtu.
The Washington State legislature passed Senate Bill 6001 in 2007, effectively
prohibiting local electric utilities from developing coal-fired facilities 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 facility for the 2009 IRP and believes such a facility is unlikely to be
approved. IGCC facilities were modeled in 200 MW increments in the PRS 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$)
Technology
Capital Cost ($/kW includes
AFUDC)
Fixed O&M
($/kW/Yr)
Heat Rate
(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- Public Draft 6-9
2009 Electric IRPAvista Corp 6-9
Chapter 6 - Generation Resource OptionsChapter 6- Generation Resource Options
Table 6.6: Columbia Basin Wind Project Levelized Costs per MWh
ItemNominal $ Real 2009$
Capital recovery and taxes 56.63 48.01
Interconnection capital recovery 4.40 3.73
AFUDC4.60 3.90
Variable O&M 3.54 3.00
Fixed O&M 20.79 17.63
CO2 emissions adder 0.00 0.00
NOx & SO2 emissions adder 0.00 0.00
Fuel costs 0.00 0.00
Integration4.05 3.50
Excise taxes and other overheads1.05 0.89
Total Cost 95.06 80.66
Table 6.7: Small Scale Project Levelized Costs per MWh
ItemNominal $ Real 2009$
Capital recovery and taxes 125.01 105.97
Interconnection capital recovery 0.00 0.00
AFUDC10.14 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 SO2 emission adder 0.00 0.00
Fuel costs 0.00 0.00
Integration4.05 3.50
Excise taxes and other overheads1.48 1.25
Total Cost 174.82 148.27
Table 6.8: Offshore Wind Project Levelized Costs per MWh
ItemNominal $ Real 2009$
Capital recovery and taxes 103.83 88.02
Interconnection capital recovery 1.16 0.99
AFUDC11.16 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 SO2 emissions adder 0.00 0.00
Fuel costs 0.00 0.00
Integration4.05 3.50
Excise taxes and other overheads1.51 1.28
Total Cost 156.58 132.81
Avista Corp 2009 Electric IRP- Public Draft 6-8
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 efficiencies. 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 CO2 emissions from 205 pounds per
MMBtu to 20.5 pounds per MMBtu.
The Washington State legislature passed Senate Bill 6001 in 2007, effectively
prohibiting local electric utilities from developing coal-fired facilities 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 facility for the 2009 IRP and believes such a facility is unlikely to be
approved. IGCC facilities were modeled in 200 MW increments in the PRS 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$)
Technology
Capital Cost ($/kW includes
AFUDC)
Fixed O&M
($/kW/Yr)
Heat Rate
(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- Public Draft 6-9
Chapter 6 - Generation Resource Options
2009 Electric IRP6-10 Avista Corp
Chapter 6- Generation Resource Options
Table 6.10: Ultra Critical Pulverized Coal Project Levelized Cost per MWh
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 SO2 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 SO2 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
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 SO2 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
Avista Corp 2009 Electric IRP- Public Draft 6-10
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 hydroelectric 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 will 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
Project
CapitalCost
(2009$)
(includesAFUDC) YearAvailable Capacity (MW)Capacity Factor
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%
Upper Falls 3,870 2019 2.0 49%
Long Lake Unit 5 2,882 2020 24.0 34%
Long Lake 2nd Powerhouse 2,454 2020 60.0 30%
Cabinet Gorge Unit 5 1,660 2015 60.0 17%
Avista Corp 2009 Electric IRP- Public Draft 6-11
2009 Electric IRPAvista Corp 6-11
Chapter 6 - Generation Resource OptionsChapter 6- Generation Resource Options
Table 6.10: Ultra Critical Pulverized Coal Project Levelized Cost per MWh
ItemNominal $ Real 2009$
Capital recovery and taxes 49.96 37.02
Interconnection capital recovery 0.60 0.57
AFUDC9.29 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 SO2 emission adder 1.30 1.26
Fuel costs 11.37 9.64
Excise taxes and other overheads2.39 2.03
Total Cost 117.34 94.32
Table 6.11: IGCC Coal Project Levelized Cost per MWh
ItemNominal $ Real 2009$
Capital recovery and taxes 59.95 44.42
Interconnection capital recovery 0.60 0.51
AFUDC11.14 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 SO2 emission adder 0.59 0.54
Fuel costs 10.47 8.88
Excise taxes and other overheads2.36 2.00
Total Cost 128.45 102.56
Table 6.12: IGCC with Carbon Sequestration Coal Project Levelized Cost ($/MWh)
ItemNominal $ Real 2009$
Capital recovery and taxes 84.71 62.77
Interconnection capital recovery 0.61 0.51
AFUDC15.75 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 SO2 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
Avista Corp 2009 Electric IRP- Public Draft 6-10
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 hydroelectric 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 will 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
Project
CapitalCost
(2009$)
(includesAFUDC) YearAvailable Capacity (MW)Capacity Factor
Little Falls Unit 1 2,787 2014 1.0 32%
Little Falls Unit 2 1,929 2015 1.0 32%
Little Falls Unit 3 3,430 2016 1.0 32%
Little Falls Unit 4 1,393 2017 1.0 32%
Post Falls Unit 6 5,359 2018 0.2 32%
Upper Falls 3,870 2019 2.0 49%
Long Lake Unit 5 2,882 2020 24.0 34%
Long Lake 2nd Powerhouse 2,454 2020 60.0 30%
Cabinet Gorge Unit 5 1,660 2015 60.0 17%
Avista Corp 2009 Electric IRP- Public Draft 6-11
Chapter 6 - Generation Resource Options
2009 Electric IRP6-12 Avista Corp
Chapter 6- Generation Resource Options
Table 6.14: Hydro Upgrade Nominal Levelized Costs per MWh
Project
Generation
Capital
Recovery & Taxes
Transmission
Capital
Recovery & Taxes AFUDC FixedO&M TotalCost
Little Falls Unit 1 81.07 0.00 5.82 0.00 86.89
Little Falls Unit 2 56.13 0.00 4.03 0.00 60.16
Little Falls Unit 3 99.78 0.00 7.16 0.00 106.94
Little Falls Unit 4 40.54 0.00 2.91 0.00 43.45
Post Falls Unit 6 155.91 0.00 11.19 0.00 167.10
Upper Falls 71.27 0.00 7.54 0.00 78.81
Long Lake Unit 5 63.58 14.38 10.93 0.40 89.29
Long Lake 2nd Powerhouse 66.52 6.51 10.56 0.90 84.49
Cabinet Gorge Unit 5 83.15 0.00 14.29 1.58 99.02
Table 6.15: Hydro Upgrade 2009$ Levelized Costs per MWh
Project
GenerationCapitalRecovery &
Taxes
TransmissionCapitalRecovery &
Taxes AFUDC
Fixed
O&M
Total
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
Long Lake Unit 5 53.90 12.19 9.26 0.34 75.71
Long Lake 2nd PH 56.39 5.52 8.95 0.76 71.65
Cabinet Gorge 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 utility-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.
SolarSolar technology has advanced in the last several years with help from renewable
portfolio standards, the federal ITC and state incentives. Solar still 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.
Avista Corp 2009 Electric IRP- Public Draft 6-12
Chapter 6- Generation Resource Options
The Northwest is not a prime location for photovoltaic solar relative to the Southwest. A well placed utility 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:
ƒ Utility Scale Photovoltaic: $7,900 per kW;
ƒ Solar or Concentrating Thermal: $4,541 per kW; and
ƒ Roof Top 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)
Item Utility Scale Photovoltaic SolarThermal Roof-TopSolar
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 SO2 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 $2,000 per year, depending upon location of manufacturing, through June of 2014. These incentives are not included in this analysis.
Avista Corp 2009 Electric IRP- Public Draft 6-13
2009 Electric IRPAvista Corp 6-13
Chapter 6 - Generation Resource OptionsChapter 6- Generation Resource Options
Table 6.14: Hydro Upgrade Nominal Levelized Costs per MWh
Project
Generation
Capital
Recovery & Taxes
Transmission
Capital
Recovery & TaxesAFUDC FixedO&M TotalCost
Little Falls Unit 181.070.00 5.82 0.0086.89
Little Falls Unit 256.130.00 4.03 0.0060.16
Little Falls Unit 3 99.780.00 7.16 0.00106.94
Little Falls Unit 440.540.00 2.91 0.0043.45
Post Falls Unit 6 155.910.00 11.19 0.00167.10
Upper Falls 71.270.00 7.54 0.0078.81
Long Lake Unit 5 63.58 14.38 10.93 0.4089.29
Long Lake 2nd Powerhouse 66.526.51 10.56 0.90 84.49
Cabinet Gorge Unit 5 83.150.00 14.29 1.5899.02
Table 6.15: Hydro Upgrade 2009$ Levelized Costs per MWh
Project
Generation
CapitalRecovery &
Taxes
Transmission
CapitalRecovery &
TaxesAFUDC
Fixed
O&M
Total
Cost
Little Falls Unit 168.720.00 4.93 0.0073.66
Little Falls Unit 247.580.00 3.42 0.0050.99
Little Falls Unit 3 84.580.00 6.07 0.0090.66
Little Falls Unit 434.360.00 2.47 0.0036.83
Post Falls Unit 6 132.160.00 9.49 0.00141.65
Upper Falls 60.420.00 6.39 0.0066.80
Long Lake Unit 5 53.90 12.19 9.26 0.3475.71
Long Lake 2nd PH 56.395.52 8.95 0.7671.65
Cabinet Gorge Unit 5 70.490.00 12.12 1.3484.00
Other Resource Options
A thorough IRP considers resources that may not be commercially or economically
ready for utility-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.
SolarSolar technology has advanced in the last several years with help from renewable
portfolio standards, the federal ITC and state incentives. Solar still 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.
Avista Corp 2009 Electric IRP- Public Draft 6-12
Chapter 6- Generation Resource Options
The Northwest is not a prime location for photovoltaic solar relative to the Southwest. A well placed utility 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:
ƒ Utility Scale Photovoltaic: $7,900 per kW;
ƒ Solar or Concentrating Thermal: $4,541 per kW; and
ƒ Roof Top 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)
Item Utility Scale Photovoltaic SolarThermal Roof-TopSolar
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 SO2 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 $2,000 per year, depending upon location of manufacturing, through June of 2014. These incentives are not included in this analysis.
Avista Corp 2009 Electric IRP- Public Draft 6-13
Chapter 6 - Generation Resource Options
2009 Electric IRP6-14 Avista Corp
Chapter 6- Generation Resource Options
Table 6.17: Solar 2009$ Levelized Cost ($/MWh)
Item
Utility Scale
Photovoltaic
Solar
Thermal
Roof-Top
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 SO2 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
Biomass and Wood Generation Avista is an industry leader in biomass generation. In 1983, the Company built one of
the largest biomass generation facilities 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
evaluated for this IRP.
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 facilities 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 receive double the federal credits. No fuel
costs were included for non-wood biomass resources because the fuel cost will depend
on the type of fuel source. For example, a digester resource located at a dairy will 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.
Avista Corp 2009 Electric IRP- Public Draft 6-14
Chapter 6- Generation Resource Options
Table 6.18: Biomass Capital Costs
Project
Capital Cost
(2009$) (includesAFUDC)
Fixed
O&M($/kW/Yr)
CCCT Wood Boiler 2,745 121
KFCT Wood Gasifier 4,645 85
Wood Gasifer Combined Cycle 3,476 85
Biomass Open-Loop 5,406 85
Biomass Closed-Loop 8,649 150
Table 6.19: Biomass Nominal Levelized Costs per MWh
Item
CCCT
WoodBoiler
KFCT
WoodGasifier
Wood
GasifierCC
Biomass
Open-Loop
Biomass
Closed-Loop
Capital recovery and taxes 24.67 43.03 32.49 48.16 77.07
Interconnection capital recovery 0.00 0.00 0.28 0.28 0.28
AFUDC 2.42 2.30 1.73 3.91 6.25
Variable O&M 7.08 9.08 9.08 3.54 11.79
Fixed O&M 18.09 12.68 12.68 12.40 21.89
CO2 emissions adder 0.00 0.00 0.00 0.00 0.00
NOx and SO2 emission adder 2.12 0.00 0.00 0.00 0.00
Fuel costs 82.50 40.46 40.46 0.00 0.00
Excise taxes and other overheads 4.75 2.69 2.69 0.69 1.46
Total Cost 141.63 110.24 99.41 68.98 118.74
Table 6.20: Biomass 2009 Dollar Levelized Cost per MWh
Item
CCCT
WoodBoiler
KFCT
WoodGasifier
Wood
GasifierCC
Biomass
Open-Loop
Biomass
Closed-Loop
Capital recovery and taxes 20.91 36.48 27.55 40.83 65.33
Interconnection capital recovery 0.00 0.00 0.24 0.24 0.24
AFUDC 2.05 1.95 1.47 3.31 5.30
Variable O&M 6.00 7.70 7.70 3.00 10.00
Fixed O&M 15.34 10.75 10.75 10.52 18.56
CO2 emissions adder 0.00 0.00 0.00 0.00 0.00
NOx and SO2 emission adder 1.83 0.00 0.00 0.00 0.00
Fuel costs 69.95 34.31 34.31 0.00 0.00
Excise taxes and other overheads 4.03 2.28 2.28 0.59 1.24
Total Cost 120.12 93.47 84.30 58.48 100.66
Avista Corp 2009 Electric IRP- Public Draft 6-15
2009 Electric IRPAvista Corp 6-15
Chapter 6 - Generation Resource OptionsChapter 6- Generation Resource Options
Table 6.17: Solar 2009$ Levelized Cost ($/MWh)
Item
Utility Scale
Photovoltaic
Solar
Thermal
Roof-Top
Solar
Capital recovery and taxes 264.93 110.90 376.79
Interconnection capital recovery 0.00 4.11 0.00
AFUDC9.38 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 SO2 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
Biomass and Wood Generation Avista is an industry leader in biomass generation. In 1983, the Company built one of
the largest biomass generation facilities 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
evaluated for this IRP.
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 facilities 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 receive double the federal credits. No fuel
costs were included for non-wood biomass resources because the fuel cost will depend
on the type of fuel source. For example, a digester resource located at a dairy will 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.
Avista Corp 2009 Electric IRP- Public Draft 6-14
Chapter 6- Generation Resource Options
Table 6.18: Biomass Capital Costs
Project
Capital Cost
(2009$) (includesAFUDC)
Fixed
O&M($/kW/Yr)
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
Item
CCCT
WoodBoiler
KFCT
WoodGasifier
Wood
GasifierCC
Biomass
Open-Loop
Biomass
Closed-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 SO2 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
Item
CCCT
WoodBoiler
KFCT
WoodGasifier
Wood
GasifierCC
Biomass
Open-Loop
Biomass
Closed-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 SO2 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- Public Draft 6-15
Chapter 6 - Generation Resource Options
2009 Electric IRP6-16 Avista Corp
Chapter 6- Generation Resource Options
GeothermalNorthwest 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 drilling several thousand feet below the earth’s crust;
each hole can cost over $3 million. 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 SO2 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 IRP 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.
Avista Corp 2009 Electric IRP- Public Draft 6-16
Chapter 6- Generation Resource Options
Table 6.22: Tidal/Wave 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 & SO2 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 I-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 SO2 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 utilities 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
difficult 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 difficulties
Avista Corp 2009 Electric IRP- Public Draft 6-17
2009 Electric IRPAvista Corp 6-17
Chapter 6 - Generation Resource OptionsChapter 6- Generation Resource Options
GeothermalNorthwest 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 drilling several thousand feet below the earth’s crust;
each hole can cost over $3 million. 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
ItemNominal $ Real 2009$
Capital recovery and taxes 49.05 41.58
Interconnection capital recovery 0.280.24
AFUDC6.855.81
Variable O&M 5.905.00
Fixed O&M 11.149.45
CO2 emissions adder 1.931.64
NOx and SO2 emission adder 0.000.00
Fuel costs 0.000.00
Excise taxes and other overheads0.820.70
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 IRP 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.
Avista Corp 2009 Electric IRP- Public Draft 6-16
Chapter 6- Generation Resource Options
Table 6.22: Tidal/Wave 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 & SO2 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 I-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 SO2 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 utilities 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
difficult 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 difficulties
Avista Corp 2009 Electric IRP- Public Draft 6-17
Chapter 6 - Generation Resource Options
2009 Electric IRP6-18 Avista Corp
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
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 SO2 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
Hydrokinetics
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 SO2 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 illustrated 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.
Avista Corp 2009 Electric IRP- Public Draft 6-18
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 SO2 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 232.41 197.01
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 SO2 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- Public Draft 6-19
2009 Electric IRPAvista Corp 6-19
Chapter 6 - Generation Resource OptionsChapter 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
ItemNominal $ Real 2009$
Capital recovery and taxes 91.79 77.81
Interconnection capital recovery 0.60 0.51
AFUDC27.23 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 SO2 emission adder 0.00 0.00
Fuel costs 12.06 10.22
Excise taxes and other overheads 0.55 0.47
Total148.17 125.61
Hydrokinetics
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
ItemNominal $ Real 2009$
Capital recovery and taxes 138.89 117.75
Interconnection capital recovery 0.00 0.00
AFUDC7.38 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 SO2 emission adder 0.00 0.00
Fuel costs 0.00 0.00
Excise taxes and other overheads0.07 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 illustrated 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.
Avista Corp 2009 Electric IRP- Public Draft 6-18
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 SO2 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 232.41 197.01
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 SO2 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- Public Draft 6-19
Chapter 6 - Generation Resource Options
2009 Electric IRP6-20 Avista Corp
Chapter 6- Generation Resource Options
Avista Corp 2009 Electric IRP- Public Draft 6-20
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 customer’s 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.]
2009 Electric IRPAvista Corp 6-21
Chapter 6 - Generation Resource OptionsChapter 6- Generation Resource Options
Avista Corp 2009 Electric IRP- Public Draft 6-20
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 customer’s 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.]
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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 AURORAxmp, 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.
Marketplace
AURORAxmp 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 – Public Draft 7-1
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 (levelized) 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
(levelized) 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 utilities to invest in twice as much generation infrastructure.
• New environment-driven investment, combined with higher market prices will
lead to higher retail rates, absent federal initiatives to limit rate increases.
• Carbon legislation is expected to increase 20-year cost (NPV, 2009 dollars) for
electricity generation by $25.7 billion (10 percent) in the Western Interconnect.
2009 Electric IRPAvista Corp 7-1
Chapter 7 - Market AnalysisChapter 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 AURORAxmp, 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.
Marketplace
AURORAxmp 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 – Public Draft 7-1
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 (levelized) 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
(levelized) 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 utilities to invest in twice as much generation infrastructure.
• New environment-driven investment, combined with higher market prices will
lead to higher retail rates, absent federal initiatives to limit rate increases.
• Carbon legislation is expected to increase 20-year cost (NPV, 2009 dollars) for
electricity generation by $25.7 billion (10 percent) in the Western Interconnect.
Chapter 7 - Market Analysis
2009 Electric IRP7-2 Avista Corp
Chapter 7- Market Analysis
Figure 7.1: NERC Interconnection Map
The Western Interconnect is separated from the Eastern Interconnect and ERCOT
systems except by eight inverter stations. The Western Interconnect follows operation
and reliability guidelines administered by the Western Electricity Coordinating Council (WECC).
The Western Interconnect electric system is divided into 16 AURORAxmp modeling
zones based on load concentrations and transmission constraints. After 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
multiple areas. The regional topology in this IRP differs from the previous plan by
reverting to a single zone.
Fundamentals-based electricity models range in their abilities to emulate power system operations. Some account for every bus and transmission line while others utilize
regions or zones. An IRP requires regional price and plant dispatch information. The
specific zones modeled are described in Table 7.1.
Avista Corp 2009 Electric IRP – Public Draft 7-2
Chapter 7- Market Analysis
Table 7.1: AURORAXMP Zones
Northwest- OR/WA/ID/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 forecast was 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 utilities 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 WA/North 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 Washington 1.69%New Mexico 1.83%
Western Oregon 0.01% Colorado 1.48%
Central Washington 2.53% Wyoming 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 – Public Draft 7-3
2009 Electric IRPAvista Corp 7-3
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Figure 7.1: NERC Interconnection Map
The Western Interconnect is separated from the Eastern Interconnect and ERCOT
systems except by eight inverter stations. The Western Interconnect follows operation
and reliability guidelines administered by the Western Electricity Coordinating Council (WECC).
The Western Interconnect electric system is divided into 16 AURORAxmp modeling
zones based on load concentrations and transmission constraints. After 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
multiple areas. The regional topology in this IRP differs from the previous plan by
reverting to a single zone.
Fundamentals-based electricity models range in their abilities to emulate power system operations. Some account for every bus and transmission line while others utilize
regions or zones. An IRP requires regional price and plant dispatch information. The
specific zones modeled are described in Table 7.1.
Avista Corp 2009 Electric IRP – Public Draft 7-2
Chapter 7- Market Analysis
Table 7.1: AURORAXMP Zones
Northwest- OR/WA/ID/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 forecast was 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 utilities 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 WA/North 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 Washington 1.69%New Mexico 1.83%
Western Oregon 0.01% Colorado 1.48%
Central Washington 2.53% Wyoming 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 – Public Draft 7-3
Chapter 7 - Market Analysis
2009 Electric IRP7-4 Avista Corp
Chapter 7- Market Analysis
Transmission
Several regional transmission projects have been announced in the last two years. Many of these projects will move renewable resources to load centers for renewable
portfolio 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 AURORAxmp 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
Project From To YearAvailable CapacityMW
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 Wyoming Utah 2015 3,000
Gateway Central Idaho Utah 2016 1,500
Sunzia/Navajo Transmission Arizona New Mexico 2013 3,000
Wyoming- Colorado Intertie Wyoming Colorado 2013 900
Gateway South Wyoming Utah 2015 3,000
Gateway West Wyoming Idaho 2016 3,000
Hemingway to Boardman Idaho Northwest 2015 1,500
Hemingway to Captain Jack Idaho Southern Oregon 2015 1,500
Total 26,600
Regional Renewable Portfolio 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. AURORAxmp does not have the ability to target RPS levels, so
RPS requirements were input into the model to ensure that renewable resource levels
satisfy state laws.
Avista Corp 2009 Electric IRP – Public Draft 7-4
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 portfolios to meet Western
Interconnect RPS obligations were developed by the Northwest Power and
Conservation Council (NPCC); these percentages were applied to estimated RPS shortfalls 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 illustrates
projected renewable resource additions to the Western Interconnect. Renewable
resources were manually added only to meet RPS requirements, not exceed it.
Chapter 7- Market Analysis
AURORAxmp 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 illustrates 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 will meet requirements with solar and wind; the
Northwest will use wind and hydro; and the Rocky Mountain states will predominately
use wind to meet RPS needs.
Figure 7.2: Renewable Resource Additions to Meet RPS
0
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Solar
Hydro
Geothermal
Biomass
Wind
Energy (aGW)
Resource Deficits
Assumptions are made on when, where and how many of each new resource type will
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 line 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.
Avista Corp 2009 Electric IRP – Public Draft 7-5
The Northwest historically has depended on hydro system flexibility 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.
AURORAxmp adds resources to meet one hour system peaks. To simulate a sustained
2009 Electric IRPAvista Corp 7-5
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Transmission
Several regional transmission projects have been announced in the last two years. Many of these projects will move renewable resources to load centers for renewable
portfolio 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 AURORAxmp 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
ProjectFromToYearAvailableCapacityMW
Canada – PNW Project British Columbia Northwest2018 3,000
PNW – California Project Northwest California2018 3,500
Eastern Nevada Intertie North Nevada South Nevada 2015 1,600
Colstrip Transmission MontanaNorthwest2012 500
Gateway South UtahNevada2014600
Gateway South Wyoming Utah2015 3,000
Gateway Central IdahoUtah2016 1,500
Sunzia/Navajo Transmission ArizonaNew Mexico 2013 3,000
Wyoming- Colorado Intertie Wyoming Colorado2013 900
Gateway South Wyoming Utah2015 3,000
Gateway West Wyoming Idaho2016 3,000
Hemingway to Boardman IdahoNorthwest2015 1,500
Hemingway to Captain Jack IdahoSouthern Oregon 2015 1,500
Total26,600
Regional Renewable Portfolio 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. AURORAxmp does not have the ability to target RPS levels, so
RPS requirements were input into the model to ensure that renewable resource levels
satisfy state laws.
Avista Corp 2009 Electric IRP – Public Draft 7-4
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 portfolios to meet Western
Interconnect RPS obligations were developed by the Northwest Power and
Conservation Council (NPCC); these percentages were applied to estimated RPS shortfalls 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 illustrates
projected renewable resource additions to the Western Interconnect. Renewable
resources were manually added only to meet RPS requirements, not exceed it.
Chapter 7- Market Analysis
AURORAxmp 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 illustrates 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 will meet requirements with solar and wind; the
Northwest will use wind and hydro; and the Rocky Mountain states will predominately
use wind to meet RPS needs.
Figure 7.2: Renewable Resource Additions to Meet RPS
0
10
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s
Solar
Hydro
Geothermal
Biomass
Wind
Energy (aGW)
Resource Deficits
Assumptions are made on when, where and how many of each new resource type will
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 line 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.
Avista Corp 2009 Electric IRP – Public Draft 7-5
The Northwest historically has depended on hydro system flexibility 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.
AURORAxmp adds resources to meet one hour system peaks. To simulate a sustained
Chapter 7 - Market Analysis
2009 Electric IRP7-6 Avista Corp
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 illustrates the Northwest resource
shortfall. Blue bars represent the capacity contributions of hydro, thermal and other
resources. The black line represents forecasted winter peak load plus net firm transfers
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
20
25
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35
40
45
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gi
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t
t
s
Resource Capacity
Peak Load w/ Planning Margin
Peak Load
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.
Avista Corp 2009 Electric IRP – Public Draft 7-6
Chapter 7- Market Analysis
Figure 7.4: Total Western Interconnect Capacity Deficits
0
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70
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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
Region CCCT/SCCT Wind Solar Nuclear Pulv.Coal IGCCCoal
IGCC
Coal w/ 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
Avista Corp 2009 Electric IRP – Public Draft 7-7
Some of the most important drivers of resource costs and values are fuel and
availability. 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.
2009 Electric IRPAvista Corp 7-7
Chapter 7 - Market Analysis
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 illustrates the Northwest resource
shortfall. Blue bars represent the capacity contributions of hydro, thermal and other
resources. The black line represents forecasted winter peak load plus net firm transfers
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 w/ Planning Margin
Peak Load
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.
Avista Corp 2009 Electric IRP – Public Draft 7-6
Chapter 7- Market Analysis
Figure 7.4: Total Western Interconnect Capacity Deficits
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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
Region CCCT/SCCT Wind Solar Nuclear Pulv.Coal IGCCCoal
IGCC
Coal w/ 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
Avista Corp 2009 Electric IRP – Public Draft 7-7
Some of the most important drivers of resource costs and values are fuel and
availability. 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.
Chapter 7 - Market Analysis
2009 Electric IRP7-8 Avista Corp
Chapter 7- Market Analysis
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 will 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 excess productive capacity for natural gas and increase
overall demand growth by 2014. Carbon legislation also will spur incremental demand for a multi-year cycle of gas-fired generation construction. This increased demand, combined
with low investments in drilling in prior years, should push prices 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 price forecast for Henry Hub; the levelized nominal price is
$9.05 per Dth and the real levelized cost is $7.67 per Dth.
Figure 7.5: Henry Hub Natural Gas Price Forecast
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Avista Corp 2009 Electric IRP – Public Draft 7-8
Prices differences across North America depend on demand at various trading hubs and the pipeline constraints between trading hubs. Many pipeline projects have been
Chapter 7- Market Analysis
announced to access cheaper gas supplies located in the Rocky Mountains. Table 7.5 presents western gas basin differentials from Henry Hub and the levelized price of gas
at each basin. Prices converge as new pipelines are built and new sources of gas come
online. To illustrate the seasonality of natural gas prices, the monthly Malin price shape
is provided in Table 7.6 for select years.
Table 7.5: Natural Gas Price Basin Differentials from Henry Hub (Nominal Dollars)
Basin 2010 2015 2020 2025
Nominal
LevelizedCost
2009$
LevelizedCosts
Henry 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% 93.4%
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%
Aug 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 facilities are based on estimates contained in the
AURORAxmp 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 – Public Draft 7-9
2009 Electric IRPAvista Corp 7-9
Chapter 7 - Market AnalysisChapter 7- Market Analysis
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 will 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 excess productive capacity for natural gas and increase
overall demand growth by 2014. Carbon legislation also will spur incremental demand for a multi-year cycle of gas-fired generation construction. This increased demand, combined
with low investments in drilling in prior years, should push prices 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 price forecast for Henry Hub; the levelized nominal price is
$9.05 per Dth and the real levelized cost is $7.67 per Dth.
Figure 7.5: Henry Hub Natural Gas Price Forecast
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Nominal
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Avista Corp 2009 Electric IRP – Public Draft 7-8
Prices differences across North America depend on demand at various trading hubs and the pipeline constraints between trading hubs. Many pipeline projects have been
Chapter 7- Market Analysis
announced to access cheaper gas supplies located in the Rocky Mountains. Table 7.5 presents western gas basin differentials from Henry Hub and the levelized price of gas
at each basin. Prices converge as new pipelines are built and new sources of gas come
online. To illustrate the seasonality of natural gas prices, the monthly Malin price shape
is provided in Table 7.6 for select years.
Table 7.5: Natural Gas Price Basin Differentials from Henry Hub (Nominal Dollars)
Basin 2010 2015 2020 2025
Nominal
LevelizedCost
2009$
LevelizedCosts
Henry 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 $7.24
Table 7.6: Monthly Price Differentials for Malin
Month 2010 2015 2020 2025
Jan 103.7% 99.8% 105.0% 106.9%
Feb 104.7% 104.9% 109.4% 107.6%
Mar 100.7% 103.7% 104.6% 101.8%
Apr 92.3% 90.6% 94.7% 93.4%
May 92.5% 94.2% 95.4% 94.1%
Jun 94.1% 93.6% 96.0% 94.8%
Jul 95.0% 96.4% 97.8% 95.9%
Aug 95.9% 97.1% 97.8% 96.4%
Sep 97.5% 97.7% 95.2% 97.4%
Oct 98.1% 98.8% 95.3% 97.6%
Nov 112.6% 111.0% 104.1% 106.7%
Dec 113.0% 112.0% 104.7% 107.4%
Coal
Coal transportation prices for existing facilities are based on estimates contained in the
AURORAxmp database. For new projects, coal mine costs are based on data provided
by the EIA for Wyoming mine-mouth coal. Transportation costs were added based on
assumed transportation rates and each existing or proposed plant’s distance from the coal supply source. The IRP includes three representative coal plant delivery distances
for all new plants: mine mouth, short haul (250 miles) and long haul (1,000 miles). Coal
details are in Table 7.7.
Avista Corp 2009 Electric IRP – Public Draft 7-9
Chapter 7 - Market Analysis
2009 Electric IRP7-10 Avista Corp
Chapter 7- Market Analysis
Table 7.7: Western Interconnect Coal Prices (2009$)
Coal type $/MMBtu $/short ton
Mine mouth $0.73 $12.41
Short haul $1.26 $21.34
Long haul $2.83 $48.11
Wood/Hog Fuel
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 sawmills 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 availability 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.
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 modeled
using data from the Canadian government.
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.
Avista Corp 2009 Electric IRP – Public Draft 7-10
Chapter 7- Market Analysis
Table 7.8: Northwest Hydro Capacity Factors
Area
Annual Average
Capacity Factor
Eastern Oregon 42%
Eastern WA/North 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%
AURORAxmp 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 portfolio standards, there will 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
Area
Wind
CF (%)
SolarCF(%) Area
WindCF(%)
Solar
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
Avista Corp 2009 Electric IRP – Public Draft 7-11
Greenhouse gas or CO2 legislation is one the greatest fundamental risks facing the
electricity marketplace today. Reducing CO2 emissions from power plants will 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 regulation of carbon emissions, but national legislation is expected to pass in the next
2009 Electric IRPAvista Corp 7-11
Chapter 7 - Market Analysis
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
Wood/Hog Fuel
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 sawmills 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 availability 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.
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 modeled
using data from the Canadian government.
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.
Avista Corp 2009 Electric IRP – Public Draft 7-10
Chapter 7- Market Analysis
Table 7.8: Northwest Hydro Capacity Factors
Area
Annual Average
Capacity Factor
Eastern Oregon 42%
Eastern WA/North 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%
AURORAxmp 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 portfolio standards, there will 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
Area
Wind
CF (%)
SolarCF(%) Area
WindCF(%)
Solar
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
Avista Corp 2009 Electric IRP – Public Draft 7-11
Greenhouse gas or CO2 legislation is one the greatest fundamental risks facing the
electricity marketplace today. Reducing CO2 emissions from power plants will 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 regulation of carbon emissions, but national legislation is expected to pass in the next
Chapter 7 - Market Analysis
2009 Electric IRP7-12 Avista Corp
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 will 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 will 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 will 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 will 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 illustrates 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.
Avista Corp 2009 Electric IRP – Public Draft 7-12
Chapter 7- Market Analysis
Figure 7.6: Price of Carbon Credits
$0
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Figure 7.7: Cost of Carbon Credits
Avista Corp 2009 Electric IRP – Public Draft 7-13
$0
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Coal- $3.00
CCCT- $7.50 Gas
CCCT- $5.00 Gas
CCCT- $10.00 Gas
2009 Electric IRPAvista Corp 7-13
Chapter 7 - Market Analysis
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 will 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 will 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 will 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 will 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 illustrates 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.
Avista Corp 2009 Electric IRP – Public Draft 7-12
Chapter 7- Market Analysis
Figure 7.6: Price of Carbon Credits
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Figure 7.7: Cost of Carbon Credits
Avista Corp 2009 Electric IRP – Public Draft 7-13
$0
$20
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$180
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Coal- $1.00
Coal- $3.00
CCCT- $7.50 Gas
CCCT- $5.00 Gas
CCCT- $10.00 Gas
Chapter 7 - Market Analysis
2009 Electric IRP7-14 Avista Corp
Chapter 7- Market Analysis
Risk Analysis
Base assumptions in this chapter were modeled stochastically to reflect that we do not know what future conditions will 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 will likely
require higher carbon prices to ensure that carbon reduction goals are met. The
increased costs will 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 illustrates 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
GasPrices GHG Prices
New
CoalPrices
Hog
FuelPrices LoadGrowth
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 difficult to determine without macroeconomic models capable of determining financial impacts outside of the electric industry. Even
with rules in place, carbon prices will 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 bill, 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 will be the probability of a certain base price level.
Avista Corp 2009 Electric IRP – Public Draft 7-14
Chapter 7- Market Analysis
Table 7.11: EPA Carbon Study (Nominal Price per Short/Ton)
Study Weight 2012 2020 2025
ADAGE 10% 28.60 50.89 72.40
IGEM 3% 40.50 70.15 98.04
ADAGE - Low Intl 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 IRP.
See Table 7.12 for the 10 base carbon scenarios modeled for this IRP.
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 prices 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.
Avista Corp 2009 Electric IRP – Public Draft 7-15
The correlation between carbon and natural gas is likely to be high because gas-fired
resources set the marginal price of electricity in most markets. A 50-percent correlation
between carbon and natural gas is used for this IRP. A 90-percent correlation scenario
2009 Electric IRPAvista Corp 7-15
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Risk Analysis
Base assumptions in this chapter were modeled stochastically to reflect that we do not know what future conditions will 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 will likely
require higher carbon prices to ensure that carbon reduction goals are met. The
increased costs will 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 illustrates 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
GasPricesGHG Prices
New
CoalPrices
Hog
FuelPricesLoadGrowth
Gas Prices 1
GHG Prices 0.501
New Coal Prices -0.251
Hog Fuel Prices 0.50 0.501
Load Growth -0.25 -0.25-0.51
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 difficult to determine without macroeconomic models capable of determining financial impacts outside of the electric industry. Even
with rules in place, carbon prices will 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 bill, 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 will be the probability of a certain base price level.
Avista Corp 2009 Electric IRP – Public Draft 7-14
Chapter 7- Market Analysis
Table 7.11: EPA Carbon Study (Nominal Price per Short/Ton)
Study Weight 2012 2020 2025
ADAGE 10% 28.60 50.89 72.40
IGEM 3% 40.50 70.15 98.04
ADAGE - Low Intl 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 IRP.
See Table 7.12 for the 10 base carbon scenarios modeled for this IRP.
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 prices 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.
Avista Corp 2009 Electric IRP – Public Draft 7-15
The correlation between carbon and natural gas is likely to be high because gas-fired
resources set the marginal price of electricity in most markets. A 50-percent correlation
between carbon and natural gas is used for this IRP. A 90-percent correlation scenario
Chapter 7 - Market Analysis
2009 Electric IRP7-16 Avista Corp
Chapter 7- Market Analysis
found no material impact on the results. The method for obtaining carbon prices and their correlation to other market drivers will be an ongoing IRP process task.
Figure 7.8: Distribution of Annual Average Carbon Prices for 2012
0%
2%
4%
6%
8%
10%
12%
14%
$0 $3 $6 $9
$1
2
$1
5
$1
8
$2
1
$2
4
$2
7
$3
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$3
3
$3
6
$3
9
carbon price per short ton
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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 will 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 illustrates 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.
Avista Corp 2009 Electric IRP – Public Draft 7-16
Chapter 7- Market Analysis
Figure 7.9: Distribution of Annual Average Natural Gas Prices for 2012
0%
2%
4%
6%
8%
10%
12%
$2
.
0
0
$3
.
5
0
$5
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price per Dth
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Figure 7.10: Henry Hub Natural Gas Distributions
$0
$5
$10
$15
$20
$25
$30
$35
$40
20
1
0
20
1
1
20
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Avista Corp 2009 Electric IRP – Public Draft 7-17
2009 Electric IRPAvista Corp 7-17
Chapter 7 - Market AnalysisChapter 7- Market Analysis
found no material impact on the results. The method for obtaining carbon prices and their correlation to other market drivers will be an ongoing IRP process task.
Figure 7.8: Distribution of Annual Average Carbon Prices for 2012
0%
2%
4%
6%
8%
10%
12%
14%
$0$3$6$9
$1
2
$1
5
$1
8
$2
1
$2
4
$2
7
$3
0
$3
3
$3
6
$3
9
carbon price per short ton
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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 will 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 illustrates 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.
Avista Corp 2009 Electric IRP – Public Draft 7-16
Chapter 7- Market Analysis
Figure 7.9: Distribution of Annual Average Natural Gas Prices for 2012
0%
2%
4%
6%
8%
10%
12%
$2
.
0
0
$3
.
5
0
$5
.
0
0
$6
.
5
0
$8
.
0
0
$9
.
5
0
$1
1
.
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0
$1
2
.
5
0
$1
4
.
0
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7
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price per Dth
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Figure 7.10: Henry Hub Natural Gas Distributions
$0
$5
$10
$15
$20
$25
$30
$35
$40
20
1
0
20
1
1
20
1
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Avista Corp 2009 Electric IRP – Public Draft 7-17
Chapter 7 - Market Analysis
2009 Electric IRP7-18 Avista Corp
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.
Figure 7.11: Random Draws from the Henry Hub Price Distribution
0
10
20
30
40
50
60
70
80
90
100
20
1
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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 probability) 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 illustrates the annual load growth trajectory for the Western Interconnect in 10 selected iterations.
Avista Corp 2009 Electric IRP – Public Draft 7-18
Chapter 7- Market Analysis
Figure 7.12: Random Draws Load Forecast with Year 2009 at 100
100
105
110
115
120
125
130
135
140
145
20
0
9
20
1
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1
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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 will continue to assess the
correlations and variation for major drivers of the electricity market. A study of historical
weather-adjusted load growth will 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 (i.e., peaking
generation). For example, without regional correlation the volatility would be measured,
but would not adequately represent heat waves and cold snaps occurring across the Western Interconnect.
Avista Corp 2009 Electric IRP – Public Draft 7-19
Tables 7.13 and 7.14 illustrate the correlations used in the IRP. The correlation statistics
are relative to the Northwest load area (Oregon, Washington, and North Idaho).
2009 Electric IRPAvista Corp 7-19
Chapter 7 - Market AnalysisChapter 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.
Figure 7.11: Random Draws from the Henry Hub Price Distribution
0
10
20
30
40
50
60
70
80
90
100
20
1
0
20
1
1
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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 probability) 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 illustrates the annual load growth trajectory for the Western Interconnect in 10 selected iterations.
Avista Corp 2009 Electric IRP – Public Draft 7-18
Chapter 7- Market Analysis
Figure 7.12: Random Draws Load Forecast with Year 2009 at 100
100
105
110
115
120
125
130
135
140
145
20
0
9
20
1
0
20
1
1
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1
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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 will continue to assess the
correlations and variation for major drivers of the electricity market. A study of historical
weather-adjusted load growth will 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 (i.e., peaking
generation). For example, without regional correlation the volatility would be measured,
but would not adequately represent heat waves and cold snaps occurring across the Western Interconnect.
Avista Corp 2009 Electric IRP – Public Draft 7-19
Tables 7.13 and 7.14 illustrate the correlations used in the IRP. The correlation statistics
are relative to the Northwest load area (Oregon, Washington, and North Idaho).
Chapter 7 - Market Analysis
2009 Electric IRP7-20 Avista Corp
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 coefficient 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 Sig 0.312
Baja 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 0.425 Not Sig 0.402 0.493 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 0.469 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 0.499 0.334 Mix Mix Not Sig 0.164
Utah 0.482 Not Sig 0.259 Mix 0.077 0.425
Wyoming 0.486 Not Sig 0.167 Mix Not Sig 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
Alberta 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 Sig Mix Mix Not Sig Not Sig
Baja 0.689 0.757 Mix Mix 0.072 0.456
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 0.426 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 0.420 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 0.487 0.249 Mix Mix Not Sig Mix
Utah 0.400 Mix 0.243 0.161 0.076 Not Sig
Wyoming 0.240 Mix Mix Mix 0.072 Not Sig
California North 0.707 0.503 Mix Mix 0.560 0.764
Avista Corp 2009 Electric IRP – Public Draft 7-20
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 Coefficient 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% 9.0% 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 – Public Draft 7-21
2009 Electric IRPAvista Corp 7-21
Chapter 7 - Market AnalysisChapter 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 coefficient 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
Alberta0.674 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 Sig 0.312
Baja 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 0.425 Not Sig 0.402 0.493 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 0.469 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 0.499 0.334 Mix Mix Not Sig 0.164
Utah 0.482 Not Sig 0.259 Mix 0.077 0.425
Wyoming 0.486 Not Sig 0.167 Mix Not Sig 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
Alberta 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 Sig Mix Mix Not Sig Not Sig
Baja 0.689 0.757 Mix Mix 0.072 0.456
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 0.426 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 0.420 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 0.487 0.249 Mix Mix Not Sig Mix
Utah 0.400 Mix 0.243 0.161 0.076 Not Sig
Wyoming 0.240 Mix Mix Mix 0.072 Not Sig
California North 0.707 0.503 Mix Mix 0.560 0.764
Avista Corp 2009 Electric IRP – Public Draft 7-20
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 Coefficient 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% 9.0% 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 – Public Draft 7-21
Chapter 7 - Market Analysis
2009 Electric IRP7-22 Avista Corp
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 will
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 availability of hog fuel varies with the economy. The IRP stochastic analysis assumes a standard
deviation of 10 percent. Further demand for wood residues will increase with aggressive
greenhouse gas and renewable portfolio standard legislation. These environmental
concerns will 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 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 Benefits 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 will 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.
Avista Corp 2009 Electric IRP – Public Draft 7-22
Chapter 7- Market Analysis
Figure 7.13: Distribution of Avista’s Hydro Generation
0%
2%
4%
6%
8%
10%
12%
14%
16%
18%
350 400 450 500 550 600 650 700 750
average megawatts
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WindWind 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 volatility 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. Variability is modeled similar to how AURORAxmp 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.
Avista Corp 2009 Electric IRP – Public Draft 7-23
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
2009 Electric IRPAvista Corp 7-23
Chapter 7 - Market AnalysisChapter 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 will
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 availability of hog fuel varies with the economy. The IRP stochastic analysis assumes a standard
deviation of 10 percent. Further demand for wood residues will increase with aggressive
greenhouse gas and renewable portfolio standard legislation. These environmental
concerns will 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 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 Benefits 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 will 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.
Avista Corp 2009 Electric IRP – Public Draft 7-22
Chapter 7- Market Analysis
Figure 7.13: Distribution of Avista’s Hydro Generation
0%
2%
4%
6%
8%
10%
12%
14%
16%
18%
350 400 450 500 550 600 650 700 750
average megawatts
pe
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7
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1
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P
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c
e
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t
i
l
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)
WindWind 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 volatility 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. Variability is modeled similar to how AURORAxmp 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.
Avista Corp 2009 Electric IRP – Public Draft 7-23
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
Chapter 7 - Market Analysis
2009 Electric IRP7-24 Avista Corp
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
0%
20%
40%
60%
80%
100%
0%
10
%
20
%
30
%
40
%
50
%
60
%
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10
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percent of time
ca
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On-Peak
Off-Peak
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 portfolio 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. Resources generating during on-peak hours generally contribute higher margins to
Avista’s resource portfolio than resources with intermediate and unpredictable output.
Avista Corp 2009 Electric IRP – Public Draft 7-24
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.
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
Chapter 7- Market Analysis
requirements, instead of using the summation of capacity needs of each utility 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.
AURORAxmp 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
portfolio. 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 variability 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 will primarily be natural gas-fired. Renewable resources added to meet
renewable portfolio standards help fill system energy needs, but fail to provide equivalent capacity for system reliability. 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 – Public Draft 7-25
2009 Electric IRPAvista Corp 7-25
Chapter 7 - Market AnalysisChapter 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
0%
20%
40%
60%
80%
100%
0%
10
%
20
%
30
%
40
%
50
%
60
%
70
%
80
%
90
%
10
0
%
percent of time
ca
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f
a
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t
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On-Peak
Off-Peak
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 portfolio 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. Resources generating during on-peak hours generally contribute higher margins to
Avista’s resource portfolio than resources with intermediate and unpredictable output.
Avista Corp 2009 Electric IRP – Public Draft 7-24
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.
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
Chapter 7- Market Analysis
requirements, instead of using the summation of capacity needs of each utility 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.
AURORAxmp 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
portfolio. 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 variability 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 will primarily be natural gas-fired. Renewable resources added to meet
renewable portfolio standards help fill system energy needs, but fail to provide equivalent capacity for system reliability. 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 – Public Draft 7-25
Chapter 7 - Market Analysis
2009 Electric IRP7-26 Avista Corp
Chapter 7- Market Analysis
Figure 7.15: Base Case New Resource Selection
(5)
10
25
40
55
70
85
100
115
130
20
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Geothermal BiomassHydroWindSolarCoal SeqCCCTSCCTCoal- retire NG- retireOil- 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 variability. 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.
Avista Corp 2009 Electric IRP – Public Draft 7-26
Chapter 7- Market Analysis
Figure 7.16: Annual Flat Mid-Columbia Electric Prices
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Figure 7.17: Selected Mid-Columbia Annual Flat Price Duration Curves
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Avista Corp 2009 Electric IRP – Public Draft 7-27
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.
2009 Electric IRPAvista Corp 7-27
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Figure 7.15: Base Case New Resource Selection
(5)
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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 variability. 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.
Avista Corp 2009 Electric IRP – Public Draft 7-26
Chapter 7- Market Analysis
Figure 7.16: Annual Flat Mid-Columbia Electric Prices
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Figure 7.17: Selected Mid-Columbia Annual Flat Price Duration Curves
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2010 2014
2017 2020
Avista Corp 2009 Electric IRP – Public Draft 7-27
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 $32.71 per MWh in 2029.
Chapter 7 - Market Analysis
2009 Electric IRP7-28 Avista Corp
Chapter 7- Market Analysis
Table 7.17: Annual Mid-Columbia Electric Prices ($/MWh)
Deterministic Stochastic Mean
Year OnPeak OffPeak Flat OnPeak OffPeak Flat
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
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 will lower emissions at twice the level as the West, but that the West would reduce it emissions by
a higher percentage.
Avista Corp 2009 Electric IRP – Public Draft 7-28
Chapter 7- Market Analysis
Figure 7.18: Western States Greenhouse Gas Emissions
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Resource Dispatch
State-level RPS and carbon legislation will change resource dispatch decisions and affect future power supply expenses. Figure 7.19 illustrates 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 will change the electric marketplace. Policy changes are
likely to move the electric generation fleet toward its most volatile contributor—natural gas. These policies will 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 built to satisfy RPS and emissions performance standards. Wholesale prices will increase with the effects of the changing resource dispatch driven by carbon emission limitations. New environment-driven investment, combined with
higher market prices, will lead to higher retail rates absent federal action.
Avista Corp 2009 Electric IRP – Public Draft 7-29
2009 Electric IRPAvista Corp 7-29
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Table 7.17: Annual Mid-Columbia Electric Prices ($/MWh)
DeterministicStochastic Mean
YearOnPeakOffPeakFlatOnPeakOffPeakFlat
2010 53.86 40.08 47.96 55.44 41.10 49.29
2011 54.40 40.35 48.38 56.70 42.10 50.44
2012 59.09 45.83 53.39 62.56 48.49 56.51
2013 63.62 50.37 57.95 68.92 54.34 62.68
2014 71.19 56.95 65.09 76.76 60.98 70.00
2015 80.72 65.87 74.36 86.94 70.07 79.71
2016 90.50 74.69 83.73 97.00 78.71 89.17
2017 95.46 78.86 88.32 103.78 84.00 95.27
2018107.32 91.28 100.45 119.24 97.01109.72
2019112.00 95.68 105.01 126.03 102.86 116.10
2020114.88 98.22 107.75 128.40 104.45 118.15
2021116.16 99.70 109.11 129.17 105.09 118.86
2022117.84 101.50 110.84 131.07 106.60 120.59
2023123.03 106.01 115.71 138.34 112.73 127.33
2024128.07 110.46 120.53 142.84 116.61 131.61
2025132.85 114.43 124.97 152.13 123.83 140.01
2026137.71 119.03 129.71 158.82 129.10 146.09
2027143.78 124.25 135.42 161.94 131.58 148.94
2028148.88 128.60 140.16 166.20 135.23 152.89
2029153.78 133.09 144.92 175.56 142.85 161.55
Nominal Levelized 93.10 77.39 86.36 102.4182.17 93.74
2009$ Levelized 79.01 65.68 73.30 86.9269.75 79.56
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 will lower emissions at twice the level as the West, but that the West would reduce it emissions by
a higher percentage.
Avista Corp 2009 Electric IRP – Public Draft 7-28
Chapter 7- Market Analysis
Figure 7.18: Western States Greenhouse Gas Emissions
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2005 Levels
1990 Levels
Resource Dispatch
State-level RPS and carbon legislation will change resource dispatch decisions and affect future power supply expenses. Figure 7.19 illustrates 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 will change the electric marketplace. Policy changes are
likely to move the electric generation fleet toward its most volatile contributor—natural gas. These policies will 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 built to satisfy RPS and emissions performance standards. Wholesale prices will increase with the effects of the changing resource dispatch driven by carbon emission limitations. New environment-driven investment, combined with
higher market prices, will lead to higher retail rates absent federal action.
Avista Corp 2009 Electric IRP – Public Draft 7-29
Chapter 7 - Market Analysis
2009 Electric IRP7-30 Avista Corp
Chapter 7- Market Analysis
Figure 7.19: Base Case Western Interconnect Resource Energy
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Scenario Analysis
Avista Corp 2009 Electric IRP – Public Draft 7-30
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 IRP.
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.
Figure 7.20: Unconstrained Carbon Emissions Resource Selection
(5)
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Mid-Columbia market prices would be lower absent carbon legislation. The deterministic
analysis found prices would be $22.43 per MWh lower on a nominal levelized 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 – Public Draft 7-31
2009 Electric IRPAvista Corp 7-31
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Figure 7.19: Base Case Western Interconnect Resource Energy
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Scenario Analysis
Avista Corp 2009 Electric IRP – Public Draft 7-30
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 IRP.
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.
Figure 7.20: Unconstrained Carbon Emissions Resource Selection
(5)
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Geothermal BiomassHydroWindCoalSolarCCCTSCCTCoal- retire NG- retireOil- retire Energy (aGW)
Mid-Columbia market prices would be lower absent carbon legislation. The deterministic
analysis found prices would be $22.43 per MWh lower on a nominal levelized 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 – Public Draft 7-31
Chapter 7 - Market Analysis
2009 Electric IRP7-32 Avista Corp
Chapter 7- Market Analysis
Figure 7.21: Mid-Columbia Prices Comparison with and without Carbon Legislation
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Avista Corp 2009 Electric IRP – Public Draft 7-32
Figure 7.22 illustrates 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
billion in present value terms (2009 dollars). Annual cost increases are shown in Figure
7.24. Carbon legislation adds $328 million in present value term (2009 dollars) over the study period for operations, but reduces capital and other non-O&M costs by $17.1 billion. In total, carbon legislation on a 20 year net present value calculation will
increase costs by $25.7 billion (10 percent).
Chapter 7- Market Analysis
Figure 7.22: Western U.S. Carbon Emissions Comparison
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Figure 7.23: Unconstrained Carbon Scenrio Resource Dispatch
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Avista Corp 2009 Electric IRP – Public Draft 7-33
2009 Electric IRPAvista Corp 7-33
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Figure 7.21: Mid-Columbia Prices Comparison with and without Carbon Legislation
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Avista Corp 2009 Electric IRP – Public Draft 7-32
Figure 7.22 illustrates 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
billion in present value terms (2009 dollars). Annual cost increases are shown in Figure
7.24. Carbon legislation adds $328 million in present value term (2009 dollars) over the study period for operations, but reduces capital and other non-O&M costs by $17.1 billion. In total, carbon legislation on a 20 year net present value calculation will
increase costs by $25.7 billion (10 percent).
Chapter 7- Market Analysis
Figure 7.22: Western U.S. Carbon Emissions Comparison
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Figure 7.23: Unconstrained Carbon Scenrio Resource Dispatch
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Avista Corp 2009 Electric IRP – Public Draft 7-33
Chapter 7 - Market Analysis
2009 Electric IRP7-34 Avista Corp
Chapter 7- Market Analysis
Figure 7.24: Western Interconnect Fuel Cost Comparison
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Unconstrained Carbon
High and Low Natural Gas Prices The High and Low Natural Gas Price scenarios illustrate 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
study and only allow nominal prices to increase with inflation. The levelized price is
$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.
Avista Corp 2009 Electric IRP – Public Draft 7-34
Chapter 7- Market Analysis
Figure 7.25: Henry Hub Prices for High and Low Natural Gas Price Scenarios
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Low Gas Prices
High Gas Prices
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 same 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 AURORAxmp 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.
Avista Corp 2009 Electric IRP – Public Draft 7-35
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.
2009 Electric IRPAvista Corp 7-35
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Figure 7.24: Western Interconnect Fuel Cost Comparison
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Base Case Difference
Unconstrained Carbon
High and Low Natural Gas Prices The High and Low Natural Gas Price scenarios illustrate 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
study and only allow nominal prices to increase with inflation. The levelized price is
$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.
Avista Corp 2009 Electric IRP – Public Draft 7-34
Chapter 7- Market Analysis
Figure 7.25: Henry Hub Prices for High and Low Natural Gas Price Scenarios
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Base Case
Low Gas Prices
High Gas Prices
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 same 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 AURORAxmp 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.
Avista Corp 2009 Electric IRP – Public Draft 7-35
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.
Chapter 7 - Market Analysis
2009 Electric IRP7-36 Avista Corp
Chapter 7- Market Analysis
Figure 7.26: Greenhouse Gas Prices for High and Low Natural Gas Price Scenarios
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Figure 7.27: High Natural Gas Prices Scenario Resource Selection
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Avista Corp 2009 Electric IRP – Public Draft 7-36
Chapter 7- Market Analysis
Figure 7.28: Low Natural Gas Prices Scenario Resource Selection
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Geothermal BiomassHydroWindSolarCoal SeqNuclearCCCTSCCTCoal- retireNG- retire Oil- retireEnergy (aGW)
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.
Avista Corp 2009 Electric IRP – Public Draft 7-37
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.
2009 Electric IRPAvista Corp 7-37
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Figure 7.26: Greenhouse Gas Prices for High and Low Natural Gas Price Scenarios
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Figure 7.27: High Natural Gas Prices Scenario Resource Selection
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Avista Corp 2009 Electric IRP – Public Draft 7-36
Chapter 7- Market Analysis
Figure 7.28: Low Natural Gas Prices Scenario Resource Selection
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Geothermal BiomassHydroWindSolarCoal SeqNuclearCCCTSCCTCoal- retireNG- retire Oil- retireEnergy (aGW)
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.
Avista Corp 2009 Electric IRP – Public Draft 7-37
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.
Chapter 7 - Market Analysis
2009 Electric IRP7-38 Avista Corp
Chapter 7- Market Analysis
Figure 7.29: Mid-Columbia Electric Price Forecast
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Figure 7.30: Resource Dispatch- High Gas Price Scenario
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Avista Corp 2009 Electric IRP – Public Draft 7-38
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 officials 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 still 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 – Public Draft 7-39
2009 Electric IRPAvista Corp 7-39
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Figure 7.29: Mid-Columbia Electric Price Forecast
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Figure 7.30: Resource Dispatch- High Gas Price Scenario
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HydroNuclearGeothermalCoalIGCC CoalIGCC Coal SeqOther RenewableWindSolar
OilGasGas PeakersTotal Resource Output
Avista Corp 2009 Electric IRP – Public Draft 7-38
Chapter 7- Market Analysis
Figure 7.31: Resource Dispatch- Low Gas Price Scenario
0%
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Hydro Nuclear GeothermalCoalIGCC Coal IGCC Coal SeqOther Renewable Wind SolarOilGasGas PeakersTotal Resource Output
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 officials 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 still 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 – Public Draft 7-39
Chapter 7 - Market Analysis
2009 Electric IRP7-40 Avista Corp
Chapter 7- Market Analysis
Figure 7.32: Solar Saturation Scenario Resource Selection
(5)
10
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Geothermal BiomassHydroWindSolarCoal SeqCCCTSCCTCoal- retire NG- retireOil- retire Energy (aGW)
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 still 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
illustrates that market prices in the Northwest will not radically change in spite of a large
amount of new solar generation being added to the system, but greenhouse gas emissions will fall along with natural gas prices.
Avista Corp 2009 Electric IRP – Public Draft 7-40
Chapter 7- Market Analysis
Figure 7.33: Western Interconnect Carbon Emissions Comparison
150
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Base Case
2005 Levels
1990 Levels
Solar Saturation
Figure 7.34: Resource Dispatch- Solar Saturation Scenario
Avista Corp 2009 Electric IRP – Public Draft 7-41
0%
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20
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Hydro Nuclear GeothermalCoalIGCC Coal IGCC Coal SeqOther Renewable Wind SolarOilGasGas Peakers
Total Resource Output
2009 Electric IRPAvista Corp 7-41
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Figure 7.32: Solar Saturation Scenario Resource Selection
(5)
10
25
40
55
70
85
100
115
130
145
160
20
1
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GeothermalBiomassHydroWindSolarCoal SeqCCCTSCCTCoal- retireNG- retireOil- retireEnergy (aGW)
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 still 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
illustrates that market prices in the Northwest will not radically change in spite of a large
amount of new solar generation being added to the system, but greenhouse gas emissions will fall along with natural gas prices.
Avista Corp 2009 Electric IRP – Public Draft 7-40
Chapter 7- Market Analysis
Figure 7.33: Western Interconnect Carbon Emissions Comparison
150
170
190
210
230
250
270
290
310
330
350
20
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Base Case
2005 Levels
1990 Levels
Solar Saturation
Figure 7.34: Resource Dispatch- Solar Saturation Scenario
Avista Corp 2009 Electric IRP – Public Draft 7-41
0%
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Hydro Nuclear GeothermalCoalIGCC Coal IGCC Coal SeqOther Renewable Wind SolarOilGasGas Peakers
Total Resource Output
Chapter 7 - Market Analysis
2009 Electric IRP7-42 Avista Corp
Chapter 7- Market Analysis
Avista Corp 2009 Electric IRP – Public Draft 7-42
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 difficult 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 will increase because new capacity and transmission resources are needed to replace aging
resources and meet new load growth. Carbon and RPS legislation will diversify fuel
supplies, but will also increase demand for cleaner burning natural gas.
2009 Electric IRPAvista Corp 7-43
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Avista Corp 2009 Electric IRP – Public Draft 7-42
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 difficult 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 will increase because new capacity and transmission resources are needed to replace aging
resources and meet new load growth. Carbon and RPS legislation will diversify fuel
supplies, but will also increase demand for cleaner burning natural gas.
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3
Chapter 8- Preferred Resource 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 the planning 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
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 portfolio 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 utility planning. It also is more actionable and
controllable by the utility, allowing for less reliance on third-party developers that might or
might not respond to utility request for proposal (RFP) efforts. It is likely that the 2009
PRS will 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 needs 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 will 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 facilities over the next five years.
Avista Corp 2009 Electric IRP- Public Draft 8-1
2009 Electric IRPAvista Corp 8-1
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource 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 the planning 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
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 portfolio 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 utility planning. It also is more actionable and
controllable by the utility, allowing for less reliance on third-party developers that might or
might not respond to utility request for proposal (RFP) efforts. It is likely that the 2009
PRS will 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 needs 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 will 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 facilities over the next five years.
Avista Corp 2009 Electric IRP- Public Draft 8-1
Site of the Proposed Reardan Wind Project
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-2 Avista Corp
Chapter 8- Preferred Resource Strategy
Figure 8.1: Resource Acquisition History
1,100
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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 portfolio comparison approach. The
AURORAxmp model, discussed in the Market Analysis chapter, calculates the operating
margin (value) of Avista’s existing resource portfolio 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.
PRiSMAvista 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.
Avista Corp 2009 Electric IRP- Public Draft 8-2
Chapter 8- Preferred Resource Strategy
Overview of the PRiSM Model PRiSM has six basic inputs:
1. Load deficits (energy and capacity);
2. RPS standards;
3. Avista’s existing portfolio’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 utility
interests (i.e., customers and shareholders). A simplified view of the linear programming
objective function formula is provided below.
PRiSM Objective Function
Minimize: (X1 * NPV2010-2019) + (X2 * NPV2010-2029) + (X3 * NPV2010-2059)
Where:X1 = Weight of net costs over the first 10 years;
X2 = Weight of net costs over 20 years of the 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 Efficient Frontier. The 2009 IRP
Efficient Frontier captures the optimal resource selection, given constraints at each level
of cost and risk. Figure 8.2 illustrates the Efficient 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 portfolio. The loss of these options further limits resource choices compared with the 2007 IRP. Avista does not expect it will be able to acquire sufficient
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- Public Draft 8-3
2009 Electric IRPAvista Corp 8-3
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
Figure 8.1: Resource Acquisition History
1,100
1,300
1,500
1,700
1,900
2,100
2,300
2,500
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9
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1/
2

C
S
2
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 portfolio comparison approach. The
AURORAxmp model, discussed in the Market Analysis chapter, calculates the operating
margin (value) of Avista’s existing resource portfolio 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.
PRiSMAvista 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.
Avista Corp 2009 Electric IRP- Public Draft 8-2
Chapter 8- Preferred Resource Strategy
Overview of the PRiSM Model PRiSM has six basic inputs:
1. Load deficits (energy and capacity);
2. RPS standards;
3. Avista’s existing portfolio’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 utility
interests (i.e., customers and shareholders). A simplified view of the linear programming
objective function formula is provided below.
PRiSM Objective Function
Minimize: (X1 * NPV2010-2019) + (X2 * NPV2010-2029) + (X3 * NPV2010-2059)
Where:X1 = Weight of net costs over the first 10 years;
X2 = Weight of net costs over 20 years of the 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 Efficient Frontier. The 2009 IRP
Efficient Frontier captures the optimal resource selection, given constraints at each level
of cost and risk. Figure 8.2 illustrates the Efficient 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 portfolio. The loss of these options further limits resource choices compared with the 2007 IRP. Avista does not expect it will be able to acquire sufficient
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- Public Draft 8-3
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-4 Avista Corp
Chapter 8- Preferred Resource 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: Efficient Frontier Curve
cost
ri
s
k
Least Cost
Least Risk
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 performance standard (SB 6001).
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 perfectly balanced with load each
year. PRiSM is allowed to model Avista’s portfolio to be as much as 50 MW short or 200 MW long in any given planning year.
Washington’s RPS fundamentally changed how Avista plans to meet future loads.
Historically an Efficient Frontier was created with the least-cost strategy on one end and
the least-risk strategy on the other. Next, management decided where they wanted to be on the continuums, based on risk appetite. Recent least-cost strategies typically
Avista Corp 2009 Electric IRP- Public Draft 8-4
Chapter 8- Preferred Resource Strategy
consisted of gas-fired resources. Portfolios 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 illustration, these strategies are
represented on the Efficient 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 efficient frontier, illustrated 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 still
complies with state laws, rather than a portfolio selected on a full vetting of cost and
risk.
Figure 8.3: Efficient Frontier in a Constrained Environment
cost
ri
s
k
Least Cost
Least Risk
PRS
Resource Shortages
Avista has adequate resources to meet annual physical energy and capacity needs until
2015. See Figure 8.4. The graphic accounts for energy efficiency and conservation
program impacts on the portfolio. Absent these efficiency 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 resources often will be
displaced with less expensive purchases from the wholesale marketplace. On an annual
Avista Corp 2009 Electric IRP- Public Draft 8-5
2009 Electric IRPAvista Corp 8-5
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource 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: Efficient Frontier Curve
cost
ri
s
k
Least Cost
Least Risk
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 performance standard (SB 6001).
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 perfectly balanced with load each
year. PRiSM is allowed to model Avista’s portfolio to be as much as 50 MW short or 200 MW long in any given planning year.
Washington’s RPS fundamentally changed how Avista plans to meet future loads.
Historically an Efficient Frontier was created with the least-cost strategy on one end and
the least-risk strategy on the other. Next, management decided where they wanted to be on the continuums, based on risk appetite. Recent least-cost strategies typically
Avista Corp 2009 Electric IRP- Public Draft 8-4
Chapter 8- Preferred Resource Strategy
consisted of gas-fired resources. Portfolios 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 illustration, these strategies are
represented on the Efficient 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 efficient frontier, illustrated 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 still
complies with state laws, rather than a portfolio selected on a full vetting of cost and
risk.
Figure 8.3: Efficient Frontier in a Constrained Environment
cost
ri
s
k
Least Cost
Least Risk
PRS
Resource Shortages
Avista has adequate resources to meet annual physical energy and capacity needs until
2015. See Figure 8.4. The graphic accounts for energy efficiency and conservation
program impacts on the portfolio. Absent these efficiency 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 resources often will be
displaced with less expensive purchases from the wholesale marketplace. On an annual
Avista Corp 2009 Electric IRP- Public Draft 8-5
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-6 Avista Corp
Chapter 8- Preferred Resource 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 will retain large energy surpluses.
Figure 8.4: Physical Resource Positions
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-800
-600
-400
-200
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Winter Capacity
Summer Capacity
Annual Energy
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.
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
Avista Corp 2009 Electric IRP- Public Draft 8-6
Chapter 8- Preferred Resource 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 Portfolio Standards (I-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 utilities to acquire
all cost effective conservation and energy efficiency 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 will need its next block of qualifying resources prior to 2016 and another
block will be required prior to 2020. Assuming Avista meets RPS requirements with
wind, as illustrated later in this section, it will require 150 MW of nameplate capacity by
2016 and a similar amount by 2020. After 2020, Avista will continue to acquire renewable resources to meet load growth as specified in I-937.
Figure 8.5: REC Requirement vs. Qualifying RECs for Washington State RPS
0
20
40
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80
100
120
140
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Avista Corp 2009 Electric IRP- Public Draft 8-7
2009 Electric IRPAvista Corp 8-7
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource 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 will retain large energy surpluses.
Figure 8.4: Physical Resource Positions
-1000
-800
-600
-400
-200
0
200
400
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Winter Capacity
Summer Capacity
Annual Energy
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.
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
Avista Corp 2009 Electric IRP- Public Draft 8-6
Chapter 8- Preferred Resource 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 Portfolio Standards (I-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 utilities to acquire
all cost effective conservation and energy efficiency 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 will need its next block of qualifying resources prior to 2016 and another
block will be required prior to 2020. Assuming Avista meets RPS requirements with
wind, as illustrated later in this section, it will require 150 MW of nameplate capacity by
2016 and a similar amount by 2020. After 2020, Avista will continue to acquire renewable resources to meet load growth as specified in I-937.
Figure 8.5: REC Requirement vs. Qualifying RECs for Washington State RPS
0
20
40
60
80
100
120
140
160
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Avista Corp 2009 Electric IRP- Public Draft 8-7
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-8 Avista Corp
Chapter 8- Preferred Resource Strategy
Preferred Resource Strategy
The 2009 PRS consists of hydro upgrades, wind, conservation, distribution efficiency
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.
Avista will 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
Falls. 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
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 tolling agreement. Table 8.1 presents PRS resources.
Table 8.1: 2009 Preferred Resource Strategy
Resource
By the End of Year
Nameplate
(MW)
Energy
(aMW)
NW Wind 2012 150.0 48.0
Distribution Efficiencies 2010-2015 5.0 2.7
Little Falls Unit Upgrades 2013-2016 3.0 0.9
NW Wind 2019 150.0 50.0
CCCT 2019 250.0 225.0
Upper Falls 2020 2.0 1.0
NW Wind 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
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 a CCCT plant was removed, due
Avista Corp 2009 Electric IRP- Public Draft 8-8
Chapter 8- Preferred Resource Strategy
to a lower load forecast and the decision to fill a temporary capacity shortfall 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
Resource By the End of Year Nameplate(MW)Energy (aMW)
Non-Wind Renewable 2011 20.0 18.0
Non-Wind Renewable 2012 10.0 9.0
NW Wind 2013 100.0 33.0
Non-Wind Renewable 2013 5.0 4.5
Share of CCCT 2014 75.0 67.5
NW Wind 2015 100.0 33.0
NW Wind 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
Energy Efficiency and Conservation Energy efficiency is an integral part of the PRS analytical process. Energy efficiency is also a critical part of the Washington RPS, where utilities 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 efficiency is shown in Figure 8.6. Avista will acquire 102 aMW of energy efficiency over the next 10 years and 226 aMW over 20 years. These acquisitions will also reduce the system peak. Efficiency gains are expected to
shave 153 MW from the 2020 peak, and 339 MW from the 2029 peak.
Avista Corp 2009 Electric IRP- Public Draft 8-9
2009 Electric IRPAvista Corp 8-9
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
Preferred Resource Strategy
The 2009 PRS consists of hydro upgrades, wind, conservation, distribution efficiency
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.
Avista will 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
Falls. 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
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 tolling agreement. Table 8.1 presents PRS resources.
Table 8.1: 2009 Preferred Resource Strategy
Resource
By the End of Year
Nameplate
(MW)
Energy
(aMW)
NW Wind 2012150.048.0
Distribution Efficiencies 2010-20155.02.7
Little Falls Unit Upgrades 2013-20163.00.9
NW Wind 2019150.050.0
CCCT2019250.0225.0
Upper Falls 20202.01.0
NW Wind 202250.017.0
CCCT2024250.0225.0
CCCT2027250.0225.0
ConservationAll Years339.0226.0
Total1,449.0 1,020.6
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 a CCCT plant was removed, due
Avista Corp 2009 Electric IRP- Public Draft 8-8
Chapter 8- Preferred Resource Strategy
to a lower load forecast and the decision to fill a temporary capacity shortfall 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
Resource By the End of Year Nameplate(MW)Energy (aMW)
Non-Wind Renewable 2011 20.0 18.0
Non-Wind Renewable 2012 10.0 9.0
NW Wind 2013 100.0 33.0
Non-Wind Renewable 2013 5.0 4.5
Share of CCCT 2014 75.0 67.5
NW Wind 2015 100.0 33.0
NW Wind 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
Energy Efficiency and Conservation Energy efficiency is an integral part of the PRS analytical process. Energy efficiency is also a critical part of the Washington RPS, where utilities 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 efficiency is shown in Figure 8.6. Avista will acquire 102 aMW of energy efficiency over the next 10 years and 226 aMW over 20 years. These acquisitions will also reduce the system peak. Efficiency gains are expected to
shave 153 MW from the 2020 peak, and 339 MW from the 2029 peak.
Avista Corp 2009 Electric IRP- Public Draft 8-9
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-10 Avista Corp
Chapter 8- Preferred Resource Strategy
Figure 8.6: Energy Efficiency Annual Expected Acquisition
0
5
10
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Local (Avista)
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-party 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 will 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 will 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
Avista Corp 2009 Electric IRP- Public Draft 8-10
Chapter 8- Preferred Resource Strategy
scenarios since they will 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 will also require new runners. The upgrades will provide 1.0 MW of
additional capacity and 0.32 aMW of energy for each unit. The Upper Falls upgrade will
include a generator rewind and runner replacement. The upgrade will 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
0
500
1,000
1,500
2,000
2,500
3,000
3,500
20
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Existing Resources ConservationDistribution Efficiencies Hydro UpgradesCCCTWindLoad + Contingency
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 portfolio 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- Public Draft 8-11
2009 Electric IRPAvista Corp 8-11
Chapter 8 - Preferred Resoure Strategy
Chapter 8- Preferred Resource Strategy
Figure 8.6: Energy Efficiency Annual Expected Acquisition
0
5
10
15
20
20
1
0
20
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Regional (NEEA)
Local (Avista)
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-party 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 will 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 will 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
Avista Corp 2009 Electric IRP- Public Draft 8-10
Chapter 8- Preferred Resource Strategy
scenarios since they will 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 will also require new runners. The upgrades will provide 1.0 MW of
additional capacity and 0.32 aMW of energy for each unit. The Upper Falls upgrade will
include a generator rewind and runner replacement. The upgrade will 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
0
500
1,000
1,500
2,000
2,500
3,000
3,500
20
1
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20
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1
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m
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a
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a
t
t
s
Existing Resources ConservationDistribution Efficiencies Hydro UpgradesCCCTWindLoad + Contingency
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 portfolio 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- Public Draft 8-11
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-12 Avista Corp
Chapter 8- Preferred Resource 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 portfolio cost. PRiSM added the first CCCT resource in 2020,
leaving a small short position in 2019 that would be filled with market purchases.
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.
Figure 8.8: Winter Peak Load and Resource Balance
0
500
1,000
1,500
2,000
2,500
3,000
3,500
20
1
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Existing Resources ConservationDistribution Efficiencies Hydro UpgradesCCCTWindLoad + Planning Margin
Avista Corp 2009 Electric IRP- Public Draft 8-12
Chapter 8- Preferred Resource Strategy
Figure 8.9: Summer Peak Load and Resource Balance
0
500
1,000
1,500
2,000
2,500
3,000
3,500
20
1
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1
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Existing Resources Conservation
Distribution Efficiencies Hydro UpgradesCCCTWind
Load + Planning Margin
Greenhouse Gas Emissions
The Market Analysis chapter discusses how greenhouse gas emissions in the Western
Interconnect will decrease. Avista’s greenhouse gas emissions might not fall due to the
cap and trade market. The projected cap and trade market interaction will first impact
less efficient carbon emitting facilities before affecting the emissions from more efficient facilities. This will affect existing coal resources with high fuel and incremental operation
costs as they will 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 will be near 2010 levels on an annual basis, but
not lower than 2010 levels by the end of 2029. Emissions from current resource portfolio will be reduced as Colstrip’s output decreases and natural gas facilities increase
generation. The addition of new gas facilities necessary to meet growing loads will
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- Public Draft 8-13
2009 Electric IRPAvista Corp 8-13
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource 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 portfolio cost. PRiSM added the first CCCT resource in 2020,
leaving a small short position in 2019 that would be filled with market purchases.
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.
Figure 8.8: Winter Peak Load and Resource Balance
0
500
1,000
1,500
2,000
2,500
3,000
3,500
20
1
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20
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Existing ResourcesConservationDistribution EfficienciesHydro UpgradesCCCTWindLoad + Planning Margin
Avista Corp 2009 Electric IRP- Public Draft 8-12
Chapter 8- Preferred Resource Strategy
Figure 8.9: Summer Peak Load and Resource Balance
0
500
1,000
1,500
2,000
2,500
3,000
3,500
20
1
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a
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Existing Resources Conservation
Distribution Efficiencies Hydro UpgradesCCCTWind
Load + Planning Margin
Greenhouse Gas Emissions
The Market Analysis chapter discusses how greenhouse gas emissions in the Western
Interconnect will decrease. Avista’s greenhouse gas emissions might not fall due to the
cap and trade market. The projected cap and trade market interaction will first impact
less efficient carbon emitting facilities before affecting the emissions from more efficient facilities. This will affect existing coal resources with high fuel and incremental operation
costs as they will 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 will be near 2010 levels on an annual basis, but
not lower than 2010 levels by the end of 2029. Emissions from current resource portfolio will be reduced as Colstrip’s output decreases and natural gas facilities increase
generation. The addition of new gas facilities necessary to meet growing loads will
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- Public Draft 8-13
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-14 Avista Corp
Chapter 8- Preferred Resource Strategy
Figure 8.10: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions
0.0
0.5
1.0
1.5
2.0
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Tons per MWh of Load
Efficient Frontier Analysis
The backbone of the PRS is the Efficient Frontier analysis. This analysis illustrates the
relative performance of potential portfolios 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 portfolios, as detailed here and in Figure 8.11:
ƒMarket Only: No conservation measures, deficits are met with spot market
purchases, and capacity and RPS constraints are not met with new resources.
ƒCapacity Only: No conservation measures or resources are added to meet capacity needs and RPS requirements are ignored.
ƒLeast Cost without Conservation: Least cost strategy (excluding conservation
measures) meeting capacity and RPS requirements.
ƒLeast Cost: Least cost strategy that includes conservation measures meeting all capacity and RPS requirements.
ƒLeast Risk: Meets capacity and RPS requirements with the lowest risk.
ƒEfficient Frontier: A set of intermediate portfolios between the least risk and
least cost options.
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 reliability.
Avista Corp 2009 Electric IRP- Public Draft 8-14
Chapter 8- Preferred Resource 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 portfolio meets RPS and capacity requirements.
Figure 8.11: Base Case Efficient Frontier
$150
$170
$190
$210
$230
$250
$270
$290
3,300 3,350 3,400 3,450 3,500 3,550
2010-2020 NPV of power supply costs (millions)
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Market Only
Capacity Only
Least Cost w/o
ConservationLeast Cost/PRS
Least RiskEfficient Frontier
The cost differentials between each portfolio quantifies the avoided costs of the
following items:
ƒ Market costs: Market Only portfolio.
ƒ Capacity costs: difference between the Market Only and Capacity Only
strategies.
ƒ RPS and risk reduction costs: difference between the Capacity Only and Least Cost without Conservation strategies.
ƒ 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- Public Draft 8-15
2009 Electric IRPAvista Corp 8-15
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
Figure 8.10: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions
0.0
0.5
1.0
1.5
2.0
2.5
3.0
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to
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p
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M
W
h
CO2 Reduced from Legislation
New Resources
Existing Resources
Tons per MWh of Load
Efficient Frontier Analysis
The backbone of the PRS is the Efficient Frontier analysis. This analysis illustrates the
relative performance of potential portfolios 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 portfolios, as detailed here and in Figure 8.11:
ƒMarket Only: No conservation measures, deficits are met with spot market
purchases, and capacity and RPS constraints are not met with new resources.
ƒCapacity Only: No conservation measures or resources are added to meet capacity needs and RPS requirements are ignored.
ƒLeast Cost without Conservation: Least cost strategy (excluding conservation
measures) meeting capacity and RPS requirements.
ƒLeast Cost: Least cost strategy that includes conservation measures meeting all capacity and RPS requirements.
ƒLeast Risk: Meets capacity and RPS requirements with the lowest risk.
ƒEfficient Frontier: A set of intermediate portfolios between the least risk and
least cost options.
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 reliability.
Avista Corp 2009 Electric IRP- Public Draft 8-14
Chapter 8- Preferred Resource 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 portfolio meets RPS and capacity requirements.
Figure 8.11: Base Case Efficient Frontier
$150
$170
$190
$210
$230
$250
$270
$290
3,300 3,350 3,400 3,450 3,500 3,550
2010-2020 NPV of power supply costs (millions)
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Market Only
Capacity Only
Least Cost w/o
ConservationLeast Cost/PRS
Least RiskEfficient Frontier
The cost differentials between each portfolio quantifies the avoided costs of the
following items:
ƒ Market costs: Market Only portfolio.
ƒ Capacity costs: difference between the Market Only and Capacity Only
strategies.
ƒ RPS and risk reduction costs: difference between the Capacity Only and Least Cost without Conservation strategies.
ƒ Carbon costs: difference between market prices in the Base Case and the
Unconstrained Carbon scenario.
The levelized avoided costs for each item are shown in Table 8.3. The annual avoided conservation costs are shown in Figure 8.12. Avoided costs are determined by resource need and Mid-Columbia market prices. The first adder to Mid-Columbia prices is the
Avista Corp 2009 Electric IRP- Public Draft 8-15
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-16 Avista Corp
Chapter 8- Preferred Resource Strategy
carbon adder in 2012, and then capacity and RPS adders are included. The RPS cost-adder disappears in 2019 and 2025, as a result of the selected resources recovering
their costs from the market rather than rate payers.
Table 8.3: Levelized Avoided Costs ($/MWh)
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
$0
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A $111.15 per MWh levelized avoided cost added enough conservation to lower costs
by $65 million from the least-cost strategy absent this resource; risk is reduced by 14
percent. The Efficient Frontier portfolios decrease risk but increase costs. These portfolios 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 Efficient Frontier, but Washington law requires portfolios to include a certain
percentage of qualified renewables, effectively causing utilities to accept less market
risk. The least-cost portfolio, with capacity and RPS constraints, was selected over alternative portfolios.
Avista Corp 2009 Electric IRP- Public Draft 8-16
Chapter 8- Preferred Resource Strategy
Efficient Frontier Portfolios The Efficient Frontier analysis creates resource portfolios 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 Efficient Frontier. Resource portfolios are similar,
but differ in the amount and timing of wind acquisitions.
Figure 8.13: Efficient Frontier Portfolios 2029 New Resources
-
200
400
600
800
1,000
1,200
1,400
1,600
Least Cost - Mid Range + Least Risk
me
g
a
w
a
t
t
s
CCCT T&D Efficiencies
Wind Hydro Upgrades
IGCC Coal IGCC Coal w/ Seq
Expected Costs
The stochastic market analysis illustrates 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.
CapitalThe 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 billion required investment is just over $1 billion. Avista may not have to supply all of the capital that has been
identified where it chooses to procure resources through power purchase agreements.
Avista Corp 2009 Electric IRP- Public Draft 8-17
2009 Electric IRPAvista Corp 8-17
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
carbon adder in 2012, and then capacity and RPS adders are included. The RPS cost-adder disappears in 2019 and 2025, as a result of the selected resources recovering
their costs from the market rather than rate payers.
Table 8.3: Levelized Avoided Costs ($/MWh)
Nominal2009 Dollars
Mid-Columbia 68.22 54.37
Carbon25.52 19.83
Capacity11.669.29
Risk5.764.68
Total111.15 88.18
Figure 8.12: Avoided Costs for Conservation
$0
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Carbon Cost
RPS
Capacity
Mid-Columbia
A $111.15 per MWh levelized avoided cost added enough conservation to lower costs
by $65 million from the least-cost strategy absent this resource; risk is reduced by 14
percent. The Efficient Frontier portfolios decrease risk but increase costs. These portfolios 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 Efficient Frontier, but Washington law requires portfolios to include a certain
percentage of qualified renewables, effectively causing utilities to accept less market
risk. The least-cost portfolio, with capacity and RPS constraints, was selected over alternative portfolios.
Avista Corp 2009 Electric IRP- Public Draft 8-16
Chapter 8- Preferred Resource Strategy
Efficient Frontier Portfolios The Efficient Frontier analysis creates resource portfolios 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 Efficient Frontier. Resource portfolios are similar,
but differ in the amount and timing of wind acquisitions.
Figure 8.13: Efficient Frontier Portfolios 2029 New Resources
-
200
400
600
800
1,000
1,200
1,400
1,600
Least Cost - Mid Range + Least Risk
me
g
a
w
a
t
t
s
CCCT T&D Efficiencies
Wind Hydro Upgrades
IGCC Coal IGCC Coal w/ Seq
Expected Costs
The stochastic market analysis illustrates 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.
CapitalThe 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 billion required investment is just over $1 billion. 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 2009 Electric IRP- Public Draft 8-17
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-18 Avista Corp
Chapter 8- Preferred Resource Strategy
Table 8.4: PRS Rate Base Additions for Capital Expenditures (Millions 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 Volatility
The PRS analyses track fuel, variable O&M, emissions and market transaction costs for
the existing resource portfolio. These costs are captured for each of the 250 iterations of the Base Case risk analysis. In addition to existing portfolio 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 million in 2010. The 80 percent
confidence interval, shown in blue, ranges between $130 and $233 million. The black diamonds represent the TailVar 90 risk level, or the top 10 percent of the worst
outcomes; this 2010 cost is $270 million, 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 portfolio.
Avista Corp 2009 Electric IRP- Public Draft 8-18
Chapter 8- Preferred Resource Strategy
Figure 8.14: Power Supply Expense
$-
$200
$400
$600
$800
$1,000
$1,200
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80% CL Low
Expected Cost
Tail Var 90
80% CL High
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 to 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 portfolio 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, illustrates 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- Public Draft 8-19
2009 Electric IRPAvista Corp 8-19
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
Table 8.4: PRS Rate Base Additions for Capital Expenditures (Millions of Dollars)
YearInvestmentYearInvestment
20104.9 2020942.1
20115.0 202110.6
20125.1 20220.0
2013278.1 2023163.3
20147.7 20240.0
20152.3 2025542.0
20160.0 20260.0
20171.7 2027571.6
20180.0 20280.0
20190.0 20290.0
2010-2019 Total 304.82020-2029 Totals 2,229.6
Annual Power Supply Expenses and Volatility
The PRS analyses track fuel, variable O&M, emissions and market transaction costs for
the existing resource portfolio. These costs are captured for each of the 250 iterations of the Base Case risk analysis. In addition to existing portfolio 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 million in 2010. The 80 percent
confidence interval, shown in blue, ranges between $130 and $233 million. The black diamonds represent the TailVar 90 risk level, or the top 10 percent of the worst
outcomes; this 2010 cost is $270 million, 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 portfolio.
Avista Corp 2009 Electric IRP- Public Draft 8-18
Chapter 8- Preferred Resource Strategy
Figure 8.14: Power Supply Expense
$-
$200
$400
$600
$800
$1,000
$1,200
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80% CL Low
Expected Cost
Tail Var 90
80% CL High
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 to 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 portfolio 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, illustrates 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- Public Draft 8-19
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-20 Avista Corp
Chapter 8- Preferred Resource Strategy
Figure 8.15: Power Supply Cost Sensitivities
0%20% 40% 60% 80% 100% 120% 140%
80% CL (Low End)
Low Gas Price Forecast
Base Case- Stochastic
Base Case- Deterministic
High Gas Price Forecast
80% CL (High End)
percent change from Base Case (2029 costs)
$0.0 $2.0 $4.0 $6.0 $8.0 $10.0
2009 dollars (billions)
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 illustrate 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 utilities. 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 will affect Avista’s system costs and rates. The costs shown
in Figure 8.16 illustrate the range of potential annual carbon costs associated with future portfolio 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 portfolio in a market without carbon
legislation.
Avista Corp 2009 Electric IRP- Public Draft 8-20
Chapter 8- Preferred Resource Strategy
Figure 8.16: Carbon Related Power Supply Expense
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80% Allocation
40% Allocation
0% Allocation
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 illustrated by the Efficient Frontier analysis in Figure 8.17. The green curve on the upper
right of the chart is the Base Case Efficient Frontier with the red dot representing the
PRS. The blue curve in the lower left corner of Figure 8.17 represents the Efficient
Frontier without carbon legislation; the curve is less risky and less costly than the Base
Case. The red dot on this curve illustrates the non-carbon constrained PRS. A major difference between the resource selections in this scenario is that the least-cost portfolio
includes gas-fired peaking plants, rather than combined cycle resources.
Avista Corp 2009 Electric IRP- Public Draft 8-21
2009 Electric IRPAvista Corp 8-21
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
Figure 8.15: Power Supply Cost Sensitivities
0%20% 40% 60% 80% 100% 120% 140%
80% CL (Low End)
Low Gas Price Forecast
Base Case- Stochastic
Base Case- Deterministic
High Gas Price Forecast
80% CL (High End)
percent change from Base Case (2029 costs)
$0.0 $2.0 $4.0 $6.0 $8.0 $10.0
2009 dollars (billions)
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 illustrate 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 utilities. 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 will affect Avista’s system costs and rates. The costs shown
in Figure 8.16 illustrate the range of potential annual carbon costs associated with future portfolio 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 portfolio in a market without carbon
legislation.
Avista Corp 2009 Electric IRP- Public Draft 8-20
Chapter 8- Preferred Resource Strategy
Figure 8.16: Carbon Related Power Supply Expense
0
50
100
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80% Allocation
40% Allocation
0% Allocation
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 illustrated by the Efficient Frontier analysis in Figure 8.17. The green curve on the upper
right of the chart is the Base Case Efficient Frontier with the red dot representing the
PRS. The blue curve in the lower left corner of Figure 8.17 represents the Efficient
Frontier without carbon legislation; the curve is less risky and less costly than the Base
Case. The red dot on this curve illustrates the non-carbon constrained PRS. A major difference between the resource selections in this scenario is that the least-cost portfolio
includes gas-fired peaking plants, rather than combined cycle resources.
Avista Corp 2009 Electric IRP- Public Draft 8-21
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-22 Avista Corp
Chapter 8- Preferred Resource Strategy
Figure 8.17: Efficient Frontier Comparison
$100
$150
$200
$250
$300
$2,500 $2,700 $2,900 $3,100 $3,300 $3,500 $3,700
2010-2020 NPV (millions)
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The least cost portfolio in this scenario is very similar to the PRS, except 750 MW of combined cycle projects is exchanged for 800 MW of LMS100 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 million 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 portfolio 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 will
not directly emit as much greenhouse gas.
Avista Corp 2009 Electric IRP- Public Draft 8-22
Chapter 8- Preferred Resource Strategy
Table 8.5: Unconstrained Carbon Scenario- Least Cost Portfolio
Resource
By the End
of Year
Nameplate
(MW)
Energy
(aMW)
NW Wind 2012 100.0 48.0
Distribution Efficiencies 2010-2015 5.0 2.7
Little Falls 4 2016 1.0 0.3
NW Wind 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
NW Wind 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: Portfolio Cost and Risk Comparison
Base Case PRS UC PRS UC Least Cost 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 (000’s) 3,311 4,016 3,575
2029 CO2 Emissions (000’s) 3,286 4,041 2,928
Portfolio Scenarios
In many resource plans, a PRS is presented with a comparison to other portfolios to illustrate cost and risk trade-offs. Avista wants to extend the portfolio analysis beyond
simple portfolio comparisons for this IRP by focusing on how the portfolio would change
if assumptions changed. This provides an array of strategies for fundamentally different
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- Public Draft 8-23
2009 Electric IRPAvista Corp 8-23
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
Figure 8.17: Efficient Frontier Comparison
$100
$150
$200
$250
$300
$2,500 $2,700 $2,900 $3,100 $3,300 $3,500 $3,700
2010-2020 NPV (millions)
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The least cost portfolio in this scenario is very similar to the PRS, except 750 MW of combined cycle projects is exchanged for 800 MW of LMS100 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 million 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 portfolio 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 will
not directly emit as much greenhouse gas.
Avista Corp 2009 Electric IRP- Public Draft 8-22
Chapter 8- Preferred Resource Strategy
Table 8.5: Unconstrained Carbon Scenario- Least Cost Portfolio
Resource
By the End
of Year
Nameplate
(MW)
Energy
(aMW)
NW Wind 2012 100.0 48.0
Distribution Efficiencies 2010-2015 5.0 2.7
Little Falls 4 2016 1.0 0.3
NW Wind 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
NW Wind 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: Portfolio Cost and Risk Comparison
Base Case PRS UC PRS UC Least Cost 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 (000’s) 3,311 4,016 3,575
2029 CO2 Emissions (000’s) 3,286 4,041 2,928
Portfolio Scenarios
In many resource plans, a PRS is presented with a comparison to other portfolios to illustrate cost and risk trade-offs. Avista wants to extend the portfolio analysis beyond
simple portfolio comparisons for this IRP by focusing on how the portfolio would change
if assumptions changed. This provides an array of strategies for fundamentally different
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- Public Draft 8-23
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-24 Avista Corp
Chapter 8- Preferred Resource 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 will 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 million or 2.3 percent and reduce power supply risk between 2015 and 2019 by 5.7 percent. The decision to acquire this resource earlier will 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 sufficient amount of
economically viable renewable resources with on-peak capacity contributions, or attractive pricing on a new CCCT.
Load Forecast Alternatives
Loads will 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 will increase the need
for capital and slower load growth will 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
Avista Corp 2009 Electric IRP- Public Draft 8-24
Chapter 8- Preferred Resource 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
Resource
By the End
of Year
Nameplate
(MW)
Energy
(aMW)
Modification to
Strategy
NW Wind 2012 100.0 48.0 No Change
Distribution Efficiencies 2010-2015 5.0 2.7 No Change
Little Falls Unit Upgrades 2013-2016 3.0 0.9 No Change
NW Wind 2019 100.0 33.0 Reduced from 150 MW
CCCT Removed 250 MW
Upper Falls 2020 2.0 1.0 Delayed to 2028
NW Wind 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
Resource
By the End
of Year
Nameplate
(MW)
Energy
(aMW)
Modification to
Strategy
NW Wind 2012 200.0 64.5 Increased from 150 MW
Simple Cycle 2011 60.0 92.3 60 MW Added
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 MW Added
Simple Cycle 2017 100.0 92.2 100 MW Added
NW Wind 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 MW Added
Upper Falls 2020 2.0 1.0 No Change
NW Wind 2022 50.0 17.0 No Change
CCCT 2024 250.0 225.0 No Change
CCCT 2027 250.0 225.0 No Change
Total 1,570.0 1,196.1
Avista Corp 2009 Electric IRP- Public Draft 8-25
2009 Electric IRPAvista Corp 8-25
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource 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 will 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 million or 2.3 percent and reduce power supply risk between 2015 and 2019 by 5.7 percent. The decision to acquire this resource earlier will 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 sufficient amount of
economically viable renewable resources with on-peak capacity contributions, or attractive pricing on a new CCCT.
Load Forecast Alternatives
Loads will 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 will increase the need
for capital and slower load growth will 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
Avista Corp 2009 Electric IRP- Public Draft 8-24
Chapter 8- Preferred Resource 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
Resource
By the End
of Year
Nameplate
(MW)
Energy
(aMW)
Modification to
Strategy
NW Wind 2012 100.0 48.0 No Change
Distribution Efficiencies 2010-2015 5.0 2.7 No Change
Little Falls Unit Upgrades 2013-2016 3.0 0.9 No Change
NW Wind 2019 100.0 33.0 Reduced from 150 MW
CCCT Removed 250 MW
Upper Falls 2020 2.0 1.0 Delayed to 2028
NW Wind 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
Resource
By the End
of Year
Nameplate
(MW)
Energy
(aMW)
Modification to
Strategy
NW Wind 2012 200.0 64.5 Increased from 150 MW
Simple Cycle 2011 60.0 92.3 60 MW Added
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 MW Added
Simple Cycle 2017 100.0 92.2 100 MW Added
NW Wind 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 MW Added
Upper Falls 2020 2.0 1.0 No Change
NW Wind 2022 50.0 17.0 No Change
CCCT 2024 250.0 225.0 No Change
CCCT 2027 250.0 225.0 No Change
Total 1,570.0 1,196.1
Avista Corp 2009 Electric IRP- Public Draft 8-25
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-26 Avista Corp
Chapter 8- Preferred Resource Strategy
The estimated cost for these portfolios 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
$3.0
$3.1
$3.2
$3.3
$3.4
$3.5
$3.6
Low Load Base Case High Load
ex
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$0.0
$0.3
$0.6
$0.9
$1.2
$1.5
$1.8
ca
p
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Expected Cost (NPV 2010-20)
Capital Expense (2010-2020)
Large Hydro Facility Scenarios
Renewable portfolio 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 will
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 will not change near-term resource acquisition plans.
Avista Corp 2009 Electric IRP- Public Draft 8-26
Chapter 8- Preferred Resource Strategy
Table 8.9: Large Hydro Upgrade Resource Strategy Modifications
Resource
By the End
of Year
Nameplate
(MW)
Energy
(aMW)
Modification to
Strategy
NW Wind 2012 100.0 48.0 No Change
Distribution Efficiencies 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 MW Added
Long Lake 2 Powerhouse 2019 60.0 18.0 60 MW Added
NW Wind 2019 100.0 33.0 Reduced from 150
MW
CCCT 2019 250.0 225.0 No Change
NW Wind 2022 50.0 17.0 No Change
CCCT 2026 400.0 360.0
Delayed from 2024
and upgraded from 250 MW
CCCT Removed 250 MW
Upper Falls 2029 2.0 1.0 Delayed from 2020
Totals 1,030.0 715.8
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 will affect project costs. This scenario illustrates changes in the PRS
if these resources were included in the Efficient Frontier analysis. As Avista solicits 150 MW of wind, it will 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 Efficient 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- Public Draft 8-27
2009 Electric IRPAvista Corp 8-27
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
The estimated cost for these portfolios 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
$3.0
$3.1
$3.2
$3.3
$3.4
$3.5
$3.6
Low Load Base Case High Load
ex
p
e
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c
o
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(
b
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)
$0.0
$0.3
$0.6
$0.9
$1.2
$1.5
$1.8
ca
p
i
t
a
l

e
x
p
e
n
s
e

(
b
i
l
l
i
o
n
s
)
Expected Cost (NPV 2010-20)
Capital Expense (2010-2020)
Large Hydro Facility Scenarios
Renewable portfolio 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 will
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 will not change near-term resource acquisition plans.
Avista Corp 2009 Electric IRP- Public Draft 8-26
Chapter 8- Preferred Resource Strategy
Table 8.9: Large Hydro Upgrade Resource Strategy Modifications
Resource
By the End
of Year
Nameplate
(MW)
Energy
(aMW)
Modification to
Strategy
NW Wind 2012 100.0 48.0 No Change
Distribution Efficiencies 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 MW Added
Long Lake 2 Powerhouse 2019 60.0 18.0 60 MW Added
NW Wind 2019 100.0 33.0 Reduced from 150
MW
CCCT 2019 250.0 225.0 No Change
NW Wind 2022 50.0 17.0 No Change
CCCT 2026 400.0 360.0
Delayed from 2024
and upgraded from 250 MW
CCCT Removed 250 MW
Upper Falls 2029 2.0 1.0 Delayed from 2020
Totals 1,030.0 715.8
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 will affect project costs. This scenario illustrates changes in the PRS
if these resources were included in the Efficient Frontier analysis. As Avista solicits 150 MW of wind, it will 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 Efficient 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- Public Draft 8-27
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-28 Avista Corp
Chapter 8- Preferred Resource 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 facilities 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
$180
$200
$220
$240
$260
$280
$300
$3,300 $3,400 $3,500 $3,600 $3,700 $3,800 $3,900
2010-2020 NPV (millions)
20
2
0

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m
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s
)
Where Avista is able to acquire non-wind renewables, its resource portfolio strategy will
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).
Avista Corp 2009 Electric IRP- Public Draft 8-28
Chapter 8- Preferred Resource Strategy
Table 8.10: Portfolio Cost and Risk Comparison
Base Case
PRS
Non-Wind Renewable
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 (‘000s) 3,311 2,771
2029 CO2 Emissions (‘000s) 3,286 3,145
Table 8.11: Other Renewables Available- Changes to PRS
Resource
By the End
of Year
Nameplate
(MW)
Energy
(aMW)
Modification to
Strategy
Biomass/Geothermal 2011 10.0 9.1 10 MW Added
Reardan Wind 2012 50.0 15.0 No Change
NW Wind 2012 50.0 17.0 Reduced from 100 MW
Biomass/Geothermal 2012 5.0 4.5 5 MW Added
Biomass/Geothermal 2013 5.0 4.5 5 MW Added
Distribution Efficiencies 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 MW Added
KFCT Wood Conversion 2019 7.0 0.0 Capacity/Energy
Neutral RECs Added
NW Wind 2019 100.0 33.0 Reduced by 50 MW
Simple Cycle CT 2019 100.0 92.3 100 MW Added
CCCT 2020 250.0 225.0 Delayed from 2019
Upper Falls 2020 2.0 1.0 No Change
NW Wind 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- Public Draft 8-29
2009 Electric IRPAvista Corp 8-29
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource 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 facilities 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
$180
$200
$220
$240
$260
$280
$300
$3,300 $3,400 $3,500 $3,600 $3,700 $3,800 $3,900
2010-2020 NPV (millions)
20
2
0

s
t
d
e
v

(
m
i
l
l
i
o
n
s
)
Where Avista is able to acquire non-wind renewables, its resource portfolio strategy will
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).
Avista Corp 2009 Electric IRP- Public Draft 8-28
Chapter 8- Preferred Resource Strategy
Table 8.10: Portfolio Cost and Risk Comparison
Base Case
PRS
Non-Wind Renewable
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 (‘000s) 3,311 2,771
2029 CO2 Emissions (‘000s) 3,286 3,145
Table 8.11: Other Renewables Available- Changes to PRS
Resource
By the End
of Year
Nameplate
(MW)
Energy
(aMW)
Modification to
Strategy
Biomass/Geothermal 2011 10.0 9.1 10 MW Added
Reardan Wind 2012 50.0 15.0 No Change
NW Wind 2012 50.0 17.0 Reduced from 100 MW
Biomass/Geothermal 2012 5.0 4.5 5 MW Added
Biomass/Geothermal 2013 5.0 4.5 5 MW Added
Distribution Efficiencies 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 MW Added
KFCT Wood Conversion 2019 7.0 0.0 Capacity/Energy
Neutral RECs Added
NW Wind 2019 100.0 33.0 Reduced by 50 MW
Simple Cycle CT 2019 100.0 92.3 100 MW Added
CCCT 2020 250.0 225.0 Delayed from 2019
Upper Falls 2020 2.0 1.0 No Change
NW Wind 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- Public Draft 8-29
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-30 Avista Corp
Chapter 8- Preferred Resource Strategy
after 2020. Avista will 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, distribution efficiency, 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 will 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
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)
0
50
100
150
200
250
300
20
0
0
20
0
2
20
0
4
20
0
6
20
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8
20
1
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Co
s
t

I
n
d
e
x

(
2
0
1
0

=

1
0
0
)
Base Case
No CO2 Costs
Actual
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
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
costs for existing resources and all costs for new resources such as operations and maintenance, taxes, depreciation and return. The lines also include incremental
conservation amounts, net market purchases and sales, and carbon costs assuming
100 percent auction.
Avista Corp 2009 Electric IRP- Public Draft 8-30
2009 Electric IRPAvista Corp 8-31
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
after 2020. Avista will 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, distribution efficiency, 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 will 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
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)
0
50
100
150
200
250
300
20
0
0
20
0
2
20
0
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20
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2
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Co
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t

I
n
d
e
x

(
2
0
1
0

=

1
0
0
)
Base Case
No CO2 Costs
Actual
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
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
costs for existing resources and all costs for new resources such as operations and maintenance, taxes, depreciation and return. The lines also include incremental
conservation amounts, net market purchases and sales, and carbon costs assuming
100 percent auction.
Avista Corp 2009 Electric IRP- Public Draft 8-30
Ch
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4
0
)

(
6
8
)

(
7
7
)

(
1
3
0
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(
1
2
6
)

(
1
4
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(
1
7
3
)

(
2
7
8
)

(
4
8
6
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(
5
0
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)

(
5
1
7
)
PR
S

R
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d
-
-

-

4
7

4
7

4
7

4
7

4
7

4
7

4
7

9
6

9
6

9
6

1
1
2

1
1
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1
1
2

1
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1
1
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1
1
2

1
1
2

CC
C
T
-
-

-

-

-

-

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-

-

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2
2
5

2
2
5

2
2
5

2
2
5

2
2
5

4
5
1

4
5
1

6
7
6

6
7
6

6
7
6

Di
s
t
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b
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n

E
f
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n
c
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s

1

1

2

2

3

3

3

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3

3

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3

3

3

3

3

3

3

3

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s
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0

1

1

1

1

1

1

2

2

2

2

2

2

2

2

2

To
t
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l

P
R
S
1
1

2

5
0

5
0

5
1

5
1

5
1

5
1

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3
2
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3
2
6

3
2
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3
4
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3
4
2

5
6
7

5
6
7

7
9
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7
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3

7
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3
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3
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8
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1
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4
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1
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7

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Av
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s
t
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C
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20
0
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E
l
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c
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r
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c

I
R
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P
u
b
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c

D
r
a
f
t

8-
3
2
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-32 Avista Corp
Ch
a
p
t
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r

8
-

P
r
e
f
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r
r
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d

R
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s
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S
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y

Ta
b
l
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8
.
1
3
:

L
o
a
d

&

R
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s

a
t

W
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P
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k

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M
W
)

20
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4

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Pl
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M
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26
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5
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3
6
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R
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58
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8
4

5
8
4

5
8
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4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
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4

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5
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Pe
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R
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2
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2
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2
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2
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2
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2
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2
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2
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Ca
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M
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Ex
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R
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2
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PR
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R
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d
-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

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-

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CC
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-

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6
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2
6
3

2
6
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6
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5
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7
8
8

7
8
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7
8
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Di
s
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t
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n

E
f
f
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c
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2

3

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5

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5

5

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5

5

5

5

5

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5

5

5

Hy
d
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U
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s
-

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1

2

2

3

3

3

3

5

5

5

5

5

5

5

5

5

To
t
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l

P
R
S
1

2

3

4

6

7

7

8

8

8

2
7
1

2
7
3

2
7
3

2
7
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7
3

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3
5

5
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5

7
9
8

7
9
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7
9
8

Ne
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P
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w
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P
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31
5

1
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7
4

6
7

3
1

(
2
0
)

(
5
5
)

5
9

1
8

(
4
2
)

9
7

6
2

2
6

(
8
)

(
4
9
)

1
7
1

1
0
7

5
4

1
7

(
1
6
)

Pla
n
n
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g

M
a
r
g
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n
33
%

2
4
%

1
9
%

1
9
%

1
7
%

1
5
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1
3
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1
9
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7
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4
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9
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8
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1
6
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1
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2
4
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9
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Av
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s
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C
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r
p

20
0
9

E
l
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c
t
r
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c

I
R
P
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P
u
b
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c

D
r
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f
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8-
3
3
Ch
a
p
t
e
r

8
-

P
r
e
f
e
r
r
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d

R
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s
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S
t
r
a
t
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g
y

Ta
b
l
e

8
.
1
3
:

L
o
a
d

&

R
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s
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c
e
s

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t

W
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t
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r

P
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k

(
M
W
)

20
1
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2
0
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2
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1
2

2
0
1
3

2
0
1
4

2
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1
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2
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1
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2
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2
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2
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2
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2
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2

2
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3

2
0
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2
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2
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2
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2
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Pe
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k

D
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d
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2
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2
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2
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Pl
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M
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26
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To
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O
b
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t
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s
2,
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2
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6
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2
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2
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Ex
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s
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4
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7
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Th
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R
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s
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c
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s
58
0

5
8
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5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
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5
8
4

5
8
4

5
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4

5
8
4

5
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5
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Pe
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R
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22
6

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2
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2
2
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2
2
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2
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6

2
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2
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6

2
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6

2
2
6

2
2
6

2
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6

2
2
6

2
2
6

2
2
6

2
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6

2
2
6

2
2
6

2
2
6

2
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6

Ca
p
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c
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o
n

M
a
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a
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e

1
0
6

1
0
5

1
0
5

1
0
0

1
0
0

1
0
0

1
0
0

1
2
7

1
0
0

1
0
0

1
0
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1
2
7

1
0
0

1
0
0

1
0
0

1
2
7

1
0
0

1
0
0

1
0
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1
2
7

Ex
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s
t
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n
g

R
e
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e
s

2
,
3
5
9
2
,
2
3
1

2
,
1
8
7

2
,
2
0
7

2
,
2
0
7

2
,
2
0
7

2
,
2
0
8

2
,
3
5
8

2
,
3
5
8

2
,
3
3
0

2
,
2
4
1

2
,
2
4
1

2
,
2
4
1

2
,
2
4
0

2
,
2
4
0

2
,
2
4
0

2
,
2
4
0

1
,
9
5
9
1
,
9
5
9 1
,
9
5
9
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t

P
o
s
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t
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n
30
2

1
2
6

3
5

1
5

(
3
6
)

(
1
0
2
)
(
1
5
2
) (
5
4
)

(
1
1
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)
(
1
8
7
) (
3
2
7
)

(
3
8
2
)
(
4
3
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)

(
4
8
9
)
(
5
5
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)

(
6
1
3
)

(
6
9
8
)
(
1
,
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3
6
)

(
1
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0
9
5
)

(
1
,
1
5
3
)
Co
n
s
e
r
v
a
t
i
o
n
12

2
4

3
6

4
8

6
2

7
5

9
0

1
0
5

1
2
0

1
3
7

1
5
3

1
7
1

1
8
9

2
0
9

2
2
8

2
4
9

2
7
0

2
9
3

3
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5

3
3
9

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t

P
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t
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n

w
/

C
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n
s
.

3
1
4

1
5
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7
1

6
3

2
5

(
2
7
)

(
6
2
)

5
1

1
0

(
5
0
)

(
1
7
4
)
(
2
1
1
) (
2
4
6
)

(
2
8
0
)
(
3
2
2
)

(
3
6
4
)

(
4
2
8
)
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7
4
3
)

(
7
8
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)

(
8
1
4
)

PR
S

R
e
s
o
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c
e
s
Wi
n
d
-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

CC
C
T
-

-

-

-

-

-

-

-

-

-

2
6
3

2
6
3

2
6
3

2
6
3

2
6
3

5
2
5

5
2
5

7
8
8

7
8
8

7
8
8

Di
s
t
r
i
b
u
t
i
o
n

E
f
f
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c
i
e
n
c
i
e
s

1

2

3

4

5

5

5

5

5

5

5

5

5

5

5

5

5

5

5

5

Hy
d
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o

U
p
g
r
a
d
e
s
-

-

-

-

1

2

2

3

3

3

3

5

5

5

5

5

5

5

5

5

To
t
a
l

P
R
S
1

2

3

4

6

7

7

8

8

8

2
7
1

2
7
3

2
7
3

2
7
3

2
7
3

5
3
5

5
3
5

7
9
8

7
9
8

7
9
8

Ne
t

P
o
s
i
t
i
o
n

w
/

P
R
S
31
5

1
5
2

7
4

6
7

3
1

(
2
0
)

(
5
5
)

5
9

1
8

(
4
2
)

9
7

6
2

2
6

(
8
)

(
4
9
)

1
7
1

1
0
7

5
4

1
7

(
1
6
)

Pla
n
n
i
n
g

M
a
r
g
i
n
33
%

2
4
%

1
9
%

1
9
%

1
7
%

1
5
%

1
3
%

1
9
%

1
7
%

1
4
%

2
1
%

1
9
%

1
8
%

1
6
%

1
4
%

2
4
%

2
1
%

1
9
%

1
8
%

1
6
%
Av
i
s
t
a

C
o
r
p

20
0
9

E
l
e
c
t
r
i
c

I
R
P
-

P
u
b
l
i
c

D
r
a
f
t

8-
3
3
2009 Electric IRPAvista Corp 8-33
Chapter 8 - Preferred Resoure Strategy
Ch
a
p
t
e
r

8
-

P
r
e
f
e
r
r
e
d

R
e
s
o
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r
c
e

S
t
r
a
t
e
g
y

Ta
b
l
e

8
.
1
4
:

L
o
a
d

&

R
e
s
o
u
r
c
e
s

a
t

S
u
m
m
e
r

P
e
a
k

(
M
W
)

20
1
0

2
0
1
1

2
0
1
2

2
0
1
3

2
0
1
4

2
0
1
5

2
0
1
6

2
0
1
7

2
0
1
8

2
0
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9

2
0
2
0

2
0
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2
0
2
2

2
0
2
3

2
0
2
4

2
0
2
5

2
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2
6

2
0
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8

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9
Pe
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k

D
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m
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d
1,
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1

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3

1
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3

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,
8
7
6

1
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9
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1
,
9
5
6

2
,
0
0
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2
,
0
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2
,
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2
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1
2
3
2
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1
6
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2
,
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2
,
2
5
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2
,
3
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2
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2
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Pla
n
n
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M
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n
25
0

2
5
7

2
6
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2
6
7

2
7
3

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8
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2
8
7

2
9
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3
0
0

3
0
6

3
1
2

3
1
8

3
2
5

3
3
1

3
3
8

3
4
6

3
5
6

3
6
2

3
6
9

3
7
6

To
t
a
l

O
b
l
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g
a
t
i
o
n
s

1
,
9
1
9
1
,
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7
2

2
,
0
1
4

2
,
0
5
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2
,
0
9
6

2
,
1
5
7

2
,
2
0
2

2
,
2
4
9

2
,
30
0

2
,
3
4
6

2
,
3
9
2

2
,
4
4
1

2
,
4
9
0
2
,
5
3
8

2
,
5
9
3

2
,
6
5
0

2
,
7
2
8

2
,
7
7
8

2
,
8
3
2

2
,
8
8
5
Ex
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s
t
i
n
g

R
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s
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c
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s
Hy
d
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95
3

9
3
2

1
,
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0
1
,
0
2
8

1
,
0
5
1

1
,
0
2
8

1
,
0
4
9

1
,
0
2
2

1
,
0
2
2

1
,
0
2
1

1
,
0
2
3
9
9
6

9
9
6

9
9
3

1
,
0
2
8
9
9
6

9
9
6

1
,
0
0
2
1
,
0
2
3 9
9
6

Ne
t

C
o
n
t
r
a
c
t
s
30
4

2
0
4

1
8
5

1
8
5

1
8
5

1
8
5

1
8
5

3
3
5

3
3
5

3
3
3

3
3
3

3
3
3

3
3
3

3
3
2

3
3
2

3
3
2

3
3
2

6
8

6
8

6
8

Th
e
r
m
a
l

R
e
s
o
u
r
c
e
s

5
7
7

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

Pe
a
k
i
n
g

R
e
s
o
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e
s

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
0

2
0
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2
0
0

2
0
0

Ma
i
n
t
e
n
a
n
c
e

a
t

P
e
a
k

1
6
8

1
5
7

4
6

3
7

1
4

3
8

1
7

4
4

4
4

1
9

1
7

4
4

4
4

4
7

1
1

4
4

4
4

3
8

1
7

4
4

Ex
i
s
t
i
n
g

R
e
s
o
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r
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e
s

2
,
2
0
1
2
,
0
7
4

2
,
0
3
1

2
,
0
3
1

2
,
0
3
1

2
,
0
3
1

2
,
0
3
1

2
,
1
8
1

2
,
18
1

2
,
1
5
3

2
,
1
5
3

2
,
1
5
3

2
,
1
5
3
2
,
1
5
3

2
,
1
5
3

2
,
1
5
3

2
,
1
5
3

1
,
8
8
9

1
,
8
8
9

1
,
8
8
9
Ne
t

P
o
s
i
t
i
o
n
28
2

1
0
2

1
7

(
2
0
)

(
6
6
)

(
1
2
6
)
(
1
7
1
) (
6
8
)

(
1
1
9
)
(
1
9
3
)

(
2
3
9
)

(
2
8
9
)

(
3
3
7
)

(
3
8
5
)
(
4
4
1
)

(
4
9
7
)

(
5
7
5
)

(
8
9
0
)
(
9
4
4
)

(
9
9
7
)
Co
n
s
e
r
v
a
t
i
o
n
12

2
4

3
6

4
8

6
2

7
5

9
0

1
0
5

1
2
0

1
3
7

1
5
3

1
7
1

1
8
9

2
0
9

2
2
8

2
4
9

2
7
0

2
9
3

3
1
5

3
3
9

Ne
t

P
o
s
i
t
i
o
n

w
/

C
o
n
s
.

2
9
4

1
2
6

5
3

2
8

(
4
)

(
5
1
)

(
8
1
)

3
7

1

(
5
6
)

(
8
6
)

(
1
1
8
)

(
1
4
8
)

(
1
7
7
)
(
2
1
3
)

(
2
4
8
)

(
3
0
5
)

(
5
9
7
)
(
6
2
9
)

(
6
5
8
)
PR
S

R
e
s
o
u
r
c
e
s
Wi
n
d
-
-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

CC
C
T
-
-

-

-

-

-

-

-

-

-

2
3
8

2
3
8

2
3
8

2
3
8

2
3
8

4
7
5

4
7
5

7
1
3

7
1
3

7
1
3

Di
s
t
r
i
b
u
t
i
o
n

E
f
f
i
c
i
e
n
c
i
e
s

1

2

3

4

5

5

5

5

5

5

5

5

5

5

5

5

5

5

5

5

Hy
d
r
o

U
p
g
r
a
d
e
s
-
-

-

-

1

2

2

3

3

3

3

5

5

5

5

5

5

5

5

5

To
t
a
l

P
R
S
1
2

3

4

6

7

7

8

8

8

2
4
5

2
4
7

2
4
7

2
4
7

2
4
7

4
8
5

4
8
5

7
2
2

7
2
2

7
2
2
Ne
t

P
o
s
i
t
i
o
n
29
5

1
2
8

5
6

3
2

2

(
4
5
)

(
7
4
)

4
5

9

(
4
9
)

1
5
9

1
2
9

9
9

7
0

3
4

2
3
6

1
7
9

1
2
5

9
3

6
4

Pla
n
n
i
n
g

M
a
r
g
i
n
33
%

2
3
%

1
9
%

1
7
%

1
6
%

1
3
%

1
2
%

1
8
%

1
6
%

1
4
%

2
4
%

2
3
%

2
1
%

2
0
%

1
8
%

2
8
%

2
5
%

2
3
%

2
2
%

2
0
%
Av
i
s
t
a

C
o
r
p

20
0
9

E
l
e
c
t
r
i
c

I
R
P
-

P
u
b
l
i
c

D
r
a
f
t

8-
3
4
Ch
a
p
t
e
r

8
-

P
r
e
f
e
r
r
e
d

R
e
s
o
u
r
c
e

S
t
r
a
t
e
g
y

Ta
b
l
e

8
.
1
4
:

L
o
a
d

&

R
e
s
o
u
r
c
e
s

a
t

S
u
m
m
e
r

P
e
a
k

(
M
W
)

20
1
0

2
0
1
1

2
0
1
2

2
0
1
3

2
0
1
4

2
0
1
5

2
0
1
6

2
0
1
7

2
0
1
8

2
0
1
9

2
0
2
0

2
0
2
1

2
0
2
2

2
0
2
3

2
0
2
4

2
0
2
5

2
0
2
6

2
0
2
7

2
0
2
8

2
0
2
9
Pe
a
k

D
e
m
a
n
d
1,
6
6
9 1
,
7
1
5

1
,
7
5
1

1
,
7
8
3

1
,
8
2
3

1
,
8
7
6

1
,
9
1
5

1
,
9
5
6

2
,
0
0
0

2
,
0
4
0

2
,
0
8
0

2
,
1
2
3
2
,
1
6
5

2
,
2
0
7

2
,
2
5
5

2
,
3
0
4
2
,
3
7
2

2
,
4
1
6

2
,
4
6
3

2
,
5
0
9
Pl
a
n
n
i
n
g

M
a
r
g
i
n
25
0

2
5
7

2
6
3

2
6
7

2
7
3

2
8
1

2
8
7

2
9
3

3
0
0

3
0
6

3
1
2

3
1
8

3
2
5

3
3
1

3
3
8

3
4
6

3
5
6

3
6
2

3
6
9

3
7
6

To
t
a
l

O
b
l
i
g
a
t
i
o
n
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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
ƒ Continue studying wind potential in the Company’s service territory, possibly
including the placement of anemometers at the most promising wind sites.
ƒ Commission a study of Montana wind resources strategically located near existing
Company transmission assets
ƒ 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 will 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 will provide
further details for the availability and cost of non-renewable resources.
Avista Corp 2009 Electric IRP – Public Draft 9-1
2009 Electric IRPAvista Corp 9-1
Chapter 9 - Action ItemsChapter 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
ƒ Continue studying wind potential in the Company’s service territory, possibly
including the placement of anemometers at the most promising wind sites.
ƒ Commission a study of Montana wind resources strategically located near existing
Company transmission assets
ƒ 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 will 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 will provide
further details for the availability and cost of non-renewable resources.
Avista Corp 2009 Electric IRP – Public Draft 9-1
Chapter 9 - Action Items
2009 Electric IRP9-2 Avista Corp
Chapter 9–Action Items
Demand Side Management
ƒ Update processes and protocols for integrating energy efficiency programs into the
IRP to improve and streamline the process.
ƒ Study and quantify transmission and distribution efficiency concepts.
ƒ Determine potential impacts and costs of load management options reviewed as part
of the Heritage Project.
ƒ 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 efficiency programs into the IRP process can be found in the Energy Efficiency chapter. Transmission and
distribution efficiency 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
Efficiency chapter.
Emissions
ƒ Continue to evaluate the implications of new rules and regulations affecting power
plant operations, most notably greenhouse gases.
ƒ 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 will continue until final rules are established for the Washington legislation and federal laws are passed. Then the focus will 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
ƒ Study the potential for fixing natural gas prices through financial instruments, coal
gasification, investments in gas fields or other means.
ƒ Continue studying the efficient frontier modeling approach to identify more and better
uses for its information.
ƒ Further enhance and refine the PRiSM model.
Avista Corp 2009 Electric IRP – Public Draft 9-2
Chapter 9–Action Items
ƒ Continue to study the impact of climate change on the load forecast.
ƒ 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 Efficient 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
ƒ 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.
ƒ Continue involvement in BPA transmission practice processes and rate proceedings to minimize costs of integrating existing resources outside of the Company’s service
area.
ƒ 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.
ƒ 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 will be revisited as items in
the 2009 Action Plan. Details about progress made towards the maintenance of existing
transmission rights, involvement in BPA 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 will 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 – Public Draft 9-3
2009 Electric IRPAvista Corp 9-3
Chapter 9 - Action ItemsChapter 9–Action Items
Demand Side Management
ƒ Update processes and protocols for integrating energy efficiency programs into the
IRP to improve and streamline the process.
ƒ Study and quantify transmission and distribution efficiency concepts.
ƒ Determine potential impacts and costs of load management options reviewed as part
of the Heritage Project.
ƒ 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 efficiency programs into the IRP process can be found in the Energy Efficiency chapter. Transmission and
distribution efficiency 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
Efficiency chapter.
Emissions
ƒ Continue to evaluate the implications of new rules and regulations affecting power
plant operations, most notably greenhouse gases.
ƒ 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 will continue until final rules are established for the Washington legislation and federal laws are passed. Then the focus will 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
ƒ Study the potential for fixing natural gas prices through financial instruments, coal
gasification, investments in gas fields or other means.
ƒ Continue studying the efficient frontier modeling approach to identify more and better
uses for its information.
ƒ Further enhance and refine the PRiSM model.
Avista Corp 2009 Electric IRP – Public Draft 9-2
Chapter 9–Action Items
ƒ Continue to study the impact of climate change on the load forecast.
ƒ 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 Efficient 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
ƒ 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.
ƒ Continue involvement in BPA transmission practice processes and rate proceedings to minimize costs of integrating existing resources outside of the Company’s service
area.
ƒ 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.
ƒ 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 will be revisited as items in
the 2009 Action Plan. Details about progress made towards the maintenance of existing
transmission rights, involvement in BPA 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 will 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 – Public Draft 9-3
Chapter 9 - Action Items
2009 Electric IRP9-4 Avista Corp
Chapter 9–Action Items
Resource Additions and Analysis
ƒ Continue to explore the potential for wind and non-renewable resources.
ƒ Issue an RFP for the Reardan wind site, and up to 100 MW of wind or other
renewables in 2009.
ƒ Finish studies regarding costs and environmental benefits of the large hydro
upgrades at Cabinet Gorge, Long Lake, Post Falls and Monroe Street.
ƒ Study potential locations for the natural gas-fired resource identified to be online
between 2015 and 2020.
ƒ Continue participation in regional IRP processes, and where agreeable find resource
opportunities to meet resource requirements on a collaborative basis.
Energy Efficiency
ƒ Pursue American Reinvestment and Recovery Act of 2009 funding for income
weatherization.
ƒ Analyze and report on results of the July 2007 through December 2009 demand
response pilot in Moscow and Sandpoint.
ƒ Have an external party do an updated study on technical, economic, achievable potential for energy efficiency in Avista’s service territory.
ƒ Study and quantify transmission and distribution efficiency concepts as they apply
toward meeting Washington RPS goals.
ƒ Update processes and protocols for conservation measurement, evaluation and
verification.
ƒ Determine potential impacts and costs of load management options.
Environmental Policy
ƒ Continue to study the potential impact of state and federal climate change
legislation.
ƒ Continue and report on the work of Avista’s Climate Change Committee.
Modeling and Forecasting Enhancements
ƒ Refine cost driver relationships in the stochastic model.
ƒ Continue to refine PRiSM by developing a resource retirement capability, adding the
ability to solve for other risk measurements and by adding more resource options.
ƒ 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.
ƒ Continue studying the impacts of climate change on the load forecast.
ƒ Stay load growth trends and their correlation to weather patterns.
Avista Corp 2009 Electric IRP – Public Draft 9-4
Chapter 9–Action Items
Transmission Planning
ƒ 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.
ƒ Continue involvement in BPA transmission practice processes and rate proceedings
to minimize costs of integrating existing resources outside of the Company’s service area.
ƒ 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.
ƒ Evaluate costs to integrate new resources across Avista’s service territory and from regions outside of the Northwest.
ƒ Study and implement distribution feeder rebuild projects to reduce system losses.
ƒ Study transmission reconfigurations to economically reduce system losses.
Avista Corp 2009 Electric IRP – Public Draft 9-5
2009 Electric IRPAvista Corp 9-5
Chapter 9 - Action ItemsChapter 9–Action Items
Resource Additions and Analysis
ƒ Continue to explore the potential for wind and non-renewable resources.
ƒ Issue an RFP for the Reardan wind site, and up to 100 MW of wind or other
renewables in 2009.
ƒ Finish studies regarding costs and environmental benefits of the large hydro
upgrades at Cabinet Gorge, Long Lake, Post Falls and Monroe Street.
ƒ Study potential locations for the natural gas-fired resource identified to be online
between 2015 and 2020.
ƒ Continue participation in regional IRP processes, and where agreeable find resource
opportunities to meet resource requirements on a collaborative basis.
Energy Efficiency
ƒ Pursue American Reinvestment and Recovery Act of 2009 funding for income
weatherization.
ƒ Analyze and report on results of the July 2007 through December 2009 demand
response pilot in Moscow and Sandpoint.
ƒ Have an external party do an updated study on technical, economic, achievable potential for energy efficiency in Avista’s service territory.
ƒ Study and quantify transmission and distribution efficiency concepts as they apply
toward meeting Washington RPS goals.
ƒ Update processes and protocols for conservation measurement, evaluation and
verification.
ƒ Determine potential impacts and costs of load management options.
Environmental Policy
ƒ Continue to study the potential impact of state and federal climate change
legislation.
ƒ Continue and report on the work of Avista’s Climate Change Committee.
Modeling and Forecasting Enhancements
ƒ Refine cost driver relationships in the stochastic model.
ƒ Continue to refine PRiSM by developing a resource retirement capability, adding the
ability to solve for other risk measurements and by adding more resource options.
ƒ 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.
ƒ Continue studying the impacts of climate change on the load forecast.
ƒ Stay load growth trends and their correlation to weather patterns.
Avista Corp 2009 Electric IRP – Public Draft 9-4
Chapter 9–Action Items
Transmission Planning
ƒ 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.
ƒ Continue involvement in BPA transmission practice processes and rate proceedings
to minimize costs of integrating existing resources outside of the Company’s service area.
ƒ 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.
ƒ Evaluate costs to integrate new resources across Avista’s service territory and from regions outside of the Northwest.
ƒ Study and implement distribution feeder rebuild projects to reduce system losses.
ƒ Study transmission reconfigurations to economically reduce system losses.
Avista Corp 2009 Electric IRP – Public Draft 9-5
Chapter 9 - Action Items
2009 Electric IRP9-6 Avista Corp
Chapter 9–Action Items
Production Credits
Primary 2009 IRP Team
Individual Contribution Contact
Clint Kalich, Manager of Resource Planning & Analysis Project Manager [e-mail]
James Gall, Senior Power
Supply Analyst
Modeling and Analysis
/Author
[e-mail]
John Lyons, Power Supply
Analyst
Research/Author/Editor [e-mail]
Randy Barcus, Chief Corporate Economist Load Forecast [e-mail]
Lori Hermanson, Partnership Solutions Manager Conservation [e-mail]
John Gibson, Senior
Efficiencies Engineer
Transmission &
Distribution
[e-mail]
Other Contributors
Jon Powell, Partnership Solutions Manager Bob Lafferty, Director of Power Supply
Greg Rahn, Manager of Natural Gas Planning Scott Waples, Chief System Planner
Kelly Irvine, Natural Gas Analyst Tracy Rolstad, Senior Planning Engineer II
Thomas Dempsey, Manager of Generation Joint Projects Steve Silkworth, Manager of Wholesale Marketing and Contracts
Avista Corp 2009 Electric IRP – Public Draft 9-6
1411 East Mission Avenue
Spokane, Washington 99202
509.489.0500
www.avistautilities.com