20130829Application for 2013 IRP.pdf

Safe Harbor Statement

This document contains forward-looking statements. Such statements are
subject to a variety of risks, uncertainties and other factors, most of which are
beyond the Company’s control, and many of which could have a significant
impact on the Company’s operations, results of operations and financial
condition, and could cause actual results to differ materially from those
anticipated.

For a further discussion of these factors and other important factors, please refer
to the Company’s reports filed with the Securities and Exchange Commission.
The forward-looking statements contained in this document speak only as of the
date hereof. 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. New factors emerge from time to time, and it is not
possible for management to predict all of such factors, nor can it assess the
impact of each such factor on the Company’s business or the extent to which any
such factor, or combination of factors, may cause actual results to differ
materially from those contained in any forward-looking statement.
Acronym List

AC: Alternating Current
aMW: Average Megawatt
AFUDC: Allowance for Funds Used During Construction
ARIMA: Auto Regressive Integrated Moving Average
BART: Best Available Retrofit Technology
BPA: Bonneville Power Administration
Btu: British Thermal Unit
CAA: Clean Air Act
CDD: Cooling Degree Days
CFL: Compact Fluorescent Light
CPA: Conservation Potential Assessment
CO2: Carbon Dioxide
COB: California Oregon Boarder
CT: Combustion Turbine
CCCT: Combined-Cycle Combustion Turbine
CPU: Central Processing Unit
DC: Direct Current
DLC: Direct Load Control
EIA: Energy Independence Act
EPA: Environmental Protection Agency
FERC: Federal Energy Regulatory Commission
FIPs: Federal Implementation Plans
GDP: Gross Domestic Product
HAPs: Hazardous Air Pollutants
HDD: Heating Degree Days
HRSG: Heat Recovery Steam Generator
HVAC: Heating, Ventilation, and Air Conditioning
IGCC: Integrated Gasification Combined-Cycle
IMHR: Implied Market Heat Rate
IPPs: Independent Power Producers
IPUC: Idaho Public Utilities Commission
IRP: Integrated Resource Plan
ITC: Investment Tax Credit
kV: Kilovolt
LGIR: Large Generator Interconnection Request
LNG: Liquid Natural Gas
LOLE: Loss of Load Expectation
LOLH: Loss of Load Hours
LOLP: Loss of Load Probability
LRC: Least Resource Cost
MATS: Mercury Air Toxic Standards
MSA: Metropolitan Statistical Area
MW: Megawatt
MWh: Megawatt Hours
NEEA: Northwest Energy Efficiency Alliance
NERC: North American Reliability Corporation
NOx: Nitrous Oxides
NPCC: Northwest Power and Conservation Council
NREL: National Renewable Energy Laboratory
NTTG: Northern Tier Transmission Group
NWPP: Northwest Power Pool
O&M: Operations and Maintenance
OATT: Open Access Transmission Tariff
OTC: Once Through Cooling
PNCA: Pacific Northwest Coordination Agreement
PRiSM: Preferred Resource Strategy Linear Programming Model
PRS: Preferred Resource Strategy
PSD: Prevention of Significant Deterioration
PM: Planning Margin
PTC: Production Tax Credit
PUDs: Public Utility Districts
RPS: Renewable Portfolio Standard
SCCT: Simple Cycle Combustion Turbine
SGDP: Smart Grid Demonstration Project
TAC: Technical Advisory Committee
TPC: Transmission Planning Committee
TRC: Total Resource Cost
UPC: Use-per-customer
UTC: Washington Utilities and Transportation Commission
WAC: Washington Administrative Code
WCI: Western Climate Initiative
WECC: Western Electricity Coordinating Council
WNP-3: Washington Nuclear Plant No. 3
WNU: Weather Normalized Usage
WSU: Washington State University
Table of Contents

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Table of Contents

Executive Summary ....................................................................................................................... i
Resource Needs ............................................................................................................................ i
Modeling and Results .................................................................................................................. iii
Electricity and Natural Gas Market Forecasts ............................................................................. iii
Energy Efficiency Acquisition ...................................................................................................... iv
Preferred Resource Strategy ....................................................................................................... v
Greenhouse Gas Emissions ..................................................................................................... viii
Action Items .................................................................................................................................. x
1. Introduction and Stakeholder Involvement ................................................................ 1-1
IRP Process ............................................................................................................................. 1-1
2013 IRP Outline ...................................................................................................................... 1-4
Regulatory Requirements ........................................................................................................ 1-5
2. Loads & Resources ....................................................................................................... 2-1
Introduction & Highlights .......................................................................................................... 2-1
Economic Characteristics of Avista’s Service Territory ............................................................ 2-1
Customer and Load Forecast Assumptions ............................................................................. 2-5
Native Load Forecast ............................................................................................................. 2-15
Peak Demand Forecast.......................................................................................................... 2-16
High and Low Load Growth Cases ........................................................................................ 2-18
Voluntary Renewable Energy Program (Buck-A-Block) ......................................................... 2-19
Customer-Owned Generation ................................................................................................ 2-20
Avista Resources and Contracts ............................................................................................ 2-22
Spokane River Hydroelectric Developments ......................................................................... 2-23
Clark Fork River Hydroelectric Developments ....................................................................... 2-24
Total Hydroelectric Generation .............................................................................................. 2-24
Thermal Resources ................................................................................................................ 2-25
Power Purchase and Sale Contracts ..................................................................................... 2-27
Reserve Margins .................................................................................................................... 2-30
Avista’s Loss of Load Analysis ............................................................................................... 2-32
Balancing Loads and Resources ........................................................................................... 2-34
Washington State Renewable Portfolio Standard .................................................................. 2-36
Resource Requirements ........................................................................................................ 2-37
3. Energy Efficiency .......................................................................................................... 3-1
Introduction ............................................................................................................................... 3-1
Conservation Potential Assessment Approach ........................................................................ 3-2
Overview of Energy Efficiency Potentials................................................................................. 3-5
Conservation Targets ............................................................................................................... 3-8
Comparison with the Sixth Power Plan Methodology .............................................................. 3-9
Avoided Cost Sensitivities ...................................................................................................... 3-10
Energy Efficiency-Related Financial Impacts ......................................................................... 3-12
Integrating Results into Business Planning and Operations .................................................. 3-13
Demand Response ................................................................................................................. 3-16
4. Policy Considerations ................................................................................................... 4-1
Environmental Issues ............................................................................................................... 4-1
Avista’s Climate Change Policy Efforts .................................................................................... 4-3
State and Federal Environmental Policy Considerations ......................................................... 4-4
EPA Regulations ...................................................................................................................... 4-5
5. Transmission & Distribution ........................................................................................ 5-1
Introduction ............................................................................................................................... 5-1
FERC Planning Requirements and Processes ........................................................................ 5-2
Regional Transmission System ................................................................................................ 5-4
Avista’s Transmission System ................................................................................................. 5-4
Transmission System Information for the 2013 IRP ................................................................ 5-5
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Distribution System Efficiencies ............................................................................................... 5-8
6. Generation Resource Options...................................................................................... 6-1
Introduction ............................................................................................................................... 6-1
Assumptions ............................................................................................................................. 6-1
Gas-Fired Combined Cycle Combustion Turbine .................................................................... 6-3
Hydroelectric Project Upgrades and Options ......................................................................... 6-15
Thermal Resource Upgrade Options ..................................................................................... 6-18
7. Market Analysis ............................................................................................................. 7-1
Introduction ............................................................................................................................... 7-1
Marketplace .............................................................................................................................. 7-2
Fuel Prices and Conditions ...................................................................................................... 7-7
Greenhouse Gas Emissions .................................................................................................. 7-12
Risk Analysis .......................................................................................................................... 7-12
Market Price Forecast ............................................................................................................ 7-19
Scenario Analysis ................................................................................................................... 7-24
High and Low Natural Gas Price Scenarios ........................................................................... 7-28
8. Preferred Resource Strategy ........................................................................................ 8-1
Introduction ............................................................................................................................... 8-1
Supply-Side Resource Acquisitions ......................................................................................... 8-1
Resource Deficiencies.............................................................................................................. 8-5
Preferred Resource Strategy ................................................................................................... 8-8
Efficient Frontier Analysis ....................................................................................................... 8-16
Determining the Avoided Costs of Energy Efficiency ............................................................. 8-19
Determining the Avoided Cost of New Generation Options ................................................... 8-20
Efficient Frontier Comparison of Greenhouse Gas Policies ................................................... 8-21
Energy Efficiency Scenarios .................................................................................................. 8-23
Colstrip ................................................................................................................................... 8-26
Other Portfolio Scenarios ....................................................................................................... 8-31
9. Action Items ................................................................................................................... 9-1
Summary of the 2011 IRP Action Plan..................................................................................... 9-1
2013 IRP Action Plan ............................................................................................................... 9-5
Production Credits .................................................................................................................... 9-7

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Table of Figures

Figure 1: Load-Resource Balance—Winter 18 Hour Capacity .......................................................... i
Figure 2: Load-Resource Balance—Summer 18 Hour Capacity ..................................................... ii
Figure 3: Load-Resource Balance—Energy ..................................................................................... ii
Figure 4: Average Mid-Columbia Electricity Price Forecast ............................................................ iii
Figure 5: Stanfield Natural Gas Price Forecast ............................................................................... iv
Figure 6: Cumulative Energy Efficiency Acquisitions ....................................................................... v
Figure 7: Efficient Frontier ............................................................................................................... vi
Figure 8: Avista’s Qualifying Renewables for Washington State’s EIA ......................................... viii
Figure 8: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions ......................... ix
Figure 9: U.S. Western Interconnect Greenhouse Gas Emissions ................................................. ix
Figure 2.1: Avista’s Service Territory............................................................................................ 2-2
Figure 2.2: Population Levels 1970 – 2011 .................................................................................. 2-2
Figure 2.3: Population Growth and U.S. Recessions, 1971-2011 ................................................ 2-3
Figure 2.4: Employment Breakdown by Major Sector, 2011 ........................................................ 2-4
Figure 2.5: Post Recession Employment Growth, June 2009-December 2012 ........................... 2-4
Figure 2.6: Personal Income Breakdown by Major Source, 2011 ................................................ 2-5
Figure 2.7: Population Forecast, 2013-2035 ................................................................................ 2-7
Figure 2.8: House Start History and Forecast (2000-2035) ......................................................... 2-8
Figure 2.9: Annual Growth in Use per Customer 2006 - 2012 ................................................... 2-10
Figure 2.10: Area Average Household Size, Historical and Forecast 1990-2035 ...................... 2-12
Figure 2.11: Residential Use per Customer, 2006-2035 ............................................................ 2-14
Figure 2.12: Avista’s Customer Growth, 1997-2033 .................................................................. 2-15
Figure 2.13: Native Load History and Forecast, 1997-2035 ...................................................... 2-16
Figure 2.14: Winter and Summer Peak Demand, 1997-2035 .................................................... 2-18
Figure 2.15: Load Growth Scenarios, 2014-2035 ...................................................................... 2-19
Figure 2.16: 15 kW Photovoltaic Installation in Rathdrum, ID .................................................... 2-20
Figure 2.17: Buck-A-Block Customer and Demand Growth ....................................................... 2-20
Figure 2.18: Net Metering Customers ........................................................................................ 2-21
Figure 2.19: Solar Energy Transfer Payments ........................................................................... 2-22
Figure 2.20: 2020 Market Reliance & Capacity Cost Tradeoffs to Achieve 5 Percent LOLP .... 2-33
Figure 2.21: Winter 1 Hour Capacity Load and Resources ........................................................ 2-34
Figure 2.22: Summer 18-Hour Capacity Load and Resources .................................................. 2-35
Figure 2.23: Annual Average Energy Load and Resources ....................................................... 2-36
Figure 3.1: Historical and Forecast Conservation Acquisition (system) ....................................... 3-2
Figure 3.2: Analysis Approach Overview ..................................................................................... 3-4
Figure 3.3: Cumulative Conservation Potentials, Selected Years ................................................ 3-7
Figure 5.1: Avista Transmission Map ........................................................................................... 5-5
Figure 5.2: Spokane’s 9th and Central Feeder (9CE12F4) Outage History ................................ 5-10
Figure 6.1: Solar’s Effect on California Load ................................................................................ 6-7
Figure 6.2: New Resource Levelized Costs (first 20 Years) ...................................................... 6-14
Figure 6.3: Historical and Planned Hydro Upgrades .................................................................. 6-16
Figure 7.1: NERC Interconnection Map ....................................................................................... 7-2
Figure 7.2: 20-Year Annual Average Western Interconnect Energy ............................................ 7-3
Figure 7.3: Resource Retirements (Nameplate Capacity) ........................................................... 7-5
Figure 7.4: Cumulative Generation Resource Additions (Nameplate Capacity) .......................... 7-6
Figure 7.5: Henry Hub Natural Gas Price Forecast ...................................................................... 7-8
Figure 7.6: Northwest Expected Energy ..................................................................................... 7-11
Figure 7.7: Regional Wind Expected Capacity Factors .............................................................. 7-12
Figure 7.8: Historical Stanfield Natural Gas Prices (2004-2012) ............................................... 7-13
Figure 7.9: Stanfield Annual Average Natural Gas Price Distribution ........................................ 7-14
Figure 7.10: Stanfield Natural Gas Distributions ........................................................................ 7-14
Figure 7.11: Wind Model Output for the Northwest Region ....................................................... 7-18
Figure 7.12: 2012 Actual Wind Output BPA Balancing Authority ............................................... 7-19
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Figure 7.13: Mid-Columbia Electric Price Forecast Range ........................................................ 7-21
Figure 7.14: Western States Greenhouse Gas Emissions ......................................................... 7-23
Figure 7.15: Base Case Western Interconnect Resource Mix ................................................... 7-24
Figure 7.16: Mid-Columbia Prices Comparison with and without Coal Plant Retirements ........ 7-25
Figure 7.17: Western U.S. Carbon Emissions Comparison ....................................................... 7-26
Figure 7.18: Greenhouse Gas Pricing Scenarios ....................................................................... 7-27
Figure 7.19: Nominal Mid-Columbia Prices for Alternative Greenhouse Gas Policies .............. 7-27
Figure 7.20: Annual Greenhouse Gas Emissions for Alternative Greenhouse Gas Policies ..... 7-28
Figure 7.21: Annual Natural Gas Price Forecast Scenarios ...................................................... 7-29
Figure 7.22: Natural Gas Price Scenario’s Mid-Columbia Price Forecasts................................ 7-29
Figure 7.23: Implied Market Heat Rate Changes ....................................................................... 7-30
Figure 7.24: Changes to Mid-Columbia Prices and Western US Greenhouse Gas Levels ....... 7-31
Figure 8.1: Resource Acquisition History ..................................................................................... 8-2
Figure 8.2: Conceptual Efficient Frontier Curve ........................................................................... 8-4
Figure 8.3: Physical Resource Positions (Includes Energy Efficiency) ........................................ 8-6
Figure 8.4: REC Requirements vs. Qualifying RECs for Washington State EIA ......................... 8-7
Figure 8.5: Energy Efficiency Annual Expected Acquisition ....................................................... 8-10
Figure 8.6: Load Forecast with/without Energy Efficiency.......................................................... 8-10
Figure 8.7: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions ................. 8-12
Figure 8.8: Power Supply Expense Range ................................................................................ 8-14
Figure 8.9: Real Power Supply Expected Rate Growth Index $/MWh (2012 = 100) ................. 8-15
Figure 8.10: Expected Case Efficient Frontier ............................................................................ 8-18
Figure 8.11: Efficient Frontier Comparison ................................................................................. 8-23
Figure 8.12: Efficient Frontier Comparison ................................................................................. 8-25
Figure 8.13: 2018-33 Power Supply Costs with and without Colstrip Units 3 and 4 .................. 8-27
Figure 8.14: Greenhouse Gas Emissions without Colstrip Units 3 and 4 .................................. 8-28
Figure 8.15: Change to Power Supply Cost without Colstrip ..................................................... 8-28
Figure 8.16: Change to Power Supply Cost without Colstrip ..................................................... 8-29
Figure 8.17: Annual Levelized Cost (2027-33) of Colstrip Scenarios ........................................ 8-31
Figure 8.18: Load Growth Scenario’s Cost/Risk Comparison .................................................... 8-35
Figure 8.19: Resource Specific Scenarios ................................................................................. 8-37

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Table of Tables

Table 1: The 2013 Preferred Resource Strategy ............................................................................. v
Table 2: The 2011 Preferred Resource Strategy ........................................................................... vii
Table 1.1: TAC Meeting Dates and Agenda Items ....................................................................... 1-2
Table 1.2: External Technical Advisory Committee Participating Organizations ......................... 1-3
Table 1.3 Idaho IRP Requirements .............................................................................................. 1-6
Table 1.4 Washington IRP Rules and Requirements ................................................................... 1-6
Table 2.1: U.S. Long-run Baseline Forecast Assumptions, 2013-2035 ....................................... 2-6
Table 2.2: Avista WA-ID MSAs Baseline Forecast Assumptions, 2013-2035 ............................. 2-6
Table 2.3: Customer Growth Correlations, January 2006-December 2012 ............................... 2-14
Table 2.4: Average Day Spokane Temperatures 1890-2012 (Degrees Fahrenheit) ................. 2-17
Table 2.5: Avista-Owned Hydro Resources ............................................................................... 2-25
Table 2.6: Avista-Owned Thermal Resources ............................................................................ 2-27
Table 2.7: Mid-Columbia Capacity and Energy Contracts ......................................................... 2-28
Table 2.8: PURPA Agreements .................................................................................................. 2-29
Table 2.9: Other Contractual Rights and Obligations ................................................................. 2-30
Table 2.10: Regional Load & Resource Balance ....................................................................... 2-32
Table 2.11: Washington State RPS Detail (aMW) ...................................................................... 2-38
Table 2.12: Winter 18-Hour Capacity Position (MW) ................................................................. 2-39
Table 2.13: Summer 18-Hour Capacity Position (MW) .............................................................. 2-40
Table 2.14: Average Annual Energy Position (aMW) ................................................................. 2-41
Table 3.1: Cumulative Potential Savings (Across All Sectors for Selected Years) ..................... 3-7
Table 3.2: Annual Achievable Potential Energy Efficiency (aMW) ............................................... 3-8
Table 5.1: IRP Requested Transmission Upgrade Studies .......................................................... 5-7
Table 5.2: Third-Party Large Generation Interconnection Requests ............................................ 5-8
Table 5.3: Completed Feeder Rebuilds ........................................................................................ 5-9
Table 5.4: Planned Feeder Rebuilds .......................................................................................... 5-10
Table 6.1: Natural Gas Fired Plant Cost and Operational Characteristics ................................... 6-5
Table 6.2: Natural Gas-Fired Plant Levelized Costs per MWh .................................................... 6-5
Table 6.4: Northwest Wind Project Levelized Costs per MWh ..................................................... 6-6
Table 6.4: Solar Nominal Levelized Cost ($/MWh) ...................................................................... 6-8
Table 6.5: Coal Capital Costs ....................................................................................................... 6-9
Table 6.6: Coal Project Levelized Cost per MWh ......................................................................... 6-9
Table 6.7: Other Resource Options Levelized Costs ($/MWh) .................................................. 6-13
Table 6.8: New Resource Levelized Costs Considered in PRS Analysis .................................. 6-15
Table 6.9: New Resource Levelized Costs Not Considered in PRS Analysis ........................... 6-15
Table 6.10: Hydro Upgrade Option Costs and Benefits ............................................................. 6-18
Table 7.1: AURORAXMP Zones ..................................................................................................... 7-2
Table 7.2: Western Interconnect Transmission Upgrades Included in Analysis .......................... 7-4
Table 7.3: Natural Gas Price Basin Differentials from Henry Hub ............................................... 7-9
Table 7.4: Monthly Price Differentials for Stanfield from Henry Hub ............................................ 7-9
Table 7.5: January through June Load Area Correlations ......................................................... 7-15
Table 7.6: July through December Load Area Correlations ....................................................... 7-16
Table 7.7: Area Load Coefficient of Determination (Standard Deviation/Mean) ........................ 7-16
Table 7.8: Area Load Coefficient of Determination (Standard Deviation/Mean) ........................ 7-16
Table 7.9: Expected Capacity factor by Region ......................................................................... 7-18
Table 7.10: Annual Average Mid-Columbia Electric Prices ($/MWh) ......................................... 7-22
Table 8.1: Qualifying Washington EIA Resources ....................................................................... 8-7
Table 8.2: 2013 Preferred Resource Strategy .............................................................................. 8-8
Table 8.3: 2011 Preferred Resource Strategy .............................................................................. 8-9
Table 8.4: PRS Rate Base Additions from Capital Expenditures ............................................... 8-13
Table 8.5: Avista Medium-Term Winter Peak Hour Capacity Tabulation ................................... 8-16
Table 8.6: Avista Medium-Term Summer 18-Hour Sustained Peak Capacity Tabulation ......... 8-16
Table 8.7: Efficient Frontier Sample Resource Mixes ................................................................ 8-18
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Table 8.8: Nominal Levelized Avoided Costs of the PRS ($/MWh) ........................................... 8-20
Table 8.9: Updated Annual Avoided Costs ($/MWh).................................................................. 8-21
Table 8.10: Alternative PRS with National Climate Change Legislation .................................... 8-22
Table 8.11: Preferred Portfolio Cost and Risk Comparison (Millions $) ..................................... 8-23
Table 8.12: Preferred Portfolio Cost and Risk Comparison for Avoided Cost Studies .............. 8-25
Table 8.13: No Colstrip Resource Strategy Scenario................................................................. 8-26
Table 8.14: Policy Portfolio Scenarios ........................................................................................ 8-33
Table 8.15: Load Growth Sensitivities ........................................................................................ 8-35
Table 8.16: Winter 1 Hour Capacity Position (MW) with New Resources.................................. 8-38
Table 8.16: Summer 18-Hour Capacity Position (MW) with New Resources ............................ 8-39
Table 8.17: Average Annual Energy Position (aMW) With New Resources .............................. 8-40

2013 Electric IRP Introduction

Avista has a long tradition of innovation as a provider of a safe, reliable, low-cost, and
clean, mix of generation resources. The 2013 Integrated Resource Plan (IRP) continues
this legacy by looking into the future energy needs of our customers. The IRP analyzes
and outlines a strategy to meet projected demand and renewable portfolio standards
through energy efficiency and a careful mix of new renewable and traditional energy
resources.

Avista currently projects having adequate resources, between owned and contractually
controlled generation, to meet our customers’ needs until 2020. Plant upgrades, energy
efficiency measures and in the longer term additional natural gas-fired generation are
integral parts of Avista’s 2013 IRP resource strategy.

Two significant changes from the 2011 IRP should be noted:
The 2011 IRP recommendations for new renewable resources have been met
with a 30-year purchased power agreement with Palouse Wind, and the Kettle
Falls Generating Station being qualified as a renewable energy resource under
Washington state’s Energy Independence Act; and
Load growth is expected to be at just over 1 percent, a decline from the growth of
1.6 percent forecast in 2011. This delays the need for a new natural gas-fired
resource by one year.

Each IRP is a thoroughly researched and data-driven document to guide responsible
resource planning for the company. 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 with input from interested community,
educational and state utility commission stakeholders.

The plan’s Preferred Resource Strategy (PRS) section covers Avista’s projected
resource acquisitions over the next 20 years.

Some highlights of the 2013 PRS include:
Demand response (temporarily reducing the demand for energy) is included in
the PRS for the first time and could provide 19 MW of peak energy reduction in
the 2022 – 2027 timeframe.
Energy efficiency (using less energy to perform activities) reduces load growth by
42 percent over the next 20 years.
486 MW of additional clean-burning natural gas-fired generation facilities are
required between 2020 and 2033.
Transmission upgrades will be needed to carry the output from new generation.
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 2015 IRP in early 2014. 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.
Executive Summary
Avista Corp 2013 Electric IRP
Executive Summary
Avista Corporation’s 2013 Electric Integrated Resource Plan (IRP) guides its resource
strategy over the next two years and directs resource procurements over the 20-year
plan. It provides a snapshot of Avista’s resources and loads and guides future resource
acquisitions over a range of expected and possible future conditions. The 2013
Preferred Resource Strategy (PRS) includes energy efficiency, upgrades at existing
generation and distribution facilities, demand response and new gas-fired generation.

The PRS balances cost, reliability, rate volatility, and renewable resource requirements.
Avista’s management and the Technical Advisory Committee (TAC) guide the
development of the PRS and the IRP by providing significant input on modeling and
planning assumptions. TAC members include customers, commission staff, the
Northwest Power and Conservation Council, consumer advocates, academics, utility
peers, government agencies, and interested internal parties.

Resource Needs
Avista’s peak planning methodology includes operating reserves, regulation, load
following, wind integration and a planning margin. Avista currently projects having
adequate resources between owned and contractually controlled generation to meet
annual physical energy and capacity needs until 2020. Chapter 2 explains the peak
planning methodology. See Figures 1 – 3 for Avista’s physical resource positions for
winter capacity, summer capacity, and annual energy load and resource balances.

Figure 1: Load-Resource Balance—Winter 18 Hour Capacity

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Executive Summary
Avista Corp 2013 Electric IRP
Figure 2: Load-Resource Balance—Summer 18 Hour Capacity

Figure 3: Load-Resource Balance—Energy

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Executive Summary
Avista Corp 2013 Electric IRP
Figures 1 – 3 include the effects of new energy efficiency programs on the load
forecast. Absent energy efficiency, Avista would be resource deficient earlier. The
region has a significant summer capacity surplus; Avista plans to meet all summer
capacity needs with term purchases. A short-term capacity need exists in the winters of
2014/15 and 2015/16. This capacity need is short-lived because a 150 MW capacity
sale contract ends in 2016. Avista expects to address these short-term deficits with
market purchases; therefore, the first long-term capacity deficit begins in 2020.

Modeling and Results
Avista uses a multiple-step approach to develop its PRS. It begins by identifying and
quantifying potential new generation resources to serve projected electricity demand
across the West. A Western Interconnect-wide study explains the impact of regional
markets on the Northwest electricity marketplace. Avista then maps its existing
resources to the present transmission grid configuration in a model simulating hourly
operations for the Western Interconnect from 2014 to 2033. The model adds cost-
effective new resources and transmission across the Western Interconnect to meet
overall projected loads. Monte Carlo-style analysis varies hydroelectric and wind
generation, loads, forced outages and natural gas price data over 500 iterations of
potential future market conditions. The simulation estimates Mid-Columbia electricity
market prices by iteration and the results of the 500 iterations form the Expected Case.

Electricity and Natural Gas Market Forecasts
Figure 4 shows the 2013 IRP electricity price forecast for the Expected Case, including
the price range over the 500 Monte Carlo iterations. The forecasted levelized average
Mid-Columbia market price is $44.08 per MWh in nominal dollars over 20 years.

Figure 4: Average Mid-Columbia Electricity Price Forecast

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Executive Summary
Avista Corp 2013 Electric IRP
Electricity and natural gas prices are highly correlated because natural gas fuels
marginal generation in the Northwest during most of the year. Figure 5 presents nominal
levelized Expected Case natural gas prices at the Stanfield trading hub, located in
northeastern Oregon, as well as the forecast range from the 500 Monte Carlo iterations
performed for the case. The average is $5.40 per dekatherm over the next 20 years.
See Chapter 7 for details on the company’s natural gas price forecast.

Figure 5: Stanfield Natural Gas Price Forecast

Energy Efficiency Acquisition
Avista commissioned a 20-year Conservation Potential Assessment in 2013. The study
analyzed over 4,300 energy efficiency equipment and measure options for residential,
commercial, and industrial applications. Data from this study formed the basis of the
IRP conservation potential evaluations. Figure 6 shows how historical efforts in energy
efficiency decrease Avista’s energy requirements by 125 aMW, or approximately ten
percent. By 2033, energy efficiency reduces load by 164 aMW. More detail about
Avista’s energy efficiency programs is contained in Chapter 3.

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Executive Summary
Avista Corp 2013 Electric IRP
Figure 6: Cumulative Energy Efficiency Acquisitions

Preferred Resource Strategy
The PRS includes careful consideration by Avista’s management and the TAC of the
information gathered and analyzed in the IRP process. It meets future load growth with
efficiency upgrades at existing generation and distribution facilities, conservation, wind,
and natural gas-fired technologies as shown in Table 1.

Table 1: The 2013 Preferred Resource Strategy

Resource By the End of
Year
Nameplate
(MW)
Energy
(aMW)
Simple Cycle CT 2019 83 76
Simple Cycle CT 2023 83 76
Combined Cycle CT 2026 270 248
Rathdrum CT Upgrade 2028 6 5
Simple Cycle CT 2032 50 46
Total 492 451
Efficiency Improvements Acquisition
Range
Peak
Reduction
Energy
(aMW)
Energy Efficiency 2014-2033 221 164
Demand Response 2022-2027 19 0
Distribution Efficiencies 2014-2017 <1 <1
Total 240 164

The 2013 PRS describes a reasonable low-cost plan along the efficient frontier of
potential resource portfolios accounting for fuel supply risk and price risk. Major
changes from the 2011 PRS include reduced contributions from conservation, wind, and
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Executive Summary
Avista Corp 2013 Electric IRP
natural gas-fired resources. For the first time the PRS includes a modest contribution
from demand response.

Each new resource and energy efficiency option is valued against the Expected Case
Mid-Columbia electricity market to identify its future value to Avista, as well as its
inherent risk measured by year-to-year portfolio cost volatility. These values, and their
associated capital and fixed operation and maintenance (O&M) costs, form the input
into Avista’s Preferred Resource Strategy Linear Programming Model (PRiSM). PRiSM
assists Avista by developing optimal mixes of new resources along an efficient frontier.
Chapter 8 provides a detailed discussion of the efficient frontier concept.

The PRS provides a “least reasonable cost” portfolio that minimizes future costs and
risks given actual or expected environmental constraints. An efficient frontier helps
determine the tradeoffs between risk and cost. The approach is similar to finding an
optimal mix of risk and return in an investment portfolio. As expected returns increase,
so do risks. Reducing risk reduces overall returns. There is a trade-off between power
supply costs and power supply cost variability. Figure 7 presents the change in cost and
risk from the PRS on the Efficient Frontier. Lower power cost variability comes from
investments in more expensive, but less risky, resources. The PRS selection is the
location on the efficient frontier where reduced risk justifies the increased cost.

Figure 7: Efficient Frontier

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Preferred Resource Strategy
Executive Summary
Avista Corp 2013 Electric IRP
The IRP includes several scenarios to identify tipping points where the PRS could
change under conditions alternative to the Expected Case. Chapter 8 includes
scenarios for load growth, capital costs, higher energy efficiency acquisitions, and
greenhouse gas policies.

The 2013 PRS is significantly different from the 2011 IRP resource strategy; the 2011
PRS is in Table 2. Since the prior plan, Avista’s renewable and capacity needs have
changed. Adding Palouse Wind to Avista’s resource mix in December 2012 satisfied the
2012 Northwest Wind component of the 2011 PRS. Changes in the Washington State
Energy Independence Act (EIA) eliminated the need for a 2019/2020 wind resource.
The amendment under SB 5575 adds the Kettle Falls Generating Station, and other
legacy biomass plants, as EIA qualifying resources beginning in 2016. The 2011 IRP
forecast 1.6 percent annual load growth, while this IRP forecasts just over 1 percent
growth (see Chapter 2). Lower expected load growth delays the first natural gas-fired
resource need by one year and eliminates the need for a combined cycle combustion
turbine in 2023.

Table 2: The 2011 Preferred Resource Strategy

Resource By the End of
Year
Nameplate
(MW)
Energy
(aMW)
Northwest Wind 2012 120 35
Simple Cycle CT 2018 83 75
Existing Thermal Resource Upgrades 2019 4 3
Northwest Wind 2019-2020 120 35
Simple Cycle CT 2020 83 75
Combined Cycle CT 2023 270 237
Combined Cycle CT 2026 270 237
Simple Cycle CT 2029 46 42
Total 996 739
Efficiency Improvements Acquisition
Range
Peak
Reduction
(MW)
Energy
(aMW)
Distribution Efficiencies 2012-2031 28 13
Energy Efficiency 2012-2031 419 310
Total 447 323

Washington voters approved the EIA through Initiative 937 in the November 2006
general election. The EIA requires utilities with over 25,000 customers to meet 3
percent of retail load from qualified renewable resources by 2012, 9 percent by 2016,
and 15 percent by 2020. The initiative also requires utilities to acquire all cost-effective
conservation and energy efficiency measures.

Avista expects to meet or exceed its renewable energy requirements through the 20-
year plan with a combination of qualifying hydroelectric upgrades, the Palouse Wind
project, the Kettle Falls Generating Station and selective renewable energy certificate
(REC) purchases. A list of the qualifying generation projects and the associated
Executive Summary
Avista Corp 2013 Electric IRP
expected output is in Table 8 below. The flexibility of I-937 to use RECs from the current
year, from the previous year, or from the following year for compliance helps Avista
mitigate year-to-year variability in the output of qualifying renewable resources.

Figure 8: Avista’s Qualifying Renewables for Washington State’s EIA

Greenhouse Gas Emissions
Forecasts of greenhouse gas emissions costs have been included as part of Avista’s
Expected Case since the 2007 IRP. Based on current legislative priorities and the
President’s Climate Action Plan, a national greenhouse gas cap-and-trade system or
tax is no longer likely. Therefore, the Expected Case does not include a market or tax
solution to reduce emissions. Instead, because the states and the EPA are
implementing regulatory models limiting emissions for new facilities, and requiring
current facilities to either implement best available control technologies or shut down,
this IRP forecasts significant numbers of plant retirements to meet these environmental
rules. Figure 9 shows projected greenhouse gas emissions for existing and new Avista
generation assets, but it does not account for emissions from market purchases or
sales. While Avista’s emissions increase modestly, western region emissions fall from
historic levels as less-cost-effective coal and older natural gas-fired plants retire (see
Figure 10). Avista does not follow this overall trajectory because the carbon intensity of
its portfolio already is relatively low. More details about state and federal greenhouse
gas policies are in chapter 4.
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Executive Summary
Avista Corp 2013 Electric IRP
Figure 9: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions

Figure 10: U.S. Western Interconnect Greenhouse Gas Emissions

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Executive Summary
Avista Corp 2013 Electric IRP
Action Items
The 2013 Action Plan updates progress on the 2011 Action Items and outlines activities
Avista intends to perform for the 2015 IRP. It includes input from Commission Staff,
Avista’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. Chapter 9 and discusses the
new Action Items.
Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2013 Electric IRP
1. Introduction and Stakeholder Involvement

Avista submits an IRP to the Idaho and Washington public utility commissions
biennially.1 The 2013 IRP is Avista’s thirteenth plan. It identifies and describes a PRS
for meeting load growth while balancing cost and risk measures with environmental
mandates.

Avista is statutorily obligated to provide reliable electricity service to its customers at
rates, terms, and conditions that are fair, just, reasonable, and sufficient. Avista
assesses different resource acquisition strategies and business plans to acquire
resources to meet resource adequacy requirements and optimize the value of its current
resource portfolio. The IRP is a resource evaluation tool rather than a plan for acquiring
a particular set of assets. The 2013 IRP continues refining Avista’s resource acquisition
efforts.

IRP Process
The 2013 IRP is developed and written with the aid of a public process. Avista actively
seeks input for its IRPs from a variety of constituents through the TAC. The TAC is 75
participants including Commission Staff from Idaho and Washington, customers,
academics, government agencies, consultants, utilities, and other interested parties who
accepted an invitation to join, or had asked to be involved in, the planning process.

Avista sponsored six TAC meetings for the 2013 IRP. The first meeting was on May 23,
2012, and the last was on June 19, 2013. TAC meetings cover different aspects of the
2013 IRP planning activities and solicited contributions to, and assessments of,
modeling assumptions, modeling processes, and results. Table 1.1 contains a list of
TAC meeting dates and the agenda items covered in each meeting.

Agendas and presentations from the TAC meetings are in Appendix A and on Avista’s
website at http://www.avistautilities.com/inside/resources/irp/electric. Past IRPs and
TAC presentations are also here.

1 Washington IRP requirements are contained in WAC 480-100-238 Integrated Resource Planning. Idaho
IRP requirements are 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.
Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2013 Electric IRP
Table 1.1: TAC Meeting Dates and Agenda Items

Meeting Date Agenda Items
TAC 1 – May 23, 2012 Powering our Future Game
2011 Renewable RFP
Palouse Wind Project Update
2011 IRP Acknowledgement
Energy Independence Act Compliance and
Forecast
Work Plan
TAC 2 – September 4 and 5,
2012
Palouse Wind Project Tour
Avista REC Planning Methods
Energy and Economic Forecast
Shared Value Report
Generation Options
Spokane River Assessment
TAC 3 – November 7, 2012 Electricity Market Modeling
Colstrip Discussion
Energy Efficiency
Peak Load Forecast
Reliability Planning
Energy Storage
TAC 4 – February 6, 2013 Natural Gas Price Forecast
Electric Price Forecast
Transmission Planning
Resource Needs Assessment
Market & Portfolio Scenario Development
TAC 5 – March 20, 2013 Market Forecast Scenario Results
Conservation Avoided Costs
Demand Response
Draft 2013 IRP Preferred Resource Strategy
Portfolio Scenarios
TAC 6 – June 19, 2013 2013 Final Preferred Resource Strategy
Portfolio Scenario Analysis
Net Metering and Buck-A-Block
Action Plan
2013 IRP Document Introduction

Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2013 Electric IRP
Avista wishes to acknowledge and thank all of the organizations identified in Table 1.2
who participated in the TAC process.

Table 1.2: External Technical Advisory Committee Participating Organizations

Organization
AES Corporation
Alexander Boats, LLC
Ameresco Quantum
City of Spokane
Clearwater Paper
Eastern Washington University
EnerNOC Utility Solutions
Eugene Water & Electric Board
First Wind
GE Energy
Gonzaga University
Grant PUD
Greater Spokane Incorporated
Idaho Power
Idaho Public Utilities Commission
Inland Power & Light
Puget Sound Energy
Residential and Small Commercial Customers
Sierra Club
TransAlta
Washington Department of Enterprise Services
Washington State Legislature
Washington Utilities and Transportation Commission
Winfiniti

Issue Specific Public Involvement Activities
In addition to the TAC meetings, Avista sponsors and participates in several other
collaborative processes involving a range of public interests.

External Energy Efficiency (“Triple E”) Board
The Triple E Board, formed in 1995, provides stakeholders and public groups biannual
opportunities to discuss Avista’s energy efficiency efforts. The Triple E Board grew out
of the DSM Issues group.

FERC Hydro Relicensing – Clark Fork and Spokane 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 FERC relicensing
application, and eventual issuance of a 45-year FERC operating license in February
2003. This collaborative process continues in the implementation of the license and
Clark Fork Settlement Agreement, with stakeholders participating in various protection,
mitigation, and enhancement efforts. More recently, Avista received a 50-year license
for the Spokane River Project following a multi-year collaborative process involving
Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2013 Electric IRP
several hundred stakeholders. Implementation began in 2009 with a variety of
collaborating parties.

Low Income Rate Assistance Program
This program is coordinated with four community action agencies in Avista’s
Washington service territory. The program began in 2001 and reviews administrative
issues and needs on a quarterly basis.

Regional Planning
The Pacific Northwest’s generation and transmission system operates in a coordinated
fashion. Avista participates in the efforts of many organization’s planning processes.
Information from this participation supplements Avista’s IRP process. Some of the
organizations that 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
North American Electric Reliability Council

Future Public Involvement
As previously explained, Avista actively solicits input from interested parties to enhance
its IRP process. We continue to expand TAC membership and diversity, and maintain
the TAC meetings as an open public process.

2013 IRP Outline
The 2013 IRP consists of nine chapters plus an executive summary and this
introduction. A series of technical appendices supplement this report.

Executive Summary
This chapter summarizes the overall results and highlights of the 2013 IRP.

Chapter 1: Introduction and Stakeholder Involvement
This chapter introduces the IRP and details public participation and involvement in the
integrated resource planning process.

Chapter 2: Loads and Resources
The first half of this chapter covers Avista’s load forecast and related local economic
forecasts. The last half describes Avista’s owned generating resources, major
contractual rights and obligations, capacity, energy and renewable energy credit
tabulations, and reserve obligations.

Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2013 Electric IRP
Chapter 3: Energy Efficiency
This chapter discusses Avista’s energy efficiency programs. It provides an overview of
the conservation potential assessment and summarizes the energy efficiency modeling
results for the 2013 IRP.

Chapter 4: Policy Considerations
This chapter focuses on some of the major policy issues for resource planning,
including state and federal greenhouse gas policies and environmental regulations.

Chapter 5: Transmission & Distribution
This chapter discusses Avista’s distribution and transmission systems, as well as
regional transmission planning issues. It includes detail on transmission cost studies
used in the IRP modeling and a summary of the 10-year Transmission Plan. The
chapter finishes with a discussion of Avista’s distribution efficiency and grid
modernization projects.

Chapter 6: Generation Resource Options
This chapter covers the costs and operating characteristics of the generation resource
options modeled for the 2013 IRP.

Chapter 7: Market Analysis
This chapter details Avista’s IRP modeling and analysis of the various wholesale
markets applicable to the 2013 IRP.

Chapter 8: Preferred Resource Strategy
This chapter details Avista’s 2013 Preferred Resource Strategy (PRS) and explains how
the PRS could change in response to scenarios differing from the Expected Case.

Chapter 9: Action Items
This chapter discusses progress made on Action Items from the 2011 IRP. It details
new Action Items for the 2015 IRP.

Regulatory Requirements
The IRP process for Idaho has several requirements documented in IPUC Orders Nos.
22299 and 24729. Table 1.3 summarizes the applicable IRP requirements.

Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2013 Electric IRP
Table 1.3 Idaho IRP Requirements

Requirement Plan Citation
Identify and list relevant operating characteristics
of existing resources by categories including:
hydroelectric, coal-fired, oil or gas-fired, PURPA
(by type), exchanges, contracts, transmission
resources, and others.
Chapter 2- Loads & Resources
Identify and discuss the 20-year load forecast
plus scenarios for the different customer classes.
Identify the assumptions and models used to
develop the load forecast.
Chapter 2- Loads & Resources
Chapter 8- Preferred Resource Strategy
Identify the utility’s plan to meet load over the 20-
year planning horizon. Include costs and risks of
the plan under a range of plausible scenarios.
Chapter 8- Preferred Resource Strategy
Identify energy efficiency resources and costs. Chapter 3- Energy Efficiency
Provide opportunities for public participation and
involvement.
Chapter 1- Introduction and Stakeholder
Involvement

The IRP process for Washington has several requirements documented in Washington
Administrative Code (WAC). Table 1.4 summarizes where within the IRP the applicable
WACs are addressed.

Table 1.4 Washington IRP Rules and Requirements

Rule and Requirement Plan Citation
–

–
–

–
–

–

–
–

–

–

Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2013 Electric IRP
WAC 480-100-238(2)(b) – LRC analysis
considers resource effect on system operation.
Chapter 7- Market Analysis
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC analysis
considers risks imposed on ratepayers.
Chapter 4- Policy Considerations
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- Policy Considerations
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- Policy Considerations
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 & 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 & 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 & 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

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 Options
Chapter 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
Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2013 Electric IRP
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
WAC 480-107-015(3) – Proposed request for
proposals for new capacity needed within three
years of the IRP.
Chapter 8- Preferred Resource Strategy

Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-1
2. Loads & Resources

Introduction & Highlights
An explanation and quantification of Avista’s loads and resources are integral to the
IRP. The load section of this chapter summarizes customer and load forecasts, load
growth scenarios, and enhancements to forecasting models and processes. The
resource section of the chapter covers Avista’s current resource mix, including
descriptions of owned and operated generation, as well as long-term power purchase
contracts. The combination of the load forecast and current generation mix show the
future resource need to meet energy, peak demand, and renewable energy
requirements.

Economic Characteristics of Avista’s Service Territory
Avista serves electricity customers in most of the urban and suburban areas of 24
counties of eastern Washington and northern Idaho. Figure 2.1 shows Avista’s
electricity and natural gas service territories. Over 80 percent of Avista’s customers are
located in three Metropolitan Statistical Areas (MSAs): Spokane MSA (Spokane County,
WA), Coeur d’Alene MSA (Kootenai County, ID), and Lewiston, ID-WA MSA (Nez Perce
County, ID and Asotin County, WA). The load portion of this chapter focuses on
population, employment and personal income for the three MSAs combined.

The 2013 IRP energy forecast grows 1.0 percent per year, replacing the 1.4
percent annual growth rate in the 2011 IRP.
Peak load growth is slower than energy growth, at 0.84 percent in the winter
and 0.90 percent in the summer.
Avista’s first long-term capacity deficit is in 2020; the first energy deficit is in
2026.
Palouse Wind became operational December 13, 2012.
Kettle Falls qualifies for the Washington State Energy Independence Act (EIA)
beginning in 2016.
This IRP meets all EIA mandates over the next 20 years with a combination of
qualifying hydro upgrades, Palouse Wind, and Kettle Falls.
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-2
Figure 2.1: Avista’s Service Territory

Population across the three MSAs is approximately 680,000. Since 1970, average
annual population growth is about 1 percent. Figure 2.2 shows population in the three
main MSAs. The Coeur d’Alene MSA has enjoyed the most rapid population growth
since the early 1990s, increasing its share of service area population from 15 percent in
1990 to over 20 percent today.

Figure 2.2: Population Levels 1970 – 2011

0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
19
7
0
19
7
2
19
7
4
19
7
6
19
7
8
19
8
0
19
8
2
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8
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6
19
9
8
20
0
0
20
0
2
20
0
4
20
0
6
20
0
8
20
1
0
to
t
a
l

p
o
p
u
l
a
t
i
o
n
Spokane MSA
Coeur d'Alene MSA
Lewiston, ID-WA MSA
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-3
Population growth is a function of both regional and national employment growth. The
regional business cycle follows the U.S. business cycle, meaning regional economic
expansions or contractions follow national trends. A study done by Eastern Washington
University’s Institute for Public Policy and Economic Analysis documents this correlation
between the regional and national business cycles.1 Econometric analysis shows that
when regional employment growth is stronger than U.S. growth (see Equation 2.2) over
expansionary periods; regional population growth tends to accelerate. The reverse also
holds true. Figure 2.3 shows annual population growth since 1971. In the deep
economic downturns of the mid-1970s, early 1980s and the recent Great Recession,
reduced population growth rates in Avista’s service territory led to lower load growth.
The Great Recession reduced population growth from nearly 2 percent in 2007 to less
than 1 percent from 2010-2012.

Figure 2.3: Population Growth and U.S. Recessions, 1971-2011

The Inland Northwest has transitioned from a natural resources-based manufacturing
economy to a services-based economy. Figure 2.4 shows the breakdown of
employment for all three MSAs. Just over 70 percent of employment is in private
services, followed by government (15 percent) and private goods-producing sectors (13
percent). Government employment in the three MSAs is notably higher than in the
Portland and Puget Sound MSAs. Farming now accounts for one percent of
employment.

1 An Exploration of Similarities between National and Regional Economic Activity in the Inland Northwest, Monograph
No. 11, May 2006. http://www.ewu.edu/cbpa/centers-and-institutes/ippea/monograph-series.xml.

-0.5%
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
3.5%
19
7
1
19
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7
5
19
7
7
19
7
9
19
8
1
19
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9
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9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
po
p
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l
a
t
i
o
n

p
e
r
c
e
n
t

c
h
a
n
g
e
Shaded
Areas =
Recessions
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-4
Figure 2.4: Employment Breakdown by Major Sector, 2011

Between 1990 and 2007, non-farm employment growth averaged 2.5 percent per year.
However, Figure 2.5 shows that since the end of the Great Recession in 2009, there
has been no regional economic growth, and a significant regional lag relative to national
employment recovery over the same period. Regional employment growth did not
materialize until the second half of 2012, when services employment started to grow.
Prior to this, reductions in federal, state, and local government offset employment gains
in the goods producing sector.

Figure 2.5: Post Recession Employment Growth, June 2009-December 2012

On a brighter economic note, the Spokane and Coeur d’Alene MSAs have emerged as
major providers of health and higher education services to the Inland Northwest. A
Non-Farm Private
Good Producing,
13%
Non-Farm Private
Service Producing,
71%
Government
(Federal, State,
Local), 15%
Farm, 1%
88
90
92
94
96
98
100
102
De
c
-07
Fe
b
-08
Ap
r
-08
Ju
n
-08
Au
g
-08
Oc
t
-08
De
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-08
Fe
b
-09
Ap
r
-09
Ju
n
-09
Au
g
-09
Oc
t
-09
De
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-09
Fe
b
-10
Ap
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-10
Ju
n
-10
Au
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-10
Oc
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-10
De
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-10
Fe
b
-11
Ap
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-11
Ju
n
-11
Au
g
-11
Oc
t
-11
De
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-11
Fe
b
-12
Ap
r
-12
Ju
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-12
Au
g
-12
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t
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De
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-12
in
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x

o
f

n
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r
m

e
m
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y
m
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t
,

d
e
c
.

20
0
7

=

1
0
0
Index Avista WA-ID MSAs
Index U.S.
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-5
recent addition to these sectors is a new University of Washington medical school
branch located in the City of Spokane. Public and private universities and the regional
medical system will support the new medical school.

Finally, Figure 2.6 shows the distribution of personal income, a broad measure of both
earned income and transfer payments, for Avista’s Washington-Idaho MSAs. Regular
income consists of net earnings from employment and investment income in the form of
dividends interest and rent. Personal current transfer payments include money income
and in-kind transfers received through unemployment benefits, low-income food
assistance, Social Security, Medicare and Medicaid.

Figure 2.6: Personal Income Breakdown by Major Source, 2011

Although roughly 60 percent of personal income is from net earnings, transfer payments
account for 23 percent, or more than one in every five dollars of personal income.
Transfer payments have been the fastest growing component of personal income in the
region. This reflects an aging regional population, a surge of military veterans, and the
Great Recession, which significantly increased payments from unemployment insurance
and other low-income assistance programs. In 1970, the share of net earnings and
transfer payments in WA-ID MSAs accounted for 64 percent and 12 percent,
respectively. The income share of transfer payments has nearly doubled over the last
40 years. The relatively high regional dependence on government employment and
transfer payments means continued fiscal consolidation at the federal level would be an
economic drag on future growth.

Customer and Load Forecast Assumptions
The customer and load forecasts use: (1) forecasts of U.S. and county-level economic
growth; (2) forecasts of heating and cooling degree-days; and (3) forecasts of use-per-
customer trends. Topics discussed below provide background to the final customer and
load forecasts.
Net Earnings, 59%
Other Transfer
Payments, 4%
Retirement Transfer
Payments, 19%
Dividends, Interest,
and Rent, 18%
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-6
Avista’s load forecasting methodology is undergoing significant restructuring. The
restructuring involves using an Auto Regressive Integrated Moving Average (ARIMA)
technique. ARIMA improves the modeling of economic drivers involving population,
industrial production, income levels and energy prices to predict long-term energy
demand. This new methodology will improve forecasts used in the 2015 IRP.

Assumptions for U.S. and County-level Economic Growth
The forecast used for this IRP, finalized July 2012, relies on national and county-level
forecasts from multiple sources. However, forecasts developed ―in-house‖ and from
Global Insight are the principle forecast sources. Avista purchases forecasts from
Global Insight, an internationally recognized economic forecasting consulting firm. Table
2.1 presents key U.S. forecast assumptions.

Table 2.1: U.S. Long-run Baseline Forecast Assumptions, 2013-2035

Assumption Average
(%)
Source
Gross Domestic Product 2.5 Global Insight, Federal Reserve, Bloomberg
Consensus Forecasts, Energy Information
Administration, and Avista Forecasts
Consumer Inflation 2.0 Federal Reserve
Worker Productivity 2.0 Global Insight
Employment Growth 0.9 Global Insight
Industrial Production 2.3 Global Insight
Population Growth 0.9 Global Insight

Long-run gross domestic product (GDP) growth reflects an average of multiple forecast
sources, including Avista’s own in-house forecasts. In theory, long-run GDP growth
should be the sum of productivity growth plus population growth—2.9 percent using the
numbers above. However, the forecast sources above generally assume fiscal
consolidation (reducing the size of government deficits and debt accumulation) in the
U.S. and other developing countries. Fiscal consolidation, along with less consumer
credit, will keep U.S. GDP growth under 2.9 percent over the next 20-years. Prior to the
Great Recession, U.S. long-run GDP growth was around 3 percent. Consumer inflation
reflects the U.S. Federal Reserve’s implied anchor for long-run inflation.

Table 2.2 presents key assumptions for the Spokane, Coeur d’Alene and Lewiston, ID-
WA MSAs. These three areas comprise more than 80 percent of Avista’s service area
economy.

Table 2.2: Avista WA-ID MSAs Baseline Forecast Assumptions, 2013-2035

Assumption Average Source
Employment Growth 0.8% Global Insight and Avista Forecasts
Housing Starts 4,200 per yr. Global Insight
Population Growth 1.1% Global Insight and Avista Forecasts
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-7
Employment growth and housing starts are key predictors of customer and population
growth. Modest forecasts in these areas translate into modest customer growth
forecasts. Long-run population growth in Avista’s service area is nearly identical to long-
run growth rates of total customers over the same period. Therefore, population growth
forecasts are a proxy for long-run customer growth, especially for the residential and
commercial customer classes.

In addition to Global Insight’s population forecasts for the major MSAs, Avista uses two
other in-house methods for generating customer growth forecasts. Both methods
provide a baseline reasonableness test of Global Insight’s population forecasts, which
forms the basis of Avista’s long-run customer forecasts. Figure 2.7 shows Global
Insight’s population forecasts.

Figure 2.7: Population Forecast, 2013-2035

While one method uses Global Insight’s annual housing forecasts to project annual
changes in residential and commercial customers in the MSAs, the second forecast
method uses the following simple time-series regression estimated from historical data:

Equation 2.1: Conservation Avoided Costs

∆Ct = α0 + α1Mt-1 + εt

Where:
α0 = Intercept value of the estimated equation.
∆Ct = Change in Avista’s total residential electric customers from year t to
year t-1 (annual numbers are 12 month averages).
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
900,000
1,000,000
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
to
t
a
l

p
o
p
u
a
l
t
i
o
n
Spokane MSA
Coeur d'Alene MSA
Lewiston, ID-WA MSA
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-8
Mt-1 = The number of housing starts (single family homes and multi-family
units) reported at time t-1 for Avista’s three combined WA-ID MSAs.
εt = Random error term.

Figure 2.8 shows housing start forecasts to the end of the IRP period using the Global
Insight forecasts.

Figure 2.8: House Start History and Forecast (2000-2035)

Annual regional and U.S. employment growth is used to forecast annual population
growth in the MSAs. The population forecast uses the simple time-series regression
model estimated from historical data in Equation 2.2.

Equation 2.2: Population Forecast

Pt = α0 + α1Et-1,MSA + α2Et-1,US + α3D2002, + εt,
Where:
α0 = Intercept value of the estimated equation.
Pt = Population growth rate in year t in Avista’s WA-ID MSAs.
Et-1,MSA = Growth rate in non-farm employment in year t-1 in Avista’s WA-
ID MSAs.
Et-1,US = U.S. growth in non-farm employment in year t-1.
D2002 = Dummy for 2002 outlier.
εt = Random error term.

Avista’s forecast uses Global Insight’s forecasts for U.S. employment growth and in-
house forecasts for local employment growth. This approach reflects the statistically
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
ho
u
s
i
n
g

s
t
a
r
t
s
Spokane MSA
Coeur d'Alene MSA
Lewiston, ID-WA MSA
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-9
significant one-year lag between regional and U.S. employment and local population
growth rates. Higher or lower employment growth in Avista’s service area relative to the
U.S. in time t-1 is associated with higher or lower population growth in time t.

The in-house employment forecasts developed using Equation 2.2 are generated
through a time-series model linking regional employment growth (the dependent
variable) to national GDP growth (the independent variable). As discussed below, this
modeling approach can generate high- and low-growth cases for load by altering
assumptions about future local employment growth.

Weather Forecasts
The load forecast uses 30-year monthly temperature averages recorded at the Spokane
International Airport weather station through 2012. Several other weather stations are
located in Avista’s service territory, but their data is available for much shorter durations
and they are highly correlated with the Spokane International Airport data.

Avista uses heating degree-days (HDD) to measure cold-weather load sensitivity and
cooling degree-days (CDD) to measure hot-weather load sensitivity. The weather
normalization process uses regressions of the following form:

Equation 2.3: Weather Normalization

kWh/Ct,y,s = α0 + α1HDDt,y,s + α2QHDDt,y,s + α3CDDt,y,s + εt,y,s for month t, year y, schedule s

Where:
kWh/Ct,y,s = Weather normalization.
α = Marginal effect of each degree-day type.
HDDt,y,s = The HDDs for month t, year y and schedule s.
QHDDt,y,s = The coldest HDD months, December through March.
CDDt,y,s = The CDDs for month t, year y and schedule s.
εt,y,s = Random error term.

The estimated regressions are used to produce two predicted values of kWh/Ct,y,s. One
estimate uses the actual data to produce kWh/Ct,y,s, measuring usage driven by weather
conditions in month ―t‖. This represents the weather-predicted value of usage per
customer for month t in year y. The second estimate, kWh/Ct,y,s, reflects the predicted
usage per customer for month t in year y, based on the 30-year National Oceanic and
Atmospheric Administration average. The difference between the two estimates reflects
the deviation of month t weather-driven usage from the usage predicted by long-run
degree-days:

Equation 2.4: Weather Normalization Adjustment Factor

Tt,y,s = Usage predicted by normal weather – Usage predicted by actual weather

The deviation Tt,y,s is then added to the actual value of kWh/Ct,y,s to obtain weather
normalized usage (WNU).
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-10
Equation 2.5: Weather Normalized Amount

(kWh/Ct,y,s)WNU = kWh/C t,y,s + Tt,y,s

Where:
(kWh/Ct,y,s)WNU = Weather normalized usage in kWh.
kWh/C t,y,s = Actual usage that was observed. Tt,y,s = Weather normalization adjustment factor.
If weather conditions in month t are hotter than average (more CDD than average), then
the adjustment factor will be negative. When added to kWh/Ct,y,s, WNU will be lower,
reflecting an adjustment back to what usage should have been with ―average‖ weather.

Use per Customer Projections
A database of monthly electricity sales and customer numbers by rate schedule forms
the basis of use-per-customer (UPC) forecasts by rate schedule, customer class and
state. Historical data is weather-normalized to remove the impact of HDD and CDD
deviations from expected normal values, as discussed above. Weather normalized UPC
forecasts multiplied by tariff schedule customer forecasts result in a total load forecast.

Historical data for Avista’s service area shows that weather normalized UPC in the
service area is declining. Figure 2.9 shows annual growth in UPC since 2006. Over this
period, the average annual rate of decline in UPC was about 0.5 percent and largely
reflected a declining trend in the residential sector. The key factors influencing long-run
UPC are: (1) own-price and cross-price elasticity; (2) income elasticity as related to
consumer purchases of energy-related goods; (3) conservation programs; and (4)
changes in household size.

Figure 2.9: Annual Growth in Use per Customer 2006 - 2012

-0.3%-0.4%
-1.6%-1.7%
2.3%
-0.1%
-1.8%
-3.0%
-2.0%
-1.0%
0.0%
1.0%
2.0%
3.0%
2006 2007 2008 2009 2010 2011 2012
pe
r
c
e
n
t

c
h
a
n
g
e

i
n

u
s
e

p
e
r

cu
s
t
o
m
e
r
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-11
Retail electricity price increases reduce electricity UPC. Own-price elasticity is an
important consideration in any electricity demand forecast because it measures the
sensitivity of quantity demanded for a given change in price. A consumer who is
sensitive to a price change 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 displayed increasing price sensitivity and
subsequently reduced electricity usage in response to relatively large price changes.
Recent research shows that the more in-home information consumers have about
electricity usage and costs, the more price sensitive they become.2

Cross-price elasticity measures the relationship between the quantity of electricity
demanded and the quantity of potential substitutes (e.g., propane or natural gas for
heat) when the price of electricity increases relative to the price of the substitute. A
positive cross elasticity coefficient indicates cross-price elasticity between electricity and
the substitute. A negative coefficient indicates the absence of cross-price elasticity, and
that considered product is not a substitute for electricity, but is instead complementary
to it. An increase in the price of electricity increases the use of the complementary good,
and a decrease in the price of electricity decreases the use of the complementary good.

The principal application of cross elasticity impact in the IRP is its substitutability by
natural gas in some applications, including water and space heating. The correlation
between retail electricity prices and the commodity cost of natural gas has increased as
the industry relies on more natural gas-fired generation to meet loads. This increased
positive correlation has reduced the net effect of cross price elasticity between retail
natural gas and electricity prices.

Income elasticity measures the relationship between a change in consumer income and
the change in consumer demand for electricity. As incomes rise, the ability of a
consumer to pay for more electricity increases. The ability to afford electricity-related
products also increases. As incomes rise, consumers are more likely to purchase more
electricity-consuming products that increase UPC, such as larger dwellings, mobile
electronic devices, high definition televisions and electric vehicles. However, it also
enables them to buy more energy efficient products reducing UPC, including more
energy efficient windows and appliances, in addition to rooftop solar photovoltaic cells.

Although elasticity plays a key role in customer behavior, estimating elasticity is
problematic. Currently Avista lacks sufficient data to estimate elasticity values for its
service area. National estimates of elasticity exist; however, for a variety of reasons,
there is no guarantee they reflect regional consumer behavior.
Elasticity comes in two forms: short-run and long-run. In terms of own-price elasticity,
quantity responses are less sensitive to price increases in the short-run because
consumers lack sufficient time to implement efficiency programs or find lower cost
2 Jessoe and Rapson (2012), The Short-run and Long-run Effects of Behavioral Interventions:
Experimental Evidence from Energy Conservation, NBER working paper 18492. Allcot and Rogers
(2012), Knowledge is (Less) Power: Experimental Evidence from Residential Energy Use, NBER work
paper 18344.
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-12
substitutes. This is not the case in the long-run, so elasticity should increase as the time
for adjustment increases. For example, the Energy Information Administration currently
uses a value of -0.3 for short-run own-price elasticity for residential electricity,
accounting for the ―…successful deployment of smart grid projects funded under the
American Recovery and Reinvestment Act of 2009.‖3 However, the Energy Information
Administration estimates long-run elasticity ranges from -0.04 to -1.45.4

Recent research (Arimura, Li, Newell, and Palmer, 2011) indicates that conservation
programs reduce long-run residential usage.5 However, empirical problems arise when
estimating the impact of energy efficiency on load. These programs affect historical
data; therefore, the forecast already contains the impacts of existing conservation
levels. However, Avista is currently working with the EnerNOC consulting group to
estimate energy efficiency savings. Future IRPs will address a more concrete empirical
estimate on the impact of energy efficiency programs to avoid double counting.

Figure 2.10 shows average household size in Avista’s electric service area since 1990.
The size has fallen to 2.5 people per household or about 2 percent smaller than in 1990.
The forecast is for average household size to stay below the current level through 2035.

Figure 2.10: Area Average Household Size, Historical and Forecast 1990-2035

3 See U.S. Energy Information Administration, Assumptions to the Annual Energy Outlook 2012,
Residential Demand Module, p. 32. 4 See U.S. Energy Information Administration, Working Memorandum from George Lady, NEMS Price
Elasticities of Demand for Residential and Commercial Energy Use, Table 2, p. 4. 5 Arimura, Li, Newell, and Palmer (2011), Cost-effectiveness of Electricity Energy Efficiency Programs,
NBER working paper 17556.
2.42
2.44
2.46
2.48
2.50
2.52
2.54
2.56
2.58
2.60
19
9
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4
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6
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6
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e
r
a
g
e

h
o
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e
h
o
l
d

S
i
z
e

Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-13
Residential use accounts for 88 percent of customers and 40 percent of load, the
factors discussed above impact the long-run trend UPC as follows:

Equation 2.6: Use per Customer

UPC Trend = ƒ(long- and short-run price and income elasticity, conservation
programs, household size, long-run weather factors)

Rather than modeling each piece on the right side of Equation 2.6, the forecast attempts
to model the long-run UPC trend as a whole using historical UPC data. An analysis of
data since 2005 shows the UPC can be modeled using a linear trend in the residential
forecast. This trend is alongside other explanatory variables related to heating and
cooling degree-days. Future forecast models will explicitly include variables that
influence UPC trends, such as household size, price and consumer income. Besides
long-run potential climate change, the only individual component related in Equation 2.6
explicitly considered is the adoption of electric vehicles in Avista’s service area.

The 2013 IRP electric vehicle adoption scenario is half of the 2011 IRP forecast. This
revision reflects evidence indicating the adoption of electric vehicles is occurring at a
slower pace than previously expected. The electric vehicle fleet is a combination of
plug-in hybrids and electric-only passenger vehicles. The 2011 IRP forecast of electric
vehicles utilized the Northwest Power and Conservation Council’s (NPCCs) forecast
from the Sixth Northwest Conservation and Power Plan.6 The slow rate of electric
vehicle adoption in Avista’s service area likely coincides to the service area’s post-
recession employment recovery (discussed above), including a 10 percent decline in
inflation-adjusted median household income since 2007, and the continued high price of
electric vehicles relative to traditional alternatives.

One forecast shown in Figure 2.11 assumes the long-run UPC will continue to decline
until 2028 when it could slowly increase due to electric vehicle adoption. The other
forecast is the no-electric vehicle case where they are not widely adopted. Here, UPC
continues to decline, but more slowly after 2028. Given current electric vehicle adoption
rates, the no-electric vehicle case seems more likely.

6 http://www.nwcouncil.org/energy/powerplan/6/plan/

Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-14
Figure 2.11: Residential Use per Customer, 2006-2035

Customer Forecast
Table 2.3 shows the historical correlation of year-over-year customer growth across the
four main customer groups: residential, commercial, industrial and streetlights. The
correlation between residential and commercial is high, meaning forecasted growth
rates should behave similarly. As a result, both the residential and commercial groups
correlate to population growth. Industrial and streetlights change very slowly; so these
forecasts use simple trending and smoothing methods.

Table 2.3: Customer Growth Correlations, January 2006-December 2012

Customer Class
(Year-over-Year)
Residential,
Year-over-
Year
Commercial,
Year-over-
Year
Industrial,
Year-over-
Year
Streetlights,
Year-over-
Year
Residential 1 Commercial 0.899 1 Industrial -0.320 -0.169 1 Streetlights -0.246 -0.205 0.280 1

To reproduce the high correlation between residential and commercial customers in the
forecast, the residential customer forecast is used as a driver for the commercial
forecast. This is done by regressing past commercial customer changes against past
residential customer changes, as shown in Equation 2.7. Using the estimated equation,
8,000
9,000
10,000
11,000
12,000
13,000
20
0
6
20
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20
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8
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1
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5
ki
l
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a
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t
-ho
u
r
s
Residential UPC, with Electric Vehicles
Residential UPC, without Electric Vehicles
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-15
forecasted customer changes are inserted to generate the forecasted change in
commercial customers.

Equation 2.7: Customer Forecast

∆Ct,commerical = α0 + α1∆Ct,residential + εt,

Where:
α0 = Intercept value of the estimated equation.
∆Ct,commerical = Change in Avista’s total commercial electric customers
from year t to year t-1 (annual numbers are 12-month averages).
∆Ct,residential = Change in Avista’s total residential electric customers from
year t to year t-1 (annual numbers are 12-month averages).
εt = Random error term.

In aggregate, average annual customer growth is 1.1 percent out to 2035, with
residential and commercial driving most of the growth at 1.1 percent annually. Industrial
growth is 0.3 percent annually. The aggregate growth forecast is considerably below the
pre-Great Recession growth rate of 1.6 percent. See Figure 2.12.

Figure 2.12: Avista’s Customer Growth, 1997-2033

Native Load Forecast
Retail sales provide the data used to project future loads. Retail sales translate into
average megawatt hours (aMW) using a regression model ensuring monthly load
shapes conform to history. The load forecast is a retail sales forecast combined with line
200,000
250,000
300,000
350,000
400,000
450,000
500,000
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Street Lights
Industrial
Commerical
Residential
Average
Annual
Growth 1997-
2007= 1.6%
Average Annual
Growth 2007-
2012= 0.8%
Average Annual
Growth 2012-
2035 = 1.1%
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-16
losses incurred in the delivery of electricity across Avista’s transmission and distribution
systems.

Figure 2.13 presents annual net native load growth. Note the significant drop in the
2000-01 Western Energy Crisis and smaller declines in the Great Recession. Annual
growth averages 1 percent through 2035.

Figure 2.13: Native Load History and Forecast, 1997-2035
Peak Demand Forecast
The energy or load forecast is important to the development of the IRP because retail
sales growth drives many future system costs. When planning to meet the needs of all
of Avista’s customers, a forecast of peak demand is also crucial to determine the need
for new capacity. In other words, Avista must not only meet the energy needs of its
customers, but also have enough capacity to meet demands in its highest load hour.

Avista’s typical peak hour is in the winter months, between November and early
February. Recent warm winters, hot summers and added air conditioning load have
created some summer months where loads were higher than the winter. This
phenomenon has transformed Avista into a dual peaking utility. Even though summer
peaks may be higher than winter, Avista still expects to have its highest electricity load
in the winter.

Avista’s peak load forecast began by normalizing historical data to set a base peak level
adjusted for temperatures. After the adjustment, peak loads trend with economic factors
similar to the energy forecast. Normalizing base peak loads begins with adjusting the
2012 peak for temperature variation from normal. Using daily peak load data for 24
months an econometric model isolates the relationship between load and temperatures,
600
800
1,000
1,200
1,400
1,600
19
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En
e
r
g
y

(
a
M
W
)
Average Annual
Growth 2012-
2035 = 1%
Average Annual
Growth 1997-
2007 = 1.6%
Average Annual
Growth 2007-
2012 = 0%
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-17
day of the week, holidays, school days, season and other factors. These relationships
are normalized using a 123-year average of historical Spokane temperatures. For the
winter forecast, the coldest day of each year is averaged to determine the base
planning temperature.7 For the summer, the same process is used but for the hottest
day. In the winter the average coldest day is 3.9 degrees Fahrenheit, the coldest
temperature on record was -17 degrees on December 30, 1968. Avista last saw an
extreme winter peak temperature in 2004 with a -9 degrees day average. For summer
peak planning, the average hottest day (average of daily high and low temperature) is
82.3 degrees. The hottest average day on record is 90 degrees on July 27, 1928. Avista’s
last extreme summer temperature was 86 degrees in 2008. See Table 2.4 for details.
One caution using the average of extreme annual temperatures is the extreme
temperature may land on a Friday, weekend, or on a holiday, the extreme temperature
is not going to have a large impact on peak load these days. This base forecast weights
the days of the week to reflect the average temperature given extreme temperatures
can happen on any given day.

Table 2.4: Average Day Spokane Temperatures 1890-2012 (Degrees Fahrenheit)

Customer Class Coldest Day Hottest Day
Extreme -17.0 90.0
Average 3.9 82.3
Standard Deviation 8.9 2.8
90th Percentile -8.8 86.0
Recent Extreme Temperatures 2004: -9.0 2008: 86.0

Using the normalized base peak levels from 2012, the peak load forecast uses an
econometric model relying on GDP growth as its primary driver, similar to the energy
forecast. With this regression relationship, peak load growth is simulated using
assumptions about future GDP growth. GDP growth out to 2017 was set at the average
of multiple forecast sources.8 Using this average shapes the near term impacts of the
business cycle on peak load growth. From 2018-35 the long-run GDP growth was 2.5
percent.

This analysis resulted in a 20-year peak growth rate of 0.84 percent in the winter and a
0.90 percent growth rate in the summer. Figure 2.14 illustrates these growth levels
compared to historical peaks for both summer and winter (other monthly peaks are
developed but not shown). Avista’s all-time native load peak was in 2009 with peak
loads at 1,821 MW, on this day the average temperature reached -7 degrees. The
historical summer peak occurred in July 2006 when average temperatures reached 87
degrees. The historical winter and summer annual average growth rates between 1997
and 2012 were 0.85 and 1.0 percent, respectively. The forecast peaks represent an
7 The coldest day based on the average of daily high and low temperatures. 8 The forecast sources are the U.S. Federal Reserve, Bloomberg’s survey of forecasters, Reuter’s survey
of forecasters, The Economist’s survey of forecasters, Global Insight, Economy.com, Blue Chip
consensus forecast. Averaging these sources reduces the systematic forecast error that can arise from
using a single source forecast.
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-18
expected peak level given average extreme temperatures; actual peak loads are
expected to deviate from this forecast. Avista resources meet the deviated peak loads
first, and market purchases meet the remaining peak loads.9

Figure 2.14: Winter and Summer Peak Demand, 1997-2035

High and Low Load Growth Cases
Avista produces high and low load forecasts to test the PRS. These forecasts are very
difficult to create because many factors influence the outcome. In past IRPs, Avista
used ranges from the NPCC’s Sixth Power Plan as a guide. This IRP relies on this basic
relationship to derive the high and low load growth rates:

Equation 2.8: Long Run Load to Customer Relationship

% change in load ≈ % change in customers + % change in UPC.10

Recalling the discussion above, population growth approximates long-run customer
growth, and population growth approximates employment growth. Therefore using
Equation 2.2 to simulate population growth should be under differing assumptions of
regional employment growth, holding U.S. employment and UPC growth rates constant.
Avista uses this method to forecast alternative load growth cases. The low case
9 Avista maintains a 14 percent planning margin above these peak levels, and operating reserves. 10 Since UPC = load/customers, calculus shows that the annual percentage change UPC ≈ percentage
change in load - percentage change in customers. Rearranging terms, we have, the annual percentage
change in load ≈ percentage change in customers + percentage change in UPC.
-
500
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g
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Winter
Summer
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-19
assumes regional employment growth averages 0.5 percent out to 2035; the high-
growth case assumes 2.5 percent. Figure 2.15 shows the results of these assumptions.
Figure 2.15 also shows the U.S. baseline forecast from the Energy Information
Administration and a low-medium forecast uses Global Insight’s base-line forecasts for
employment growth to forecast population growth.

Figure 2.15: Load Growth Scenarios, 2014-2035

Voluntary Renewable Energy Program (Buck-A-Block)
Since 2002, Avista has offered customers the opportunity to purchase renewable
energy voluntarily as part of their utility billing process. Customers currently can
purchase 300 kWh blocks for $1.00 to meet their personal renewable energy goals. This
program is rate neutral and funded by participating customers. Avista’s 35 MW share of
the Stateline Wind project supplies most of the program through March 2014. Along with
the wind energy, the purchase agreement includes renewable energy credits. The
current mix of renewable credits used by Buck-A-Block customers is 85 percent from
wind, 14.8 percent from biomass and the remaining 0.2 percent from the 15 kW
Rathdrum Solar project (see Figure 2.16).

Since inception, participants purchased an average of 8.1 aMW of renewable energy
through the Buck-A-Block program. Figure 2.17 shows the growth of customers and
purchased energy in the program. After initial growth in the program, purchases leveled
off in 2008 at just over 8.0 aMW per year.

0.0%
0.4%
0.8%
1.2%
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Low Growth High Growth
Medium-Low EIA Forecast
Expected Growth
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-20
Figure 2.16: 15 kW Photovoltaic Installation in Rathdrum, ID

Figure 2.17: Buck-A-Block Customer and Demand Growth

Customer-Owned Generation
A small but growing number of customers continue to install their own generation at an
increasing pace. In 2007 and 2008, the average new net-metering customers were 10,
and between 2009 and 2012, the average increased to 38 per year, likely in response to
generous federal and state tax incentives. These projects qualify for the federal
government’s 30 percent tax credit and in the state of Washington, customer-owned
projects can qualify for additional tax incentives of up to $5,000 per year. The quantity of
generation each year through 2020 determines the amount of incentives paid. The
Washington state utility taxes credit finances the incentives. Solar projects can qualify
for total incentives worth up to $0.54 per kWh with solar panels and inverters
manufactured in Washington. All other customer-owned generation receives a minimum
0.7
2.9
5.8
6.4
7.6
8.1 8.1 8.2 8.6 8.3
0
1,000
2,000
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4.0
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2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
cu
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Customers
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-21
payment of $0.12 per kWh, increasing depending upon the manufacturing location of
the installed equipment.

At this time, 190 customers have installed net-metered generation equipment for a total
of 1.1 MW of capacity. This level equals approximately 0.5 percent of Avista’s
generation capacity. Eighty percent of the installations are in Washington, with most in
Spokane County. Figure 2.18 shows annual net metering customer additions. Solar is
83 percent of net metered technology; the remaining is a mix of wind, combined solar
and wind systems, and biogas. The average annual capacity factor of the solar facilities
is 13 percent. Small wind turbines typically produce less than a 10 percent capacity
factor depending on location. At current tax incentive levels, the number of new net-
metered systems will continue at their current pace or may even increase. Where tax
subsidies end without a significant reduction in technology cost, the interest in net
metering likely will return to pre-tax incentive levels. If the number of net-metering
customers continues to increase, Avista may need to adjust rate structures for
customers who rely on the utility’s infrastructure but do not contribute financially for
infrastructure costs.

Figure 2.18: Net Metering Customers
The reason for increased interest in customer-owned generation may have more to do
with economics than environmental benefits. Figure 2.19 shows how current
government subsidies make solar energy attractive to customers. This example uses a
0.0
0.3
0.6
0.9
1.2
1.5
0
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2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
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an
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ID
WA
Cumulative Capacity (MW)
290 customers through first
quarter2013
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-22
5 kW system at $7,000 per kW, or a $35,000 total installation cost.11 The cost without
government assistance is 80 cents per kWh, roughly ten times Avista’s retail electricity
rate. The federal tax Investment Tax Credit (ITC) and favorable federal depreciation
rules transfers up to 42 cents per kWh from the system owner to taxpayers. Washington
state picks up an additional 12 to 54 cents per KWh. With combined federal and state
subsidies, a customer has the potential to install ―made in Washington‖ panels and
inverters and have not only its entire costs paid for, but also make a profit and receive
free energy. Given these generous incentives, the potential exists for additional net
metering customers on Avista’s system, especially where present funding is limited
under RCW 82.16.130 to the lesser of 0.5 percent of taxable power sales or $100,000.

Figure 2.19: Solar Energy Transfer Payments

Avista Resources and Contracts
Avista relies on a diverse portfolio of generating assets to meet customer loads,
including owning and operating eight hydroelectric developments located on the
Spokane and Clark Fork rivers. Avista’s thermal assets include partial ownership of two
coal-fired units in Montana, five natural gas-fired projects, and a biomass plant located
near Kettle Falls, Washington.

11 A higher cost of solar is used to represent the costs of panels and inverters manufactured in
Washington with typically higher installation costs to illustrate the costs/benefits of the ―made in
Washington‖ Renewable Energy Systems Cost Recovery Incentive Payments.
ProfitState Incentive
State Incentive
Federal Depr
Federal Depr
Federal Depr
Federal ITC
Federal ITC
Federal ITC
Cost
Cost Cost
-125 ¢/kWh
-100 ¢/kWh
-75 ¢/kWh
-50 ¢/kWh
-25 ¢/kWh
¢/kWh
25 ¢/kWh
50 ¢/kWh
75 ¢/kWh
100 ¢/kWh
No Subsidies With Fed. Incentives With Fed. and WA
State Incentives
(Low)
With Fed. and WA
State Incentives
(High)
0
Avista Retail Rate
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-23
Spokane River Hydroelectric Developments
Avista owns and operates six hydroelectric developments on the Spokane River. Five of
these developments received a new 50-year FERC operating license in June 2009. The
following section describes the Spokane River developments and provides the
maximum on-peak capacity and nameplate capacity ratings for each plant. The
maximum on-peak capacity of a generating unit is the total amount of electricity a plant
can safely generate. This is often higher than the nameplate rating for hydroelectric
developments. The nameplate, or installed capacity, is the capacity of a plant as rated
by the manufacturer. All six of the hydroelectric developments on the Spokane River
connect to Avista’s transmission system.

Post Falls
Post Falls is the most upstream hydroelectricity facility on the Spokane River. It is
located several miles east of the Washington/Idaho border. The development began
operating in 1906, and during summer months maintains the elevation of Lake Coeur
d’Alene. The development has six units, with the last unit added in 1980. Post Falls has
a 14.75 MW nameplate rating and is capable of producing 18.0 MW.

Upper Falls
The Upper Falls development began generating in 1922 in downtown Spokane, and
now is within the boundaries of Riverfront Park. This project is comprised of a single
10.0 MW nameplate unit with a 10.26 MW maximum capacity rating.

Monroe Street
Monroe Street was Avista’s first generation development. It began serving customers in
1890 near what is now Riverfront Park. Rebuilt in 1992, the single generating unit has a
14.8 MW nameplate rating and a 15.0 MW maximum capacity rating.

Nine Mile
A private developer built the Nine Mile development in 1908 near Nine Mile Falls,
Washington, nine miles northwest of Spokane. Avista (then Washington Water Power)
purchased the project in 1925 from the Spokane & Inland Empire Railroad Company. Its
four units have a 26.4 MW nameplate rating and 17.6 MW maximum capacity rating.12 A
new hydraulic control system was installed in 2010, replacing the original flashboard
system that maintained full pool conditions seasonally.

Nine Mile is currently undergoing substantial multi-year upgrades. Nine Mile Units 1 and
2 upgrades to two 8 MW generators/turbines, replace both existing 3 MW units. Once
operational in 2016, the new units will add 1.4 aMW of energy beyond the original
configuration and 6.4 MW of capacity above current generation levels. In addition to
these capacity upgrades, the facility will receive upgrades to the hydraulic governors,
static excitation system, switchgear, station service, control and protection packages,
ventilation upgrades, rehabilitation of intake gates and sediment bypass system, and
12 This is the de-rated capacity considering the outage of Nine Mile Unit 1 and de-rate of Unit 2.
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-24
other investments. The fall 2013 Unit 4 overhaul includes new turbine runners, thrust
bearings, and operating system. Avista plans to overhaul Unit 3 in 2018-19.

Long Lake
The Long Lake development is located northwest of Spokane and maintains the Lake
Spokane reservoir, also known as Long Lake. The plant received new runners in the
1990s, adding 2.2 aMW of additional energy. The project’s four units have an 81.6 MW
nameplate rating and provide 88.0 MW of combined capacity.

Little Falls
The Little Falls development, completed in 1910 near Ford, Washington, is the furthest
downstream hydro facility on the Spokane River. A new runner upgrade in 2001
generates 0.6 aMW more energy. The facility’s four units generate 35.2 MW of on-peak
capacity and have a 32.0 MW nameplate rating. Avista is carrying out a series of
upgrades to the Little Falls development. Much of the new electrical equipment and the
installation of a new generator excitation system are complete. Current projects include
replacing station service equipment, updating the powerhouse crane, and developing
new control schemes and panels. After the preliminary work is completed, replacing
generators, turbines, and unit protection and control systems on the four units will start.

Clark Fork River Hydroelectric Developments
The Clark Fork River Developments includes hydroelectric projects located near Clark
Fork, Idaho, and Noxon, Montana, 70 miles south of the Canadian border. The plants
operate under a FERC license through 2046. Both hydroelectric projects on the Clark
Fork River connect to Avista’s transmission system.

Cabinet Gorge
The Cabinet Gorge development started generating power in 1952 with two units. The
plant added two additional generators the following year. The current maximum on-peak
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 the Unit 1 turbine in 1994. Unit 3 received an
upgrade in 2001. Unit 2 received an upgrade in 2004. Unit 4 received a turbine runner
upgrade in 2007.

Noxon Rapids
The Noxon Rapids development includes four generators installed between 1959 and
1960, and a fifth unit added in 1977. Avista recently completed a major turbine upgrade,
with Units 1 through 4 receiving new runners between 2009 and 2012. The upgrades
increased the capacity of each unit from 105 MW to 112.5 MW and added a total of 6.6
aMW of EIA qualified energy.

Total Hydroelectric Generation
In total, Avista’s hydroelectric plants have 1,065.4 MW of on-peak capacity. Table 2.5
summarizes the location and operational capacities of Avista’s hydroelectric projects.
This table includes the expected energy output of each facility based on the 70-year
hydrologic record for the year ending 2012.
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-25
Table 2.5: Avista-Owned Hydro Resources

Project Name River
System
Location Nameplate
Capacity
(MW)
Maximum
Capability
(MW)
Expected
Energy
(aMW)
Monroe Street Spokane Spokane, WA 14.8 15.0 11.6
Post Falls Spokane Post Falls, ID 14.8 18.0 10.0
Nine Mile Spokane Nine Mile Falls, WA 26.0 17.5 12.5
Little Falls Spokane Ford, WA 32.0 35.2 22.1
Long Lake Spokane Ford, WA 81.6 89.0 53.4
Upper Falls Spokane Spokane, WA 10.0 10.2 7.5
Cabinet Gorge Clark Fork Clark Fork, ID 265.2 270.5 124.8
Noxon Rapids Clark Fork Noxon, MT 518.0 610.0 198.3
Total 962.4 1,065.4 440.2

Thermal Resources
Avista owns seven thermal generation assets located across the Northwest. Based on
IRP analysis, Avista expects each plant to continue operation through the 20-year IRP
planning horizon. The resources provide dependable energy and capacity to serve base
loads and provide peak load-serving capabilities. A summary of Avista thermal
resources is in Table 2.6.

Colstrip Units 3 and 4
The Colstrip plant, located in Eastern Montana, consists of four coal-fired steam plants
connected to the double circuit 500 kV BPA transmission line under a long-term
wheeling agreement. PPL Global operates the facilities on behalf of the six owners.
Avista owns 15 percent of Units 3 and 4. Unit 3 began operating in 1984 and Unit 4 was
finished in 1986. Avista’s share of Colstrip Units 3 and 4 has a maximum net capacity of
111.0 MW, and a nameplate rating of 123.5 MW per unit. Avista has no ownership
interests in Colstrip Unites 1 and 2.

Rathdrum
Rathdrum consists of two simple-cycle combustion turbine units. This natural gas-fired
plant is located near Rathdrum, Idaho and connects to Avista’s transmission system. It
entered service in 1995 and has a maximum capacity of 178.0 MW in the winter and
126.0 MW in the summer. The nameplate rating is 166.5 MW.

Northeast
The Northeast plant, located in Spokane, is two aero-derivative simple-cycle units
completed in 1978 and connects to Avista’s transmission system. The plant is capable
of burning natural gas or fuel oil, but current air permits preclude 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. The plant is currently limited to run no
more than approximately 550 hours per year.

Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-26
Boulder Park
The Boulder Park project entered service in Spokane Valley in 2002 and connects to
Avista’s transmission system. The site uses six natural gas-fired internal combustion
reciprocating 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. This plant connects to BPA’s 500 kV transmission system under a
long-term transmission agreement. The plant began service in 2003. Its maximum
capacity is 274 MW in the winter and 221 MW in the summer with a duct burner
providing additional capacity of up to 28 MW. The plant’s nameplate rating is 287.3 MW.

Avista is in the process of upgrading Coyote Springs 2. Upgrades include cooling
optimization and cold day controls. The 2011 IRP process studied both of these
updates. The cold day controls remove firing temperature suppression that occurs when
ambient temperatures are below 60 degrees. The upgrade improves the heat rate by
0.5 percent and output by approximately 2.0 MW during cold temperature operations.
The cooling optimization package improves compressor and natural gas turbine
efficiency, resulting in an overall increase in plant output of 2.0 MW. In addition to these
upgrades, Coyote Springs 2 now has a Mark VIe control upgrade, a new digital front
end on the EX2100 gas turbine exciter, and model-based control with enhanced
transient capability. Each of these projects allows Avista to maintain high reliability,
reduce future O&M costs, improve our ability to maintain compliance with WECC
reliability standards, and help prevent damage that might occur to the machine when
electrical system disturbances occur.

Kettle Falls Generation Station and Kettle Falls Combustion Turbine
The Kettle Falls Generating Station, a biomass facility, entered service in 1983 near
Kettle Falls, Washington. It is among the largest biomass plants in North America and
connects to Avista’s 115 kV transmission system. The open-loop biomass steam plant
uses waste wood products from area mills and forest slash, but can also burn natural
gas. A combustion turbine (CT), added to the facility in 2002, burns natural gas and
increases overall plant efficiency by sending exhaust heat to the wood boiler.

The wood-fired portion of the plant has a maximum capacity of approximately 50.0 MW,
and its nameplate rating is 50.7 MW. The plant typically operates between 45 and 47
MW because of fuel conditions. The plant’s capacity increases to 57.0 MW when
operated in combined-cycle mode with the CT. The CT produces 8 MW of peaking
capability in the summer and 11 MW in the winter. The CT resource is limited in winter
when the natural gas pipeline is capacity constrained; for IRP modeling, the CT does
not run when temperatures fall below zero and natural gas pipeline capacity is assumed
to serve local natural gas distribution demand.

Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-27
Table 2.6: Avista-Owned Thermal Resources

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 178.0 126.0 166.5
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 312.0 251.0 290.0
Kettle Falls Kettle Falls, WA Wood 1983 47.0 47.0 50.7
Kettle Falls CT13 Kettle Falls, WA Gas 2002 11.0 8.0 7.5

Power Purchase and Sale Contracts
Avista utilizes power supply purchase and sale arrangements of varying lengths to meet
a portion of its load requirements. This chapter describes the contracts in effect during
the scope of the 2013 IRP. Contracts provide many benefits, including environmentally
low-impact and low-cost hydro and wind power. A 2012 annual summary of Avista’s
large contracts is in Table 2.7.

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 large when
compared to loads then served by the PUDs. Long-term contracts with public,
municipal, and investor-owned utilities throughout the Northwest assisted with project
financing, and ensured a market for the surplus power. The contract terms obligate the
PUDs to deliver power to Avista points of interconnection.

Avista entered into long-term contracts for the output of four of these projects ―at cost.‖
Later, Avista competed in capacity auctions in 2009 through 2013 to purchase new
short-term contracts at market-based prices. The Mid-Columbia contracts in Table 2.7
provide energy, capacity, and reserve capabilities; in 2014, the contracts provide
approximately 127 MW of capacity and 76 aMW of energy. Over the next 20 years the
Douglas PUD (2018) and Chelan PUD (2014) contracts will expire. Avista may extend
these contracts or even gain additional capacity in auctions; however, we have no
assurance that we will successfully extend our contract rights. Due to this uncertainty
around future availability and cost, the IRP does not include these contracts in the
resource mix beyond their expiration dates.

The timing of the power received from the Mid-Columbia projects is also a result of
agreements including the Columbia River Treaty signed in 1961 and the Pacific
13 The Kettle Falls CT numbers include output of the gas turbine plus the benefit of its steam to the main
unit’s boiler.
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-28
Northwest Coordination Agreement (PNCA) signed in 1964. Both agreements optimize
hydro project operations in the Northwest United States and Canada. In return for these
benefits, Canada receives return energy (Canadian Entitlement). The Columbia River
Treaty and the PNCA call for storage water in upstream reservoirs for coordinated flood
control and power generation optimization. On September 16, 2024, given a minimum
of 10 years written advance notice, the Columbia River Treaty may end. Studies are
underway by U.S. and Canadian entities to determine possible post-2024 Columbia
River operations. Federal agencies are soliciting feedback from stakeholders and soon
negotiations will begin in earnest to decide whether the current treaty will continue,
should be ended, or if a new agreement will be struck. This IRP does not model
potential alternative outcomes regarding the treaty negotiation, as it is not expected to
impact long-term resource acquisition and we cannot speculate on future wholesale
electricity market impacts of the treaty.

Table 2.7: Mid-Columbia Capacity and Energy Contracts

Counter Party Project(s) Percent
Share
(%)
Start
Date
End
Date
Estimated
On-Peak
Capability
(MW)
Annual
Energy
(aMW)
Grant PUD Priest Rapids 3.7 Dec-01 Dec-52 28.2 16.7
Grant PUD Wanapum 3.7 Dec-01 Dec-52 31.0 17.9
Chelan PUD Rocky Reach 3.0 Jul-11 Dec-14 34.5 21.0
Chelan PUD Rock Island 3.0 Jul-11 Dec-14 13.9 10.7
Douglas PUD Wells 3.3 Feb-65 Aug-18 27.9 14.7
Canadian Entitlement -8.1 -4.6
2014 Total Net Contracted Capacity and Energy 127.4 76.4
2015 Total Net Contracted Capacity and Energy 81.9 46.3

Lancaster Power Purchase Agreement
Avista acquired the output rights to the Lancaster combined-cycle generating station,
located in Rathdrum, Idaho, as part of the sale of Avista Energy in 2007. Lancaster
presently connects to the BPA transmission system under a long-term wheeling
agreement, but Avista is working with the federal agency to interconnect the plant
directly with Avista’s transmission system at the BPA Lancaster substation. Avista has
the sole right to dispatch the plant, and is responsible for providing fuel and energy and
capacity payments, under a tolling contract expiring in October 2026.

Public Utility Regulatory Policies Act (PURPA)
In 1978, Congress passed PURPA requiring utilities to purchase power from
Independent Power Producers (IPPs) meeting certain criteria depending on their size
and fuel source. Over the years, Avista has entered into many such contracts. Current
PURPA contracts are in Table 2.8. Avista will renegotiate many of these contracts after
the term of the current contract has ended.

Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-29
Table 2.8: PURPA Agreements

Contract Owner Fuel
Source
Location End
Date
Size
(MW)
Annual
Energy
(aMW)
Meyers Falls Hydro
Technology
Systems Inc
Hydro Kettle Falls,
WA
12/2013 1.30 1.05
Fighting Creek
Landfill Gas to
Energy Station
Kootenai Electric
Cooperative
Municipal
Waste
Coeur d’Alene,
ID
12/2013 3.20 1.31
Spokane
Waste to
Energy
City of Spokane Municipal
Waste
Spokane, WA 11/2014 18.00 16.00
Spokane
County
Digester
Spokane County Municipal
Waste
Spokane, WA 8/2016 0.26 0.14
Plummer Saw
Mill
Stimson Lumber Wood
Waste
Plummer, ID 11/2016 5.80 4.00
Deep Creek Deep Creek
Energy
Hydro Northpoint, WA 12/2016 0.41 0.23
Clark Fork
Hydro
James White Hydro Clark Fork, ID 12/2017 0.22 0.12
Upriver Dam14 City of Spokane Hydro Spokane, WA 12/2019 17.60 6.17
Sheep Creek
Hydro
Sheep Creek
Hydro Inc
Hydro Northpoint, WA 6/2021 1.40 0.79
Ford Hydro LP Ford Hydro Ltd
Partnership
Hydro Weippe, ID 6/2022 1.41 0.39
John Day
Hydro
David Cereghino Hydro Lucille, ID 9/2022 0.90 0.25
Phillips Ranch Glenn Phillips Hydro Northpoint, WA n/a 0.02 0.01
Total 50.52 30.45

Bonneville Power Administration – WNP-3 Settlement
Avista signed settlement agreements with BPA and Energy Northwest 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
Avista for WPPSS – Washington Nuclear Plant No. 3 (WNP-3) preservation costs and
an irrevocable offer of WNP-3 capability 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 Avista 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.
14 Energy estimate is net of pumping load.
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-30
The second provision provides BPA approximately 32 aMW of return energy at a cost
equal to the actual operating cost of Avista’s highest-cost resource. A further discussion
of this obligation, and how Avista plans to account for it, is under the Energy Planning
section.

Palouse Wind – Power Purchase Agreement
Avista signed a 30-year power purchase agreement in 2011 with Palouse Wind for the
entire output of the 105 MW project. Avista has the option to purchase the project after
year 10 of the contract. Commercial operation began in December 2012. The project is
EIA qualified and directly connected to Avista’s transmission system.

Table 2.9: Other Contractual Rights and Obligations

Contract Type Fuel
Source
End
Date
Winter
Capacity
(MW)
Summer
Capacity
(MW)
Annual
Energy
(aMW)
Stateline Purchase Wind 3/2014 0 0 9
Sacramento Municipal
Utility District
Sale System 12/2014 -50 -50 -50
PGE Capacity
Exchange
Exchange System 12/2016 -150 -150 0
Douglas Settlement Purchase Hydro 9/2018 2 2 3
WNP-3 Purchase System 6/2019 82 0 42
Lancaster Purchase Natural
Gas
10/2026 290 249 222
Palouse Wind Purchase Wind 12/2042 0 0 40
Nichols Pumping Sale System n/a -1 -1 -1
Total 173 50 265

Reserve Margins
Planning reserves accommodate situations when loads exceed and/or resource outputs
are below expectations due to adverse weather, forced outages, poor water conditions,
or other contingencies. There are disagreements within the industry on reserve margin
levels utilities should carry. Many disagreements stem from system differences, such as
resource mix, system size, and transmission interconnections.

Reserve margins, on average, increase customer rates when compared to resource
portfolios without reserves because of the additional cost of carrying additional
generating capacity that is rarely used. Reserve resources have the physical capability
to generate electricity, but high operating costs limit their economic dispatch and
revenues.

Avista Planning Margin
Avista retains two planning margin targets—capacity and energy. Capacity planning is
the traditional metric ensuring utilities can meet peak loads at times of system strain,
and cover variability inherent in their generation resources with unpredictable fuel
supplies, such as wind and hydro, and varying loads.
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-31
Capacity Planning
Utility capacity planning begins with regional planning. Resource and load positions of
the region as a whole affect individual utility resource acquisition decisions. The Pacific
Northwest has a history of being capacity surplus and energy deficit. The 2000-01
energy crisis led to the rapid development of 3,425 MW of natural gas-fired generation
in the Northwest. Over the following 10 years, the Northwest added 2,000 MW of natural
gas-fired generation. During this same time, Oregon and Washington added 6,000 MW
of wind. With recent wind additions, and their lack of capacity contribution, the region is
approaching a capacity balance with loads; but the region remains long on energy due
to the quantity of wind generation added to the system.

In recognition of these regional changes, the NPCC has done a considerable amount of
analytical work to understand and develop methodologies to identify capacity needs in
the region. Based on their work, the Northwest begins to fail a five percent Loss of Load
Probability (LOLP) test in the winter of 2017-18.15 Five percent LOLP means utilities
meet all customer demand in 19 of 20 years, or one loss of load event permitted on a
planning basis in 20 years due to insufficient generation. The NPCC identifies a need of
350 MW of new capacity, or 300 aMW of peak load reduction, to eliminate potential
2017-18 resource shortfall. The identified regional problem months are in the winter,
with a small change of problems in the summer months. The NPCC also studied load
growth and market availability scenarios. In the event of higher loads or reduced market
availability, the NPCC study indicated that the region should add 2,850 MW of new
capacity by 2017.

Because Avista often relies on the Northwest market to serve a portion of its peak load
needs, it requested additional data from the NPCC to develop regional load and
resource balance reports to understand the regional load and resource system balance.
With the NPCC data, Avista developed the information shown in Table 2.10. This table
illustrates the region’s substantial summer surplus and dwindling winter supplies. The
table also illustrates the resource capability based on the length of the peak event. The
table shows one, four, and ten-hour peaks, illustrating the unique impact that hydro has
on the Northwest’s ability to meet peak loads. These regional balances do not include
wind capacity.

In January 2018, the one hour implied planning margin is 24.3 percent, but with regional
IPPs included, the margin improves to 34.3 percent. During a one-hour event the
system has 8,050 excess MW or 11,374 with the IPPs. The real problem lies in a ten-
hour event, where only a 4.3 percent planning margin exists absent the IPPs, and a 15
percent margin with them. This translates into modest surpluses of 1,334 MW and 4,658
MW, respectively.

The region is long by more than 11,000 MW without, and over 14,000 MW with, the
IPPs in the summer. The main concern during a summer peak load event is that excess
power may be scheduled outside of the region on a pre-schedule basis, leaving limited
15 John Fazio, NPCC, ―Adequacy Assessment of the 2017 Pacific Northwest Power Supply‖, NW
Resource Adequacy Forum Steering Committee Meeting, October 26, 2012 in Portland, OR.
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-32
resource available for the Northwest. The maximum regional export to California is
estimated to be up to 7,980 MW absent any transmission derates. Power could also be
exported east through Idaho, but the limit east is 2,250 MW.16 The Northwest region has
options to import power from British Columbia and Montana. The NPCC believes the
region has sufficient capacity in the summer, but lacks capacity beginning in 2017 in the
winter.

Table 2.10: Regional Load & Resource Balance

January 2018 August 2018
1 Hour 4 Hour 10 Hour 1 Hour 4 Hour 10 Hour
Implied Planning Margin (PM) 24.3% 11.7% 4.3% 44.7% 46.4% 49.3%
w/ IPP Implied PM 34.3% 21.9% 15.0% 56.6% 58.6% 62.0%
Length (MW) 8,050 3,789 1,334 11,687 11,894 12,113
w/ IPP Length (MW) 11,374 7,112 4,658 14,804 15,010 15,229
January 2025 August 2025
1 Hour 4 Hour 10 Hour 1 Hour 4 Hour 10 Hour
Implied Planning Margin (PM) 12.5% -1.5% -12.0% 30.7% 29.3% 28.7%
w/ IPP Implied PM 19.1% 5.2% -5.0% 38.4% 37.1% 36.8%
Length (MW) 4,489 -533 -4,042 8,706 8,141 7,631
w/ IPP Length (MW) 6,853 1,831 -1,679 10,862 10,297 9,788

Avista’s Loss of Load Analysis
In the Northwest, reliability matrices can help address the issue of how much planning
margin is required. Typical results of these models are LOLP, Loss of Load Hours
(LOLH), and Loss of Load Expectation (LOLE) measures. A reliable system is typically
defined as having no more than one interruption event in twenty years, or a five percent
LOLP. These analyses can be helpful, but usually have an inherent flaw due to the need
to assume how much out-of-area imported generation is available for the study.

Avista developed its LOLP model to simulate reliability events caused by to poor hydro
runoff, forced outages, and extreme weather conditions on its system, finding that
forced outages are the main driver of reliability events and/or the need for imported
power. Avista is well positioned to import power. It has adequate transmission
capabilities to import power from the wholesale energy markets, but the amount of
generation actually available for purchase from third parties at times of system peak is
difficult to estimate. To address this concern, a sophisticated regional model must
estimate required regional planning margins. As discussed above, the NPCC has
performed this regional assessment. The challenge, even at the regional level, is
modeling market imports into or exports from the region. To address this shortfall the
NPCC and Avista use scenario analyses.17
The results of Avista’s LOLP study are in Figure 2.20. The results use scenario
analyses to illustrate potential planning margins using a test year of 2020. The
scenarios change the amount of market reliance compared with new resource
16 Ibid. 17 Ibid.
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-33
acquisitions by Avista. This chart indicates that with a 12 percent planning margin Avista
would rely on 275 MW from the market to meet a 5 percent LOLP metric. To eliminate
market reliance, Avista would require a 31 percent planning margin at an additional
power supply cost of $40 million per year.

Figure 2.20: 2020 Market Reliance & Capacity Cost Tradeoffs to Achieve 5 Percent LOLP

While scenario analysis helps management understand the tradeoffs between imports
and new plant construction, it does not help identify the actual planning margin. For this
IRP, Avista chose a 14 percent basic planning margin. The addition of operating
reserves and other ancillary services results in a total planning margin of 22 percent.
This level is similar to the planning margin used in the 2011 IRP and is similar to other
utilities. Further, the planning margin is similar to NPCC’s 23 percent recommendation
for the region.18 The 14 percent planning margin implies Avista will rely on 240 MW of
market power in some peak events.

In addition to understanding the level of imports Avista will depend on during extreme
peak events, it considers the regional resource position before deciding to procure new
resources. Based on the current regional surplus shown in Table 2.10, Avista does not
believe it is necessary procure new resources for future summer deficits. During
summer months, the regional resource position is longer than the winter position. As a
dual-peaking utility, Avista is concerned with summer reliability, but with the regional
resource length described above, the addition of new resources likely is unnecessary.
18 The NPCC does not consider operating reserves and ancillary services separately from the planning
margin, but instead combines them together into one figure.
0
5
10
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20
25
30
35
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45
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12%13%15%16%18%19%21%22%24%25%27%28%30%31%
in
c
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e
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(
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(
M
W
)
planning margin
MW
Annual Cost
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-34
Where the region shows signs of becoming resource deficient in the future, Avista will
re-evaluate its positions.

Balancing Loads and Resources
Both the single-hour and sustained-peak requirements compare future projections of
utility loads and resources. The single peak hour is more of a concern in the winter than
the three-day sustained 18-hour peak. During winter months, the hydro system is able
to sustain generation levels for longer periods than in the summer months due to higher
inflows. Figure 2.21 illustrates the winter balance of loads and resources; the first year
Avista identifies a significant winter capacity deficit is January 2020. Avista has small
deficits in 2015 and 2016, but regional surplus and the expiration of the 150 MW
capacity contract with Portland General Electric at the end of 2016 suggests the utility
should rely on the short-term marketplace to meet these deficits. A detailed table of
Avista’s annual loads and resources is at the end of this chapter in Tables 2.12 through
2.14.

Figure 2.21: Winter 1 Hour Capacity Load and Resources

The 2013 IRP does not anticipate meeting summer capacity deficits with new
resources, because of the significant regional surplus in the summer. Similar to the
region, Avista’s generation additions to meet winter peaks will substantially eliminate
summer deficits.

Avista’s summer resource balance is in Figure 2.22. This chart differs from the winter
load and resource balance by using an 18-hour sustained peak rather than the single
hour peak. The sustained peak is more constraining in the summer months due to
reservoir restrictions and lower river flows reducing the amount of continuous hydro
-500
0
500
1,000
1,500
2,000
2,500
20
1
4
20
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5
20
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6
20
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3
me
g
a
w
a
t
t
s
Net Firm Contracts Peaking ThermalsBaseload Thermals HydroLoad Forecast Load Forecast + PM/Reserves
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-35
generation available to meet load. This chart also differs from the winter because Avista
is not adding a planning margin to the summer due to expected regional surpluses. See
Table 2.13 for more details.

Figure 2.22: Summer 18-Hour Capacity Load and Resources

Energy Planning
For energy planning, resources must be adequate to meet customer requirements even
when loads are high for extended periods or an outage limits the output of a resource.
Where generation capability is not adequate to meet these variations, customers and
the utility must rely on the volatile short-term electricity market. In addition to load
variability, planning margins accounts for variations in hydroelectric generation.

As with capacity planning, there are differences in regional opinion on the proper
method for establishing energy-planning margins. Many utilities in the Northwest base
their planning on the amount of energy available during the critical water period of
1936/37.19 The critical water year of 1936/37 was low on an annual basis, but it was not
necessarily low in every month. The IRP could target resource development to reach a
99 percent confidence level on being able to deliver energy to its customers, and it
would significantly decrease the frequency of its market purchases. However, this
strategy requires investments in approximately 200 MW of generation in addition to the
margins included in Expected Case of the IRP. Expenditures to support this high level of
reliability would put upward pressure on retail rates for a modest benefit. Avista instead
plans to the 90th percentile for hydro. There is a 10 percent chance of needing to
purchase energy from the market in any given month over the IRP timeframe, but in
19 The critical water year represents the lowest historical generation level in the streamflow record.
-500
0
500
1,000
1,500
2,000
2,500
20
1
4
20
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me
g
a
w
a
t
t
s
Net Firm Contracts Peaking Thermals
Baseload Thermals Hydro
Load Forecast + PM/Reserves
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-36
nine of ten years, Avista would meet all of its energy requirements and sell surplus
electricity into the marketplace.

Beyond load and hydroelectricity variability, Avista’s WNP-3 contract with BPA contains
supply risk. The contract includes a return energy provision in favor of BPA that can
equal 32 aMW annually. Under adverse market conditions, BPA almost certainly would
exercise this right, as it did during the 2001 Energy Crisis. To account for contract risk,
the energy contingency is increased by 32 aMW until the contract expires in 2019. With
the addition of WNP-3 to load and hydroelectricity variability, the total energy
contingency equals 228 aMW in 2014. See Figure 2.23 for the summary of the annual
average energy load and resource net position.

Figure 2.23: Annual Average Energy Load and Resources

Washington State Renewable Portfolio Standard
In the November 2006 general election, Washington voters approved the EIA. The EIA
requires utilities with more than 25,000 customers to source 3 percent of their energy
from qualified non-hydroelectric renewables by 2012, 9 percent by 2016, and 15 percent
by 2020. Utilities also must acquire all cost effective conservation and energy efficiency
measures. In 2011, Avista acquired the Palouse Wind project through a 30-year power
purchase agreement to help meet the renewable goal. In 2012, an amendment to the
EIA allowed biomass facilities built prior to 1999 to qualify under the law beginning in
2016. This amendment allows Avista’s 50 MW Kettle Falls project to qualify and further
help the company meet EIA requirements. Table 2.11 shows the forecast amount of
RECs required to meet Washington state law, and the amount of qualifying resources
already in Avista’s generation portfolio. The sales forecast uses the Washington portion
of the current load forecast. It illustrates how Avista will maintain a modest surplus of
0
500
1,000
1,500
2,000
2,500
20
1
4
20
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5
20
1
6
20
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e
r
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e

m
e
g
a
w
a
t
t
s
Net Firm Contracts Peaking Thermals
Baseload Thermals Hydro
Load Forecast Load Forecast + Contingency
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-37
approximately 10 aMW in 2016 to account for annual generation variability at its EIA-
qualifying plants.

Resource Requirements
The resource requirements discussed in this section do not include energy efficiency
acquisitions beyond what is contained in the load forecast. The PRS chapter discusses
conservation beyond assumptions contained in the load forecast. The following tables
present loads and resources to illustrate future resource requirements.

During winter peak periods (Table 2.12), surplus capacity exists through 2019 after
taking into account market purchases.20 Without these purchases, a capacity deficit
would exist in 2012. Avista believes that the present market can meet these minor
winter capacity shortfalls and therefore will optimize its portfolio to postpone new
resource investments for winter capacity until 2020.

The summer peak projection in Table 2.13shows lower loads than in winter, but
resource capabilities are also lower due to lower hydroelectricity output and reduced
capacity at natural gas-fired resources. The IRP shows persistent summer deficits
throughout the 20-year timeframe, but regional surpluses are adequate to fill in these
gaps. Many near-term deficits are from decreased hydroelectricity capacity during
periods of planned maintenance and upgrades. Taking into account regional surpluses,
the load and resource balance is 54 MW short only in 2016. After 2016, when the
Portland General Electricity capacity sale contract expires, the next capacity need is in
2019 at 98 MW.

The traditional measure of resource need in the region is the annual average energy
position. Table 2.14 shows the energy position. There is enough energy on an annual
average basis to meet customer requirements until 2020, when the utility is short 49
aMW. Avista will require 112 aMW of new energy by 2025, and 475 aMW in 2031.

20 Avista relied on work by the NPCC in its Resource Adequacy Forum exercises to determine the level of
surplus summer energy and capacity. Reliance is limited to Avista’s prorated share of regional load.
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-38
Table 2.11: Washington State RPS Detail (aMW)
On
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1
2
20
1
3
20
1
4
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5
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6
20
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7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
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8
20
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9
20
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0
20
3
1
20
3
2
20
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3
WA

S
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F
o
r
e
c
a
s
t
62
8

63
3

64
0

64
6

65
0

65
8

66
5

66
8

67
1

67
6

68
0

68
4

68
7

69
4

69
8

70
2

70
4

71
1

71
6

72
2

72
6

73
5

RP
S

%
3%
3%
3%
3%
9%
9%
9%
9%
15
%
15
%
15
%
15
%
15
%
15
%
15
%
15
%
15
%
15
%
15
%
15
%
15
%
15
%
RE
Q
U
I
R
E
D

R
E
N
E
W
A
B
L
E

E
N
E
R
G
Y
19
.
0
19
.
0
18
.
9
19
.
1
57
.
9
58
.
3
58
.
9
59
.
5
10
0
.
0
10
0
.
5
10
1
.
0
10
1
.
7
10
2
.
2
10
2
.
8
10
3
.
6
10
4
.
4
10
5
.
0
10
5
.
4
10
6
.
1
10
7
.
0
10
7
.
9
10
8
.
6
In
c
r
e
m
e
n
t
a
l

H
y
d
r
o
Lo
n
g

L
a
k
e

3
19
9
9
1.0
1.
6
1.
6
1.
6
1.
6
1.
6
1.
6
1.
6
1.6
1.
6
1.
6
1.
6
1.
6
1.
6
1.6
1.
6
1.
6
1.
6
1.
6
1.
6
1.
6
1.
6
1.
6
1.
6
Lit
t
l
e

F
a
l
l
s

4
20
0
1
1.0
0.
6
0.
6
0.
6
0.
6
0.
6
0.
6
0.
6
0.6
0.
6
0.
6
0.
6
0.
6
0.
6
0.6
0.
6
0.
6
0.
6
0.
6
0.
6
0.
6
0.
6
0.
6
0.
6
Ca
b
i
n
e
t

2
20
0
4
1.0
3.
3
3.
3
3.
3
3.
3
3.
3
3.
3
3.
3
3.3
3.
3
3.
3
3.
3
3.
3
3.
3
3.3
3.
3
3.
3
3.
3
3.
3
3.
3
3.
3
3.
3
3.
3
3.
3
Ca
b
i
n
e
t

3
20
0
1
1.0
5.
2
5.
2
5.
2
5.
2
5.
2
5.
2
5.
2
5.2
5.
2
5.
2
5.
2
5.
2
5.
2
5.2
5.
2
5.
2
5.
2
5.
2
5.
2
5.
2
5.
2
5.
2
5.
2
Ca
b
i
n
e
t

4
20
0
7
1.0
2.
3
2.
3
2.
3
2.
3
2.
3
2.
3
2.
3
2.3
2.
3
2.
3
2.
3
2.
3
2.
3
2.3
2.
3
2.
3
2.
3
2.
3
2.
3
2.
3
2.
3
2.
3
2.
3
No
x
o
n

1
20
0
9
1.0
2.
4
2.
4
2.
4
2.
4
2.
4
2.
4
2.
4
2.4
2.
4
2.
4
2.
4
2.
4
2.
4
2.4
2.
4
2.
4
2.
4
2.
4
2.
4
2.
4
2.
4
2.
4
2.
4
No
x
o
n

3
20
1
0
1.0
1.
7
1.
7
1.
7
1.
7
1.
7
1.
7
1.
7
1.7
1.
7
1.
7
1.
7
1.
7
1.
7
1.7
1.
7
1.
7
1.
7
1.
7
1.
7
1.
7
1.
7
1.
7
1.
7
No
x
o
n

2
20
1
1
1.0
0.
9
0.
9
0.
9
0.
9
0.
9
0.
9
0.
9
0.9
0.
9
0.
9
0.
9
0.
9
0.
9
0.9
0.
9
0.
9
0.
9
0.
9
0.
9
0.
9
0.
9
0.
9
0.
9
No
x
o
n

4
20
1
2
1.0
1.
4
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
1.
4
1.
4
1.
4
1.
4
1.
4
1.
4
1.
4
Nin
e

M
i
l
e
20
1
5
1.0
1.
4
0.
0
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
1.
4
1.
4
1.
4
1.
4
1.
4
1.
4
1.
4
Wa
n
a
p
u
m

F
i
s
h

B
y
p
a
s
s
20
0
8
1.0
2.
5
2.
5
2.
4
2.
4
2.
4
2.
4
2.4
2.
4
2.
4
2.
4
2.
4
2.
4
2.4
2.
4
2.
4
2.
4
2.
4
2.
4
2.
4
2.
4
2.
4
2.
4
To
t
a
l

Q
u
a
l
i
f
y
i
n
g

R
e
s
o
u
r
c
e
s
21
.
3
23
.
3
23
.
2
23
.
2
23
.
2
23
.
2
23
.
2
23
.
2
23
.
2
23
.
2
23
.
2
23
.
2
23
.
2
23
.
2
23
.
2
23
.
2
23
.
2
23
.
2
23
.
2
23
.
2
23
.
2
23
.
2
RE
C

P
O
S
I
T
I
O
N

N
E
T

O
F

I
N
C
R
E
M
E
N
T
A
L

H
Y
D
R
O
0.
0
0.
0
0.
0
0.
0
-3
4
.
7
-3
5
.
2
-3
5
.
7
-3
6
.
4
-7
6
.
8
-7
7
.
3
-7
7
.
9
-7
8
.
5
-7
9
.
1
-7
9
.
6
-8
0
.
4
-8
1
.
2
-8
1
.
8
-8
2
.
2
-8
2
.
9
-8
3
.
8
-8
4
.
7
-8
5
.
5
Qu
a
l
i
f
y
i
n
g

R
e
n
e
w
a
b
l
e

R
e
s
o
u
r
c
e
s
/
R
E
C
s
Pu
r
c
h
a
s
e
d

R
E
C
s
0.
0
0.
0
0.
0
5.
7
0.
0
0.
0
0.0
0.
0
0.
0
0.
0
0.
0
0.
0
0.0
0.
0
0.
0
0.
0
0.
0
0.
0
0.
0
0.
0
0.
0
0.
0
Ke
t
t
l
e

F
a
l
l
s
19
8
3
1.0
0.
0
0.
0
0.
0
0.
0
32
.
5
32
.
1
31
.
9
32
.
5
32
.
4
33
.
2
31
.
8
32
.
5
31
.
8
32
.
5
31
.
8
32
.
5
31
.
8
32
.
5
31
.
8
32
.
5
31
.
8
31
.
8
Pa
l
o
u
s
e

W
i
n
d
20
1
2
1.2
39
.
9
0.
0
47
.
9
47
.
9
47
.
9
47
.
9
47
.
9
47
.
9
47
.
9
47
.
9
47
.
9
47
.
9
47
.
9
47
.
9
47
.
9
47
.
9
47
.
9
47
.
9
47
.
9
47
.
9
47
.
9
47
.
9
47
.
9
To
t
a
l

Q
u
a
l
i
f
y
i
n
g

R
e
s
o
u
r
c
e
s
0.
0
47
.
9
47
.
9
53
.
6
80
.
4
80
.
0
79
.
9
80
.
4
80
.
3
81
.
2
79
.
7
80
.
4
79
.
7
80
.
4
79
.
7
80
.
4
79
.
7
80
.
4
79
.
7
80
.
4
79
.
7
79
.
7
NE
T

R
E
C

P
O
S
I
T
I
O
N

B
E
F
O
R
E

B
A
N
K
I
N
G

&

R
E
S
E
R
V
E
S
0.
0
47
.
9
47
.
9
53
.
6
45
.
7
44
.
8
44
.
2
44
.
1
3.
5
3.
9
1.
8
1.
9
0.6
0.
8
-0
.
7
-0
.
8
-2
.
1
-1
.
8
-3
.
2
-3
.
4
-5
.
0
-5
.
8
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-39
Table 2.12: Winter 18-Hour Capacity Position (MW)

20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
RE
Q
U
I
R
E
M
E
N
T
S
Na
t
i
v
e

L
o
a
d
-1
,
6
6
5
-1
,
6
8
3
-1
,
7
0
0
-1
,
7
1
3
-1
,
7
2
7
-1
,
7
4
1
-1
,
7
5
5
-1
,
7
6
9
-1
,
7
8
3
-1
,
7
9
8
-1
,
8
1
2
-1
,
8
2
7
-1
,
8
4
2
-1
,
8
5
6
-1
,
8
7
1
-1
,
8
8
7
-1
,
9
0
2
-1
,
9
1
7
-1
,
9
3
3
-1
,
9
4
8
Fi
r
m

P
o
w
e
r

S
a
l
e
s
-2
1
1
-1
5
8
-1
5
8
-8
-8
-6
-6
-6
-6
-6
-6
-6
-6
-6
-6
-6
-6
-6
-6
-6
To
t
a
l

R
e
q
u
i
r
e
m
e
n
t
s
-1
,
8
7
5
-1
,
8
4
1
-1
,
8
5
7
-1
,
7
2
1
-1
,
7
3
5
-1
,
7
4
7
-1
,
7
6
1
-1
,
7
7
5
-1
,
7
8
9
-1
,
8
0
4
-1
,
8
1
8
-1
,
8
3
3
-1
,
8
4
8
-1
,
8
6
3
-1
,
8
7
8
-1
,
8
9
3
-1
,
9
0
8
-1
,
9
2
3
-1
,
9
3
9
-1
,
9
5
4
RE
S
O
U
R
C
E
S
Fi
r
m

P
o
w
e
r

P
u
r
c
h
a
s
e
s
11
7
11
7
11
7
11
7
11
7
11
6
34
34
33
33
33
33
33
33
33
33
33
33
33
33
Hy
d
r
o

R
e
s
o
u
r
c
e
s
99
8
88
8
88
9
95
5
95
5
91
9
92
4
92
0
92
0
92
8
92
0
92
0
92
8
92
0
92
0
92
8
92
0
92
0
92
8
92
0
Ba
s
e

L
o
a
d

T
h
e
r
m
a
l
s
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
61
7
61
7
61
7
61
7
61
7
61
7
61
7
Wi
n
d

R
e
s
o
u
r
c
e
s
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Pe
a
k
i
n
g

U
n
i
t
s
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
To
t
a
l

R
e
s
o
u
r
c
e
s
2,
2
5
2
2,
1
4
3
2,
1
4
3
2,
2
1
0
2,
2
1
0
2,
1
7
2
2,
0
9
5
2,
0
9
1
2,
0
9
1
2,
0
9
8
2,
0
9
0
2,
0
9
0
2,
0
9
8
1,
8
1
1
1,8
1
1
1,8
1
9
1,8
1
1
1,8
1
1
1,
8
1
9
1,
8
1
1
Pe
a
k

P
o
s
i
t
i
o
n

B
e
f
o
r
e

R
e
s
e
r
v
e

P
l
a
n
n
i
n
g
37
7
30
2
28
6
48
9
47
5
42
5
33
4
31
6
30
1
29
4
27
2
25
7
25
0
-5
1
-6
6
-7
4
-9
7
-1
1
2
-1
2
0
-1
4
3
RE
S
E
R
V
E

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

M
a
r
g
i
n
-2
3
3
-2
3
6
-2
3
8
-2
4
0
-2
4
2
-2
4
4
-2
4
6
-2
4
8
-2
5
0
-2
5
2
-2
5
4
-2
5
6
-2
5
8
-2
6
0
-2
6
2
-2
6
4
-2
6
6
-2
6
8
-2
7
1
-2
7
3
To
t
a
l

A
n
c
i
l
l
a
r
y

S
e
r
v
i
c
e
s

R
e
q
u
i
r
e
d
-1
3
9
-1
3
6
-1
3
7
-1
2
8
-1
2
9
-1
3
1
-1
3
6
-1
3
7
-1
3
8
-1
3
9
-1
4
1
-1
4
2
-1
4
3
-1
3
9
-1
3
9
-1
4
0
-1
4
0
-1
4
0
-1
4
0
-1
4
0
Re
s
e
r
v
e

&

C
o
n
t
i
n
g
e
n
c
y

A
v
a
i
l
a
b
i
l
i
t
y
13
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
De
m
a
n
d

R
e
s
p
o
n
s
e
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
To
t
a
l

R
e
s
e
r
v
e

P
l
a
n
n
i
n
g
-3
5
9
-3
6
6
-3
6
9
-3
6
2
-3
6
6
-3
6
9
-3
7
6
-3
7
9
-3
8
2
-3
8
6
-3
8
9
-3
9
2
-3
9
5
-3
9
3
-3
9
6
-3
9
8
-4
0
0
-4
0
3
-4
0
6
-4
0
8
Pe
a
k

P
o
s
i
t
i
o
n

w
/

R
e
s
e
r
v
e

P
l
a
n
n
i
n
g
17
-6
4
-8
4
12
6
11
0
56
-4
2
-6
4
-8
1
-9
2
-1
1
7
-1
3
5
-1
4
5
-4
4
5
-4
6
2
-4
7
2
-4
9
7
-5
1
5
-5
2
5
-5
5
1
Im
p
l
i
e
d

P
l
a
n
n
i
n
g

M
a
r
g
i
n
21
%
17
%
16
%
29
%
28
%
25
%
19
%
18
%
17
%
17
%
15
%
14
%
14
%
-2
%
-3
%
-4
%
-5
%
-6
%
-6
%
-7
%
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-40
Table 2.13: Summer 18-Hour Capacity Position (MW)
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
RE
Q
U
I
R
E
M
E
N
T
S
Na
t
i
v
e

L
o
a
d
-1
,
4
6
5
-1
,
4
8
2
-1
,
4
9
8
-1
,
5
1
0
-1
,
5
2
3
-1
,
5
3
6
-1
,
5
5
0
-1
,
5
6
3
-1
,
5
7
6
-1
,
5
9
0
-1
,
6
0
4
-1
,
6
1
8
-1
,
6
3
1
-1
,
6
4
6
-1
,
6
6
0
-1
,
6
7
4
-1
,
6
8
9
-1
,
7
0
3
-1
,
7
1
8
-1
,
7
3
3
Fi
r
m

P
o
w
e
r

S
a
l
e
s
-2
1
2
-1
5
9
-1
5
9
-9
-9
-8
-8
-7
-7
-7
-7
-7
-7
-7
-7
-7
-7
-7
-7
-7
To
t
a
l

R
e
q
u
i
r
e
m
e
n
t
s
-1
,
6
7
7
-1
,
6
4
1
-1
,
6
5
7
-1
,
5
1
9
-1
,
5
3
2
-1
,
5
4
4
-1
,
5
5
7
-1
,
5
7
0
-1
,
5
8
4
-1
,
5
9
7
-1
,
6
1
1
-1
,
6
2
5
-1
,
6
3
9
-1
,
6
5
3
-1
,
6
6
7
-1
,
6
8
1
-1
,
6
9
6
-1
,
7
1
0
-1
,
7
2
5
-1
,
7
4
0
RE
S
O
U
R
C
E
S
Fi
r
m

P
o
w
e
r

P
u
r
c
h
a
s
e
s
29
29
29
29
29
26
26
26
26
25
25
25
25
25
25
25
25
25
25
25
Hy
d
r
o

R
e
s
o
u
r
c
e
s
70
1
70
7
66
3
63
1
63
8
58
3
58
0
62
2
62
4
62
2
62
2
62
4
62
2
62
2
62
4
62
2
62
2
62
4
62
2
62
2
Ba
s
e

L
o
a
d

T
h
e
r
m
a
l
s
78
5
78
5
78
5
78
5
78
5
78
5
78
5
78
5
78
5
78
5
78
5
78
5
78
5
55
6
55
6
55
6
55
6
55
6
55
6
55
6
Wi
n
d

R
e
s
o
u
r
c
e
s
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Pe
a
k
i
n
g

U
n
i
t
s
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
To
t
a
l

R
e
s
o
u
r
c
e
s
1,
6
9
1
1,
6
9
8
1,
6
5
3
1,
6
2
1
1,
6
2
8
1,
5
7
1
1,
5
6
8
1,
6
0
9
1,6
1
1
1,
6
0
9
1,
6
0
9
1,
6
1
1
1,
6
0
9
1,
3
7
9
1,
3
8
1
1,
3
7
9
1,
3
7
9
1,
3
8
1
1,
3
7
9
1,3
7
9
Pe
a
k

P
o
s
i
t
i
o
n

B
e
f
o
r
e

R
e
s
e
r
v
e

P
l
a
n
n
i
n
g
14
57
-3
10
2
96
27
11
39
27
11
-2
-1
4
-3
0
-2
7
4
-2
8
6
-3
0
2
-3
1
7
-3
3
0
-3
4
6
-3
6
1
RE
S
E
R
V
E

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

M
a
r
g
i
n
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
To
t
a
l

A
n
c
i
l
l
a
r
y

S
e
r
v
i
c
e
s

R
e
q
u
i
r
e
d
-1
7
7
-1
7
6
-1
7
7
-1
7
0
-1
7
2
-1
7
3
-1
7
5
-1
7
6
-1
7
7
-1
7
9
-1
8
0
-1
8
1
-1
8
2
-1
6
6
-1
6
7
-1
6
7
-1
6
8
-1
6
9
-1
6
9
-1
7
0
Re
s
e
r
v
e

&

C
o
n
t
i
n
g
e
n
c
y

A
v
a
i
l
a
b
i
l
i
t
y
17
7
17
6
17
7
17
0
17
2
17
3
17
5
17
6
17
7
17
9
18
0
18
1
18
2
16
6
16
7
16
7
16
8
16
9
16
9
17
0
De
m
a
n
d

R
e
s
p
o
n
s
e
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
To
t
a
l

R
e
s
e
r
v
e

P
l
a
n
n
i
n
g
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Pe
a
k

P
o
s
i
t
i
o
n

w
/

R
e
s
e
r
v
e

P
l
a
n
n
i
n
g
14
57
-3
10
2
96
27
11
39
27
11
-2
-1
4
-3
0
-2
7
4
-2
8
6
-3
0
2
-3
1
7
-3
3
0
-3
4
6
-3
6
1
Im
p
l
i
e
d

P
l
a
n
n
i
n
g

M
a
r
g
i
n
11
%
14
%
10
%
18
%
17
%
13
%
12
%
14
%
13
%
12
%
11
%
10
%
9%
-7
%
-7
%
-8
%
-9
%
-9
%
-1
0
%
-1
1
%
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-41
Table 2.14: Average Annual Energy Position (aMW)

20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
RE
Q
U
I
R
E
M
E
N
T
S
Na
t
i
v
e

L
o
a
d
-1
,
0
5
4
-1
,
0
6
7
-1
,
0
7
9
-1
,
0
9
3
-1
,
1
0
5
-1
,
1
1
4
-1
,
1
2
5
-1
,
1
3
5
-1
,
1
4
5
-1
,
1
5
5
-1
,
1
6
7
-1
,
1
8
0
-1
,
1
9
0
-1
,
2
0
1
-1
,
2
1
2
-1
,
2
2
5
-1
,
2
3
9
-1
,
2
5
4
-1
,
2
7
0
-1
,
2
8
5
Fi
r
m

P
o
w
e
r

S
a
l
e
s
-1
0
9
-5
8
-5
8
-6
-6
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
To
t
a
l

R
e
q
u
i
r
e
m
e
n
t
s
-1
,
1
6
3
-1
,
1
2
5
-1
,
1
3
7
-1
,
0
9
9
-1
,
1
1
1
-1
,
1
1
9
-1
,
1
3
0
-1
,
1
4
0
-1
,
1
5
0
-1
,
1
6
0
-1
,
1
7
2
-1
,
1
8
5
-1
,
1
9
5
-1
,
2
0
6
-1
,
2
1
7
-1
,
2
3
0
-1
,
2
4
4
-1
,
2
5
9
-1
,
2
7
4
-1
,
2
9
0
RE
S
O
U
R
C
E
S
Fi
r
m

P
o
w
e
r

P
u
r
c
h
a
s
e
s
12
8
12
9
12
8
76
76
56
31
30
30
29
29
29
29
29
29
29
29
29
29
29
Hy
d
r
o

R
e
s
o
u
r
c
e
s
52
7
49
5
49
5
49
5
49
0
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
Ba
s
e

L
o
a
d

T
h
e
r
m
a
l
s
72
3
72
5
71
8
71
5
73
2
71
1
72
4
73
6
71
3
71
7
71
4
71
9
67
3
50
6
50
4
50
6
50
4
50
6
50
4
50
6
Wi
n
d

R
e
s
o
u
r
c
e
s
42
40
40
40
40
40
40
40
40
40
40
40
40
40
40
40
40
40
40
40
Pe
a
k
i
n
g

U
n
i
t
s
15
3
13
9
15
4
15
3
15
3
15
3
14
7
15
1
15
2
15
3
15
2
15
3
15
2
15
3
15
2
15
3
15
2
15
3
15
2
15
3
To
t
a
l

R
e
s
o
u
r
c
e
s
1,
5
7
3
1,
5
2
8
1,
5
3
5
1,
4
7
9
1,4
9
0
1,
4
4
0
1,
4
2
2
1,
4
3
8
1,
4
1
6
1,
4
2
0
1,
4
1
5
1,
4
2
1
1,
3
7
4
1,
2
0
8
1,
2
0
6
1,
2
0
8
1,
2
0
6
1,
2
0
8
1,
2
0
6
1,
2
0
8
Pe
a
k

P
o
s
i
t
i
o
n

B
e
f
o
r
e

R
e
s
e
r
v
e

P
l
a
n
n
i
n
g
41
0
40
4
39
8
38
0
37
9
32
1
29
2
29
9
26
6
25
9
24
3
23
7
17
9
2
-1
2
-2
2
-3
9
-5
1
-6
9
-8
2
RE
S
E
R
V
E

P
L
A
N
N
I
N
G
Co
n
t
i
n
g
e
n
c
y
-2
2
8
-2
3
1
-2
3
1
-2
3
2
-2
3
2
-2
1
4
-1
9
5
-1
9
6
-1
9
6
-1
9
7
-1
9
7
-1
9
8
-1
9
8
-1
9
9
-1
9
9
-2
0
0
-2
0
0
-2
0
1
-2
0
2
-2
0
2
Pe
a
k

P
o
s
i
t
i
o
n

w
/

R
e
s
e
r
v
e

P
l
a
n
n
i
n
g
18
2
17
3
16
7
14
8
14
7
10
6
96
10
3
70
63
46
39
-1
9
-1
9
7
-2
1
1
-2
2
1
-2
3
9
-2
5
2
-2
7
0
-2
8
4

Chapter 3–Energy Efficiency
Avista Corp 2013 Electric IRP
3. Energy Efficiency

Introduction
Avista began offering energy efficiency programs to customers in 1978. Notable
efficiency achievements include the Energy Exchanger program (1992 to 1994)
converting approximately 20,000 homes from electricity to natural gas space and/or
water heat. Avista pioneered the country’s first system benefit charge for energy
efficiency in 1995. In response to the 2001 Western Energy Crisis, Avista acquired over
three times the annual acquisition at only double the cost over a six-month period.
During the summer of 2011, Avista distributed 2.3 million compact fluorescent lights
(CFLs) to residential and commercial customers for an estimated energy savings of
39,005 MWh. Conservation programs regularly meet or exceed regional shares of
energy efficiency gains as outlined by the NPCC.

Figure 3.1 illustrates Avista’s historical electricity conservation acquisitions. Avista has
acquired 168 aMW of energy efficiency since 1978; however, the 18-year average life of
the conservation portfolio means some measures have reached the end of their useful
lives and are no longer reducing loads. The 18-year assumed measure life accounts for
the difference between the Cumulative and Online lines in Figure 3.1.

Section Highlights
This IRP includes a Conservation Potential Assessment of Avista’s Idaho and
Washington service territories.
Current Avista-sponsored conservation reduces retail loads by nearly 10
percent, or 115 aMW.
Avista evaluated over 3,000 equipment options, and over 1,700 measure
options covering all major end use equipment, as well as devices and actions
to reduce energy consumption for this IRP.

Chapter 3–Energy Efficiency
Avista Corp 2013 Electric IRP
Figure 3.1: Historical and Forecast Conservation Acquisition (system)

Avista’s energy efficiency programs provide a range of conservation and education
options to residential, low income, commercial, and industrial customer segments. The
programs are either prescriptive or site-specific. Prescriptive programs, or standard
offerings, provide cash incentives for standardized products such as the installation of
specified high-efficiency heating equipment. Prescriptive programs are suitable in
situations where uniform products or offerings are applicable for large groups of
homogeneous customers and primarily offered to residential and small commercial
customers. Site-specific programs, or customized offerings, provide cash incentives for
any cost-effective energy saving measure or equipment with an economic payback
greater than one year and less than eight years for non-LED lighting projects, or less
than 13 years for all other end uses and technologies.

Efficiency programs with economic paybacks of less than one year are ineligible for
incentives, although Avista assists in educating and informing customers about these
types of efficiency measures. Site-specific programs require customized services for
commercial and industrial customers because of the unique characteristics of each of
their premises and processes. In some cases, Avista uses a prescriptive approach
where similar applications of energy efficiency measures result in reasonably consistent
savings estimates in conjunction with a high achievable savings potential. An example
is prescriptive lighting for commercial and industrial applications.

Conservation Potential Assessment Approach
The EIA obligates Avista to complete an independent Conservation Potential
Assessment (CPA) biennially.1 This study forms the basis for the conservation portion of
1 See WAC 480-109 and RCW 19.285
0
60
120
180
240
300
360
420
480
540
600
0
2
4
6
8
10
12
14
16
18
20
19
7
8
19
8
0
19
8
2
19
8
4
19
8
6
19
8
8
19
9
0
19
9
2
19
9
4
19
9
6
19
9
8
20
0
0
20
0
2
20
0
4
20
0
6
20
0
8
20
1
0
20
1
2
20
1
4
20
1
6
20
1
8
20
2
0
20
2
2
20
2
4
20
2
6
20
2
8
20
3
0
20
3
2
cu
m
u
l
a
t
i
v
e

s
a
v
i
n
g
s

(
a
M
W
)
an
n
u
a
l

s
a
v
i
n
g
s

(
a
M
W
)
Cumulative
Online
Chapter 3–Energy Efficiency
Avista Corp 2013 Electric IRP
this IRP. In 2010, Avista retained Global Energy Partners to conduct this study for its
Idaho and Washington electric service territories. EnerNOC acquired the company in
2011 and updated the previous study for this IRP. The CPA identifies the 20-year
potential for energy efficiency and provides data on resources specific to Avista’s
service territory for use in the 2013 IRP, in accordance with the EIA energy efficiency
goals. The energy efficiency potential considers the impacts of existing programs, the
influence of known building codes and standards, technology developments and
innovations, changes to the economic influences, and energy prices.

EnerNOC took the following steps to assess and analyze energy efficiency and potential
within Avista’s service territory. Figure 3.2 illustrates the steps of the analysis.

1. Market Assessment: Categorizes energy consumption in the residential
(including low-income customers), commercial, and industrial sectors. This
assessment uses utility and secondary data to characterize customers’ electric
usage behavior in Avista’s service territory. EnerNOC uses this assessment to
develop energy market profiles describing energy consumption by market
segment, vintage (existing or new construction), end use, and technology.
2. Demand Forecast: Develops a demand forecast absent the effects of future
conservation program by sector and by end use for the entire study period.
3. Program Assessment: Identifies energy-efficiency measures appropriate for
Avista’s service territory, including regional savings from energy efficiency
measures acquired through Northwest Energy Efficiency Alliance (NEEA) efforts.
4. Potential: Analyzes programs to identify the technical, economic and achievable
potential. Technical potential chooses the most efficient measure, regardless of
cost. Economic potential chooses the most efficient cost-effective measure.
Achievable potential adjusts economic potential to account for factors other than
pure economics, such as consumer behavior or market penetration rates.

Chapter 3–Energy Efficiency
Avista Corp 2013 Electric IRP
Figure 3.2: Analysis Approach Overview

Market Segmentation
The CPA segments Avista customers by state and rate schedule, translating to
residential, commercial and industrial general, commercial and industrial large general,
extra large commercial, and extra large industrial services. The residential class
segments include single family, multi-family, manufactured home and low-income
customers. The low-income threshold for this study is 200 percent of the federal poverty
level2.

Pumping represents only about 2 percent of total utility loads; the energy savings
projected for the pumping customer classification by the NPCC calculator is
approximately 4 percent of total savings potential. Within each segment, energy use is
characterized by end use, such as space heating, cooling, lighting, water heat or motors
and by technology including heat pump, resistance heating and furnace for space
heating.

The baseline projection is the “business as usual” metric without future utility
conservation programs. It indicates annual electricity consumption and peak demand by
customer segment and end use absent future efficiency programs. The baseline
projection includes projected impacts of known building codes and energy efficiency
standards as of 2012 when the study began. Codes and standards have direct bearing
on the amount of energy efficiency potential that exists beyond the impact of these
efforts. The baseline projection accounts for market changes including:

customer and market growth;
income growth;
retail rates forecasts;
2 Available from census data and the American Community Survey data.
Avista data
Avista data/ secondary data
Develop prototypes and
perform energy analysis
Forecast assumptions:
Customer growth
Price forecast
Purchase shares
Codes and standards
Energy efficiency measure list
measure costs and savings
analysis
Base-year energy consumption
by state, fuel, and sector
Energy market profiles by end
use, fuel, segment, and vintage
Baseline forecast by end use
Energy efficiency potential
Chapter 3–Energy Efficiency
Avista Corp 2013 Electric IRP
trends in end use and technology saturations;
equipment purchase decisions;
consumer price elasticity;
income; and
persons per household.

For each customer segment, a robust list of electrical energy efficiency measures and
equipment is compiled, drawing upon the NPCC’s Sixth Power Plan, the Regional
Technical Forum, and other measures applicable to Avista. This list of energy efficiency
equipment and measures includes 3,076 equipment and 1,774 measure options,
representing a wide variety of end use applications, as well as devices and actions able
to reduce customer energy consumption. A comprehensive list of equipment and
measure options is available in Appendix C. Measure cost, savings, estimated useful
life, and other performance factors identified for the list of measures and economic
screening performed on each measure for every year of the study to develop the
economic potential. Many measures initially do not pass the economic screen using
current avoided costs, but some measures may become part of the energy efficiency
program as contributing factors evolve during the 20-year planning horizon.

Avista supplements its energy efficiency activities by including potentials for distribution
efficiency measures for consistency with the EIA conservation targets and the NPCC
Sixth Power Plan. Details about the distribution efficiency projects are in the
Transmission and Distribution chapter of this IRP.

Overview of Energy Efficiency Potentials
EnerNOC utilized an approach adhering to the conventions outlined in the National
Action Plan for Energy Efficiency Guide for Conducting Potential Studies.3 The guide
represents the most credible and comprehensive national industry standard practice for
specifying energy efficiency potential. Specifically, three types of potentials are in this
study, as discussed below.

Technical Potential
Technical conservation potential uses the most efficient option commercially
available to each purchase decision, regardless of cost. This theoretical case
provides the broadest and highest definition of savings potentials because it
quantifies savings that would result if all current equipment, processes, and practices
in all market sectors were replaced by the most efficient and feasible technology.
Technical potential does not take into account the cost-effectiveness of the
measures. Technical potential is defined as “phase-in technical potential” assuming
only that the portion of the current equipment stock that has reached the end of its
useful life and is due for turnover is changed out by the most efficient measures
available. Non-equipment measures, such as controls and other devices (e.g.,
programmable thermostats) phase-in over time, just like the equipment measures.
3 National Action Plan for Energy Efficiency (2007). National Action Plan for Energy Efficiency Vision for
2025: Developing a Framework for Change. www.epa.gov/eeactionplan.

Chapter 3–Energy Efficiency
Avista Corp 2013 Electric IRP
Economic Potential
Economic potential conservation includes the purchase of the most efficient cost-
effective option available for each given equipment or non-equipment measure.4
Cost effectiveness is determined by applying the Total Resource Cost (TRC) test
using all quantifiable costs and benefits regardless of who accrues them and
inclusive of non-energy benefits as identified by the NPCC.5 Measures that pass the
economic screen represent aggregate economic potential. As with technical
potential, economic potential calculations use a phased-in approach. Economic
potential is a hypothetical upper-boundary of savings potential representing only
economic measures; it does not consider customer acceptance and other factors.

Achievable Potential
Achievable potential refines economic potential by taking into account expected
program participation, customer preferences, and budget constraints. This level of
potential estimates the achievable savings that could be attained through Avista’s
energy efficiency programs when considering market maturity and barriers, customer
willingness to adopt new technologies, incentive levels, as well as whether the program
is mature or represents the addition of a new program. During this stage, EnerNOC
applied market acceptance rates based upon NPCC-defined ramp rates from the Sixth
Power Plan taking into account market barriers and measure lives. However, EnerNOC
adjusted the ramp rates for the measures and equipment to reflect Avista’s market-
specific conditions and program history. In some cases, Avista’s ramp rates exceed the
Council’s, illustrating a mature energy efficiency program reaching a greater percentage
of the market than estimated by the NPCC’s Sixth Power Plan. In other cases, where a
program does not currently exist, a ramp rate could be less than the NPCC’s ramp rate,
acknowledging additional design and implementation time is necessary to launch a new
program. Other examples of changes to ramp rates include measures or equipment
where the regional market shows lower adoption rates than estimated by the NPCC,
such as heat pump water heaters.

The CPA forecasts incremental annual achievable potential for all sectors at 6.0 aMW
(52,657 MWh) in 2014, increasing to cumulative savings of 156.1 aMW (1,367,490
MWh) by 2033. Table 3.1 and Figure 3.3 show the CPA results for technical, economic,
and achievable potentials. The projected baseline electricity consumption forecast
increases 44 percent during the 20-year planning horizon. Figure 3.3 compares the
technical, economic, achievable potentials, and cumulative first-year savings, for
selected years.

4 The Industry definition of economic potential and the definition of economic potential referred to in this
document are consistent with the definition of “realizable potential for all realistically achievable units”. 5 There are other tests to represent economic potential from the perspective of stakeholders (e.g.,
Participant or Utility Cost), but the TRC is generally accepted as the most appropriate representation of
economic potential because it tends to represent the net benefits of energy efficiency to society. The
economic screen uses the TRC as a proxy for moving forward and representing achievable energy
efficiency savings potential for measures that are most cost-effective.
Chapter 3–Energy Efficiency
Avista Corp 2013 Electric IRP
Table 3.1: Cumulative Potential Savings (Across All Sectors for Selected Years6)

2014 2015 2018 2023 2028 2033
Cumulative Annual Savings (MWh)
Achievable
Potential
52,657 104,806 337,150 648,778 991,979 1,367,490
Economic
Potential
316,722 480,967 1,091,669 1,670,165 2,274,053 2,667,367
Technical
Potential
1,163,373 1,372,283 2,251,749 3,188,349 3,899,655 4,355,152
Cumulative Annual Savings (aMW)
Achievable
Potential
6.0 12.0 38.5 74.1 113.2 156.1
Economic
Potential
36.2 54.9 124.6 190.7 259.6 304.5
Technical
Potential
132.8 156.7 257.0 364.0 445.2 497.2

Figure 3.3: Cumulative Conservation Potentials, Selected Years

6 Projections include pumping as derived from the Sixth Power Plan’s calculator as well as Schedule 25P
being modeled separately based on that customer’s historical program participation. The decision to
model Schedule 25P separately was due to this rate schedule being one large industrial customer and
this method seemed more accurate than treating and modeling this customer as a generic industrial
customer.
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Conservation Targets
This IRP process provides a biennial conservation target for the EIA Biennial
Conservation Plan. Other components, such as conservation from distribution and
transmission efficiency improvements, combined with the energy efficiency target to
arrive at the full Biennial Conservation Plan target for Washington comparable to what is
included in the NPCC Sixth Power Plan target.

Based on first year incremental savings, Table 3.2 illustrates Avista’s achievable
potential for 2014-2015, as well as a comparison with the Sixth Power Plan’s calculator
option 1. The Sixth Power Plan includes components other than conservation such as
distribution system efficiencies. Table 3.2 compares the CPA results with the
calculator’s energy efficiency portion, excluding distribution efficiency.

Table 3.2: Annual Achievable Potential Energy Efficiency (aMW)

2014 2015
NPCC Sixth Power Plan Target
Idaho 5.92 6.13
Washington 9.47 9.81
Total 15.39 15.94

Less Distribution Efficiency from the Sixth Power Plan
Idaho (0.33) (0.45)
Washington (0.69) (0.96)
Total (1.02) (1.42)

Sixth Power Plan Conservation Target
Idaho 5.59 5.68
Washington 8.78 8.84
Total 14.37 14.52

Achievable Potential (i.e. Target), net of conversions
Idaho 1.75 1.57
Washington 3.80 3.87
Total 5.55 5.44

The 2014-15 Biennial Conservation Plan compliance period targets are below those
from the Sixth Power Plan for several reasons. First, the calculator provides an
approximation of the level of conservation utilities should pursue using regional
assumptions; these assumptions may differ from the specifics of a utility’s service
territory. Avista’s CPA study employs a methodology consistent with the NPCC while
incorporating Avista-specific assumptions to develop an estimate of savings potential for
acquisition through energy efficiency programs. Second, the Sixth Power Plan is
relatively dated and was developed prior to the Great Recession. It thus contains
assumptions of higher growth than observed in recent years. Lower growth reduces
potential savings. The Sixth Power Plan does not incorporate the effects of various
residential appliance equipment standards promulgated after the Sixth Power Plan.
Further, the higher than projected 2010-11 conservation acquisition results decreased
Chapter 3–Energy Efficiency
Avista Corp 2013 Electric IRP
baseline use, thereby diminishing future conservation potential since Avista had already
captured those savings. Finally, avoided costs are significantly lower than projected
when the Sixth Power Plan was developed.

Electricity to Natural Gas Fuel Switching
While fuel efficiency is not included in the NPCC Sixth Power Plan, Avista has a history
of fuel switching from electricity to natural gas, and continues to target natural gas direct
use as the most efficient resource option when available. Incremental to the targets
listed above are energy savings potential attributable to space and water heat electric to
natural gas conversions. Table 3.3 illustrates energy savings potentials from converting
electric furnaces and water heaters to natural gas. Nearly all savings are in the
residential sector. Conversions ramp up slowly, but because it removes most of the
electricity use from two of the largest residential end uses (water and space heating).
Space and water heating conversions account for approximately 19 percent of the
residential savings during the 20-year IRP period.

Table 3.3: Cumulative Achievable Savings from Conversion to Natural Gas (MWh)

Washington Conversion Potential 2014 2015 2018 2023 2033
Water heater - convert to gas potential 825 1,586 4,112 9,924 20,221
Furnace - convert to gas potential 2,322 5,047 12,715 25,105 55,787
Total Washington conversion potential 3,147 6.633 16,827 35,028 76,009
Idaho Conversion Potential 2014 2015 2018 2023 2033
Water heater - convert to gas potential 47 121 602 4,264 16,451
Furnace - convert to gas potential 837 1,792 4,460 8,698 19,598
Total Idaho conversion potential 884 1,913 5,062 12,961 36,049
Total Service Territory Savings 4,031 1,920 21,889 47,989 112,058

Comparison with the Sixth Power Plan Methodology
As required by Washington Administrative Code (WAC) Chapter 480-109-010 (3)(c),
this section describes the technologies, data collection, processes, procedures and
assumptions used to develop its biennial targets, along with changes in assumptions or
methodologies used in Avista’s IRP or the NPCC Sixth Power Plan. WAC Chapter 480-
109-010 (4)(c) requires the Washington Utilities and Transportation Commission’s
(UTC) approval, approval with modifications, or rejection of the targets.

EnerNOC worked with the NPCC staff to compare methodologies and approaches to
ensure methodological consistency. The CPA methodology is consistent with the Sixth
Power Plan in several key ways. Both the Sixth Power Plan and EnerNOC’s
approaches utilized end use models employing a bottom-up approach. The models
draw on appliance stock, saturation levels and efficiencies information to construct
future load requirements. EnerNOC conducted a thorough review of baseline and
measure assumptions used by the NPCC and developed a baseline energy- use
projection absent any additional energy efficiency measures while including the impact
of known codes and standards currently approved at the time of this study. The study
reviewed and incorporated NPCC assumptions when Avista-specific or more updated
data was not available.
Chapter 3–Energy Efficiency
Avista Corp 2013 Electric IRP
The CPA study developed a comprehensive list of energy-efficiency technologies and
end use measures, including those in the Sixth Power Plan. Since the efficiency
measures, equipment, and other data used in the Sixth Power Plan are somewhat
dated, information from the latest Regional Technical Forum workbooks were used, as
well as additional information on measures and equipment specific to Avista. EnerNOC
developed equipment saturations, measure costs, savings, estimated useful lives and
other parameters based on data from the Sixth Power Plan Conservation Supply Curve
workbook databases, the Regional Technical Forum, Avista’s Technical Reference
Manual, NEEA reports, and other data sources. Similar to the Sixth Power Plan, the
study accounts for the difference between lost and non-lost opportunities, and how this
affects the rate at which energy efficiency measures penetrate the market. The study
used the TRC test as the measure for judging cost-effectiveness. For a more detailed
discussion of measures and equipment evaluated within the potential study, please
refer to the CPA report prepared by EnerNOC in Appendix C.

After screening measures for cost-effectiveness, the CPA applied a series of factors to
evaluate realistic market acceptance rates and program implementation considerations.
The resulting achievable potential reflects the realistic deployment rates of energy
efficiency measures in Avista’s service territory. These factors account for market
barriers, customer acceptance, and the time required to implement programs. To
develop these factors, EnerNOC reviewed the ramp rates used in the Sixth Power Plan
Conservation Supply Curve workbooks and considered Avista’s experience.

The Sixth Power Plan assessed a 20-year period beginning in 2010, while this CPA
study begins in 2014. Where the Sixth Power Plan relied on average regional data, the
CPA utilized data from Avista’s service territory, as well as current economic data.
Therefore, an allocation of regional potential based on sales, as applied in the Sixth
Power Plan, would not necessarily account for Avista’s unique service territory
characteristics such as customer mix, use per customer, end use saturations, fuel
shares, current measure saturations, and expected customer and economic growth. In
addition, some industries included in the Sixth Power Plan may not exist in Avista’s
service territory. While the Sixth Power Plan incorporates distribution system
efficiencies, the Avista CPA includes only energy efficiency from energy conservation
while distribution system efficiencies and thermal system efficiencies are part of Avista’s
targets from other sources. A detailed discussion of Avista’s distribution feeder program
is in Chapter 5, Transmission & Distribution.

Avoided Cost Sensitivities
EnerNOC modeled several scenarios with varying avoided costs assumptions in
addition to the Expected Case used for the 2013 IRP to test sensitivity to changes in
avoided costs. The scenarios included 150 percent, 125 percent, 100 percent, and 75
percent of the avoided costs relative to the 110 percent level used in the Expected
Case. Figure 3.4 illustrates the avoided cost scenarios. Overall, energy efficiency
proved to be sensitive to avoided cost assumptions. In particular, acquiring incremental
energy efficiency becomes increasingly expensive, so increases in avoided costs do not
provide equivalent percentage increases in achievable potential. The Expected Case
achievable potential is approximately 154 aMW by 2033, excluding savings from
Chapter 3–Energy Efficiency
Avista Corp 2013 Electric IRP
distribution line losses. With the 150 percent avoided cost case, cumulative achievable
potential increases by 23 percent compared with the Expected Case reference
scenario, while the 125 percent, 100 percent, and the 75 percent avoided cost cases
yielded achievable potential equal to 85 percent, 94 percent and 113 percent of the
reference scenario, respectively. Table 3.4 shows achievable potential under the five
avoided cost scenarios and the cost impact over the IRP timeframe.

Table 3.4: Achievable Potential with Varying Avoided Costs

75% AC 100% AC Expected
Case 125% AC 150% AC
Cumulative energy savings
(aMW)
131 145 154 174 189
Savings percentage change
compared to Expected Case
-15% -6% 0% 13% 23%
20-Year Nominal Spending
(millions)
$459 $560 $711 $949 $1,150
Cost percentage change
compared to Expected Case
-35% -21% 0% 34% 62%

In 2014, 41 percent of the projected achievable potential is from residential class
measures. This roughly 40/60 allocation between residential and nonresidential savings
is consistent with a finding from the previous CPA that the nonresidential sector is
becoming the source of a larger share of savings potential. This shift is occurring
because many low-cost residential measures are implemented and residential
equipment codes and standards are capturing savings previously incented through
utility programs.

Approximately 48 percent of residential projected savings come from lighting in 2018,
followed by water and space heating. In subsequent years, the percentage of residential
savings from lighting decreases as lighting codes and standards are enacted. As a
result, space and water heating measures provide greater relative savings potential in
the later years of the study.

In the commercial and industrial sectors, lighting accounts for approximately 64 percent
of savings potential in 2018 followed by office equipment, heating, ventilation and air
conditioning (HVAC), refrigeration, and machine drives. Similar to the residential sector,
the savings potential from lighting decreases to about one-third of cumulative potential
in 2033, with HVAC, water heating and industrial measures gaining an increasing share
of long-term potential.

Heat pump water heater measures in the Sixth Power Plan were projected to replace
the CFLs contribution (i.e. significant savings at relatively low costs) in earlier plans. The
CPA found heat pump water heaters begin to pass the cost-effectiveness screen in
2014. However, because they are unsuitable for installation in conditioned spaces, the
CPA assumes they are not applicable in multifamily and mobile homes. The market for
this technology remains immature, limiting the number of near-term installations.
Chapter 3–Energy Efficiency
Avista Corp 2013 Electric IRP
Figure 3.4 shows supply curves composed of the stacked measures and equipment for
the IRP time horizon in ascending order of avoided cost. Since there is a gap in the cost
of the energy efficiency measures moving up the supply curve, the measures with a
very high cost cause a rapid sloping of the curve. The shift of the supply curve toward
the right as avoided costs increase is a consequence of increasing amounts of cost-
effective potential, but the average cost of acquiring that potential is increasing.

Figure 3.4: Conservation Supply Curve (2033- No Fuel Switching, Pumping and Losses)

Energy Efficiency-Related Financial Impacts
The EIA requires utilities with over 25,000 customers to obtain a fixed percentage of
their electricity from qualifying renewable resources and to acquire all cost-effective and
achievable energy conservation.7 For the first 24-month period under the law (2010-11),
this equaled a ramped-in share of the regional 10-year target identified in the Sixth
Power Plan. Penalties of at least $50 per MWh exist for utilities not achieving
Washington targets for conservation resource acquisition.

Regional discussions were under way regarding the definition of “pro-rata” during the
2009 IRP. Avista proposed ramping the 10-year targets identified in the Sixth Power
Plan instead of acquiring 20 percent of the first 10-year target identified in the Sixth
Power Plan. The “pro-rata” amount would have created drastic ramping challenges,
especially in the early years. Due to inconsistencies between the 2009 IRP and the
Council’s methodology, Avista elected to use Option 1 of the Sixth Power Plan to
establish its conservation acquisition target, adjusted to include electric-to-natural gas
space and water heating fuel conversions. The acquisition target was 11 percent
7 The EIA defines cost effective as 10 percent higher than the cost a utility would otherwise spend on
energy acquisition.
$0
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Avista Corp 2013 Electric IRP
greater than Avista’s IRP energy efficiency target for the same period. In April 2010, the
UTC approved Avista’s 10-year Achievable Potential and Biennial Conservation Target
Report in Docket UE-100176.

The EIA requirement to acquire all cost-effective and achievable conservation may pose
significant financial implications for Washington customers. Based on the CPA results,
the projected 2014 cost to electric customers is $12.6 million (1.7 percent of total
electric revenue requirement) with approximately $9 million of that projected to be for
Washington. This annual amount grows to $22.2 million by the tenth year, representing
a total of $215.8 million over this 10-year period for electric customers. Figure 3.5
shows the annual cost (in millions of nominal dollars) for the utility to acquire the
projected electric achievable potential.

Figure 3.5: Existing & Future Energy Efficiency Costs and Energy Savings

Integrating Results into Business Planning and Operations
The CPA and IRP energy efficiency evaluation processes provide high-level estimates
of cost-effective conservation acquisition opportunities. While results of the IRP
analyses establish baseline goals for continued development and enhancement of
energy efficiency programs, the results are not detailed enough to form an acquisition
plan. Avista uses both CPA and IRP evaluation results to establish a budget for energy
efficiency measures, to help determine the size and skill sets necessary for future
operations, and for identifying general target markets for energy efficiency programs.
This section provides an overview of recent operations of the individual sectors as well
as energy efficiency business planning.

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Chapter 3–Energy Efficiency
Avista Corp 2013 Electric IRP
Avista retained EnerNOC to develop an independent conservation potential assessment
study for its Washington and Idaho electric service territory. This study is useful for the
implementation of energy efficiency programs in the following ways.

Identify conservation resource potential by sector, segment, end use and
measure of where energy savings may come from. The energy efficiency
implementation staff can use CPA results to determine the segments and end
uses/measures to target.
Identify the measures with the highest TRC benefit-cost ratios, resulting in the
lowest cost resources with the greatest benefit.
Identify measures with great adoption barriers based on the economic versus
achievable results by measure. With this information, staff can develop effective
programs for measures with slow adoption or significant barriers.
Improve the design of current program offerings. Staff can review the measure
level results by sector and compare the savings with the largest-saving measures
currently offered. This analysis may lead to the addition or elimination of
programs. Consideration for lost opportunities, and whether to target one
particular measure over another measure, are made. One possibility may be to
offer higher incentives on measures with higher benefits and lower incentives on
measures with lower benefits.

The CPA study illustrates potential markets and provides a list of cost-effective
measures to analyze through the on-going energy efficiency business planning process.
This review of residential and non-residential program concepts and their sensitivity to
more detailed assumptions will feed into program plans for target markets. Potential
measures not currently considered at the time of the CPA may develop in the future will
be evaluated for possible inclusion in Avista’s Business Plan.

Residential Sector Overview
Avista offers most residential energy efficiency programs through prescriptive or
standard offer programs targeting a range of end uses. Programs offered through this
prescriptive approach during 2012 included space and water heating conversions,
ENERGY STAR® appliances, ENERGY STAR® homes, space and water equipment
upgrades and home weatherization. The ENERGY STAR® appliance program phases
out in 2013 due to results of a Cadmus net-to-gross study indicating market
transformation to a point that incentives are no longer required.

Avista offers its remaining residential energy efficiency programs through other
channels. For example, a third-party administer, JACO, operates the refrigerator/freezer
recycling program. UCONS administers a manufactured home duct-sealing program.
CFL and specialty CFL buy-downs at the manufacturer level provide customers access
to lower-priced lamps. Home energy audits, subsidized by a grant from the American
Recovery and Reinvestment Act (ARRA), ended in 2012. This program offered home
inspections including numerous diagnostic tests and provided a leave-behind kit
containing CFLs and weatherization materials. Avista provides educational tips and
CFLs at various rural and urban events in an effort to reach all areas within its service
Chapter 3–Energy Efficiency
Avista Corp 2013 Electric IRP
territory. Avista processed 14,300 energy efficiency rebates in 2012, benefiting
approximately 14,000 households. Over $2.3 million of rebates offset the cost of
implementing energy efficiency upgrades for our customers. Third-party contractors
implemented a second appliance-recycling program and a manufactured home duct-
sealing program. Avista participated in a regional upstream buy-down program called
Simple Steps Smart Savings where lighting and showerheads were provided through
participating retailers at a reduced amount for customers. Finally, Avista distributed over
26,000 CFLs at various community events throughout the service territory. Residential
programs contributed 17,744 MWh and 341,187 therms of energy savings.

Low Income Sector Overview
Six Community Action Agencies administer low-income programs. During 2012 these
programs targeted a range of end uses including space and water heating conversions,
ENERGY STAR® refrigerators, space and water heating equipment upgrades, and
weatherization offered site-specifically through individualized home audits. Avista also
funds health and human safety investments considered necessary to ensure habitability
of homes and protect investments in energy efficiency, as well as administrative fees
enabling Community Action Agencies to continue to deliver these programs.

The Community Action Agencies had 2012 budgets of $2.0 million for Washington and
$940,000 for Idaho as well as an additional $50,000 for conservation education in
Idaho. Avista processed approximately 1,400 rebates, benefitting 400 households.
During 2012, Avista paid $2.6 million in rebates to the Community Action Agencies to
provide fully-subsidized energy efficiency upgrades, health and human safety, and
administrative costs for the agencies to administer these programs. The agencies spent
nearly $394,000 on health and human safety or 13 percent of their total expenditures
and within their 15 percent allowance for this spending category. Low-income energy
efficiency programs contributed 1,111 MWh of electricity savings and 33,029 therms of
natural gas savings.

Non-Residential Sector Overview
For the non-residential sectors (commercial, industrial and multi-family applications),
energy efficiency programs are offered on a site-specific or custom basis. Avista offers
a more prescriptive approach when treatments result in similar savings and the
technical potential is high. An example is the prescriptive lighting program. The
applications are not purely prescriptive in the traditional sense, such as with residential
applications where homogenous programs are provided for all residential customers;
however, a more prescriptive approach can be applied for these similar applications.

Non-residential prescriptive programs offered by Avista include, but are not limited to,
space and water heating conversions, space and water heating equipment upgrades,
appliance upgrades, cooking equipment upgrades, personal computer network controls,
commercial clothes washers, lighting, motors, refrigerated warehouses, traffic signals,
and vending controls. Also included are residential program offerings such as multi-
family and multi-family market transformation since these projects are implemented site-
specifically unlike other residential programs.

Chapter 3–Energy Efficiency
Avista Corp 2013 Electric IRP
During 2012, Avista processed 4,167 energy efficiency projects resulting in the payment
of over $13.5 million in rebates paid directly to customers to offset the cost of their
energy efficiency projects. These projects contributed 58,756 MWh of electricity and
399,733 therms of natural gas savings.

Energy Smart Grocer is a regional, turnkey program administrated through PECI. This
program has been operating for several years. This program will approach saturation
levels during the early part of this 20-year planning horizon.

The programs highlighted by the recently completed CPA study will be reviewed for the
development of target marketing and the creation of new energy efficiency programs. All
electric-efficiency measures with a simple payback exceeding one year and less than
eight years for lighting measures or thirteen years for other measures automatically
qualify for the non-residential portfolio. The IRP provides account executives, program
managers/coordinators and energy efficiency 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 for
non-residential customers.

Demand Response
Over the past decade, demand response has gained attention in the industry as an
alternative method to meet peak load growth instead of constructing new generation.
Demand response cuts load to specific customers during peak demand use. Typically,
customers enroll in programs allowing the utility to change its usage in exchange for
discounts. National attention focuses on residential programs to control water heaters,
space heating and air conditioners.

Past and Current Programs
Avista’s experience with demand response or load management dates back to the 2001
Energy Crisis. Avista responded with an All-Customer Buy-Back program, an Irrigation
Buy-Back program and bi-lateral agreements with large industrial customers. These
methods along with commercial and residential enhanced energy efficiency programs
were effective and enabled Avista to reduce its need for purchases in a very high cost
Western energy market. Experience was gained in July 2006 when a multi-day heat
wave required Avista to invoke immediate demand response through a media request
for customers to conserve and a large customer reduction, Avista was able to reduce
same day load by an estimated 50 MW.

Avista conducted a two-year residential load control pilot between 2007 and 2009 to
study specific technologies, examine cost-effectiveness and customer acceptance. The
intent of this pilot was to be scalable with Direct Load Control (DLC) devices installed in
approximately 100 volunteer households in Sandpoint and Moscow, Idaho. This small
sample allowed Avista to test the product and systems with the same benefits as if this
were a larger scale project, but in a controlled and customer-friendly manner. DLC
devices were installed on heat pumps, water heaters, electric forced-air furnaces and air
conditioners to control operation during 10 scheduled events at peak times ranging from
two hours to four hours. A separate group within those communities participated in an
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Avista Corp 2013 Electric IRP
In-Home-Display device study as part of this pilot. The program intended to gain
customer experience with “near-real time” energy usage feedback equipment.
Information gained from the pilot is detailed in the report filed with the Idaho Public
Utilities Commission (IPUC).

Avista is engaged in a new demand response program as part of the Northwest
Regional Smart Grid Demonstration Project (SGDP) with Washington State University
(WSU) and approximately 70 residential customers in the Pullman and Albion,
Washington communities. Residential customer assets include a forced-air electric
furnace, heat pump, and central air-conditioning with enabling control technology of a
Smart Communicating Thermostat provided and installed by Avista. The control
approach is non-traditional in several ways. First, the demand response “events” are not
prescheduled, but assets are directly controlled by predefined customer preferences (no
more than a 2 degree offset for the residential customers, and an energy management
system at WSU with a consol operator) at anytime the regional Transactive signal
needs the curtailment. More importantly, the technology used in this demand response
portion of the SGDP predicts if equipment is available for participation in the control
event. Lastly, value quantification extends beyond demand and energy savings and
explores bill management options for customers with whole house usage data analyzed
in conjunction with smart thermostat data. Inefficient homes identified through this
analysis prompt customer engagement.

Experiences from the both residential DLC pilots (North Idaho Pilot and the SGDP)
show participating customer engagement is high; however, recruiting participants is
challenging. Avista’s service territory has a high penetration of natural gas for both
typical DLC appliance types of space heat and water heat. Customers who have
interest may not have qualifying equipment making them ineligible for participation in
the Program. Secondly, customers initially are not interested enough in DLC programs.
Supporting evidence of this second aspect is in recent regional DLC programs
conducted by the BPA. Lastly, Avista is unable at this time to offer pricing strategies
other then direct incentives to compensate customers for participation in the program,
which limits customer interest.

The amount of demand and energy reductions per household is lower than a
commercial and/or industrial DLC program. Consequently, many households are
required to yield significant peak reduction savings, which is why residential DLC
programs are commonly mass-market programs. Mass-market scale is needed for
program cost effectiveness. Rather than focusing on residential demand response,
Avista will focus its Demand Response studies towards commercial and industrial
customers. Fewer but larger loads are anticipated to yield adequate acquisition. For this
IRP, Avista assumes a potential of five MW per year for a 20 MW total acquisition,
assuming a cost of $120 per kW-year (2012 dollars). As an Action Item, Avista will need
to complete an assessment of potential demand response in its commercial and
industrial customers, including, a measure of peak reduction, flexibility capability (i.e.
spinning reserves) and costs to implement programs.

Chapter 4–Policy Considerations
Avista Corp 2013 Electric IRP
4. Policy Considerations

Public policy can significantly affect Avista’s current generation resources and the types
of resources Avista pursues. The political and regulatory environments have changed
significantly since publication of the last IRP. Prospects for implementing a federal cap
and trade program to reduce greenhouse gases have greatly diminished. At the same
time, a range of regulatory measures pursued by the Environmental Protection Agency
(EPA), coupled with political and legal efforts initiated by environmental groups and
others, has increased pressures on thermal generation – specifically coal-fired
generation. New regulations have particular implications for coal generation, as they
involve regional haze, coal ash disposal, mercury emissions, water quality, and
greenhouse gas emissions. This chapter provides an overview and discussion about
some of the more pertinent public policy issues relevant to the IRP.

Environmental Issues
Environmental concerns present unique resource planning challenges due to the
continuously evolving nature of environmental regulation. If avoiding certain air
emissions were the only issue faced by electric utilities, resource planning would only
require a determination of the amounts and types of renewable generating technology
and energy efficiency to acquire. However, the need to maintain system reliability,
acquire resources at least cost, mitigate price volatility, meet renewable generation
requirements, manage financial risks, and meet environmental laws complicates utility
planning. Each generating resource has distinctive operating characteristics, cost
structures, and environmental regulatory challenges.

Traditional thermal generation technologies, like coal-fired and natural gas-fired plants,
are reliable and provide capacity along with energy. Coal-fired units have high capital
costs, long permitting and construction lead times, and relatively low and stable fuel
costs. New coal plants are currently difficult, if not impossible, to site due to state and
federal laws and regulations, local opposition, and environmental concerns ranging from
the impacts of coal mining to power plant emissions. Remote mine locations increase
costs from either the transportation of coal to the plant or the transportation of the
generated electricity to load centers. By comparison, natural gas-fired plants have
relatively low capital costs compared to coal, can typically be located near load centers,
can be constructed in relatively short time frames, emit less than half the greenhouse
gases emitted by coal, and are the only utility-scale baseload resource that can be
developed in many locations. Higher fuel price volatility has historically affected the
Chapter Highlights
Avista’s Climate Policy Council monitors greenhouse gas legislation and
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Avista Corp 2013 Electric IRP
economics of natural gas-fired plants. Their performance also decreases in hot weather
conditions, it is increasingly difficult to secure sufficient water rights for their efficient
operation, and they emit significant greenhouse gases relative to renewable resources.

Renewable energy technologies such as wind, biomass, and solar generation have
different challenges. Renewable resources are attractive because they have low or no
fuel costs and few, if any, direct emissions. However, solar- and wind-based renewable
generation has limited or no capacity value for the operation of Avista’s system, and
their variable output presents integration challenges requiring additional non-variable
capacity investments.

Renewable projects also draw the attention of environmental groups interested in
protecting visual aspects of landscapes and wildlife populations. Similar to coal plants,
renewable resource projects are located near their fuel sources rather than load
centers. The need to site renewable resources in remote locations often requires
significant investments in transmission interconnection and capacity expansion, as well
as mitigating possible wildlife and aesthetic issues. Unlike coal or natural gas-fired
plants, the fuel for non-biomass renewable resources may not be transportable from
one location to another to utilize existing transmission facilities or to minimize opposition
to project development. Dependence on the health of the forest products industry and
access to biomass materials, often located in publicly owned forests, poses challenges
to biomass facilities.

The long-term economic viability of renewable resources is uncertain for at least two
important reasons. First, federal investment and production tax credits will begin
expiring for projects beginning construction after 2013. The continuation of credits and
grants 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 and solar technology
development. Second, many relatively unpredictable factors affect the costs of
renewable technologies, such as renewable portfolio standard mandates, material
prices and currency exchange rates. Capital costs for wind and solar have decreased
since the 2011 IRP, but future costs remain uncertain.

Even though there appears to be very little, if any, chance of a national greenhouse gas
cap and trade program, uncertainty still exists about greenhouse gas regulation at this
IRP’s writing. There are pockets of strong regional and national support to address
climate change, but little political will at the national level to implement significant new
laws to reduce greenhouse gas emissions. However, since the 2011 IRP publication,
changes in the approach to greenhouse gas emissions regulation have occurred,
including:

The EPA has commenced actions to regulate greenhouse gas emissions under
the Federal Clean Air Act, although some of these efforts have been delayed and
most of these initiatives are being legally challenged; and
California has established economy-wide cap and trade regulation.

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Avista Corp 2013 Electric IRP
Avista’s Climate Change Policy Efforts
Avista’s Climate Policy Council is an interdisciplinary team of management and non-
management employees that:
Facilitates internal and external communications regarding climate change
issues;
Analyzes policy impacts, anticipates opportunities and evaluates strategies for
Avista Corporation; and
Develops recommendations on climate related policy positions and action plans.

The core team of the Climate Policy Council includes members from Environmental
Affairs, Government Relations, External Communications, Engineering, Energy
Solutions and Resource Planning groups. Other areas of Avista participate as needed
to provide input on certain topics. The monthly meetings for this group include work
divided into immediate and long-term concerns. The immediate concerns include
reviewing and analyzing proposed or pending state and federal legislation, reviewing
corporate climate change policy, and responding to internal and external data requests
about climate change issues. Longer-term issues involve emissions tracking and
certification, considering the merits of different greenhouse gas policies, actively
participating in the development of legislation, and benchmarking climate change
policies and activities against other organizations.

Membership in the Edison Electric Institute is Avista’s vehicle to engage in federal-level
climate change dialog. Avista participates in discussions about hydroelectric and
biomass issues through membership in national hydroelectric and biomass
associations.

Greenhouse Gas Emissions Concerns for Resource Planning
Resource planning in the context of greenhouse gas emissions regulation raises
concerns about the balance between Avista’s obligations for environmental
stewardship, and cost implications for its customers. Resource planning must consider
the cost effectiveness of resource decisions, as well as the need to mitigate the financial
impact of potential future emissions risks. Although some parties would advocate for the
immediate reduction or elimination of certain resource technologies, such as coal or
even natural gas-fired plants, there are economic and reliability limitations and other
concerns related to pursuing this type of policy. Technologically, it is possible to replace
fossil-fueled generation with renewables, but the increased prices to customers and the
challenges of obtaining enough renewable generation while maintaining system
reliability are daunting.
Complying with greenhouse gas regulations, particularly in the form of a cap and trade
mechanism, involves at least two approaches: ensuring Avista maintains sufficient
allowances and/or offsets to correspond with its emissions during a compliance period,
and undertaking measures to reduce Avista’s future emissions. Enabling emission
reductions on a utility-wide basis could entail any or all of the following:

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Avista Corp 2013 Electric IRP
Increasing the efficiency of existing fossil-fueled generation resources;
Reducing emissions from existing fossil-fueled generation through fuel
displacement including co-firing with biomass or biofuels;
Permanently decreasing the output from existing fossil-fueled resources and
substituting resources with lower greenhouse gas emissions;
Decommissioning or divesting of a fossil-fueled generation and substituting with
lower-emitting resources;
Reducing exposure to market purchases of fossil-fueled generation, particularly
during periods of diminished hydropower production, by establishing larger
reserves based on lower-emitting technologies; and
Increasing investments in energy efficiency measures, thereby displacing future
resource needs.

With the exception of Avista’s commitment to energy efficiency, the specific costs and
risks of the actions listed above cannot be adequately evaluated until greenhouse gas
emission regulations are established. After a regulatory regime has been implemented
the economic effects can be modeled. A specific reduction strategy in a future IRP may
occur when greater regulatory clarity and better modeling parameters exist. In the
meantime, greenhouse gas emissions reductions in this IRP rely upon EPA and state
regulations, established renewable portfolio policies, and established state level
greenhouse gas emissions laws.

State and Federal Environmental Policy Considerations
The direction of federal greenhouse gas emissions policies has changed significantly
since the 2011 IRP. In the prior plan, Avista based greenhouse gas emissions costs on
a weighted average of four different reduction policies that included various levels of
state and federal cap and trade programs and carbon taxes. The state of political
discourse during the development of this IRP indicates there is no imminent federal cap
and trade or carbon tax. Even though there is no national greenhouse gas emissions
cost in the Expected Case, this IRP includes a greenhouse gas reduction scenario, with
high and low prices for offset/taxes as a proxy to model the possible impacts of future
regulation. Chapter 7, Market Analysis, describes the greenhouse gas scenarios and
the modeling results.

The President’s Climate Action Plan was released on June 25, 2013, after the modeling
for this IRP was completed. The plan outlines the Obama administration’s three pillars
of executive action regarding climate change, which include the following:

Reduce U.S. carbon emissions;
Make infrastructure preparations to mitigate the impacts of climate change; and
Work on efforts to reduce international greenhouse gas emissions and prepare
for the impacts of climate change.

A presidential memo was also sent to the Administrator of the EPA on the same day as
the Climate Action Plan with several climate change related policy targets. The memo
directed the EPA to do the following:
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Avista Corp 2013 Electric IRP
Issue new proposed greenhouse gas emissions standards for new electric
generation resources by September 30, 2013.
Issue new proposed standards for existing and modified sources by June 1,
2014, final standards by June 1, 2015, and require State implementation plans by
June 30, 2016.

The federal Production Tax Credit (PTC), Investment Tax Credit (ITC), and Treasury
grant programs are key federal policy considerations for incenting the development of
renewable generation. The current PTC and ITC programs are available for projects
that begin construction before the end of 2013. The date is 2016 for solar projects. We
did not model an extension of these tax incentives because of the uncertainty of their
continuation due to the current federal budget deficit situation. Extension of the PTC
may accelerate the development of some regional renewable energy projects. This may
affect the development of renewable projects in the Western Interconnect, but not
necessarily for Avista, because the current resource mix and low projected load growth
do not necessitate the development of new renewables in this IRP.

EPA Regulations
The EPA regulations that directly, or indirectly, affect electricity generation include the
Clean Air Act, along with its various components, such as the Acid Rain Program,
National Ambient Air Quality Standard, Hazardous Air Pollutant rules and the Regional
Haze Programs. The U.S. Supreme Court ruled the EPA has authority under the Clean
Air Act to regulate greenhouse gas emissions from new motor vehicles and has issued
such regulations. When these regulations became effective, carbon dioxide and other
greenhouse gases became regulated pollutants under the Prevention of Significant
Deterioration (PSD) preconstruction permit program and the Title V operating permit
program. Both of these programs apply to power plants and other commercial and
industrial facilities. In 2010, the EPA issued a final rule, known as the Tailoring Rule,
governing the application of these programs to stationary sources, such as power
plants. Most recently, EPA proposed a rule in early 2012 setting standards of
performance for greenhouse gas emissions from new and modified fossil-fuel-fired
electric generating units and announced plans to issue greenhouse gas guidelines for
existing sources.

Promulgated PSD permit rules may affect Avista’s thermal generation facilities in the
future. These rules can affect the amount of time it takes to obtain permits for new
generation and major modifications to existing generating units and the final limitations
contained in permits. The promulgated and proposed greenhouse gas rulemakings
mentioned above have been legally challenged in multiple venues so we cannot fully
anticipate the outcome or extent our facilities may be impacted, nor the timing of rule
finalization.

Clean Air Act
The Clean Air Act (CAA), originally adopted in 1970 and modified significantly since,
intends to control covered air pollutants to protect and improve air quality. Avista
complies with the requirements under the CAA in operating our thermal generating
plants. The CAA currently requires a Title V operating permit for Colstrip Units 3 and 4
Chapter 4–Policy Considerations
Avista Corp 2013 Electric IRP
(expires in 2017), Coyote Springs 2 (renewal expected in 2013), the Kettle Falls GS
(renewal expected in 2013), and the Rathdrum CT (expires in 2016). Boulder Park,
Northeast CT, and other small activities only require minor source operating or
registration permits based on their limited operation and emissions. Title V operating
permits renewals occur every five years and typically update all applicable CAA
requirements for each facility. Discussion of some major CAA programs follows.

Acid Rain Program
The Acid Rain Program is an emission-trading program for reducing nitrous dioxide by
two million tons and sulfur dioxide by 10 million tons below 1980 levels from electric
generation facilities. Avista manages annual emissions under this program for Colstrip
Units 3 and 4, Coyote Springs 2, and Rathdrum Generating Stations.

National Ambient Air Quality Standards
EPA sets National Ambient Air Quality Standards for pollutants considered harmful to
public health and the environment. The CAA requires regular court-mandated updates
to occur in June 2013 for nitrogen dioxide, ozone, and particulate matter. Avista does
not anticipate any material impacts on its generation facilities from the revised
standards at this time.

Hazardous Air Pollutants (HAPs)
HAPs, often known as toxic air pollutants or air toxics, are those pollutants that may
cause cancer or other serious health effects. EPA regulates toxic air pollutants from a
published list of industrial sources referred to as "source categories". These pollutants
must meet control technology requirements if they emit one or more of the pollutants in
significant quantities. EPA recently finalized the Mercury Air Toxic Standards (MATS)
for the coal and oil-fired source category. Colstrip Units 3 and 4’s existing emission
control systems should be sufficient to meet mercury limits. For the remaining portion of
the rule that specifically addresses air toxics (including metals and acid gases), the joint
owners of Colstrip are currently evaluating what type of new emission control systems
will be required to meet MATS compliance in 2015. Avista is unable to determine to
what extent, or if there will be any, material impact to Colstrip Units 3 and 4 at this time.

Regional Haze Program
EPA set a national goal to eliminate man-made visibility degradation in Class I areas by
the year 2064. Individual states are to take actions to make “reasonable progress”
through 10-year plans, including application of Best Available Retrofit Technology
(BART) requirements. BART is a retrofit program applied to large emission sources,
including electric generating units built between 1962 and 1977. In the absence of state
programs, EPA may adopt Federal Implementation Plans (FIPs). On September 18,
2012, EPA finalized the Regional Haze FIP for Montana. The FIP includes both
emission limitations and pollution controls for Colstrip Units 1 and 2. Colstrip Units 3 and
4 are not currently affected, although the units will be evaluated for Reasonable
Progress at the next review period in September 2017. Avista does not anticipate any
material impacts on Colstrip Units 3 and 4 at this time.

Chapter 4–Policy Considerations
Avista Corp 2013 Electric IRP
EPA Mandatory Reporting Rule
Any facility emitting over 25,000 metric tons of greenhouse gases per year must report
its emissions to EPA. Colstrip Units 3 and 4, Coyote Springs 2, and Rathdrum CT are
currently reporting under this requirement. The Mandatory Reporting Rule also requires
greenhouse gas reporting for natural gas distribution system throughput, fugitive
emissions from electric power transmission and distribution systems, fugitive emissions
from natural gas distribution systems, and from natural gas storage facilities. Avista
reported the applicable greenhouse gas emissions in 2012. The State of Washington
requires mandatory greenhouse gas emissions reporting similar to the EPA
requirements. Oregon has similar reporting requirements.

State and Regional Level Policy Considerations
The lack of a comprehensive federal greenhouse gas policy encouraged several states,
such as California, to develop their own climate change laws and regulations. Climate
change legislation can take many forms, including economy-wide regulation in the form
of a cap and trade system, tax or emissions performance standards for power plants.
Comprehensive climate change policy can have multiple individual components, such
as renewable portfolio standards, energy efficiency standards, and emission
performance standards. Washington enacted all of these components, but other
jurisdictions where Avista operates have not. Individual state actions produce a
patchwork of competing rules and regulations for utilities to follow, and may be
particularly problematic for multi-jurisdictional utilities such as Avista. There are 29
states, plus the District of Columbia, with active renewable portfolio standards, and eight
additional states have adopted voluntary standards.1

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 agreement included the following signatory jurisdictions: Arizona, British
Columbia, California, Manitoba, Montana, New Mexico, Oregon, Utah, Quebec and
Washington. In July 2010, the WCI released its Final Design for a regional cap and
trade regulatory system to cover 90 percent of the societal greenhouse gas emissions
within the region by 2015. Arizona, Montana, New Mexico, Oregon, Utah and
Washington formally left WCI in November 2011.2 The only remaining WCI members
are British Columbia, California, Manitoba, Ontario, and Quebec.

Idaho Policy Considerations
Idaho currently does not regulate greenhouse gases or have a renewable portfolio
standard (RPS). There is no indication that Idaho is moving toward the active regulation
of greenhouse gas emissions. However, the Idaho Department of Environmental Quality
would administer greenhouse gas standards under its CAA delegation from the EPA.

Montana Policy Considerations
Montana has a non-statutory goal to reduce greenhouse gas emissions to 1990 levels
by 2020. Montana’s RPS law, enacted through Senate Bill 415 in 2005, requires utilities
1 http://www.dsireusa.org/rpsdata/index.cfm 2 http://www.platts.com/RSSFeedDetailedNews/RSSFeed/ElectricPower/6695863
Chapter 4–Policy Considerations
Avista Corp 2013 Electric IRP
to meet 10 percent of their load with qualified renewables from 2010 through 2014, and
15 percent beginning in 2015. Avista is exempt from the Montana RPS and its reporting
requirements beginning on January 2, 2013, with the passage of SB 164 and its
signature by the Governor.

Montana implemented a mercury emission standard under Rule 17.8.771 in 2009. The
standard exceeds the most recently adopted federal mercury limit. Avista’s generation
at Colstrip Units 3 and 4 have emissions controls meeting Montana’s mercury emissions
goal.

Oregon Policy Considerations
The State of Oregon has a history of considering greenhouse gas emissions and
renewable portfolio standards legislation. The Legislature enacted House Bill 3543 in
2007, calling for, but not requiring, reductions of greenhouse gas emissions to 10
percent below 1990 levels by 2020, and 75 percent below 1990 levels by 2050.
Compliance is expected through a combination of the RPS and other complementary
policies, like low carbon fuel standards and energy efficiency measures. The state has
not adopted any comprehensive requirements. These reduction goals are in addition to
a 1997 regulation requiring fossil-fueled generation developers to offset carbon dioxide
(CO2) emissions exceeding 83 percent of the emissions of a state-of-the-art gas-fired
combined cycle combustion turbine by paying into the Climate Trust of Oregon. Senate
Bill 838 created a renewable portfolio standard requiring large electric utilities to
generate 25 percent of annual electricity sales with renewable resources by 2025.
Intermediate term goals include five percent by 2011, 15 percent by 2015, and 20
percent by 2020. Oregon ceased being an active member in the Western Climate
Initiative in November 2011. The Boardman coal plant is the only active coal-fired
generation facility in Oregon; by 2020, it will cease burning coal. The decision by
Portland General Electric to make near-term investments to control emissions from the
facility and to discontinue the use of coal, serves as an example of how regulatory,
environmental, political and economic pressures can culminate in an agreement that
results in the early closure of a coal-fired power plant.

Washington State Policy Considerations
Similar circumstances leading to the closure of the Boardman facility in Oregon
encouraged TransAlta, the owner of the Centralia Coal Plant, to agree to shut down one
unit at the facility by December 31, 2020, and the other unit by December 31, 2025. The
confluence of regulatory, environmental, political and economic pressures brought
about the scheduled closure of the Centralia Plant. The State of Washington enacted
several measures concerning fossil-fueled generation emissions and generation
resource diversification. A 2004 law requires new fossil-fueled thermal electric
generating facilities of more than 25 MW of generation capacity to mitigate CO2
emissions through third-party mitigation, purchased carbon credits, or cogeneration.
Washington’s EIA, passed in the November 2006 general election, established a
requirement for utilities with more than 25,000 retail customers to use qualified
renewable energy or renewable energy credits to serve 3 percent of retail load by 2012,
9 percent by 2016 and 15 percent by 2020. Failure to meet these RPS requirements
results in at least a $50 per MWh fine. The initiative also requires utilities to acquire all
cost effective conservation and energy efficiency measures up to 110 percent of
Chapter 4–Policy Considerations
Avista Corp 2013 Electric IRP
avoided cost. Additional details about the energy efficiency portion of the EIA are in
Chapter 3.
A utility can also comply with the renewable energy standard by investing in at least 4
percent of its total annual retail revenue requirement on the incremental costs of
renewable energy resources and/or renewable energy credits. In 2012, Senate Bill 5575
amended the EIA to define Kettle Falls Generating Station and other legacy biomass
facilities that commenced operation before March 31, 1999, as EIA qualified resources
beginning in 2016. A 2013 amendment allows multistate utilities to import RECs from
outside the Pacific Northwest to meet renewable goals and allows utilities to acquire
output from the Centralia coal plant without jeopardizing alternative compliance
methods.

Avista will meet or exceed its renewable requirements in this IRP planning period
through a combination of qualified hydroelectric upgrades, wind generation from the
Palouse Wind PPA, and output from Kettle Falls beginning in 2016. The 2013 IRP
Expected Case ensures that Avista meets all EIA RPS goals.

Former Governor Christine Gregoire signed Executive Order 07-02 in February 2007
establishing the following GHG emissions goals:

1990 levels by 2020;
25 percent below 1990 levels by 2035;
50 percent below 1990 levels by 2050 or 70 percent below Washington’s
expected emissions in 2050;
Increase clean energy jobs to 25,000 by 2020; and
Reduce statewide fuel imports by 20 percent.

Washington state's Department of Ecology has adopted regulations to ensure that its
State Implementation Plan comports with the requirements of the EPA's regulation of
greenhouse gas emissions. We will continue to monitor actions by the Department as it
may proceed to adopt additional regulations under its CAA authorities. In 2007, Senate
Bill 6001 prohibited electric utilities from entering into long-term financial commitments
beyond five years duration for fossil-fueled generation creating 1,100 pounds per MWh
or more of greenhouse gases. Beginning in 2013, the emissions performance standard
is 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 and 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 long-term financial
commitments for electricity deliveries that include more than 12 percent of the total
power from unspecified sources. The Department of Commerce (Commerce) has
commenced a process expected to result in the adoption of a lower emissions
performance standard in 2013; a new standard would not be applicable until at least
Chapter 4–Policy Considerations
Avista Corp 2013 Electric IRP
2017. Commerce filed a final rule with 970 pounds per MWh for greenhouse gas
emissions on March 6, 2013, with rules becoming effective on April 6, 2013.3

Washington Governor Inslee signed the Climate Action bill (Senate Bill 5802) on April 2,
2013. This law established an independent evaluation of the costs and benefits of
established greenhouse gas emissions reductions programs. Results of this study are
due by October 15, 2013 and will help inform development of a climate strategy to meet
Washington’s greenhouse gas reduction goals.

3 http://www.commerce.wa.gov/Programs/Energy/Office/Utilities/Pages/EmissionPerfStandards.aspx
Chapter 5 – Transmission & Distribution

Avista Corp 2013 Electric IRP 5-1

5. Transmission & Distribution

Introduction
Avista delivers electricity from generators to customer meters through a network of
conductors, or links and stations, or nodes. The network system is operated at higher
voltages where the energy must travel longer distances to reduce current losses across
the system. A common rule to determine efficient energy delivery is one kV per mile.
For example, a 115 kV power system commonly transfers energy over a distance of 115
miles, while 13 kV power systems are generally limited to delivering energy within 13
miles.

Avista categorizes its energy delivery systems between transmission and distribution
voltages. Avista’s transmission system operates at 230 kV and 115 kV nominal
voltages; the distribution system operates between 4.16 kV and 34.5 kV, but typically at
13.2 kV in its urban service centers. In addition to voltages, the transmission system
operates distinctly from the distribution system. For example, the transmission system is
a network linking multiple sources with multiple loads, while the distribution system
configuration uses radial feeders to link a single source to multiple loads.

Coordinating transmission system operations and planning activities with regional
transmission providers maintains a reliable and economic transmission service for our
customers. Transmission providers and interested stakeholders coordinate the region’s
approach to planning, constructing, and operating the transmission system under
Federal Energy Regulatory Commission (FERC) rules and state and local agency
guidance. This chapter complies with Avista’s FERC Standards of Conduct compliance
program governing communications between Avista merchant and transmission
functions.

This chapter describes Avista’s completed and planned distribution upgrade feeder
program, the transmission system, completed and planned upgrades, and estimated
costs and issues of new generation resource integration.

Chapter Highlights
Avista continues to participate in regional transmission planning forums.
The Spokane Valley Reinforcement Project includes both station update and
conductor upgrades.
A large upgrade project is under construction at the Moscow substation to
maintain adequate load service and a Noxon substation rebuild project is in
the design phase.
Five distribution feeder rebuilds are complete since the last IRP, six additional
feeders rebuilds are planned for 2014.
Significant generation interconnection study work around Thornton and Lind
substations continues.
Chapter 5 – Transmission & Distribution

Avista Corp 2013 Electric IRP 5-2

FERC Planning Requirements and Processes
FERC provides guidance to both regional and local area transmission planning. This
section describes several of its requirements and processes important to Avista
transmission planning.

FERC Tariff Attachment K
Avista’s Open Access Transmission Tariff (OATT) includes Attachment K, satisfying
nine transmission planning principles outlined in FERC Order 890. Avista’s Attachment
K process ensures open and transparent coordination of local, regional, and sub-
regional transmission planning. Avista develops a biannual Local Planning Report (in
coordination with Avista's five- and ten-year Transmission Plans). Avista encourages
participation by interconnected utilities, transmission customers, and other stakeholders
in the Local Planning Process. Avista satisfies its sub-regional and regional FERC
transmission planning requirements through its membership in ColumbiaGrid. Avista
also participates in the Northern Tier Transmission Group and several Western
Electricity Coordinating Council (WECC) processes and groups. Participation in these
efforts supports regional coordination of Avista's transmission projects.

Western Electricity Coordinating Council
WECC coordinates and promotes electric system reliability in the Western
Interconnection. It supports training in power system operations and scheduling
functions, and coordinated transmission planning activities throughout the Western
Interconnection. Avista participates in WECC’s Planning Coordination, Operations,
Transmission Expansion Planning Policy and Market Interface Committees, as well as
sub groups and other processes such as the Transmission Coordination Work Group.

Northwest Power Pool
Avista is a member of the Northwest Power Pool (NWPP). Formed in 1942 when the
federal government directed utilities to coordinate operations in support of wartime
production, NWPP committees include the Operating Committee, the Reserve Sharing
Group Committee, the Pacific Northwest Coordination Agreement (PNCA) Coordinating
Group, and the Transmission Planning Committee (TPC). The TPC exists as a forum
addressing northwest electric planning issues and concerns, including a structured
interface with external stakeholders.

The NWPP serves as an electricity reliability forum, helping to coordinate present and
future industry restructuring, promoting member cooperation to achieve reliable system
operation, coordinating power system planning, and assisting the transmission planning
process. NWPP membership is voluntary and includes the major generating utilities
serving the Northwestern U.S., British Columbia and Alberta. Smaller, principally non-
generating utilities participate in an indirect manner through their member systems,
such as the BPA.

Chapter 5 – Transmission & Distribution

Avista Corp 2013 Electric IRP 5-3

ColumbiaGrid
ColumbiaGrid formed on March 31, 2006, and its membership includes Avista, BPA,
Chelan County PUD, Grant County PUD, Puget Sound Energy, Seattle City Light,
Snohomish County PUD, and Tacoma Power. ColumbiaGrid was formed to enhance
and improve the operational efficiency, reliability, and planned expansion of the Pacific
Northwest transmission grid. Consistent with FERC requirements issued in Orders 890
and 1000, ColumbiaGrid develops sub-regional transmission plans, assesses
transmission alternatives (including non-wires alternatives), and provides a decision-
making forum and cost-allocation methodology for new transmission projects.

Northern Tier Transmission Group
The Northern Tier Transmission Group (NTTG) formed on August 10, 2007. NTTG
members include Deseret Power Electric Cooperative, Idaho Power, Northwestern
Energy, PacifiCorp, Portland General Electric, and Utah Associated Municipal Power
Systems. These members rely upon the NTTG committee structure to meet FERC’s
coordinated transmission planning requirements. Avista’s transmission network has a
number of strong interconnections with three of the six NTTG member systems. Due to
the geographical and electrical positions of Avista’s transmission network related to
NTTG members, Avista participates in the NTTG planning process to foster
collaborative relationships with our interconnected utilities.

Transmission Coordination Work Group
The Transmission Coordination Work Group is a joint effort between 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 a proposed Northeast Oregon station near
Boardman, Oregon. These projects follow WECC Regional Planning and Project Rating
Guidelines. Detailed information on projects presently under consideration is available
at www.nwpp.org/tcwg. Many of the projects from this effort are on hold or have been
terminated.

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
NWPP. Through involvement in WECC and NWPP standing committees and sub-
committees, Avista participates in developing new and revised criteria while
coordinating transmission system planning and operation with neighboring systems.
Mandatory reliability standards promulgated through FERC and NERC subject Avista to
periodic performance audits through these regional organizations.

Avista’s transmission system is constructed for the primary purposes of providing
reliable and efficient transmission service from the company’s portfolio of power
resources to its retail native load customers. Portions of Avista’s transmission system
are fully subscribed for retail load service. Transmission capacity that is not reserved
and scheduled for native load service is made available to third parties pursuant to
FERC regulations and the terms and conditions of Avista’s OATT. Such surplus
transmission capacity that is not sold on a long-term (greater than one year) basis is
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Avista Corp 2013 Electric IRP 5-4

marketed on a short-term basis to third parties and used by Avista for short-term
resource optimization.

Regional Transmission System
BPA owns and operates over 15,000 miles of transmission-level facilities, and it owns
the largest portion of the region’s high voltage (230 kV or higher) transmission grid.
Avista uses BPA transmission to transfer output from its remote generation sources to
Avista’s transmission system, including its share in Colstrip Units 3 and 4, Coyote
Springs 2, Lancaster, and its WNP-3 settlement contract. Avista also contracts with BPA
for Network Integration Transmission Service to transfer power to several delivery
points on the BPA system to serve portions of Avista’s retail load, and to sell power
surplus to its needs to other parties in the region.

Avista participates in BPA transmission 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 electricity grid expansion will likely require new transmission assets by federal
and other entities. BPA is developing several transmission projects in the Interstate-5
corridor, as well as projects in southern Washington necessary for integrating wind
generation resources located in the Columbia Gorge. Each project has the potential to
increase BPA transmission rates and thereby affect Avista’s costs.

Avista’s Transmission System
Avista owns and operates a system of over 2,200 miles of electric transmission
facilities. This includes approximately 685 miles of 230 kV line and 1,527 miles of 115
kV line. Figure 5.1 illustrates Avista’s transmission system. Avista owns an 11 percent
interest in 495 miles of double circuit 500 kV lines 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. Avista also has network interconnections with the
following utilities:

BPA
Chelan County PUD
Grant County PUD
Idaho Power Company
NorthWestern Energy
PacifiCorp
Pend Oreille County PUD
Chapter 5 – Transmission & Distribution

Avista Corp 2013 Electric IRP 5-5

Figure 5.1: Avista Transmission Map

Transmission System Information for the 2013 IRP
Since the 2011 IRP, Avista completed transmission projects to support new generation,
increase reliability, and provide system voltage support including;
Thornton 230 kV switching station
Garden Springs to Hallet & White section of South Fairchild 115 kV Tap
Irvin – Opportunity 115 kV line
Burke Substation to Montana border section of Burke – Thompson Falls A&B 115
kV lines
Southern half of Bronx – Cabinet Gorge 115 kV line
Capacitor bank installed at the Lind 115 kV switching station.

Lancaster Integration
Avista has evaluated and proposed an interconnection with BPA at its Lancaster 230 kV
Switching Station. Avista and BPA have determined the preferred alternative is to loop
the Avista Boulder-Rathdrum 230 kV line into the BPA Lancaster 230 kV station. This
interconnection allows Avista to eliminate or offset BPA wheeling charges for moving
the output from Lancaster to Avista’s system. Besides reducing transmission payments
to BPA by Avista, the interconnection benefits both Avista and the BPA by increasing
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Avista Corp 2013 Electric IRP 5-6

system reliability, decreasing losses, and delaying the need for additional transformation
at BPA’s Bell Substation. Studies indicate this project may allow more transfer capability
across the combined transmission interconnections of Avista and BPA. This project, in
conjunction with other Avista upgrades, also supports increasing the Montana-to-
Northwest path rating by as much as 800 MW. Avista has worked collaboratively with
BPA and the Lancaster 230 kV interconnection project is planned for completion by the
end of 2013.

South Spokane 230 kV Reinforcement
Transmission studies continue to support the need for an additional 230 kV line to the
south and west of Spokane. Avista currently has no 230 kV source in these areas and
instead relies on its 115 kV system for load service and bulk power flows through the
area. The project scope is under development, and preliminary studies indicate the
need for the following (or similar) projects:

A new 230/115 kV station near Garden Springs. Property acquisition for the
Garden Springs station and preliminary geo-technical station design work has
commenced;
Tap of the Benewah-Boulder 230 kV line southwest of the Liberty Lake area and
construction of a new 230 kV switching station (for later development of a
230/115 kV substation); alternatively, reconstruction of the 115 kV circuits
between Beacon and Ninth & Central, and the installation of a 230/115 kV station
at that site could be pursued;
Connecting the Liberty Lake 230 kV station with the Garden Springs 230 kV
station; alternatively, connecting the Ninth & Central station to the Garden
Springs station;
Construction of a new 230 kV line from Garden Springs to Westside; and
Origination and termination of the 115 kV lines from the new Spokane area
230/115 kV station(s).

The South Spokane 230 kV Reinforcement project was scoped at the end of 2012 with
a planned in-service date by the end of 2018. The project is planned to enter service in
a staged fashion beginning in 2014.

Avista Station Upgrades
As reported in the 2011 IRP, Avista planned to upgrade its Moscow, Noxon, and
Westside 230 kV substations. These upgrades improve reliability, add capacity, and
update aging components. The Moscow station upgrades, scheduled for completion in
2014, will result in a new facility with a single 250 MVA 230/115 kV station doubling the
current station capacity over the next five to 10 years. Further upgrades or rebuilds are
planned at the following substations:

Irvin 115 kV Switching Station [Spokane Valley Reinforcement] (2016)
Millwood 115 kV Distribution Substation [Spokane Valley Reinforcement] (2013)
North Lewiston 115 kV Distribution Substation (2014)
Moscow 230/115 kV Substation (2011-2014)
Stratford 115 kV Switching Station (2014)
Chapter 5 – Transmission & Distribution

Avista Corp 2013 Electric IRP 5-7

Blue Creek 115 kV Distribution Substation (2014)
Harrington 115 kV Distribution Substation (2014)
Noxon 230 kV Switching Station (2013-2016)
9th & Central 115 kV Distribution Substation (2015)
Greenacres 115 kV Distribution Substation (2014)
Beacon 230/115 kV Station Partial Rebuild (2017+)

Avista Transmission Upgrades
Avista plans to complete several 115 kV reconductor projects throughout its
transmission system over the next decade. These projects focus on replacing decades-
old small conductor with conductor capable of greater load-carrying capability and
provide more efficient (i.e., fewer electrical losses) service. The following list gives an
example of planned transmission projects:

Spokane Valley Reinforcement Project (2011-2016)
Bronx – Cabinet Gorge 115 kV (2011-2015)
Burke – Pine Creek 115 kV (2012-2014)
Benton – Othello 115 kV (2014-2016)
Devils Gap – Lind 115 kV (2014-2016)
Coeur d’Alene – Pine Creek 115 kV (2014-2017)

Generation Interconnection Requests
Avista’s Power Supply Department requested generator interconnection studies in
several areas of Avista’s transmission system for the 2013 IRP. Developers have also
requested studies through Avista’s Large Generation Interconnection Request (LGIR)
process. Table 5.1 states the projects and cost information for each of the IRP-related
studies. The study results for each project, including cost and integration options, may
be found in Appendix D. These studies are a high level view of the generation
interconnect request similar to what would be performed as a feasibility study for a third
party under the LGIR process.

Table 5.1: IRP Requested Transmission Upgrade Studies

Project Size (MW) Cost1
Nine Mile 60 No cost
Long Lake 68 $9.9 million
Monroe Street 80 No cost2
Upper Falls 40 No cost3
Post Falls 16 No cost
Cabinet Gorge 60 No cost
Thornton 200 $4 million
Benewah to Boulder 300 $7-$15 million
Rathdrum 300 $7-$30+ million
1 Cost estimates are in 2013 dollars and use engineering judgment with a 50 percent margin for error. 2 An upgrade to the College & Walnut substation may require upgrades. 3 Ibid.
Chapter 5 – Transmission & Distribution

Avista Corp 2013 Electric IRP 5-8

Large Generation Interconnection Requests
Third-party generation companies or independent power producers may make requests
for transmission studies to understand the cost and timelines for integrating potential
new generation projects. These types of projects follow a strict FERC process and
include three study steps to estimate the feasibility, system impact, and facility
requirement costs for project integration. Each of these studies provides the requester
with a different level of project costs, and the studies are typically complete over at least
a one-year period. After this process is completed a contract can be offered to integrate
the project and negotiations can begin to enter into a transmission agreement if
necessary. Each of the proposed projects are made public to some degree (customer
names remain anonymous). Below Table 5.2 lists the current projects remaining in
Avista’s transmission queue.

Table 5.2: Third-Party Large Generation Interconnection Requests

Project # Size (MW) Type Interconnection
#33 400 Wind Lind 115 kV Substation
#35 200 CT Thornton 230 kV Switching Station
#36 105 Wind Thornton 230 kV Switching Station

Distribution System Efficiencies
In 2008, an Avista system efficiencies team of operational, engineering, and planning
staff developed a plan to evaluate potential energy savings from Transmission and
Distribution system upgrades. The first phase summarized potential energy savings
from distribution feeder upgrades. The second phase, beginning in the summer of 2009,
combined transmission system topologies with “right sizing” distribution feeders to
reduce system losses, improve system reliability, and meet future load growth.

The system efficiencies team evaluated several efficiency programs to improve both
urban and rural distribution feeders. The programs consisted of the following system
enhancements:

 Conductor losses;
 Distribution transformers;
 Secondary districts; and
 Volt-ampere reactive compensation.

The energy losses, capital investments, and reductions in operations and maintenance
(O&M) costs resulting from the individual efficiency programs under consideration were
combined on a per feeder basis. This approach provided a means to rank and compare
the energy savings and net resource costs for each feeder.

Feeder Upgrade Program
Avista’s distribution system consists of approximately 330 feeders covering 30,000
square miles, ranging in length from three to 73 miles. For rural distribution, feeder
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Avista Corp 2013 Electric IRP 5-9

lengths vary widely to meet the electrical loads resulting from the startup and shutdown
business swings of the timber, mining and agriculture industries.

The Feeder Upgrade Program’s charter criterion has grown to include a more holistic
approach to the way Avista addresses each project. This vital program integrates work
performed under various operational initiatives in Avista including the Wood Pole
Management Program, the Transformer Change-out Program, the Vegetation
Management Program and the Feeder Automation Program. The work of the Feeder
Upgrade Program includes the replacement of undersized and deteriorating conductors,
replacement of failed and end-of-life infrastructure materials including wood poles, cross
arms, fuses and insulators. Inaccessible pole alignment, right-away, undergrounding
and clear zone compliance issues are addressed for each feeder section as well as
regular maintenance work such as leaning poles, guy anchors, unauthorized
attachments and joint-use management. This systematic overview enables Avista to
cost-effectively deliver a modernized and robust electric distribution system that is more
efficient, easier to maintain and more reliable for our customers.

Figure 5.2 illustrates the reliability advantages and reasons for the program. Prior to the
2009 feeder rebuild pilot program, outages were increasing at up to 13 outages per
year. After the project, outages declined significantly. In the past two years, only one
outage was recorded. The program is in its second year of regular funding and its
intended purpose of capturing energy savings through reduced losses, increased
reliability and decreased O&M costs is being realized. The feeders addressed through
this program to date are shown in Table 5.3. The total energy savings, from both re-
conductor and transformer efficiencies for all of these feeders, is approximately 4,869
MWh annually.

Table 5.3: Completed Feeder Rebuilds

Feeder Area Year
Complete
Annual Energy
Savings (MWh)
9CE12F4 Spokane, WA (9th & Central) 2009 601
BEA12F1 Spokane, WA (Beacon) 2012 972
F&C12F2 Spokane, WA (Francis & Cedar) 2012 570
BEA12F5 Spokane, WA (Beacon) 2013 885
WIL12F2 Wilbur, WA 2013 1,403
CDA121 Coeur d’Alene, ID 2013 438
Total 4,869

The additional benefits ascertained through the work performed through the Feeder
Upgrade Program are just now coming to fruition and will require a multi-year study to
verify all of the planned benefits. Table 5.4 includes the working plan for feeder rebuilds
over the next several years. The additional energy savings is anticipated to reach 1,626
MWh per year.

Chapter 5 – Transmission & Distribution

Avista Corp 2013 Electric IRP 5-10

Figure 5.2: Spokane’s 9th and Central Feeder (9CE12F4) Outage History

Table 5.4: Planned Feeder Rebuilds

Feeder Area Planned
Year
Annual Energy
Savings (MWh)
NE12F3 Spokane, WA 2014 115
RAT231 Rathdrum, ID 2014 91
OTH502 Othello, WA 2014 21
M23621 Moscow, ID 2014 151
DVP12F2 Davenport, WA 2014 35
HAR4F1 Harrington, WA 2014 69
BEA12F3 Spokane, WA 2015 167
FWT12F3 Spokane, WA 2015 121
TEN1255 Lewiston, ID/Clarkston, WA 2015 249
ROS12F1 Spokane, WA 2016 267
SPI12F1 Northport, WA 2016 162
TUR112 Pullman, WA 2016 101
TUR113 Pullman, WA 2017-2018 76
Total 1,626

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Chapter 6- Generation Resource Options
Avista Corp 2013 Electric IRP
6. Generation Resource Options

Introduction
Several generating resource options are available to meet future load growth. Avista
can upgrade existing resources, build new facilities, or contract with other energy
companies for future delivery. This section describes resources Avista considered in the
2013 IRP to meet future needs. The new resources described in this chapter are mostly
generic. Actual resources may differ in size, cost, and operating characteristics due to
siting or engineering requirements.

Assumptions
For the PRS analyses, Avista only considers commercially available resources with
well-known costs, availability and generation profiles. These resources include gas-fired
combined cycle combustion turbines (CCCT), simple cycle combustion turbines
(SCCT), large-scale wind, storage, hydro upgrades, and certain solar technologies
proven on a large-scale commercial basis. Several other resource options described
later in the chapter were not included in the PRS analysis, but their costs were
estimated for comparative analysis. Potential contractual arrangements with other
energy companies are not an option for this plan, but are an option when Avista seeks
new resources through a RFP.

Levelized costs referred to throughout this section are at the generation busbar. The
nominal discount rate used in the analyses is 6.67 percent based on Avista’s weighted
average cost of capital approved by the states of Idaho and Washington. Nominal
levelized costs result from discounting nominal cash flows at the rate of general
inflation. All costs in this section are in 2014 nominal dollars unless otherwise noted.
Section Highlights
Upgrades to Avista’s Spokane and Clark Fork
Chapter 6- Generation Resource Options
Avista Corp 2013 Electric IRP
Certain renewable resources receive federal and state tax incentives today and into the
near future. Solar tax benefits fall by two-thirds after 2016 and all other renewable
benefits end in 20131. These incentives are included in IRP modeling.

Levelized resource costs presented in this chapter use the maximum available energy
for each year, not expected generation. For example, wind generation assumes 34
percent availability, CCCT generation assumes 90 percent availability, and SCCT
generation assumes 91 percent availability. Wind resources typically operate at or near
assumed availability because the fuel is free, but CCCT or SCCT plants operate at
levels well below their availability factors because their output will be displaced when
lower-cost wholesale market power is available. Costs are levelized for the first 20 years
of the project life using longer useful-life depreciation schedules. The following are
definitions for the levelized cost components used in this chapter:

Capital Recovery and Taxes: Depreciation, return of and on capital, federal and
state income taxes, property taxes, insurance, and miscellaneous charges such
as uncollectible accounts and state taxes for each of these items pertaining to a
generation asset investment.
Allowance for Funds Used During Construction (AFUDC): The cost of money
associated with construction payments made on a generation asset during
construction.
Federal Tax Incentives: The estimated federal tax incentive (per MWh) in the
form of a PTC, a cash grant, or an ITC, attributable to qualified generation
options.
Fuel Costs: The average cost of fuel such as natural gas, coal, or wood, per
MWh of generation. Additional fuel prices details are included in the Market
Analysis section.
Fuel Transport: The cost to transport fuel to the plant, including pipeline capacity
charges.
Fixed Operations and Maintenance (O&M): Costs related to operating the plant
such as labor, parts, and other maintenance services that are not based on
generation levels.
Variable O&M: Costs per MWh related to incremental generation.
Transmission: 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 and/or third party transmission charges.
Other Overheads: Includes miscellaneous charges for non-capital expenses such
as uncollectibles, excise taxes and commission fees.

The tables at the end of this section show incremental capacity, heat rates, generation
capital costs, fixed O&M, variable costs, and peak credits for each resource option.2
1 After completion of the modeling for this IRP, the PTC for wind was expanded to allow any project under
construction by the end of 2013 might qualify upon its completion.
Chapter 6- Generation Resource Options
Avista Corp 2013 Electric IRP
Figure 6.2 compares the levelized costs of different resource types. Avista relies on a
variety of sources including the NPCC, press releases, regulatory filings, internal
analysis, and Avista’s experiences with certain technologies for its resource
assumptions.

Gas-Fired Combined Cycle Combustion Turbine
Gas-fired CCCT plants provide a reliable source of both capacity and energy for a
relatively modest capital investment. The main disadvantage is generation cost volatility
due to reliance on natural gas, unless the fuel price is hedged. CCCTs in this IRP are
“one-on-one” (1x1) configurations, using air-cooling technology. The 1x1 configuration
consists of a single gas turbine, a single heat recovery steam generator (HRSG), and a
duct burner to gain more generation from the HRSG. The plants have nameplate ratings
between 250 MW and 330 MW each depending on configuration and location. A 2x1
CCCT plant configuration is possible with two turbines and one HRSG, generating up to
600 MW. Avista would need to share the plant with one or more utilities to take
advantage of the modest economies of scale and efficiency of a 2x1 plant configuration
due to its large size relative to our needs.

Water cooling technology could be an option for CCCT development, depending on the
plant location; however, this IRP assumes air-cooled technology because of the
difficulties in obtaining new water rights. Where water-cooling technology is available,
the plant may require a lower capital investment and have a better heat rate relative to
air-cooled technology.

The most likely CCCT configuration for Avista is a 270-300 MW air-cooled plant located
in the Idaho portion of Avista’s service territory, mainly due to Idaho’s lack of an excise
tax on natural gas consumed for power generation, a lower sales tax rate relative to
Washington, and no fees on carbon dioxide emissions.3 Potential combined cycle plant
sites would likely be on the Avista transmission system to avoid third-party wheeling
rates. Another advantage of siting a CCCT resource in Avista’s service territory in Idaho
is access to low-cost natural gas on the GTN pipeline.

Cost and operational estimates for CCCTs modeled in the IRP use data from Avista’s
internal engineering analyses. The heat rate modeled for an air-cooled CCCT resource
is 6,832 Btu/kWh in 2014. The projected CCCT heat rate falls by 0.5 percent annually to
reflect anticipated technological improvements. The plants include duct firing for 7
percent of rated capacity at a heat rate of 8,910 Btu/kWh. If Avista were able to site a
water-cooled plant, the heat rate would likely be 2 percent lower and net plant output
might increase by five MW.

The IRP includes a 6 percent forced outage rate for CCCTs, and 14 days of annual
plant maintenance. The plants are capable of backing down to 50 percent of nameplate
2 Peak credit is the amount of capacity a resource contributes at the time of system peak load. 3 Washington state applies an excise tax on all fuel consumed for wholesale power generation, the same
as it does for retail natural gas service, at approximately 3.875 percent. Washington also has higher sales
taxes and has carbon dioxide mitigation fees.
Chapter 6- Generation Resource Options
Avista Corp 2013 Electric IRP
capacity, and ramping from zero to full load in four hours. Carbon dioxide emissions are
117 pounds per dekatherm of fuel burned. The maximum capability of each plant is
highly dependent on ambient temperature and plant elevation.

The anticipated capital cost for an air-cooled CCCT located in Idaho on Avista’s
transmission system, with AFUDC, is $1,279 per kW in 2014; $345 million for a 270 MW
plant. Table 6.1 shows the overnight costs for an air-cooled CCCT resource in nominal
dollars; Table 6.2 shows levelized costs. The costs include firm natural gas
transportation. At this time, excess pipeline capacity exists on the major pipelines near
all potential siting locations to supply firm natural gas service.

Natural Gas-Fired Peakers
Natural gas-fired CTs and reciprocating engines, or peaking resources, provide low-cost
capacity and are capable of providing energy as needed. Technological advances allow
the plants to start and ramp quickly, providing regulation services and reserves for load
following and to integrate variable resources such as wind and solar.

The IRP models four peaking resource options: Frame (GE 7EA), hybrid aero-derivative
or intercooled (GE LMS 100), reciprocating engines (Wartsila 18V34), and aero-
derivative (Pratt FT8). The different peaking technologies range in their abilities to follow
load, costs, generating capabilities, and energy-conversion efficiencies. Table 6.1
shows cost and operational estimates based on Avista’s internal engineering estimates.
All peaking plants assume 0.5 percent annual real dollar cost decrease and forced
outage and maintenance rates. The levelized cost for each of the technologies is in
Table 6.2.

Firm fuel transportation has become an electric reliability issue with FERC, and is being
discussed at several regional and extra-regional forums. For this IRP, Avista continues
to assume it will not procure firm natural gas transportation for its peaking resources.
Firm transportation could be necessary where pipeline capacity becomes scarce during
utility peak hours; however, pipelines near potential sites being modeled by Avista in the
IRP are not currently subscribed or expected to be subscribed in the near future to
levels high enough to warrant the additional costs of having firm supply. Avista
continues to monitor natural gas transportation options for its portfolio. Where non-firm
natural gas transportation options become inadequate for system reliability, three
options exist: contracting for firm natural gas transportation rights, or on-site oil or
natural gas storage.

The lowest-cost peaking resource, as measured by production cost in Table 6.2, is
hybrid technology. However, this comparison is misleading, as a peaking resource does
not operate at its theoretical maximum operating levels. Peaking resources generally
operate only a small number of hours in the year. Therefore, lower capacity-cost
resources may be more cost-effective for the portfolio in relation to hybrid technology
when considering the number of expected operating hours in the broader IRP modeling
process.

Chapter 6- Generation Resource Options
Avista Corp 2013 Electric IRP

Table 6.1: Natural Gas Fired Plant Cost and Operational Characteristics

Item Air Cooled
CCCT
Frame Hybrid Recip.
Engines
Aero-
Derivative
Capital Cost with AFUDC
($/kW)
$1,279 $910 $1,199 $1,141 $1,185
Fixed O&M ($/kW- yr) $22.70 $11.48 $16.07 $18.78 $13.56
Heat Rate (Btu/kWh) 6,832 11,286 8,712 8,712 9,802
Variable O&M ($/MWh) $1.77 $3.13 $5.22 $6.26 $4.17
Units Assumed at Site 1 2 1 6 2
Unit Size (MW) 270 83 92 19 50
Total Project Size (MW) 270 166 92 114 100
Total Cost for Segment
Size (millions)
$345 $151 $110 $128 $119

Table 6.2: Natural Gas-Fired Plant Levelized Costs per MWh

Item Air
Cooled
CCCT
Frame Hybrid Recip.
Engines
Aero-
Derivative
Capital Recovery & Taxes 18.69 13.79 18.17 16.83 17.96
AFUDC 2.02 0.58 0.76 0.70 0.75
Fuel Costs4 41.43 59.68 46.07 46.07 51.83
Fixed O&M 3.72 1.83 2.57 2.92 2.17
Variable O&M 2.25 3.97 6.62 7.94 5.29
Transmission 1.07 0.40 0.72 0.58 0.67
Other Overheads 1.44 1.96 1.67 1.71 1.78
Total Cost 70.62 82.21 76.57 76.75 80.45

Wind Generation
Concerns over the environmental impact of carbon-based generation technologies have
increased demand for wind generation. Governments are promoting wind generation
with tax credits, renewable portfolio standards, carbon emission restrictions, and stricter
controls on existing non-renewable resources. The 2013 “Fiscal Cliff” deal in the U.S.
Congress extended the PTC for wind through December 31, 2013, with provisions
allowing projects to qualify after 2013 so long as construction begins in 2013. This IRP
does not assume the PTC extends beyond this term, but does assume the preferential
5-year tax depreciation remains.

The IRP considers two wind generation resources located both on- and off-system. Both
resources assume similar capital costs and wind patterns. On-system projects pay only
transmission interconnection costs, whereas off-system projects must pay both
interconnection and third-party wheeling costs.

4 The Air-Cooled CCCT technologies fuel cost includes a charge for fuel transport to reserve capacity on
a major pipeline. The levelized cost of the charge is estimated to be $5.04 per MWh.
Chapter 6- Generation Resource Options
Avista Corp 2013 Electric IRP
Wind resources benefit from having no emissions profile or fuel costs, but they are not
dispatchable, and have high capital and labor costs on a per-MWh basis when
compared to most other resource options. Wind capital costs in 2014, including AFUDC
and transmission interconnection, are $2,340 per kW, with annual fixed O&M costs of
$46 per kW-yr. Fixed O&M includes indirect charges to account for the inherent
variation in wind generation, oftentimes referred to as “wind integration.” The cost of
wind integration depends on the penetration of wind in Avista’s portfolio, and the market
price of power; for this IRP, wind integration is $4 per kW-year in 2014. These estimates
come from Avista’s experience in the wind market at the time of the IRP, and results
from Avista’s Wind Integration Study.

The wind capacity factors in the Northwest vary depending on project location, with
capacity factors roughly ranging between 25 and 40 percent. This plan assumes
Northwest wind has a 33 percent average capacity factor; on-system wind projects have
a 34 percent capacity factor. A statistical method, based on regional wind studies,
derives a range of annual capacity factors depending on the wind regime in each year
(see stochastic modeling assumptions for more details). The expected capacity factor
can have a dramatic impact on the levelized cost of a wind project. For example, a 30
percent capacity factor site could be $30 per MWh higher than a 40 percent capacity
factor site holding all other assumptions equal.

Levelized costs, using these expected capacity factors, capital, and operating costs, are
in Table 6.4. Actual wind resource costs vary depending on a project’s capacity factor,
interconnection point, and the amount of tax related subsidies available. Further, this
plan assumes wind resources selected in the PRS include the 20 percent REC
apprenticeship adder for Washington state renewable portfolio standard eligible
renewable resources. This adder applies only for Washington state compliance with the
EIA, requiring 15 percent of the construction labor to be from apprentices through a
state-certified apprenticeship program to qualify.

Table 6.3: Northwest Wind Project Levelized Costs per MWh

Item On-System Off-System
Capital Recovery & Taxes 80.68 83.12
AFUDC 4.73 4.87
Fuel Costs 0.00 0.00
Fixed O&M 19.81 20.41
Variable O&M 2.65 2.65
Transmission 1.77 9.99
Other Overheads 0.72 0.98
Total Cost 110.36 122.02

Solar Photovoltaic
Solar photovoltaic generation technology costs have fallen substantially in the last
several years partly due to low-cost imports, and from renewable portfolio standards
and government tax incentives, both inside and outside of the United States. Even with
these large cost reductions, Avista’s analysis shows that solar still is uneconomic for
Chapter 6- Generation Resource Options
Avista Corp 2013 Electric IRP
winter-peaking utilities in the Northwest when compared to other generation resource
options, both renewable and non-renewable. This is due to solar’s low capacity factor,
its lack of on-peak output during cold winter peak periods, and relatively high capital
cost. Solar does provide predictable daytime generation complementing the loads of
summer-peaking utilities, though fixed panels typically do not produce full output at
system peak.

In the Northwest solar provides no wintertime on-peak capability. If a substantial amount
of solar is added to a summer peaking utility (e.g., in the desert Southwest), the peak
hour recorded prior to the solar installation will be reduced, but the peak will simply be
shifted toward sundown when the solar facility witnesses a substantial output reduction.
Figure 6.1 presents an example based on California Independent System Operator
Daily Renewables output data for August 14, 2012. To better illustrate solar
generation’s impact, the figure shows a ten-fold increase to actual solar output.
Assuming 10,000 MW of alternating current (AC) nameplate solar lowers the peak by
5,662 MW from the actual peak of 45,227, and shifts the overall system peak by two
hours.5 The example shows a net 56 percent peak credit for solar because solar’s
output falls off drastically in the later hours of the day.

Figure 6.1: Solar’s Effect on California Load

Utility-scale photovoltaic generation can be optimally located for the best solar radiation,
albeit at the expense of lower overall generation levels. Solar thermal technologies can
5 Solar output generally is quoted on a direct current (DC) basis; however, for an alternating current
system output is reduced by approximately 15-23 percent to account for DC-AC conversion and other on-
site losses. The actual capacity of the solar generation profile is unknown, it is likely between 1,000 and
1,500 MW.
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Chapter 6- Generation Resource Options
Avista Corp 2013 Electric IRP
produce higher capacity factors than photovoltaic solar projects by as much as 30
percent, and can store energy for several hours for later use in reducing peak loads.
Utility-scale solar capital costs in the IRP, including AFUDC, are $3,403 per kW for
photovoltaic and $6,587 for solar-thermal or concentrating solar projects. A well-placed
utility-scale photovoltaic system located in the Pacific Northwest would achieve a
capacity factor of less than 18 percent; the IRP uses a 15 percent capacity factor. Only
utility-scale photovoltaic was included as an option for the PRS. Avista does not believe
solar-thermal is an economically viable option in Avista’s service territory given our
modest solar resource and the relatively higher capital costs when compared to
photovoltaic projects.

Table 6.4 shows the levelized costs of solar resources, including federal incentives.
Even with declining prices, solar will continue to struggle as a cost-competitive resource
in the Northwest because of its high installation costs and because the technology
cannot meet winter peak system requirements. One advantage given to solar in the
state of Washington is if the total plant is less than five megawatts it counts as two
RECs towards Washington’s EIA. Washington state also offers substantial financial
incentives for consumer-owned solar. This IRP does not explicitly consider consumer-
owned solar, as the overall incentives are not available to utilities and would otherwise
be capped at a level that would not affect this plan. Consumer-owned solar continues to
be accounted for through reductions in Avista’s retail load forecast.

Table 6.4: Solar Nominal Levelized Cost ($/MWh)

Item Photovoltaic
Solar
Capital Recovery &Taxes 293.32
AFUDC 9.56
Fuel Costs 0.00
Fixed O&M 48.32
Variable O&M 0.00
Transmission 21.61
Other Overheads 2.08
Total Cost (without federal tax incentive) 374.89
Total Cost (with federal tax incentive) 283.58

Coal Generation
The coal generation industry is at a crossroads. In many states, like Washington, new
coal-fired plants are unlikely due to emission performance standards. Coal remains a
viable option in other parts of the country, but the risks associated with future carbon
legislation make investments in this technology challenging. The EPA has proposed a
greenhouse gas emission performance standard average of 1,000 lbs per MWh
(averaged over a 30-year period). This proposed rule effectively eliminates new coal-
fired generation without carbon sequestration, as non-sequestered coal options
generate between 1,760 and 1,825 lbs of carbon dioxide per MWh.

Chapter 6- Generation Resource Options
Avista Corp 2013 Electric IRP
Avista does not plan to build or participate in any new coal-fired generation resources in
the future due to the risk of future national carbon mitigation legislation and the effective
prohibition contained in Washington state law. Technologies reducing or capturing
greenhouse gas emissions in coal-fired resources might enable coal to become a viable
technology in the future, but the technology is not commercially available. Though
Avista will not pursue coal in this plan, three coal technologies are shown to illustrate
their costs: super critical pulverized, integrated gasification combined cycle (IGCC), and
IGCC with sequestration. IGCC plants gasify coal, thereby creating a more efficient use
of the fuel, lowering carbon emissions and removing other toxic substances before
combustion. Sequestration technologies, if they become commercially available, might
potentially sequester 90 percent of CO2 emissions. Table 6.6 shows the costs, heat
rates, and CO2 emissions of the three coal-fired technologies based on estimates from
the NPCC’s Sixth Power plan and adjusted for Avista’s projected inflation rates. Table
6.7 shows the nominal levelized cost per MWh based on the capital costs and plant
efficiencies shown in Table 6.6.

Table 6.5: Coal Capital Costs

Item Super-
Critical
IGCC IGCC w/
Sequestration
Capital Costs ($/kW includes AFUDC) $3,683 $4,895 $7,342
Typical Size 600 600 550
Cost per Unit (Millions) $2,210 $2,937 $4,038
Heat Rate (Btu/kWh) 8,910 8,594 10,652
CO2 (lbs per MWh) 1,827 1,762 218

Table 6.6: Coal Project Levelized Cost per MWh

Item Super-
Critical
IGCC IGCC w/
Sequestration
Capital Recovery & Taxes 54.90 72.26 108.38
AFUDC 8.25 13.35 20.02
Fuel Costs 14.52 14.00 17.36
Fixed O&M 7.24 11.07 11.07
Variable O&M 3.64 8.34 11.25
Transmission 9.47 9.62 4.38
Other Overheads 1.04 1.28 1.31
Total Cost 99.06 129.92 173.77

Chapter 6- Generation Resource Options
Avista Corp 2013 Electric IRP
Energy Storage
Increasing amounts of solar and wind generation on the electric grid makes energy
storage technologies attractive from an operational perspective. The technologies could
be an ideal way to smooth out renewable generation variability and assist in load
following and regulation needs. The technology also could meet peak demand, provide
voltage support, relieve transmission congestion, take power during over supply events,
and supply other non-energy needs for the system. Over time, storage may become an
important part of the nation’s grid. Several storage technologies currently exist,
including; pumped hydro, traditional and chemical batteries, flywheels, and compressed
air.

There are many challenges with storage technology. First, existing technologies
consume a significant amount of electricity relative to their output through conversion
losses. Second, the cost of storage is high, at near $4,000 per kW. This cost is nearly
four times the initial cost of a natural gas-fired peaking plant that can provide many, but
not all, of the same capabilities without the electricity consumption characteristics of
storage. Storage costs are forecast to decline over time, and Avista continues to
monitor the technologies as part of the IRP process. Third, the current scale of most
storage projects is small, limiting their applicability to utility-scale deployment. Fourth,
early adoption of technology can be risky, with many industry examples of battery fires
and bankruptcy.

The Northwest might be slower in adopting storage technology relative to other regions
in the country. The Northwest hydro system already contains a significant amount of
storage relative to the rest of the country. However, as more capacity consuming
renewables are added to the grid, new storage technologies might play a significant role
in meeting the need for additional operational flexibility where upfront capital costs and
operational losses fall.

One of the biggest obstacles to energy storage is quantifying and properly valuing its
benefits. At a minimum, the value of storage is the spread or difference between the
value of energy in on versus off-peak hours (load factoring), minus the losses. Since the
technology can meet regulation, load following, and operating reserves, there is value
beyond load factoring. Valuing these benefits requires new system modeling tools.
Presently there are no adequate tools available in the marketplace. Avista is developing
a tool it believes will enable detailed valuations of storage (and other) technologies
within our existing mix of flexible hydro and thermal system. The results of these studies
are not available for this plan, but should be available in the next IRP.

Other Generation Resource Options
A thorough IRP considers generation resources not readily available in large quantities
or commercially or economically ready for utility-scale development. Today a number of
emerging technologies, like energy storage, are attractive from an operational or
environmental perspective, but are significantly higher-cost than other technologies
providing substantially similar capabilities at lower cost. Avista analyzed several of
these technologies for the IRP using estimates from the NPCC’s Sixth Power Plan,
Chapter 6- Generation Resource Options
Avista Corp 2013 Electric IRP
publically available data, and Avista internal engineering analysis. The resources
include biomass, geothermal, co-generation, nuclear, landfill gas, and anaerobic
digesters. Table 6.7 shows the expected cost of these options. Their costs vary
depending on site-specific conditions. All prices shown are utility-scale estimates with
no federal tax incentives. However, given the lack of utility-scale development, cost
could be substantially higher than shown.

Failure to be included in the PRS is not the last opportunity for technologies to be in
Avista’s portfolio. The resources will compete with those included in the PRS through
Avista’s RFP processes. RFP processes identify competitive technologies that might
displace resources otherwise included in the IRP strategy. Another possibility is
acquisition through federal PURPA law mandates. PURPA provides non-utility
developers the ability to sell qualifying power to Avista at guaranteed prices and terms.6
Since the 2011 IRP, Avista has acquired three renewable energy projects under
PURPA.

Woody Biomass Generation
Woody biomass generation projects use waste wood from lumber or forest restoration
process. The generation process is similar to a coal plant: a turbine converts boiler-
created steam into electricity. A substantial amount of wood fuel is required for utility-
scale generation. Avista’s 50 MW Kettle Falls Generation Station consumes over
350,000 tons of wood waste annually, or 48 semi-truck loads of wood chips per day. It
typically takes 1.5 tons of wood to make one MWh of electricity; the ratio varies
seasonally with the moisture content of the fuel. The viability of another Avista biomass
projects depends significantly on the availability and cost of the fuel supply. Many
announced biomass projects fail due to lack of a long-term fuel source. If an RFP
identifies a potential project, Avista will consider it for a future acquisition. A 25 MW
utility scale biomass plant would cost approximately $111 million in initial capital
expenditure ($4,436 per kW), with fuel and O&M costs increasing the total cost to an
amount approaching $160 per MWh.

Geothermal Generation
Northwest utilities have shown increased interest in geothermal energy over the past
several years. It provides predictable electrical capacity and energy with minimal carbon
dioxide emissions (zero to 200 pounds per MWh). The technology typically involves
injecting water into deep wells; hot earth temperatures heat water and spin turbines for
power generation. In recent years, a few projects were built in the Northwest. Due to the
geologic conditions of Avista’s service territory, no geothermal projects are likely to be
developed. For Avista to add this technology to its portfolio, it would require a third-party
transmission wheel and be acquired through an RFP process.

Geothermal energy struggles to compete due to high development costs stemming from
having to drill several holes thousands of feet below the earth’s crust; each hole can
cost over $3 million. Ongoing geothermal costs are low, but the capital required to
locate and prove a viable site is significant. Costs shown in this section do not account
6 Rates, terms, and conditions are at www.avistautilities.com under Schedule 62.
Chapter 6- Generation Resource Options
Avista Corp 2013 Electric IRP
for dry-hole risk associated with sites that do not prove to be viable after drilling has
taken place. Recent construction estimates for a 15 MW facility are $71.5 million
($4,767 per kW). The levelized cost of geothermal power is $104 per MWh.

Landfill Gas Generation
Landfill gas projects generally use reciprocating engines to burn methane gas collected
at landfills. The Northwest has successfully developed many landfill gas resources. The
costs of a landfill gas project will depend greatly on the site specifics of a landfill. The
Spokane area had a project on one of its landfills, but it was retired after the fuel source
depleted to an unsustainable level. The Spokane area no longer landfills its waste and
instead uses its Municipal Waste Incinerator. Nearby in Kootenai County, Idaho, the
Kootenai Electric Cooperative has developed a 3.2 MW Fighting Creek Project. It is
currently under a PURPA contract with Avista. Using publically available costs and the
NPCC estimates, landfill gas resources are economically promising, but are limited in
their size, quantity, and location. Cost estimates in Table 6.7 assume a 3.2 MW unit with
a capital cost of $8.5 million ($2,654 per kW including AFUDC). At an 88 percent
capacity factor, a landfill gas project could cost up to $106 per MWh.

Anaerobic Digesters (Manure/Wastewater Treatment)
The number of anaerobic digesters is increasing in the Northwest. These plants typically
capture methane from agricultural waste, such as manure or plant residuals, and burn
the gas in reciprocating engines to power generators. These facilities tend to be
significantly smaller than utility-scale generation projects (less than five MW). Most
facilities are located in large dairies or feedlots. A survey of Avista’s service territory
found no large-scale livestock operations capable of implementing this technology.

Wastewater treatment facilities can also host anaerobic digesting technology. Digesters
installed when a facility is initially constructed helps the economics of a project greatly,
though costs range greatly depending on the system configuration. Retrofits to existing
wastewater treatment facilities are possible, but tend to have higher costs. Many of
these projects offset energy needs of the facility, so there may be little, if any, surplus
generation capability. Avista currently has a 260 kW waste water system under a
PURPA contract with a Spokane County facility.

Typical digester projects are 200 kW to five MW. Current estimates are $4,775 per kW
for utility development, or $24 million in capital for a five MW project. The actual cost of
the technology depends on the fuel source, site specifics, and subsidies available for
the project. For example, many digesters qualify for agricultural loans and/or grants.
Fuel costs vary based on feedstock prices and transportation costs to move fuel to the
digester. The cost of the technology is $110 per MWh without fuel charges.

Small Cogeneration
Avista has few industrial customers capable of developing cost-effective cogeneration
projects. If an interested customer was inclined to develop a small cogeneration project,
it could provide benefits including reduced transmission and distribution losses, shared
fuel, capital, and emissions costs, and credit toward Washington’s EIA targets.
Chapter 6- Generation Resource Options
Avista Corp 2013 Electric IRP
Another potentially promising option is natural gas pipeline cogeneration. This
technology uses waste-heat from large natural gas pipeline compressor stations. In
Avista’s service territory few compressor stations exist, but the existing compressors in
our service territory have potential for this generation technology. Avista has discussed
adding cogeneration with pipeline owners.

A big challenge in developing any new cogeneration project is aligning the needs of the
cogenerator and the utility’s need for power. The optimal time to add cogeneration is
when an industrial process is being retrofitted, but oftentimes the utility does not need
the new capacity at this time. Another challenge to cogeneration within an IRP is
estimating costs when host operations drive costs for a particular project.

Nuclear
Avista does not include nuclear plants as a resource option in the IRP given the
uncertainty of their economics, the apparent lack of regional political support for the
technology, U.S. nuclear waste handling policies, and Avista’s modest needs relative to
the size of modern nuclear plants. Nuclear resources could be in Avista’s future only if
other utilities in the Western Interconnect incorporate nuclear power in their resource
mix and offer Avista an ownership share.

The viability of nuclear power could change as national policy priorities focus attention
on de-carbonizing the nation’s energy supply. The lack of newly completed nuclear
facility construction experience in the United States makes estimating construction costs
difficult. Cost projections in the IRP are from industry studies, recent nuclear plant
license proposals, and a small number of projects currently under development. New
smaller, and more modular, nuclear design could increase the potential for nuclear by
shortening the permitting and construction phase (lower AFUDC costs), and make these
traditionally large projects better fit the needs of smaller utilities.

Table 6.7’s nuclear cost estimate is for a 1,100 MW facility. This assumes a capital cost
of $9,125 per kW (including AFUDC). At this cost, a large facility could easily cost $10
billion to build and cost $173 per MWh over the first 20 years of project life.

Table 6.7: Other Resource Options Levelized Costs ($/MWh)

Landfill
Gas
Manure
Digester
Wood
Biomass
Geothermal Nuclear
Capital Recovery & Taxes 36.35 65.43 60.09 57.12 114.25
AFUDC 1.01 1.03 4.43 8.78 29.93
Fuel Costs 33.60 33.60 56.40 0.00 10.83
Fixed O&M 4.45 7.70 31.84 29.43 15.41
Variable O&M 25.14 31.75 4.90 5.95 1.98
Transmission 4.67 4.13 1.41 4.08 4.13
Other Overheads 2.02 2.30 2.81 1.17 0.96
Total Cost 107.24 145.95 161.88 106.53 177.50

Chapter 6- Generation Resource Options
Avista Corp 2013 Electric IRP
New Resources Cost Summary
Avista has several resource alternatives for this IRP. Each alternative provides different
benefits, costs and risks. The IRP identifies the relevant characteristics and chooses a
set of resources that are actionable, meet energy and capacity needs, balance
renewable requirements, and minimize costs. Figure 6.2 shows comparative cost per
MWh of each new resource alternative over the first 20 years of project life using
nominal levelized costs. Tables 6.8 and 6.9 provide detailed assumptions for each type
of resource. The ultimate resource selection goes beyond simple levelized cost
analyses and considers the capacity contribution of each resource, among other items
discussed in the IRP.

Figure 6.2: New Resource Levelized Costs (first 20 Years)

Chapter 6- Generation Resource Options
Avista Corp 2013 Electric IRP
Table 6.8: New Resource Levelized Costs Considered in PRS Analysis

Resource Size
(MW)
Heat
Rate
(Btu/
kWh)
Capital
Cost
($/kW)
Fixed
O&M
($/kW-yr)
Variable
O&M
($/MWh)
Peak
Credit
(Winter/
Summer)
CCCT (air cooled) 270 6,832 1,279 22.7 1.77 104/94
Frame CT 83 11,286 910 11.5 3.13 104/94
Hybrid CT 92 8,712 1,199 16.1 5.22 104/94
Reciprocating Engines 114 8,712 1,141 18.8 6.26 100/100
Aero CT 100 9,802 1,185 13.6 4.17 104/94
Wind 100 n/a 2,340 53.0 2.09 0/0
Storage 5 n/a 3,889 52.2 0.00 100/100
Solar (photovoltaic) 5 n/a 3,403 53.0 0.00 0/62

Table 6.9: New Resource Levelized Costs Not Considered in PRS Analysis

Resource Size
(MW)
Heat
Rate
(Btu/
kWh)
Capital
Cost
($/kW)
Fixed
O&M
($/kW-yr)
Variable
O&M
($/MWh)
Peak
Credit
(Winter/
Summer)
Pulverized Coal 600 8,910 3,683 41.73 2.87 100/100
IGCC Coal 600 8,594 4,895 62.60 6.57 100/100
IGCC Coal w/ Seq. 550 10,652 7,342 62.60 8.87 100/100
Woody Biomass 25 13,500 4,436 187.80 3.86 100/100
Geothermal 15 n/a 4,767 182.59 4.70 100/100
Landfill Gas 3.2 10,500 2,654 27.13 19.82 100/100
Anaerobic Digester 1 10,500 4,721 46.95 25.04 100/100
Nuclear 1100 10,400 9,125 93.90 1.57 100/100

Hydroelectric Project Upgrades and Options
Avista continues to upgrade many of its hydroelectric facilities. The latest hydroelectric
upgrade added nine megawatts to the Noxon Rapids Development in April 2012. Figure
6.3 shows the history of upgrades to Avista’s hydroelectric system by year and
cumulatively. Avista added 40.1 aMW of incremental hydroelectric energy between
1992 and 2012. Upgrades completed after 1999 qualify for the EIA, thereby reducing
the need for additional higher-cost renewable energy options.

Chapter 6- Generation Resource Options
Avista Corp 2013 Electric IRP
Figure 6.3: Historical and Planned Hydro Upgrades

Avista’s next upgrade is at Nine Mile, replacing two of the four project units. Avista is
currently removing the old equipment on units one and two, and replacing the 105-year
old technology with new turbines, runners, generators, and other electrical equipment.
The project is scheduled for completion in 2016.

The Spokane River developments were built in the late 1800s and early 1900s, when
the priority was to meet then-current loads. They do not to capture a majority of the river
flow. In 2012, Avista re-assessed its Spokane River developments. The goal was to
develop a long-term strategy and prioritize potential facility upgrades. Avista evaluated
five of the six Spokane River developments and estimated costs for generation upgrade
options at each. Each upgrade option should qualify for the EIA, meeting the
Washington state renewable energy goal. These studies were part of the 2011 IRP
Action Plan and are discussed below. Each of these upgrades would be a major
engineering project, taking several years to complete, and require major changes to the
FERC licenses and project water rights.

Long Lake Second Powerhouse
Avista studied adding a second powerhouse at Long Lake over 20 years ago by using a
small arch dam (Saddle Dam) located on the south end of the project site. This project
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Chapter 6- Generation Resource Options
Avista Corp 2013 Electric IRP
would be a major undertaking and require several years to complete, including major
changes to the Spokane River license and water rights. In addition to providing
customers with a clean energy source, this project could help reduce total dissolved gas
concerns by reducing spill at the project and provide incremental capacity to meet peak
load growth.

The study focused on three alternatives. The first replaces the existing four-unit
powerhouse with four larger units to total 120 MW, increasing capability by 32 MW. The
other two alternatives develop a second powerhouse with a penstock beginning from a
new intake near the existing saddle dam. One powerhouse option was a single 68 MW
turbine project. The second was a two-unit 152 MW project. The best alternative in the
study was the single 68 MW option. Table 6.10 shows upgrade costs and
characteristics.

Post Falls Refurbishment
The Post Falls hydroelectric development is 108 years old. Three alternatives could
increase the existing capacity from 18 MW up to 40 MW. The first option is a new two-
unit 40 MW powerhouse on the south channel that removes the existing powerhouse.
Alternative 2 retrofits the existing powerhouse with five 8.0 MW units (40 MW total).
The last alternative retrofits the existing powerhouse with six 5.6-MW units (33.6 MW
total). The cost differences between developing a new powerhouse in the south channel
and the smaller plant refurbishment is small. Over the next decade, these alternatives
will continue to be studied to address the aging infrastructure of the plant.

Monroe Street/Upper Falls Second Power House
Avista replaced the powerhouse at its Monroe Street project on the Spokane River in
1992. There are three options to increase its capability. Each would be a major
undertaking requiring substantial cooperation with the City of Spokane to mitigate
disruption in Riverfront Park and downtown Spokane during construction. The upgrade
could increase capability by up to 80 MW. To minimize impacts on the downtown area
and the park, a tunnel on the east side of Canada Island could be drilled, avoiding most
above ground excavation of the south channel. A smaller option would be to add a
second 40 MW Upper Falls powerhouse, but this option would require south channel
excavation. The least cost option is an 80 MW upgrade adjacent to the existing Upper
Falls facility.

Cabinet Gorge Second Powerhouse
Avista is exploring the addition of a second powerhouse at the Cabinet Gorge
development site to mitigate total dissolved gas and produce additional electricity. A
new powerhouse would benefit from an existing diversion tube around the dam and
could range in size between 55 and 110 MW.

Chapter 6- Generation Resource Options
Avista Corp 2013 Electric IRP
Table 6.10: Hydro Upgrade Option Costs and Benefits

Resource Inc.
Capacity
(MW)
Inc.
Energy
(MWh)
Inc.
Energy
(aMW)
Peak
Credit
(Winter/
Summer)
Capital
Cost
($ Mill)
Levelized
Cost
($/MWh)
Post Falls 22 90,122 10.3 24/0 $110 158.60
Monroe St/Upper Falls 80 237,352 27.1 31/0 $153 87.50
Long Lake 68 202,592 23.1 100/100 $141 97.45
Cabinet Gorge 55 80,963 9.2 0/0 $116 192.56

Thermal Resource Upgrade Options
The 2011 IRP identified several thermal upgrade options for Avista’s fleet. Since then
Avista has negotiated with the turbine servicers to have some of the upgrades
completed as part of an enhancement package during the 2013 maintenance cycle for
Coyote Springs 2. The upgrades include Mark Vie controls, digital front end on the
EX2100 gas turbine exciter, and model based controls with enhanced transient
capability. These enhancements will improve reliability of the plant, reduce future O&M
costs, improve our ability to maintain compliance with WECC reliability standards, and
help prevent damage to the machine if electrical system disturbances occur. Installation
of cold day controls and cooling optimization will occur after permitting is complete.

In addition to the upgrades at Coyote Springs 2, there are options at the Rathdrum CT
site. Other Avista-owned project sites were reviewed, but based on economics none of
the options were included for the 2013 IRP.

Rathdrum CT to CCCT Conversion
The Rathdrum CT has two GE 7EA units in simple cycle configuration built in 1995 with
an approximate 160 MW of combined output used to serve customers in peak load
conditions. It is possible to convert this peaking facility to a combined cycle plant by
adding 80 MW of steam-turbine capacity (depending upon temperature), and increasing
operating efficiency from a heat rate of 11,612 Btu/kWh, in its existing configuration, to a
heat rate of about 8,000 Btu/kWh. A major issue with this conversion, besides overall
cost, is noise. Residential development at the site since the plant’s construction adds
complexity to a project that would shift from occasional use during peak periods to more
of a base-load configuration.

Rathdrum CT Water Demineralizer
Another identified upgrade at Rathdrum is the addition of a water demineralizer to allow
summertime inlet fogging. Fogging increases peak output during hot summer load
periods. The plant utilized a leased demineralizer in the past, but high leasing costs
moved Avista to end the program.

Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
7. Market Analysis

Introduction
This section describes the electricity and natural gas market environment developed for
the 2013 IRP. It contains pricing risks Avista considers to meet customer demands at
the lowest reasonable cost. The analytical foundation for the 2013 IRP is a
fundamentals-based electricity model of the entire Western Interconnect. The market
analysis evaluates potential resource options on their net value when operated in the
wholesale marketplace, rather than on the simple summation of their installation,
operation, maintenance, and fuel costs. The PRS analysis uses these net values when
selecting future resource portfolios.

Understanding market conditions in the geographic areas of the Western Interconnect is
important, because regional markets are highly correlated by 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 values of company-owned and contracted-for resources. The backbone of
the analysis is AURORAXMP, an electric market model that emulates the dispatch of
resources to loads across the Western Interconnect given fuel prices, hydroelectric
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.

Section Highlights
Natural gas and wind resources dominate new generation additions in the
West.
Shale gas continues to lower natural gas and electricity price forecasts.
A growing Northwest wind fleet reduces springtime market prices below zero
in many hours.
Federal greenhouse gas policy remains uncertain, but new EPA policies point
toward a regulatory model rather than a cap-and-trade system.
Lower natural gas prices and lower loads have reduced greenhouse gas
emissions from the U.S. power industry by 11 percent since 2007.
The Expected Case forecasts a continuing reduction to Western Interconnect
greenhouse gas emissions due to coal plant shut downs brought on by EPA
regulations.
Coal plant shut downs have similar carbon reduction results as a cap-and-
trade market scheme, but have the advantage of not causing wholesale
market price disruptions.
Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
Marketplace
AURORAXMP is a fundamentals-based modeling tool used by Avista to simulate the
Western Interconnect electricity market. 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 240,000 MW.

Figure 7.1: NERC Interconnection Map

The Western Interconnect is separated from the Eastern and ERCOT interconnects to
the east by eight DC inverter stations. It follows operation and reliability guidelines
administered by WECC. Avista modeled the electric system as 17 zones based on load
concentrations and transmission constraints. After extensive study in prior IRPs, Avista
now models the Northwest region as a single zone because this configuration
dispatches resources in a manner more reflective of historical operations. Table 7.1
describes the specific zones modeled in this IRP.

Table 7.1: AURORAXMP Zones

Northwest- OR/WA/ID/MT Southern Idaho
COB- OR/CA Border Wyoming
Eastern Montana Southern California
Northern California Arizona
Central California New Mexico
Colorado Alberta
British Columbia South Nevada
North Nevada Baja, Mexico
Utah

Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
Western Interconnect Loads
The 2013 IRP relies on a load forecast for each zone of the Western Interconnect.
Avista uses other utilities’ resource plans to quantify load growth across the west. These
estimates include energy efficiency and demand reduction caused by current and
potential emissions legislation, and associated price increases also expected to reduce
load growth rates from their present trajectory.

Regional load growth estimates are in Figure 7.2. Avista forecasts overall Western
Interconnect loads will rise nearly 1 percent annually over the next 20 years. This is a
significant reduction in expected energy growth from the 2011 IRP’s 1.65 percent load
growth assumption. Between 2008 and 2011, actual Western U.S. electricity demand
declined by approximately 1 percent. However, loads did recover from their 2010 low of
2.6 percent below 2008 levels. The reduced energy growth projection is due to lower
estimates of economic growth combined with energy efficiency gains that have reducing
energy use. On a regional basis, the West Coast and Rocky Mountain states forecasts
lower than 1 percent growth, while the desert Southwest region continues to expect
growth in the 1 to 2 percent range. The strongest projected growth area in the region
comes from Alberta at 2.5 percent.

From a system reliability perspective, Avista expects peak loads to grow at a slower
pace than the last IRP. Northwest peak load growth rates average 0.93 percent
annually. In California, demand response and high end-use solar penetration should
reduce its system peak by 0.26 percent per year. Remaining regions should have
growth rates similar to their energy forecast.

Figure 7.2: 20-Year Annual Average Western Interconnect Energy

California
Northwest
Desert SW
Rocky Mountains
Canada
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Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
Transmission
In past IRP’s, expansion to the region’s transmission system was expected to occur in
the middle of the 20-year planning horizon. Due to changes in the marketplace, such as
lower natural gas prices and the significant reduction in the cost of solar, many
transmission projects expected in the 2011 IRP are on hold or cancelled. Remaining
transmission projects are smaller or delayed. Table 7.2 shows the regional transmission
upgrades included in this IRP. Only upgrades between modeled zones are shown, as
transmission upgrades within AURORAXMP zones are not explicitly in the model; they do
not affect power transactions between zones.

Table 7.2: Western Interconnect Transmission Upgrades Included in Analysis

Project From To Year
Available
Capacity
MW
Eastern Nevada Intertie North Nevada South Nevada 2016 1,000
Gateway South Wyoming Utah 2015 3,000
Gateway Central Idaho Utah 2015 1,350
Gateway West Wyoming Idaho 2016 1,500
SunZia/Navajo Transmission Arizona New Mexico 2017 3,000
Wyoming – Colorado Intertie Wyoming Colorado 2014 900
Hemingway to Boardman Idaho Northwest 2020 1,400

Resource Retirements
Since filing the 2011 IRP, new attention across western states is being directed to retire
aging power plants, specifically plants with larger environmental impacts, such as once-
through-cooling (OTC) in California and older coal technology throughout North
America. Recently various states, encouraged by environmentally-focused groups, are
developing rules to eliminate certain generation technologies. In California, all OTC
facilities require retrofitting to eliminate OTC technology, or must retire. Over 14,200
MW of OTC natural gas-fired generators in California are forecast to be retired and
replaced in the IRP timeframe. Remaining OTC natural gas-fired and nuclear facilities
with more favorable fundamentals are expected to be retrofitted with other cooling
technology. Many OTC plants have identified shutdown dates from their utility owners’
IRPs, and company news releases. The remaining plants are assumed to shut down
between 2017 and 2024; this retirement schedule is similar to WECC studies (see
Figure 7.3 for the retirement schedule assumed in the 2013 IRP). Elimination of OTC
plants in California will eliminate older technology presently used for reserves and high
demand hours. While replacements will be expensive for California customers, they will
be served by a more modern generation fleet.

Coal-fired facilities are also under increasing regulatory scrutiny. In the Northwest, the
Centralia and Boardman coal plants are scheduled to retire in 2020 and 2025
respectively, a reduction of 1,961 megawatts. Other coal-fired plants throughout the
Western Interconnect have announced plant closures, including Four Corners, Carbon,
Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
Arapahoe, San Juan, and Corette. Due to recent EPA standards, the IRP forecasts
additional coal-fired facility retrofits or retirements.1

Plant retirements are based on Avista analyses, considering each plant’s location, their
unit sizes and fuel costs, and their current emission control technology. Based on these
factors, Avista judges whether the plant is likely to face enough regulatory burdens to
make the plant uneconomic. It is not the intent of the IRP to include a perfect coal
retirement forecast, as this would be impossible. Instead, such analyses help Avista
understand the potential effects a reduction in coal output in the West will have on
pricing and the benefit of future resource investments by Avista. The analysis found that
12,300 MW of coal generation might shut down over the 20-year planning horizon. A
graphical representation of the retirement is in Figure 7.3.

Figure 7.3: Resource Retirements (Nameplate Capacity)

New Resource Additions
New resource capacity is required to meet future load growth and replace retiring power
plants over the next 20 years. To fill the gap, resources are added to each region to
sustain a 5 percent Loss of Load Probability (LOLP), or in other words, all system
demand must be met in 95 percent of simulated forecasts. The generation additions
must meet capacity, energy, ancillary services, and renewable portfolio mandates. To
meet future requirements, natural gas-fired CCCT or SCCT, solar, wind, coal IGCC with
sequestration, and nuclear options were considered.2 The IRP does not include new
1 A recently passed Nevada law allows NV Energy to retire its coal plants. 2 Based on analysis in Chapter 6, Generation Resource Options, solar generation in the southern states
receives a 56 percent capacity factor, while in the Northwest it would receive no peak credit. Wind
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25,000
30,000
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Natural Gas
Coal
Cumulative Retirements
Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
non-sequestered pulverized coal plants over the forecast horizon, consistent with recent
EPA new source performance standard issued in late 2012.

Many states have RPS requirements promoting renewable generation to reduce
greenhouse gas emissions, provide jobs, and diversify their energy mix. RPS legislation
generally requires utilities to meet a portion of their load with qualified renewable
resources. No federal RPS mandate exists presently; therefore, each state defines RPS
obligations differently. AURORAXMP cannot model RPS levels explicitly. Instead, Avista
inputs RPS requirements into the model at levels sufficient to satisfy state laws.

Figure 7.4 illustrates new capacity and RPS additions made in the modeling process.
Wind and solar facilities meet most renewable energy requirements. Geothermal,
biomass, and hydroelectric resources provide limited RPS contributions. Renewable
resource choices differ depending on state laws and the local availability of renewable
resources. For example, the Southwest will meet RPS requirements with solar and wind
given policy choices by those states. The Northwest will use a combination of wind and
hydroelectric upgrades because the costs of these resources are the lowest. Rocky
Mountain states will predominately meet RPS requirements with wind.

Figure 7.4: Cumulative Generation Resource Additions (Nameplate Capacity)

With lower load growth, and even with 26 GW in resource retirements, the forecast for
new resource capacity additions is lower than prior IRPs. Compared to the 2011 IRP,

receives a 5 percent capacity credit on a regional basis, but receives no capacity credit for meeting
Avista’s balancing authority requirements.
0
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Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
future natural gas capacity is down 5 GW, wind is lower by 10 GW, other renewables
are slightly lower, and solar maintains similar additions.

The Northwest market will need new capacity beginning in 2017 with the addition of
combined- or simple-cycle CTs. Based on market simulation results, a 21 percent
regional planning margin (including operating reserves) is necessary. The Northwest
likely will continue to develop wind to meet RPS requirements, with small contributions
from other renewable resources. Over the 20-year forecast, six gigawatts of new natural
gas capacity is projected, along with over seven gigawatts of new wind capacity and
one gigawatt of other renewable including solar, biomass, geothermal, and hydro.

Fuel Prices and Conditions
Fuel cost and availability are some of the most important drivers of the overall
wholesale marketplace and resource values. Some resources, including geothermal
and biomass, have limited fuel options or sources, while coal and natural gas have
more potential. Hydro, wind, and solar benefit from free fuel, but are highly dependent
on weather and limited siting opportunities.

Natural Gas
The fuel of choice for new base-load and peaking capability continues to be natural gas.
Natural gas in past years was subject to significant price volatility. Unconventional
sources have since reduced overall price levels and volatility, although it unknown how
much volatility will exist in the future market as technology plays out against regulatory
pressures and the potential for new demand created by falling prices. Avista uses
forward market prices and a combination of two December 2012 forecasts from
prominent energy industry consultants to develop its natural gas price forecast for this
IRP. The levelized nominal price is $5.62 per dekatherm at Henry Hub (shown in Figure
7.5 as the gray bars). For the first year of the forecast, forward prices are used. After the
first year, a 50/50 average of the consultant forecasts combines with the forward market
to transition from a forward pricing methodology to a fundamental price forecast, as
follows:

2015: 75 percent market, 25 percent consultant average;
2016: 50 percent market, 50 percent consultant average; and
2017-19: 25 percent market, 75 percent consultant average.

Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
Figure 7.5: Henry Hub Natural Gas Price Forecast

Natural gas market transformation has brought consultant assumptions closer together.
In previous forecasts, the Alaskan natural gas pipeline was included in many forecasts,
but is no longer included in either forecast. Growth in the residential, commercial, and
industrial markets is flat. Carbon legislation used to be included early and robust in both
forecasts, but it is now delayed and less robust. The forecast from one consultant has
muted demand growth through 2015. As domestic and global GDP growth rates
improve, demand growth begins to materialize. This growth is led by natural gas utilized
for power generation in support of renewable energy, and by coal plant retirements
caused by new EPA regulations. Additionally, widespread adoption of natural gas for
transportation and LNG exports increase demand in later years of the forecast. The
forecast from one of the consultants has growth driven almost entirely by natural gas
generation. LNG exports are also included in this forecast at a very modest level
beginning in 2018.

Price differences across North America depend on demand at the trading hubs and the
pipeline constraints between them. Many pipeline projects are in the works in the
Northwest and the West to access historically cheaper natural gas supplies located in
the Rocky Mountains. Table 7.3 presents western natural gas basin differentials from
Henry Hub prices. Prices converge over the course of the study as new pipelines and
sources of natural gas materialize. To illustrate the seasonality of natural gas prices,
monthly Stanfield price shapes in Table 7.4 show selected forecast years.

$0.00
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Forwards (Nov 2012)
Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
Table 7.3: Natural Gas Price Basin Differentials from Henry Hub

Basin 2015 2020 2025 2030
Stanfield 101% 95% 94% 96%
Malin 102% 97% 95% 98%
Sumas 96% 94% 93% 95%
AECO 90% 87% 85% 87%
Rockies 100% 92% 86% 85%
Southern CA 106% 102% 103% 106%

Table 7.4: Monthly Price Differentials for Stanfield from Henry Hub

Month 2015 2020 2025 2030
Jan 103.3% 95.3% 93.3% 94.2%
Feb 102.6% 96.1% 93.1% 94.4%
Mar 103.1% 97.8% 96.7% 98.6%
Apr 101.7% 96.8% 93.4% 96.0%
May 98.8% 94.5% 91.9% 93.9%
Jun 98.6% 94.0% 92.0% 92.9%
Jul 98.6% 93.9% 91.8% 94.4%
Aug 98.3% 93.6% 92.9% 95.1%
Sep 97.7% 93.7% 92.7% 95.2%
Oct 99.1% 94.7% 93.6% 95.9%
Nov 103.2% 98.2% 97.3% 99.0%
Dec 102.5% 96.7% 94.6% 98.1%

Unconventional Natural Gas Supplies
Shale natural gas production has game-changing impacts on the natural gas industry,
dramatically revising the amount of economical natural gas production. Shale gas can
cost less than conventional natural gas production because of economies of scale, near
elimination of exploration risks, standardization, and sophisticated production
techniques that streamline costs and minimize the time from drilling to market delivery.
Shale gas will continue to be a major factor in the natural gas marketplace, holding
down both prices and volatility over the long run as production responds to changing
market conditions. This in turn leads to numerous ripple effects, including longer-term
bilateral hedging transactions, new financing structures including cost index pricing,
and/or vertical integration by utilities choosing to limit their exposure to natural gas price
increases and volatility.

Shale gas is not without controversy. Concerns about water, air, noise, and seismic
impacts arise from unconventional extraction techniques. Water issues include
availability, chemical mixing, groundwater contamination, and disposal. Air quality
concerns stem from methane leaks during production and processing. Mitigating
excessive noise in urban drilling and potential elevated seismic activity near drilling sites
are also concerns. State and federal agencies are reviewing the environmental impacts
of this production method. As a result, unconventional natural gas production has
Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
stopped in some areas. Increased environmental protections might change costs and
environmental uncertainty could precipitate increased price volatility.

Shale gas production influences the U.S. liquid natural gas (LNG) market. It has broken
the link between North American natural gas and global LNG prices. Numerous planned
re-gasification terminals are on hold or cancelled. Some facilities are seeking approvals
to become LNG exporters rather than importers. These changes appear to affect natural
gas storage and transportation infrastructure. For example, the Kitimat LNG export
terminal in northern British Columbia, if built, will export significant LNG quantities to
Asian markets. These exports will affect overall market conditions for natural gas in the
United States and the Pacific Northwest, as British Columbia traditionally has provided
significant natural gas supplies to the northwest United States.

Coal
This IRP models no new coal plants in the Western Interconnect, so coal price forecasts
affect only existing facilities. The average annual price increase over the IRP timeframe
is 2.9 percent based on Energy Information Administration estimates for Wyoming Coal
Prices. For Colstrip Units 3 and 4, Avista used escalation rates based on expectations
from existing contracts.

Hydroelectric
The Northwest U.S., British Columbia, and California have substantial hydroelectric
generation capacity. A favorable characteristic of hydroelectric power is its ability to
provide near-instantaneous generation up to and potentially beyond its nameplate
rating. This characteristic is valuable for meeting peak load, following general intra-day
load trends, shaping energy for sale during higher-valued hours, and integrating
variable generation resources. The key drawback to hydroelectricity is its variable and
limited fuel supply.

This IRP uses an 80-year hydro record from the 2014 BPA rate case. The study
provides monthly energy levels for the region over an 80-year hydrological record
spanning 1928 to 2009. This IRP also includes BPA hydro estimates for the 80-year
record for British Columbia and California. The 80-year record is less than 1 percent
lower than the 70-year record used in previous IRPs.

Many IRP analyses use an average of the 80-year hydroelectric record; whereas
stochastic studies randomly draw from the 80-year record, as the historical distribution
of hydroelectric generation is not normally distributed. Avista does both. Figure 7.6
shows the average hydroelectric energy of 15,706 aMW in Washington, Oregon, Idaho,
and western Montana. The chart also shows the range in potential energy used in the
stochastic study, with a 10th percentile water year of 12,370 aMW (-21 percent), and a
90th percentile water year of 18,475 aMW (+18 percent).

AURORAXMP maps each hydroelectric plant to a load zone, creating a similar energy
shape for all hydro projects in a load zone. For Avista hydroelectric plants, AURORAXMP
uses the output from proprietary software with a better representation of operating
Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
characteristics and capabilities. For modeling, 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 maximizes the value of the system consistent with actual operations.

Figure 7.6: Northwest Expected Energy

Wind
Additional wind resources are necessary to satisfy renewable portfolio standards. These
additions mean significant competition for the remaining higher-quality wind sites. The
capacity factors in Figure 7.7 present average generation for the entire area, not for
specific projects. The IRP uses capacity factors from a review of the BPA and the
National Renewable Energy Laboratory (NREL) wind data.

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Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
Figure 7.7: Regional Wind Expected Capacity Factors

Greenhouse Gas Emissions
Greenhouse gas regulation is a significant risk for the electricity marketplace today
because of the industry’s heavy reliance on carbon-emitting thermal power generation.
Reducing carbon emissions at existing power plants, and the construction of low- and
non-carbon-emitting technologies, changes the resource mix over time. Since 2007,
carbon emissions from electric generation have fallen from highs by nearly 11 percent
due to reduced loads and lower coal generation levels.

Future carbon emissions could continue to fall due to fundamental market changes. To
accelerate the reductions, national legislation would be required, but this plan assumes
that no federal cap and trade regulations or carbon tax will constrain greenhouse
emissions in the IRP timeframe. However, EPA regulations aimed at reducing air
pollutants such as NOX and SO2 will have some marginal impacts on the generation
fleet profile. In the interim, California and some Canadian provinces have greenhouse
reduction goals and costs on greenhouse gas emissions. Within the Expected Case’s
market price forecast of this IRP, only existing greenhouse gas regulations and a
forecast of expected plant closures based on current EPA regulations affect the market.
No national cap and trade or carbon tax is included with the exception of a carbon-
pricing scenario discussed later in this chapter. Environmental regulations decrease or
maintain existing greenhouse gas emissions levels, instead of the cap and trade or tax
mechanisms used in Avista’s earlier IRPs.

Risk Analysis
To account for future electricity price uncertainty, a stochastic study is preformed using
the variables discussed earlier in this chapter. It is better to represent the electricity
32.0%33.5%34.5%
30.7%
37.2%38.5%
28.8%29.0%
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NW BC AB CA MT WY SW UT CO
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Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
price forecast as a range instead of a point estimate, as point estimates are unlikely to
forecast underlying assumptions perfectly. Stochastic price forecasts develop a more
robust resource strategy by accounting for tail risk. This IRP developed 500 20-year
market futures to provide a distribution of the marketplace and illustrate potential tail risk
outcomes. The next several pages discuss the input variables driving market prices,
and describe the methodology and the range in inputs used in the modeling process.

Natural Gas
Natural gas prices are among the most volatile of any traded commodity. Daily Stanfield
prices ranged between $1.72 and $13.69 per dekatherm between 2004 and 2012.
Average Stanfield monthly prices since January 2004 are in Figure 7.8. Prices retreated
from 2008 highs to a monthly price of $1.87 per dekatherm in April 2012.

Figure 7.8: Historical Stanfield Natural Gas Prices (2004-2012)

There are several methods to stochastically model natural gas prices. This IRP retains
the 2011 IRP method with the mean prices discussed in Figure 7.5 as the starting point.
Prices vary using historical month-to-month volatility and a lognormal distribution.

Figure 7.9 shows Stanfield natural gas price duration curves for 2014, 2020, 2026 and
2032. The chart illustrates a larger price range in later years, reflecting a growing
distribution. Shorter-term prices are more certain due to additional market information
and the quantity of near term natural gas trading. Another view of the forecast is in
Figure 7.10. The mean price in 2014 is $3.95 per dekatherm, represented by the
horizontal bar; the median level is $3.89 per dekatherm. The bottom and top of the bars
represent the 10th and 90th percentiles. The bar length indicates price uncertainty.
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Figure 7.9: Stanfield Annual Average Natural Gas Price Distribution

Figure 7.10: Stanfield Natural Gas Distributions

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Regional Load Variation
Several factors drive load uncertainty. The largest short-run driver is weather. Over the
long-run economic conditions, such as the Great Recession, tend to have a more
significant effect on the load forecast. IRP loads increase on average at the levels
discussed earlier in this chapter, but risk analyses emulate varying weather conditions
and base load impacts.

Avista continues to use a method it first adopted for its 2003 IRP to model weather
variation. FERC Form 714 data for the years 2007 through 2011 for the Western
Interconnect form the basis for the analysis. Correlations between the Northwest and
other Western Interconnect load areas represent how loads change together across the
larger system. This method avoids oversimplifying the Western Interconnect load
picture. Absent the use of correlation, stochastic models will offset changes in one
variable with changes in another, thereby virtually eliminating the possibility of modeling
correlated excursions actually experienced by a system. Given the high degree of
interdependency across the Western Interconnect created by significant intertie
connections, the additional accuracy from modeling loads in this matter is crucial for
understanding variation in wholesale electricity market prices. It is also crucial for
understanding the value of peaking resources and heir use in meeting system variation.

Tables 7.5 and 7.6 present the load correlations used for the 2013 IRP. Statistics are
relative to the Northwest load area (Oregon, Washington and Idaho). ―NotSig‖ in the
table indicates that no statistically valid correlation exists in the evaluated load data.
―Mix‖ indicates the relationship was not consistent across the 2007 to 2011 period. For
regions and periods with NotSig and Mix results, no correlations are modeled. Tables
7.7 and 7.8 provide the coefficient of determination values for each zone.3

Table 7.5: January through June Load Area Correlations

Area Jan Feb Mar Apr May Jun
Alberta Not Sig 17% 25% 8% Mix Mix
Arizona 8% 42% Mix Not Sig Mix Not Sig
Avista 89% 85% 84% 83% 47% 53%
British Columbia 91% 88% 71% 77% 52% 61%
California Not Sig Not Sig Mix Mix 17% 32%
CO-UT-WY -7% Mix Mix -20% -3% -17%
Montana 27% 30% 72% 63% 10% 18%
New Mexico Not Sig Not Sig Mix Not Sig Mix Mix
North Nevada 62% 27% Not Sig Not Sig Mix 18%
South Idaho 84% 79% 68% Not Sig Not Sig 29%
South Nevada 17% 56% Mix Not Sig Mix Not Sig

3 The coefficient of determination is the standard deviation divided by the average.
Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
Table 7.6: July through December Load Area Correlations

Area Jul Aug Sep Oct Nov Dec
Alberta Not Sig Mix 16% Not Sig 50% Not Sig
Arizona Not Sig Not Sig Mix Not Sig Mix Not Sig
Avista 66% 77% 68% 77% 93% 91%
British Columbia 70% 38% 19% 79% 90% 81%
California 10% Not Sig Not Sig -11% Mix Not Sig
CO-UT-WY -10% -2% -5% Not Sig 22% Mix
Montana Mix 8% 8% Not Sig 77% 73%
New Mexico Mix Mix Mix -9% Not Sig Not Sig
North Nevada 52% 44% 26% Not Sig 77% 52%
South Idaho 51% 64% Not Sig Mix 86% 89%
South Nevada Not Sig 25% Mix -8% Mix 56%

Table 7.7: Area Load Coefficient of Determination (Standard Deviation/Mean)

Area Jan Feb Mar Apr May Jun
Alberta 2.9% 2.5% 3.1% 2.6% 2.7% 3.0%
Arizona 5.1% 5.0% 3.5% 5.8% 8.6% 10.3%
Avista 6.9% 5.4% 6.3% 5.9% 5.2% 5.7%
British Columbia 4.8% 4.4% 5.1% 5.3% 5.2% 3.9%
California 5.4% 5.1% 5.3% 5.9% 7.4% 8.1%
CO-UT-WY 4.6% 4.6% 4.4% 3.7% 4.8% 7.9%
Montana 5.5% 4.4% 4.2% 4.3% 3.7% 5.9%
New Mexico 4.5% 5.0% 4.3% 4.6% 6.9% 6.7%
Northern Nevada 2.8% 3.0% 3.2% 3.2% 4.3% 5.5%
Pacific Northwest 6.7% 6.0% 5.6% 5.8% 4.7% 4.3%
South Idaho 6.0% 5.6% 5.1% 6.1% 8.3% 14.7%
South Nevada 5.0% 4.1% 3.5% 6.5% 10.7% 12.7%
Baja Mexico 5.4% 5.1% 5.3% 5.9% 7.4% 8.1%

Table 7.8: Area Load Coefficient of Determination (Standard Deviation/Mean)

Area Jul Aug Sep Oct Nov Dec
Alberta 3.1% 3.2% 2.7% 2.7% 2.9% 3.1%
Arizona 6.5% 6.7% 7.8% 9.2% 4.0% 5.0%
Avista 6.2% 7.2% 5.3% 5.4% 7.0% 6.8%
British Columbia 4.8% 4.4% 4.2% 5.0% 7.0% 5.8%
California 7.0% 7.6% 9.1% 6.7% 5.7% 5.4%
CO-UT-WY 6.7% 5.7% 5.7% 4.1% 4.6% 4.4%
Montana 5.0% 5.0% 3.6% 3.9% 5.1% 5.1%
New Mexico 5.9% 5.4% 6.0% 5.6% 4.6% 4.6%
Northern Nevada 4.7% 4.8% 4.6% 2.8% 3.7% 3.5%
Pacific Northwest 5.5% 5.6% 4.4% 5.1% 7.2% 8.0%
South Idaho 5.1% 7.0% 8.9% 5.7% 7.0% 6.1%
South Nevada 6.6% 7.2% 10.0% 8.7% 3.6% 4.2%
Baja Mexico 7.0% 7.6% 9.1% 6.7% 5.7% 5.4%
Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
Hydroelectric Variation
Hydroelectric generation is the most commonly modeled stochastic variable in the
Northwest because it has a large impact on regional electricity prices than other
variables. The IRP uses an 80-year hydro record starting with the 1928/29 water year.
Every iteration starts with a randomly drawn water year from the historical record, so
each water year is selected approximately 125 times in the study (500 scenarios x 20
years / 80 water year records). There is some debate in the Northwest over whether the
hydroelectric record has year-to-year correlation. Avista did not model year-to-year
correlation after finding a modest 35 percent correlation over the 80-year record.

Wind Variation
Wind has the most volatile short-term generation profile of any large-scale resource
presently available to utilities. Storage, apart from some integration with hydroelectric
projects, is not a financially viable alternative at this time. This makes it necessary to
capture wind volatility in the power supply model to determine its value in the wholesale
power market. Accurately modeling wind resources requires hourly and intra-hour
generation shapes. For regional market modeling, the representation is similar to how
AURORAXMP models hydroelectric resources. A single wind generation shape
represents all wind resources in each load area. This shape is smoother than it would
be for an individual wind plant, but it closely represents the diversity that a large number
of wind farms located across a zone would create.

This simplified wind methodology works well for forecasting electricity prices across a
large market, but it does not accurately represent the volatility of specific wind resources
Avista might select as part of its Preferred Resource Strategy. Therefore individual wind
farm shapes form the basis of wind resource options for Avista.

Ten potential 8,760-hour annual wind shapes represent each geographic region or
facility. Each year contains a wind shape drawn from these 10 representations. The IRP
relies on two data sources for the wind shapes. The first is BPA balancing area wind
data. The second is NREL-modeled data between 2004 and 2006.

Avista believes that an accurate representation of a wind shape across the West
requires meeting several conditions:

1. The data is correlated between areas and reflective of history.
2. Data within load areas is auto-correlated.4
3. The average and standard deviation of each load area’s wind capacity factor is
consistent with the expected amount of energy for a particular area in the year
and month.
4. The relationship between on- and off-peak wind energy is consistent with historic
wind conditions. For example, more energy in off-peak hours than on-peak hours
where this has been experienced historically.
4 Adjoining hours or groups of hours are correlated to each other.
Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
5. Hourly capacity factors for a diversified wind region are never be greater than
about 90 percent due to turbine outages and wind diversity within-area.

Absent meeting these conditions, it is unlikely any wind study provides a level of
accuracy adequate for planning efforts. The methodology developed for the 2013 IRP
attempts to adhere to the five requirements by first using a regression model based on
historic data for each region. The independent variables used in the analysis were
month, hour type (night or day), and generation levels from the prior two hours. To
reflect correlation between regions, a capacity factor adjustment reflects historic
regional correlation using an assumed normal distribution with the historic correlation as
the mean. After this adjustment, a capacity factor adjustment takes account of those
hours with generation levels exceeding a 90 percent capacity factor. The resulting
capacity factors for each region are in Table 7.9. A Northwest region example of an
8,760-hour wind generation profile is in Figure 7.11. This example, shown in blue, has a
33 percent capacity factor. Figure 7.12 shows actual 2012 generation recorded by BPA
Transmission; in 2012, the average wind fleet in BPA’s balancing authority had a 26.2
percent capacity factor.

Table 7.9: Expected Capacity factor by Region

Region Capacity
Factor
Region Capacity
Factor
Northwest 32.0% Southwest 28.9%
California 30.9% Utah 28.8%
Montana 37.2% Colorado 32.2%
Wyoming 38.5% British Columbia 33.4%
Eastern Washington 30.7% Alberta 34.5%

Figure 7.11: Wind Model Output for the Northwest Region

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Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
Figure 7.12: 2012 Actual Wind Output BPA Balancing Authority5

There is speculation that correlation exists between wind and hydro, especially outside
of the winter months where storm events bring both rain to the river system and wind to
the wind farms. This IRP does not correlate wind and hydro due to a lack of historical
wind data to test this hypothesis. Where correlation exists, it would be optimal to run the
model 80 historical wind years with matching historical water years.

Forced Outages
Generator forced outages are represented by a simple average reduction to maximum
capability in most deterministic market modeling studies. This over simplification
generally represents expected values well; however, it is better to represent the system
more accurately in stochastic modeling by randomly placing non-hydro units out of
service based on a mean time to repair and an average forced outage rate. Internal
studies show that this level of modeling detail is necessary only for natural gas-fired,
coal, and nuclear plants with generating capacities in excess of 100 MW. Plants on
forced outage smaller than 100 MW do not have a material impact on market prices and
therefore are not modeled. Forced outage rates and mean time to repair data for the
larger units in the WECC come from analyzing the North American Electric Reliability
Corporation’s Generating Availability Data System database.

Market Price Forecast
An optimal resource portfolio cannot ignore the extrinsic value inherent in its resource
choices. The 2013 IRP simulation compares each resource’s expected hourly output
using forecasted Mid-Columbia hourly prices over 500 iterations of Monte Carlo-style
scenario analysis.
5 Chart data is from the BPA at: http://transmission.bpa.gov/Business/Operations/Wind/default.aspx.
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Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
Hourly zonal electricity prices are equal to either the operating cost of the marginal unit
in the modeled zone, or the economic cost to generate and move power from one zone
to another. A forecast of available future resources helps create an electricity market
price projection. The IRP uses regional planning margins to set minimum capacity
requirements rather than simply summing of the capacity needs of individual utilities in
the region. This reflects the fact that Western regions can have resource surpluses even
where individual utilities are deficit. This imbalance can be due in part to ownership of
regional generation by independent power producers, and possible differences in
planning methodologies used by utilities in the region.

AURORAXMP assigns market values to each resource alternative available to the PRS,
but the model does not itself select PRS resources. Several market price forecasts
determine the value and volatility of a resource portfolio. As Avista does not know what
will happen in the future, it relies on risk analyses to help determine an optimal resource
strategy. Risk analysis uses several market price forecasts with assumptions differing
from the expected case, or changes the underlying statistics of a study. The modeling
splits alternate cases into stochastic and deterministic studies.

A stochastic study uses Monte Carlo analysis to quantify the variability in future market
prices. These analyses include 500 iterations of varying natural gas prices, loads,
hydroelectric generation, thermal outages, and wind generation shapes. The IRP
includes two stochastic studies—an Expected Case and a case with greenhouse gas
emissions pricing. All remaining studies were deterministic; modifying one or more key
input assumptions and using average values for the remaining variables.

Mid-Columbia Price Forecast
The Mid-Columbia is Avista’s primary electricity trading hub. The Western Interconnect
also has trading hubs at the California/Oregon Border (COB), Four Corners (corner of
northwestern New Mexico), Palo Verde (central Arizona), SP15 (southern California),
NP15 (northern California) and Mead (southern Nevada). The Mid-Columbia market is
usually the lowest cost because of the hubs dominant hydroelectric generation assets,
though other markets can be less expensive when Rocky Mountain-area natural gas
prices are low and natural gas-fired generation is setting marginal power prices.

Fundamentals-based market analysis is critical to understanding the power industry
environment. The Expected Case includes two studies. The first is a deterministic
market view using expected levels for the key assumptions discussed in the first part of
this chapter. The second is a risk or stochastic study with 500 unique scenarios based
on different underlining assumptions for natural gas prices, load, wind generation,
hydroelectric generation, forced outages, and others. Each study simulates the entire
Western Interconnect hourly between 2014 and 2033. The analysis used 25 central
processing units (CPUs) linked to a SQL server, creating over 45 GB of data in 3,000
CPU-hours.

The stochastic market average prices are similar to the results from the deterministic
model. Figure 7.13 shows the stochastic market price results as horizontal bars
Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
represent the 10th to 90th percentile range for annual prices, the circle shows the
average prices, while the triangle represents the 95th percentile. The 20-year nominal
levelized price is $44.08 per MWh. The levelized deterministic price is $0.10 per MWh
higher than the levelized stochastic price presented in Figure 7.14.

Figure 7.13: Mid-Columbia Electric Price Forecast Range
The annual averages of the stochastic case on-peak, off-peak, and levelized prices are
in Table 7.10. Spreads between on- and off-peak prices average $9.76 per MWh over
20 years. The 2011 IRP annual average nominal price was $70.50 per MWh. The
reduction in pricing is a result of lower natural gas prices, lower loads, higher
percentages of new low-heat-rate natural gas plants, and the elimination of direct
carbon pricing.

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Table 7.10: Annual Average Mid-Columbia Electric Prices ($/MWh)

Year Flat Off-
Peak
On-
Peak
2014 31.02 25.63 35.18
2015 33.06 27.57 37.17
2016 33.91 28.52 37.93
2017 34.14 28.78 38.21
2018 36.18 30.90 40.16
2019 38.29 32.99 42.17
2020 41.34 36.15 45.06
2021 43.72 38.34 47.65
2022 46.06 40.49 50.04
2023 48.85 43.29 52.92
2024 49.52 43.78 53.64
2025 49.35 43.59 53.57
2026 52.04 46.31 56.16
2027 53.37 47.60 57.70
2028 55.65 49.77 59.79
2029 57.94 51.94 62.27
2030 61.39 55.12 66.06
2031 63.06 56.48 67.96
2032 65.65 59.02 70.57
2033 66.97 60.25 71.94
Levelized 44.08 38.46 48.22

Greenhouse Gas Emission Levels
Greenhouse gas levels could increase over the study period absent regulatory policies
reversing the trend. This IRP does not include a legislative mandate to reduce
greenhouse gases in the Expected Case, such as a cap and trade program or a carbon
tax. Rather the forecast includes cap-and-trade pricing in California and power plant
shut downs due to EPA and state regulations. This IRP models the California and
Canadian carbon laws. Further discussion of carbon policy is in Chapter 4, Policy
Considerations.

Figure 7.14 shows historic and expected greenhouse gas emissions for the Western
Interconnect. Greenhouse gas emissions from electric generation decrease 10.8
percent between 2010 and 2033. The figure also includes the 10th and 90th percentile
statistics from the 500-iteration dataset. The reduction drivers are a lower load forecast
when compared to prior IRPs, lower natural gas prices, renewable portfolio standards,
and forecasted coal-fired generation retirements.

Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
Figure 7.14: Western States Greenhouse Gas Emissions

Resource Dispatch
State-level RPS goals and greenhouse gas legislation changes resource dispatch
decisions and affect future power prices. The Northwest already is witnessing the
market-changing effects of more than an 8,500 MW wind fleet. Figure 7.15 illustrates
how natural gas will increase its contribution as a percentage of Western Interconnect
generation, from 24 percent in 2014 to 41 percent 2033. The increase offsets coal-fired
generation; coal drops from 28 percent in 2014 to 15 percent in 2034. Utility-owned
solar and wind increase from 8 percent in 2014 to 11 percent by 2033. New renewable
generation sources also reduce coal generation, but natural gas is the primary resource
meeting load growth.

Public policy changes encouraging renewable energy development reduce greenhouse
gas emissions, but they also change electricity marketplace fundamentals. On the
present trajectory, policy changes are likely to move the generation fleet toward natural
gas, with its currently low but historically volatile prices. These policies will displace low-
cost coal-fired generation with higher-cost renewables and natural gas-fired generation
having lower capacity factors (wind) and higher marginal costs (natural gas). If history is
our guide, regulated utilities will recover their stranded coal plant investments from
customers, requiring customers to pay more. Further, wholesale prices likely will
increase with the effects of the changing resource dispatch driven by carbon emission
limits and renewable generation integration. New environmental policy driven
investments, combined with higher market prices, will necessarily lead to retail rates
that are higher than they otherwise would be absent greenhouse gas reduction policies.

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Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
Figure 7.15: Base Case Western Interconnect Resource Mix

Scenario Analysis
Scenario analysis evaluates the impact of specific changes in underlying assumptions
on the market, Avista’s generation portfolio, and new generation resource options’
values. In addition to the Expected Case, a stochastic greenhouse gas reduction case
was studied: the Carbon Pricing Scenario. The case is similar to the 2011 IRP Expected
Case. In addition to stochastic market scenarios, deterministic scenarios explain the
impacts of lower and higher natural gas prices and higher state RPS. Prior IRPs used
market scenarios to stress test the PRS. Since the PRS accounts for a range of
possible outcomes in its risk analysis, the market scenario section is more limited in this
IRP. Additional scenarios illustrate impacts potential future policies might have on the
industry, and how Avista could respond.

No Coal Retirement Scenario
The Expected Case price forecast includes speculative coal plant retirements based on
how Avista understands state and federal environmental policies, and the effect on
power generation in the Western Interconnect. The No Coal Retirement scenario
models the impact coal retirements might have on market prices, greenhouse gas
emissions, and the costs to meet customer load growth. In the event coal plants are not
retired, the impact on wholesale power prices is minimal. The levelized prices of power
over the 20-year period is $1.25 per MWh lower than the Expected Case (see Figure
7.16), with the largest annual price difference being 4.4 percent.

Hydro
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Avista Corp 2013 Electric IRP
Figure 7.16: Mid-Columbia Prices Comparison with and without Coal Plant Retirements

Figure 7.17 illustrates the difference between greenhouse gas emissions with and
without the coal plant retirements. Based on the model results and assumptions,
emissions would be nearly 9 percent higher in 2033 without the assumed coal plant
retirements. The coal plant retirements due to regulations has a similar greenhouse gas
reduction as a carbon tax or cap and trade scheme, but does not have a substantial
impact on market prices. With forced earlier retirement, coal plant owners will face
replacement costs up front rather the delayed until carbon prices make coal
uneconomic. As regulations continue to force coal plants to improve their environmental
footprint, lower compliance costs could take shape as engineers focus on solutions to
meet stricter guidelines to reduce air emissions.

The No Coal Retirement scenario allows an estimate of the short-term (20-year) cost of
greenhouse gas reduction. This estimate takes into account the changes to the Western
Interconnect resources’ fuel and variable O&M costs. The analysis also takes into
account capital cost changes reflecting investments in new capacity and its associated
fixed O&M costs. Based on cost changes and carbon emission reductions, the implied
2019-2033 levelized price paid to reduce carbon emissions is $95.33 per metric ton
(2014$) for the Western Interconnect.

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Figure 7.17: Western U.S. Carbon Emissions Comparison

Carbon Pricing Scenario
In Avista’s recent IRPs, the Expected Case has included explicit costs for greenhouse
gas emissions. The Expected Case in this IRP does not include these costs explicitly.
The political climate in the last several IRPs was more amenable to national
greenhouse gas policies. To understand the costs and ramifications of a national
greenhouse gas reduction policy, this scenario quantifies the potential outcomes. It
considers four potential carbon mitigation alternatives. Figure 7.18 shows each
alternative modeled as a cap and trade mechanism. Figure 7.19 shows the levelized
electric market price results of these alternatives compared to the Expected case. The
levelized costs are not substantially higher than the Expected Case, as the levelization
methodology discounts later periods where carbon policies are expected; therefore,
levelization masks future higher market prices for utility customers. Figure 7.20 shows
the annual expected greenhouse gas emissions levels for each of the policies. The four
potential outcomes represent a range of futures under different forms of greenhouse
gas emissions legislation. Over the last nine years of this study the weighted average
levelized price is $22.36 per metric ton, the high case is $55.06 and the low case is
$19.15 per metric ton.

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Figure 7.18: Greenhouse Gas Pricing Scenarios

Figure 7.19: Nominal Mid-Columbia Prices for Alternative Greenhouse Gas Policies

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Figure 7.20: Annual Greenhouse Gas Emissions for Alternative Greenhouse Gas Policies

High and Low Natural Gas Price Scenarios
The high and low natural gas price scenarios provide important information about how a
potential resource strategy might change if the natural gas prices vary substantially from
the Expected Case. They also provide an overview of how the energy market behaves
when natural gas prices vary. Over the past several years, as natural gas prices have
fallen, certain resources, such as coal, are dispatching differently. For this IRP, Avista
completed two natural gas pricing scenarios in addition to the stochastic cases. The
stochastic cases’ 500 natural gas scenarios are considered a better method to consider
the risk of price changes, but these two scenarios are useful in understanding the
fundamental market changes.

The high and low price scenarios assume prices either rise or decline up to 35 percent
relative to the Expected Case over time. The Expected Case assumes a levelized price
of $5.62 per dekatherm, while the high price scenario is $7.48. The low price scenario is
$3.97 per dekatherm. Figure 7.21 shows the resultant annual prices. The electricity
price forecast follows the general tendencies of the change in natural gas in Figure
7.22. Important to note, the implied market heat rate (IMHR) shown in Figure 7.23
changes significantly with natural gas prices. The IMHR divides natural gas prices by
electric prices and is illustrative of the market point in which a heat rate of a natural gas
facility is profitable. For example, the approximate heat rate of a CCCT is 7,000
Btu/kWh. Lower natural gas prices make operating gas plants more frequently a better
option.

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Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
Figure 7.21: Annual Natural Gas Price Forecast Scenarios

Figure 7.22: Natural Gas Price Scenario’s Mid-Columbia Price Forecasts

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Figure 7.23: Implied Market Heat Rate Changes

Increased State Renewable Portfolio Standards
Many western states have RPS requirements. As utilities reach their mandated levels of
renewables, some states have increased the goals for reasons of further reducing
energy risk, creating green jobs, and lowering carbon emissions. This scenario attempts
to address the impact of RPS legislation on the Northwest energy market. If the only
goal of the RPS is to lower carbon emissions, this method can be costly. This IRP does
not attempt to address these costs for the existing RPS rules, but rather discusses what
the costs and benefits are from additional rules.

This scenario is speculative in many ways, such as from which states an increase in
RPS levels will come from, and the type of technology used to meet the increased
goals. For this analysis, the renewable requirement increases after 2025, and focuses
on states where existing standards stop increasing in 2020. For example, this scenario
assumes Washington state increases from 15 percent to 25 percent in 2025, and
California’s increases from 33 percent to 50 percent by 2030. Other states’ increases
include Colorado, Nevada, New Mexico, and Arizona. Solar will meet much of the need
in states with increased requirements that have strong solar potential; additions beyond
the current standard could strain existing transmission systems and produce low
capacity factors. For this analysis, 7,000 MW of wind, 29,000 MW of solar and 1,000
MW of other renewable technology is added to meet the assumed higher standards of
this scenario. The net added cost to the West for these assumed law changes is $120
billion (2012$). This compares to the estimated $17 billion spent on renewable energy
investments in the Northwest to date.6
6This scenario assumes 8,500 MW of Northwest wind using an average cost of $2,000 per kW.
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Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
The market and greenhouse gas reduction benefits of the increased RPS scenario are
shown in Figure 7.24 for the years 2025 to 2033. As more solar and wind generation are
added to the system wholesale market prices are expected to decline; this scenario
shows wholesale price reductions of 3 percent to 4 percent. Overall system costs of the
Western Interconnect will not fall due to the large investment levels. The added
renewables reduce greenhouse gas emissions from the Expected Case by up to 9
percent toward the end of the study. As with the forced coal plant retirements in the
Expected Case, an assumption included in this RPS scenario as well, the higher RPS
results in an implied price for carbon. The implied cost of reduced carbon emissions for
this increased RPS scenario is $198 per metric ton. For further information on this
calculation, refer to the Expected Case analysis described on page 7.27. While added
renewables can reduce fuel costs, the incremental investments in new renewable
generation greatly overwhelms the fuel cost savings.

Figure 7.24: Changes to Mid-Columbia Prices and Western US Greenhouse Gas Levels

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Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-1

8. Preferred Resource Strategy

Introduction
The PRS chapter describes potential costs and financial risks of various resource
acquisition strategies. Further, the chapter details planning and resource decision
methods and strategies, the impact of climate change policies, and provides an
overview of alternative resource strategies.

The 2013 PRS describes a reasonable low-cost plan along the efficient frontier of
potential resource portfolios accounting for fuel supply and price risks. Major changes
from the 2011 plan include reduced energy efficiency, wind, and natural gas-fired fired
resources and, for the first time, a modest contribution from demand response. The plan
no longer calls for new renewable resources due to the recent acquisition of the 105
MW Palouse Wind Project and the recent law change allowing the Kettle Falls
Generation Station to qualify for Washington’s EIA beginning in 2016. The strategy’s
lower energy efficiency level is due to lower avoided costs, increased codes and
standards supplanting the need for utility-sponsored acquisition, and rising
implementation and verification costs associated with utility-sponsored energy efficiency
programs. The reduction in natural gas-fired resources results primarily from a lower
retail load forecast. Demand response is included because lower energy prices increase
the value of resources providing on-peak capacity.

Supply-Side Resource Acquisitions
Avista began its shift away from coal-fired resources with the sale of its 210 MW share
of the Centralia coal plant in 2000, and its replacement with natural gas-fired generation
projects. See Figure 8.1. Since the Centralia sale, Avista has made several generation
acquisitions and upgrades, including:

25 MW Boulder Park natural gas-fired reciprocating engines (2002);
Section Highlights
Avista’
size better fitting Avista’s resource deficits.
Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-2

7 MW Kettle Falls gas-fired CT (2002);
35 MW Stateline wind power purchase agreement (2004);
56 MW (total) hydroelectric upgrades (through 2012);
270 MW natural gas-fired Lancaster Generation Station power purchase
agreement (2010); and
105 MW Palouse Wind power purchase agreement (2012).

Figure 8.1: Resource Acquisition History

Resource Selection Process
Avista uses several decision support systems to develop its resource strategy, including
AURORAXMP and Avista’s PRiSM model. The AURORAXMP model, discussed in detail in
the Market Analysis chapter, calculates the operating margin (value) of every resource
option considered in each of the 500 Monte Carlo simulations of the Expected Case, as
well as Avista’s existing portfolio of generation assets. The PRiSM model helps make
resource decisions. Its objective is to meet resource deficits while accounting for overall
cost, risk, capacity, energy, renewable energy requirements, and other constraints.
PRiSM evaluates resource values by combining operating margins with capital and
fixed operating costs. The model creates an efficient frontier of resources, or the least
cost portfolios, given a certain level of risk and constraints. Avista’s management
selects a resource strategy using this efficient frontier to meet all capacity, energy, RPS,
and other requirements.

PRiSM
Avista staff developed the first version of its PRiSM model in 2002 to support resource
decision making. PRiSM uses a linear programming routine to support complex decision
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Avista Corp 2013 Electric IRP 8-3

making with multiple objectives. Linear programming tools provide optimal values for
variables, given system constraints.

Overview of the PRiSM model
The PRiSM model requires a number of inputs:
1. Expected future deficiencies
o Greater of summer 1- or 18-hour capacity
o Greater of winter 1- or 18-hour capacity
o Annual energy
o I-937 RPS requirements
2. Costs to serve future retail loads
3. Existing resource contributions
o Operating margins
o Fixed operating costs
4. Resource Options
o Fixed operating costs
o Return on capital
o Interest expense
o Taxes
o Generation levels
o Emission levels
5. Constraints
o The level of Market reliance (surplus/deficit limits on energy, capacity and
RPS)
o Resources quantities available to meet future deficits

PRiSM uses these inputs to develop an optimal resource mix over time at varying levels
of risk. It weights the first twenty years more heavily than the later years to highlight the
importance of nearer-term decisions. A simplified view of the PRiSM linear
programming objective function is below.

Equation 8.1: PRiSM Objective Function

Minimize: (X1 * NPV2014-2033) + (X2 * NPV2014-2063)

Where: X1 = Weight of net costs over the first 20 years (95 percent)
X2 = Weight of net costs over the next 50 years (5 percent)
NPV is the net present value of total system cost.1

An efficient frontier captures the optimal resource mix graphically given varying levels of
cost and risk. Figure 8.2 illustrates the efficient frontier concept. As you attempt to lower
risk, costs increase. The optimal point on the efficient frontier depends on the level of
risk Avista and its customers are willing to accept. The best point on the curve could be

1 Total system cost is the existing resource marginal costs, all future resource fixed and variable costs,
and all future energy efficiency costs and the net short-term market sales/purchases.
Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-4

where you can make small incremental cost additions for large reductions in risk.
Portfolios to the left of the curve would be more optimal, but do not meet the planning
requirements or resource constraints. Examples of these constraints are environmental
legislation cost, regulation, and the availability of commercially viable technologies
greatly limit utility-scale resource options. Further, portfolios to the right of the curve are
less efficient as they have higher costs than a portfolio with the same level of risk. The
model does not meet deficits with market purchases, or allow the construction of
resources in any incremental size.2 Instead, it uses market purchases to fill short-term
gaps and “constructs” resources in block sizes equal to the project sizes Avista could
build.

Figure 8.2: Conceptual Efficient Frontier Curve

Constraints
As discussed earlier in this chapter, reflecting real-world constraints in the model is
necessary to create a more realistic representation of the future. Some constraints are
physical and others are societal. The major resource constraints are capacity and
energy needs, Washington’s RPS, and greenhouse gas emissions performance
standard.

The PRiSM model selects from combined- and simple-cycle natural gas-fired
combustion turbines, natural gas-fired reciprocating engines, wind, solar, storage
batteries, carbon-sequestered coal, and upgrades to existing thermal and hydro
resources. Energy efficiency is a fixed input derived from an iterative process of

2 Market reliance, as identified in Section 2, is determined prior to PRiSM’s optimization.
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Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-5

developing avoided costs using PRiSM. Further, scenarios illustrate energy efficiencies’
impact on resource selections. Non-sequestered coal plants are not an option in this
IRP because Washington’s emissions performance standard bans them.3

Washington’s EIA or RPS fundamentally changed how Avista meets future loads.
Before the addition of an RPS obligation, the efficient frontier contained a least-cost
strategy on one axis, the least-risk strategy on the other axis, and all of the points in
between. Management used the efficient frontier to help determine where they wanted
to be on the cost-risk continuum. The least cost strategy typically consisted of natural
gas-fired peaking resources. Portfolios with less risk generally replaced some of the
natural gas-fired peaking resources with wind generation, other renewables, combined
cycle natural gas-fired plants, or coal-fired resources. Past IRPs identified resource
strategies including all of these risk-reducing resources. Added environmental and
legislative constraints reduce the ability of resource choices to positively impact future
costs and/or risks, at least in the traditional sense, and the requirement to procure
renewable generation resources previously were included only in lower-risk and higher-
cost portfolios. Further, these laws increase customer costs by obligating the utility to
pay for energy efficiency levels above their direct financial benefit.

Resource Deficiencies
Avista uses a single-hour and a three-day, 18-hour (6 hours each day), peak event
methodology to measure resource adequacy. The three-day 18-hour, methodology
assures our energy-limited hydro resources can meet a multiday extreme weather
event.

Avista considers the regional power surpluses consistent with the NPCC’s forecast, and
does not plan to acquire long-term generation assets while the region is significantly
surplus.

Avista’s peak planning methodology includes operating reserves, regulation, load
following, wind integration and a planning margin. Even with this planning methodology,
Avista currently projects having adequate resources between owned and contractually
controlled generation to meet physical energy and capacity needs until 2020.4 See
Figure 8.3 for Avista’s physical resource positions for annual energy, summer capacity,
and winter capacity. This figure accounts for the effects of new energy efficiency
programs on the load forecast. Absent energy efficiency, Avista would be deficient
earlier. Figure 8.3 illustrates short-term capacity needs in the winter of 2014/15 and
2015/16. This period is short-lived because a 150 MW capacity sale contract ends in
2016. Avista expects to address these short-term deficits with market purchases;
therefore, the first long-term capacity deficit begins 2020. If Avista uses a similar
planning margin in the summer as winter (14 percent plus reserves); Avista would be
deficit in the summer of 2025. Given the region has a capacity surplus in the summer;

3 See RCW 80.80. 4 See Chapter 2 for further details on this peak planning methodology.
Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-6

Avista will meet its ancillary service needs from its own portfolio, but rely on term
purchases to meet other deficits.

PRiSM selects new resources to fill capacity and energy deficits, although the model
may over- or under-build where economics support it. Because of acquisitions driven by
capacity RPS compliance, large energy surpluses result.

Figure 8.3: Physical Resource Positions (Includes Energy Efficiency)

Renewable Portfolio Standards
Washington voters approved the EIA in the November 2006 general election. The EIA
requires utilities with over 25,000 customers to meet 3 percent of retail load from
qualified renewable resources by 2012, 9 percent by 2016, and 15 percent by 2020.
The initiative also requires utilities to acquire all cost-effective energy efficiency and
energy efficiency. Avista participates in the UTC’s Renewable Portfolio Standard
Workgroup to help interpret application of this law.

Avista expects to meet or exceed its EIA requirements through the 20-year plan with a
combination of qualifying hydroelectric upgrades, the Palouse Wind project, the Kettle
Falls Generating Station and selective REC purchases. A list of the qualifying
generation projects and the associated expected output is in Table 8.1 below. The
forecast REC positions are in Figure 8.4. The flexibility included in the EIA to use RECs
from the current year, from the previous year, or from the following year for compliance
helps mitigate year-to-year variability in the output of qualifying renewable resources.

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Table 8.1: Qualifying Washington EIA Resources

Kettle Falls GS5 Biomass 1983 47.0 374,824 281,118 32.1
Long Lake 3 Hydro 1999 4.5 14,197 14,197 1.6
Little Falls 4 Hydro 2001 4.5 4,862 4,862 0.6
Cabinet Gorge 3 Hydro 2001 17.0 45,808 45,808 5.2
Cabinet Gorge 2 Hydro 2004 17.0 29,008 29,008 3.3
Cabinet Gorge 4 Hydro 2007 9.0 20,517 20,517 2.3
Wanapum Hydro 2008 0.0 22,206 22,206 2.5
Noxon Rapids 1 Hydro 2009 7.0 21,435 21,435 2.4
Noxon Rapids 2 Hydro 2010 7.0 7,709 7,709 0.9
Noxon Rapids 3 Hydro 2011 7.0 14,529 14,529 1.7
Noxon Rapids 4 Hydro 2012 7.0 12,024 12,024 1.4
Palouse Wind Wind 2012 105.0 349,726 419,671 47.9
Nine Mile 1 & 2 Hydro 2016 4.0 11,826 11,826 1.4

Figure 8.4: REC Requirements vs. Qualifying RECs for Washington State EIA

5 The Kettle Falls Generation Station becomes EIA qualified beginning in 2016. Clarification is required to
determine the amount of energy to qualify for the law (75 percent qualifying is currently assumed).
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Avista Corp 2013 Electric IRP 8-8

Preferred Resource Strategy
The 2013 PRS consists of existing thermal resource upgrades, energy efficiency,
demand response, and natural gas-fired simple- and combined-cycle gas turbines. A list
of forecast acquisitions is in Table 8.2. The first resource acquisition is 83 MW of natural
gas-fired peaking technology by the end of 2019. This resource acquisition fills the
capacity deficit created by the expiration of the WNP-3 contract with the BPA (82 MW),
the expiration of the Douglas County PUD contract for a portion of the Wells
hydroelectric facility (28 MW) and load growth. In this IRP evaluation, frame technology
SCCTs are preferred. Given the relatively small cost differences between the evaluated
natural gas-fired peaker technologies, the ultimate technology selection will be made in
a future RFP. Further, technological changes in efficiency and flexibility may mean the
Avista will need to revisit this resource choice closer to the actual need. Since the need
is six years out, Avista will not release an RFP in the next two years, but will begin a
process to evaluate technologies, and potential site locations prior, to a RFP release,
likely following the 2015 IRP.

Table 8.2: 2013 Preferred Resource Strategy

Resource By the End of
Year
Nameplate
(MW)
Energy
(aMW)
Simple Cycle CT 2019 83 76
Simple Cycle CT 2023 83 76
Combined Cycle CT 2026 270 248
Rathdrum CT Upgrade 2028 6 5
Simple Cycle CT 2032 50 46
Total 492 453
Efficiency Improvements Acquisition
Range
Peak
Reduction
Energy
(aMW)
Energy Efficiency 2014-2033 221 164
Demand Response 2022-2027 19 0
Distribution Efficiencies 2014-2017 <1 <1
Total 240 164

The next resource acquisition is another natural gas-fired peaking technology by the
end of 2023. The 2019 acquisition could increase in size to accommodate the 2023 unit,
or the 2019 site could be designed to add a second unit later. Given the length in time
for this decision, more studies will occur in the next IRP.

The proposed 270 MW CCCT is to replace the Lancaster tolling agreement expiring in
October 2026. Avista could renegotiate the current PPA or find other mutual terms to
retain the plant for customers. If Avista is not able to retain Lancaster generation, Avista
would need to build or procure a similar-sized natural gas-fired unit. The new plant size
could meet future load growth needs and could delay or eliminate the need for later two
additional resource acquisitions in this plan. Due to the uncertainty surrounding
replacing Lancaster, this IRP assumes the replacement is a new facility of similar size.
As 2026 approaches, more information and costs will be known and discussed in future
IRPs.
Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-9

The 2013 PRS is significantly different from the 2011 IRP resource strategy. The 2011
PRS is in Table 8.3. Since the prior plan, Avista’s renewable and capacity needs have
changed. First, the 2012 NW Wind need was met with the acquisition of the Palouse
Wind PPA and its subsequent commercial operation date of December 2012. Changes
in the EIA eliminated the 2019/2020 wind resource acquisition. The amendment under
SB 5575 allows the Kettle Falls Generating Station and other legacy biomass resources
to be counted as qualifying resources beginning in 2016. Previously, the EIA excluded
Kettle Falls due to its age. Another significant change from the 2011 PRS is a lower
load growth projection. Loads were expected to grow at 1.6 percent per year in the 2011
IRP. This IRP forecasts 1 percent growth (see Chapter 2, Loads and Resources). This
change in load growth delays the first natural gas-fired resource acquisition by one year
and eliminates the need for a CCCT in 2023.

Table 8.3: 2011 Preferred Resource Strategy

Resource By the End of
Year
Nameplate
(MW)
Energy
(aMW)
NW Wind 2012 120 35
Simple Cycle CT 2018 83 75
Existing Thermal Resource Upgrades 2019 4 3
NW Wind 2019-2020 120 35
Simple Cycle CT 2020 83 75
Combined Cycle CT 2023 270 237
Combined Cycle CT 2026 270 237
Simple Cycle CT 2029 46 42
Total 996 739
Efficiency Improvements Acquisition
Range
Peak
Reduction
(MW)
Energy
(aMW)
Distribution Efficiencies 2012-2031 28 13
Energy Efficiency 2012-2031 419 310
Total 447 323

Energy Efficiency
Energy efficiency is an integral part of the IRP analytical process. It also is a critical
component of the EIA, where the law requires utilities to obtain all cost effective energy
efficiency at below 110 percent of generation alternatives. Avista developed avoided
energy costs and compared those figures against a energy efficiency supply curve
developed by EnerNOC. The 20-year forecast of energy efficiency acquisitions is in
Figure 8.5. Avista plans to acquire 77 aMW of energy efficiency over the next 10 years
and 164 aMW over 20 years.6 These acquisitions will reduce system peak, shaving 104
MW from peak needs by 2023, and 221 MW by 2033. To illustrate the benefits of
energy efficiency, the before and after load forecast is shown in Figure 8.6. Prior to
energy efficiency, loads would increase at 1.7 percent per year; with energy efficiency
loads growth at 1.07 percent per year. Energy efficiency reduces load growth by 43

6 Includes savings with system losses; at the customer’s meter savings are 154 aMW.
Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-10

percent over the 20-year plan. Please refer to Chapter 3 for a more detailed discussion
of energy efficiency resources.

Figure 8.5: Energy Efficiency Annual Expected Acquisition

Figure 8.6: Load Forecast with/without Energy Efficiency

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Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-11

Demand Response
For the first time in an Avista IRP, demand response is a selected resource option in the
PRS. Demand response is selected beginning in 2022 and continuing through 2027.
Demand response could also offset part of the 2019 simple cycle resource, depending
on its achievable potential and the actual costs incurred to procure it. Demand response
will likely come from industrial and commercial customers with flexible processes; given
Avista’s limited experience with this resource, demand response research is included as
an action item for the IRP.

Distribution Feeder Upgrades
Distribution feeder upgrades entered the PRS for the first time in the 2009 IRP. The
upgrade process began with our Ninth and Central Streets feeder in Spokane. The
decision to rebuild a feeder considers energy, operation and maintenance savings, the
age of existing equipment, reliability indexes, and the number of customers on the
feeder. The driver for pursuing a feeder rebuild generally is not energy savings, but
rather system reliability. Since the 2011 IRP, several additional feeders were rebuilt.
Avista plans to rebuild 13 feeders over the next four years. A broader discussion of our
feeder rebuild program is in Chapter 5.

Simple Cycle Combustion Turbines
Avista plans to identify potential sites for new natural gas-fired generation capacity
within its service territory ahead of an anticipated need. Avista’s service territory has
areas with different combinations of benefits and costs. Locations in Washington have
higher generation costs because of natural gas fuel taxes and carbon mitigation fees.
However, there are other potential benefits of a Washington location, including proximity
to natural gas pipelines and Avista’s transmission system, lower project elevations
providing higher on-peak capacity contributions per investment dollar, and potential for
water to cool the facility. In Idaho, lower taxes and fees decrease the cost of a potential
facility, but fewer locations exist to site a facility near natural gas pipelines, fewer low
cost transmission interconnection points are available, and fewer sites have available
cooling water. The identification and procurement of a natural gas project site option will
again be an action item for this IRP. Further siting factors for consideration include
proximity to neighbors, environmental review, transmission access, pipeline access,
elevation, and water availability.

Avista is not specifying a preferred peaking technology until an RFP is completed.
Given current assumptions, the resource strategy would select a Frame CT machine.
Tradeoffs will occur between capital costs, operating efficiency and flexibility. Frame CT
machines are a lower capital cost option, but have higher operating costs and less
flexibility, while the hybrid technology has higher capital costs, lower operating costs,
and more operational flexibility. Given the hours of operating, the lowest cost option is
the less efficient and less flexible Frame CT. Increased flexibility requirements and
greenhouse gas emissions costs could make a hybrid machine preferable. If Avista
needs regulation or reserve capacity, a hybrid machine may be selected over the Frame
CT if no other opportunities were available. If greenhouse gas reductions were identified
as the only reason to choose hybrid technology, the emissions reductions would cost
Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-12

$147 per reduced metric ton of greenhouse gas emissions. The emissions reductions
will not be realized by the owning utility, but rather the power system as a whole. If
Avista selected hybrid technology over a Frame CT, the unit would run substantially
more hours than the Frame CT causing utility emissions to increase, but regional
emissions to slightly decrease because of the higher efficiency of the hybrid machine.
Avista plans to study the tradeoffs of peaking technology in the next IRP.

Greenhouse Gas Emissions
Chapter 7, Market Analysis, discusses how greenhouse gas emissions decrease due to
coal plant closures because of EPA and state regulations. Avista’s resource mix does
not include any retirements due to current or proposed environmental regulations. The
only significant lost resource with carbon emissions is the expiration of the Lancaster
PPA in 2026, but it will be replaced to maintain system reliability and stabilize rates.
Figure 8.7 presents Avista’s expected greenhouse gas emissions (excluding Kettle Falls
Generating Station) with the addition of PRS resources. Emissions should not change
significantly prior to 2019 other than from year-to-year fluctuations resulting from
periodic maintenance outages, market fluctuations, and regional hydroelectric
generation levels. Beginning in 2019 additional emissions will occur from new peaking
resources, but these resources will not affect overall emissions levels much due to low
projected runtime hours. The estimates in Figure 8.6 do not include emissions from
purchased power or a reduction in emissions for off-system sales. Avista expects its
greenhouse gas emissions intensity from owned and controlled generation to fall from
0.35 short tons per MWh to 0.32 short tons per MWh with the current resource mix and
the new generation identified in the PRS.

Figure 8.7: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions

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Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-13

Capital Spending Requirements
One of the major assumptions in this IRP is Avista will finance and own all new
resources. Using this assumption, and the resources identified in the 2013 PRS, the first
capital addition to rate base is in 2020 for the first natural gas-fired peaker. The
development is likely to begin multiple years earlier but would likely enter rate base
January 1, 2020. Avista may begin making major capital investments for the addition in
2017. The capital cash flows in Table 8.4 include AFUDC, transmission investments for
generation, and account for tax incentives, and sales taxes. Over the 20-year IRP
timeframe, a total of $782 million (nominal) in generation and related transmission
expenditure is required to support the PRS. The capital investment projection does not
include any capital to exercise the Palouse Wind PPA purchase option.

Table 8.4: PRS Rate Base Additions from Capital Expenditures
(Millions of Dollars)

Year Investment Year Investment
2014 0.0 2024 91.6
2015 0.0 2025 0.0
2016 0.0 2026 0.0
2017 0.0 2027 421.7
2018 0.0 2028 97.0
2019 0.0 2029 2.4
2020 85.8 2030 0.0
2021 0.0 2031 0.0
2022 0.0 2032 0.0
2023 0.0 2033 83.6
2014-23 Total 85.8 2024-33 Totals 696.2

Annual Power Supply Expenses and Volatility
PRS variance analysis tracks fuel, variable O&M, emissions, and market transaction
costs for the existing resource portfolio for each of the 500 Monte Carlo iterations of the
Expected 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 of potential costs
to serve future loads. Figure 8.8 shows expected PRS costs through 2033 as the blue
bar (nominal dollars). In 2014, costs are expected to be $24 per MWh. The chart shows
costs with a range of two sigma. The lower range is represented by yellow diamonds
($19 per MWh in 2014) and the upper range is shown with orange dots ($28 per MWh in
2014). The main driver increasing power supply costs and volatility in future years is
natural gas prices and weather (hydro and load variability), Avista increases the
volatility assumption of natural gas prices in the future as the commodity price has many
unknown future risks and has a history of volatility.

A common IRP question is what will be the change to power supply costs over the time
horizon of the plan. Figure 8.9 shows total portfolio costs, but does not account for
future load growth that would offset much of the increase as viewed from a customer bill
Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-14

perspective. Figure 8.9 illustrates expected PRS power supply cost changes compared
to historical power supply costs, and provides a representation more correlated to future
customer bills. Power supply costs, on a per-MWh basis, have increased 2.3 percent
per year over inflation between 2002 and 2012. In the next 10 years power supply costs
are forecast to fall from 2012 levels if expected energy prices come to fruition along with
cost reductions from increased renewable energy credit sales, reduced energy
efficiency costs, and consideration of 23 months of increased revenues from a power
sale contract with Portland General Electric.7

Figure 8.8: Power Supply Expense Range

7 Since 1998, the capacity payments paid by Portland General Electric to Avista were monetized.
Beginning February 2014, the capacity payments will be paid to Avista and reduce power supply costs.
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Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-15

Figure 8.9: Real Power Supply Expected Rate Growth Index $/MWh (2012 = 100)

Near Term Load and Resource Balance
Under Washington regulation (WAC 480-107-15), utilities having supply deficits within
three years of an IRP filing must file a RFP with the WUTC. The RFP is due to the
WUTC no later than 135 days after the IRP filing. After WUTC approval, bids to meet
the anticipated capacity shortfall must be solicited within 30 days.

Tables 8.16 and 8.17, shown later in this section, detail Avista’s capacity position over
the IRP timeframe. With a portion of loads met by Avista’s share of the regional capacity
surplus, Avista does not require winter capacity until 2019. Simplified summaries for the
near-term are displayed below in Tables 8.5 and 8.6. They show short-term capacity
deficits met by market transactions in 2015 and 2016. Avista’s short positions are short
lived as a 150 MW capacity sale to Portland General Electric expires at the end of 2016.
As part of the IRP Action Items, Avista will develop a short-term capacity position report
to monitor capacity requirements.

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Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-16

Table 8.5: Avista Medium-Term Winter Peak Hour Capacity Tabulation

2014 2015 2016 2017
Load Obligations 1,665 1,683 1,700 1,713
Other Firm Requirements 211 158 158 8
Reserves Planning 359 366 369 362
Total Obligations 2,235 2,206 2,227 2,084

Firm Power Purchases 117 117 117 117
Owned & Contracted Hydro 998 888 889 955
Thermal Resources 1,137 1,137 1,137 1,137
Wind (at Peak) 0 0 0 0
Total Resources 2,252 2,143 2,143 2,210

Net Position 17 -64 -84 126

Short Term Market Purchase 0 75 100 0
Net Position 17 11 16 126

Table 8.6: Avista Medium-Term Summer 18-Hour Sustained Peak Capacity Tabulation

2014 2015 2016 2017
Load Obligations 1,465 1,482 1,498 1,510
Other Firm Requirements 212 159 159 9
Reserves Planning8 0 0 0 0
Total Obligations 1,677 1,641 1,657 1,519

Firm Power Purchases 29 29 29 29
Owned & Contracted Hydro 701 707 663 631
Thermal Resources 961 961 961 961
Wind (at Peak) 0 0 0 0
Total Resources 1,691 1,698 1,653 1,621

Net Position 14 57 -3 102

Short Term Market Purchase 0 0 25 0
Net Position 14 57 22 102

Efficient Frontier Analysis
Efficient frontier analysis is the backbone of the PRS. The PRiSM model develops the
efficient frontier by simulating the costs and risks of resource portfolios using a mixed-
integer linear program. PRiSM finds an optimized least cost portfolio for a full range of
risk levels. The PRS analyses examined the following portfolios.

8 Due to the sustained peak planning methodology, hydroelectric capacity exceeding sustained maximum
capability is used for operating and control area reserves.
Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-17

Market Only: Meets all resource deficits with spot market purchases. The
portfolio is least cost from a long-term financial perspective, but has the highest
level of risk. The strategy fails to meet capacity, energy, and RPS requirements
with Avista-controlled assets.
Least Cost: Meets all capacity, energy and RPS requirements with the least-cost
resource options. This portfolio ignores power supply expense volatility in favor of
lowest-cost resources.
Least Risk: Meets all capacity, energy and RPS requirements with the least-risk
mix of resources. This portfolio ignores the overall cost of the selected portfolio in
favor of minimizing portfolio volatility (risk).
Efficient Frontier: Meets all capacity, energy and RPS requirements met with
sets of intermediate portfolios between the least risk and least cost options.
Given the resource assumptions, no resource portfolio can be at a better cost
and risk combination than these portfolios.
Preferred Resource Strategy: Meets all capacity, energy and RPS
requirements while recognizing both the overall cost and risk inherent in the
portfolio. Avista’s management chose this portfolio as the most reasonable path
to follow given current information.

Figure 8.10 presents the Efficient Frontier. The x-axis is the levelized nominal cost per
year for the power supply portfolio, including capital recovery, operating costs, and fuel
expense; the y-axis displays the standard deviation of power supply costs in 2028. The
year 2028 is far enough out to account for the risk tradeoffs of several resource
decisions. If a near term year was selected to measure risk, there would be too few new
resource decisions available to distinguish between portfolios. It is necessary to move
far enough into the future so load growth provides PRiSM the opportunity to make new
resource decisions. By choosing a year later in the planning horizon, relevant resource
decisions can be studied.

Avista is not choosing to pursue the least cost strategy, as it relies exclusively on
natural gas-fired peaking facilities. This strategy would include more market risk than
exists in the portfolio today because the portfolio would trade the Lancaster (CCCT
plant) for a SCCT. The PRS instead diversifies Avista’s resource mix with peaking and
combined-cycle natural gas-fired plants. Further, based on an analysis of the efficient
frontier, the additional cost of this strategy is near zero (0.1 percent) on an NPV basis
and reduces market risk by 11 percent. Table 8.7 shows a sampling of portfolios along
the efficient frontier with the costs, risks, and carbon emissions described.

Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-18

Figure 8.10: Expected Case Efficient Frontier

Table 8.7: Efficient Frontier Sample Resource Mixes

Nameplate (MW) PRS Low
Cost
Medium
High
Risk
Medium
Risk
Medium
Low
Risk
Low
Risk
Combined Cycle CT 270 - 270 270 540 540
Natural Gas-Fired Peaker 299 566 296 216 100 68
Wind - - - 30 50 350
Solar - - - - - -
Biomass - - - - - 50
Coal (sequestered) - - - - - -
Hydro Upgrade - - - - - -
Thermal Upgrade 6 6 6 85 85 80
Demand Response 19 20 20 8 12 17
Total (excluded efficiency) 594 592 592 609 788 1,104

Power Supply Revenue Requirement Cost Metrics (Millions)
20-yr Levelized Cost $358.4 $357.9 $357.9 $362.3 $367.0 $396.0
2028 Power Supply Std Dev $65.7 $74.0 $64.4 $60.5 $54.1 $40.2
2033 GHG Emissions
(millions of metric tons)
3.2 2.9 3.4 3.4 3.9 3.8
$20 Mil
$30 Mil
$40 Mil
$50 Mil
$60 Mil
$70 Mil
$80 Mil
$325 Mil $350 Mil $375 Mil $400 Mil $425 Mil $450 Mil
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Market Only
Least Cost
Least Risk
Preferred Resource Strategy
Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-19

Determining the Avoided Costs of Energy Efficiency
The efficient frontier methodology determines the avoided cost of the new resource
additions included in the PRS. There are two avoided cost calculations for this IRP: one
for energy efficiency and one for new generation resources. The energy efficiency
avoided cost is higher because it includes various benefits beyond generation resource
value, as detailed in Table 8.8.

Avoided Cost of Energy Efficiency
Three portfolios are required to derive the supply-side cost components of the avoided
cost for energy efficiency calculations. The differences between each portfolio sum to
the avoided cost of energy efficiency:

Commodity Energy (Market Only): This resource portfolio includes no new
resource additions and the incremental cost of new power supply is the cost
to buy power from the short-term market. These prices used are determined
from the long-term energy price forecast discussed in Chapter 7.
Capacity: This resource portfolio builds a least-cost strategy to meet peak
demand. The difference between the Commodity Energy and Capacity
strategies equals the capacity value of the new resources. This estimate
typically shows the incremental cost divided by the incremental kilowatts of
installed capacity. For this example the $/kW adder is translated to $/MWh
assuming a flat energy delivery.
Pre-Preferred Resource Strategy: This resource portfolio is similar to the
PRS resource mix, but it assumes Avista does no further energy efficiency.

The avoided cost of energy efficiency includes the various components of avoided cost
only in those periods where Avista is deficit. For example, the avoided costs of energy
efficiency programs only include a capacity value in the years where Avista has capacity
needs. Further, the commodity component applies to each energy efficiency program
depending on the expected timing of its energy delivery. For example, an air
conditioning program receives an energy value based on expected savings in the
summer months when actual energy savings occur.

The EIA requires avoided costs used for energy efficiency to be increased by 10
percent to incent energy efficiency acquisition in the IRP. Additionally, reduced
transmission and distribution losses, and operations and maintenance are credited in
the avoided cost of energy efficiency. The following formula details the avoided cost for
energy efficiency measures.

Equation 8.2: Energy Efficiency Avoided Costs

{(E + PC + R) + (E * L) + DC)} * (1 + P)
Where:
E = Market energy price. The price calculated with AURORAXMP is $44.08
per MWh.
Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-20

PC = New resource capacity savings. This value is calculated using
PRiSM and is estimated to be $11.74 per MWh.
R = Risk premium to account for RPS and rate volatility reductions. This
PRiSM-calculated value is $1.89 per MWh.
P = Power Act preference premium. This is the additional 10 percent
premium given as a preference towards energy efficiency measures.
L = Transmission and distribution losses. This component is 6.1 percent
based on Avista’s estimated system average losses.
DC = Distribution capacity savings. This value is approximately $10/kW-
year or $1.35 per MWh.

Table 8.8 estimates the levelized avoided cost for a theoretical energy efficiency
program reducing load by one megawatt each hour of the year:

Table 8.8: Nominal Levelized Avoided Costs of the PRS ($/MWh)

2014-2033
Energy Forecast 44.08
Capacity Value 11.74
Risk Premium 1.89
Transmission & Distribution Losses 2.69
Distribution Capacity Savings 1.35
Power Act Premium 6.17
Total 67.92

Determining the Avoided Cost of New Generation Options
Avoided costs change as new information becomes available, including changes to
market prices, loads, and resources. Therefore, the estimates in Table 8.9 must be
updated at the time a new resource is evaluated. Table 8.9 shows the avoided costs
derived from the Preferred Resource Strategy. These prices represent the value of
energy from a project making equal deliveries over the year in all hours. In this case, a
new resource (such as PURPA qualifying project) would not qualify for capacity
payments until 2020, because Avista does not need capacity resources until then.

Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-21

Table 8.9: Updated Annual Avoided Costs ($/MWh)

Year Energy Capacity Risk Total
2014 31.02 0.00 0.00 31.02
2015 33.06 0.00 0.00 33.06
2016 33.91 0.00 0.00 33.91
2017 34.14 0.00 0.00 34.14
2018 36.18 0.00 0.00 36.18
2019 38.29 0.00 0.00 38.29
2020 41.34 15.15 0.56 57.06
2021 43.72 15.77 0.59 60.08
2022 46.06 16.41 0.61 63.09
2023 48.85 17.08 0.64 66.57
2024 49.52 17.78 0.66 67.96
2025 49.35 18.50 0.69 68.54
2026 52.04 19.26 0.72 72.01
2027 53.37 20.04 0.75 74.16
2028 55.65 20.86 0.78 77.29
2029 57.94 21.71 0.81 80.46
2030 61.39 22.59 0.84 84.82
2031 63.06 23.51 0.87 87.44
2032 65.65 24.47 0.91 91.03
2033 66.97 25.47 0.95 93.38

Efficient Frontier Comparison of Greenhouse Gas Policies
In addition to the stochastic Expected Case, Avista evaluated a National Climate
Change policy scenario. Several hypothetical climate change policies are included in
the 500 Monte Carlo market futures to capture the range of policy alternatives (see
Chapter 7, Market Analysis for further detail). Given the higher market prices resulting
from climate legislation, 20.5 aMW of additional energy efficiency would be acquired
over the IRP period, a 12.5 percent increase. The cost of this incremental energy
efficiency is 37 percent higher than in the Expected Case.

Except for increased energy efficiency, the PRS under the National Climate Change
policy remains similar to the Expected Case’s strategy. Somewhat surprisingly, this
scenario increases the total resource build, but natural gas-fired frame peaking
resources are replaced with hybrid CTs. This change reflects the increasing margin of
lower heat rate machines. A detail of the Least Cost strategy, and the likely PRS, under
a National Climate Change policy is in Table 8.10.

Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-22

Table 8.10: Alternative PRS with National Climate Change Legislation

Resource By the End of
Year
Nameplate
(MW)
Energy
(aMW)
Simple Cycle CT 2019 92 85
Simple Cycle CT 2024 92 85
Combined Cycle CT 2026 270 248
Rathdrum CT Upgrade 2024 6 5
Simple Cycle CT 2032 92 85
Total 552 508
Efficiency Improvements By the End of
Year
Peak
Reduction
Energy
(aMW)
Energy Efficiency 2014-2033 249 185
Demand Response 2022-2027 5 0
Distribution Efficiencies 2014-2017 <1 <1
Total 254 185

Figure 8.11 illustrates the efficient frontier in the Expected Case and a case with
National Climate Change legislation. With climate change legislation, the cost curve
moves to the right, showing increased customer costs. The curve also shows lower risk,
because higher risk resources, such as frame CTs, are no longer the least cost
resource. The most cost effective resource shifts from frame CTs to hybrid CTs. A
carbon-pricing regime would also increase the amount of energy efficiency pursued by
Avista. Figure 8.11 shows this efficient frontier in orange. The higher avoided cost of the
national climate change policy increases the amount of energy efficiency, thereby
reducing risk through lower loads, but with increased costs.

The lesson learned from this scenario is the utility’s cost and financial risk increases. If
climate policies were enacted, Avista likely would acquire more energy efficiency. This
additional energy efficiency would reduce risk, but at overall higher costs. In reality, if
this legislation is passed, a new portfolio would be developed to select resources better
suited to a carbon-restricted environment; in this case, Frame CT’s are traded for hybrid
CTs, lowering risk and lowering cost. Table 8.11 summarizes these cost and risk
changes. Since Avista’s resource need is at the end of the decade, Avista is able to
postpone its technology decision until closer to the time of need.

Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-23

Figure 8.11: Efficient Frontier Comparison

Table 8.11: Preferred Portfolio Cost and Risk Comparison (Millions $)

Portfolio 20-Yr Power Supply Levelized Cost
Expected Case Carbon Pricing
Scenario
PRS 358.4 367.3
PRS w/ Higher Efficiency 365.0 377.8
Climate Scenario- PRS 364.7 374.5
Portfolio 2028 Power Supply Cost Standard
Deviation
Expected Case Carbon Pricing
Scenario
PRS 65.7 72.6
PRS w/ Higher Efficiency 63.9 70.3
Climate Scenario- PRS 61.0 63.6

Energy Efficiency Scenarios
Due to the complexities introduced by EIA, energy efficiency is not directly modeled in
PRiSM. Instead, it is separately modeled using the avoided costs discussed above.
Avista has found this method of determining energy efficiency investments is robust.
$25 Mil
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PRS (Expected Case)
PRS-(Carbon Pricing)
PRS-Higher Conservation
(Carbon Pricing)
Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-24

Refer to Figure 8.12 for an illustration of this point. This figure demonstrates the
changes in risk and cost from the point of view of the PRS and the efficient frontier.

Under current Washington rules, Avista must acquire all cost effective energy efficiency
up to 110 percent of the avoided cost. Energy efficiency resources are oversubscribed
compared to alternative generating resource options. To illustrate this concept, a
portfolio acquiring energy efficiency up to 100 percent of avoided costs is shown as a
“light blue dot”. This portfolio adds 154 aMW of energy efficiency (rather than the 168
aMW from the PRS shown as the “green diamond”). This portfolio illustrates power
supply costs would be 2.7 percent lower and risk would be 0.3 percent higher if the
utility could select this portfolio. This portfolio does not appear on the efficient frontier
and is considered more optimal than any portfolio on the efficient frontier as it is to the
left of the valid portfolio options, but is an invalid option due to the EIA requirement to
over-invest in energy efficiency. A scenario acquiring energy efficiency to a level more
consistent with its true contribution to the portfolio likely would lower costs.

If Avista did not acquire any energy efficiency, total power supply costs and risks would
increase. This portfolio, shown as a dark orange dot, is 8.6 percent more expensive
than the PRS and has 20 percent more risk. This confirms energy efficiency is an
effective tool to lower costs and risks, but must be properly balanced to achieve optimal
benefits for customers.

Three additional studies illustrating the effect of acquiring energy efficiency beyond 110
percent of cost effectiveness. These portfolios are shown as an orange dot for 125
percent of avoided costs and as a light orange dot for 150 percent of avoided cost in
Figure 8.12. These options add 3.6 percent and 8.6 percent to the power supply costs
and reduce volatility by 2.9 percent and 5.0 percent respectively. The light blue dot
shows the 100 percent of avoided costs case. The efficient frontier illustrates these risk
reductions are achievable at lower cost by acquiring generation instead of energy
efficiency resources. Further information on the energy efficiency analysis is in Chapter
3, Energy Efficiency. Table 8.12 captures the resource selection of each of these
portfolios, the costs, risks and carbon emissions.

Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-25

Figure 8.12: Efficient Frontier Comparison

Table 8.12: Preferred Portfolio Cost and Risk Comparison for Avoided Cost Studies

Nameplate (MW) 75% 100% PRS 125% 150% 0%
Combined Cycle CT 270 270 270 270 270 270
Natural Gas-Fired Peaker 313 316 299 271 228 481
Wind - - - - - -
Solar - - - - - -
Biomass - - - - - -
Coal (sequestered) - - - - - -
Hydro Upgrade - - - - - 68
Thermal Upgrade 6 - 6 6 6 -
Energy Efficiency (aMW) 139 154 164 185 201 -
Demand Response 20 19 19 20 20 20
Total 748 748 758 752 725 839

20-year Levelized Cost
(millions)
$346.1 $349.5 $354.8 $363.7 $371.3 $389.1
2028 Power Supply Stdev
(millions)
$67.7 $66.0 $65.7 $63.8 $62.4 $79.2
2033 Greenhouse Gas
Emissions (millions of
metric tons)
3.2 3.2 3.3 3.2 3.1 3.2
-70%
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Efficient Frontier
PRS
75% AC
100% AC
125% AC
150% AC
No Conservation
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Avista Corp 2013 Electric IRP 8-26

Colstrip
Coal-fired generation has been the target of increased regulatory and legal attention.
Colstrip is a four unit coal-fired plant jointly owned by Avista, NorthWestern Energy,
PacifiCorp, PPL- Montana, Portland General Electric, and Puget Sound Energy. Avista’s
share of the plant is 15 percent of Units 3 and 4, or 222 MW. Units 3 and 4 are newer
and larger technology than Units 1 and 2. Avista has no ownership interest in Units 1 or
2 at Colstrip.

As part of the 2011 IRP acknowledgement, the UTC requested that Avista study two
Colstrip scenarios. The first scenario is a cost and utility impact if Colstrip is not part of
Avista’s resource portfolio. The second case examines the costs and utility impacts on
Colstrip (Units 3 and 4) from additional environmental controls to meet potential new
rules from the EPA. These portfolio scenarios are studied in the Expected Case and the
Carbon Pricing scenarios.

No Colstrip Resource Strategy Scenario
In the scenario where Colstrip Units 3 and 4 are no longer resources for Avista
customers, Colstrip exits the portfolio at the end of 2017. This case focuses on the costs
and risk to replace its capacity and energy, not the revenues from a sale of the asset or
the cost of reclamation. Table 8.13 shows an alternative PRS excluding Colstrip Units 3
and 4. The major difference between a portfolio with and without Colstrip is the addition
of a CCCT to replace Colstrip Units 3 and 4 in 2017; the remaining portfolio is very
similar to the Expected Case PRS.

Table 8.13: No Colstrip Resource Strategy Scenario

Resource By the End
of Year
Nameplate
(MW)
Energy
(aMW)
Combined Cycle CT 2017 270 248
Simple Cycle CT 2020 50 46
Simple Cycle CT 2023 50 46
Combined Cycle CT 2026 270 248
Simple Cycle CT 2026 51 47
Simple Cycle CT 2029 55 51
Simple Cycle CT 2032 50 46
Total 797 733
Efficiency Improvements By the End
of Year
Peak
Reduction
Energy
(aMW)
(MW)
Energy Efficiency 2014-2033 221 164
Demand Response 2022-2027 20 0
Distribution Efficiencies 2014-2017 <1 <1
Total 241 164

Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-27

Removing Colstrip Units 3 and 4 from Avista’s resource portfolio has a large impact on
portfolio costs. Figure 8.13 illustrates the cost impact. In the Expected Case, the present
value of added cost is $505 million or $52.4 million per year levelized. This is 12.8
percent higher than the PRS (includes Avista’s Colstrip generation). Greenhouse gases
decrease by 1.2 million short tons in 2018 and one million tons on average over the 16
years of the study, as shown in Figure 8.14.9 The average greenhouse gas reduction
cost Avista customers is $45 per metric ton (levelized).

Using the carbon-pricing scenario, levelized costs increase by $47.2 million or 10.9
percent per year. In any case evaluated, removing Colstrip Units 3 and 4 from Avista’s
resource portfolio creates significantly higher customer costs. To understand the annual
impact to power supply expense and risk, Figure 8.15 shows the Expected Case cost
difference without Colstrip, and two-sigma tail risk. In the first year, Power Supply Costs
are expected to be over $60 million higher than with the plant, and slowly fall as the
substitute plant is depreciated. Another way to look at the increased costs without
Colstrip Units 3 and 4 is in Figure 8.16. This figure shows the power supply cost index
from earlier in this chapter and includes the no-Colstrip scenario.

Figure 8.13: 2018-33 Power Supply Costs with and without Colstrip Units 3 and 4

9 This figure does not include the carbon neutral emissions from Kettle Falls.
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Carbon Pricing
Scenario-RS w/o
Colstrip
Carbon Pricing
Scenario-LC RS
w/ Colstrip
Expected Case-
No Colstrip RS
Expected Case-
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Figure 8.14: Greenhouse Gas Emissions without Colstrip Units 3 and 4

Figure 8.15: Change to Power Supply Cost without Colstrip

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Avista Corp 2013 Electric IRP 8-29

Figure 8.16: Change to Power Supply Cost without Colstrip

Environmental Control Review
There are potential costly regulations Colstrip Units 3 and 4 could face over the next 20
years of this resource plan if state or federal agencies promulgate new coal-fired
generation environmental regulations. This section identifies anticipated regulations the
EPA could establish over the time horizon of this plan based on information available
during the development of this plan. The President’s Climate Action Plan was released
after the analysis for this IRP was completed, but details about the plan are in Chapter
4, Policy Considerations. Avista will monitor and review implications of the plan as they
develop. This discussion is speculative unless otherwise noted and only pertain to
Colstrip Units 3 and 4. The following section discusses four main areas of possible new
environmental regulations.

Hazardous Air Pollutants
MATS is for the coal and oil-fired source category. For Colstrip Units 3 and 4, existing
emission control systems should be sufficient to meet MATS limitations.

Coal Ash Management/Disposal
Avista does not anticipate a significant change in operation at Colstrip Units 3 and 4 due
to coal ash management or disposal issues at this time.

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Avista Corp 2013 Electric IRP 8-30

Effluent Discharge Guidelines
Avista does not anticipate a significant change in operation at Colstrip Units 3 and 4 due
to coal ash management or disposal issues at this time because it is a zero discharge
facility managing wastewater onsite.

Regional Haze Program
Colstrip Units 3 and 4 will be evaluated for reasonable progress on approximately 10-
year intervals going forward. Avista anticipates Nitrous Oxides (NOX) emission controls
could be required in 2027. The cost to comply with this potential regulation is unknown
due to technology changes potentially on the horizon to reduce NOX emissions. In order
to understand this regulation if imposed on Colstrip Units 3 and 4 using existing
technology, a study was completed and submitted to EPA in 2010.

This study evaluates whether or not the cost of installing this existing technology would
have an impact on the ongoing operations of the Colstrip Units 3 and 4. The study
estimated the cost of a SCR NOX control to be $280 million per unit (2011 dollars);
Avista chose to increase these estimates by 25 percent to account for potential retrofit
costs. Further, Avista believes these control costs are on the high end of the cost range.
In this case, Avista’s share of this cost for both units would be $105 million in capital,
and about $560,000 in annual O&M (2014$). Over the life of this technology, the
levelized cost of the controls is $8.39 per MWh (2014 dollars nominal). Further analysis
is in Figure 8.17. This chart illustrates three scenarios for the two market price forecasts
(Expected Case and Carbon Pricing Scenario). The results shown in the Expected
Case’s removal of Colstrip Units 3 and 4 from the portfolio adds $34 million or (6.1
percent) to power supply costs compared to installing the SCR controls scenario. In the
Carbon Pricing Scenario, $25 million per year is added or 4.3 percent per year without
Colstrip Units 3 and 4 compared to installing the SCR. Based on this study using high
cost to comply with potential regional haze regulation costs, Colstrip Units 3 and 4
remain a viable and cost-effective resource for Avista’s customers.

Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-31

Figure 8.17: Annual Levelized Cost (2027-33) of Colstrip Scenarios

Other Portfolio Scenarios
Avista examined a number of possible policy outcomes affecting future resource
selection. These scenarios review how Avista’s resource strategy might change in
response to new policies

Higher Washington RPS
Avista’s current resource mix fully meets the EIA, but it is possible new legislation or a
citizen’s initiative could increase the renewable goals further. This scenario
contemplates this change to understand the resulting cost, risk, and emissions impacts.
The scenario assumes an additional step in the renewable goal of 25 percent of
Washington retail sales to be from qualified renewables. Such a goal would require
Avista to add 77 aMW of qualified renewables beyond the present plan. The PRiSM
model found the most cost-effective method to meet this requirement, with a similar risk
profile to the PRS would be Spokane River hydroelectric upgrades. Both Long Lake (68
MW) and Monroe Street (55 MW) second powerhouse additions would meet the
renewable requirement if they were certified as EIA-qualifying resources. The addition
of these upgrades would prevent the final natural gas peaking resource from being
required in the PRS. While the 20-year levelized cost is slightly higher than the PRS, the
costs between 2025 and 2033 are $18 million levelized higher, or 3.5 percent.

$549
$574
$608
$587
$612
$637
$400 Mil
$500 Mil
$600 Mil
$700 Mil
PRS PRS_SCR No Colstrip LC LC_SCR No Colstrip
Expected
Case
Expected
Case
Expected
Case
Carbon
Pricing
Scenario
Carbon
Pricing
Scenario
Carbon
Pricing
Scenario
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Avista Corp 2013 Electric IRP 8-32

National RPS
Over the past several years, several bills have proposed national RPS legislation. This
legislation has not been enacted, but is a potential future scenario to understand.
Differences in the proposals have ranged from the type of resources qualifying for the
RPS, percentages and timing of renewables required, and hydroelectric netting.10 For
the National RPS scenario, Avista assumes a 20 percent renewable standard with
hydroelectric generation (existing or new) netted from load. Given these assumptions,
78 aMW of renewables would be required by the end of this plan. The hydro netting
provision would have an impact on how Avista would meet this potential law. As shown
in the higher Washington RPS scenario hydro upgrades were selected in the national
RPS scenario. If the hydro netting provision counted hydro upgrades as a load
reduction rather than a qualifying renewable resource, the hydro upgrades would need
to be replaced by new wind generation.

Higher Capacity Planning Margins
This IRP uses a 14 percent planning margin (plus operating reserves) above the winter
peak load forecast. Planning margins are not necessarily a precise target and there is
no universally accepted standard. To increase reliability, and to protect Avista’s
customers from the potential of regional power shortages, a higher planning margin
standard could be implemented. This scenario increases the planning margin to 20
percent, or an additional 117 MW by the end of plan. In addition to requiring more
capacity on the planning horizon, Avista’s first-year deficit would occur earlier in 2016.

2011 IRP Preferred Resource Strategy
This scenario illustrates the impacts of changes since the 2011 IRP. Since then, load
growth has fallen from 1.6 percent to 1.0 percent per year, reducing Avista’s need for
new capacity. In addition to load growth changes, the Washington RPS was amended
to include Kettle Falls and other legacy biomass projects as a qualifying renewable
resource beginning in 2016. These changes eliminate the need for new resources
following Avista’s recent acquisition of output from the Palouse Wind project.

10 Hydroelectric netting subtracts a utility’s hydroelectric generation from the amount of load that the utility
would have their RPS based on. For example, a utility with 1,000,000 MWh of load and 300,000 MWh of
hydroelectric generation would only have an RPS requirement based on 700,000 MWh of load.
Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-33

Table 8.14: Policy Portfolio Scenarios

Nameplate (MW) PRS Higher
WA St.
RPS
National
RPS
Higher
Capacity
Margins
2011
PRS
CCCT 270 270 270 270 540
Natural Gas-Fired Peaker 299 249 296 435 187
Wind - - 203 - 120
Solar - - - - -
Biomass - - - - -
Coal (sequestered) - - - - -
Hydro Upgrade - 148 - - -
Thermal Upgrade 6 6 6 6 -
Demand Response 19 10 20 8 -
Total 594 683 795 718 847

20-year Levelized Cost (millions) $354.8 $360.3 $365.3 $364.2 $373.9
2028 Power Supply Stdev (millions) $65.7 $64.8 $63.6 $65.8 $54.0
2033 Greenhouse Gas Emissions
(millions of metric tons)
3.2 3.2 3.3 3.4 3.7

Resource Tipping Point Analysis
In many resource plans, a PRS is presented with a comparison to other portfolios to
help illustrate cost and risk trade-offs. This IRP extends the portfolio analysis beyond
this exercise by focusing on how the portfolio might change if key assumptions
changed. This section identifies assumptions that could alter the PRS, such as changes
to load growth, varying resource capital costs, the emergence of other non-wind and
non-solar renewable options, or an expansion of the region’s nuclear generation fleet.

Solar Capital Costs Sensitivity
For the past several years, photovoltaic solar generation costs have decreased and
more solar generation installed. Solar has benefited from the federal 30 percent ITC,
accelerated depreciation, and lucrative state incentives. Solar price decreases have
allowed the technology (with government subsidies) to be cost effective compared with
retail utility rates in some parts of the western US. After a review of solar potential in the
Northwest, and the needs of our system, solar is not a good fit. As discussed throughout
this document, Avista and the Northwest require new capacity for winter peak periods.
Avista (and the region) experience winter peaks between 6:00 am and 8:00 am or
between 5:00 pm and 6:00 pm. In December and January, the months most likely for a
peak to occur, these hours have very little or no sunlight. Adding solar to Avista’s
resource mix will not delay or remove the need for other resource options. Solar costs
would have to fall by a further 88 percent to be cost effective compared to other options.

Nuclear Capital Cost Sensitivity
Nuclear power has made a small resurgence on the U.S. energy-planning horizon, with
several large East Coast utilities planning construction of the multi-billion dollar projects.
Nuclear’s resurgence is driven by a search for low greenhouse gas emitting base-load
Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-34

power. Avista is not large enough, nor does Avista have the load requirements, to
construct a large-scale nuclear plant. It is possible that a group of utilities could co-
develop a large project, but the failure of the past regional attempt in the 1980s makes
that option unlikely. New research has begun on smaller scale nuclear facilities to make
the technology more readily available to smaller utilities. This sensitivity study reduces
nuclear capital costs until it was picked as a resource in the PRiSM model. Selection by
PRiSM indicates lower cost than other options. The model selected nuclear when its
capital costs decreased by 70 percent.

IGCC Coal with Sequestration Capital Cost Sensitivity
Like nuclear facilities, much attention has been given to coal gasification along with the
sequestration of CO2 emissions. Also like nuclear power, this technology is expensive,
has long lead times, and requires large project scale. The plant is beyond Avista’s
needs, but a group of utilities could jointly develop a sequestered coal plant. In order to
be selected by the PRiSM model, and compete economically with other options,
sequestered IGCC capital costs would need to decrease 87 percent from present
estimates. Like nuclear plants, the technology has high O&M costs. The O&M costs are
nearly as much as the total cost of natural gas CTs including fuel.

Load Forecast Alternatives
An important test in an IRP is to understand how the plan should change with
alternative load growth sensitivities. Since Avista’s first new resource need is not until
the end of 2019, Avista has time to change its resource needs if loads grow faster or
slower than predicted. In order to be nimble Avista must have resource options
available to quickly add capacity. Three different resource positions based on varying
load growth scenarios, along with the Expected Case, are shown below in Figure 8.18.
Chapter 2 discusses the economic drivers of these forecasts. The Low Load Growth
scenario changes Avista’s first deficit year, but the High caseload Growth scenario
increases the need from 42 MW to 88 MW. The Low Load Growth and the Medium
Load Growth cases push the need to 2024 or 2022 respectively. Toward the end of the
plan, the range in resource need is 267 MW between the High and Low Load Growth
cases.

Table 8.15 shows the generation resource strategies meeting the load growth
alternatives. These strategies are designed to have similar resource portfolios and risk
levels as the PRS. Energy efficiency levels also change, reflecting the expected
achievable cost effective levels given the changes to new construction assumed in the
load forecast scenarios. Energy efficiency levels will differ depending on the amount of
existing structures versus new structures, because new structures are built with more
efficient building codes. Energy efficiency for existing structures should remain relatively
unchanged, but as economic activity changes, the amount of energy efficiency from
new construction will vary. Since 87 percent of energy efficiency is from existing
structures, the levels of energy efficiency in the Low Load to High Load Growth
forecasts do not materially change.

Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-35

Figure 8.18: Load Growth Scenario’s Cost/Risk Comparison

Table 8.15: Load Growth Sensitivities

Year PRS Low Load
Growth
Medium Low
Load Growth
High Load
Growth
2019 83 MW SCCT 150 MW SCCT
2020
2021
2022 6 MW Upgrade 92 MW SCCT
2023 83 MW SCCT 90 MW SCCT
2024
2025
2026 270 MW CCCT 270 MW CCCT 270 MW CCCT 270 MW CCCT
2027 50 MW SCCT 92 MW SCCT
2028 6 MW Upgrade
2029 6 MW Upgrade 50 MW SCCT
2030
2031
2032
2033 50 MW SCCT 50 MW SCCT
Demand Res. (MW) 19 1 20 20
Efficiency (aMW) 164 142 147 175
(900)
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Avista Corp 2013 Electric IRP 8-36

Resource-Specific Scenarios
As part of an IRP, resource specific scenarios are helpful to gain understanding of
specific resource decisions. This section covers four resource specific scenarios. This
exercise illustrates the changes in cost and risk with selective resource decision
making. The scenarios evaluate different resource decision such as more renewables,
or switching from CTs to CCCTs. Figure 8.19 shows the results of the four scenarios
outlined below

200 MW Wind and CTs: 200 MW of new wind is added to the portfolio, 100 MW
in 2020 and another 100 MW in 2025. This scenario meets capacity needs with
Frame CT’s and Demand Response. In the case, costs are 5.5 percent higher
and risk 5 percent higher than the PRS. Further, this portfolio lays to the right of
the efficient frontier indicating there are more optimal portfolios to meet capacity
objectives.
200 MW Solar and CTs: 10 MW of solar is added each year totaling 200 MW
over the 20-year planning horizon. Since solar does not provide any capacity
benefit to Avista in the winter, Frame CT’s are added along with a demand
response to meet capacity needs. This scenario results in power supply costs 8
percent higher and risk is 8.5 percent higher
Hydro Upgrades and CTs: The Spokane River hydro upgrades (Post Falls,
Monroe Street 2, and Long Lake 2) and Cabinet Gorge upgrades are included in
this scenario beginning in 2024 and adding an upgrade each year through 2027.
This scenario also fills in remaining capacity needs with CT’s, in this portfolio
costs and risks are also increased as compared to the PRS. Costs are 5 percent
higher and risk is 13 percent higher.
Two CCCTs: The first capacity need in 2019 replaces the SCCT with a CCCT,
creating a short-term resource surplus. This scenario then uses another CCCT in
2027 to replace Lancaster (similar to the PRS). The portfolio is on the efficient
frontier and reduces power supply volatility. This case lowers risk by 13 percent,
but costs increase 2 percent. An RFP would evaluate this portfolio option prior to
selecting a new resource in 2020.

The risk is higher in all renewable scenarios, compared to the PRS, because of
increased dependence on the energy market. The PRS includes a combination of
CCCT and CT plants. CCCT plants reduce market risk as hedges against short-term
market shortages. Figure 8.19 shows that the combination of CTs and renewable
resources do not outperform the PRS from a risk measure, this illustrates the CCCT
plan reduces market risk more than renewables. Renewables help lower risk, this is
shown by comparing the portfolio point to the upper most black dot (CT only portfolio).
Renewables do not significantly reduce risk because all of the energy is excess to load
needs and the energy is sold on the market, where as the CCCT plant is used to meet
capacity and energy needs.

Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-37

Figure 8.19: Resource Specific Scenarios

-60%
-50%
-40%
-30%
-20%
-10%
0%
10%
20%
-5%0%5%10%15%20%25%
pe
r
c
e
n
t

c
h
a
n
g
e

f
r
o
m

P
R
S

-
ri
s
k
percent change from PRS-cost
Efficient Frontier
PRS
200 MW Wind (CT)
200 MW Solar (CT)
Hydro Upgrades (CT)
Two CCCTs
Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-38

Table 8.16: Winter 1 Hour Capacity Position (MW) with New Resources

20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
TO
T
A
L

L
O
A
D

O
B
L
I
G
A
T
I
O
N
S
Na
t
i
v
e

L
o
a
d

F
o
r
e
c
a
s
t
1,
6
7
3
1,
6
9
9
1,
7
2
7
1,
7
5
3
1,
7
8
0
1,8
0
9
1,
8
3
0
1,
8
5
3
1,8
7
8
1,
9
0
1
1,
9
2
4
1,9
5
1
1,
9
7
8
2,
0
0
4
2,
0
3
1
2,
0
5
6
2,
0
8
2
2,
1
0
9
2,
1
3
9
2,
1
7
0
Co
n
s
e
r
v
a
t
i
o
n

F
o
r
e
c
a
s
t
8
16
27
39
53
68
75
84
95
10
4
11
2
12
4
13
6
14
8
16
0
17
0
18
0
19
2
20
6
22
1
Ne
t

N
a
t
i
v
e

L
o
a
d

F
o
r
e
c
a
s
t
1,
6
6
5
1,
6
8
3
1,
7
0
0
1,
7
1
3
1,
7
2
7
1,7
4
1
1,
7
5
5
1,
7
6
9
1,7
8
3
1,
7
9
8
1,
8
1
2
1,8
2
7
1,
8
4
2
1,
8
5
6
1,
8
7
1
1,
8
8
7
1,
9
0
2
1,
9
1
7
1,
9
3
3
1,
9
4
8
Fi
r
m

P
o
w
e
r

S
a
l
e
s
21
1
15
8
15
8
8
8
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
To
t
a
l

R
e
q
u
i
r
e
m
e
n
t
s
1,
8
7
5
1,
8
4
1
1,
8
5
7
1,
7
2
1
1,
7
3
5
1,7
4
7
1,
7
6
1
1,
7
7
5
1,7
8
9
1,
8
0
4
1,
8
1
8
1,8
3
3
1,
8
4
8
1,
8
6
3
1,
8
7
8
1,
8
9
3
1,
9
0
8
1,
9
2
3
1,
9
3
9
1,
9
5
4
RE
S
O
U
R
C
E
S
Fi
r
m

P
o
w
e
r

P
u
r
c
h
a
s
e
s
11
7
11
7
11
7
11
7
11
7
11
6
34
34
33
33
33
33
33
33
33
33
33
33
33
33
Hy
d
r
o

R
e
s
o
u
r
c
e
s
99
8
88
8
88
9
95
5
95
5
91
9
92
4
92
0
92
0
92
8
92
0
92
0
92
8
92
0
92
0
92
8
92
0
92
0
92
8
92
0
Ba
s
e

L
o
a
d

T
h
e
r
m
a
l
s
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
61
7
61
7
61
7
61
7
61
7
61
7
61
7
Wi
n
d

R
e
s
o
u
r
c
e
s
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Pe
a
k
i
n
g

U
n
i
t
s
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
To
t
a
l

R
e
s
o
u
r
c
e
s
2,
2
5
2
2,
1
4
3
2,
1
4
3
2,
2
1
0
2,
2
1
0
2,1
7
2
2,
0
9
5
2,
0
9
1
2,0
9
1
2,
0
9
8
2,
0
9
0
2,0
9
0
2,
0
9
8
1,
8
1
1
1,
8
1
1
1,
8
1
9
1,
8
1
1
1,
8
1
1
1,
8
1
9
1,
8
1
1
Pe
a
k

P
o
s
i
t
i
o
n

B
e
f
o
r
e

R
e
s
e
r
v
e

P
l
a
n
n
i
n
g
37
7
30
2
28
6
48
9
47
5
42
5
33
4
31
6
30
1
29
4
27
2
25
7
25
0
-5
1
-6
6
-7
4
-9
7
-1
1
2
-1
2
0
-1
4
3
RE
S
E
R
V
E

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

M
a
r
g
i
n
-2
3
3
-2
3
6
-2
3
8
-2
4
0
-2
4
2
-2
4
4
-2
4
6
-2
4
8
-2
5
0
-2
5
2
-2
5
4
-2
5
6
-2
5
8
-2
6
0
-2
6
2
-2
6
4
-2
6
6
-2
6
8
-2
7
1
-2
7
3
To
t
a
l

A
n
c
i
l
l
a
r
y

S
e
r
v
i
c
e
s

R
e
q
u
i
r
e
d
-1
3
9
-1
3
6
-1
3
7
-1
2
8
-1
2
9
-1
3
1
-1
3
6
-1
3
7
-1
3
8
-1
3
9
-1
4
1
-1
4
2
-1
4
3
-1
3
9
-1
3
9
-1
4
0
-1
4
0
-1
4
0
-1
4
0
-1
4
0
Re
s
e
r
v
e

&

C
o
n
t
i
n
g
e
n
c
y

A
v
a
i
l
a
b
i
l
i
t
y

m
e
t

b
y

H
y
d
r
o
13
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
De
m
a
n
d

R
e
s
p
o
n
s
e
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
To
t
a
l

R
e
s
e
r
v
e

P
l
a
n
n
i
n
g
-3
5
9
-3
6
6
-3
6
9
-3
6
2
-3
6
6
-3
6
9
-3
7
6
-3
7
9
-3
8
2
-3
8
6
-3
8
9
-3
9
2
-3
9
5
-3
9
3
-3
9
6
-3
9
8
-4
0
0
-4
0
3
-4
0
6
-4
0
8
Pe
a
k

P
o
s
i
t
i
o
n

w
/

C
o
n
t
i
n
g
e
n
c
y
17
-6
4
-8
4
12
6
11
0
56
-4
2
-6
4
-8
1
-9
2
-1
1
7
-1
3
5
-1
4
5
-4
4
5
-4
6
2
-4
7
2
-4
9
7
-5
1
5
-5
2
5
-5
5
1
Pl
a
n
n
i
n
g

M
a
r
g
i
n
20
%
16
%
15
%
28
%
27
%
24
%
19
%
18
%
17
%
16
%
15
%
14
%
14
%
-3
%
-4
%
-4
%
-5
%
-6
%
-6
%
-7
%
NE
W

R
E
S
O
U
R
C
E
S
Sh
o
r
t
-
T
e
r
m

M
a
r
k
e
t

P
u
r
c
h
a
s
e
0
75
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Ne
w

N
G

F
i
r
e
d

P
e
a
k
e
r
s
0
0
0
0
0
0
80
80
80
80
16
0
16
0
16
0
16
0
24
0
24
0
24
0
24
0
24
0
28
8
Ne
w

C
o
m
b
i
n
e
d

C
y
c
l
e

C
T
0
0
0
0
0
0
0
0
0
0
0
0
0
26
0
26
0
26
0
26
0
26
0
26
0
26
0
Th
e
r
m
a
l

R
e
s
o
u
r
c
e

U
p
g
r
a
d
e
s
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2
2
2
2
2
De
m
a
n
d

R
e
s
p
o
n
s
e
0
0
0
0
0
0
0
0
1
6
6
10
15
20
20
20
20
20
20
20
To
t
a
l

N
e
w

R
e
s
o
u
r
c
e
s
0
75
10
0
0
0
0
80
80
81
86
16
6
16
9
17
5
44
0
52
0
52
2
52
2
52
2
52
2
57
0
Pe
a
k

P
o
s
i
t
i
o
n

w
i
t
h

N
e
w

R
e
s
o
u
r
c
e
s
17
11
16
12
6
11
0
56
38
16
0
-5
49
34
30
-5
58
50
25
7
-4
19
Pl
a
n
n
i
n
g

M
a
r
g
i
n

w
i
t
h

N
e
w

R
e
s
o
u
r
c
e
s
20
%
20
%
21
%
28
%
27
%
24
%
23
%
22
%
21
%
21
%
24
%
23
%
23
%
21
%
24
%
24
%
22
%
21
%
21
%
22
%
Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-39

Table 8.17: Summer 18-Hour Capacity Position (MW) with New Resources

20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
TO
T
A
L

L
O
A
D

O
B
L
I
G
A
T
I
O
N
S
Na
t
i
v
e

L
o
a
d

F
o
r
e
c
a
s
t
1,
4
7
4
1,5
0
0
1,
5
2
7
1,
5
5
3
1,
5
8
1
1,
6
1
1
1,
6
3
1
1,
6
5
5
1,
6
7
9
1,
7
0
3
1,
7
2
6
1,
7
5
3
1,
7
8
0
1,
8
0
6
1,8
3
4
1,
8
5
9
1,
8
8
5
1,9
1
2
1,
9
4
3
1,
9
7
4
Co
n
s
e
r
v
a
t
i
o
n

F
o
r
e
c
a
s
t
9
18
30
43
58
74
82
92
10
3
11
3
12
2
13
5
14
8
16
1
17
4
18
5
19
6
20
9
22
5
24
1
Ne
t

N
a
t
i
v
e

L
o
a
d

F
o
r
e
c
a
s
t
1,
4
6
5
1,4
8
2
1,
4
9
8
1,
5
1
0
1,
5
2
3
1,
5
3
6
1,
5
5
0
1,
5
6
3
1,
5
7
6
1,
5
9
0
1,
6
0
4
1,
6
1
8
1,
6
3
1
1,
6
4
6
1,6
6
0
1,
6
7
4
1,
6
8
9
1,7
0
3
1,
7
1
8
1,
7
3
3
Fi
r
m

P
o
w
e
r

S
a
l
e
s
21
2
15
9
15
9
9
9
8
8
7
7
7
7
7
7
7
7
7
7
7
7
7
To
t
a
l

R
e
q
u
i
r
e
m
e
n
t
s
1,
6
7
7
1,6
4
1
1,
6
5
7
1,
5
1
9
1,
5
3
2
1,
5
4
4
1,
5
5
7
1,
5
7
0
1,
5
8
4
1,
5
9
7
1,
6
1
1
1,
6
2
5
1,
6
3
9
1,
6
5
3
1,6
6
7
1,
6
8
1
1,
6
9
6
1,7
1
0
1,
7
2
5
1,
7
4
0
RE
S
O
U
R
C
E
S
Fi
r
m

P
o
w
e
r

P
u
r
c
h
a
s
e
s
29
29
29
29
29
26
26
26
26
25
25
25
25
25
25
25
25
25
25
25
Hy
d
r
o

R
e
s
o
u
r
c
e
s
70
1
70
7
66
3
63
1
63
8
58
3
58
0
62
2
62
4
62
2
62
2
62
4
62
2
62
2
62
4
62
2
62
2
62
4
62
2
62
2
Ba
s
e

L
o
a
d

T
h
e
r
m
a
l
s
78
5
78
5
78
5
78
5
78
5
78
5
78
5
78
5
78
5
78
5
78
5
78
5
78
5
55
6
55
6
55
6
55
6
55
6
55
6
55
6
Wi
n
d

R
e
s
o
u
r
c
e
s
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Pe
a
k
i
n
g

U
n
i
t
s
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
To
t
a
l

R
e
s
o
u
r
c
e
s
1,
6
9
1
1,6
9
8
1,
6
5
3
1,
6
2
1
1,
6
2
8
1,
5
7
1
1,
5
6
8
1,
6
0
9
1,
6
1
1
1,
6
0
9
1,
6
0
9
1,
6
1
1
1,
6
0
9
1,
3
7
9
1,3
8
1
1,
3
7
9
1,
3
7
9
1,3
8
1
1,
3
7
9
1,
3
7
9
Pe
a
k

P
o
s
i
t
i
o
n

B
e
f
o
r
e

R
e
s
e
r
v
e

P
l
a
n
n
i
n
g
14
57
-3
10
2
96
27
11
39
27
11
-2
-1
4
-3
0
-2
7
4
-2
8
6
-3
0
2
-3
1
7
-3
3
0
-3
4
6
-3
6
1
RE
S
E
R
V
E

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

M
a
r
g
i
n
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
To
t
a
l

A
n
c
i
l
l
a
r
y

S
e
r
v
i
c
e
s

R
e
q
u
i
r
e
d
-1
7
7
-1
7
6
-1
7
7
-1
7
0
-1
7
2
-1
7
3
-1
7
5
-1
7
6
-1
7
7
-1
7
9
-1
8
0
-1
8
1
-1
8
2
-1
6
6
-1
6
7
-1
6
7
-1
6
8
-1
6
9
-1
6
9
-1
7
0
Re
s
e
r
v
e

&

C
o
n
t
i
n
g
e
n
c
y

A
v
a
i
l
a
b
i
l
i
t
y

m
e
t

b
y

H
y
d
r
o
17
7
17
6
17
7
17
0
17
2
17
3
17
5
17
6
17
7
17
9
18
0
18
1
18
2
16
6
16
7
16
7
16
8
16
9
16
9
17
0
De
m
a
n
d

R
e
s
p
o
n
s
e
0
0
0
0
0
0
0
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0
0
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0
0
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0
0
0
0
0
To
t
a
l

R
e
s
e
r
v
e

P
l
a
n
n
i
n
g
0
0
0
0
0
0
0
0
0
0
0
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0
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0
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0
Pe
a
k

P
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s
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t
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n

w
/

C
o
n
t
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n
g
e
n
c
y
14
57
-3
10
2
96
27
11
39
27
11
-2
-1
4
-3
0
-2
7
4
-2
8
6
-3
0
2
-3
1
7
-3
3
0
-3
4
6
-3
6
1
Pl
a
n
n
i
n
g

M
a
r
g
i
n
1%
3%
0%
7%
6%
2%
1%
2%
2%
1%
0%
-1
%
-2
%
-1
7
%
-1
7
%
-1
8
%
-1
9
%
-1
9
%
-2
0
%
-2
1
%
NE
W

R
E
S
O
U
R
C
E
S
Sh
o
r
t
-
T
e
r
m

M
a
r
k
e
t

P
u
r
c
h
a
s
e
0
0
25
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Ne
w

N
G

F
i
r
e
d

P
e
a
k
e
r
s
0
0
0
0
0
0
72
72
72
72
14
4
14
4
14
4
14
4
21
7
21
7
21
7
21
7
21
7
26
0
Ne
w

C
o
m
b
i
n
e
d

C
y
c
l
e

C
T
0
0
0
0
0
0
0
0
0
0
0
0
0
23
5
23
5
23
5
23
5
23
5
23
5
23
5
Th
e
r
m
a
l

R
e
s
o
u
r
c
e

U
p
g
r
a
d
e
s
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
5
5
5
5
5
De
m
a
n
d

R
e
s
p
o
n
s
e
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
To
t
a
l

N
e
w

R
e
s
o
u
r
c
e
s
0
0
25
0
0
0
72
72
72
72
14
4
14
4
14
4
37
9
45
1
45
7
45
7
45
7
45
7
50
0
Pe
a
k

P
o
s
i
t
i
o
n

w
i
t
h

N
e
w

R
e
s
o
u
r
c
e
s
14
57
22
10
2
96
27
83
11
1
99
84
14
2
13
0
11
4
10
5
16
5
15
4
14
0
12
7
11
1
13
9
Pl
a
n
n
i
n
g

M
a
r
g
i
n

w
i
t
h

N
e
w

R
e
s
o
u
r
c
e
s
1%
3%
1%
7%
6%
2%
5%
7%
6%
5%
9%
8%
7%
6%
10
%
9%
8%
7%
6%
8%
Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-40

Table 8.18: Average Annual Energy Position (aMW) With New Resources

20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
TO
T
A
L

L
O
A
D

O
B
L
I
G
A
T
I
O
N
S
Na
t
i
v
e

L
o
a
d

F
o
r
e
c
a
s
t
1,0
6
0
1,
0
7
9
1,
1
0
0
1,
1
2
3
1,
1
4
4
1,1
6
5
1,
1
8
1
1,
1
9
7
1,
2
1
5
1,
2
3
2
1,2
5
0
1,
2
7
2
1,
2
9
1
1,
3
1
1
1,
3
3
1
1,3
5
1
1,
3
7
3
1,
3
9
6
1,
4
2
2
1,
4
4
9
Co
n
s
e
r
v
a
t
i
o
n

F
o
r
e
c
a
s
t
6
12
20
29
39
51
55
62
70
77
83
92
10
1
10
9
11
8
12
6
13
4
14
2
15
3
16
4
Ne
t

N
a
t
i
v
e

L
o
a
d

F
o
r
e
c
a
s
t
1,0
5
4
1,
0
6
7
1,
0
7
9
1,
0
9
3
1,
1
0
5
1,1
1
4
1,
1
2
5
1,
1
3
5
1,
1
4
5
1,
1
5
5
1,1
6
7
1,
1
8
0
1,
1
9
0
1,
2
0
1
1,
2
1
2
1,2
2
5
1,
2
3
9
1,
2
5
4
1,
2
7
0
1,
2
8
5
Fi
r
m

P
o
w
e
r

S
a
l
e
s
10
9
58
58
6
6
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
To
t
a
l

R
e
q
u
i
r
e
m
e
n
t
s
1,1
6
3
1,
1
2
5
1,
1
3
7
1,
0
9
9
1,
1
1
1
1,1
1
9
1,
1
3
0
1,
1
4
0
1,
1
5
0
1,
1
6
0
1,1
7
2
1,
1
8
5
1,
1
9
5
1,
2
0
6
1,
2
1
7
1,2
3
0
1,
2
4
4
1,
2
5
9
1,
2
7
4
1,
2
9
0
RE
S
O
U
R
C
E
S
Fi
r
m

P
o
w
e
r

P
u
r
c
h
a
s
e
s
12
8
12
9
12
8
76
76
56
31
30
30
29
29
29
29
29
29
29
29
29
29
29
Hy
d
r
o

R
e
s
o
u
r
c
e
s
52
7
49
5
49
5
49
5
49
0
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
Ba
s
e

L
o
a
d

T
h
e
r
m
a
l
s
72
3
72
5
71
8
71
5
73
2
71
1
72
4
73
6
71
3
71
7
71
4
71
9
67
3
50
6
50
4
50
6
50
4
50
6
50
4
50
6
Win
d

R
e
s
o
u
r
c
e
s
42
40
40
40
40
40
40
40
40
40
40
40
40
40
40
40
40
40
40
40
Pe
a
k
i
n
g

U
n
i
t
s
15
3
13
9
15
4
15
3
15
3
15
3
14
7
15
1
15
2
15
3
15
2
15
3
15
2
15
3
15
2
15
3
15
2
15
3
15
2
15
3
To
t
a
l

R
e
s
o
u
r
c
e
s
1,5
7
3
1,
5
2
8
1,
5
3
5
1,
4
7
9
1,
4
9
0
1,4
4
0
1,
4
2
2
1,
4
3
8
1,
4
1
6
1,
4
2
0
1,4
1
5
1,
4
2
1
1,
3
7
4
1,
2
0
8
1,
2
0
6
1,2
0
8
1,
2
0
6
1,
2
0
8
1,
2
0
6
1,
2
0
8
En
e
r
g
y

P
o
s
i
t
i
o
n

B
e
f
o
r
e

R
e
s
e
r
v
e

P
l
a
n
n
i
n
g
41
0
40
4
39
8
38
0
37
9
32
1
29
2
29
9
26
6
25
9
24
3
23
7
17
9
2
-1
2
-2
2
-3
9
-5
1
-6
9
-8
2
RE
S
E
R
V
E

P
L
A
N
N
I
N
G
Co
n
t
i
n
g
e
n
c
y
-2
2
8
-2
3
1
-2
3
1
-2
3
2
-2
3
2
-2
1
4
-1
9
5
-1
9
6
-1
9
6
-1
9
7
-1
9
7
-1
9
8
-1
9
8
-1
9
9
-1
9
9
-2
0
0
-2
0
0
-2
0
1
-2
0
2
-2
0
2
En
e
r
g
y

P
o
s
i
t
i
o
n

w
/

C
o
n
t
i
n
g
e
n
c
y
18
2
17
3
16
7
14
8
14
7
10
6
96
10
3
70
63
46
39
-1
9
-1
9
7
-2
1
1
-2
2
1
-2
3
9
-2
5
2
-2
7
0
-2
8
4
NE
W

R
E
S
O
U
R
C
E
S
Sh
o
r
t
-
T
e
r
m

M
a
r
k
e
t

P
u
r
c
h
a
s
e
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Ne
w

N
G

F
i
r
e
d

P
e
a
k
e
r
s
0
0
0
0
0
0
68
68
68
68
13
5
13
5
13
5
13
5
20
4
20
4
20
4
20
4
20
4
24
9
Ne
w

C
o
m
b
i
n
e
d

C
y
c
l
e

C
T
0
0
0
0
0
0
0
0
0
0
0
0
0
24
5
24
5
24
5
24
5
24
5
24
5
24
5
Th
e
r
m
a
l

R
e
s
o
u
r
c
e

U
p
g
r
a
d
e
s
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
5
5
5
5
5
De
m
a
n
d

R
e
s
p
o
n
s
e
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
To
t
a
l

N
e
w

R
e
s
o
u
r
c
e
s
0
0
0
0
0
0
68
68
68
68
13
5
13
5
13
5
38
0
44
9
45
4
45
4
45
4
45
4
50
0
En
e
r
g
y

P
o
s
i
t
i
o
n

w
i
t
h

N
e
w

R
e
s
o
u
r
c
e
s
18
2
17
3
16
7
14
8
14
7
10
6
16
4
17
0
13
7
13
0
18
1
17
4
11
6
18
4
23
8
23
3
21
5
20
3
18
4
21
6
Chapter 9–Action Items
Avista Corp 2013 Electric IRP
9. Action Items

The IRP is an ongoing and iterative process balancing regular publication timelines with
pursuing the best 20-year resource strategies. The biennial publication date provides
opportunities to document ongoing improvements to the modeling and forecasting
procedures and tools, as well as enhance the process with new research as the
planning environment changes. This section provides an overview of the progress made
on the 2011 IRP Action Plan and provides the 2013 Action Plan.

Summary of the 2011 IRP Action Plan
The 2011 Action Plan included five separate categories: resource additions and
analysis, energy efficiency, environmental policies, modeling and forecasting
enhancements, and transmission planning.

2011 Action Plan and Progress Report – Resource Additions and Analysis
Continue to explore and follow potential new resource opportunities.
o Over the past two years, Avista began investigating sites for future
peaking-capable generation. This process consisted of interconnection
feasibility studies, site visits, and permitting and environmental evaluation.
Avista will continue this effort over the next several years prior to releasing
an RFP for new peaking capacity.
o Avista is ending studies on wind resource development with the passage
of SB 5575 in Washington and the subsequent lack of need for
renewables in this IRP. This includes ceasing development at the Reardan
Wind site.

Continue studies on the costs, energy, capacity and environmental benefits of hydro
upgrades at both Spokane and Clark Fork River projects.
o During 2012, Avista studied upgrade options to the Spokane River Project.
The assessment included an engineering screening of several upgrade
options for the five upper Spokane River developments and concluded
with a recommendation to rehabilitate the Nine Mile Falls project rather
building or rebuilding the powerhouse. The assessment provided
perspectives on the river system’s potential for meeting future load
requirements, and options to add renewable energy at a price competitive
with other renewables. Details on Spokane River upgrade opportunities
are in Chapter 6, Generation Resource Options.
o Avista completed high-level studies for the Cabinet Gorge hydroelectric
development. The review evaluated options to add a fifth unit in the
original bypass tunnel for additional capacity and to reduce total dissolved
gases. This alternative was uneconomic compared to other utility
alternatives.
Study potential locations for the natural gas-fired resource identified to be online by
the end of 2018.
Chapter 9–Action Items
Avista Corp 2013 Electric IRP
o Avista has begun its efforts to identify a site for a new natural gas-fired
peaker. A small cross-function team is investigating potential sites within
the service territory. Site selection considers proximity to natural gas
pipelines, transmission, and distance away from population centers or
locations with potential environmental liabilities. Avista has initiated
transmission studies for potential areas discussed in Chapter 5.

Continue participation in regional IRP processes and, where agreeable, find
opportunities to meet resource requirements on a collaborative basis with other
utilities.
o Avista monitors and attends when appropriate other northwest utility’s IRP
processes. With Avista’s needs toward the beginning of the next decade,
and for smaller unit sizes, the potential for resource collaboration is
unlikely. Collaboration works best on developing large projects where
economies of scale benefits smaller off-takers. Given the PRS’s first
identified resource is for a small peaker, collaborating on a project would
be unlikely.
o Avista’s staff continues to participate in regional processes including the
development of the Seventh Power Plan, PNUCC studies, and work done
by the Western Governors Association.

Provide an update on the Little Falls and Nine Mile hydroelectric project upgrades.
o The Nine Mile hydro facility is undergoing rehabilitation. Units 1 and 2
have been removed and engineering work is complete. A status update
will be included in the next IRP; the project is scheduled for completion in
2016.
o At Little Falls, new electrical equipment and generator excitation systems
are installed. Avista is replacing station service, updating the powerhouse
crane, and developing new control systems on each of the units.

Study potential for demand response projects with industrial customers.
o Avista has begun preliminary investigation into demand response from
industrial and commercial customers. For this IRP Avista identified 20 MW
of commercial demand response. Avista intends to conduct a market
assessment study during the next IRP process, and begin preliminary
discussion with large industrial customers.

Continue to monitor regional surplus capacity and Avista’s reliance on this surplus
for near- and medium-term needs.
o Avista participates in the NPCC Resource Adequacy Forum. On January
23, 2013, the NPCC released a resource adequacy study. The study
found that the Northwest has sufficient resources until a small regional
deficit (350 MW) begins in 2017.
o Avista has short-term winter peaking needs in 2015 and 2016; thereafter a
150 MW return of the PGE capacity sale will provide sufficient capacity
through 2019. The Resource Adequacy forum studies provide evidence
Chapter 9–Action Items
Avista Corp 2013 Electric IRP
that Avista can rely on for market capacity during this period. Further, the
report identifies the regional summer peak periods to be surplus into the
future, and that Avista can lower its planning margin requirements during
summer months.

2011 Action Plan and Progress Report – Energy Efficiency
Study and quantify transmission and distribution efficiency projects as they apply to
the Washington RPS goals.
o Avista continues to update its transmission and distribution system since
the 2011 IRP; it has completed several distribution feeder upgrades and
installed smart grid technology in Pullman and Spokane. In the 2010/2011
conservation target report Avista reported 3,512 MWh of savings. In the
upcoming 2012/2013 report Avista plans on filing 32,387 MWh of savings.

Update processes and protocols for conservation, measurement, evaluation and
verification.
o Avista is continuing to work through the process of updating and
documenting its processes and procedures for the conservation programs
offered through the utility. For evaluation, measurement and verification,
Avista is guided by its framework and is committed to revisiting with
stakeholders as necessary with the intent of updating and editing it as
circumstances warrant.

Continue to determine the potential impacts and costs of load management options.
o Avista is participating in the Northwest Regional Smart Grid
Demonstration Project to help understand the costs and benefits of load
management programs. In the past, Avista has sponsored a pilot in Idaho
as a way to understand how these programs could work and understand
the costs and benefits. In the future, Avista will focus more on commercial
and industrial opportunities by studying the potential and costs of such a
programs.

2011 Action Plan and Progress Report – Environmental Policy
Continue studies of state and federal climate change policies.
o Avista actively engages in reviewing and participating in state and federal
discussions about climate change policies related to electric generation
and natural gas distribution. Details about the issues covered are in
Chapter 4, Policy Considerations.

Continue and report on the work of Avista’s Climate Policy Council.
o Avista’s Climate Policy Council and the Resource Planning team actively
analyze state and federal greenhouse gas legislation. This work will
continue until final rules are established and laws passed. The focus will
then shift to mitigating the costs of meeting the applicable laws and
regulations. Avista has quantified its greenhouse gas emissions using the
World Resources Initiative–World Business Council for Sustainable
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Avista Corp 2013 Electric IRP
Development inventory protocol in anticipation of state and federal
greenhouse gas reporting mandates. Details about Climate Policy Council
efforts are in Chapter 4, Policy Considerations.

2011 Action Plan and Progress Report – Modeling and Forecasting
Continue following regional reliability processes and develop Avista-centric modeling
for possible inclusion in the 2013 IRP.
o Avista has developed, with support from NPCC staff, an Avista view of the
northwest load and resource balance (see Chapter 2). Given today’s
assumptions, the region has enough capacity to meet Northwest winter
needs to 2017, and summer capacity needs indefinitely where the larger
winter capacity needs are met.
o Since the 2011, IRP Avista updated and added logic and reporting
enhancements to Avista’s LOLP model per NPCC staff recommendations.
The results of this discussion and analysis led Avista to rely on the mixture
of new resources and market purchases to meet a 5 percent LOLP
reliability target. See Chapter 2, Loads & Resources, for a discussion of
this study.

Continue studying the impacts of climate change on retail loads.
o The load forecast includes changes in Spokane temperatures away from
the 30-year normal to include fewer heating degree days and more cooling
degree days per a 2008 University of Washington study. The study
anticipates there will not be a large effect on retail loads from potential
climate change activities. Avista investigated studies regarding changing
water conditions from climate change and found there is no evidence of
changing annual average conditions, but rather higher flows earlier in the
year. The higher flows indirectly benefit customers as increased flow
periods coincide with higher loads.

Refine the stochastic model for cost-driver relationships, including further analyzing
year-to-year hydro correlation and the correlation between wind, load, and hydro.
o Quality regional wind output data is available from the BPA website only
back to 2007. Given this short term dataset, correlating to load and hydro
data will provide statistically insignificant results. The best way to estimate
these correlations is to fund a long-term weather consultant study; the
NPCC’s Seventh Power Plan would benefit from such a study. Avista will
be participating in this planning process and will recommend a study
based on long-term data.

2011 Action Plan and Progress Report – Transmission and Distribution Planning
Work to maintain Avista’s existing transmission rights, under applicable FERC
policies, for transmission service to bundled retail native load.
o Avista has maintained its existing transmission rights to meet native
customer load.

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Avista Corp 2013 Electric IRP
Continue to participate in BPA transmission processes and rate proceedings to
minimize the costs of integrating existing resources outside of Avista’s service area.
o Avista is actively participating in the BPA transmission rate proceedings.

Continue to participate in regional and sub-regional efforts to establish new regional
transmission structures to facilitate long-term expansion of the regional transmission
system.
o Avista staff participate in and lead many regional transmission efforts
including Columbia Grid and the Transmission Coordination Work Group
(TCWG).

Evaluate costs to integrate new resources across Avista’s service territory and from
regions outside of the Northwest.
o Avista’s Transmission group performed seven studies of potential
generation upgrades and new facilities, these studies are in Appendix D
and Chapter 5.

Study and implement distribution feeder rebuilds to reduce system losses.
o Since the 2011 IRP, Avista has completed two feeder rebuilds. These
rebuilds reduce losses by 1,542 MWh, improve reliability, and decrease
future operation and maintenance costs.

Continue to study other potential areas to implement Smart Grid projects to other
areas of the service territory.
o With the completion of the Spokane and Pullman Smart Grid projects,
Avista put all such future projects on hold. Additional projects will be
evaluated on a case-by-case basis for cost effectiveness and increased
reliability.

Study transmission reconfigurations that economically reduce system losses.
o Avista’s transmission department continues to review potential projects to
increase reliability and reduce system losses. Chapter 5, Transmission &
distribution, discusses projects meeting this objective.

2013 IRP Action Plan
Avista’s 2013 PRS provides direction and guidance for the type, timing and size of
future resource acquisitions. The 2013 IRP Action Plan highlights the activities planned
for possible inclusion in the 2015 IRP. Progress and results for the 2013 Action Plan
items are reported to the TAC and the results will be included in Avista’s 2015 IRP. The
2013 Action Plan includes input from Commission Staff, Avista’s management team,
and the TAC.

Generation Resource Related Analysis
Consider Spokane and Clark Fork River hydro upgrade options in the next IRP as
potential resource options to meet energy, capacity and environmental
requirements.
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Avista Corp 2013 Electric IRP
Continue to evaluate potential locations for the natural gas-fired resource identified
to be online by the end of 2019, including environmental reviews, transmission
studies, and potential land acquisition.
Continue participation in regional IRP and regional planning processes and monitor
regional surplus capacity and continue to participate in regional capacity planning
processes.
Commission a demand response potential and cost assessment of commercial and
industrial customers per its inclusion in the middle of the PRS action plan.
Continue monitoring state and federal climate change policies and report work from
Avista’s Climate Change Council.
Review and update the energy forecast methodology to better integrate economic,
regional, and weather drivers of energy use.
Evaluate the benefits of a short-term (up to 24-months) capacity position report.
Evaluate options to integrate intermittent resources.

Energy Efficiency
Work with NPCC, the UTC, and others to resolve adjusted market baseline issues
for setting energy efficiency target setting and acquisition claims in Washington.
Study and quantify transmission and distribution efficiency projects as they apply to
EIA goals.
Update processes and protocols for conservation measurement, evaluation and
verification.
Assess energy efficiency potential on Avista’s generation facilities.

Transmission and Distribution Planning
Work to maintain Avista’s existing transmission rights, under applicable FERC
policies, for transmission service to bundled retail native load.
Continue to participate in BPA transmission processes and rate proceedings to
minimize costs of integrating existing resources outside of Avista’s service area.
Continue to participate in regional and sub-regional efforts to establish new regional
transmission structures to facilitate long-term expansion of the regional transmission
system.

Chapter 9–Action Items
Avista Corp 2013 Electric IRP
Production Credits

Primary Avista 2013 Electric IRP Team

Individual Title Contribution
Clint Kalich Manager of Resource Planning & Analysis Project Manager
James Gall Senior Power Supply Analyst Analysis/Author
John Lyons Senior Resource Policy Analyst Research/Author/Editor
Grant Forsyth Senior Forecaster & Economist Load Forecast
Lori Hermanson Utility Resource Analyst Energy Efficiency
Richard Maguire System Planning Engineer Transmission & Distribution

2013 Electric IRP Contributors

Name Title
Shawn Bonfield Regulatory Policy Analyst
Troy Dehnel Feeder Upgrade Project Coordinator
Thomas Dempsey Manager, Generation Joint Projects
Leona Doege DSM Program Manager
Mike Gonnella Manager of Generation Substation Support
Kelly Irvine Manager of Natural Gas Planning
Jon Powell Partnership Solutions Manager
Dave Schwall Senior Engineer
Darrell Soyars Manager of Corporate Environmental Compliance
Xin Shane Power Supply Analyst
Steve Wenke Chief Generation Engineer
Jessie Wuerst Senior External Communications Manager

Contact contributors via email by placing their names in this email address format:
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