20150601Kinney Exhibit 4.pdf

DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
[e-mail]

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-15-05
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 4
AND NATURAL GAS CUSTOMERS IN THE )
STATE OF IDAHO ) SCOTT J. KINNEY
)

FOR AVISTA CORPORATION

(ELECTRIC ONLY)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1 of 1125

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 2 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 3 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 4 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 5 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 6 of 1125
Table of Contents

Avista Corp 2013 Electric IRP i
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 7 of 1125
Table of Contents

Avista Corp 2013 Electric IRP ii
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

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 8 of 1125
Table of Contents

Avista Corp 2013 Electric IRP iii
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 9 of 1125
Table of Contents

Avista Corp 2013 Electric IRP iv
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

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 10 of 1125
Table of Contents

Avista Corp 2013 Electric IRP v
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 11 of 1125
Table of Contents

Avista Corp 2013 Electric IRP vi
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

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 12 of 1125
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 13 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 14 of 1125
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

-500
0
500
1,000
1,500
2,000
2,500
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
me
g
a
w
a
t
t
s
Net Firm Contracts Peaking ThermalsBaseload Thermals HydroLoad Forecast Load Forecast + PM/Reserves
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 15 of 1125
Executive Summary
Avista Corp 2013 Electric IRP
Figure 2: Load-Resource Balance—Summer 18 Hour Capacity

Figure 3: Load-Resource Balance—Energy

-500
0
500
1,000
1,500
2,000
2,500
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
me
g
a
w
a
t
t
s
Net Firm Contracts Peaking ThermalsBaseload Thermals HydroLoad Forecast + PM/Reserves
0
500
1,000
1,500
2,000
2,500
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
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
Net Firm Contracts Peaking Thermals
Baseload Thermals Hydro
Load Forecast Load Forecast + Contingency
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 16 of 1125
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

$0
$20
$40
$60
$80
$100
$120
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
1
4
-33
do
l
l
a
r
s

p
e
r

M
W
h
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 17 of 1125
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.

$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
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
do
l
l
a
r
s

p
e
r

d
e
k
a
t
h
e
r
m
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 18 of 1125
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
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 19 of 1125
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

$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
20
2
8

p
o
w
e
r

s
u
p
p
l
y

c
o
s
t

s
t
d
e
v
20 yr levelized annual power supply rev. req.
Market Only
Least Cost
Least Risk
Preferred Resource Strategy
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 20 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 21 of 1125
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.
0
20
40
60
80
100
120
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
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
Qualifying Hydro Upgrades Qualifying ResourcesPurchased RECs Available Bank
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 22 of 1125
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

0.00
0.10
0.20
0.30
0.40
0.50
Mil
1 Mil
2 Mil
3 Mil
4 Mil
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
me
t
r
i
c

t
o
n
s

p
e
r

M
W
h
me
t
r
i
c

t
o
n
s
Total
Tons per MWh of Load
0
50
100
150
200
250
300
350
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
mi
l
l
i
o
n

m
e
t
r
i
c

t
o
n
s

C
O
2
Historical
Expected Case
10th Percentile
90th Percentile
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 23 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 24 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 25 of 1125
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

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 26 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 27 of 1125
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 28 of 1125
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 29 of 1125
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

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 30 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 31 of 1125
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

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 32 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 33 of 1125
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
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
to
t
a
l

p
o
p
u
l
a
t
i
o
n
Spokane MSA
Coeur d'Alene MSA
Lewiston, ID-WA MSA
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 34 of 1125
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
7
3
19
7
5
19
7
7
19
7
9
19
8
1
19
8
3
19
8
5
19
8
7
19
8
9
19
9
1
19
9
3
19
9
5
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
po
p
u
l
a
t
i
o
n

p
e
r
c
e
n
t

c
h
a
n
g
e
ShadedAreas =
Recessions
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 35 of 1125
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
c
-08
Fe
b
-09
Ap
r
-09
Ju
n
-09
Au
g
-09
Oc
t
-09
De
c
-09
Fe
b
-10
Ap
r
-10
Ju
n
-10
Au
g
-10
Oc
t
-10
De
c
-10
Fe
b
-11
Ap
r
-11
Ju
n
-11
Au
g
-11
Oc
t
-11
De
c
-11
Fe
b
-12
Ap
r
-12
Ju
n
-12
Au
g
-12
Oc
t
-12
De
c
-12
in
d
e
x

o
f

n
o
n
-fa
r
m

e
m
p
l
o
y
m
e
n
t
,

d
e
c
.

20
0
7

=

1
0
0
Index Avista WA-ID MSAs
Index U.S.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 36 of 1125
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%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 37 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 38 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 39 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 40 of 1125
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).
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 41 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 42 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 43 of 1125
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
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
20
3
4
av
e
r
a
g
e

h
o
u
s
e
h
o
l
d

S
i
z
e

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 44 of 1125
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/
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 45 of 1125
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
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
20
3
4
20
3
5
ki
l
o
w
a
t
t
-ho
u
r
s
Residential UPC, with Electric Vehicles
Residential UPC, without Electric Vehicles
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 46 of 1125
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
19
9
7
19
9
8
19
9
9
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
to
t
a
l

c
u
s
t
o
m
e
r
s
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%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 47 of 1125
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
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
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%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 48 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 49 of 1125
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
1,000
1,500
2,000
2,500
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
me
g
a
w
a
t
t
s
Winter
Summer
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 50 of 1125
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%
1.6%
2.0%
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
lo
a
d

g
r
o
w
t
h

p
e
r
c
e
n
t

c
h
a
n
g
e
Low Growth High Growth
Medium-Low EIA Forecast
Expected Growth
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 51 of 1125
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
3,000
4,000
5,000
0.0
2.0
4.0
6.0
8.0
10.0
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
cu
s
t
o
m
e
r
s
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
aMW
Customers
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 52 of 1125
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
10
20
30
40
50
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
cu
m
u
l
a
t
i
v
e

c
a
p
a
c
i
t
y

(
M
W
)
an
n
u
a
l

n
e
w

c
u
s
t
o
m
e
r
s
ID
WA
Cumulative Capacity (MW)
290 customers through first
quarter 2013
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 53 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 54 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 55 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 56 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 57 of 1125
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 58 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 59 of 1125
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 60 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 61 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 62 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 63 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 64 of 1125
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
15
20
25
30
35
40
45
-
50
100
150
200
250
300
12%13%15%16%18%19%21%22%24%25%27%28%30%31%
in
c
r
e
m
e
n
t
a
l

c
o
s
t

(
$
M
i
l
l
/
Y
r
)
ma
r
k
e
t

c
o
n
t
r
i
b
u
t
i
o
n

(
M
W
)
planning margin
MW
Annual Cost
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 65 of 1125
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
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
me
g
a
w
a
t
t
s
Net Firm Contracts Peaking ThermalsBaseload Thermals HydroLoad Forecast Load Forecast + PM/Reserves
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 66 of 1125
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
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
me
g
a
w
a
t
t
s
Net Firm Contracts Peaking ThermalsBaseload Thermals HydroLoad Forecast + PM/Reserves
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 67 of 1125
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
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
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
Net Firm Contracts Peaking Thermals
Baseload Thermals HydroLoad Forecast Load Forecast + Contingency
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 68 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 69 of 1125
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-38
Table 2.11: Washington State RPS Detail (aMW)
On
-
l
i
n
e

Ye
a
r
Ap
p
r
e
n
t
i
c
e

La
b
o
r

Cr
e
d
i
t
En
e
r
g
y
20
1
2

2
0
1
3

2
0
1
4

2
0
1
5

2
0
1
6

2
0
1
7

2
0
1
8

2
0
1
9

2
0
2
0

2
0
2
1

2
0
2
2

2
0
2
3

2
0
2
4

2
0
2
5

2
0
2
6

2
0
2
7

2
0
2
8

2
0
2
9

2
0
3
0

2
0
3
1

2
0
3
2

2
0
3
3
WA

S
t
a
t
e

R
e
t
a
i
l

S
a
l
e
s

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
%

1
5
%

1
5
%

1
5
%

1
5
%

1
5
%

1
5
%

1
5
%

1
5
%

1
5
%

1
5
%

1
5
%

1
5
%

1
5
%

1
5
%
RE
Q
U
I
R
E
D

R
E
N
E
W
A
B
L
E

E
N
E
R
G
Y
19
.
0

1
9
.
0

1
8
.
9

1
9
.
1

5
7
.
9

5
8
.
3

5
8
.
9

5
9
.
5

1
0
0
.
0

1
0
0
.
5

1
0
1
.
0

1
0
1
.
7

1
0
2
.
2

1
0
2
.
8

1
0
3
.
6

1
0
4
.
4

1
0
5
.
0

1
0
5
.
4

1
0
6
.
1

1
0
7
.
0

1
0
7
.
9

1
0
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
Li
t
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

2
3
.
3

2
3
.
2

2
3
.
2

2
3
.
2

2
3
.
2

2
3
.
2

2
3
.
2

2
3
.
2

2
3
.
2

2
3
.
2

2
3
.
2

2
3
.
2

2
3
.
2

2
3
.
2

2
3
.
2

2
3
.
2

2
3
.
2

2
3
.
2

2
3
.
2

2
3
.
2

2
3
.
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

3
2
.
5

3
2
.
1

3
1
.
9

3
2
.
5

3
2
.
4

3
3
.
2

3
1
.
8

3
2
.
5

3
1
.
8

3
2
.
5

3
1
.
8

3
2
.
5

3
1
.
8

3
2
.
5

3
1
.
8

3
2
.
5

3
1
.
8

3
1
.
8
Pa
l
o
u
s
e

W
i
n
d
20
1
2
1.
2

3
9
.
9

0
.
0

4
7
.
9

4
7
.
9

4
7
.
9

4
7
.
9

4
7
.
9

4
7
.
9

4
7
.
9

4
7
.
9

4
7
.
9

4
7
.
9

4
7
.
9

4
7
.
9

4
7
.
9

4
7
.
9

4
7
.
9

4
7
.
9

4
7
.
9

4
7
.
9

4
7
.
9

4
7
.
9

4
7
.
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

4
7
.
9

4
7
.
9

5
3
.
6

8
0
.
4

8
0
.
0

7
9
.
9

8
0
.
4

8
0
.
3

8
1
.
2

7
9
.
7

8
0
.
4

7
9
.
7

8
0
.
4

7
9
.
7

8
0
.
4

7
9
.
7

8
0
.
4

7
9
.
7

8
0
.
4

7
9
.
7

7
9
.
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

4
7
.
9

4
7
.
9

5
3
.
6

4
5
.
7

4
4
.
8

4
4
.
2

4
4
.
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 70 of 1125
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-39
Table 2.12: Winter 18-Hour Capacity Position (MW)

20
1
4

2
0
1
5

2
0
1
6

2
0
1
7

2
0
1
8

2
0
1
9

2
0
2
0

2
0
2
1

2
0
2
2

2
0
2
3

2
0
2
4

2
0
2
5

2
0
2
6

2
0
2
7

2
0
2
8

2
0
2
9

2
0
3
0

2
0
3
1

2
0
3
2

2
0
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

1
1
7

1
1
7

1
1
7

1
1
7

1
1
6

3
4

3
4

3
3

3
3

3
3

3
3

3
3

3
3

3
3

3
3

3
3

3
3

3
3

3
3
Hy
d
r
o

R
e
s
o
u
r
c
e
s
99
8

8
8
8

8
8
9

9
5
5

9
5
5

9
1
9

9
2
4

9
2
0

9
2
0

9
2
8

9
2
0

9
2
0

9
2
8

9
2
0

9
2
0

9
2
8

9
2
0

9
2
0

9
2
8

9
2
0
Ba
s
e

L
o
a
d

T
h
e
r
m
a
l
s
89
5

8
9
5

8
9
5

8
9
5

8
9
5

8
9
5

8
9
5

8
9
5

8
9
5

8
9
5

8
9
5

8
9
5

8
9
5

6
1
7

6
1
7

6
1
7

6
1
7

6
1
7

6
1
7

6
1
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

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
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

3
0
2

2
8
6

4
8
9

4
7
5

4
2
5

3
3
4

3
1
6

3
0
1

2
9
4

2
7
2

2
5
7

2
5
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

1
1
0

5
6
-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
%

1
7
%

1
6
%

2
9
%

2
8
%

2
5
%

1
9
%

1
8
%

1
7
%

1
7
%

1
5
%

1
4
%

1
4
%
-2
%

-
3
%

-
4
%

-
5
%

-
6
%

-
6
%

-
7
%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 71 of 1125
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-40
Table 2.13: Summer 18-Hour Capacity Position (MW)
20
1
4

2
0
1
5

2
0
1
6

2
0
1
7

2
0
1
8

2
0
1
9

2
0
2
0

2
0
2
1

2
0
2
2

2
0
2
3

2
0
2
4

2
0
2
5

2
0
2
6

2
0
2
7

2
0
2
8

2
0
2
9

2
0
3
0

2
0
3
1

2
0
3
2

2
0
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

2
9

2
9

2
9

2
9

2
6

2
6

2
6

2
6

2
5

2
5

2
5

2
5

2
5

2
5

2
5

2
5

2
5

2
5

2
5
Hy
d
r
o

R
e
s
o
u
r
c
e
s
70
1

7
0
7

6
6
3

6
3
1

6
3
8

5
8
3

5
8
0

6
2
2

6
2
4

6
2
2

6
2
2

6
2
4

6
2
2

6
2
2

6
2
4

6
2
2

6
2
2

6
2
4

6
2
2

6
2
2
Ba
s
e

L
o
a
d

T
h
e
r
m
a
l
s
78
5

7
8
5

7
8
5

7
8
5

7
8
5

7
8
5

7
8
5

7
8
5

7
8
5

7
8
5

7
8
5

7
8
5

7
8
5

5
5
6

5
5
6

5
5
6

5
5
6

5
5
6

5
5
6

5
5
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

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
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

5
7
-3
10
2

9
6

2
7

1
1

3
9

2
7

1
1
-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

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
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

5
7
-3
10
2

9
6

2
7

1
1

3
9

2
7

1
1
-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
%

1
4
%

1
0
%

1
8
%

1
7
%

1
3
%

1
2
%

1
4
%

1
3
%

1
2
%

1
1
%

1
0
%

9
%
-7
%

-
7
%

-
8
%

-
9
%

-
9
%

-
1
0
%

-
1
1
%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 72 of 1125
Chapter 2: Loads & Resources
Avista Corp 2013 Electric IRP 2-41
Table 2.14: Average Annual Energy Position (aMW)

20
1
4

2
0
1
5

2
0
1
6

2
0
1
7

2
0
1
8

2
0
1
9

2
0
2
0

2
0
2
1

2
0
2
2

2
0
2
3

2
0
2
4

2
0
2
5

2
0
2
6

2
0
2
7

2
0
2
8

2
0
2
9

2
0
3
0

2
0
3
1

2
0
3
2

2
0
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

1
2
9

1
2
8

7
6

7
6

5
6

3
1

3
0

3
0

2
9

2
9

2
9

2
9

2
9

2
9

2
9

2
9

2
9

2
9

2
9
Hy
d
r
o

R
e
s
o
u
r
c
e
s
52
7

4
9
5

4
9
5

4
9
5

4
9
0

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1
Ba
s
e

L
o
a
d

T
h
e
r
m
a
l
s
72
3

7
2
5

7
1
8

7
1
5

7
3
2

7
1
1

7
2
4

7
3
6

7
1
3

7
1
7

7
1
4

7
1
9

6
7
3

5
0
6

5
0
4

5
0
6

5
0
4

5
0
6

5
0
4

5
0
6
Wi
n
d

R
e
s
o
u
r
c
e
s
42

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0
Pe
a
k
i
n
g

U
n
i
t
s
15
3

1
3
9

1
5
4

1
5
3

1
5
3

1
5
3

1
4
7

1
5
1

1
5
2

1
5
3

1
5
2

1
5
3

1
5
2

1
5
3

1
5
2

1
5
3

1
5
2

1
5
3

1
5
2

1
5
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

4
0
4

3
9
8

3
8
0

3
7
9

3
2
1

2
9
2

2
9
9

2
6
6

2
5
9

2
4
3

2
3
7

1
7
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

1
7
3

1
6
7

1
4
8

1
4
7

1
0
6

9
6

1
0
3

7
0

6
3

4
6

3
9
-1
9

-
1
9
7

-
2
1
1

-
2
2
1

-
2
3
9

-
2
5
2

-
2
7
0

-
2
8
4
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 73 of 1125

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 74 of 1125
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 75 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 76 of 1125
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 77 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 78 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 79 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 80 of 1125
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.
0
100
200
300
400
500
600
2014 2015 2018 2023 2028 2033
en
e
r
g
y

s
a
v
i
n
g
s

(
a
M
W
)
Technical Potential
Economic Potential
Achievable Potential
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 81 of 1125
Chapter 3–Energy Efficiency
Avista Corp 2013 Electric IRP
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 82 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 83 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 84 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 85 of 1125
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
$100
$200
$300
$400
$500
0 50 100 150 200
$
p
e
r

M
W
h
average megawatts
Conservation Supply Curve
Expected Case Conservation
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 86 of 1125
Chapter 3–Energy Efficiency
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.

0
10
20
30
40
50
60
70
80
90
19
9
9
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
Energy Savings (aMW)
Spending (millions $)
Levelized Cost ($/MWh)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 87 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 88 of 1125
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 89 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 90 of 1125
Chapter 3–Energy Efficiency
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 91 of 1125

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 92 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 93 of 1125
Chapter 4–Policy Considerations
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 94 of 1125
Chapter 4–Policy Considerations
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:

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 95 of 1125
Chapter 4–Policy Considerations
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:
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 96 of 1125
Chapter 4–Policy Considerations
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 97 of 1125
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 98 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 99 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 100 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 101 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 102 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 103 of 1125
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 104 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 105 of 1125
Chapter 5 – Transmission & Distribution
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 106 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 107 of 1125
Chapter 5 – Transmission & Distribution
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)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 108 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 109 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 110 of 1125
Chapter 5 – Transmission & Distribution
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 111 of 1125
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

1
6
5
6
5
13 13
8
11
7
0
1
0
2
4
6
8
10
12
14
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
ou
t
a
g
e
s
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 112 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 113 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 114 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 115 of 1125
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 116 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 117 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 118 of 1125
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.
0
10,000
20,000
30,000
40,000
50,000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
me
g
a
w
a
t
t
s
hour
Net Load
Load
Solar Output
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 119 of 1125
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 120 of 1125
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

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 121 of 1125
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,
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 122 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 123 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 124 of 1125
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

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 125 of 1125
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)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 126 of 1125
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 127 of 1125
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
0
10
20
30
40
50
0
2
4
6
8
10
19
9
2

-
Mo
n
r
o
e

S
t
r
e
e
t

U
n
i
t

1
19
9
4

-
Ni
n
e

M
i
l
e

U
n
i
t
s

3

&

4
19
9
4

-
Ca
b
i
n
e
t

U
n
i
t

1
19
9
4

-
Lo
n
g

L
a
k
e

U
n
i
t

4
19
9
4

-
Li
t
t
l
e

F
a
l
l
s

U
n
i
t

3
19
9
6

-
Lo
n
g

L
a
k
e

U
n
i
t

1
19
9
7

-
Lo
n
g

L
a
k
e

U
n
i
t

2
19
9
9

-
Lo
n
g

L
a
k
e

U
n
i
t

3
20
0
1

-
Ca
b
i
n
e
t

U
n
i
t

3
20
0
1

-
Li
t
t
l
e

F
a
l
l
s

U
n
i
t

4
20
0
4

-
Ca
b
i
n
e
t

U
n
i
t

2
20
0
7

-
Ca
b
i
n
e
t

U
n
i
t

4
20
0
9

-
No
x
o
n

U
n
i
t

1
20
1
0

-
No
x
o
n

U
n
i
t

2
20
1
1

-
No
x
o
n

U
n
i
t

3
20
1
2

-
No
x
o
n

U
n
i
t

4
20
1
6

-
Ni
n
e

M
i
l
e

U
n
i
t
s

1

&

2
cu
m
u
l
a
t
i
v
e

a
v
e
r
a
g
e

m
e
g
a
w
a
t
t
s
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 128 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 129 of 1125
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 130 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 131 of 1125
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

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 132 of 1125
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
-
20,000
40,000
60,000
80,000
100,000
120,000
140,000
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
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 133 of 1125
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,
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 134 of 1125
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
-
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
-
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
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
cu
m
u
l
a
t
i
v
e

m
e
g
a
w
a
t
t
s
me
g
a
w
a
t
t
s
Natural Gas
Coal
Cumulative Retirements
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 135 of 1125
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
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
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
me
g
a
w
a
t
t
s
Other Wind
Solar SCCT
CCCT
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 136 of 1125
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 137 of 1125
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
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
$9.00
$10.00
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
do
l
l
a
r
s

p
e
r

d
e
k
a
t
h
e
r
m
Forecast
Consultant 1
Consultant 2
Forwards (Nov 2012)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 138 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 139 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 140 of 1125
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.

0%
2%
4%
6%
8%
10%
12%
12
,
0
0
0
12
,
5
0
0
13
,
0
0
0
13
,
5
0
0
14
,
0
0
0
14
,
5
0
0
15
,
0
0
0
15
,
5
0
0
16
,
0
0
0
16
,
5
0
0
17
,
0
0
0
17
,
5
0
0
18
,
0
0
0
18
,
5
0
0
19
,
0
0
0
19
,
5
0
0
20
,
0
0
0
20
,
5
0
0
pe
r
c
e
n
t

o
f

w
a
t
e
r

y
e
a
r
s
average megawatts
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 141 of 1125
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%
32.3%
0%
10%
20%
30%
40%
50%
NW BC AB CA MT WY SW UT CO
ca
p
a
c
i
t
y

f
a
c
t
o
r

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 142 of 1125
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.
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
Ja
n
-04
Ju
n
-04
No
v
-04
Ap
r
-05
Se
p
-05
Fe
b
-06
Ju
l
-06
De
c
-06
Ma
y
-07
Oc
t
-07
Ma
r
-08
Au
g
-08
Ja
n
-09
Ju
n
-09
No
v
-09
Ap
r
-10
Se
p
-10
Fe
b
-11
Ju
l
-11
De
c
-11
Ma
y
-12
Oc
t
-12
do
l
l
a
r
s

p
e
r

d
e
k
a
t
h
e
r
m
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 143 of 1125
Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
Figure 7.9: Stanfield Annual Average Natural Gas Price Distribution

Figure 7.10: Stanfield Natural Gas Distributions

0
100
200
300
400
500
$2
.
0
0
$3
.
0
0
$4
.
0
0
$5
.
0
0
$6
.
0
0
$7
.
0
0
$8
.
0
0
$9
.
0
0
$1
0
.
0
0
$1
1
.
0
0
$1
2
.
0
0
$1
3
.
0
0
it
e
r
a
t
i
o
n
dollars per dekatherm
2014 2020
2026 2032
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
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
do
l
l
a
r
s

p
e
r

d
e
k
a
t
h
e
r
m
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 144 of 1125
Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 145 of 1125
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%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 146 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 147 of 1125
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

0%
20%
40%
60%
80%
100%
1 877 1,753 2,629 3,505 4,381 5,257 6,133 7,009 7,885
ca
p
a
c
i
t
y

f
a
c
t
o
r
hours
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 148 of 1125
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.
0%
20%
40%
60%
80%
100%
1 877 1,753 2,629 3,505 4,381 5,257 6,133 7,009 7,885
ca
p
a
c
i
t
y

f
a
c
t
o
r
hours
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 149 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 150 of 1125
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.

$0
$20
$40
$60
$80
$100
$120
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
1
4
-33
do
l
l
a
r
s

p
e
r

M
W
h
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 151 of 1125
Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 152 of 1125
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.

0
50
100
150
200
250
300
350
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
mi
l
l
i
o
n

m
e
t
r
i
c

t
o
n
s

C
O
2
Historical
Expected Case
10th Percentile
90th Percentile
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 153 of 1125
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
NuclearOther
Coal
WindSolar
Natural Gas
0
20
40
60
80
100
120
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
av
e
r
a
g
e

g
i
g
a
w
a
t
t
s
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 154 of 1125
Chapter 7- Market Analysis
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.

$0
$10
$20
$30
$40
$50
$60
$70
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
do
l
l
e
r
s

p
e
r

M
W
h
No Coal Retirements
Expected Case
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 155 of 1125
Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
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.

0
50
100
150
200
250
300
350
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
mi
l
l
i
o
n

m
e
t
r
i
c

t
o
n
s

C
O
2
Expected Case
No Coal Retirements
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 156 of 1125
Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
Figure 7.18: Greenhouse Gas Pricing Scenarios

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

$0
$10
$20
$30
$40
$50
$60
$70
$80
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
do
l
l
a
r
s

p
e
r

m
e
t
r
i
c

t
o
n
Weighted Average
Expected Case
2020 High GHG Pricing Case
2020 Low GHG Pricing Case
2025 High GHG Pricing Case
2025 Low GHG Pricing Case
$44.60 $42.93
$49.22 $52.00
$46.51
$56.99
$47.19
$0
$10
$20
$30
$40
$50
$60
$70
Expected Case No Coal Retirements Weighted Average 2025 High 2025 Low 2020 High 2020 Low
Carbon Pricing Scenario
Carbon Pricing Scenario
Carbon Pricing Scenario
Carbon Pricing Scenario
Carbon Pricing Scenario
do
l
l
a
r
s

p
e
r

M
W
h
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 157 of 1125
Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
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.

-
50
100
150
200
250
300
350
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
mi
l
l
i
o
n

m
e
t
r
i
c

t
o
n
s

C
O
2
Expected Case No Coal Retirements
2025 High GHG Pricing Case 2025 Low GHG Pricing Case
2020 High GHG Pricing Case 2020 Low GHG Pricing Case
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 158 of 1125
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

$0
$2
$4
$6
$8
$10
$12
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
do
l
l
a
r
s

p
e
r

d
e
k
a
t
h
e
r
m
Expected Case
High Natural Gas Prices
Low Natural Gas Prices
$44.18
$55.97
$33.86
$0
$10
$20
$30
$40
$50
$60
Expected Case High Natural Gas Prices Low Natural Gas Prices
do
l
l
a
r
s

p
e
r

m
e
g
a
w
a
t
t
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 159 of 1125
Chapter 7- Market Analysis
Avista Corp 2013 Electric IRP
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.
5,000
6,000
7,000
8,000
9,000
10,000
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
im
p
l
i
e
d

m
a
r
k
e
t

h
e
a
t

r
a
t
e
Expected Case
High Natural Gas Prices
Low Natural Gas Prices
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 160 of 1125
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

0%
2%
4%
6%
8%
10%
2025 2026 2027 2028 2029 2030 2031 2032 2033
pe
r
c
e
n
t

r
e
d
u
c
t
i
o
n
Reduction in Electric Market Prices
Reduction in Greenhouse Gas Emissions
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 161 of 1125

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 162 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 163 of 1125
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
1,100
1,300
1,500
1,700
1,900
2,100
2,300
2,500
19
9
4
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
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
me
g
a
w
a
t
t

c
a
p
a
c
i
t
y
Ra
t
h
d
r
u
m
Ce
n
t
r
a
l
i
a

S
a
l
e
BP

&

K
F
C
T
1/
2

C
S
2
St
a
t
e
l
i
n
e
Hydro Upgrades
La
n
c
a
s
t
e
r
1/
2

C
S
2
Pa
l
o
u
s
e
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 164 of 1125
Chapter 8 – Preferred Resource Strategy

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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 165 of 1125
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.
ri
s
k
cost
Least Cost
Least Risk
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 166 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 167 of 1125
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.

-600
-500
-400
-300
-200
-100
0
100
200
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
me
g
a
w
a
t
t
s
/

a
v
e
r
a
g
e

m
e
g
a
w
a
t
t
s
January 1 Hour Peak (MW)
August 18 Hour Peak (MW)
Energy (aMW)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 168 of 1125
Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-7

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).
0
20
40
60
80
100
120
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
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
Qualifying Hydro Upgrades Qualifying Resources
Purchased RECs Available Bank
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 169 of 1125
Chapter 8 – Preferred Resource Strategy

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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 170 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 171 of 1125
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

0
20
40
60
80
100
120
140
160
180
0
2
4
6
8
10
12
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
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
Annual
Cumulative
0
200
400
600
800
1,000
1,200
1,400
1,600
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
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
Expected Case
Without Conservation
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 172 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 173 of 1125
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

0.00
0.10
0.20
0.30
0.40
0.50
Mil
1 Mil
2 Mil
3 Mil
4 Mil
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
me
t
r
i
c

t
o
n
s

p
e
r

M
W
h
me
t
r
i
c

t
o
n
s
Total
Tons per MWh of Load
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 174 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 175 of 1125
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.
$0
$10
$20
$30
$40
$50
$60
$70
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
do
l
l
a
r
s

p
e
r

M
W
h

(
n
o
m
i
n
a
l
)
Expected Cost
Two Sigma Low
Two Sigma High
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 176 of 1125
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.

0
20
40
60
80
100
120
140
160
180
200
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
po
w
e
r

s
u
p
p
l
y

c
o
s
t

i
n
d
e
x

Historical
Forecast
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 177 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 178 of 1125
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 179 of 1125
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
20
2
8

p
o
w
e
r

s
u
p
p
l
y

c
o
s
t

s
t
d
e
v
20 yr levelized annual power supply rev. req.
Market Only
Least Cost
Least Risk
Preferred Resource Strategy
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 180 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 181 of 1125
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 182 of 1125
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 183 of 1125
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 184 of 1125
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
$50 Mil
$75 Mil
$100 Mil
$300 Mil $350 Mil $400 Mil $450 Mil $500 Mil
20
2
8

p
o
w
e
r

s
u
p
p
l
y

s
t
d
e
v
20 yr levelized annual power supply rev. req.
Expected Case
Carbon Pricing Scenario
Carbon Pricing Scenario (Inc Conservation)
PRS (Expected Case)
PRS-(Carbon Pricing)
PRS-Higher Conservation
(Carbon Pricing)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 185 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 186 of 1125
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%
-60%
-50%
-40%
-30%
-20%
-10%
0%
10%
20%
30%
-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 FrontierPRS75% AC100% AC
125% AC
150% AC
No Conservation
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 187 of 1125
Chapter 8 – Preferred Resource Strategy

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

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 188 of 1125
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.
$482
$435 $460
$408
$0 Mil
$100 Mil
$200 Mil
$300 Mil
$400 Mil
$500 Mil
$600 Mil
Carbon Pricing Scenario-RS w/o
Colstrip
Carbon Pricing Scenario-LC RS
w/ Colstrip
Expected Case-No Colstrip RS Expected Case-PRS
le
v
e
l
i
z
e
d

p
o
w
e
r

s
u
p
p
l
y

c
o
s
t

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 189 of 1125
Chapter 8 – Preferred Resource Strategy

Avista Corp 2013 Electric IRP 8-28

Figure 8.14: Greenhouse Gas Emissions without Colstrip Units 3 and 4

Figure 8.15: Change to Power Supply Cost without Colstrip

-
0.10
0.20
0.30
0.40
0.50
Mil
1 Mil
2 Mil
3 Mil
4 Mil
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
me
t
r
i
c

t
o
n
s

p
e
r

M
W
h
me
t
r
i
c

t
o
n
s
Colstrip Reduction
Other Resources
Tons per MWh (Without Colstrip)
Tons per MWh with Colstrip
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
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
Ch
a
n
g
e

t
o

A
n
n
u
a
l

P
o
w
e
r

S
u
p
p
l
y

Ex
p
e
n
s
e
Expected Case
Expected Case (Two Sigma Risk)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 190 of 1125
Chapter 8 – Preferred Resource Strategy

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.

0
20
40
60
80
100
120
140
160
180
200
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
po
w
e
r

s
u
p
p
l
y

c
o
s
t

i
n
d
e
x

Historical
Forecast
Forecast without Colstrip
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 191 of 1125
Chapter 8 – Preferred Resource Strategy

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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 192 of 1125
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
le
v
e
l
i
z
e
d

c
o
s
t

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 193 of 1125
Chapter 8 – Preferred Resource Strategy

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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 194 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 195 of 1125
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 196 of 1125
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)
(600)
(300)
-
300
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
me
g
a
w
a
t
t
s
Low Growth
Medium Low Growth
Expected Case
High Growth
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 197 of 1125
Chapter 8 – Preferred Resource Strategy

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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 198 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 199 of 1125
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

2
0
1
5

2
0
1
6

2
0
1
7

2
0
1
8

2
0
1
9

2
0
2
0

2
0
2
1

2
0
2
2

2
0
2
3

2
0
2
4

2
0
2
5

2
0
2
6

2
0
2
7

2
0
2
8

2
0
2
9

2
0
3
0

2
0
3
1

2
0
3
2

2
0
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

2
7

3
9

5
3

6
8

7
5

8
4

9
5

1
0
4

1
1
2

1
2
4

1
3
6

1
4
8

1
6
0

1
7
0

1
8
0

1
9
2

2
0
6

2
2
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

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

1
1
7

1
1
7

1
1
7

1
1
7

1
1
6

3
4

3
4

3
3

3
3

3
3

3
3

3
3

3
3

3
3

3
3

3
3

3
3

3
3

3
3
Hy
d
r
o

R
e
s
o
u
r
c
e
s
99
8

8
8
8

8
8
9

9
5
5

9
5
5

9
1
9

9
2
4

9
2
0

9
2
0

9
2
8

9
2
0

9
2
0

9
2
8

9
2
0

9
2
0

9
2
8

9
2
0

9
2
0

9
2
8

9
2
0
Ba
s
e

L
o
a
d

T
h
e
r
m
a
l
s
89
5

8
9
5

8
9
5

8
9
5

8
9
5

8
9
5

8
9
5

8
9
5

8
9
5

8
9
5

8
9
5

8
9
5

8
9
5

6
1
7

6
1
7

6
1
7

6
1
7

6
1
7

6
1
7

6
1
7
Win
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

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
2

2
4
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

3
0
2

2
8
6

4
8
9

4
7
5

4
2
5

3
3
4

3
1
6

3
0
1

2
9
4

2
7
2

2
5
7

2
5
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
Pla
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

1
1
0

5
6
-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
%

1
6
%

1
5
%

2
8
%

2
7
%

2
4
%

1
9
%

1
8
%

1
7
%

1
6
%

1
5
%

1
4
%

1
4
%
-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

1
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
80

8
0

8
0

8
0

1
6
0

1
6
0

1
6
0

1
6
0

2
4
0

2
4
0

2
4
0

2
4
0

2
4
0

2
8
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

2
6
0

2
6
0

2
6
0

2
6
0

2
6
0

2
6
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

1
5

2
0

2
0

2
0

2
0

2
0

2
0

2
0
To
t
a
l

N
e
w

R
e
s
o
u
r
c
e
s
0
75

1
0
0
0
0

0
80

8
0

8
1

8
6

1
6
6

1
6
9

1
7
5

4
4
0

5
2
0

5
2
2

5
2
2

5
2
2

5
2
2

5
7
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

1
1

1
6

1
2
6

1
1
0

5
6

3
8

1
6
0
-5
49

3
4

3
0
-5
58

5
0

2
5
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
%

2
0
%

2
1
%

2
8
%

2
7
%

2
4
%

2
3
%

2
2
%

2
1
%

2
1
%

2
4
%

2
3
%

2
3
%

2
1
%

2
4
%

2
4
%

2
2
%

2
1
%

2
1
%

2
2
%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 200 of 1125
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

2
0
1
5

2
0
1
6

2
0
1
7

2
0
1
8

2
0
1
9

2
0
2
0

2
0
2
1

2
0
2
2

2
0
2
3

2
0
2
4

2
0
2
5

2
0
2
6

2
0
2
7

2
0
2
8

2
0
2
9

2
0
3
0

2
0
3
1

2
0
3
2

2
0
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

3
0

4
3

5
8

7
4

8
2

9
2

1
0
3

1
1
3

1
2
2

1
3
5

1
4
8

1
6
1

1
7
4

1
8
5

1
9
6

2
0
9

2
2
5

2
4
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

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

2
9

2
9

2
9

2
9

2
6

2
6

2
6

2
6

2
5

2
5

2
5

2
5

2
5

2
5

2
5

2
5

2
5

2
5

2
5
Hy
d
r
o

R
e
s
o
u
r
c
e
s
70
1

7
0
7

6
6
3

6
3
1

6
3
8

5
8
3

5
8
0

6
2
2

6
2
4

6
2
2

6
2
2

6
2
4

6
2
2

6
2
2

6
2
4

6
2
2

6
2
2

6
2
4

6
2
2

6
2
2
Ba
s
e

L
o
a
d

T
h
e
r
m
a
l
s
78
5

7
8
5

7
8
5

7
8
5

7
8
5

7
8
5

7
8
5

7
8
5

7
8
5

7
8
5

7
8
5

7
8
5

7
8
5

5
5
6

5
5
6

5
5
6

5
5
6

5
5
6

5
5
6

5
5
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

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
6

1
7
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

5
7
-3
10
2

9
6

2
7

1
1

3
9

2
7

1
1
-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

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
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
/

C
o
n
t
i
n
g
e
n
c
y
14

5
7
-3
10
2

9
6

2
7

1
1

3
9

2
7

1
1
-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

7
2

7
2

7
2

1
4
4

1
4
4

1
4
4

1
4
4

2
1
7

2
1
7

2
1
7

2
1
7

2
1
7

2
6
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

2
3
5

2
3
5

2
3
5

2
3
5

2
3
5

2
3
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

7
2

7
2

7
2

1
4
4

1
4
4

1
4
4

3
7
9

4
5
1

4
5
7

4
5
7

4
5
7

4
5
7

5
0
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

5
7

2
2

1
0
2

9
6

2
7

8
3

1
1
1

9
9

8
4

1
4
2

1
3
0

1
1
4

1
0
5

1
6
5

1
5
4

1
4
0

1
2
7

1
1
1

1
3
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
%

1
0
%

9
%

8
%

7
%

6
%

8
%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 201 of 1125
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

2
0
1
5

2
0
1
6

2
0
1
7

2
0
1
8

2
0
1
9

2
0
2
0

2
0
2
1

2
0
2
2

2
0
2
3

2
0
2
4

2
0
2
5

2
0
2
6

2
0
2
7

2
0
2
8

2
0
2
9

2
0
3
0

2
0
3
1

2
0
3
2

2
0
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

2
0

2
9

3
9

5
1

5
5

6
2

7
0

7
7

8
3

9
2

1
0
1

1
0
9

1
1
8

1
2
6

1
3
4

1
4
2

1
5
3

1
6
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

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

1
2
9

1
2
8

7
6

7
6

5
6

3
1

3
0

3
0

2
9

2
9

2
9

2
9

2
9

2
9

2
9

2
9

2
9

2
9

2
9
Hy
d
r
o

R
e
s
o
u
r
c
e
s
52
7

4
9
5

4
9
5

4
9
5

4
9
0

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1

4
8
1
Ba
s
e

L
o
a
d

T
h
e
r
m
a
l
s
72
3

7
2
5

7
1
8

7
1
5

7
3
2

7
1
1

7
2
4

7
3
6

7
1
3

7
1
7

7
1
4

7
1
9

6
7
3

5
0
6

5
0
4

5
0
6

5
0
4

5
0
6

5
0
4

5
0
6
Wi
n
d

R
e
s
o
u
r
c
e
s
42

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0

4
0
Pe
a
k
i
n
g

U
n
i
t
s
15
3

1
3
9

1
5
4

1
5
3

1
5
3

1
5
3

1
4
7

1
5
1

1
5
2

1
5
3

1
5
2

1
5
3

1
5
2

1
5
3

1
5
2

1
5
3

1
5
2

1
5
3

1
5
2

1
5
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

4
0
4

3
9
8

3
8
0

3
7
9

3
2
1

2
9
2

2
9
9

2
6
6

2
5
9

2
4
3

2
3
7

1
7
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

1
7
3

1
6
7

1
4
8

1
4
7

1
0
6

9
6

1
0
3

7
0

6
3

4
6

3
9
-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

6
8

6
8

6
8

1
3
5

1
3
5

1
3
5

1
3
5

2
0
4

2
0
4

2
0
4

2
0
4

2
0
4

2
4
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

2
4
5

2
4
5

2
4
5

2
4
5

2
4
5

2
4
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

6
8

6
8

6
8

1
3
5

1
3
5

1
3
5

3
8
0

4
4
9

4
5
4

4
5
4

4
5
4

4
5
4

5
0
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

1
7
3

1
6
7

1
4
8

1
4
7

1
0
6

1
6
4

1
7
0

1
3
7

1
3
0

1
8
1

1
7
4

1
1
6

1
8
4

2
3
8

2
3
3

2
1
5

2
0
3

1
8
4

2
1
6
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 202 of 1125
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 203 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 204 of 1125
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 205 of 1125
Chapter 9–Action Items
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 206 of 1125
Chapter 9–Action Items
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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 207 of 1125
Chapter 9–Action Items
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.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 208 of 1125
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 ManagerMike 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 ComplianceXin 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:
[e-mail]

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 209 of 1125

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 210 of 1125

2013 Electric Integrated
Resource Plan

Appendices
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 211 of 1125
Table of Contents

Appendix A – Technical Advisory Committee Presentations (Page 1)
Technical Advisory Committee Meeting 1 (Page 1)
Technical Advisory Committee Meeting 2 (Page 73)
Technical Advisory Committee Meeting 3 (Page 146)
Technical Advisory Committee Meeting 4 (Page 257)
Technical Advisory Committee Meeting 5 (Page 416)
Technical Advisory Committee Meeting 6 (Page 518)

Appendix B – 2013 Work Plan (Page 572)

Appendix C – Conservation Potential Assessment Study (Page 579)

Appendix D – Transmission Studies (Page 872)

Appendix E – New Resource Table for Transmission (Page 910)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 212 of 1125

2013 Electric Integrated
Resource Plan

Appendix A – 2013 Electric IRP
Technical Advisory Committee
Presentations

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 213 of 1125
Avista’s 2013 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 1 Agenda
Wednesday, May 23, 2012
Conference Room 130

Topic Time Staff

1. Introduction 8:30 Kalich

2. Powering Our Future Game 8:35 Silkworth

3. 2011 Renewable RFP 10:30 Silkworth

4. Palouse Wind Project Update 11:00 First Wind

5. Lunch 12:00

6. 2011 IRP Acknowledgement 12:45 Kalich

7. Energy Independence Act Compliance 1:45 Lyons/Gall
& Forecast

8. Work Plan 2:15 Lyons

9. Adjourn 3:00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 214 of 1125
Powering Our Future Game

Steve Silkworth, Manager of Wholesale Marketing & Contracts
Anna Scarlett, Communications Manager
First Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
May 23, 2012

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 215 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 216 of 1125
You’re the power planner
Meet demand
Meet renewable portfolio standards
Tomorrow - 2030
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 217 of 1125
Wash. Renewable Portfolio Standards
2012 - 3% of energy delivered to Washington customers *Dam upgrades, purchased renewable energy 2016 - 9% *Palouse Wind *Kettle Falls 2020 (and beyond) - 15% 
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 218 of 1125
Today’s Energy Generation Capability
42.5%
12.7%
34.0%
0.5%
2.8%
7.5% Gas
Coal
Hydro
Wind
Biomass
Conservation
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 219 of 1125
Natural Gas
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 220 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 221 of 1125
8
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 222 of 1125
1.Review the materials at your table.
2.Choose a note taker and a spokesperson from your table.
3.Write table # on your worksheet.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 223 of 1125
Round 1
Using your blocks, choose any mix you like, placing them on the corresponding spaces on your game board.
Each block signifies 10 percent of your total new resources and you may only use a total of 10 blocks (or 100%).
You can use any combination you like, and you can even use one resource for all your new energy if you like.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 224 of 1125
Round 1 Conclusion
1.Record your ‘resource mix’ on the worksheet.
2.Give your worksheet to a facilitator when you are finished.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 225 of 1125
Group discussion
12
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 226 of 1125
•Wind
•Solar •Natural Gas
•Coal
•Nuclear
•Biomass
•Hydropower

Meets Wash. Renewable Portfolio Standards
Dependable/can be generated on demand to meet peak demand
Conservation
13
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 227 of 1125
Round 2
Meet electric demand.
Meet renewable portfolio requirements over the next 20 years.
Consider customers’ bills, carbon emissions, and your ability to generate enough power to serve all your customers during peak demand times.

14
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 228 of 1125
Meets Wash.
Renewable Portfolio
Mandates
Meets customer needs
during peak demand

Relative Cost
Conservation/Energy Efficiency*  $-$$$
Natural Gas  $
Wind  $$
Hydroelectric**   $$
Biomass***   $$$
Coal  $$$
Nuclear  $$$$
Solar  $$$$$
* Energy efficiency programs cost more as the amount of energy that is saved increases.
** Only new hydroelectric plants and the additional energy produced with upgrades performed after 1999 qualify as renewable under
Washington State Renewable Portfolio Standards.
***Only biomass plants built after 1999 qualify as renewable under Washington State Renewable Portfolio Standards.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 229 of 1125
Round 2
Using your blocks, choose any mix you like, placing them on the corresponding spaces on your game board.
Each block signifies 10 percent of your total new resources and you may only use a total of 10 blocks (or 100%).
Use a combination of resources that meet Renewable Portfolio Mandates and resources that are considered dependable and will meet peak demand.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 230 of 1125
Round 2 Conclusion
1.Record your ‘resource mix’ on the worksheet.
2.Give your worksheet to a facilitator when you are finished.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 231 of 1125
Group Discussion

Discussion of impact to emissions, costs, risk
Meet demand at peak times?
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 232 of 1125
Conclusion
Were there any surprises?
What did you learn? What questions do you have?

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 233 of 1125
2011 Renewable RFP
Steve Silkworth, Manager of Wholesale Marketing & Contracts
First Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
May 23, 2012

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 234 of 1125
2

•2009 IRP: identified the need for 48 aMW RECs by 2016 to meet
the 9% renewable goal in Washington state
• Over supply of turbines. Turbine prices declined to 2004 levels
• ITC/PTC expires in 2012
• Washington state 75% sales tax exemption through June 2013
• Levelized costs were estimated to result in 30% to 40% lower cost
than the 2009 RFP of 14 months prior
• REC demand will increase in the next few years as the 2016
tranche approaches

Why Issue a Renewables RFP in 2011?
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 235 of 1125
3
• RFP Issued: February 22, 2011
• Quantity: up to 35 aMW of I-937 qualifying renewable power
including all renewable energy attributes
• Delivery Start: on or before 12/31/2012
• Term: 20+ years
• Avista requested competitive bids for projects or project
output at the most favorable price available. Expected
Delivered Price: $62 per MWh (20 yr) levelized

Renewable Resource RFP Overview
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 236 of 1125
4
• Received proposals from 11 bidders with 17 options.
• Technologies submitted
o Wind – Approximately 769 MW
o Landfill gas – 5 MW
• Pricing was very competitive and reflected the current down-turn
in the renewable energy market.
• Comparable projects proposed through the 2009 RFP
(approximately 15 months prior) were now up to 30% to 40%
less expensive in the 2011 solicitation.

Renewable Resource RFP Overview
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 237 of 1125
5
Montana
Wind
Wind
Palouse Wind
Wind
Wind
Wind
Land Fill Gas
Wind
Wind Wind
Wind
Bid Project Locations
Received bids totaling 774 MW (769 MW wind, 5 MW landfill gas)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 238 of 1125
6
Evaluation Criteria
1.Risk Management (30%)
– Financing ability/experience
2.Net Price (40%)
– Expected benefit - expected cost
3.Price Risk (10%)
– Pricing type, O&M, generation quality, and optionality
4.Electric Factors (10%)
– Transmission, procurement process and equipment
5.Environmental/Community (10%)
– Permits process and location
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 239 of 1125
7
Palouse Wind
• Approximately 105 MW
• Near Oakesdale, WA (35 miles south of Spokane)
• Interconnected directly to Avista system
• Developed by First Wind
• Commercial operation by 12/31/2012
• Vestas 1.8 MW turbines – 100M Rotors
• Net capacity factor – expected: 37.5%
• Developer will take advantage of expiring tax incentives

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 240 of 1125
Palouse Wind - 2013 Avista IRP TAC Meeting
Spokane, WA – May 23, 2012

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 241 of 1125
Overview
•Founded in 2002 and headquartered in Boston
with 200+ employees at offices and project
sites around the U.S.
•Focused on renewable energy, natural gas,
energy storage and transmission
development in core markets, such as the
Northeast, West and Hawaii
•Wind projects range from 15 – 205 MW,
situated on private, state and federal lands
•Vertically integrated to develop projects from
conception through operations bringing stable,
long-term contracts to utilities and customers in
high-demand markets
•Successfully raised over $6 billion to convert
development projects into operating assets

2
Milford Wind – 306 MW in Utah
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 242 of 1125
First Wind Projects
•Own and Operate: 12 projects, 750 MW
•Operate: 1 project, 45 MW
•In Construction: 4 projects, 230 MW
3
Mars Hill 42 MW
Stetson I 57 MW
Stetson II 26 MW
Steel Winds I 20 MW
Sheffield 40 MW
Rollins 60 MW
Cohocton 125 MW
Milford I 204 MW
Milford II 102 MW
KWP I 30 MW
KWP II 21 MW
Kahuku 30 MW
Steel Winds II 15 MW
Palouse 105 MW
Kawailoa 69 MW
Kahuku, HI
KWP, HI Milford I & II, UT
Cohocton, NY
Mars Hill, ME
Power County 45 MW
Projects we Own and Operate
Projects Under Construction
Development Areas
First Wind Office
Operating Projects
Steel Winds, NY
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 243 of 1125
A Company of Firsts
Consistently demonstrated leadership in Innovation, Environmental
Stewardship, and Community Engagement

4
Siting
•Steel Winds (20 MW) – Development on EPA
Brownfield Site
Environmental
•KWP (30 MW) – Development with Habitat
Conservation Plan
Power Sales
•Stetson Phase II (26 MW) – Unique PPA off-
take with Harvard University
Transmission Engineering
•Milford (204+ MW) – Developed 88-mile
Generator Lead
Technology
•Kahuku (30 MW) – Integrated 15 MW Battery
Energy Storage System
Our first-in-the-state Sheffield Wind project required
considerable environmental innovations in Vermont.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 244 of 1125
Track Record
•Asset Conversion: Since its founding, First Wind has raised over $6 billion to
convert development projects into operating assets
5
$0
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
$7,000
2005 2006 2007 2008 2009 2010 2011
Mi
l
l
i
o
n
s

PPA Prepayment
Turbine Supply Loan
Corporate Debt
ITC Grant
Tax Equity
Project Debt
Select Partners
Sources of capital by year
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 245 of 1125
Palouse Wind
6
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 246 of 1125
•Located on ridges between State Route
195 and the town of Oakesdale in
Whitman County
•Strong winter peaking wind resource,
complimentary to regional spring hydro
resource
•Utilizing 58 Vestas V100 wind turbines,
with total capacity of 105 MW
•30-year PPA with Avista, and
interconnection to their new Benewah to
Shawnee 230kV line
•$210 million capital raise from private
sector
•Will be largest energy facility in
Whitman County, producing renewable
energy for 30,000 homes
•40 farmers involved

Palouse Wind
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 247 of 1125
Phases of Developing a Palouse Wind
• 3 years of
wind data from
4 tower
locations
• Third party
wind validation

Wind
Resource
Assessment
Transmission
Analysis Development
Permitting/
Public
Involvement
Power
Purchase
Agreement
• Transmission
• Gen-tie
routing
• Site design
• Landowner
Relations
• Community
Involvement
• Envr. Studies
• Public Meetings
• EIS and CUP
Hearing
2007 2008 2009 2010 2011
• Avista PPA
signed
• Interconnection
Agreement
• Financing
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 248 of 1125
Thorough Environmental Review
•First EIS in Whitman County – ever
•All areas of the built and natural environment were evaluated
per state law
•Over 250 Comments received during EIS process
•164 conditions to consider
during construction and operations
Important Conditions
1.County CUP Compliance Package. Preconstruction micrositing surveys
2.Habitat Mitigation. WDFW and Palouse Prairie impacts
3.Avian fatality monitoring
4.Technical Advisory Committee
5.Decommissioning Requirements

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 249 of 1125
Successful Financing
•First Wind has secured $210 Million to finance the
Palouse Wind project
•Key Bank-Joint lead arranger and administrative
agent
•Norddeutsche Landesbank Girozentrale, CoBank ACB,
Banco Santander served as joint lead arrangers

“We applaud First Wind’s dedication that
brings significant investment to Eastern
Washington. The financing of Palouse Wind
demonstrates the solid fundamentals of the
wind project that will provide an excellent
source of renewable power for Washington
ratepayers.”
- Andrew Redinger
KeyBanc Director Utility &Renewable Energy
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 250 of 1125
Palouse Wind represents a Major Investment in
Whitman County
•Construction will support 150 - 250 jobs
•Approximately $30 million of spending with local
businesses in Whitman County and the Inland Northwest
•15 full-time operations jobs, and
ongoing contracting with local businesses
•Property Tax and Sales Tax Revenue
•Over $700,000 per year generated in tax revenue
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 251 of 1125
Construction of Palouse Wind
•Construction meets the standards of County CUP conditions
•40 permanent acres impacted, 5 acres CRP/grassland
•RMT, Inc selected as General Contractor
•Approximately 50 workers on site since October,
increasing to 250 this summer
•Civil work on roads and turbine pads
•Avista switchyard construction
12
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 252 of 1125
Inland NW Jobs
Contractors to-date include
•Busch Distributors, Oakesdale
•Pearson Fence, Colfax
•Wheatland Inn, Colfax
•Crossets Market, Oakesdale
•Brass Rail, Rosaila
•Plateau Archeology, Pullman
•Stewart Title, Pullman
•Schweitzer Engineering, Pullman
•Memorable Events, Colfax
•Goodfellow Brothers, Wenatchee
•Lydig Construction, Spokane
•Garco Construction, Spokane
•STRATA, Pullman
•Taylor Engineering, Pullman
•Atlas Sand and Gravel, Clarkston
(local gravel pit)
•Landau Associates, Colfax
•Gallatin, Spokane
•Henkles & McCoy, Vancouver
•Ch2MHill, Spokane

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 253 of 1125
Long Term Commitment on the Palouse
•First Wind Scholarship Program
•Palouse Empire Fair, Lentil Fest
•High School boosters
•4H and FFA Clubs
•Fishing Kids
•Bikes for Books
•Youth sports sponsorship
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 254 of 1125
What to expect in 2012
April May June July August Sept Oct Nov Dec
Mob all
construction units
Transmission Line
Foundations
Turbine Installation
Substation Commercial
Operation
Hire Operations
Staff
Collector System
Turbine Commissioning
O&M Building
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 255 of 1125
Ben Fairbanks
Director, Business Development
p – 971.998.1411
[e-mail]
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 256 of 1125

2011 Electric Integrated Resource Plan
Acknowledgement Review

Clint Kalich, Manager of Resource Planning and Analysis
First Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
May 23, 2012

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 257 of 1125
Acknowledgements
Idaho Public Utilities Commission (IPUC) Case No. AVU-E-11-04,
ORDER NO. 32444 acknowledged Avista’s 2011 IRP.
Washington Utilities and Transportation Commission (UTC) Docket No.
UE-101482 acknowledged Avista’s IRP on January 12, 2012.
Acknowledgement is not a pre-approval of the Preferred Resource
Strategy or the IRP itself. Future acquisitions obtain a prudence
determination in general rate cases.
IPUC encouraged Avista to make continued efforts to include more
public involvement in the TAC.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 258 of 1125
Public Comments
No public comments received in Washington jurisdiction.
Two public comments in Idaho jurisdiction:
An individual commenter thought the Company should not receive
any public money or rate increases for wind generation.
Benewah County, Idaho was concerned that the potential federal
greenhouse gas policies in the IRP would lead to increased rates
and negatively impact the County, and the polices were not
supported by the science. They advocated for Avista to develop
alternative policies to benefit the environment and the County.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 259 of 1125
Resource Needs
IPUC believes the capacity planning assumptions are reasonable
given the Company’s access to and the availability of markets if
resource deficits are higher than predicted.
UTC: The 14% summer and 15% winter planning margin above
operating reserves are appropriate for planning for peak loads and are
consistent with other regional utilities. This is an improvement over
the 2009 IRP methodology.
UTC: Continue involvement in the NPCC Resource Adequacy Forum.
UTC: Continue to analyze planning margin to determine the most
cost-effective way to reliably meet resource adequacy needs.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 260 of 1125
Load Forecasts
IPUC supports the inclusion of projected electric vehicle consumption.
IPUC believes the load forecast assumptions to be reasonable.
UTC requested a range of load forecasts in the 2009 IRP
acknowledgement. 2011 IRP included a high growth case (2.33%) and
a low growth case (0.93%). This is expected to continue in future
IRPs.
UTC: the Global Insights forecasts on Table 2.1, p. 2-4. GDP growth
(2.7%), unemployment (5%), 1.58 million housing starts per year, and
4.75% federal funds rate may be too optimistic given the current state
of the economy. Need to continue to monitor and test models under
more conservative growth assumptions.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 261 of 1125
Energy Efficiency
IPUC has concerns that the Company “…may not pursue “all” cost-
effective conservation if it adheres to certain conservation-potential
limitations expressed in the IRP” (maximum versus realistic achievable
potential). The 2007 and draft 2012 Idaho State Energy Plans direct
the IPUC to encourage utilities to pursue “all cost effective
conservation.”
UTC: Considers the Conservation Potential Assessment (CPA) done for
the 2011 IRP to be sound and includes a reasonable range of forecast
assumptions.
UTC: Finds the CPA sensitivity analysis regarding changes to avoided
cost “… to be useful in identifying both the potential achievable over this
time horizon, but also for identifying higher costs along the supply
curves.”

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 262 of 1125
Renewable Portfolio Standard
IPUC: Early acquisition of wind to meet RPS requirements ahead of
need will be will be scrutinized in a future rate case, but the early
acquisition allows for the use of tax incentives and lower wind costs.
UTC: The Company needs to more clearly describe the method used
to calculate REC reserve requirements and how the reserves are used
for RPS compliance.
UTC: Need to provide clear analysis of how the Company specifically
(new resources, RECs or banking) plans to meet the higher RPS goals
from 2016 and beyond.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 263 of 1125
Transmission & Distribution
IPUC: Staff is encouraged by efforts to include distribution savings
and supports continued involvement with regional transmission groups.
UTC: Estimated costs for the integration of new resources are useful.
UTC: Want to see continued cooperation with BPA on the direct
interconnection of Lancaster to ensure completion of the project by the
end of 2012.
UTC: Continue to refine the analysis of feeder upgrades as they are
completed and track actual loss savings in the 2013 IRP.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 264 of 1125
Generation Resource Options
UTC would like to see a discussion and analysis of electric storage
technologies for “firming intermittent generation resources or for
meeting peaks in load.” This should include cost-effectiveness,
commercial availability, and where this resource would fit in relation to
other generating resources.
UTC wants “… an explicit discussion of the future costs and liabilities
of operating Colstrip over the 20 year planning horizon” including costs
of anticipated EPA regulations because it is a significant resource and
the Company’s only coal-fired asset.
UTC: Model a scenario for the 2013 IRP without Colstrip in the
Company’s resource portfolio and show “… estimates of the impact on
Net Present Value (cost) of its portfolio and rates”.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 265 of 1125
Modeling Approach
UTC: Finds the efficient frontier analysis to be informative in
highlighting the tradeoff between risk and cost when choosing
resources.
UTC: Support the continued improvement of modeling for the IRP “…
and urge the Company to explore its thinking and strategy with the
TAC (technical advisory committee) at an early date.”

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 266 of 1125
Preferred Resource Strategy
IPUC: Supports increased levels of energy efficiency. Should also
include analysis and consideration of cost-effective demand response
in the next IRP.
IPUC: Tipping point analysis is beneficial to test how robust the PRS is
and to point out which variables are most important to the PRS.
UTC: Sensitivity analyses were informative.
High and low load growth cases (50% of expected load growth) is
too improbable as a tipping point. Want to see this refined.
Should include “… load growth variances that result in incremental
changes to the PRS, such as the delaying the acquisition of the
2018 SCCT.”

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 267 of 1125
Action Plan
IPUC: The Company made progress on the 2009 IRP Action Items
and the 2011 Action Items should enhance the 2013 IRP.
UTC: 2011 Action Plan is presented well and is well grounded in the
modeling and analysis.
UTC: encourages close monitoring of actual load growth and changes
in the market which may require changes to the PRS and the Action
Plan.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 268 of 1125

Energy Independence Act Compliance &
Forecast
John Lyons, Power Supply Analyst
James Gall, Senior Power Supply Analyst
First Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
May 23, 2012

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 269 of 1125
Energy Independence Act
RCW 19.285 – The Energy Independence Act is also known as Initiative Measure No. 937 (I-937)
Requires utilities with more than 25,000 customers to obtain
fifteen percent of their electricity from qualified renewable
resources by 2020.
Also requires the acquisition of all cost-effective energy
conservation.
I-937 approved by Washington voters on November 6, 2006.

2 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 270 of 1125
Reporting Requirements
Annual compliance report, per WAC 480-109-040, is due on or before June 1st
beginning in 2012 and must include the following:
Utility’s annual Washington load for the prior two years,
Amount of eligible renewable resources and/or renewable resource credits
needed to meet annual goal by January 1 of the target year,
Amount and cost of each type of eligible resource used,
Amount and cost of any renewable energy credits acquired,
Type and cost of the least-cost substitute non-eligible resources available,
Incremental cost of eligible renewable resources and renewable energy
credits, and
The ratio of this investment relative to the utility's total annual retail revenue
requirement.

3 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 271 of 1125
Renewable Energy Requirements
Based on a percentage of Washington state
retail sales using two year rolling average
3% of sales by January 1, 2012
9% of sales by January 1, 2016
15% of sales by January 1, 2020
4 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 272 of 1125
2012 Legislative Modifications
SB 6414: Review Process for Electric Generation Project or Conservation
Review
SB 5575: Biomass Bill
Avista’s 50 MW Kettle Falls plant becomes a “qualified renewable
resource” beginning January 1, 2016 for the Energy Independence Act

5 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 273 of 1125
2012 Projected Compliance
aMW
Required Renewable Energy 18.9
Spokane River
Long Lake #3 1.6
Little Falls #4 0.6
Clark Fork River
Cabinet Gorge 2-4 10.8
Noxon Rapids 1-4 5.8
Wanapum Fish Bypass 2.0
Total Hydro Upgrades 20.8
Palouse Wind (2012) TBD
6 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 274 of 1125
Long-Term Renewable Energy Requirements
& Compliance Forecast
0
20
40
60
80
100
120
140
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
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
Qualifying Hydro Upgrades Kettle Falls Palouse Wind
Purchased RECs Potential Banking Requirement & Contingency
Requirement
7 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 275 of 1125
Work Plan
John Lyons, Power Supply Analyst
First Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
May 23, 2012

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 276 of 1125
Technical Advisory Committee Meetings
May 23, 2012: Powering Our Future Game, 2011 Renewable RFP, Palouse Wind
Project Update, 2011 IRP Acknowledgements, Energy Independence Act
Compliance & Forecast, and 2013 Work Plan.
September 2012: Two day TAC meeting. Day 1: Plant tour. Day 2: new resource
assumptions, Spokane River assessment, and energy efficiency.
November 2012: Load & resource forecast, reliability planning, stochastic
assumptions, and transmission cost studies.
January 2013: Environmental policy update, electric and gas price forecasts,
scenario development.
March 2013: Draft Preferred Resource Strategy (PRS), energy efficiency, review of
scenarios and futures, and portfolio analysis.
April 2013: Review of the final PRS and action items.
June 2013: Review of the Draft 2013 IRP.

2
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 277 of 1125
2013 Draft Electric IRP Timeline
Preferred Resource Strategy (PRS) Tasks Target Date
Finalize load forecast July 2012
Identify regional resource options for electric market price forecast September 2012
Identify Avista’s supply & conservation resource options September 2012
Update AURORAxmp database for electric market price forecast October 2012
Finalize data sets/statistics variables for risk studies October 2012
Draft transmission study due October 2012
Energy efficiency load shapes input into AURORAxmp October 2012
Final transmission study due November 2012
Select natural gas price forecast December 2012
Finalize deterministic base case December 2012
Base case stochastic study complete January 2013
Finalize PRiSM 3.0 model January 2013
Develop efficient frontier and PRS January 2013
Simulation of risk studies “futures’ complete February 2013
Simulate market scenarios in AURORAxmp February 2013
Evaluate resource strategies against market and future scenarios March 2013
Present preliminary study and PRS to TAC March 2013
3
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 278 of 1125
2013 Draft Electric IRP Timeline
Writing Tasks Target Date
File 2013 IRP Work Plan August 2012
Prepare report and appendix outline September 2012
Prepare text drafts April 2013
Prepare charts and tables April 2013
Internal drafts released at Avista May 2013
External draft released to the TAC June 2013
Final editing and printing August 2013
Final IRP submission to Commissions and distribution to TAC August 31, 2013
4
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 279 of 1125
2013 Integrated Resource Plan Modeling Process
Preferred
Resource
Strategy

AURORA
“Wholesale Electric Market” 500 Simulations

PRiSM
“Avista Portfolio” Efficient Frontier
Fuel Prices
Fuel Availability
Resource Availability
Demand
Emission Pricing
Existing Resources
Resource Options
Transmission
Resource & Portfolio Margins
Conservation
Trends
Existing
Resources
Avista Load
Forecast
Energy, Capacity, & RPS Balances New Resource Options & Costs
Cost Effective T&D Projects/Costs
Cost Effective Conservation Measures/Costs
Mid-Columbia Prices
Stochastic Inputs Deterministic Inputs
Capacity Value
Avoided
Costs
5
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 280 of 1125
2013 Electric IRP Draft Outline
Executive Summary
Introduction and Stakeholder Involvement
Loads and Resources
Economic Conditions
Avista Load Forecast
Load Forecast Scenarios
Avista Resources and Contracts
Reserve Margins
Resource Requirements

6
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 281 of 1125
2013 Electric IRP Draft Outline
Energy Efficiency and Demand Response
Conservation Potential Assessment
Overview of Energy Efficiency Potentials
Sensitivity of Potential to Customer and Economic Growth
Avoided Cost Sensitivities
Energy Efficiency Related Financial Impacts
Integrating Results into Business Planning and Operations
Policy Considerations
Environmental Concerns
Greenhouse Gas Issues
State and Regional Level Policies

7
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 282 of 1125
2013 Electric IRP Draft Outline
Transmission & Distribution
Avista’s Transmission System
Regional Transmission Issues
Transmission Construction Costs
Integration of Resources on the Avista Transmission System
Distribution Efficiencies
Generation Resource Options
Assumptions
New Resources
Hydroelectric and Thermal Plant Upgrades

8
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 283 of 1125
2013 Electric IRP Draft Outline
Market Analysis
Assumptions and Fuel Prices
Market Price Forecasts
Scenario Analysis
Preferred Resource Strategy
Resource Selection Process
Preferred Resource Strategy
Efficient Frontier Analysis
Avoided Costs
Portfolio Scenarios
Action Items

9
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 284 of 1125
Avista’s 2013 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 2 Agenda
Wednesday, September 5, 2012
Conference Room 328

Topic Time Staff
1. Introduction 8:30 Storro

2. Avista REC Planning Methods 8:35 Gall

3. Energy and Economic Forecasts 9:00 Forsyth

4. Break 10:30

5. Shared Value Report 10:45 Wuerst

6. Lunch 11:30

7. Generation Options 12:30 Lyons

8. Break 1:30

9. Spokane River Assessment 1:45 Schwall

10. Adjourn 3:00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 285 of 1125

Avista REC Planning Methods
James Gall, Senior Power Supply Analyst
Second Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
September 5, 2012

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 286 of 1125
Energy Independence Act - Refresher
RCW 19.285 – The Energy Independence Act is also known as Initiative Measure No. 937 (I-937)
Requires utilities with more than 25,000 customers to obtain
fifteen percent of their electricity from qualified renewable
resources by 2020.
Also requires the acquisition of all cost-effective energy
conservation.
I-937 approved by Washington voters on November 6, 2006.

2 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 287 of 1125
Renewable Energy Requirements - Refresher
Based on a percentage of Washington state
retail sales using two year rolling average
3% of sales by January 1, 2012
9% of sales by January 1, 2016
15% of sales by January 1, 2020
3 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 288 of 1125
2011 IRP Planning Margin Requirements
In past IRP’s Avista included a REC planning margin for the variability of load and generation due to weather for
compliance of the EIA.
The 2011 IRP included a planning margin of 7 to 8 aMW
between 2012 and 2016 and 23+ aMW after 2016 to account for wind variability
This planning margin was a threshold for the minimum amount of additional REC’s to hold over the expected
requirement.

4 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 289 of 1125
What Has Changed Since 2011 IRP
Load forecast is lower
Signed 105 MW PPA for Palouse Wind
Washington SB 5575 counts Kettle Falls as “renewable”
beginning in 2016
Hydro upgrades may use long-term average incremental energy rather than estimated actual incremental energy for compliance

5 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 290 of 1125
What Planning Margin Do We Need Now?
Develop risk model of REC compliance
o Simulates future loads and qualifying wind, hydro, and
biomass output
o Accounts for actual and potential REC purchases and sales
o Simulates 100 future outcomes
Model allows RECs to be “Rolled” over to future years
o Does not allow bring RECs back from future years
o Pulling REC’s from future years is allowed but creates a
short position that would be needed to be filled
Tested several REC scenarios and the effects of policy choices

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 291 of 1125
Risk Assumptions
Load: Expected Forecast with Standard Deviation of 4.2% of
Mean with a normal distribution
Hydro: 1986 to 2011 upgrade estimated energy savings
(random draw)
Palouse: 1990 to 2010 estimates provided by First Wind
(random draw)
Kettle Falls: Expected to run 10 out of 12 months with standard
deviation at 5% of mean with a normal distribution. Assumes
75% of fuel counts as renewable

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 292 of 1125
REC Planning Margin Over Time
2015 (aMW) 2020 aMW
Scenario Expected
REC
Position
5th
Confidence
Level REC
Position
Implied
Planning
Margin
Expected
2020 REC
Position
(aMW)
2009 Status
Higher load forecast, no Palouse or Kettle Falls, Hydro is variable, no EWEB purchase, no Wanapum RECs
-3.1 -9.6 6.5 91.3
2009 with “Hydro
Methodology 3”:
Same study as above with 10 year historical hydro
-0.9 -1.9 1.0 89.0
Today’s expectations
Lower load forecast, Palouse signed, Kettle Falls Counts, Hydro is flat, EWEB sold through 2014.
Long Long Zero Zero
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 293 of 1125
2013 IRP Implications
REC surplus exceeds potential planning margin requirements
No REC planning margin will be included for this IRP to meet
the EIA
Planning margins will be taken into account when selling excess
RECs
Without Kettle Falls we would have a 9.9+ aMW Planning
Margin for Load/Wind Variation (assumes hydro is fixed)

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 294 of 1125
Commerce REC Filing
Handout:
http://www.commerce.wa.gov/site/1001/default.aspx
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 295 of 1125
TAC Economic Outlook
September 5, 2012
Grant D. Forsyth, Ph.D.
Chief Economist
509-495-2765
[e-mail]
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 296 of 1125
Goals of Update
Highlight national and regional economic
conditions that impact customer and usage
forecasts.

Highlight long-run issues related long-run growth
and fiscal consolidation.

Review most recent electric load forecast.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 297 of 1125
National GDP Growth and Inflation: Recent Global
Insight (GI) Forecasts
Data Source: BEA, Global Insight, and author’s calculations.
 Modest growth with increasing downside risks to growth in 2012 and 2013: Europe, Asia,
and Congress (aka “Fiscal Cliff”).
 Housing market appears to be stabilizing.
2.9 2.8
3.3
2.6
2.2 2.4
3.4
2.6
2.1
1.8
2.8 2.6
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
2012 Forecast 2013 Forecast 2014 Forecast Long-Run Average
Forecast 2015-2041
Re
a
l

G
D
P

G
r
o
w
t
h

(
%
)
Comparison of Global Insight Forecasts for U.S. GDP Growth
May 2011 GI Forecast June 2012 GI Forecast August 2012 GI Forecast
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 298 of 1125
SA Employment Index in Key MSAs, June 2009-July 2012
Data Source: BLS and author’s calculations.
 Employment levels similar to late 2009. Employment is growing in big metro areas.
Holding down service area population growth and household formation.
94
96
98
100
102
104
106
Ju
n
e

2
0
0
9

=

1
0
0
Nez Perce+Asotin ID-WA Jackson, OR Spokane+Kootenai WA-ID
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 299 of 1125
SA Employment Index for Avista’s Service Area, June
2009-July 2012
Data Source: BLS and author’s calculations.
94
95
96
97
98
99
100
101
102
103
Ju
n
e

2
0
0
9

=

1
0
0
U.S.Avista MSAs
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 300 of 1125
Unemployment Rate for July, 2009-2012
Data Source: BLS and author’s calculations.
 Jackson, OR (Medford MSA) has fallen the most, rates still high.
 Some of the declines reflect a falling labor force from discourage workers “dropping out.”
 Expect unemployment rates to remain elevated for rest of 2012 and into 2013.
0%
2%
4%
6%
8%
10%
12%
14%
Nez Perce+Asotin ID-WA Spokane+Kootenai WA-ID Whitman, WA 6-Border WA-ID Jackson, OR
Ju
l
y

U
n
e
m
p
l
o
y
m
e
n
t

R
a
t
e
Jul-09
Jul-10
Jul-11
Jul-12
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 301 of 1125
Spokane+Kootenai Leading Indicator, 2011-2012
Data Source: Global Insight and author’s calculations.
 Highly correlated with employment changes 12 to 15 months in advance.
Signaling very slow employment growth for the rest of 2012 and through the first half of 2013.
74
76
78
80
82
84
86
88
90
92
Spokane-Kootenai Regional Leading Index, March 2004 = 100
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 302 of 1125
Old vs. New Long-Run: Annualized Employment and
Population Growth in Spokane+Kootenai
1990 2007 2011
+2.7% -1.6%
Data Source: BLS and author’s calculations.
+1.5% to +1.8%
Population Growth
Regional Population Growth = (U.S. Employ. Growth, Regional Employ. Growth)
(-) (+) +1.1% to +1.3%
2021
Employment Growth = (U.S. Real GDP Growth)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 303 of 1125
The Potential Drag of Fiscal Consolidation: Government Transfer
Payments to Total Personal Income, 2007 and 2010
Data Source: BEA and author’s calculations.
Message: Be careful what you ask for in terms of smaller government when government is
an important part of your economy.

12%
32%
27%26%
20%
23%
16%
18%
8%
17%
38%
35%
33%
24%
26%
18%
22%
11%
0%
5%
10%
15%
20%
25%
30%
35%
40%
Washington Ferry Pend Oreille Stevens Adams Lincoln Whitman Spokane King
Re
l
a
t
i
v
e

S
h
a
r
e
Share of Government Payments for Selected Counties, 2007 and 2010
2007 Gov. Transfer Payments/Personal Income 2010 Gov. Transfer Payments/Personal Income
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 304 of 1125
The Potential Drag of Fiscal Consolidation: Government
Employment as a Share of Total Employment, 2007 and 2010
Data Source: BEA and author’s calculations.
16%
37%
35%
21%22%
35%
44%
14%
11%
17%
40%39%
23%22%
33%
43%
15%
12%
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
Washington Ferry Pend Oreille Stevens Adams Lincoln Whitman Spokane King
Re
l
a
t
i
v
e

S
h
a
r
e
Share of Government Employment for Selected Counties, 2007 and 2010
2007 Government Emp./Non-Farm Emp.2010 Government Emp./Non-Farm Emp.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 305 of 1125
Looking Forward: Other Issues Potentially
Impacting Growth
• Aerospace firms have shown robust growth. This should
continue given Boeing’s order book. Potential new 737 plant
not in forecast.
•Air force is moving ahead with the evaluations of bases for
refueling tankers. The 10 finalists will be chosen by late
summer 2012. Those chosen for expansion will be announced
at year-end.
• Changes in the price of natural gas.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 306 of 1125
Native Load Forecast Lower
900
1,000
1,100
1,200
1,300
1,400
1,500
1,600
19
9
7
19
9
8
19
9
9
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
Av
e
r
a
g
e

M
W

i
n
c
l
u
d
i
n
g

l
o
s
s
e
s
Avista Combined Native Load
Washington and Idaho
F2013 F2012 F2011 F2010 F2008
Forecast 2013-2023
(adjusted for EVs)
Actual to May 2012
Forecast Native Load Growth Rates from 2013
5 yr = 1.04% 10 yr = 0.95% 22 yr = 1.01%
Forecast Customer Growth Rates from 2013
5 yr = 1.3% 10 yr = 1.2% 22 yr = 1.1%
1997-2000
3.0% p.a.
2001-2008
2.0% p.a.
2009-2011
0.6% p.a.
1.3%
p.a.
1.0%
p.a.
Reflects weaker sales to
commercial and industrial
customers.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 307 of 1125
Annual Residental Use Per Customer, 1997-2035
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
19
9
7
19
9
8
19
9
9
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
20
3
4
20
3
5
An
n
u
a
l

k
W
h

R
e
s
i
d
e
n
t
i
a
l
Electric Average Use per Average Customer
Weather Adjusted
Residential Residential w/o PEV
Electric Car Impact
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 308 of 1125
“Together We Will Build Shared Value”
Avista’s 2012 report on our performance
Technical Advisory Committee
Sept. 5, 2012
Jessie Wuerst, Sr. Communications Manager
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 309 of 1125
Cross-Company Shared Value Action Team
Consumer Affairs
Customer Service
Electric Operations
Energy Solutions/DSM
Environmental
Facilities
Gas Operations

Generation & Production
Health & Safety
Human Resources
Rates
Resource Planning
Supply Chain
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 310 of 1125
The business case for reporting

• Increase opportunities to build understanding of Avista’s operations for all
stakeholders

• Provide information that stakeholder groups want to know about

• Create opportunities for discussing partnerships with stakeholders that bring
value to all

• Enhance transparency of Avista as a business to build trust and two-way
communication
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 311 of 1125
The “Shared Value” Pyramid
Creating Shared Value
Customers, Shareholders,
Communities, Employees
Sustainability
Protect the future
Compliance
Laws, Licenses, Codes of Conduct, Philanthropy

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 312 of 1125
Shared Value – Changing Business Practices

“The principle of shared value…involves creating economic value in a
way that also creates value for society by addressing its needs and
challenges. Businesses must reconnect company success with social
progress. Shared value is not social responsibility, philanthropy, or even
sustainability, but a new way to achieve economic success.”
Harvard Business Review – Jan. 2011
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 313 of 1125
Shared Value – An Opportunity
Shared value opportunities are core to Avista’s vision:
“Delivering reliable energy service and the choices that matter most to you”
Avista operations,
programs, people
Underlying community/society
issues
Avista strategic plans
A snapshot in time of what Avista does well that grows our business and at the same
time provides “social” value
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 314 of 1125
• Customer Engagement
• Improvement and innovation
• Safe & reliable infrastructure
• Responsible resources
• Regulatory outcomes
• People and culture
• Community partnership
• Financial strength
Shared Value reporting should focus on:
Linking business strategic priorities and what we know is of interest/concern to
customers, media, investors and other stakeholders
• Customer Satisfaction
• Power quality & Reliability
• Corporate Citizenship –
Philanthropy
Community involvement
Environmental stewardship
• Energy Efficiency programs
• Communications

Shared Value
Opportunities
Avista Strategic Priorities External Priorities
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 315 of 1125
How can we most effectively share this information with stakeholders?
Segment stakeholders, identify current points of
contact with each group and insert messaging
throughout the year…
Bill insert Newsletter
Social Media
Website
Community presentations (RBMs etc.)
Employees e.g. account executives
Employee communications: quarterly
meetings, eview, View
Editorial board meetings
News releases
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 316 of 1125
An integrated family of reports
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 317 of 1125
Materiality Matters
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 318 of 1125
Questions or Comments?
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 319 of 1125
Generation Options
John Lyons, Senior Resource Policy Analyst
Second Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
September 5, 2012

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 320 of 1125
Supply Side Resource Data Sources
• Northwest Power and Conservation Council – 6th Northwest Power Plan
• Internally developed resource lists from:
• Trade journals
• Press releases from other companies
• Engineering studies and other models
• State commission announcements
• Proposals from developers
• Consulting firms and reports
• State and federal resource studies and publications
• Data sources are used to check and refine generic resource assumptions
2
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 321 of 1125
Natural Gas-Fired Resources
3
Resource Type First
Year
Size
(MW)
Levelized
Overnight Costs
(2012 $/MWh) *
Capital Cost
Excludes AFUDC
(2012$)
SCCT (aero) 2015 100 $79 $1,101/kW
SCCT (frame EA) 2015 166 $81 $845/kW
SCCT (frame FA) 2015 175 $70 $728/kW
Hybrid SCCT 2015 92 $75 $1,114/kW
CCCT (air) 2017 270 $70 $1,117/kW
Reciprocating Engine 2015 113 $76 $1,060 /kW
* Prices are based on a preliminary natural gas price forecast
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 322 of 1125
Other Thermal Resources
4
Resource Type First
Year
Size
(MW)
Levelized
Overnight
Costs
(2012
$/MWh)
Capital Cost
Excludes AFUDC
(2012$)
Coal (Super-critical) 2018 300 $97 $3,100/kW
Coal (IGCC) 2014 300 $127 $4,000/kW
Coal (IGCC
w/sequestration)
2018 250 $170 $6,000/kW
Nuclear 2023 100* $173 $7,000/kW
Small Scale Nuclear 2023 25 $107 $4,000/kW
* This represents a 100 MW of a 1,100 MW plant.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 323 of 1125
Renewable and Storage Resources
5
Resource Type First
Year
Size
(MW)
Levelized
Overnight
Costs (2012
$/MWh)
Capital Cost
Excludes AFUDC
(Nominal 2012)
Wind (On System) 2013 100 $115 $2,140/kW
Wind (Off System) 2013 100 $123 $2,140/kW
Geothermal 2017 15 $104 $4,000/kW
Wood Biomass 2015 25 $160 $4,000/kW
Landfill Gas 2014 3.2 $106 $2,500/kW
Manure Digester 2013 0.85 $144 $4,500/kW
Waste Water Treatment 2014 0.85 $109 $4,500/kW
Solar Photovoltaic 2014 5 $312 $3,500/kW
Solar Thermal 2014 50 $414 $6,500/kW
Battery Storage 2015 5 $126 $4,000/kW
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 324 of 1125
Avista Upgrade Alternatives
• Avista thermal upgrades
• Rathdrum CT
• Coyote Springs 2
• Avista hydroelectric upgrades
• Spokane River Project
• Clark Fork River Project
6
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 325 of 1125
7
$414
$312
$173
$170
$160
$144
$127
$126
$123
$115
$109
$107
$106
$104
$97
$81
$79
$76
$75
$70
$70
$0 $100 $200 $300 $400 $500
Solar Thermal
Solar Photovoltaic
Nuclear
Coal (IGCC w/ Seq)
Wood Biomass
Manure Digester
Coal (IGCC)
Battery Storage
Wind Off System
Wind On System
Waste Water Treatment
Small Scale Nuclear
Landfill Gas
Geothermal
Coal (Super-Critical)
Frame EA CT
Aero CT
Reciprocating Engine
Intercooled CT
Frame FA CT
CCCT (1x1) w/ duct burner (air)
New Resource Options Levelized
Costs ($/MWh)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 326 of 1125
Hydro Modernization Initiative
Modernize Avista’s existing fleet
of hydro resources to:
Generate incremental energy to meet load
growth
Produce RECs to meet renewable portfolio
standards
Increase plant efficiency through utilization
of new technology
Reduce risk through improved reliability
and environmental mitigation
Clean
Resources
Develop long-term strategy to assess and prioritize Spokane River
plant opportunities, and study Cabinet Gorge modifications to mitigate
total dissolved gas issues
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 327 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 328 of 1125
Value Proposition
Improve reliability by replacing aging equipment
Improve performance (energy and capacity) through
technology advancements
Produce renewable energy credits to meet RPS requirements
Take advantage of favorable tax treatment
Possible resolution of total dissolved gas issues
Clean
Resources
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 329 of 1125
Spokane River Project
Clean
Resources
•Spokane River was built out in the late
1800’s and early 1900’s to meet the
growing demands of the Spokane
region.
•Undersized by today’s design
standards for hydro development
capturing 30% – 60% of available water
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 330 of 1125
Spokane River Project
Clean
Resources Original Monroe Street Powerhouse
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 331 of 1125
Current Spokane River Project
Clean
Resources
Facility Year
Built
Generation
Capability
(MW)
Net Energy
Output (MWh)
Post Falls 1906 14.8 90,000
Upper Falls 1922 10.0 71,000
Monroe St 1992 14.8 106,000
Nine Mile 1908 26.4 101,000
Long Lake 1915 78.0 480,000
Little Falls 1910 32.0 201,000
Total 176.0 1049,000
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 332 of 1125
Spokane River Project Flow Duration Curve

Clean
Resources
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 333 of 1125
Spokane River Assessment
Clean
Resources
Goals of the Spokane River Assessment:

•Fully develop the Spokane River
- Capture 70% - 80%

•Provide cost effective generation alternatives
to meet resource needs

• Increase plant efficiency and reliability

•Address environmental and regulatory
considerations
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 334 of 1125
0
50
100
150
200
250
300
350
400
450
0
10
20
30
40
50
60
70
80
Mo
n
r
o
e

S
t
r
e
e
t

U
n
i
t

1

Ni
n
e

M
i
l
e

U
n
i
t
s

3

&

4

Ca
b
i
n
e
t

U
n
i
t

1

Lo
n
g

L
a
k
e

U
n
i
t

4

Lit
t
l
e

F
a
l
l
s

U
n
i
t

3

Lo
n
g

L
a
k
e

U
n
i
t

1

Lo
n
g

L
a
k
e

U
n
i
t

2

Lo
n
g

L
a
k
e

U
n
i
t

3

Ca
b
i
n
e
t

U
n
i
t

3

Lit
t
l
e

F
a
l
l
s

U
n
i
t

4

Ca
b
i
n
e
t

U
n
i
t

2

Ca
b
i
n
e
t

U
n
i
t

4

No
x
o
n

U
n
i
t

1

No
x
o
n

U
n
i
t

3

No
x
o
n

U
n
i
t

2

No
x
o
n

U
n
i
t

4

Ni
n
e

M
i
l
e

U
n
i
t
s

1

&

2

Lit
t
l
e

F
a
l
l
s

U
n
i
t

1

Lit
t
l
e

F
a
l
l
s

U
n
i
t

2

Up
p
e
r

F
a
l
l
s

2
n
d

P
o
w
e
r
h
o
u
s
e

Nin
e

M
i
l
e

N
e
w

P
h
s
e

Lo
n
g

L
a
k
e

2
n
d

P
h
s
e

Ca
b
i
n
e
t

G
o
r
g
e

2
n
d

P
h
s
e

Po
s
t

F
a
l
l
s

R
e
d
e
v
e
l
o
p

Mo
n
r
o
e

S
t
r
e
e
t

2
n
d

P
h
s
e

1992 1994 1994 1994 1994 1996 1997 1999 2001 2001 2004 2007 2009 2010 2011 2012 2015 2015 2016
Cu
m
u
l
a
t
i
v
e

C
a
p
a
c
i
t
y

(
M
W
)

In
c
r
e
m
e
n
t
a
l

C
a
p
a
c
i
t
y

(
M
W
)

Planned
12 MW
Clean
Resources
A History of Hydro Upgrades
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 335 of 1125
A History of Hydro Upgrades
Clean
Resources
-
200.0
400.0
600.0
800.0
1,000.0
1,200.0
0
20
40
60
80
100
120
140
160
180
Mo
n
r
o
e

S
t
r
e
e
t

U
n
i
t

1

Ni
n
e

M
i
l
e

U
n
i
t
s

3

&

4

Ca
b
i
n
e
t

U
n
i
t

1

Lo
n
g

L
a
k
e

U
n
i
t

4

Li
t
t
l
e

F
a
l
l
s

U
n
i
t

3

Lo
n
g

L
a
k
e

U
n
i
t

1

Lo
n
g

L
a
k
e

U
n
i
t

2

Lo
n
g

L
a
k
e

U
n
i
t

3

Ca
b
i
n
e
t

U
n
i
t

3

Li
t
t
l
e

F
a
l
l
s

U
n
i
t

4

Ca
b
i
n
e
t

U
n
i
t

2

Ca
b
i
n
e
t

U
n
i
t

4

No
x
o
n

U
n
i
t

1

No
x
o
n

U
n
i
t

3

No
x
o
n

U
n
i
t

2

No
x
o
n

U
n
i
t

4

Ni
n
e

M
i
l
e

U
n
i
t
s

1

&

2

Li
t
t
l
e

F
a
l
l
s

U
n
i
t

1

Li
t
t
l
e

F
a
l
l
s

U
n
i
t

2

Up
p
e
r

F
a
l
l
s

2
n
d

P
o
w
e
r
h
o
u
s
e

Ni
n
e

M
i
l
e

N
e
w

P
h
s
e

Lo
n
g

L
a
k
e

2
n
d

P
h
s
e

Ca
b
i
n
e
t

G
o
r
g
e

2
n
d

P
h
s
e

Po
s
t

F
a
l
l
s

R
e
d
e
v
e
l
o
p

Mo
n
r
o
e

S
t
r
e
e
t

2
n
d

P
h
s
e

1992 1994 1994 1994 1994 1996 1997 1999 2001 2001 2004 2007 2009 2010 2011 2012 2015 2015 2016
Cu
m
u
l
a
t
i
v
e

E
n
e
r
g
y

G
W
h

In
c
r
e
m
e
n
t
a
l

E
n
e
r
g
y

G
W
h
Future Study
600 GWh
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 336 of 1125
Post Falls Possible Modifications
Clean
Resources New Powerhouse in the South Channel - 40 MW (2x20)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 337 of 1125
Post Falls Possible Modifications
Clean
Resources Replace Existing Powerhouse - 40 MW (5x8)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 338 of 1125
Post Falls Possible Modifications
Clean
Resources Rebuild Existing Powerhouse Turbine Generators - 33.6 MW (6x5.6)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 339 of 1125
Upper Falls Possible Modifications
Clean
Resources Second Powerhouse with Channel Excavation – 40 MW
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 340 of 1125
Monroe Street Possible Modifications
Clean
Resources
Second Powerhouse – with Channel Excavation 80 MW
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 341 of 1125
Monroe Street Possible Modifications
Clean
Resources
Second Powerhouse – with Tunnel 80 MW
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 342 of 1125
Monroe Street Possible Modifications
Clean
Resources
Second Powerhouse – From Monroe Street Dam 44 MW
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 343 of 1125
Nine Mile Possible Modifications
Clean
Resources
Existing Powerhouse Upgrade Units 1 and 2 – 32MW (4x8)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 344 of 1125
Nine Mile Possible Modifications
Clean
Resources
New Powerhouse Downstream Left Bank – 60 MW (3x20)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 345 of 1125
Nine Mile Possible Modifications
Clean
Resources
New Powerhouse Downstream Left Bank – 60 MW (5x12)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 346 of 1125
Nine Mile Possible Modifications
Clean
Resources
New Powerhouse Existing Location – 60 MW (5x12)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 347 of 1125
Long Lake Possible Modifications
Clean
Resources Replace Turbine Generators 120 MW (4x30)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 348 of 1125
Long Lake Possible Modifications
Clean
Resources Section View - Replace Turbine Generators 120 MW (4x30)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 349 of 1125
Long Lake Possible Modifications
Clean
Resources Second Powerhouse from Saddle Dam - 68MW
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 350 of 1125
Little Falls Powerhouse Rebuild
Clean
Resources
• Replace Generators
• Replace Turbines
• Replace Generator Breakers
• Replace Excitation Systems
• New Modern Control System
• New Powerhouse Crane
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 351 of 1125
Spokane River Project Potential
Clean
Resources
Facility Year
Built
Generation
Capability
(MW)
Net Energy
Output
(MWh)
Upgraded
Capability
(MW)
Upgraded
Energy
(MWh)
Post Falls 1906 14.8 90,000 33.6 142,500
Upper Falls 1922 10.0 71,000 50.0 184,200
Monroe St 1992 14.8 106,000 58.8 223,600
Nine Mile 1908 26.4 101,000 60.0 221,500
Long Lake 1915 78.0 480,000 146.0 619,800
Little Falls 1910 32.0 201,000 32.0 201,000
Total 176.0 1049,000 380.4 1,592,600
Percent
Increase 116% 52%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 352 of 1125
Clark Fork River Project
Clean
Resources
•Clark Fork River Project was built in the
1950’s and 1960’s to meet the growing
demands of the Spokane region.
•Cabinet Gorge completed in 1952
•Noxon Rapids completed in 1960
•5th Unit was added in 1978
•Improvements to date include
•New Turbines - efficiency upgrades
•New Generators and rewinds
•New Generator Step-Up Transformers

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 353 of 1125
Cabinet Gorge HED Refurbishment :
•Replaced 4 turbine runners & rebuilt generators
•Refurbished other turbine generator parts to like new condition
•Upgraded plant from 220 MW to 270 MW
•Environmentally friendly features – greaseless bearings and more
efficient turbines
•Upgrade costs $5 to $12M, total $40M
•Complete in 2004

Clean
Resources
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 354 of 1125
Clean
Resources
Noxon Rapids HED Refurbishment
• Replaced Units 1- 4 turbine runners &
rebuilt generators
• Replaced Unit 5 generator
• Refurbish other turbine generator parts
to like new condition
• Replaced GSU Transformers
• Upgraded plant from 548 MW to 598 MW
• Environmentally friendly features –
greaseless bearings and more efficient
turbines
• Upgrade costs $9 to $17M, total $77M
• Completed in May2012
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 355 of 1125
Cabinet Gorge Possible Modifications
Clean
Resources Second Powerhouse in Tunnel
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 356 of 1125
Cabinet Gorge Possible Modifications
Clean
Resources
•Increased plant capacity will reduce Spring
spillway flows, and thus reduce contributions
to total dissolved gas (TDG)
•Could increase plant capacity by 55 - 110 MW
•Range of plant configurations under study
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 357 of 1125
Avista’s 2013 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 3 Agenda
Wednesday, November 7, 2012
Conference Room 328

Topic Time Staff

1. Introduction 8:30 Storro

2. Modeling 8:35 Gall

3. Colstrip Discussion 9:15 Lyons

4. Energy Efficiency 10:00 Borstein

5. Lunch 11:30

6. Peak Load Forecast 12:30 Gall/Forsyth

7. Reliability Planning 1:15 Gall

8. Break 2:00

9. Energy Storage 2:15 Lyons

Adjourn 3:00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 358 of 1125
Materiality Ratings
Avista’s 2013 Electric Integrated Resource Plan Technical Advisory Committee
Weighted score – number of responses x rated importance/relevance September 2012
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 359 of 1125

2013 IRP Modeling Approach
James Gall, Senior Power Supply Analyst
Third Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
November 7, 2012

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 360 of 1125
2013 IRP Modeling Process
Preferred
Resource
Strategy

AURORA
“Wholesale Electric Market” 500 Simulations

PRiSM
“Avista Portfolio” Efficient Frontier
Fuel Prices
Fuel Availability
Resource Availability
Demand
Environmental Considerations
Existing Resources
Resource Options
Transmission
Resource & Portfolio Margins
Conservation
Trends
Existing
Resources
Avista Load
Forecast
Energy, Capacity, & RPS Balances New Resource Options & Costs
Cost Effective T&D Projects/Costs
Cost Effective Conservation Measures/Costs
Mid-Columbia Prices
Stochastic Inputs Deterministic Inputs
Capacity Value
Avoided
Costs
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 361 of 1125
3rd party software- EPIS, Inc.
Electric market fundamentals- production cost model
Simulates generation dispatch to meet load
Outputs:
– Market prices
– Regional energy mix
– Transmission usage
– Greenhouse gas emissions
– Power plant margins, generation levels, fuel costs
– Avista’s variable power supply costs
Electric Market Modeling
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 362 of 1125
PRiSM- Preferred Resource Strategy Model
Internally developed using Excel based linear program model
(What’s Best)
Selects new resources to meet Avista’s capacity, energy, and
renewable energy requirements
Outputs:
– Power supply costs (variable and fixed)
– Power supply costs variation
– New resource selection
– Emissions
– Capital requirements

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 363 of 1125
AURORA Inputs
Regional loads
Natural gas & coal prices
Hydro levels
Wind variation
Environmental resolutions
Resource availability
Transmission

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 364 of 1125
Regional Loads
Forecast load growth for all regions in the Western Interconnect
Consider both peak and energy
Use regional published studies and public IRP’s
Stochastic modeling simulates load changes due to weather and
considers regional correlation of weather patterns
Load changes due to economic reasons are difficult to quantify
and are usually picked up as IRP’s are published every two years
Peak load is becoming more difficult to quantify as “Demand
Response” programs my cause data integrity issues
Energy demand forecasts need to be net of conservation

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 365 of 1125
California
Northwest
Desert SW
Rocky Mountains
Canada
0
50,000
100,000
150,000
200,000
250,000
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
20
3
4
20
3
5
MW
Western Interconnect Peak Load Forecast
Energy & Peak Forecast (draft)
Energy AAGR
Canada 1.91%
Rocky Mtns. 0.69%
Desert SW 1.64%
California 0.48%
Northwest 0.90%
Peak AAGR
Canada 1.80%
Rocky Mtns. 0.98%
Desert SW 1.71%
California -0.26%
Northwest 0.93%
California
Northwest
Desert SWRocky Mountains
Canada
0
50,000
100,000
150,000
200,000
250,000
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
20
3
4
20
3
5
Av
e
r
a
g
e

M
W
Western Interconnect Energy Forecast
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 366 of 1125
Electric Vehicles (PHEV)
A potential change in customer load shapes could be a result of
PHEV
To address this- a load adder will be applied to reflect new
demand with a majority of load added in off peak hours
In the 2011 IRP electric vehicle demand was estimated to be
1,370 MW (off-peak) for 2020 (western interconnect)
The load forecasts from other IRP’s typically include PHEV
assumptions
PHEV load will be pullout out of the forecast and modeled as
load with an alternative load shape to reflect typical charging
patterns

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 367 of 1125
Natural Gas Prices
Natural gas prices are one of the most difficult inputs to quantify
A combination of forward prices and consultant studies will be
used as the “Base Case” for this IRP. This work should be
complete by December 2012
500 different prices using an auto regressive technique will be
modeled, the mean value of the 500 simulations will be equal to
the “Base Case” forecast
A controversial input for these prices is the amount of variance
within the 500 simulation.
– Historically prices we highly volatile, recent history is more
stable
– Final variance estimates will look at current market volatility
and implied variance from options contracts

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 368 of 1125
Natural Gas Prices
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
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
$
p
e
r

D
t
h
2011 IRP
Forwards (6/1/12)
Forwards (10/30/12)
Actual
Avista-Mid 2012
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 369 of 1125
Coal Prices
With lower natural prices and EPA regulations the demand for
US based coal is lower, but potential exports may stabilize the
industry
Western US coal plants typically have long-term contracts and
many are mine mouth
Rail coal projects are subject to diesel price risk
Prices will be based on review of coal plant publically available
prices and EIA mine mouth and rail forecasts

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 370 of 1125
Hydro
70 year average hydro conditions are used for the Northwest
states, British Columbia and California provided by BPA
– Hydro levels change monthly
– AURORA dispatches the monthly hydro based on whether its
run-of-river or storage.
For stochastic studies the hydro levels will be randomly drawn
from the 70 year record
A new Columbia River Treaty could change regional hydro
patterns, but until there is resolution, no changes will be
considered

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 371 of 1125
Northwest Hydro Variability
-
5,000
10,000
15,000
20,000
25,000
El Niño Neutral La Niña All Data
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Mean
2 Stdev High
2 Stdev Low
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 372 of 1125
Wind
Wind generation in the Northwest’s is the fastest growing
resource type
RECs and PTC’s have caused wind facilities to economically
generate in oversupply periods in the Northwest- particularly in
the spring months
Wind is modeled using an autoregressive technique to simulate
output in similar to reported data available from BPA, CAISO,
and other publically available data sources- also considers
correlation between regions
For stochastic studies several wind curves will be drawn from to
simulate variation in wind output each year
Will pursue temperature/wind correlation for stochastic study

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 373 of 1125
Wind Generation Profile (First week of January 2007-12)
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
1 7 13 19 25 31 37 43 49 55 61 67 73 79 85 91 97
10
3
10
9
11
5
12
1
12
7
13
3
13
9
14
5
15
1
15
7
16
3
Ca
p
a
c
i
t
y

F
a
c
t
o
r
Hour of January
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 374 of 1125
Jan Feb Mar Apr May Jun Jul Aug
2011 8 10 4 31 39 85 25 0
2012 0 0 8 60 84 260 137 3
0
50
100
150
200
250
300
Mi
d
-Co
l
u
m
b
i
a

P
r
i
c
e

H
o
u
r
s

B
e
l
o
w

Z
e
r
o
Hours Mid-Columbia Prices Were Less Than $0/MWh
2011: 202 Hrs
2012: 552 Hrs
Source: Powerdex daily average prices- substantially more hours had trades with negative pricing
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 375 of 1125
Greenhouse Emission Reduction Scheme
Currently no eminent national climate change legislation
Alternative methods for reducing greenhouse gases are more likely
than a national cap-and-trade mechanism; such as early retirement
of coal plants and regional greenhouse gas limits
This IRP will model the CO2 tax in British Columbia and an expected
market clearing price for CO2 in California
Rather than use a cap & trade or tax method in the IRP base case
the model will rather consider all announced coal plants retirements
and determine future coal/natural gas plants likely to be retired due to
environmental or economic reasons
This method will show reductions to greenhouse gases in the
western US without causing price shocks to the wholesale power
markets

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 376 of 1125
Coal Retirements
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
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
Cu
m
u
l
a
t
i
v
e

C
o
a
l

M
W

t
o

b
e

R
e
t
i
r
e
d
An
n
u
a
l

C
o
a
l

M
W

T
o

B
e

R
e
t
i
r
e
d
Announced Coal Plant Retirements
Annual
Cumulative
Announced retirements of 13% of coal plant capacity in the west
Avista will review all Western Interconnect coal plants and retire
plants for modeling purposes. This method is to estimate likely
EPA/State related retirements

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 377 of 1125
Water Issues
Once-through cooling
– California plants with this cooling technology must be
converted to alternative cooling methods or retired
– For modeling purposes: older natural gas units will be retired
and Nuclear plants will be considered retrofitted
– San Onofre?
Traditional water cooling
– New NG resources are finding it more difficult to use water
cooling- for new resources air cooling will be assumed

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 378 of 1125
Once-Through Cooling Affect
13,500 MW of natural gas plants in California could be affected
by once-through-cooling rules- nearly 4,000 MW announced
retirement
Represents 27% of California’s natural gas fleet

0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
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
Cu
m
u
l
a
t
i
v
e

C
o
a
l

M
W

t
o

b
e

R
e
t
i
r
e
d
An
n
u
a
l

C
o
a
l

M
W

T
o

B
e

R
e
t
i
r
e
d
Announced Natural Gas Plant Retirements
Annual
Cumulative
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 379 of 1125
Western State’s Renewable Portfolio Standards
Nine western states have renewable portfolio standards (RPS)
– A majority of qualifying projects will not be selected in
AURORA due to economics, therefore renewable resources
are added based likely resource types up to the RPS
requirement
Challenges are with California
– What renewable quantity will CA allow for import- 25%?
– How much behind the meter solar will be developed?
Will state RPS’s change- easier or more stringent?
– Washington recently allowed legacy biomass
– Colorado increased its requirement from 10% to 30%

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 380 of 1125
Transmission Expansion
Regional transmission expansion plans have been discussed
much of the last decade- with little to show for it!

For modeling purposes- a review of the expansion opportunities
will be discussed and projects that are in advanced stages of
development will be included

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 381 of 1125
PRiSM
Find optimal resource strategy to meet resource deficits over
planning horizon
Model selects its resources to reduce cost, risk, or both.
Objective Function:
– Minimize: Total Power Supply Cost on NPV basis (2014-
2054)- Focus on first 10 years of the plan
– Subject to:
•Risk level
•Capacity need +/- deviation
•Energy need +/- deviation
•Renewable portfolio standards
•Resource limitations, sizes, and timing

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 382 of 1125
Efficient Frontier
 Demonstrates the trade off of cost and risk
 Avoided Cost Calculation
Ri
s
k

Least Cost Portfolio
Least Risk Portfolio
Find least cost portfolio
at a given level of risk
Short-Term
Market
Market + Capacity + RPS = Avoided Cost
Capacity
Need
+ Risk
Cost
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 383 of 1125

Colstrip Discussion
John Lyons, Senior Resource Policy Analyst
Third Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
November 7, 2012

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 384 of 1125
Future of Colstrip – Planning
• Scenarios about the future of Colstrip will be modeled in this IRP
• Washington Commission acknowledgement of the 2011 IRP:
• “The Company should conduct a broad examination of the cost of continuing the
operation of Colstrip over the 20-year planning horizon, including a range of
anticipated costs associated with potential U.S. Environmental Protection Agency
regulations on coal-fired generation.”
• “The Company should model a scenario without Colstrip that includes results
showing how Avista would choose to meet its load obligations without Colstrip in its
portfolio, and estimates of the impact on Net Present Value (cost) of its portfolio
and rates.” (Docket UE-101482)

2
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 385 of 1125
Colstrip Ownership Information
3
Colstrip Basic Data Colstrip Ownership Percentages
Colstrip
Unit #
Size
(MW)
Year
Online
Avista NorthWestern
Energy, LLC
PacifiCorp Portland
General
Electric
PPL
Montana,
LLC
Puget
Sound
Energy
Unit #1 307 1975 0% 0% 0% 0% 50% 50%
Unit #2 307 1976 0% 0% 0% 0% 50% 50%
Unit #3 740 1984 15% 0% 10% 20% 30% 25%
Unit #4 740 1986 15% 30% 10% 20% 0% 25%
Total 2,094 11% 11% 7% 14% 25% 32%
Colstrip Units #1 – 4 use about one rail car (110 tons) of coal for every five minutes
of operation – the whole project uses about 10 million tons of coal per year
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 386 of 1125
Colstrip Economic Benefits
• The plant employs 360 people and the mine has 373
employees
• $104 million in annual Montana state and local taxes (4.5% of all state revenue collections)
• 3,740 additional jobs and 7,700 more residents in
Montana
• $360 million in additional personal income
• $638 million more in additional Montana output

Data from The Economic Contribution of Colstrip Steam Electric Station Units 1-4, November 2010.

4
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 387 of 1125
Colstrip – Importance as a Resource
• Colstrip provides 222 MW of capacity for Avista
• 1,416,000 MWh in 2011 (162 aMW)

5
Other includes: full load surge pond variable costs, environmental air pollution taxes,
paste plant, coal handling, coal handling dust suppression, bottom ash handling,
bottom ash hauling contract and coal conditioning costs.
Coal, 80%
Mercury Control, 5%
Lime, 3%
Gen/Wet Tax, 3%
Scrubbers, 2%Water Treatment
Chemicals, 1%
Other, 5%
Other, 20%
2013 Colstrip Units #3 & 4 Projected Full Load Variable Costs
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 388 of 1125
Colstrip Fuel Supply
• Avista’s total annual fuel use at Colstrip is approximately 980,000 tons
• Mine mouth facility
• Current fuel contract expires at the end of 2019
• Currently negotiating a fuel supply extension

6
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 389 of 1125
Colstrip Modeling in the 2013 IRP
Base Case:
•Colstrip Units #3 – 4 kept in service through IRP modeling period
•Will comply with current and future environmental regulations
Colstrip Scenarios:
•How many scenarios are needed?
•What date or dates should be used to model a shut down of the
plant?
•Other assumptions?

7
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 390 of 1125
Avista Utilities
Conservation Potential Assessment
Approach for 2013 Update
November 7, 2012 Jan Borstein Project Manager, Energy Analysis and Planning
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 391 of 1125
2
Outline
CPA objectives
Analysis approach
– Update 2010 study
– Changes in approach
Project schedule

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 392 of 1125
3
CPA Objectives
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 393 of 1125
4
CPA objectives
Assess and analyze 20-year cost-effective conservation potential
Meet Washington I-937 Conservation Potential Assessment requirements
– Biennium target for 2014-2015
Support Avista IRP development
Provide information to support Business Plan development

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 394 of 1125
5
Analysis Approach
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 395 of 1125
6
CPA considerations
The CPA approach accounts for the following factors
Impacts of existing programs
Impacts of codes and standards
Technology developments and innovation
Economic conditions
Customer growth trends
Energy prices

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 396 of 1125
7

Develop three levels of potential
Potential studies identify future opportunities for EE that can be achieved through
programs

Technical EE Potential
Theoretical upper limit of EE, where all efficiency measures are phased in regardless of cost

Economic EE Potential
EE potential, which includes measures that are cost-effective

Achievable EE Potential
EE potential that can be realistically achieved by utilities, accounting for customer adoption rates and how quickly programs can be implemented

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 397 of 1125
8
Consistency with Sixth Plan
End-use model — bottom-up
Building characteristics
Fuel and equipment saturations
Measure life
Stock accounting
Existing and new vintage
Lost- and non-lost opportunities
Measure saturation and applicability
Measure savings, including contribution to peak
Codes and standards
Ramp rates to model market acceptance and program implementation

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 398 of 1125
9
Consistency with Sixth Plan (cont.)
Measures
Include nearly all in Sixth Plan
Others also, e.g., conversion of electric water heaters and furnaces to
natural gas
Sources for measure characterization
– Avista Technical Reference Manual (TRM )
– RTF measure workbooks
– EnerNOC databases, some of same sources used in Sixth Plan
Economic potential, total resource cost (TRC) test
Considers non-energy benefits
Achievable potential – ramp rates
Based on Council Sixth Plan ramps rates
Modified to reflect Avista program history
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 399 of 1125
10
Avista-specific items
End-use model
Building characteristics, fuel shares, and equipment saturations are
Avista-specific
Calibrated to Avista 2009 sales by sector
Update with newly available RBSA data, e.g., information on measure
saturation
Measure savings, including contribution to peak
Building codes and appliance standards updated as of 2012
Avista-specific customer growth forecasts
Avista retail rate and avoided cost forecasts
Ramp rates adjusted to match Avista program history

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 400 of 1125
11
Potential study analysis framework
EE measure data Utility data
Engineering analysis
Secondary data
Market segmentation and characterization
Customer participation
rates
Technical and
economic potential
forecasts
Achievable potential
forecast
Utility data
Customer surveys
Secondary data
Base-year energy use
by fuel, segment
Baseline forecasting
Supply curves Scenario analyses Custom analyses Project report
End-use forecast by
segment
Prototypes and
energy analysis
Program results
Survey data
Secondary data
Forecast data
Synthesis / analysis
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 401 of 1125
12
LoadMAPTM analysis tool
LoadMAP stands for Load
Management, Analysis and
Planning
LoadMAP modeling features:
– Embodies principles of
rigorous end-use models (like
REEPS and COMMEND)
– Uses stock-accounting
– Isolates new construction
– Uses a simple decision logic
– Models customized by end
use
From user’s perspective:
– Excel-based model
– Easy to update assumptions
– Enables sensitivity analysis
– Answers what-if questions

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 402 of 1125
13
Base-year energy consumption
Base year is 2009
At start of past study in summer 2010, 2009 was most recent year with
complete sales and customer data
2009 was also base year for Avista load research study, which provides
peak data
We will calibrate the first few years of the forecast to sales history

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 403 of 1125
14
Market segmentation by rate class
Used 2009 base year sales data to develop control totals
Number of customers, annual use, and peak load by sector

Sector Rate
Schedule(s)
Number of meters
(customers)
2009 Electricity
sales (MWh)
Peak demand
(MW)
Residential 001 299,714 3,634,086 993
General Service 011, 012 46,387 738,505 125
Large General Service 021, 022 4,808 2,256,882 347
Extra Large General Service 025, 025P 32 1,145,277 174
Extra Large GS Potlatch 025P 1 892,291 101
Pumping 031, 032 3,673 194,884 14
Total 354,615 8,861,961 1,753
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 404 of 1125
15
Market characterization
Sector Segment Vintage
End Use
Space heating
Air-source heat pump
Geothermal heat pump
Electric furnace
Electric resistance
Air-source heat pump
SEER 13
SEER 14
SEER 15
SEER 16
Ductless Minisplit
Technology Efficiency
options
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 405 of 1125
16
Market characterization by segment

Sector Customers 2009 Electricity
sales (GWh)
Residential 299,714 3,634,086
General Service 46,387 738,505
Large General Service 4,808 2,256,882
Extra Large GS 32 1,145,277
Extra Large GS Potlatch 1 892
Pumping 3,673 194,884
Total 354,615 8,861,961
Residential
Segment
Number of
Customers
Intensity
(kWh/HH)
Electricity Sales
(GWh)
Single family 168,339 14,250 2,398,874
Multi family 23,456 8,613 202,032
Mobile/Manufactured 10,022 12,724 127,523
Limited Income 97,896 9,251 905,656
Total 299,714 12,125 3,634,086
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 406 of 1125
17
Energy Market Profiles

Market profiles – a
snapshot of how customers
use energy by end use and
technology
– Number of customers
– Saturations
– Unit energy consumption
(UEC) or
energy use intensity (EUI)
– Peak factors — fraction of
annual electricity use
coincident with the system peak
Existing (average) buildings
and new construction
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 407 of 1125
18
Energy Market Profiles (continued)

Sample for
residential sector,
all segments
UEC Intensity Usage
(kWh) (kWh/HH) (GWh)
Cooling Central AC 29%1,613 470 141
Cooling Room AC 20% 643 131 39
Combined Heating/Cooling Air Source Heat Pump 14%5,051 699 209
Combined Heating/Cooling Geothermal Heat Pump 0%3,715 15 4
Space Heating Electric Resistance 18%6,114 1,119 335
Space Heating Electric Furnace 22%6,779 1,492 447
Space Heating Supplemental 9% 83 8 2
Water Heating Water Heater 66%2,796 1,834 550
Interior Lighting Screw-in 100%1,144 1,144 343
Interior Lighting Linear Fluorescent 66% 121 80 24
Interior Lighting Pin-based 92% 59 55 16
Exterior Lighting Screw-in 70% 301 211 63
Exterior Lighting High Intensity/Flood 2% 116 2 1
Appliances Clothes Washer 84% 105 88 26
Appliances Clothes Dryer 80% 621 498 149
Appliances Dishwasher 86% 185 160 48
Appliances Refrigerator 100% 746 746 224
Appliances Freezer 62% 760 474 142
Appliances Second Refrigerator 35% 787 277 83
Appliances Stove 86% 299 257 77
Appliances Microwave 95% 144 137 41
Electronics Personal Computers 121% 263 317 95
Electronics TVs 222% 311 688 206
Electronics Devices and Gadgets 100% 48 48 14
Miscellaneous Pool Pump 10%1,328 130 39
Miscellaneous Furnace Fan 26% 404 107 32
Miscellaneous Miscellaneous 100% 940 940 282
12,125 3,634
-
Average Market Profile - Residential Sector
End Use Technology Saturation
Total
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 408 of 1125
19
Baseline forecasting

Model equipment choices for replacement or new construction
Define equipment efficiency options, up to 10 per technology
Define baseline purchase shares —begin with Annual Energy Outlook
shipments data and modified for Avista service territory or local data
Building codes and appliance standards

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 409 of 1125
20
Baseline forecasting

Air source heat pump example
Efficiency Level Relative
Energy Use Lifetime Standards
Status
2011
Baseline
Purchase
Shares
2015
Baseline
Purchase
Shares
E1 − SEER 13 100.0% 15 Baseline until
2014 78% 0%
E2 − SEER 14 (ENERGY STAR) 91.7% 15 Baseline after
2014 0% 78%
E3 − SEER 15 (CEE Tier 2) 88.6% 15 15% 15%
E4 − SEER 16 (CEE Tier 3) 86.1% 15 7% 7%
E5− Ductless Mini-split
System 75.0% 15 0% 0%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 410 of 1125
21
Baseline forecasting

Market size / customer growth
Income growth
Avista retail rates forecast
Trends in end-use/technology saturations
Equipment purchase decisions
Cooling and heating degree day
values
Persons/household and physical home size
Elasticities by end use for each variable (from client or default values
based on EPRI REEPS and COMMEND models)

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 411 of 1125
22
Baseline forecast – Residential
Use per Household Use per household
End Use 2009
(MWh)
2012
(MWh)
2017
(MWh)
2022
(MWh)
2027
(MWh)
2032
(MWh)
% Change
('09–'32)
Avg. growth
rate
Cooling 180,022 164,872 197,096 239,735 293,189 357,837 99% 3.0%
Space Heating 784,854 783,258 906,261 1,051,822 1,210,093 1,383,665 76% 2.5%
Heat & Cool 213,860 201,414 229,351 259,524 296,812 343,830 61% 2.1%
Water Heating 549,606 557,026 611,989 675,078 748,532 830,990 51% 1.8%
Appliances 790,377 776,522 796,390 837,724 899,380 996,282 26% 1.0%
Interior Lighting 383,305 375,894 335,220 397,188 465,499 543,171 42% 1.5%
Exterior Lighting 63,864 62,362 61,507 71,895 84,283 98,404 54% 1.9%
Electronics 315,599 336,232 404,126 484,986 570,101 669,577 112% 3.3%
Miscellaneous 352,599 374,582 448,055 540,785 650,016 779,045 121% 3.4%
Total 3,634,086 3,632,162 3,989,994 4,558,738 5,217,905 6,002,803 65% 2.2%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 412 of 1125
23
Baseline forecast – Commercial & Industrial
Total growth of 27.1% over forecast period
Average annual growth of 1.04%

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 413 of 1125
24
Baseline forecast summary — previous CPA
Overall 48% growth in electricity use
Average annual growth rate of 1.7%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 414 of 1125
25
Develop measure list using
– Existing programs
– RTF data
– EnerNOC databases
Characterization
– Description
– Costs
– Savings
– Applicability
– Lifetime
Update measure data
– Avista TRM
– RTF measure databases
– BEST simulations
– EnerNOC databases
Measure identification & characterization
Water heating measures
Conventional (EF 0.95)
Heat pump water heater (EF 2.3)
Solar water heater
Low-flow showerheads
Timer / Thermostat setback
Tank blanket
Drainwater heat recovery
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 415 of 1125
26
Technical potential

Technical potential
Hypothetical case
Most efficient option taken, regardless of cost
Equipment is replaced at time of failure
Other devices are phased in over time using a diffusion curve
– Slope of curve varies according to complexity of measure and cost

Label Water Heater Technology Relative
Energy Use
Off
Market
E1 EF 0.9 100.0% 2014
E2 EF 0.95 94.0%
E3 EF 2.3 (HPWH) 39.1%
E4 Solar 38.2%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 416 of 1125
27
Economic potential

Assumptions
Avoided costs forecasts for energy and capacity
T&D line losses
Administrative cost adders
Total Resource Cost test for B/C ratio ≥ 1.0
Most efficient cost-effective option is selected
Screening performed for every year

Label Water Heater Technologies Relative
Energy Use
Off
Market
B/C
Ratio
2012
B/C
Ratio
2017
E1 EF 0.9 100.0% 2014 1.00 -
E2 EF 0.95 94.0% 1.03 1.00
E3 EF 2.3 (HPWH) 39.1% 1.05 1.08
E4 Solar 38.2% 0.68 0.70
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 417 of 1125
28
Estimate achievable potential

Requires assumptions about customer acceptance, market
barriers, and market maturity
Model applies series of factors to economic potential
Savings may be acquired through a variety of means
Utility incentive programs
Utility educational programs
Market transformation, including NEEA

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 418 of 1125
29
Sample potential results from previous CPA
2012 2013 2017 2021 2022 2027 2032
8,805,759 9,000,280 9,600,889 10,425,853 10,646,717 11,876,679 13,310,674
Achievable 52,188 116,482 465,933 917,085 1,069,455 1,765,226 2,493,450
Economic 250,938 520,969 1,627,739 2,454,017 2,632,030 3,259,492 3,813,122
Technical 336,303 702,900 2,224,063 3,411,428 3,664,844 4,590,026 5,311,276
Achievable 0.6% 1.3% 4.9% 8.8% 10.0% 14.9% 18.7%
Economic 2.8% 5.8% 17.0% 23.5% 24.7% 27.4% 28.6%
Technical 3.8% 7.8% 23.2% 32.7% 34.4% 38.6% 39.9%
Cumulative Energy Savings (% of Baseline)
Cumulative Energy Savings (MWh)
Baseline Forecast (MWh)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 419 of 1125
30
Sample potential results (continued)

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 420 of 1125
31
Project Schedule
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 421 of 1125
32
Project Schedule
Present project approach to the TAC on November 7, 2012
Deliver preliminary results in January 2013
Deliver final results mid-February 2013
Present final study results to TAC and draft report in March, 2013
Support the filing in August 2013 with a complete CPA report (including
appendices)

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 422 of 1125
33

Jan Borstein [e-mail] 303-530-5195

Ingrid Rohmund [e-mail] 760-943-1532

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 423 of 1125

Peak Load Forecast
James Gall, Senior Power Supply Analyst
Grant Forsyth, Senior Forecaster & Economist
Third Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
November 7, 2012

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 424 of 1125
Peak Load History
y = 13.637x + 1501.3
R² = 0.2915
y = 15.266x + 1370.4
R² = 0.6058
1,000
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
2,000
19
9
7
19
9
8
19
9
9
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
Me
g
a
W
a
t
t
s
Winter Summer Linear (Winter)Linear (Summer)
Winter:
0.85% AAGR
Summer:
1.0% AAGR
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 425 of 1125
Forecast Methodology
Use multi-variable regression analysis to identify the 2011/2012
weather adjusted peak load
Use two years of daily load data as the sample data
Remove large industrial loads and focus on weather related load
Variables include:
Heating degree days set at 55°, 45°, and 15°
Cooling degree days set at 65° and 70°
Prior day cooling degree days set at 65° for past two days
Summer sunlight percentage
NERC and school holidays
Number of industrial & residential customers
Day of week and month of year

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 426 of 1125
Forecast Methodology (continued)
Peak load data was adjusted to the natural log to better estimate
peak load hours
Resulting r2: is 0.94 Standard error: 36 MW or 3.3% Durbin-Watson: 1.475(d-1), 1.973(d-2)
Weather adjustment includes 123 years of historical Spokane
temperatures and four weekday combinations
Peak forecast is 1 in 2 peak on a weekday
LOLP analysis will consider probability of weekend extreme
temperatures and will consider it in the planning margin
L&R will use three day average peak and single hour peak
Peak forecast includes existing conservation programs- additional
programs could further lower the forecast

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 427 of 1125
Historical Average Day Temperatures 1890-2012
0%
2%
4%
6%
8%
10%
12%
14%
16%
-20 -17 -14 -11 -8 -5 -2 1 4 7 10 13 16 19 22 25 28 31
Fr
e
q
u
e
n
c
y
Day Average Temperature
Winter Temperature Variation
0%
2%
4%
6%
8%
10%
12%
14%
16%
74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91
Fr
e
q
u
e
n
c
y
Day Average Temperature
Summer Temperature Variation
Coldest Day Hottest Day
Extreme -17° 90°
Average 3.9° 82.3°
Standard Deviation 8.9° 2.8°
90th Percentile -8.8° 86°
Last Tail Event 2004: -9° 2008: 86°
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 428 of 1125
1,000
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
2,000
100%90%80%70%60%50%40%30%20%10%
Me
g
a
W
a
t
t
s
Percentile
December
July
2011/2012 Weather Adjusted Peak Loads
Jan 2012: 1,554 Aug 2012: 1,579
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 429 of 1125
-
500
1,000
1,500
2,000
2,500
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
Me
g
a
w
a
t
t
s
Winter Summer
2013 IRP Peak Load Forecast
Annual Growth Winter Summer
5 Year 1.02% 1.09%
10 Year 0.90% 0.96%
20 Year 0.84% 0.90%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 430 of 1125
Linking Peak Load Growth to GDP Growth
Peak loads are not constant over time. Controlling for weather
and other seasonal factors, the long-run trend is towards
increasing peaks
Monthly Peak = f(weather, non-weather seasonal factors, economic factors)
If we account for weather and non-weather seasonal factors, then changes in
the peak load, we assume, are due to economic factors
Since we cannot easily identify specific economic factors, we use
GDP growth as a catch-all proxy
Econometric evidence suggests that Avista’s load growth, excluding weather
and seasonal effects, is significantly, positively correlated with GDP growth.
Weather and Seasonal Adjusted Peak Growth = f(GDP Growth) is a
relationship estimated with historical data
If we have forecasts of GDP growth we can estimated what peak load growth
under the assumption that the future GDP/load relationship will not be
materially different than what it was in the past

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 431 of 1125
Linking Peak Load Growth to GDP Growth (Cont)
There is growing evidence that winter peak load growth is slower
than summer peak load growth
Could be a function of increased use of air conditioning on new and existing
homes
Weather and Seasonal Adjusted Peak Growth = f(GDP Growth) is estimated
for winter peaks and summer peaks. The estimation does produced a slightly
higher growth rate for the summer peak
Where do the forecasts for GDP growth come from?
5-year forecasts are obtained by averaging GDP forecasts across multiple
sources: Bloomberg survey of forecasters, The Economist poll of forecasters,
WSJ survey of forecasters, Global Insight, Economy.com, and several others
From this set of forecasts have an average, a high, and a low forecast out five
years. This gives us some sense of how the business cycle will impact peak
growth
Beyond five years we assume a long-rung GDP growth rate of 2.5%

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 432 of 1125
IRP Peak Forecast Changes
1,000
1,250
1,500
1,750
2,000
2,250
2,500
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
Me
g
a
w
a
t
t
s
Winter Peak
2009 IRP
2011 IRP
2013 IRP
1,000
1,250
1,500
1,750
2,000
2,250
2,500
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
Me
g
a
w
a
t
t
s
Summer Peak
2009 IRP
2011 IRP
2013 IRP
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 433 of 1125
Weather Variation (1 in 20)
-
500
1,000
1,500
2,000
2,500
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
Me
g
a
w
a
t
t
s
Winter
Summer
Winter-High
Winter-Low
Summer-High
Summer-Low
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 434 of 1125

Reliability Planning
James Gall, Senior Power Supply Analyst
Third Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
November 7, 2012

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 435 of 1125
What is Reliability Planning?
Assessment of resource adequacy
Estimate probability of failing to serve all load
Used to estimate the planning margin to apply to the peak load
forecast

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 436 of 1125
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Transfers Clark Fork Spokane RiverNatural Gas Mid-Columbia WindBiomassCoalLoad + Ancillary ServicesLoad
Peak Day Example- August 7, 2012
- 80° day with peak load 1,579 MW
- 11.1% resource margin
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 437 of 1125
The Tool
Excel based model with linear program to optimize resource
generation to meet load and reserve requires taking into account
potential market purchases and sales
Focus on year 2020
Simulates 1,000 future scenarios
Temperatures, Hydro Availability, Forced Outages, Wind
Generation
Attempts to correlate interaction between variables

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 438 of 1125
Load

Forced Outage
Rates
Historical
Temperatures
Thermal
Availability
Maintenance
Schedules
Wind
Randomization
Model
Hydro
Availability
Wind
Output
Demand
Response
Operating
Reserves
Net Power
Contracts
Thermal Capacity
Curves
Historical Water
Conditions
Reliability Model Data Work Flow Diagram
Customer Appeal
Other DR Programs
Long-Term
Contracts + Short
Term Contract
Limits
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 439 of 1125
Loads
Load shapes are derived from historic daily high and low temperatures
Uses 120+ years of Spokane temperatures
The average load and the average of the seasonal peak load of the
1,000 scenarios are designed to match the long-term energy & peak
forecasts
Two years of historical hourly loads (netted of large industrials) were
used as the dependant variable of a regression analysis
303 independent variables were considered including: temperature,
holidays, day of week, month, and hour
Resulted in a 94% R2 and 5.3% standard error

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 440 of 1125
Hydro
Randomly selects a hydro year between 1928 and 1999
Each hydro year includes monthly energy averages
Run-of-river facilities
– Monthly energy average is used for all hours of the month
– No shaping or reserves are assumed to be available
Storage facilities
– Monthly average generation equals the “drawn” hydro level
– In case of planned/forced outage, water can be spilled
– Linear program moves energy into hours needed to meet load
– Reservoir min and max levels, ramping rates, and daily limits are enforced
– Unused capacity is held as operating reserves
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 441 of 1125
Thermal
Temperature dependency
–Gas-fired facilities use capacity based upon location
temperatures
– Temperatures are randomly drawn and are the same as the
temperatures used in the load and wind calculation
Forced outages
– Input forced outage rate and mean-time-to-repair
– Outages occur randomly using a frequency and duration
method
– Ramp rates are used following outages
Maintenance schedules
– Planned maintenance schedules are assumed
– Typical outages are in April though June

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 442 of 1125
Wind
In 2020, only one wind project is expected to be on-line- The 105
MW Palouse Wind Farm
The project is expected to be on-line by the end of 2012
Little generation data is available at this time- only a few years of
wind speed at a few locations
To simulate wind generation a regression analysis was used to
create a algorithm adjusting generation based on month,
temperature, daytime vs nighttime and previous hour(s)
generation.
Method creates realistic generation profile, but due to lack of
historical data- scenarios will done to understand the variability of
wind during high or low temperatures.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 443 of 1125
Demand Curtailment
Customer appeal
– Public appeal to all customers to conserve energy, radio/TV
broadcasts
– Base case includes 25 MW reductions up to two times per year
for hours across the peak
Industrial process
– Not included in base case
– Designed to shift load from peak hours
Sensitivities studies can help determine value of programs

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 444 of 1125
Reserves
Operating Reserves:
– 5% hydro, 7% thermal, 5% wind generation
Regulating Margin:
– 1.6% of average hourly load level (based on historical average
of max load within hour versus average load)
Intermediate (Wind) Resource Regulation:
– Lesser of 10% of nameplate capacity or generation amount
Reserves are met by excess hydro capacity (for spin & non-spin)
and thermal generation not running may be used for non-spin.
In the event a unit trips- the model will call on regional reserves for
1 hour

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 445 of 1125
Contracts & Market
Long-term contracts are included as hourly fixed power coming
into the system
Short-term system balancing transaction are allowed with limits:
– On Peak: 500 MW
– Off Peak: 1000 MW
– On Peak Constrained: 0 MW
– Off Peak Constrained: 500 MW
Hourly market is modeled dynamically adjusting for regional
temperatures and hydro conditions (future enhancement would be
to include wind correlation)

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 446 of 1125
Objective Function
Load Serving
- Load [SM]
+ Thermal commitment [RM]
+ Hydro commitment [LP]
+ Wind generation [SM/RM]
+/- LT Contracts
+ Demand curtailment (optional) [LP]
+/- Market transactions
>= 0 or event triggered
Operating Reserves
- Operating Reserve Requirement
- Intra-hour load regulation
- Wind regulation
+ Available thermal non-spin capability
+ Unused hydro capability (spin & non-spin)
>= 0 or event triggered

SM: Stochastic Model
RM: Randomization Model
LP: Linear Program
What should the penalty be for curtailing load?
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 447 of 1125
Metrics
Monthly and Annual Data
Loss of Load Probability (LOLP): percent of iterations with a reserve or load loss
– Calculation: iterations with event / # of iterations
– Metric: 5% or less
Loss of Load Hour (LOLH): expected number of hours each year with a load loss
– Calculation: total hours with event / (# of iterations)
– Metric: 0.24 (24 hours per 10 years)
Loss of Load Expectation (LOLE): expected number of days each year with a load
loss
– Calculation: Days with event / # of iterations
– Metric: 1 day in 10 years or 0.10 or less [or do we want 0.05, 1 in 20?]
Equivalent Unserved Energy (EUE): average MWh of lost load over a year

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 448 of 1125
Planning Margin Approach
Simulate system by adding new resources and/or market reliance
until the 5% LOLP threshold is met
Estimate annual power supply costs for each case
Management must decide on the acceptable level of market
reliance given the cost of new generation
Year 2020 is used to estimate planning margin for other years

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 449 of 1125
2020 Position Forecast (Draft)
3 day x 6 hour Sustained Peak
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Load -1,786 -1,639 -1,518 -1,362 -1,238 -1,369 -1,665 -1,636 -1,332 -1,418 -1,651 -1,814
Contracts Sales -6 -6 -6 -6 -7 -7 -8 -8 -7 -6 -6 -6
Total Peak Obligation -1,793 -1,646 -1,524 -1,368 -1,245 -1,376 -1,673 -1,644 -1,339 -1,424 -1,657 -1,820
Contract Purchases 92 94 96 96 97 95 88 85 85 87 89 92
Hydro 881 823 749 1,052 1,050 1,045 883 840 763 857 878 890
Thermal 884 881 874 755 450 499 775 780 797 865 873 882
Wind 0 0 0 0 0 0 0 0 0 0 0 0
Peaking 242 236 230 222 182 180 172 176 114 92 232 240
Total Resouarces 2,100 2,034 1,950 2,125 1,778 1,818 1,919 1,881 1,759 1,901 2,072 2,105
Position 307 389 426 757 534 443 246 237 421 477 415 284
Net Reserve Requirement -40 -61 -153 -140 -130 -139 -30 -31 0 0 -21 -41
Position Net Reserves 267 328 273 617 404 304 216 206 421 477 394 243
Implied Planning Margin 15% 20% 18% 45% 32% 22% 13% 13% 31% 33% 24% 13%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 450 of 1125
2020 Probabilistic Capacity Requirements
(No Additions or Market Availability)
0
50
100
150
200
250
300
350
400
0%5%
10
%
15
%
20
%
25
%
30
%
35
%
40
%
45
%
50
%
55
%
60
%
65
%
70
%
75
%
80
%
85
%
90
%
95
%
Ca
p
a
c
i
t
y

S
h
o
r
t
f
a
l
l

(
a
M
W
)
Percent of Iterations
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 451 of 1125
2020 Measure of Hours and Shortfall aMW
0
50
100
150
200
250
300
350
400
0 10 20 30 40 50 60 70 80
Sh
o
r
t
f
a
l
l

(
a
M
W
)
Shortfall Hours
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 452 of 1125
0%
10%
20%
30%
40%
50%
60%
70%
Zero 100 200 250 275 285 300 400
LO
L
P
Market Reliance
Market Reliance Affect to LOLP in 2020
Target LOLP
5%
28
0

M
W

=

5
%

L
O
L
P

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 453 of 1125
2020 LOLP Monthly Results
Market
Reliance Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual
Zero 10% 3% 1% 0% 0% 0% 27% 23% 0% 0% 2% 10% 58.2%
100 5% 1% 0% 0% 0% 0% 14% 12% 0% 0% 1% 5% 32.9%
200 2% 0% 0% 0% 0% 0% 6% 4% 0% 0% 0% 1% 12.4%
250 1% 0% 0% 0% 0% 0% 3% 2% 0% 0% 0% 1% 7.3%
275 1% 0% 0% 0% 0% 0% 2% 2% 0% 0% 0% 1% 5.4%
285 0% 0% 0% 0% 0% 0% 2% 2% 0% 0% 0% 0% 4.6%
300 1% 0% 0% 0% 0% 0% 2% 1% 0% 0% 0% 1% 4.1%
400 0% 0% 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 1.0%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 454 of 1125
2020 LOLH Monthly Results
Market
Reliance Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual
Zero

0.86

0.22

0.07

-

-

-

1.94

1.28

0.03

0.01

0.32

0.78

5.50
100

0.46

0.06

0.00

-

-

-

0.82

0.51

0.04

0.00

0.10

0.26

2.26
200

0.08

0.02

0.00

-

-

-

0.28

0.15

0.00

-

0.01

0.08

0.62
250

0.04

0.02

-

-

-

-

0.16

0.09

-

-

0.02

0.02

0.35
275

0.03

0.01

-

-

-

-

0.12

0.06

-

-

0.02

0.01

0.24
285

0.02

0.01

-

-

-

-

0.10

0.06

-

-

0.01

0.01

0.21
300

0.04

-

0.00

-

-

-

0.10

0.03

-

-

0.01

0.03

0.20
0.24 on an annual basis is considered a “reliable” system
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 455 of 1125
Unit Size Affect to LOLP in 2020
Measure Definition Goal
300 MW
Market
3- 100
MW
Units
2- 150
MW
Units
1- 300
MW
Unit
LOLP Probability 5% 4.1% 7.5% 8.4% 10.8%
LOLH Hrs/Yr 0.24 0.20 0.30 0.38 0.45
EUE aMW N/A 16 22 30 37
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 456 of 1125
Resource allocation to get to 5% LOLP goal
0
5
10
15
20
25
30
35
40
45
-
50
100
150
200
250
300
0 25 50 75 100 125 150 175 200 225 250 275 300 325
In
c
r
e
m
e
n
t
a
l

C
o
s
t

(
$
M
i
l
l
/
Y
r
)
Ma
r
k
e
t

D
e
p
e
n
d
a
n
c
e

(
M
W
)
New Capacity
MW
Annual Cost
34% 30% 21% 18% 28% 25% 16% 14% Winter PM Summer PM
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 457 of 1125

Energy Storage Technologies
John Lyons, Senior Resource Policy Analyst
Third Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
November 7, 2012

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 458 of 1125
Types of Energy Storage
Pumped Hydro
Batteries
Flywheel
Compressed Air

2
http://www.electricitystorage.org/images/uploads/static_content/technology/technology_resources/ratings_large.gif
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 459 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 460 of 1125
Energy Storage Applications
Electric Supply
• Electric energy time-shift
• Electric supply capacity

Ancillary Services
• Load following
• Area regulation
• Electric supply reserve capacity
• Voltage support

4
Grid System
• Transmission support
• Transmission congestion
relief
• Transmission and distribution upgrade deferral
• Substation on-site power

Eyer, J. and Corey, G. (2010) Energy Storage for the Electricity Grid: Benefits and Market Potential Assessment
Guide. Sandia National Laboratory.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 461 of 1125
Energy Storage Applications
5
End User/Utility Customer
• Time-of-use energy cost management
• Demand charge management
• Electric service reliability
• Electric service power quality

Renewables Integration
• Renewables energy time-shift
• Renewables capacity firming
• Wind generation grid integration

Eyer, J. and Corey, G. (2010) Energy Storage for the Electricity Grid: Benefits and Market Potential Assessment
Guide. Sandia National Laboratory.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 462 of 1125
Pumped Hydro Storage
• Works by pumping water between two reservoirs with different elevations during off peak periods
• Largest share of current energy storage in the US – over 20 GW capacity with 31 GW proposed

6
http://en.wikipedia.org/wiki/File:Raccoon_Mountain_Pumped-Storage_Plant.svg
• Tend to be long lead time
resources with
unique licensing and siting issues
• Avista has pumped storage
potential at Long Lake and Noxon
Rapids

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 463 of 1125
Batteries
• Charge off-peak, or during periods of excess variable generation, for later use
• Several different types available:
• Litium-ion
• Sodium-sulfur
• Redox flow
• Zinc bromine

7 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 464 of 1125
Flywheels
• Converts electric energy into rotational energy, which can be called on quickly to convert back to electricity
• Uses: grid energy storage, short-term storage of excess wind generation and providing regulation services
• Stephentown, NY – 20 MW (5 MWh over 15 minutes)

8 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 465 of 1125
Compressed Air
• Technology based on compressing air and pumping it into geological storage in off-peak periods for use in
subsequent periods.
• Ongoing projects
•1978 – 290 MW Huntorf in Germany (salt dome)
•1991 – 110 MW McIntosh, Alabama (salt cavern)
• Scheduled projects
•2016 – 300 MW (10 hours) PG&E in Kern County, California
•2013 – 200 MW ADELE facility in Germany
•2016 – 317 MW Bethel Energy Center in Anderson County, Texas

9 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 466 of 1125
Energy Storage Federal and State Policies
• No real federal policies requiring the development of energy storage
• Many federal proposals for tax benefits and proposed and actual funding of pilot projects
• Many proposals at the state level, but few implemented

10 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 467 of 1125
Economic Issues
• High cost of installation
• Low differentials between on and off peak prices
• 2013 IRP = $4,000/kW for 5 MW in 2015

11
http://www.electricitystorage.org/images/uploads/static_content/technology/technology_resources/cycle_large.gif
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 468 of 1125
Avista’s 2013 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 4 Agenda
Wednesday, February 6, 2013
Conference Room 428

Topic Time Staff
1. Introduction 8:30

2. Natural Gas Price Forecast 8:35 Irvine

3. Electric Price Forecast 9:45 Gall

4. Break 10:45

5. Transmission Planning 11:00 Maguire

6. Lunch 12:00

7. Resource Needs Assessment 1:00 Kalich

8. Break 2:00

9. Market & Portfolio Scenario Development 2:15 Lyons

10. Adjourn 3:00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 469 of 1125
Avista Electric IRP
Natural Gas Price Forecast
Technical Advisory Committee Meeting
February 6, 2013
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 470 of 1125
Agenda
• Natural Gas 101
• Pacific Northwest Supply and Infrastructure
• Natural Gas Price Fundamentals
• Short Term
• Long Term
• Fracking Facts and the Future of Shale

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 471 of 1125
A Brief History ...
3 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 472 of 1125
The Natural Gas System
My House
Pipeline
Receipt
Point
Delivery Point/
Gate Station
Storage
Gathering
System
Local
Distribution
System
Producer
Supply
4 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 473 of 1125
Pipelines Offered a Bundled Service – “One Call, That’s All™”
Producer
Pipeline $$$
Supply
Utility/Thermal
Generation $$$
5 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 474 of 1125
Pipeline
FERC ORDER 436
Pushed the Pipelines Out of the Supply Business

6 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 475 of 1125
Avista Utilities
Puget Sound Energy
Shell
BP
Boeing
Gonzaga
Marketer B
Example of Contracting on a Pipeline
7 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 476 of 1125
Now Services are Unbundled –
You Control the Price for Each Component
Supply $
Basin 1
Marketer $
Supply $
Basin 3
Hedge Fund $
Pipeline $
Supply $
Basin 2
Producer $
Pipeline $
Utility/Thermal
Generation $$$
8 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 477 of 1125
Natural Gas Infrastructure in the Pacific Northwest
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 478 of 1125
10
Pacific Northwest Supply and Infrastructure
AECO
Canadian gas coming out of Alberta, Canada
Rockies
U.S. domestic gas coming from Wyoming and Colorado
Sumas
Canadian gas coming out of British Columbia, Canada
Malin
South central at the Oregon and California border
Stanfield
Intersection of two major pipelines in North Central Oregon

Williams Northwest Pipeline
TransCanada Gas Transmission Northwest
TransCanada Foothills
TransCanada Alberta
Spectra Energy
Ruby Pipeline

Jackson Prairie Storage
Mist Storage
SU
P
P
L
Y

PI
P
E
L
I
N
E
S

ST
O
R
A
G
E

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 479 of 1125
Types of Pipeline Contracts
Firm Transport
• Contractual rights to:
• Receive
• Transport
• Deliver
• From point A to point B
Interruptible Transport
• Contractual rights to:
• Receive
• Transport
• Deliver
• From point A to Point B AFTER FIRM TRANSPORT HAS BEEN SCHEDULED
Seasonal Transport
• Firm service available for limited periods (Nov-Mar) or for a limited amount (TF2 on NWP)
Alternate Firm Transport
• The use of firm transport outside of the primary path
• Priority rights below firm
• Priority rights above interruptible
11
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 480 of 1125
Pipeline Rate Structure
• Pipeline charges a higher demand charge and a lower variable or commodity charge
Straight Fixed Variable (SFV)
• Pipeline charges a lower demand charge and a higher variable or commodity charge
Enhanced fixed variable
• Pay the same demand and variable costs regardless of how far the gas is transported
Postage Stamp Rate
• Pay a variable and demand charge based on how far the gas is transported Mileage Based
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 481 of 1125
Straight Fixed Variable Costs vs. Enhanced Fixed Variable
Demand Charge: Paid whether transport is used or not
Commodity or variable charge: Only paid when gas
is actually transported
Commodity
$.05
Commodity
$.01
Demand
$.40
Demand
$.44
EFV SFV
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 482 of 1125
TransCanada Gas Transmission Northwest (GTN)
• Mileage Based
• Point to Point
• Alternate firm allowed in path
• Mostly – demand based with a couple Nomination based points
•Demand based refers to gas that will be taken off the pipeline
based on the demand behind the delivery point.
•Nomination based refers to the pipeline only delivering what was
nominated (requested).
• Usually requires upstream transportation
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 483 of 1125
Mileage Base: Pay
based on how far
you move the gas
Jackson Prairie
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 484 of 1125
Williams Northwest Pipeline (NWP)
• Postage Stamp Based
• Point to Point
•Delivery to „zones‟ allowed
• Alternate firm allowed in and out of path
• Demand based delivery
•Demand based refers to gas that will be taken off the pipeline
based on the demand behind the delivery point.
•Nomination based refers to the pipeline only delivering what was
nominated (requested).
• May or may not require upstream transportation
• Enhanced fixed variable structure
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 485 of 1125
Postage Stamp:
Same costs
regardless of
distance or locations
Jackson Prairie
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 486 of 1125
Gas Fields
Williams NW Pipeline
Connecting Pipelines Seattle Jackson Prairie
British Columbia Alberta
Jackson Prairie Natural Gas Storage
Chehalis, Washington
Mist
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 487 of 1125
The Facility
• Jackson Prairie is a series of
deep, underground reservoirs
– basically thick, porous
sandstone deposits.
• The sand layers lie
approximately 1,000 to 3,000
feet below the ground
surface.
• Large compressors and
pipelines are employed to
both inject and withdraw
natural gas at 54 wells
spread across the 3,200 acre
facility.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 488 of 1125
1.2 Bcf per day (energy equivalent)
10 coal trains with 100 - 50 ton cars each
29 - 500 MW gas-fired power plants
13 Hanford-sized nuclear power plants
2 Grand Coulee-sized hydro plants (biggest in US)

46 Bcf of stored gas
12” pipeline 11,000,000 miles long (226,000 miles to the moon)
1,400 Safeco Fields (Baseball Stadiums)
Average flow of the Columbia River for 2 days
Cube - 3,550 feet on a side
Jackson Prairie Interesting Energy Comparisons
20 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 489 of 1125
Natural Gas Pricing Fundamentals
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 490 of 1125
What Drives the Natural Gas Market?
Natural Gas Spot Prices (Henry Hub)
22

Supply
– Type: Conventional vs. Non-conventional
– Location
– Cost
Demand
– Residential/Commercial/Industrial
– Power Generation
– Natural Gas Vehicles
Legislation
– Environmental
Energy Correlations
– Oil vs. Gas
– Coal vs. Gas
– Natural Gas Liquids
Weather
Storage
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 491 of 1125
$0
$2
$4
$6
$8
$10
$12
$14
Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13
no
m
i
n
a
l

$
/
m
m
b
t
u
Henry Hub: History & Forecast
Source: Wood Mackenzie, ICE
The Evolving Trend in Henry Hub Pricing
???
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 492 of 1125
Short Term Market Perspective
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
1-Jan 1-Feb 1-Mar 1-Apr 1-May 1-Jun 1-Jul 1-Aug 1-Sep 1-Oct 1-Nov 1-Dec
$/
D
t
h
Spot Henry Hub Price
Five Year Range
(2007 -2011)
2012
2013
Source: EIA
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 493 of 1125
Short Term Market Perspective
0
10
20
30
40
50
60
70
80
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Bc
f
/
d
Dry Gas Production
Five Year Range (2006 -2010)
2011
2012
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 494 of 1125
Short Term Market Perspective
Storage (as of January 25, 2013)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 495 of 1125
The Short Term Fundamentals
Bulls
• Weather – Normal is now bullish.
• Dwindling rig counts.
• Economic recovery.
• Coal/Nuke displacement.

Bears
• Production is high.
• Demand is weak.
• Storage is full.
• Oh yeah, production is high.
• Did I mention, production is high.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 496 of 1125
28
$-
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
$9.00
$10.00
$11.00
$12.00
$13.00
$14.00
$/
D
e
k
a
t
h
e
r
m
Fundamental Forecasts vs. Actual Prices
Henry Hub
Consultant 1 -Dec 2012 Consultant 2 -Dec 2012 NYMEX -Jan 9, 2013 EIA -Jan 2013
Actuals Forecast
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 497 of 1125
Forecasted Long Term Natural Gas Production
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 498 of 1125
1316
429
0
10
20
30
40
50
60
70
80
0
200
400
600
800
1,000
1,200
1,400
1,600
Fe
b

'
0
9
Ma
r
Ap
r
Ma
y
Ju
n
Ju
l
Au
g
Se
p
Oc
t
No
v
De
c
Ja
n

'
1
0
Fe
b
Ma
r
Ap
r
Ma
y
Ju
n
Ju
l
Au
g
Se
p
Oc
t
No
v
De
c
Ja
n

'
1
1
Fe
b
Ma
r
Ap
r
Ma
y
Ju
n
Ju
l
Au
g
Se
p
Oc
t
No
v
De
c
Ja
n

'
1
2
Fe
b
Ma
r
Ap
r
Ma
y
Ju
n
e
Ju
l
y
Au
g
Se
p
Oc
t
No
v
De
c
Ja
n

'
1
3
Bc
f
/
d
# o
f

R
i
g
s
Production Oil Gas
Forecast
The Link Between Rig Counts and Production
It ain’t what it used to be.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 499 of 1125
North American Pipeline Infrastructure
31 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 500 of 1125
Shale Changed Everything
If shale were a country ... it would be the third-largest gas producer!
32 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 501 of 1125
The Evolving Flow Dynamics
33 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 502 of 1125
The Decoupling of Crude Oil vs. Natural Gas Prices
Old rules
don‟t
apply!
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 503 of 1125
NGL’s Impact on the Cost to Produce
35
Natural Gas Liquids (NGL‟s) include ethane, propane, normal butane,
isobutane, pentane, natural gasoline, and sulphur. They are a bi-product
of natural gas production and have many uses and great value.
• Ethane – is used to create etheleyne a feedstock in petrochemical
production.
• Propane - used as a fuel source. Can be used in cigarette
lighters, motor vehicle fuel, portable stoves and lamps, and heating
fuel.
• Normal butane and Isobutane – used in refinery akylation
• Natural gasoline – used in refinery feedstock, crude dilutent, and
chemical applications.
• Sulphur – used in agricultural fertilizers and industrial feedstock.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 504 of 1125
NGL’s Impact on the Cost to Produce cont.
36
NGL‟s enhance the production economics for producers. NGL‟s are a
main contributor to understanding why gas production companies
continue to produce even with gas prices at very low levels.

The following table illustrates how the economics can improve with a
credit for NGL‟s.

Shale Play Cost to Produce
without NGL’s
Credit
Cost to Produce
including NGL’s
Credit
Marcellus $4.81 $2.83
Montney $3.85 $0.57
Barnett $5.39 $2.41
Note: This information is from one of our consultants. These costs are indicative of the impact. The costs can vary from play to
play and company to company.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 505 of 1125
Canada Dry vs. Canada Not Dry
Why won’t Canada be dry?
• Tons of JV money
• IP rates are proving to be better than
anticipated.
• Horn River IP rates have
increased 150%
• Economics are pretty good too.
• Duverney in particular is liquids
rich.
• New discoveries = Liard Basin

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 506 of 1125
LNG Export is the New Import
Source: Federal Energy Regulatory Commission

Source: Geology.com
LNG traditionally flows to North America after other higher-priced markets receive their share
Source: Apache LNG
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 507 of 1125
 Declining rig counts
 “Fracking” bans and/or legislation
 Any economic recovery
 Power generation
 Carbon legislation
 LNG exports
“The Best Indicator Of Future Behavior Is Past Behavior?”
 Production levels continue to remain
higher than expected
 Slow economic recovery
 Moderation in weather
How low can you go?
Seems more upside risk?
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 508 of 1125
Long Term Gas Price Drivers
•Economy = Demand
•Recession, Depression, Inflation, etc.
•Industrial Demand
•Demand for Power Generation
•US Natural Gas Production
•LNG Exports/Imports – Global Dynamics
•North American Storage Capacity
•Correlation (or lack thereof) with other energy products
•The Environment
•Carbon Legislation
•Renewable Portfolio Standards
•The “F” Word - FRACKING
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 509 of 1125
IRP Natural Gas Price Forecast Methodology
1.Two fundamental forecasts (Consultant #1 & Consultant #2)
2.Forward prices
3.Carbon legislation adder beginning in 2023 ($14/ton grows to $22/ton)
4.Year 1 forward price only
5.Year 2 75% forward price / 25% average consultant forecasts
6.Year 3 50% forward price / 50% average consultant forecasts
7.Year 4 – 6 25% forward price / 75% average consultant forecasts
8.Year 7 50% average consultant without CO2 / 50% average consultant
with CO2

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 510 of 1125
Henry Hub Price Forecasts
Nominal $/Dth
$-
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
$16.00
$18.00
$20.00
$22.00
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
$/
D
t
h
Consult1 Consult2 AEO NYMEX NPCC Low NPCC Medium NPCC High
2009 IRP Forecasted Prices
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 511 of 1125
Natural Gas Price Forecasts
Nominal $/Dth
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
$9.00
$10.00
Consultant 1
Consultant 2
Consultant Avg
Forwards (11/30/12)
Consultant Avg w/o CO2 Leg.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 512 of 1125
Forecasted Levelized Henry Hub Price (2013 – 2033)
Nominal $/Dth
5.46
4.59 4.95
-
3.00
6.00
9.00
$/
D
t
h
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 513 of 1125
Selected Basin Forecasted Prices
Nominal $/Dth
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
$9.00
$10.00
AECO
Stanfield
Malin
Henry Hub
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 514 of 1125
Forecasted Levelized Selected Basin Prices (2013 – 2033)
Nominal $/Dth
5.46
$4.78
$5.24 $5.33
$0.00
$3.00
$6.00
$9.00
$/
D
t
h
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 515 of 1125
Fracking Facts and the Future of Shale
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 516 of 1125
What is Shale Gas?
Shale gas refers to natural
gas that is trapped within
shale formations.

Shales are fine-grained
sedimentary rocks that can
be rich sources of
petroleum and natural gas.

Over the past decade, the
combination of horizontal
drilling and hydraulic
fracturing has allowed
access to large volumes of
shale gas that were
previously uneconomical to
produce.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 517 of 1125
Fracking “Facts” Make Headlines
“Insiders Sound an Alarm Amid a Natural Gas Rush”
“Shale plays are just giant Ponzi schemes” – New York
Times

“Because it’s releasing gases, they’re not able to trap it
as much, it’s coming right through the ground.”
” – John Krasinski “The Late Show with David
Letterman”

“Fracking Shale Gas Emissions Far Worse Than Coal” –
Cornell Chronicle
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 518 of 1125
The “F” Word
What is “Fracking”?
Hydraulic fracturing (HF or “fracking”) is a process for producing oil and
natural gas. A mixture of water, chemicals and a “proppant” (usually sand)
is pumped into a well at extremely high pressures to fracture rock and allow
natural gas to escape.
An estimated 11,000 new wells are fractured each year; and estimates
show another 1,400 existing wells are re-fractured to stimulate production or
to produce natural gas from a different production zone.
HF has been around for well over 60 years. This process has been used on
over one million producing oil and gas wells. Federal, state and other
regulatory bodies have had regulations in place for over 50 years.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 519 of 1125
What Are Some Of The Issues?
Of the many allegations made in the headlines, recent press has
focused its attention on the volumes, costs, and environmental
impacts of shale gas production.

Issue #1: Shale resources are overestimated.

Issue #2: Shale gas is uneconomic to produce.

Issue #3: Hydraulic fracturing pollutes the air, contaminates water,
and causes earthquakes.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 520 of 1125
What Are The Facts?
Fact: Many independent organizations, companies,
and governments have examined and assessed data
in order to develop estimated shale gas resource
figures. All have concluded that the reserve base is
much greater than previously anticipated.

A recently released MIT study states:
“In the US, despite their relative maturity, natural gas
resources continue to grow, and the development of low-cost
and abundant unconventional gas resources, particularly
shale gas has a material impact on future availability and
price.” Ernest Moniz, MIT Professor at a hearing before the
Senate Energy and Natural Resources Committee.
Issue #1: Shale resources are overestimated.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 521 of 1125
Who Estimates The Reserve Base?
One of the most widely
used estimate is from the
Potential Gas Committee.

Shale had its first noticeable
impact in 2006, nobody
questioned it.

In 2008, as more data
becomes available another
adjustment is made, nobody
questioned it.

Now, with even more data a
modest increase in shale
reserves is made, and now
the questioning begins.

Who is the Potential Gas Committee? 100 Volunteer Geoscientists & Petroleum Engineers
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 522 of 1125
What Are The Facts?
Fact: It is true that current gas prices have fallen to low levels making
the economics of some wells challenging. However, there are several
factors that are helping to make the economics work.

• Natural Gas Liquids – many of the shale plays are liquids rich. These
liquids can be sold at prices which are linked to higher priced oil. The
liquids revenue helps to offset costs.
• Drilling effectiveness – producers are showing increases in:
• Wells per year per rig
• Lateral length
• 30 day average production rate.

It‟s only math: Costs/Volume (Costs / Volumes )

Issue #2: Shale gas is uneconomic to
produce.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 523 of 1125
What Are The Facts?
Fact: Water contamination – Contamination
of water could occur in a couple of ways,
one is by factures seeping gas and oil into
the water table. Secondarily, much water is
used in the HF process. This water is mixed
with other things and could be spilled and be
absorbed into the water table.

Issue #3: “Hydraulic fracturing contaminates ground water, pollutes the air,
and causes earthquakes.”
FracFocus.org – Public registry created and managed by
state regulators
Searchable public database with well-by-well
information and glossary of chemicals
More than 10,000 wells and over 100 participating
companies; several states using as tool for
compliance reporting

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 524 of 1125
Hydraulic Fracturing and the Water Table
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 525 of 1125
How much is 5 Million
gallons of water?

It is equivalent to the
amount of water
consumed by:

• New York City in about
seven (7) minutes
• A 500 megawatt coal-
fired power plant in 1 day
• A golf course in 25 days
• 10 acres of cotton in a
season

While these represent
continuing consumption,
the water used for a gas
well is a one-time use.
How Much Water Is Used in Hydraulic
Fracturing?
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 526 of 1125
What Are The Facts?
Fact: Pollution – as with most industrial activities there the issue of
pollution must be addressed. Most concerning in natural gas
processing is the release of volatile organic compounds (VOC) or
carcinogens and methane.

Most of the air pollutants at gas sites occurs during the completion
phase of processing. The EPA just established rules that will curtail
the amount of air pollution caused by gas and oil production.
Companies have until 2015 to comply with the new rules, however
over half of the companies currently use the required technology.
Issue #3 cont.: “Hydraulic fracturing contaminates ground water, pollutes
the air, and causes earthquakes.”
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 527 of 1125
What Are The Facts?
Fact: Earthquakes – It was reported that a recent study conducted by
the US Geological Survey appeared to indicate increased seismic
activity due to HF.

"USGS's studies do not suggest that hydraulic fracturing, commonly known as
'fracking,' causes the increased rate of earthquakes," Hayes wrote. "USGS's
scientists have found, however, that at some locations the increase in
seismicity coincides with the injection of wastewater in deep disposal wells.“ –
DOI Deputy Secretary David Hayes

Issue #3 cont.: “Hydraulic fracturing contaminates ground water, pollutes
the air, and causes earthquakes.”
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 528 of 1125
Bottom Line:
Many benefits can be realized:
• Providing jobs
• Rejuvenating the chemical,
manufacturing, and steel industry
• Bridge fuel to a renewable energy
future
• Reduce dependence on foreign oil

However, there are important environmental
issues that will need to continue to be
addressed. Industry and regulators should
continue to work together to ensure safe
development of this vital resource.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 529 of 1125
Electric Price Forecast
James Gall
Fourth Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
February 6, 2013

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 530 of 1125
Historical Mid-Columbia Prices- What year is it?
13.40
23.06 23.62
122.13
129.51
22.33
38.09 42.44
58.89
45.76
51.85
59.48
32.86 32.99
24.18 19.58
$0
$20
$40
$60
$80
$100
$120
$140
19
9
7
19
9
8
19
9
9
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
$
p
e
r

M
W
h
Energy Crisis
Natural Gas Market Tightens
Shale Development Cheap Natural
Gas, good
hydro
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 531 of 1125
Historic Mid-Columbia and Stanfield Prices
-
10.00
20.00
30.00
40.00
50.00
60.00
70.00
2004 2005 2006 2007 2008 2009 2010 2011 2012
$
p
e
r

M
W
h
Mid Columbia Firm Electric Prices
-
1.00
2.00
3.00
4.00
5.00
6.00
7.00
8.00
9.00
2004 2005 2006 2007 2008 2009 2010 2011 2012
$
p
e
r

D
T
H
Stanfield Natural Gas Prices
Strong tie between natural gas and electric market
Increased natural gas supply/ lower prices causing price declines at the Mid-Columbia
Are prices now at a new normal?
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 532 of 1125
Pricing Relationships
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
2004 2005 2006 2007 2008 2009 2010 2011 2012
IM
H
R
:

M
i
d

C
/
S
t
a
n
f
i
e
l
d

Annual Implied Market Heat Rate
(4.00)
(2.00)
-
2.00
4.00
6.00
8.00
2004 2005 2006 2007 2008 2009 2010 2011 2012
(M
i
d

C

-
St
a
n
f
i
e
l
d

*

7
)
Spark Spread
Implied Market Heat Rate illustrates new wind supply contributing to lowering market prices
Spark Spread shows margin opportunities for Combined Cycle Resources
2011’s above average hydro reduced prices further
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 533 of 1125
The Ghost of IRP’s Past
$0
$20
$40
$60
$80
$100
$120
$140
$160
$180
$200
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
$
p
e
r

M
W
h
Index 2003 2005
2007 2009 2011
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 534 of 1125
2013 IRP Modeling Process
Preferred
Resource
Strategy

AURORA
“Wholesale Electric Market” 500 Simulations

PRiSM
“Avista Portfolio” Efficient Frontier
Fuel Prices
Fuel Availability
Resource Availability
Demand
Environmental Considerations
Existing Resources
Resource Options
Transmission
Resource & Portfolio Margins
Conservation
Trends
Existing
Resources
Avista Load
Forecast
Energy, Capacity, & RPS Balances New Resource Options & Costs
Cost Effective T&D Projects/Costs
Cost Effective Conservation Measures/Costs
Mid-Columbia Prices
Stochastic Inputs Deterministic Inputs
Capacity Value
Avoided
Costs
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 535 of 1125
Retail Sales by Western State
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
2004 2005 2006 2007 2008 2009 2010 2011
Av
e
r
a
g
e

M
W
NV UT AZ NM CO WY MT ID OR WA CA
WA14%
OR7%ID3%MT2%
WY2%CO8%
NM3%
AZ11%
CA41%
UT4%
NV5%
Source: SNL
1.2%
annual
growth
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 536 of 1125
0
100
200
300
400
500
600
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
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
Av
e
r
a
g
e

G
i
g
a
w
a
t
t
s
Other Wind Oil Natural Gas Coal Nuclear Hydro
National Historic Power Generation
Source: SNL
Coal
43%
Natural Gas24%
Nuclear19%
Oil
1%
Hydro
8%
Wind3%Other2%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 537 of 1125
-4
-2
0
2
4
6
8
10
12
14
Natural Gas Nuclear Oil Hydro Wind Other Lost Load
Av
e
r
a
g
e

G
i
g
a
w
a
t
t
s
US Coal Generation Displacement
Between 2007 and 2011, Coal Generation decreased 32 aGW
Source: SNL
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 538 of 1125
US Western Interconnect Generation by Fuel Type
Source: SNL
2004 2005 2006 2007 2008 2009 2010 2011
Other 3 3 3 3 3 3 3 3
Wind 1 1 1 1 2 2 3 4
Hydro 19 20 23 20 19 19 19 25
Oil 0 0 0 0 0 0 0 0
Nuclear 8 8 7 8 8 8 8 8
Natural Gas 21 21 23 26 27 26 24 20
Coal 27 27 25 26 26 25 25 24
Total 79 80 84 85 86 84 83 84
-
10
20
30
40
50
60
70
80
90
100
Av
e
r
a
g
e

G
i
g
a
w
a
t
t
s
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 539 of 1125
US Western Interconnect Energy Versus Capacity
Coal
16%
Natural
Gas
42%Nuclear
5%
Oil
0%
Hydro
27%
Wind
7%
Other
3%
Coal 29%
Natural
Gas
23%Nuclear 10%
Oil 0%
Hydro
30%
Wind
4%
Other 4%
2011 Energy
84 aGW
2011 Capacity
204 GW
Source: SNL
Actual coincident peak was 128.7 GW (8/25/2011)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 540 of 1125
Historic US Greenhouse Gas Emissions
Source: EIA
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Mi
l
l
i
o
n

M
e
t
r
i
c

T
o
n
s
Residential Commercial
Industrial Electric Power
Transportation
-1.0%-0.5%0.0%0.5%1.0%1.5%
Commercial
Industrial
Residential
Transportation
Electric Power
Total
Annual Average Emissions Growth (1990-2010)
Electric power in 2011
is 4.6% below 2010,
A total of 11%
reduction since 2007
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 541 of 1125
Western Electric Generation Greenhouse Gas Emissions
Source: EIA
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Delta AAGR
WY 40 39 43 41 43 40 41 41 44 42 44 44 42 43 44 43 43 43 44 41 42 2.3 0.3%
WA 8 8 10 10 12 8 11 9 12 11 14 14 11 14 14 14 9 12 13 13 13 5.5 2.8%
UT 29 28 30 30 31 29 30 31 31 32 33 32 33 34 34 35 35 37 38 35 34 4.9 0.8%
OR 2 4 5 4 5 3 3 3 6 6 7 9 6 8 8 8 6 10 10 9 10 7.8 8.8%
NV 17 18 19 18 20 18 20 19 21 21 25 24 21 23 25 26 17 17 18 18 17 -0.1 0.0%
NM 27 23 26 27 28 27 28 29 29 30 31 30 28 30 30 32 32 31 30 32 29 1.7 0.3%
MT 16 17 18 15 18 17 14 16 18 18 17 18 16 18 19 19 19 20 20 17 20 3.7 1.1%
ID 0 0 0 0 0 0 0 0 0 0 0 1 0 1 1 1 1 1 1 1 1 0.7 41.1%
CO 31 31 32 32 33 33 34 34 35 35 39 41 40 40 40 40 41 42 41 38 39 8.1 1.2%
CA 40 38 46 42 49 37 33 36 39 43 53 58 44 43 46 42 46 50 51 48 43 3.2 0.4%
AZ 33 33 35 37 38 32 32 35 37 39 44 45 45 46 51 50 52 55 57 52 54 21.4 2.6%
TOTAL 242 238 263 256 278 245 245 253 273 278 306 315 286 299 312 310 302 316 321 303 301 59.2 1.1%
0
50
100
150
200
250
300
350
Mi
l
l
i
o
n

M
e
t
r
i
c

T
o
n
s
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 542 of 1125
3rd party software- EPIS, Inc.
Electric market fundamentals- production cost model
Simulates generation dispatch to meet load
Outputs:
– Market prices
– Regional energy mix
– Transmission usage
– Greenhouse gas emissions
– Power plant margins, generation levels, fuel costs
– Avista’s variable power supply costs
Electric Market Modeling
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 543 of 1125
Stochastic Approach
Simulate Western Electric market hourly for next 20 years (2014-33)
– That is 175,248 hours for each study
Model 500 potential outcomes
– Variables include fuel prices, loads, wind, hydro, outages, inflation
– Simulating 87.6 million hours
Run time is about 5 days on 27 processors
Why do we do this?
– Allows for complete financial evaluation of resource alternatives
– Without stochastic prices we cannot account for tail risk

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 544 of 1125
Aurora Pricing Example- Supply/Demand Curve
-$100
-$50
$0
$50
$100
$150
$200
$250
$300
$350
0 10,000 20,000 30,000 40,000 50,000
$
p
e
r

M
W
h
Capability (MW)
Hydro (Must Run for Negative Pricing)
CCCT
Peakers
Demand
Hydro Availability
Fu
e
l

P
r
i
c
e
s
/
V
a
r
i
a
b
l
e

O
&
M

Other Resource Availability
Nuclear/ Co-Gen/ Coal/ Other
Wind (Net PTC/REC)
Market Price
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 545 of 1125
Modeled Western Interconnect Topology
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 546 of 1125
Greenhouse Gas Emissions Modeling
No national greenhouse gas tax or cap & trade is modeled
California, Alberta, and British Columbia greenhouse gas
reduction schemes are modeled
Assumes some coal plants will retire due to EPA regulations
Plants were selected for retirement based on fuel costs,
emission control technology and its location
Assume certain natural gas once-through-cooling plants in
California will be retired over time
State RPS requirements met mostly by wind & solar

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 547 of 1125
Forecasted Resource Retirements
-
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
-
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
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
Cu
m
u
l
a
t
i
v
e

M
e
g
a
w
a
t
t
s
Me
g
a
w
a
t
t
s
Oil NG Coal Cumulative Retirements
Natural Gas retirements are related to lost generation from once-through-cooling technology phase out in California
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 548 of 1125
New Resource Alternatives
Western Interconnect
Resource alternatives to meet Renewable Portfolio Standards
– Wind
– Solar
– Biomass
– Geothermal
– Hydro Upgrades
Resource alternatives to meet regional capacity requirements
– Combined Cycle
– Simple Cycle (Aero, Frame, Hybrid)
– Solar
– Wind (non RPS states)
– Nuclear
– Coal IGCC with Sequestration
– Energy Storage (not modeled)

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 549 of 1125
Resource Additions (Western Interconnect)
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
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
Cu
m
u
l
a
t
i
v
e

M
W
An
n
u
a
l

M
W
Hydro Geothermal Biomass
Wind Solar SCCT
CCCT Cumulative Capacity
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 550 of 1125
Resource Additions (Northwest)- Maintain 5% LOLP
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
0
500
1,000
1,500
2,000
2,500
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
Cu
m
u
l
a
t
i
v
e

M
W
An
n
u
a
l

M
W
Hydro Geothermal Biomass
Wind Solar SCCT
CCCT Cumulative Capacity
Will policy makers
want more
renewables?
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 551 of 1125
US Western Interconnect Resource Forecasted Output
DRAFT
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
Other 6 6 7 7 7 7 8 8 8 8 9 9 9 9 9 9 9 9 9 9
Wind 6 6 6 7 7 7 7 7 8 8 8 8 8 8 8 8 8 8 8 8
Oil 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Natural Gas 21 23 24 25 25 26 26 28 29 30 32 33 34 36 37 39 40 43 44 45
Coal 25 23 21 21 21 20 20 20 19 19 19 19 18 18 18 17 17 16 16 16
Nuclear 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7
Hydro 23 23 24 23 23 24 23 24 24 24 23 23 24 23 23 24 23 23 23 23
Total 89 89 89 90 91 92 93 94 95 97 98 99 100 101 103 105 106 107 109 110
0
20
40
60
80
100
120
Av
e
r
a
g
e

G
i
g
a
w
a
t
t
s
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 552 of 1125
Stanfield Natural Gas Price Forecast
$0
$2
$4
$6
$8
$10
$12
$14
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
$
p
e
r

M
W
h
Mean
Median
5th Percentile
95th Percentile
Levelized Price: $5.38/Dth
5th Percentile: $4.14/Dth
95th Percentile: $7.12/Dth
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 553 of 1125
$0
$10
$20
$30
$40
$50
$60
$70
$80
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
$
p
e
r

M
W
h
Flat
Off-Peak
On-Peak
Mid-Columbia Annual Average Forecast
Levelized Price: $44.60/MWh
DRAFT
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 554 of 1125
$0
$20
$40
$60
$80
$100
$120
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
$
p
e
r

M
W
h
Mean
Median
5th Percentile
95th Percentile
Mid-Columbia Electric Prices: Stochastic Results
Levelized Price: $44.60/MWh
5th Percentile: $36.00/MWh
95th Percentile: $57.15/MWh
DRAFT
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 555 of 1125
Implied Market Heat Rate (Mid-C / Stanfield x 1,000)
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
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
Mi
d
-C/
S
t
a
n
f
i
e
l
d

x

1
0
0
0
Mean
5th Percentile
95th Percentile
DRAFT
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 556 of 1125
Mid-Columbia Negative Electric Pricing
0
500
1,000
1,500
2,000
2,500
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
r
s

w
i
t
h

N
e
g
a
t
i
v
e

P
r
i
c
e
s
Mean
Median
5th Percentile
95th Percentile
2011 had 202 hours and 2012 had 552 according to Powerdex hourly index
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 557 of 1125
Western US Greenhouse Gas Emissions Forecast
DRAFT
0
50
100
150
200
250
300
350
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
Mi
l
l
i
o
n
s

M
e
t
r
i
c

T
o
n
s
Mean 5th Percentile 95th Percentile
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 558 of 1125
$0
$20
$40
$60
$80
$100
$120
$140
$160
$180
$200
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
$
p
e
r

M
W
h
Index
2003
2005
2007
2009
2011
2013
IRP Electric Price Forecast Comparison
2007-2011 IRP expected case forecasts included carbon reduction schemes increasing market prices
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 559 of 1125
IRP Price Forecast Comparison (No CO2 Pricing)
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
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
$
p
e
r

M
W
h
Index20032005
2007*2009*
2011*2013Forwards
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 560 of 1125
TAC PRESENTATION
New Resource Integration – Transmission

SYSTEM PLANNING
Prepared by Richard Maguire and the Avista System Planning Group
February 6, 2013
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 561 of 1125
Federal Standards of Conduct
1.No non-public transmission information can be shared with the
Avista Merchant Function
2.There are Avista Merchant Function personnel in attendance
3.We can’t share non-public transmission information today
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 562 of 1125
Agenda
•Introduction to Avista System Planning
•Engineering of Local Generation Requests
•Recent Avista Projects
•Large Generation Interconnection Agreement (LGIA) Queue
•Integrated Resource Plan (IRP) Generation Requests
•Future Transmission Planning Initiatives

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 563 of 1125
Introduction to Avista System Planning
Broad Scope of What We Care About:
•Avista System Performance
•Federal, Regional, and State Compliance
•Regional Transmission System Coordination
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 564 of 1125
Introduction to Avista System Planning
Regional Coordination
WECC
NWPP
CG
NTTG
etc.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 565 of 1125
Introduction to Avista System Planning
We also spend our time:
•Developing internal standards and processes
•Engineering the transmission system
•Engineering the distribution system
•Managing Avista assets
•Projecting future loads and resources
•Engineering local generation requests
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 566 of 1125
Agenda
•Introduction to Avista System Planning
•Engineering of Local Generation Requests
•Recent Avista Projects
•Large Generation Interconnection Request (LGIR) Queue
•Integrated Resource Plan (IRP) Generation Requests
•Future Transmission Planning Initiatives

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 567 of 1125
Engineering of Local Generation Requests
Typical Process for Generation Requests
•We generally get requests via two sources:
•Internal via the IRP requests
•External and Internal via LGIA requests
•We hold a scoping meeting to discuss particulars
•We outline a study plan
•We augment WECC approved cases for our studies
•We analyze the system against the standards
•We publish our findings and recommendations

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 568 of 1125
Engineering of Local Generation Requests
Case Development
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 569 of 1125
Engineering of Local Generation Requests
Case Analysis
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 570 of 1125
Engineering of Local Generation Requests
Mandatory Federal Standards Include:
No overloads all lines and equipment in service (N-0)
No overloads or loss of load for one element out of service (N-1)
Some relaxation of the above for two elements out (N-2)
Standards are “Request Agnostic”
Potential Sanctions:
Up to $1M Per Day Per Occurrence
Mitigation Plan must be provided and progress demonstrated
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 571 of 1125
Engineering of Local Generation Requests
Publish Results
www.oasis.oati.com/avat/index.html
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 572 of 1125
Agenda
•Introduction to Avista System Planning
•Engineering of Local Generation Requests
•Recent Avista Projects
•Large Generation Interconnection Request (LGIR) Queue
•Integrated Resource Plan (IRP) Generation Requests
•Future Transmission Planning Initiatives
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 573 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 574 of 1125
Recent Avista Projects
Palouse Wind:
58 turbines
105 MW
Thornton 230 kV
Substation
$4.35M
Benewah – Shawnee
230 kV Transmission
Line
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 575 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 576 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 577 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 578 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 579 of 1125
Recent Avista Projects
Lind Capacitor Bank
~$750K
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 580 of 1125
Recent Avista Projects
Idaho Road 115 kV Substation
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 581 of 1125
Recent Avista Projects
Turner 115 kV Substation
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 582 of 1125
Recent Avista Projects
115 kV Transmission Lines
$2.5M
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 583 of 1125
Agenda
•Introduction to Avista System Planning
•Engineering of Local Generation Requests
•Recent Avista Projects
•Large Generation Interconnection Request (LGIR) Queue
•Integrated Resource Plan (IRP) Generation Requests
•Future Transmission Planning Initiatives

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 584 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 585 of 1125
Avista Non-IRP Generation Queue
Project # 08: 75 MW with Facility Study completed
$6.6M 230 kV switching station and tap
$5.6M 115 kV breaker position and reconductor
Project # 26: 42MW with System Impact Study completed
Project # 33: 400 MW in Feasibility Study stage
Project # 35: 200 MW in System Impact Study stage
Project # 36: 105 MW in Feasibility Study stage
http://www.oasis.oati.com/AVAT
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 586 of 1125
Agenda
•Introduction to Avista System Planning
•Engineering of Local Generation Requests
•Recent Avista Projects
•Large Generation Interconnection Request (LGIR) Queue
•Integrated Resource Plan (IRP) Generation Requests
•Future Transmission Planning Initiatives

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 587 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 588 of 1125
Avista Non-IRP Generation Queue
Nine Mile HED: 60 MW total
Long Lake HED: 68 MW additional (156 MW total)
Studied coincident with Nine Mile IRP request
$9.9M for 115 kV Transmission Line reconductoring
Monroe Street HED: 80 MW additional (95 MW total)
Upper Falls HED: 40 MW additional (50.26 MW total)
Post Falls HED: 33.5 MW total
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 589 of 1125
Avista Non-IRP Generation Queue
Cabinet Gorge HED: 60 MW additional (330.5 MW total)
No capacity available today during Heavy Summer loading
Considering RAS or potential Transmission System upgrades
Benewah – Boulder: 300 MW project currently under study
Rathdrum: 300 MW
$7M for new breaker position at Rathdrum 230 kV Substation
Rosalia: 200 MW
$4M for new breaker position at Thornton 230 kV Substation
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 590 of 1125
Agenda
•Introduction to Avista System Planning
•Engineering of Local Generation Requests
•Recent Avista Projects
•Large Generation Interconnection Request (LGIR) Queue
•Integrated Resource Plan (IRP) Generation Requests
•Future Transmission Planning Initiatives

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 591 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 592 of 1125
Examples of Future Construction Required to Meet
NERC / WECC Reliability Standards
Moscow Station:
250 MVA transformer
Increases capacity to the Moscow / Pullman area and
relieves loading on the Shawnee transformer
Westside Station:
Two 250 MVA transformers
Increases capacity and security to the West Plains area of
Spokane County, and relieves heavy loading on large
transformers in the central Spokane area
Irvin 115 kV and Associated 115 kV Reconductoring:
115 kV Switching Station and other upgrades to meet
additional load growth in the Spokane Valley
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 593 of 1125
Recent Avista Projects
Moscow Station Construction
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 594 of 1125
Future Work?
Generic Break Point Studies for IRP / 3rd Party Developers:
“How many MW can we integrate where for about what $$?”
Main Grid 230 kV Stations.
Select 115 kV Stations.
Potential Open Seasons:
“Does anyone want to get to the Mid Columbia?”
“Does anyone want to get out of Montana?”
“Does anyone want to get to PAC or IPC?”
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 595 of 1125

Questions?
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 596 of 1125

Resource Needs Assessment
Clint Kalich
Fourth Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
February 6, 2013

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 597 of 1125
Power Supply Reliability Key Terms
Peak Demand
Winter and Summer single hour view to verify the utility can meet its highest
expected load hour in a given year
Sustained Peak Demand
Winter and summer multi-day event (3 day x 6 hour) view to verify the utility
can meet its highest expected load hour in a given year
 Energy
On an annual basis the utility has enough energy to meet load plus
contingencies (e.g., load and hydro variability)
Operating Reserves
System capacity “reserved” to meet unanticipated generation outages; 5%
of wind and hydro, and 7% of thermal, plants
Regulation to cover moment-to-moment load and generation variability
Loss of Load Probability (LOLP)
Number of modeling exercises where system resources are inadequate to
meet needs; 1-in-20 (5%) is deemed adequate
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 598 of 1125
Historical Avista Planning Margin Targets
1979: 6% (single hour, hydro only); 15 to 20% with thermal units
Somewhere in between 1979 and 1986: 13.4% to 18.7%
1986 to 2007: 10% + 90 MW (single hour peak)
2009: 15%
2011: Move to an 18-hour sustained peak per NPCC
Winter: 14% + Operating Reserves
Summer: 15% + Operating Reserves
Equivalent to NPCC 23/24% planning criteria for the Northwest
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 599 of 1125
Adequacy Assessment for the
2017 Pacific Northwest Power Supply
Steering Committee Meeting
October 26, 2012
Portland, Oregon 4
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 600 of 1125
NW Adequacy Standard
Metric: Loss-of-load probability (LOLP)
Threshold: Maximum of 5 percent

LOLP is the probability that extraordinary actions would
have to be taken in a future year to avoid curtailment of
electricity service
Calculated assuming existing resources only and
expected efficiency savings
5
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 601 of 1125
Major Assumptions
Existing resources (sited and licensed)
6th Power Plan conservation
Market supplies
–NW: 3,450 MW winter, 1,000 MW summer
–SW on-peak: 1,700 MW winter, none summer
–SW off-peak: 3,000 MW year round
Council’s medium load forecast
6
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 602 of 1125
Major Uncertainties
Explicitly modeled
–Water supply
–Temperature load variation
–Wind
–Forced outages
Not modeled explicitly
–Economic load growth
–Uncertainty in SW market
7
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 603 of 1125
2017 Assessment
The expected LOLP is 6.6%
January, February and August most
critical months

Interpretation: Relying only on existing
resources and expected efficiency savings
yields a power supply in 2017 whose
likelihood of curtailment exceeds our
agreed upon threshold
8
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 604 of 1125
Actions to Alleviate Inadequacy
350 MW of new generating resource
capacity drops the expected LOLP to 5%
Equivalently, 300 average megawatts of
additional energy efficiency does the same
Demand response measures could help
This is consistent with utility plans and the
Council’s resource strategy
9
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 605 of 1125
2017 Monthly LOLP
10
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 606 of 1125
Effects of Uncertainties
11
Load SW Winter Market LOLP
Low High 2.8%
Low None 8.4%
High High 7.8%
High None 16.8%
Expected Expected 6.6%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 607 of 1125
Illustration of LOLP Probability
12
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 608 of 1125
Effects of Adding Resources
13
350 MW of new resource moved the
reference case LOLP of 6.6% down to 5.0%

2,850 MW of new resource moved a high
LOLP of 13.3% down to 5.0%

Sum of utility planned* resources exceeds
3,000 MW
*In this context “planned” means request for proposals or RFPs.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 609 of 1125
Variation in LOLP due to Load and Market
14
Load change in percent from medium >>>>
Market -2.50 -2.25 -2.00 -1.75 -1.50 -1.25 -1.00 -0.75 -0.50 -0.25 0.00 0.25 0.50 0.75 1.00 1.25 1.50 1.75 2.00 2.25 2.50
0 8.4 11.8 16.8
100 13.2
200 13.3
300 13.2
400 13.2
500
600
700
800
900 6.3 10.4
1000 5.1
1100 4.8
1200
1300 5.4
1400
1500
1600
1700 3.7 4.5 6.6 9.8
1800
1900
2000
2100
2200
2300
2400
2500 3.8 7.2
2600
2700
2800
2900
3000
3100
3200 2.8 5.0 7.8
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 610 of 1125
Thermal derate schedules
15
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 611 of 1125
Thermal derate schedules
16
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 612 of 1125
How much CT gets you to 5%
17
Add a CT resource that will bring study
cases with >5.0% LOLP down to 5.0%
Study Summary LOLP Pk LOLP E LOLP A EUSR CVaRE CVaRPk EUE LOLH
Study Case Load Dev. Mkt. Add CT (%) (%) (%) (%) (MWh) (MW) (MWh (Hr/sYr)
Reference Case 0.00%1700 350 5.0 1.5 5.0 7.3 76466 3410 3851 2.1
High Load, High Market 2.50%3200 750 5.0 0.9 5.0 7.9 43510 2913 2197 1.4
High Load, Low Market 2.50% 0 4800 5.0 0.8 5.0 6.2 43007 2645 2162 1.4
Low Load, High Market -2.50%3200 NA
Low Load, Low Market -2.50% 0 1155 5.0 1.5 5.0 6.5 76118 2593 3829 2.4
Med-High Load, Med-High Mkt 1.50%2500 525 5.0 1.1 5.0 8.0 58041 3165 2923 1.7
Med-High Load, Med-Low Mkt 1.50%900 1950 5.0 1.3 5.0 6.8 61092 2866 3071 1.9
Med-Low Load, Med-High Mkt -1.50%2500 NA
Med-Low Load, Med-Low Mkt -1.50%900 450 5.0 1.5 5.0 6.7 80421 3184 4033 2.3
Reference Load, High Market 0.00%3200 NA
Reference Load, Low Market 0.00% 0 2750 5.0 0.8 5.0 6.3 53995 2443 2717 1.9
High Load, Reference Market 2.50%1700 1200 5.0 1.5 5.0 7.7 75020 3400 3778 2.1
Low Load, Reference Market -2.50%1700 NA
High Case within likely region 1.25%200 2850 5.0 1.0 5.0 6.6 56369 2587 2836 1.9
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 613 of 1125
Regional Position (2016/17- Peak Hour)
2016 2016 2016 2017 2017 2017 2017 2017 2017 2017 2017 2017
10 11 12 1 2 3 4 5 6 7 8 9
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep
1-Hr Peak
Avg Load 24,458 28,593 31,838 33,143 29,949 27,929 25,454 23,596 25,078 26,773 26,151 23,589
Hydro 25,059 25,857 26,675 27,944 26,400 25,773 25,388 25,852 27,271 26,394 25,232 25,198
Hydro Ind.299 299 299 299 299 299 299 299 299 299 299 299
Total Non-Hydro 25,358 26,155 26,974 28,242 26,699 26,072 25,687 26,151 27,569 26,692 25,531 25,497
Small Renewables 109 109 109 109 109 109 109 109 109 109 109 109
Nuclear 1,130 1,130 1,130 1,130 1,130 1,130 1,130 1,130 1,130 1,130 1,130 1,130
Coal 4,708 4,708 4,708 4,708 4,708 4,708 4,708 4,708 4,708 4,708 4,708 4,708
CCCT 4,868 4,961 5,151 5,151 5,054 4,961 4,868 4,775 4,678 4,678 4,678 4,775
Peakers 1,751 1,784 1,853 1,853 1,817 1,784 1,751 1,717 1,682 1,682 1,682 1,717
Total Non-Hydro 12,566 12,692 12,951 12,951 12,819 12,692 12,566 12,440 12,307 12,307 12,307 12,440
Total Generation 37,924 38,848 39,925 41,194 39,518 38,764 38,253 38,591 39,877 39,000 37,838 37,937
Physicial Position 13,466 10,255 8,087 8,050 9,568 10,836 12,799 14,995 14,798 12,227 11,687 14,348
Implied Planning Margin 55% 36% 25% 24% 32% 39% 50% 64% 59% 46% 45% 61%
IPP Generation 3,200 3,240 3,324 3,324 3,281 3,240 3,200 3,159 3,116 3,116 3,116 3,159
Physicial Position w/ IPP 16,666 13,495 11,410 11,374 12,849 14,076 15,999 18,154 17,915 15,343 14,804 17,507
W/ IPP Implied Plannin Margin 68% 47% 36% 34% 43% 50% 63% 77% 71% 57% 57% 74%
Data provided by Northwest Power & Conservation Council
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 614 of 1125
Regional Position (2016/17- 10 Hour Peak)
2016 2016 2016 2017 2017 2017 2017 2017 2017 2017 2017 2017
10 11 12 1 2 3 4 5 6 7 8 9
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep
10-Hr Peak
Avg Load 22,991 26,878 29,928 31,155 28,152 26,253 23,926 22,181 23,574 25,166 24,582 22,174
Hydro West 3,107 3,656 2,862 2,711 2,597 3,443 3,548 3,736 3,640 3,282 3,366 3,160
Hydro East 21,090 21,564 19,414 16,178 15,722 17,375 19,708 21,239 20,835 19,884 20,723 19,824
Hydro Ind.299 299 299 299 299 299 299 299 299 299 299 299
Total Hydro 24,496 25,518 22,574 19,188 18,617 21,117 23,554 25,273 24,774 23,464 24,387 23,283
Small Renewables 109 109 109 109 109 109 109 109 109 109 109 109
Nuclear 1,130 1,130 1,130 1,130 1,130 1,130 1,130 1,130 1,130 1,130 1,130 1,130
Coal 4,708 4,708 4,708 4,708 4,708 4,708 4,708 4,708 4,708 4,708 4,708 4,708
CCCT 4,868 4,961 5,151 5,151 5,054 4,961 4,868 4,775 4,678 4,678 4,678 4,775
Peakers 1,751 1,784 1,853 2,203 1,817 1,784 1,751 1,717 1,682 1,682 1,682 1,717
Total Non-Hydro 12,566 12,692 12,951 13,301 12,819 12,692 12,566 12,440 12,307 12,307 12,307 12,440
Total Generation 37,062 38,211 35,525 32,489 31,436 33,809 36,121 37,713 37,081 35,771 36,695 35,723
Physicial Position 14,072 11,333 5,598 1,334 3,283 7,556 12,194 15,533 13,507 10,605 12,113 13,549
Implied Planning Margin 61% 42% 19% 4% 12% 29% 51% 70% 57% 42% 49% 61%
IPP Generation 3,200 3,240 3,324 3,324 3,281 3,240 3,200 3,159 3,116 3,116 3,116 3,159
Physicial Position w/ IPP 17,271 14,573 8,921 4,658 6,564 10,796 15,394 18,692 16,624 13,721 15,229 16,708
W/ IPP Implied Plannin Margin 75% 54% 30% 15% 23% 41% 64% 84% 71% 55% 62% 75%
Data provided by Northwest Power & Conservation Council
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 615 of 1125
Translating the Regional Position to Avista
NPCC indicates region will be short capacity in the 2016/7 winter
timeframe
With region in surplus, utility can rely on market in peak conditions
Changes in load growth or out-of-region transfers can change
adequacy results
Summer adequacy is strong for the region
With regional summer length- dual peaking utilities can rely on
system for summer peaks
Future build-outs for winter peaks likely will ensure adequate
regional summer capacity
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 616 of 1125
Resource allocation to get Avista to 5% LOLP goal
0
5
10
15
20
25
30
35
40
45
-
50
100
150
200
250
300
0 25 50 75 100 125 150 175 200 225 250 275 300 325
In
c
r
e
m
e
n
t
a
l

C
o
s
t

(
$
M
i
l
l
/
Y
r
)
Ma
r
k
e
t

D
e
p
e
n
d
a
n
c
e

(
M
W
)
New Capacity
MW
Annual Cost
34% 30% 21% 18% 28% 25% 16% 14% Winter PM Summer PM
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 617 of 1125
Avista’s Peak Planning Criteria
Winter Peak
14% planning margin above load, plus operating reserves
If Avista is deficit prior to 2016/17, and where the NW market
has been shown adequately surplus, market purchases will
meet deficit needs
Summer Peak
Avista operating reserves are the planning requirement,
unless region’s “natural” deficit shifts to summer
If utility is deficit, market purchases will meet deficit needs
However, as with the region, building to meet winter peak
generally addresses our summer need
Both sustained- and single-hour peak positions are considered
Wind and solar provide no winter peaking capability
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 618 of 1125
January: 18 Hour Peak Position Forecast
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
REQUIREMENTS
1 Native Load -1,596 -1,613 -1,629 -1,643 -1,656 -1,669 -1,683 -1,696 -1,710 -1,724 -1,738 -1,752 -1,766 -1,780 -1,794 -1,809 -1,824 -1,838 -1,853 -1,8682 Firm Power Sales -211 -158 -158 -8 -8 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6
3 Total Requirements -1,807 -1,771 -1,787 -1,650 -1,663 -1,675 -1,689 -1,702 -1,716 -1,730 -1,744 -1,758 -1,772 -1,786 -1,801 -1,815 -1,830 -1,844 -1,859 -1,874
RESOURCES
4 Firm Power Purchases 117 117 117 117 117 116 34 34 33 33 33 33 33 33 33 33 33 33 33 33
5 Hydro Resources 973 866 867 932 932 896 900 896 896 904 896 896 904 896 896 904 896 896 904 896
6 Base Load Thermals 895 895 895 895 895 895 895 895 895 895 895 895 895 617 617 617 617 617 617 617
7 Wind Resources 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 08 Peaking Units 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242
9 Total Resources 2,227 2,121 2,122 2,187 2,186 2,149 2,071 2,068 2,067 2,074 2,067 2,067 2,074 1,788 1,788 1,796 1,788 1,788 1,796 1,788
10 PEAK POSITION 421 350 334 536 523 473 383 365 351 345 323 309 303 2 -13 -19 -42 -57 -64 -86
RESERVE PLANNING
11 Planning Margin -223 -226 -228 -230 -232 -234 -236 -237 -239 -241 -243 -245 -247 -249 -251 -253 -255 -257 -259 -262
12 Total Ancillary Services Required -186 -184 -185 -177 -179 -180 -186 -187 -189 -191 -192 -193 -194 -195 -196 -197 -197 -198 -199 -19913Reserve & Contingency Availability 25 9 9 17 17 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16
14 Demand Response 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
15 Total Reserve Planning -385 -401 -405 -390 -394 -398 -405 -409 -412 -416 -419 -422 -425 -428 -431 -434 -436 -439 -442 -444
16 Peak Position w/ Contingency 36 -51 -70 146 129 76 -22 -43 -61 -71 -96 -113 -123 -426 -443 -453 -478 -495 -506 -531
17 Implied Planning Margin 25% 20% 19% 33% 32% 29% 24% 22% 21% 21% 19% 18% 18% 1% 0% 0%-1% -2% -3% -4%
18 NPCC Market Adjustment 0 51 70 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
19 Peak Position Net Market 36 0 0 146 129 76 (22) (43) (61) (71) (96) (113) (123) (426) (443) (453) (478) (495) (506) (531)
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
Winter 1 Hour 17 0 0 126 110 56 (42) (64) (81) (92) (117) (135) (145) (445) (462) (472) (497) (515) (525) (551)Winter 18 Hour 36 0 0 146 129 76 (22) (43) (61) (71) (96) (113) (123) (426) (443) (453) (478) (495) (506) (531)
Delta 19 0 0 19 19 20 20 20 20 21 21 22 22 18 19 19 19 19 20 20
18 Hour to 1 Hour Comparison
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 619 of 1125
August: 18 Hour Peak Position Forecast
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
REQUIREMENTS
1 Native Load -1,465 -1,482 -1,498 -1,510 -1,523 -1,536 -1,550 -1,563 -1,576 -1,590 -1,604 -1,618 -1,631 -1,646 -1,660 -1,674 -1,689 -1,703 -1,718 -1,7332 Firm Power Sales -212 -159 -159 -9 -9 -8 -8 -7 -7 -7 -7 -7 -7 -7 -7 -7 -7 -7 -7 -7
3 Total Requirements -1,677 -1,641 -1,657 -1,519 -1,532 -1,544 -1,557 -1,570 -1,584 -1,597 -1,611 -1,625 -1,639 -1,653 -1,667 -1,681 -1,696 -1,710 -1,725 -1,740
RESOURCES
4 Firm Power Purchases 29 29 29 29 29 26 26 26 26 25 25 25 25 25 25 25 25 25 25 25
5 Hydro Resources 701 707 663 631 638 583 580 622 624 622 622 624 622 622 624 622 622 624 622 622
6 Base Load Thermals 785 785 785 785 785 785 785 785 785 785 785 785 785 556 556 556 556 556 556 556
7 Wind Resources 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 08 Peaking Units 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176
9 Total Resources 1,691 1,698 1,653 1,621 1,628 1,571 1,568 1,609 1,611 1,609 1,609 1,611 1,609 1,379 1,381 1,379 1,379 1,381 1,379 1,379
10 PEAK POSITION 14 57 -3 102 96 27 11 39 27 11 -2 -14 -30 -274 -286 -302 -317 -330 -346 -361
RESERVE PLANNING
11 Planning Margin 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
12 Total Ancillary Services Required -177 -176 -177 -170 -172 -173 -175 -176 -177 -179 -180 -181 -182 -166 -167 -167 -168 -169 -169 -17013Reserve & Contingency Availability 177 176 177 170 172 173 175 176 177 179 180 181 182 166 167 167 168 169 169 170
14 Demand Response 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
15 Total Reserve Planning 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
16 Peak Position w/ Contingency 14 57 -3 102 96 27 11 39 27 11 -2 -14 -30 -274 -286 -302 -317 -330 -346 -361
17 Implied Planning Margin 11% 14% 10% 18% 17% 13% 12% 14% 13% 12% 11% 10% 9%-7% -7% -8% -9% -9% -10% -11%
18 NPCC Market Adjustment 0 0 3 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
19 Peak Position Net Market 14 57 0 102 96 27 11 39 27 11 (2) (14) (30) (274) (286) (302) (317) (330) (346) (361)
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
Summer 1 Hour 114 159 85 193 185 113 95 125 112 94 79 65 48 (191) (204) (221) (236) (249) (267) (282)Summer 18 Hour 14 57 0 102 96 27 11 39 27 11 (2) (14) (30) (274) (286) (302) (317) (330) (346) (361)
Delta (100) (102) (85) (91) (89) (86) (84) (87) (85) (83) (81) (80) (78) (83) (83) (82) (81) (80) (79) (79)
18 Hour to 1 Hour Comparison
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 620 of 1125

Market and Portfolio Scenario
Development
John Lyons, Senior Resource Policy Analyst
Fourth Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
February 6, 2013

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 621 of 1125
Scenarios in the 2013 IRP
Scenarios provide details about potential impacts of different critical planning
assumptions that could have a major
impact on resource choices, such as technological, regulatory or environmental
changes.

Scenarios will be developed for:
• Avista’s current load and resource portfolio
• Preferred Resource Strategy (PRS)
• Wholesale electric market
• Different resource options

2 Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 622 of 1125
2013 IRP Scenario Types
3

1.Deterministic Market Scenarios: use expected input levels (natural gas prices, hydro, loads, wind, and thermal outages)

2.Stochastic Market Scenarios: use a Monte Carlo analysis

3.Portfolio Scenarios: show alternative portfolios to highlight the cost differences from the PRS

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 623 of 1125
Deterministic Market Scenarios
4
Deterministic scenarios test the PRS across several fundamentally different futures:
• Low and High Natural Gas Prices
• Carbon Pricing
• No Coal Retirements
• High Storage Technology Penetration
• Increasing RPS

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 624 of 1125
Stochastic Market Scenarios
5
• Expected Case: assumes average levels of hydro, loads, gas prices, wind, emissions prices and forced outages

• Carbon Pricing Scenario: various pricing trajectories similar to the 2011 IRP expected case
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 625 of 1125
Portfolio Scenarios
6
• Market reliance only
•CO2 credit allocations
• 2011 PRS
• Increased Washington RPS – 25% by 2025
• National renewable energy standard – 20% with and
without hydro netting
• Alternative Planning Margins
• CT and CCCT tipping points
• Solar cost tipping point
• Nuclear cost tipping point
• Coal sequestration cost tipping point

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 626 of 1125
Colstrip Scenarios
7
• 2017 Retirement Date
• 2022 Retirement Date
• Incremental Pollution Controls
• Carbon Sequestration
• Railed Coal

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 627 of 1125
Avista’s 2013 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 5 Agenda
Wednesday, March 20, 2013
Conference Room 428

Topic Time Staff
1. Introduction 9:00

2. Market Forecast Scenario Results 9:05 Gall and Conservation Avoided Costs

3. Conservation Results 9:30 Borstein

4. Break 11:00

5. Demand Response 11:15 Doege

6. Lunch 12:00

7. 2013 IRP Preferred Resource Strategy 1:00 Gall

8. Break 2:00

9. Portfolio Scenarios 2:15 Gall

10. Adjourn 3:00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 628 of 1125
Electric Price Forecast Scenario Analysis
James Gall
Fifth Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
March 20, 2013

1
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 629 of 1125
Scenario Planning
This IRP reviews two types of market scenarios to help understand
how market forces can impact Avista’s resource strategy
1.Deterministic studies- point forecast of future major assumptions
2.Stochastic studies- Monte-Carlo style analysis using 500
iterations for major assumptions

2
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 630 of 1125
$0
$10
$20
$30
$40
$50
$60
$70
$80
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
$
p
e
r

M
W
h
Flat
Off -Peak
On-Peak
Expected Case Refresher
Levelized Price: $44.08/MWh
stochastic case
3
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 631 of 1125
Greenhouse Gas Pricing Scenario
Developed to understand the ramifications of national
greenhouse gas reduction legislation to Avista’s resource strategy
This scenario uses 500 iterations with different potential CO2
pricing schemes using a cap-and-trade market mechanism
Five weighted potential pricing structures were developed to
create a wide range of potential futures (2014 $)
Expected Case- $0/ton (33.3%)
2020 High- $30/ton (16.7%), 2025 High- $40/ton (16.7%)
2020 Low- $10/ton (16.7%), 2025 Low- $15/ton (16.7%)

4
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 632 of 1125
Greenhouse Gas Pricing Scenario Price Assumptions
$0
$10
$20
$30
$40
$50
$60
$70
$80
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
$
p
e
r

S
h
o
r
t

T
o
n
Weighted Average
Expected Case
2025 High GHG Pricing Case
2025 Low GHG Pricing Case
2020 High GHG Pricing Case
2020 Low GHG Pricing Case
5
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 633 of 1125
Greenhouse Gas Scenario Market Prices
$0
$20
$40
$60
$80
$100
$120
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
$
p
e
r

M
W
h
Weighted Avg GHG Case
2025 High GHG Pricing Case
2025 Low GHG Pricing Case
2020 High GHG Pricing Case
2020 Low GHG Pricing Case
Expected Case
deterministic case
6
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 634 of 1125
20-Year Levelized Greenhouse Gas Scenario Prices
deterministic case
$44.18
$49.22 $52.00
$46.51
$56.99
$47.19
$0
$10
$20
$30
$40
$50
$60
$70
$80
Expected
Case
Weighted
Avg GHG
Case
2025 High
GHG Pricing
Case
2025 Low
GHG Pricing
Case
2020 High
GHG Pricing
Case
2020 Low
GHG Pricing
Case
$
p
e
r

M
W
h
7
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 635 of 1125
0%
10%
20%
30%
40%
50%
60%
Weighted Avg
GHG Case
2025 High GHG
Pricing Case
2025 Low GHG
Pricing Case
2020 High GHG
Pricing Case
2020 Low GHG
Pricing Case
Pe
r
c
e
n
t

I
n
c
r
e
a
s
e
The Real Increase to Electric Market Prices
Average increase to market prices between 2025-2033,
as compared to the Expected Case
8
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 636 of 1125
Greenhouse Gas Scenario Reductions
-
50
100
150
200
250
300
350
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
Mi
l
l
i
o
n
s

o
f

M
e
t
r
i
c

T
o
n
s
2025 High GHG Pricing Case 2025 Low GHG Pricing Case
2020 High GHG Pricing Case 2020 Low GHG Pricing Case
Weighted Avg GHG Case Expected Case
1990 Levels
deterministic case
9
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 637 of 1125
$0
$10
$20
$30
$40
$50
$60
$70
$80
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
$
p
e
r

M
W
h
No Coal Retirements
Expected Case
No Coal Plant Retirement Scenario
Expected Case: $44.18/MWh levelized
No Coal Retirements: $42.93/MWh levelized
- Retains 12,000 MW of coal generation for the duration of the forecast
deterministic case
10
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 638 of 1125
-
50
100
150
200
250
300
350
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
Mi
l
l
i
o
n
s

o
f

M
e
t
r
i
c

T
o
n
s
No Coal Retirements
Expected Case
Greenhouse Gas Emissions Increase Without Coal
Retirements
US Western Interconnect GHG emissions are reduced by 8 percent.
This is an effective cost of $87 per short ton of GHG in 2014 dollars
deterministic case
11
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 639 of 1125
State RPS’s Increased Scenario
-Assumes in beginning in 2025, states with lower RPS begin new higher standards
0%10%20%30%40%50%60%
Arizona
California
Colorado
Idaho
Montana
New Mexico
Nevada
Oregon
Utah
Washington
Wyoming
Renewable Energy Goal
Expected Case
RPS Scenario
Adds
Wind: 7,000 MW
Solar: 29,000 MW
Other: 1,000 MW

Cost: $80 billion (2012$)
12
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 640 of 1125
Changes to Market Prices and GHG Emissions
0%
2%
4%
6%
8%
10%
2025 2026 2027 2028 2029 2030 2031 2032 2033
Pe
r
c
e
n
t

R
e
d
u
c
t
i
o
n
Reduction in Market Prices
Reduction in GHG
Added cost of RPS is equivalent to
a GHG cost of $180 per short ton
(2014 dollars)
13
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 641 of 1125
Conservation Avoided Costs
James Gall
Fifth Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
March 20, 2013

14
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 642 of 1125
How to Value Conservation
{(E + PC + R) * (1 + P)} * (1 + L) + DC * (1 + L)

Where:
E = market energy price (calculated by Aurora, including forecasted CO2 mitigation)
PC = new resource capacity savings (calculated by PRiSM)
R = Risk premium to account for RPS and rate volatility reduction (calculated by PRiSM)
P = Power Act preference premium (10% assumption)
DC = distribution capacity savings (~$10/kW-year based on Heritage Project calculation)
L = transmission and distribution losses (6.1% assumption based on Avista’s system average losses)
15
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 643 of 1125
Efficient Frontier Approach
Assumes no additional Conservation Resources
Portfolio Cost
Po
r
t
f
o
l
i
o

R
i
s
k

Market $44.63/ MWh
Capacity $107 kW-Yr
Risk 0.29/ MWh
Market Only
PRS Mix
Efficient Frontier
16
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 644 of 1125
Avoided Cost Calculation
For 1 MW Measure with Flat Delivery
Item $/MWh
Energy Price 44.63
Capacity Savings 13.33
Risk Premium 0.29
Subtotal 58.26
Item $/MWh
10% Preference 6.19
Distribution Capacity Savings 0.88
T&D losses 2.72
Subtotal 9.79
Avoided Cost:
$68.05
per
MWh
2011 IRP was $104.39/MWh Analysis based on earlier draft of Market Prices
17
Converts $107/kW-yr to $/MWh
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 645 of 1125
Avista Conservation Potential
Assessment – 2013 Update
Overview of Approach and Analysis Results
March 20, 2013
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 646 of 1125
2
Agenda
• Introductions
• Study objectives
• Analysis approach
• Summary of results
• Consistency with NWPCC Methodology
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 647 of 1125
3
Introductions
Ingrid Rohmund
Practice Lead,
Energy Analysis
and Planning

Jan Borstein
Project Manager

Various analysts

EnerNOC Team EnerNOC Utility Solutions
Consulting
• Previously Global Energy Partners,
and before that a part of EPRI
• Practice areas:
• Energy Analysis & Planning
• Program Evaluation and
Load Analysis
• Engineering Services
• 30 full-time consultants
• Economists/statisticians
• Engineers
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 648 of 1125
4
EnerNOC experience with potential studies
Northwest:
Avista Utilities*
Idaho Power
Seattle City Light*
Portland GE*
BPA
Inland P&L*
Cowlitz PUD* OTECC

Southwest: LADWP
State of NM State of HI
National/Regional:
EPRI National DSM Study
FERC Nat’l Assessment of DR
IEE Analysis of Codes and Standards*
Midwest ISO EE and DR Assessment
International:
Manitoba Hydro
ECRA (Saudi Arabia)
ElectraNet (Australia)
KERI (Korea)*
Midwest :
Ameren Missouri*
Ameren Illinois Indianapolis P&L
Citizens Energy Vectren
Iowa TVA
Northeast:
Con Edison of NY PECO Energy
New Jersey BPU
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 649 of 1125
5
Study objectives
• Study continues Avista’s process of updating estimates of conservation
potential on a regular basis
• Specific objectives:
•Provide credible and transparent estimates of conservation potential
•Assess savings by measure or bundled measure and sector
•Support Avista’s IRP development
•Establish 2014-2015 biennial target per requirements of Washington I-937
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 650 of 1125
6
Analysis Approach
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 651 of 1125
7
Study objectives
Characterize
the Market
Base-year energy use by segment
Prototypes and energy analysis (BEST) Avista Forecast data
Codes and standards RTF data Secondary data
Project the
Baseline
End-use projection by segment
Screen Measures
and Options
Measure descriptions Avista program data, TRM
Avoided costs NWPCC/RTF workbooks
Technical and economic potential
Establish Customer
Acceptance
Program results Other studies
Market acceptance rates
Achievable potential
Synthesize Review Annual Business Plans
Sensitivity analysis
Study results
Avista billing data Program data Energy Market Profiles
RBSA and other saturation surveys Secondary data Previous study results
Study approach
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 652 of 1125
8
Market segmentation by rate class, 2009

Sector Rate
Schedule(s)
Number of
meters
(customers)
2009
Electricity
sales (MWh)
Residential 001 299,714 3,634,086
General Service 011, 012 46,387 738,505
Large General Service 021, 022 4,808 2,256,882
Extra Large GS – Comm. 025 12 336,047
Extra Large GS – Ind* 19 809,298
Pumping 031, 032 3,673 194,884
Total 354,613 7,969,701
* Idaho 25P was included in previous CPA but for the 2013 study it has been analyzed separately from other large industrial customers.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 653 of 1125
9
Residential market characterization, 2009
• Market segmentation developed using U.S.
Census American Community Survey data
• Limited Income is defined as customers with
annual income approximately two times the
poverty level
Segment Annual Use
(1000 MWh)
Number of
Customers
Intensity
(kWh/HH)
% of Total
Usage
Single Family 2,399 168,339 14,250 66%
Multi Family 202 23,456 8,613 6%
Mobile Home 128 10,022 12,724 4%
Limited Income 906 97,896 9,251 25%
Total 3,634 299,714 12,125 100%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 654 of 1125
10
Residential market profile, 2009

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 655 of 1125
11
Baseline projection
•Model equipment choices for replacement or new construction
•Define baseline purchase shares —begin with Annual Energy Outlook shipments data
and modify for Avista data and program history
•Incorporates building codes and appliance standards currently enacted
•In some cases, this eliminates potential future savings, as higher efficiency option
becomes the baseline, least efficient option

Today's Efficiency or Standard Assumption 1st Standard (relative to today's standard)
2nd Standard (relative to today's standard)
End Use Technology 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Central AC
Room AC
Cooling/Heating Heat Pump
Water Heater (<=55
gallons)Water Heater (>55 gallons)
Screw-in/Pin Lamps
Linear Fluorescent
Refrigerator/2nd
RefrigeratorFreezer
Dishwasher
Clothes Washer
Clothes Dryer
Cooling SEER 13 SEER 14
EER 9.8 EER 11.0
SEER 13.0/HSPF 7.7 SEER 14.0/HSPF 8.0
Water Heating EF 0.90 EF 0.95
EF 0.90 Heat Pump Water Heater
NAECA Standard 25% more efficient
NAECA Standard 25% more efficient
Appliances
Lighting Incandescent Advanced Incandescent - tier 1 Advanced Incandescent - tier 2
T8
Conventional (355
kWh/yr)
14% more efficient (307 kWh/yr)
Conventional (MEF 1.26 for top loader)MEF 1.72 for top loader MEF 2.0 for top loader
Conventional (EF 3.01)5% more efficient (EF 3.17)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 656 of 1125
12
Baseline projection
•Drivers
• Market size / customer growth
• Income growth
• Avista retail rates forecast
• Trends in end-use/technology saturations
• Equipment purchase decisions
• Cooling and heating degree days
• Persons/household and physical home size
• Elasticities by end use for each forecast driver
•Calibrated model to align with 2010-2012 sales and conservation program history
• Began with Sixth Power Plan measure ramp rates and adjusted to program achievements
• Baseline projection aligns with sales + program achievements

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 657 of 1125
13
The baseline projection (absent future conservation)
• The metric against which savings are measured. It includes:
•Current saturations of appliances, equipment, and legacy measures
•Assumptions about customer and economic growth
•Trends in fuel shares and appliance/equipment saturations
•Exogenous variables including electricity prices, income, etc.
Sample Residential Projection
(Use per Household )
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 658 of 1125
14

Develop three levels of potential
Potential studies identify future opportunities for EE that can be achieved through
programs
Technical Potential
Theoretical upper limit of conservation, where all efficiency measures are phased in regardless of cost
Economic Potential
Conservation potential that includes measures that are cost-effective

Achievable Potential
Conservation potential that can be realistically achieved, accounting for customer adoption rates and how quickly programs can be implemented

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 659 of 1125
15
Economic
screen
Measure characterization
Conservation measure assessment approach
Measure
descriptions
Energy
savings Costs
Lifetime Applicability
EnerNOC
universal
measure list
Building
simulations
EnerNOC measure
data library
NWPCC
Client measure data library
(RTF, TRMs,
evaluation reports,
etc.)
Avoided costs,
discount rate, delivery losses
Client review /
feedback
Inputs Process
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 660 of 1125
16
Potential Results
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 661 of 1125
17
All sectors potential
• Cumulative achievable savings
potential in 2014 is 4.4 aMW
• Cumulative achievable savings
potential in 2015 is 8.7 aMW

2014 2015 2018 2023 2028 2033
Cumulative Savings (MWh)
Achievable Potential 38,726 76,352 300,112 610,600 928,320 1,271,323
Economic Potential 272,830 446,842 1,127,376 1,723,424 2,312,719 2,675,318
Technical Potential 1,173,173 1,392,531 2,374,256 3,366,522 4,122,161 4,604,718
Cumulative Savings (aMW)
Achievable Potential 4.4 8.7 34.3 69.7 106.0 145.1
Economic Potential 31.1 51.0 128.7 196.7 264.0 305.4
Technical Potential 133.9 159.0 271.0 384.3 470.6 525.7
0
50
100
150
200
250
300
350
400
450
500
2015 2018 2023 2028
En
e
r
g
y

S
a
v
i
n
g
s

(
a
M
W
)
Achievable Potential
Economic Potential
Technical Potential
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 662 of 1125
18
All sectors potential

0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
En
e
r
g
y

C
o
n
s
u
m
p
t
i
o
n

(
1
,
0
0
0

M
W
h
)

Baseline Forecast
Achievable Potential
Economic Potential
Technical Potential
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 663 of 1125
19
All sectors potential

-
20
40
60
80
100
120
140
160
180
Cu
m
u
l
a
t
i
v
e

A
c
h
i
e
v
a
b
l
e

P
o
t
e
n
t
i
a
l

S
a
v
i
n
g
s

(
a
M
W
)
ID Pumping
ID C&I
ID Res
WA Pumping
WA C&I
WA Res
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 664 of 1125
20
Residential potential
• Cumulative achievable savings
potential is 1.9 aMW in 2014
• Grow to 3.4 aMW in 2015
2014 2015 2018 2023 2028 2033
Cumulative Savings (MWh)
Achievable Potential 16,247 30,197 124,161 202,569 319,277 503,671
Economic Potential 206,661 322,861 781,184 1,051,855 1,430,505 1,643,220
Technical Potential 987,175 1,070,490 1,415,574 1,557,797 1,870,448 2,071,698
Cumulative Savings (aMW)
Achievable Potential 1.9 3.4 14.2 23.1 36.4 57.5
Economic Potential 23.6 36.9 89.2 120.1 163.3 187.6
Technical Potential 112.7 122.2 161.6 177.8 213.5 236.5
0
50
100
150
200
250
2015 2018 2023 2028
En
e
r
g
y

S
a
v
i
n
g
s

(
a
M
W
)
Achievable Potential
Economic Potential
Technical Potential
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 665 of 1125
21
Residential achievable savings potential – top
measures
• Lighting – largely CFLs (including specialty
lamps), with LEDs starting to pass the cost-
effectiveness test in 2015
• Space heating savings from conversion to
gas and ductless heat pumps as well as
new programs for duct sealing and
shell/infiltration measures
• Water heating savings from conversion to
gas; also low-flow fixtures, tank/pipe
insulation
• Refrigerator and freezer recycling
• Programmable thermostats
• ENERGY STAR homes and new
construction efficiency

Cumulative Achievable
Potential in 2018
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 666 of 1125
22
Commercial & Industrial potential
• Cumulative potential in
2015 is 5.3 aMW
2014 2015 2018 2023 2028 2033
Cumulative Savings (MWh)
Achievable Potential 22,478 46,155 175,951 400,188 609,043 767,651
Economic Potential 66,170 123,981 346,193 627,462 1,474,041 1,032,097
Technical Potential 185,998 322,041 958,683 1,782,838 2,251,713 2,533,019
Cumulative Savings (aMW)
Achievable Potential 2.6 5.3 20.1 45.7 69.5 87.6
Economic Potential 7.6 14.2 39.5 71.6 168.3 117.8
Technical Potential 21.2 36.8 109.4 203.5 257.0 289.2
0
50
100
150
200
250
300
2015 2018 2023 2028
En
e
r
g
y

S
a
v
i
n
g
s

(
a
M
W
)
Achievable Potential
Economic Potential
Technical Potential
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 667 of 1125
23
C&I Conservation potential – top measures
• Lighting – mix of lamps including
LEDs, various controls
• HVAC – controls, economizers,
variable air volume (VAV)
ventilation
• Machine drive and process – 6%
from various measures for air
compressors, fans, and pumps
• Also low-flow fixtures, tank/pipe
insulation
• Office equipment – efficient
servers, desktop computers, and
printers

Achievable Potential in 2018
Cooling
2%Space Heating
0%
Ventilation
6%Water
Heating
6%
Interior Lighting
47%
Exterior Lighting
8%
Refrigeration
5%
Food Preparation
1%
Office Equipment
19%
Process
2%
Machine Drive
4%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 668 of 1125
24
Conservation potential – sensitivity to avoided costs
-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
1,800,000
Re
s
,

C
&
I

C
u
m
u
l
a
t
i
v
e

A
c
h
i
e
v
a
b
l
e

P
o
t
e
n
t
i
a
l

S
a
v
i
n
g
s

(M
W
h
)
Reference Case Avoided Costs
150% of Reference Case
125% of Reference Case
75% of Reference Case
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 669 of 1125
25
Supply curve for 2015 – cumulative savings
• Nearly 35 GWh of savings are low- or no-cost.
$0.00
$0.05
$0.10
$0.15
$0.20
$0.25
$0.30
$0.35
$0.40
0 10 20 30 40 50 60 70 80
Co
s
t

o
f

C
o
n
s
e
r
v
e
d

En
e
r
g
y
($
/
k
W
h
)
Savings (GWh)
Levelized Cost/kWh for Measures in 2015
Levelized Cost/kWh
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 670 of 1125
26
Supply curves for 2020 – avoided costs scenarios
$-
$0.10
$0.20
$0.30
$0.40
$0.50
$0.60
$0.70
-100 200 300 400 500 600
Co
s
t

p
e
r

k
W
h

s
a
v
e
d

(
2
0
0
9
$
)
Cumulative Savings (GWh)
Reference case 100% avoided costs
75% avoided costs scenario
125% avoided costs scenario
150% avoided costs scenario
∆ Portfolio average cost
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 671 of 1125
27
Annual and cumulative savings
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
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 672 of 1125
28
Consistency with the NWPCC
Methodology
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 673 of 1125
29
Initiative 937 Conservation Provisions
• Washington Initiative 937 approved by voters in 2006
• Requires that utilities estimate 10-year potentials
•Utility Analysis Option must be consistent with the methodology of the Northwest Power
and Conservation Council’s most recent Power Plan
•Used to set a two-year biennium conservation target
•Must be repeated every two years
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 674 of 1125
30
Consistency with Council Methodology
• End-use model — bottom-up
•Building characteristics
•Fuel and equipment saturations
•Stock accounting based on measure life
•Codes and standards
•Existing and new vintage
•Lost- and non-lost opportunities
•Measure saturation and applicability
•Measure savings, including HVAC interactions and contribution to peak
•Ramp rates to model market acceptance and program implementation

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 675 of 1125
31
Consistency with Council Methodology (cont.)
• Measures
•Include nearly all in Sixth Power Plan
•Plus others. e.g., conversion of electric water heaters / furnaces to gas
•Sources for measure characterization
• RTF measure workbooks
• Avista Technical Reference Manual (TRM )
• EnerNOC databases, which draw upon same sources used by RTF
• Economic potential, total resource cost (TRC) test
•Considers non-energy benefits
•Considers HVAC interactions
•Include 10% credit based on Conservation Act
• Achievable potential – ramp rates
•Based on Council Sixth Power Plan ramps rates
•Modified to reflect Avista program history
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 676 of 1125
32
Avista-specific items
• Avista customer characteristics
•Calibrated to Avista 2009 sales by sector
•Average use per customer based on actual billing data
•Equipment saturations and unit energy consumption calibrated to match usage
•Updated with newly available NW Residential Building Stock Assessment data, e.g.,
information on measure saturation
• Building codes and appliance standards updated as of 2012
• Avista-specific customer growth forecasts
• Avista retail rate and avoided cost forecasts
• Ramp rates adjusted to match Avista program history

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 677 of 1125
33
Measure reconciliation
• Develop comprehensive measure list using
•Avista existing programs and business plan
•RTF Unit Energy Savings workbooks
•Sixth Power Plan
•Previous Avista CPA
•Recent EnerNOC studies

Water heating measures
Conventional (EF 0.95)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 678 of 1125
34
Measure reconciliation (cont.)
• Characterization
•Description
•Costs
•Savings
•Applicability
•Lifetime
• Measure data sources
•RTF UES measure databases
•Sixth Power Plan Workbooks
•Avista TRM
•SEEM data
•BEST simulations
•EnerNOC databases

• Convert to LoadMAP format
•Savings as % of baseline use
•Per household, scaled to match Avista
calibration
•Per sq. ft. for C&I
•Remove non-applicable adjustments
such as storage rate
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 679 of 1125
35
Market adoption rates for achievable potential

•Achievable potential requires assumptions about customer acceptance and market
maturity
•Northwest Power & Conservation Council’s Sixth Power Plan Lost Opportunity ramp
rates used to develop market acceptance factors
•It is most important to focus on near-term ramp rates because studies are updated every
two years

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 680 of 1125
36
Market adoption rates for achievable potential (cont.)

•Calibrated ramp rates to actual program achievements for Lighting and HVAC
measures
•Acceptance different from Sixth Power Plan rates

0%
10%
20%
30%
40%
50%
60%
70%
80%
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20
Ma
r
k
e
t

A
c
c
e
p
t
a
n
c
e

R
a
t
e
s

Year
Lighting Acceptance Rates
Lighting CFL and LED
LostOp_5yr
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20
Ma
r
k
e
t

A
c
c
e
p
t
a
n
c
e

R
a
t
e
s
Year
HVAC Equipment Acceptance Rates
Res HVAC mature program
LostOp_20yr
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 681 of 1125
37
Study schedule
•Presented project approach to the TAC on November 7, 2012
•Delivered preliminary results in late-February 2013
•Present final study results to TAC March 20, 2013
•Fine-tune analysis
•Draft report in April, 2013
•Support the filing in August 2013 with a complete CPA report
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 682 of 1125
Ingrid Rohmund
Practice Lead
760.943.1532
[e-mail]
Jan Borstein
Project Manager
303.530.5195
[e-mail]
www.enernoc.com
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 683 of 1125
Demand Response
Technical Advisory Committee #5
March 20th, 2013
Leona Doege
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 684 of 1125
What is Demand Response
Passive:
Pricing programs….
Time-of-Use, Critical Peak Pricing, Peak Time Rebate
Active:
Direct Load Control

Combination programs……
Pricing program with
enabling technology
Purpose: Reduce or shift load at certain times
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 685 of 1125
Passive Demand Response
Supporting Dynamic Pricing:
• Avista’s Billing System doesn’t allow for dynamic rates
• Q3 2014, New Billing System will be capable.
• Metering and its infrastructure would need
to be upgraded in many areas.

• Merit to the inverted tail block rate structure currently used.
“Inclining block rates can reduce energy consumption by 6 percent
in the near term and more over the long haul” (used in contrast to a flat
rate structure, Ahmad Faroqui, “Inclining toward Energy Efficiency,” Public Utilities
Fortnightly, August 2008 (http://www.fortnightly.com/exclusive.cfm?o_id=94 )

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 686 of 1125
Direct Load Control
Mass Market:
Residential loads, electric space heat, central air-conditioning,
electric water heating, pool pumps.

Commercial Programs:
Irrigation, variety of commercial/industrial
processes. Often a 3rd party aggregator is used.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 687 of 1125
Avista’s Direct Load Control Programs
North Idaho Pilot
• 2007-2009:
• 50 DLC Thermostats, 50 DLC
Switches
• 10 Events called ranging from 2 to
4 hours each, in both the summer
and winter seasons.
• Heat Pumps, Water Heaters,
Electric Forced Air Furnaces, Air
Conditioning

Smart Grid Demonstration Project
Smart Thermostat Pilot Program
• June 2012 – Dec 31st, 2014
• 69 Thermostats, capable of 1500
• Events are automatic ranging from
10 minutes to 24 hours, temp off-set
of 2 degrees.
• Currently in testing mode, ready for
real dispatch summer season 2013.
• Heat Pumps, Electric Forced Air
Furnaces, Air Conditioning
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 688 of 1125
Other Avista DR Activities
2001 Western Energy Crisis
Nickel Buy Back Program

Operational issues of July 2006
Public Plea
Bi-Lateral Agreement with Industrial Customers

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 689 of 1125
Knowledge Gained
DR Works as Designed

DR Builds Customer Engagement

DLC Value lies in Capacity

High Penetration of Natural Gas in Avista service area
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 690 of 1125
Demand Response Costs (Regional Estimates from NPCC)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 691 of 1125
What’s Next ?
Discussion of DR Options

Q&A

Thank you for your time!
Leona Doege
DSM Program Manager
[phone]
[e-mail]

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 692 of 1125
Draft 2013 Preferred Resource Strategy
James Gall
Fifth Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
March 20, 2013

1
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 693 of 1125
DRAFT 2013 IRP Modeling Process
Preferred
Resource
Strategy

AURORA
“Wholesale Electric Market” 500 Simulations

PRiSM
“Avista Portfolio” Efficient Frontier
Fuel Prices
Fuel Availability
Resource Availability
Demand
Environmental Considerations
Existing Resources
Resource Options
Transmission
Resource & Portfolio Margins
Conservation
Trends
Existing
Resources
Avista Load
Forecast
Energy, Capacity, & RPS Balances New Resource Options & Costs
Cost Effective T&D Projects/Costs
Cost Effective Conservation Measures/Costs
Mid-Columbia Prices
Stochastic Inputs Deterministic Inputs
Capacity Value
Avoided
Costs
2
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 694 of 1125
DRAFT
2011 Preferred Resource Strategy
Year Ending Resource
2012 Wind (~ 42 aMW REC)
2018 Simple Cycle CT(~ 83 MW)
2020 Simple Cycle CT (~ 83 MW)
2018-2019 Thermal Upgrades (~ 7 MW)
2018-2019 Wind (~ 43 aMW REC)
2023 Combined Cycle CT (~ 270 MW)
2026/27 Combined Cycle CT (~ 270 MW)
2029 Simple Cycle CT (~ 46 MW)
2012+ Distribution Feeder Upgrades (13 aMW by 2031)
2012+ Conservation (310 aMW by 2031)
Palouse Wind
8.9 aMW in 2012*
Smart Grid/Feeder
Rebuilds
* Early estimate to be verified by third party and does not include regional savings from NEEA 3
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 695 of 1125
DRAFT
Annual Energy Position
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
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
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
Hydro Resources Base/Intermediate Resources Net Firm Contracts
Peaking Resources Wind Resources Load
Load + Contingency Planning
4
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 696 of 1125
DRAFT
Winter Single Hour Peak Position
0
500
1,000
1,500
2,000
2,500
3,000
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
me
g
a
w
a
t
t
s
Hydro Resources Base/Intermediate Resources Net Firm Contracts
Peaking Resources Load Load + Contingency Planning
5
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 697 of 1125
DRAFT
Summer Single Hour Peak Position
0
500
1,000
1,500
2,000
2,500
3,000
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
me
g
a
w
a
t
t
s
Hydro Resources Base/Intermediate Resources Net Firm Contracts
Peaking Resources Load Load + Contingency Planning
6
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 698 of 1125
DRAFT
Washington Energy Independence Act Compliance
0
20
40
60
80
100
120
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
Av
e
r
a
g
e

M
W
Purchases Prior Year RECs
New Resources Palouse Wind
Kettle Falls Hydro Upgrades
Requirement
Assumes conservative estimate of Kettle Falls with 75 percent capacity factor
7
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 699 of 1125
DRAFT
Load Forecast Scenarios
-
200
400
600
800
1,000
1,200
1,400
1,600
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
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
Expected Case
Low Growth Case
High Growth Case
Low-Medium Case
8
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 700 of 1125
DRAFT
PRiSM Objective Function
Linear program solving for the optimal resource strategy to meet
resource deficits over the planning horizon.
Model selects its resources to reduce cost, risk, or both.

Minimize: Total Power Supply Cost on NPV basis (2014-2054 with
emphasis on the first 14 years of the plan)

Subject to:
Risk Level
Capacity Need +/- deviation
Energy Need +/- deviation
Renewable Portfolio Standards
Resource Limitations and Timing
9
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 701 of 1125
DRAFT
Efficient Frontier
 Demonstrates the trade off between cost and risk
 Avoided Cost Calculation
Ri
s
k

Least Cost Portfolio
Least Risk Portfolio
Find least cost portfolio
at a given level of risk
Short-Term
Market
Market + Capacity + RPS = Avoided Cost
Capacity
Need
+ Risk
Cost
10
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 702 of 1125
DRAFT
Natural Gas Turbines Cost/Risk Tradeoffs
Frame
CT
Recip.
Engines
CCCT Ri
s
k

Cost
Aero CT
Ignoring size constraints
Hybrid
CT
All gas peaking turbines are
“nearly” the same cost/risk
and will have to be
compared in an RFP
process near acquisition
11
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 703 of 1125
DRAFT
Natural Gas Turbines Cost/Risk Tradeoffs
Frame
CT
Recip.
Engines
CCCT
Ri
s
k

Cost
Aero CT
Includes size constraints
Hybrid
CT
12
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 704 of 1125
DRAFT
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
$400 $420 $440 $460 $480 $500 $520 $540 $560 $580
20
2
8

S
t
d
e
v
Expected Levelized Cost (2014-2033) (2013$)
Efficient Frontier ($millions)
Least Cost
Market Only
Preferred Resource Strategy
Least Risk
13
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 705 of 1125
DRAFT
Efficient Frontier- Percent Change
-70.0%
-60.0%
-50.0%
-40.0%
-30.0%
-20.0%
-10.0%
0.0%
0.0%5.0%10.0%15.0%20.0%25.0%30.0%
De
c
r
e
m
e
n
t
a
l

R
i
s
k
Incremental Cost
14
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 706 of 1125
DRAFT
Draft 2013 Preferred Resource Strategy
0
100
200
300
400
500
600
700
800
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
Na
m
e
p
l
a
t
e

M
e
g
a
w
a
t
t
s
Demand Response Plant Upgrade
Market Other
Coal Other Renewables
Solar Wind
SCCT CCCT
Conservation
15
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 707 of 1125
DRAFT
Draft 2013 Preferred Resource Strategy
Resource By the
End of
Year
Winter Peak
(MW)
Energy
Capability
(aMW)
SCCT 2019 88 69
Rathdrum CT Upgrade 2021 2 6
SCCT 2023 46 40
SCCT 2026 78 62
CCCT 2026 281 245
SCCT 2029-32 79 69
Generation Total 574 491
Conservation 2014-33 199 147
Demand Response 2022-30 20 0
Distribution Efficiencies 2014-16 <1 <1
16
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 708 of 1125
DRAFT
Conservation Forecast
0
40
80
120
160
200
0
3
6
9
12
15
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
Cu
m
u
l
a
t
i
v
e

(
a
M
W
)
an
n
u
a
l

(
a
M
W
)
Energy (annual)
Energy (cumulative)
17
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 709 of 1125
DRAFT
Cost of Conservation
$0
$20
$40
$60
$80
$100
$120
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
Cost (Millions)
Levelized $/MWh
18
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 710 of 1125
DRAFT
Avista Greenhouse Gas Emissions
19
-
0.05
0.10
0.15
0.20
0.25
0.30
0.35
0.40
0.45
0.50
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
5.0
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
Sh
o
r
t

T
o
n
s

p
e
r

M
W
h
Sh
o
r
t

T
o
n
s

(
M
i
l
l
i
o
n
s
)
Short Tons (Avg)
Short Tons per MWh
Includes generating resources under Avista control
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 711 of 1125
DRAFT
Draft 2013 PRS Capital Requirements (and Conservation
Expense)
$0
$200
$400
$600
$800
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
Mi
l
l
i
o
n
s

(
A
n
n
u
a
l
)
Capital (Millions)
Conservation (annual)
Cumulative (Millions)
Conservation (Cumulative)
20
Blue bars and Red line is generation capital investment White bars and Red line is cost effective conservation Chart illustrates comparison of generation to conservation investment
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 712 of 1125
DRAFT
Power Supply Cost Forecast (Range)
0
200
400
600
800
1,000
1,200
1,400
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
Mi
l
l
i
o
n
s

(
N
o
m
i
n
a
l
)
Expected Cost
2 Sigma Low
2 Sigma High
Max
21
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 713 of 1125
DRAFT
Power Supply Cost Forecast Index ($/MWh)
0
20
40
60
80
100
120
140
160
180
200
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
po
w
e
r

s
u
p
p
l
y

c
o
s
t

i
n
d
e
x

(
2
0
1
2

=

1
0
0
)
DRAFT
22
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 714 of 1125
Resource Strategy Scenarios
James Gall
Fifth Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
March 20, 2013

1
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 715 of 1125
DRAFT
Scenario Modeling Status Update
Scenarios still in progress
Conservation
Stochastic carbon pricing (and other CO2 related scenarios)
Colstrip scenarios
These will be presented at the Sixth TAC meeting on June 19,
2013

2
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 716 of 1125
DRAFT
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
$400 $420 $440 $460 $480 $500 $520 $540 $560 $580
20
2
8

S
t
d
e
v
Expected Levelized Cost (2014-2033) (2013$)
Efficient Frontier ($millions)
Least Cost
Market Only
Preferred Resource Strategy
Least Risk
3
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 717 of 1125
DRAFT
Portfolios Along the Efficient Frontier
Risk Level
Nameplate (MW) PRS High
Medium
High Medium
Medium
Low Low
CCCT 270 - 270 540 270 270
SCCT 278 549 251 190 149 51
Wind - - - 165 99 350
Solar - - - - - -
Other Renewables - - - - - 50
Coal (sequestered) - - - - 250 295
Other - - - - - -
Market - - - - - -
Plant Upgrade 6 6 85 - 80 80
Demand Response 20 20 20 - 10 15
Total 574 575 626 895 857 1,110
Change in Cost (2028) -1.0% 1.4% 21.3% 75.8% 109.6%
Change in Risk (2028) 11.0% -3.5% -19.4% -35.9% -53.1%
4
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 718 of 1125
DRAFT
2011 PRS Scenario
Year Ending Resource
2012 Wind (~ 42 aMW REC)
2018 Simple Cycle CT(~ 83 MW)
2020 Simple Cycle CT (~ 83 MW)
2018-2019 Thermal Upgrades (~ 7 MW)
2018-2019 Wind (~ 43 aMW REC)
2023 Combined Cycle CT (~ 270 MW)
2026/27 Combined Cycle CT (~ 270 MW)
2029 Simple Cycle CT (~ 46 MW)
2012+ Distribution Feeder Upgrades (13 aMW by 2031)
2012+ Conservation (310 aMW by 2031)
5
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 719 of 1125
DRAFT
2011 IRP PRS
With a lower load forecast and the passage of the biomass bill in
Washington, the 2011 PRS overbuilds the needs for the 2013 IRP
timeframe
The adjusted 2011 PRS portfolio is 5.7% higher NPV and lowers
power supply risk by 14%- the higher cost is due to overbuilding
the expected demand requirements
6
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 720 of 1125
DRAFT
25% Washington RPS by 2025 Scenario
The Washington Energy Independence Act (I-937) requires
15% of Washington retail sales to be from renewables by 2020
This scenario evaluates the costs and benefits if the goal is
changed to 25% by 2025

0
20
40
60
80
100
120
140
160
180
200
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
Av
e
r
a
g
e

M
W
Palouse Wind Kettle Falls
Hydro Upgrades Requirement 77 aMW
Need
7
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 721 of 1125
DRAFT
0
20
40
60
80
100
120
140
160
180
200
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
Av
e
r
a
g
e

M
W
Purchases Prior Year RECs
New Resources Palouse Wind
Kettle Falls Hydro Upgrades
Requirement
25% Washington RPS in 2025 – Scenario Results
Hydro upgrades to Long Lake and Monroe Street (148 MW)
could meet most of the incremental RPS requirement
Assuming these resources provide winter capability and
summer needs are met by market, this strategy would lower
SCCT needs need by 93 MW
The 2028 cost is 3.7% higher than PRS and risk is 1.8% lower
Hydro upgrades
8
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 722 of 1125
DRAFT
National Renewable Portfolio Standard Scenario
If the federal government passed legislation requiring renewable
generation (i.e. National RPS), this scenario addresses the
change in resource strategy and potential costs
This scenario assumes 10% of load is met by renewables by
2020, then 15% by 2025, and 20% by 2030
All Avista owned hydro generation would be netted from load to
reduce the required quantity of “RECs” – any hydro upgrades
would be netted against load rather than receive a REC credit
For modeling purposes, no banking is assumed and average
hydro is used for “hydro netting”

9
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 723 of 1125
DRAFT
National RPS Scenario Renewable Requirements (aMW)
2015 2020 2025 2030 2033
Average Load 1,067 1,125 1,180 1,239 1,285
Average Hydro 495 481 481 481 481
Net Load 572 644 699 759 805
RPS % 0% 10% 15% 20% 20%
RPS Required 0 64 105 152 161
Palouse Wind 40 40 40 40 40
Kettle Falls 42 43 43 42 43
Total Existing RECs 82 83 83 82 83
RECs Required 0 0 22 69 78
10
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 724 of 1125
DRAFT
National RPS Scenario Portfolio Results
Will require 230 MW of new wind capacity
Hydro upgrades are not economic without a REC credit
No other resources change within the Expected Case
20 year NPV increases 3.4% over the Expected Case
2028 Power Supply Costs are 4% higher and risk is 2.8% lower
11
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 725 of 1125
DRAFT
Load Forecast Scenarios Impact to Net Position
(800)
(700)
(600)
(500)
(400)
(300)
(200)
(100)
-
100
200
300
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
me
g
a
w
a
t
t
s
Winter Single Hour Peak
Low
Medium Low
Expected Case
High
12
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 726 of 1125
DRAFT
Load Scenario Results
Load Forecast
Nameplate (MW) PRS Low
Medium
Low High
CCCT 270 270 270 270
SCCT 278 32 91 408
Wind - 0 0 0
Solar - 0 0 0
Other Renewables - 0 0 0
Coal (seq) - 0 0 0
Other - 0 0 0
Market - 0 0 0
Plant Upgrade 6 6 6 6
Demand Response 20 15 20 20
Total 574 323 387 704
Change in Cost (2028) -5.3% -3.7% 3.4%
Change in Risk (2028) -0.1% -0.5% -0.4%
13
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 727 of 1125
DRAFT
High Planning Margin Study (Less Market Dependence)
This scenario adds more capacity resource need earlier in the
study horizon and at a higher quantity, similar to a high load
growth scenario
New resources would be required by the end of 2016 rather
then the end of 2019
Requires 117 MW of additional capacity to be built (assumes
met with peaking natural gas resource)
Result 2.9% higher NPV, 2028 cost is 3.5% higher, risk level is
similar to the PRS
14
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 728 of 1125
DRAFT
Tipping Point Analyses
Assumes no government incentives
Find capital cost where resource would join a similar risk
portfolio structure as the PRS
Solar: $430 per kW ($3,500 per kW modeled)
Solar suffers from providing no winter peak capacity, thus
competes on an energy basis only (with little energy)
IGCC Coal w/ sequestration: $750 per kW ($6,000 per kW
modeled)
Nuclear: $2,150 per kW ($7,000 per kW modeled)
Nuclear and Coal has high O&M cost, if those costs were
lowered a higher capital cost could be afforded

15
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 729 of 1125
Avista’s 2013 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 6 Agenda
Wednesday, June 19, 2013
Conference Room 428

Topic Time Staff
1. Introduction 9:30

2. 2013 Final Preferred Resource Strategy 9:35 Gall

3. Break 10:15

4. Portfolio Scenario Analysis 10:30 Gall

5. Lunch 12:00

6. Net Metering and Buck-a-Block 1:00 Kalich

7. Break 1:30

8. Action Plan 1:45 Lyons

9. 2013 IRP Document Introduction 2:15 Kalich

10. Adjourn 3:00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 730 of 1125
2013 Preferred Resource Strategy
James Gall, Senior Power Supply Analyst
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 731 of 1125
Reliability Needs
-600
-500
-400
-300
-200
-100
0
100
200
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
me
g
a
w
a
t
t
s
/

a
v
e
r
a
g
e

m
e
g
a
w
a
t
t
s
January 1 Hour Peak
August 18 Hour Peak
Energy
2
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 732 of 1125
Renewable Requirements Met
0
20
40
60
80
100
120
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
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
Qualifying Hydro Upgrades Qualifying Resources
Purchased RECs Available Bank3
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 733 of 1125
Efficient Frontier Analysis
$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
20
2
8

p
o
w
e
r

s
u
p
p
l
y

c
o
s
t

s
t
d
e
v
20 yr levelized annual power supply rev. req.
Market Only
Least Cost
Least Risk
Preferred Resource Strategy
4
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 734 of 1125
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
Peak Reduction
(MW)
Energy Efficiency 2014-2033 221 164
Demand Response 2022-2027 19 0
Distribution Efficiencies 2014-2017 <1 <1
Total 240 164
Efficiency Improvements By the End of
Year
Energy (aMW)
5
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 735 of 1125
Resource Capital Requirements
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
6
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 736 of 1125
Conservation Meets 42% of Load Growth
0
200
400
600
800
1,000
1,200
1,400
1,600
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
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
Expected Case
Without Conservation 1.71%
1.07%
7
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 737 of 1125
Past and Future Conservation

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
8
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 738 of 1125
Conservation Supply Curve

$0
$100
$200
$300
$400
$500
0 50 100 150 200
$
p
e
r

M
W
h
average megawatts
Conservation Supply Curve
Expected Case Conservation
Note: excludes fuel switching and pumping programs; not grossed up for line-losses.
9
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 739 of 1125
Cost of Conservation

0
10
20
30
40
50
60
70
80
90
19
9
9
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
Energy Savings (aMW)
Spending (millions $)
Levelized Cost ($/MWh)
Years
Energy
Savings
(aMW)
Avg
Spending
(millions $)
Levelized
Cost
($/MWh)
1997-2007 6.12 $7.58 $14.32
2008-2012 10.22 $19.89 $21.92
2014-2023 7.41 $21.58 $32.18
2024-2033 8.20 $49.51 $66.93
10
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 740 of 1125
Greenhouse Gas Emission Forecast
0.00
0.10
0.20
0.30
0.40
0.50
Mil
1 Mil
2 Mil
3 Mil
4 Mil
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
me
t
r
i
c

t
o
n
s

p
e
r

M
W
h
me
t
r
i
c

t
o
n
s
Total
Tons per MWh of Load
11
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 741 of 1125
Power Supply Cost Index Forecast (2012$)

0
20
40
60
80
100
120
140
160
180
200
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
po
w
e
r

s
u
p
p
l
y

c
o
s
t

i
n
d
e
x

Historical
Forecast
Includes: conservation spending, power/REC market transactions, fuel
expense, power plant operations and maintenance costs, plant depreciation,
cost of money, taxes, and other miscellaneous expenses.
12
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 742 of 1125
Portfolio Scenario Analysis
James Gall, Senior Power Supply Analyst
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 743 of 1125
Scenarios
• Efficient Frontier Analysis
• Carbon Pricing
• Conservation
• Load Growth
• Resource & Policy Specific Portfolios
• Colstrip

2
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 744 of 1125
Efficient Frontier
$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
20
2
8

p
o
w
e
r

s
u
p
p
l
y

c
o
s
t

s
t
d
e
v
20 yr levelized annual power supply rev. req.
Market Only
Least Cost
Least Risk
Preferred Resource Strategy
What are
these
portfolios?
3
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 745 of 1125
Portfolio Mix at Alternative Risk Levels
Nameplate (MW) PRS High Risk Medium
High Risk
Medium
Risk
Medium
Low Risk
Low Risk
CCCT 270 - 270 270 540 540
SCCT 299 566 296 216 100 68
Wind - - - 30 50 350
Solar - - - - - -
Biomass - - - - - 50
Coal (seq) - - - - - -
Hydro Upgrade - - - - - -
Thermal Upgrade 6 6 6 85 85 80
Demand Response 19 20 20 8 12 17
Total (excluded DSM) 594 592 592 609 788 1,104

20-yr Levelized Cost (mill) $358.4 $357.9 $357.9 $362.3 $367.0 $396.0
2028 Power Supply Stdev (mill) $65.7 $74.0 $64.4 $60.5 $54.1 $40.2
2033 Greenhouse Gas Emissions
(millions of metric tons) 3.2 2.9 3.4 3.4 3.9 3.8
4
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 746 of 1125
Carbon Pricing Effect to Efficient Frontier
$25 Mil
$50 Mil
$75 Mil
$100 Mil
$300 Mil $350 Mil $400 Mil $450 Mil $500 Mil
20
2
8

p
o
w
e
r

s
u
p
p
l
y

s
t
d
e
v
20 yr levelized annual power supply rev. req.
Expected Case
Carbon Pricing Scenario
Carbon Pricing Scenario (Inc Conservation)
PRS (Expected Case)
PRS-(Carbon Pricing)
PRS-Higher Conservation
(Carbon Pricing)
5
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 747 of 1125
Carbon Pricing Scenario- Least Cost
Strategy
Peaking Technology Switches to Higher Efficient Turbines
Portfolio 20-Yr Power Supply Levelized Cost
Expected Case Carbon Pricing
Scenario
PRS $358.4 $367.3
PRS w/ Higher Conservation $365.0 $377.8
Carbon Pricing Scenario- LC RS $364.7 $374.5
Portfolio 2028 Power Supply Cost Standard
Deviation
Expected Case Carbon Pricing
Scenario
PRS $65.7 $72.6
PRS w/ Higher Conservation $63.9 $70.3
Carbon Pricing Scenario- LC RS $61.0 $63.6
6
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 748 of 1125
Conservation Avoided Cost Scenarios
• Change cost effective point of conservation
• 20 Year Avoided Cost for Conservation is
$67.91/MWh

Avoided Cost
Percentage
20 Year
aMW
Delta
aMW
75% 139 -25
100% 154 -10
Expected Case (110%) 164 0
125% 184 +20
150% 201 +37
7
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 749 of 1125
Conservation Avoided Cost Scenarios
-70%
-60%
-50%
-40%
-30%
-20%
-10%
0%
10%
20%
30%
-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 FrontierPRS
75% AC
100% AC
125% AC
150% AC
No Conservation
8
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 750 of 1125
Load Growth Sensitivities
Winter Peak Position

(900)
(600)
(300)
-
300
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
me
g
a
w
a
t
t
s
Low Growth
Medium Low Growth
Expected Case
High Growth
9
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 751 of 1125
Load Growth Scenarios: Resource Selection
Year PRS Low Growth Medium Low
Growth
High Growth
2014
2015
2016
2017
2018
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 Response (MW) 19 1 20 20
Conservation (aMW) 164 142 147 175 10
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 752 of 1125
Resource Strategies from Policy Changes
Nameplate (MW) PRS Higher WA St.
RPS
National RPS Higher
Capacity
Margins
2011 PRS
CCCT 270 270 270 270 540
NG Peaker 299 249 296 435 187
Wind - - 203 - 120
Solar - - - - -
Biomass - - - - -
Coal (seq) - - - - -
Hydro Upgrade - 148 - - -
Thermal Upgrade 6 6 6 6 -
Demand Response 19 10 20 8 -
Total (Excluding Conservation) 594 683 795 718 847

20-yr 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
11
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 753 of 1125
Resource Specific Portfolios
-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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 754 of 1125
Colstrip Scenarios
• No Colstrip Resource Strategy Scenario
– Colstrip is removed from portfolio beginning in 2018
– No costs/benefits included due to its removal
• Regional Haze Program Scenario
– Assumes Colstrip #3 & #4 must install SCR or shut
down in 2027
– SCR costs are expected to be $105 million (Avista
share) plus $560k each year in O&M or $8.39/MWh
total cost levelized
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 755 of 1125
Resource Strategy Without Colstrip
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
Peak Reduction
(MW)
Energy Efficiency 2014-2033 221 164
Demand Response 2022-2027 20 0
Distribution Efficiencies 2014-2017 <1 <1
Total 241 164
Efficiency Improvements By the End
of Year
Energy (aMW)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 756 of 1125
Colstrip Scenarios: Levelized Cost
Comparison
$482
$435 $460
$408
$0 Mil
$100 Mil
$200 Mil
$300 Mil
$400 Mil
$500 Mil
$600 Mil
Carbon Pricing
Scenario-RS w/o
Colstrip
Carbon Pricing
Scenario-LC RS
w/ Colstrip
Expected Case-
No Colstrip RS
Expected Case-
PRS
le
v
e
l
i
z
e
d

p
o
w
e
r

s
u
p
p
l
y

c
o
s
t

15
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 757 of 1125
Greenhouse Gas Emissions without Colstrip
-
0.10
0.20
0.30
0.40
0.50
Mil
1 Mil
2 Mil
3 Mil
4 Mil
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
me
t
r
i
c

t
o
n
s

p
e
r

M
W
h
me
t
r
i
c

t
o
n
s
Colstrip Reduction
Other Resources
Tons per MWh (Without Colstrip)
Tons per MWh with Colstrip
16
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 758 of 1125
Power Supply Cost Index Comparison
0
20
40
60
80
100
120
140
160
180
200
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
po
w
e
r

s
u
p
p
l
y

c
o
s
t

i
n
d
e
x

Historical
Forecast
Forecast without Colstrip
17
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 759 of 1125
2027-33 Colstrip SCR Analysis
$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
le
v
e
l
i
z
e
d

c
o
s
t

18
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 760 of 1125
Net Metering and Buck-A-Block
Clint Kalich
Sixth Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
June 19, 2013

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 761 of 1125
Avista’s Net Metering Customers
0.0
0.3
0.6
0.9
1.2
1.5
0
10
20
30
40
50
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
cu
m
u
l
a
t
i
v
e

c
a
p
a
c
i
t
y

(
M
W
)
an
n
u
a
l

n
e
w

c
u
s
t
o
m
e
r
s
ID
WA
Cumulative Capacity (MW)
2
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 762 of 1125
Avista Buck-A-Block Program
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
3,000
4,000
5,000
0.0
2.0
4.0
6.0
8.0
10.0
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
cu
s
t
o
m
e
r
s
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
aMW
Customers
3
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 763 of 1125
Solar Energy Subsidies
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
4
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 764 of 1125
13
16
44
95
198
0 50 100 150 200
Low Carbon Price
Medium Carbon Price
High Carbon Price
Mandatory Coal Retirements
Increased RPS *
$/metric ton
GHG Reduction Option Costs ($/Ton)
Renewable Portfolio Standards are Least Efficient, by Far
5
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 765 of 1125
2013 IRP Action Plan
John Lyons
Sixth Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
June 19, 2013

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 766 of 1125
Generation Resource Related Analysis
• Spokane and Clark Fork River hydro upgrade options in
the 2015 IRP.
• Evaluate potential locations for the natural gas-fired
resource for 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.
• Provide status update on the Little Falls and Nine Mile
hydroelectric project upgrade progress.
2
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 767 of 1125
Generation Resource Related Analysis
• Commission a demand response potential and cost
assessment of commercial and industrial customers.
• 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.
• Develop short-term (up to 24-months) capacity position
report.

3
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 768 of 1125
Energy Efficiency
• Work with NPCC, the Washington Utilities and
Transportation Commission, 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 I-937 goals.
• Update processes and protocols for conservation
measurement, evaluation and verification.

4
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 769 of 1125
Transmission and Distribution Planning
• Work to maintain the Company’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.

5
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 770 of 1125
2013 IRP Overview
Clint Kalich
Sixth Technical Advisory Committee Meeting
2013 Electric Integrated Resource Plan
June 19, 2013

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 771 of 1125
Executive Summary
2
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 772 of 1125
2013 IRP Chapters
• Executive Summary
• Introduction and Stakeholder Involvement
• Loads & Resources
• Energy Efficiency
• Policy Considerations
• Transmission & Distribution
• Generation Resource Options
• Market Analysis
• Preferred Resource Strategy
• Action Items

3
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 773 of 1125
Loads & Resources
•The 2013 IRP energy forecast grows 1.0 percent per year,
replacing the 1.4 percent annual growth rate from the last IRP.
• Peak load growth is slower than energy growth at, 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 beginning in 2016.
• This IRP meets all I-937 mandates over the next 20 years with
a combination of qualifying hydro upgrades, Palouse Wind and
Kettle Falls.
4
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 774 of 1125
Energy Efficiency
• This IRP includes a Conservation Potential Assessment
of the Company’s Idaho and Washington service
territories.
• Current Company-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.
5
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 775 of 1125
Policy Considerations
• The 2013 IRP does not include a federal cap and trade
or greenhouse gas emissions tax in its Expected Case
because there is no policy development underway in a
regulatory context.
• The impact of potential greenhouse gas policies are
addressed through scenario analyses.
• The plan anticipates specific regulatory policies to
reduce greenhouse gas emissions.
6
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 776 of 1125
Transmission & Distribution
• Avista continues to participate in regional 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 rebuilds are planned for 2014.
• Significant generation interconnection study work at Thornton
and Lind stations continues.
7
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 777 of 1125
Generation Resource Options
• Only resources with well-defined costs and operating
histories are in the PRS analysis.
• Wind, solar, and hydro upgrades represent renewable
options available to the Company; future RFPs might
identify competing renewable technologies.
• Renewable resource costs assume no extensions of
state and federal incentives.
• This IRP models battery storage technology as a
resource option for the first time in an Avista IRP.
• Upgrades to Avista’s Spokane and Clark Fork River
facilities are included as resource options.
8
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 778 of 1125
Market Analysis
• Gas and wind resources dominate new generation
additions in the West.
• Shale gas continues to lower 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 towards a regulatory model
rather than a cap-and-trade system.
• Lower natural gas prices and lower loads have reduced
greenhouse gas emissions from the US power industry
by 11 percent since 2007.
9
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 779 of 1125
Market Analysis continued
• 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.
10
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 780 of 1125
Preferred Resource Strategy
• Avista’s first anticipated resource acquisition is a natural
gas fired peaker by the end of 2019 to replace expiring
contracts and growing loads.
• A combined cycle combustion turbine replaces the
Lancaster Facility when its contract ends in 2026.
• The selection of natural gas-fired peaking units is due
primarily to their smaller size better fitting Avista’s
modest resource deficits.
• The Preferred Resource Strategy includes demand
response programs for the first time.
• Conservation offsets projected load growth by 42
percent through the 20-year IRP timeframe.
11
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 781 of 1125
Preferred Resource Strategy continued
• Conservation spending ($711 million) exceeds new
generation resource capital spending ($696 million) over
the 20-year plan.
• The Colstrip coal plant remains a viable and cost-
effective resource throughout the planning horizon, even
under scenarios most adverse to the plant.
12
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 782 of 1125
Remaining 2013 IRP Schedule
• June 23 TAC
• May 2013 – internal draft released at
Avista
• June 2013 – external draft released to
the TAC
• August 2013 – final editing and printing
• August 31, 2013 – final IRP
submission to Commissions and
distribution to TAC
• June 19, 2013 TAC meeting
• June 21, 2013 Management review of
Internal Draft 2013 IRP complete
• June 26, 2013 distribution of Draft
2013 IRP to TAC participants
• July 24, 2013: External review by TAC
complete
• August 30, 2013: 2013 IRP
documents sent to the Idaho and
Washington Commissions
• August 31, 2013: 2013 IRP available
to public, including publication on the
Company’s web site

13
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 783 of 1125

2013 Electric Integrated
Resource Plan

Appendix B – 2013 Electric IRP
Work Plan

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 784 of 1125

Work Plan for Avista’s
2013 Electric Integrated Resource
Plan

For the
Washington Utilities and Transportation Commission

August 30, 2012

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 785 of 1125

2 | P a g e
2013 Integrated Resource Planning Work Plan
This Work Plan is submitted in compliance with the Washington Utilities and Transportation Commission’s (UTC) Integrated Resource Planning (IRP) rules (WAC 480-100-238). It
outlines the process Avista will follow to develop its 2013 Electric IRP. The Company’s 2013 Electric IRP will be filed with Washington and Idaho Commissions by August 31, 2013. Avista uses a public process to solicit technical expertise and feedback throughout the
development of the IRP through a series of public Technical Advisory Committee (TAC) meetings. Avista held the first TAC meeting for the 2013 IRP on May 23, 2012.
The 2013 IRP process will be similar to those used to produce the previous four published plans. AURORAxmp will be used for electric market price forecasting, resource valuation, and for conducting Monte-Carlo style risk analyses. AURORAxmp

modeling results will be used to
select the Preferred Resource Strategy (PRS) using Avista’s proprietary PRiSM model. This tool is used to determine how to fill future capacity and energy (physical/renewable) deficits with new resources using an efficient frontier approach to evaluate quantitative portfolio risk
versus portfolio cost while accounting for environmental laws and regulations. Qualitative risks will be evaluated in separate analyses. The process timeline is shown in Exhibit 1 and the process to identify the PRS is shown in Exhibit 2.
Avista intends to use both detailed site-specific and generic resource assumptions in its development of the 2013 IRP. The assumptions are based on a combination of Avista’s
research of similar technologies, engineering studies, and the Northwest Power and Conservation Council’s Sixth Power Plan. This plan will study renewable portfolio standards, energy storage, environmental costs, sustained peaking requirements and resource
adequacy, energy efficiency programs, and demand response. The IRP will develop a strategy that meets or exceeds both the renewable portfolio standards and greenhouse gas emissions regulations.
Avista intends to test the PRS against several scenarios and potential futures. The TAC meetings will be an important factor to determine the underlying assumptions used in the
scenarios and futures. The IRP process is very technical and data intensive; public comments are welcome, however input and participation will be needed in a timely manner for appropriate inclusion into the process so the plan can be submitted according to the
tentative schedule outlined in this Work Plan. Topics and meeting times may change depending on the availability of Company staff and
requests for additional topics from the TAC members. The tentative timeline and agenda items for Technical Advisory Committee meetings follows:
• 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, and 2013 IRP Work Plan discussion.
• TAC 2 (Day 1) – September 4, 2012: Palouse Wind Project tour.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 786 of 1125

3 | P a g e
• TAC 2 (Day 2) – September 5, 2012: Avista renewable energy credit planning methods, energy and economic forecasts, 2012 Shared Value Report, generation options, and Spokane River Assessment.

• TAC 3 – November 7, 2012: Peak load forecast, reliability planning, Colstrip discussion, energy storage technologies, modeling, and energy efficiency.
• TAC 4 – February 6, 2013: Electric and natural gas price forecasts, transmission
planning, resource needs assessment, and market and portfolio scenario development.
• TAC 5 – March 20, 2013: Draft PRS, review of scenarios and futures, and portfolio analysis

• TAC 6 – June 19, 2013: Review of final PRS and action items.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 787 of 1125

4 | P a g e
2013 Electric IRP Draft Outline

This section provides a draft outline of the major sections in the 2013 Electric IRP. This outline will be updated as IRP studies are completed and input from the Technical Advisory Committee has been received.

1. Executive Summary
2. Introduction and Stakeholder Involvement
3. Loads and Resources a. Economic Conditions b. Avista Energy & Peak Load Forecast
c. Load Forecast Scenarios d. Avista’s Resources and Contracts e. Reliability Planning and Reserve Margins
f. Resource Requirements
4. Energy Efficiency and Demand Response a. Conservation Potential Assessment
b. Demand Response Opportunities c. Washington State Energy Independence Act
5. Policy Considerations
a. Environmental Concerns b. State and Federal Policies
6. Transmission Planning
a. Avista’s Transmission System b. Future Upgrades and Interconnections c. Transmission Construction Costs and Integration
d. Efficiencies
7. Generation Resource Options a. New Resource Options
b. Avista Plant Upgrades
8. Market Analysis a. Marketplace
b. Fuel Price Forecasts
c. Market Price Forecast d. Scenario Analysis
9. Preferred Resource Strategy
a. Resource Selection Process b. Preferred Resource Strategy
c. Efficient Frontier Analysis
d. Avoided Costs e. Portfolio Scenarios
f. Tipping Point Analysis
10. Action Plan a. 2011 Action Plan Summary
b. 2013 Action Plan
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 788 of 1125

5 | P a g e

Exhibit 1: 2013 Electric IRP Timeline
Task Target Date
Preferred Resource Strategy (PRS)
xmp
xmp
xmp
Writing Tasks

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 789 of 1125

Exhibit 2: 2013 Electric IRP Modeling Process
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 790 of 1125

2013 Electric Integrated
Resource Plan

Appendix C – 2013 Electric IRP
Avista Electric Conservation
Potential Assessment Study

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 791 of 1125

Avista Electric Conservation Potential
Assessment Study

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 792 of 1125

This report was prepared by
EnerNOC Utility Solutions
500 Ygnacio Valley Blvd., Suite 450
Walnut Creek, CA 94596
Project Director: I. Rohmund
Project Manager: J. Borstein
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 793 of 1125

EnerNOC Utility Solutions Consulting iii
EXECUTIVE SUMMARY
Avista Corporation (Avista) engaged EnerNOC Utility Solutions (EnerNOC) to conduct a
Conservation Potential Assessment (CPA). The CPA is a 20-year conservation potential study to
provide data on conservation resources for developing Avista’s 2013 Integrated Resource Plan
(IRP), and in accordance with Washington Initiative 937 (I-937). The study updates Avista’s last
CPA, which EnerNOC performed in 2011. The 2011 CPA used 2009, the first year for which
complete billing data was available at the time, as the base year. This update kept 2009 as the
base year for the analysis, and calibrated the model used for the assessment to align with actual
sales and conservation program achievements for the years 2010–2012.
Study Objectives
The study objectives included:
Conduct a conservation potential study for electricity for Washington and Idaho. The study
accounted for:
o Impacts of existing Avista conservation programs
o Impacts of codes and standards
o Technology developments and innovation
o The economy and energy prices
Assess and analyze cost-effective conservation potentials in accordance with the Northwest
Power and Conservation Council's (NPPC) Sixth Power Plan methodology and Washington I-
937 requirements.
Obtain supply curves showing the incremental costs associated with achieving higher levels
of conservation and stacking efficiency resources by cost of conserved energy.
Analyze various market penetration rates associated with technical, economic, and achievable
potential estimates.
Definitions of Potential
Technical potential is defined as the theoretical upper limit of conservation potential. It
assumes that customers adopt all feasible measures regardless of their cost. At the time of
existing equipment failure, customers replace their equipment with the most efficient optio n
available. In new construction, customers and developers also choose the most efficient
equipment option. Examples of measures that make up technical potential for electricity in
the residential sector include:
o High-efficiency heat pumps for homes with ducts
o Ductless mini-split heat pumps for homes without ducts
o Heat pump water heaters
o LED lighting
Technical potential also assumes the adoption of every other available measure, where
applicable. For example, it includes installation of high-efficiency windows in all new construction
opportunities and furnace maintenance in all existing buildings with furnace systems. These
retrofit measures are phased in over a number of years, which is longer for higher-cost and
complex measures.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 794 of 1125
Executive Summary
iv enernoc.com
Economic potential represents the adoption of all cost-effective conservation measures.
In this analysis, cost-effectiveness is measured by the total resource cost (TRC) test, which
compares lifetime energy and capacity benefits to the incremental cost of the measure. If the
benefits outweigh the costs (that is, if the TRC ratio is greater than 1.0), a given measure is
considered in the economic potential. Customers are then assumed to purchase the most
cost-effective option applicable to them at any decision juncture.
Achievable potential takes into account market maturity, customer preferences for
energy-efficient technologies, and expected program participation. Achievable potential
establishes a realistic target for the conservation savings that a utility can hope to achieve
through its programs. It is determined by applying a series of annual market adoption factors
to the economic potential for each conservation measure. These factors represent the ramp
rates at which technologies will penetrate the market. To develop these factors, the project
team reviewed Avista’s past conservation program achievements and program history over
the last five years, as well as the Northwest Power and Conservation Council (NPCC) ramp
rates used in the Sixth Plan. Details regarding the market adoption factors appear in
Appendix D.
Study Approach
To execute this project, EnerNOC used a bottom-up analysis approach as shown in Figure ES-1.
The analysis involved the following steps.
1. Held a meeting with the client project team to refine the objectives.
2. Performed a market characterization to describe sector-level electricity use for the residential
and non-residential (commercial and industrial) sectors for the base year, 2009. This step
drew upon the market characterization from the 2011 CPA, but updated the characterization
to incorporate new information from the Northwest Energy Efficiency Alliance (NEEA) 2012
Residential Building Stock Assessment (RBSA), EnerNOC’s own databases and tools, and
other secondary data sources such as the American Community Survey (ACS), Northwest
Power and Conservation Council (NPCC), and the Energy Information Administration (EIA).
3. Developed a baseline electricity use projection by sector, segment, and end use for 2009
through 2033. The baseline projection is the ―business as usual‖ metric, without new utility
conservation programs, against which energy savings from conservation measures are
compared. The baseline projection includes the impacts of known codes and standards, as of
2012 when the study was conducted, including the Energy Independence and Security Act
(EISA) lighting standards, which phase in during 2012–2014, and the 2010 appliance standards. This baseline projection process incorporates the changes in market conditions
such as customer and market growth, income growth, Avista’s retail rates forecast, trends in end-use and technology saturations, equipment purchase decisions, consumer price
elasticity, and income and persons per household.
4. Identified and characterized conservation measures. Measures to include and data to
characterize them were drawn from the Regional Technical Forum measure workbooks, the
Sixth Plan, Avista’s business plan, its technical reference manual, and EnerNOC’s own
measure database.
5. Estimated three levels of conservation potential: Technical, Economic, and Achievable.
We used EnerNOC’s Load Management Analysis and Planning tool (LoadMAPTM) version 3.0 to
develop both the baseline projection and the estimates of conservation potential. EnerNOC
developed LoadMAP in 2007 and has enhanced it over time, using it for the EPRI National
Potential Study and numerous utility-specific forecasting and potential studies.
Details of the approach as well as the data sources used in the study appear in Chapter 2.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 795 of 1125
Executive Summary
EnerNOC Utility Solutions Consulting v
Figure ES-1 Overview of Analysis Approach

Market Characterization
During 2009, Avista served 354,615 residential, commercial, industrial, and pumping customers
with a combined electricity use of approximately 8,862 GWh. The study segmented these
customers by state and rate class as shown in Table ES-1 and Table ES-2. In addition, the
residential class was segmented by housing type and income (single family, multi-family, mobile
home, and low income). The low-income threshold for purposes of this study was defined as
200% of the Federal poverty level.
For this study, the project team decided not to explicitly model the conservation potential for
pumping customers, which represent 2% of load, but instead to use the NPCC Sixth Plan
calculator to estimate pumping potential. Results of that calculation appear in Chapter 4.
Potential for rate class 25P was also estimated outside of the LoadMAP framework, and thus 25P
sales are not included in Table ES-2.
Table ES-1 Electricity Sales and Peak Demand by Rate Class, Washington 2009
Sector / Rate Class Rate Schedule(s)
Number of
meters
(customers)
2009 Electricity
Sales (GWh)
2009 Peak
Demand (MW)
Residential 001 200,134 2,452 710
General Service 011, 012 27,142 416 64
Large General Service 021, 022 3,352 1,557 232
Extra Large Commercial 025C 9 266 134 Extra Large Industrial 025I 13 614
Pumping 031, 032 2,361 136 10
Total 233,011 5,440 1,150
EE measure data
Utility data
Engineering analysis
Secondary data
Market segmentation
and characterization
Customer participation
rates
Technical and economic
potential projections
Achievable potential
projection
Utility data
Customer surveys
Secondary data
Base-year energy use by
fuel, segment
Baseline
Supply curves
Scenario analyses
Custom analyses
Project report
End-use projection by
segment
Prototypes and
energy analysis
Program results
Survey data
Secondary data
Forecast data
Synthesis / analysis
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 796 of 1125
Executive Summary
vi enernoc.com
Table ES-2 Electricity Sales and Peak Demand by Rate Class, Idaho 2009
Sector / Rate Class Rate Schedule(s) Number of meters
(customers)
2009 Electricity
Sales (MWh)
2009 Peak
Demand (MW)
Residential 001 99,580 1,182 283
General Service 011, 012 19,245 323 61
Large General Service 021, 022 1,456 700 115
Extra Large Commercial 025C 3 70 140 Extra Large Industrial 025I 6 196
Pumping 031, 032 1,312 59 4
Total 121,602 2,530 603
Note: Excludes sales to rate class 25P.
Within each segment, energy use was characterized by end-use (e.g., space heating, cooling,
lighting, water heat, motors, etc.) and by technology (e.g., heat pump, resistance heating,
furnace for space heating).
Figure ES-2 presents the residential end-use breakout in terms of intensity, kWh/household-year,
by segment for Washington and Idaho combined. Space heating is the largest single use in all
housing types, accounting for 29% of residential use overall. In three of the four segments,
appliances are the second largest energy consumer, followed by water heating and then interior
lighting. The exception is multi family housing, where water heating is the second largest end
use while appliances are the third largest end use, due to a high saturation of electric water
heating compared with the other segments. Across all housing types, interior and exterior
lighting combined represents 14% of electricity use in 2009. Electronics, which includes personal
computers, televisions, home audio, video game consoles, etc., is 8% of residential electricity
usage. The miscellaneous end use includes such devices as furnace fans, pool pumps, and other
plug loads (hair dryers, power tools, coffee makers, etc.).
Figure ES-2 Residential Intensity by End Use and Segment (kWh/household, 2009)

Figure 3-6 displays the breakdown of energy use by segment within the C&I sector. Lighting is
the largest single energy use across all of the commercial buildings, accounting for 34% of
energy use, followed by HVAC with 27% of use. For the extra large industrial customers,
machine drive and process loads dominate, together accounting for 64% of energy use.
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
Single Family Multi Family Mobile Home Low Income All Homes
In
t
e
n
s
i
t
y

(
k
W
h
/
H
H
/
y
r
)
Cooling
Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 797 of 1125
Executive Summary
EnerNOC Utility Solutions Consulting vii
Figure ES-3 C&I Electricity Consumption by End Use and Segment (2009)
This market characterization is further detailed in Chapter 3.
Conservation Potential Results
All results below show cumulative potential, indicating how a measure installed in one year
continues to provide savings in subsequent years through the end of its useful measure life. Incremental annual results appear in Appendix E. Figure ES-4 and Table ES-3 summarize the
achievable potential. The C&I sector accounts for the about 55% of the savings initially, and over
time its share of savings grows to around 60%.
Figure ES-4 Cumulative Achievable Potential by Sector (MWh)

0
500
1000
1500
2000
2500
Small/Medium
Commercial
Large Commercial Extra Large
Commercial
Extra Large
Industrial
An
n
u
a
l

U
s
e

(
1
,
0
0
0
0

M
W
h
)
Cooling
Space Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
Process
Machine Drive
-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
Cu
m
u
l
a
t
i
v
e

S
a
v
i
n
g
s

(
M
W
h
)
25P Cumulative Savings (MWh)
WA and ID Irrigation Cumulative Savings (MWh)
C&I Cumulative Savings (MWh)
Residential Cumulative Savings (MWh)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 798 of 1125
Executive Summary
viii enernoc.com
Table ES-3 Cumulative Achievable Potential by State and Sector (MWh)
2014 2015 2018 2023 2028 2033
Washington Achievable Cumulative Savings (MWh)
Residential 15,091 29,603 100,792 172,576 266,751 369,293
C&I 19,927 40,930 123,755 256,653 392,186 543,380
Pumping 1,402 3,237 8,742 10,535 10,535 10,535
Total 36,420 73,770 233,289 439,764 669,472 923,208
Washington Achievable Cumulative Savings (aMW)
Residential 1.7 3.4 11.5 19.7 30.5 42.2
C&I 2.3 4.7 14.1 29.3 44.8 62.0
Pumping 0.2 0.4 1.0 1.2 1.2 1.2
Total 4.2 8.4 26.6 50.2 76.4 105.4
2014 2015 2018 2023 2028 2033
Idaho Achievable Cumulative Savings (MWh)
Residential 6,757 13,183 46,795 79,385 125,347 177,826
C&I 8,863 16,427 53,214 124,987 192,518 261,813
Pumping 618 1,426 3,852 4,642 4,642 4,642
Total 16,238 31,036 103,861 209,014 322,507 444,281
Idaho Achievable Cumulative Savings (aMW)
Residential 0.8 1.5 5.3 9.1 14.3 20.3
C&I 1.0 1.9 6.1 14.3 22.0 29.9
Pumping 0.1 0.2 0.4 0.5 0.5 0.5
Total 1.9 3.5 11.9 23.9 36.8 50.7
2014 2015 2018 2023 2028 2033
Washington and Idaho Achievable Cumulative Savings (MWh)
Residential 21,848 42,786 147,588 251,961 392,098 547,119
C&I 28,790 57,357 176,969 381,640 584,703 805,193
Pumping 2,020 4,663 12,593 15,177 15,177 15,177
Total 52,657 104,806 337,150 648,778 991,979 1,367,490
Washington and Idaho Achievable Cumulative Savings (aMW)
Residential 2.5 4.9 16.8 28.8 44.8 62.5
C&I 3.3 6.5 20.2 43.6 66.7 91.9
Pumping 0.2 0.5 1.4 1.7 1.7 1.7
Total 6.0 12.0 38.5 74.1 113.2 156.1

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 799 of 1125
Executive Summary
EnerNOC Utility Solutions Consulting ix
Figure ES-5 presents the residential cumulative achievable potential in 2018 by end use. We note
the following:
Lighting, primarily the conversion of both interior and exterior lamps to compact fluorescent
lamps in the first few years, followed by LEDs for exterior lighting stating in 2015 and for
interior lighting starting in 2017, represents 70,446 MWh or 47% of savings. Utility programs
and other market transformation programs have made customers accepting of new lighting
technologies, and thus these technologies are relatively well accepted by consumers.
Water heating is the next highest source of achievable potential. As discussed above, water
heating provides the largest economic potential, but the market for heat pump water heaters
remains immature, and thus the uptake of this technology is limited in the near term.
Although conversion to gas water heating is a mature technology and readily accepted,
customers may be unable to convert at the time of replacement due to timing issues or other
considerations.
Space heating provides 20% of achievable potential mainly due to electric furnaces being
converted to gas units, and resistance heating being displaced by ductless heat pumps.
Figure ES-5 Residential Cumulative Achievable Potential by End Use in 2018
As shown in Figure ES-6, the primary sources of C&I sector achievable savings in 2018 are as
follows:
Interior and exterior lighting, comprising lamps, fixtures, and controls, account for 64% of
C&I sector achievable potential. Not only is economic potential high for lighting measures,
but they are more readily accepted and implemented in the market than many other, higher
cost and more complex measures.
Office Equipment, which is the second largest portion of this sector’s achievable potential
(11%)
Water heating and Ventilation each provides 6% of the total savings
Cooling
3%
Space Heating
20%
Water Heating
24%
Interior Lighting
38%
Exterior
Lighting
9%
Appliances
3%
Electronics
6%
Miscellaneous
1%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 800 of 1125
Executive Summary
x enernoc.com
Figure ES-6 C&I Cumulative Achievable Potential Cumulative Savings by End Use in 2018
(percentage of total)

Cooling
2%
Space Heating
1%Ventilation
6%
Water Heating
6%
Food Preparation
1%
Refrigeration
5%
Interior Lighting
57%
Exterior Lighting
7%
Office Equipment
11%
Machine Drive
2%
Process
2%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 801 of 1125
Executive Summary
EnerNOC Utility Solutions Consulting xi
Table ES-4 summarizes the potential, by state and for the overall service territory, for selected
years. For pumping and rate class 25P, only achievable potential was calculated. Economic and
technical potential for these two relatively small rate classes were assumed to be equal to
achievable potential. Figure ES -7 presents this information graphically.
Key findings related to cumulative conservation potentials are as follows.
Achievable potential, for the residential, commercial, and industrial sectors is 100,143
MWh or 11.4 aMW for the 2014–2015 biennium. With the addition of pumping, achievable
potential is 12.0 aMW for the 2014-2015 biennium and increases to 156.1 aMW by 2033.
Washington provides approximately 70% of the potential in most years. Over the 2014–2033
period, the achievable potential forecast offsets 39% of the overall growth in the residential
and C&I combined baseline projections.
Economic potential, which reflects the savings when all cost-effective measures are taken,
is 480,967 MWh or 54.9 aMW for2014–2015. By 2033, economic potential reaches 304.5
aMW.
Technical potential, which reflects the adoption of all conservation measures regardless of
cost-effectiveness, is a theoretical upper bound on savings. For 2014–2015, technical
potential savings are 1,372,283 MWh or 156.7 aMW. By 2033, technical potential reaches
497.2 aMW.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 802 of 1125
Executive Summary
xii enernoc.com
Table ES-4 Summary of Cumulative Conservation Potential
2014 2015 2018 2023 2028 2033
Washington Cumulative Savings (MWh)
Achievable Potential 36,420 73,770 233,289 439,764 669,472 923,208
Economic Potential 214,944 329,262 741,547 1,131,761 1,539,860 1,807,576
Technical Potential 794,447 941,497 1,550,783 2,212,885 2,704,067 3,024,259
Washington Cumulative Savings (aMW)
Achievable Potential 4.2 8.4 26.6 50.2 76.4 105.4
Economic Potential 24.5 37.6 84.7 129.2 175.8 206.3
Technical Potential 90.7 107.5 177.0 252.6 308.7 345.2
Idaho Cumulative Savings (MWh)
Achievable Potential 16,238 31,036 103,861 209,014 322,507 444,281
Economic Potential 101,779 151,705 350,121 538,404 734,193 859,791
Technical Potential 368,926 430,787 700,966 975,464 1,195,587 1,330,893
Idaho Cumulative Savings (aMW)
Achievable Potential 1.9 3.5 11.9 23.9 36.8 50.7
Economic Potential 11.6 17.3 40.0 61.5 83.8 98.1
Technical Potential 42.1 49.2 80.0 111.4 136.5 151.9
Total Washington and Idaho Cumulative 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
Total Washington and Idaho Cumulative 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
Note: For pumping and rate class 25P, only achievable potential was calculated and thus economic and technical
potential were assumed to be equal to achievable potential for these two rate classes.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 803 of 1125
Executive Summary
EnerNOC Utility Solutions Consulting xiii
Figure ES -7 Summary of Cumulative Energy Savings, Residential and C&I

Note: Excludes pumping and 25P.

Chapter 4 provides additional detail by sector and segment.
Sensitivity of Potential to Avoided Cost
Similar to the 2011 CPA, EnerNOC modeled several scenarios with varying levels of avoided costs
in addition to the reference case. For this study’s purposes, we have included a case where the
10% adder per NW Power and Conservation Act is removed. The other scenarios included 150%,
125%, and 75% of the avoided costs used in the reference case. Figure ES-8 and Table ES-5
show how achievable potential varies under the four scenarios.
The reference case achievable potential reaches approximately at 1,352,291 MWh by 2033.
Removing the 10% adder from the avoided costs decreased this achievable potential to
1,272,206 MWh, 6% reduction.
With the 150% avoided cost case, achievable potential increased to 1,657,741 MWh (23%
increase from reference) while the 125% avoided cost case and the 75% avoided cost case
yielded achievable potential equal to 1,521,856 (13% increase) and 1,146,105 MWh (15%
decrease) respectively.
While the changes are significant, the relationship between avoided cost and achievable potential
is not linear and increases in avoided costs do not provide equivalent percentage increases in
achievable potential. Technical potential imposes a limit on the amount of additional conservation
and each incremental unit of DSM becomes increasingly expensive.
0
100
200
300
400
500
600
2014 2015 2018 2023 2028 2033
En
e
r
g
y

S
a
v
i
n
g
s

(
a
M
W
)
Achievable Potential
Economic Potential
Technical Potential
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 804 of 1125
Executive Summary
xiv enernoc.com
Figure ES-8 Energy Savings, Cumulative Achievable Potential by Avoided Costs
Scenario (MWh)
Note: Excludes pumping and 25P.

Table ES-5 Achievable Potential with Varying Avoided Costs
End Use Reference
Scenario
Remove
10% adder
75% of
avoided
costs
125% of
avoided
costs
150% of
avoided
costs
Achievable potential savings
2033 (MWh) 1,352,291 1,272,206 1,146,105 1,521,856 1,657,741
Percentage change in savings vs.
100% avoided cost Scenario -6% -15% 13% 23%
Note: Excludes pumping and 25P.

Supply Curves
The project also developed supply curves for each year to support the IRP process. At Avista’s
request, the supply curves did not consider economic screening based on Avista’s avoided costs.
Instead, all measures were included and the amount of savings from each measure in each year
was limited by the ramp rates used for achievable potential. The supply curves do not include
the savings from electricity to natural gas fuel switching, discussed above.
A sample supply curve for one year is shown in Figure ES-9. This supply curve is created by
stacking measures and equipment over the 20-year planning horizon in ascending order of cost.
As expected, this stacking of conservation resources produces a traditional upward-sloping
supply curve. Because there is a gap in the cost of the energy efficiency measures as you move
up the supply curve, the measures with a very high cost cause a rapid sloping of the supply
curve. The supply curve also shows that substantial savings are available at low- or no-cost.
-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
1,800,000
2,000,000
Cu
m
u
l
a
t
i
v
e

S
a
v
i
n
g
s

(
M
W
h
)
100% of reference case avoided costs
150% of avoided costs
125% of avoided costs
Reference case without 10% adder
75% of avoided costs
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 805 of 1125
Executive Summary
EnerNOC Utility Solutions Consulting xv
Figure ES-9 Supply Curves for Evaluated EE Measures and Avoided Cost Scenarios
Note: Excludes pumping and 25P.
Washington Potential Excluding Conversions to Natural Gas
Avista has a history of fuel switching from electricity to natural gas and continues to target direct
use as the most efficient resource option when available. The conservation potential reported
above includes savings potential attributable to conversion of electric space and water heating to
natural gas. However, fuel efficiency is not considered in the NPCC Sixth Plan, and thus potential
due to fuel conversions is not included in Avista’s conservation target consistent with Washington
I-937. Washington potential consistent with the NPCC Conservation Plan methodology appears in
Table ES -6. The energy efficiency target illustrated in Table ES-6, in addition to Avista’s
distribution efficiency target, make up the I-397 target that will be filed in Avista upcoming
Biennial Conservation Plan for the 2014–2015 biennium.
Table ES -6 Washington Cumulative Potential Consistent with Conservation Plan
Methodology
2014 2015 2018 2023
Cumulative Savings (MWh)
Residential 15,091 29,603 100,792 172,576
Commercial and Industrial 19,927 40,930 123,755 256,653
Pumping 1,402 3,237 8,742 0
Conversions to Natural Gas (3,148) (6,633) (16,827) (35,028)
Total 33,272 67,137 216,462 394,200
Cumulative Savings (aMW)
Residential 1.72 3.38 11.51 19.70
Commercial and Industrial 2.27 4.67 14.13 29.30
Pumping 0.16 0.37 1.00 0.00
Conversions to Natural Gas (0.36) (0.76) (1.92) (4.00)
Total 3.80 7.66 24.71 45.00
$-
$0.10
$0.20
$0.30
$0.40
$0.50
$0.60
$0.70
$0.80
$0.90
$1.00
-100 200 300 400 500 600 700 800
Co
s
t

o
f

Co
n
s
e
v
e
d
En
e
r
g
y

(
2
0
0
9
$
/
k
W
h
)
Cumulative Savings 2020 (GWh)
Cost/kWh
Avoided Cost ($0.0489kWh)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 806 of 1125
Executive Summary
xvi enernoc.com
Additional details on potential by sector and segment appear in Chapter 4. A second volume
provides appendices with supporting information and additional results.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 807 of 1125

EnerNOC Utility Solutions Consulting xvii
CONTENTS

1 INTRODUCTION .................................................................................................... 1-1
Abbreviations and Acronyms ........................................................................................... 1-2
2 ANALYSIS APPROACH AND DATA DEVELOPMENT ................................................ 2-1
Analysis Approach .......................................................................................................... 2-1
LoadMAP Model ................................................................................................. 2-2
Market Characterization ...................................................................................... 2-3
Market Profiles ................................................................................................... 2-6
Baseline Projection ............................................................................................. 2-6
Conservation Measure Analysis ........................................................................... 2-6
Conservation Potential ...................................................................................... 2-10
Data Development ....................................................................................................... 2-11
Data Sources ................................................................................................... 2-11
Data Application ............................................................................................... 2-13
3 MARKET CHARACTERIZATION AND MARKET PROFILES ...................................... 3-1
Energy Use Summary ..................................................................................................... 3-1
Residential Sector .......................................................................................................... 3-3
C&I Sector ..................................................................................................................... 3-8
4 CONSERVATION POTENTIAL ................................................................................ 4-1
Overall Potential ............................................................................................................ 4-1
Residential Sector .......................................................................................................... 4-4
Residential Potential by End Use, Technology, and Measure Type ......................... 4-6
Residential Potential by Market Segment ........................................................... 4-10
C&I Sector Potential ..................................................................................................... 4-12
C&I Potential by End Use, Technology, and Measure Type.................................. 4-14
C&I Potential by Market Segment ...................................................................... 4-19
Sensitivity of Potential to Avoided Cost .......................................................................... 4-20
Electricity to Natural Gas Fuel Switching ........................................................................ 4-21
Supply Curves .............................................................................................................. 4-22
Pumping Potential ........................................................................................................ 4-23
Washington Potential Excluding Conversions to Natural Gas ........................................... 4-24
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 808 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 809 of 1125

EnerNOC Utility Solutions Consulting xix
LIST OF FIGURES
Figure ES-1 Overview of Analysis Approach ................................................................................. v
Figure ES-2 Residential Intensity by End Use and Segment (kWh/household, 2009) ...................... vi
Figure ES-3 C&I Electricity Consumption by End Use and Segment (2009) .................................. vii
Figure ES-4 Cumulative Achievable Potential by Sector (MWh) .................................................... vii
Figure ES-5 Residential Cumulative Achievable Potential by End Use in 2018 ................................ ix
Figure ES-6 C&I Cumulative Achievable Potential Cumulative Savings by End Use in 2018
(percentage of total) ................................................................................................ x
Figure ES -7 Summary of Cumulative Energy Savings, Residential and C&I ................................... xii
Figure ES-8 Energy Savings, Cumulative Achievable Potential by Avoided Costs Scenario (MWh) .. xiii
Figure ES-9 Supply Curves for Evaluated EE Measures and Avoided Cost Scenarios..................... xiv
Figure 2-1 Overview of Analysis Approach .............................................................................. 2-1
Figure 2-2 LoadMAP Analysis Framework ................................................................................ 2-3
Figure 2-3 Approach for Measure Assessment ......................................................................... 2-7
Figure 2-4 Avoided Costs ..................................................................................................... 2-20
Figure 3-1 Electricity Sales by Rate Class, 2009 ...................................................................... 3-2
Figure 3-2 Electricity Sales by Rate Class, Idaho 2009 ............................................................. 3-2
Figure 3-3 Percentage of Residential Electricity Use by End Use and Segment (2009) ............... 3-7
Figure 3-4 Residential Intensity by End Use and Segment (kWh/household, 2009) .................... 3-8
Figure 3-5 Commercial and Industrial Electricity Consumption by Segment 2009 ...................... 3-9
Figure 3-6 C&I Electricity Consumption by End Use, 2009 ..................................................... 3-11
Figure 3-7 C&I Electricity Consumption by End Use and Segment (2009) ............................... 3-12
Figure 4-1 Cumulative Achievable Potential by Sector (MWh) ................................................... 4-1
Figure 4-2 Summary of Cumulative Energy Savings, Residential and C&I .................................. 4-4
Figure 4-4 Residential Cumulative Savings by Potential Case ................................................... 4-5
Figure 4-5 Residential Cumulative Achievable Potential by End Use in 2018 .............................. 4-8
Figure 4-6 C&I Cumulative Savings by Potential Case ............................................................ 4-13
Figure 4-7 C&I Cumulative Achievable Potential Cumulative Savings by End Use in 2018
(percentage of total) ........................................................................................... 4-18
Figure 4-8 C&I Cumulative Achievable Savings in 2018 by End Use and Building Type ............ 4-20
Figure 4-9 Energy Savings, Cumulative Achievable Potential by Avoided Costs Scenario (MWh)4-21
Figure 4-10 Supply Curves for Evaluated EE Measures and Avoided Cost Scenarios................... 4-23
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 810 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 811 of 1125

EnerNOC Utility Solutions Consulting xxi
LIST OF TABLES
Table ES-1 Electricity Sales and Peak Demand by Rate Class, Washington 2009 ........................... v
Table ES-2 Electricity Sales and Peak Demand by Rate Class, Idaho 2009 ................................... vi
Table ES-3 Cumulative Achievable Potential by State and Sector (MWh) .................................... viii
Table ES-4 Summary of Cumulative Conservation Potential ........................................................ xi
Table ES-5 Achievable Potential with Varying Avoided Costs ...................................................... xiii
Table ES -6 Washington Cumulative Potential Consistent with Conservation Plan Methodology .... xiv
Table 1-1 Explanation of Abbreviations and Acronyms ............................................................ 1-3
Table 2-1 Overview of Segmentation Scheme for Potentials Modeling ..................................... 2-3
Table 2-2 Residential Electric End Uses and Technologies ...................................................... 2-4
Table 2-3 C&I Electric End Uses and Technologies ................................................................. 2-5
Table 2-4 Number of Measures Evaluated ............................................................................. 2-8
Table 2-5 Example Equipment Measures for Air-Source Heat Pump – Single Family Home ........ 2-9
Table 2-6 Example Non-Equipment Measures – Single Family Home, Existing .......................... 2-9
Table 2-7 Economic Screen Results for Selected Single Family Equipment Measures .............. 2-10
Table 2-8 Data Applied for the Market Profiles ..................................................................... 2-14
Table 2-9 Data Needs for the Baseline Projection and Potentials Estimation in LoadMAP ........ 2-15
Table 2-10 Residential Electric Equipment Standards Applicable to Avista ................................ 2-16
Table 2-11 Commercial Electric Equipment Standards Applicable to Avista .............................. 2-17
Table 2-12 Industrial Electric Equipment Standards Applicable to Avista .................................. 2-18
Table 2-13 Data Needs for the Measure Characteristics in LoadMAP ....................................... 2-19
Table 3-1 Electricity Sales and Peak Demand by Rate Class, Washington 2009 ........................ 3-1
Table 3-2 Electricity Sales and Peak Demand by Rate Class, Idaho 2009 ................................. 3-1
Table 3-3 Residential Sector Allocation by Segments, 2009 .................................................... 3-3
Table 3-4 Residential Electricity Usage and Intensity by Segment and State, 2009 ................... 3-4
Table 3-5 Average Residential Sector Market Profile, Washington ........................................... 3-5
Table 3-6 Average Residential Sector Market Profile, Idaho .................................................... 3-6
Table 3-7 Residential Electricity Use by End Use and Segment (kWh/HH/year, 2009) ............... 3-7
Table 3-8 Commercial and Industrial Sector Market Characterization Results, Washington 20093-9
Table 3-9 Commercial and Industrial Sector Market Characterization Results, Idaho 2009 ........ 3-9
Table 3-10 Large Commercial Segment Market Profile, Washington, 2009 ............................... 3-10
Table 3-11 C&I Electricity Consumption by End Use and Segment (GWh, 2009) ..................... 3-11
Table 4-1 Cumulative Achievable Potential by State and Sector (MWh) ................................... 4-2
Table 4-2 Summary of Cumulative Conservation Potential ...................................................... 4-3
Table 4-4 Residential Cumulative Savings by End Use and Potential Type (MWh)..................... 4-6
Table 4-5 Residential Cumulative Achievable Potential for Equipment Measures (MWh) ............ 4-9
Table 4-6 Residential Cumulative Achievable Potential by Market Segment ............................ 4-11
Table 4-7 Residential Cumulative Achievable Potential by End Use and Market Segment, 2018
(MWh) ............................................................................................................... 4-11
Table 4-8 Residential Cumulative Achievable Potential by End Use and Market Segment, 2018
(MWh) ............................................................................................................... 4-12
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 812 of 1125

xxii enernoc.com
Table 4-9 Cumulative Conservation Potential for the C&I Sector ........................................... 4-12
Table 4-10 C&I Cumulative Potential by End Use and Potential Type (MWh) ........................... 4-14
Table 4-11 C&I Cumulative Achievable Savings for Equipment Measures (MWh) ...................... 4-16
Table 4-12 C&I Cumulative Achievable Savings for Non-equipment Measures (MWh) ............... 4-17
Table 4-13 C&I Cumulative Potential by Market Segment, 2018 .............................................. 4-19
Table 4-14 C&I Cumulative Achievable Savings in 2018 by End Use and Rate Class(MWh) ....... 4-19
Table 4-15 Achievable Potential with Varying Avoided Costs ................................................... 4-21
Table 4-16 Cumulative Achievable Potential from Conversion to Natural Gas (MWh) ................ 4-22
Table 4-17 Pumping Rate Classes, Electricity Sales and Peak Demand 2009 ............................ 4-23
Table 4-18 Sixth Plan Calculator Agriculture Incremental Annual Potential, 2014–2019 (MWh) . 4-24
Table 4-19 Washington Cumulative Potential Consistent with Conservation Plan Methodology .. 4-24
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 813 of 1125

EnerNOC Utility Solutions Consulting 1-1
INTRODUCTION
Background
Avista Corporation (Avista) engaged EnerNOC Utility Solutions (EnerNOC) to conduct a
Conservation Potential Assessment (CPA). The CPA is a 20-year conservation potential study to
provide data on conservation resources for developing Avista’s 2013 Integrated Resource Plan
(IRP), and in accordance with Washington Initiative 937 (I-937). The study updates Avista’s last
CPA, which EnerNOC performed in 2011. The 2011 CPA used 2009, the first year for which
complete billing data was available at the time, as the base year. This update kept 2009 as the
base year for the analysis, and calibrated the model used for the assessment to align with actual
sales and conservation program achievements for the years 2010–2012.
Report Organization
This remainder of this report is presented in three chapters as outlined below.
Chapter 2 — Analysis Approach and Data Development
Chapter 3 — Market Characterization and Market Profiles
Chapter 4 — Conservation Potential
Definition of Potential
In this study, we estimate the potential for conservation savings. The savings estimates
represent gross savings developed into three types of potential: technical potential, economic
potential, and achievable potential. Technical and economic potential are both theoretical limits
to conservation savings. Achievable potential embodies a set of assumptions about the decisions
consumers make regarding the efficiency of the equipment they purchase, the maintenance
activities they undertake, the controls they use for energy-consuming equipment, and the
elements of building construction. The various levels are described below.
Technical potential is defined as the theoretical upper limit of conservation potential. It
assumes that customers adopt all feasible measures regardless of their cost. At the time of
existing equipment failure, customers replace their equipment with the most efficient option
available. In new construction, customers and developers also choose the most efficient
equipment option. Examples of measures that make up technical potential for electricity in
the residential sector include:
o High-efficiency heat pumps for homes with ducts
o Ductless mini-split heat pumps for homes without ducts
o Heat pump water heaters
o LED lighting
Technical potential also assumes the adoption of every other available measure, where
applicable. For example, it includes installation of high-efficiency windows in all new construction
opportunities and furnace maintenance in all existing buildings with furnace systems. These
retrofit measures are phased in over a number of years, which is longer for higher-cost and
complex measures.
Economic potential represents the adoption of all cost-effective conservation measures.
In this analysis, cost-effectiveness is measured by the total resource cost (TRC) test, which
compares lifetime energy and capacity benefits to the incremental cost of the measure. If the
benefits outweigh the costs (that is, if the TRC ratio is greater than 1.0), a given measure is
CHAPTER 1
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 814 of 1125
Introduction
1-2 www.enernoc.com
considered in the economic potential. Customers are then assumed to purchase the most
cost-effective option applicable to them at any decision juncture.
Achievable potential takes into account market maturity, customer preferences for
energy-efficient technologies, and expected program participation. Achievable potential
establishes a realistic target for the conservation savings that a utility can hope to achieve
through its programs. It is determined by applying a series of annual market adoption factors
to the economic potential for each conservation measure. These factors represent the ramp
rates at which technologies will penetrate the market. To develop these factors, the project
team reviewed Avista’s past conservation program achievements and program history over
the last five years, as well as the Northwest Power and Conservation Council (NPCC) ramp
rates used in the Sixth Plan. Details regarding the market adoption factors appear in
Appendix D.
Abbreviations and Acronyms
Throughout the report we use several abbreviations and acronyms. Table 1-1 shows the abbreviation or acronym, along with an explanation.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 815 of 1125
Introduction
EnerNOC Utility Solutions Consulting 1-3
Table 1-1 Explanation of Abbreviations and Acronyms
Acronym Explanation
ACS American Community Survey
AEO Annual Energy Outlook forecast developed annual by the Energy Information
Administration of the DOE
B/C Ratio Benefit to cost ratio
BEST EnerNOC’s Building Energy Simulation Tool
CAC Central air conditioning
C&I Commercial and industrial
CBECS Commercial Building Energy Consumption Survey (prepared by EIA)
CBSA NEAA Commercial Building Stock Assessment
CFL Compact fluorescent lamp
DEEM EnerNOC’s Database of Energy Efficiency Measures
DEER State of California Database for Energy-Efficient Resources
DSM Demand side management
EE Energy efficiency
EIA Energy Information Administration
EISA Energy Efficiency and Security Act of 2007
EPACT Energy Policy Act of 2005
EPRI Electric Power Research Institute
EUI Energy-use index
HH Household
HID High intensity discharge lamps
HPWH Heat pump water heater
IRP Integrated Resource Plan
LED Light emitting diode lamp
LoadMAP EnerNOC’s Load Management Analysis and PlanningTM tool
MECS Manufacturing Energy Consumption Survey (prepared by EIA)
NEEA Northwest Energy Efficiency Alliance
NPCC Northwest Power and Conservation Council
RTF Regional Technical Forum
RASS California Residential Appliance Saturation Survey
CEUS California Commercial End-Use Survey
REEPS EPRI Residential End-use Energy Planning System
COMMEND EPRI COMMercial END-use planning system
RBSA NEAA Residential Building Stock Assessment
RECS Residential Energy Consumption Survey (prepared by EIA)
RTU Roof top unit
Sq. ft. Square feet
TRM Technical Reference Manual
TRC Total resource cost
UEC Unit energy consumption
UES Unit energy savings (as defined in RTF measure workbooks)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 816 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 817 of 1125

EnerNOC Utility Solutions Consulting 2-1
ANALYSIS APPROACH AND DATA DEVELOPMENT
This section describes the analysis approach taken for the study and the data sources used to
develop the potential estimates.
Analysis Approach
To perform the conservation potential analysis, EnerNOC used a bottom-up analysis approach as
shown in Figure 2-1.
Figure 2-1 Overview of Analysis Approach

The analysis involved the following steps.
1. Held a meeting with the client project team to refine the objectives of the project in detail.
This resulted in a work plan for the study.
2. Performed a market characterization to describe sector-level electricity use for the residential
and non-residential (commercial and industrial) sectors for the base year, 2009. This step
drew upon the market characterization from the 2011 CPA, but updated the characterization
to incorporate new information from the Northwest Energy Efficiency Alliance (NEEA) 2012
Residential Building Stock Assessment (RBSA), EnerNOC’s own databases and tools, and
other secondary data sources such as the American Community Survey (ACS), Northwest
Power and Conservation Council (NPCC), and the Energy Information Administration (EIA).
3. Developed a baseline electricity use projection by sector, segment, and end use for 2009
through 2033.
EE measure data
Utility data
Engineering analysis
Secondary data
Market segmentation
and characterization
Customer participation
rates
Technical and economic
potential projections
Achievable potential
projection
Utility data
Customer surveys
Secondary data
Base-year energy use by
fuel, segment
Baseline
Supply curves
Scenario analyses
Custom analyses
Project report
End-use projection by
segment
Prototypes and
energy analysis
Program results
Survey data
Secondary data
Forecast data
Synthesis / analysis
CHAPTER 2
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 818 of 1125
Analysis Approach and Data Development
2-2 www.enernoc.com
4. Identified and characterized conservation measures.
5. Estimated three levels of conservation potential: measure-level conservation potential:
Technical, Economic, and Achievable.
The analysis approach for all these steps is described in further detail throughout the remainder
of this chapter.
LoadMAP Model
We used EnerNOC’s Load Management Analysis and Planning tool (LoadMAPTM) version 3.0 to
develop both the baseline forecast and the estimates of conservation potential. EnerNOC
developed LoadMAP in 2007 and has enhanced it over time, using it for the EPRI National
Potential Study and numerous utility-specific forecasting and potential studies. Built in Excel, the
LoadMAP framework, illustrated in Figure 2-1, is both accessible and transparent and has the
following key features.
Embodies the basic principles of rigorous end-use models (such as EPRI’s REEPS and
COMMEND) but in a more simplified, accessible form.
Includes stock-accounting algorithms that treat older, less efficient appliance/equipment
stock separately from newer, more efficient equipment. Equipment is replaced according to
the measure life and appliance vintage distributions defined by the user.
Balances the competing needs of simplicity and robustness by incorporating important
modeling details related to equipment saturations, efficiencies, vintage, and the like, where
market data are available, and treats end uses separately to account for varying importance
and availability of data resources.
Isolates new construction from existing equipment and buildings and treats purchase
decisions for new construction and existing buildings separately.
Uses a simple logic for appliance and equipment decisions. LoadMAP allows the user to drive
the appliance and equipment choices year by year directly in the model. This flexible
approach allows users to import the results from diffusion models or to input individual
assumptions. The framework also facilitates sensitivity analysis.
Includes appliance and equipment models customized by end use. For example, the logic for
lighting is distinct from refrigerators and freezers.
Can accommodate various levels of segmentation. Analysis can be performed at the sector
level (e.g., total residential) or for customized segments within sectors (e.g., housing type or
income level).
Consistent with the segmentation scheme and the market profiles we describe below, the
LoadMAP model provides projections of baseline energy use by sector, segment, end use, and technology for existing and new buildings. It also provides projections of total energy use and
conservation savings associated with the three types of potential.1

1 The model computes energy and peak-demand forecasts for each type of potential for each end use as an intermediate calculation. Annual-energy and peak-demand savings are calculated as the difference between the value in the baseline forecast and the value in
the potential forecast (e.g., the technical potential forecast).
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 819 of 1125
Analysis Approach and Data Development
EnerNOC Utility Solutions Consulting 2-3
Figure 2-2 LoadMAP Analysis Framework

Market Characterization
In order to estimate the savings potential from conservation measures, it is necessary to
understand how much energy is used today and what equipment is currently being used. This
characterization begins with a segmentation of Avista’s energy footprint to quantify energy use
by sector, segment, fuel, end-use application, and the current set of technologies used. We
incorporate information from the secondary research sources to advise the market
characterization.
Segmentation for Modeling Purposes
The market assessment first defined the market segments (building types, end uses and other
dimensions) that are relevant in the Avista service territory. The segmentation scheme for this project
is presented in Table 2-1, and is the same as that used in the 2011 CPA.
Table 2-1 Overview of Segmentation Scheme for Potentials Modeling
Market
Dimension Segmentation Variable Dimension Examples
1 Sector Residential, commercial and industrial
2 Building type
Residential (single family, multi family, mobile home,
low income)
Commercial and Industrial (small/medium
commercial, large commercial, extra large
commercial, extra large industrial)
3 Vintage Existing and new construction
4 Fuel Electricity
5 End uses Cooling, space heating, lighting, water heat, motors,
etc. (as appropriate by sector)
6 Appliances/end uses and
technologies
Technologies such as lamp type, air conditioning
equipment, motors by application, etc.
7 Equipment efficiency levels for new
purchases
Baseline and higher-efficiency options as appropriate
for each technology
Market Profiles
Market size
Equipment saturationFuel sharesTechnology shares
Vintage distribution
Unit energy consumptionCoincident demand
Base-year Energy
Consumption
by technology,
end use, segment, vintage & sector
Economic DataCustomer growthEnergy prices
Exogenous factors
Elasticities
Energy-efficiency
analysis
List of measuresSaturationsAdoption ratesAvoided costs
Cost-effectiveness screening
Baseline
Projection
Savings
Estimates(Annual & peak)Technical potential
Economic potentialAchievable potential
Customer segmentation Energy-efficiency
Projection:TechnicalEconomic
Achievable
Technology Data
Efficiency optionsCodes and standards
Purchase shares
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 820 of 1125
Analysis Approach and Data Development
2-4 www.enernoc.com
Following this scheme, the residential sector was segmented as described below, starting with
customer segments by building type:
Single family
Multi family
Mobile home
Low income
In addition to segmentation by housing type, we identified the set of end uses and technologies
that are appropriate for Avista’s residential sector. These are shown in Table 2-2.
Table 2-2 Residential Electric End Uses and Technologies
End Use Technology
Cooling Central Air Conditioning (CAC)
Cooling Room Air Conditioning (RAC)
Cooling/Space Heating Air-Source Heat Pump
Cooling/Space Heating Geothermal Heat Pump
Space Heating Electric Resistance
Space Heating Electric Furnace
Space Heating Supplemental
Water Heating Water Heater <= 55 gal
Water Heating Water Heater > 55 gal
Interior Lighting Screw-in Lamps
Interior Lighting Linear Fluorescent Lamps
Interior Lighting Specialty
Exterior Lighting Screw-in Lamps
Appliances Clothes Washer
Appliances Clothes Dryer
Appliances Dishwasher
Appliances Refrigerator
Appliances Freezer
Appliances Second Refrigerator
Appliances Stove
Appliances Microwaves
Electronics Personal Computers
Electronics TVs
Electronics Set-top Boxes/DVR
Electronics Devices and Gadgets
Miscellaneous Pool Pump
Miscellaneous Furnace Fan
Miscellaneous Miscellaneous

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 821 of 1125
Analysis Approach and Data Development
EnerNOC Utility Solutions Consulting 2-5
For the commercial and industrial sector (C&I), we segmented the market based on Avista’s rate
classes, using the following segments.
Small/medium Commercial
Large Commercial
Extra Large Commercial
Extra Large Industrial
The set of end uses and technologies for the C&I sector appear in Table 2-3.
Table 2-3 C&I Electric End Uses and Technologies
End Use Technology
Cooling Central Chiller
Cooling Roof top AC
Cooling/Heating Heat Pump
Space Heating Electric Resistance
Space Heating Electric Furnace
Ventilation Ventilation
Water Heating Water Heater
Interior Lighting Screw-in
Interior Lighting High-Bay Fixtures
Interior Lighting Linear Fluorescent
Exterior Lighting Exterior Screw-in
Exterior Lighting HID
Refrigeration Walk-in Refrigerator
Refrigeration Reach-in Refrigerator
Refrigeration Glass Door Display
Refrigeration Open Display Case
Refrigeration Icemaker
Refrigeration Vending Machine
Food Preparation Oven
Food Preparation Fryer
Food Preparation Dishwasher
Food Preparation Hot Food Container
Office Equipment Desktop Computer
Office Equipment Laptop Computer
Office Equipment Server
Office Equipment Monitor
Office Equipment Printer/Copier/Fax
Office Equipment POS Terminal
Process Process Cooling/Refrigeration
Process Process Heating
Process Electrochemical Process
Machine Drive Less than 5 HP
Machine Drive 5 - 24 HP
Machine Drive 25 - 99 HP
Machine Drive 100 - 249 HP
Machine Drive 250 – 499 HP
Machine Drive 500 and more HP
Miscellaneous Non-HVAC Motors
Miscellaneous Miscellaneous
Miscellaneous Other Miscellaneous
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 822 of 1125
Analysis Approach and Data Development
2-6 www.enernoc.com
For the 2011 study, we performed a high-level market characterization of electricity sales in the
2009 base year to allocate sales to each customer segment. We used Avista billing data by rate
class as well as various secondary data sources to identify the annual sales in each customer
segment, as well as the market size for each segment. This information provided control totals at
a sector level for calibrating the LoadMAP model to known data for the base-year and was used
for this CPA update as well.
Market Profiles
The next step was to develop market profiles for each sector, customer segment, end use, and
technology. A market profile includes the following elements:
Market size is a representation of the number of customers in the segment. For the
residential sector, it is number of households. In the commercial and industrial sector, it is
floor space measured in square feet.
Saturations define the fraction of homes or C&I square feet with the various technologies.
(e.g., homes with electric space heating).
UEC (unit energy consumption) or EUI (energy-use index) describes the amount of
energy consumed in 2009 by a specific technology in buildings that have the technology.
UECs are expressed in kWh/household for the residential sector, while EUIs are expressed in
kWh/square foot for C&I.
Intensity for the residential sector represents the average energy use for the technology
across all homes in 2009. It is computed as the product of the saturation and the UEC and is
defined as kWh/household for electricity. For the commercial and industrial sectors, intensity,
computed as the product of the saturation and the EUI, represents the average use for the
technology across all floor space in 2009.
Usage is the annual energy use by an end use technology in the segment. It is the product
of the market size and intensity and is quantified in GWh. The market assessment results and
the market profiles are presented in Chapter 3.
Baseline Projection
The next step was to develop the baseline projection of annual electricity usage for 2009 through
2033 by customer segment and end use without new utility programs or naturally occurring
efficiency. The end-use projection does include the relatively certain impacts of codes and
standards that will unfold over the study timeframe. All such mandates that were defined as of
January 2012 are included in the baseline. The baseline projection is the foundation for the
analysis of savings from future conservation efforts as well as the metric against which potential
savings are measured.
Inputs to the baseline projection include:
Avista historic sales data and conservation program achievements for 2009 through 2012
Current economic growth forecasts (i.e., customer growth, income growth)
Electricity price forecasts
Trends in fuel shares and equipment saturations
Existing and approved changes to building codes and equipment standards
Conservation Measure Analysis
This section describes the framework used to assess the savings, costs, and other attributes of
conservation measures. These characteristics form the basis for measure-level cost-effectiveness
analyses as well as for determining measure-level savings. For all measures, EnerNOC assembled
information to reflect equipment performance, incremental costs, and equipment lifetimes. We
used this information, along with Avista’s avoided costs data, in the economic screen to
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 823 of 1125
Analysis Approach and Data Development
EnerNOC Utility Solutions Consulting 2-7
determine economically feasible measures. Figure 2-3 outlines the framework for measure
analysis.
Figure 2-3 Approach for Measure Assessment

The framework for assessing savings, costs, and other attributes of conservation measures
involves identifying the list of conservation measures to include in the analysis, determining their
applicability to each market sector and segment, fully characterizing each measure, and
performing cost-effectiveness screening.
The first step of the conservation measure analysis was to identify the list of all relevant
conservation measures that should be considered for the Avista potential assessment. EnerNOC
prepared a preliminary list of measures that compared the list of measures included in Avista’s
previous CPA with those in its business plan, its technical reference manual, the Sixth Plan, the
RTF measure workbooks, and EnerNOC’s own measure database in order to reconcile the various
measure lists and provide the widest possible list of measures. This universal list of conservation
measures covers all major types of end-use equipment, as well as devices and actions to reduce
energy consumption. If considered today, some of these measures would not pass the economic
screens initially, but may pass in future years as a result of lower projected equipment costs or
higher avoided costs. After receiving feedback from Avista, we finalized the measures list.
The selected measures are categorized into two types according to the LoadMAP taxonomy:
equipment measures and non-equipment measures.
Equipment measures are efficient energy-consuming pieces of equipment that save energy
by providing the same service with a lower energy requirement than a standard unit. An
example is an ENERGY STAR refrigerator that replaces a standard efficiency refrigerator. For
equipment measures, many efficiency levels may be available for a given technology, ranging
Economic
screen
Measure characterization
Measure
descriptions
Energy
savings Costs
Lifetime Applicability
EnerNOC
universal
measure list
Building
simulations
EnerNOC measure
data library
NWPCC
Client measure data
library
(NWPCC, TRMs, evaluation reports, etc.)
Avoided costs, discount rate, delivery losses
Client review /
feedback
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 824 of 1125
Analysis Approach and Data Development
2-8 www.enernoc.com
from the baseline unit (often determined by code or standard) up to the most efficient
product commercially available. For instance, in the case of central air conditioners, this list
begins with the current federal standard SEER 13 unit and spans a broad spectrum up to a
maximum efficiency of a SEER 21 unit.
Non-equipment measures save energy by reducing the need for delivered energy, but do
not involve replacement or purchase of major end-use equipment (such as a refrigerator or
air conditioner). An example would be a programmable thermostat that is pre-set to run
heating and cooling systems only when people are home. Non-equipment measures can
apply to more than one end use. For instance, addition of wall insulation will affect the
energy use of both space heating and cooling. Non-equipment measures typically fall into
one of the following categories:
Building shell (windows, insulation, roofing material)
Equipment controls (thermostat, energy management system)
Equipment maintenance (air conditioning and heat pump maintenance, changing
setpoints)
Whole-building design (building orientation, passive solar lighting)
Lighting retrofits (included as a non-equipment measure because retrofits are performed
prior to the equipment’s normal end of life)
Displacement measures (ceiling fan to reduce use of central air conditioners)
Commissioning and retrocommissioning
Table 2-4 summarizes the number of equipment and non-equipment measures evaluated for
each segment within each sector.
Table 2-4 Number of Measures Evaluated
Residential C&I
Total Number of
Measures
Equipment Measures Evaluated 1,536 1540 3,076
Non-Equipment Measures Evaluated 860 914 1,774
Total Measures Evaluated 2,396 2454 4,850

Once we assembled the list of conservation measures, the project team assessed their energy-
saving characteristics. For each measure we also characterized incremental cost, service life, and
other performance factors. Following the measure characterization, we performed an economic
screening of each measure, which serves as the basis for developing the economic and
achievable potential. The residential and C&I measures are listed and described in Appendix B
and Appendix C respectively.
Representative Measure Data Inputs
To provide an example of the measure data, Table 2-5 and Table 2-6 present examples of the
detailed data inputs behind both equipment and non-equipment measures, respectively, for the
case of heat pumps in single-family homes. Table 2-6 displays the various efficiency levels
available as equipment measures, as well as the corresponding useful life, energy usage, and
cost estimates. The columns labeled On Market and Off Market reflect equipment availability due
to codes and standards or the entry of new products to the market.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 825 of 1125
Analysis Approach and Data Development
EnerNOC Utility Solutions Consulting 2-9
Table 2-5 Example Equipment Measures for Air-Source Heat Pump – Single Family Home
Efficiency Level Useful Life Equipment
Cost
Energy
Usage(kWh/yr)
On
Market
Off
Market
SEER 13 15 $5,700 857 2009 2014
SEER 14 (Energy Star) 15 $5,767 771 2009 n/a
SEER 15 (CEE Tier 2) 15 $8,018 760 2009 n/a
SEER 16 (CEE Tier 3) 15 $9,205 737 2009 n/a

Table 2-6 lists some of the non-equipment measures applicable to space heating in an existing
single-family home. All measures are evaluated for cost-effectiveness based on the lifetime
benefits relative to the cost of the measure. The total savings and costs are calculated for each
year of the study and depend on the base year saturation of the measure, the applicability2 of
the measure, and the savings as a percentage of the relevant energy end uses.
Table 2-6 Example Non-Equipment Measures – Single Family Home, Existing
End Use Measure Saturation
in 20093 Applicability Lifetime
(yrs)
Measure
Installed
Cost
Energy
Savings (%)
Space
Heating Insulation - Ducting 15% 59% 18 $500 5%
Space
Heating Repair and Sealing - Ducting 12% 100% 20 $571 23%
Space
Heating
Thermostat -
Clock/Programmable 72% 75% 15 $249 6%
Space
Heating Doors - Storm and Thermal 38% 100% 12 $320 1%
Space
Heating
Insulation - Infiltration
Control 46% 100% 25 $306 9%
Space
Heating Insulation - Ceiling 76% 75% 25 $630 10%
Space
Heating Insulation - Radiant Barrier 5% 100% 12 $923 6%
Space
Heating
Windows - High
Efficiency/ENERGY STAR 78% 100% 25 $5,201 30%
Space
Heating Behavioral Measures 20% 50% 1 $12 1%

Screening Measures for Cost-Effectiveness
Only measures that are cost-effective are included in economic and achievable potential.
Therefore, for each individual measure, LoadMAP performs an economic screen. This study uses
the TRC test that compares the lifetime energy and peak demand benefits, as well as well as any
non-energy benefits included in the RTF measure database, with the measure’s incremental
installed cost, including material and labor. The lifetime benefits are calculated by multiplying the
annual energy and demand savings for each measure by all appropriate avoided costs for each
year, and discounting the dollar savings to the present value equivalent. The analysis uses each
measure’s values for savings, costs, and lifetimes that were developed as part of the measure

2 The applicability factors take into account whether the measure is applicable to a particular building type and whether it is feasible to
install the measure. For instance, attic fans are not applicable to homes where there is insufficient space in the attic or there is no attic
at all. 3 Note that saturation levels reflected for the base year change over time as more measures are adopted.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 826 of 1125
Analysis Approach and Data Development
2-10 www.enernoc.com
characterization process described above. The analysis also accounts for transmission and
distribution losses, and for program administration costs.
The LoadMAP model performs this screening dynamically, taking into account changing savings
and cost data over time. Thus, some measures pass the economic screen for some — but not all
— of the years in the study period.
It is important to note the following about the economic screen:
The economic evaluation of every measure in the screen is conducted relative to a baseline
condition. For instance, in order to determine the kilowatt-hour (kWh) savings potential of a
measure, kWh consumption with the measure applied must be compared to the kWh
consumption of a baseline condition.
The economic screening was conducted only for measures that are applicable to each
building type and vintage; thus if a measure is deemed to be irrelevant to a particular
building type and vintage, it is excluded from the respective economic screen.
If the measure passes the screen (has a B/C ratio greater than or equal to 1), the measure is
included in economic potential. Otherwise, it is screened out for that year. If multiple equipment
measures have B/C ratios greater than or equal to 1.0, the most efficient technology is selected
by the economic screen. Table 2-7 shows the results of the economic screen for selected
measures, indicating how the economic unit for a given technology may vary over time. For
example, CFLs are initially the economical unit for interior screw-in lighting, but as the price of
LEDs decreases, they become the economical unit for single family homes starting in 2017. For
exterior lighting, due to longer hours of operation, LEDs are cost-effective starting in 2015.
Table 2-7 Economic Screen Results for Selected Single Family Equipment Measures
Technology 2014 2015 2016 2017 2018 2019
Interior Screw-in Lighting CFL CFL CFL LED LED LED
Exterior Screw-in Lighting CFL LED LED LED LED LED

Conservation Potential
The approach we used for this study adheres to the approaches and conventions outlined in the
National Action Plan for Energy-Efficiency (NAPEE) Guide for Conducting Potential Studies
(November 2007).4 The NAPEE Guide represents the most credible and comprehensive industry
practice for specifying energy-efficiency potential. As described in Chapter 1, three types of
potentials were developed as part of this effort: Technical potential, Economic potential, and
Achievable potential.
Technical potential is a theoretical construct that assumes the highest efficiency measures
that are technically feasible to install are adopted by customers, regardless of cost or
customer preferences. Thus, determining the technical potential is relatively straightforward.
LoadMAP selects the most efficient equipment options for each technology at the time of
equipment replacement. In addition, it installs all relevant non-equipment measures for each
technology to calculate savings. For example, for a central heat pump, as shown in Table 2-
5, the most efficient option is a SEER 16 system. The multiple non-equipment measures
shown in Table 2-6 are then applied to the energy used by the ductless mini-split system to
further reduce space conditioning energy use. LoadMAP applies the savings due to the non-
equipment measures one-by-one to avoid double counting of savings. The measures are
evaluated in order of their B/C ratio, with the measure with the highest B/C ratio applied

4 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.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 827 of 1125
Analysis Approach and Data Development
EnerNOC Utility Solutions Consulting 2-11
first. Each time a measure is applied, the baseline energy use for the end use is reduced and
the percentage savings for the next measure is applied to the revised (lower) usage.
Economic potential results from the purchase of the most efficient cost-effective option
available for a given equipment or non-equipment measure as determined in the cost-
effectiveness screening process described above. As with technical potential, economic
potential is a phased-in approach. Economic potential is still a hypothetical upper-boundary
of savings potential as it represents only measures that are economic but does not yet
consider customer acceptance and other factors.
Achievable potential defines the range of savings that is very likely to occur. It accounts
for customers’ awareness of efficiency options, any barriers to customer adoption, limits to
program design, and other factors that influence the rate at which conservation measures
penetrate the market.
The calculation of technical and economic potential is straightforward as described above. To
develop estimates for achievable potential, we specify market adoption rates for each measure
and each year. For Avista, the project team began with the ramp rates specified in the Sixth Plan
conservation workbooks, but modified these to match Avista program history and service
territory specifics. For specific measures, we examined historic program results for the four-year
period of 2009 through 2012. We then adjusted the 2009–2013 market acceptance rates so that
the achievable potential for these measures aligned with the historical results. This provided a
starting point for the ramp rates in 2014. For future years, we increased the potential factors to
model increasing market acceptance and program improvements. For measures not currently
included in Avista programs, we relied upon the Sixth Plan ramp rates and recent EnerNOC
potential studies to create market adoption rates. The market adoption rates for each measure
appear in Appendix D.
Results of all the potentials analysis are presented in Chapter 4.
Data Development
This section details the data sources used in this study, followed by a discussion of how these
sources were applied. In general, data were adapted to local conditions, for example, by using
local sources for measure data and local weather for building simulations.
Data Sources
The data sources are organized into the following categories:
Avista data
NPCC and RTF data
EnerNOC’s databases and analysis tools
Other secondary data and reports
Avista Data
Our highest priority data sources for this study were those that were specific to Avista.
Avista customer data: Avista provided number of customers and total electric usage by
sector from the customer billing database.
Avista Business Plan and program implementation and evaluation data: Data that
outlines the details of conservation programs, program goals, and achievements to date.
Avista Technical Resources Manual: provides collection of UES for prescriptive programs
delivered by Avista as informed by its most recent impact evaluation efforts.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 828 of 1125
Analysis Approach and Data Development
2-12 www.enernoc.com
Northwest Power and Conservation Council Data
Northwest Power and Conservation Council Sixth Plan Conservation Supply Curve
Workbooks, 2010. To develop its Power Plan, the Council used workbooks with detailed
information about measures, available at
http://www.nwcouncil.org/energy/powerplan/6/supplycurves/default.htm .
Regional Technical Forum Deemed Measures. The NWPCC Regional Technical Forum
maintains databases of deemed measure savings data, available at
http://www.nwcouncil.org/energy/rtf/measures/Default.asp .
Regional Technical Forum Residential SEEM modeling results
http://rtf.nwcouncil.org/measures/support/Default.asp
EnerNOC Databases, Analysis Tools, and Reports
EnerNOC maintains several databases and modeling tools that we use for forecasting and
potential studies.
EnerNOC Energy Market Profiles: For more than 10 years, EnerNOC staff have
maintained profiles of end-use consumption for the residential, commercial, and industrial
sectors. These profiles include market size, fuel shares, unit consumption estimates, and
annual energy use by fuel (electricity and natural gas), customer segment and end use for 10
regions in the U.S. The Energy Information Administration surveys (RECS, CBECS and MECS)
as well as state-level statistics and local customer research provide the foundation for these
regional profiles.
Building Energy Simulation Tool (BEST). EnerNOC’s BEST is a derivative of the DOE 2.2
building simulation model, used to estimate base-year UECs and EUIs, as well as measure savings for the HVAC-related measures.
EnerNOC’s EnergyShape™: This database of load shapes includes the following:
Residential – electric load shapes for 10 regions, 3 housing types, 13 end uses; Commercial –
electric load shapes for 9 regions, 54 building types, 10 end uses; Industrial – electric load
shapes, whole facility only, 19 2-digit SIC codes, as well as various 3-digit and 4-digit SIC
codes
EnerNOC’s Database of Energy Efficiency Measures (DEEM): EnerNOC maintains an
extensive database of measure data for our studies. Our database draws upon reliable
sources including the California Database for Energy Efficient Resources (DEER), the EIA
Technology Forecast Updates – Residential and Commercial Building Technologies –
Reference Case, RS Means cost data, and Grainger Catalog Cost data.
Recent studies. EnerNOC has conducted numerous studies of conservation potential in the
last five years. We checked our input assumptions and analysis results against the results
from these other studies, which include Idaho Power, and Seattle City Light. In addition, we
used the information about impacts of building codes and appliance standards from a recent
report for the Institute for Energy Efficiency.5
Other Secondary Data and Reports
Finally, a variety of secondary data sources and reports were used for this study. The main
sources are identified below.
Residential Building Stock Assessment: NEEA’s 2011 Residential Building Stock
Assessment (RBSA) provides results of a regional study of 1,404 homes, of which 27 are
located within Avista’s service territory. Due to the relatively low number of customers, 27,
within Avista’s service territory, we used the results for 113 homes in eastern Washington

5 ―Assessment of Electricity Savings in the U.S. Achievable through New Appliance/Equipment Efficiency Standards and Building Efficiency Codes (2010 – 2025).‖ Global Energy Partners, LLC for the Institute for Electric Efficiency, May 2011.
http://www.edisonfoundation.net/iee/reports/IEE_CodesandStandardsAssessment_2010-2025_UPDATE.pdf
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 829 of 1125
Analysis Approach and Data Development
EnerNOC Utility Solutions Consulting 2-13
and 52 homes in northern Idaho as proxies for Avista’s Washington and Idaho service
territories respectively. This information allowed us to update the single family home market
profiles from the 2011 CPA. At the time of the 2013 CPA, the RBSA results for mobile and
multifamily homes had not yet been released.
http://neea.org/docs/reports/residential-building-stock-assessment-single-family-
characteristics-and-energy-use.pdf?sfvrsn=6
Commercial Building Stock Assessment: NEEA’s Commercial Building Stock Assessment
(CBSA) provides data on regional commercial buildings. As of the most recent update in
2009, the database contains site-specific information for 2,061 buildings.
http://neea.org/resource-center/regional-data-resources/commercial-building-stock-
assessment
American Community Survey: The US Census American Community Survey is an ongoing
survey that provides data every year on household characteristics.
http://www.census.gov/acs/www/
Residential Energy Consumption Survey (RECS).
http://www.eia.gov/consumption/residential/data/2009/
Annual Energy Outlook. The Annual Energy Outlook (AEO), conducted each year by the
U.S. Energy Information Administration (EIA), presents yearly projections and analysis of
energy topics. For this study, we used data from the 2011 AEO.
California Statewide Surveys. The Residential Appliance Saturation Survey (RASS) and
the Commercial End Use Survey (CEUS) are comprehensive market research studies
conducted by the California Energy Commission. These databases provide a wealth of
information on appliance use in homes and businesses. RASS is based on information from
almost 25,000 homes and CEUS is based on information from a stratified random sample of
almost 3,000 businesses in California.
Electric Power Research Institute – Assessment of Achievable Potential from
Energy Efficiency and Demand Response Programs in the U.S., also known as the
EPRI National Potential Study (2009). In 2009, EPRI hired EnerNOC to conduct an
assessment of the national potential for energy efficiency, with estimates derived for the four
DOE regions.
EPRI End-Use Models (REEPS and COMMEND). These models provide the elasticities we
apply to electricity prices, household income, home size and heating and cooling.
Database for Energy Efficient Resources (DEER). The California Energy Commission
and California Public Utilities Commission (CPUC) sponsor this database, which is designed to provide well-documented estimates of energy and peak demand savings values, measure
costs, and effective useful life (EUL) for the state of California. We used the DEER database
to cross check the measure savings we developed using BEST and DEEM.
Northwest Power and Conservation Council Sixth Plan workbooks. To develop its
Power Plan, the Council maintains workbooks with detailed information about measures.
Other relevant regional sources. These include reports from the Consortium for Energy
Efficiency, the EPA, and the American Council for an Energy-Efficient Economy.
Data Application
We now discuss how the data sources described above were used for each step of the study.
Data Application for Market Characterization
To construct the high-level market characterization of electricity use and households/floor space
for the residential, commercial, and industrial sectors, we applied the following data sources:
Avista internal data, RECS 2009 and the American Community Survey to allocate residential
customers by housing type
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 830 of 1125
Analysis Approach and Data Development
2-14 www.enernoc.com
Data Application for Market Profiles
The specific data elements for the market profiles, together with the key data sources, are
shown in Table 2-8. This CPA update began with the market profiles previously developed for the
2011 CPA, but we incorporated new residential sector data from the RBSA as described above.
The C&I market profiles were largely unchanged because no significant additional data was
available regarding Avista’s C&I customers.
To develop the market profiles for each segment, we used the following approach:
1. Developed control totals for each segment. These include market size, segment-level annual
electricity use, and annual intensity.
2. Used NEEA reports including the recently released RBSA Single Family report, the Inland
Power & Light survey of its residential customers, and RECS to provide information about
market size for customer segments, appliance and equipment saturations, appliance and
equipment characteristics, UECs, building characteristics, customer behavior, operating
characteristics, and energy-efficiency actions already taken.
3. Incorporated secondary data sources to supplement and corroborate the data from items 1
and 2 above.
4. Compared and cross-checked with regional data obtained as part of the EPRI National
Potential Study and with the Energy Market Profiles Database.
5. Ensured calibration to control totals for annual electricity sales in each sector and segment.
6. Worked with Avista staff to vet the data against their knowledge and experience.
Table 2-8 Data Applied for the Market Profiles
Model Inputs Description Key Sources
Market size Base-year residential dwellings and C&I
floor space
Avista billing data, NEEA Reports, NPCC
data
Annual intensity
Residential: Annual energy use
(kWh/household)
C&I: Annual energy use
Energy Market Profiles , NEEA reports,
AEO, Inland Power & Light 2009
Conservation Potential Assessment,
previous studies
Appliance/equipment
saturations
Fraction of dwellings with an
appliance/technology;

Percentage of C&I floor space with
equipment/technology
NEAA reports, Inland Power & Light
residential saturation survey, RECS, and
other secondary data
UEC/EUI for each end-
use technology
UEC: Annual electricity use for a
technology in dwellings that have the
technology

EUI: Annual electricity use per square
foot/employee for a technology in floor
space that has the technology
NEAA reports, RASS, CEUS, engineering
analysis, prototype simulations,
engineering analysis
Appliance/equipment
vintage distribution Age distribution for each technology NEEA reports, RASS, CEUS, secondary
data (DEEM, EIA, EPRI, DEER, etc.)
Efficiency options for
each technology
List of available efficiency options and
annual energy use for each technology
Prototype simulations, engineering
analysis, appliance/equipment
standards, secondary data (DEEM, EIA,
EPRI, DEER, etc.)
Peak factors Share of technology energy use that
occurs during the peak hour
Avista data; EnerNOC’s EnergyShape
database
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 831 of 1125
Analysis Approach and Data Development
EnerNOC Utility Solutions Consulting 2-15
Data Application for Baseline Projection
Table 2-9 summarizes the LoadMAP model inputs requirements. These inputs are required for each
segment within each sector, as well as for new construction and existing dwellings/buildings.
Table 2-9 Data Needs for the Baseline Projection and Potentials Estimation in LoadMAP
Model Inputs Description Key Sources
Customer growth forecasts Forecasts of new construction in
residential and C&I sectors
AEO 2011 growth forecast
US BLS
Equipment purchase shares for
baseline projection
For each equipment/technology,
purchase shares for each efficiency
level; specified separately for
existing equipment replacement
and new construction
Shipments data from AEO
AEO 2011 regional forecast
assumptions6
Appliance/efficiency standards
analysis
Avista program results and
evaluation reports
Electricity prices
Forecast of average energy and
capacity avoided costs and retail
prices
Avista projections
AEO 2011
Utilization model parameters Price elasticities, elasticities for
other variables (income, weather)
EPRI’s REEPS and COMMEND
models
AEO 2011
Avista’s historical data for normal
cooling & heating degree days.

In addition, we implemented assumptions for known future equipment standards as of January,
2012, as shown in the tables below.

6 We developed baseline purchase decisions using the Energy Information Agency’s Annual Energy Outlook report (2011), which utilizes
the National Energy Modeling System (NEMS) to produce a self-consistent supply and demand economic model. We calibrated
equipment purchase options to match manufacturer shipment data for recent years and then held values constant for the study period. This removes any effects of naturally occurring conservation or effects of future DSM programs that may be embedded in the AEO
forecasts.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 832 of 1125
Analysis Approach and Data Development
2-16 www.enernoc.com
Table 2-10 Residential Electric Equipment Standards Applicable to Avista

Today's Efficiency or Standard Assumption 1st Standard (relative to today's standard)
2nd Standard (relative to today's standard)
End Use Technology 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Central AC
Room AC
Cooling/Heating Heat Pump
Water Heater (<=55 gallons)
Water Heater (>55 gallons)
Screw-in/Pin Lamps
Linear Fluorescent
Refrigerator/2nd Refrigerator
Freezer
Dishwasher
Clothes Washer
Clothes Dryer
Range/Oven
Microwave
Cooling
SEER 13 SEER 14
EER 9.8 EER 11.0
SEER 13.0/HSPF 7.7 SEER 14.0/HSPF 8.0
Water Heating
EF 0.90 EF 0.95
EF 0.90 Heat Pump Water Heater
Appliances
NAECA Standard 25% more efficient
NAECA Standard 25% more efficient
Conventional
Conventional
Conventional (355
kWh/yr)14% more efficient (307 kWh/yr)
Conventional (MEF 1.26 for top loader)MEF 1.72 for top loader MEF 2.0 for top loader
Conventional (EF 3.01)5% more efficient (EF 3.17)
Lighting
Incandescent Advanced Incandescent - tier 1 Advanced Incandescent - tier 2
T8
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 833 of 1125
Analysis Approach and Data Development
EnerNOC Utility Solutions Consulting 2-17
Table 2-11 Commercial Electric Equipment Standards Applicable to Avista

Today's Efficiency or Standard Assumption 1st Standard (relative to today's standard)
2nd Standard (relative to today's standard)
End Use Technology 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Chillers
Roof Top Units
Packaged Terminal AC/HP EER 9.8
Screw-in/Pin Lamps
Linear Fluorescent T12
High Intensity Discharge
Walk-in Refrigerator/Freezer
Reach-in Refrigerator
Glass Door Display EPACT 2005
Standard
Open Display Case EPACT 2005
Standard
Vending Machines EPACT 2005
Standard
Icemaker
Non-HVAC Motors
Commercial Laundry
Cooling
2007 ASHRAE 90.1
EER 11.0/11.2
EER 11.0
Lighting
Incandescent Advanced Incandescent - tier 1 Advanced Incandescent - tier 2
T8
Metal Halide
Refrigeration
EISA 2007 Standard
EPACT 2005 Standard
42% more efficient
18% more efficient
33% more efficient
2010 Standard
Miscellaneous 62.3% Efficiency 70% Efficiency
MEF 1.26 MEF 1.6
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 834 of 1125
Analysis Approach and Data Development
2-18 www.enernoc.com
Table 2-12 Industrial Electric Equipment Standards Applicable to Avista

Today's Efficiency or Standard Assumption 1st Standard (relative to today's standard)
2nd Standard (relative to today's standard)
End Use Technology 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Chillers
Roof Top Units
Packaged Terminal AC/HP EER 9.8
Screw-in/Pin Lamps
Linear Fluorescent T12
High Intensity Discharge
Less than 5 HP
5-24 HP
25-99 HP
100-249 HP
250-499 HP
500 or more HP
Cooling
2007 ASHRAE 90.1
EER 11.0/11.2
EER 11.0
Lighting
Incandescent Advanced Incandescent - tier 1 Advanced Incandescent - tier 2
T8
Metal Halide
Machine Drive
62.3% Efficiency 70% Efficiency
EISA 2007 Standards
EISA 2007 Standards
EISA 2007 Standards
EISA 2007 Standards
EISA 2007 Standards
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 835 of 1125
Analysis Approach and Data Development
EnerNOC Utility Solutions Consulting 2-19
Conservation Measure Data Application
Table 2-13 details the data sources used for measure characterization.
Table 2-13 Data Needs for the Measure Characteristics in LoadMAP
Model Inputs Description Key Sources
Energy Impacts
The annual reduction in consumption attributable
to each specific measure. Savings were developed
as a percentage of the energy end use that the
measure affects.
Avista program results and
evaluation reports
BEST
DEEM
DEER
NPCC workbooks
Other secondary sources
Peak Demand Impacts
Savings during the peak demand periods are
specified for each electric measure. These impacts
relate to the energy savings and depend on the
extent to which each measure is coincident with
the system peak.
Avista program results and
evaluation reports
BEST
EnergyShape
Costs
Equipment Measures: Includes the full cost of
purchasing and installing the equipment on a per-
household, per-square-foot, or per employee basis
for the residential, commercial, and industrial
sectors, respectively.
Non-equipment measures: Existing buildings – full
installed cost. New Construction - the costs may be
either the full cost of the measure, or as
appropriate, it may be the incremental cost of
upgrading from a standard level to a higher
efficiency level.
Avista program results and
evaluation reports
DEEM
DEER
NPCC workbooks
RS Means
Other secondary sources
Measure Lifetimes
Estimates derived from the technical data and
secondary data sources that support the measure
demand and energy savings analysis.
Avista program results and
evaluation reports
DEEM
DEER
NPCC workbooks
Other secondary sources
Applicability
Estimate of the percentage of either dwellings in
the residential sector or square feet/employment
in the C&I sector where the measure is applicable
and where it is technically feasible to implement.
DEEM
DEER
NPCC workbooks
Other secondary sources
On Market and Off
Market Availability
Expressed as years for equipment measures to
reflect when the equipment technology is available
or no longer available in the market.
EnerNOC appliance
standards and building codes
analysis
Data Application for Cost-effectiveness Screening
To perform the cost-effectiveness screening, the following information was needed:
Preliminary avoided cost of energy and capacity provided by Avista and based on 2013 IRP
planning assumptions, shown in Figure 2-4; note that Avista does not expect to incur any
avoided cost for capacity until 2019.
Line losses of 6.12%, provided by Avista
Discount rate of 4%, provided by Avista (real)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 836 of 1125
Analysis Approach and Data Development
2-20 www.enernoc.com
Program administration costs. Program administration costs can typically vary between 5–
50% of total program costs. For this study, we used values of 30% that were provided by
Avista, based on its program history.
Figure 2-4 Avoided Costs

Achievable Potential Estimation
To estimate potentials, two sets of parameters were required.
Adoption rates for non-equipment measures. Equipment is assumed to be replaced at
the end of its useful life, but for non-equipment measures, a set of factors is required to
model the gradual implementation over time. Rather than installing all non-equipment
measures in the first year of the forecast (instantaneous potential), they are phased in
according to adoption schedules that vary based on equipment cost and measure complexity.
The adoption rates for the Avista study were based on ramp rate curves specified in the
NPCC Sixth Power Plan, but modified to reflect Avista’s program history. These adoption
rates are used within LoadMAP to generate the technical and economic potentials.
Market acceptance rates (MARs). These factors are applied to Economic potential to
estimate Achievable potential. These rates were developed by beginning with the Northwest
Power and Conservation Council ramp rates but then adjusting those rates to reflect Avista’s
DSM program history.
Ramp rates and MARs are discussed in Appendix D.

0
50
100
150
200
250
-
10
20
30
40
50
60
Av
o
i
d
e
d

C
a
p
a
c
i
t
y

C
o
s
t
s

(
$
/
k
W
)
Av
o
i
d
e
d

E
n
e
r
g
y

C
o
s
t
,

$
/
M
W
h

Avoided Energy Cost, $/MWh
Avoided Capacity Cost ($/kW)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 837 of 1125

EnerNOC Utility Solutions Consulting 3-1
CHAPTER 3
MARKET CHARACTERIZATION AND MARKET PROFILES
Avista Utilities, headquartered in Spokane, Washington, is an investor-owned utility with annual
revenues of more than $1.6 billion. Avista provides electric and natural gas service to about
680,000 customers in a service territory of more than 30,000 square miles. Avista uses a mix of
hydro, natural gas, coal and biomass generation. Avista currently operates a portfolio of electric
and natural gas conservation programs in Washington, Idaho, and Oregon for residential, low
income, and non-residential customers that is funded by a non-bypassable systems benefits
charge. This study addresses electricity conservation potential in Washington and Idaho only.
This chapter characterizes the electricity use patterns of Avista’s customers.
Energy Use Summary
Table 3-1 and Table 3-2 provide 2009 customer counts and weather-normalized electricity use by
sector for Washington and Idaho, respectively. For this study, the NPCC Sixth Plan calculator to
estimate conservation potential for pumping. Results of that calculation appear in Chapter 4.
Potential for rate class 25P was also estimated outside of the LoadMAP framework, and thus 25P
sales are not included in Table 3-2.
Table 3-1 Electricity Sales and Peak Demand by Rate Class, Washington 2009
Sector / Rate Class Rate Schedule(s)
Number of
meters
(customers)
2009 Electricity
Sales (GWh)
2009 Peak
Demand (MW)
Residential 001 200,134 2,452 710
General Service 011, 012 27,142 416 64
Large General Service 021, 022 3,352 1,557 232
Extra Large Commercial 025C 9 266 134 Extra Large Industrial 025I 13 614
Pumping 031, 032 2,361 136 10
Total 233,011 5,440 1,150
Table 3-2 Electricity Sales and Peak Demand by Rate Class, Idaho 2009
Sector / Rate Class Rate Schedule(s) Number of meters
(customers)
2009 Electricity
Sales (MWh)
2009 Peak
Demand (MW)
Residential 001 99,580 1,182 283
General Service 011, 012 19,245 323 61
Large General Service 021, 022 1,456 700 115
Extra Large Commercial 025C 3 70 140 Extra Large Industrial 025I 6 196
Pumping 031, 032 1,312 59 4
Total 121,602 2,530 603
Note: Excludes sales to rate class 25P.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 838 of 1125
Market Characterization and Market Profiles
3-2 www.enernoc.com
After excluding pumping and 25 P, the distribution among the sectors in Washington and Idaho
is similar, with the largest sector, residential, accounting for 46% of Washington sales and 48%
of Idaho sales as shown in Figure 3-1 and Figure 3-2.
Figure 3-1 Electricity Sales by Rate Class, 2009

Figure 3-2 Electricity Sales by Rate Class, Idaho 2009

Note: Excludes sales to rate class 25P.

Residential
46%
General Service
8%
Large General
Service
29%
Extra Large
Commercial
5%Extra Large
Industrial
12%
Residential
48%
General
Service
13%
Large General
Service
28%
Extra Large
Commercial
3%
Extra Large Industrial
8%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 839 of 1125
Market Characterization and Market Profiles
EnerNOC Utility Solutions Consulting 3-3
Residential Sector
The total number of households and electric sales for the service territory were obtained from
Avista’s financial reporting database. In 2009, there were 200,134 households in Washington and
99,580 in Idaho. We allocated these totals into the four residential segments for each segment
based on housing type and level of income: Single family, multi family, mobile home, and low
income. The single family segment includes single-family detached homes, townhouses, and
duplexes or row houses. The multi family segment includes apartments or condos in buildings
with more than two units. The mobile homes segment includes mobile homes and other
manufactured housing. The low income segment is composed of all three of the housing types:
single-family homes, multi-family homes, and mobile homes.
Table 3-3 shows how customers were allocated to segments. Because Avista does not maintain
information on housing type or income level, we relied on a variety of survey and demographic
sources for segmenting the residential market, including the U.S. Census American Community
Survey 2006-2008, and a 2009 Inland Power customer survey. Avista defines the low-income
category as those customers with annual income less than or equal to two times the poverty
level. For an average household size of 2.5 persons, two times the poverty level is $32,880. For
the purpose of our analysis, we used a slightly higher income level cutoff of $35,000 to define
this segment, which allowed us to take advantage of the data sources listed above.
Table 3-3 Residential Sector Allocation by Segments, 2009

Washington Idaho
Segment Allocation of
Customers % of Total Allocation of
Customers % of Total
Single Family 109,134 54% 59,205 59%
Multi Family 18,219 9% 5,237 5%
Mobile Home 5,248 3% 4,774 5%
Low Income 67,533 34% 30,363 31%
Total 200,134 100% 99,580 100%

Next, to determine the residential whole building energy intensity (kWh/household) by segment,
we drew upon data from the Energy Information Agency, the NEEA 2012 RBSA, previous NEEA
residential reports, and the Inland Power & Light 2009 Conservation Potential Assessment. Based
on these sources, we developed the segment level energy intensities shown in Table 3-4. The
selected energy intensity values multiplied by the number of households equal the annual sales
for each segment. These values sum to the total annual energy use for the residential sector in
each state. The single-family segment used roughly two-thirds of the total 2009 residential
sector electricity sales.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 840 of 1125
Market Characterization and Market Profiles
3-4 www.enernoc.com
Table 3-4 Residential Electricity Usage and Intensity by Segment and State, 2009
Washington
Segment
No. of
Households
Intensity
(kWh/HH)
% of
Customers
2009 Electricity
Use (GWh) % of Sales
Single Family 109,134 14,547 54% 1,588 65%
Multi Family 18,219 8,728 9% 159 6%
Mobile Home 5,248 13,092 3% 69 3%
Low Income 67,533 9,424 34% 636 26%
Total 200,134 12,250 100% 2,452 100%
Idaho
Segment
No. of
Households
Intensity
(kWh/HH)
% of
Customers
2009 Electricity
Use (GWh)
% of Sales
Single Family 59,205 13,703 59% 811 69%
Multi Family 5,237 8,213 5% 43 4%
Mobile Home 4,774 12,320 5% 59 5%
Low Income 30,363 8,868 31% 269 23%
Total 99,580 11,874 100% 1,182 100%

As we describe in the previous chapter, the market profiles provide the foundation upon which
we develop the baseline projection. For each segment, we created a market profile, which
includes the following elements:
Market size represents the number of customers in the segment
Saturations embody the fraction of homes with the electric technologies. (e.g., homes with
electric space heating). We developed these using a combination of data from sources
including Avista TRM and Business Plan data, NEEA’s RBSA and other NEEA reports, Inland
Power & Light, NPCC, and AEO data.
UEC (unit energy consumption) describes the amount of electricity consumed in 2009 by a
specific technology in homes that have the technology (in kWh/household). As above, we
used data from Avista, NEEA, Inland Power & Light, NPCC, and AEO. We also used data from
various utility potential studies that EnerNOC has recently completed. As needed, minor
adjustments were made to calibrate to whole-building intensities.
Intensity represents the average use for the technology across all homes in 2009. It is
computed as the product of the saturation and the UEC and is defined as kWh/household.
Usage is the annual electricity use by a technology/end use in the segment. It is the product
of the number of households and intensity and is quantified in GWh.
Table 3-5 and Table 3-6 present the average existing home market profile for all residential
segments in Washington and Idaho combined. The existing-home profile represents all the
housing stock in 2009. Market profiles for each of the residential segments in Washington and
Idaho appear in Appendix A.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 841 of 1125
Market Characterization and Market Profiles
EnerNOC Utility Solutions Consulting 3-5
Table 3-5 Average Residential Sector Market Profile, Washington

UEC Intensity Usage
(kWh) (kWh/HH) (GWh)
Cooling Central AC 28.6% 1,150 330 66
Cooling Room AC 20.7%360 75 15
Cooling Air Source Heat Pump 16.3%735 120 24
Cooling Geothermal Heat Pump 0.2%730 2 0
Space Heating Electric Resistance 20.4% 6,624 1,350 270
Space Heating Electric Furnace 10.7% 9,173 980 196
Space Heating Air Source Heat Pump 16.3% 7,498 1,222 245
Space Heating Geothermal Heat Pump 0.2% 4,833 11 2
Space Heating Supplemental 7.8%260 20 4
Water Heating Water Heater <= 55 Gal 66.3% 3,074 2,038 408
Water Heating Water Heater > 55 Gal 3.1% 4,552 140 28
Interior Lighting Screw-in 100.0% 1,060 1,060 212
Interior Lighting Linear Fluorescent 100.0%107 107 21
Interior Lighting Specialty 100.0%275 275 55
Exterior Lighting Screw-in 100.0%254 254 51
Appliances Clothes Washer 82.7%114 94 19
Appliances Clothes Dryer 78.8%493 389 78
Appliances Dishwasher 85.6%386 330 66
Appliances Refrigerator 100.0%694 694 139
Appliances Freezer 56.1%774 434 87
Appliances Second Refrigerator 25.9%977 253 51
Appliances Stove 87.7%386 338 68
Appliances Microwave 95.6%114 109 22
Electronics Personal Computers 119.0%205 244 49
Electronics TVs 204.4%221 452 90
Electronics Set-top Boxes/DVR 155.2%128 198 40
Electronics Devices and Gadgets 100.0%55 55 11
Miscellaneous Pool Pump 3.6% 1,415 52 10
Miscellaneous Furnace Fan 43.7%577 252 50
Miscellaneous Miscellaneous 100.0%373 373 75
12,250 2,452
End Use Technology
Average Market Profiles - Washington
Total
Saturation
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 842 of 1125
Market Characterization and Market Profiles
3-6 www.enernoc.com
Table 3-6 Average Residential Sector Market Profile, Idaho

Table 3-7 and Figure 3-3 present the end-use shares of electricity use by housing type. Space
heating is the largest single use in all housing types, accounting for 29% of residential use
overall. In the single family, mobile home, and low income segments, appliances are the second
largest energy consumer, followed by water heating and then interior lighting. In the case of
multi-family housing, water heating is the second largest end use while appliances are the third
largest end use, due to a high saturation of electric water heating compared with the other
segments. Across all housing types, interior and exterior lighting combined represents 14% of
electricity use in 2009. The electronics end use, which includes personal computers, televisions,
home audio, video game consoles, etc., is 8% of residential electricity usage across all housing
types. The miscellaneous end use includes such devices as furnace fans, pool pumps, and other
plug loads (hair dryers, power tools, coffee makers, etc.).
UEC Intensity Usage
(kWh) (kWh/HH) (GWh)
Cooling Central AC 22.0%945 207 21
Cooling Room AC 19.7%297 58 6
Cooling Air Source Heat Pump 12.9%609 79 8
Cooling Geothermal Heat Pump 0.7%657 5 0
Space Heating Electric Resistance 20.8% 7,481 1,556 155
Space Heating Electric Furnace 9.7% 8,401 815 81
Space Heating Air Source Heat Pump 12.9% 7,415 959 95
Space Heating Geothermal Heat Pump 0.7% 5,075 35 3
Space Heating Supplemental 7.5%258 19 2
Water Heating Water Heater <= 55 Gal 60.8% 3,127 1,901 189
Water Heating Water Heater > 55 Gal 3.4% 4,779 160 16
Interior Lighting Screw-in 100.0% 1,109 1,109 110
Interior Lighting Linear Fluorescent 100.0%111 111 11
Interior Lighting Specialty 100.0%293 293 29
Exterior Lighting Screw-in 100.0%280 280 28
Appliances Clothes Washer 85.8%113 97 10
Appliances Clothes Dryer 81.9%490 402 40
Appliances Dishwasher 87.0%384 334 33
Appliances Refrigerator 100.0%690 690 69
Appliances Freezer 57.8%768 444 44
Appliances Second Refrigerator 23.0%954 219 22
Appliances Stove 80.9%379 306 31
Appliances Microwave 96.0%114 109 11
Electronics Personal Computers 122.5%204 250 25
Electronics TVs 207.5%219 454 45
Electronics Set-top Boxes/DVR 146.1%125 182 18
Electronics Devices and Gadgets 100.0%54 54 5
Miscellaneous Pool Pump 5.1% 1,422 73 7
Miscellaneous Furnace Fan 44.0%593 261 26
Miscellaneous Miscellaneous 100.0%410 410 41
11,874 1,182
Average Market Profiles - Idaho
Total
SaturationEnd Use Technology
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 843 of 1125
Market Characterization and Market Profiles
EnerNOC Utility Solutions Consulting 3-7
Table 3-7 Residential Electricity Use by End Use and Segment (kWh/HH/year, 2009)
End Use Single Family Multi Family Mobile Home Low Income Total
Residential
Cooling 652 112 259 256 467
Space Heating 3,739 3,312 5,224 3,009 3,517
Water Heating 2,341 1,628 1,928 1,937 2,139
Interior Lighting 1,810 1,002 1,351 998 1,466
Exterior Lighting 370 21 276 135 263
Appliances 3,163 1,540 2,197 2,013 2,628
Electronics 1,163 726 887 630 945
Miscellaneous 1,013 271 602 272 699
Total 14,250 8,613 12,724 9,251 12,125

Figure 3-3 Percentage of Residential Electricity Use by End Use and Segment (2009)

Figure 3-4 presents the end-use breakout in terms of intensity, kWh/household-year, by segment
for both states combined.
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Single Family Multi Family Mobile Home Low Income All Homes
%
o
f

T
o
t
a
l

E
n
e
r
g
y

U
s
e
Cooling
Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 844 of 1125
Market Characterization and Market Profiles
3-8 www.enernoc.com
Figure 3-4 Residential Intensity by End Use and Segment (kWh/household, 2009)

C&I Sector
The approach we used for the C&I sectors is analogous to the residential sector. It begins with
segmentation, then defines market size and annual electricity use, and concludes with market
profiles.
We developed the nonresidential energy use by segment using Avista 2009 billing data by rate
class. Table 3-7 and Table 3-8 present the results for the market characterization for Washington
and Idaho respectively. Although the General Service 011 and Large General Service 021 rate
classes include a small percentage of industrial customers, we chose to model these as primarily
commercial building types. For the General Service segment, we assumed facilities were small to
medium buildings, dominated by retail facilities. For the Large General Service segment, we
assumed the typical facility was an office building. When developing the market profiles, as
further described below, we began with these assumed prototypical building types, but adjusted
them to account for the diversity in each segment. For the Extra Large General Service rate class
025, we divided customers into separate commercial and industrial segments. This grouping
enabled better modeling of the industrial customers. Note that potential for Idaho rate class
025P was determined outside of the LoadMAP modeling framework because it was more
appropriate to treat this one large customer separately as opposed to modeling it as a generic
C&I customer.
Figure 3-5 shows the relative energy use of each segment as a percentage of C&I sector energy
sales.
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
Single Family Multi Family Mobile Home Low Income All Homes
In
t
e
n
s
i
t
y

(
k
W
h
/
H
H
/
y
r
)
Cooling
Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 845 of 1125
Market Characterization and Market Profiles
EnerNOC Utility Solutions Consulting 3-9
Table 3-8 Commercial and Industrial Sector Market Characterization Results, Washington
2009
Segment Electricity Use
(GWh)
Intensity
(kWh/SqFt)
Floor Space
(million SqFt)
Small/Medium Commercial 416 18 24
Large Commercial 1,557 17 93
Extra Large Commercial 266 14 19
Extra Large Industrial 614 40 15
Total 2,852 19 151
Table 3-9 Commercial and Industrial Sector Market Characterization Results, Idaho 2009
Segment Electricity Use
(GWh)
Intensity
(kWh/SqFt)
Floor Space
(million SqFt)
Small/Medium Commercial 323 18 18
Large Commercial 700 17 42
Extra Large Commercial 70 14 5
Extra Large Industrial 196 40 5
Total 1,289 18 70
Note: Excludes sales to rate class 25P.
Figure 3-5 Commercial and Industrial Electricity Consumption by Segment 2009

We used data from NEEA reports including the 2009 CBSA, the California Commercial End Use
Study (CEUS), and recently completed EnerNOC studies to estimate floor space and annual
intensities (in kWh/square foot) for each segment. Because of the heterogeneous nature of the
Small/Medium
Commercial
18%
Large
Commercial
54%
Extra Large
Commercial
8%
Extra Large
Industrial
20%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 846 of 1125
Market Characterization and Market Profiles
3-10 www.enernoc.com
C&I sectors and the wide variation in customer size (compared to residential homes), floor space
is used as the unit of measure to quantify energy use and equipment inventories on a per-
square-foot basis. Note that we are not concerned with absolute square footage, as the purpose
of this study is not to estimate C&I floor space, but with the relative size of each segment and its
growth over time.
We then developed market profiles for each non-residential segment in each state. Table 3-10
shows an example commercial average base year market profile, in this case for the Washington
Small/Medium Commercial Segment. The market profiles for each of the Washington and Idaho
C&I segments are shown in Appendix A.
Table 3-10 Large Commercial Segment Market Profile, Washington, 2009

EUI Intensity Usage
(kWh) (kWh/Sqft.) (GWh)
Cooling Central Chiller 24.7% 2.1 0.5 49
Cooling RTU 37.8% 2.5 1.0 89
Cooling Heat Pump 9.1% 3.5 0.3 30
Space Heating Heat Pump 9.1% 2.3 0.2 20
Space Heating Electric Resistance 5.9% 3.6 0.2 20
Space Heating Furnace 12.7% 4.7 0.6 55
Ventilation Ventilation 75.1% 1.7 1.2 116
Interior Lighting Interior Screw-in 100.0% 0.9 0.9 88
Interior Lighting High Bay Fixtures 100.0% 0.7 0.7 66
Interior Lighting Linear Fluorescent 100.0% 3.3 3.3 307
Exterior Lighting Exterior Screw-in 100.0% 0.1 0.1 9
Exterior Lighting HID 100.0% 0.7 0.7 65
Water Heating Water Heater 54.2% 2.3 1.3 117
Food Preparation Fryer 18.4% 0.4 0.1 6
Food Preparation Oven 18.4% 1.9 0.3 32
Food Preparation Dishwasher 18.4% 0.2 0.0 3
Food Preparation Hot Food Container 18.4% 0.3 0.1 5
Food Preparation Food Prep 18.4% 0.0 0.0 0
Refrigeration Walk in Refrigeration 39.1% 0.5 0.2 17
Refrigeration Glass Door Display 39.1% 0.4 0.1 13
Refrigeration Reach-in Refrigerator 39.1% 0.8 0.3 28
Refrigeration Open Display Case 39.1% 0.3 0.1 10
Refrigeration Vending Machine 39.1% 0.4 0.1 13
Refrigeration Icemaker 39.1% 0.7 0.3 24
Office Equipment Desktop Computer 98.4% 0.9 0.9 82
Office Equipment Laptop Computer 98.4% 0.1 0.1 6
Office Equipment Server 98.4% 0.4 0.4 38
Office Equipment Monitor 98.4% 0.2 0.2 19
Office Equipment Printer/copier/fax 98.4% 0.2 0.2 19
Office Equipment POS Terminal 98.4% 0.1 0.1 6
Miscellaneous Non-HVAC Motor 57.7% 1.4 0.8 75
Miscellaneous Other Miscellaneous 100.0% 1.4 1.4 127
16.7 1,557 Total
End Use Technology Saturation
Average Market Profiles
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 847 of 1125
Market Characterization and Market Profiles
EnerNOC Utility Solutions Consulting 3-11
Figure 3-6 displays the breakdown of energy use by end use for all C&I segments combined. This
information is further detailed in Table 3-11 and Figure 3-7, which present the end-use shares of
electricity use by segment.
Figure 3-6 C&I Electricity Consumption by End Use, 2009

Table 3-11 C&I Electricity Consumption by End Use and Segment (GWh, 2009)
End Use Small/Medium
Commercial
Large
Commercial
Extra Large
Commercial
Extra Large
Industrial Total C&I
Cooling 87 244 43 48 421
Space Heating 68 168 42 68 347
Ventilation 53 169 24 - 246
Water Heating 213 668 93 50 1,024
Interior Lighting 39 108 22 5 174
Exterior Lighting 36 153 14 - 204
Refrigeration 16 68 8 - 92
Food Preparation 70 248 26 - 344
Office Equipment 81 293 37 99 510
Miscellaneous 75 138 28 25 266
Process - - - 162 162
Machine Drive - - - 352 352
Total 739 2,257 336 809 4,141

Cooling
10%
Space Heating
7%
Ventilation
8%
Water Heating
6%
Interior Lighting
25%
Exterior Lighting
4%
Refrigeration
5%
Food Preparation
2%
Office Equipment
8%
Miscellaneous
12%
Process
4%
Machine Drive
9%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 848 of 1125
Market Characterization and Market Profiles
3-12 www.enernoc.com
Figure 3-7 C&I Electricity Consumption by End Use and Segment (2009)
Observations include the following:
Commercial buildings, including Small/Medium, Large, and Extra Large
o Lighting is the largest single energy use across all of the commercial buildings,
accounting for 34% of energy use.
o Space conditioning, including space heating, cooling, and ventilation, is close behind with
27% of energy use.
o Miscellaneous, which includes non-HVAC motors, vertical transport (e.g. elevators,
escalators), medical equipment, telecommunications equipment, and various other loads,
is the next largest energy use at 12%.
o Office equipment, with 10% of use, is the fourth largest end use.
o Water heating, refrigeration, and food preparation are only a small portion of energy use
in the commercial sector overall, though they are more significant in specific building
types (supermarkets, restaurants, hospitals, lodging).
Extra Large Industrial facilities
o Machine drive and process loads dominate in this segment, together accounting for 64%
of energy use.
o HVAC and interior lighting consume 17% and 7% of energy respectively.

0
500
1000
1500
2000
2500
Small/Medium
Commercial
Large Commercial Extra Large
Commercial
Extra Large
Industrial
An
n
u
a
l

U
s
e

(
1
,
0
0
0
0

M
W
h
)
Cooling
Space Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
Process
Machine Drive
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 849 of 1125

EnerNOC Utility Solutions Consulting 4-1
CHAPTER 4
CONSERVATION POTENTIAL
This chapter presents the results of the potential analysis, beginning with overall potential,
followed by details for each sector. All results show cumulative potential, indicating how a
measure installed in one year continues to provide savings in subsequent years through the end
of its useful measure life. Incremental annual results appear in Appendix E.
Overall Potential
Figure 4-1 and Table 4-1 summarize the achievable potential across all sectors. The C&I sector
accounts for the about 55% of the savings initially, and over time its share of savings grows to
around 60%.
Figure 4-1 Cumulative Achievable Potential by Sector (MWh)

-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
Cu
m
u
l
a
t
i
v
e

S
a
v
i
n
g
s

(
M
W
h
)
Irrigation Cumulative Savings (MWh)
C&I Cumulative Savings (MWh)
Residential Cumulative Savings (MWh)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 850 of 1125
Conservation Potential
4-2 www.enernoc.com
Table 4-1 Cumulative Achievable Potential by State and Sector (MWh)
2014 2015 2018 2023 2028 2033
Washington Achievable Cumulative Savings (MWh)
Residential 15,091 29,603 100,792 172,576 266,751 369,293
C&I 19,927 40,930 123,755 256,653 392,186 543,380
Pumping 1,402 3,237 8,742 10,535 10,535 10,535
Total 36,420 73,770 233,289 439,764 669,472 923,208
Washington Achievable Cumulative Savings (aMW)
Residential 1.7 3.4 11.5 19.7 30.5 42.2
C&I 2.3 4.7 14.1 29.3 44.8 62.0
Pumping 0.2 0.4 1.0 1.2 1.2 1.2
Total 4.2 8.4 26.6 50.2 76.4 105.4
2014 2015 2018 2023 2028 2033
Idaho Achievable Cumulative Savings (MWh)
Residential 6,757 13,183 46,795 79,385 125,347 177,826
C&I 8,863 16,427 53,214 124,987 192,518 261,813
Pumping 618 1,426 3,852 4,642 4,642 4,642
Total 16,238 31,036 103,861 209,014 322,507 444,281
Idaho Achievable Cumulative Savings (aMW)
Residential 0.8 1.5 5.3 9.1 14.3 20.3
C&I 1.0 1.9 6.1 14.3 22.0 29.9
Pumping 0.1 0.2 0.4 0.5 0.5 0.5
Total 1.9 3.5 11.9 23.9 36.8 50.7
2014 2015 2018 2023 2028 2033
Washington and Idaho Achievable Cumulative Savings (MWh)
Residential 21,848 42,786 147,588 251,961 392,098 547,119
C&I 28,790 57,357 176,969 381,640 584,703 805,193
Pumping 2,020 4,663 12,593 15,177 15,177 15,177
Total 52,657 104,806 337,150 648,778 991,979 1,367,490
Washington and Idaho Achievable Cumulative Savings (aMW)
Residential 2.5 4.9 16.8 28.8 44.8 62.5
C&I 3.3 6.5 20.2 43.6 66.7 91.9
Pumping 0.2 0.5 1.4 1.7 1.7 1.7
Total 6.0 12.0 38.5 74.1 113.2 156.1

Table 4-2 summarizes the three levels of conservation potential, by state and for the overall
service territory, for selected years. For rate class 25P and pumping customers, only achievable
potential was assessed; economic and technical potential for these two small rate classes are
assumed to be equal to achievable potential.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 851 of 1125
Conservation Potential
EnerNOC Utility Solutions Consulting 4-3
Table 4-2 Summary of Cumulative Conservation Potential
2014 2015 2018 2023 2028 2033
Washington Cumulative Savings (MWh)
Achievable Potential 36,420 73,770 233,289 439,764 669,472 923,208
Economic Potential 214,944 329,262 741,547 1,131,761 1,539,860 1,807,576
Technical Potential 794,447 941,497 1,550,783 2,212,885 2,704,067 3,024,259
Washington Cumulative Savings (aMW)
Achievable Potential 4.2 8.4 26.6 50.2 76.4 105.4
Economic Potential 24.5 37.6 84.7 129.2 175.8 206.3
Technical Potential 90.7 107.5 177.0 252.6 308.7 345.2
Idaho Cumulative Savings (MWh)
Achievable Potential 16,238 31,036 103,861 209,014 322,507 444,281
Economic Potential 101,779 151,705 350,121 538,404 734,193 859,791
Technical Potential 368,926 430,787 700,966 975,464 1,195,587 1,330,893
Idaho Cumulative Savings (aMW)
Achievable Potential 1.9 3.5 11.9 23.9 36.8 50.7
Economic Potential 11.6 17.3 40.0 61.5 83.8 98.1
Technical Potential 42.1 49.2 80.0 111.4 136.5 151.9
Total Washington and Idaho Cumulative 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
Total Washington and Idaho Cumulative 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
Note: For pumping and rate class 25P, only achievable potential was calculated and thus economic and technical
potential were assumed to be equal to achievable potential for these two rate classes.
Key findings related to cumulative conservation potentials are as follows.
Achievable potential, for the residential, commercial, and industrial sectors is 100,143
MWh or 11.4 aMW for the 2014–2015 biennium. With the addition of pumping, achievable
potential is 12.0 aMW for the 2014-2015 biennium and increases to 156.1 aMW by 2033.
Washington provides approximately 70% of the potential in most years. Washington provides
approximately 70% of the potential in most years. Over the 2014–2033 period, the
achievable potential forecast offsets 39% of the overall growth in the residential and C&I
combined baseline projections.
Economic potential, which reflects the savings when all cost-effective measures are taken,
is 480,967 MWh or 54.9 aMW for2014-2015. By 2033, economic potential reaches 304.5
aMW.
Technical potential, which reflects the adoption of all conservation measures regardless of
cost-effectiveness, is a theoretical upper bound on savings. For 2014–2015, technical
potential savings are 1, 372,283 MWh or 156.7 aMW. By 2033, technical potential reaches
497.2 aMW.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 852 of 1125
Conservation Potential
4-4 www.enernoc.com
Error! Not a valid bookmark self-reference. presents the three levels of potential for
Residential and C&I graphically.
Figure 4-2 Summary of Cumulative Energy Savings, Residential and C&I

Note: Excludes pumping and rate class 25P.
Residential Sector
Table 4-3 presents estimates for the three types of potential for the residential sector.
Table 4-3 Conservation Potential for the Residential Sector
2014 2015 2018 2023 2028 2033
Cumulative Savings (MWh)
Achievable Potential 21,848 42,786 147,588 251,961 392,098 547,119
Economic Potential 231,078 335,111 744,684 1,041,719 1,390,377 1,549,252
Technical Potential 963,411 1,037,905 1,338,457 1,473,324 1,727,383 1,911,746
Energy Savings (aMW)
Achievable Potential 2.5 4.9 16.8 28.8 44.8 62.5
Economic Potential 26.4 38.3 85.0 118.9 158.7 176.9
Technical Potential 110.0 118.5 152.8 168.2 197.2 218.2

We note the following:
Achievable potential for the 2014-2015 biennium is 42,786 MWh, or approximately 4.9
aMW. By 2033, the cumulative achievable projection savings are 62.5 aMW.
Economic potential, which reflects the savings when all cost-effective measures are taken,
is 335,111 MWh for 2014-2015. By 2033, economic potential reaches 176.9 aMW.
0
100
200
300
400
500
600
2014 2015 2018 2023 2028 2033
En
e
r
g
y

S
a
v
i
n
g
s

(
a
M
W
)
Achievable Potential
Economic Potential
Technical Potential
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 853 of 1125
Conservation Potential
EnerNOC Utility Solutions Consulting 4-5
Technical potential in the residential sector is substantial, because measures such as LED
lamps, heat pump water heaters, and solar water heating could cut energy use dramatically.
The 2014–2015 technical potential is 1,037,905 MWh. By 2033, technical potential reaches
218.2 aMW. The relatively wide gap between technical and economic potential reflects the
fact that Avista’s long-running residential conservation programs have already achieved much
of the conservation that is cost-effective. In addition, avoided costs are lower than in the
past CPA. As a result, additional conservation measures are becoming relatively more costly,
and many do not pass the cost-effectiveness screen based on Avista’s current avoided costs.
Figure 4-3 depicts the potential energy savings estimates graphically.
Figure 4-3 Residential Cumulative Savings by Potential Case

0
50
100
150
200
250
2014 2015 2018 2023 2028 2033
En
e
r
g
y

S
a
v
i
n
g
s

(
a
M
W
)
Achievable Potential
Economic Potential
Technical Potential
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 854 of 1125
Conservation Potential
4-6 www.enernoc.com
Residential Potential by End Use, Technology, and Measure Type
Table 4-4 provides estimates of savings for each end use and type of potential.
Table 4-4 Residential Cumulative Savings by End Use and Potential Type (MWh)
End Use Potential Case 2014 2015 2018 2023 2028 2033
Cooling
Achievable 620 1,206 3,955 8,711 13,826 16,615
Economic 1,968 2,742 8,812 14,724 19,958 23,154
Technical 80,951 84,487 96,347 115,936 138,315 155,998
Space
Heating
Achievable 3,984 8,769 29,422 72,188 126,808 178,884
Economic 33,250 59,904 165,564 317,802 479,738 572,297
Technical 426,183 437,898 485,931 568,938 690,804 784,960
Water
Heating
Achievable 3,409 9,111 35,322 88,903 146,861 201,703
Economic 139,048 174,837 285,037 498,268 694,979 750,037
Technical 205,283 224,051 279,694 387,782 492,126 528,826
Interior
Lighting
Achievable 9,112 15,439 56,325 50,856 61,722 77,434
Economic 36,447 61,757 193,632 121,765 101,412 89,845
Technical 69,443 97,468 237,734 172,522 159,744 176,303
Exterior
Lighting
Achievable 3,121 5,340 14,121 7,568 1,767 4,771
Economic 12,486 21,361 56,554 18,869 4,680 5,178
Technical 29,639 37,425 63,855 27,506 18,316 19,975
Appliances
Achievable 1,210 1,979 4,746 11,476 15,137 22,253
Economic 2,171 3,494 7,934 23,758 26,088 31,776
Technical 110,903 106,754 97,381 96,098 99,364 99,247
Electronics
Achievable 269 635 2,466 8,038 16,469 27,134
Economic 4,242 8,047 19,593 31,158 39,062 44,050
Technical 38,001 44,875 66,641 83,650 96,504 106,895
Misc.
Achievable 122 307 1,232 4,220 9,509 18,325
Economic 1,465 2,969 7,558 15,375 24,460 32,915
Technical 3,009 4,947 10,872 20,892 32,212 39,542
5Total
Achievable 21,848 42,786 147,588 251,961 392,098 547,119
Economic 231,078 335,111 744,684 1,041,719 1,390,377 1,549,252
Technical 963,411 1,037,905 1,338,457 1,473,324 1,727,383 1,911,746

Focusing first on technical and economic potential, there are significant savings that are both
possible and economic in numerous end uses:
Space heating offers the highest technical potential, which would be achieved if all electric
furnaces were replaced with SEER 16 air-source heat pumps (either when furnaces fail or by
installing a heat pump in lieu of a furnace during new construction) and all electric resistance
heat was converted to ductless mini-split systems. Note that conversion to gas is not
included in the technical potential because it does not result in the least energy use at the
site level.7 On the other hand, conversion to gas furnaces is cost-effective and is thus
included in the economic potential. In addition, replacing electric resistance heat with

7 Based on multiplying site-level electricity use in kWh by 3.412 to convert to equivalent kBTU for comparison with natural gas use.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 855 of 1125
Conservation Potential
EnerNOC Utility Solutions Consulting 4-7
ductless heat pumps, selected shell measures, and thermostats also contribute to economic
potential. By 2018, space heating is the third highest contributor to economic potential.
Water heating offers the second-highest technical potential savings in 2014, which reflects
the across-the-board installation of heat pump water heaters and solar water heating.
Although solar water heating does not pass the TRC B/C screening, HPWH are found to be
cost-effective for water heaters in single family homes.8 As with furnaces, conversion to gas
is not included in technical potential, but does feature in economic potential. Consequently,
economic potential actually grows more rapidly than technical potential. By 2018, water
heating is projected to be the largest contributor to economic potential.
Appliances offer the third-highest technical potential in the near term. This reflects both the
replacement of failed white-goods appliances with the highest-efficiency option and removal
of second refrigerators in appliance recycling programs. However, once the new appliance
standards take effect in 2015, relative savings in this category diminish and therefore many
technologies no longer pass the economic screen, yielding economic potential that is
relatively small.
Interior and Exterior Lighting combine to provide the fourth largest source of technical
potential. Initially, economic potential is substantial as well, due to CFLs and high-efficiency
linear fluorescent options. By 2018, LEDs have become the cost-effective option in many
segments, and thus economic potential grows substantially, making lighting the second
highest source of economic potential, behind only water heating.
Cooling also offer substantial technical potential savings opportunities which would be
achieved if all air conditioning systems were converted to the highest efficiency units.
However, standards again diminish savings relative to the base case and lower cost-
effectiveness such that cooling measures are eliminated from economic potential.
Electronics provides substantial technical potential as well, but most alternatives for higher
efficiency are not cost effective, largely because the baseline case already incorporates
relatively high efficiency equipment, as a result of successful market transformation efforts to
date.
Figure 4-4 presents the residential cumulative achievable potential in 2018. This reflects the
application of market acceptance rate factor to economic potential, to model how factors
including market barriers, customer acceptance, and program maturity affect how quickly
measures are implemented. As discussed in Chapter 2, market acceptance rates were developed
based on the Sixth Plan ramp rates with adjustments to match Avista program history. We note
the following:
Lighting, primarily the conversion of both interior and exterior lamps to compact fluorescent
lamps in the first few years, followed by LEDs starting in 2017, represents 70,446 MWh or
47% of savings. Utility programs and other market transformation programs have made
customers accepting of new lighting technologies, and thus these technologies are relatively
well accepted by consumers.
Water heating is the next highest source of achievable potential. As discussed above, water
heating provides the largest economic potential, but the market for heat pump water heaters
remains immature, and thus the uptake of this technology is limited in the near term.
Although conversion to gas water heating is a mature technology and readily accepted,
customers may be unable to convert at the time of replacement due to timing issues or other
considerations.
Space heating provides 20% of achievable potential mainly due to electric furnaces being
converted to gas units, and resistance heating being displaced by ductless heat pumps.

8 HPWH become the baseline technology for water heaters ≥55 gallons beginning in 2016 due to a standards change, and thus the
larger water heaters do not contribute to potential after 2016.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 856 of 1125
Conservation Potential
4-8 www.enernoc.com
Figure 4-4 Residential Cumulative Achievable Potential by End Use in 2018
As described in Chapter 2, using our LoadMAP model, we develop separate estimates of potential
for equipment and non-equipment measures. Table 4-5 presents results for equipment
achievable potential at the technology level and Table 4-6 presents non-equipment measures for
those measures that passed the cost-effectiveness screening. Initially, the majority of the
savings come from the equipment measures, with lighting leading the way. Water heating, space
heating, appliances and electronics, mainly televisions, provide savings as well. Over time, non-
equipment measures, which are phased into the market more slowly but produce long-lasting
savings (e.g., controls, water-saving fixtures, shell measures), produce a greater share of
savings. In the non-equipment category, tank blanket installation, pipe insulation and thermostat
setbacks for water heaters provide the greatest savings.

Cooling
3%
Space Heating
20%
Water Heating
24%
Interior Lighting
38%
Exterior
Lighting
9%
Appliances
3%
Electronics
6%
Miscellaneous
1%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 857 of 1125
Conservation Potential
EnerNOC Utility Solutions Consulting 4-9
Table 4-5 Residential Cumulative Achievable Potential for Equipment Measures (MWh)
End Use Technology 2014 2015 2018 2023 2028 2033
Cooling
Central AC 500 1,014 2,687 5,462 8,714 10,055
Room AC - - - - - -
Air Source Heat Pump 93 94 95 96 97 205
Geothermal Heat Pump - - - - - -
Space Heating
Electric Resistance 348 837 3,738 13,323 31,336 52,036
Electric Furnace 3,159 6,839 17,175 33,802 56,037 75,385
Air Source Heat Pump 256 257 261 264 267 3,561
Geothermal Heat Pump - - - - - -
Water
Heating
Water Heater <= 55 Gal 1,604 3,654 11,129 38,369 82,577 136,249
Water Heater > 55 Gal 119 166 331 810 1,387 1,944
Interior
Lighting
Screw-in 6,268 9,722 39,805 18,279 7,524 15
Linear Fluorescent 5 10 36 8 - 21
Specialty 2,838 5,707 16,484 32,296 53,577 76,495
Exterior
Lighting Screw-in 3,121 5,340 14,121 7,568 1,767 4,771
Appliances
Clothes Washer 548 546 542 533 53 12
Clothes Dryer - - - - - -
Dishwasher - - - 80 288 601
Refrigerator 383 775 2,187 4,655 5,854 9,371
Freezer 34 172 789 1,527 2,647 4,219
Second Refrigerator 131 259 668 1,413 1,851 3,151
Stove 114 227 560 1,296 2,109 2,470
Microwave - - - - - -
Electronics
Personal Computers 106 260 1,111 3,079 5,678 9,692
TVs 74 187 745 2,543 5,118 7,419
Set-top boxes/DVR 89 188 610 2,417 5,673 10,023
Devices and Gadgets - - - - - -
Miscellaneous
Pool Pump 6 15 62 241 968 2,961
Furnace Fan 116 291 1,170 3,979 8,541 15,364
Miscellaneous - - - - - -
Grand Total 19,915 36,560 114,306 172,041 282,064 426,022

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 858 of 1125
Conservation Potential
4-10 www.enernoc.com
Table 4-6 Residential Cumulative Achievable Savings for Non-equipment Measures (MWh),
continued
Measure 2014 2015 2018 2023 2028 2033
Insulation - Ceiling - - 53 174 308 606
Insulation - Foundation - - 791 2,225 4,753 7,090
Insulation - Infiltration Control - - 1,692 9,543 16,408 20,226
Insulation - Wall Cavity 5 18 101 399 1,025 2,887
Refrigerator - Remove Second Unit - - - 1,973 2,335 2,429
Thermostat - Clock/Programmable 243 917 6,783 14,483 18,457 18,619
Water Heater - Faucet Aerators 238 807 3,244 6,411 7,897 7,706
Water Heater - Pipe Insulation 335 1,129 4,790 9,307 11,296 10,828
Water Heater - Low Flow Showerheads 203 606 5,885 14,759 17,448 17,087
Water Heater - Tank Blanket/Insulation 575 1,909 7,317 13,150 14,736 12,937
Water Heater - Thermostat Setback 334 841 2,626 6,097 11,519 14,951
Advanced New Construction Designs - - - - 1,079 1,801
Behavioral Measures - - - 1,400 2,773 3,930
Total 1,933 6,226 33,281 79,920 110,034 121,098

Residential Potential by Market Segment
Single-family homes were slightly more than half of Avista’s residential customers and
represented 66% of the sector’s energy use in 2009. Furthermore, potential savings are
generally higher in single family homes, which have larger saturations of equipment beyond the
basics of space heating, water heating, and appliances. Thus, single-family homes account for
the largest share of potential savings by segment, representing approximately 73% of achievable
potential across the study period as indicated in Table 4-6. Table 4-7 shows the three potential
cases by housing type in 2018.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 859 of 1125
Conservation Potential
EnerNOC Utility Solutions Consulting 4-11
Table 4-6 Residential Cumulative Achievable Potential by Market Segment
2014 2015 2018 2023 2028 2033
Achievable Savings (MWh)
Single Family 15,922 30,820 102,461 174,454 268,519 370,353
Multi Family 765 1,551 6,307 11,114 17,841 26,271
Mobile Home 619 1,259 4,131 6,589 10,014 13,837
Low Income 4,541 9,156 34,688 59,803 95,724 136,659
Total 21,848 42,786 147,588 251,961 392,098 547,119
Achievable - % of Savings
Single Family 73% 72% 69% 69% 68% 68%
Multi Family 4% 4% 4% 4% 5% 5%
Mobile Home 3% 3% 3% 3% 3% 3%
Low Income 21% 21% 24% 24% 24% 25%
Total 100% 100% 100% 100% 100% 100%

Table 4-7 Residential Cumulative Achievable Potential by End Use and Market Segment, 2018
(MWh)
Single Family Multi Family Mobile Home Low Income
Energy Savings (MWh)
Achievable Potential 102,461 6,307 4,131 34,688
Economic Potential 464,782 37,980 31,907 210,015
Technical Potential 1,434,368 173,515 131,221 909,267
Energy Savings (aMW)
Achievable Potential 4% 3% 3% 4%
Economic Potential 20% 20% 26% 24%
Technical Potential 61% 90% 106% 105%

Table 4-8 shows the savings by end use and market segment in 2018. Across all housing types,
as discussed previous, lighting is the single largest opportunity, followed by water heating, and
space heating. In mobile homes and low income, however, the potential for space heating is
higher than for water heating, due to the higher saturation of electric heat, as well as less
efficient building shells.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 860 of 1125
Conservation Potential
4-12 www.enernoc.com
Table 4-8 Residential Cumulative Achievable Potential by End Use and Market Segment, 2018
(MWh)
End Use Single Family Multi Family Mobile Home Low Income All Homes
Cooling 3,029 31 57 838 3,955
Space Heating 17,689 982 1,117 9,634 29,422
Water Heating 25,266 1,761 490 7,805 35,322
Interior Lighting 39,315 3,053 1,728 12,228 56,325
Exterior Lighting 11,190 87 488 2,355 14,121
Appliances 3,276 228 131 1,112 4,746
Electronics 1,698 142 75 550 2,466
Miscellaneous 998 23 45 167 1,232
Total 102,461 6,307 4,131 34,688 147,588

C&I Sector Potential
The baseline projection for the commercial sector grows steadily during the projection period as
the region emerges from the economic downturn. As a result, opportunities for energy-efficiency
savings are significant for the C&I sector.
Achievable potential for the 2014-2015 biennium is 57,354 MWh, or approximately 6.5
aMW. By 2033, the cumulative achievable projection savings are 91.9 aMW. Potential for rate
class 25P was separately assessed, outside the LoadMAP model, at approximately 1 MWh
annually.
Economic potential is 141,191 MWh for 2014-2015. By 2033, economic potential reaches
125.9 aMW.
Technical potential for 2014–2015 potential is 329,713 MWh. By 2033, technical potential
reaches 277.2 aMW.
Table 4-9 and Note: Excludes rate class 25P.
Figure 4-5 present the savings associated with each level of potential.
Table 4-9 Cumulative Conservation Potential for the C&I Sector
2014 2015 2018 2023 2028 2033
Cumulative Savings (MWh)
Achievable Potential 28,789 57,354 176,964 381,630 584,687 805,172
Economic Potential 83,624 141,191 334,386 613,258 868,483 1,102,916
Technical Potential 197,941 329,713 900,694 1,699,836 2,157,078 2,428,207
Cumulative Savings (aMW)
Achievable Potential 3.3 6.5 20.2 43.6 66.7 91.9
Economic Potential 9.5 16.1 38.2 70.0 165.7 125.9
Technical Potential 22.6 37.6 102.8 194.0 246.2 277.2
Note: Excludes rate class 25P.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 861 of 1125
Conservation Potential
EnerNOC Utility Solutions Consulting 4-13
Figure 4-5 C&I Cumulative Savings by Potential Case
Note: Excludes rate class 25P.

0
50
100
150
200
250
300
2014 2015 2018 2023 2028 2033
En
e
r
g
y

S
a
v
i
n
g
s

(
a
M
W
)
Achievable Potential
Economic Potential
Technical Potential
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 862 of 1125
Conservation Potential
4-14 www.enernoc.com
C&I Potential by End Use, Technology, and Measure Type
Table 4-10 presents the commercial and industrial sector savings by end use and potential type.
Table 4-10 C&I Cumulative Potential by End Use and Potential Type (MWh)
End Use Potential 2014 2015 2018 2023 2028 2033
Cooling
Achievable Potential 868 1,376 4,173 16,795 34,853 49,278
Economic Potential 1,691 2,488 7,079 27,350 53,462 72,875
Technical Potential 19,454 29,736 97,875 196,371 253,620 294,929
Space Heating
Achievable Potential 519 715 1,803 6,917 15,359 23,827
Economic Potential 1,288 1,733 4,283 14,806 29,018 41,719
Technical Potential 11,159 16,184 44,222 108,389 148,257 173,675
Ventilation
Achievable Potential 963 2,239 10,061 31,438 55,099 77,805
Economic Potential 1,133 2,739 12,553 38,972 66,375 92,514
Technical Potential 12,706 22,200 83,691 184,710 226,874 241,650
Water
Heating
Achievable Potential 1,597 3,270 10,777 32,637 78,331 126,429
Economic Potential 11,899 22,573 57,844 122,614 211,538 238,809
Technical Potential 15,102 29,004 80,484 159,912 266,475 297,971
Interior
Lighting
Achievable Potential 17,099 34,790 99,910 159,448 196,299 274,184
Economic Potential 44,373 71,064 145,394 208,161 247,368 342,873
Technical Potential 77,989 127,519 332,806 565,237 668,438 745,387
Exterior
Lighting
Achievable Potential 1,891 3,353 12,231 33,437 48,284 52,775
Economic Potential 7,402 11,324 33,083 53,407 58,412 60,364
Technical Potential 12,582 17,733 42,800 75,475 84,874 93,215
Food
Preparation
Achievable Potential 1,658 3,354 9,246 20,001 28,341 35,406
Economic Potential 2,127 4,265 11,312 24,224 34,077 42,363
Technical Potential 3,928 7,015 17,911 40,248 58,963 73,609
Refrigeration
Achievable Potential 93 343 1,833 4,922 12,431 28,158
Economic Potential 186 603 2,490 6,123 14,718 33,143
Technical Potential 3,663 7,396 19,377 40,458 56,695 65,200
Office
Equipment
Achievable Potential 3,000 5,894 19,718 46,832 67,723 76,351
Economic Potential 11,327 20,590 48,337 73,793 83,277 91,979
Technical Potential 29,051 51,981 104,158 128,436 143,820 158,781
Machine
Drive
Achievable Potential 4 8 40 165 300 439
Economic Potential 8 15 73 295 512 713
Technical Potential 188 695 2,625 6,418 10,018 11,764
Process
Achievable Potential 426 766 3,337 13,761 26,438 35,254
Economic Potential 862 1,501 6,179 23,952 43,702 54,818
Technical Potential 10,272 17,192 66,674 169,003 205,886 233,266
Miscellaneous
Achievable Potential 670 1,248 3,835 15,277 21,229 25,265
Economic Potential 1,329 2,295 5,758 19,561 26,024 30,744
Technical Potential 1,848 3,057 8,070 25,178 33,157 38,761
Total
Achievable Potential 28,789 57,354 176,964 381,630 584,687 805,172
Economic Potential 83,624 141,191 334,386 613,258 868,483 1,102,916
Technical Potential 197,941 329,713 900,694 1,699,836 2,157,078 2,428,207
Note: Excludes rate class 25P.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 863 of 1125
Conservation Potential
EnerNOC Utility Solutions Consulting 4-15
The end uses with the highest technical and economic potential are:
Interior lighting, as a result of LED lighting that is now commercially available, has the
highest technical potential at 332,806 MWh in 2018. LEDs are found to be cost-effective in all
applications beginning in either 2014 or 2015, as a result of longer hours of operation in
commercial buildings. In addition, super T8s for linear fluorescent systems, T5s for high-bay
fixtures, and control systems also contribute to lighting economic potential. Therefore,
economic potential is highest for lighting as well, at 145,394 MWh in 2018, which is roughly
44% of the lighting technical potential and 43% of total economic potential in 2018.
HVAC end uses collectively comprise 25% of technical potential or 225,778 MWh. However,
relatively few measures pass the economic screen, so that economic potential is only 23,915
MWh, or about one tenth of the technical potential.
Office equipment has significant technical potential of 101,158 MWh in 2018, and
economic potential of 48,337 MWh
Water heating technical potential comes next, with 80,484 MWh, and because measures
such as HPWH and water saving devices are cost-effective, economic potential is 57,844
MWh.
Table 4-11 and Table 4-12 present achievable potential savings for equipment measures and
non-equipment measures, respectively. Table 4-12 presents only measures that passed the cost-
effectiveness test.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 864 of 1125
Conservation Potential
4-16 www.enernoc.com
Table 4-11 C&I Cumulative Achievable Savings for Equipment Measures (MWh)
End Use Technology 2014 2015 2018 2023 2028 2033
Cooling
Central Chiller 350 670 2,231 6,803 12,639 17,307
RTU - - - - - -
Heat Pump - - - - - -
Space Heating
Heat Pump - - - - - -
Electric Resistance - - - - - -
Furnace - - - - - -
Ventilation Ventilation 963 2,072 8,768 26,596 49,646 72,087
Water
Heating Water Heater 1,311 2,844 9,464 26,736 64,973 107,400
Interior
Lighting
Linear Fluorescent 93 141 5,268 29,001 44,645 68,240
Interior Screw-in 10,160 19,861 42,656 29,637 12,498 42,051
High Bay Fixtures 6,482 14,295 48,666 77,212 85,244 94,133
Exterior
Lighting
HID 1,140 2,519 8,105 27,952 41,884 47,529
Exterior Screw-in 678 708 3,507 2,823 2,075 -
Refrigeration
Reach-in Refrigerator 409 839 2,364 5,026 7,600 10,224
Glass Door Display 462 946 2,614 5,502 8,266 10,964
Open Display Case - - - - - -
Icemaker 291 589 1,595 3,648 4,865 5,399
Vending Machine 452 921 2,520 5,382 6,822 7,744
Walk in Refrigerator - - - - - -
Food
Preparation
Oven - 137 944 2,673 8,844 23,982
Fryer 93 207 670 1,532 2,303 2,660
Dishwasher - - - - - -
Hot Food Container - - 220 717 1,284 1,516
Other Food Prep - - - - - -
Office
Equipment
Desktop Computers 1,381 2,607 6,968 13,526 20,092 22,514
Server 1,095 2,340 7,192 16,419 23,871 26,404
Monitor 121 229 1,979 4,709 6,994 7,837
Printer/copier/fax - - 395 3,452 5,311 6,242
POS Terminal - - 381 956 1,425 1,613
Laptop Computer 96 182 487 945 1,403 1,573
Miscellaneous Non-HVAC Motor
Other Miscellaneous - - - - - -
Process
Process
Cooling/Refrigeration 301 574 1,810 8,290 11,076 12,927
Process Heating - - - - - -
Electrochemical Process 293 558 1,614 5,791 8,190 9,645
Machine
Drive
Less than 5 HP 3 27 122 241 640 851
5-24 HP 7 14 41 160 212 247
25-99 HP 19 36 104 405 537 623
100-249 HP 11 20 59 230 305 353
250-499 HP 3 6 32 287 343 392
500 and more HP 6 12 60 543 649 742
Grand Total 26,202 53,316 160,683 306,133 433,342 601,609
Note: Excludes rate class 25P.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 865 of 1125
Conservation Potential
EnerNOC Utility Solutions Consulting 4-17
Table 4-12 C&I Cumulative Achievable Savings for Non-equipment Measures (MWh)
Measure 2014 2015 2018 2023 2028 2033
Energy Management System 1,142 1,525 3,673 15,912 39,422 63,759
Exterior Lighting - Daylighting Controls 0 0 5 58 271 482
Interior Lighting - Occupancy Sensors 0 0 9 58 113 160
Thermostat - Clock/Programmable 213 296 754 2,471 4,822 6,948
Heat Pump - Maintenance 41 69 277 918 1,387 1,634
Water Heater - Faucet Aerators/Low Flow
Nozzles - - - - - 411
Water Heater - High Efficiency Circulation
Pump 285 425 1,313 5,900 13,358 18,617
Retrocommissioning - Lighting - - 1,689 17,461 38,207 43,900
Air-Cooled Chiller - Cond. Water Temperature
Reset 0 0 87 761 1,218 1,689
Chiller - Chilled Water Reset - - - - 17 63
Chiller - Chilled Water Variable-Flow System 0 0 3 16 40 64
Chiller - High Efficiency Cooling Tower Fans 0 0 6 37 69 103
Cooling - Economizer Installation - - 168 1,916 4,085 4,999
Fans - Energy Efficient Motors - 161 720 2,249 2,533 2,293
Interior Lighting - Time Clocks and Timers - - - 21 92 140
Refrigeration - Strip Curtain 43 59 149 415 710 920
LED Exit Lighting 4 20 483 599 771 748
Refrigeration - High Efficiency Case Lighting - 1 5 29 78 153
Exterior Lighting - Cold Cathode Lighting 72 125 507 1,442 1,703 1,989
Laundry - High Efficiency Clothes Washer 4 7 35 115 157 192
Interior Lighting - Skylights - - 7 108 279 469
Office Equipment - Smart Power Strips 305 536 2,316 6,826 8,626 10,168
Ventilation - Demand Control Ventilation 0 5 571 2,576 2,875 3,349
Strategic Energy Management 5 7 62 434 1,163 1,968
Refrigeration - System Controls 28 38 85 192 297 350
Refrigeration - System Maintenance 28 44 169 482 665 829
Refrigeration - System Optimization 17 29 116 252 285 298
Motors - Variable Frequency Drive 6 13 197 1,167 2,159 3,207
Motors - Magnetic Adjustable Speed Drives 222 380 1,489 3,821 4,690 5,921
Compressed Air - System Optimization and
Improvements 7 14 196 2,992 9,116 11,744
Compressed Air - Compressor Replacement 100 172 655 2,485 5,571 8,169
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 866 of 1125
Conservation Potential
4-18 www.enernoc.com
Measure 2014 2015 2018 2023 2028 2033
Fan System - Controls 3 6 27 89 126 160
Fan System - Optimization 17 29 113 291 350 382
Fan System - Maintenance 0 0 1 8 14 20
Pumping System - Controls 21 37 228 975 1,610 2,275
Pumping System - Maintenance 0 1 13 67 117 169
Total 2,566 4,001 16,130 74,436 150,049 202,076
Note: Excludes rate class 25P.

As shown in Figure 4-6, the primary sources of C&I sector achievable savings in 2018 are as
follows:
Interior and exterior lighting, comprising lamps, fixtures, and controls, account for 64% of
C&I sector achievable potential. Not only is economic potential high for lighting measures, but they are more readily accepted and implemented in the market than many other, higher
cost and more complex measures.
Office Equipment, which is the second largest portion of this sector’s achievable potential
(11%)
Water heating and Ventilation each provides 6% of the total savings
Figure 4-6 C&I Cumulative Achievable Potential Cumulative Savings by End Use in 2018
(percentage of total)
Note: Excludes rate class 25P.

Cooling
2%
Space Heating
1%Ventilation
6%
Water Heating
6%
Food Preparation
1%
Refrigeration
5%
Interior Lighting
57%
Exterior Lighting
7%
Office Equipment
11%
Machine Drive
2%
Process
2%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 867 of 1125
Conservation Potential
EnerNOC Utility Solutions Consulting 4-19
C&I Potential by Market Segment
Table 4-13 shows potential estimates by segment in 2018. The large commercial segment has
the largest achievable conservation potential of 201,247 MWh, roughly 58% of the overall
commercial achievable potential. The small/medium segment follows with a large gap at 64,655
MWh.
Table 4-13 C&I Cumulative Potential by Market Segment, 2018
Energy Savings (MWh)
Achievable
Potential
Economic
Potential
Technical
Potential
Small/Med. Commercial 34,044 64,655 174,575
Large Commercial 101,745 201,247 529,133
Extra Large Commercial 16,950 31,634 79,582
Extra Large Industrial 24,224 36,850 117,403
Total 176,964 334,386 900,694
Note: Excludes rate class 25P.

Figure 4-7 presents the achievable potential in 2018 by end use and building type. Lighting
measures are key measure across all buildings.
Table 4-14 C&I Cumulative Achievable Savings in 2018 by End Use and Rate Class(MWh)
End Use Small/Medium
Commercial
Large
Commercial
Extra Large
Commercial
Extra Large
Industrial Total
Cooling 835 1,305 665 1,368 4,173
Space Heating 717 163 296 627 1,803
Ventilation 1,740 1,124 1,165 6,031 10,061
Water Heating 1,990 7,772 1,016 - 10,777
Interior Lighting 20,429 61,213 9,566 8,702 99,910
Exterior Lighting 2,967 7,669 1,276 318 12,231
Refrigeration 2,211 6,457 578 - 9,246
Food Preparation 220 639 975 - 1,833
Office Equipment 2,928 15,379 1,411 - 19,718
Miscellaneous 8 24 2 5 40
Process - - - 3,835 3,835
Machine Drive - - - 3,337 3,337
Total 34,044 101,745 16,950 24,224 176,964
Note: Excludes rate class 25P.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 868 of 1125
Conservation Potential
4-20 www.enernoc.com
Figure 4-7 C&I Cumulative Achievable Savings in 2018 by End Use and Building Type

Note: Excludes rate class 25P.

Sensitivity of Potential to Avoided Cost
Similar to the 2011 CPA, EnerNOC modeled several scenarios with varying levels of avoided costs
in addition to the reference case. For this study’s purposes, we have included a case where the
10% adder per NW Power and Conservation Act is removed. The other scenarios included 150%,
125%, and 75% of the avoided costs used in the reference case. Figure 4-8 and Table 4-15 show
how achievable potential varies under the four scenarios.
The reference case achievable potential reaches approximately at 1,352,291 MWh by 2033.
Removing the 10% adder from the avoided costs decreased this achievable potential to
1,272,206 MWh, 6% reduction.
With the 150% avoided cost case, achievable potential increased to 1,657,741 MWh while
the 125% avoided cost case and the 75% avoided cost case yielded achievable potential
equal to 1,521,856 and 1,146,105 MWh respectively.
While the changes are significant, the relationship between avoided cost and achievable potential
is not linear and increases in avoided costs do not provide equivalent percentage increases in
achievable potential. Technical potential imposes a limit on the amount of additional conservation
and each incremental unit of DSM becomes increasingly expensive.
0
20,000
40,000
60,000
80,000
100,000
120,000
Small/Medium
Commercial
Large Commercial Extra Large
Commercial
Extra Large
Industrial
Ac
h
i
e
v
a
b
l
e

P
o
t
e
n
t
i
a
l

S
a
v
i
n
g
s

(

M
W
h
)
Cooling
Space Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
Machine Drive
Process
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 869 of 1125
Conservation Potential
EnerNOC Utility Solutions Consulting 4-21
Figure 4-8 Energy Savings, Cumulative Achievable Potential by Avoided Costs Scenario (MWh)

Note: Excludes pumping and rate class 25P.

Table 4-15 Achievable Potential with Varying Avoided Costs
End Use Reference
Scenario
Remove
10% adder
75% of
avoided
costs
125% of
avoided
costs
150% of
avoided
costs
Achievable potential savings
2033 (MWh) 1,352,291 1,272,206 1,146,105 1,521,856 1,657,741
Percentage change in savings vs.
100% avoided cost Scenario -6% -15% 13% 23%
Note: Excludes pumping and rate class 25P.

Electricity to Natural Gas Fuel Switching
While fuel efficiency is not considered in the NPCC Sixth Plan, Avista has a history of fuel
switching from electricity to natural gas and continues to target direct use as the most efficient
resource option when available. The conservation potential modeled above includes savings
potential attributable to conversion of electric space and water heating to natural gas. Table 4-16
displays savings potential from converting electric furnaces and water heaters to natural gas.
Within LoadMAP, we modeled savings for these measures in the residential sector only, but
because we calibrated the level of expected conversions to Avista’s recent program history that
includes small commercial building conversions as well, this potential may reflect a small
percentage of commercial section conversions. Because conversions remove most of the
electricity use from two of the largest residential end uses (water and space heating), it accounts
for 8.3% of combined residential, commercial and industrial savings by 2033. For water heating,
about one-fifth of the savings from gas conversions occurs in new construction. For furnaces,
new construction accounts for roughly 27% of the total.

-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
1,800,000
2,000,000
Cu
m
u
l
a
t
i
v
e

S
a
v
i
n
g
s

(
M
W
h
)
100% of reference case avoided costs
150% of avoided costs
125% of avoided costs
Reference case without 10% adder
75% of avoided costs
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 870 of 1125
Conservation Potential
4-22 www.enernoc.com
Table 4-16 Cumulative Achievable Potential from Conversion to Natural Gas (MWh)
2014 2015 2018 2023 2028 2033
Washington Cumulative Savings (MWh)
Furnace Conversions 2,322 5,047 12,715 25,105 41,493 55,787
Water Heating Conversions 825 1,586 4,112 9,924 14,362 20,221
Total Conversions 3,148 6,633 16,827 35,028 55,855 76,009
Idaho Cumulative Savings (MWh)
Furnace Conversions 837 1,792 4,460 8,698 14,544 19,598
Water Heating Conversions 47 121 602 4,264 10,085 16,451
Total Conversions 884 1,913 5,062 12,961 24,629 36,049
Total Washington and Idaho Cumulative Savings (MWh)
Furnace Conversions 3,159 6,839 17,175 33,802 56,037 75,385
Water Heating Conversions 873 1,707 4,714 14,187 24,447 36,673
Total Conversions 4,032 8,546 21,889 47,990 80,484 112,058

Supply Curves
The project also developed supply curves for each year to support the IRP process. At Avista’s
request, the supply curves did not consider economic screening based on Avista’s avoided costs.
Instead, all measures were included and the amount of savings from each measure in each year
was limited by the ramp rates used for achievable potential. The supply curves do not include
the savings from electricity to natural gas fuel switching, discussed above.
A sample supply curve for one year is shown in Figure 4-9. This supply curve is created by
stacking measures and equipment over the 20-year planning horizon in ascending order of cost.
As expected, this stacking of conservation resources produces a traditional upward-sloping
supply curve. Because there is a gap in the cost of the energy efficiency measures as you move
up the supply curve, the measures with a very high cost cause a rapid sloping of the supply
curve. The supply curve also shows that substantial savings are available at low- or no-cost.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 871 of 1125
Conservation Potential
EnerNOC Utility Solutions Consulting 4-23
Figure 4-9 Supply Curves for Evaluated EE Measures and Avoided Cost Scenarios
Note: Excludes pumping and rate class 25P.

Pumping Potential
Table 4-18 displays the 2009 electricity sales and peak demand of Avista’s pumping customers.
These customers include mostly municipal water systems and some irrigation customers. The
pumping accounts represent 2.4% of total electricity sales and 0.8% of peak demand (see Table
3-1 and Table 3-2). Because pumping represents a relatively small percentage of Avista’s total
sales, the project team decided to estimate achievable potential for pumping based on the Sixth
Plan calculator agriculture sector, option 3.9
Table 4-17 Pumping Rate Classes, Electricity Sales and Peak Demand 2009
Sector Rate Schedule (s) Number of meters
(customers)
2009 Electricity
Sales (MWh)
Peak demand
(MW)
Pumping, Washington 031, 032 2,361 135,999 10
Pumping, Idaho 031, 032 1,312 58,885 4
Pumping, Total 3,673 194,884 14
Percentage of System Total 2.4% 0.8%

The Sixth Plan Calculator estimates agricultural conservation targets based on 2007 sales. It
provides annual conservation targets through 2019. Table 4-18 displays incremental annual
savings potential for 2014–2019.

9 Available on the NWPCC website at http://www.nwcouncil.org/energy/powerplan/6/assessmentmethodology/.
$-
$0.10
$0.20
$0.30
$0.40
$0.50
$0.60
$0.70
$0.80
$0.90
$1.00
-100 200 300 400 500 600 700 800
Co
s
t

o
f

Co
n
s
e
v
e
d
En
e
r
g
y

(
2
0
0
9
$
/
k
W
h
)
Cumulative Savings 2020 (GWh)
Cost/kWh
Avoided Cost ($0.0489kWh)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 872 of 1125
Conservation Potential
4-24 www.enernoc.com
Table 4-18 Sixth Plan Calculator Agriculture Incremental Annual Potential, 2014–2019 (MWh)
Segment 2014 2015 2016 2017 2018 2019
Pumping, Washington 1,402 1,835 1,856 1,835 1,814 1,794
Pumping, Idaho 618 809 818 809 799 790
Pumping, Total 2,020 2,643 2,673 2,643 2,614 2,584
Washington Potential Excluding Conversions to Natural Gas
Based on the modeling described above, Washington potential consistent with the NPCC
Conservation Plan methodology is as shown in Table 4-19.
Table 4-19 Washington Cumulative Potential Consistent with Conservation Plan Methodology
2014 2015 2018 2023
Cumulative Savings (MWh)
Residential 15,091 29,603 100,792 172,576
Commercial and Industrial 19,927 40,930 123,755 256,653
Pumping 1,402 3,237 8,742 0
Conversions to Natural Gas (3,148) (6,633) (16,827) (35,028)
Total 33,272 67,137 216,462 394,200
Cumulative Savings (aMW)
Residential 1.72 3.38 11.51 19.70
Commercial and Industrial 2.27 4.67 14.13 29.30
Pumping 0.16 0.37 1.00 0.00
Conversions to Natural Gas (0.36) (0.76) (1.92) (4.00)
Total 3.80 7.66 24.71 45.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 873 of 1125

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 874 of 1125

EnerNOC Utility Solutions Consulting
500 Ygnacio Valley Road, Suite 450 Walnut Creek, CA 94596
P: 925.482.2000 F: 925.284.3147
About EnerNOC
EnerNOC’s Utility Solutions Consulting team is part of EnerNOC’s Utility Solutions,
which provides a comprehensive suite of demand-side management (DSM)
services to utilities and grid operators worldwide. Hundreds of utilities have
leveraged our technology, our people, and our proven processes to make their
energy efficiency (EE) and demand response (DR) initiatives a success. Utilities
trust EnerNOC to work with them at every stage of the DSM program lifecycle –
assessing market potential, designing effective programs, implementing those
programs, and measuring program results.
EnerNOC’s Utility Solutions deliver value to our utility clients through two
separate practice areas – Implementation and Consulting.
• Our Implementation team leverages EnerNOC’s deep ―behind-the-meter
expertise‖ and world-class technology platform to help utilities create and
manage DR and EE programs that deliver reliable and cost-effective energy
savings. We focus exclusively on the commercial and industrial (C&I)
customer segments, with a track record of successful partnerships that
spans more than a decade. Through a focus on high quality, measurable
savings, EnerNOC has successfully delivered hundreds of thousands of MWh
of energy efficiency for our utility clients, and we have thousands of MW of
demand response capacity under management.
• The Consulting team provides expertise and analysis to support a broad
range of utility DSM activities, including: potential assessments; end-use
forecasts; integrated resource planning; EE, DR, and smart grid pilot and
program design and administration; load research; technology assessments
and demonstrations; evaluation, measurement and verification; and
regulatory support.
The team has decades of combined experience in the utility DSM industry. The
staff is comprised of professional electrical, mechanical, chemical, civil, industrial,
and environmental engineers as well as economists, business planners, project
managers, market researchers, load research professionals, and statisticians.
Utilities view EnerNOC’s experts as trusted advisors, and we work together
collaboratively to make any DSM initiative a success.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 875 of 1125

Avista Electric Conservation Potential
Assessment Study

Appendices

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 876 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 877 of 1125

EnerNOC Utility Solutions Consulting iii

This report was prepared by
EnerNOC Utility Solutions Consulting
500 Ygnacio Valley Blvd., Suite 450
Walnut Creek, CA 94596

Project Director: I. Rohmund
Project Manager: J. Borstein

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 878 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 879 of 1125

EnerNOC Utility Solutions Consulting v
CONTENTS
A MARKET PROFILES ............................................................................................... A-1
B RESIDENTIAL ENERGY EFFICIENCY EQUIPMENT AND MEASURE DATA .............. B-1
C C&I ENERGY EFFICIENCY EQUIPMENT AND MEASURE DATA .............................. C-1
D MARKET ADOPTION FACTORS .............................................................................. D-1
E ANNUAL SAVINGS ................................................................................................. E-1

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 880 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 881 of 1125

EnerNOC Utility Solutions Consulting vii
CONTENTS

LIST OF TABLES
Table A-1 Single Family Electric Market Profile, Washington 2009 .......................................... A-2
Table A-2 Multi Family Electric Market Profile, Washington 2009 ............................................ A-3
Table A-3 Mobile Home Electric Market Profile, Washington 2009 .......................................... A-4
Table A-4 Low Income Electric Market Profile, Washington 2009 ............................................ A-5
Table A-5 Single Family Electric Market Profile, Idaho 2009 ................................................... A-6
Table A-6 Multi Family Electric Market Profile, Idaho 2009 ..................................................... A-7
Table A-7 Mobile Home Electric Market Profile, Idaho 2009 ................................................... A-8
Table A-8 Low income Electric Market Profile, Idaho 2009 ..................................................... A-9
Table A-9 Small/Medium Commercial Electric Market Profile, Washington 2009 ...................... A-10
Table A-10 Large Commercial Electric Market Profile, Washington 2009 .................................. A-11
Table A-11 Extra Large Commercial Electric Market Profile, Washington 2009 .......................... A-12
Table A-12 Extra Large Industrial Electric Market Profile, Washington 2009 ............................. A-13
Table A-13 Small/Medium Commercial Electric Market Profile, Idaho 2009............................... A-14
Table A-14 Large Commercial Electric Market Profile, Idaho 2009 ........................................... A-15
Table A-15 Extra Large Commercial Electric Market Profile, Idaho 2009 .................................. A-16
Table A-16 Extra Large Industrial Electric Market Profile, Idaho 2009 ...................................... A-17
Table B-1 Residential Energy Efficiency Equipment Measure Descriptions ................................B-2
Table B-2 Residential Energy Efficiency Non-Equipment Measure Descriptions .........................B-6
Table B-3 Energy Efficiency Equipment Data, Electric—Single Family, Existing Vintage,
Washington ........................................................................................................ B-10
Table B-4 Energy Efficiency Equipment Data, Electric—Single Family, New Vintage, WashingtonB-13
Table B-5 Energy Efficiency Equipment Data, Electric—Single Family, Existing Vintage, Idaho B-16
Table B-6 Energy Efficiency Equipment Data, Electric—Single Family, New Vintage, Idaho ..... B-19
Table B-7 Energy Efficiency Equipment Data, Electric—Multi Family, Existing Vintage, WashingtonB-22
Table B-8 Energy EfficiencyEquipment Data, Electric—Multi Family, New Vintage, Washington B-25
Table B-9 Energy Efficiency Equipment Data, Electric—Multi Family, Existing Vintage, Idaho .. B-28
Table B-10 Energy Efficiency Equipment Data, Electric—Multi Family, New Vintage, Idaho ....... B-31
Table B-11 Energy Efficiency Equipment Data, Electric—Mobile Home, Existing Vintage,
Washington ........................................................................................................ B-34
Table B-12 Energy Efficiency Equipment Data, Electric—Mobile Home, New Vintage, WashingtonB-37
Table B-13 Energy Efficiency Equipment Data, Electric—Mobile Home, Existing Vintage, Idaho . B-40
Table B-14 Energy Efficiency Equipment Data, Electric—Mobile Home, New Vintage, Idaho ...... B-43
Table B-15 Energy Efficiency Equipment Data, Electric—Low income, Existing Vintage, WashingtonB-46
Table B-16 Energy Efficiency Equipment Data, Electric—Low Income, New Vintage, WashingtonB-49
Table B-17 Energy Efficiency Equipment Data, Electric—Low Income, Existing Vintage, Idaho .. B-52
Table B-18 Energy Efficiency Equipment Data, Electric—Low income, New Vintage, Idaho ....... B-55
Table B-19 Energy Efficiency Non-Equipment Data, Electric—Single Family, Existing Vintage,
Washington ........................................................................................................ B-58
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 882 of 1125

viii www.enernoc.com
Table B-20 Energy Efficiency Non-Equipment Data, Electric—Single Family, New Vintage,
Washington ........................................................................................................ B-59
Table B-21 Energy Efficiency Non-Equipment Data, Electric—Single Family, Existing Vintage, IdahoB-60
Table B-22 Energy Efficiency Non-Equipment Data, Electric—Single Family, New Vintage, IdahoB-61
Table B-23 Energy Efficiency Non-Equipment Data, Electric—Multi Family, Existing Vintage,
Washington ........................................................................................................ B-62
Table B-24 Energy Efficiency Non-Equipment Data, Electric—Multi Family, New Vintage,
Washington ........................................................................................................ B-63
Table B-25 Energy Efficiency Non-Equipment Data, Electric—Multi Family, Existing Vintage, IdahoB-64
Table B-26 Energy Efficiency Non-Equipment Data, Electric—Multi Family, New Vintage, Idaho B-65
Table B-27 Energy Efficiency Non-Equipment Data, Electric—Mobile Home, Existing Vintage,
Washington ........................................................................................................ B-66
Table B-28 Energy Efficiency Non-Equipment Data, Electric—Mobile Home, New Vintage,
Washington ........................................................................................................ B-67
Table B-29 Energy Efficiency Non-Equipment Data, Electric—Mobile Home, Existing Vintage, IdahoB-68
Table B-30 Energy Efficiency Non-Equipment Data, Electric—Mobile Home, New Vintage, IdahoB-69
Table B-31 Energy Efficiency Non-Equipment Data, Electric—Low income, Existing Vintage,
Washington ........................................................................................................ B-70
Table B-32 Energy Efficiency Non-Equipment Data, Electric—Low income, New Vintage,
Washington ........................................................................................................ B-71
Table B-33 Energy Efficiency Non-Equipment Data, Electric—Low income, Existing Vintage, IdahoB-72
Table B-34 Energy Efficiency Non-Equipment Data, Electric—Low income, New Vintage, Idaho B-73
Table C-1 C&I Energy Efficiency Equipment Measure Descriptions .......................................... C-2
Table C-2 Commercial and Industrial Energy Efficiency Non-Equipment Measure Descriptions . C-5
Table C-3 Energy Efficiency Equipment Data, Electric—Small/Medium Commercial, Existing
Vintage, Washington ........................................................................................... C-11
Table C-4 Energy Efficiency Equipment Data, Electric—Small/Medium Commercial, New Vintage,
Washington ........................................................................................................ C-14
Table C-5 Energy Efficiency Equipment Data, Small/Medium Commercial, Existing Vintage, IdahoC-17
Table C-6 Energy Efficiency Equipment Data, Electric— Small/Medium Commercial, New Vintage,
Idaho ................................................................................................................. C-20
Table C-7 Energy Efficiency Equipment Data, Electric—Large Commercial, Existing Vintage,
Washington ........................................................................................................ C-23
Table C-8 Energy Efficiency Equipment Data, Electric— Large Commercial, New Vintage,
Washington ........................................................................................................ C-26
Table C-9 Energy Efficiency Equipment Data, Electric—Large Commercial, Existing Vintage, IdahoC-29
Table C-10 Energy Efficiency Equipment Data, Electric— Large Commercial, New Vintage, IdahoC-32
Table C-11 Energy Efficiency Equipment Data, Electric—Extra Large Commercial, Existing Vintage,
Washington ........................................................................................................ C-35
Table C-12 Energy Efficiency Equipment Data, Electric— Extra Large Commercial, New Vintage,
Washington ........................................................................................................ C-38
Table C-13 Energy Efficiency Equipment Data, Electric—Extra Large Commercial, Existing Vintage,
Idaho ................................................................................................................. C-41
Table C-14 Energy Efficiency Equipment Data, Electric— Extra Large Commercial, New Vintage,
Idaho ................................................................................................................. C-44
Table C-15 Energy Efficiency Equipment Data, Electric—Extra Large Industrial, Existing Vintage,
Washington ........................................................................................................ C-47
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 883 of 1125

EnerNOC Utility Solutions Consulting ix
Table C-16 Energy Efficiency Equipment Data, Electric— Extra Large Industrial, New Vintage,
Washington ........................................................................................................ C-50
Table C-17 Energy Efficiency Equipment Data, Electric—Extra Large Industrial, Existing Vintage,
Idaho ................................................................................................................. C-53
Table C-18 Energy Efficiency Equipment Data, Electric— Extra Large Industrial, New Vintage,
Idaho ................................................................................................................. C-56
Table C-19 Energy Efficiency Non-Equipment Data—Small/Medium Commercial, Existing Vintage,
Washington ........................................................................................................ C-59
Table C-20 Energy Efficiency Non-Equipment Data— Small/ Medium Commercial, New Vintage,
Washington ........................................................................................................ C-61
Table C-21 Energy Efficiency Non-Equipment Data— Small/Medium Commercial, Existing Vintage,
Idaho ................................................................................................................. C-63
Table C-22 Energy Efficiency Non-Equipment Data— Small/ Medium Commercial, New Vintage,
Idaho ................................................................................................................. C-65
Table C-23 Energy Efficiency Non-Equipment Data— Large Commercial, Existing Vintage,
Washington ........................................................................................................ C-67
Table C-24 Energy Efficiency Non-Equipment Data— Large Commercial, New Vintage, WashingtonC-69
Table C-25 Energy Efficiency Non-Equipment Data— Large Commercial, Existing Vintage, IdahoC-71
Table C-26 Energy Efficiency Non-Equipment Data— Large Commercial, New Vintage, Idaho ... C-73
Table C-27 Energy Efficiency Non-Equipment Data— Extra Large Commercial, Existing Vintage,
Washington ........................................................................................................ C-75
Table C-28 Energy Efficiency Non-Equipment Data— Extra Large Commercial, New Vintage,
Washington ........................................................................................................ C-77
Table C-29 Energy Efficiency Non-Equipment Data— Extra Large Commercial, Existing Vintage,
Idaho ................................................................................................................. C-79
Table C-30 Energy Efficiency Non-Equipment Data— Extra Large Commercial, New Vintage, IdahoC-81
Table C-31 Energy Efficiency Non-Equipment Data— Extra Large Industrial, Existing Vintage,
Washington ........................................................................................................ C-83
Table C-32 Energy Efficiency Non-Equipment Data— Extra Large Industrial, New Vintage,
Washington ........................................................................................................ C-85
Table C-33 Energy Efficiency Non-Equipment Data— Extra Large Industrial, Existing Vintage, IdahoC-87
Table C-34 Energy Efficiency Non-Equipment Data— Extra Large Industrial, New Vintage, IdahoC-89
Table D-1 Residential Equipment Measures—Achievable Potential Market Adoption Factors ..... D-2
Table D-2 Residential Non-Equipment Measures— Achievable Potential Market Adoption FactorsD-3
Table D-3 C/I Equipment Measures — Achievable Potential Market Adoption Factors ............... D-4
Table D-4 C/I Non-Equipment Measures — Achievable Potential Market Adoption Factors ........ D-6
Table E-1 Annual Electric Energy Savings, All Sectors (1,000 MWh) ........................................ E-1
Table E-2 Annual Electric Energy Savings, All Sectors (1,000 MWh) (continued) ...................... E-2
Table E-3 Annual Electric Energy Savings, Residential (1,000 MWh) ........................................ E-3
Table E-4 Annual Electric Energy Savings, Residential (1,000 MWh) (continued) ...................... E-4
Table E-5 Annual Electric Energy Savings, C/I (1,000 MWh) ................................................... E-5
Table E-6 Annual Electric Energy Savings, C/I (1,000 MWh) (continued) ................................. E-6

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 884 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 885 of 1125

EnerNOC Utility Solutions Consulting A-1
APPENDIX A
MARKET PROFILES
Market profiles describe electricity use by sector, segment, end use and technology in the base
year of the study (2009). The market profiles are given for average buildings and new vintages.
As explained in Chapter 2 of the Avista Conservation Potential Assessment (CPA) report , a
market profile includes the following elements:
Market size is a representation of the number of customers in the segment. For the
residential sector, it is number of households. In the commercial and industrial sector, it
is floor space measured in square feet.
Saturations define the fraction of buildings with the specific technologies. (e.g., homes
with electric space heating).
UEC (unit energy consumption) or EUI (energy-use index) describes the amount
of energy consumed in the base year by a specific technology in buildings that have the
technology. We use UECs expressed in kWh/household for the residential sector, and
EUIs expressed in kWh/square foot for the commercial and industrial sectors.
Intensity for the residential sector represents the average energy use for the
technology across all households in the base year. It is computed as the product of the
saturation and the UEC and is defined as kWh/household for electricity. For the
commercial and industrial sector, intensity, computed as the product of the saturation
and the EUI, represents the average use for the technology across all floor space.
Usage is the annual energy use by a technology/end use in the segment. It is the
product of the market size and intensity and is quantified in GWh for electricity.
This appendix presents the following market profiles:
Residential market profiles by housing type and state (Table A-1 through Table A-8)
C&I by rate class and state (Table A-9 through Table A-16)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 886 of 1125
Market Profiles
A-2 www.enernoc.com
Table A-1 Single Family Electric Market Profile, Washington 2009
Average Market Profile New Units
End Use Technology Saturation UEC
(kWh)
Intensity
(kWh/HH)
Usage
(GWh) Saturation UEC
(kWh)
Intensity
(kWh/HH)
Compared to
Average
Cooling Central AC 36.8% 1,393 513 56 66.1% 1,601 1,058 15.0%
Cooling Room AC 10.8% 512 55 6 8.7% 589 51 15.0%
Cooling Air Source Heat Pump 22.2% 833 185 20 23.3% 958 223 15.0%
Cooling Geothermal Heat Pump 0.4% 730 3 0 0.4% 840 4 15.0%
Cooling Ductless HP 0.0% 456 - - 0.0% 524 - 15.0%
Space Heating Electric Resistance 7.7% 10,302 792 86 3.8% 11,847 455 15.0%
Space Heating Electric Furnace 9.8% 11,757 1,157 126 8.9% 13,521 1,198 15.0%
Space Heating Supplemental 3.3% 117 4 0 3.3% 134 4 15.0%
Space Heating Air Source Heat Pump 22.2% 8,561 1,903 208 22.2% 9,845 2,188 15.0%
Space Heating Geothermal Heat Pump 0.4% 4,833 20 2 0.4% 5,558 23 15.0%
Space Heating Ductless HP 0.0% 4,000 - - 0.0% 4,600 - 15.0%
Water Heating Water Heater <= 55 Gal 53.2% 4,031 2,143 234 48.6% 3,684 1,790 -8.6%
Water Heating Water Heater > 55 Gal 5.6% 4,552 257 28 5.2% 4,157 214 -8.7%
Interior Lighting Screw-in 100.0% 1,295 1,295 141 100.0% 1,425 1,425 10.0%
Interior Lighting Linear Fluorescent 100.0% 128 128 14 100.0% 141 141 10.0%
Interior Lighting Specialty 100.0% 356 356 39 100.0% 409 409 15.0%
Exterior Lighting Screw-in 100.0% 363 363 40 100.0% 400 400 10.0%
Appliances Clothes Washer 98.0% 126 124 13 99.8% 95 94 -25.0%
Appliances Clothes Dryer 92.8% 549 509 56 97.4% 466 454 -15.0%
Appliances Dishwasher 93.9% 434 407 44 98.6% 369 364 -15.0%
Appliances Refrigerator 100.0% 793 793 87 100.0% 539 539 -32.0%
Appliances Freezer 59.9% 881 528 58 69.4% 554 384 -37.1%
Appliances Second Refrigerator 31.3% 1,083 339 37 31.3% 693 217 -36.0%
Appliances Stove 85.1% 443 377 41 82.1% 443 364 0.0%
Appliances Microwave 98.5% 130 128 14 98.5% 134 132 3.0%
Electronics Personal Computers 140.0% 227 317 35 154.0% 227 349 0.0%
Electronics TVs 234.0% 240 562 61 245.7% 240 590 0.0%
Electronics Set-top boxes/DVR 171.7% 136 234 26 188.8% 136 257 0.0%
Electronics Devices and Gadgets 100.0% 60 60 7 105.0% 67 70 10.0%
Miscellaneous Pool Pump 5.0% 1,500 75 8 5.3% 1,526 80 1.7%
Miscellaneous Furnace Fan 59.4% 622 370 40 62.4% 622 388 0.0%
Miscellaneous Miscellaneous 100.0% 549 549 60 100.0% 604 604 10.0%
Total 14,547 1,588 14,471 -0.5%

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 887 of 1125
Market Profiles
EnerNOC Utility Solutions Consulting A-3
Table A-2 Multi Family Electric Market Profile, Washington 2009
Average Market Profile New Units
End Use Technology Saturation UEC
(kWh)
Intensity
(kWh/HH)
Usage
(GWh) Saturation UEC
(kWh)
Intensity
(kWh/HH)
Compared to
Average
Cooling Central AC 5.0% 464 23 0 15.0% 534 80 15.0%
Cooling Room AC 25.0% 355 89 2 18.9% 409 77 15.0%
Cooling Air Source Heat Pump 1.0% 429 4 0 1.1% 493 5 15.0%
Cooling Geothermal Heat Pump 0.0% 444 - - 0.2% 511 1 15.0%
Cooling Ductless HP 0.0% 229 - - 0.0% 263 - 15.0%
Space Heating Electric Resistance 59.0% 5,180 3,056 56 47.2% 5,957 2,812 15.0%
Space Heating Electric Furnace 5.0% 5,162 258 5 6.0% 5,936 356 15.0%
Space Heating Supplemental 18.0% 61 11 0 18.0% 70 13 15.0%
Space Heating Air Source Heat Pump 1.0% 3,220 32 1 1.0% 3,703 37 15.0%
Space Heating Geothermal Heat Pump 0.0% 2,898 - - 0.0% 3,333 - 15.0%
Space Heating Ductless HP 0.0% 2,011 - - 0.0% 2,313 - 15.0%
Water Heating Water Heater <= 55 Gal 77.0% 2,142 1,650 30 75.0% 1,958 1,469 -8.6%
Water Heating Water Heater > 55 Gal 0.0% 3,142 - - 0.0% 2,870 - -8.7%
Interior Lighting Screw-in 100.0% 784 784 14 100.0% 863 863 10.0%
Interior Lighting Linear Fluorescent 100.0% 89 89 2 100.0% 98 98 10.0%
Interior Lighting Specialty 100.0% 143 143 3 100.0% 164 164 15.0%
Exterior Lighting Screw-in 100.0% 21 21 0 100.0% 23 23 10.0%
Appliances Clothes Washer 32.0% 101 32 1 48.0% 76 36 -25.0%
Appliances Clothes Dryer 30.7% 439 135 2 46.1% 373 172 -15.0%
Appliances Dishwasher 64.0% 347 222 4 96.0% 295 283 -15.0%
Appliances Refrigerator 100.0% 634 634 12 100.0% 431 431 -32.0%
Appliances Freezer 8.4% 705 59 1 8.9% 443 39 -37.1%
Appliances Second Refrigerator 5.0% 866 43 1 5.0% 554 28 -36.0%
Appliances Stove 96.4% 354 342 6 96.4% 354 342 0.0%
Appliances Microwave 90.0% 104 94 2 90.0% 107 96 3.0%
Electronics Personal Computers 63.0% 181 114 2 69.3% 181 126 0.0%
Electronics TVs 165.0% 216 357 7 173.3% 216 375 0.0%
Electronics Set-top boxes/DVR 154.5% 136 211 4 170.0% 136 232 0.0%
Electronics Devices and Gadgets 100.0% 54 54 1 105.0% 60 63 10.0%
Miscellaneous Pool Pump 0.0% 1,500 - - 0.0% 1,526 - 1.7%
Miscellaneous Furnace Fan 13.0% 498 65 1 13.7% 498 68 0.0%
Miscellaneous Miscellaneous 100.0% 206 206 4 100.0% 226 226 10.0%
Total 8,728 159 8,514 -2.5%

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 888 of 1125
Market Profiles
A-4 www.enernoc.com
Table A-3 Mobile Home Electric Market Profile, Washington 2009
Average Market Profile New Units
End Use Technology Saturation UEC
(kWh)
Intensity
(kWh/HH)
Usage
(GWh) Saturation UEC
(kWh)
Intensity
(kWh/HH)
Compared to
Average
Cooling Central AC 23.2% 553 128 1 39.4% 594 234 7.5%
Cooling Room AC 23.2% 305 71 0 22.0% 328 72 7.5%
Cooling Air Source Heat Pump 21.7% 361 79 0 22.8% 388 89 7.5%
Cooling Geothermal Heat Pump 0.0% 325 - - 0.0% 349 - 7.5%
Cooling Ductless HP 0.0% 302 - - 0.0% 324 - 7.5%
Space Heating Electric Resistance 1.2% 6,823 81 0 1.1% 7,335 83 7.5%
Space Heating Electric Furnace 57.6% 7,321 4,214 22 57.6% 7,870 4,530 7.5%
Space Heating Supplemental 1.4% 3,780 54 0 1.5% 4,064 61 7.5%
Space Heating Air Source Heat Pump 21.7% 4,667 1,015 5 22.8% 5,017 1,146 7.5%
Space Heating Geothermal Heat Pump 0.0% 4,200 - - 0.2% 4,515 9 7.5%
Space Heating Ductless HP 0.0% 2,649 - - 0.0% 2,848 - 7.5%
Water Heating Water Heater <= 55 Gal 75.6% 2,620 1,980 10 75.6% 2,508 1,895 -4.3%
Water Heating Water Heater > 55 Gal 0.0% 2,959 - - 0.0% 2,831 - -4.3%
Interior Lighting Screw-in 100.0% 1,010 1,010 5 100.0% 1,061 1,061 5.0%
Interior Lighting Linear Fluorescent 100.0% 100 100 1 100.0% 105 105 5.0%
Interior Lighting Specialty 100.0% 278 278 1 100.0% 298 298 7.5%
Exterior Lighting Screw-in 100.0% 283 283 1 100.0% 298 298 5.0%
Appliances Clothes Washer 86.7% 98 85 0 86.7% 86 75 -12.5%
Appliances Clothes Dryer 88.9% 428 380 2 88.9% 396 352 -7.5%
Appliances Dishwasher 80.1% 338 271 1 84.1% 313 263 -7.5%
Appliances Refrigerator 100.0% 618 618 3 100.0% 520 520 -16.0%
Appliances Freezer 53.3% 687 366 2 53.3% 559 298 -18.6%
Appliances Second Refrigerator 17.6% 845 148 1 17.6% 693 122 -18.0%
Appliances Stove 84.5% 345 292 2 84.5% 345 292 0.0%
Appliances Microwave 93.6% 101 95 0 93.6% 103 96 1.5%
Electronics Personal Computers 104.8% 193 202 1 110.1% 193 212 0.0%
Electronics TVs 234.0% 204 478 3 234.0% 204 478 0.0%
Electronics Set-top boxes/DVR 154.5% 116 179 1 170.0% 116 197 0.0%
Electronics Devices and Gadgets 100.0% 51 51 0 100.0% 54 54 5.0%
Miscellaneous Pool Pump 5.6% 1,125 63 0 5.8% 1,135 66 0.8%
Miscellaneous Furnace Fan 63.3% 467 296 2 63.3% 467 296 0.0%
Miscellaneous Miscellaneous 100.0% 274 274 1 100.0% 288 288 5.0%
Total 13,092 69 13,488 3.0%

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 889 of 1125
Market Profiles
EnerNOC Utility Solutions Consulting A-5
Table A-4 Low Income Electric Market Profile, Washington 2009
Average Market Profile New Units
End Use Technology Saturation UEC
(kWh)
Intensity
(kWh/HH)
Usage
(GWh) Saturation UEC
(kWh)
Intensity
(kWh/HH)
Compared to
Average
Cooling Central AC 22.2% 591 131 9 28.7% 635 182 7.5%
Cooling Room AC 35.4% 289 102 7 18.0% 311 56 7.5%
Cooling Air Source Heat Pump 10.4% 467 49 3 10.4% 502 52 7.5%
Cooling Geothermal Heat Pump 0.0% 437 - - 0.5% 470 2 7.5%
Cooling Ductless HP 0.0% 262 - - 0.0% 281 - 7.5%
Space Heating Electric Resistance 32.0% 5,914 1,891 128 28.8% 6,358 1,830 7.5%
Space Heating Electric Furnace 9.9% 6,413 637 43 8.9% 6,894 614 7.5%
Space Heating Supplemental 12.7% 364 46 3 13.4% 392 52 7.5%
Space Heating Air Source Heat Pump 10.4% 4,401 459 31 10.4% 4,731 493 7.5%
Space Heating Geothermal Heat Pump 0.0% 3,042 - - 0.0% 3,270 - 7.5%
Space Heating Ductless HP 0.0% 2,296 - - 0.0% 2,468 - 7.5%
Water Heating Water Heater <= 55 Gal 83.9% 2,357 1,977 133 83.9% 2,255 1,892 -4.3%
Water Heating Water Heater > 55 Gal 0.0% 2,950 - - 0.0% 2,822 - -4.3%
Interior Lighting Screw-in 100.0% 758 758 51 100.0% 796 796 5.0%
Interior Lighting Linear Fluorescent 100.0% 79 79 5 100.0% 83 83 5.0%
Interior Lighting Specialty 100.0% 181 181 12 100.0% 195 195 7.5%
Exterior Lighting Screw-in 100.0% 138 138 9 100.0% 145 145 5.0%
Appliances Clothes Washer 71.3% 89 63 4 78.4% 78 61 -12.5%
Appliances Clothes Dryer 68.6% 385 264 18 75.4% 356 269 -7.5%
Appliances Dishwasher 78.5% 305 239 16 86.3% 282 243 -7.5%
Appliances Refrigerator 100.0% 557 557 38 100.0% 468 468 -16.0%
Appliances Freezer 63.0% 619 390 26 63.0% 504 317 -18.6%
Appliances Second Refrigerator 23.4% 761 178 12 23.4% 624 146 -18.0%
Appliances Stove 89.7% 311 279 19 89.7% 311 279 0.0%
Appliances Microwave 92.6% 91 85 6 92.6% 93 86 1.5%
Electronics Personal Computers 101.4% 160 163 11 106.5% 160 171 0.0%
Electronics TVs 165.0% 180 297 20 165.0% 180 297 0.0%
Electronics Set-top boxes/DVR 128.8% 107 138 9 141.6% 107 152 0.0%
Electronics Devices and Gadgets 100.0% 45 45 3 105.0% 48 50 5.0%
Miscellaneous Pool Pump 2.3% 1,170 27 2 2.3% 1,180 27 0.8%
Miscellaneous Furnace Fan 25.2% 436 110 7 25.2% 436 110 0.0%
Miscellaneous Miscellaneous 100.0% 140 140 9 100.0% 147 147 5.0%
Total 9,424 636 9,215 -2.2%

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 890 of 1125
Market Profiles
A-6 www.enernoc.com
Table A-5 Single Family Electric Market Profile, Idaho 2009
Average Market Profile New Units
End Use Technology Saturation UEC
(kWh)
Intensity
(kWh/HH)
Usage
(GWh) Saturation UEC
(kWh)
Intensity
(kWh/HH)
Compared to
Average
Cooling Central AC 23.2% 1,253 291 17 66.1% 1,441 952 15.0%
Cooling Room AC 10.8% 461 50 3 8.7% 530 46 15.0%
Cooling Air Source Heat Pump 14.6% 750 109 6 15.3% 862 132 15.0%
Cooling Geothermal Heat Pump 1.2% 657 8 0 0.8% 756 6 15.0%
Cooling Ductless HP 0.0% 478 - - 0.0% 550 - 15.0%
Space Heating Electric Resistance 13.3% 10,817 1,436 85 6.6% 12,440 825 15.0%
Space Heating Electric Furnace 5.5% 12,345 679 40 4.9% 14,197 702 15.0%
Space Heating Supplemental 4.4% 111 5 0 4.4% 128 6 15.0%
Space Heating Air Source Heat Pump 14.6% 8,989 1,310 78 14.6% 10,338 1,506 15.0%
Space Heating Geothermal Heat Pump 1.2% 5,075 58 3 1.2% 5,836 67 15.0%
Space Heating Ductless HP 0.0% 4,200 - - 0.0% 4,830 - 15.0%
Water Heating Water Heater <= 55 Gal 46.4% 4,233 1,962 116 42.4% 3,869 1,639 -8.6%
Water Heating Water Heater > 55 Gal 5.6% 4,779 270 16 5.2% 4,365 225 -8.7%
Interior Lighting Screw-in 100.0% 1,360 1,360 81 100.0% 1,496 1,496 10.0%
Interior Lighting Linear Fluorescent 100.0% 134 134 8 100.0% 148 148 10.0%
Interior Lighting Specialty 100.0% 374 374 22 100.0% 430 430 15.0%
Exterior Lighting Screw-in 100.0% 381 381 23 100.0% 420 420 10.0%
Appliances Clothes Washer 98.0% 126 124 7 99.8% 95 94 -25.0%
Appliances Clothes Dryer 92.8% 549 509 30 97.4% 466 454 -15.0%
Appliances Dishwasher 93.9% 434 407 24 98.6% 369 364 -15.0%
Appliances Refrigerator 100.0% 793 793 47 100.0% 539 539 -32.0%
Appliances Freezer 59.8% 881 527 31 69.4% 554 384 -37.1%
Appliances Second Refrigerator 24.8% 1,083 269 16 24.8% 693 172 -36.0%
Appliances Stove 74.8% 443 331 20 82.1% 487 400 10.0%
Appliances Microwave 98.5% 130 128 8 98.5% 134 132 3.0%
Electronics Personal Computers 140.0% 227 317 19 154.0% 227 349 0.0%
Electronics TVs 231.0% 240 555 33 242.6% 240 583 0.0%
Electronics Set-top boxes/DVR 153.5% 136 209 12 168.9% 136 230 0.0%
Electronics Devices and Gadgets 100.0% 60 60 4 105.0% 67 70 10.0%
Miscellaneous Pool Pump 7.0% 1,500 105 6 7.4% 1,526 112 1.7%
Miscellaneous Furnace Fan 54.9% 654 359 21 57.7% 654 377 0.0%
Miscellaneous Miscellaneous 100.0% 584 584 35 100.0% 642 642 10.0%
Total 1,253 13,703 811 13,502 -1.5%

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 891 of 1125
Market Profiles
EnerNOC Utility Solutions Consulting A-7
Table A-6 Multi Family Electric Market Profile, Idaho 2009
Average Market Profile New Units
End Use Technology Saturation UEC
(kWh)
Intensity
(kWh/HH)
Usage
(GWh) Saturation UEC
(kWh)
Intensity
(kWh/HH)
Compared to
Average
Cooling Central AC 5.0% 395 20 0 15.0% 454 68 15.0%
Cooling Room AC 25.0% 302 75 0 18.9% 347 66 15.0%
Cooling Air Source Heat Pump 1.0% 365 4 0 1.1% 419 4 15.0%
Cooling Geothermal Heat Pump 0.0% 377 - - 0.2% 434 1 15.0%
Cooling Ductless HP 0.0% 215 - - 0.0% 248 - 15.0%
Space Heating Electric Resistance 59.0% 4,869 2,873 15 47.2% 5,599 2,643 15.0%
Space Heating Electric Furnace 5.0% 4,852 243 1 6.0% 5,580 335 15.0%
Space Heating Supplemental 18.0% 58 10 0 18.0% 66 12 15.0%
Space Heating Air Source Heat Pump 1.0% 3,027 30 0 1.0% 3,481 35 15.0%
Space Heating Geothermal Heat Pump 0.0% 2,724 - - 0.0% 3,133 - 15.0%
Space Heating Ductless HP 0.0% 1,890 - - 0.0% 2,174 - 15.0%
Water Heating Water Heater <= 55 Gal 77.0% 2,014 1,551 8 75.0% 1,841 1,380 -8.6%
Water Heating Water Heater > 55 Gal 0.0% 2,954 - - 0.0% 2,698 - -8.7%
Interior Lighting Screw-in 100.0% 737 737 4 100.0% 811 811 10.0%
Interior Lighting Linear Fluorescent 100.0% 84 84 0 100.0% 92 92 10.0%
Interior Lighting Specialty 100.0% 134 134 1 100.0% 154 154 15.0%
Exterior Lighting Screw-in 100.0% 20 20 0 100.0% 22 22 10.0%
Appliances Clothes Washer 32.0% 95 30 0 48.0% 71 34 -25.0%
Appliances Clothes Dryer 30.7% 412 127 1 46.1% 351 161 -15.0%
Appliances Dishwasher 64.0% 326 209 1 96.0% 277 266 -15.0%
Appliances Refrigerator 100.0% 596 596 3 100.0% 405 405 -32.0%
Appliances Freezer 8.4% 662 56 0 8.9% 416 37 -37.1%
Appliances Second Refrigerator 5.0% 814 41 0 5.0% 521 26 -36.0%
Appliances Stove 96.4% 333 321 2 96.4% 333 321 0.0%
Appliances Microwave 90.0% 98 88 0 90.0% 101 91 3.0%
Electronics Personal Computers 63.0% 170 107 1 69.3% 170 118 0.0%
Electronics TVs 165.0% 203 335 2 173.3% 203 352 0.0%
Electronics Set-top boxes/DVR 154.5% 128 198 1 170.0% 128 218 0.0%
Electronics Devices and Gadgets 100.0% 51 51 0 105.0% 56 59 10.0%
Miscellaneous Pool Pump 0.0% 1,410 - - 0.0% 1,434 - 1.7%
Miscellaneous Furnace Fan 13.0% 468 61 0 13.7% 468 64 0.0%
Miscellaneous Miscellaneous 100.0% 213 213 1 100.0% 234 234 10.0%
Total 8,213 43 8,010 -2.5%

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 892 of 1125
Market Profiles
A-8 www.enernoc.com
Table A-7 Mobile Home Electric Market Profile, Idaho 2009
Average Market Profile New Units
End Use Technology Saturation UEC
(kWh)
Intensity
(kWh/HH)
Usage
(GWh) Saturation UEC
(kWh)
Intensity
(kWh/HH)
Compared to
Average
Cooling Central AC 23.2% 475 110 1 39.4% 511 201 7.5%
Cooling Room AC 23.2% 262 61 0 22.0% 282 62 7.5%
Cooling Air Source Heat Pump 21.7% 311 68 0 22.8% 334 76 7.5%
Cooling Geothermal Heat Pump 0.0% 280 - - 0.0% 300 - 7.5%
Cooling Ductless HP 0.0% 285 - - 0.0% 307 - 7.5%
Space Heating Electric Resistance 1.2% 6,448 77 0 1.1% 6,931 78 7.5%
Space Heating Electric Furnace 57.6% 6,918 3,982 19 57.6% 7,437 4,281 7.5%
Space Heating Supplemental 1.4% 3,572 51 0 1.5% 3,840 58 7.5%
Space Heating Air Source Heat Pump 21.7% 4,410 959 5 22.8% 4,741 1,083 7.5%
Space Heating Geothermal Heat Pump 0.0% 3,969 - - 0.0% 4,267 - 7.5%
Space Heating Ductless HP 0.0% 2,503 - - 0.0% 2,691 - 7.5%
Water Heating Water Heater <= 55 Gal 75.6% 2,476 1,871 9 75.6% 2,370 1,791 -4.3%
Water Heating Water Heater > 55 Gal 0.0% 2,796 - - 0.0% 2,675 - -4.3%
Interior Lighting Screw-in 100.0% 955 955 5 100.0% 1,003 1,003 5.0%
Interior Lighting Linear Fluorescent 100.0% 94 94 0 100.0% 99 99 5.0%
Interior Lighting Specialty 100.0% 262 262 1 100.0% 282 282 7.5%
Exterior Lighting Screw-in 100.0% 268 268 1 100.0% 281 281 5.0%
Appliances Clothes Washer 86.7% 93 81 0 86.7% 81 71 -12.5%
Appliances Clothes Dryer 88.9% 404 359 2 88.9% 374 332 -7.5%
Appliances Dishwasher 80.1% 320 256 1 84.1% 296 249 -7.5%
Appliances Refrigerator 100.0% 584 584 3 100.0% 491 491 -16.0%
Appliances Freezer 53.3% 649 346 2 53.3% 529 282 -18.6%
Appliances Second Refrigerator 17.6% 798 140 1 17.6% 655 115 -18.0%
Appliances Stove 84.5% 326 276 1 84.5% 326 276 0.0%
Appliances Microwave 93.6% 96 90 0 93.6% 97 91 1.5%
Electronics Personal Computers 104.8% 182 191 1 110.1% 182 200 0.0%
Electronics TVs 234.0% 193 452 2 234.0% 193 452 0.0%
Electronics Set-top boxes/DVR 154.5% 110 169 1 170.0% 110 186 0.0%
Electronics Devices and Gadgets 100.0% 49 49 0 100.0% 51 51 5.0%
Miscellaneous Pool Pump 5.6% 1,063 59 0 5.8% 1,072 63 0.8%
Miscellaneous Furnace Fan 63.3% 441 279 1 63.3% 441 279 0.0%
Miscellaneous Miscellaneous 100.0% 230 230 1 100.0% 242 242 5.0%
Total 12,320 59 12,674 2.9%

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 893 of 1125
Market Profiles
EnerNOC Utility Solutions Consulting A-9
Table A-8 Low income Electric Market Profile, Idaho 2009
Average Market Profile New Units
End Use Technology Saturation UEC
(kWh)
Intensity
(kWh/HH)
Usage
(GWh) Saturation UEC
(kWh)
Intensity
(kWh/HH)
Compared to
Average
Cooling Central AC 22.2% 414 92 3 28.7% 445 128 7.5%
Cooling Room AC 35.4% 202 72 2 18.0% 218 39 7.5%
Cooling Air Source Heat Pump 10.4% 327 34 1 10.4% 351 37 7.5%
Cooling Geothermal Heat Pump 0.0% 306 - - 0.5% 329 2 7.5%
Cooling Ductless HP 0.0% 249 - - 0.0% 267 - 7.5%
Space Heating Electric Resistance 32.0% 5,619 1,797 55 28.8% 6,040 1,738 7.5%
Space Heating Electric Furnace 11.2% 6,092 680 21 10.0% 6,549 655 7.5%
Space Heating Supplemental 12.7% 346 44 1 13.4% 372 50 7.5%
Space Heating Air Source Heat Pump 10.4% 4,181 436 13 10.4% 4,494 468 7.5%
Space Heating Geothermal Heat Pump 0.0% 2,890 - - 0.0% 3,107 - 7.5%
Space Heating Ductless HP 0.0% 2,181 - - 0.0% 2,345 - 7.5%
Water Heating Water Heater <= 55 Gal 83.9% 2,203 1,848 56 83.9% 2,109 1,769 -4.3%
Water Heating Water Heater > 55 Gal 0.0% 2,758 - - 0.0% 2,639 - -4.3%
Interior Lighting Screw-in 100.0% 709 709 22 100.0% 745 745 5.0%
Interior Lighting Linear Fluorescent 100.0% 74 74 2 100.0% 78 78 5.0%
Interior Lighting Specialty 100.0% 169 169 5 100.0% 182 182 7.5%
Exterior Lighting Screw-in 100.0% 129 129 4 100.0% 136 136 5.0%
Appliances Clothes Washer 71.3% 83 59 2 78.4% 72 57 -12.5%
Appliances Clothes Dryer 68.6% 360 247 7 75.4% 333 251 -7.5%
Appliances Dishwasher 78.5% 285 224 7 86.3% 263 227 -7.5%
Appliances Refrigerator 100.0% 521 521 16 100.0% 437 437 -16.0%
Appliances Freezer 63.0% 578 364 11 63.0% 471 297 -18.6%
Appliances Second Refrigerator 23.4% 711 167 5 23.4% 583 137 -18.0%
Appliances Stove 89.7% 291 261 8 89.7% 291 261 0.0%
Appliances Microwave 92.6% 85 79 2 92.6% 87 80 1.5%
Electronics Personal Computers 101.4% 150 152 5 106.5% 150 160 0.0%
Electronics TVs 165.0% 168 277 8 165.0% 168 277 0.0%
Electronics Set-top boxes/DVR 128.8% 100 129 4 141.6% 100 142 0.0%
Electronics Devices and Gadgets 100.0% 42 42 1 105.0% 44 47 5.0%
Miscellaneous Pool Pump 2.3% 1,094 25 1 2.3% 1,103 25 0.8%
Miscellaneous Furnace Fan 25.2% 407 103 3 25.2% 407 103 0.0%
Miscellaneous Miscellaneous 100.0% 133 133 4 100.0% 140 140 5.0%
Total 8,868 269 8,666 -2.3%

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 894 of 1125
Market Profiles
A-10 www.enernoc.com
Table A-9 Small/Medium Commercial Electric Market Profile, Washington 2009
Average Market Profile New Units
End Use Technology Saturation UEC
(kWh)
Intensity
(kWh/HH)
Usage
(GWh) Saturation UEC
(kWh)
Intensity
(kWh/HH)
Compared to
Average
Cooling Central Chiller 13.8% 2 0 8 13.8% 2 0 -13.6%
Cooling RTU 63.1% 2 2 37 63.1% 2 1 -15.9%
Cooling Heat Pump 3.6% 5 0 4 3.6% 4 0 -15.9%
Space Heating Electric Resistance 5.9% 7 0 9 5.9% 6 0 -5.0%
Space Heating Furnace 17.7% 7 1 30 17.7% 7 1 -5.0%
Space Heating Heat Pump 3.6% 4 0 3 3.6% 3 0 -6.8%
Ventilation Ventilation 76.9% 2 2 38 76.9% 2 1 -14.8%
Interior Lighting Interior Screw-in 100.0% 1 1 24 100.0% 1 1 -1.2%
Interior Lighting High Bay Fixtures 100.0% 1 1 16 100.0% 1 1 -20.0%
Interior Lighting Linear Fluorescent 100.0% 3 3 80 100.0% 3 3 -12.7%
Exterior Lighting Exterior Screw-in 100.0% 0 0 4 100.0% 0 0 -26.0%
Exterior Lighting HID 100.0% 1 1 18 100.0% 1 1 -26.4%
Water Heating Water Heater 63.0% 2 1 30 63.0% 2 1 -6.0%
Food Preparation Fryer 25.8% 0 0 1 30.8% 0 0 -0.6%
Food Preparation Oven 25.8% 1 0 6 35.8% 1 0 -1.2%
Food Preparation Dishwasher 25.8% 0 0 0 35.8% 0 0 -24.1%
Food Preparation Hot Food Container 25.8% 0 0 2 35.8% 0 0 -20.0%
Food Preparation Food Prep 25.8% 0 0 0 35.8% 0 0 -20.0%
Refrigeration Walk in Refrigeration 52.4% - - - 62.4% - - 0.0%
Refrigeration Glass Door Display 52.4% 0 0 6 57.4% 0 0 -8.8%
Refrigeration Reach-in Refrigerator 52.4% 1 0 6 57.4% 0 0 -30.0%
Refrigeration Open Display Case 52.4% 0 0 1 57.4% 0 0 -8.4%
Refrigeration Vending Machine 52.4% 0 0 4 57.4% 0 0 -12.8%
Refrigeration Icemaker 52.4% 0 0 4 57.4% 0 0 -11.9%
Office Equipment Desktop Computer 99.9% 0 0 11 104.9% 0 1 -0.7%
Office Equipment Laptop Computer 99.9% 0 0 1 104.9% 0 0 -0.7%
Office Equipment Server 99.9% 0 0 9 104.9% 0 0 -4.7%
Office Equipment Monitor 99.9% 0 0 6 104.9% 0 0 -2.8%
Office Equipment Printer/copier/fax 99.9% 0 0 6 104.9% 0 0 -6.1%
Office Equipment POS Terminal 99.9% 0 0 7 104.9% 0 0 -15.6%
Miscellaneous Non-HVAC Motor 40.2% 1 0 12 40.2% 1 1 5.1%
Miscellaneous Other Miscellaneous 100.0% 1 1 34 100.0% 2 2 20.0%
Total 18 416 16 -6.9%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 895 of 1125
Market Profiles
EnerNOC Utility Solutions Consulting A-11
Table A-10 Large Commercial Electric Market Profile, Washington 2009
Average Market Profile New Units
End Use Technology Saturation UEC
(kWh)
Intensity
(kWh/HH)
Usage
(GWh) Saturation UEC
(kWh)
Intensity
(kWh/HH)
Compared to
Average
Cooling Central Chiller 24.7% 2 1 49 24.7% 2 0 -16.9%
Cooling RTU 37.8% 3 1 89 37.8% 2 1 -17.4%
Cooling Heat Pump 9.1% 4 0 30 9.1% 3 0 -16.9%
Space Heating Electric Resistance 5.9% 4 0 20 5.9% 3 0 -12.6%
Space Heating Furnace 12.7% 5 1 55 12.7% 4 1 -12.6%
Space Heating Heat Pump 9.1% 2 0 20 9.1% 2 0 -3.5%
Ventilation Ventilation 75.1% 2 1 116 75.1% 1 1 -14.8%
Interior Lighting Interior Screw-in 100.0% 1 1 88 100.0% 1 1 -1.4%
Interior Lighting High Bay Fixtures 100.0% 1 1 66 100.0% 1 1 -20.0%
Interior Lighting Linear Fluorescent 100.0% 3 3 307 100.0% 3 3 -13.6%
Exterior Lighting Exterior Screw-in 100.0% 0 0 9 100.0% 0 0 -18.1%
Exterior Lighting HID 100.0% 1 1 65 100.0% 1 1 -26.4%
Water Heating Water Heater 54.2% 2 1 117 54.2% 2 1 -4.0%
Food Preparation Fryer 18.4% 0 0 6 23.4% 0 0 -0.6%
Food Preparation Oven 18.4% 2 0 32 28.4% 2 1 -1.2%
Food Preparation Dishwasher 18.4% 0 0 3 28.4% 0 0 -24.1%
Food Preparation Hot Food Container 18.4% 0 0 5 28.4% 0 0 -39.9%
Food Preparation Food Prep 18.4% 0 0 0 28.4% 0 0 -20.0%
Refrigeration Walk in Refrigeration 39.1% 0 0 17 49.1% 0 0 -30.0%
Refrigeration Glass Door Display 39.1% 0 0 13 44.1% 0 0 -9.7%
Refrigeration Reach-in Refrigerator 39.1% 1 0 28 44.1% 1 0 -30.0%
Refrigeration Open Display Case 39.1% 0 0 10 44.1% 0 0 -9.3%
Refrigeration Vending Machine 39.1% 0 0 13 44.1% 0 0 -12.8%
Refrigeration Icemaker 39.1% 1 0 24 44.1% 1 0 -12.2%
Office Equipment Desktop Computer 98.4% 1 1 82 103.4% 1 1 -0.7%
Office Equipment Laptop Computer 98.4% 0 0 6 103.4% 0 0 -0.7%
Office Equipment Server 98.4% 0 0 38 103.4% 0 0 -4.7%
Office Equipment Monitor 98.4% 0 0 19 103.4% 0 0 -2.8%
Office Equipment Printer/copier/fax 98.4% 0 0 19 103.4% 0 0 -6.1%
Office Equipment POS Terminal 98.4% 0 0 6 103.4% 0 0 -15.6%
Miscellaneous Non-HVAC Motor 57.7% 1 1 75 57.7% 1 1 5.1%
Miscellaneous Other Miscellaneous 100.0% 1 1 127 100.0% 2 2 10.0%
Total 17 1,557 16 -6.8%

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 896 of 1125
Market Profiles
A-12 www.enernoc.com
Table A-11 Extra Large Commercial Electric Market Profile, Washington 2009
Average Market Profile New Units
End Use Technology Saturation UEC
(kWh)
Intensity
(kWh/HH)
Usage
(GWh) Saturation UEC
(kWh)
Intensity
(kWh/HH)
Compared to
Average
Cooling Central Chiller 52.2% 2 1 21 52.2% 2 1 -14.7%
Cooling RTU 24.7% 2 1 10 24.7% 2 0 -16.7%
Cooling Heat Pump 4.4% 2 0 2 4.4% 2 0 -26.2%
Space Heating Electric Resistance 15.8% 4 1 13 15.8% 4 1 -13.1%
Space Heating Furnace 5.6% 6 0 6 5.6% 5 0 -13.1%
Space Heating Heat Pump 90.2% 2 2 33 90.2% 2 2 -12.1%
Ventilation Ventilation 100.0% 1 1 26 100.0% 1 1 -2.7%
Interior Lighting Interior Screw-in 100.0% 0 0 6 100.0% 0 0 -20.0%
Interior Lighting High Bay Fixtures 100.0% 2 2 42 100.0% 2 2 -8.3%
Interior Lighting Linear Fluorescent 100.0% 0 0 1 100.0% 0 0 -51.9%
Exterior Lighting Exterior Screw-in 100.0% 1 1 17 100.0% 1 1 -26.4%
Exterior Lighting HID 26.3% 4 1 19 26.3% 4 1 -2.0%
Water Heating Water Heater 13.8% 0 0 0 18.8% 0 0 -0.6%
Food Preparation Fryer 13.8% 2 0 6 23.8% 2 0 -1.2%
Food Preparation Oven 13.8% 0 0 0 23.8% 0 0 -24.1%
Food Preparation Dishwasher 13.8% 0 0 0 23.8% 0 0 -39.9%
Food Preparation Hot Food Container 13.8% 0 0 0 23.8% 0 0 0.0%
Food Preparation Food Prep 26.6% 0 0 1 36.6% 0 0 -30.0%
Refrigeration Walk in Refrigeration 26.6% 0 0 1 31.6% 0 0 -9.7%
Refrigeration Glass Door Display 26.6% 1 0 4 31.6% 0 0 -30.0%
Refrigeration Reach-in Refrigerator 26.6% 0 0 3 31.6% 0 0 -9.3%
Refrigeration Open Display Case 26.6% 0 0 2 31.6% 0 0 -27.9%
Refrigeration Vending Machine 26.6% 0 0 2 31.6% 0 0 -11.4%
Refrigeration Icemaker 100.0% 1 1 12 105.0% 1 1 -0.7%
Office Equipment Desktop Computer 100.0% 0 0 1 105.0% 0 0 -0.7%
Office Equipment Laptop Computer 100.0% 0 0 3 105.0% 0 0 -4.7%
Office Equipment Server 100.0% 0 0 2 105.0% 0 0 -2.8%
Office Equipment Monitor 100.0% 0 0 1 105.0% 0 0 -6.1%
Office Equipment Printer/copier/fax 100.0% 0 0 0 105.0% 0 0 -15.6%
Office Equipment POS Terminal 88.8% 1 1 14 88.8% 1 1 5.1%
Miscellaneous Non-HVAC Motor 100.0% 1 1 15 100.0% 1 1 10.0%
Miscellaneous Other Miscellaneous 4.4% 3 0 3 4.4% 3 0 -3.1%
Total 14 266 13 -6.0%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 897 of 1125
Market Profiles
EnerNOC Utility Solutions Consulting A-13
Table A-12 Extra Large Industrial Electric Market Profile, Washington 2009
Average Market Profile New Units
End Use Technology Saturation UEC
(kWh)
Intensity
(kWh/HH)
Usage
(GWh) Saturation UEC
(kWh)
Intensity
(kWh/HH)
Compared to
Average
Cooling Central Chiller 14.4% 8 1 18 14.4% 7 1 -11.7%
Cooling RTU 17.1% 6 1 17 17.1% 6 1 -12.3%
Cooling Heat Pump 2.7% 5 0 2 2.7% 4 0 -20.9%
Space Heating Electric Resistance 10.8% 9 1 14 10.8% 8 1 -5.0%
Space Heating Furnace 2.0% 9 0 3 2.0% 9 0 0.0%
Space Heating Heat Pump 2.7% 4 0 2 2.7% 4 0 -4.9%
Ventilation Ventilation 27.4% 12 3 52 27.4% 10 3 -15.0%
Interior Lighting Interior Screw-in 100.0% 0 0 5 100.0% 0 0 -5.0%
Interior Lighting High Bay Fixtures 100.0% 1 1 16 100.0% 1 1 -12.7%
Interior Lighting Linear Fluorescent 100.0% 1 1 17 100.0% 1 1 -26.0%
Exterior Lighting Exterior Screw-in 100.0% 0 0 0 100.0% 0 0 -26.4%
Exterior Lighting HID 100.0% 0 0 4 100.0% 0 0 -26.4%
Process Process Cooling/Refrigeration 2.4% 100 2 37 2.5% 100 3 0.0%
Process Process Heating 26.2% 14 4 55 27.5% 14 4 0.0%
Process Electrochemical Process 2.6% 77 2 31 2.7% 77 2 0.0%
Machine Drive Less than 5 HP 90.5% 1 1 13 95.0% 1 1 0.0%
Machine Drive 5-24 HP 80.1% 2 2 28 84.1% 2 2 0.0%
Machine Drive 25-99 HP 72.4% 6 4 68 76.0% 6 5 0.0%
Machine Drive 100-249 HP 65.3% 4 3 38 68.6% 4 3 0.0%
Machine Drive 250-499 HP 23.7% 12 3 42 24.9% 12 3 0.0%
Machine Drive 500 and more HP 26.1% 20 5 78 27.4% 20 5 0.0%
Miscellaneous Miscellaneous 100.0% 5 5 75 103.0% 5 5 0.0%
Total 40 614 40 0.2%

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 898 of 1125
Market Profiles
A-14 www.enernoc.com
Table A-13 Small/Medium Commercial Electric Market Profile, Idaho 2009
Average Market Profile New Units
End Use Technology Saturation UEC
(kWh)
Intensity
(kWh/HH)
Usage
(GWh) Saturation UEC
(kWh)
Intensity
(kWh/HH)
Compared to
Average
Cooling Central Chiller 13.8% 2 0 6 13.8% 2 0 -13.6%
Cooling RTU 63.1% 2 2 29 63.1% 2 1 -15.9%
Cooling Heat Pump 3.6% 5 0 3 3.6% 4 0 -15.9%
Space Heating Electric Resistance 5.9% 7 0 7 5.9% 6 0 -5.0%
Space Heating Furnace 17.7% 7 1 23 17.7% 7 1 -5.0%
Space Heating Heat Pump 3.6% 4 0 2 3.6% 3 0 -6.8%
Ventilation Ventilation 76.9% 2 2 30 76.9% 2 1 -14.8%
Interior Lighting Interior Screw-in 100.0% 1 1 18 100.0% 1 1 -1.2%
Interior Lighting High Bay Fixtures 100.0% 1 1 13 100.0% 1 1 -20.0%
Interior Lighting Linear Fluorescent 100.0% 3 3 62 100.0% 3 3 -12.7%
Exterior Lighting Exterior Screw-in 100.0% 0 0 4 100.0% 0 0 -26.0%
Exterior Lighting HID 100.0% 1 1 13 100.0% 1 1 -26.4%
Water Heating Water Heater 63.0% 2 1 23 63.0% 2 1 -6.0%
Food Preparation Fryer 25.8% 0 0 1 30.8% 0 0 -0.6%
Food Preparation Oven 25.8% 1 0 5 35.8% 1 0 -1.2%
Food Preparation Dishwasher 25.8% 0 0 0 35.8% 0 0 -24.1%
Food Preparation Hot Food Container 25.8% 0 0 1 35.8% 0 0 -20.0%
Food Preparation Food Prep 25.8% 0 0 0 35.8% 0 0 -20.0%
Refrigeration Walk in Refrigeration 52.4% - - - 62.4% - - 0.0%
Refrigeration Glass Door Display 52.4% 0 0 4 57.4% 0 0 -8.8%
Refrigeration Reach-in Refrigerator 52.4% 1 0 5 57.4% 0 0 -30.0%
Refrigeration Open Display Case 52.4% 0 0 0 57.4% 0 0 -8.4%
Refrigeration Vending Machine 52.4% 0 0 3 57.4% 0 0 -12.8%
Refrigeration Icemaker 52.4% 0 0 3 57.4% 0 0 -11.9%
Office Equipment Desktop Computer 99.9% 0 0 9 104.9% 0 1 -0.7%
Office Equipment Laptop Computer 99.9% 0 0 1 104.9% 0 0 -0.7%
Office Equipment Server 99.9% 0 0 7 104.9% 0 0 -4.7%
Office Equipment Monitor 99.9% 0 0 5 104.9% 0 0 -2.8%
Office Equipment Printer/copier/fax 99.9% 0 0 4 104.9% 0 0 -6.1%
Office Equipment POS Terminal 99.9% 0 0 5 104.9% 0 0 -15.6%
Miscellaneous Non-HVAC Motor 40.2% 1 0 9 40.2% 1 1 5.1%
Miscellaneous Other Miscellaneous 100.0% 1 1 26 100.0% 2 2 20.0%
Total 18 323 16 -6.9%

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 899 of 1125
Market Profiles
EnerNOC Utility Solutions Consulting A-15
Table A-14 Large Commercial Electric Market Profile, Idaho 2009
Average Market Profile New Units
End Use Technology Saturation UEC
(kWh)
Intensity
(kWh/HH)
Usage
(GWh) Saturation UEC
(kWh)
Intensity
(kWh/HH)
Compared to
Average
Cooling Central Chiller 24.7% 2 1 22 24.7% 2 0 -16.9%
Cooling RTU 37.8% 3 1 40 37.8% 2 1 -17.4%
Cooling Heat Pump 9.1% 4 0 14 9.1% 3 0 -16.9%
Space Heating Electric Resistance 5.9% 4 0 9 5.9% 3 0 -12.6%
Space Heating Furnace 12.7% 5 1 25 12.7% 4 1 -12.6%
Space Heating Heat Pump 9.1% 2 0 9 9.1% 2 0 -3.5%
Ventilation Ventilation 75.1% 2 1 52 75.1% 1 1 -14.8%
Interior Lighting Interior Screw-in 100.0% 1 1 39 100.0% 1 1 -1.4%
Interior Lighting High Bay Fixtures 100.0% 1 1 30 100.0% 1 1 -20.0%
Interior Lighting Linear Fluorescent 100.0% 3 3 138 100.0% 3 3 -13.6%
Exterior Lighting Exterior Screw-in 100.0% 0 0 4 100.0% 0 0 -18.1%
Exterior Lighting HID 100.0% 1 1 29 100.0% 1 1 -26.4%
Water Heating Water Heater 54.2% 2 1 53 54.2% 2 1 -4.0%
Food Preparation Fryer 18.4% 0 0 3 23.4% 0 0 -0.6%
Food Preparation Oven 18.4% 2 0 14 28.4% 2 1 -1.2%
Food Preparation Dishwasher 18.4% 0 0 1 28.4% 0 0 -24.1%
Food Preparation Hot Food Container 18.4% 0 0 2 28.4% 0 0 -39.9%
Food Preparation Food Prep 18.4% 0 0 0 28.4% 0 0 -20.0%
Refrigeration Walk in Refrigeration 39.1% 0 0 8 49.1% 0 0 -30.0%
Refrigeration Glass Door Display 39.1% 0 0 6 44.1% 0 0 -9.7%
Refrigeration Reach-in Refrigerator 39.1% 1 0 13 44.1% 1 0 -30.0%
Refrigeration Open Display Case 39.1% 0 0 4 44.1% 0 0 -9.3%
Refrigeration Vending Machine 39.1% 0 0 6 44.1% 0 0 -12.8%
Refrigeration Icemaker 39.1% 1 0 11 44.1% 1 0 -12.2%
Office Equipment Desktop Computer 98.4% 1 1 37 103.4% 1 1 -0.7%
Office Equipment Laptop Computer 98.4% 0 0 3 103.4% 0 0 -0.7%
Office Equipment Server 98.4% 0 0 17 103.4% 0 0 -4.7%
Office Equipment Monitor 98.4% 0 0 9 103.4% 0 0 -2.8%
Office Equipment Printer/copier/fax 98.4% 0 0 9 103.4% 0 0 -6.1%
Office Equipment POS Terminal 98.4% 0 0 3 103.4% 0 0 -15.6%
Miscellaneous Non-HVAC Motor 57.7% 1 1 34 57.7% 1 1 5.1%
Miscellaneous Other Miscellaneous 100.0% 1 1 57 100.0% 2 2 10.0%
Total 17 700 16 -6.8%

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 900 of 1125
Market Profiles
A-16 www.enernoc.com
Table A-15 Extra Large Commercial Electric Market Profile, Idaho 2009
Average Market Profile New Units
End Use Technology Saturation UEC
(kWh)
Intensity
(kWh/HH)
Usage
(GWh) Saturation UEC
(kWh)
Intensity
(kWh/HH)
Compared to
Average
Cooling Central Chiller 52.2% 2 1 6 52.2% 2 1 -14.7%
Cooling RTU 24.7% 2 1 3 24.7% 2 0 -16.7%
Cooling Heat Pump 4.4% 2 0 0 4.4% 2 0 -26.2%
Space Heating Electric Resistance 15.8% 4 1 4 15.8% 4 1 -13.1%
Space Heating Furnace 5.6% 6 0 2 5.6% 5 0 -13.1%
Space Heating Heat Pump 90.2% 2 2 9 90.2% 2 2 -12.1%
Ventilation Ventilation 100.0% 1 1 7 100.0% 1 1 -2.7%
Interior Lighting Interior Screw-in 100.0% 0 0 1 100.0% 0 0 -20.0%
Interior Lighting High Bay Fixtures 100.0% 2 2 11 100.0% 2 2 -8.3%
Interior Lighting Linear Fluorescent 100.0% 0 0 0 100.0% 0 0 -51.9%
Exterior Lighting Exterior Screw-in 100.0% 1 1 4 100.0% 1 1 -26.4%
Exterior Lighting HID 26.3% 4 1 5 26.3% 4 1 -2.0%
Water Heating Water Heater 13.8% 0 0 0 23.8% 0 0 -0.6%
Food Preparation Fryer 13.8% 2 0 1 23.8% 2 0 -1.2%
Food Preparation Oven 13.8% 0 0 0 23.8% 0 0 -24.1%
Food Preparation Dishwasher 13.8% 0 0 0 23.8% 0 0 -39.9%
Food Preparation Hot Food Container 13.8% 0 0 0 23.8% 0 0 0.0%
Food Preparation Food Prep 26.6% 0 0 0 31.6% 0 0 -30.0%
Refrigeration Walk in Refrigeration 26.6% 0 0 0 31.6% 0 0 -9.7%
Refrigeration Glass Door Display 26.6% 1 0 1 31.6% 0 0 -30.0%
Refrigeration Reach-in Refrigerator 26.6% 0 0 1 31.6% 0 0 -9.3%
Refrigeration Open Display Case 26.6% 0 0 1 31.6% 0 0 -27.9%
Refrigeration Vending Machine 26.6% 0 0 0 31.6% 0 0 -11.4%
Refrigeration Icemaker 100.0% 1 1 3 105.0% 1 1 -0.7%
Office Equipment Desktop Computer 100.0% 0 0 0 105.0% 0 0 -0.7%
Office Equipment Laptop Computer 100.0% 0 0 1 105.0% 0 0 -4.7%
Office Equipment Server 100.0% 0 0 1 105.0% 0 0 -2.8%
Office Equipment Monitor 100.0% 0 0 0 105.0% 0 0 -6.1%
Office Equipment Printer/copier/fax 100.0% 0 0 0 100.0% 0 0 -15.6%
Office Equipment POS Terminal 88.8% 1 1 4 88.8% 1 1 5.1%
Miscellaneous Non-HVAC Motor 100.0% 1 1 4 100.0% 1 1 10.0%
Miscellaneous Other Miscellaneous 4.4% 3 0 1 4.4% 3 0 -3.1%
Total 14 70 13 -6.0%

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 901 of 1125
Market Profiles
EnerNOC Utility Solutions Consulting A-17
Table A-16 Extra Large Industrial Electric Market Profile, Idaho 2009
Average Market Profile New Units
End Use Technology Saturation UEC
(kWh)
Intensity
(kWh/HH)
Usage
(GWh) Saturation UEC
(kWh)
Intensity
(kWh/HH)
Compared to
Average
Cooling Central Chiller 14.4% 8 1 6 14.4% 7 1 -11.7%
Cooling RTU 17.1% 6 1 5 17.1% 6 1 -12.3%
Cooling Heat Pump 2.7% 4 0 0 2.7% 3 0 -20.9%
Space Heating Electric Resistance 10.8% 9 1 5 10.8% 8 1 -5.0%
Space Heating Furnace 2.0% 9 0 1 2.0% 9 0 0.0%
Space Heating Heat Pump 27.4% 12 3 17 27.4% 10 3 -15.0%
Ventilation Ventilation 100.0% 0 0 2 100.0% 0 0 -5.0%
Interior Lighting Interior Screw-in 100.0% 1 1 5 100.0% 1 1 -12.7%
Interior Lighting High Bay Fixtures 100.0% 1 1 5 100.0% 1 1 -26.0%
Interior Lighting Linear Fluorescent 100.0% 0 0 0 100.0% 0 0 -26.4%
Exterior Lighting Exterior Screw-in 100.0% 0 0 1 100.0% 0 0 -26.4%
Exterior Lighting HID 2.4% 100 2 12 2.5% 100 3 0.0%
Process Process Cooling/Refrigeration 26.2% 14 4 18 27.5% 14 4 0.0%
Process Process Heating 2.6% 77 2 10 2.7% 77 2 0.0%
Process Electrochemical Process 90.5% 1 1 4 95.0% 1 1 0.0%
Machine Drive Less than 5 HP 80.1% 2 2 9 84.1% 2 2 0.0%
Machine Drive 5-24 HP 72.4% 6 4 22 76.0% 6 5 0.0%
Machine Drive 25-99 HP 65.3% 4 3 12 68.6% 4 3 0.0%
Machine Drive 100-249 HP 23.7% 12 3 13 24.9% 12 3 0.0%
Machine Drive 250-499 HP 26.1% 20 5 25 27.4% 20 5 0.0%
Machine Drive 500 and more HP 100.0% 5 5 24 103.0% 5 5 0.0%
Miscellaneous Miscellaneous 2.7% 5 0 1 2.7% 5 0 -4.9%
Total 40 196 40 0.2%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 902 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 903 of 1125

EnerNOC Utility Solutions Consulting B-1
APPENDIX B
RESIDENTIAL ENERGY EFFICIENCY EQUIPMENT AND MEASURE
DATA
This appendix presents detailed information for all energy-efficiency measures (equipment and
non-equipment measures per the LoadMAP taxonomy) that were evaluated as part of this study.
Several sets of tables are provided.
Measure Descriptions
Table B-1 and Table B-2 provide brief descriptions for all equipment and non-equipment
measures that were assessed for potential.
Equipment Measure Data
Table B-3 through Table B-18 list the detailed unit-level data of Washington and Idaho for the
equipment measures for each of the housing type segments — Single Family, Multi Family,
Mobile Home, and Low income for existing and new construction, respectively. Savings are in
annual kWh per household, and incremental costs are in $/household ($/HH), unless noted
otherwise. The BC ratio shown in the tables are for the first year of the potential analysis (2014),
although the B/C ratio is calculated within LoadMAP for each year of the forecast. The B/C ratio
in the tables is 1.00 if the measure represents the baseline technology, and zero if the
technology is not available in 2014. The final data item in these tables is the levelized cost of
conserved energy, which is defined as the cost of the measure divided by the cumulative amount
of energy savings accrued over the measure’s lifetime ($/kWh).
Non-Equipment Measure Data
Table B-19 through Table B-34 list the detailed unit-level data of Washington and Idaho for the
non-equipment energy efficiency measures for each of the housing type segments and for
existing and new construction, respectively. Because these measures can produce energy-use
savings for multiple end-use loads (e.g., insulation affects heating and cooling energy use)
savings are expressed as a net percentage of all the relevant, combined end-use loads. Base
saturation indicates the percentage of homes in which the measure is already installed.
Applicability is a factor that account for whether the measure is applicable to the building. Cost is
expressed in $/household. The detailed measure-level tables present the results of the
benefit/cost (B/C) analysis for the first year of the potential analysis (2014) although the B/C
ratio is calculated within LoadMAP for each year of the forecast. These tables also contain the
levelized cost of conserved energy, which is defined as the cost of the measure divided by the
cumulative amount of energy savings accrued over the measure’s lifetime, given in terms of $/kWh.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 904 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-2 www.enernoc.com
Table B-1 Residential Energy Efficiency Equipment Measure Descriptions
End Use Technology Measure Description
Cooling Central AC
Central air conditioners consist of a refrigeration system using a direct
expansion cycle. Equipment includes a compressor, an air-cooled
condenser (located outdoors), an expansion valve, and an evaporator
coil. A supply fan near the evaporator coil distributes supply air through
air ducts to the building. Cooling efficiencies vary based on materials
used, equipment size, condenser type, and system configuration. CACs
may be unitary (all components housed in a factory-built assembly) or
split system (an outdoor condenser section and an indoor evaporator
section connected by refrigerant lines and with the compressor either
indoors or outdoors). Energy efficiency is rated according to the size of
the unit using the Seasonal Energy Efficiency Rating (SEER). Ductless
systems with Variable Refrigerant Flow further improve the operating
efficiency.
Cooling Room AC
Room air conditioners are designed to cool a single room or space. They
incorporate a complete air-cooled refrigeration and air-handling system
in an individual package. Room air conditioners come in several forms,
including window, split-type, and packaged terminal units. Energy
efficiency is rated according to the size of the unit using the Energy
Efficiency Rating (EER).
Cooling/ Space
Heating
Ductless Heat
Pump
Ductless heat pumps systems are similar to convential air-source heat
pumps in that they use electricity to transfer heat between outdoor and
indoor air via a vapor compression cycle. They can thus provide both
heating and colling. However, they are mounted though a wall and thus
can be retrofitted in homes that use electric zonal baseboard, wall, or
ceiling units and as a result do not have ducts. They may also be suitable
in new construction, where one or more systems can be installed.
Cooling/ Space
Heating
Air-Source Heat
Pump
A central heat pump consists of components similar to a CAC system, but
is usually designed to function both as a heat pump and an air
conditioner. It consists of a refrigeration system using a direct expansion
(DX) cycle. Equipment includes a compressor, an air-cooled condenser
(located outdoors), an expansion valve, and an evaporator coil (located in
the supply air duct near the supply fan) and a reversing valve to change
the DX cycle from cooling to heating when required. The cooling and
heating efficiencies vary based on the materials used, equipment size,
condenser type, and system configuration. Heat pumps may be unitary
(all components housed in a factory-built assembly) or a split system (an
outdoor condenser section and an indoor evaporator section connected
by refrigerant lines, with either outdoors or indoors. A high-efficiency
option for a ductless mini-split system is also analyzed.
Cooling/ Space
Heating
Geothermal Heat
Pump
Geothermal heat pumps are similar to air-source heat pumps, but use the
ground or groundwater instead of outside air to provide a heat
source/sink. A geothermal heat pump system generally consists of three
major subsystems or parts: a geothermal heat pump to move heat
between the building and the fluid in the earth connection, an earth
connection for transferring heat between the fluid and the earth, and a
distribution subsystem for delivering heating or cooling to the building.
The system may also have a desuperheater to supplement the building's
water heater, or a full-demand water heater to meet all of the building's
hot water needs.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 905 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-3
End Use Technology Measure Description
Space Heating Electric Resistance
Resistive heating elements are used to convert electricity directly to heat.
Conductive fins surrounding the element or another mechanism is used
to deliver the heat directly to the surrounding room or area. These are
typically either baseboard or wall-mounted units.
Space Heating Electric Furnace
Furnaces heat air and distribute the heated air through the building using
ducts. Efficiency improvements can include: exhaust fan controls,
electronic ignition (no pilot light), compact size and lighter weight to
reduce cycling losses, smaller-diameter flue pipe, and sealed combustion.
Very high efficiency units, or condensing units, condense the water vapor
produced in the combustion process and also use the heat from this
condensation.
Water Heating Water Heater
For electric hot water heating, the most common type is a storage heater,
which incorporates an electric heating element, storage tank, outer
jacket, insulation, and controls in a single unit. Efficient units are
characterized by a high recovery or thermal efficiency and low standby
losses (the ratio of heat lost per hour to the content of the stored water).
A further efficiency gain is available through a heat pump water heater
(HPWH), which uses a vapor-compression thermodynamic cycle similar to
that found in an air-conditioner or refrigerator to extract heat from an
available source (e.g., air) and reject that heat to a higher temperature
sink, in this case, the water in the water heater. Electric instantaneous
water heaters are available, but are excluded from this study due to
potentially high instantaneous demand concerns.
For natural gas hot water heating, the most common type is a storage
heater, which incorporates a burner, storage tank, outer jacket,
insulation, and controls in a single unit. Efficient units are characterized
by a high recovery or thermal efficiency and low standby losses (the ratio
of heat lost per hour to the content of the stored water). A further
efficiency gain is available in condensing units, which condense the water
vapor produced in the combustion process and also use the heat from
this condensation.
Interior Lighting Screw-in
Infrared halogen lamps are designed to be a replacement for standards
incandescent lamps. Also referred to as advanced incandescent lamps,
these products meet the Energy Independence and Security Act (EISA)
lighting standards and are phased in as the baseline technology screw-in
lamp technology to reflect the timeline over which the EISA lighting
standards take effect. Compact fluorescent lamps are designed to be a
replacement for standard incandescent lamps and use about 25% of the
energy used by standard incandescent lamps to produce the same lumen
output. They can use either electronic or magnetic ballasts. Integral
compact fluorescent lamps have the ballast integrated into the base of
the lamp and have a standard screw-in base that permits installation into
existing incandescent fixtures. Light-emitting diode (LED) lighting has
seen recent penetration in specific applications such as traffic lights and
exit signs. With the potential for extremely high efficiency, LEDs show
promise to provide general-use lighting for interior spaces. Current
models commercially available have efficacies comparable to CFLs.
However, theoretical efficiencies are significantly higher. LED models
under development are expected to provide improved efficacies.
Interior Lighting Linear Fluorescent
T8 fluorescent lamps are smaller in diameter than standard T12 lamps,
resulting in greater light output per watt. T8 lamps also operate at a
lower current and wattage, which increases the efficiency of the ballast
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 906 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-4 www.enernoc.com
End Use Technology Measure Description
but requires the lamps to be compatible with the ballast. Fluorescent
lamp fixtures can include a reflector that increases the light output from
the fixture, and thus make it possible to use a fewer number of lamps in
each fixture. T5 lamps further increase efficiency by reducing the lamp
diameter to 5/8”. Light-emitting diode (LED) lighting has seen recent
penetration in specific applications such as traffic lights and exit signs.
With the potential for extremely high efficiency, LEDs show promise to
provide general-use lighting for interior spaces. Current models
commercially available have efficacies comparable to CFLs. However,
theoretical efficiencies are significantly higher. LED models under
development are expected to provide improved efficacies.
Interior Lighting Specialty Lighting
Bulbs that the DOE does not consider conventional and are not covered
by federal efficiency standards. These include: appliance bulbs, heavy-
duty bulbs, dimmable bulbs, three-way bulbs, G shape (globe) lamps,
candelabra base, and others.
Exterior
Lighting Screw-in
Infrared halogen lamps are designed to be a replacement for standards
incandescent lamps. Also referred to as advanced incandescent lamps,
these products meet the Energy Independence and Security Act (EISA)
lighting standards and are phased in as the baseline technology screw-in
lamp technology to reflect the timeline over which the EISA lighting
standards take effect. Compact fluorescent lamps are designed to be a
replacement for standard incandescent lamps and use about 25% of the
energy used by standard incandescent lamps to produce the same lumen
output. They can use either electronic or magnetic ballasts. Integral
compact fluorescent lamps have the ballast integrated into the base of
the lamp and have a standard screw-in base that permits installation into
existing incandescent fixtures. Light-emitting diode (LED) lighting has
seen recent penetration in specific applications such as traffic lights and
exit signs. With the potential for extremely high efficiency, LEDs show
promise to provide general-use lighting for interior spaces. Current
models commercially available have efficacies comparable to CFLs.
However, theoretical efficiencies are significantly higher. LED models
under development are expected to provide improved efficacies.
Appliances Refrigerator
Energy-efficient refrigerators/freezers incorporate features such as
improved cabinet insulation, more efficient compressors and evaporator
fans, defrost controls, mullion heaters, oversized condenser coils, and
improved door seals. Further efficiency increases can be obtained by
reducing the volume of refrigerated space, or adding multiple
compartments to reduce losses from opening doors.
Appliances Second
Refrigerator
Energy-efficient refrigerators/freezers incorporate features such as
improved cabinet insulation, more efficient compressors and evaporator
fans, defrost controls, mullion heaters, oversized condenser coils, and
improved door seals. Further efficiency increases can be obtained by
reducing the volume of refrigerated space, or adding multiple
compartments to reduce losses from opening doors.
Appliances Freezer
Energy-efficient refrigerators/freezers incorporate features such as
improved cabinet insulation, more efficient compressors and evaporator
fans, defrost controls, mullion heaters, oversized condenser coils, and
improved door seals. Further efficiency increases can be obtained by
reducing the volume of refrigerated space, or adding multiple
compartments to reduce losses from opening doors.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 907 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-5
End Use Technology Measure Description
Appliances Clothes Washer
High efficiency clothes washers use superior designs that require less
water. Sensors match the hot water needs to the size and soil level of the
load, preventing energy waste. Further energy and water savings can be
achieved through advanced technologies such as inverter-drive or
combination washer-dryer units. MEF is the official energy efficiency
metric used to compare relative efficiencies of different clothes washers.
MEF considers the energy used to run the washer, heat the water, and
run the dryer. The higher the MEF, the more efficient the clothes washer.
Appliances Clothes Dryer
An energy-efficient clothes dryer has a moisture-sensing device to
terminate the drying cycle rather than using a timer and an energy-
efficient motor is used for spinning the dryer tub. Application of a heat
pump cycle for extracting the moisture from clothes leads to additional
energy savings.
Appliances Dishwasher
High efficiency dishwashers save by using both improved technology for
the primary wash cycle, and by using less hot water. Construction
includes more effective washing action, energy-efficient motors, and
other advanced technology such as sensors that determine the length of
the wash cycle and the temperature of the water necessary to clean the
dishes.
Appliances Stove
These products have additional insulation in the oven compartment and
tighter-fitting oven door gaskets and hinges to save energy. Conventional
ovens must first heat up about 35 pounds of steel and a large amount of
air before they heat up the food. Higher efficiency options include
convection ovens, halogen burners, and induction burners.
Appliances Microwave No high efficiency option is modeled.
Electronics Personal
Computers
Improved power management can significantly reduce the annual energy
consumption of PCs and monitors in both standby and normal operation.
ENERGY STAR and Climate Savers labeled products provide increasing
level of energy efficiency.
Electronics TVs
In the average home, TVs consume significant energy, even when they
are turned off, to maintain features like clocks, remote control, and
channel/station memory. ENERGY STAR labeled consumer electronics can
drastically reduce consumption during standby mode, in addition to
saving energy through advanced power management during normal use.
Electronics Devices and
Gadgets
High efficiency electronics can use efficient components and employ
sleep/powersave modes.
Electronics Set-top Boxes/DVR High efficiency electronics can use efficient components and employ
sleep/powersave modes.
Miscellaneous Pool Pump High-efficiency motors and two-speed pumps provide improved energy
efficiency for this load.
Miscellaneous Furnace Fan
In homes heated by a furnace, there is still substantial energy use by the
fan responsible for moving the hot air throughout the ductwork.
Application of an Electronically Commutating Motor (ECM) ensures that
motor speed matches the heating requirements of the system and saves
energy when compared to a continuously operating standard motor.
Miscellaneous Miscellaneous Improvement of miscellaneous electricity uses.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 908 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-6 www.enernoc.com
Table B-2 Residential Energy Efficiency Non-Equipment Measure Descriptions
End Use Measure Description
HVAC (All) Insulation - Ceiling
Thermal insulation is material or combinations of materials that are used to
inhibit the flow of heat energy by conductive, convective, and radiative transfer
modes. Thus, thermal insulation above ceilings can conserve energy by
reducing the heat loss or gain into attics and/or through roofs. The type of
building construction defines insulating possibilities. Typical insulating
materials include: loose-fill (blown) cellulose, loose-fill (blown) fiberglass, and
rigid polystyrene.
Cooling Insulation - Ducting
Air distribution ducts can be insulated to reduce heating or cooling losses. Best
results can be achieved by covering the entire surface area with insulation.
Several types of ducts and duct insulation are available, including flexible duct,
pre-insulated duct, duct board, duct wrap, tacked, or glued rigid insulation, and
waterproof hard shell materials for exterior ducts. This analysis assumes that
installing duct insulation can reduce the temperature drop/gain in ducts by
50%.
HVAC (All) Insulation -
Foundation
Thermal insulation is material or combinations of materials that are used to
inhibit the flow of heat energy by conductive, convective, and radiative transfer
modes. Thus, thermal insulation can conserve energy by reducing heat loss or
gain from a building. The type of building construction defines insulating
possibilities. Typical insulating materials include: loose-fill (blown) cellulose,
loose-fill (blown) fiberglass, and rigid polystyrene. Foundation insulation is
modeled for new construction / major retrofits only.
HVAC (All) Insulation -
Infiltration Control
Lowering the air infiltration rate by caulking small leaks and weather-stripping
around window frames, doorframes, power outlets, plumbing, and wall corners
can provide significant energy savings. Weather-stripping doors and windows
will create a tight seal and further reduce air infiltration.
HVAC (All) Insulation - Radiant
Barrier
Radiant barriers are materials installed to reduce the heat gain in buildings.
Radiant barriers are made from materials that are highly reflective and have
low emissivity like aluminum. The closer the emissivity is to 0 the better they
will perform. Radiant barriers can be placed above the insulation or on the
roof rafters.
HVAC (All) Insulation - Wall
Cavity
Thermal insulation is material or combinations of materials that are used to
inhibit the flow of heat energy by conductive, convective, and radiative transfer
modes. Thus, thermal insulation can conserve energy by reducing heat loss or
gain from a building. The type of building construction defines insulating
possibilities. Typical insulating materials include: loose-fill (blown) cellulose,
loose-fill (blown) fiberglass, and rigid polystyrene. Wall insulation is modeled
for new construction / major retrofits only.
HVAC (All) Insulation - Wall
Sheathing
Thermal insulation is material or combinations of materials that are used to
inhibit the flow of heat energy by conductive, convective, and radiative transfer
modes. Thus, thermal insulation can conserve energy by reducing heat loss or
gain from a building. The type of building construction defines insulating
possibilities. Typical insulating materials include: loose-fill (blown) cellulose,
loose-fill (blown) fiberglass, and rigid polystyrene. Wall sheathing is modeled
for new construction / major retrofits only.
Cooling Ducting - Repair and
Sealing
Leakage in unsealed ducts varies considerably because of the differences in
fabricating machinery used, the methods for assembly, installation
workmanship, and age of the ductwork. Air leaks from the system to the
outdoors result in a direct loss proportional to the amount of leakage and the
difference in enthalpy between the outdoor air and the conditioned air. To
seal ducts, a wide variety of sealing methods and products exist. Each has a
relatively short shelf life, and no documented research has identified the aging
characteristics of sealant applications.
HVAC (All)
Windows - High
Efficiency/ENERGY
STAR
High-efficiency windows, such as those labeled under the ENERGY STAR
Program, are designed to reduce energy use and increase occupant comfort.
High-efficiency windows reduce the amount of heat transfer through the
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 909 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-7
End Use Measure Description
glazing surface. For example, some windows have a low-E coating, a thin film of
metallic oxide coating on the glass surface that allows passage of short-wave
solar energy through glass and prevents long-wave energy from escaping.
Another example is double-pane glass that reduces conductive and convective
heat transfer. Some double-pane windows are gas-filled (usually argon) to
further increase the insulating properties of the window.
HVAC (All) Windows - Install
Reflective Film
Reflective films applied to the window interior help reduce solar gain into the
space and thus lower cooling energy use.
HVAC (All) Doors - Storm and
Thermal
Like other components of the shell, doors are subject to several types of heat
loss: conduction, infiltration, and radiant losses. Similar to a storm window, a
storm door creates an insulating air space between the storm and primary
doors. A tight fitting storm door can also help reduce air leakage or infiltration.
Thermal doors have exceptional thermal insulation properties and also are
provided with weather-stripping on the doorframe to reduce air leakage.
HVAC (All) Roofs - High
Reflectivity
The color and material of a building structure surface will determine the
amount of solar radiation absorbed by that surface and subsequently
transferred into a building. This is called solar absorptance. By using a living
roof or a roofing material with a light color (and a lower solar absorptance), the
roof will absorb less solar radiation and consequently reduce the cooling load.
Living roofs also reduce stormwater runoff.
HVAC (All) Attic Fan -
Installation
Attic fans can reduce the need for AC by reducing heat transfer from the attic
through the ceiling of the house. A well-ventilated attic can be several degrees
cooler than a comparable, unventilated attic. An option for an attic fan
equipped with a small solar photovoltaic generator is also modeled.
HVAC (All)
Attic Fan -
Photovoltaic -
Installation
Attic fans can reduce the need for AC by reducing heat transfer from the attic
through the ceiling of the house. A well-ventilated attic can be several degrees
cooler than a comparable, unventilated attic. An option for an attic fan
equipped with a small solar photovoltaic generator is also modeled.
HVAC (All) Whole-House Fan -
Installation
Whole-house fans can reduce the need for AC on moderate-weather days or on
cool evenings. The fan facilitates a quick air change throughout the entire
house. Several windows must be open to achieve the best results. The fan is
mounted on the top floor of the house, usually in a hallway ceiling.
HVAC (All) Ceiling Fan -
Installation
Ceiling fans can reduce the need for air conditioning. However, the house
occupants must also select a ceiling fan with a high-efficiency motor and either
shutoff the AC system or setup the thermostat temperature of the air
conditioning system to realize the potential energy savings. Some ceiling fans
also come with lamps. In this analysis, it is assumed that there are no lamps,
and installing a ceiling fan will allow occupants to increase the thermostat
cooling setpoint up by 2°F.
HVAC (All) Thermostat -
Clock/Programmable
A programmable thermostat can be added to most heating/cooling systems.
They are typically used during winter to lower temperatures at night and in
summer to increase temperatures during the afternoon. The energy savings
from this type of thermostat are identical to those of a "setback" strategy with
standard thermostats, but the convenience of a programmable thermostat
makes it a much more attractive option. In this analysis, the baseline is
assumed to have no thermostat setback.
HVAC (All) Home Energy
Management System
A centralized home energy management system can be used to control and
schedule cooling, space heating, lighting, and possibly appliances as well. Some
designs also allow the homeowner to remotely control loads via the Internet.
Cooling Central AC - Early
Replacement
CAC systems currently on the market are significantly more efficient that older
units, due to technology improvement and stricter appliance standards. This
measure incents homeowners to replace an aging but still working unit with a
new, higher-efficiency one.
Cooling
Central AC -
Maintenance and
Tune-Up
An air conditioner's filters, coils, and fins require regular cleaning and
maintenance for the unit to function effectively and efficiently throughout its
life. Neglecting necessary maintenance leads to a steady decline in
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 910 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-8 www.enernoc.com
End Use Measure Description
performance, requiring the AC unit to use more energy for the same cooling
load.
Cooling /
Space Heating
Central Heat Pump -
Maintenance
A heat pump's filters, coils, and fins require regular cleaning and maintenance
for the unit to function effectively and efficiently throughout its life. Neglecting
necessary maintenance ensures a steady decline in performance while energy
use steadily increases.
Cooling Room AC - Removal
of Second Unit
Homeowners may have a second room AC unit that is extremely inefficient.
This measure incents homeowners to recycle the second unit and thus also
eliminates associated electricity use.
Water
Heating
Water Heater -
Drainwater Heat
Recovery
Drainwater Heat Recovery is a system in which drain water is used to preheat
cold water entering the water heater. While these systems themselves are
relatively inexpensive, upgrading an existing system could be unreasonable
because of demolition costs. Thus they are modeled for new vintage only.
Water
Heating
Water Heater -
Faucet Aerators
Water faucet aerators are threaded screens that attach to existing faucets.
They reduce the volume of water coming out of faucets while introducing air
into the water stream. This measure provides energy saving by reducing hot
water use, as well as water conservation for both hot and cold water.
Water
Heating
Water Heater - Low-
Flow Showerheads
Similar to faucet aerators, low-flow showerheads reduce the consumption of
hot water, which in turn decreases water heating energy use.
Water
Heating
Water Heater - Pipe
Insulation
Insulating hot water pipes decreases energy losses from piping that distributes
hot water throughout the building. It also results in quicker delivery of hot
water and may allow the lowering of the hot water set point, which saves
energy. The most common insulation materials for this purpose are
polyethylene and neoprene.
Water
Heating
Water Heater -
Timer
These measures use either a programmable thermostat or a timer to adjust the
water heater setpoint at times of low usage, typically when a home is
unoccupied.
Water
Heating
Water Heater -
Desuperheater
A desuperheater can be added to an existing geothermal heat pump system
(typically installed with the primary function of space heating and cooling) in
order to draw off a portion of the geothermal heat for water heating purposes.
The system can either supplement the building's water heater, or be a full-
demand water heater that meets all of the building's hot water needs.
Water
Heating
Water Heater - Solar
System
Solar water heating systems can be used in residential buildings that have an
appropriate near-south-facing roof or nearby unshaded grounds for installing a
collector. Although system types vary, in general these systems use a solar
absorber surface within a solar collector or an actual storage tank. Either a
heat-transfer fluid or the actual potable water flows through tubes attached to
the absorber and transfers heat from it. (Systems with a separate heat-
transfer-fluid loop include a heat exchanger that then heats the potable water.)
The heated water is stored in a separate preheat tank or a conventional water
heater tank. If additional heat is needed, it is provided by a conventional
water-heating system.
Water
Heating
Tank Blanket
Insulation
Many water heaters have a high factory-set temperature, at 140 degrees F or
higher, but most users operate comfortably with the thermostat at 120
degrees F. Reducing the water heater temperature by as little as 10 degrees
can save between 3-5% in energy costs.
Water
Heating Thermostat Setback
Many water heaters have a high factory-set temperature, at 140 degrees F or
higher, but most users operate comfortably with the thermostat at 125
degrees F. Reducing the water heater temperature by as little as 10 degrees
can save between 3-5% in energy costs.
Interior
Lighting
Interior Lighting -
Occupancy Sensors
Occupancy sensors turn lights off when a space is unoccupied. They are
appropriate for areas with intermittent use, such as bathrooms or storage
areas.
Exterior
Lighting
Exterior Lighting -
Photosensor Control
Photosensor controls turn exterior lighting on or off based on ambient lighting
levels. Compared with manual operation, this can reduce the operation of
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 911 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-9
End Use Measure Description
exterior lighting during daylight hours.
Exterior
Lighting
Exterior Lighting -
Photovoltaic
Installation
Solar photovoltaic generation may be used to power exterior lighting and thus
eliminate all or part of the electrical energy use.
Exterior
Lighting
Exterior Lighting -
Timeclock
Installation
Lighting timers turn exterior lighting on or off based on a preset schedule.
Compared with manual operation, this can reduce the operation of exterior
lighting during daylight hours.
Appliances Refrigerator - Early
Replacement
Refrigerators/freezers currently on the market are significantly more efficient
that older units, due to technology improvement and stricter appliance
standards. This measure incents homeowners to replace an aging but still
working unit with a new, higher-efficiency one.
Appliances Refrigerator -
Remove Second Unit
Homeowners may have a second refrigerator or freezer that is not used to full
capacity and that, because of its age, is extremely inefficient. This measure
incents homeowners to recycle the second unit and thus also eliminates
associated electricity use.
Appliances Freezer - Remove
Second Unit
Homeowners may have a second refrigerator or freezer that is not used to full
capacity and that, because of its age, is extremely inefficient. This measure
incents homeowners to recycle the second unit and thus also eliminates
associated electricity use.
Appliances Freezer - Early
Replacement
Refrigerators/freezers currently on the market are significantly more efficient
that older units, due to technology improvement and stricter appliance
standards. This measure incents homeowners to replace an aging but still
working unit with a new, higher-efficiency one.
Electronics
Reduce Standby
Wattage - Smart
Power Strips
Representing a growing portion of home electricity consumption, plug-in
electronics such as set-top boxes, DVD players, gaming systems, digital video
recorders, and even battery chargers for mobile phones and laptop computers
are often designed to supply a set voltage. When the units are not in use, this
voltage could be dropped significantly (~1 W) and thereby generate a
significant energy savings, assumed for this analysis to be between 4-5% on
average. These savings are in excess of the measures already discussed for
computers and televisions.
Miscellaneous Pool Pump - Timer A pool pump timer allows the pump to turn off automatically, eliminating the
wasted energy associated with unnecessary pumping.
Miscellaneous Behavioral Measures
The behavioral measure models the wide range of options for providing
homeowners with ongoing information on their energy use, for example via a
web portal. These tools are based on the premise that homeowners will reduce
energy use if they better understand how they use energy and the associated
costs. The level of assumed savings is based on isolated behavioral effects and
excludes the technology effects of all other measures listed here.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 912 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-10 www.enernoc.com
Table B-3 Energy Efficiency Equipment Data, Electric—Single Family, Existing Vintage,
Washington
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Cooling Central AC SEER 13 - $0.00 15 - $0.00
Cooling Central AC SEER 14 (Energy Star) 116.70 $277.86 15 1.40 $0.21
Cooling Central AC SEER 15 (CEE Tier 2) 160.13 $555.71 15 0.95 $0.30
Cooling Central AC SEER 16 (CEE Tier 3) 196.50 $833.57 15 0.90 $0.37
Cooling Central AC Ductless Mini-Split
System 352.42 $4,399.48 20 0.64 $0.88
Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00
Cooling Room AC EER 10.8 (Energy
Star) 46.56 $104.04 10 0.84 $0.26
Cooling Room AC EER 11 54.94 $282.26 10 0.64 $0.61
Cooling Room AC EER 11.5 74.37 $625.50 10 0.44 $1.00
Cooling Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Cooling Air Source Heat
Pump SEER 14 (Energy Star) 85.84 $0.00 15 1.30 $0.00
Cooling Air Source Heat
Pump SEER 15 (CEE Tier 2) 97.34 $0.00 15 0.89 $0.00
Cooling Air Source Heat
Pump SEER 16 (CEE Tier 3) 119.45 $0.00 15 0.83 $0.00
Cooling Air Source Heat
Pump
Ductless Mini-Split
System 214.24 $0.00 20 0.83 $0.00
Cooling Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Cooling Geothermal Heat
Pump High Efficiency 104.84 $0.00 15 0.91 $0.00
Cooling Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance Electric Resistance - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance
Ductless Mini-Split
System 3,605.70 $156.87 20 1.34 $0.00
Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00
Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00
Space Heating Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Space Heating Air Source Heat
Pump SEER 14 (Energy Star) 126.61 $67.05 15 1.30 $0.05
Space Heating Air Source Heat
Pump SEER 15 (CEE Tier 2) 998.92 $2,318.20 15 0.89 $0.20
Space Heating Air Source Heat
Pump SEER 16 (CEE Tier 3) 1,225.79 $3,504.51 15 0.83 $0.25
Space Heating Air Source Heat
Pump
Ductless Mini-Split
System 2,198.46 $5,655.04 20 0.83 $0.18
Space Heating Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Space Heating Geothermal Heat
Pump High Efficiency 693.85 $1,500.00 15 0.91 $0.19
Space Heating Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Water Heating Water Heater <=
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater <=
55 Gal
High Efficiency
(EF=0.95) 207.44 $77.11 15 1.03 $0.03
Water Heating Water Heater <=
55 Gal EF 2.3 (HP) 1,999.65 $1,761.86 15 0.91 $0.08
Water Heating Water Heater <=
55 Gal Solar 2,791.58 $6,214.86 15 0.47 $0.19
Water Heating Water Heater >
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater > High Efficiency 264.15 $97.23 15 1.03 $0.03
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 913 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-11
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
55 Gal (EF=0.95)
Water Heating Water Heater >
55 Gal EF 2.3 (HP) 2,000.81 $1,691.15 15 0.93 $0.07
Water Heating Water Heater >
55 Gal Solar 3,154.00 $6,144.15 15 0.52 $0.17
Interior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Interior
Lighting Screw-in Infrared Halogen 269.42 $188.19 5 1.00 $0.15
Interior
Lighting Screw-in CFL 855.57 $33.82 6 2.54 $0.01
Interior
Lighting Screw-in LED 1,169.35 $1,937.55 12 - $0.17
Interior
Lighting Screw-in LED 1,169.35 $1,937.55 12 - $0.17
Interior
Lighting
Linear
Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting
Linear
Fluorescent T8 11.21 -$3.65 6 1.14 -$0.06
Interior
Lighting
Linear
Fluorescent Super T8 33.57 $29.17 6 0.70 $0.16
Interior
Lighting
Linear
Fluorescent T5 34.89 $49.41 6 0.55 $0.26
Interior
Lighting
Linear
Fluorescent LED 36.60 $433.68 10 0.19 $1.40
Interior
Lighting Specialty Halogen - $0.00 4 1.00 $0.00
Interior
Lighting Specialty CFL 263.66 $1.92 7 1.91 $0.00
Interior
Lighting Specialty LED 277.40 $522.52 12 0.29 $0.19
Exterior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Exterior
Lighting Screw-in Infrared Halogen 92.90 $51.30 5 1.00 $0.12
Exterior
Lighting Screw-in CFL 315.29 -$1.24 3 4.38 $0.00
Exterior
Lighting Screw-in LED 365.98 $757.28 12 - $0.21
Exterior
Lighting Screw-in LED 365.98 $757.28 12 - $0.21
Appliances Clothes Washer Baseline - $0.00 14 - $0.00
Appliances Clothes Washer Energy Star (MEF >
1.8) 51.92 $69.81 14 - $0.12
Appliances Clothes Washer Horizontal Axis 71.68 $150.80 14 1.00 $0.19
Appliances Clothes Dryer Baseline - $0.00 13 - $0.00
Appliances Clothes Dryer Moisture Detection 76.97 $48.40 13 1.00 $0.06
Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00
Appliances Dishwasher Energy Star 64.27 $460.95 9 - $0.93
Appliances Dishwasher Energy Star (2011) 8.42 $5.61 15 1.00 $0.06
Appliances Refrigerator Baseline - $0.00 20 - $0.00
Appliances Refrigerator Energy Star 55.03 $20.67 20 - $0.03
Appliances Refrigerator Baseline (2014) 100.80 $0.00 13 1.00 $0.00
Appliances Refrigerator Energy Star (2014) 161.28 $88.71 13 1.02 $0.05
Appliances Freezer Baseline - $0.00 22 - $0.00
Appliances Freezer Energy Star 44.98 $3.98 22 - $0.01
Appliances Freezer Baseline (2014) 104.39 -$145.00 11 1.00 -$0.15
Appliances Freezer Energy Star (2014) 167.03 -$112.83 11 1.00 -$0.07
Appliances Second
Refrigerator Baseline - $0.00 20 - $0.00
Appliances Second
Refrigerator Energy Star 75.16 $20.67 20 - $0.02
Appliances Second
Refrigerator Baseline (2014) 137.68 $0.00 13 1.00 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 914 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-12 www.enernoc.com
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Appliances Second
Refrigerator Energy Star (2014) 220.29 $88.71 13 1.01 $0.04
Appliances Stove Baseline - $0.00 13 1.00 $0.00
Appliances Stove Convection Oven 10.67 $1.86 13 1.00 $0.02
Appliances Stove Induction (High
Efficiency) 53.33 $1,432.20 13 0.39 $2.59
Appliances Microwave Baseline - $0.00 9 1.00 $0.00
Electronics Personal
Computers Baseline - $0.00 5 1.00 $0.00
Electronics Personal
Computers Energy Star 89.47 $1.20 5 1.01 $0.00
Electronics Personal
Computers Climate Savers 127.82 $175.49 5 0.85 $0.30
Electronics TVs Baseline - $0.00 11 1.00 $0.00
Electronics TVs Energy Star 52.12 $0.56 10 0.95 $0.00
Electronics Set-top
boxes/DVR Baseline - $0.00 11 1.00 $0.00
Electronics Set-top
boxes/DVR Energy Star 31.55 $0.56 11 1.01 $0.00
Electronics Devices and
Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00
Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00
Miscellaneous Pool Pump High Efficiency Pump 137.76 $85.00 15 1.00 $0.05
Miscellaneous Pool Pump Two-Speed Pump 551.02 $579.00 15 0.83 $0.09
Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00
Miscellaneous Furnace Fan Furnace Fan with
ECM 157.58 $0.64 18 1.28 $0.00
Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 915 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-13
Table B-4 Energy Efficiency Equipment Data, Electric—Single Family, New Vintage,
Washington
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Cooling Central AC SEER 13 - $0.00 15 - $0.00
Cooling Central AC SEER 14 (Energy Star) 148.36 $277.86 15 1.40 $0.16
Cooling Central AC SEER 15 (CEE Tier 2) 197.61 $555.71 15 0.95 $0.24
Cooling Central AC SEER 16 (CEE Tier 3) 238.95 $833.57 15 0.90 $0.30
Cooling Central AC Ductless Mini-Split
System 448.12 $4,399.48 20 0.65 $0.69
Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00
Cooling Room AC EER 10.8 (Energy
Star) 57.89 $104.04 10 0.85 $0.21
Cooling Room AC EER 11 68.22 $282.26 10 0.65 $0.49
Cooling Room AC EER 11.5 92.51 $625.50 10 0.45 $0.80
Cooling Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Cooling Air Source Heat
Pump SEER 14 (Energy Star) 109.44 $67.05 15 1.30 $0.05
Cooling Air Source Heat
Pump SEER 15 (CEE Tier 2) 120.45 $2,318.20 15 0.91 $1.66
Cooling Air Source Heat
Pump SEER 16 (CEE Tier 3) 145.65 $3,504.51 15 0.85 $2.08
Cooling Air Source Heat
Pump
Ductless Mini-Split
System 273.14 $5,655.04 20 0.87 $1.46
Cooling Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Cooling Geothermal Heat
Pump High Efficiency 124.81 $1,500.00 15 0.92 $1.04
Cooling Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance Electric Resistance - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance
Ductless Mini-Split
System 4,146.56 $156.87 20 1.35 $0.00
Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00
Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00
Space Heating Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Space Heating Air Source Heat
Pump SEER 14 (Energy Star) 161.42 $67.05 15 1.30 $0.04
Space Heating Air Source Heat
Pump SEER 15 (CEE Tier 2) 1,236.03 $2,318.20 15 0.91 $0.16
Space Heating Air Source Heat
Pump SEER 16 (CEE Tier 3) 1,494.65 $3,504.51 15 0.85 $0.20
Space Heating Air Source Heat
Pump
Ductless Mini-Split
System 2,802.94 $5,655.04 20 0.87 $0.14
Space Heating Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Space Heating Geothermal Heat
Pump High Efficiency 826.07 $1,500.00 15 0.92 $0.16
Space Heating Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Water Heating Water Heater <=
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater <=
55 Gal
High Efficiency
(EF=0.95) 207.44 $77.11 15 1.03 $0.03
Water Heating Water Heater <=
55 Gal EF 2.3 (HP) 1,999.65 $1,761.86 15 0.91 $0.08
Water Heating Water Heater <=
55 Gal Solar 2,791.58 $6,214.86 15 0.47 $0.19
Water Heating Water Heater >
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater > High Efficiency 264.15 $97.23 15 1.03 $0.03
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 916 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-14 www.enernoc.com
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
55 Gal (EF=0.95)
Water Heating Water Heater >
55 Gal EF 2.3 (HP) 2,000.81 $1,691.15 15 0.93 $0.07
Water Heating Water Heater >
55 Gal Solar 3,154.00 $6,144.15 15 0.52 $0.17
Interior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Interior
Lighting Screw-in Infrared Halogen 307.59 $188.19 5 1.00 $0.13
Interior
Lighting Screw-in CFL 976.77 $33.82 6 2.46 $0.01
Interior
Lighting Screw-in LED 1,334.99 $1,937.55 12 - $0.15
Interior
Lighting Screw-in LED 1,334.99 $1,937.55 12 - $0.15
Interior
Lighting
Linear
Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting
Linear
Fluorescent T8 13.19 -$3.65 6 1.13 -$0.05
Interior
Lighting
Linear
Fluorescent Super T8 39.53 $29.17 6 0.73 $0.14
Interior
Lighting
Linear
Fluorescent T5 41.09 $49.41 6 0.58 $0.22
Interior
Lighting
Linear
Fluorescent LED 43.10 $433.68 10 0.21 $1.19
Interior
Lighting Specialty Halogen - $0.00 4 1.00 $0.00
Interior
Lighting Specialty CFL 303.20 -$6.90 7 2.33 $0.00
Interior
Lighting Specialty LED 319.01 $163.55 12 0.76 $0.05
Exterior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Exterior
Lighting Screw-in Infrared Halogen 168.10 $20.17 5 1.00 $0.03
Exterior
Lighting Screw-in CFL 473.06 $0.00 3 4.21 $0.00
Exterior
Lighting Screw-in LED 599.29 $88.71 12 - $0.02
Exterior
Lighting Screw-in LED 599.29 $88.71 12 - $0.02
Appliances Clothes Washer Baseline - $0.00 14 - $0.00
Appliances Clothes Washer Energy Star (MEF >
1.8) 100.07 $3.98 14 - $0.00
Appliances Clothes Washer Horizontal Axis 183.40 -$145.00 14 1.00 -$0.07
Appliances Clothes Dryer Baseline - $0.00 13 - $0.00
Appliances Clothes Dryer Moisture Detection 76.97 $48.40 13 1.00 $0.06
Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00
Appliances Dishwasher Energy Star 64.52 $460.95 9 - $0.92
Appliances Dishwasher Energy Star (2011) 8.45 $5.61 15 1.00 $0.06
Appliances Refrigerator Baseline - $0.00 20 - $0.00
Appliances Refrigerator Energy Star 62.37 $20.17 20 - $0.02
Appliances Refrigerator Baseline (2014) 114.24 $0.00 13 1.00 $0.00
Appliances Refrigerator Energy Star (2014) 182.79 $88.71 13 1.02 $0.05
Appliances Freezer Baseline - $0.00 22 - $0.00
Appliances Freezer Energy Star 48.14 $3.98 22 - $0.01
Appliances Freezer Baseline (2014) 111.72 -$145.00 11 1.00 -$0.14
Appliances Freezer Energy Star (2014) 178.76 -$112.83 11 1.01 -$0.07
Appliances Second
Refrigerator Baseline - $0.00 20 - $0.00
Appliances Second
Refrigerator Energy Star 80.17 $20.67 20 - $0.02
Appliances Second
Refrigerator Baseline (2014) 146.86 $0.00 13 1.00 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 917 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-15
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Appliances Second
Refrigerator Energy Star (2014) 234.98 $88.71 13 1.01 $0.04
Appliances Stove Baseline - $0.00 13 1.00 $0.00
Appliances Stove Convection Oven 10.66 $1.86 13 1.00 $0.02
Appliances Stove Induction (High
Efficiency) 53.32 $1,432.20 13 0.39 $2.59
Appliances Microwave Baseline - $0.00 9 1.00 $0.00
Electronics Personal
Computers Baseline - $0.00 5 1.00 $0.00
Electronics Personal
Computers Energy Star 87.57 $1.20 5 1.01 $0.00
Electronics Personal
Computers Climate Savers 125.09 $175.49 5 0.85 $0.30
Electronics TVs Baseline - $0.00 11 1.00 $0.00
Electronics TVs Energy Star 57.91 $0.56 11 1.02 $0.00
Electronics Set-top
boxes/DVR Baseline - $0.00 11 1.00 $0.00
Electronics Set-top
boxes/DVR Energy Star 31.55 $0.56 11 1.01 $0.00
Electronics Devices and
Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00
Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00
Miscellaneous Pool Pump High Efficiency Pump 155.66 $85.00 15 1.01 $0.05
Miscellaneous Pool Pump Two-Speed Pump 622.65 $579.00 15 0.88 $0.08
Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00
Miscellaneous Furnace Fan Furnace Fan with
ECM 157.58 $0.64 18 1.28 $0.00
Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 918 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-16 www.enernoc.com
Table B-5 Energy Efficiency Equipment Data, Electric—Single Family, Existing Vintage, Idaho
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Cooling Central AC SEER 13 - $0.00 15 - $0.00
Cooling Central AC SEER 14 (Energy Star) 105.03 $277.86 15 1.40 $0.23
Cooling Central AC SEER 15 (CEE Tier 2) 144.12 $555.71 15 0.94 $0.33
Cooling Central AC SEER 16 (CEE Tier 3) 176.85 $833.57 15 0.89 $0.41
Cooling Central AC Ductless Mini-Split
System 317.18 $4,399.48 20 0.64 $0.98
Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00
Cooling Room AC EER 10.8 (Energy
Star) 41.90 $104.04 10 0.83 $0.29
Cooling Room AC EER 11 49.45 $282.26 10 0.63 $0.68
Cooling Room AC EER 11.5 66.94 $625.50 10 0.43 $1.11
Cooling Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Cooling Air Source Heat
Pump SEER 14 (Energy Star) 77.25 $0.00 15 1.30 $0.00
Cooling Air Source Heat
Pump SEER 15 (CEE Tier 2) 87.61 $0.00 15 0.89 $0.00
Cooling Air Source Heat
Pump SEER 16 (CEE Tier 3) 107.51 $0.00 15 0.84 $0.00
Cooling Air Source Heat
Pump
Ductless Mini-Split
System 192.81 $0.00 20 0.85 $0.00
Cooling Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Cooling Geothermal Heat
Pump High Efficiency 94.35 $0.00 15 0.91 $0.00
Cooling Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance Electric Resistance - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance
Ductless Mini-Split
System 3,785.99 $156.87 20 1.35 $0.00
Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00
Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00
Space Heating Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Space Heating Air Source Heat
Pump SEER 14 (Energy Star) 132.94 $67.05 15 1.30 $0.04
Space Heating Air Source Heat
Pump SEER 15 (CEE Tier 2) 1,048.86 $2,318.20 15 0.89 $0.19
Space Heating Air Source Heat
Pump SEER 16 (CEE Tier 3) 1,287.08 $3,504.51 15 0.84 $0.24
Space Heating Air Source Heat
Pump
Ductless Mini-Split
System 2,308.39 $5,655.04 20 0.85 $0.17
Space Heating Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Space Heating Geothermal Heat
Pump High Efficiency 728.55 $1,500.00 15 0.91 $0.18
Space Heating Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Water Heating Water Heater <=
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater <=
55 Gal
High Efficiency
(EF=0.95) 217.82 $77.11 15 1.03 $0.03
Water Heating Water Heater <=
55 Gal EF 2.3 (HP) 2,099.63 $1,761.86 15 0.87 $0.07
Water Heating Water Heater <=
55 Gal Solar 2,931.16 $6,214.86 15 0.44 $0.18
Water Heating Water Heater >
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater >
55 Gal
High Efficiency
(EF=0.95) 277.36 $97.23 15 1.03 $0.03
Water Heating Water Heater > EF 2.3 (HP) 2,100.85 $1,691.15 15 0.90 $0.07
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 919 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-17
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
55 Gal
Water Heating Water Heater >
55 Gal Solar 1,877.26 $6,144.15 15 0.43 $0.28
Interior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Interior
Lighting Screw-in Infrared Halogen 282.89 $188.19 5 1.00 $0.14
Interior
Lighting Screw-in CFL 898.35 $33.82 6 2.59 $0.01
Interior
Lighting Screw-in LED 1,227.82 $1,937.55 12 - $0.16
Interior
Lighting Screw-in LED 1,227.82 $1,937.55 12 - $0.16
Interior
Lighting
Linear
Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting
Linear
Fluorescent T8 11.77 -$3.50 6 1.14 -$0.05
Interior
Lighting
Linear
Fluorescent Super T8 35.25 $28.01 6 0.71 $0.15
Interior
Lighting
Linear
Fluorescent T5 36.64 $47.43 6 0.56 $0.24
Interior
Lighting
Linear
Fluorescent LED 38.43 $416.33 10 0.20 $1.28
Interior
Lighting Specialty Halogen - $0.00 4 1.00 $0.00
Interior
Lighting Specialty CFL 276.84 $1.92 7 1.93 $0.00
Interior
Lighting Specialty LED 291.27 $522.52 12 0.30 $0.18
Exterior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Exterior
Lighting Screw-in Infrared Halogen 97.55 $49.25 5 1.00 $0.11
Exterior
Lighting Screw-in CFL 331.06 -$1.19 3 4.38 $0.00
Exterior
Lighting Screw-in LED 384.28 $726.99 12 - $0.19
Exterior
Lighting Screw-in LED 384.28 $726.99 12 - $0.19
Appliances Clothes Washer Baseline - $0.00 14 - $0.00
Appliances Clothes Washer Energy Star (MEF >
1.8) 51.92 $69.81 14 - $0.12
Appliances Clothes Washer Horizontal Axis 71.68 $150.80 14 1.00 $0.19
Appliances Clothes Dryer Baseline - $0.00 13 - $0.00
Appliances Clothes Dryer Moisture Detection 76.97 $48.40 13 1.00 $0.06
Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00
Appliances Dishwasher Energy Star 64.27 $460.95 9 - $0.93
Appliances Dishwasher Energy Star (2011) 8.42 $5.61 15 1.00 $0.06
Appliances Refrigerator Baseline - $0.00 20 - $0.00
Appliances Refrigerator Energy Star 55.03 $20.17 20 - $0.03
Appliances Refrigerator Baseline (2014) 100.80 $0.00 13 1.00 $0.00
Appliances Refrigerator Energy Star (2014) 161.28 $88.71 13 1.01 $0.05
Appliances Freezer Baseline - $0.00 22 - $0.00
Appliances Freezer Energy Star 44.98 $3.98 22 - $0.01
Appliances Freezer Baseline (2014) 104.39 -$145.00 11 1.00 -$0.15
Appliances Freezer Energy Star (2014) 167.03 -$112.83 11 1.00 -$0.07
Appliances Second
Refrigerator Baseline - $0.00 20 - $0.00
Appliances Second
Refrigerator Energy Star 75.16 $20.67 20 - $0.02
Appliances Second
Refrigerator Baseline (2014) 137.68 $0.00 13 1.00 $0.00
Appliances Second
Refrigerator Energy Star (2014) 220.29 $88.71 13 1.01 $0.04
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 920 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-18 www.enernoc.com
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Appliances Stove Baseline - $0.00 13 1.00 $0.00
Appliances Stove Convection Oven 10.67 $1.86 13 1.00 $0.02
Appliances Stove Induction (High
Efficiency) 53.33 $1,432.20 13 0.38 $2.59
Appliances Microwave Baseline - $0.00 9 1.00 $0.00
Electronics Personal
Computers Baseline - $0.00 5 1.00 $0.00
Electronics Personal
Computers Energy Star 89.47 $1.20 5 1.01 $0.00
Electronics Personal
Computers Climate Savers 127.82 $175.49 5 0.85 $0.30
Electronics TVs Baseline - $0.00 11 1.00 $0.00
Electronics TVs Energy Star 52.12 $0.56 11 1.02 $0.00
Electronics Set-top
boxes/DVR Baseline - $0.00 11 1.00 $0.00
Electronics Set-top
boxes/DVR Energy Star 31.55 $0.56 11 1.01 $0.00
Electronics Devices and
Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00
Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00
Miscellaneous Pool Pump High Efficiency Pump 137.76 $85.00 15 1.00 $0.05
Miscellaneous Pool Pump Two-Speed Pump 551.02 $579.00 15 0.83 $0.09
Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00
Miscellaneous Furnace Fan Furnace Fan with
ECM 165.46 $0.64 18 1.29 $0.00
Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 921 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-19
Table B-6 Energy Efficiency Equipment Data, Electric—Single Family, New Vintage, Idaho
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Cooling Central AC SEER 13 - $0.00 15 - $0.00
Cooling Central AC SEER 14 (Energy Star) 133.52 $277.86 15 1.40 $0.18
Cooling Central AC SEER 15 (CEE Tier 2) 177.85 $555.71 15 0.95 $0.27
Cooling Central AC SEER 16 (CEE Tier 3) 215.06 $833.57 15 0.90 $0.34
Cooling Central AC Ductless Mini-Split
System 403.30 $4,399.48 20 0.64 $0.77
Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00
Cooling Room AC EER 10.8 (Energy
Star) 52.10 $104.04 10 0.84 $0.24
Cooling Room AC EER 11 61.40 $282.26 10 0.64 $0.55
Cooling Room AC EER 11.5 83.26 $625.50 10 0.44 $0.89
Cooling Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Cooling Air Source Heat
Pump SEER 14 (Energy Star) 98.49 $67.05 15 1.30 $0.06
Cooling Air Source Heat
Pump SEER 15 (CEE Tier 2) 108.40 $2,318.20 15 0.92 $1.85
Cooling Air Source Heat
Pump SEER 16 (CEE Tier 3) 131.09 $3,504.51 15 0.87 $2.31
Cooling Air Source Heat
Pump
Ductless Mini-Split
System 245.83 $5,655.04 20 0.88 $1.63
Cooling Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Cooling Geothermal Heat
Pump High Efficiency 112.33 $1,500.00 15 0.92 $1.15
Cooling Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance Electric Resistance - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance
Ductless Mini-Split
System 4,353.88 $156.87 20 1.37 $0.00
Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00
Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00
Space Heating Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Space Heating Air Source Heat
Pump SEER 14 (Energy Star) 169.49 $67.05 15 1.30 $0.03
Space Heating Air Source Heat
Pump SEER 15 (CEE Tier 2) 1,297.83 $2,318.20 15 0.92 $0.15
Space Heating Air Source Heat
Pump SEER 16 (CEE Tier 3) 1,569.38 $3,504.51 15 0.87 $0.19
Space Heating Air Source Heat
Pump
Ductless Mini-Split
System 2,943.09 $5,655.04 20 0.88 $0.14
Space Heating Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Space Heating Geothermal Heat
Pump High Efficiency 867.38 $1,500.00 15 0.92 $0.15
Space Heating Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Water Heating Water Heater <=
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater <=
55 Gal
High Efficiency
(EF=0.95) 217.82 $77.11 15 1.03 $0.03
Water Heating Water Heater <=
55 Gal EF 2.3 (HP) 2,099.63 $1,761.86 15 0.87 $0.07
Water Heating Water Heater <=
55 Gal Solar 2,931.16 $6,214.86 15 0.44 $0.18
Water Heating Water Heater >
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater >
55 Gal
High Efficiency
(EF=0.95) 277.36 $97.23 15 1.03 $0.03
Water Heating Water Heater > EF 2.3 (HP) 2,100.85 $1,691.15 15 0.90 $0.07
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 922 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-20 www.enernoc.com
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
55 Gal
Water Heating Water Heater >
55 Gal Solar 1,877.26 $6,144.15 15 0.43 $0.28
Interior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Interior
Lighting Screw-in Infrared Halogen 322.96 $188.19 5 1.00 $0.13
Interior
Lighting Screw-in CFL 1,025.61 $33.82 6 2.51 $0.01
Interior
Lighting Screw-in LED 1,401.74 $1,937.55 12 - $0.14
Interior
Lighting Screw-in LED 1,401.74 $1,937.55 12 - $0.14
Interior
Lighting
Linear
Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting
Linear
Fluorescent T8 13.85 -$3.50 6 1.13 -$0.05
Interior
Lighting
Linear
Fluorescent Super T8 41.50 $28.01 6 0.74 $0.12
Interior
Lighting
Linear
Fluorescent T5 43.14 $47.43 6 0.59 $0.20
Interior
Lighting
Linear
Fluorescent LED 45.26 $416.33 10 0.21 $1.09
Interior
Lighting Specialty Halogen - $0.00 4 1.00 $0.00
Interior
Lighting Specialty CFL 318.36 -$6.40 7 2.32 $0.00
Interior
Lighting Specialty LED 334.96 $164.04 12 0.77 $0.05
Exterior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Exterior
Lighting Screw-in Infrared Halogen 173.38 $20.17 5 1.00 $0.03
Exterior
Lighting Screw-in CFL 491.00 $0.00 3 4.30 $0.00
Exterior
Lighting Screw-in LED 620.11 $88.71 12 - $0.01
Exterior
Lighting Screw-in LED 620.11 $88.71 12 - $0.01
Appliances Clothes Washer Baseline - $0.00 14 - $0.00
Appliances Clothes Washer Energy Star (MEF >
1.8) 100.07 $3.98 14 - $0.00
Appliances Clothes Washer Horizontal Axis 183.40 -$145.00 14 1.00 -$0.07
Appliances Clothes Dryer Baseline - $0.00 13 - $0.00
Appliances Clothes Dryer Moisture Detection 76.97 $48.40 13 1.00 $0.06
Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00
Appliances Dishwasher Energy Star 64.52 $460.95 9 - $0.92
Appliances Dishwasher Energy Star (2011) 8.45 $5.61 15 1.00 $0.06
Appliances Refrigerator Baseline - $0.00 20 - $0.00
Appliances Refrigerator Energy Star 62.37 $20.17 20 - $0.02
Appliances Refrigerator Baseline (2014) 114.24 $0.00 13 1.00 $0.00
Appliances Refrigerator Energy Star (2014) 182.79 $88.71 13 1.02 $0.05
Appliances Freezer Baseline - $0.00 22 - $0.00
Appliances Freezer Energy Star 48.14 $3.98 22 - $0.01
Appliances Freezer Baseline (2014) 111.72 -$145.00 11 1.00 -$0.14
Appliances Freezer Energy Star (2014) 178.76 -$112.83 11 1.00 -$0.07
Appliances Second
Refrigerator Baseline - $0.00 20 - $0.00
Appliances Second
Refrigerator Energy Star 80.17 $20.67 20 - $0.02
Appliances Second
Refrigerator Baseline (2014) 146.86 $0.00 13 1.00 $0.00
Appliances Second
Refrigerator Energy Star (2014) 234.98 $88.71 13 1.01 $0.04
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 923 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-21
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Appliances Stove Baseline - $0.00 13 1.00 $0.00
Appliances Stove Convection Oven 11.73 $1.86 13 1.00 $0.02
Appliances Stove Induction (High
Efficiency) 58.65 $1,432.20 13 0.38 $2.35
Appliances Microwave Baseline - $0.00 9 1.00 $0.00
Electronics Personal
Computers Baseline - $0.00 5 1.00 $0.00
Electronics Personal
Computers Energy Star 87.57 $1.20 5 1.01 $0.00
Electronics Personal
Computers Climate Savers 125.09 $175.49 5 0.85 $0.30
Electronics TVs Baseline - $0.00 11 1.00 $0.00
Electronics TVs Energy Star 57.91 $0.56 11 1.02 $0.00
Electronics Set-top
boxes/DVR Baseline - $0.00 11 1.00 $0.00
Electronics Set-top
boxes/DVR Energy Star 31.55 $0.56 11 1.01 $0.00
Electronics Devices and
Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00
Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00
Miscellaneous Pool Pump High Efficiency Pump 155.66 $85.00 15 1.01 $0.05
Miscellaneous Pool Pump Two-Speed Pump 622.65 $579.00 15 0.87 $0.08
Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00
Miscellaneous Furnace Fan Furnace Fan with
ECM 165.46 $0.64 18 1.29 $0.00
Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 924 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-22 www.enernoc.com
Table B-7 Energy Efficiency Equipment Data, Electric—Multi Family, Existing Vintage,
Washington
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Cooling Central AC SEER 13 - $0.00 15 - $0.00
Cooling Central AC SEER 14 (Energy Star) 41.57 $92.62 15 1.40 $0.19
Cooling Central AC SEER 15 (CEE Tier 2) 81.72 $185.24 15 0.96 $0.20
Cooling Central AC SEER 16 (CEE Tier 3) 115.28 $277.86 15 0.93 $0.21
Cooling Central AC Ductless Mini-Split
System 150.88 $2,012.28 20 0.62 $0.94
Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00
Cooling Room AC EER 10.8 (Energy
Star) 32.61 $52.02 10 0.86 $0.19
Cooling Room AC EER 11 38.42 $141.13 10 0.66 $0.44
Cooling Room AC EER 11.5 52.05 $312.75 10 0.46 $0.71
Cooling Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Cooling Air Source Heat
Pump SEER 14 (Energy Star) 44.14 $1,245.78 15 1.30 $2.44
Cooling Air Source Heat
Pump SEER 15 (CEE Tier 2) 71.87 $2,315.13 15 0.92 $2.79
Cooling Air Source Heat
Pump SEER 16 (CEE Tier 3) 101.38 $3,277.48 15 0.85 $2.80
Cooling Air Source Heat
Pump
Ductless Mini-Split
System 132.69 $5,022.03 20 0.85 $2.68
Cooling Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Cooling Geothermal Heat
Pump High Efficiency 63.75 $1,500.00 15 0.89 $2.03
Cooling Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance Electric Resistance - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance
Ductless Mini-Split
System 1,812.94 $156.87 20 1.27 $0.01
Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00
Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00
Space Heating Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Space Heating Air Source Heat
Pump SEER 14 (Energy Star) 172.19 $1,245.78 15 1.30 $0.63
Space Heating Air Source Heat
Pump SEER 15 (CEE Tier 2) 538.74 $2,315.13 15 0.92 $0.37
Space Heating Air Source Heat
Pump SEER 16 (CEE Tier 3) 760.01 $3,277.48 15 0.85 $0.37
Space Heating Air Source Heat
Pump
Ductless Mini-Split
System 994.66 $5,022.03 20 0.85 $0.36
Space Heating Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Space Heating Geothermal Heat
Pump High Efficiency 416.01 $1,500.00 15 0.89 $0.31
Space Heating Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Water Heating Water Heater <=
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater <=
55 Gal
High Efficiency
(EF=0.95) 110.09 $77.11 15 1.01 $0.06
Water Heating Water Heater <=
55 Gal EF 2.3 (HP) 1,061.19 $1,761.86 15 0.64 $0.14
Water Heating Water Heater <=
55 Gal Solar 1,202.35 $6,214.86 15 0.27 $0.45
Water Heating Water Heater >
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater > High Efficiency 182.05 $97.23 15 1.02 $0.05
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 925 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-23
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
55 Gal (EF=0.95)
Water Heating Water Heater >
55 Gal EF 2.3 (HP) 1,378.92 $1,691.15 15 0.78 $0.11
Water Heating Water Heater >
55 Gal Solar 1,231.85 $6,144.15 15 0.35 $0.43
Interior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Interior
Lighting Screw-in Infrared Halogen 163.13 $134.14 5 1.00 $0.18
Interior
Lighting Screw-in CFL 518.03 $12.45 6 2.94 $0.00
Interior
Lighting Screw-in LED 708.02 $1,161.45 12 - $0.17
Interior
Lighting Screw-in LED 708.02 $1,161.45 12 - $0.17
Interior
Lighting
Linear
Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting
Linear
Fluorescent T8 7.79 -$1.83 6 1.13 -$0.04
Interior
Lighting
Linear
Fluorescent Super T8 23.35 $14.59 6 0.76 $0.11
Interior
Lighting
Linear
Fluorescent T5 24.27 $24.70 6 0.61 $0.19
Interior
Lighting
Linear
Fluorescent LED 25.46 $216.84 10 0.23 $1.01
Interior
Lighting Specialty Halogen - $0.00 4 1.00 $0.00
Interior
Lighting Specialty CFL 105.71 $0.77 7 1.91 $0.00
Interior
Lighting Specialty LED 111.22 $209.01 12 0.29 $0.19
Exterior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Exterior
Lighting Screw-in Infrared Halogen 5.39 $5.08 5 1.00 $0.20
Exterior
Lighting Screw-in CFL 18.28 -$0.32 3 5.74 -$0.01
Exterior
Lighting Screw-in LED 21.22 $1,167.57 12 - $5.64
Exterior
Lighting Screw-in LED 21.22 $1,167.57 12 - $5.64
Appliances Clothes Washer Baseline - $0.00 14 - $0.00
Appliances Clothes Washer Energy Star (MEF >
1.8) 41.54 $69.81 14 - $0.15
Appliances Clothes Washer Horizontal Axis 57.34 $150.80 14 1.00 $0.24
Appliances Clothes Dryer Baseline - $0.00 13 - $0.00
Appliances Clothes Dryer Moisture Detection 61.35 $48.40 13 1.00 $0.08
Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00
Appliances Dishwasher Energy Star 51.42 $460.95 15 - $0.78
Appliances Dishwasher Energy Star (2011) 6.74 $5.61 15 1.00 $0.07
Appliances Refrigerator Baseline - $0.00 20 - $0.00
Appliances Refrigerator Energy Star 44.02 $20.17 20 - $0.03
Appliances Refrigerator Baseline (2014) 80.64 $0.00 13 1.00 $0.00
Appliances Refrigerator Energy Star (2014) 129.03 $88.71 13 1.01 $0.07
Appliances Freezer Baseline - $0.00 22 - $0.00
Appliances Freezer Energy Star 35.99 $3.98 22 - $0.01
Appliances Freezer Baseline (2014) 83.52 -$145.00 11 1.00 -$0.19
Appliances Freezer Energy Star (2014) 133.62 -$112.83 11 0.99 -$0.09
Appliances Second
Refrigerator Baseline - $0.00 20 - $0.00
Appliances Second
Refrigerator Energy Star 60.13 $20.67 20 - $0.02
Appliances Second
Refrigerator Baseline (2014) 110.14 $0.00 13 1.00 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 926 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-24 www.enernoc.com
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Appliances Second
Refrigerator Energy Star (2014) 176.23 $88.71 13 1.01 $0.05
Appliances Stove Baseline - $0.00 13 1.00 $0.00
Appliances Stove Convection Oven 8.53 $1.86 13 1.00 $0.02
Appliances Stove Induction (High
Efficiency) 42.66 $1,432.20 13 0.38 $3.23
Appliances Microwave Baseline - $0.00 9 1.00 $0.00
Electronics Personal
Computers Baseline - $0.00 5 1.00 $0.00
Electronics Personal
Computers Energy Star 71.58 $1.20 5 1.01 $0.00
Electronics Personal
Computers Climate Savers 102.26 $175.49 5 0.85 $0.37
Electronics TVs Baseline - $0.00 11 1.00 $0.00
Electronics TVs Energy Star 46.91 $0.56 11 1.02 $0.00
Electronics Set-top
boxes/DVR Baseline - $0.00 11 1.00 $0.00
Electronics Set-top
boxes/DVR Energy Star 31.55 $0.56 11 1.01 $0.00
Electronics Devices and
Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00
Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00
Miscellaneous Pool Pump High Efficiency Pump 137.76 $85.00 15 1.00 $0.05
Miscellaneous Pool Pump Two-Speed Pump 551.02 $579.00 15 0.83 $0.09
Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00
Miscellaneous Furnace Fan Furnace Fan with
ECM 126.06 $0.00 18 1.27 $0.00
Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 927 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-25
Table B-8 Energy EfficiencyEquipment Data, Electric—Multi Family, New Vintage, Washington
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Cooling Central AC SEER 13 - $0.00 15 - $0.00
Cooling Central AC SEER 14 (Energy Star) 53.20 $92.62 15 1.40 $0.15
Cooling Central AC SEER 15 (CEE Tier 2) 103.85 $185.24 15 0.97 $0.15
Cooling Central AC SEER 16 (CEE Tier 3) 146.35 $277.86 15 0.93 $0.16
Cooling Central AC Ductless Mini-Split
System 192.62 $2,012.28 20 0.63 $0.74
Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00
Cooling Room AC EER 10.8 (Energy
Star) 40.50 $52.02 10 0.87 $0.15
Cooling Room AC EER 11 47.72 $141.13 10 0.69 $0.35
Cooling Room AC EER 11.5 64.71 $312.75 10 0.49 $0.57
Cooling Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Cooling Air Source Heat
Pump SEER 14 (Energy Star) 56.37 $1,245.78 15 1.30 $1.91
Cooling Air Source Heat
Pump SEER 15 (CEE Tier 2) 91.36 $2,315.13 15 0.94 $2.19
Cooling Air Source Heat
Pump SEER 16 (CEE Tier 3) 128.74 $3,277.48 15 0.88 $2.20
Cooling Air Source Heat
Pump
Ductless Mini-Split
System 169.45 $5,022.03 20 0.87 $2.10
Cooling Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Cooling Geothermal Heat
Pump High Efficiency 75.90 $1,500.00 15 0.90 $1.71
Cooling Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance Electric Resistance - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance
Ductless Mini-Split
System 2,084.88 $156.87 20 1.29 $0.01
Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00
Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00
Space Heating Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Space Heating Air Source Heat
Pump SEER 14 (Energy Star) 219.90 $1,245.78 15 1.30 $0.49
Space Heating Air Source Heat
Pump SEER 15 (CEE Tier 2) 684.88 $2,315.13 15 0.94 $0.29
Space Heating Air Source Heat
Pump SEER 16 (CEE Tier 3) 965.10 $3,277.48 15 0.88 $0.29
Space Heating Air Source Heat
Pump
Ductless Mini-Split
System 1,270.27 $5,022.03 20 0.87 $0.28
Space Heating Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Space Heating Geothermal Heat
Pump High Efficiency 495.28 $1,500.00 15 0.90 $0.26
Space Heating Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Water Heating Water Heater <=
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater <=
55 Gal
High Efficiency
(EF=0.95) 110.09 $77.11 15 1.01 $0.06
Water Heating Water Heater <=
55 Gal EF 2.3 (HP) 1,061.19 $1,761.86 15 0.64 $0.14
Water Heating Water Heater <=
55 Gal Solar 1,202.35 $6,214.86 15 0.27 $0.45
Water Heating Water Heater >
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater >
55 Gal
High Efficiency
(EF=0.95) 182.05 $97.23 15 1.02 $0.05
Water Heating Water Heater > EF 2.3 (HP) 1,378.92 $1,691.15 15 0.78 $0.11
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 928 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-26 www.enernoc.com
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
55 Gal
Water Heating Water Heater >
55 Gal Solar 1,231.85 $6,144.15 15 0.35 $0.43
Interior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Interior
Lighting Screw-in Infrared Halogen 186.22 $134.14 5 1.00 $0.16
Interior
Lighting Screw-in CFL 591.38 $12.45 6 2.81 $0.00
Interior
Lighting Screw-in LED 808.26 $1,381.00 12 - $0.18
Interior
Lighting Screw-in LED 808.26 $1,381.00 12 - $0.18
Interior
Lighting
Linear
Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting
Linear
Fluorescent T8 9.18 -$1.83 6 1.13 -$0.04
Interior
Lighting
Linear
Fluorescent Super T8 27.49 $14.59 6 0.80 $0.10
Interior
Lighting
Linear
Fluorescent T5 28.58 $24.70 6 0.65 $0.16
Interior
Lighting
Linear
Fluorescent LED 29.98 $216.84 10 0.24 $0.86
Interior
Lighting Specialty Halogen - $0.00 4 1.00 $0.00
Interior
Lighting Specialty CFL 121.57 -$13.05 7 3.30 -$0.02
Interior
Lighting Specialty LED 127.91 $62.12 12 1.02 $0.05
Exterior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Exterior
Lighting Screw-in Infrared Halogen 6.13 $5.08 5 1.00 $0.18
Exterior
Lighting Screw-in CFL 20.80 -$0.32 3 5.55 -$0.01
Exterior
Lighting Screw-in LED 24.14 $75.05 12 - $0.32
Exterior
Lighting Screw-in LED 24.14 $75.05 12 - $0.32
Appliances Clothes Washer Baseline - $0.00 14 - $0.00
Appliances Clothes Washer Energy Star (MEF >
1.8) 41.54 $69.81 14 - $0.15
Appliances Clothes Washer Horizontal Axis 57.34 $150.80 14 1.00 $0.24
Appliances Clothes Dryer Baseline - $0.00 13 - $0.00
Appliances Clothes Dryer Moisture Detection 61.35 $48.40 13 1.00 $0.08
Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00
Appliances Dishwasher Energy Star 51.61 $460.95 9 - $1.15
Appliances Dishwasher Energy Star (2011) 6.76 $5.61 15 1.00 $0.07
Appliances Refrigerator Baseline - $0.00 20 - $0.00
Appliances Refrigerator Energy Star 49.89 $20.17 20 - $0.03
Appliances Refrigerator Baseline (2014) 91.39 $0.00 13 1.00 $0.00
Appliances Refrigerator Energy Star (2014) 146.23 $88.71 13 1.01 $0.06
Appliances Freezer Baseline - $0.00 22 - $0.00
Appliances Freezer Energy Star 38.51 $3.98 22 - $0.01
Appliances Freezer Baseline (2014) 89.38 -$145.00 11 1.00 -$0.18
Appliances Freezer Energy Star (2014) 143.01 -$112.83 11 1.00 -$0.09
Appliances Second
Refrigerator Baseline - $0.00 13 - $0.00
Appliances Second
Refrigerator Energy Star 64.14 $20.67 20 - $0.02
Appliances Second
Refrigerator Baseline (2014) 117.49 $0.00 13 1.00 $0.00
Appliances Second
Refrigerator Energy Star (2014) 187.98 $88.71 13 1.01 $0.05
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 929 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-27
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Appliances Stove Baseline - $0.00 13 1.00 $0.00
Appliances Stove Convection Oven 8.53 $1.86 13 1.00 $0.02
Appliances Stove Induction (High
Efficiency) 42.66 $1,432.20 13 0.38 $3.23
Appliances Microwave Baseline - $0.00 9 1.00 $0.00
Electronics Personal
Computers Baseline - $0.00 5 1.00 $0.00
Electronics Personal
Computers Energy Star 70.05 $1.20 5 1.01 $0.00
Electronics Personal
Computers Climate Savers 100.08 $175.49 5 0.85 $0.38
Electronics TVs Baseline - $0.00 11 1.00 $0.00
Electronics TVs Energy Star 52.12 $0.56 11 1.02 $0.00
Electronics Set-top
boxes/DVR Baseline - $0.00 11 1.00 $0.00
Electronics Set-top
boxes/DVR Energy Star 31.55 $0.56 11 1.01 $0.00
Electronics Devices and
Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00
Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00
Miscellaneous Pool Pump High Efficiency Pump 155.66 $85.00 15 1.01 $0.05
Miscellaneous Pool Pump Two-Speed Pump 622.65 $579.00 15 0.88 $0.08
Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00
Miscellaneous Furnace Fan Furnace Fan with
ECM 126.06 $0.64 18 1.27 $0.00
Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 930 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-28 www.enernoc.com
Table B-9 Energy Efficiency Equipment Data, Electric—Multi Family, Existing Vintage, Idaho
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Cooling Central AC SEER 13 - $0.00 15 - $0.00
Cooling Central AC SEER 14 (Energy Star) 35.49 $92.62 15 1.40 $0.23
Cooling Central AC SEER 15 (CEE Tier 2) 69.76 $185.24 15 0.96 $0.23
Cooling Central AC SEER 16 (CEE Tier 3) 98.42 $277.86 15 0.92 $0.24
Cooling Central AC Ductless Mini-Split
System 128.81 $2,012.28 20 0.62 $1.11
Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00
Cooling Room AC EER 10.8 (Energy
Star) 27.73 $52.02 10 0.84 $0.22
Cooling Room AC EER 11 32.67 $141.13 10 0.65 $0.51
Cooling Room AC EER 11.5 44.26 $312.75 10 0.45 $0.84
Cooling Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Cooling Air Source Heat
Pump SEER 14 (Energy Star) 37.52 $1,245.78 15 1.30 $2.87
Cooling Air Source Heat
Pump SEER 15 (CEE Tier 2) 61.09 $2,315.13 15 0.92 $3.28
Cooling Air Source Heat
Pump SEER 16 (CEE Tier 3) 86.18 $3,277.48 15 0.85 $3.29
Cooling Air Source Heat
Pump
Ductless Mini-Split
System 112.78 $5,022.03 20 0.84 $3.15
Cooling Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Cooling Geothermal Heat
Pump High Efficiency 54.19 $1,500.00 15 0.87 $2.39
Cooling Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance Electric Resistance - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance
Ductless Mini-Split
System 1,704.17 $156.87 20 1.27 $0.01
Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00
Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00
Space Heating Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Space Heating Air Source Heat
Pump SEER 14 (Energy Star) 161.86 $1,245.78 15 1.30 $0.67
Space Heating Air Source Heat
Pump SEER 15 (CEE Tier 2) 506.41 $2,315.13 15 0.92 $0.40
Space Heating Air Source Heat
Pump SEER 16 (CEE Tier 3) 714.41 $3,277.48 15 0.85 $0.40
Space Heating Air Source Heat
Pump
Ductless Mini-Split
System 934.98 $5,022.03 20 0.84 $0.38
Space Heating Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Space Heating Geothermal Heat
Pump High Efficiency 391.05 $1,500.00 15 0.87 $0.33
Space Heating Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Water Heating Water Heater <=
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater <=
55 Gal
High Efficiency
(EF=0.95) 103.48 $77.11 15 1.00 $0.06
Water Heating Water Heater <=
55 Gal EF 2.3 (HP) 997.52 $1,761.86 15 0.57 $0.15
Water Heating Water Heater <=
55 Gal Solar 1,130.20 $6,214.86 15 0.24 $0.48
Water Heating Water Heater >
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater >
55 Gal
High Efficiency
(EF=0.95) 171.13 $97.23 15 1.01 $0.05
Water Heating Water Heater > EF 2.3 (HP) 1,296.19 $1,691.15 15 0.71 $0.11
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 931 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-29
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
55 Gal
Water Heating Water Heater >
55 Gal Solar 1,158.24 $6,144.15 15 0.31 $0.46
Interior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Interior
Lighting Screw-in Infrared Halogen 153.34 $134.14 5 1.00 $0.19
Interior
Lighting Screw-in CFL 486.95 $12.45 6 3.12 $0.00
Interior
Lighting Screw-in LED 665.53 $1,161.45 12 - $0.18
Interior
Lighting Screw-in LED 665.53 $1,161.45 12 - $0.18
Interior
Lighting
Linear
Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting
Linear
Fluorescent T8 7.33 -$1.83 6 1.13 -$0.05
Interior
Lighting
Linear
Fluorescent Super T8 21.95 $14.59 6 0.75 $0.12
Interior
Lighting
Linear
Fluorescent T5 22.81 $24.70 6 0.60 $0.20
Interior
Lighting
Linear
Fluorescent LED 23.93 $216.84 10 0.22 $1.07
Interior
Lighting Specialty Halogen - $0.00 4 1.00 $0.00
Interior
Lighting Specialty CFL 99.37 $0.77 7 1.91 $0.00
Interior
Lighting Specialty LED 104.55 $209.01 12 0.28 $0.20
Exterior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Exterior
Lighting Screw-in Infrared Halogen 5.06 $5.08 5 1.00 $0.22
Exterior
Lighting Screw-in CFL 17.18 -$0.32 3 5.89 -$0.01
Exterior
Lighting Screw-in LED 19.94 $1,167.57 12 - $6.00
Exterior
Lighting Screw-in LED 19.94 $1,167.57 12 - $6.00
Appliances Clothes Washer Baseline - $0.00 14 - $0.00
Appliances Clothes Washer Energy Star (MEF >
1.8) 39.05 $69.81 14 - $0.16
Appliances Clothes Washer Horizontal Axis 53.90 $150.80 14 1.00 $0.25
Appliances Clothes Dryer Baseline - $0.00 13 - $0.00
Appliances Clothes Dryer Moisture Detection 57.67 $48.40 13 1.00 $0.08
Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00
Appliances Dishwasher Energy Star 48.33 $460.95 9 - $1.23
Appliances Dishwasher Energy Star (2011) 6.33 $5.61 15 0.99 $0.08
Appliances Refrigerator Baseline - $0.00 20 - $0.00
Appliances Refrigerator Energy Star 41.38 $20.17 20 - $0.03
Appliances Refrigerator Baseline (2014) 75.80 $0.00 13 1.00 $0.00
Appliances Refrigerator Energy Star (2014) 121.28 $88.71 13 1.01 $0.07
Appliances Freezer Baseline - $0.00 22 - $0.00
Appliances Freezer Energy Star 33.83 $3.98 22 - $0.01
Appliances Freezer Baseline (2014) 78.50 -$145.00 11 1.00 -$0.20
Appliances Freezer Energy Star (2014) 125.61 -$112.83 11 0.99 -$0.10
Appliances Second
Refrigerator Baseline - $0.00 20 - $0.00
Appliances Second
Refrigerator Energy Star 56.52 $20.67 20 - $0.03
Appliances Second
Refrigerator Baseline (2014) 103.54 $0.00 13 1.00 $0.00
Appliances Second
Refrigerator Energy Star (2014) 165.66 $88.71 13 1.00 $0.05
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 932 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-30 www.enernoc.com
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Appliances Stove Baseline - $0.00 13 1.00 $0.00
Appliances Stove Convection Oven 8.02 $1.86 13 1.00 $0.02
Appliances Stove Induction (High
Efficiency) 40.10 $1,432.20 13 0.37 $3.44
Appliances Microwave Baseline - $0.00 9 1.00 $0.00
Electronics Personal
Computers Baseline - $0.00 5 1.00 $0.00
Electronics Personal
Computers Energy Star 67.28 $1.20 5 1.01 $0.00
Electronics Personal
Computers Climate Savers 96.12 $175.49 5 0.85 $0.39
Electronics TVs Baseline - $0.00 11 1.00 $0.00
Electronics TVs Energy Star 44.09 $0.56 11 1.02 $0.00
Electronics Set-top
boxes/DVR Baseline - $0.00 11 1.00 $0.00
Electronics Set-top
boxes/DVR Energy Star 29.65 $0.56 11 1.01 $0.00
Electronics Devices and
Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00
Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00
Miscellaneous Pool Pump High Efficiency Pump 129.49 $85.00 15 1.00 $0.06
Miscellaneous Pool Pump Two-Speed Pump 517.96 $579.00 15 0.81 $0.10
Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00
Miscellaneous Furnace Fan Furnace Fan with
ECM 118.50 $0.00 18 1.27 $0.00
Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 933 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-31
Table B-10 Energy Efficiency Equipment Data, Electric—Multi Family, New Vintage, Idaho
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Cooling Central AC SEER 13 - $0.00 15 - $0.00
Cooling Central AC SEER 14 (Energy Star) 45.42 $92.62 15 1.40 $0.18
Cooling Central AC SEER 15 (CEE Tier 2) 88.66 $185.24 15 0.96 $0.18
Cooling Central AC SEER 16 (CEE Tier 3) 124.94 $277.86 15 0.93 $0.19
Cooling Central AC Ductless Mini-Split
System 164.44 $2,012.28 20 0.63 $0.87
Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00
Cooling Room AC EER 10.8 (Energy
Star) 34.44 $52.02 10 0.86 $0.18
Cooling Room AC EER 11 40.58 $141.13 10 0.67 $0.41
Cooling Room AC EER 11.5 55.03 $312.75 10 0.47 $0.67
Cooling Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Cooling Air Source Heat
Pump SEER 14 (Energy Star) 47.92 $1,245.78 15 1.30 $2.25
Cooling Air Source Heat
Pump SEER 15 (CEE Tier 2) 77.66 $2,315.13 15 0.93 $2.58
Cooling Air Source Heat
Pump SEER 16 (CEE Tier 3) 109.43 $3,277.48 15 0.87 $2.59
Cooling Air Source Heat
Pump
Ductless Mini-Split
System 144.03 $5,022.03 20 0.86 $2.47
Cooling Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Cooling Geothermal Heat
Pump High Efficiency 64.51 $1,500.00 15 0.87 $2.01
Cooling Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance Electric Resistance - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance
Ductless Mini-Split
System 1,959.79 $156.87 20 1.29 $0.01
Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00
Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00
Space Heating Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Space Heating Air Source Heat
Pump SEER 14 (Energy Star) 206.71 $1,245.78 15 1.30 $0.52
Space Heating Air Source Heat
Pump SEER 15 (CEE Tier 2) 643.79 $2,315.13 15 0.93 $0.31
Space Heating Air Source Heat
Pump SEER 16 (CEE Tier 3) 907.19 $3,277.48 15 0.87 $0.31
Space Heating Air Source Heat
Pump
Ductless Mini-Split
System 1,194.05 $5,022.03 20 0.86 $0.30
Space Heating Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Space Heating Geothermal Heat
Pump High Efficiency 465.56 $1,500.00 15 0.87 $0.28
Space Heating Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Water Heating Water Heater <=
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater <=
55 Gal
High Efficiency
(EF=0.95) 103.48 $77.11 15 1.00 $0.06
Water Heating Water Heater <=
55 Gal EF 2.3 (HP) 997.52 $1,761.86 15 0.57 $0.15
Water Heating Water Heater <=
55 Gal Solar 1,130.20 $6,214.86 15 0.24 $0.48
Water Heating Water Heater >
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater >
55 Gal
High Efficiency
(EF=0.95) 171.13 $97.23 15 1.01 $0.05
Water Heating Water Heater > EF 2.3 (HP) 1,296.19 $1,691.15 15 0.71 $0.11
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 934 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-32 www.enernoc.com
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
55 Gal
Water Heating Water Heater >
55 Gal Solar 1,158.24 $6,144.15 15 0.31 $0.46
Interior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Interior
Lighting Screw-in Infrared Halogen 175.05 $134.14 5 1.00 $0.17
Interior
Lighting Screw-in CFL 555.89 $12.45 6 2.98 $0.00
Interior
Lighting Screw-in LED 759.76 $1,381.00 12 - $0.19
Interior
Lighting Screw-in LED 759.76 $1,381.00 12 - $0.19
Interior
Lighting
Linear
Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting
Linear
Fluorescent T8 8.63 -$1.83 6 1.13 -$0.04
Interior
Lighting
Linear
Fluorescent Super T8 25.84 $14.59 6 0.78 $0.10
Interior
Lighting
Linear
Fluorescent T5 26.86 $24.70 6 0.63 $0.17
Interior
Lighting
Linear
Fluorescent LED 28.18 $216.84 10 0.23 $0.91
Interior
Lighting Specialty Halogen - $0.00 4 1.00 $0.00
Interior
Lighting Specialty CFL 114.28 -$13.07 7 3.40 -$0.02
Interior
Lighting Specialty LED 120.23 $61.68 12 1.01 $0.05
Exterior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Exterior
Lighting Screw-in Infrared Halogen 5.76 $5.08 5 1.00 $0.19
Exterior
Lighting Screw-in CFL 19.55 -$0.34 3 5.79 -$0.01
Exterior
Lighting Screw-in LED 22.70 $75.05 12 - $0.34
Exterior
Lighting Screw-in LED 22.70 $75.05 12 - $0.34
Appliances Clothes Washer Baseline - $0.00 14 - $0.00
Appliances Clothes Washer Energy Star (MEF >
1.8) 39.05 $69.81 14 - $0.16
Appliances Clothes Washer Horizontal Axis 53.90 $150.80 14 1.00 $0.25
Appliances Clothes Dryer Baseline - $0.00 13 - $0.00
Appliances Clothes Dryer Moisture Detection 57.67 $48.40 13 1.00 $0.08
Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00
Appliances Dishwasher Energy Star 48.52 $460.95 9 - $1.23
Appliances Dishwasher Energy Star (2011) 6.36 $5.61 15 0.99 $0.08
Appliances Refrigerator Baseline - $0.00 20 - $0.00
Appliances Refrigerator Energy Star 46.90 $20.17 20 - $0.03
Appliances Refrigerator Baseline (2014) 85.91 $0.00 13 1.00 $0.00
Appliances Refrigerator Energy Star (2014) 137.46 $88.71 13 1.01 $0.06
Appliances Freezer Baseline - $0.00 22 - $0.00
Appliances Freezer Energy Star 36.20 $3.98 22 - $0.01
Appliances Freezer Baseline (2014) 84.02 -$145.00 11 1.00 -$0.19
Appliances Freezer Energy Star (2014) 134.43 -$112.83 11 0.99 -$0.09
Appliances Second
Refrigerator Baseline - $0.00 20 - $0.00
Appliances Second
Refrigerator Energy Star 60.29 $20.67 20 - $0.02
Appliances Second
Refrigerator Baseline (2014) 110.44 $0.00 13 1.00 $0.00
Appliances Second
Refrigerator Energy Star (2014) 176.70 $88.71 13 1.00 $0.05
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 935 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-33
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Appliances Stove Baseline - $0.00 13 1.00 $0.00
Appliances Stove Convection Oven 8.02 $1.86 13 1.00 $0.02
Appliances Stove Induction (High
Efficiency) 40.10 $1,432.20 13 0.37 $3.44
Appliances Microwave Baseline - $0.00 9 1.00 $0.00
Electronics Personal
Computers Baseline - $0.00 5 1.00 $0.00
Electronics Personal
Computers Energy Star 65.85 $1.20 5 1.01 $0.00
Electronics Personal
Computers Climate Savers 94.07 $175.49 5 0.85 $0.40
Electronics TVs Baseline - $0.00 11 1.00 $0.00
Electronics TVs Energy Star 48.99 $0.56 11 1.02 $0.00
Electronics Set-top
boxes/DVR Baseline - $0.00 11 1.00 $0.00
Electronics Set-top
boxes/DVR Energy Star 29.65 $0.56 11 1.01 $0.00
Electronics Devices and
Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00
Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00
Miscellaneous Pool Pump High Efficiency Pump 146.32 $85.00 15 1.01 $0.05
Miscellaneous Pool Pump Two-Speed Pump 585.29 $579.00 15 0.85 $0.09
Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00
Miscellaneous Furnace Fan Furnace Fan with
ECM 118.50 $0.64 18 1.27 $0.00
Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 936 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-34 www.enernoc.com
Table B-11 Energy Efficiency Equipment Data, Electric—Mobile Home, Existing Vintage,
Washington
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Cooling Central AC SEER 13 - $0.00 15 - $0.00
Cooling Central AC SEER 14 (Energy Star) 46.32 $277.86 20 1.40 $0.42
Cooling Central AC SEER 15 (CEE Tier 2) 63.55 $555.71 15 0.78 $0.76
Cooling Central AC SEER 16 (CEE Tier 3) 77.99 $833.57 15 0.73 $0.92
Cooling Central AC Ductless Mini-Split
System
139.87 $4,399.48 20 0.51 $2.23
Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00
Cooling Room AC EER 10.8 (Energy
Star)
27.99 $52.02 10 0.85 $0.22
Cooling Room AC EER 11 33.03 $141.13 10 0.65 $0.51
Cooling Room AC EER 11.5 44.72 $312.75 10 0.45 $0.83
Cooling Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Cooling Air Source Heat
Pump SEER 14 (Energy Star) 43.49 $1,720.87 15 1.30 $3.42
Cooling Air Source Heat
Pump SEER 15 (CEE Tier 2) 40.94 $2,315.13 15 0.96 $4.89
Cooling Air Source Heat
Pump SEER 16 (CEE Tier 3) 50.24 $3,277.48 15 0.88 $5.64
Cooling Air Source Heat
Pump
Ductless Mini-Split
System
90.11 $5,022.03 20 0.89 $3.94
Cooling Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Cooling Geothermal Heat
Pump High Efficiency 46.66 $1,500.00 15 0.90 $2.78
Cooling Ductless HP Ductless Mini-Split
System
- $0.00 20 1.00 $0.00
Space Heating Electric
Resistance Electric Resistance - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance
Ductless Mini-Split
System
2,388.11 $156.87 20 1.28 $0.00
Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00
Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00
Space Heating Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Space Heating Air Source Heat
Pump SEER 14 (Energy Star) 239.45 $1,720.87 15 1.30 $0.62
Space Heating Air Source Heat
Pump SEER 15 (CEE Tier 2) 528.37 $2,315.13 15 0.96 $0.38
Space Heating Air Source Heat
Pump SEER 16 (CEE Tier 3) 648.37 $3,277.48 15 0.88 $0.44
Space Heating Air Source Heat
Pump
Ductless Mini-Split
System
1,162.86 $5,022.03 20 0.89 $0.31
Space Heating Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Space Heating Geothermal Heat
Pump High Efficiency 813.13 $188.19 15 0.90 $0.02
Space Heating Ductless HP Ductless Mini-Split
System
- $0.00 20 1.00 $0.00
Water Heating Water Heater <=
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater <=
55 Gal
High Efficiency
(EF=0.95)
134.84 $77.11 15 1.01 $0.05
Water Heating Water Heater <=
55 Gal EF 2.3 (HP) 1,299.77 $1,761.86 15 0.72 $0.12
Water Heating Water Heater <=
55 Gal Solar 1,472.84 $6,214.86 15 0.32 $0.36
Water Heating Water Heater >
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater > High Efficiency 171.70 $97.23 15 1.02 $0.05
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 937 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-35
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
55 Gal (EF=0.95)
Water Heating Water Heater >
55 Gal EF 2.3 (HP) 1,300.53 $1,691.15 15 0.76 $0.11
Water Heating Water Heater >
55 Gal Solar 1,162.12 $6,144.15 15 0.34 $0.46
Interior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Interior
Lighting Screw-in Infrared Halogen 210.16 $188.19 5 1.00 $0.19
Interior
Lighting Screw-in CFL 667.39 $28.57 6 2.81 $0.01
Interior
Lighting Screw-in LED 912.15 $1,353.42 12 - $0.15
Interior
Lighting Screw-in LED 912.15 $1,353.42 12 - $0.15
Interior
Lighting
Linear
Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting
Linear
Fluorescent T8 8.74 -$3.65 6 1.14 -$0.08
Interior
Lighting
Linear
Fluorescent Super T8 26.18 $29.17 6 0.65 $0.20
Interior
Lighting
Linear
Fluorescent T5 27.22 $49.41 6 0.51 $0.33
Interior
Lighting
Linear
Fluorescent LED 28.55 $433.68 10 0.17 $1.80
Interior
Lighting Specialty Halogen - $0.00 4 1.00 $0.00
Interior
Lighting Specialty CFL 205.65 $1.34 7 1.92 $0.00
Interior
Lighting Specialty LED 216.37 $365.76 12 0.31 $0.17
Exterior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Exterior
Lighting Screw-in Infrared Halogen 72.47 $51.30 5 1.00 $0.15
Exterior
Lighting Screw-in CFL 245.95 -$1.81 3 4.75 $0.00
Exterior
Lighting Screw-in LED 285.49 $1,356.06 12 - $0.49
Exterior
Lighting Screw-in LED 285.49 $1,356.06 12 - $0.49
Appliances Clothes Washer Baseline - $0.00 14 - $0.00
Appliances Clothes Washer Energy Star (MEF >
1.8)
40.50 $69.81 14 - $0.16
Appliances Clothes Washer Horizontal Axis 55.91 $150.80 14 1.00 $0.25
Appliances Clothes Dryer Baseline - $0.00 13 - $0.00
Appliances Clothes Dryer Moisture Detection 60.29 $48.40 13 1.00 $0.08
Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00
Appliances Dishwasher Energy Star 50.13 $460.95 9 - $1.19
Appliances Dishwasher Energy Star (2011) 6.57 $5.61 15 1.00 $0.07
Appliances Refrigerator Baseline - $0.00 20 - $0.00
Appliances Refrigerator Energy Star 42.92 $20.17 20 - $0.03
Appliances Refrigerator Baseline (2014) 78.63 $0.00 13 1.00 $0.00
Appliances Refrigerator Energy Star (2014) 125.80 $88.71 13 1.01 $0.07
Appliances Freezer Baseline - $0.00 22 - $0.00
Appliances Freezer Energy Star 35.09 $3.98 22 - $0.01
Appliances Freezer Baseline (2014) 81.43 -$145.00 11 1.00 -$0.20
Appliances Freezer Energy Star (2014) 130.28 -$112.83 11 0.99 -$0.10
Appliances Second
Refrigerator Baseline - $0.00 20 - $0.00
Appliances Second
Refrigerator Energy Star 58.63 $20.67 20 - $0.02
Appliances Second
Refrigerator Baseline (2014) 107.39 $0.00 13 1.00 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 938 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-36 www.enernoc.com
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Appliances Second
Refrigerator Energy Star (2014) 171.83 $88.71 13 1.01 $0.05
Appliances Stove Baseline - $0.00 13 1.00 $0.00
Appliances Stove Convection Oven 8.32 $1.86 13 1.00 $0.02
Appliances Stove Induction (High
Efficiency)
41.60 $1,432.20 13 0.37 $3.32
Appliances Microwave Baseline - $0.00 9 1.00 $0.00
Electronics Personal
Computers Baseline - $0.00 5 1.00 $0.00
Electronics Personal
Computers Energy Star 76.05 $1.20 5 1.01 $0.00
Electronics Personal
Computers Climate Savers 108.65 $175.49 5 0.85 $0.35
Electronics TVs Baseline - $0.00 11 1.00 $0.00
Electronics TVs Energy Star 44.30 $0.56 11 1.02 $0.00
Electronics Set-top
boxes/DVR Baseline - $0.00 11 1.00 $0.00
Electronics Set-top
boxes/DVR Energy Star 26.81 $0.56 11 1.01 $0.00
Electronics Devices and
Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00
Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00
Miscellaneous Pool Pump High Efficiency Pump 103.32 $85.00 15 0.98 $0.07
Miscellaneous Pool Pump Two-Speed Pump 413.27 $579.00 15 0.74 $0.12
Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00
Miscellaneous Furnace Fan Furnace Fan with
ECM
118.18 $0.64 18 1.27 $0.00
Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 939 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-37
Table B-12 Energy Efficiency Equipment Data, Electric—Mobile Home, New Vintage,
Washington
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Cooling Central AC SEER 13 - $0.00 15 - $0.00
Cooling Central AC SEER 14 (Energy Star) 55.05 $277.86 15 1.40 $0.44
Cooling Central AC SEER 15 (CEE Tier 2) 73.33 $555.71 15 0.94 $0.66
Cooling Central AC SEER 16 (CEE Tier 3) 88.67 $833.57 15 0.89 $0.81
Cooling Central AC Ductless Mini-Split
System 166.28 $4,399.48 20 0.62 $1.87
Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00
Cooling Room AC EER 10.8 (Energy
Star) 32.54 $52.02 10 0.86 $0.19
Cooling Room AC EER 11 38.34 $141.13 10 0.66 $0.44
Cooling Room AC EER 11.5 51.99 $312.75 10 0.46 $0.71
Cooling Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Cooling Air Source Heat
Pump SEER 14 (Energy Star) 51.74 $1,720.87 15 1.30 $2.88
Cooling Air Source Heat
Pump SEER 15 (CEE Tier 2) 47.26 $2,315.13 15 0.97 $4.24
Cooling Air Source Heat
Pump SEER 16 (CEE Tier 3) 57.15 $3,277.48 15 0.89 $4.96
Cooling Air Source Heat
Pump
Ductless Mini-Split
System 107.18 $5,022.03 20 0.90 $3.32
Cooling Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Cooling Geothermal Heat
Pump High Efficiency 51.93 $1,500.00 15 0.91 $2.50
Cooling Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance Electric Resistance - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance
Ductless Mini-Split
System 2,567.22 $156.87 20 1.29 $0.00
Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00
Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00
Space Heating Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Space Heating Air Source Heat
Pump SEER 14 (Energy Star) 284.83 $1,720.87 15 1.30 $0.52
Space Heating Air Source Heat
Pump SEER 15 (CEE Tier 2) 609.96 $2,315.13 15 0.97 $0.33
Space Heating Air Source Heat
Pump SEER 16 (CEE Tier 3) 737.59 $3,277.48 15 0.89 $0.38
Space Heating Air Source Heat
Pump
Ductless Mini-Split
System 1,383.21 $5,022.03 20 0.90 $0.26
Space Heating Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Space Heating Geothermal Heat
Pump High Efficiency 671.05 $1,500.00 15 0.91 $0.19
Space Heating Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Water Heating Water Heater <=
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater <=
55 Gal
High Efficiency
(EF=0.95) 141.18 $77.11 15 1.02 $0.05
Water Heating Water Heater <=
55 Gal EF 2.3 (HP) 1,360.93 $1,761.86 15 0.73 $0.11
Water Heating Water Heater <=
55 Gal Solar 1,542.14 $6,214.86 15 0.33 $0.35
Water Heating Water Heater >
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater > High Efficiency 179.84 $97.23 15 1.02 $0.05
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 940 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-38 www.enernoc.com
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
55 Gal (EF=0.95)
Water Heating Water Heater >
55 Gal EF 2.3 (HP) 1,362.23 $1,691.15 15 0.77 $0.11
Water Heating Water Heater >
55 Gal Solar 1,217.25 $6,144.15 15 0.35 $0.44
Interior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Interior
Lighting Screw-in Infrared Halogen 229.01 $188.19 5 1.00 $0.18
Interior
Lighting Screw-in CFL 727.25 $28.57 6 2.74 $0.01
Interior
Lighting Screw-in LED 993.96 $1,937.55 12 - $0.20
Interior
Lighting Screw-in LED 993.96 $1,937.55 12 - $0.20
Interior
Lighting
Linear
Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting
Linear
Fluorescent T8 9.82 -$3.65 6 1.14 -$0.07
Interior
Lighting
Linear
Fluorescent Super T8 29.43 $29.17 6 0.67 $0.18
Interior
Lighting
Linear
Fluorescent T5 30.59 $49.41 6 0.53 $0.30
Interior
Lighting
Linear
Fluorescent LED 32.09 $433.68 10 0.18 $1.60
Interior
Lighting Specialty Halogen - $0.00 4 1.00 $0.00
Interior
Lighting Specialty CFL 221.07 -$7.66 7 2.45 -$0.01
Interior
Lighting Specialty LED 232.60 $134.50 12 0.74 $0.06
Exterior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Exterior
Lighting Screw-in Infrared Halogen 78.72 $51.30 5 1.00 $0.14
Exterior
Lighting Screw-in CFL 267.15 -$2.04 3 4.76 $0.00
Exterior
Lighting Screw-in LED 310.10 $757.28 12 - $0.25
Exterior
Lighting Screw-in LED 310.10 $757.28 12 - $0.25
Appliances Clothes Washer Baseline - $0.00 14 - $0.00
Appliances Clothes Washer Energy Star (MEF >
1.8) 47.25 $69.81 14 - $0.13
Appliances Clothes Washer Horizontal Axis 65.23 $150.80 14 1.00 $0.21
Appliances Clothes Dryer Baseline - $0.00 13 - $0.00
Appliances Clothes Dryer Moisture Detection 65.61 $48.40 13 1.00 $0.07
Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00
Appliances Dishwasher Energy Star 54.76 $460.95 9 - $1.09
Appliances Dishwasher Energy Star (2011) 7.17 $5.61 15 1.00 $0.07
Appliances Refrigerator Baseline - $0.00 20 - $0.00
Appliances Refrigerator Energy Star 60.09 $20.17 20 - $0.02
Appliances Refrigerator Baseline (2014) 110.08 $0.00 13 1.00 $0.00
Appliances Refrigerator Energy Star (2014) 176.12 $88.71 13 1.02 $0.05
Appliances Freezer Baseline - $0.00 22 - $0.00
Appliances Freezer Energy Star 48.64 $3.98 22 - $0.01
Appliances Freezer Baseline (2014) 112.87 -$145.00 11 1.00 -$0.14
Appliances Freezer Energy Star (2014) 180.59 -$112.83 11 1.01 -$0.07
Appliances Second
Refrigerator Baseline - $0.00 20 - $0.00
Appliances Second
Refrigerator Energy Star 80.12 $20.67 20 - $0.02
Appliances Second
Refrigerator Baseline (2014) 146.77 $0.00 13 1.00 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 941 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-39
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Appliances Second
Refrigerator Energy Star (2014) 234.83 $88.71 13 1.01 $0.04
Appliances Stove Baseline - $0.00 13 1.00 $0.00
Appliances Stove Convection Oven 35.13 $0.56 13 1.00 $0.00
Appliances Stove Induction (High
Efficiency) 41.59 $0.00 13 0.37 $0.00
Appliances Microwave Baseline - $0.00 9 1.00 $0.00
Electronics Personal
Computers Baseline - $0.00 5 1.00 $0.00
Electronics Personal
Computers Energy Star 74.43 $1.20 5 1.01 $0.00
Electronics Personal
Computers Climate Savers 106.33 $175.49 5 0.85 $0.36
Electronics TVs Baseline - $0.00 11 1.00 $0.00
Electronics TVs Energy Star 49.22 $0.56 11 1.02 $0.00
Electronics Set-top
boxes/DVR Baseline - $0.00 11 1.00 $0.00
Electronics Set-top
boxes/DVR Energy Star 26.81 $0.56 11 1.01 $0.00
Electronics Devices and
Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00
Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00
Miscellaneous Pool Pump High Efficiency Pump 115.77 $85.00 15 0.99 $0.06
Miscellaneous Pool Pump Two-Speed Pump 463.09 $579.00 15 0.78 $0.11
Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00
Miscellaneous Furnace Fan Furnace Fan with
ECM 118.18 $0.64 18 1.27 $0.00
Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 942 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-40 www.enernoc.com
Table B-13 Energy Efficiency Equipment Data, Electric—Mobile Home, Existing Vintage, Idaho
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Cooling Central AC SEER 13 - $0.00 15 - $0.00
Cooling Central AC SEER 14 (Energy Star) 39.83 $277.86 15 1.40 $0.60
Cooling Central AC SEER 15 (CEE Tier 2) 54.66 $555.71 15 0.94 $0.88
Cooling Central AC SEER 16 (CEE Tier 3) 67.07 $833.57 15 0.89 $1.07
Cooling Central AC Ductless Mini-Split
System 120.29 $4,399.48 20 0.62 $2.59
Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00
Cooling Room AC EER 10.8 (Energy
Star) 24.07 $52.02 10 0.84 $0.26
Cooling Room AC EER 11 28.41 $141.13 10 0.64 $0.59
Cooling Room AC EER 11.5 38.46 $312.75 10 0.44 $0.96
Cooling Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Cooling Air Source Heat
Pump SEER 14 (Energy Star) 37.41 $1,720.87 15 1.30 $3.98
Cooling Air Source Heat
Pump SEER 15 (CEE Tier 2) 35.21 $2,315.13 15 0.96 $5.69
Cooling Air Source Heat
Pump SEER 16 (CEE Tier 3) 43.21 $3,277.48 15 0.88 $6.56
Cooling Air Source Heat
Pump
Ductless Mini-Split
System 77.49 $5,022.03 20 0.88 $4.59
Cooling Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Cooling Geothermal Heat
Pump High Efficiency 40.13 $1,500.00 15 0.89 $3.23
Cooling Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance Electric Resistance - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance
Ductless Mini-Split
System 2,256.76 $156.87 20 1.27 $0.00
Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00
Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00
Space Heating Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Space Heating Air Source Heat
Pump SEER 14 (Energy Star) 226.28 $1,720.87 15 1.30 $0.66
Space Heating Air Source Heat
Pump SEER 15 (CEE Tier 2) 499.31 $2,315.13 15 0.96 $0.40
Space Heating Air Source Heat
Pump SEER 16 (CEE Tier 3) 612.71 $3,277.48 15 0.88 $0.46
Space Heating Air Source Heat
Pump
Ductless Mini-Split
System 1,098.90 $5,022.03 20 0.88 $0.32
Space Heating Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Space Heating Geothermal Heat
Pump High Efficiency 768.40 $188.19 15 0.89 $0.02
Space Heating Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Water Heating Water Heater <=
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater <=
55 Gal
High Efficiency
(EF=0.95) 127.42 $77.11 15 1.01 $0.05
Water Heating Water Heater <=
55 Gal EF 2.3 (HP) 1,228.29 $1,761.86 15 0.64 $0.12
Water Heating Water Heater <=
55 Gal Solar 1,391.83 $6,214.86 15 0.27 $0.39
Water Heating Water Heater >
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater >
55 Gal
High Efficiency
(EF=0.95) 162.25 $97.23 15 1.01 $0.05
Water Heating Water Heater > EF 2.3 (HP) 1,229.00 $1,691.15 15 0.68 $0.12
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 943 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-41
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
55 Gal
Water Heating Water Heater >
55 Gal Solar 1,098.20 $6,144.15 15 0.30 $0.48
Interior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Interior
Lighting Screw-in Infrared Halogen 198.60 $188.19 5 1.00 $0.20
Interior
Lighting Screw-in CFL 630.68 $28.57 6 2.95 $0.01
Interior
Lighting Screw-in LED 861.98 $1,353.42 12 - $0.16
Interior
Lighting Screw-in LED 861.98 $1,353.42 12 - $0.16
Interior
Lighting
Linear
Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting
Linear
Fluorescent T8 8.26 -$3.50 6 1.14 -$0.08
Interior
Lighting
Linear
Fluorescent Super T8 24.74 $28.01 6 0.65 $0.21
Interior
Lighting
Linear
Fluorescent T5 25.72 $47.43 6 0.50 $0.34
Interior
Lighting
Linear
Fluorescent LED 26.98 $416.33 10 0.17 $1.83
Interior
Lighting Specialty Halogen - $0.00 4 1.00 $0.00
Interior
Lighting Specialty CFL 194.34 $1.34 7 1.93 $0.00
Interior
Lighting Specialty LED 204.47 $365.76 12 0.30 $0.18
Exterior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Exterior
Lighting Screw-in Infrared Halogen 68.48 $49.25 5 1.00 $0.16
Exterior
Lighting Screw-in CFL 232.42 -$1.53 3 4.76 $0.00
Exterior
Lighting Screw-in LED 269.78 $1,356.33 12 - $0.52
Exterior
Lighting Screw-in LED 269.78 $1,356.33 12 - $0.52
Appliances Clothes Washer Baseline - $0.00 14 - $0.00
Appliances Clothes Washer Energy Star (MEF >
1.8) 38.27 $69.81 14 - $0.17
Appliances Clothes Washer Horizontal Axis 52.83 $150.80 14 1.00 $0.26
Appliances Clothes Dryer Baseline - $0.00 13 - $0.00
Appliances Clothes Dryer Moisture Detection 56.98 $48.40 13 1.00 $0.08
Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00
Appliances Dishwasher Energy Star 47.38 $460.95 9 - $1.26
Appliances Dishwasher Energy Star (2011) 6.21 $5.61 15 0.99 $0.08
Appliances Refrigerator Baseline - $0.00 20 - $0.00
Appliances Refrigerator Energy Star 40.56 $20.17 20 - $0.04
Appliances Refrigerator Baseline (2014) 74.30 $0.00 13 1.00 $0.00
Appliances Refrigerator Energy Star (2014) 118.88 $88.71 13 1.01 $0.07
Appliances Freezer Baseline - $0.00 22 - $0.00
Appliances Freezer Energy Star 33.16 $3.98 22 - $0.01
Appliances Freezer Baseline (2014) 76.95 -$145.00 11 1.00 -$0.21
Appliances Freezer Energy Star (2014) 123.12 -$112.83 11 0.99 -$0.10
Appliances Second
Refrigerator Baseline - $0.00 20 - $0.00
Appliances Second
Refrigerator Energy Star 55.40 $20.67 20 - $0.03
Appliances Second
Refrigerator Baseline (2014) 101.48 $0.00 13 1.00 $0.00
Appliances Second
Refrigerator Energy Star (2014) 162.38 $88.71 13 1.00 $0.05
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 944 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-42 www.enernoc.com
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Appliances Stove Baseline - $0.00 13 1.00 $0.00
Appliances Stove Convection Oven 7.86 $1.86 13 1.00 $0.02
Appliances Stove Induction (High
Efficiency) 39.31 $1,432.20 13 0.37 $3.51
Appliances Microwave Baseline - $0.00 9 1.00 $0.00
Electronics Personal
Computers Baseline - $0.00 5 1.00 $0.00
Electronics Personal
Computers Energy Star 71.87 $1.20 5 1.01 $0.00
Electronics Personal
Computers Climate Savers 102.67 $175.49 5 0.85 $0.37
Electronics TVs Baseline - $0.00 11 1.00 $0.00
Electronics TVs Energy Star 41.87 $0.56 11 1.02 $0.00
Electronics Set-top
boxes/DVR Baseline - $0.00 11 1.00 $0.00
Electronics Set-top
boxes/DVR Energy Star 25.34 $0.56 11 1.01 $0.00
Electronics Devices and
Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00
Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00
Miscellaneous Pool Pump High Efficiency Pump 97.63 $85.00 15 0.97 $0.08
Miscellaneous Pool Pump Two-Speed Pump 390.54 $579.00 15 0.71 $0.13
Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00
Miscellaneous Furnace Fan Furnace Fan with
ECM 111.68 $0.64 18 1.26 $0.00
Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 945 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-43
Table B-14 Energy Efficiency Equipment Data, Electric—Mobile Home, New Vintage, Idaho
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Cooling Central AC SEER 13 - $0.00 15 - $0.00
Cooling Central AC SEER 14 (Energy Star) 47.34 $277.86 15 1.40 $0.51
Cooling Central AC SEER 15 (CEE Tier 2) 63.06 $555.71 15 0.94 $0.76
Cooling Central AC SEER 16 (CEE Tier 3) 76.25 $833.57 15 0.89 $0.95
Cooling Central AC Ductless Mini-Split
System 143.00 $4,399.48 20 0.62 $2.18
Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00
Cooling Room AC EER 10.8 (Energy
Star) 27.98 $52.02 10 0.85 $0.22
Cooling Room AC EER 11 32.97 $141.13 10 0.65 $0.51
Cooling Room AC EER 11.5 44.72 $312.75 10 0.45 $0.83
Cooling Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Cooling Air Source Heat
Pump SEER 14 (Energy Star) 44.49 $1,720.87 15 1.30 $3.34
Cooling Air Source Heat
Pump SEER 15 (CEE Tier 2) 40.65 $2,315.13 15 0.97 $4.93
Cooling Air Source Heat
Pump SEER 16 (CEE Tier 3) 49.15 $3,277.48 15 0.89 $5.77
Cooling Air Source Heat
Pump
Ductless Mini-Split
System 92.17 $5,022.03 20 0.90 $3.85
Cooling Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Cooling Geothermal Heat
Pump High Efficiency 44.66 $1,500.00 15 0.90 $2.90
Cooling Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance Electric Resistance - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance
Ductless Mini-Split
System 2,426.02 $156.87 20 1.29 $0.00
Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00
Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00
Space Heating Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Space Heating Air Source Heat
Pump SEER 14 (Energy Star) 269.16 $1,720.87 15 1.30 $0.55
Space Heating Air Source Heat
Pump SEER 15 (CEE Tier 2) 576.42 $2,315.13 15 0.97 $0.35
Space Heating Air Source Heat
Pump SEER 16 (CEE Tier 3) 697.02 $3,277.48 15 0.89 $0.41
Space Heating Air Source Heat
Pump
Ductless Mini-Split
System 1,307.13 $5,022.03 20 0.90 $0.27
Space Heating Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Space Heating Geothermal Heat
Pump High Efficiency 634.14 $1,500.00 15 0.90 $0.20
Space Heating Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Water Heating Water Heater <=
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater <=
55 Gal
High Efficiency
(EF=0.95) 133.42 $77.11 15 1.01 $0.05
Water Heating Water Heater <=
55 Gal EF 2.3 (HP) 1,286.08 $1,761.86 15 0.66 $0.12
Water Heating Water Heater <=
55 Gal Solar 1,457.32 $6,214.86 15 0.29 $0.37
Water Heating Water Heater >
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater >
55 Gal
High Efficiency
(EF=0.95) 169.95 $97.23 15 1.01 $0.05
Water Heating Water Heater > EF 2.3 (HP) 1,287.31 $1,691.15 15 0.71 $0.11
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 946 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-44 www.enernoc.com
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
55 Gal
Water Heating Water Heater >
55 Gal Solar 1,150.30 $6,144.15 15 0.31 $0.46
Interior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Interior
Lighting Screw-in Infrared Halogen 216.42 $188.19 5 1.00 $0.19
Interior
Lighting Screw-in CFL 687.25 $28.57 6 2.88 $0.01
Interior
Lighting Screw-in LED 939.30 $1,937.55 12 - $0.21
Interior
Lighting Screw-in LED 939.30 $1,937.55 12 - $0.21
Interior
Lighting
Linear
Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting
Linear
Fluorescent T8 9.28 -$3.50 6 1.14 -$0.07
Interior
Lighting
Linear
Fluorescent Super T8 27.81 $28.01 6 0.67 $0.18
Interior
Lighting
Linear
Fluorescent T5 28.91 $47.43 6 0.52 $0.30
Interior
Lighting
Linear
Fluorescent LED 30.33 $416.33 10 0.18 $1.63
Interior
Lighting Specialty Halogen - $0.00 4 1.00 $0.00
Interior
Lighting Specialty CFL 208.91 -$7.12 7 2.46 -$0.01
Interior
Lighting Specialty LED 219.80 $140.97 12 0.70 $0.07
Exterior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Exterior
Lighting Screw-in Infrared Halogen 74.39 $49.25 5 1.00 $0.14
Exterior
Lighting Screw-in CFL 252.46 -$1.76 3 4.76 $0.00
Exterior
Lighting Screw-in LED 293.05 $726.99 12 - $0.25
Exterior
Lighting Screw-in LED 293.05 $726.99 12 - $0.25
Appliances Clothes Washer Baseline - $0.00 14 - $0.00
Appliances Clothes Washer Energy Star (MEF >
1.8) 44.65 $69.81 14 - $0.14
Appliances Clothes Washer Horizontal Axis 61.64 $150.80 14 1.00 $0.22
Appliances Clothes Dryer Baseline - $0.00 13 - $0.00
Appliances Clothes Dryer Moisture Detection 62.00 $48.40 13 1.00 $0.08
Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00
Appliances Dishwasher Energy Star 51.75 $460.95 9 - $1.15
Appliances Dishwasher Energy Star (2011) 6.78 $5.61 15 0.99 $0.07
Appliances Refrigerator Baseline - $0.00 20 - $0.00
Appliances Refrigerator Energy Star 56.79 $20.17 20 - $0.03
Appliances Refrigerator Baseline (2014) 104.02 $0.00 13 1.00 $0.00
Appliances Refrigerator Energy Star (2014) 166.43 $88.71 13 1.02 $0.05
Appliances Freezer Baseline - $0.00 22 - $0.00
Appliances Freezer Energy Star 45.96 $3.98 22 - $0.01
Appliances Freezer Baseline (2014) 106.66 -$145.00 11 1.00 -$0.15
Appliances Freezer Energy Star (2014) 170.66 -$112.83 11 1.00 -$0.07
Appliances Second
Refrigerator Baseline - $0.00 20 - $0.00
Appliances Second
Refrigerator Energy Star 75.71 $20.67 20 - $0.02
Appliances Second
Refrigerator Baseline (2014) 138.70 $0.00 13 1.00 $0.00
Appliances Second
Refrigerator Energy Star (2014) 221.91 $88.71 13 1.01 $0.04
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 947 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-45
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Appliances Stove Baseline - $0.00 13 1.00 $0.00
Appliances Stove Convection Oven 33.20 $0.56 13 1.00 $0.00
Appliances Stove Induction (High
Efficiency) 39.30 $0.00 13 0.36 $0.00
Appliances Microwave Baseline - $0.00 9 1.00 $0.00
Electronics Personal
Computers Baseline - $0.00 5 1.00 $0.00
Electronics Personal
Computers Energy Star 70.34 $1.20 5 1.01 $0.00
Electronics Personal
Computers Climate Savers 100.48 $175.49 5 0.85 $0.38
Electronics TVs Baseline - $0.00 11 1.00 $0.00
Electronics TVs Energy Star 46.52 $0.56 11 1.02 $0.00
Electronics Set-top
boxes/DVR Baseline - $0.00 11 1.00 $0.00
Electronics Set-top
boxes/DVR Energy Star 25.34 $0.56 11 1.01 $0.00
Electronics Devices and
Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00
Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00
Miscellaneous Pool Pump High Efficiency Pump 109.40 $85.00 15 0.99 $0.07
Miscellaneous Pool Pump Two-Speed Pump 437.62 $579.00 15 0.76 $0.11
Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00
Miscellaneous Furnace Fan Furnace Fan with
ECM 111.68 $0.64 18 1.27 $0.00
Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 948 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-46 www.enernoc.com
Table B-15 Energy Efficiency Equipment Data, Electric—Low income, Existing Vintage,
Washington
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Cooling Central AC SEER 13 - $0.00 15 - $0.00
Cooling Central AC SEER 14 (Energy Star) 49.41 $185.24 15 1.40 $0.32
Cooling Central AC SEER 15 (CEE Tier 2) 67.79 $370.47 15 0.93 $0.47
Cooling Central AC SEER 16 (CEE Tier 3) 83.19 $555.71 15 0.87 $0.58
Cooling Central AC Ductless Mini-Split
System 149.20 $2,394.23 20 0.64 $1.14
Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00
Cooling Room AC EER 10.8 (Energy
Star) 26.53 $104.04 10 0.81 $0.46
Cooling Room AC EER 11 31.30 $282.26 10 0.60 $1.07
Cooling Room AC EER 11.5 42.38 $625.50 10 0.40 $1.75
Cooling Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Cooling Air Source Heat
Pump SEER 14 (Energy Star) 37.76 $1,245.78 15 1.30 $2.85
Cooling Air Source Heat
Pump SEER 15 (CEE Tier 2) 51.80 $2,315.13 15 0.91 $3.86
Cooling Air Source Heat
Pump SEER 16 (CEE Tier 3) 63.57 $3,277.48 15 0.84 $4.46
Cooling Air Source Heat
Pump
Ductless Mini-Split
System 114.01 $5,022.03 20 0.84 $3.12
Cooling Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Cooling Geothermal Heat
Pump High Efficiency 62.78 $1,500.00 15 0.89 $2.07
Cooling Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance Electric Resistance - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance
Ductless Mini-Split
System 2,070.05 $156.87 20 1.29 $0.01
Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00
Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00
Space Heating Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Space Heating Air Source Heat
Pump SEER 14 (Energy Star) 355.79 $1,245.78 15 1.30 $0.30
Space Heating Air Source Heat
Pump SEER 15 (CEE Tier 2) 488.18 $2,315.13 15 0.91 $0.41
Space Heating Air Source Heat
Pump SEER 16 (CEE Tier 3) 599.06 $3,277.48 15 0.84 $0.47
Space Heating Air Source Heat
Pump
Ductless Mini-Split
System 1,074.41 $5,022.03 20 0.84 $0.33
Space Heating Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Space Heating Geothermal Heat
Pump High Efficiency 436.67 $1,500.00 15 0.89 $0.30
Space Heating Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Water Heating Water Heater <=
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater <=
55 Gal
High Efficiency
(EF=0.95) 121.27 $77.11 15 1.01 $0.05
Water Heating Water Heater <=
55 Gal EF 2.3 (HP) 1,168.96 $1,761.86 15 0.67 $0.13
Water Heating Water Heater <=
55 Gal Solar 1,324.61 $6,214.86 15 0.29 $0.41
Water Heating Water Heater >
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater > High Efficiency 171.20 $97.23 15 1.02 $0.05
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 949 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-47
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
55 Gal (EF=0.95)
Water Heating Water Heater >
55 Gal EF 2.3 (HP) 1,296.77 $1,691.15 15 0.76 $0.11
Water Heating Water Heater >
55 Gal Solar 1,158.76 $6,144.15 15 0.34 $0.46
Interior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Interior
Lighting Screw-in Infrared Halogen 157.77 $98.38 5 1.00 $0.13
Interior
Lighting Screw-in CFL 501.00 $17.84 6 2.46 $0.01
Interior
Lighting Screw-in LED 684.74 $1,012.85 12 - $0.15
Interior
Lighting Screw-in LED 684.74 $1,012.85 12 - $0.15
Interior
Lighting
Linear
Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting
Linear
Fluorescent T8 6.94 -$1.79 6 1.13 -$0.05
Interior
Lighting
Linear
Fluorescent Super T8 20.79 $14.30 6 0.74 $0.13
Interior
Lighting
Linear
Fluorescent T5 21.61 $24.22 6 0.59 $0.21
Interior
Lighting
Linear
Fluorescent LED 22.67 $212.60 10 0.21 $1.11
Interior
Lighting Specialty Halogen - $0.00 4 1.00 $0.00
Interior
Lighting Specialty CFL 134.16 $0.96 7 1.91 $0.00
Interior
Lighting Specialty LED 141.16 $261.26 12 0.29 $0.19
Exterior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Exterior
Lighting Screw-in Infrared Halogen 35.33 $9.82 5 1.00 $0.06
Exterior
Lighting Screw-in CFL 119.89 -$0.47 3 4.15 $0.00
Exterior
Lighting Screw-in LED 139.17 $1,016.52 12 - $0.75
Exterior
Lighting Screw-in LED 139.17 $1,016.52 12 - $0.75
Appliances Clothes Washer Baseline - $0.00 14 - $0.00
Appliances Clothes Washer Energy Star (MEF >
1.8) 36.47 $69.81 14 - $0.17
Appliances Clothes Washer Horizontal Axis 50.35 $150.80 14 1.00 $0.27
Appliances Clothes Dryer Baseline - $0.00 13 - $0.00
Appliances Clothes Dryer Moisture Detection 53.87 $48.40 13 1.00 $0.09
Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00
Appliances Dishwasher Energy Star 45.15 $460.95 9 - $1.32
Appliances Dishwasher Energy Star (2011) 5.91 $5.61 15 0.99 $0.08
Appliances Refrigerator Baseline - $0.00 20 - $0.00
Appliances Refrigerator Energy Star 38.65 $20.17 20 - $0.04
Appliances Refrigerator Baseline (2014) 70.80 $0.00 13 1.00 $0.00
Appliances Refrigerator Energy Star (2014) 113.29 $88.71 13 1.01 $0.08
Appliances Freezer Baseline - $0.00 22 - $0.00
Appliances Freezer Energy Star 31.60 $3.98 22 - $0.01
Appliances Freezer Baseline (2014) 73.33 -$145.00 11 1.00 -$0.22
Appliances Freezer Energy Star (2014) 117.32 -$112.83 11 0.99 -$0.11
Appliances Second
Refrigerator Baseline - $0.00 13 - $0.00
Appliances Second
Refrigerator Energy Star 52.79 $20.67 20 - $0.03
Appliances Second
Refrigerator Baseline (2014) 96.71 $0.00 13 1.00 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 950 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-48 www.enernoc.com
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Appliances Second
Refrigerator Energy Star (2014) 154.73 $88.71 13 1.00 $0.06
Appliances Stove Baseline - $0.00 13 1.00 $0.00
Appliances Stove Convection Oven 7.49 $1.86 13 1.00 $0.02
Appliances Stove Induction (High
Efficiency) 37.46 $1,432.20 13 0.37 $3.68
Appliances Microwave Baseline - $0.00 9 1.00 $0.00
Electronics Personal
Computers Baseline - $0.00 5 1.00 $0.00
Electronics Personal
Computers Energy Star 63.35 $1.20 5 1.01 $0.00
Electronics Personal
Computers Climate Savers 90.50 $175.49 5 0.85 $0.42
Electronics TVs Baseline - $0.00 11 1.00 $0.00
Electronics TVs Energy Star 38.99 $0.56 11 1.02 $0.00
Electronics Set-top
boxes/DVR Baseline - $0.00 11 1.00 $0.00
Electronics Set-top
boxes/DVR Energy Star 24.86 $0.56 11 1.01 $0.00
Electronics Devices and
Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00
Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00
Miscellaneous Pool Pump High Efficiency Pump 107.45 $85.00 15 0.99 $0.07
Miscellaneous Pool Pump Two-Speed Pump 429.80 $579.00 15 0.75 $0.12
Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00
Miscellaneous Furnace Fan Furnace Fan with
ECM 110.30 $0.64 18 1.27 $0.00
Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 951 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-49
Table B-16 Energy Efficiency Equipment Data, Electric—Low Income, New Vintage,
Washington
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Cooling Central AC SEER 13 - $0.00 15 - $0.00
Cooling Central AC SEER 14 (Energy Star) 58.73 $185.24 15 1.40 $0.27
Cooling Central AC SEER 15 (CEE Tier 2) 78.22 $370.47 15 0.93 $0.41
Cooling Central AC SEER 16 (CEE Tier 3) 94.59 $555.71 15 0.87 $0.51
Cooling Central AC Ductless Mini-Split
System 177.38 $2,394.23 20 0.65 $0.95
Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00
Cooling Room AC EER 10.8 (Energy
Star) 30.83 $104.04 10 0.82 $0.40
Cooling Room AC EER 11 36.33 $282.26 10 0.61 $0.92
Cooling Room AC EER 11.5 49.27 $625.50 10 0.41 $1.50
Cooling Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Cooling Air Source Heat
Pump SEER 14 (Energy Star) 44.94 $0.00 15 1.30 $0.00
Cooling Air Source Heat
Pump SEER 15 (CEE Tier 2) 59.86 $0.00 15 0.91 $0.00
Cooling Air Source Heat
Pump SEER 16 (CEE Tier 3) 72.38 $0.00 15 0.85 $0.00
Cooling Air Source Heat
Pump
Ductless Mini-Split
System 135.74 $0.00 20 0.86 $0.00
Cooling Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Cooling Geothermal Heat
Pump High Efficiency 69.87 $0.00 15 0.89 $0.00
Cooling Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance Electric Resistance - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance
Ductless Mini-Split
System 2,225.30 $156.87 20 1.30 $0.00
Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00
Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00
Space Heating Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Space Heating Air Source Heat
Pump SEER 14 (Energy Star) 423.49 $1,245.78 15 1.30 $0.25
Space Heating Air Source Heat
Pump SEER 15 (CEE Tier 2) 564.08 $2,315.13 15 0.91 $0.35
Space Heating Air Source Heat
Pump SEER 16 (CEE Tier 3) 682.10 $3,277.48 15 0.85 $0.42
Space Heating Air Source Heat
Pump
Ductless Mini-Split
System 1,279.15 $5,022.03 20 0.86 $0.28
Space Heating Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Space Heating Geothermal Heat
Pump High Efficiency 485.98 $1,500.00 15 0.89 $0.27
Space Heating Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Water Heating Water Heater <=
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater <=
55 Gal
High Efficiency
(EF=0.95) 126.97 $77.11 15 1.01 $0.05
Water Heating Water Heater <=
55 Gal EF 2.3 (HP) 1,223.96 $1,761.86 15 0.69 $0.12
Water Heating Water Heater <=
55 Gal Solar 1,386.93 $6,214.86 15 0.30 $0.39
Water Heating Water Heater >
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater > High Efficiency 179.32 $97.23 15 1.02 $0.05
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 952 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-50 www.enernoc.com
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
55 Gal (EF=0.95)
Water Heating Water Heater >
55 Gal EF 2.3 (HP) 1,358.29 $1,691.15 15 0.77 $0.11
Water Heating Water Heater >
55 Gal Solar 1,213.73 $6,144.15 15 0.35 $0.44
Interior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Interior
Lighting Screw-in Infrared Halogen 171.92 $98.38 5 1.00 $0.12
Interior
Lighting Screw-in CFL 545.94 $17.84 6 2.41 $0.01
Interior
Lighting Screw-in LED 746.16 $1,012.85 12 - $0.14
Interior
Lighting Screw-in LED 746.16 $1,012.85 12 - $0.14
Interior
Lighting
Linear
Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting
Linear
Fluorescent T8 7.80 -$1.79 6 1.13 -$0.04
Interior
Lighting
Linear
Fluorescent Super T8 23.37 $14.30 6 0.77 $0.11
Interior
Lighting
Linear
Fluorescent T5 24.29 $24.22 6 0.62 $0.18
Interior
Lighting
Linear
Fluorescent LED 25.48 $212.60 10 0.23 $0.99
Interior
Lighting Specialty Halogen - $0.00 4 1.00 $0.00
Interior
Lighting Specialty CFL 144.22 -$9.74 7 2.86 -$0.01
Interior
Lighting Specialty LED 151.74 $67.71 12 0.95 $0.05
Exterior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Exterior
Lighting Screw-in Infrared Halogen 38.38 $9.82 5 1.00 $0.06
Exterior
Lighting Screw-in CFL 130.23 -$0.51 3 4.13 $0.00
Exterior
Lighting Screw-in LED 151.17 $144.92 12 - $0.10
Exterior
Lighting Screw-in LED 151.17 $144.92 12 - $0.10
Appliances Clothes Washer Baseline - $0.00 14 - $0.00
Appliances Clothes Washer Energy Star (MEF >
1.8) 42.55 $69.81 14 - $0.15
Appliances Clothes Washer Horizontal Axis 58.74 $150.80 14 1.00 $0.23
Appliances Clothes Dryer Baseline - $0.00 13 - $0.00
Appliances Clothes Dryer Moisture Detection 58.62 $48.40 13 1.00 $0.08
Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00
Appliances Dishwasher Energy Star 49.31 $460.95 9 - $1.21
Appliances Dishwasher Energy Star (2011) 6.46 $5.61 15 0.99 $0.08
Appliances Refrigerator Baseline - $0.00 20 - $0.00
Appliances Refrigerator Energy Star 54.11 $20.17 20 - $0.03
Appliances Refrigerator Baseline (2014) 99.12 $0.00 13 1.00 $0.00
Appliances Refrigerator Energy Star (2014) 158.60 $88.71 13 1.02 $0.05
Appliances Freezer Baseline - $0.00 22 - $0.00
Appliances Freezer Energy Star 43.80 $3.98 22 - $0.01
Appliances Freezer Baseline (2014) 101.64 -$145.00 11 1.00 -$0.16
Appliances Freezer Energy Star (2014) 162.63 -$112.83 11 1.00 -$0.08
Appliances Second
Refrigerator Baseline - $0.00 20 - $0.00
Appliances Second
Refrigerator Energy Star 72.15 $20.67 20 - $0.02
Appliances Second
Refrigerator Baseline (2014) 132.17 $0.00 13 1.00 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 953 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-51
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Appliances Second
Refrigerator Energy Star (2014) 211.47 $88.71 13 1.01 $0.04
Appliances Stove Baseline - $0.00 13 1.00 $0.00
Appliances Stove Convection Oven 7.49 $1.86 13 1.00 $0.02
Appliances Stove Induction (High
Efficiency) 37.45 $1,432.20 13 0.37 $3.68
Appliances Microwave Baseline - $0.00 9 1.00 $0.00
Electronics Personal
Computers Baseline - $0.00 5 1.00 $0.00
Electronics Personal
Computers Energy Star 62.00 $1.20 5 1.01 $0.00
Electronics Personal
Computers Climate Savers 88.57 $175.49 5 0.85 $0.43
Electronics TVs Baseline - $0.00 11 1.00 $0.00
Electronics TVs Energy Star 43.32 $0.56 11 1.02 $0.00
Electronics Set-top
boxes/DVR Baseline - $0.00 11 1.00 $0.00
Electronics Set-top
boxes/DVR Energy Star 24.86 $0.56 11 1.01 $0.00
Electronics Devices and
Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00
Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00
Miscellaneous Pool Pump High Efficiency Pump 120.40 $85.00 15 0.99 $0.06
Miscellaneous Pool Pump Two-Speed Pump 481.61 $579.00 15 0.79 $0.10
Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00
Miscellaneous Furnace Fan Furnace Fan with
ECM 110.30 $0.64 18 1.27 $0.00
Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 954 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-52 www.enernoc.com
Table B-17 Energy Efficiency Equipment Data, Electric—Low Income, Existing Vintage, Idaho
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Cooling Central AC SEER 13 - $0.00 15 - $0.00
Cooling Central AC SEER 14 (Energy Star) 34.58 $185.24 15 1.40 $0.46
Cooling Central AC SEER 15 (CEE Tier 2) 47.45 $370.47 15 0.93 $0.68
Cooling Central AC SEER 16 (CEE Tier 3) 58.23 $555.71 15 0.87 $0.83
Cooling Central AC Ductless Mini-Split
System 104.44 $2,394.23 20 0.63 $1.62
Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00
Cooling Room AC EER 10.8 (Energy
Star) 18.57 $104.04 10 0.80 $0.66
Cooling Room AC EER 11 21.91 $282.26 10 0.59 $1.53
Cooling Room AC EER 11.5 29.66 $625.50 10 0.39 $2.50
Cooling Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Cooling Air Source Heat
Pump SEER 14 (Energy Star) 26.43 $1,245.78 15 1.30 $4.08
Cooling Air Source Heat
Pump SEER 15 (CEE Tier 2) 36.26 $2,315.13 15 0.91 $5.52
Cooling Air Source Heat
Pump SEER 16 (CEE Tier 3) 44.50 $3,277.48 15 0.83 $6.37
Cooling Air Source Heat
Pump
Ductless Mini-Split
System 79.81 $5,022.03 20 0.84 $4.45
Cooling Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Cooling Geothermal Heat
Pump High Efficiency 43.95 $1,500.00 15 0.87 $2.95
Cooling Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance Electric Resistance - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance
Ductless Mini-Split
System 1,966.55 $156.87 20 1.29 $0.01
Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00
Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00
Space Heating Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Space Heating Air Source Heat
Pump SEER 14 (Energy Star) 338.00 $1,245.78 15 1.30 $0.32
Space Heating Air Source Heat
Pump SEER 15 (CEE Tier 2) 463.77 $2,315.13 15 0.91 $0.43
Space Heating Air Source Heat
Pump SEER 16 (CEE Tier 3) 569.10 $3,277.48 15 0.83 $0.50
Space Heating Air Source Heat
Pump
Ductless Mini-Split
System 1,020.69 $5,022.03 20 0.84 $0.35
Space Heating Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Space Heating Geothermal Heat
Pump High Efficiency 414.84 $1,500.00 15 0.87 $0.31
Space Heating Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Water Heating Water Heater <=
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater <=
55 Gal
High Efficiency
(EF=0.95) 113.39 $77.11 15 1.00 $0.06
Water Heating Water Heater <=
55 Gal EF 2.3 (HP) 1,092.98 $1,761.86 15 0.60 $0.14
Water Heating Water Heater <=
55 Gal Solar 1,238.51 $6,214.86 15 0.26 $0.43
Water Heating Water Heater >
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater >
55 Gal
High Efficiency
(EF=0.95) 160.07 $97.23 15 1.01 $0.05
Water Heating Water Heater > EF 2.3 (HP) 1,212.48 $1,691.15 15 0.68 $0.12
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 955 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-53
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
55 Gal
Water Heating Water Heater >
55 Gal Solar 1,083.44 $6,144.15 15 0.30 $0.49
Interior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Interior
Lighting Screw-in Infrared Halogen 147.51 $98.38 5 1.00 $0.14
Interior
Lighting Screw-in CFL 468.44 $17.84 6 2.59 $0.01
Interior
Lighting Screw-in LED 640.24 $1,012.85 12 - $0.16
Interior
Lighting Screw-in LED 640.24 $1,012.85 12 - $0.16
Interior
Lighting
Linear
Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting
Linear
Fluorescent T8 6.49 -$1.79 6 1.13 -$0.05
Interior
Lighting
Linear
Fluorescent Super T8 19.44 $14.30 6 0.73 $0.13
Interior
Lighting
Linear
Fluorescent T5 20.21 $24.22 6 0.57 $0.22
Interior
Lighting
Linear
Fluorescent LED 21.20 $212.60 10 0.21 $1.19
Interior
Lighting Specialty Halogen - $0.00 4 1.00 $0.00
Interior
Lighting Specialty CFL 125.44 $0.96 7 1.91 $0.00
Interior
Lighting Specialty LED 131.98 $261.26 12 0.28 $0.20
Exterior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Exterior
Lighting Screw-in Infrared Halogen 33.03 $9.82 5 1.00 $0.06
Exterior
Lighting Screw-in CFL 112.10 -$0.47 3 4.28 $0.00
Exterior
Lighting Screw-in LED 130.12 $1,016.52 12 - $0.80
Exterior
Lighting Screw-in LED 130.12 $1,016.52 12 - $0.80
Appliances Clothes Washer Baseline - $0.00 14 - $0.00
Appliances Clothes Washer Energy Star (MEF >
1.8) 34.10 $69.81 14 - $0.19
Appliances Clothes Washer Horizontal Axis 47.07 $150.80 14 1.00 $0.29
Appliances Clothes Dryer Baseline - $0.00 13 - $0.00
Appliances Clothes Dryer Moisture Detection 50.36 $48.40 13 1.00 $0.09
Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00
Appliances Dishwasher Energy Star 42.21 $460.95 9 - $1.41
Appliances Dishwasher Energy Star (2011) 5.53 $5.61 15 0.99 $0.09
Appliances Refrigerator Baseline - $0.00 20 - $0.00
Appliances Refrigerator Energy Star 36.14 $20.17 20 - $0.04
Appliances Refrigerator Baseline (2014) 66.20 $0.00 13 1.00 $0.00
Appliances Refrigerator Energy Star (2014) 105.92 $88.71 13 1.00 $0.08
Appliances Freezer Baseline - $0.00 22 - $0.00
Appliances Freezer Energy Star 29.54 $3.98 22 - $0.01
Appliances Freezer Baseline (2014) 68.56 -$145.00 11 1.00 -$0.23
Appliances Freezer Energy Star (2014) 109.70 -$112.83 11 0.98 -$0.11
Appliances Second
Refrigerator Baseline - $0.00 20 - $0.00
Appliances Second
Refrigerator Energy Star 49.36 $20.67 20 - $0.03
Appliances Second
Refrigerator Baseline (2014) 90.42 $0.00 13 1.00 $0.00
Appliances Second
Refrigerator Energy Star (2014) 144.67 $88.71 13 1.00 $0.06
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 956 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-54 www.enernoc.com
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Appliances Stove Baseline - $0.00 13 1.00 $0.00
Appliances Stove Convection Oven 7.00 $1.86 13 1.00 $0.03
Appliances Stove Induction (High
Efficiency) 35.02 $1,432.20 13 0.36 $3.94
Appliances Microwave Baseline - $0.00 9 1.00 $0.00
Electronics Personal
Computers Baseline - $0.00 5 1.00 $0.00
Electronics Personal
Computers Energy Star 59.23 $1.20 5 1.01 $0.00
Electronics Personal
Computers Climate Savers 84.61 $175.49 5 0.85 $0.45
Electronics TVs Baseline - $0.00 11 1.00 $0.00
Electronics TVs Energy Star 36.45 $0.56 11 1.01 $0.00
Electronics Set-top
boxes/DVR Baseline - $0.00 11 1.00 $0.00
Electronics Set-top
boxes/DVR Energy Star 23.24 $0.56 11 1.01 $0.00
Electronics Devices and
Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00
Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00
Miscellaneous Pool Pump High Efficiency Pump 100.46 $85.00 15 0.98 $0.07
Miscellaneous Pool Pump Two-Speed Pump 401.86 $579.00 15 0.73 $0.12
Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00
Miscellaneous Furnace Fan Furnace Fan with
ECM 103.13 $0.64 18 1.26 $0.00
Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 957 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-55
Table B-18 Energy Efficiency Equipment Data, Electric—Low income, New Vintage,
Idaho
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Cooling Central AC SEER 13 - $0.00 15 - $0.00
Cooling Central AC SEER 14 (Energy Star) 41.11 $185.24 15 1.40 $0.39
Cooling Central AC SEER 15 (CEE Tier 2) 54.76 $370.47 15 0.93 $0.59
Cooling Central AC SEER 16 (CEE Tier 3) 66.21 $555.71 15 0.87 $0.73
Cooling Central AC Ductless Mini-Split
System 124.17 $2,394.23 20 0.64 $1.36
Cooling Room AC EER 9.8 - $0.00 10 1.00 $0.00
Cooling Room AC EER 10.8 (Energy
Star) 21.58 $104.04 10 0.80 $0.57
Cooling Room AC EER 11 25.43 $282.26 10 0.59 $1.32
Cooling Room AC EER 11.5 34.49 $625.50 10 0.39 $2.15
Cooling Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Cooling Air Source Heat
Pump SEER 14 (Energy Star) 31.46 $0.00 15 1.30 $0.00
Cooling Air Source Heat
Pump SEER 15 (CEE Tier 2) 41.90 $0.00 15 0.91 $0.00
Cooling Air Source Heat
Pump SEER 16 (CEE Tier 3) 50.67 $0.00 15 0.85 $0.00
Cooling Air Source Heat
Pump
Ductless Mini-Split
System 95.02 $0.00 20 0.85 $0.00
Cooling Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Cooling Geothermal Heat
Pump High Efficiency 48.91 $0.00 15 0.87 $0.00
Cooling Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance Electric Resistance - $0.00 20 1.00 $0.00
Space Heating Electric
Resistance
Ductless Mini-Split
System 2,114.04 $156.87 20 1.30 $0.01
Space Heating Electric Furnace 3400 BTU/KW - $0.00 15 1.00 $0.00
Space Heating Supplemental Supplemental - $0.00 5 1.00 $0.00
Space Heating Air Source Heat
Pump SEER 13 - $0.00 15 - $0.00
Space Heating Air Source Heat
Pump SEER 14 (Energy Star) 402.32 $1,245.78 15 1.30 $0.27
Space Heating Air Source Heat
Pump SEER 15 (CEE Tier 2) 535.87 $2,315.13 15 0.91 $0.37
Space Heating Air Source Heat
Pump SEER 16 (CEE Tier 3) 647.99 $3,277.48 15 0.85 $0.44
Space Heating Air Source Heat
Pump
Ductless Mini-Split
System 1,215.19 $5,022.03 20 0.85 $0.29
Space Heating Geothermal Heat
Pump Standard - $0.00 15 1.00 $0.00
Space Heating Geothermal Heat
Pump High Efficiency 461.68 $1,500.00 15 0.87 $0.28
Space Heating Ductless HP Ductless Mini-Split
System - $0.00 20 1.00 $0.00
Water Heating Water Heater <=
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater <=
55 Gal
High Efficiency
(EF=0.95) 118.72 $77.11 15 1.00 $0.06
Water Heating Water Heater <=
55 Gal EF 2.3 (HP) 1,144.40 $1,761.86 15 0.62 $0.13
Water Heating Water Heater <=
55 Gal Solar 1,296.78 $6,214.86 15 0.26 $0.41
Water Heating Water Heater >
55 Gal Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater >
55 Gal
High Efficiency
(EF=0.95) 167.67 $97.23 15 1.01 $0.05
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 958 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-56 www.enernoc.com
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Water Heating Water Heater >
55 Gal EF 2.3 (HP) 1,270.00 $1,691.15 15 0.70 $0.12
Water Heating Water Heater >
55 Gal Solar 1,134.84 $6,144.15 15 0.31 $0.47
Interior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Interior
Lighting Screw-in Infrared Halogen 160.74 $98.38 5 1.00 $0.13
Interior
Lighting Screw-in CFL 510.45 $17.84 6 2.54 $0.01
Interior
Lighting Screw-in LED 697.66 $1,012.85 12 - $0.15
Interior
Lighting Screw-in LED 697.66 $1,012.85 12 - $0.15
Interior
Lighting
Linear
Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting
Linear
Fluorescent T8 7.29 -$1.79 6 1.13 -$0.05
Interior
Lighting
Linear
Fluorescent Super T8 21.85 $14.30 6 0.75 $0.12
Interior
Lighting
Linear
Fluorescent T5 22.71 $24.22 6 0.60 $0.20
Interior
Lighting
Linear
Fluorescent LED 23.82 $212.60 10 0.22 $1.06
Interior
Lighting Specialty Halogen - $0.00 4 1.00 $0.00
Interior
Lighting Specialty CFL 134.85 -$9.64 7 2.92 -$0.01
Interior
Lighting Specialty LED 141.88 $71.04 12 0.91 $0.05
Exterior
Lighting Screw-in Incandescent - $0.00 4 - $0.00
Exterior
Lighting Screw-in Infrared Halogen 35.88 $9.82 5 1.00 $0.06
Exterior
Lighting Screw-in CFL 121.77 -$0.51 3 4.25 $0.00
Exterior
Lighting Screw-in LED 141.35 $144.92 12 - $0.11
Exterior
Lighting Screw-in LED 141.35 $144.92 12 - $0.11
Appliances Clothes Washer Baseline - $0.00 14 - $0.00
Appliances Clothes Washer Energy Star (MEF >
1.8) 39.78 $69.81 14 - $0.16
Appliances Clothes Washer Horizontal Axis 54.92 $150.80 14 1.00 $0.25
Appliances Clothes Dryer Baseline - $0.00 13 - $0.00
Appliances Clothes Dryer Moisture Detection 54.81 $48.40 13 1.00 $0.09
Appliances Dishwasher Baseline - $0.00 15 1.00 $0.00
Appliances Dishwasher Energy Star 46.11 $460.95 9 - $1.29
Appliances Dishwasher Energy Star (2011) 6.04 $5.61 15 0.99 $0.08
Appliances Refrigerator Baseline - $0.00 20 - $0.00
Appliances Refrigerator Energy Star 50.60 $20.17 20 - $0.03
Appliances Refrigerator Baseline (2014) 92.68 $0.00 13 1.00 $0.00
Appliances Refrigerator Energy Star (2014) 148.29 $88.71 13 1.01 $0.06
Appliances Freezer Baseline - $0.00 22 - $0.00
Appliances Freezer Energy Star 40.95 $3.98 22 - $0.01
Appliances Freezer Baseline (2014) 95.04 -$145.00 11 1.00 -$0.17
Appliances Freezer Energy Star (2014) 152.06 -$112.83 11 1.00 -$0.08
Appliances Second
Refrigerator Baseline - $0.00 20 - $0.00
Appliances Second
Refrigerator Energy Star 67.46 $20.67 20 - $0.02
Appliances Second
Refrigerator Baseline (2014) 123.58 $0.00 13 1.00 $0.00
Appliances Second Energy Star (2014) 197.72 $88.71 13 1.01 $0.04
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 959 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-57
End Use Technology Eff. Definition Savings
(kWh/HH/yr)
Incremental
Cost ($/HH)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized Cost
of Energy
($/kWh)
Refrigerator
Appliances Stove Baseline - $0.00 13 1.00 $0.00
Appliances Stove Convection Oven 7.00 $1.86 13 1.00 $0.03
Appliances Stove Induction (High
Efficiency) 35.02 $1,432.20 13 0.36 $3.94
Appliances Microwave Baseline - $0.00 9 1.00 $0.00
Electronics Personal
Computers Baseline - $0.00 5 1.00 $0.00
Electronics Personal
Computers Energy Star 57.97 $1.20 5 1.01 $0.00
Electronics Personal
Computers Climate Savers 82.81 $175.49 5 0.85 $0.46
Electronics TVs Baseline - $0.00 11 1.00 $0.00
Electronics TVs Energy Star 40.50 $0.56 11 1.02 $0.00
Electronics Set-top
boxes/DVR Baseline - $0.00 11 1.00 $0.00
Electronics Set-top
boxes/DVR Energy Star 23.24 $0.56 11 1.01 $0.00
Electronics Devices and
Gadgets Devices and Gadgets - $0.00 5 1.00 $0.00
Miscellaneous Pool Pump Baseline Pump - $0.00 15 1.00 $0.00
Miscellaneous Pool Pump High Efficiency Pump 112.58 $85.00 15 0.99 $0.07
Miscellaneous Pool Pump Two-Speed Pump 450.31 $579.00 15 0.77 $0.11
Miscellaneous Furnace Fan Baseline - $0.00 18 1.00 $0.00
Miscellaneous Furnace Fan Furnace Fan with
ECM 103.13 $0.64 18 1.26 $0.00
Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 960 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-58 www.enernoc.com
Table B-19 Energy Efficiency Non-Equipment Data, Electric—Single Family, Existing
Vintage, Washington
Measure Base
Saturation Applicability Lifetime
(Years)
Cost
($/HH)
Savings
(kWh)
BC
Ratio
Levelized
Cost
($/kWh)
Central AC - Early Replacement 0.0% 80.0% 15 $2,895.00 139.3 0.00 $2.133
Central AC - Maintenance and Tune-Up 41.0% 100.0% 4 $125.00 137.4 0.06 $0.251
Room AC - Removal of Second Unit 0.0% 100.0% 5 $75.00 512.4 0.42 $0.033
Attic Fan - Installation 12.0% 50.0% 18 $115.80 6.2 0.00 $1.736
Attic Fan - Photovoltaic - Installation 13.0% 100.0% 19 $350.00 6.2 0.00 $5.107
Ceiling Fan - Installation 51.0% 100.0% 15 $160.00 108.8 0.06 $0.151
Whole-House Fan - Installation 6.9% 25.0% 18 $200.00 174.6 0.08 $0.106
Air Source Heat Pump - Maintenance 37.8% 100.0% 4 $125.00 926.7 0.42 $0.037
Insulation - Ducting 15.0% 59.4% 18 $500.00 483.1 0.09 $0.096
Repair and Sealing - Ducting 12.3% 100.0% 20 $571.38 2,111.0 0.35 $0.024
Thermostat - Clock/Programmable 71.8% 75.0% 15 $249.47 587.7 0.49 $0.044
Doors - Storm and Thermal 38.0% 100.0% 12 $320.00 116.9 0.05 $0.322
Insulation - Infiltration Control 46.0% 100.0% 25 $306.11 876.6 0.48 $0.028
Insulation - Ceiling 76.4% 75.0% 25 $630.45 991.9 0.18 $0.051
Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 571.9 0.09 $0.190
Roofs - High Reflectivity 5.0% 100.0% 15 $1,549.61 82.7 0.00 $1.923
Windows - Reflective Film 5.0% 50.0% 10 $266.67 369.6 0.12 $0.096
Windows - High Efficiency/Energy Star 77.6% 100.0% 25 $5,200.97 4,270.5 0.11 $0.098
Interior Lighting - Occupancy Sensor 23.5% 50.0% 15 $750.00 444.7 0.05 $0.173
Exterior Lighting - Photovoltaic
Installation 10.0% 100.0% 15 $2,975.00 53.8 0.00 $5.679
Exterior Lighting - Photosensor Control 23.5% 100.0% 8 $90.00 36.3 0.03 $0.388
Exterior Lighting - Timeclock
Installation 10.0% 100.0% 8 $72.00 36.3 0.04 $0.310
Water Heater - Faucet Aerators 53.2% 100.0% 25 $24.00 275.8 1.23 $0.007
Water Heater - Pipe Insulation 17.0% 100.0% 13 $15.00 242.9 1.94 $0.007
Water Heater - Low Flow Showerheads 75.5% 100.0% 10 $25.48 354.0 1.87 $0.010
Water Heater - Tank Blanket/Insulation 54.0% 100.0% 10 $15.00 781.1 4.19 $0.003
Water Heater - Thermostat Setback 17.0% 100.0% 5 $40.00 781.1 1.23 $0.012
Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 117.4 0.47 $0.027
Refrigerator - Early Replacement 10.0% 85.0% 7 $109.00 319.9 0.16 $0.059
Refrigerator - Remove Second Unit 17.3% 85.0% 7 $109.00 437.0 0.83 $0.043
Freezer - Early Replacement 10.0% 85.0% 5 $109.00 355.4 0.14 $0.070
Freezer - Remove Second Unit 17.3% 85.0% 5 $109.00 384.9 0.75 $0.065
Behavioral Measures 20.0% 50.0% 1 $12.00 125.0 0.20 $0.096
Pool - Pump Timer 58.8% 100.0% 15 $160.00 194.3 0.12 $0.085
Insulation - Foundation 25.9% 39.0% 25 $750.53 521.1 0.19 $0.116
Insulation - Wall Cavity 88.4% 100.0% 25 $1,415.87 2,186.1 0.17 $0.052
Insulation - Wall Sheathing 64.4% 100.0% 20 $300.00 276.9 0.14 $0.096
Water Heater - Solar System 5.0% 25.0% 20 $6,500.00 6,437.3 0.11 $0.089

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 961 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-59
Table B-20 Energy Efficiency Non-Equipment Data, Electric—Single Family, New
Vintage, Washington
Measure Base
Saturation Applicability Lifetime
(Years)
Cost
($/HH)
Savings
(kWh)
BC
Ratio
Levelized
Cost
($/kWh)
Central AC - Maintenance and Tune-Up 41.0% 100.0% 4 $125.00 158.0 0.07 $0.218
Attic Fan - Installation 12.6% 50.0% 18 $96.50 8.7 0.01 $1.027
Attic Fan - Photovoltaic - Installation 4.0% 25.0% 19 $200.00 8.7 0.00 $2.072
Ceiling Fan - Installation 52.6% 100.0% 15 $160.00 174.2 0.10 $0.094
Whole-House Fan - Installation 4.0% 25.0% 18 $200.00 239.6 0.12 $0.078
Air Source Heat Pump - Maintenance 37.8% 100.0% 4 $125.00 1,065.7 0.53 $0.032
Insulation - Ducting 50.0% 59.4% 18 $250.00 553.3 0.22 $0.042
Thermostat - Clock/Programmable 90.6% 95.0% 15 $249.47 608.2 0.41 $0.042
Doors - Storm and Thermal 13.0% 100.0% 12 $180.00 203.5 0.16 $0.104
Insulation - Ceiling 81.8% 75.0% 20 $634.00 549.5 0.13 $0.102
Insulation - Radiant Barrier 25.0% 100.0% 12 $922.68 193.4 0.03 $0.561
Roofs - High Reflectivity 5.0% 100.0% 15 $516.54 129.8 0.02 $0.408
Windows - Reflective Film 2.0% 50.0% 10 $266.67 338.0 0.11 $0.105
Windows - High Efficiency/Energy Star 95.5% 100.0% 25 $2,200.00 3,037.6 0.22 $0.058
Interior Lighting - Occupancy Sensor 23.5% 30.0% 15 $500.00 493.6 0.10 $0.104
Exterior Lighting - Photovoltaic
Installation 10.0% 100.0% 15 $2,975.00 60.1 0.00 $5.076
Exterior Lighting - Photosensor Control 13.2% 100.0% 8 $90.00 40.0 0.05 $0.352
Exterior Lighting - Timeclock
Installation 16.0% 100.0% 8 $72.00 40.0 0.06 $0.282
Water Heater - Faucet Aerators 38.3% 100.0% 25 $24.00 251.6 1.13 $0.008
Water Heater - Pipe Insulation 8.0% 100.0% 13 $15.00 221.9 1.78 $0.008
Water Heater - Low Flow Showerheads 89.8% 100.0% 10 $25.48 354.0 1.81 $0.010
Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $15.00 713.6 3.82 $0.003
Water Heater - Thermostat Setback 5.0% 100.0% 5 $40.00 713.6 1.13 $0.013
Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 126.7 0.53 $0.025
Behavioral Measures 20.0% 75.0% 1 $12.00 142.7 0.24 $0.084
Pool - Pump Timer 55.0% 100.0% 15 $160.00 200.1 0.14 $0.082
Insulation - Foundation 54.8% 63.6% 20 $358.00 744.7 0.49 $0.042
Insulation - Wall Cavity 91.1% 100.0% 25 $236.00 558.7 0.38 $0.034
Insulation - Wall Sheathing 64.4% 100.0% 20 $300.00 315.7 0.17 $0.084
Water Heater - Drainwater Heat
Reocvery 1.0% 100.0% 25 $899.00 1,176.3 0.14 $0.061

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 962 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-60 www.enernoc.com
Table B-21 Energy Efficiency Non-Equipment Data, Electric—Single Family, Existing Vintage,
Idaho
Measure Base
Saturation Applicability Lifetime
(Years)
Cost
($/HH)
Savings
(kWh)
BC
Ratio
Levelized
Cost
($/kWh)
Central AC - Early Replacement 0.0% 80.0% 15 $2,895.00 139.3 0.00 $2.133
Central AC - Maintenance and Tune-Up 41.0% 100.0% 4 $125.00 137.4 0.06 $0.251
Room AC - Removal of Second Unit 0.0% 100.0% 5 $75.00 512.4 0.42 $0.033
Attic Fan - Installation 12.0% 50.0% 18 $115.80 6.2 0.00 $1.736
Attic Fan - Photovoltaic - Installation 13.0% 100.0% 19 $350.00 6.2 0.00 $5.107
Ceiling Fan - Installation 51.0% 100.0% 15 $160.00 108.8 0.06 $0.151
Whole-House Fan - Installation 6.9% 25.0% 18 $200.00 174.6 0.08 $0.106
Air Source Heat Pump - Maintenance 37.8% 100.0% 4 $125.00 926.7 0.42 $0.037
Insulation - Ducting 15.0% 59.4% 18 $500.00 483.1 0.09 $0.096
Repair and Sealing - Ducting 12.3% 100.0% 20 $571.38 2,111.0 0.35 $0.024
Thermostat - Clock/Programmable 71.8% 75.0% 15 $249.47 587.7 0.49 $0.044
Doors - Storm and Thermal 38.0% 100.0% 12 $320.00 116.9 0.05 $0.322
Insulation - Infiltration Control 46.0% 100.0% 25 $306.11 876.6 0.48 $0.028
Insulation - Ceiling 76.4% 75.0% 25 $630.45 991.9 0.18 $0.051
Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 571.9 0.09 $0.190
Roofs - High Reflectivity 5.0% 100.0% 15 $1,549.61 82.7 0.00 $1.923
Windows - Reflective Film 5.0% 50.0% 10 $266.67 369.6 0.12 $0.096
Windows - High Efficiency/Energy Star 77.6% 100.0% 25 $5,200.97 4,270.5 0.11 $0.098
Interior Lighting - Occupancy Sensor 23.5% 50.0% 15 $750.00 444.7 0.05 $0.173
Exterior Lighting - Photovoltaic
Installation 10.0% 100.0% 15 $2,975.00 53.8 0.00 $5.679
Exterior Lighting - Photosensor Control 23.5% 100.0% 8 $90.00 36.3 0.03 $0.388
Exterior Lighting - Timeclock
Installation 10.0% 100.0% 8 $72.00 36.3 0.04 $0.310
Water Heater - Faucet Aerators 53.2% 100.0% 25 $24.00 275.8 1.23 $0.007
Water Heater - Pipe Insulation 17.0% 100.0% 13 $15.00 242.9 1.94 $0.007
Water Heater - Low Flow Showerheads 75.5% 100.0% 10 $25.48 354.0 1.87 $0.010
Water Heater - Tank Blanket/Insulation 54.0% 100.0% 10 $15.00 781.1 4.19 $0.003
Water Heater - Thermostat Setback 17.0% 100.0% 5 $40.00 781.1 1.23 $0.012
Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 117.4 0.47 $0.027
Refrigerator - Early Replacement 10.0% 85.0% 7 $109.00 319.9 0.16 $0.059
Refrigerator - Remove Second Unit 17.3% 85.0% 7 $109.00 437.0 0.83 $0.043
Freezer - Early Replacement 10.0% 85.0% 5 $109.00 355.4 0.14 $0.070
Freezer - Remove Second Unit 17.3% 85.0% 5 $109.00 384.9 0.75 $0.065
Behavioral Measures 20.0% 50.0% 1 $12.00 125.0 0.20 $0.096
Pool - Pump Timer 58.8% 100.0% 15 $160.00 194.3 0.12 $0.085
Insulation - Foundation 25.9% 39.0% 25 $750.53 521.1 0.19 $0.116
Insulation - Wall Cavity 88.4% 100.0% 25 $1,415.87 2,186.1 0.17 $0.052
Insulation - Wall Sheathing 64.4% 100.0% 20 $300.00 276.9 0.14 $0.096
Water Heater - Solar System 5.0% 25.0% 20 $6,500.00 6,437.3 0.11 $0.089

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 963 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-61
Table B-22 Energy Efficiency Non-Equipment Data, Electric—Single Family, New Vintage, Idaho
Measure Base
Saturation Applicability Lifetime
(Years)
Cost
($/HH)
Savings
(kWh)
BC
Ratio
Levelized
Cost
($/kWh)
Central AC - Maintenance and Tune-Up 41.0% 100.0% 4 $125.00 158.0 0.07 $0.218
Attic Fan - Installation 12.6% 50.0% 18 $96.50 8.7 0.01 $1.027
Attic Fan - Photovoltaic - Installation 4.0% 25.0% 19 $200.00 8.7 0.00 $2.072
Ceiling Fan - Installation 52.6% 100.0% 15 $160.00 174.2 0.10 $0.094
Whole-House Fan - Installation 4.0% 25.0% 18 $200.00 239.6 0.12 $0.078
Air Source Heat Pump - Maintenance 37.8% 100.0% 4 $125.00 1,065.7 0.53 $0.032
Insulation - Ducting 50.0% 59.4% 18 $250.00 553.3 0.22 $0.042
Thermostat - Clock/Programmable 90.6% 95.0% 15 $249.47 608.2 0.41 $0.042
Doors - Storm and Thermal 13.0% 100.0% 12 $180.00 203.5 0.16 $0.104
Insulation - Ceiling 81.8% 75.0% 20 $634.00 549.5 0.13 $0.102
Insulation - Radiant Barrier 25.0% 100.0% 12 $922.68 193.4 0.03 $0.561
Roofs - High Reflectivity 5.0% 100.0% 15 $516.54 129.8 0.02 $0.408
Windows - Reflective Film 2.0% 50.0% 10 $266.67 338.0 0.11 $0.105
Windows - High Efficiency/Energy Star 95.5% 100.0% 25 $2,200.00 3,037.6 0.22 $0.058
Interior Lighting - Occupancy Sensor 23.5% 30.0% 15 $500.00 493.6 0.10 $0.104
Exterior Lighting - Photovoltaic
Installation 10.0% 100.0% 15 $2,975.00 60.1 0.00 $5.076
Exterior Lighting - Photosensor Control 13.2% 100.0% 8 $90.00 40.0 0.05 $0.352
Exterior Lighting - Timeclock
Installation 16.0% 100.0% 8 $72.00 40.0 0.06 $0.282
Water Heater - Faucet Aerators 38.3% 100.0% 25 $24.00 251.6 1.13 $0.008
Water Heater - Pipe Insulation 8.0% 100.0% 13 $15.00 221.9 1.78 $0.008
Water Heater - Low Flow Showerheads 89.8% 100.0% 10 $25.48 354.0 1.81 $0.010
Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $15.00 713.6 3.82 $0.003
Water Heater - Thermostat Setback 5.0% 100.0% 5 $40.00 713.6 1.13 $0.013
Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 126.7 0.53 $0.025
Behavioral Measures 20.0% 75.0% 1 $12.00 142.7 0.24 $0.084
Pool - Pump Timer 55.0% 100.0% 15 $160.00 200.1 0.14 $0.082
Insulation - Foundation 54.8% 63.6% 20 $358.00 744.7 0.49 $0.042
Insulation - Wall Cavity 91.1% 100.0% 25 $236.00 558.7 0.38 $0.034
Insulation - Wall Sheathing 64.4% 100.0% 20 $300.00 315.7 0.17 $0.084
Water Heater - Drainwater Heat
Reocvery 1.0% 100.0% 25 $899.00 1,176.3 0.14 $0.061

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 964 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-62 www.enernoc.com
Table B-23 Energy Efficiency Non-Equipment Data, Electric—Multi Family, Existing
Vintage, Washington
Measure Base
Saturation Applicability Lifetime
(Years)
Cost
($/HH)
Savings
(kWh)
BC
Ratio
Levelized
Cost
($/kWh)
Central AC - Early Replacement 0.0% 80.0% 15 $2,895.00 46.4 0.00 $6.400
Central AC - Maintenance and Tune-Up 32.8% 100.0% 4 $100.00 45.8 0.03 $0.602
Room AC - Removal of Second Unit 0.0% 100.0% 5 $75.00 355.3 0.29 $0.048
Ceiling Fan - Installation 32.4% 100.0% 15 $80.00 37.9 0.04 $0.216
Air Source Heat Pump - Maintenance 25.0% 100.0% 4 $100.00 360.1 0.21 $0.077
Insulation - Ducting 13.0% 13.0% 18 $375.00 7.0 0.00 $4.945
Repair and Sealing - Ducting 11.8% 100.0% 18 $500.00 720.5 0.13 $0.064
Thermostat - Clock/Programmable 27.0% 75.0% 15 $114.42 315.1 0.35 $0.037
Doors - Storm and Thermal 17.0% 100.0% 12 $320.00 - - $0.000
Insulation - Infiltration Control 19.0% 100.0% 12 $266.00 283.6 0.17 $0.110
Insulation - Ceiling 30.0% 40.0% 20 $215.00 277.6 0.17 $0.068
Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 433.3 0.06 $0.251
Roofs - High Reflectivity 3.0% 100.0% 15 $1,549.61 39.3 0.00 $4.045
Windows - Reflective Film 5.0% 50.0% 10 $166.67 112.4 0.06 $0.197
Windows - High Efficiency/Energy Star 70.4% 100.0% 25 $2,500.00 1,020.7 0.05 $0.196
Interior Lighting - Occupancy Sensor 5.6% 20.0% 15 $256.00 253.9 0.08 $0.103
Exterior Lighting - Photovoltaic
Installation 10.0% 100.0% 15 $2,975.00 5.5 0.00 $55.926
Exterior Lighting - Photosensor Control 7.1% 100.0% 8 $90.00 2.1 0.00 $6.688
Exterior Lighting - Timeclock
Installation 6.0% 100.0% 8 $72.00 2.1 0.00 $5.350
Water Heater - Faucet Aerators 43.2% 100.0% 25 $24.00 237.5 1.05 $0.008
Water Heater - Pipe Insulation 6.0% 100.0% 13 $15.00 149.6 0.90 $0.011
Water Heater - Low Flow Showerheads 71.6% 100.0% 10 $25.48 282.0 1.11 $0.012
Water Heater - Tank Blanket/Insulation 54.0% 100.0% 10 $15.00 480.9 2.25 $0.004
Water Heater - Thermostat Setback 17.0% 100.0% 5 $40.00 480.9 0.67 $0.019
Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 73.6 0.31 $0.043
Refrigerator - Early Replacement 10.0% 85.0% 7 $109.00 255.9 0.13 $0.074
Refrigerator - Remove Second Unit 17.3% 85.0% 7 $109.00 437.0 0.83 $0.043
Freezer - Early Replacement 10.0% 85.0% 5 $109.00 307.9 0.12 $0.081
Freezer - Remove Second Unit 17.3% 85.0% 5 $109.00 384.9 0.75 $0.065
Behavioral Measures 5.0% 25.0% 1 $12.00 65.5 0.10 $0.183
Insulation - Wall Cavity 80.0% 100.0% 25 $707.94 522.3 0.09 $0.109
Insulation - Wall Sheathing 55.1% 100.0% 20 $210.00 356.6 0.22 $0.052

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 965 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-63
Table B-24 Energy Efficiency Non-Equipment Data, Electric—Multi Family, New
Vintage, Washington
Measure Base
Saturation Applicability Lifetime
(Years)
Cost
($/HH)
Savings
(kWh)
BC
Ratio
Levelized
Cost
($/kWh)
Central AC - Maintenance and Tune-Up 32.8% 100.0% 4 $100.00 52.7 0.03 $0.524
Ceiling Fan - Installation 17.6% 100.0% 15 $80.00 59.7 0.07 $0.138
Air Source Heat Pump - Maintenance 25.0% 100.0% 4 $100.00 414.1 0.27 $0.067
Insulation - Ducting 13.0% 13.0% 18 $200.00 7.3 0.00 $2.531
Thermostat - Clock/Programmable 77.0% 80.0% 15 $114.42 364.1 0.36 $0.032
Doors - Storm and Thermal 19.0% 100.0% 12 $180.00 - - $0.000
Insulation - Ceiling 30.7% 50.0% 20 $152.00 430.5 0.37 $0.031
Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 160.5 0.02 $0.677
Roofs - High Reflectivity 0.0% 100.0% 15 $516.54 35.4 0.01 $1.498
Windows - Reflective Film 2.0% 50.0% 10 $166.67 129.5 0.07 $0.171
Windows - High Efficiency/Energy Star 89.2% 100.0% 25 $2,200.00 2,298.8 0.14 $0.077
Interior Lighting - Occupancy Sensor 5.6% 10.0% 15 $256.00 281.1 0.11 $0.093
Exterior Lighting - Photovoltaic
Installation 10.0% 100.0% 15 $2,975.00 6.3 0.00 $48.646
Exterior Lighting - Photosensor Control 0.7% 100.0% 8 $90.00 2.3 0.00 $6.080
Exterior Lighting - Timeclock
Installation 11.0% 100.0% 8 $72.00 2.3 0.01 $4.864
Water Heater - Faucet Aerators 11.0% 100.0% 25 $24.00 217.0 1.04 $0.009
Water Heater - Pipe Insulation 0.0% 100.0% 13 $15.00 136.6 1.11 $0.012
Water Heater - Low Flow Showerheads 66.2% 100.0% 10 $25.48 282.0 1.42 $0.012
Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $15.00 439.3 2.67 $0.005
Water Heater - Thermostat Setback 5.0% 100.0% 5 $40.00 439.3 0.76 $0.021
Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 79.5 0.35 $0.039
Behavioral Measures 5.0% 75.0% 1 $12.00 75.1 0.13 $0.160
Insulation - Wall Cavity 91.1% 100.0% 25 $62.50 478.4 1.03 $0.010
Insulation - Wall Sheathing 55.1% 100.0% 20 $210.00 410.2 0.26 $0.045
Water Heater - Drainwater Heat
Reocvery 1.0% 100.0% 25 $899.00 724.2 0.09 $0.100

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 966 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-64 www.enernoc.com
Table B-25 Energy Efficiency Non-Equipment Data, Electric—Multi Family, Existing Vintage,
Idaho
Measure Base
Saturation Applicability Lifetime
(Years)
Cost
($/HH)
Savings
(kWh)
BC
Ratio
Levelized
Cost
($/kWh)
Central AC - Early Replacement 0.0% 80.0% 15 $2,895.00 46.4 0.00 $6.400
Central AC - Maintenance and Tune-Up 32.8% 100.0% 4 $100.00 45.8 0.03 $0.602
Room AC - Removal of Second Unit 0.0% 100.0% 5 $75.00 355.3 0.29 $0.048
Ceiling Fan - Installation 32.4% 100.0% 15 $80.00 37.9 0.04 $0.216
Air Source Heat Pump - Maintenance 25.0% 100.0% 4 $100.00 360.1 0.21 $0.077
Insulation - Ducting 13.0% 13.0% 18 $375.00 7.0 0.00 $4.945
Repair and Sealing - Ducting 11.8% 100.0% 18 $500.00 720.5 0.13 $0.064
Thermostat - Clock/Programmable 27.0% 75.0% 15 $114.42 315.1 0.35 $0.037
Doors - Storm and Thermal 17.0% 100.0% 12 $320.00 - - $0.000
Insulation - Infiltration Control 19.0% 100.0% 12 $266.00 283.6 0.17 $0.110
Insulation - Ceiling 30.0% 40.0% 20 $215.00 277.6 0.17 $0.068
Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 433.3 0.06 $0.251
Roofs - High Reflectivity 3.0% 100.0% 15 $1,549.61 39.3 0.00 $4.045
Windows - Reflective Film 5.0% 50.0% 10 $166.67 112.4 0.06 $0.197
Windows - High Efficiency/Energy Star 70.4% 100.0% 25 $2,500.00 1,020.7 0.05 $0.196
Interior Lighting - Occupancy Sensor 5.6% 20.0% 15 $256.00 253.9 0.08 $0.103
Exterior Lighting - Photovoltaic
Installation 10.0% 100.0% 15 $2,975.00 5.5 0.00 $55.926
Exterior Lighting - Photosensor Control 7.1% 100.0% 8 $90.00 2.1 0.00 $6.688
Exterior Lighting - Timeclock
Installation 6.0% 100.0% 8 $72.00 2.1 0.00 $5.350
Water Heater - Faucet Aerators 43.2% 100.0% 25 $24.00 237.5 1.05 $0.008
Water Heater - Pipe Insulation 6.0% 100.0% 13 $15.00 149.6 0.90 $0.011
Water Heater - Low Flow Showerheads 71.6% 100.0% 10 $25.48 282.0 1.11 $0.012
Water Heater - Tank Blanket/Insulation 54.0% 100.0% 10 $15.00 480.9 2.25 $0.004
Water Heater - Thermostat Setback 17.0% 100.0% 5 $40.00 480.9 0.67 $0.019
Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 73.6 0.31 $0.043
Refrigerator - Early Replacement 10.0% 85.0% 7 $109.00 255.9 0.13 $0.074
Refrigerator - Remove Second Unit 17.3% 85.0% 7 $109.00 437.0 0.83 $0.043
Freezer - Early Replacement 10.0% 85.0% 5 $109.00 307.9 0.12 $0.081
Freezer - Remove Second Unit 17.3% 85.0% 5 $109.00 384.9 0.75 $0.065
Behavioral Measures 5.0% 25.0% 1 $12.00 65.5 0.10 $0.183
Insulation - Wall Cavity 80.0% 100.0% 25 $707.94 522.3 0.09 $0.109
Insulation - Wall Sheathing 55.1% 100.0% 20 $210.00 356.6 0.22 $0.052

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 967 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-65
Table B-26 Energy Efficiency Non-Equipment Data, Electric—Multi Family, New Vintage, Idaho
Measure Base
Saturation Applicability Lifetime
(Years)
Cost
($/HH)
Savings
(kWh)
BC
Ratio
Levelized
Cost
($/kWh)
Central AC - Maintenance and Tune-Up 32.8% 100.0% 4 $100.00 52.7 0.03 $0.524
Ceiling Fan - Installation 17.6% 100.0% 15 $80.00 59.7 0.07 $0.138
Air Source Heat Pump - Maintenance 25.0% 100.0% 4 $100.00 414.1 0.27 $0.067
Insulation - Ducting 13.0% 13.0% 18 $200.00 7.3 0.00 $2.531
Thermostat - Clock/Programmable 77.0% 80.0% 15 $114.42 364.1 0.36 $0.032
Doors - Storm and Thermal 19.0% 100.0% 12 $180.00 - - $0.000
Insulation - Ceiling 30.7% 50.0% 20 $152.00 430.5 0.37 $0.031
Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 160.5 0.02 $0.677
Roofs - High Reflectivity 0.0% 100.0% 15 $516.54 35.4 0.01 $1.498
Windows - Reflective Film 2.0% 50.0% 10 $166.67 129.5 0.07 $0.171
Windows - High Efficiency/Energy Star 89.2% 100.0% 25 $2,200.00 2,298.8 0.14 $0.077
Interior Lighting - Occupancy Sensor 5.6% 10.0% 15 $256.00 281.1 0.11 $0.093
Exterior Lighting - Photovoltaic
Installation 10.0% 100.0% 15 $2,975.00 6.3 0.00 $48.646
Exterior Lighting - Photosensor Control 0.7% 100.0% 8 $90.00 2.3 0.00 $6.080
Exterior Lighting - Timeclock
Installation 11.0% 100.0% 8 $72.00 2.3 0.01 $4.864
Water Heater - Faucet Aerators 11.0% 100.0% 25 $24.00 217.0 1.04 $0.009
Water Heater - Pipe Insulation 0.0% 100.0% 13 $15.00 136.6 1.11 $0.012
Water Heater - Low Flow Showerheads 66.2% 100.0% 10 $25.48 282.0 1.42 $0.012
Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $15.00 439.3 2.67 $0.005
Water Heater - Thermostat Setback 5.0% 100.0% 5 $40.00 439.3 0.76 $0.021
Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 79.5 0.35 $0.039
Behavioral Measures 5.0% 75.0% 1 $12.00 75.1 0.13 $0.160
Insulation - Wall Cavity 91.1% 100.0% 25 $62.50 478.4 1.03 $0.010
Insulation - Wall Sheathing 55.1% 100.0% 20 $210.00 410.2 0.26 $0.045
Water Heater - Drainwater Heat
Reocvery 1.0% 100.0% 25 $899.00 724.2 0.09 $0.100

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 968 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-66 www.enernoc.com
Table B-27 Energy Efficiency Non-Equipment Data, Electric—Mobile Home, Existing
Vintage, Washington
Measure Base
Saturation Applicability Lifetime
(Years)
Cost
($/HH)
Savings
(kWh)
BC
Ratio
Levelized
Cost
($/kWh)
Central AC - Early Replacement 0.0% 80.0% 15 $2,895.00 55.3 0.00 $5.373
Central AC - Maintenance and Tune-Up 58.9% 100.0% 4 $100.00 54.5 0.03 $0.506
Room AC - Removal of Second Unit 0.0% 100.0% 5 $75.00 305.2 0.25 $0.056
Ceiling Fan - Installation 60.0% 100.0% 15 $80.00 41.2 0.05 $0.199
Whole-House Fan - Installation 5.2% 25.0% 18 $150.00 66.1 0.04 $0.211
Air Source Heat Pump - Maintenance 25.0% 100.0% 4 $125.00 496.0 0.22 $0.070
Insulation - Ducting 15.0% 65.0% 18 $375.00 320.3 0.08 $0.109
Repair and Sealing - Ducting 12.3% 100.0% 18 $398.09 2,477.4 0.59 $0.015
Thermostat - Clock/Programmable 51.0% 75.0% 15 $114.42 513.2 0.94 $0.023
Doors - Storm and Thermal 38.0% 100.0% 12 $320.00 79.1 0.04 $0.476
Insulation - Infiltration Control 46.0% 100.0% 25 $208.70 364.9 0.42 $0.046
Insulation - Ceiling 46.2% 85.0% 25 $276.18 355.8 0.18 $0.062
Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 387.5 0.07 $0.280
Roofs - High Reflectivity 5.0% 100.0% 15 $1,549.61 31.3 0.00 $5.080
Windows - Reflective Film 5.0% 50.0% 10 $166.67 139.9 0.07 $0.159
Windows - High Efficiency/Energy Star 52.4% 100.0% 25 $3,171.89 4,053.4 0.16 $0.063
Interior Lighting - Occupancy Sensor 66.6% 80.0% 15 $750.00 346.9 0.04 $0.222
Exterior Lighting - Photovoltaic
Installation 10.0% 100.0% 15 $2,975.00 41.9 0.00 $7.281
Exterior Lighting - Photosensor Control 23.4% 100.0% 8 $90.00 28.3 0.02 $0.497
Exterior Lighting - Timeclock Installation 10.0% 100.0% 8 $72.00 28.3 0.03 $0.398
Water Heater - Faucet Aerators 78.9% 100.0% 25 $24.00 179.3 1.02 $0.011
Water Heater - Pipe Insulation 17.0% 100.0% 13 $15.00 157.9 1.14 $0.011
Water Heater - Low Flow Showerheads 92.1% 100.0% 10 $25.48 816.8 2.74 $0.004
Water Heater - Tank Blanket/Insulation 54.0% 100.0% 10 $15.00 507.7 2.43 $0.004
Water Heater - Thermostat Setback 17.0% 100.0% 5 $40.00 507.7 0.72 $0.018
Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 91.0 0.37 $0.034
Refrigerator - Early Replacement 10.0% 85.0% 7 $109.00 249.5 0.12 $0.076
Refrigerator - Remove Second Unit 17.3% 85.0% 7 $109.00 437.0 0.83 $0.043
Freezer - Early Replacement 10.0% 85.0% 5 $109.00 300.2 0.12 $0.083
Freezer - Remove Second Unit 17.3% 85.0% 5 $109.00 384.9 0.75 $0.065
Behavioral Measures 20.0% 50.0% 1 $12.00 84.5 0.14 $0.142
Pool - Pump Timer 50.0% 100.0% 15 $160.00 145.7 0.09 $0.113
Insulation - Wall Cavity 81.8% 100.0% 25 $707.94 1,004.5 0.17 $0.057
Insulation - Wall Sheathing 64.4% 100.0% 20 $300.00 187.2 0.11 $0.141

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 969 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-67
Table B-28 Energy Efficiency Non-Equipment Data, Electric—Mobile Home, New
Vintage, Washington
Measure Base
Saturation Applicability Lifetime
(Years)
Cost
($/HH)
Savings
(kWh)
BC
Ratio
Levelized
Cost
($/kWh)
Central AC - Maintenance and Tune-Up 58.9% 100.0% 4 $100.00 58.6 0.03 $0.471
Ceiling Fan - Installation 57.0% 100.0% 15 $80.00 60.2 0.07 $0.136
Whole-House Fan - Installation 4.0% 25.0% 18 $150.00 82.8 0.05 $0.168
Air Source Heat Pump - Maintenance 25.0% 100.0% 4 $125.00 533.2 0.26 $0.065
Insulation - Ducting 55.0% 65.0% 18 $200.00 344.0 0.17 $0.054
Thermostat - Clock/Programmable 57.0% 75.0% 15 $114.42 552.4 0.77 $0.021
Doors - Storm and Thermal 13.0% 100.0% 12 $180.00 126.6 0.11 $0.167
Insulation - Ceiling 46.2% 85.0% 20 $176.00 341.1 0.32 $0.046
Insulation - Radiant Barrier 25.0% 100.0% 12 $922.68 115.6 0.02 $0.939
Roofs - High Reflectivity 5.0% 100.0% 15 $516.54 44.8 0.01 $1.183
Windows - Reflective Film 2.0% 50.0% 10 $166.67 116.7 0.06 $0.190
Windows - High Efficiency/Energy Star 95.5% 100.0% 25 $2,200.00 1,916.5 0.15 $0.092
Interior Lighting - Occupancy Sensor 66.6% 80.0% 15 $500.00 366.0 0.08 $0.140
Exterior Lighting - Photovoltaic
Installation 10.0% 100.0% 15 $2,975.00 44.8 0.00 $6.818
Exterior Lighting - Photosensor Control 13.2% 100.0% 8 $90.00 29.8 0.04 $0.473
Exterior Lighting - Timeclock
Installation 16.0% 100.0% 8 $72.00 29.8 0.05 $0.379
Water Heater - Faucet Aerators 56.6% 100.0% 25 $24.00 171.3 1.01 $0.011
Water Heater - Pipe Insulation 8.0% 100.0% 13 $15.00 151.1 1.43 $0.011
Water Heater - Low Flow Showerheads 92.1% 100.0% 10 $25.48 781.8 3.37 $0.004
Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $15.00 485.8 2.95 $0.004
Water Heater - Thermostat Setback 5.0% 100.0% 5 $40.00 485.8 0.84 $0.019
Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 94.1 0.40 $0.033
Behavioral Measures 20.0% 75.0% 1 $12.00 90.5 0.15 $0.133
Pool - Pump Timer 35.0% 100.0% 15 $160.00 148.8 0.10 $0.110
Insulation - Wall Cavity 64.5% 100.0% 25 $197.06 356.6 0.31 $0.044
Insulation - Wall Sheathing 64.4% 100.0% 20 $300.00 200.7 0.11 $0.132
Water Heater - Drainwater Heat
Reocvery 1.0% 100.0% 25 $899.00 800.7 0.11 $0.090

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 970 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-68 www.enernoc.com
Table B-29 Energy Efficiency Non-Equipment Data, Electric—Mobile Home, Existing Vintage,
Idaho
Measure Base
Saturation Applicability Lifetime
(Years)
Cost
($/HH)
Savings
(kWh)
BC
Ratio
Levelized
Cost
($/kWh)
Central AC - Early Replacement 0.0% 80.0% 15 $2,895.00 55.3 0.00 $5.373
Central AC - Maintenance and Tune-Up 58.9% 100.0% 4 $100.00 54.5 0.03 $0.506
Room AC - Removal of Second Unit 0.0% 100.0% 5 $75.00 305.2 0.25 $0.056
Ceiling Fan - Installation 60.0% 100.0% 15 $80.00 41.2 0.05 $0.199
Whole-House Fan - Installation 5.2% 25.0% 18 $150.00 66.1 0.04 $0.211
Air Source Heat Pump - Maintenance 25.0% 100.0% 4 $125.00 496.0 0.22 $0.070
Insulation - Ducting 15.0% 65.0% 18 $375.00 320.3 0.08 $0.109
Repair and Sealing - Ducting 12.3% 100.0% 18 $398.09 2,477.4 0.59 $0.015
Thermostat - Clock/Programmable 51.0% 75.0% 15 $114.42 513.2 0.94 $0.023
Doors - Storm and Thermal 38.0% 100.0% 12 $320.00 79.1 0.04 $0.476
Insulation - Infiltration Control 46.0% 100.0% 25 $208.70 364.9 0.42 $0.046
Insulation - Ceiling 46.2% 85.0% 25 $276.18 355.8 0.18 $0.062
Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 387.5 0.07 $0.280
Roofs - High Reflectivity 5.0% 100.0% 15 $1,549.61 31.3 0.00 $5.080
Windows - Reflective Film 5.0% 50.0% 10 $166.67 139.9 0.07 $0.159
Windows - High Efficiency/Energy Star 52.4% 100.0% 25 $3,171.89 4,053.4 0.16 $0.063
Interior Lighting - Occupancy Sensor 66.6% 80.0% 15 $750.00 346.9 0.04 $0.222
Exterior Lighting - Photovoltaic
Installation 10.0% 100.0% 15 $2,975.00 41.9 0.00 $7.281
Exterior Lighting - Photosensor Control 23.4% 100.0% 8 $90.00 28.3 0.02 $0.497
Exterior Lighting - Timeclock
Installation 10.0% 100.0% 8 $72.00 28.3 0.03 $0.398
Water Heater - Faucet Aerators 78.9% 100.0% 25 $24.00 179.3 1.02 $0.011
Water Heater - Pipe Insulation 17.0% 100.0% 13 $15.00 157.9 1.14 $0.011
Water Heater - Low Flow Showerheads 92.1% 100.0% 10 $25.48 816.8 2.74 $0.004
Water Heater - Tank Blanket/Insulation 54.0% 100.0% 10 $15.00 507.7 2.43 $0.004
Water Heater - Thermostat Setback 17.0% 100.0% 5 $40.00 507.7 0.72 $0.018
Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 91.0 0.37 $0.034
Refrigerator - Early Replacement 10.0% 85.0% 7 $109.00 249.5 0.12 $0.076
Refrigerator - Remove Second Unit 17.3% 85.0% 7 $109.00 437.0 0.83 $0.043
Freezer - Early Replacement 10.0% 85.0% 5 $109.00 300.2 0.12 $0.083
Freezer - Remove Second Unit 17.3% 85.0% 5 $109.00 384.9 0.75 $0.065
Behavioral Measures 20.0% 50.0% 1 $12.00 84.5 0.14 $0.142
Pool - Pump Timer 50.0% 100.0% 15 $160.00 145.7 0.09 $0.113
Insulation - Wall Cavity 81.8% 100.0% 25 $707.94 1,004.5 0.17 $0.057
Insulation - Wall Sheathing 64.4% 100.0% 20 $300.00 187.2 0.11 $0.141

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 971 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-69
Table B-30 Energy Efficiency Non-Equipment Data, Electric—Mobile Home, New Vintage, Idaho
Measure Base
Saturation Applicability Lifetime
(Years)
Cost
($/HH)
Savings
(kWh)
BC
Ratio
Levelized
Cost
($/kWh)
Central AC - Maintenance and Tune-Up 58.9% 100.0% 4 $100.00 58.6 0.03 $0.471
Ceiling Fan - Installation 57.0% 100.0% 15 $80.00 60.2 0.07 $0.136
Whole-House Fan - Installation 4.0% 25.0% 18 $150.00 82.8 0.05 $0.168
Air Source Heat Pump - Maintenance 25.0% 100.0% 4 $125.00 533.2 0.26 $0.065
Insulation - Ducting 55.0% 65.0% 18 $200.00 344.0 0.17 $0.054
Thermostat - Clock/Programmable 57.0% 75.0% 15 $114.42 552.4 0.77 $0.021
Doors - Storm and Thermal 13.0% 100.0% 12 $180.00 126.6 0.11 $0.167
Insulation - Ceiling 46.2% 85.0% 20 $176.00 341.1 0.32 $0.046
Insulation - Radiant Barrier 25.0% 100.0% 12 $922.68 115.6 0.02 $0.939
Roofs - High Reflectivity 5.0% 100.0% 15 $516.54 44.8 0.01 $1.183
Windows - Reflective Film 2.0% 50.0% 10 $166.67 116.7 0.06 $0.190
Windows - High Efficiency/Energy Star 95.5% 100.0% 25 $2,200.00 1,916.5 0.15 $0.092
Interior Lighting - Occupancy Sensor 66.6% 80.0% 15 $500.00 366.0 0.08 $0.140
Exterior Lighting - Photovoltaic
Installation 10.0% 100.0% 15 $2,975.00 44.8 0.00 $6.818
Exterior Lighting - Photosensor Control 13.2% 100.0% 8 $90.00 29.8 0.04 $0.473
Exterior Lighting - Timeclock
Installation 16.0% 100.0% 8 $72.00 29.8 0.05 $0.379
Water Heater - Faucet Aerators 56.6% 100.0% 25 $24.00 171.3 1.01 $0.011
Water Heater - Pipe Insulation 8.0% 100.0% 13 $15.00 151.1 1.43 $0.011
Water Heater - Low Flow Showerheads 92.1% 100.0% 10 $25.48 781.8 3.37 $0.004
Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $15.00 485.8 2.95 $0.004
Water Heater - Thermostat Setback 5.0% 100.0% 5 $40.00 485.8 0.84 $0.019
Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 94.1 0.40 $0.033
Behavioral Measures 20.0% 75.0% 1 $12.00 90.5 0.15 $0.133
Pool - Pump Timer 35.0% 100.0% 15 $160.00 148.8 0.10 $0.110
Insulation - Wall Cavity 64.5% 100.0% 25 $197.06 356.6 0.31 $0.044
Insulation - Wall Sheathing 64.4% 100.0% 20 $300.00 200.7 0.11 $0.132
Water Heater - Drainwater Heat
Reocvery 1.0% 100.0% 25 $899.00 800.7 0.11 $0.090

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 972 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-70 www.enernoc.com
Table B-31 Energy Efficiency Non-Equipment Data, Electric—Low income, Existing
Vintage, Washington
Measure Base
Saturation Applicability Lifetime
(Years)
Cost
($/HH)
Savings
(kWh)
BC
Ratio
Levelized
Cost
($/kWh)
Central AC - Early Replacement 0.0% 80.0% 15 $2,895.00 59.1 0.00 $5.026
Central AC - Maintenance and Tune-Up 24.6% 100.0% 4 $100.00 58.3 0.43 $0.473
Room AC - Removal of Second Unit 0.0% 100.0% 5 $75.00 289.2 0.24 $0.059
Attic Fan - Installation 2.9% 50.0% 18 $115.80 2.4 0.00 $4.502
Attic Fan - Photovoltaic - Installation 2.0% 25.0% 19 $350.00 2.4 0.00 $13.244
Ceiling Fan - Installation 40.8% 100.0% 15 $80.00 42.0 0.05 $0.196
Whole-House Fan - Installation 5.3% 25.0% 18 $150.00 67.3 0.04 $0.207
Air Source Heat Pump - Maintenance 25.0% 100.0% 4 $125.00 480.2 0.62 $0.072
Insulation - Ducting 13.0% 25.0% 18 $395.00 279.5 0.37 $0.131
Repair and Sealing - Ducting 11.8% 100.0% 18 $500.00 837.0 0.46 $0.056
Thermostat - Clock/Programmable 35.9% 75.0% 15 $114.42 450.0 1.19 $0.026
Doors - Storm and Thermal 17.0% 100.0% 12 $320.00 68.7 0.04 $0.548
Insulation - Infiltration Control 19.0% 100.0% 12 $266.00 522.9 0.64 $0.060
Insulation - Ceiling 39.3% 55.0% 20 $215.00 170.6 0.45 $0.111
Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 336.6 0.36 $0.323
Roofs - High Reflectivity 3.0% 100.0% 15 $1,549.61 31.9 0.00 $4.987
Windows - Reflective Film 5.0% 50.0% 10 $166.67 142.5 0.07 $0.156
Windows - High Efficiency/Energy Star 71.3% 100.0% 25 $2,500.00 1,226.3 0.40 $0.163
Interior Lighting - Occupancy Sensor 8.2% 20.0% 15 $256.00 254.7 0.09 $0.103
Exterior Lighting - Photovoltaic
Installation 10.0% 100.0% 15 $2,975.00 20.4 0.00 $14.935
Exterior Lighting - Photosensor Control 8.4% 100.0% 8 $90.00 13.8 0.01 $1.020
Exterior Lighting - Timeclock
Installation 6.0% 100.0% 8 $72.00 13.8 0.02 $0.816
Water Heater - Faucet Aerators 45.5% 100.0% 25 $24.00 170.6 1.00 $0.011
Water Heater - Pipe Insulation 6.0% 100.0% 13 $15.00 150.2 1.22 $0.011
Water Heater - Low Flow Showerheads 73.8% 100.0% 10 $25.48 777.0 2.77 $0.004
Water Heater - Tank Blanket/Insulation 54.0% 100.0% 10 $15.00 482.9 2.29 $0.004
Water Heater - Thermostat Setback 17.0% 100.0% 5 $40.00 482.9 0.68 $0.019
Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 64.3 0.27 $0.049
Refrigerator - Early Replacement 10.0% 85.0% 7 $109.00 224.7 0.11 $0.084
Refrigerator - Remove Second Unit 17.3% 85.0% 7 $109.00 437.0 0.83 $0.043
Freezer - Early Replacement 10.0% 85.0% 5 $109.00 270.4 0.10 $0.092
Freezer - Remove Second Unit 17.3% 85.0% 5 $109.00 384.9 0.75 $0.065
Behavioral Measures 5.0% 25.0% 1 $12.00 71.9 0.11 $0.167
Pool - Pump Timer 50.0% 100.0% 15 $160.00 151.5 0.10 $0.108
Insulation - Foundation 13.0% 40.0% 20 $358.00 361.5 0.63 $0.087
Insulation - Wall Cavity 44.2% 100.0% 25 $1,415.87 870.1 0.38 $0.130
Insulation - Wall Sheathing 58.8% 100.0% 20 $210.00 162.6 0.44 $0.114

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 973 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-71
Table B-32 Energy Efficiency Non-Equipment Data, Electric—Low income, New
Vintage, Washington
Measure Base
Saturation Applicability Lifetime
(Years)
Cost
($/HH)
Savings
(kWh)
BC
Ratio
Levelized
Cost
($/kWh)
Central AC - Maintenance and Tune-Up 24.6% 100.0% 4 $100.00 62.7 0.44 $0.440
Attic Fan - Installation 15.0% 50.0% 18 $96.50 3.3 0.00 $2.739
Attic Fan - Photovoltaic - Installation 5.0% 25.0% 19 $200.00 3.3 0.00 $5.524
Ceiling Fan - Installation 33.0% 100.0% 15 $80.00 65.4 0.08 $0.126
Whole-House Fan - Installation 4.0% 25.0% 18 $150.00 89.9 0.06 $0.155
Air Source Heat Pump - Maintenance 37.8% 100.0% 4 $125.00 516.2 0.65 $0.067
Insulation - Ducting 25.0% 25.0% 18 $210.00 303.0 0.44 $0.064
Thermostat - Clock/Programmable 45.3% 75.0% 15 $114.42 490.0 1.05 $0.024
Doors - Storm and Thermal 19.0% 100.0% 12 $180.00 111.5 0.10 $0.190
Insulation - Ceiling 39.0% 50.0% 20 $152.00 300.6 0.67 $0.045
Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 103.0 0.32 $1.054
Roofs - High Reflectivity 0.0% 100.0% 15 $516.54 48.7 0.01 $1.089
Windows - Reflective Film 2.0% 50.0% 10 $166.67 126.8 0.07 $0.175
Windows - High Efficiency/Energy Star 80.2% 100.0% 25 $2,200.00 1,681.0 0.44 $0.105
Interior Lighting - Occupancy Sensor 8.2% 10.0% 15 $256.00 268.5 0.12 $0.098
Exterior Lighting - Photovoltaic
Installation 10.0% 100.0% 15 $2,975.00 21.8 0.00 $13.986
Exterior Lighting - Photosensor Control 0.0% 100.0% 8 $90.00 14.5 0.02 $0.971
Exterior Lighting - Timeclock
Installation 11.0% 100.0% 8 $72.00 14.5 0.02 $0.777
Water Heater - Faucet Aerators 10.6% 100.0% 25 $24.00 162.9 1.04 $0.012
Water Heater - Pipe Insulation 0.0% 100.0% 13 $15.00 143.7 1.56 $0.012
Water Heater - Low Flow Showerheads 66.2% 100.0% 10 $25.48 743.6 3.45 $0.005
Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $15.00 462.1 2.80 $0.004
Water Heater - Thermostat Setback 5.0% 100.0% 5 $40.00 462.1 0.80 $0.020
Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 66.9 0.29 $0.047
Behavioral Measures 5.0% 75.0% 1 $12.00 77.7 0.13 $0.154
Pool - Pump Timer 35.0% 100.0% 15 $160.00 154.7 0.11 $0.106
Insulation - Foundation 27.4% 40.0% 20 $358.00 395.1 0.65 $0.080
Insulation - Wall Cavity 45.6% 100.0% 25 $62.50 311.7 1.25 $0.016
Insulation - Wall Sheathing 58.8% 100.0% 20 $210.00 175.7 0.46 $0.105
Water Heater - Drainwater Heat
Reocvery 1.0% 100.0% 25 $899.00 761.6 0.12 $0.095

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 974 of 1125
Residential Energy Efficiency Equipment and Measure Data
B-72 www.enernoc.com
Table B-33 Energy Efficiency Non-Equipment Data, Electric—Low income, Existing Vintage,
Idaho
Measure Base
Saturation Applicability Lifetime
(Years)
Cost
($/HH)
Savings
(kWh)
BC
Ratio
Levelized
Cost
($/kWh)
Central AC - Early Replacement 0.0% 80.0% 15 $2,895.00 59.1 0.00 $5.026
Central AC - Maintenance and Tune-Up 24.6% 100.0% 4 $100.00 58.3 0.43 $0.473
Room AC - Removal of Second Unit 0.0% 100.0% 5 $75.00 289.2 0.24 $0.059
Attic Fan - Installation 2.9% 50.0% 18 $115.80 2.4 0.00 $4.502
Attic Fan - Photovoltaic - Installation 2.0% 25.0% 19 $350.00 2.4 0.00 $13.244
Ceiling Fan - Installation 40.8% 100.0% 15 $80.00 42.0 0.05 $0.196
Whole-House Fan - Installation 5.3% 25.0% 18 $150.00 67.3 0.04 $0.207
Air Source Heat Pump - Maintenance 25.0% 100.0% 4 $125.00 480.2 0.62 $0.072
Insulation - Ducting 13.0% 25.0% 18 $395.00 279.5 0.37 $0.131
Repair and Sealing - Ducting 11.8% 100.0% 18 $500.00 837.0 0.46 $0.056
Thermostat - Clock/Programmable 35.9% 75.0% 15 $114.42 450.0 1.19 $0.026
Doors - Storm and Thermal 17.0% 100.0% 12 $320.00 68.7 0.04 $0.548
Insulation - Infiltration Control 19.0% 100.0% 12 $266.00 522.9 0.64 $0.060
Insulation - Ceiling 39.3% 55.0% 20 $215.00 170.6 0.45 $0.111
Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 336.6 0.36 $0.323
Roofs - High Reflectivity 3.0% 100.0% 15 $1,549.61 31.9 0.00 $4.987
Windows - Reflective Film 5.0% 50.0% 10 $166.67 142.5 0.07 $0.156
Windows - High Efficiency/Energy Star 71.3% 100.0% 25 $2,500.00 1,226.3 0.40 $0.163
Interior Lighting - Occupancy Sensor 8.2% 20.0% 15 $256.00 254.7 0.09 $0.103
Exterior Lighting - Photovoltaic
Installation 10.0% 100.0% 15 $2,975.00 20.4 0.00 $14.935
Exterior Lighting - Photosensor Control 8.4% 100.0% 8 $90.00 13.8 0.01 $1.020
Exterior Lighting - Timeclock
Installation 6.0% 100.0% 8 $72.00 13.8 0.02 $0.816
Water Heater - Faucet Aerators 45.5% 100.0% 25 $24.00 170.6 1.00 $0.011
Water Heater - Pipe Insulation 6.0% 100.0% 13 $15.00 150.2 1.22 $0.011
Water Heater - Low Flow Showerheads 73.8% 100.0% 10 $25.48 777.0 2.77 $0.004
Water Heater - Tank Blanket/Insulation 54.0% 100.0% 10 $15.00 482.9 2.29 $0.004
Water Heater - Thermostat Setback 17.0% 100.0% 5 $40.00 482.9 0.68 $0.019
Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 64.3 0.27 $0.049
Refrigerator - Early Replacement 10.0% 85.0% 7 $109.00 224.7 0.11 $0.084
Refrigerator - Remove Second Unit 17.3% 85.0% 7 $109.00 437.0 0.83 $0.043

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 975 of 1125
Residential Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting B-73
Table B-34 Energy Efficiency Non-Equipment Data, Electric—Low income, New Vintage, Idaho
Measure Base
Saturation Applicability Lifetime
(Years)
Cost
($/HH)
Savings
(kWh)
BC
Ratio
Levelized
Cost
($/kWh)
Central AC - Maintenance and Tune-Up 24.6% 100.0% 4 $100.00 62.7 0.44 $0.440
Attic Fan - Installation 15.0% 50.0% 18 $96.50 3.3 0.00 $2.739
Attic Fan - Photovoltaic - Installation 5.0% 25.0% 19 $200.00 3.3 0.00 $5.524
Ceiling Fan - Installation 33.0% 100.0% 15 $80.00 65.4 0.08 $0.126
Whole-House Fan - Installation 4.0% 25.0% 18 $150.00 89.9 0.06 $0.155
Air Source Heat Pump - Maintenance 37.8% 100.0% 4 $125.00 516.2 0.65 $0.067
Insulation - Ducting 25.0% 25.0% 18 $210.00 303.0 0.44 $0.064
Thermostat - Clock/Programmable 45.3% 75.0% 15 $114.42 490.0 1.05 $0.024
Doors - Storm and Thermal 19.0% 100.0% 12 $180.00 111.5 0.10 $0.190
Insulation - Ceiling 39.0% 50.0% 20 $152.00 300.6 0.67 $0.045
Insulation - Radiant Barrier 5.0% 100.0% 12 $922.68 103.0 0.32 $1.054
Roofs - High Reflectivity 0.0% 100.0% 15 $516.54 48.7 0.01 $1.089
Windows - Reflective Film 2.0% 50.0% 10 $166.67 126.8 0.07 $0.175
Windows - High Efficiency/Energy Star 80.2% 100.0% 25 $2,200.00 1,681.0 0.44 $0.105
Interior Lighting - Occupancy Sensor 8.2% 10.0% 15 $256.00 268.5 0.12 $0.098
Exterior Lighting - Photovoltaic
Installation 10.0% 100.0% 15 $2,975.00 21.8 0.00 $13.986
Exterior Lighting - Photosensor Control 0.0% 100.0% 8 $90.00 14.5 0.02 $0.971
Exterior Lighting - Timeclock
Installation 11.0% 100.0% 8 $72.00 14.5 0.02 $0.777
Water Heater - Faucet Aerators 10.6% 100.0% 25 $24.00 162.9 1.04 $0.012
Water Heater - Pipe Insulation 0.0% 100.0% 13 $15.00 143.7 1.56 $0.012
Water Heater - Low Flow Showerheads 66.2% 100.0% 10 $25.48 743.6 3.45 $0.005
Water Heater - Tank Blanket/Insulation 0.0% 0.0% 10 $15.00 462.1 2.80 $0.004
Water Heater - Thermostat Setback 5.0% 100.0% 5 $40.00 462.1 0.80 $0.020
Electronics - Reduce Standby Wattage 5.0% 100.0% 8 $20.00 66.9 0.29 $0.047
Behavioral Measures 5.0% 75.0% 1 $12.00 77.7 0.13 $0.154
Pool - Pump Timer 35.0% 100.0% 15 $160.00 154.7 0.11 $0.106
Insulation - Foundation 27.4% 40.0% 20 $358.00 395.1 0.65 $0.080
Insulation - Wall Cavity 45.6% 100.0% 25 $62.50 311.7 1.25 $0.016
Insulation - Wall Sheathing 58.8% 100.0% 20 $210.00 175.7 0.46 $0.105
Water Heater - Drainwater Heat
Reocvery 1.0% 100.0% 25 $899.00 761.6 0.12 $0.095

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 976 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 977 of 1125

EnerNOC Utility Solutions Consulting C-1
APPENDIX C
C&I ENERGY EFFICIENCY EQUIPMENT AND MEASURE DATA
This appendix presents detailed information for all commercial energy-efficiency measures
(equipment and non-equipment measures per the LoadMAP taxonomy) that were evaluated in
this study.
Table C-1 and Table C-2 provide brief narrative descriptions for all equipment and non-
equipment measures that were assessed for potential.
Table C-3 through Table C-18 list the detailed unit-level data (including economic screen results)
for commercial equipment measures in existing and new buildings. The column headings and
units are the same as described for the corresponding residential sector tables above.
Table C-19 through Table C-34 list the detailed unit-level data (including economic screen
results) for commercial non-equipment measures in existing and new construction. The column
headings and units are the same as described for the corresponding residential sector tables
above.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 978 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-2 www.enernoc.com
Table C-1 C&I Energy Efficiency Equipment Measure Descriptions
End Use Technology Measure Description
Cooling Air-Cooled Chiller
A central chiller plant creates chilled water for distribution throughout the
facility. Because of the wide variety of system types and sizes, savings and cost
values for efficiency improvements represent an average over screw,
reciprocating, and centrifugal technologies. Under this simplified approach,
each central system is characterized by an aggregate efficiency value (inclusive
of chiller, pumps, and motors), in kW/ton with a further efficiency upgrade
through the application of variable refrigerant flow technology.
Cooling Water-Cooled Chiller
A central chiller plant creates chilled water for distribution throughout the
facility. Water source chillers include heat rejection via a condenser loop and
cooling tower. Because of the wide variety of system types and sizes, savings
and cost values for efficiency improvements represent an average over screw,
reciprocating, and centrifugal technologies. Under this simplified approach,
each central system is characterized by an aggregate efficiency value (inclusive
of chiller, pumps, motors, and condenser loop equipment), in kW/ton with a
further efficiency upgrade through the application of variable refrigerant flow
technology.
Cooling Roof Top AC
Packaged cooling systems, such as rooftop units (RTUs), are simple to install
and maintain, and are commonly used in small and medium-sized commercial
buildings. Applications range from a single supply system with air intake filters,
supply fan, and cooling coil, or can become more complex with the addition of
a return air duct, return air fan, and various controls to optimize performance.
For packaged RTUs, varying Energy Efficiency Ratios (EER) are modeled, as well
as a ductless mini-split system.
Cooling /
Space Heating
Air-Source Heat
Pump
For heat pumps, units with increasing EER and COP levels are evaluated, as well
as a ductless mini-split system.
Cooling /
Space Heating
Geothermal Heat
Pump For heat pumps, units with increasing EER and COP levels are evaluated.
Space Heating Electric Furnace
Resistive heating elements are used to convert electricity directly to heat. The
heat is then delivered by a supply fan and duct system to the regions that
require heating.
Space Heating Electric Resistance
Resistive heating elements are used to convert electricity directly to heat.
Conductive fins surrounding the element or another mechanism is used to
deliver the heat directly to the surrounding room or area. These are typically
either baseboard or wall-mounted units.
Ventilation Ventilation
A variable air volume ventilation system modulates the air flow rate as needed
based on the interior conditions of the building to reduce fan load, improve
dehumidification, and reduce energy usage.
Water
Heating Water Heater
Efficient electric water heaters are characterized by a high recovery or thermal
efficiency (percentage of delivered electric energy which is transferred to the
water) and low standby losses (the ratio of heat lost per hour to the content of
the stored water). Included in the savings associated with high-efficiency
electric water heaters are timers that allow temperature setpoints to change
with hot water demand patterns. For example, the heating element could be
shut off throughout the night, increasing the overall energy factor of the unit.
In addition, tank and pipe insulation reduces standby losses and therefore
reduces the demands on the water heater. This analysis considers conventional
electric water heaters and heat pump water heaters.
Interior
Lighting Screw-in This measure evaluates higher-efficiency alternatives for screw-in interior
lamps including halogen, CFL, and LED.
Interior
Lighting High-Bay Fixtures
With the exception of screw-in lighting, commercial and industrial lighting
efficiency changes typically require more than the simple purchase and
installation of an alternative lamp Restrictions regarding ballasts, fixtures, and
circuitry limit the potential for direct substitution of one lamp type for another.
Also, during the buildout for a leased office space, management could decide
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 979 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-3
End Use Technology Measure Description
to replace all lamps, ballasts, and fixtures with different configurations. This
type of decision-making is modeled on a stock turnover basis because of the
time between opportunities for upgrades. For High-Bay fixtures, alternatives
include mercury vapor, metal halides, T5 fluorescent high output, and high-
pressure sodium.
Interior
Lighting Linear Fluorescent
With the exception of screw-in lighting, commercial and industrial lighting
efficiency changes typically require more than the simple purchase and
installation of an alternative lamp. Restrictions regarding ballasts, fixtures, and
circuitry limit the potential for direct substitution of one lamp type for another.
Also, during the buildout for a leased office space, management could decide
to replace all lamps, ballasts, and fixtures with different configurations. This
type of decision-making is modeled on a stock turnover basis because of the
time between opportunities for upgrades. For linear fluorescent fixtures,
alternatives include T12, T8, Super T8, T5, and LED.
Exterior
Lighting Screw-in This measure evaluates higher-efficiency alternatives for screw-in interior
lamps including halogen, CFL, and LED.
Exterior
Lighting HID Alternatives modeled include metal halides, T8 and T5 high output, high
pressure sodium, and LEDs
Exterior
Lighting Linear Fluorescent For linear fluorescent fixtures, alternatives include T12, T8, Super T8, T5, and
LED.
Refrigeration Walk-in Refrigerator
These refrigerators can be designed to perform at higher efficiency through a
combination of compressor equipment upgrades, default temperature settings,
and defrost patterns. Standard refrigeration compressors typically operate at
approximately 65% efficiency. High-efficiency models are available that can
improve compressor efficiency by 15%. Analysis assumes unit with: 140 square
feet, Cooling capacity of 26,230 BTU/hr.
Refrigeration Reach-in
Refrigerator
A significant amount of energy in the commercial sector can be attributed to
"reach-in" units. These stand-alone appliances can range from a residential-
style refrigerator/freezer unit in an office kitchen or the breakroom of a retail
store, to the larger reach-in units in foodservice applications. As in the case of
residential units, these refrigerators can be designed to perform at higher
efficiency through a combination of compressor equipment upgrades, default
temperature settings, and defrost patterns. Analysis assumes unit with: 48
cubic feet, Cooling capacity of 3000 BTU/hr.
Refrigeration Glass Door Display,
Open Display Case
These refrigerators can be designed to perform at higher efficiency through a
combination of compressor equipment upgrades, default temperature settings,
and defrost patterns. Standard refrigeration compressors typically operate at
approximately 65% efficiency. High-efficiency models are available that can
improve compressor efficiency by 15%. Analysis assumes unit with: Cooling
capacity of 20,000 BTU/hr
Refrigeration Icemaker By optimizing the timing of ice production and the type of output to the
specific application, icemakers are assumed to deliver electricity savings.
Refrigeration Vending Machine High-efficiency vending machines incorporate more efficient compressors and
lighting.
Food
Preparation
Ovens,Fryers, Hot
Food Containers,
Dishwashers
This set of measures includes high-efficiency fryers, ovens, dishwashers, and
hot food containers. Less common equipment, such as broilers and steamers,
and assumed to be modeled with the other more common equipment types.
Office
Equipment
Desktop Computer,
Laptop, Monitors
ENERGY STAR labeled computers automatically power down to 15 watts or less
when not in use and may actually last longer than conventional products
because they spend a large portion of time in a low-power sleep mode.
ENERGY STAR labeled computers also generate less heat than conventional
models.
Office
Equipment Server
In addition to the "sleep" mode a reductions, servers have additional energy-
saving opportunities through "virtualization" and other architecture solutions
that involve optimal matching of computation tasks to hardware requirements
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 980 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-4 www.enernoc.com
End Use Technology Measure Description
Office
Equipment Printer/Copier/Fax
ENERGY STAR labeled office equipment saves energy by powering down and
"going to sleep" when not in use. ENERGY STAR labeled copiers are equipped
with a feature that allows them to automatically turn off after a period of
inactivity.
Office
Equipment POS Terminal
Point-of-sale terminals in retail and supermarket facilities are always on.
Efficient models incorporate a high-efficiency power supply to reduce energy
use.
Miscellaneous Non-HVAC Motors
Includes motors for a variety of non-HVAC uses including vertical
transportation. Premium efficiency motors can provide savings of 0.5% to 3%
over standard motors. The savings results from the fact that energy efficient
motors run cooler than their standard counterparts, resulting in an increase in
the life of the motor insulation and bearing. In general, an efficient motor is a
more reliable motor because there are fewer winding failures, longer periods
between needed maintenance, and fewer forced outages. For example, using
copper instead of aluminum in the windings, and increasing conductor cross-
sectional area, lowers a motor’s I2R losses.
Miscellaneous Miscellaneous Improvement of miscellaneous electricity uses

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 981 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-5
Table C-2 Commercial and Industrial Energy Efficiency Non-Equipment Measure Descriptions
End Use Measure Description
HVAC (All) Insulation - Ceiling
Thermal insulation is material or combinations of materials that are used to
inhibit the flow of heat energy by conductive, convective, and radiative transfer
modes. Thus, thermal insulation can conserve energy by reducing the heat loss
or gain of a building. The type of building construction defines insulating
possibilities. Typical insulating materials include: loose-fill (blown) cellulose;
loose-fill (blown) fiberglass; and rigid polystyrene.
HVAC (All) Insulation - Ducting
Air distribution ducts can be insulated to reduce heating or cooling losses. Best
results can be achieved by covering the entire surface area with insulation.
Insulation material inhibits the transfer of heat through the air-supply duct.
Several types of ducts and duct insulation are available, including flexible duct,
pre-insulated duct, duct board, duct wrap, tacked, or glued rigid insulation, and
waterproof hard shell materials for exterior ducts.
HVAC (All) Insulation - Radiant
Barrier
Radiant barriers are materials installed to reduce the heat gain in buildings.
Radiant barriers are made from materials that are highly reflective and have
low emissivity like aluminum. The closer the emissivity is to 0 the better they
will perform. Radiant barriers can be placed above the insulation or on the
roof rafters.
HVAC (All) Insulation - Wall
Cavity
Thermal insulation is material or combinations of materials that are used to
inhibit the flow of heat energy by conductive, convective, and radiative transfer
modes. Thus, thermal insulation can conserve energy by reducing the heat loss
or gain of a building. The type of building construction defines insulating
possibilities. Typical insulating materials include: loose-fill (blown) cellulose;
loose-fill (blown) fiberglass; and rigid polystyrene.
HVAC (All) Ducting - Repair and
Sealing
Leakage in unsealed ducts varies considerably because of the differences in
fabricating machinery used, the methods for assembly, installation
workmanship, and age of the ductwork. Air leaks from the system to the
outdoors result in a direct loss proportional to the amount of leakage and the
difference in enthalpy between the outdoor air and the conditioned air. To
seal ducts, a wide variety of sealing methods and products exist. Each has a
relatively short shelf life, and no documented research has identified the aging
characteristics of sealant applications.
HVAC (All) Windows - High
Efficiency
High-efficiency windows, such as those labeled under the ENERGY STAR
Program, are designed to reduce a building's energy bill while increasing
comfort for the occupants at the same time. High-efficiency windows have
reducing properties that reduce the amount of heat transfer through the
glazing surface. For example, some windows have a low-E coating, which is a
thin film of metallic oxide coating on the glass surface that allows passage of
short-wave solar energy through glass and prevents long-wave energy from
escaping. Another example is double-pane glass that reduces conductive and
convective heat transfer. There are also double-pane glasses that are gas-filled
(usually argon) to further increase the insulating properties of the window.
HVAC (All) Roof - High
Reflectivity
The color and material of a building structure surface will determine the
amount of solar radiation absorbed by that surface and subsequently
transferred into a building. This is called solar absorptance. By using a living
roof or a roofing material with a light color (and a lower solar absorptance), the
roof will absorb less solar radiation and consequently reduce the cooling load.
Living roofs also reduce stormwater runoff.
HVAC (All) Roofs - Green
A green roof covers a section or the entire building roof with a waterproof
membrane and vegetative material. Like cool roofs, green roofs can reduce
solar absorptance and they can also provide insulation. They also provide non-
energy benefits by absorbing rainwater and thus reducing storm water run-off,
providing wildlife habitat, and reducing so-called urban heat island effects.
Cooling
Chiller - Condenser
Water Temperature
Reset
Resetting the condenser water temperature to the lowest possible setting
allows the cooling tower to generate cooler water whenever possible and
decreases the temperature lift between the condenser and the evaporator.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 982 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-6 www.enernoc.com
End Use Measure Description
This will generally increase chiller part-load efficiency, though it may require
increased tower fan energy use.
Cooling Chiller - Economizer
Economizers allow outside air (when it is cool and dry enough) to be brought
into the building space to meet cooling loads instead of using mechanically
cooled interior air. A dual enthalpy economizer consists of indoor and outdoor
temperature and humidity sensors, dampers, motors, and motor controls.
Economizers are most applicable to temperate climates and savings will be
smaller in extremely hot or humid areas.
Cooling Chiller - VSD on Fans Variable speed drives, which reduce chiller energy use under part load, are
modeled for both air-cooled and water-cooled chillers.
Cooling Chiller - Chilled
Water Reset
Chilled water reset controls save energy by improving chiller performance
through increasing the supply chilled water temperature, which allows
increased suction pressure during low load periods. Raising the chilled water
temperature also reduces chilled water piping losses. However, the primary
savings from the chilled water reset measure results from chiller efficiency
improvement. This is due partly to the smaller temperature difference
between chilled water and ambient air, and partly due to the sensitivity of
chiller performance to suction temperature.
Cooling
Chiller - Chilled
Water Variable-Flow
System
The part-load efficiency of chilled water loops can be improved substantially by
varying the flow speed of the delivered water with the building demand for
cooling.
Cooling
Chiller - High
Efficiency Cooling
Tower Fans
High-efficiency cooling fans utilize efficient components and variable frequency
drives that improve fan performance by adjusting fan speed and rotation as
conditions change.
Cooling RTU - Evaporative
Precooler
Evaporative precooling can improve the performance of air conditioning
systems, most commonly RTUs. These systems typically use indirect
evaporative cooling as a first stage to pre-cool outside air. If the evaporative
system cannot meet the full cooling load, the air steam is further cooled with
conventional refrigerative air conditioning technology.
Cooling RTU - Maintenance
Regular cleaning and maintenance enables a roof top unit to function
effectively and efficiently throughout its years of service. Neglecting necessary
maintenance leads to a steady decline in performance while energy use
increases. Maintenance can increase the efficiency of poorly performing
equipment by as much as 10%.
Cooling /
Space Heating
Heat Pump -
Maintenance
Regular cleaning and maintenance enables a heat pump to function effectively
and efficiently throughout its years of service. Neglecting necessary
maintenance leads to a steady decline in performance while energy use
increases. Maintenance can increase the efficiency of poorly performing
equipment by as much as 10%.
Ventilation
Ventilation -
Demand Control
Ventilation
Also known as CO2 Controlled, this measure uses carbon dioxide (CO2) levels
to indicate the level of occupancy in a space. Sensors monitor CO2 levels so
that air handling controls can adjust the amount of outside air intake.
Ventilation rates are thereby controlled based on occupancy, rather than a
fixed rate, thus saving HVAC energy use.
Ventilation Fans – Energy
Efficient Motors
High-efficiency motors are essentially interchangeable with standard motors,
but differences in construction make them more efficient. Energy-efficient
motors achieve their improved efficiency by reducing the losses that occur in
the conversion of electrical energy to mechanical energy. This analysis
assumes that the efficiency of supply fans is increased by 5% due to installing
energy-efficient motors.
Water
Heating
Water Heater -
Faucet Aerators/Low
Flow Nozzles
A faucet aerator or low flow nozzle spreads the stream from a faucet helping to
reduce water usage. The amount of water passing through the aerator is
measured in gallons per minute (GPM) and the lower the GPM the more water
the aerator conserves.
Water
Heating
Water Heater - High
Efficiency Circulation
A high efficiency circulation pump uses an electronically commutated motor
(ECM) to improve motor efficiency over a larger range of partial loads. In
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 983 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-7
End Use Measure Description
Pump addition, an ECM allows for improved low RPM performance with greater
torque and smaller pump dimensions.
Water
Heating
Water Heater - Pipe
Insulation
Insulating hot water pipes decreases the amount of energy lost during
distribution of hot water throughout the building. Insulating pipes will result in
quicker delivery of hot water and allows lowering the water heating set point.
There are several different types of insulation, the most common being
polyethylene and neoprene.
Water
Heating
Water Heater - Tank
Blanket/Insulation
Insulation levels on hot water heaters can be increased by installing a fiberglass
blanket on the outside of the tank. This increase in insulation reduces standby
losses and thus saves energy. Water heater insulation is available either by the
blanket or by square foot of fiberglass insulation with R-values ranging from 5
to 14.
Water
Heating Thermostat setback Installing a setback thermostat on the water heater can lead to significant
energy savings during periods when there is no one in the building.
Interior
Lighting
Interior Lighting –
Central Lighting
Controls
Daylighting controls use a photosensor to detect ambient light and adjust or
turn off electric lights accordingly.
Interior
Lighting
Photocell controlled
T8 dimming ballasts
Photocells, in concert with dimming ballasts, can detect when adequate
daylighting is available and dim or turn off lights to reduce electricity
consumption. Usually one photocell is used to control a group of fixtures, a
zone, or a circuit.
Interior
Lighting LED Exit Lighting
The lamps inside exit signs represent a significant energy end-use, since they
usually operate 24 hours per day. Many old exit signs use incandescent lamps,
which consume approximately 40 watts per sign. The incandescent lamps can
be replaced with LED lamps that are specially designed for this specific
purpose. In comparison, the LED lamps consume approximately 2-5 watts.
Interior
Lighting
Interior Lighting -
Occupancy Sensors
The installation of occupancy sensors allows lights to be turned off during
periods when a space is unoccupied, virtually eliminating the wasted energy
due to lights being left on. There are several types of occupancy sensors in the
market.
Interior
Lighting
Interior Lighting -
Timeclocks and
Timers
In many cases lighting remains on at night and during weekends. A simple
timer can set a schedule for turning lights off to reduce operating hours.
Interior
Lighting
Interior Screw-in -
Task Lighting
Individual work areas can use task lighting instead of brightly lighting the entire
area. Significant energy savings can be realized by focusing light directly where
it is needed and lowering the general lighting level. An example of task lighting
is the common desk lamp. A 25W desk lamp can be installed in place of a
typical lamp in a fixture.
Interior
Lighting
Interior Lighting –
Hotel Guestroom
Controls
Hotel guestrooms can be fitted with occupancy controls that turn off energy-
using equipment when the guest is not using the room. The occupancy
controls comes in several forms, but this analysis assumes the simplest kind,
which is a simple switch near the room’s entry where the guest can deposit
their room key or card. If the key or card is present, then lights, TV, and air
conditioning can receive power and operate. When the guest leaves and takes
the key, all equipment shuts off.
Interior
Lighting
Interior Lighting -
Skylights
Addition of transparent windows/fixtures in the roof to allow daylight to enter
and reduce the need for powered lighting. Applies to new construction only.
Interior
Lighting
Interior Fluorescent -
Bi-Level Fixture
Bi-level fixtures have the ability to reduce light output to a lower level, given a
control strategy that is based on a timer, occupancy sensor, motion sensor, or
manual switch.
Interior
Lighting
Interior Fluorescent
– High Bay Fixtures
Fluorescent fixtures designed for high-bay applications have several
advantages over similar HID fixtures: lower energy consumption, lower lumen
depreciation rates, better dimming options, faster start-up and restrike, better
color rendition, more pupil lumens, and reduced glare.
Exterior Exterior Lighting - Daylighting controls use a photosensor to detect ambient light and adjust or
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 984 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-8 www.enernoc.com
End Use Measure Description
Lighting Daylighting Controls turn off electric lights accordingly.
Exterior
Lighting
Exterior Lighting -
Photovoltaic
Installation
Solar photovoltaic generation may be used to power exterior lighting and thus
eliminate all or part of the electrical energy use.
Exterior
Lighting
Exterior Lighting –
Cold Cathode
Lighting
Cold cathode lighting does not use an external heat source to provide
thermionic emission of electrons. Cold cathode lighting is typically used for
exterior signage or where temperatures are likely to drop below freezing.
Food
Preparation
Cooking Exhaust
hood with sensor
control
Improved exhaust hoods involve installing variable-speed controls on
commercial kitchen hoods. These controls provide ventilation based on actual
cooking loads. When grills, broilers, stoves, fryers or other kitchen appliances
are not being used, the controls automatically sense the reduced load and
decrease the fan speed accordingly. This results in lower energy consumption
because the system is only running as needed rather than at 100% capacity at
all times.
Refrigeration
Refrigerator - Anti-
Sweat Heater/ Auto
Door Closer
Anti-sweat heaters are used in virtually all low-temperature display cases and
many medium-temperature cases to control humidity and prevent the
condensation of water vapor on the sides and doors and on the products
contained in the cases. Typically, these heaters stay on all the time, even
though they only need to be on about half the time. Anti-sweat heater controls
can come in the form of humidity sensors or time clocks.
Refrigeration Refrigerator - Door
Gasket Replacement
This measure involves replacing aging door gaskets that no longer adequately
seal reach-in refrigerators or glass door display cases.
Refrigeration
Refrigerator -
Floating Head
Pressure
Floating head pressure control allows the pressure in the condenser to "float"
with ambient temperatures. This method reduces refrigeration compression
ratios, improves system efficiency and extends the compressor life. The
greatest savings with a floating head pressure approach occurs when the
ambient temperatures are low, such as in the winter season. Floating head
pressure control is most practical for new installations. However, retrofits
installation can be completed with some existing refrigeration systems.
Installing floating head pressure control increases the capacity of the
compressor when temperatures are low, which may lead to short cycling.
Refrigeration Refrigerator - Strip
Curtain
Strip curtains at the entrances to large walk-in coolers or freezers, such as
those used in supermarkets, reduce air transfer between the refrigerated space
and the surrounding space.
Refrigeration
(All)
Insulation - Bare
suction lines
Suction lines deliver refrigerant fluid from to the inlet or suction side of a
compressor. Insulating these lines prevents ambient air from heating the fluid
in the line, and thus improves efficiency.
Refrigeration
Refrigerator - High
Efficiency Case
Lighting
High-efficiency case lightin, usually with LEDs, reduces waste heat from lighting
that must be removed from refrigeratied display cases.
Refrigeration Refrigerator – Night
Covers
Night covers can be used on open refrigeration cases when a facility is closed
or few customers are in the store.
Refrigeration Vending Machine -
Controller
Cold beverage vending machines usually operate 24 hours a day regardless of
whether the surrounding area is occupied or not. The result is that the vending
machine consumes energy unnecessarily, because it will operate all night to
keep the beverage cold even when there would be no customer until the next
morning. A vending machine controller can reduce energy consumption
without compromising the temperature of the vended product. The controller
uses an infrared sensor to monitor the surrounding area’s occupancy and will
power down the vending machine when the area is unoccupied. It will also
monitor the room’s temperature and will re -power the machine at one to
three hour intervals independent of occupancy to ensure that the product
stays cold.
Office
Equipment
Office Equipment –
Smart Power Strips
These power strips encorporate motion sensing to power down office
equipment when not in use.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 985 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-9
End Use Measure Description
Micellaneous
Laundry – High
Efficiency Clothes
Washer
High efficiency clothes washers use designs that require less water. These
machines use sensors to match the hot water needs to the load, preventing
energy waste. There are two designs: top-loading and front-loading. Further
energy and water savings can be achieved through advanced technologies such
as inverter-drive or combination washer-dryer units.
Micellaneous
Micellaneous –
ENERGY STAR
Washer Cooler
An ENERGY STAR water cooler has more insulation and improved chilling
mechanisms, resulting in about half the energy use of a standard cooler.
Micellaneous Pumps - Variable
Speed Control
The part-load efficiency of drive systems can be improved by varying the speed
of the motor drive. An additional benefit of variable-speed controls is the
ability to start and stop the motor and process gradually, thus extending the
life of the motor and associated machinery.
Machine
Drive
Motors – Variable
Frequency Drive
In addition to energy savings, VFDs increase motor and system life and provide
a greater degree of control over the motor system. Especially for motor
systems handling fluids, VFDs can efficiently respond to changing operating
conditions.
Machine
Drive
Motors – Magnetic
Adjustable Speed
Drives
To allow for adjustable speed operation, this technology uses magnetic
induction to couple a drive to its load. Varying the magnetic slip within the
coupling controls the speed of the output shaft. Magnetic drives perform best
at the upper end of the speed range due to the energy consumed by the slip.
Unlike traditional ASDs, magnetically coupled ASDs create no power distortion
on the electrical system. However, magnetically coupled ASD efficiency is best
when power needs are greatest. VFDs may show greater efficiency when the
average load speed is below 90% of the motor speed, however this occurs
when power demands are reduced.
Machine
Drive
Compressed Air –
System Controls,
Optimization and
Imrovements,
Maintenance
Controls for compressed air systems can shift load from two partially loaded
compressors to one compressor in order to maximize compression efficiency
and may also involve the addition of VFDs. Improvements include installing
high-efficiency motors. Maintenance includes fixing air leaks and replacing air
filters.
Machine
Drive
Fan Systems –
Controls,
Optimization and
Improvements,
Maintenance
Controls for compressed air systems can shift load from two partially loaded
compressors to one compressor in order to maximize compression efficiency
and may also involve the addition of VFDs. Improvements include installing
high-efficiency motors. Maintenance includes fixing air leaks and replacing air
filters.
Machine
Drive
Pumping Systems –
Controls,
Optimization and
Maintenance
Pumping systems optimization includes installing VFDs, correctly resizing the
motors, and installing timers and automated on-off controls. Maintenance
includes repairing diaphragms and fixing piping leaks.
Machine
Drive
Motors -
Synchronous Belts
Synchronous belts offer higher efficiency compared with standard belts due to
reduced slipping, as well as less maintenance and retensioning.
Process
Refrigeration –
System Controls,
Maintenance, and
Optimization
Because refrigeration equipment performance degrades over time and control
settings are frequently overridden, these measures account for savings that
can be achieved through system maintenance and controls optimization.
HVAC (All) Energy Management
System
An energy management system (EMS) allows managers/owners to monitor and
control the major energy-consuming systems within a commercial building. At
the minimum, the EMS can be used to monitor and record energy consumption
of the different end-uses in a building, and can control operation schedules of
the HVAC and lighting systems. The monitoring function helps building
managers/owners to identify systems that are operating inefficiently so that
actions can be taken to correct the problem. The EMS can also provide
preventive maintenance scheduling that will reduce the cost of operations and
maintenance in the long run. The control functionality of the EMS allows the
building manager/owner to operate building systems from one central
location. The operation schedules set via the EMS help to prevent building
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 986 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-10 www.enernoc.com
End Use Measure Description
systems from operating during unwanted or unoccupied periods. This analysis
assumes that this measure is limited to buildings with a central HVAC system.
HVAC (All) Thermostat -
Clock/Programmable
A programmable thermostat can be added to most heating/cooling systems.
They are typically used during winter to lower temperatures at night and in
summer to increase temperatures during the afternoon. There are two-setting
models, and well as models that allow separate programming for each day of
the week. The energy savings from this type of thermostat are identical to
those of a "setback" strategy with standard thermostats, but the convenience
of a programmable thermostat makes it a much more attractive option. In this
analysis, the baseline is assumed to have no thermostat setback.
HVAC (All) Advanced New
Construction Designs
Advanced new construction designs use an integrated approach to the design
of new buildings to account for the interaction of building systems. Designs
may specify the building orientation, building shell, proper sizing of equipment
and systems, and controls strategies with the goal of optimizing building energy
efficiency and comfort. Options that may be evaluated and incorporated
include passive solar strategies, increased thermal mass, natural ventilation,
energy recovery ventilation, daylighting strategies, and shading strategies. This
measure is modeled for new vintage only.
HVAC,
Lighting
Commissioning -
HVAC, Lighting,
Comprehensive
For new construction and major renovations, commissioning ensures that
building systems are properly designed, specified, and installed to meet the
design intent and provide high-efficiency performance. As the names suggests,
HVAC Commissioning and Lighting Commissioning focus only on HVAC and
lighting equipment and controls. Comprehensive commissioning addresses
these systems but usually begins earlier in the design process, and may also
address domestic hot water, non-HVAC fans, vertical transport,
telecommunications, fire protection, and other building systems.
HVAC,
Lighting
Retrocommissioning
- HVAC, Lighting
In existing buildings, the retrocommissioning process identifies low-cost or no
cost measures, including controls adjustments, to improve building
performance and reduce operating costs. Retrocommissioning addresses
HVAC, lighting, DHW, and other major building systems.
All Transformer
All electric power passes through one or more transformers on its way to
service equipment, lighting, and other loads. Currently available materials and
designs can considerably reduce both load and no-load losses. The new NEMA
TP-1 standard is used as the reference definition for energy -efficient products.
Tier-1 represents TP-1 dry-type transformers while Tier-2 reflects a switch to
liquid immersed TP-1 products. More efficient transformers with attractive
payback periods are estimated to save 40 to 50 percent of the energy lost by a
"typical" transformer, which translates into a one to three percent reduction in
electric bills for commercial and industrial customers.
All Strategic Energy
Management
Strategic Energy Management is a systematic approach to integrating energy
management into an organization’s business practices and creating lasting
energy management processes that produce reliable energy savings.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 987 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-11
Table C-3 Energy Efficiency Equipment Data, Electric—Small/Medium Commercial,
Existing Vintage, Washington
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Cooling Central Chiller 1.5 kw/ton, COP 2.3 - $0.00 20 - $0.00
Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.31 $0.39 20 1.10 $0.09
Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.38 $0.50 20 0.96 $0.09
Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.79 $0.62 20 0.99 $0.06
Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.83 $0.74 20 0.95 $0.06
Cooling Central Chiller Variable Refrigerant
Flow 1.09 $11.57 20 0.18 $0.75
Cooling RTU EER 9.2 - $0.00 16 - $0.00
Cooling RTU EER 10.1 0.21 $0.18 16 - $0.07
Cooling RTU EER 11.2 0.42 $0.35 16 1.00 $0.07
Cooling RTU EER 12.0 0.55 $0.58 16 0.91 $0.09
Cooling RTU Ductless VRF 0.68 $5.12 16 0.28 $0.62
Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Cooling Heat Pump EER 10.3, COP 3.2 0.42 $0.39 15 - $0.08
Cooling Heat Pump EER 11.0, COP 3.3 0.66 $1.18 15 1.00 $0.15
Cooling Heat Pump EER 11.7, COP 3.4 0.88 $1.57 15 0.97 $0.15
Cooling Heat Pump EER 12, COP 3.4 0.97 $1.96 15 0.93 $0.18
Cooling Heat Pump Ductless Mini-Split
System 1.07 $11.50 20 0.52 $0.76
Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00
Space Heating Furnace Standard - $0.00 18 1.00 $0.00
Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00
Ventilation Ventilation Variable Air Volume 1.37 $1.22 15 0.92 $0.08
Interior
Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00
Interior
Lighting Interior Screw-in Infrared Halogen 0.47 $0.09 1 1.00 $0.18
Interior
Lighting Interior Screw-in CFL 1.96 $0.03 4 5.64 $0.00
Interior
Lighting Interior Screw-in LED 2.17 $1.18 12 - $0.06
Interior
Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00
Interior
Lighting High Bay Fixtures High Pressure Sodium 0.25 -$0.07 9 2.04 -$0.04
Interior
Lighting High Bay Fixtures T8 0.25 -$0.15 6 4.03 -$0.11
Interior
Lighting High Bay Fixtures T5 0.32 -$0.15 6 4.81 -$0.08
Interior
Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting Linear Fluorescent T8 0.34 -$0.03 6 1.11 -$0.02
Interior
Lighting Linear Fluorescent Super T8 1.03 $0.25 6 0.94 $0.04
Interior
Lighting Linear Fluorescent T5 1.07 $0.43 6 0.81 $0.07
Interior
Lighting Linear Fluorescent LED 1.12 $3.74 15 - $0.29
Exterior
Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00
Exterior
Lighting Exterior Screw-in Infrared Halogen 0.09 $0.05 1 1.00 $0.50
Exterior
Lighting Exterior Screw-in CFL 0.38 $0.02 4 6.92 $0.01
Exterior
Lighting Exterior Screw-in Metal Halides 0.39 $0.05 4 3.30 $0.04
Exterior
Lighting Exterior Screw-in LED 0.43 $0.64 12 - $0.15
Exterior HID Metal Halides - $0.00 6 1.00 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 988 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-12 www.enernoc.com
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Lighting
Exterior
Lighting HID High Pressure Sodium 0.17 -$0.13 9 2.08 -$0.10
Exterior
Lighting HID Low Pressure Sodium 0.18 $0.55 9 0.57 $0.40
Water Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water Heating Water Heater High Efficiency (EF=0.95) 0.11 $0.02 15 1.02 $0.02
Water Heating Water Heater EF 2.0 1.07 -$0.48 15 2.84 -$0.04
Water Heating Water Heater EF 2.3 1.20 -$0.47 15 3.25 -$0.03
Water Heating Water Heater EF 2.4 1.24 -$0.47 15 3.38 -$0.03
Water Heating Water Heater Geothermal Heat Pump 1.42 $3.53 15 0.38 $0.21
Water Heating Water Heater Solar 1.56 $3.03 15 0.44 $0.17
Food
Preparation Fryer Standard - $0.00 12 1.00 $0.00
Food
Preparation Fryer Efficient 0.03 $0.04 12 0.87 $0.12
Food
Preparation Oven Standard - $0.00 12 1.00 $0.00
Food
Preparation Oven Efficient 0.39 $0.36 12 0.92 $0.10
Food
Preparation Dishwasher Standard - $0.00 12 1.00 $0.00
Food
Preparation Dishwasher Efficient 0.02 $0.05 12 0.87 $0.28
Food
Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00
Food
Preparation Hot Food Container Efficient 0.32 $0.16 12 0.96 $0.05
Food
Preparation Food Prep Standard - $0.00 12 1.00 $0.00
Food
Preparation Food Prep Efficient 0.00 $0.03 12 0.88 $1.40
Refrigeration Walk in
Refrigeration Standard - $0.00 18 1.00 $0.00
Refrigeration Walk in
Refrigeration Efficient - $0.09 18 0.90 $0.00
Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00
Refrigeration Glass Door Display Efficient 0.16 $0.00 18 1.36 $0.00
Refrigeration Reach-in
Refrigerator Standard - $0.00 18 1.00 $0.00
Refrigeration Reach-in
Refrigerator Efficient 0.15 $0.02 18 1.15 $0.01
Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00
Refrigeration Open Display Case Efficient 0.00 $0.00 18 0.92 $0.33
Refrigeration Vending Machine Base - $0.00 10 - $0.00
Refrigeration Vending Machine Base (2012) 0.09 $0.00 10 1.00 $0.00
Refrigeration Vending Machine High Efficiency 0.11 $0.00 10 - $0.00
Refrigeration Vending Machine High Efficiency (2012) 0.17 $0.00 10 1.18 $0.00
Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00
Refrigeration Icemaker Efficient 0.05 $0.00 12 1.11 $0.01
Office
Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Desktop Computer Energy Star 0.21 $0.00 4 1.01 $0.00
Office
Equipment Desktop Computer Climate Savers 0.30 $0.36 4 0.85 $0.32
Office
Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Laptop Computer Energy Star 0.02 $0.00 4 1.00 $0.01
Office
Equipment Laptop Computer Climate Savers 0.04 $0.12 4 0.84 $0.87
Office Server Standard - $0.00 3 1.00 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 989 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-13
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Equipment
Office
Equipment Server Energy Star 0.11 $0.01 3 0.99 $0.04
Office
Equipment Monitor Standard - $0.00 4 1.00 $0.00
Office
Equipment Monitor Energy Star 0.06 $0.00 4 1.03 $0.01
Office
Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00
Office
Equipment Printer/copier/fax Energy Star 0.08 $0.04 6 0.95 $0.09
Office
Equipment POS Terminal Standard - $0.00 4 1.00 $0.00
Office
Equipment POS Terminal Energy Star 0.02 $0.00 4 1.00 $0.03
Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00
Miscellaneous Non-HVAC Motor Standard (2015) 0.01 $0.06 15 - $0.71
Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00
Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.06 $0.06 15 0.98 $0.08
Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00
Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 990 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-14 www.enernoc.com
Table C-4 Energy Efficiency Equipment Data, Electric—Small/Medium Commercial,
New Vintage, Washington
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Cooling Central Chiller 1.5 kw/ton, COP 2.3 - $0.00 20 - $0.00
Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.28 $0.39 20 1.10 $0.10
Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.34 $0.50 20 0.96 $0.11
Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.70 $0.62 20 0.98 $0.06
Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.74 $0.74 20 0.94 $0.07
Cooling Central Chiller Variable Refrigerant
Flow 0.97 $11.57 20 0.18 $0.84
Cooling RTU EER 9.2 - $0.00 16 - $0.00
Cooling RTU EER 10.1 0.20 $0.18 16 - $0.08
Cooling RTU EER 11.2 0.41 $0.35 16 1.00 $0.07
Cooling RTU EER 12.0 0.53 $0.58 16 0.91 $0.09
Cooling RTU Ductless VRF 0.65 $5.12 16 0.28 $0.65
Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Cooling Heat Pump EER 10.3, COP 3.2 0.40 $0.39 15 - $0.08
Cooling Heat Pump EER 11.0, COP 3.3 0.63 $1.18 15 1.00 $0.16
Cooling Heat Pump EER 11.7, COP 3.4 0.84 $1.57 15 0.97 $0.16
Cooling Heat Pump EER 12, COP 3.4 0.93 $1.96 15 0.93 $0.18
Cooling Heat Pump Ductless Mini-Split
System 1.03 $11.50 20 0.52 $0.79
Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00
Space Heating Furnace Standard - $0.00 18 1.00 $0.00
Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00
Ventilation Ventilation Variable Air Volume 1.89 $1.22 15 1.01 $0.06
Interior
Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00
Interior
Lighting Interior Screw-in Infrared Halogen 0.65 $0.09 1 1.00 $0.13
Interior
Lighting Interior Screw-in CFL 2.67 $0.03 4 5.27 $0.00
Interior
Lighting Interior Screw-in LED 2.96 $1.18 12 - $0.04
Interior
Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00
Interior
Lighting High Bay Fixtures High Pressure Sodium 0.24 -$0.07 9 2.06 -$0.04
Interior
Lighting High Bay Fixtures T8 0.24 -$0.15 6 4.16 -$0.11
Interior
Lighting High Bay Fixtures T5 0.30 -$0.15 6 4.95 -$0.09
Interior
Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting Linear Fluorescent T8 0.32 -$0.03 6 1.11 -$0.02
Interior
Lighting Linear Fluorescent Super T8 0.96 $0.25 6 0.93 $0.05
Interior
Lighting Linear Fluorescent T5 1.00 $0.43 6 0.79 $0.08
Interior
Lighting Linear Fluorescent LED 1.05 $3.74 15 - $0.31
Exterior
Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00
Exterior
Lighting Exterior Screw-in Infrared Halogen 0.08 $0.05 1 1.00 $0.60
Exterior
Lighting Exterior Screw-in CFL 0.32 $0.02 4 7.11 $0.02
Exterior
Lighting Exterior Screw-in Metal Halides 0.32 $0.05 4 3.29 $0.04
Exterior
Lighting Exterior Screw-in LED 0.36 $0.64 12 - $0.18
Exterior HID Metal Halides - $0.00 6 1.00 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 991 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-15
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Lighting
Exterior
Lighting HID High Pressure Sodium 0.17 -$0.13 9 2.08 -$0.10
Exterior
Lighting HID Low Pressure Sodium 0.18 $0.55 9 0.57 $0.40
Water
Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water
Heating Water Heater High Efficiency (EF=0.95) 0.11 $0.02 15 1.02 $0.02
Water
Heating Water Heater EF 2.0 1.05 -$0.48 15 2.86 -$0.04
Water
Heating Water Heater EF 2.3 1.18 -$0.47 15 3.27 -$0.03
Water
Heating Water Heater EF 2.4 1.22 -$0.47 15 3.40 -$0.03
Water
Heating Water Heater Geothermal Heat Pump 1.39 $3.53 15 0.38 $0.22
Water
Heating Water Heater Solar 1.53 $3.03 15 0.43 $0.17
Food
Preparation Fryer Standard - $0.00 12 1.00 $0.00
Food
Preparation Fryer Efficient 0.03 $0.04 12 0.87 $0.12
Food
Preparation Oven Standard - $0.00 12 1.00 $0.00
Food
Preparation Oven Efficient 0.39 $0.36 12 0.92 $0.10
Food
Preparation Dishwasher Standard - $0.00 12 1.00 $0.00
Food
Preparation Dishwasher Efficient 0.02 $0.05 12 0.87 $0.28
Food
Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00
Food
Preparation Hot Food Container Efficient 0.32 $0.16 12 0.96 $0.05
Food
Preparation Food Prep Standard - $0.00 12 1.00 $0.00
Food
Preparation Food Prep Efficient 0.00 $0.03 12 0.87 $1.73
Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00
Refrigeration Walk in Refrigeration Efficient - $0.09 18 0.90 $0.00
Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00
Refrigeration Glass Door Display Efficient 0.16 $0.00 18 1.36 $0.00
Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00
Refrigeration Reach-in Refrigerator Efficient 0.15 $0.02 18 1.15 $0.01
Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00
Refrigeration Open Display Case Efficient 0.00 $0.00 18 0.91 $0.35
Refrigeration Vending Machine Base - $0.00 10 - $0.00
Refrigeration Vending Machine Base (2012) 0.09 $0.00 10 1.00 $0.00
Refrigeration Vending Machine High Efficiency 0.11 $0.00 10 - $0.00
Refrigeration Vending Machine High Efficiency (2012) 0.17 $0.00 10 1.18 $0.00
Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00
Refrigeration Icemaker Efficient 0.05 $0.00 12 1.11 $0.01
Office
Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Desktop Computer Energy Star 0.21 $0.00 4 1.01 $0.00
Office
Equipment Desktop Computer Climate Savers 0.30 $0.36 4 0.85 $0.32
Office
Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Laptop Computer Energy Star 0.02 $0.00 4 1.00 $0.01
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 992 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-16 www.enernoc.com
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Office
Equipment Laptop Computer Climate Savers 0.04 $0.12 4 0.84 $0.87
Office
Equipment Server Standard - $0.00 3 1.00 $0.00
Office
Equipment Server Energy Star 0.11 $0.01 3 0.99 $0.04
Office
Equipment Monitor Standard - $0.00 4 1.00 $0.00
Office
Equipment Monitor Energy Star 0.06 $0.00 4 1.03 $0.01
Office
Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00
Office
Equipment Printer/copier/fax Energy Star 0.08 $0.04 6 0.95 $0.09
Office
Equipment POS Terminal Standard - $0.00 4 1.00 $0.00
Office
Equipment POS Terminal Energy Star 0.02 $0.00 4 1.00 $0.03
Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00
Miscellaneous Non-HVAC Motor Standard (2015) 0.01 $0.06 15 - $0.71
Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00
Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.06 $0.06 15 0.98 $0.08
Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00
Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 993 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-17
Table C-5 Energy Efficiency Equipment Data, Small/Medium Commercial, Existing
Vintage, Idaho
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Cooling Central Chiller 1.5 kw/ton, COP 2.3 - $0.00 20 - $0.00
Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.31 $0.39 20 1.10 $0.09
Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.38 $0.50 20 0.96 $0.09
Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.79 $0.62 20 0.99 $0.06
Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.83 $0.74 20 0.95 $0.06
Cooling Central Chiller Variable Refrigerant
Flow 1.09 $11.57 20 0.18 $0.75
Cooling RTU EER 9.2 - $0.00 16 - $0.00
Cooling RTU EER 10.1 0.21 $0.18 16 - $0.07
Cooling RTU EER 11.2 0.42 $0.35 16 1.00 $0.07
Cooling RTU EER 12.0 0.55 $0.58 16 0.91 $0.09
Cooling RTU Ductless VRF 0.68 $5.12 16 0.28 $0.62
Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Cooling Heat Pump EER 10.3, COP 3.2 0.42 $0.39 15 - $0.08
Cooling Heat Pump EER 11.0, COP 3.3 0.66 $1.18 15 1.00 $0.15
Cooling Heat Pump EER 11.7, COP 3.4 0.88 $1.57 15 0.97 $0.15
Cooling Heat Pump EER 12, COP 3.4 0.97 $1.96 15 0.93 $0.18
Cooling Heat Pump Ductless Mini-Split
System 1.07 $11.50 20 0.51 $0.76
Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00
Space Heating Furnace Standard - $0.00 18 1.00 $0.00
Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00
Ventilation Ventilation Variable Air Volume 1.37 $1.22 15 0.93 $0.08
Interior
Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00
Interior
Lighting Interior Screw-in Infrared Halogen 0.47 $0.09 1 1.00 $0.18
Interior
Lighting Interior Screw-in CFL 1.96 $0.03 4 5.64 $0.00
Interior
Lighting Interior Screw-in LED 2.17 $1.18 12 - $0.06
Interior
Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00
Interior
Lighting High Bay Fixtures High Pressure Sodium 0.25 -$0.07 9 2.01 -$0.04
Interior
Lighting High Bay Fixtures T8 0.25 -$0.15 6 3.95 -$0.11
Interior
Lighting High Bay Fixtures T5 0.32 -$0.15 6 4.72 -$0.08
Interior
Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting Linear Fluorescent T8 0.34 -$0.03 6 1.11 -$0.02
Interior
Lighting Linear Fluorescent Super T8 1.03 $0.25 6 0.95 $0.04
Interior
Lighting Linear Fluorescent T5 1.07 $0.43 6 0.82 $0.07
Interior
Lighting Linear Fluorescent LED 1.12 $3.74 15 - $0.29
Exterior
Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00
Exterior
Lighting Exterior Screw-in Infrared Halogen 0.13 $0.05 1 1.00 $0.37
Exterior
Lighting Exterior Screw-in CFL 0.52 $0.02 4 6.55 $0.01
Exterior
Lighting Exterior Screw-in Metal Halides 0.52 $0.05 4 3.32 $0.03
Exterior
Lighting Exterior Screw-in LED 0.58 $0.64 12 - $0.11
Exterior HID Metal Halides - $0.00 6 1.00 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 994 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-18 www.enernoc.com
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Lighting
Exterior
Lighting HID High Pressure Sodium 0.15 -$0.13 9 2.09 -$0.11
Exterior
Lighting HID Low Pressure Sodium 0.16 $0.55 9 0.57 $0.43
Water
Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water
Heating Water Heater High Efficiency
(EF=0.95) 0.11 $0.02 15 1.03 $0.02
Water
Heating Water Heater EF 2.0 1.07 -$0.48 15 2.79 -$0.04
Water
Heating Water Heater EF 2.3 1.20 -$0.47 15 3.19 -$0.03
Water
Heating Water Heater EF 2.4 1.24 -$0.47 15 3.32 -$0.03
Water
Heating Water Heater Geothermal Heat Pump 1.42 $3.53 15 0.40 $0.21
Water
Heating Water Heater Solar 1.56 $3.03 15 0.46 $0.17
Food
Preparation Fryer Standard - $0.00 12 1.00 $0.00
Food
Preparation Fryer Efficient 0.03 $0.04 12 0.88 $0.12
Food
Preparation Oven Standard - $0.00 12 1.00 $0.00
Food
Preparation Oven Efficient 0.39 $0.36 12 0.93 $0.10
Food
Preparation Dishwasher Standard - $0.00 12 1.00 $0.00
Food
Preparation Dishwasher Efficient 0.02 $0.05 12 0.87 $0.28
Food
Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00
Food
Preparation Hot Food Container Efficient 0.32 $0.16 12 0.98 $0.05
Food
Preparation Food Prep Standard - $0.00 12 1.00 $0.00
Food
Preparation Food Prep Efficient 0.00 $0.03 12 0.87 $1.73
Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00
Refrigeration Walk in Refrigeration Efficient - $0.09 18 0.90 $0.00
Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00
Refrigeration Glass Door Display Efficient 0.16 $0.00 18 1.37 $0.00
Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00
Refrigeration Reach-in Refrigerator Efficient 0.15 $0.02 18 1.16 $0.01
Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00
Refrigeration Open Display Case Efficient 0.00 $0.00 18 0.92 $0.33
Refrigeration Vending Machine Base - $0.00 10 - $0.00
Refrigeration Vending Machine Base (2012) 0.09 $0.00 10 1.00 $0.00
Refrigeration Vending Machine High Efficiency 0.11 $0.00 10 - $0.00
Refrigeration Vending Machine High Efficiency (2012) 0.17 $0.00 10 1.19 $0.00
Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00
Refrigeration Icemaker Efficient 0.05 $0.00 12 1.11 $0.01
Office
Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Desktop Computer Energy Star 0.21 $0.00 4 1.01 $0.00
Office
Equipment Desktop Computer Climate Savers 0.30 $0.36 4 0.85 $0.32
Office
Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Laptop Computer Energy Star 0.02 $0.00 4 1.00 $0.01
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 995 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-19
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Office
Equipment Laptop Computer Climate Savers 0.04 $0.12 4 0.84 $0.87
Office
Equipment Server Standard - $0.00 3 1.00 $0.00
Office
Equipment Server Energy Star 0.11 $0.01 3 0.99 $0.04
Office
Equipment Monitor Standard - $0.00 4 1.00 $0.00
Office
Equipment Monitor Energy Star 0.06 $0.00 4 1.03 $0.01
Office
Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00
Office
Equipment Printer/copier/fax Energy Star 0.08 $0.04 6 0.95 $0.09
Office
Equipment POS Terminal Standard - $0.00 4 1.00 $0.00
Office
Equipment POS Terminal Energy Star 0.02 $0.00 4 1.00 $0.03
Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00
Miscellaneous Non-HVAC Motor Standard (2015) 0.01 $0.06 15 - $0.71
Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00
Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.06 $0.06 15 0.98 $0.08
Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00
Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 996 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-20 www.enernoc.com
Table C-6 Energy Efficiency Equipment Data, Electric— Small/Medium Commercial,
New Vintage, Idaho
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Cooling Central Chiller 1.5 kw/ton, COP 2.3 - $0.00 20 - $0.00
Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.28 $0.39 20 1.10 $0.10
Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.34 $0.50 20 0.96 $0.11
Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.70 $0.62 20 0.98 $0.06
Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.74 $0.74 20 0.94 $0.07
Cooling Central Chiller Variable Refrigerant
Flow 0.97 $11.57 20 0.18 $0.84
Cooling RTU EER 9.2 - $0.00 16 - $0.00
Cooling RTU EER 10.1 0.20 $0.18 16 - $0.08
Cooling RTU EER 11.2 0.41 $0.35 16 1.00 $0.07
Cooling RTU EER 12.0 0.53 $0.58 16 0.91 $0.09
Cooling RTU Ductless VRF 0.65 $5.12 16 0.28 $0.65
Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Cooling Heat Pump EER 10.3, COP 3.2 0.40 $0.39 15 - $0.08
Cooling Heat Pump EER 11.0, COP 3.3 0.63 $1.18 15 1.00 $0.16
Cooling Heat Pump EER 11.7, COP 3.4 0.84 $1.57 15 0.97 $0.16
Cooling Heat Pump EER 12, COP 3.4 0.93 $1.96 15 0.93 $0.18
Cooling Heat Pump Ductless Mini-Split
System 1.03 $11.50 20 0.51 $0.79
Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00
Space Heating Furnace Standard - $0.00 18 1.00 $0.00
Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00
Ventilation Ventilation Variable Air Volume 1.89 $1.22 15 1.02 $0.06
Interior
Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00
Interior
Lighting Interior Screw-in Infrared Halogen 0.65 $0.09 1 1.00 $0.13
Interior
Lighting Interior Screw-in CFL 2.67 $0.03 4 5.28 $0.00
Interior
Lighting Interior Screw-in LED 2.96 $1.18 12 - $0.04
Interior
Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00
Interior
Lighting High Bay Fixtures High Pressure Sodium 0.24 -$0.07 9 2.03 -$0.04
Interior
Lighting High Bay Fixtures T8 0.24 -$0.15 6 4.08 -$0.11
Interior
Lighting High Bay Fixtures T5 0.30 -$0.15 6 4.86 -$0.09
Interior
Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting Linear Fluorescent T8 0.32 -$0.03 6 1.11 -$0.02
Interior
Lighting Linear Fluorescent Super T8 0.96 $0.25 6 0.94 $0.05
Interior
Lighting Linear Fluorescent T5 1.00 $0.43 6 0.80 $0.08
Interior
Lighting Linear Fluorescent LED 1.05 $3.74 15 - $0.31
Exterior
Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00
Exterior
Lighting Exterior Screw-in Infrared Halogen 0.11 $0.05 1 1.00 $0.44
Exterior
Lighting Exterior Screw-in CFL 0.44 $0.02 4 6.76 $0.01
Exterior
Lighting Exterior Screw-in Metal Halides 0.44 $0.05 4 3.31 $0.03
Exterior
Lighting Exterior Screw-in LED 0.48 $0.64 12 - $0.14
Exterior HID Metal Halides - $0.00 6 1.00 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 997 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-21
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Lighting
Exterior
Lighting HID High Pressure Sodium 0.15 -$0.13 9 2.09 -$0.11
Exterior
Lighting HID Low Pressure Sodium 0.16 $0.55 9 0.57 $0.43
Water
Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water
Heating Water Heater High Efficiency
(EF=0.95) 0.11 $0.02 15 1.03 $0.02
Water
Heating Water Heater EF 2.0 1.05 -$0.48 15 2.80 -$0.04
Water
Heating Water Heater EF 2.3 1.18 -$0.47 15 3.20 -$0.03
Water
Heating Water Heater EF 2.4 1.22 -$0.47 15 3.33 -$0.03
Water
Heating Water Heater Geothermal Heat Pump 1.39 $3.53 15 0.39 $0.22
Water
Heating Water Heater Solar 1.53 $3.03 15 0.45 $0.17
Food
Preparation Fryer Standard - $0.00 12 1.00 $0.00
Food
Preparation Fryer Efficient 0.03 $0.04 12 0.88 $0.12
Food
Preparation Oven Standard - $0.00 12 1.00 $0.00
Food
Preparation Oven Efficient 0.39 $0.36 12 0.93 $0.10
Food
Preparation Dishwasher Standard - $0.00 12 1.00 $0.00
Food
Preparation Dishwasher Efficient 0.02 $0.05 12 0.87 $0.28
Food
Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00
Food
Preparation Hot Food Container Efficient 0.32 $0.16 12 0.98 $0.05
Food
Preparation Food Prep Standard - $0.00 12 1.00 $0.00
Food
Preparation Food Prep Efficient 0.00 $0.03 12 0.87 $1.73
Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00
Refrigeration Walk in Refrigeration Efficient - $0.09 18 0.90 $0.00
Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00
Refrigeration Glass Door Display Efficient 0.16 $0.00 18 1.37 $0.00
Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00
Refrigeration Reach-in Refrigerator Efficient 0.15 $0.02 18 1.16 $0.01
Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00
Refrigeration Open Display Case Efficient 0.00 $0.00 18 0.92 $0.35
Refrigeration Vending Machine Base - $0.00 10 - $0.00
Refrigeration Vending Machine Base (2012) 0.09 $0.00 10 1.00 $0.00
Refrigeration Vending Machine High Efficiency 0.11 $0.00 10 - $0.00
Refrigeration Vending Machine High Efficiency (2012) 0.17 $0.00 10 1.19 $0.00
Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00
Refrigeration Icemaker Efficient 0.05 $0.00 12 1.11 $0.01
Office
Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Desktop Computer Energy Star 0.21 $0.00 4 1.01 $0.00
Office
Equipment Desktop Computer Climate Savers 0.30 $0.36 4 0.85 $0.32
Office
Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Laptop Computer Energy Star 0.02 $0.00 4 1.00 $0.01
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 998 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-22 www.enernoc.com
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Office
Equipment Laptop Computer Climate Savers 0.04 $0.12 4 0.84 $0.87
Office
Equipment Server Standard - $0.00 3 1.00 $0.00
Office
Equipment Server Energy Star 0.11 $0.01 3 0.99 $0.04
Office
Equipment Monitor Standard - $0.00 4 1.00 $0.00
Office
Equipment Monitor Energy Star 0.06 $0.00 4 1.03 $0.01
Office
Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00
Office
Equipment Printer/copier/fax Energy Star 0.08 $0.04 6 0.95 $0.09
Office
Equipment POS Terminal Standard - $0.00 4 1.00 $0.00
Office
Equipment POS Terminal Energy Star 0.02 $0.00 4 1.00 $0.03
Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00
Miscellaneous Non-HVAC Motor Standard (2015) 0.01 $0.06 15 - $0.71
Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00
Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.06 $0.06 15 0.98 $0.08
Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00
Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 999 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-23
Table C-7 Energy Efficiency Equipment Data, Electric—Large Commercial, Existing
Vintage, Washington
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Cooling Central Chiller 1.5 kw/ton, COP 2.3 - $0.00 20 - $0.00
Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.29 $0.26 20 1.10 $0.06
Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.34 $0.33 20 0.97 $0.07
Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.71 $0.41 20 1.02 $0.04
Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.76 $0.49 20 0.99 $0.05
Cooling Central Chiller Variable Refrigerant
Flow 0.99 $7.63 20 0.21 $0.54
Cooling RTU EER 9.2 - $0.00 16 - $0.00
Cooling RTU EER 10.1 0.22 $0.13 16 - $0.05
Cooling RTU EER 11.2 0.44 $0.25 16 1.00 $0.05
Cooling RTU EER 12.0 0.57 $0.41 16 0.93 $0.06
Cooling RTU Ductless VRF 0.70 $3.67 16 0.32 $0.43
Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Cooling Heat Pump EER 10.3, COP 3.2 0.29 $0.18 15 - $0.06
Cooling Heat Pump EER 11.0, COP 3.3 0.45 $0.55 15 1.00 $0.10
Cooling Heat Pump EER 11.7, COP 3.4 0.61 $0.73 15 0.98 $0.10
Cooling Heat Pump EER 12, COP 3.4 0.66 $0.91 15 0.95 $0.12
Cooling Heat Pump Ductless Mini-Split
System 0.74 $5.35 20 0.56 $0.51
Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00
Space Heating Furnace Standard - $0.00 18 1.00 $0.00
Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00
Ventilation Ventilation Variable Air Volume 1.39 $1.22 15 0.91 $0.08
Interior
Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00
Interior
Lighting Interior Screw-in Infrared Halogen 0.49 $0.08 1 1.00 $0.16
Interior
Lighting Interior Screw-in CFL 2.03 $0.03 4 5.52 $0.00
Interior
Lighting Interior Screw-in LED 2.24 $1.11 12 - $0.05
Interior
Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00
Interior
Lighting High Bay Fixtures High Pressure Sodium 0.24 -$0.08 9 2.10 -$0.04
Interior
Lighting High Bay Fixtures T8 0.24 -$0.16 6 4.40 -$0.12
Interior
Lighting High Bay Fixtures T5 0.31 -$0.16 6 5.23 -$0.10
Interior
Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting Linear Fluorescent T8 0.34 -$0.03 6 1.11 -$0.02
Interior
Lighting Linear Fluorescent Super T8 1.03 $0.25 6 0.94 $0.04
Interior
Lighting Linear Fluorescent T5 1.07 $0.42 6 0.81 $0.07
Interior
Lighting Linear Fluorescent LED 1.12 $3.67 15 - $0.28
Exterior
Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00
Exterior
Lighting Exterior Screw-in Infrared Halogen 0.05 $0.01 1 1.00 $0.26
Exterior
Lighting Exterior Screw-in CFL 0.22 $0.01 4 6.10 $0.01
Exterior
Lighting Exterior Screw-in Metal Halides 0.22 $0.02 4 3.35 $0.02
Exterior
Lighting Exterior Screw-in LED 0.24 $0.19 12 - $0.08
Exterior HID Metal Halides - $0.00 6 1.00 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1000 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-24 www.enernoc.com
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Lighting
Exterior
Lighting HID High Pressure Sodium 0.15 -$0.11 9 2.03 -$0.09
Exterior
Lighting HID Low Pressure Sodium 0.16 $0.45 9 0.58 $0.36
Water
Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water
Heating Water Heater High Efficiency
(EF=0.95) 0.13 $0.02 15 1.03 $0.01
Water
Heating Water Heater EF 2.0 1.26 -$0.48 15 2.78 -$0.03
Water
Heating Water Heater EF 2.3 1.42 -$0.47 15 3.18 -$0.03
Water
Heating Water Heater EF 2.4 1.46 -$0.47 15 3.30 -$0.03
Water
Heating Water Heater Geothermal Heat Pump 1.67 $3.53 15 0.40 $0.18
Water
Heating Water Heater Solar 1.84 $3.03 15 0.46 $0.14
Food
Preparation Fryer Standard - $0.00 12 1.00 $0.00
Food
Preparation Fryer Efficient 0.07 $0.02 12 1.07 $0.03
Food
Preparation Oven Standard - $0.00 12 1.00 $0.00
Food
Preparation Oven Efficient 0.74 $0.46 12 0.95 $0.06
Food
Preparation Dishwasher Standard - $0.00 12 1.00 $0.00
Food
Preparation Dishwasher Efficient 0.06 $0.10 12 0.89 $0.16
Food
Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00
Food
Preparation Hot Food Container Efficient 0.21 $0.30 12 0.70 $0.15
Food
Preparation Food Prep Standard - $0.00 12 1.00 $0.00
Food
Preparation Food Prep Efficient 0.01 $0.03 12 0.88 $0.46
Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00
Refrigeration Walk in Refrigeration Efficient 0.11 $1.26 18 0.88 $0.87
Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00
Refrigeration Glass Door Display Efficient 0.13 $0.01 18 1.25 $0.00
Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00
Refrigeration Reach-in Refrigerator Efficient 0.16 $0.08 18 1.01 $0.04
Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00
Refrigeration Open Display Case Efficient 0.00 $0.04 18 0.88 $0.55
Refrigeration Vending Machine Base - $0.00 10 - $0.00
Refrigeration Vending Machine Base (2012) 0.11 $0.00 10 1.00 $0.00
Refrigeration Vending Machine High Efficiency 0.13 $0.00 10 - $0.00
Refrigeration Vending Machine High Efficiency (2012) 0.20 $0.00 10 1.09 $0.00
Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00
Refrigeration Icemaker Efficient 0.10 $0.02 12 1.06 $0.02
Office
Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Desktop Computer Energy Star 0.39 $0.00 4 1.02 $0.00
Office
Equipment Desktop Computer Climate Savers 0.55 $0.32 4 0.87 $0.15
Office
Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Laptop Computer Energy Star 0.02 $0.00 4 1.01 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1001 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-25
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Office
Equipment Laptop Computer Climate Savers 0.04 $0.06 4 0.85 $0.42
Office
Equipment Server Standard - $0.00 3 1.00 $0.00
Office
Equipment Server Energy Star 0.13 $0.01 3 1.02 $0.02
Office
Equipment Monitor Standard - $0.00 4 1.00 $0.00
Office
Equipment Monitor Energy Star 0.05 $0.01 4 1.00 $0.03
Office
Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00
Office
Equipment Printer/copier/fax Energy Star 0.07 $0.02 6 0.98 $0.04
Office
Equipment POS Terminal Standard - $0.00 4 1.00 $0.00
Office
Equipment POS Terminal Energy Star 0.01 $0.00 4 1.00 $0.03
Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00
Miscellaneous Non-HVAC Motor Standard (2015) 0.01 $0.06 15 - $0.63
Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00
Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.07 $0.06 15 0.98 $0.07
Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00
Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1002 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-26 www.enernoc.com
Table C-8 Energy Efficiency Equipment Data, Electric— Large Commercial, New
Vintage, Washington
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Cooling Central Chiller 1.5 kw/ton, COP 2.3 - $0.00 20 - $0.00
Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.26 $0.24 20 1.10 $0.07
Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.31 $0.31 20 0.97 $0.07
Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.64 $0.38 20 1.02 $0.04
Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.68 $0.45 20 0.99 $0.05
Cooling Central Chiller Variable Refrigerant
Flow 0.89 $7.06 20 0.21 $0.56
Cooling RTU EER 9.2 - $0.00 16 - $0.00
Cooling RTU EER 10.1 0.21 $0.13 16 - $0.05
Cooling RTU EER 11.2 0.41 $0.25 16 1.00 $0.05
Cooling RTU EER 12.0 0.54 $0.41 16 0.93 $0.06
Cooling RTU Ductless VRF 0.66 $3.67 16 0.32 $0.46
Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Cooling Heat Pump EER 10.3, COP 3.2 0.31 $0.18 15 - $0.05
Cooling Heat Pump EER 11.0, COP 3.3 0.50 $0.55 15 1.00 $0.10
Cooling Heat Pump EER 11.7, COP 3.4 0.66 $0.73 15 0.98 $0.10
Cooling Heat Pump EER 12, COP 3.4 0.73 $0.91 15 0.96 $0.11
Cooling Heat Pump Ductless Mini-Split
System 0.81 $5.35 20 0.57 $0.47
Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00
Space Heating Furnace Standard - $0.00 18 1.00 $0.00
Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00
Ventilation Ventilation Variable Air Volume 1.79 $1.22 15 0.99 $0.06
Interior
Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00
Interior
Lighting Interior Screw-in Infrared Halogen 0.61 $0.08 1 1.00 $0.13
Interior
Lighting Interior Screw-in CFL 2.52 $0.03 4 5.27 $0.00
Interior
Lighting Interior Screw-in LED 2.78 $1.11 12 - $0.04
Interior
Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00
Interior
Lighting High Bay Fixtures High Pressure Sodium 0.25 -$0.08 9 2.09 -$0.04
Interior
Lighting High Bay Fixtures T8 0.25 -$0.16 6 4.36 -$0.12
Interior
Lighting High Bay Fixtures T5 0.31 -$0.16 6 5.19 -$0.09
Interior
Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting Linear Fluorescent T8 0.31 -$0.03 6 1.11 -$0.02
Interior
Lighting Linear Fluorescent Super T8 0.93 $0.25 6 0.92 $0.05
Interior
Lighting Linear Fluorescent T5 0.97 $0.42 6 0.78 $0.08
Interior
Lighting Linear Fluorescent LED 1.02 $3.67 15 - $0.31
Exterior
Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00
Exterior
Lighting Exterior Screw-in Infrared Halogen 0.05 $0.01 1 1.00 $0.26
Exterior
Lighting Exterior Screw-in CFL 0.22 $0.01 4 6.10 $0.01
Exterior
Lighting Exterior Screw-in Metal Halides 0.22 $0.02 4 3.35 $0.02
Exterior
Lighting Exterior Screw-in LED 0.24 $0.19 12 - $0.08
Exterior HID Metal Halides - $0.00 6 1.00 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1003 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-27
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Lighting
Exterior
Lighting HID High Pressure Sodium 0.15 -$0.11 9 2.03 -$0.09
Exterior
Lighting HID Low Pressure Sodium 0.16 $0.45 9 0.58 $0.36
Water
Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water
Heating Water Heater High Efficiency
(EF=0.95) 0.12 $0.02 15 1.03 $0.02
Water
Heating Water Heater EF 2.0 1.21 -$0.48 15 2.81 -$0.03
Water
Heating Water Heater EF 2.3 1.35 -$0.47 15 3.21 -$0.03
Water
Heating Water Heater EF 2.4 1.39 -$0.47 15 3.34 -$0.03
Water
Heating Water Heater Geothermal Heat Pump 1.60 $3.53 15 0.39 $0.19
Water
Heating Water Heater Solar 1.76 $3.03 15 0.45 $0.15
Food
Preparation Fryer Standard - $0.00 12 1.00 $0.00
Food
Preparation Fryer Efficient 0.07 $0.02 12 1.07 $0.03
Food
Preparation Oven Standard - $0.00 12 1.00 $0.00
Food
Preparation Oven Efficient 0.74 $0.46 12 0.95 $0.06
Food
Preparation Dishwasher Standard - $0.00 12 1.00 $0.00
Food
Preparation Dishwasher Efficient 0.06 $0.10 12 0.89 $0.16
Food
Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00
Food
Preparation Hot Food Container Efficient 0.21 $0.30 12 0.70 $0.15
Food
Preparation Food Prep Standard - $0.00 12 1.00 $0.00
Food
Preparation Food Prep Efficient 0.01 $0.03 12 0.88 $0.46
Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00
Refrigeration Walk in Refrigeration Efficient 0.11 $1.26 18 0.88 $0.88
Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00
Refrigeration Glass Door Display Efficient 0.13 $0.01 18 1.25 $0.00
Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00
Refrigeration Reach-in Refrigerator Efficient 0.23 $0.08 18 1.05 $0.03
Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00
Refrigeration Open Display Case Efficient 0.00 $0.04 18 0.88 $0.55
Refrigeration Vending Machine Base - $0.00 10 - $0.00
Refrigeration Vending Machine Base (2012) 0.11 $0.00 10 1.00 $0.00
Refrigeration Vending Machine High Efficiency 0.13 $0.00 10 - $0.00
Refrigeration Vending Machine High Efficiency (2012) 0.20 $0.00 10 1.09 $0.00
Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00
Refrigeration Icemaker Efficient 0.09 $0.02 12 1.06 $0.02
Office
Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Desktop Computer Energy Star 0.39 $0.00 4 1.02 $0.00
Office
Equipment Desktop Computer Climate Savers 0.55 $0.32 4 0.87 $0.15
Office
Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Laptop Computer Energy Star 0.02 $0.00 4 1.01 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1004 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-28 www.enernoc.com
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Office
Equipment Laptop Computer Climate Savers 0.04 $0.06 4 0.85 $0.42
Office
Equipment Server Standard - $0.00 3 1.00 $0.00
Office
Equipment Server Energy Star 0.13 $0.01 3 1.02 $0.02
Office
Equipment Monitor Standard - $0.00 4 1.00 $0.00
Office
Equipment Monitor Energy Star 0.05 $0.01 4 1.00 $0.03
Office
Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00
Office
Equipment Printer/copier/fax Energy Star 0.07 $0.02 6 0.98 $0.04
Office
Equipment POS Terminal Standard - $0.00 4 1.00 $0.00
Office
Equipment POS Terminal Energy Star 0.01 $0.00 4 1.00 $0.03
Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00
Miscellaneous Non-HVAC Motor Standard (2015) 0.01 $0.06 15 - $0.63
Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00
Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.07 $0.06 15 0.98 $0.07
Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00
Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1005 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-29
Table C-9 Energy Efficiency Equipment Data, Electric—Large Commercial, Existing
Vintage, Idaho
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Cooling Central Chiller 1.5 kw/ton, COP 2.3 - $0.00 20 - $0.00
Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.29 $0.26 20 1.10 $0.06
Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.34 $0.33 20 0.97 $0.07
Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.71 $0.41 20 1.02 $0.04
Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.76 $0.49 20 0.99 $0.05
Cooling Central Chiller Variable Refrigerant
Flow 0.99 $7.63 20 0.21 $0.54
Cooling RTU EER 9.2 - $0.00 16 - $0.00
Cooling RTU EER 10.1 0.22 $0.13 16 - $0.05
Cooling RTU EER 11.2 0.44 $0.25 16 1.00 $0.05
Cooling RTU EER 12.0 0.57 $0.41 16 0.93 $0.06
Cooling RTU Ductless VRF 0.70 $3.67 16 0.32 $0.43
Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Cooling Heat Pump EER 10.3, COP 3.2 0.29 $0.18 15 - $0.06
Cooling Heat Pump EER 11.0, COP 3.3 0.45 $0.55 15 1.00 $0.10
Cooling Heat Pump EER 11.7, COP 3.4 0.61 $0.73 15 0.98 $0.10
Cooling Heat Pump EER 12, COP 3.4 0.66 $0.91 15 0.95 $0.12
Cooling Heat Pump Ductless Mini-Split
System 0.74 $5.35 20 0.56 $0.51
Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00
Space Heating Furnace Standard - $0.00 18 1.00 $0.00
Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00
Ventilation Ventilation Variable Air Volume 1.39 $1.22 15 0.92 $0.08
Interior
Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00
Interior
Lighting Interior Screw-in Infrared Halogen 0.49 $0.08 1 1.00 $0.16
Interior
Lighting Interior Screw-in CFL 2.03 $0.03 4 5.53 $0.00
Interior
Lighting Interior Screw-in LED 2.24 $1.11 12 - $0.05
Interior
Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00
Interior
Lighting High Bay Fixtures High Pressure Sodium 0.24 -$0.08 9 2.09 -$0.04
Interior
Lighting High Bay Fixtures T8 0.24 -$0.16 6 4.37 -$0.12
Interior
Lighting High Bay Fixtures T5 0.31 -$0.16 6 5.20 -$0.10
Interior
Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting Linear Fluorescent T8 0.34 -$0.03 6 1.11 -$0.02
Interior
Lighting Linear Fluorescent Super T8 1.03 $0.25 6 0.95 $0.04
Interior
Lighting Linear Fluorescent T5 1.07 $0.42 6 0.81 $0.07
Interior
Lighting Linear Fluorescent LED 1.12 $3.67 15 - $0.28
Exterior
Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00
Exterior
Lighting Exterior Screw-in Infrared Halogen 0.05 $0.01 1 1.00 $0.26
Exterior
Lighting Exterior Screw-in CFL 0.22 $0.01 4 6.10 $0.01
Exterior
Lighting Exterior Screw-in Metal Halides 0.22 $0.02 4 3.35 $0.02
Exterior
Lighting Exterior Screw-in LED 0.24 $0.19 12 - $0.08
Exterior HID Metal Halides - $0.00 6 1.00 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1006 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-30 www.enernoc.com
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Lighting
Exterior
Lighting HID High Pressure Sodium 0.15 -$0.11 9 2.02 -$0.09
Exterior
Lighting HID Low Pressure Sodium 0.16 $0.45 9 0.58 $0.36
Water
Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water
Heating Water Heater High Efficiency
(EF=0.95) 0.13 $0.02 15 1.03 $0.01
Water
Heating Water Heater EF 2.0 1.26 -$0.48 15 2.76 -$0.03
Water
Heating Water Heater EF 2.3 1.42 -$0.47 15 3.16 -$0.03
Water
Heating Water Heater EF 2.4 1.46 -$0.47 15 3.29 -$0.03
Water
Heating Water Heater Geothermal Heat Pump 1.67 $3.53 15 0.41 $0.18
Water
Heating Water Heater Solar 1.84 $3.03 15 0.47 $0.14
Food
Preparation Fryer Standard - $0.00 12 1.00 $0.00
Food
Preparation Fryer Efficient 0.07 $0.02 12 1.07 $0.03
Food
Preparation Oven Standard - $0.00 12 1.00 $0.00
Food
Preparation Oven Efficient 0.74 $0.46 12 0.96 $0.06
Food
Preparation Dishwasher Standard - $0.00 12 1.00 $0.00
Food
Preparation Dishwasher Efficient 0.06 $0.10 12 0.89 $0.16
Food
Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00
Food
Preparation Hot Food Container Efficient 0.21 $0.30 12 0.70 $0.15
Food
Preparation Food Prep Standard - $0.00 12 1.00 $0.00
Food
Preparation Food Prep Efficient 0.01 $0.03 12 0.88 $0.46
Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00
Refrigeration Walk in Refrigeration Efficient 0.11 $1.26 18 0.88 $0.87
Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00
Refrigeration Glass Door Display Efficient 0.13 $0.01 18 1.26 $0.00
Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00
Refrigeration Reach-in Refrigerator Efficient 0.16 $0.08 18 1.02 $0.04
Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00
Refrigeration Open Display Case Efficient 0.00 $0.04 18 0.88 $0.55
Refrigeration Vending Machine Base - $0.00 10 - $0.00
Refrigeration Vending Machine Base (2012) 0.11 $0.00 10 1.00 $0.00
Refrigeration Vending Machine High Efficiency 0.13 $0.00 10 - $0.00
Refrigeration Vending Machine High Efficiency (2012) 0.20 $0.00 10 1.09 $0.00
Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00
Refrigeration Icemaker Efficient 0.10 $0.02 12 1.06 $0.02
Office
Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Desktop Computer Energy Star 0.39 $0.00 4 1.02 $0.00
Office
Equipment Desktop Computer Climate Savers 0.55 $0.32 4 0.87 $0.15
Office
Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Laptop Computer Energy Star 0.02 $0.00 4 1.01 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1007 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-31
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Office
Equipment Laptop Computer Climate Savers 0.04 $0.06 4 0.85 $0.42
Office
Equipment Server Standard - $0.00 3 1.00 $0.00
Office
Equipment Server Energy Star 0.13 $0.01 3 1.01 $0.02
Office
Equipment Monitor Standard - $0.00 4 1.00 $0.00
Office
Equipment Monitor Energy Star 0.05 $0.01 4 1.00 $0.03
Office
Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00
Office
Equipment Printer/copier/fax Energy Star 0.07 $0.02 6 0.98 $0.04
Office
Equipment POS Terminal Standard - $0.00 4 1.00 $0.00
Office
Equipment POS Terminal Energy Star 0.01 $0.00 4 1.00 $0.03
Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00
Miscellaneous Non-HVAC Motor Standard (2015) 0.01 $0.06 15 - $0.63
Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00
Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.07 $0.06 15 0.98 $0.07
Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00
Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1008 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-32 www.enernoc.com
Table C-10 Energy Efficiency Equipment Data, Electric— Large Commercial, New
Vintage, Idaho
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Cooling Central Chiller 1.5 kw/ton, COP 2.3 - $0.00 20 - $0.00
Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.26 $0.24 20 1.10 $0.07
Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.31 $0.31 20 0.97 $0.07
Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.64 $0.38 20 1.02 $0.04
Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.68 $0.45 20 0.99 $0.05
Cooling Central Chiller Variable Refrigerant
Flow 0.89 $7.06 20 0.21 $0.56
Cooling RTU EER 9.2 - $0.00 16 - $0.00
Cooling RTU EER 10.1 0.21 $0.13 16 - $0.05
Cooling RTU EER 11.2 0.41 $0.25 16 1.00 $0.05
Cooling RTU EER 12.0 0.54 $0.41 16 0.93 $0.06
Cooling RTU Ductless VRF 0.66 $3.67 16 0.32 $0.46
Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Cooling Heat Pump EER 10.3, COP 3.2 0.31 $0.18 15 - $0.05
Cooling Heat Pump EER 11.0, COP 3.3 0.50 $0.55 15 1.00 $0.10
Cooling Heat Pump EER 11.7, COP 3.4 0.66 $0.73 15 0.98 $0.10
Cooling Heat Pump EER 12, COP 3.4 0.73 $0.91 15 0.95 $0.11
Cooling Heat Pump Ductless Mini-Split
System 0.81 $5.35 20 0.57 $0.47
Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00
Space Heating Furnace Standard - $0.00 18 1.00 $0.00
Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00
Ventilation Ventilation Variable Air Volume 1.79 $1.22 15 1.00 $0.06
Interior
Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00
Interior
Lighting Interior Screw-in Infrared Halogen 0.61 $0.08 1 1.00 $0.13
Interior
Lighting Interior Screw-in CFL 2.52 $0.03 4 5.28 $0.00
Interior
Lighting Interior Screw-in LED 2.78 $1.11 12 - $0.04
Interior
Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00
Interior
Lighting High Bay Fixtures High Pressure Sodium 0.25 -$0.08 9 2.08 -$0.04
Interior
Lighting High Bay Fixtures T8 0.25 -$0.16 6 4.34 -$0.12
Interior
Lighting High Bay Fixtures T5 0.31 -$0.16 6 5.16 -$0.09
Interior
Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting Linear Fluorescent T8 0.31 -$0.03 6 1.11 -$0.02
Interior
Lighting Linear Fluorescent Super T8 0.93 $0.25 6 0.92 $0.05
Interior
Lighting Linear Fluorescent T5 0.97 $0.42 6 0.79 $0.08
Interior
Lighting Linear Fluorescent LED 1.02 $3.67 15 - $0.31
Exterior
Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00
Exterior
Lighting Exterior Screw-in Infrared Halogen 0.05 $0.01 1 1.00 $0.26
Exterior
Lighting Exterior Screw-in CFL 0.22 $0.01 4 6.10 $0.01
Exterior
Lighting Exterior Screw-in Metal Halides 0.22 $0.02 4 3.35 $0.02
Exterior
Lighting Exterior Screw-in LED 0.24 $0.19 12 - $0.08
Exterior HID Metal Halides - $0.00 6 1.00 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1009 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-33
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Lighting
Exterior
Lighting HID High Pressure Sodium 0.15 -$0.11 9 2.02 -$0.09
Exterior
Lighting HID Low Pressure Sodium 0.16 $0.45 9 0.58 $0.36
Water
Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water
Heating Water Heater High Efficiency
(EF=0.95) 0.12 $0.02 15 1.03 $0.02
Water
Heating Water Heater EF 2.0 1.21 -$0.48 15 2.79 -$0.03
Water
Heating Water Heater EF 2.3 1.35 -$0.47 15 3.19 -$0.03
Water
Heating Water Heater EF 2.4 1.39 -$0.47 15 3.32 -$0.03
Water
Heating Water Heater Geothermal Heat Pump 1.60 $3.53 15 0.40 $0.19
Water
Heating Water Heater Solar 1.76 $3.03 15 0.46 $0.15
Food
Preparation Fryer Standard - $0.00 12 1.00 $0.00
Food
Preparation Fryer Efficient 0.07 $0.02 12 1.07 $0.03
Food
Preparation Oven Standard - $0.00 12 1.00 $0.00
Food
Preparation Oven Efficient 0.74 $0.46 12 0.96 $0.06
Food
Preparation Dishwasher Standard - $0.00 12 1.00 $0.00
Food
Preparation Dishwasher Efficient 0.06 $0.10 12 0.89 $0.16
Food
Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00
Food
Preparation Hot Food Container Efficient 0.21 $0.30 12 0.70 $0.15
Food
Preparation Food Prep Standard - $0.00 12 1.00 $0.00
Food
Preparation Food Prep Efficient 0.01 $0.03 12 0.88 $0.46
Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00
Refrigeration Walk in Refrigeration Efficient 0.11 $1.26 18 0.88 $0.88
Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00
Refrigeration Glass Door Display Efficient 0.13 $0.01 18 1.26 $0.00
Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00
Refrigeration Reach-in Refrigerator Efficient 0.23 $0.08 18 1.05 $0.03
Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00
Refrigeration Open Display Case Efficient 0.00 $0.04 18 0.88 $0.55
Refrigeration Vending Machine Base - $0.00 10 - $0.00
Refrigeration Vending Machine Base (2012) 0.11 $0.00 10 1.00 $0.00
Refrigeration Vending Machine High Efficiency 0.13 $0.00 10 - $0.00
Refrigeration Vending Machine High Efficiency (2012) 0.20 $0.00 10 1.09 $0.00
Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00
Refrigeration Icemaker Efficient 0.09 $0.02 12 1.06 $0.02
Office
Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Desktop Computer Energy Star 0.39 $0.00 4 1.02 $0.00
Office
Equipment Desktop Computer Climate Savers 0.55 $0.32 4 0.87 $0.15
Office
Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Laptop Computer Energy Star 0.02 $0.00 4 1.01 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1010 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-34 www.enernoc.com
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Office
Equipment Laptop Computer Climate Savers 0.04 $0.06 4 0.85 $0.42
Office
Equipment Server Standard - $0.00 3 1.00 $0.00
Office
Equipment Server Energy Star 0.13 $0.01 3 1.01 $0.02
Office
Equipment Monitor Standard - $0.00 4 1.00 $0.00
Office
Equipment Monitor Energy Star 0.05 $0.01 4 1.00 $0.03
Office
Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00
Office
Equipment Printer/copier/fax Energy Star 0.07 $0.02 6 0.98 $0.04
Office
Equipment POS Terminal Standard - $0.00 4 1.00 $0.00
Office
Equipment POS Terminal Energy Star 0.01 $0.00 4 1.00 $0.03
Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00
Miscellaneous Non-HVAC Motor Standard (2015) 0.01 $0.06 15 - $0.63
Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00
Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.07 $0.06 15 0.98 $0.07
Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00
Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1011 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-35
Table C-11 Energy Efficiency Equipment Data, Electric—Extra Large Commercial,
Existing Vintage, Washington
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Cooling Central Chiller Variable Refrigerant
Flow 1.08 $10.92 20 0.15 $0.71
Cooling RTU EER 9.2 - $0.00 16 - $0.00
Cooling RTU EER 10.1 0.20 $0.24 16 - $0.10
Cooling RTU EER 11.2 0.40 $0.45 16 1.00 $0.09
Cooling RTU EER 12.0 0.52 $0.75 16 0.89 $0.12
Cooling RTU Ductless VRF 0.63 $6.64 16 0.26 $0.87
Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Cooling Heat Pump EER 10.3, COP 3.2 0.20 $0.24 15 - $0.11
Cooling Heat Pump EER 11.0, COP 3.3 0.31 $0.73 15 1.00 $0.20
Cooling Heat Pump EER 11.7, COP 3.4 0.42 $0.97 15 0.97 $0.20
Cooling Heat Pump EER 12, COP 3.4 0.46 $1.21 15 0.94 $0.23
Cooling Heat Pump Ductless Mini-Split
System 0.51 $7.10 20 0.54 $0.99
Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00
Space Heating Furnace Standard - $0.00 18 1.00 $0.00
Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00
Ventilation Ventilation Variable Air Volume 2.10 $1.22 15 1.04 $0.05
Interior
Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00
Interior
Lighting Interior Screw-in Infrared Halogen 0.79 $0.14 1 1.00 $0.18
Interior
Lighting Interior Screw-in CFL 3.25 $0.06 4 5.60 $0.00
Interior
Lighting Interior Screw-in LED 3.59 $1.90 12 - $0.05
Interior
Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00
Interior
Lighting High Bay Fixtures High Pressure Sodium 0.10 -$0.05 9 2.23 -$0.07
Interior
Lighting High Bay Fixtures T8 0.10 -$0.11 6 5.65 -$0.19
Interior
Lighting High Bay Fixtures T5 0.13 -$0.10 6 6.21 -$0.15
Interior
Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting Linear Fluorescent T8 0.23 -$0.03 6 1.12 -$0.02
Interior
Lighting Linear Fluorescent Super T8 0.69 $0.21 6 0.89 $0.06
Interior
Lighting Linear Fluorescent T5 0.71 $0.35 6 0.75 $0.09
Interior
Lighting Linear Fluorescent LED 0.75 $3.08 15 - $0.36
Exterior
Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00
Exterior
Lighting Exterior Screw-in Infrared Halogen 0.02 $0.00 1 1.00 $0.22
Exterior
Lighting Exterior Screw-in CFL 0.07 $0.00 4 5.89 $0.01
Exterior
Lighting Exterior Screw-in Metal Halides 0.07 $0.00 4 3.36 $0.02
Exterior
Lighting Exterior Screw-in LED 0.07 $0.05 12 - $0.07
Exterior
Lighting HID Metal Halides - $0.00 6 1.00 $0.00
Exterior
Lighting HID High Pressure Sodium 0.19 -$0.16 9 2.08 -$0.10
Exterior
Lighting HID Low Pressure Sodium 0.21 $0.64 9 0.57 $0.40
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1012 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-36 www.enernoc.com
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Water
Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water
Heating Water Heater High Efficiency
(EF=0.95) 0.20 $0.02 15 1.04 $0.01
Water
Heating Water Heater EF 2.0 1.95 -$0.48 15 2.49 -$0.02
Water
Heating Water Heater EF 2.3 2.19 -$0.47 15 2.86 -$0.02
Water
Heating Water Heater EF 2.4 2.26 -$0.47 15 2.98 -$0.02
Water
Heating Water Heater Geothermal Heat Pump 2.59 $3.53 15 0.56 $0.12
Water
Heating Water Heater Solar 2.84 $3.03 15 0.65 $0.09
Food
Preparation Fryer Standard - $0.00 12 1.00 $0.00
Food
Preparation Fryer Efficient 0.03 $0.00 12 1.13 $0.02
Food
Preparation Oven Standard - $0.00 12 1.00 $0.00
Food
Preparation Oven Efficient 0.84 $0.38 12 1.00 $0.05
Food
Preparation Dishwasher Standard - $0.00 12 1.00 $0.00
Food
Preparation Dishwasher Efficient 0.03 $0.04 12 0.89 $0.18
Food
Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00
Food
Preparation Hot Food Container Efficient 0.10 $0.22 12 0.66 $0.22
Food
Preparation Food Prep Standard - $0.00 12 1.00 $0.00
Food
Preparation Food Prep Efficient 0.00 $0.03 12 0.88 $0.77
Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00
Refrigeration Walk in Refrigeration Efficient 0.04 $0.05 18 0.95 $0.08
Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00
Refrigeration Glass Door Display Efficient 0.04 $0.00 18 1.39 $0.00
Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00
Refrigeration Reach-in Refrigerator Efficient 0.21 $0.02 18 1.19 $0.01
Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00
Refrigeration Open Display Case Efficient 0.01 $0.03 18 0.93 $0.25
Refrigeration Vending Machine Base - $0.00 10 - $0.00
Refrigeration Vending Machine Base (2012) 0.12 $0.00 10 1.00 $0.00
Refrigeration Vending Machine High Efficiency 0.14 $0.00 10 - $0.00
Refrigeration Vending Machine High Efficiency (2012) 0.21 $0.00 10 1.24 $0.00
Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00
Refrigeration Icemaker Efficient 0.04 $0.00 12 1.12 $0.01
Office
Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Desktop Computer Energy Star 0.28 $0.00 4 1.02 $0.00
Office
Equipment Desktop Computer Climate Savers 0.39 $0.33 4 0.86 $0.22
Office
Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Laptop Computer Energy Star 0.03 $0.00 4 1.00 $0.01
Office
Equipment Laptop Computer Climate Savers 0.04 $0.10 4 0.84 $0.61
Office
Equipment Server Standard - $0.00 3 1.00 $0.00
Office Server Energy Star 0.05 $0.00 3 1.00 $0.03
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1013 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-37
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Equipment
Office
Equipment Monitor Standard - $0.00 4 1.00 $0.00
Office
Equipment Monitor Energy Star 0.03 $0.01 4 0.99 $0.04
Office
Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00
Office
Equipment Printer/copier/fax Energy Star 0.02 $0.01 6 0.96 $0.06
Office
Equipment POS Terminal Standard - $0.00 4 1.00 $0.00
Office
Equipment POS Terminal Energy Star 0.00 $0.00 4 0.99 $0.05
Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00
Miscellaneous Non-HVAC Motor Standard (2015) 0.00 $0.06 15 - $1.06
Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00
Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.04 $0.06 15 0.97 $0.12
Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00
Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1014 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-38 www.enernoc.com
Table C-12 Energy Efficiency Equipment Data, Electric— Extra Large Commercial, New
Vintage, Washington
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Cooling Central Chiller Variable Refrigerant
Flow 1.01 $10.92 20 0.15 $0.77
Cooling RTU EER 9.2 - $0.00 16 - $0.00
Cooling RTU EER 10.1 0.19 $0.24 16 - $0.10
Cooling RTU EER 11.2 0.38 $0.44 16 1.00 $0.10
Cooling RTU EER 12.0 0.49 $0.73 16 0.89 $0.12
Cooling RTU Ductless VRF 0.60 $6.51 16 0.26 $0.90
Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Cooling Heat Pump EER 10.3, COP 3.2 0.17 $0.24 15 - $0.12
Cooling Heat Pump EER 11.0, COP 3.3 0.28 $0.73 15 1.00 $0.23
Cooling Heat Pump EER 11.7, COP 3.4 0.37 $0.97 15 0.97 $0.23
Cooling Heat Pump EER 12, COP 3.4 0.41 $1.21 15 0.94 $0.26
Cooling Heat Pump Ductless Mini-Split
System 0.45 $7.10 20 0.54 $1.12
Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00
Space Heating Furnace Standard - $0.00 18 1.00 $0.00
Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00
Ventilation Ventilation Variable Air Volume 2.23 $1.22 15 1.06 $0.05
Interior
Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00
Interior
Lighting Interior Screw-in Infrared Halogen 0.87 $0.14 1 1.00 $0.16
Interior
Lighting Interior Screw-in CFL 3.61 $0.06 4 5.48 $0.00
Interior
Lighting Interior Screw-in LED 3.99 $1.90 12 - $0.05
Interior
Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00
Interior
Lighting High Bay Fixtures High Pressure Sodium 0.10 -$0.05 9 2.23 -$0.07
Interior
Lighting High Bay Fixtures T8 0.10 -$0.11 6 5.65 -$0.19
Interior
Lighting High Bay Fixtures T5 0.13 -$0.10 6 6.21 -$0.15
Interior
Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting Linear Fluorescent T8 0.22 -$0.03 6 1.12 -$0.02
Interior
Lighting Linear Fluorescent Super T8 0.66 $0.21 6 0.88 $0.06
Interior
Lighting Linear Fluorescent T5 0.68 $0.35 6 0.74 $0.09
Interior
Lighting Linear Fluorescent LED 0.72 $3.08 15 - $0.37
Exterior
Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00
Exterior
Lighting Exterior Screw-in Infrared Halogen 0.01 $0.00 1 1.00 $0.38
Exterior
Lighting Exterior Screw-in CFL 0.04 $0.00 4 6.57 $0.01
Exterior
Lighting Exterior Screw-in Metal Halides 0.04 $0.00 4 3.32 $0.03
Exterior
Lighting Exterior Screw-in LED 0.04 $0.05 12 - $0.12
Exterior
Lighting HID Metal Halides - $0.00 6 1.00 $0.00
Exterior
Lighting HID High Pressure Sodium 0.19 -$0.16 9 2.08 -$0.10
Exterior
Lighting HID Low Pressure Sodium 0.21 $0.64 9 0.57 $0.40
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1015 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-39
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Water
Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water
Heating Water Heater High Efficiency
(EF=0.95) 0.20 $0.02 15 1.04 $0.01
Water
Heating Water Heater EF 2.0 1.98 -$0.48 15 2.49 -$0.02
Water
Heating Water Heater EF 2.3 2.22 -$0.47 15 2.85 -$0.02
Water
Heating Water Heater EF 2.4 2.29 -$0.47 15 2.97 -$0.02
Water
Heating Water Heater Geothermal Heat Pump 2.62 $3.53 15 0.57 $0.12
Water
Heating Water Heater Solar 2.88 $3.03 15 0.66 $0.09
Food
Preparation Fryer Standard - $0.00 12 1.00 $0.00
Food
Preparation Fryer Efficient 0.03 $0.00 12 1.13 $0.02
Food
Preparation Oven Standard - $0.00 12 1.00 $0.00
Food
Preparation Oven Efficient 0.84 $0.38 12 1.00 $0.05
Food
Preparation Dishwasher Standard - $0.00 12 1.00 $0.00
Food
Preparation Dishwasher Efficient 0.03 $0.04 12 0.89 $0.18
Food
Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00
Food
Preparation Hot Food Container Efficient 0.10 $0.22 12 0.66 $0.22
Food
Preparation Food Prep Standard - $0.00 12 1.00 $0.00
Food
Preparation Food Prep Efficient 0.00 $0.03 12 0.88 $0.62
Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00
Refrigeration Walk in Refrigeration Efficient 0.04 $0.05 18 0.95 $0.08
Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00
Refrigeration Glass Door Display Efficient 0.04 $0.00 18 1.39 $0.00
Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00
Refrigeration Reach-in Refrigerator Efficient 0.21 $0.02 18 1.20 $0.01
Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00
Refrigeration Open Display Case Efficient 0.01 $0.03 18 0.93 $0.25
Refrigeration Vending Machine Base - $0.00 10 - $0.00
Refrigeration Vending Machine Base (2012) 0.10 $0.00 10 1.00 $0.00
Refrigeration Vending Machine High Efficiency 0.12 $0.00 10 - $0.00
Refrigeration Vending Machine High Efficiency (2012) 0.18 $0.00 10 1.21 $0.00
Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00
Refrigeration Icemaker Efficient 0.04 $0.00 12 1.12 $0.01
Office
Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Desktop Computer Energy Star 0.28 $0.00 4 1.02 $0.00
Office
Equipment Desktop Computer Climate Savers 0.39 $0.33 4 0.86 $0.22
Office
Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Laptop Computer Energy Star 0.03 $0.00 4 1.00 $0.01
Office
Equipment Laptop Computer Climate Savers 0.04 $0.10 4 0.84 $0.61
Office
Equipment Server Standard - $0.00 3 1.00 $0.00
Office Server Energy Star 0.05 $0.00 3 1.00 $0.03
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1016 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-40 www.enernoc.com
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Equipment
Office
Equipment Monitor Standard - $0.00 4 1.00 $0.00
Office
Equipment Monitor Energy Star 0.03 $0.01 4 0.99 $0.04
Office
Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00
Office
Equipment Printer/copier/fax Energy Star 0.02 $0.01 6 0.96 $0.06
Office
Equipment POS Terminal Standard - $0.00 4 1.00 $0.00
Office
Equipment POS Terminal Energy Star 0.00 $0.00 4 0.99 $0.05
Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00
Miscellaneous Non-HVAC Motor Standard (2015) 0.00 $0.06 15 - $1.06
Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00
Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.04 $0.06 15 0.97 $0.12
Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00
Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1017 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-41
Table C-13 Energy Efficiency Equipment Data, Electric—Extra Large Commercial,
Existing Vintage, Idaho
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Cooling Central Chiller Variable Refrigerant
Flow 1.08 $10.92 20 0.16 $0.71
Cooling RTU EER 9.2 - $0.00 16 - $0.00
Cooling RTU EER 10.1 0.20 $0.24 16 - $0.10
Cooling RTU EER 11.2 0.40 $0.45 16 1.00 $0.09
Cooling RTU EER 12.0 0.52 $0.75 16 0.89 $0.12
Cooling RTU Ductless VRF 0.63 $6.64 16 0.26 $0.87
Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Cooling Heat Pump EER 10.3, COP 3.2 0.20 $0.24 15 - $0.11
Cooling Heat Pump EER 11.0, COP 3.3 0.31 $0.73 15 1.00 $0.20
Cooling Heat Pump EER 11.7, COP 3.4 0.42 $0.97 15 0.97 $0.20
Cooling Heat Pump EER 12, COP 3.4 0.46 $1.21 15 0.94 $0.23
Cooling Heat Pump Ductless Mini-Split
System 0.51 $7.10 20 0.53 $0.99
Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00
Space Heating Furnace Standard - $0.00 18 1.00 $0.00
Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00
Ventilation Ventilation Variable Air Volume 2.10 $1.22 15 1.02 $0.05
Interior
Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00
Interior
Lighting Interior Screw-in Infrared Halogen 0.79 $0.14 1 1.00 $0.18
Interior
Lighting Interior Screw-in CFL 3.25 $0.06 4 5.61 $0.00
Interior
Lighting Interior Screw-in LED 3.59 $1.90 12 - $0.05
Interior
Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00
Interior
Lighting High Bay Fixtures High Pressure Sodium 0.10 -$0.05 9 2.26 -$0.07
Interior
Lighting High Bay Fixtures T8 0.10 -$0.11 6 5.77 -$0.19
Interior
Lighting High Bay Fixtures T5 0.13 -$0.10 6 6.31 -$0.15
Interior
Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting Linear Fluorescent T8 0.23 -$0.03 6 1.12 -$0.02
Interior
Lighting Linear Fluorescent Super T8 0.69 $0.21 6 0.88 $0.06
Interior
Lighting Linear Fluorescent T5 0.71 $0.35 6 0.74 $0.09
Interior
Lighting Linear Fluorescent LED 0.75 $3.08 15 - $0.36
Exterior
Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00
Exterior
Lighting Exterior Screw-in Infrared Halogen 0.02 $0.00 1 1.00 $0.22
Exterior
Lighting Exterior Screw-in CFL 0.07 $0.00 4 5.90 $0.01
Exterior
Lighting Exterior Screw-in Metal Halides 0.07 $0.00 4 3.36 $0.02
Exterior
Lighting Exterior Screw-in LED 0.07 $0.05 12 - $0.07
Exterior
Lighting HID Metal Halides - $0.00 6 1.00 $0.00
Exterior
Lighting HID High Pressure Sodium 0.19 -$0.16 9 2.09 -$0.10
Exterior
Lighting HID Low Pressure Sodium 0.21 $0.64 9 0.57 $0.40
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1018 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-42 www.enernoc.com
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Water
Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water
Heating Water Heater High Efficiency
(EF=0.95) 0.20 $0.02 15 1.03 $0.01
Water
Heating Water Heater EF 2.0 1.95 -$0.48 15 2.55 -$0.02
Water
Heating Water Heater EF 2.3 2.19 -$0.47 15 2.92 -$0.02
Water
Heating Water Heater EF 2.4 2.26 -$0.47 15 3.04 -$0.02
Water
Heating Water Heater Geothermal Heat Pump 2.59 $3.53 15 0.52 $0.12
Water
Heating Water Heater Solar 2.84 $3.03 15 0.60 $0.09
Food
Preparation Fryer Standard - $0.00 12 1.00 $0.00
Food
Preparation Fryer Efficient 0.03 $0.00 12 1.11 $0.02
Food
Preparation Oven Standard - $0.00 12 1.00 $0.00
Food
Preparation Oven Efficient 0.84 $0.38 12 0.99 $0.05
Food
Preparation Dishwasher Standard - $0.00 12 1.00 $0.00
Food
Preparation Dishwasher Efficient 0.03 $0.04 12 0.88 $0.18
Food
Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00
Food
Preparation Hot Food Container Efficient 0.10 $0.22 12 0.65 $0.22
Food
Preparation Food Prep Standard - $0.00 12 1.00 $0.00
Food
Preparation Food Prep Efficient 0.00 $0.03 12 0.88 $0.77
Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00
Refrigeration Walk in Refrigeration Efficient 0.04 $0.05 18 0.95 $0.08
Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00
Refrigeration Glass Door Display Efficient 0.04 $0.00 18 1.39 $0.00
Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00
Refrigeration Reach-in Refrigerator Efficient 0.21 $0.02 18 1.18 $0.01
Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00
Refrigeration Open Display Case Efficient 0.01 $0.03 18 0.93 $0.25
Refrigeration Vending Machine Base - $0.00 10 - $0.00
Refrigeration Vending Machine Base (2012) 0.12 $0.00 10 1.00 $0.00
Refrigeration Vending Machine High Efficiency 0.14 $0.00 10 - $0.00
Refrigeration Vending Machine High Efficiency (2012) 0.21 $0.00 10 1.23 $0.00
Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00
Refrigeration Icemaker Efficient 0.04 $0.00 12 1.12 $0.01
Office
Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Desktop Computer Energy Star 0.28 $0.00 4 1.02 $0.00
Office
Equipment Desktop Computer Climate Savers 0.39 $0.33 4 0.86 $0.22
Office
Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Laptop Computer Energy Star 0.03 $0.00 4 1.00 $0.01
Office
Equipment Laptop Computer Climate Savers 0.04 $0.10 4 0.84 $0.61
Office
Equipment Server Standard - $0.00 3 1.00 $0.00
Office Server Energy Star 0.05 $0.00 3 1.00 $0.03
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1019 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-43
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Equipment
Office
Equipment Monitor Standard - $0.00 4 1.00 $0.00
Office
Equipment Monitor Energy Star 0.03 $0.01 4 0.99 $0.04
Office
Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00
Office
Equipment Printer/copier/fax Energy Star 0.02 $0.01 6 0.96 $0.06
Office
Equipment POS Terminal Standard - $0.00 4 1.00 $0.00
Office
Equipment POS Terminal Energy Star 0.00 $0.00 4 0.99 $0.05
Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00
Miscellaneous Non-HVAC Motor Standard (2015) 0.00 $0.06 15 - $1.06
Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00
Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.04 $0.06 15 0.97 $0.12
Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00
Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1020 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-44 www.enernoc.com
Table C-14 Energy Efficiency Equipment Data, Electric— Extra Large Commercial, New
Vintage, Idaho
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Cooling Central Chiller Variable Refrigerant
Flow 1.01 $10.92 20 0.15 $0.77
Cooling RTU EER 9.2 - $0.00 16 - $0.00
Cooling RTU EER 10.1 0.19 $0.24 16 - $0.10
Cooling RTU EER 11.2 0.38 $0.44 16 1.00 $0.10
Cooling RTU EER 12.0 0.49 $0.73 16 0.89 $0.12
Cooling RTU Ductless VRF 0.60 $6.51 16 0.26 $0.90
Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Cooling Heat Pump EER 10.3, COP 3.2 0.17 $0.24 15 - $0.12
Cooling Heat Pump EER 11.0, COP 3.3 0.28 $0.73 15 1.00 $0.23
Cooling Heat Pump EER 11.7, COP 3.4 0.37 $0.97 15 0.97 $0.23
Cooling Heat Pump EER 12, COP 3.4 0.41 $1.21 15 0.94 $0.26
Cooling Heat Pump Ductless Mini-Split
System 0.45 $7.10 20 0.53 $1.12
Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00
Space Heating Furnace Standard - $0.00 18 1.00 $0.00
Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00
Ventilation Ventilation Variable Air Volume 2.23 $1.22 15 1.05 $0.05
Interior
Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00
Interior
Lighting Interior Screw-in Infrared Halogen 0.87 $0.14 1 1.00 $0.16
Interior
Lighting Interior Screw-in CFL 3.61 $0.06 4 5.48 $0.00
Interior
Lighting Interior Screw-in LED 3.99 $1.90 12 - $0.05
Interior
Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00
Interior
Lighting High Bay Fixtures High Pressure Sodium 0.10 -$0.05 9 2.26 -$0.07
Interior
Lighting High Bay Fixtures T8 0.10 -$0.11 6 5.77 -$0.19
Interior
Lighting High Bay Fixtures T5 0.13 -$0.10 6 6.31 -$0.15
Interior
Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting Linear Fluorescent T8 0.22 -$0.03 6 1.12 -$0.02
Interior
Lighting Linear Fluorescent Super T8 0.66 $0.21 6 0.87 $0.06
Interior
Lighting Linear Fluorescent T5 0.68 $0.35 6 0.73 $0.09
Interior
Lighting Linear Fluorescent LED 0.72 $3.08 15 - $0.37
Exterior
Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00
Exterior
Lighting Exterior Screw-in Infrared Halogen 0.01 $0.00 1 1.00 $0.38
Exterior
Lighting Exterior Screw-in CFL 0.04 $0.00 4 6.58 $0.01
Exterior
Lighting Exterior Screw-in Metal Halides 0.04 $0.00 4 3.32 $0.03
Exterior
Lighting Exterior Screw-in LED 0.04 $0.05 12 - $0.12
Exterior
Lighting HID Metal Halides - $0.00 6 1.00 $0.00
Exterior
Lighting HID High Pressure Sodium 0.19 -$0.16 9 2.09 -$0.10
Exterior
Lighting HID Low Pressure Sodium 0.21 $0.64 9 0.57 $0.40
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1021 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-45
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Water
Heating Water Heater Baseline (EF=0.90) - $0.00 15 1.00 $0.00
Water
Heating Water Heater High Efficiency
(EF=0.95) 0.20 $0.02 15 1.03 $0.01
Water
Heating Water Heater EF 2.0 1.98 -$0.48 15 2.54 -$0.02
Water
Heating Water Heater EF 2.3 2.22 -$0.47 15 2.92 -$0.02
Water
Heating Water Heater EF 2.4 2.29 -$0.47 15 3.04 -$0.02
Water
Heating Water Heater Geothermal Heat Pump 2.62 $3.53 15 0.52 $0.12
Water
Heating Water Heater Solar 2.88 $3.03 15 0.60 $0.09
Food
Preparation Fryer Standard - $0.00 12 1.00 $0.00
Food
Preparation Fryer Efficient 0.03 $0.00 12 1.11 $0.02
Food
Preparation Oven Standard - $0.00 12 1.00 $0.00
Food
Preparation Oven Efficient 0.84 $0.38 12 0.99 $0.05
Food
Preparation Dishwasher Standard - $0.00 12 1.00 $0.00
Food
Preparation Dishwasher Efficient 0.03 $0.04 12 0.88 $0.18
Food
Preparation Hot Food Container Standard - $0.00 12 1.00 $0.00
Food
Preparation Hot Food Container Efficient 0.10 $0.22 12 0.65 $0.22
Food
Preparation Food Prep Standard - $0.00 12 1.00 $0.00
Food
Preparation Food Prep Efficient 0.00 $0.03 12 0.88 $0.62
Refrigeration Walk in Refrigeration Standard - $0.00 18 1.00 $0.00
Refrigeration Walk in Refrigeration Efficient 0.04 $0.05 18 0.95 $0.08
Refrigeration Glass Door Display Standard - $0.00 18 1.00 $0.00
Refrigeration Glass Door Display Efficient 0.04 $0.00 18 1.39 $0.00
Refrigeration Reach-in Refrigerator Standard - $0.00 18 1.00 $0.00
Refrigeration Reach-in Refrigerator Efficient 0.21 $0.02 18 1.19 $0.01
Refrigeration Open Display Case Standard - $0.00 18 1.00 $0.00
Refrigeration Open Display Case Efficient 0.01 $0.03 18 0.93 $0.25
Refrigeration Vending Machine Base - $0.00 10 - $0.00
Refrigeration Vending Machine Base (2012) 0.10 $0.00 10 1.00 $0.00
Refrigeration Vending Machine High Efficiency 0.12 $0.00 10 - $0.00
Refrigeration Vending Machine High Efficiency (2012) 0.18 $0.00 10 1.20 $0.00
Refrigeration Icemaker Standard - $0.00 12 1.00 $0.00
Refrigeration Icemaker Efficient 0.04 $0.00 12 1.12 $0.01
Office
Equipment Desktop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Desktop Computer Energy Star 0.28 $0.00 4 1.02 $0.00
Office
Equipment Desktop Computer Climate Savers 0.39 $0.33 4 0.86 $0.22
Office
Equipment Laptop Computer Baseline - $0.00 4 1.00 $0.00
Office
Equipment Laptop Computer Energy Star 0.03 $0.00 4 1.00 $0.01
Office
Equipment Laptop Computer Climate Savers 0.04 $0.10 4 0.84 $0.61
Office
Equipment Server Standard - $0.00 3 1.00 $0.00
Office Server Energy Star 0.05 $0.00 3 1.00 $0.03
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1022 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-46 www.enernoc.com
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Equipment
Office
Equipment Monitor Standard - $0.00 4 1.00 $0.00
Office
Equipment Monitor Energy Star 0.03 $0.01 4 0.99 $0.04
Office
Equipment Printer/copier/fax Standard - $0.00 6 1.00 $0.00
Office
Equipment Printer/copier/fax Energy Star 0.02 $0.01 6 0.96 $0.06
Office
Equipment POS Terminal Standard - $0.00 4 1.00 $0.00
Office
Equipment POS Terminal Energy Star 0.00 $0.00 4 0.99 $0.05
Miscellaneous Non-HVAC Motor Standard - $0.00 15 - $0.00
Miscellaneous Non-HVAC Motor Standard (2015) 0.00 $0.06 15 - $1.06
Miscellaneous Non-HVAC Motor High Efficiency 0.01 $0.00 15 1.00 $0.00
Miscellaneous Non-HVAC Motor High Efficiency (2015) 0.04 $0.06 15 0.97 $0.12
Miscellaneous Non-HVAC Motor Premium - $0.00 0 - $0.00
Miscellaneous Non-HVAC Motor Premium (2015) - $0.00 0 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous - $0.00 5 - $0.00
Miscellaneous Other Miscellaneous Miscellaneous (2013) 0.00 $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1023 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-47
Table C-15 Energy Efficiency Equipment Data, Electric—Extra Large Industrial,
Existing Vintage, Washington
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Cooling Central Chiller 0.75 kw/ton, COP 4.7 - $0.00 20 - $0.00
Cooling Central Chiller 0.60 kw/ton, COP 5.9 1.69 $0.33 20 1.10 $0.01
Cooling Central Chiller 0.58 kw/ton, COP 6.1 1.91 $0.66 20 0.97 $0.02
Cooling Central Chiller 0.55 kw/Ton, COP 6.4 2.25 $0.93 20 0.95 $0.03
Cooling Central Chiller 0.51 kw/ton, COP 6.9 2.70 $1.59 20 0.90 $0.04
Cooling Central Chiller 0.50 kw/Ton, COP 7.0 2.81 $1.92 20 0.87 $0.05
Cooling Central Chiller 0.48 kw/ton, COP 7.3 3.04 $2.25 20 0.84 $0.05
Cooling Central Chiller Variable Refrigerant
Flow 3.92 $39.62 20 0.15 $0.72
Cooling RTU EER 9.2 - $0.00 16 - $0.00
Cooling RTU EER 10.1 0.56 $0.39 16 - $0.06
Cooling RTU EER 11.2 1.12 $0.73 16 1.00 $0.05
Cooling RTU EER 12.0 1.47 $1.22 16 0.92 $0.07
Cooling RTU Ductless VRF 1.79 $10.83 16 0.31 $0.50
Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Cooling Heat Pump EER 10.3, COP 3.2 0.41 $0.92 15 - $0.19
Cooling Heat Pump EER 11.0, COP 3.3 0.65 $2.75 15 1.00 $0.36
Cooling Heat Pump EER 11.7, COP 3.4 0.87 $3.66 15 0.95 $0.36
Cooling Heat Pump EER 12, COP 3.4 0.95 $4.58 15 0.90 $0.42
Cooling Heat Pump Ductless Mini-Split
System 1.06 $26.86 20 0.45 $1.80
Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00
Space Heating Furnace Standard - $0.00 18 1.00 $0.00
Space Heating Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Space Heating Heat Pump EER 10.3, COP 3.2 0.13 $0.92 15 - $0.61
Space Heating Heat Pump EER 11.0, COP 3.3 0.25 $2.75 15 1.00 $0.95
Space Heating Heat Pump EER 11.7, COP 3.4 0.37 $3.66 15 0.95 $0.87
Space Heating Heat Pump EER 12, COP 3.4 0.47 $4.58 15 0.90 $0.84
Space Heating Heat Pump Ductless Mini-Split
System 1.04 $26.86 20 0.45 $1.83
Space Heating Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Space Heating Heat Pump EER 10.3, COP 3.2 0.13 $0.92 15 - $0.61
Space Heating Heat Pump EER 11.0, COP 3.3 0.25 $2.75 15 1.00 $0.95
Space Heating Heat Pump EER 11.7, COP 3.4 0.37 $3.66 15 0.95 $0.87
Space Heating Heat Pump EER 12, COP 3.4 0.47 $4.58 15 0.90 $0.84
Space Heating Heat Pump Ductless Mini-Split
System 1.04 $26.86 20 0.45 $1.83
Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00
Ventilation Ventilation Variable Air Volume 8.88 $1.22 15 1.46 $0.01
Interior
Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00
Interior
Lighting Interior Screw-in Infrared Halogen 0.18 $0.04 1 1.00 $0.20
Interior
Lighting Interior Screw-in CFL 0.76 $0.02 4 5.79 $0.01
Interior
Lighting Interior Screw-in LED 0.84 $0.52 12 - $0.06
Interior
Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00
Interior
Lighting High Bay Fixtures High Pressure Sodium 0.40 -$0.14 9 2.11 -$0.04
Interior
Lighting High Bay Fixtures T8 0.40 -$0.28 6 4.58 -$0.13
Interior
Lighting High Bay Fixtures T5 0.51 -$0.28 6 5.58 -$0.10
Interior
Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting Linear Fluorescent T8 0.09 -$0.01 6 1.12 -$0.02
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1024 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-48 www.enernoc.com
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Interior
Lighting Linear Fluorescent Super T8 0.26 $0.08 6 0.88 $0.06
Interior
Lighting Linear Fluorescent T5 0.27 $0.14 6 0.74 $0.09
Interior
Lighting Linear Fluorescent LED 0.29 $1.21 15 - $0.37
Exterior
Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00
Exterior
Lighting Exterior Screw-in Infrared Halogen 0.01 $0.00 1 1.00 $0.24
Exterior
Lighting Exterior Screw-in CFL 0.04 $0.00 4 6.00 $0.01
Exterior
Lighting Exterior Screw-in Metal Halides 0.04 $0.00 4 3.36 $0.02
Exterior
Lighting Exterior Screw-in LED 0.04 $0.03 12 - $0.07
Exterior
Lighting HID Metal Halides - $0.00 6 1.00 $0.00
Exterior
Lighting HID High Pressure Sodium 0.05 -$0.04 9 2.10 -$0.11
Exterior
Lighting HID Low Pressure Sodium 0.06 $0.18 9 0.57 $0.42
Process Process
Cooling/Refrigeration Standard - $0.00 10 1.00 $0.00
Process Process
Cooling/Refrigeration Efficient 18.88 $5.59 10 1.23 $0.04
Process Process Heating Standard - $0.00 10 1.00 $0.00
Process Electrochemical
Process Standard - $0.00 10 1.00 $0.00
Process Electrochemical
Process Efficient 13.16 $2.64 10 1.20 $0.02
Machine
Drive Less than 5 HP Standard - $0.00 15 - $0.00
Machine
Drive Less than 5 HP High Efficiency 0.00 $0.06 15 - $0.99
Machine
Drive Less than 5 HP Standard (2015) 0.01 $0.00 15 1.00 $0.00
Machine
Drive Less than 5 HP Premium 0.04 $0.06 15 1.04 $0.11
Machine
Drive Less than 5 HP High Efficiency (2015) - $0.00 0 - $0.00
Machine
Drive Less than 5 HP Premium (2015) - $0.00 0 - $0.00
Machine
Drive 5-24 HP Standard - $0.00 10 1.00 $0.00
Machine
Drive 5-24 HP High 0.01 $0.02 10 1.01 $0.17
Machine
Drive 5-24 HP Premium - $0.00 0 - $0.00
Machine
Drive 25-99 HP Standard - $0.00 10 1.00 $0.00
Machine
Drive 25-99 HP High 0.03 $0.02 10 1.01 $0.06
Machine
Drive 25-99 HP Premium - $0.00 0 - $0.00
Machine
Drive 100-249 HP Standard - $0.00 10 1.00 $0.00
Machine
Drive 100-249 HP High 0.02 $0.02 10 1.01 $0.10
Machine
Drive 100-249 HP Premium - $0.00 0 - $0.00
Machine
Drive 250-499 HP Standard - $0.00 10 1.00 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1025 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-49
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Machine
Drive 250-499 HP High 0.06 $0.02 10 1.01 $0.03
Machine
Drive 250-499 HP Premium - $0.00 0 - $0.00
Machine
Drive 500 and more HP Standard - $0.00 10 1.00 $0.00
Machine
Drive 500 and more HP High 0.10 $0.02 10 1.01 $0.02
Machine
Drive 500 and more HP Premium - $0.00 0 - $0.00
Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1026 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-50 www.enernoc.com
Table C-16 Energy Efficiency Equipment Data, Electric— Extra Large Industrial, New
Vintage, Washington
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Cooling Central Chiller 0.75 kw/ton, COP 4.7 - $0.00 20 - $0.00
Cooling Central Chiller 0.60 kw/ton, COP 5.9 1.58 $0.33 20 1.10 $0.01
Cooling Central Chiller 0.58 kw/ton, COP 6.1 1.79 $0.66 20 0.97 $0.03
Cooling Central Chiller 0.55 kw/Ton, COP 6.4 2.11 $0.93 20 0.95 $0.03
Cooling Central Chiller 0.51 kw/ton, COP 6.9 2.53 $1.59 20 0.89 $0.04
Cooling Central Chiller 0.50 kw/Ton, COP 7.0 2.63 $1.92 20 0.86 $0.05
Cooling Central Chiller 0.48 kw/ton, COP 7.3 2.84 $2.25 20 0.83 $0.06
Cooling Central Chiller Variable Refrigerant
Flow 3.67 $39.62 20 0.15 $0.76
Cooling RTU EER 9.2 - $0.00 16 - $0.00
Cooling RTU EER 10.1 0.56 $0.39 16 - $0.06
Cooling RTU EER 11.2 1.12 $0.74 16 1.00 $0.05
Cooling RTU EER 12.0 1.47 $1.23 16 0.92 $0.07
Cooling RTU Ductless VRF 1.79 $10.88 16 0.30 $0.50
Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Cooling Heat Pump EER 10.3, COP 3.2 0.39 $0.92 15 - $0.20
Cooling Heat Pump EER 11.0, COP 3.3 0.62 $2.75 15 1.00 $0.38
Cooling Heat Pump EER 11.7, COP 3.4 0.83 $3.66 15 0.95 $0.38
Cooling Heat Pump EER 12, COP 3.4 0.91 $4.58 15 0.90 $0.43
Cooling Heat Pump Ductless Mini-Split
System 1.01 $26.86 20 0.45 $1.88
Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00
Space Heating Furnace Standard - $0.00 18 1.00 $0.00
Space Heating Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Space Heating Heat Pump EER 10.3, COP 3.2 0.13 $0.92 15 - $0.62
Space Heating Heat Pump EER 11.0, COP 3.3 0.25 $2.75 15 1.00 $0.96
Space Heating Heat Pump EER 11.7, COP 3.4 0.36 $3.66 15 0.95 $0.88
Space Heating Heat Pump EER 12, COP 3.4 0.47 $4.58 15 0.90 $0.85
Space Heating Heat Pump Ductless Mini-Split
System 1.02 $26.86 20 0.45 $1.86
Space Heating Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Space Heating Heat Pump EER 10.3, COP 3.2 0.13 $0.92 15 - $0.62
Space Heating Heat Pump EER 11.0, COP 3.3 0.25 $2.75 15 1.00 $0.96
Space Heating Heat Pump EER 11.7, COP 3.4 0.36 $3.66 15 0.95 $0.88
Space Heating Heat Pump EER 12, COP 3.4 0.47 $4.58 15 0.90 $0.85
Space Heating Heat Pump Ductless Mini-Split
System 1.02 $26.86 20 0.45 $1.86
Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00
Ventilation Ventilation Variable Air Volume 13.69 $1.22 15 1.63 $0.01
Interior
Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00
Interior
Lighting Interior Screw-in Infrared Halogen 0.21 $0.04 1 1.00 $0.18
Interior
Lighting Interior Screw-in CFL 0.85 $0.02 4 5.65 $0.00
Interior
Lighting Interior Screw-in LED 0.94 $0.52 12 - $0.06
Interior
Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00
Interior
Lighting High Bay Fixtures High Pressure Sodium 0.40 -$0.14 9 2.11 -$0.04
Interior
Lighting High Bay Fixtures T8 0.40 -$0.28 6 4.58 -$0.13
Interior
Lighting High Bay Fixtures T5 0.51 -$0.28 6 5.58 -$0.10
Interior
Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting Linear Fluorescent T8 0.09 -$0.01 6 1.12 -$0.02
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1027 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-51
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Interior
Lighting Linear Fluorescent Super T8 0.27 $0.08 6 0.89 $0.06
Interior
Lighting Linear Fluorescent T5 0.28 $0.14 6 0.75 $0.09
Interior
Lighting Linear Fluorescent LED 0.29 $1.21 15 - $0.36
Exterior
Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00
Exterior
Lighting Exterior Screw-in Infrared Halogen 0.01 $0.00 1 1.00 $0.24
Exterior
Lighting Exterior Screw-in CFL 0.04 $0.00 4 6.00 $0.01
Exterior
Lighting Exterior Screw-in Metal Halides 0.04 $0.00 4 3.36 $0.02
Exterior
Lighting Exterior Screw-in LED 0.04 $0.03 12 - $0.07
Exterior
Lighting HID Metal Halides - $0.00 6 1.00 $0.00
Exterior
Lighting HID High Pressure Sodium 0.05 -$0.04 9 2.10 -$0.11
Exterior
Lighting HID Low Pressure Sodium 0.06 $0.18 9 0.57 $0.42
Process Process
Cooling/Refrigeration Standard - $0.00 10 1.00 $0.00
Process Process
Cooling/Refrigeration Efficient 18.88 $5.59 10 1.23 $0.04
Process Process Heating Standard - $0.00 10 1.00 $0.00
Process Electrochemical
Process Standard - $0.00 10 1.00 $0.00
Process Electrochemical
Process Efficient 13.16 $2.64 10 1.20 $0.02
Machine
Drive Less than 5 HP Standard - $0.00 15 - $0.00
Machine
Drive Less than 5 HP High Efficiency 0.00 $0.06 15 - $0.99
Machine
Drive Less than 5 HP Standard (2015) 0.01 $0.00 15 1.00 $0.00
Machine
Drive Less than 5 HP Premium 0.04 $0.06 15 1.04 $0.11
Machine
Drive Less than 5 HP High Efficiency (2015) - $0.00 0 - $0.00
Machine
Drive Less than 5 HP Premium (2015) - $0.00 0 - $0.00
Machine
Drive 5-24 HP Standard - $0.00 10 1.00 $0.00
Machine
Drive 5-24 HP High 0.01 $0.02 10 1.01 $0.17
Machine
Drive 5-24 HP Premium - $0.00 0 - $0.00
Machine
Drive 25-99 HP Standard - $0.00 10 1.00 $0.00
Machine
Drive 25-99 HP High 0.03 $0.02 10 1.01 $0.06
Machine
Drive 25-99 HP Premium - $0.00 0 - $0.00
Machine
Drive 100-249 HP Standard - $0.00 10 1.00 $0.00
Machine
Drive 100-249 HP High 0.02 $0.02 10 1.01 $0.10
Machine
Drive 100-249 HP Premium - $0.00 0 - $0.00
Machine
Drive 250-499 HP Standard - $0.00 10 1.00 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1028 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-52 www.enernoc.com
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Machine
Drive 250-499 HP High 0.06 $0.02 10 1.01 $0.03
Machine
Drive 250-499 HP Premium - $0.00 0 - $0.00
Machine
Drive 500 and more HP Standard - $0.00 10 1.00 $0.00
Machine
Drive 500 and more HP High 0.10 $0.02 10 1.01 $0.02
Machine
Drive 500 and more HP Premium - $0.00 0 - $0.00
Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1029 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-53
Table C-17 Energy Efficiency Equipment Data, Electric—Extra Large Industrial,
Existing Vintage, Idaho
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Cooling Central Chiller 0.75 kw/ton, COP 4.7 - $0.00 20 - $0.00
Cooling Central Chiller 0.60 kw/ton, COP 5.9 1.69 $0.33 20 1.10 $0.01
Cooling Central Chiller 0.58 kw/ton, COP 6.1 1.91 $0.66 20 0.97 $0.02
Cooling Central Chiller 0.55 kw/Ton, COP 6.4 2.25 $0.93 20 0.95 $0.03
Cooling Central Chiller 0.51 kw/ton, COP 6.9 2.70 $1.59 20 0.90 $0.04
Cooling Central Chiller 0.50 kw/Ton, COP 7.0 2.81 $1.92 20 0.87 $0.05
Cooling Central Chiller 0.48 kw/ton, COP 7.3 3.04 $2.25 20 0.84 $0.05
Cooling Central Chiller Variable Refrigerant
Flow 3.92 $39.62 20 0.15 $0.72
Cooling RTU EER 9.2 - $0.00 16 - $0.00
Cooling RTU EER 10.1 0.56 $0.39 16 - $0.06
Cooling RTU EER 11.2 1.12 $0.73 16 1.00 $0.05
Cooling RTU EER 12.0 1.47 $1.22 16 0.92 $0.07
Cooling RTU Ductless VRF 1.79 $10.83 16 0.31 $0.50
Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Cooling Heat Pump EER 10.3, COP 3.2 0.41 $0.92 15 - $0.19
Cooling Heat Pump EER 11.0, COP 3.3 0.65 $2.75 15 1.00 $0.36
Cooling Heat Pump EER 11.7, COP 3.4 0.87 $3.66 15 0.95 $0.36
Cooling Heat Pump EER 12, COP 3.4 0.95 $4.58 15 0.90 $0.42
Cooling Heat Pump Ductless Mini-Split
System 1.06 $26.86 20 0.45 $1.80
Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00
Space Heating Furnace Standard - $0.00 18 1.00 $0.00
Space Heating Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Space Heating Heat Pump EER 10.3, COP 3.2 0.13 $0.92 15 - $0.61
Space Heating Heat Pump EER 11.0, COP 3.3 0.25 $2.75 15 1.00 $0.95
Space Heating Heat Pump EER 11.7, COP 3.4 0.37 $3.66 15 0.95 $0.87
Space Heating Heat Pump EER 12, COP 3.4 0.47 $4.58 15 0.90 $0.84
Space Heating Heat Pump Ductless Mini-Split
System 1.04 $26.86 20 0.45 $1.83
Space Heating Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Space Heating Heat Pump EER 10.3, COP 3.2 0.13 $0.92 15 - $0.61
Space Heating Heat Pump EER 11.0, COP 3.3 0.25 $2.75 15 1.00 $0.95
Space Heating Heat Pump EER 11.7, COP 3.4 0.37 $3.66 15 0.95 $0.87
Space Heating Heat Pump EER 12, COP 3.4 0.47 $4.58 15 0.90 $0.84
Space Heating Heat Pump Ductless Mini-Split
System 1.04 $26.86 20 0.45 $1.83
Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00
Ventilation Ventilation Variable Air Volume 8.88 $1.22 15 1.46 $0.01
Interior
Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00
Interior
Lighting Interior Screw-in Infrared Halogen 0.18 $0.04 1 1.00 $0.20
Interior
Lighting Interior Screw-in CFL 0.76 $0.02 4 5.79 $0.01
Interior
Lighting Interior Screw-in LED 0.84 $0.52 12 - $0.06
Interior
Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00
Interior
Lighting High Bay Fixtures High Pressure Sodium 0.40 -$0.14 9 2.11 -$0.04
Interior
Lighting High Bay Fixtures T8 0.40 -$0.28 6 4.58 -$0.13
Interior
Lighting High Bay Fixtures T5 0.51 -$0.28 6 5.58 -$0.10
Interior
Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting Linear Fluorescent T8 0.09 -$0.01 6 1.12 -$0.02
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1030 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-54 www.enernoc.com
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Interior
Lighting Linear Fluorescent Super T8 0.26 $0.08 6 0.88 $0.06
Interior
Lighting Linear Fluorescent T5 0.27 $0.14 6 0.74 $0.09
Interior
Lighting Linear Fluorescent LED 0.29 $1.21 15 - $0.37
Exterior
Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00
Exterior
Lighting Exterior Screw-in Infrared Halogen 0.01 $0.00 1 1.00 $0.24
Exterior
Lighting Exterior Screw-in CFL 0.04 $0.00 4 6.00 $0.01
Exterior
Lighting Exterior Screw-in Metal Halides 0.04 $0.00 4 3.36 $0.02
Exterior
Lighting Exterior Screw-in LED 0.04 $0.03 12 - $0.07
Exterior
Lighting HID Metal Halides - $0.00 6 1.00 $0.00
Exterior
Lighting HID High Pressure Sodium 0.05 -$0.04 9 2.10 -$0.11
Exterior
Lighting HID Low Pressure Sodium 0.06 $0.18 9 0.57 $0.42
Process Process
Cooling/Refrigeration Standard - $0.00 10 1.00 $0.00
Process Process
Cooling/Refrigeration Efficient 18.88 $5.59 10 1.23 $0.04
Process Process Heating Standard - $0.00 10 1.00 $0.00
Process Electrochemical
Process Standard - $0.00 10 1.00 $0.00
Process Electrochemical
Process Efficient 13.16 $2.64 10 1.20 $0.02
Machine
Drive Less than 5 HP Standard - $0.00 15 - $0.00
Machine
Drive Less than 5 HP High Efficiency 0.00 $0.06 15 - $0.99
Machine
Drive Less than 5 HP Standard (2015) 0.01 $0.00 15 1.00 $0.00
Machine
Drive Less than 5 HP Premium 0.04 $0.06 15 1.04 $0.11
Machine
Drive Less than 5 HP High Efficiency (2015) - $0.00 0 - $0.00
Machine
Drive Less than 5 HP Premium (2015) - $0.00 0 - $0.00
Machine
Drive 5-24 HP Standard - $0.00 10 1.00 $0.00
Machine
Drive 5-24 HP High 0.01 $0.02 10 1.01 $0.17
Machine
Drive 5-24 HP Premium - $0.00 0 - $0.00
Machine
Drive 25-99 HP Standard - $0.00 10 1.00 $0.00
Machine
Drive 25-99 HP High 0.03 $0.02 10 1.01 $0.06
Machine
Drive 25-99 HP Premium - $0.00 0 - $0.00
Machine
Drive 100-249 HP Standard - $0.00 10 1.00 $0.00
Machine
Drive 100-249 HP High 0.02 $0.02 10 1.01 $0.10
Machine
Drive 100-249 HP Premium - $0.00 0 - $0.00
Machine
Drive 250-499 HP Standard - $0.00 10 1.00 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1031 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-55
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Machine
Drive 250-499 HP High 0.06 $0.02 10 1.01 $0.03
Machine
Drive 250-499 HP Premium - $0.00 0 - $0.00
Machine
Drive 500 and more HP Standard - $0.00 10 1.00 $0.00
Machine
Drive 500 and more HP High 0.10 $0.02 10 1.01 $0.02
Machine
Drive 500 and more HP Premium - $0.00 0 - $0.00
Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1032 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-56 www.enernoc.com
Table C-18 Energy Efficiency Equipment Data, Electric— Extra Large Industrial, New
Vintage, Idaho
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Cooling Central Chiller 0.75 kw/ton, COP 4.7 - $0.00 20 - $0.00
Cooling Central Chiller 0.60 kw/ton, COP 5.9 1.58 $0.33 20 1.10 $0.01
Cooling Central Chiller 0.58 kw/ton, COP 6.1 1.79 $0.66 20 0.97 $0.03
Cooling Central Chiller 0.55 kw/Ton, COP 6.4 2.11 $0.93 20 0.95 $0.03
Cooling Central Chiller 0.51 kw/ton, COP 6.9 2.53 $1.59 20 0.89 $0.04
Cooling Central Chiller 0.50 kw/Ton, COP 7.0 2.63 $1.92 20 0.86 $0.05
Cooling Central Chiller 0.48 kw/ton, COP 7.3 2.84 $2.25 20 0.83 $0.06
Cooling Central Chiller Variable Refrigerant
Flow 3.67 $39.62 20 0.15 $0.76
Cooling RTU EER 9.2 - $0.00 16 - $0.00
Cooling RTU EER 10.1 0.56 $0.39 16 - $0.06
Cooling RTU EER 11.2 1.12 $0.74 16 1.00 $0.05
Cooling RTU EER 12.0 1.47 $1.23 16 0.92 $0.07
Cooling RTU Ductless VRF 1.79 $10.88 16 0.30 $0.50
Cooling Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Cooling Heat Pump EER 10.3, COP 3.2 0.39 $0.92 15 - $0.20
Cooling Heat Pump EER 11.0, COP 3.3 0.62 $2.75 15 1.00 $0.38
Cooling Heat Pump EER 11.7, COP 3.4 0.83 $3.66 15 0.95 $0.38
Cooling Heat Pump EER 12, COP 3.4 0.91 $4.58 15 0.90 $0.43
Cooling Heat Pump Ductless Mini-Split
System 1.01 $26.86 20 0.45 $1.88
Space Heating Electric Resistance Standard - $0.00 25 1.00 $0.00
Space Heating Furnace Standard - $0.00 18 1.00 $0.00
Space Heating Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Space Heating Heat Pump EER 10.3, COP 3.2 0.13 $0.92 15 - $0.62
Space Heating Heat Pump EER 11.0, COP 3.3 0.25 $2.75 15 1.00 $0.96
Space Heating Heat Pump EER 11.7, COP 3.4 0.36 $3.66 15 0.95 $0.88
Space Heating Heat Pump EER 12, COP 3.4 0.47 $4.58 15 0.90 $0.85
Space Heating Heat Pump Ductless Mini-Split
System 1.02 $26.86 20 0.45 $1.86
Space Heating Heat Pump EER 9.3, COP 3.1 - $0.00 15 - $0.00
Space Heating Heat Pump EER 10.3, COP 3.2 0.13 $0.92 15 - $0.62
Space Heating Heat Pump EER 11.0, COP 3.3 0.25 $2.75 15 1.00 $0.96
Space Heating Heat Pump EER 11.7, COP 3.4 0.36 $3.66 15 0.95 $0.88
Space Heating Heat Pump EER 12, COP 3.4 0.47 $4.58 15 0.90 $0.85
Space Heating Heat Pump Ductless Mini-Split
System 1.02 $26.86 20 0.45 $1.86
Ventilation Ventilation Constant Volume - $0.00 15 1.00 $0.00
Ventilation Ventilation Variable Air Volume 13.69 $1.22 15 1.63 $0.01
Interior
Lighting Interior Screw-in Incandescents - $0.00 1 - $0.00
Interior
Lighting Interior Screw-in Infrared Halogen 0.21 $0.04 1 1.00 $0.18
Interior
Lighting Interior Screw-in CFL 0.85 $0.02 4 5.65 $0.00
Interior
Lighting Interior Screw-in LED 0.94 $0.52 12 - $0.06
Interior
Lighting High Bay Fixtures Metal Halides - $0.00 6 1.00 $0.00
Interior
Lighting High Bay Fixtures High Pressure Sodium 0.40 -$0.14 9 2.11 -$0.04
Interior
Lighting High Bay Fixtures T8 0.40 -$0.28 6 4.58 -$0.13
Interior
Lighting High Bay Fixtures T5 0.51 -$0.28 6 5.58 -$0.10
Interior
Lighting Linear Fluorescent T12 - $0.00 6 1.00 $0.00
Interior
Lighting Linear Fluorescent T8 0.09 -$0.01 6 1.12 -$0.02
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1033 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-57
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Interior
Lighting Linear Fluorescent Super T8 0.27 $0.08 6 0.89 $0.06
Interior
Lighting Linear Fluorescent T5 0.28 $0.14 6 0.75 $0.09
Interior
Lighting Linear Fluorescent LED 0.29 $1.21 15 - $0.36
Exterior
Lighting Exterior Screw-in Incandescent - $0.00 1 - $0.00
Exterior
Lighting Exterior Screw-in Infrared Halogen 0.01 $0.00 1 1.00 $0.24
Exterior
Lighting Exterior Screw-in CFL 0.04 $0.00 4 6.00 $0.01
Exterior
Lighting Exterior Screw-in Metal Halides 0.04 $0.00 4 3.36 $0.02
Exterior
Lighting Exterior Screw-in LED 0.04 $0.03 12 - $0.07
Exterior
Lighting HID Metal Halides - $0.00 6 1.00 $0.00
Exterior
Lighting HID High Pressure Sodium 0.05 -$0.04 9 2.10 -$0.11
Exterior
Lighting HID Low Pressure Sodium 0.06 $0.18 9 0.57 $0.42
Process Process
Cooling/Refrigeration Standard - $0.00 10 1.00 $0.00
Process Process
Cooling/Refrigeration Efficient 18.88 $5.59 10 1.23 $0.04
Process Process Heating Standard - $0.00 10 1.00 $0.00
Process Electrochemical
Process Standard - $0.00 10 1.00 $0.00
Process Electrochemical
Process Efficient 13.16 $2.64 10 1.20 $0.02
Machine
Drive Less than 5 HP Standard - $0.00 15 - $0.00
Machine
Drive Less than 5 HP High Efficiency 0.00 $0.06 15 - $0.99
Machine
Drive Less than 5 HP Standard (2015) 0.01 $0.00 15 1.00 $0.00
Machine
Drive Less than 5 HP Premium 0.04 $0.06 15 1.04 $0.11
Machine
Drive Less than 5 HP High Efficiency (2015) - $0.00 0 - $0.00
Machine
Drive Less than 5 HP Premium (2015) - $0.00 0 - $0.00
Machine
Drive 5-24 HP Standard - $0.00 10 1.00 $0.00
Machine
Drive 5-24 HP High 0.01 $0.02 10 1.01 $0.17
Machine
Drive 5-24 HP Premium - $0.00 0 - $0.00
Machine
Drive 25-99 HP Standard - $0.00 10 1.00 $0.00
Machine
Drive 25-99 HP High 0.03 $0.02 10 1.01 $0.06
Machine
Drive 25-99 HP Premium - $0.00 0 - $0.00
Machine
Drive 100-249 HP Standard - $0.00 10 1.00 $0.00
Machine
Drive 100-249 HP High 0.02 $0.02 10 1.01 $0.10
Machine
Drive 100-249 HP Premium - $0.00 0 - $0.00
Machine
Drive 250-499 HP Standard - $0.00 10 1.00 $0.00
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1034 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-58 www.enernoc.com
End Use Technology Efficiency Definition
Savings
(kWh/SQ
FT/yr)
Incremental
Cost ($/SQ
FT)
Lifetime
(Years)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Machine
Drive 250-499 HP High 0.06 $0.02 10 1.01 $0.03
Machine
Drive 250-499 HP Premium - $0.00 0 - $0.00
Machine
Drive 500 and more HP Standard - $0.00 10 1.00 $0.00
Machine
Drive 500 and more HP High 0.10 $0.02 10 1.01 $0.02
Machine
Drive 500 and more HP Premium - $0.00 0 - $0.00
Miscellaneous Miscellaneous Miscellaneous - $0.00 5 1.00 $0.00

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1035 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-59
Table C-19 Energy Efficiency Non-Equipment Data—Small/Medium Commercial,
Existing Vintage, Washington
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/Sq
Ft)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
RTU - Maintenance 14.0% 100.0% 4 $0.08 0.4 0.22 $0.060
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.2 0.21 $0.061
Chiller - Chilled Water Reset 0.0% 0.0% 4 $0.86 0.4 0.03 $0.529
Chiller - Chilled Water Variable-Flow
System 0.0% 0.0% 10 $0.86 0.1 0.02 $1.018
Chiller - VSD 0.0% 0.0% 20 $1.17 0.8 0.11 $0.105
Chiller - High Efficiency Cooling Tower
Fans 0.0% 0.0% 10 $0.04 0.0 0.00 $10.961
Chiller - Condenser Water Temprature
Reset 0.0% 0.0% 14 $0.87 0.4 0.07 $0.206
Cooling - Economizer Installation 51.8% 65.0% 15 $0.15 0.6 0.64 $0.020
Heat Pump - Maintenance 28.1% 100.0% 4 $0.03 0.9 1.42 $0.009
Insulation - Ducting 9.0% 100.0% 20 $0.41 0.2 0.36 $0.136
Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.7 0.47 $0.048
Energy Management System 34.8% 100.0% 14 $0.35 0.8 0.37 $0.040
Cooking - Exhaust Hoods with Sensor
Control 1.0% 20.0% 10 $0.04 - - $0.000
Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.25 $0.057
Fans - Variable Speed Control 10.9% 100.0% 10 $0.20 0.7 0.32 $0.033
Retrocommissioning - HVAC 15.0% 100.0% 4 $0.60 0.6 0.35 $0.280
Pumps - Variable Speed Control 0.0% 45.0% 10 $0.44 0.0 0.00 $5.336
Thermostat - Clock/Programmable 38.7% 50.0% 11 $0.11 0.3 0.32 $0.044
Insulation - Ceiling 19.0% 90.0% 20 $0.64 0.7 0.43 $0.066
Insulation - Radiant Barrier 10.3% 25.0% 20 $0.26 0.4 0.45 $0.050
Roofs - High Reflectivity 3.3% 100.0% 15 $0.18 0.2 0.21 $0.063
Windows - High Efficiency 66.1% 100.0% 20 $0.44 1.0 0.52 $0.032
Interior Lighting - Central Lighting
Controls 81.2% 100.0% 8 $0.65 0.2 0.02 $0.581
Interior Lighting - Photocell Controlled
T8 Dimming Ballasts 0.9% 60.0% 8 $0.50 0.8 0.14 $0.085
Exterior Lighting - Daylighting Controls 1.6% 100.0% 8 $0.11 0.5 0.28 $0.029
Interior Fluorescent - Bi-Level Fixture
w/Occupancy Sensor 10.0% 30.0% 8 $0.50 0.3 0.06 $0.212
Interior Fluorescent - High Bay Fixtures 10.0% 30.0% 11 $0.70 1.7 0.21 $0.046
Interior Lighting - Occupancy Sensors 7.1% 60.0% 8 $0.20 0.2 0.14 $0.179
Exterior Lighting - Photovoltaic
Installation 5.0% 25.0% 5 $0.92 0.6 0.03 $0.307
Interior Screw-in - Task Lighting 25.0% 100.0% 5 $0.24 0.1 0.02 $0.500
Interior Lighting - Time Clocks and
Timers 9.1% 75.0% 8 $0.20 0.1 0.07 $0.357
Water Heater - Faucet Aerators/Low
Flow Nozzles 50.5% 100.0% 9 $0.01 0.1 0.68 $0.016
Water Heater - Pipe Insulation 45.6% 100.0% 15 $0.28 0.1 0.04 $0.216
Water Heater - High Efficiency
Circulation Pump 0.0% 0.0% 10 $0.11 1.4 1.11 $0.009
Water Heater - Tank Blanket/Insulation 68.0% 100.0% 10 $0.02 0.1 0.44 $0.024
Water Heater - Thermostat Setback 5.0% 100.0% 10 $0.11 0.1 0.06 $0.163
Refrigeration - Anti-Sweat Heater/Auto
Door Closer 0.0% 100.0% 16 $0.20 0.1 0.03 $0.264
Refrigeration - Floating Head Pressure 17.9% 50.0% 16 $0.35 0.0 0.01 $1.061
Refrigeration - Door Gasket
Replacement 5.0% 100.0% 8 $0.10 0.0 0.01 $0.710
Insulation - Bare Suction Lines 5.0% 100.0% 8 $0.10 0.0 0.02 $0.525
Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.02 $2.859
Refrigeration - Strip Curtain 5.0% 56.3% 4 $0.00 - - $0.000
Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.0 0.01 $0.701
LED Exit Lighting 46.9% 90.0% 10 $0.00 0.0 4.04 $0.006
Retrocommissioning - Lighting 5.0% 100.0% 5 $0.10 0.3 0.15 $0.081
Refrigeration - High Efficiency Case 12.0% 56.0% 6 $0.04 0.0 0.01 $1.656
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1036 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-60 www.enernoc.com
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/Sq
Ft)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Lighting
Exterior Lighting - Cold Cathode
Lighting 14.6% 50.0% 5 $0.00 0.4 16.94 $0.001
Laundry - High Efficiency Clothes
Washer 6.9% 10.0% 10 $0.00 0.0 4.82 $0.002
Interior Lighting - Hotel Guestroom
Controls 0.0% 0.0% 8 $0.14 0.1 0.04 $0.211
Miscellaneous - Energy Star Water
Cooler 5.0% 100.0% 8 $0.00 0.0 0.27 $0.044
Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 0.2 1.00 $0.000
Ventilation - Demand Control
Ventilation 6.4% 20.0% 10 $0.04 0.1 0.52 $0.065
Office Equipment - Smart Power Strips 15.4% 30.0% 7 $0.00 0.4 286.03 $0.000
Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000
Refrigeration - Multiplex - Floating
section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex Controls -
Floating section Pressure - Evap. Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff. Air-
cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff. Water-
cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
RTU - Maintenance 14.0% 100.0% 4 $0.08 0.4 0.22 $0.060
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.2 0.21 $0.061
Chiller - Chilled Water Reset 0.0% 0.0% 4 $0.86 0.4 0.03 $0.529
Chiller - Chilled Water Variable-Flow
System 0.0% 0.0% 10 $0.86 0.1 0.02 $1.018
Chiller - VSD 0.0% 0.0% 20 $1.17 0.8 0.11 $0.105
Chiller - High Efficiency Cooling Tower
Fans 0.0% 0.0% 10 $0.04 0.0 0.00 $10.961
Chiller - Condenser Water Temprature
Reset 0.0% 0.0% 14 $0.87 0.4 0.07 $0.206
Cooling - Economizer Installation 51.8% 65.0% 15 $0.15 0.6 0.64 $0.020
Heat Pump - Maintenance 28.1% 100.0% 4 $0.03 0.9 1.42 $0.009
Insulation - Ducting 9.0% 100.0% 20 $0.41 0.2 0.36 $0.136
Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.7 0.47 $0.048
Energy Management System 34.8% 100.0% 14 $0.35 0.8 0.37 $0.040
Cooking - Exhaust Hoods with Sensor
Control 1.0% 20.0% 10 $0.04 - - $0.000
Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.25 $0.057
Fans - Variable Speed Control 10.9% 100.0% 10 $0.20 0.7 0.32 $0.033
Retrocommissioning - HVAC 15.0% 100.0% 4 $0.60 0.6 0.35 $0.280
Pumps - Variable Speed Control 0.0% 45.0% 10 $0.44 0.0 0.00 $5.336
Thermostat - Clock/Programmable 38.7% 50.0% 11 $0.11 0.3 0.32 $0.044
Insulation - Ceiling 19.0% 90.0% 20 $0.64 0.7 0.43 $0.066
Insulation - Radiant Barrier 10.3% 25.0% 20 $0.26 0.4 0.45 $0.050

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1037 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-61
Table C-20 Energy Efficiency Non-Equipment Data— Small/ Medium Commercial, New
Vintage, Washington
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
RTU - Maintenance 14.0% 100.0% 4 $0.08 0.2 0.14 $0.102
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.0 0.18 $0.073
Chiller - Chilled Water Reset 0.0% 0.0% 4 $0.86 0.4 0.02 $0.641
Chiller - Chilled Water Variable-Flow
System 0.0% 0.0% 10 $0.86 0.1 0.02 $0.823
Chiller - VSD 0.0% 0.0% 20 $1.17 0.7 0.10 $0.122
Chiller - High Efficiency Cooling
Tower Fans 0.0% 0.0% 10 $0.04 0.0 0.00 $8.973
Chiller - Condenser Water
Temprature Reset 0.0% 0.0% 14 $0.87 0.3 0.06 $0.247
Cooling - Economizer Installation 51.8% 65.0% 15 $0.15 - 0.28 $0.000
Heat Pump - Maintenance 28.1% 100.0% 4 $0.03 0.5 0.96 $0.015
Insulation - Ducting 9.0% 50.0% 20 $0.41 - 0.32 $0.000
Energy Management System 27.7% 100.0% 14 $0.35 1.9 0.63 $0.017
Cooking - Exhaust Hoods with Sensor
Control 1.0% 20.0% 10 $0.04 - - $0.000
Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.17 $0.067
Fans - Variable Speed Control 8.0% 100.0% 10 $0.20 0.5 0.25 $0.044
Pumps - Variable Speed Control 5.0% 45.0% 10 $0.44 0.0 0.00 $5.075
Thermostat - Clock/Programmable 34.0% 50.0% 11 $0.11 1.0 0.86 $0.012
Insulation - Ceiling 15.3% 90.0% 20 $0.16 - 0.38 $0.000
Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 - 0.30 $0.000
Roofs - High Reflectivity 5.0% 100.0% 15 $0.09 - 0.07 $0.000
Windows - High Efficiency 60.5% 100.0% 20 $0.35 - 0.31 $0.000
Interior Lighting - Central Lighting
Controls 81.2% 100.0% 8 $0.65 - - $0.000
Interior Lighting - Photocell
Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.38 0.7 0.16 $0.074
Exterior Lighting - Daylighting
Controls 10.0% 100.0% 8 $0.09 - 0.00 $0.000
Interior Fluorescent - Bi-Level Fixture
w/Occupancy Sensor 10.0% 30.0% 8 $0.50 0.3 0.05 $0.243
Interior Fluorescent - High Bay
Fixtures 10.0% 30.0% 11 $0.70 1.5 0.20 $0.052
Interior Lighting - Occupancy Sensors 7.1% 60.0% 8 $0.20 - 0.07 $0.000
Exterior Lighting - Photovoltaic
Installation 5.0% 25.0% 5 $0.92 - - $0.000
Interior Screw-in - Task Lighting 25.0% 100.0% 5 $0.24 0.1 0.03 $0.507
Interior Lighting - Time Clocks and
Timers 9.1% 75.0% 8 $0.20 - 0.05 $0.000
Water Heater - Faucet Aerators/Low
Flow Nozzles 50.5% 100.0% 9 $0.01 0.1 0.67 $0.017
Water Heater - Pipe Insulation 45.6% 100.0% 15 $0.28 0.1 0.04 $0.227
Water Heater - High Efficiency
Circulation Pump 0.0% 0.0% 10 $0.11 1.3 1.09 $0.010
Water Heater - Tank
Blanket/Insulation 40.4% 100.0% 10 $0.02 0.0 0.21 $0.051
Water Heater - Thermostat Setback 10.0% 100.0% 10 $0.11 0.1 0.06 $0.174
Refrigeration - Anti-Sweat
Heater/Auto Door Closer 0.0% 100.0% 16 $0.20 0.1 0.03 $0.289
Refrigeration - Floating Head
Pressure 17.9% 50.0% 16 $0.35 - 0.00 $0.000
Refrigeration - Door Gasket
Replacement 5.0% 100.0% 8 $0.10 0.0 0.01 $1.014
Insulation - Bare Suction Lines 5.0% 100.0% 8 $0.10 - - $0.000
Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.02 $3.122
Refrigeration - Strip Curtain 5.0% 56.3% 4 $0.00 - - $0.000
Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.0 0.01 $0.804
LED Exit Lighting 91.2% 90.0% 10 $0.00 0.0 5.42 $0.006
Refrigeration - High Efficiency Case 26.1% 56.0% 6 $0.02 0.0 0.38 $0.559
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1038 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-62 www.enernoc.com
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Lighting
Exterior Lighting - Cold Cathode
Lighting 14.6% 50.0% 5 $0.00 0.3 20.03 $0.001
Laundry - High Efficiency Clothes
Washer 6.9% 10.0% 10 $0.00 0.0 5.78 $0.002
Interior Lighting - Hotel Guestroom
Controls 0.0% 0.0% 8 $0.14 0.1 0.06 $0.213
Miscellaneous - Energy Star Water
Cooler 5.0% 100.0% 8 $0.00 0.0 0.33 $0.037
Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Ventilation - Demand Control
Ventilation 12.9% 20.0% 10 $0.04 - 0.38 $0.000
Office Equipment - Smart Power
Strips 15.4% 30.0% 7 $0.00 0.5 393.51 $0.000
Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000
Refrigeration - Multiplex - Floating
section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex Controls -
Floating section Pressure - Evap.
Cond.
0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff. Air-
cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff.
Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
RTU - Maintenance 14.0% 100.0% 4 $0.08 0.2 0.14 $0.102
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.0 0.18 $0.073
Chiller - Chilled Water Reset 0.0% 0.0% 4 $0.86 0.4 0.02 $0.641
Chiller - Chilled Water Variable-Flow
System 0.0% 0.0% 10 $0.86 0.1 0.02 $0.823
Chiller - VSD 0.0% 0.0% 20 $1.17 0.7 0.10 $0.122
Chiller - High Efficiency Cooling
Tower Fans 0.0% 0.0% 10 $0.04 0.0 0.00 $8.973
Chiller - Condenser Water
Temprature Reset 0.0% 0.0% 14 $0.87 0.3 0.06 $0.247
Cooling - Economizer Installation 51.8% 65.0% 15 $0.15 - 0.28 $0.000
Heat Pump - Maintenance 28.1% 100.0% 4 $0.03 0.5 0.96 $0.015
Insulation - Ducting 9.0% 50.0% 20 $0.41 - 0.32 $0.000
Energy Management System 27.7% 100.0% 14 $0.35 1.9 0.63 $0.017
Cooking - Exhaust Hoods with Sensor
Control 1.0% 20.0% 10 $0.04 - - $0.000
Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.17 $0.067
Fans - Variable Speed Control 8.0% 100.0% 10 $0.20 0.5 0.25 $0.044
Pumps - Variable Speed Control 5.0% 45.0% 10 $0.44 0.0 0.00 $5.075
Thermostat - Clock/Programmable 34.0% 50.0% 11 $0.11 1.0 0.86 $0.012
Insulation - Ceiling 15.3% 90.0% 20 $0.16 - 0.38 $0.000
Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 - 0.30 $0.000
Roofs - High Reflectivity 5.0% 100.0% 15 $0.09 - 0.07 $0.000
Windows - High Efficiency 60.5% 100.0% 20 $0.35 - 0.31 $0.000
Interior Lighting - Central Lighting
Controls 81.2% 100.0% 8 $0.65 - - $0.000
Interior Lighting - Photocell
Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.38 0.7 0.16 $0.074
Exterior Lighting - Daylighting
Controls 10.0% 100.0% 8 $0.09 - 0.00 $0.000

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1039 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-63
Table C-21 Energy Efficiency Non-Equipment Data— Small/Medium Commercial,
Existing Vintage, Idaho
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
RTU - Maintenance 31.3% 100.0% 4 $0.08 0.4 0.22 $0.060
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.2 0.21 $0.061
Chiller - Chilled Water Reset 0.0% 0.0% 4 $0.86 0.4 0.03 $0.529
Chiller - Chilled Water Variable-Flow
System 0.0% 0.0% 10 $0.86 0.1 0.02 $1.018
Chiller - VSD 0.0% 0.0% 20 $1.17 0.8 0.11 $0.105
Chiller - High Efficiency Cooling
Tower Fans 0.0% 0.0% 10 $0.04 0.0 0.00 $10.961
Chiller - Condenser Water
Temprature Reset 0.0% 0.0% 14 $0.87 0.4 0.07 $0.206
Cooling - Economizer Installation 51.8% 65.0% 15 $0.15 0.1 0.36 $0.140
Heat Pump - Maintenance 28.1% 100.0% 4 $0.03 0.9 1.41 $0.009
Insulation - Ducting 9.0% 100.0% 20 $0.41 0.0 0.31 $1.480
Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.1 0.32 $0.586
Energy Management System 34.8% 100.0% 14 $0.35 4.4 1.28 $0.007
Cooking - Exhaust Hoods with Sensor
Control 1.0% 20.0% 10 $0.04 - - $0.000
Fans - Energy Efficient Motors 28.9% 100.0% 10 $0.05 0.5 0.98 $0.011
Fans - Variable Speed Control 26.5% 100.0% 10 $0.20 0.7 0.31 $0.033
Retrocommissioning - HVAC 15.0% 100.0% 4 $0.60 0.1 0.31 $1.917
Pumps - Variable Speed Control 0.0% 45.0% 10 $0.44 0.0 0.00 $5.336
Thermostat - Clock/Programmable 38.7% 50.0% 11 $0.11 2.8 2.30 $0.004
Insulation - Ceiling 10.0% 90.0% 20 $0.64 0.1 0.35 $0.580
Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 0.0 0.33 $0.567
Roofs - High Reflectivity 4.5% 100.0% 15 $0.18 0.0 0.12 $0.434
Windows - High Efficiency 60.5% 100.0% 20 $0.44 0.1 0.33 $0.392
Interior Lighting - Central Lighting
Controls 81.2% 100.0% 8 $0.65 0.1 0.01 $1.389
Interior Lighting - Photocell
Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.50 0.8 0.14 $0.085
Exterior Lighting - Daylighting
Controls 1.6% 100.0% 8 $0.11 0.1 0.07 $0.121
Interior Fluorescent - Bi-Level Fixture
w/Occupancy Sensor 10.0% 30.0% 8 $0.50 0.3 0.06 $0.212
Interior Fluorescent - High Bay
Fixtures 15.4% 30.0% 11 $0.70 1.7 0.21 $0.046
Interior Lighting - Occupancy Sensors 18.3% 60.0% 8 $0.20 0.1 0.10 $0.427
Exterior Lighting - Photovoltaic
Installation 5.0% 25.0% 5 $0.92 0.2 0.01 $1.278
Interior Screw-in - Task Lighting 25.0% 100.0% 5 $0.24 0.1 0.02 $0.500
Interior Lighting - Time Clocks and
Timers 9.1% 75.0% 8 $0.20 0.0 0.05 $0.855
Water Heater - Faucet Aerators/Low
Flow Nozzles 50.5% 100.0% 9 $0.01 0.1 0.67 $0.016
Water Heater - Pipe Insulation 45.6% 100.0% 15 $0.28 0.1 0.04 $0.216
Water Heater - High Efficiency
Circulation Pump 0.0% 0.0% 10 $0.11 1.4 1.10 $0.009
Water Heater - Tank
Blanket/Insulation 68.0% 100.0% 10 $0.02 0.1 0.43 $0.024
Water Heater - Thermostat Setback 5.0% 100.0% 10 $0.11 0.1 0.06 $0.163
Refrigeration - Anti-Sweat
Heater/Auto Door Closer 0.0% 100.0% 16 $0.20 0.1 0.03 $0.264
Refrigeration - Floating Head
Pressure 17.9% 50.0% 16 $0.35 - 0.00 $0.000
Refrigeration - Door Gasket
Replacement 5.0% 100.0% 8 $0.10 0.0 0.01 $0.710
Insulation - Bare Suction Lines 5.0% 100.0% 8 $0.10 - - $0.000
Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.02 $2.859
Refrigeration - Strip Curtain 5.0% 56.3% 4 $0.00 - - $0.000
Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.0 0.01 $0.701
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1040 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-64 www.enernoc.com
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
LED Exit Lighting 46.9% 90.0% 10 $0.00 0.0 3.34 $0.006
Retrocommissioning - Lighting 24.1% 100.0% 5 $0.10 0.1 0.05 $0.233
Refrigeration - High Efficiency Case
Lighting 12.0% 56.0% 6 $0.04 0.0 0.01 $1.909
Exterior Lighting - Cold Cathode
Lighting 14.6% 50.0% 5 $0.00 0.3 15.57 $0.001
Laundry - High Efficiency Clothes
Washer 6.9% 10.0% 10 $0.00 0.0 4.79 $0.002
Interior Lighting - Hotel Guestroom
Controls 0.0% 0.0% 8 $0.14 0.1 0.03 $0.211
Miscellaneous - Energy Star Water
Cooler 24.1% 100.0% 8 $0.00 0.0 0.27 $0.044
Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 0.1 1.00 $0.000
Ventilation - Demand Control
Ventilation 10.2% 20.0% 10 $0.04 0.0 0.42 $0.134
Office Equipment - Smart Power
Strips 15.4% 30.0% 7 $0.00 0.4 285.77 $0.000
Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000
Refrigeration - Multiplex - Floating
section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex Controls -
Floating section Pressure - Evap.
Cond.
0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff. Air-
cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff.
Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
RTU - Maintenance 31.3% 100.0% 4 $0.08 0.4 0.22 $0.060
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.2 0.21 $0.061
Chiller - Chilled Water Reset 0.0% 0.0% 4 $0.86 0.4 0.03 $0.529
Chiller - Chilled Water Variable-Flow
System 0.0% 0.0% 10 $0.86 0.1 0.02 $1.018
Chiller - VSD 0.0% 0.0% 20 $1.17 0.8 0.11 $0.105
Chiller - High Efficiency Cooling
Tower Fans 0.0% 0.0% 10 $0.04 0.0 0.00 $10.961
Chiller - Condenser Water
Temprature Reset 0.0% 0.0% 14 $0.87 0.4 0.07 $0.206
Cooling - Economizer Installation 51.8% 65.0% 15 $0.15 0.1 0.36 $0.140
Heat Pump - Maintenance 28.1% 100.0% 4 $0.03 0.9 1.41 $0.009
Insulation - Ducting 9.0% 100.0% 20 $0.41 0.0 0.31 $1.480
Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.1 0.32 $0.586
Energy Management System 34.8% 100.0% 14 $0.35 4.4 1.28 $0.007
Cooking - Exhaust Hoods with Sensor
Control 1.0% 20.0% 10 $0.04 - - $0.000
Fans - Energy Efficient Motors 28.9% 100.0% 10 $0.05 0.5 0.98 $0.011
Fans - Variable Speed Control 26.5% 100.0% 10 $0.20 0.7 0.31 $0.033
Retrocommissioning - HVAC 15.0% 100.0% 4 $0.60 0.1 0.31 $1.917
Pumps - Variable Speed Control 0.0% 45.0% 10 $0.44 0.0 0.00 $5.336
Thermostat - Clock/Programmable 38.7% 50.0% 11 $0.11 2.8 2.30 $0.004
Insulation - Ceiling 10.0% 90.0% 20 $0.64 0.1 0.35 $0.580
Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 0.0 0.33 $0.567

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1041 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-65
Table C-22 Energy Efficiency Non-Equipment Data— Small/ Medium Commercial, New
Vintage, Idaho
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
RTU - Maintenance 21.4% 100.0% 4 $0.08 0.2 0.14 $0.102
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.0 0.18 $0.073
Chiller - Chilled Water Reset 0.0% 0.0% 4 $0.86 0.4 0.02 $0.641
Chiller - Chilled Water Variable-Flow
System 0.0% 0.0% 10 $0.86 0.1 0.02 $0.823
Chiller - VSD 0.0% 0.0% 20 $1.17 0.7 0.09 $0.122
Chiller - High Efficiency Cooling
Tower Fans 0.0% 0.0% 10 $0.04 0.0 0.00 $8.973
Chiller - Condenser Water
Temprature Reset 0.0% 0.0% 14 $0.87 0.3 0.06 $0.247
Cooling - Economizer Installation 51.8% 65.0% 15 $0.15 - 0.28 $0.000
Heat Pump - Maintenance 28.1% 100.0% 4 $0.03 0.5 0.96 $0.015
Insulation - Ducting 9.0% 50.0% 20 $0.41 - 0.32 $0.000
Energy Management System 34.8% 100.0% 14 $0.35 2.2 0.73 $0.014
Cooking - Exhaust Hoods with Sensor
Control 1.0% 20.0% 10 $0.04 - - $0.000
Fans - Energy Efficient Motors 28.9% 100.0% 10 $0.05 0.1 0.21 $0.067
Fans - Variable Speed Control 50.5% 100.0% 10 $0.20 0.5 0.25 $0.044
Pumps - Variable Speed Control 5.0% 45.0% 10 $0.44 0.0 0.00 $5.075
Thermostat - Clock/Programmable 34.0% 50.0% 11 $0.11 1.4 1.19 $0.009
Insulation - Ceiling 21.5% 90.0% 20 $0.16 - 0.38 $0.000
Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 - 0.30 $0.000
Roofs - High Reflectivity 5.0% 100.0% 15 $0.09 - 0.07 $0.000
Windows - High Efficiency 60.5% 100.0% 20 $0.35 - 0.31 $0.000
Interior Lighting - Central Lighting
Controls 81.2% 100.0% 8 $0.65 - - $0.000
Interior Lighting - Photocell
Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.38 0.7 0.16 $0.074
Exterior Lighting - Daylighting
Controls 10.0% 100.0% 8 $0.09 - 0.00 $0.000
Interior Fluorescent - Bi-Level Fixture
w/Occupancy Sensor 10.0% 30.0% 8 $0.50 0.3 0.05 $0.243
Interior Fluorescent - High Bay
Fixtures 13.7% 30.0% 11 $0.70 1.5 0.19 $0.052
Interior Lighting - Occupancy Sensors 11.9% 60.0% 8 $0.20 - 0.07 $0.000
Exterior Lighting - Photovoltaic
Installation 5.0% 25.0% 5 $0.92 - - $0.000
Interior Screw-in - Task Lighting 25.0% 100.0% 5 $0.24 0.1 0.03 $0.507
Interior Lighting - Time Clocks and
Timers 9.1% 75.0% 8 $0.20 - 0.05 $0.000
Water Heater - Faucet Aerators/Low
Flow Nozzles 50.5% 100.0% 9 $0.01 0.1 0.66 $0.017
Water Heater - Pipe Insulation 45.6% 100.0% 15 $0.28 0.1 0.04 $0.227
Water Heater - High Efficiency
Circulation Pump 0.0% 0.0% 10 $0.11 1.3 1.08 $0.010
Water Heater - Tank
Blanket/Insulation 68.0% 100.0% 10 $0.02 0.0 0.21 $0.051
Water Heater - Thermostat Setback 10.0% 100.0% 10 $0.11 0.1 0.06 $0.174
Refrigeration - Anti-Sweat
Heater/Auto Door Closer 0.0% 100.0% 16 $0.20 0.1 0.03 $0.289
Refrigeration - Floating Head
Pressure 17.9% 50.0% 16 $0.35 0.1 0.03 $0.323
Refrigeration - Door Gasket
Replacement 5.0% 100.0% 8 $0.10 0.0 0.01 $1.014
Insulation - Bare Suction Lines 5.0% 100.0% 8 $0.10 0.1 0.08 $0.160
Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.02 $3.122
Refrigeration - Strip Curtain 5.0% 56.3% 4 $0.00 - - $0.000
Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.0 0.01 $0.804
LED Exit Lighting 91.2% 90.0% 10 $0.00 0.0 5.18 $0.006
Refrigeration - High Efficiency Case 30.0% 56.0% 6 $0.02 0.0 0.32 $0.292
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1042 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-66 www.enernoc.com
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Lighting
Exterior Lighting - Cold Cathode
Lighting 14.6% 50.0% 5 $0.00 0.3 18.13 $0.001
Laundry - High Efficiency Clothes
Washer 6.9% 10.0% 10 $0.00 0.0 5.75 $0.002
Interior Lighting - Hotel Guestroom
Controls 0.0% 0.0% 8 $0.14 0.1 0.05 $0.213
Miscellaneous - Energy Star Water
Cooler 11.9% 100.0% 8 $0.00 0.0 0.33 $0.037
Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Ventilation - Demand Control
Ventilation 19.7% 20.0% 10 $0.04 - 0.38 $0.000
Office Equipment - Smart Power
Strips 15.4% 30.0% 7 $0.00 0.3 215.34 $0.000
Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000
Refrigeration - Multiplex - Floating
section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex Controls -
Floating section Pressure - Evap.
Cond.
0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff. Air-
cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff.
Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
RTU - Maintenance 21.4% 100.0% 4 $0.08 0.2 0.14 $0.102
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.0 0.18 $0.073
Chiller - Chilled Water Reset 0.0% 0.0% 4 $0.86 0.4 0.02 $0.641
Chiller - Chilled Water Variable-Flow
System 0.0% 0.0% 10 $0.86 0.1 0.02 $0.823
Chiller - VSD 0.0% 0.0% 20 $1.17 0.7 0.09 $0.122
Chiller - High Efficiency Cooling
Tower Fans 0.0% 0.0% 10 $0.04 0.0 0.00 $8.973
Chiller - Condenser Water
Temprature Reset 0.0% 0.0% 14 $0.87 0.3 0.06 $0.247
Cooling - Economizer Installation 51.8% 65.0% 15 $0.15 - 0.28 $0.000
Heat Pump - Maintenance 28.1% 100.0% 4 $0.03 0.5 0.96 $0.015
Insulation - Ducting 9.0% 50.0% 20 $0.41 - 0.32 $0.000
Energy Management System 34.8% 100.0% 14 $0.35 2.2 0.73 $0.014
Cooking - Exhaust Hoods with Sensor
Control 1.0% 20.0% 10 $0.04 - - $0.000
Fans - Energy Efficient Motors 28.9% 100.0% 10 $0.05 0.1 0.21 $0.067
Fans - Variable Speed Control 50.5% 100.0% 10 $0.20 0.5 0.25 $0.044
Pumps - Variable Speed Control 5.0% 45.0% 10 $0.44 0.0 0.00 $5.075
Thermostat - Clock/Programmable 34.0% 50.0% 11 $0.11 1.4 1.19 $0.009
Insulation - Ceiling 21.5% 90.0% 20 $0.16 - 0.38 $0.000
Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 - 0.30 $0.000
Roofs - High Reflectivity 5.0% 100.0% 15 $0.09 - 0.07 $0.000
Windows - High Efficiency 60.5% 100.0% 20 $0.35 - 0.31 $0.000
Interior Lighting - Central Lighting
Controls 81.2% 100.0% 8 $0.65 - - $0.000
Interior Lighting - Photocell
Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.38 0.7 0.16 $0.074
Exterior Lighting - Daylighting
Controls 10.0% 100.0% 8 $0.09 - 0.00 $0.000

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1043 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-67
Table C-23 Energy Efficiency Non-Equipment Data— Large Commercial, Existing
Vintage, Washington
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
RTU - Maintenance 27.0% 100.0% 4 $0.06 0.4 0.30 $0.044
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.3 0.12 $0.060
Chiller - Chilled Water Reset 15.0% 100.0% 4 $0.18 0.4 0.11 $0.120
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.18 0.1 0.04 $0.226
Chiller - VSD 15.0% 88.2% 20 $1.17 0.7 0.05 $0.117
Chiller - High Efficiency Cooling
Tower Fans 15.0% 43.5% 10 $0.04 0.0 0.00 $11.820
Chiller - Condenser Water
Temprature Reset 5.0% 100.0% 14 $0.18 0.4 0.17 $0.046
Cooling - Economizer Installation 51.6% 65.0% 15 $0.15 0.8 0.47 $0.015
Heat Pump - Maintenance 28.1% 100.0% 4 $0.06 0.8 0.61 $0.021
Insulation - Ducting 8.0% 100.0% 20 $0.41 0.0 0.31 $1.046
Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.1 0.32 $0.421
Energy Management System 44.0% 100.0% 14 $0.35 2.5 0.68 $0.013
Cooking - Exhaust Hoods with Sensor
Control 1.0% 15.0% 10 $0.04 - - $0.000
Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.17 $0.072
Fans - Variable Speed Control 2.0% 100.0% 10 $0.20 0.6 0.27 $0.040
Retrocommissioning - HVAC 15.0% 100.0% 4 $0.30 0.4 0.37 $0.216
Pumps - Variable Speed Control 0.0% 45.0% 10 $0.13 0.0 0.01 $1.381
Thermostat - Clock/Programmable 33.0% 50.0% 11 $0.11 0.8 0.65 $0.015
Insulation - Ceiling 9.0% 40.0% 20 $0.85 0.4 0.34 $0.152
Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 0.0 0.31 $0.521
Roofs - High Reflectivity 1.5% 100.0% 15 $0.08 0.1 0.07 $0.109
Windows - High Efficiency 71.9% 100.0% 20 $0.88 0.2 0.32 $0.385
Interior Lighting - Central Lighting
Controls 85.7% 100.0% 8 $0.65 0.2 0.03 $0.384
Interior Lighting - Photocell
Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.45 0.8 0.15 $0.078
Exterior Lighting - Daylighting
Controls 1.6% 25.0% 8 $0.29 0.1 0.02 $0.549
Interior Fluorescent - Bi-Level Fixture
w/Occupancy Sensor 10.0% 30.0% 8 $0.40 0.3 0.07 $0.173
Interior Fluorescent - High Bay
Fixtures 10.0% 30.0% 11 $0.63 1.6 0.24 $0.042
Interior Lighting - Occupancy Sensors 12.6% 60.0% 8 $0.20 0.2 0.16 $0.118
Exterior Lighting - Photovoltaic
Installation 5.0% 25.0% 5 $0.92 0.1 0.00 $2.235
Interior Screw-in - Task Lighting 10.0% 100.0% 5 $0.24 0.1 0.02 $0.531
Interior Lighting - Time Clocks and
Timers 9.3% 75.0% 8 $0.20 0.1 0.09 $0.236
Water Heater - Faucet Aerators/Low
Flow Nozzles 3.0% 100.0% 9 $0.03 0.1 0.27 $0.042
Water Heater - Pipe Insulation 0.0% 0.0% 15 $0.28 0.1 0.04 $0.185
Water Heater - High Efficiency
Circulation Pump 0.6% 25.0% 10 $0.11 1.6 1.31 $0.008
Water Heater - Tank
Blanket/Insulation 0.0% 0.0% 10 $0.04 0.1 0.26 $0.041
Water Heater - Thermostat Setback 0.0% 0.0% 10 $0.11 0.1 0.07 $0.141
Refrigeration - Anti-Sweat
Heater/Auto Door Closer 0.0% 100.0% 16 $0.20 0.1 0.02 $0.321
Refrigeration - Floating Head
Pressure 38.0% 60.0% 16 $0.35 0.0 0.00 $1.320
Refrigeration - Door Gasket
Replacement 5.0% 100.0% 8 $0.10 0.0 0.02 $0.463
Insulation - Bare Suction Lines 5.0% 100.0% 8 $0.10 0.0 0.02 $0.653
Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.04 $0.449
Refrigeration - Strip Curtain 12.6% 56.3% 4 $0.00 0.0 19.02 $0.001
Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.1 0.01 $0.596
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1044 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-68 www.enernoc.com
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
LED Exit Lighting 46.9% 90.0% 10 $0.00 0.0 3.74 $0.006
Retrocommissioning - Lighting 5.0% 100.0% 5 $0.05 0.3 0.31 $0.042
Refrigeration - High Efficiency Case
Lighting 12.0% 56.0% 6 $0.04 - - $0.000
Exterior Lighting - Cold Cathode
Lighting 14.6% 50.0% 5 $0.00 0.3 15.65 $0.001
Laundry - High Efficiency Clothes
Washer 6.9% 10.0% 10 $0.00 0.0 4.60 $0.002
Interior Lighting - Hotel Guestroom
Controls 1.0% 2.0% 8 $0.14 0.1 0.04 $0.224
Miscellaneous - Energy Star Water
Cooler 5.0% 100.0% 8 $0.00 0.0 0.26 $0.047
Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 0.4 1.00 $0.000
Ventilation - Demand Control
Ventilation 7.9% 15.0% 10 $0.04 0.2 0.88 $0.029
Office Equipment - Smart Power
Strips 15.4% 30.0% 7 $0.00 0.3 208.80 $0.000
Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000
Refrigeration - Multiplex - Floating
section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex Controls -
Floating section Pressure - Evap.
Cond.
0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff. Air-
cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff.
Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
RTU - Maintenance 27.0% 100.0% 4 $0.06 0.4 0.30 $0.044
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.3 0.12 $0.060
Chiller - Chilled Water Reset 15.0% 100.0% 4 $0.18 0.4 0.11 $0.120
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.18 0.1 0.04 $0.226
Chiller - VSD 15.0% 88.2% 20 $1.17 0.7 0.05 $0.117
Chiller - High Efficiency Cooling
Tower Fans 15.0% 43.5% 10 $0.04 0.0 0.00 $11.820
Chiller - Condenser Water
Temprature Reset 5.0% 100.0% 14 $0.18 0.4 0.17 $0.046
Cooling - Economizer Installation 51.6% 65.0% 15 $0.15 0.8 0.47 $0.015
Heat Pump - Maintenance 28.1% 100.0% 4 $0.06 0.8 0.61 $0.021
Insulation - Ducting 8.0% 100.0% 20 $0.41 0.0 0.31 $1.046
Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.1 0.32 $0.421
Energy Management System 44.0% 100.0% 14 $0.35 2.5 0.68 $0.013
Cooking - Exhaust Hoods with Sensor
Control 1.0% 15.0% 10 $0.04 - - $0.000
Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.17 $0.072
Fans - Variable Speed Control 2.0% 100.0% 10 $0.20 0.6 0.27 $0.040
Retrocommissioning - HVAC 15.0% 100.0% 4 $0.30 0.4 0.37 $0.216
Pumps - Variable Speed Control 0.0% 45.0% 10 $0.13 0.0 0.01 $1.381
Thermostat - Clock/Programmable 33.0% 50.0% 11 $0.11 0.8 0.65 $0.015
Insulation - Ceiling 9.0% 40.0% 20 $0.85 0.4 0.34 $0.152
Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 0.0 0.31 $0.521

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1045 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-69
Table C-24 Energy Efficiency Non-Equipment Data— Large Commercial, New Vintage,
Washington
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
RTU - Maintenance 27.0% 100.0% 4 $0.06 0.2 0.19 $0.076
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.0 0.11 $0.073
Chiller - Chilled Water Reset 30.0% 100.0% 4 $0.18 0.3 0.09 $0.151
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.18 0.1 0.06 $0.168
Chiller - VSD 15.0% 88.2% 20 $1.17 0.6 0.05 $0.141
Chiller - High Efficiency Cooling
Tower Fans 15.0% 43.5% 10 $0.04 0.0 0.00 $10.716
Chiller - Condenser Water
Temprature Reset 25.0% 100.0% 14 $0.18 0.3 0.14 $0.058
Cooling - Economizer Installation 44.3% 65.0% 15 $0.15 0.0 0.04 $0.517
Heat Pump - Maintenance 14.7% 100.0% 4 $0.06 0.5 0.44 $0.034
Insulation - Ducting 8.0% 50.0% 20 $0.41 0.0 0.30 $15.903
Energy Management System 48.5% 100.0% 14 $0.35 2.9 0.81 $0.011
Cooking - Exhaust Hoods with Sensor
Control 1.0% 15.0% 10 $0.04 - - $0.000
Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.19 $0.084
Fans - Variable Speed Control 2.0% 100.0% 10 $0.20 0.5 0.22 $0.051
Pumps - Variable Speed Control 5.0% 45.0% 10 $0.13 0.0 0.01 $1.313
Thermostat - Clock/Programmable 33.0% 50.0% 11 $0.11 1.4 1.14 $0.009
Insulation - Ceiling 75.0% 90.0% 20 $0.35 0.0 0.31 $2.770
Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 0.0 0.30 $29.882
Roofs - High Reflectivity 5.0% 100.0% 15 $0.05 0.0 0.01 $2.520
Windows - High Efficiency 71.9% 100.0% 20 $0.88 0.0 0.30 $17.807
Interior Lighting - Central Lighting
Controls 85.7% 100.0% 8 $0.65 - - $0.000
Interior Lighting - Photocell
Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.34 0.7 0.18 $0.068
Exterior Lighting - Daylighting
Controls 10.0% 25.0% 8 $0.19 - 0.00 $0.000
Interior Fluorescent - Bi-Level Fixture
w/Occupancy Sensor 10.0% 30.0% 8 $0.40 0.3 0.06 $0.201
Interior Fluorescent - High Bay
Fixtures 10.0% 30.0% 11 $0.63 1.4 0.21 $0.049
Interior Lighting - Occupancy Sensors 12.6% 60.0% 8 $0.20 - 0.06 $0.000
Exterior Lighting - Photovoltaic
Installation 5.0% 25.0% 5 $0.92 - - $0.000
Interior Screw-in - Task Lighting 10.0% 100.0% 5 $0.24 0.1 0.03 $0.538
Interior Lighting - Time Clocks and
Timers 9.3% 75.0% 8 $0.20 - 0.05 $0.000
Water Heater - Faucet Aerators/Low
Flow Nozzles 3.0% 100.0% 9 $0.03 0.1 0.26 $0.044
Water Heater - Pipe Insulation 0.0% 0.0% 15 $0.28 0.1 0.03 $0.295
Water Heater - High Efficiency
Circulation Pump 0.6% 25.0% 10 $0.11 1.6 1.30 $0.008
Water Heater - Tank
Blanket/Insulation 0.0% 0.0% 10 $0.04 0.1 0.25 $0.043
Water Heater - Thermostat Setback 0.0% 0.0% 10 $0.11 0.1 0.07 $0.147
Refrigeration - Anti-Sweat
Heater/Auto Door Closer 0.0% 100.0% 16 $0.20 0.0 0.03 $0.355
Refrigeration - Floating Head
Pressure 38.0% 60.0% 16 $0.35 - 0.00 $0.000
Refrigeration - Door Gasket
Replacement 5.0% 100.0% 8 $0.10 0.0 0.02 $0.662
Insulation - Bare Suction Lines 5.0% 100.0% 8 $0.10 - - $0.000
Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.04 $0.495
Refrigeration - Strip Curtain 12.6% 56.3% 4 $0.00 0.0 15.67 $0.001
Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.0 0.01 $0.684
LED Exit Lighting 91.2% 90.0% 10 $0.00 0.0 4.71 $0.006
Refrigeration - High Efficiency Case 24.0% 56.0% 6 $0.02 0.1 0.23 $0.061
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1046 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-70 www.enernoc.com
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Lighting
Exterior Lighting - Cold Cathode
Lighting 14.6% 50.0% 5 $0.00 0.3 18.50 $0.001
Laundry - High Efficiency Clothes
Washer 6.9% 10.0% 10 $0.00 0.0 5.06 $0.002
Interior Lighting - Hotel Guestroom
Controls 1.0% 2.0% 8 $0.14 0.1 0.05 $0.227
Miscellaneous - Energy Star Water
Cooler 5.0% 100.0% 8 $0.00 0.0 0.29 $0.042
Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Ventilation - Demand Control
Ventilation 12.4% 15.0% 10 $0.04 - 0.53 $0.000
Office Equipment - Smart Power
Strips 15.4% 30.0% 7 $0.00 0.3 221.56 $0.000
Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000
Refrigeration - Multiplex - Floating
section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex Controls -
Floating section Pressure - Evap.
Cond.
0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff. Air-
cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff.
Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
RTU - Maintenance 27.0% 100.0% 4 $0.06 0.2 0.19 $0.076
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.0 0.11 $0.073
Chiller - Chilled Water Reset 30.0% 100.0% 4 $0.18 0.3 0.09 $0.151
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.18 0.1 0.06 $0.168
Chiller - VSD 15.0% 88.2% 20 $1.17 0.6 0.05 $0.141
Chiller - High Efficiency Cooling
Tower Fans 15.0% 43.5% 10 $0.04 0.0 0.00 $10.716
Chiller - Condenser Water
Temprature Reset 25.0% 100.0% 14 $0.18 0.3 0.14 $0.058
Cooling - Economizer Installation 44.3% 65.0% 15 $0.15 0.0 0.04 $0.517
Heat Pump - Maintenance 14.7% 100.0% 4 $0.06 0.5 0.44 $0.034
Insulation - Ducting 8.0% 50.0% 20 $0.41 0.0 0.30 $15.903
Energy Management System 48.5% 100.0% 14 $0.35 2.9 0.81 $0.011
Cooking - Exhaust Hoods with Sensor
Control 1.0% 15.0% 10 $0.04 - - $0.000
Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.19 $0.084
Fans - Variable Speed Control 2.0% 100.0% 10 $0.20 0.5 0.22 $0.051
Pumps - Variable Speed Control 5.0% 45.0% 10 $0.13 0.0 0.01 $1.313
Thermostat - Clock/Programmable 33.0% 50.0% 11 $0.11 1.4 1.14 $0.009
Insulation - Ceiling 75.0% 90.0% 20 $0.35 0.0 0.31 $2.770
Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 0.0 0.30 $29.882
Roofs - High Reflectivity 5.0% 100.0% 15 $0.05 0.0 0.01 $2.520
Windows - High Efficiency 71.9% 100.0% 20 $0.88 0.0 0.30 $17.807
Interior Lighting - Central Lighting
Controls 85.7% 100.0% 8 $0.65 - - $0.000
Interior Lighting - Photocell
Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.34 0.7 0.18 $0.068
Exterior Lighting - Daylighting
Controls 10.0% 25.0% 8 $0.19 - 0.00 $0.000

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1047 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-71
Table C-25 Energy Efficiency Non-Equipment Data— Large Commercial, Existing
Vintage, Idaho
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
RTU - Maintenance 36.9% 100.0% 4 $0.06 0.4 0.30 $0.044
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.3 0.12 $0.060
Chiller - Chilled Water Reset 15.0% 100.0% 4 $0.18 0.4 0.11 $0.120
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.18 0.1 0.04 $0.226
Chiller - VSD 15.0% 88.2% 20 $1.17 0.7 0.05 $0.117
Chiller - High Efficiency Cooling
Tower Fans 15.0% 43.5% 10 $0.04 0.0 0.00 $11.820
Chiller - Condenser Water
Temprature Reset 18.5% 100.0% 14 $0.18 0.4 0.17 $0.046
Cooling - Economizer Installation 51.6% 65.0% 15 $0.15 0.2 0.14 $0.068
Heat Pump - Maintenance 28.1% 100.0% 4 $0.06 0.8 0.61 $0.021
Insulation - Ducting 8.0% 100.0% 20 $0.41 0.0 0.30 $2.323
Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.0 0.31 $0.792
Energy Management System 45.9% 100.0% 14 $0.35 1.7 0.47 $0.019
Cooking - Exhaust Hoods with Sensor
Control 1.0% 15.0% 10 $0.04 - - $0.000
Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.14 $0.072
Fans - Variable Speed Control 21.7% 100.0% 10 $0.20 0.6 0.27 $0.040
Retrocommissioning - HVAC 15.0% 100.0% 4 $0.30 0.1 0.31 $1.053
Pumps - Variable Speed Control 0.0% 45.0% 10 $0.13 0.0 0.01 $1.381
Thermostat - Clock/Programmable 33.0% 50.0% 11 $0.11 0.6 0.44 $0.022
Insulation - Ceiling 9.0% 40.0% 20 $0.85 0.1 0.31 $0.599
Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 0.0 0.30 $1.652
Roofs - High Reflectivity 1.5% 100.0% 15 $0.08 0.0 0.02 $0.482
Windows - High Efficiency 71.9% 100.0% 20 $0.88 0.1 0.31 $0.833
Interior Lighting - Central Lighting
Controls 85.7% 100.0% 8 $0.65 0.3 0.03 $0.328
Interior Lighting - Photocell
Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.45 0.8 0.15 $0.078
Exterior Lighting - Daylighting
Controls 1.6% 25.0% 8 $0.29 - 0.00 $0.000
Interior Fluorescent - Bi-Level Fixture
w/Occupancy Sensor 10.0% 30.0% 8 $0.40 0.3 0.07 $0.173
Interior Fluorescent - High Bay
Fixtures 15.4% 30.0% 11 $0.63 1.6 0.23 $0.042
Interior Lighting - Occupancy Sensors 23.2% 60.0% 8 $0.20 0.3 0.17 $0.101
Exterior Lighting - Photovoltaic
Installation 5.0% 25.0% 5 $0.92 - - $0.000
Interior Screw-in - Task Lighting 10.0% 100.0% 5 $0.24 0.1 0.02 $0.531
Interior Lighting - Time Clocks and
Timers 9.3% 75.0% 8 $0.20 0.1 0.09 $0.202
Water Heater - Faucet Aerators/Low
Flow Nozzles 47.9% 100.0% 9 $0.03 0.1 0.26 $0.042
Water Heater - Pipe Insulation 0.0% 0.0% 15 $0.28 0.1 0.04 $0.185
Water Heater - High Efficiency
Circulation Pump 0.6% 25.0% 10 $0.11 1.6 1.30 $0.008
Water Heater - Tank
Blanket/Insulation 0.0% 0.0% 10 $0.04 0.1 0.26 $0.041
Water Heater - Thermostat Setback 0.0% 0.0% 10 $0.11 0.1 0.07 $0.141
Refrigeration - Anti-Sweat
Heater/Auto Door Closer 0.0% 100.0% 16 $0.20 0.1 0.02 $0.321
Refrigeration - Floating Head
Pressure 38.0% 60.0% 16 $0.35 - 0.00 $0.000
Refrigeration - Door Gasket
Replacement 5.0% 100.0% 8 $0.10 0.0 0.02 $0.463
Insulation - Bare Suction Lines 5.0% 100.0% 8 $0.10 - - $0.000
Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.04 $0.449
Refrigeration - Strip Curtain 12.6% 56.3% 4 $0.00 0.0 18.97 $0.001
Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.1 0.01 $0.596
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1048 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-72 www.enernoc.com
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
LED Exit Lighting 46.9% 90.0% 10 $0.00 0.0 3.00 $0.006
Retrocommissioning - Lighting 24.1% 100.0% 5 $0.05 0.3 0.33 $0.038
Refrigeration - High Efficiency Case
Lighting 12.0% 56.0% 6 $0.04 0.0 0.00 $5.412
Exterior Lighting - Cold Cathode
Lighting 14.6% 50.0% 5 $0.00 0.3 15.57 $0.001
Laundry - High Efficiency Clothes
Washer 6.9% 10.0% 10 $0.00 0.0 4.57 $0.002
Interior Lighting - Hotel Guestroom
Controls 1.0% 2.0% 8 $0.14 0.1 0.03 $0.224
Miscellaneous - Energy Star Water
Cooler 24.1% 100.0% 8 $0.00 0.0 0.26 $0.047
Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 0.4 1.00 $0.000
Ventilation - Demand Control
Ventilation 7.9% 15.0% 10 $0.04 0.0 0.53 $0.315
Office Equipment - Smart Power
Strips 15.4% 30.0% 7 $0.00 0.5 353.57 $0.000
Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000
Refrigeration - Multiplex - Floating
section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex Controls -
Floating section Pressure - Evap.
Cond.
0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff. Air-
cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff.
Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
RTU - Maintenance 36.9% 100.0% 4 $0.06 0.4 0.30 $0.044
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.3 0.12 $0.060
Chiller - Chilled Water Reset 15.0% 100.0% 4 $0.18 0.4 0.11 $0.120
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.18 0.1 0.04 $0.226
Chiller - VSD 15.0% 88.2% 20 $1.17 0.7 0.05 $0.117
Chiller - High Efficiency Cooling
Tower Fans 15.0% 43.5% 10 $0.04 0.0 0.00 $11.820
Chiller - Condenser Water
Temprature Reset 18.5% 100.0% 14 $0.18 0.4 0.17 $0.046
Cooling - Economizer Installation 51.6% 65.0% 15 $0.15 0.2 0.14 $0.068
Heat Pump - Maintenance 28.1% 100.0% 4 $0.06 0.8 0.61 $0.021
Insulation - Ducting 8.0% 100.0% 20 $0.41 0.0 0.30 $2.323
Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.0 0.31 $0.792
Energy Management System 45.9% 100.0% 14 $0.35 1.7 0.47 $0.019
Cooking - Exhaust Hoods with Sensor
Control 1.0% 15.0% 10 $0.04 - - $0.000
Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.14 $0.072
Fans - Variable Speed Control 21.7% 100.0% 10 $0.20 0.6 0.27 $0.040
Retrocommissioning - HVAC 15.0% 100.0% 4 $0.30 0.1 0.31 $1.053
Pumps - Variable Speed Control 0.0% 45.0% 10 $0.13 0.0 0.01 $1.381
Thermostat - Clock/Programmable 33.0% 50.0% 11 $0.11 0.6 0.44 $0.022
Insulation - Ceiling 9.0% 40.0% 20 $0.85 0.1 0.31 $0.599
Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 0.0 0.30 $1.652

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1049 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-73
Table C-26 Energy Efficiency Non-Equipment Data— Large Commercial, New Vintage, Idaho
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
RTU - Maintenance 27.0% 100.0% 4 $0.06 0.2 0.19 $0.076
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.0 0.11 $0.073
Chiller - Chilled Water Reset 30.0% 100.0% 4 $0.18 0.3 0.10 $0.151
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.18 0.1 0.06 $0.168
Chiller - VSD 15.0% 88.2% 20 $1.17 0.6 0.05 $0.141
Chiller - High Efficiency Cooling
Tower Fans 15.0% 43.5% 10 $0.04 0.0 0.00 $10.716
Chiller - Condenser Water
Temprature Reset 31.4% 100.0% 14 $0.18 0.3 0.15 $0.058
Cooling - Economizer Installation 44.3% 65.0% 15 $0.15 - 0.03 $0.000
Heat Pump - Maintenance 28.1% 100.0% 4 $0.06 0.5 0.43 $0.034
Insulation - Ducting 8.0% 50.0% 20 $0.41 - 0.30 $0.000
Energy Management System 55.8% 100.0% 14 $0.35 1.6 0.47 $0.020
Cooking - Exhaust Hoods with Sensor
Control 1.0% 15.0% 10 $0.04 - - $0.000
Fans - Energy Efficient Motors 28.9% 100.0% 10 $0.05 0.1 0.17 $0.084
Fans - Variable Speed Control 47.3% 100.0% 10 $0.20 0.5 0.23 $0.051
Pumps - Variable Speed Control 5.0% 45.0% 10 $0.13 0.0 0.01 $1.313
Thermostat - Clock/Programmable 33.0% 50.0% 11 $0.11 0.4 0.29 $0.033
Insulation - Ceiling 75.0% 90.0% 20 $0.35 - 0.30 $0.000
Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 - 0.30 $0.000
Roofs - High Reflectivity 5.0% 100.0% 15 $0.05 - 0.01 $0.000
Windows - High Efficiency 71.9% 100.0% 20 $0.88 - 0.30 $0.000
Interior Lighting - Central Lighting
Controls 85.7% 100.0% 8 $0.65 0.4 0.06 $0.213
Interior Lighting - Photocell
Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.34 0.7 0.18 $0.068
Exterior Lighting - Daylighting
Controls 14.5% 25.0% 8 $0.19 1.7 0.75 $0.016
Interior Fluorescent - Bi-Level Fixture
w/Occupancy Sensor 10.0% 30.0% 8 $0.40 0.3 0.06 $0.201
Interior Fluorescent - High Bay
Fixtures 15.4% 30.0% 11 $0.63 1.4 0.21 $0.049
Interior Lighting - Occupancy Sensors 23.2% 60.0% 8 $0.20 0.4 0.24 $0.066
Exterior Lighting - Photovoltaic
Installation 5.0% 25.0% 5 $0.92 2.0 0.15 $0.100
Interior Screw-in - Task Lighting 10.0% 100.0% 5 $0.24 0.1 0.02 $0.538
Interior Lighting - Time Clocks and
Timers 15.2% 75.0% 8 $0.20 0.2 0.14 $0.131
Water Heater - Faucet Aerators/Low
Flow Nozzles 47.9% 100.0% 9 $0.03 0.1 0.26 $0.044
Water Heater - Pipe Insulation 0.0% 0.0% 15 $0.28 0.1 0.03 $0.295
Water Heater - High Efficiency
Circulation Pump 0.6% 25.0% 10 $0.11 1.6 1.28 $0.008
Water Heater - Tank
Blanket/Insulation 0.0% 0.0% 10 $0.04 0.1 0.25 $0.043
Water Heater - Thermostat Setback 0.0% 0.0% 10 $0.11 0.1 0.07 $0.147
Refrigeration - Anti-Sweat
Heater/Auto Door Closer 0.0% 100.0% 16 $0.20 0.0 0.03 $0.355
Refrigeration - Floating Head
Pressure 38.0% 60.0% 16 $0.35 0.1 0.02 $0.330
Refrigeration - Door Gasket
Replacement 5.0% 100.0% 8 $0.10 0.0 0.02 $0.662
Insulation - Bare Suction Lines 5.0% 100.0% 8 $0.10 0.1 0.08 $0.163
Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.04 $0.495
Refrigeration - Strip Curtain 29.7% 56.3% 4 $0.00 0.0 15.63 $0.001
Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.0 0.01 $0.684
LED Exit Lighting 91.2% 90.0% 10 $0.00 0.0 4.50 $0.006
Refrigeration - High Efficiency Case 24.0% 56.0% 6 $0.02 0.0 0.14 $0.102
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1050 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-74 www.enernoc.com
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Lighting
Exterior Lighting - Cold Cathode
Lighting 14.6% 50.0% 5 $0.00 0.3 18.13 $0.001
Laundry - High Efficiency Clothes
Washer 6.9% 10.0% 10 $0.00 0.0 5.03 $0.002
Interior Lighting - Hotel Guestroom
Controls 1.0% 2.0% 8 $0.14 0.1 0.05 $0.227
Miscellaneous - Energy Star Water
Cooler 11.9% 100.0% 8 $0.00 0.0 0.29 $0.042
Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 0.7 1.00 $0.000
Ventilation - Demand Control
Ventilation 15.0% 15.0% 10 $0.04 - 0.54 $0.000
Office Equipment - Smart Power
Strips 15.4% 30.0% 7 $0.00 0.3 219.97 $0.000
Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000
Refrigeration - Multiplex - Floating
section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex Controls -
Floating section Pressure - Evap.
Cond.
0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff. Air-
cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff.
Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
RTU - Maintenance 27.0% 100.0% 4 $0.06 0.2 0.19 $0.076
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.0 0.11 $0.073
Chiller - Chilled Water Reset 30.0% 100.0% 4 $0.18 0.3 0.10 $0.151
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.18 0.1 0.06 $0.168
Chiller - VSD 15.0% 88.2% 20 $1.17 0.6 0.05 $0.141
Chiller - High Efficiency Cooling
Tower Fans 15.0% 43.5% 10 $0.04 0.0 0.00 $10.716
Chiller - Condenser Water
Temprature Reset 31.4% 100.0% 14 $0.18 0.3 0.15 $0.058
Cooling - Economizer Installation 44.3% 65.0% 15 $0.15 - 0.03 $0.000
Heat Pump - Maintenance 28.1% 100.0% 4 $0.06 0.5 0.43 $0.034
Insulation - Ducting 8.0% 50.0% 20 $0.41 - 0.30 $0.000
Energy Management System 55.8% 100.0% 14 $0.35 1.6 0.47 $0.020
Cooking - Exhaust Hoods with Sensor
Control 1.0% 15.0% 10 $0.04 - - $0.000
Fans - Energy Efficient Motors 28.9% 100.0% 10 $0.05 0.1 0.17 $0.084
Fans - Variable Speed Control 47.3% 100.0% 10 $0.20 0.5 0.23 $0.051
Pumps - Variable Speed Control 5.0% 45.0% 10 $0.13 0.0 0.01 $1.313
Thermostat - Clock/Programmable 33.0% 50.0% 11 $0.11 0.4 0.29 $0.033
Insulation - Ceiling 75.0% 90.0% 20 $0.35 - 0.30 $0.000
Insulation - Radiant Barrier 7.0% 25.0% 20 $0.26 - 0.30 $0.000
Roofs - High Reflectivity 5.0% 100.0% 15 $0.05 - 0.01 $0.000
Windows - High Efficiency 71.9% 100.0% 20 $0.88 - 0.30 $0.000
Interior Lighting - Central Lighting
Controls 85.7% 100.0% 8 $0.65 0.4 0.06 $0.213
Interior Lighting - Photocell
Controlled T8 Dimming Ballasts 0.9% 60.0% 8 $0.34 0.7 0.18 $0.068
Exterior Lighting - Daylighting
Controls 14.5% 25.0% 8 $0.19 1.7 0.75 $0.016

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1051 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-75
Table C-27 Energy Efficiency Non-Equipment Data— Extra Large Commercial, Existing
Vintage, Washington
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
RTU - Maintenance 47.0% 100.0% 4 $0.06 0.3 0.27 $0.050
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.1 0.12 $0.068
Chiller - Chilled Water Reset 30.0% 100.0% 4 $0.09 0.3 0.19 $0.072
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.09 0.1 0.11 $0.097
Chiller - VSD 3.0% 100.0% 20 $1.17 0.7 0.07 $0.118
Chiller - High Efficiency Cooling
Tower Fans 25.0% 73.7% 10 $0.04 0.0 0.00 $12.451
Chiller - Condenser Water
Temprature Reset 31.4% 100.0% 14 $0.09 0.3 0.32 $0.024
Cooling - Economizer Installation 73.4% 90.0% 15 $0.15 0.0 0.03 $0.577
Heat Pump - Maintenance 5.0% 100.0% 4 $0.06 0.4 0.30 $0.043
Insulation - Ducting 2.0% 100.0% 20 $0.41 0.1 0.33 $0.274
Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.3 0.39 $0.099
Energy Management System 81.3% 100.0% 14 $0.35 4.1 1.10 $0.008
Cooking - Exhaust Hoods with Sensor
Control 1.0% 10.0% 10 $0.04 0.0 0.10 $0.103
Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.17 $0.061
Fans - Variable Speed Control 2.0% 100.0% 10 $0.20 0.6 0.29 $0.037
Retrocommissioning - HVAC 15.0% 100.0% 4 $0.20 0.2 0.36 $0.268
Pumps - Variable Speed Control 1.0% 45.0% 10 $0.44 0.0 0.00 $7.933
Thermostat - Clock/Programmable 25.0% 50.0% 11 $0.11 2.1 1.71 $0.006
Insulation - Ceiling 2.0% 90.0% 20 $0.85 0.2 0.33 $0.265
Insulation - Radiant Barrier 2.0% 25.0% 20 $0.26 0.0 0.32 $0.426
Roofs - High Reflectivity 0.0% 100.0% 15 $0.18 0.0 0.02 $0.687
Windows - High Efficiency 94.6% 100.0% 20 $2.10 0.1 0.30 $1.632
Interior Lighting - Central Lighting
Controls 78.1% 100.0% 8 $0.65 0.0 0.00 $3.005
Interior Lighting - Photocell
Controlled T8 Dimming Ballasts 2.5% 60.0% 8 $0.40 0.5 0.11 $0.105
Exterior Lighting - Daylighting
Controls 1.6% 20.0% 8 $0.29 0.3 0.06 $0.135
Interior Fluorescent - Bi-Level Fixture
w/Occupancy Sensor 10.0% 30.0% 8 $0.20 0.2 0.09 $0.131
Interior Fluorescent - High Bay
Fixtures 10.0% 30.0% 11 $0.56 1.1 0.18 $0.056
Interior Lighting - Occupancy Sensors 41.7% 60.0% 8 $0.20 0.0 0.07 $0.925
Exterior Lighting - Photovoltaic
Installation 5.0% 25.0% 5 $0.92 0.4 0.02 $0.549
Interior Screw-in - Task Lighting 5.0% 100.0% 5 $0.24 0.1 0.03 $0.366
Interior Lighting - Time Clocks and
Timers 12.1% 75.0% 8 $0.20 0.0 0.05 $1.849
Water Heater - Faucet Aerators/Low
Flow Nozzles 47.3% 100.0% 9 $0.03 0.1 0.43 $0.026
Water Heater - Pipe Insulation 0.0% 0.0% 15 $0.28 0.2 0.07 $0.115
Water Heater - High Efficiency
Circulation Pump 0.6% 25.0% 10 $0.11 2.6 2.11 $0.005
Water Heater - Tank
Blanket/Insulation 0.0% 0.0% 10 $0.04 0.2 0.41 $0.026
Water Heater - Thermostat Setback 0.0% 0.0% 10 $0.11 0.1 0.12 $0.088
Refrigeration - Anti-Sweat
Heater/Auto Door Closer 10.0% 100.0% 16 $0.20 0.0 0.01 $1.098
Refrigeration - Floating Head
Pressure 10.0% 50.0% 16 $0.35 0.0 0.00 $2.158
Refrigeration - Door Gasket
Replacement 5.0% 100.0% 8 $0.10 0.0 0.02 $0.505
Insulation - Bare Suction Lines 5.0% 100.0% 8 $0.10 0.0 0.01 $1.067
Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.06 $0.239
Refrigeration - Strip Curtain 12.6% 56.3% 4 $0.00 0.0 3.75 $0.004
Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.1 0.01 $0.566
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1052 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-76 www.enernoc.com
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
LED Exit Lighting 46.9% 90.0% 10 $0.00 0.0 4.54 $0.004
Retrocommissioning - Lighting 5.0% 100.0% 5 $0.05 0.1 0.09 $0.118
Refrigeration - High Efficiency Case
Lighting 12.0% 56.0% 6 $0.04 0.2 0.34 $0.043
Exterior Lighting - Cold Cathode
Lighting 14.6% 50.0% 5 $0.00 0.4 19.92 $0.000
Laundry - High Efficiency Clothes
Washer 6.9% 10.0% 10 $0.00 0.0 2.68 $0.004
Interior Lighting - Hotel Guestroom
Controls 0.0% 0.0% 8 $0.14 0.1 0.06 $0.154
Miscellaneous - Energy Star Water
Cooler 5.0% 100.0% 8 $0.00 0.0 0.15 $0.080
Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 0.0 1.00 $0.000
Ventilation - Demand Control
Ventilation 1.0% 10.0% 10 $0.04 0.0 0.13 $0.415
Office Equipment - Smart Power
Strips 15.4% 30.0% 7 $0.00 0.3 207.83 $0.000
Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000
Refrigeration - Multiplex - Floating
section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex Controls -
Floating section Pressure - Evap.
Cond.
0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff. Air-
cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff.
Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
RTU - Maintenance 47.0% 100.0% 4 $0.06 0.3 0.27 $0.050
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.1 0.12 $0.068
Chiller - Chilled Water Reset 30.0% 100.0% 4 $0.09 0.3 0.19 $0.072
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.09 0.1 0.11 $0.097
Chiller - VSD 3.0% 100.0% 20 $1.17 0.7 0.07 $0.118
Chiller - High Efficiency Cooling
Tower Fans 25.0% 73.7% 10 $0.04 0.0 0.00 $12.451
Chiller - Condenser Water
Temprature Reset 31.4% 100.0% 14 $0.09 0.3 0.32 $0.024
Cooling - Economizer Installation 73.4% 90.0% 15 $0.15 0.0 0.03 $0.577
Heat Pump - Maintenance 5.0% 100.0% 4 $0.06 0.4 0.30 $0.043
Insulation - Ducting 2.0% 100.0% 20 $0.41 0.1 0.33 $0.274
Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.3 0.39 $0.099
Energy Management System 81.3% 100.0% 14 $0.35 4.1 1.10 $0.008
Cooking - Exhaust Hoods with Sensor
Control 1.0% 10.0% 10 $0.04 0.0 0.10 $0.103
Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.17 $0.061
Fans - Variable Speed Control 2.0% 100.0% 10 $0.20 0.6 0.29 $0.037
Retrocommissioning - HVAC 15.0% 100.0% 4 $0.20 0.2 0.36 $0.268
Pumps - Variable Speed Control 1.0% 45.0% 10 $0.44 0.0 0.00 $7.933
Thermostat - Clock/Programmable 25.0% 50.0% 11 $0.11 2.1 1.71 $0.006
Insulation - Ceiling 2.0% 90.0% 20 $0.85 0.2 0.33 $0.265
Insulation - Radiant Barrier 2.0% 25.0% 20 $0.26 0.0 0.32 $0.426

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1053 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-77
Table C-28 Energy Efficiency Non-Equipment Data— Extra Large Commercial, New
Vintage, Washington
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
RTU - Maintenance 47.0% 100.0% 4 $0.06 0.2 0.17 $0.086
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 0.9 0.11 $0.082
Chiller - Chilled Water Reset 60.0% 100.0% 4 $0.09 0.3 0.16 $0.091
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.09 0.1 0.08 $0.127
Chiller - VSD 3.0% 100.0% 20 $1.17 0.6 0.06 $0.138
Chiller - High Efficiency Cooling
Tower Fans 25.0% 73.7% 10 $0.04 0.0 0.00 $11.601
Chiller - Condenser Water
Temprature Reset 57.1% 100.0% 14 $0.09 0.3 0.34 $0.030
Cooling - Economizer Installation 73.4% 90.0% 15 $0.15 - 0.02 $0.000
Heat Pump - Maintenance 5.0% 100.0% 4 $0.06 0.2 0.18 $0.082
Insulation - Ducting 2.0% 50.0% 20 $0.41 - 0.31 $0.000
Energy Management System 80.0% 100.0% 14 $0.35 2.7 0.78 $0.012
Cooking - Exhaust Hoods with Sensor
Control 1.0% 10.0% 10 $0.04 0.0 0.10 $0.117
Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.16 $0.070
Fans - Variable Speed Control 2.0% 100.0% 10 $0.20 0.6 0.31 $0.037
Pumps - Variable Speed Control 1.0% 45.0% 10 $0.44 0.0 0.00 $7.545
Thermostat - Clock/Programmable 25.0% 50.0% 11 $0.11 2.0 1.61 $0.006
Insulation - Ceiling 2.0% 90.0% 20 $0.35 - 0.31 $0.000
Insulation - Radiant Barrier 2.0% 25.0% 20 $0.26 - 0.30 $0.000
Roofs - High Reflectivity 5.0% 100.0% 15 $0.18 - 0.01 $0.000
Windows - High Efficiency 94.6% 100.0% 20 $1.69 - 0.30 $0.000
Interior Lighting - Central Lighting
Controls 78.1% 100.0% 8 $0.65 - - $0.000
Interior Lighting - Photocell
Controlled T8 Dimming Ballasts 2.5% 60.0% 8 $0.30 0.5 0.14 $0.086
Exterior Lighting - Daylighting
Controls 10.0% 20.0% 8 $0.19 - 0.00 $0.000
Interior Fluorescent - Bi-Level Fixture
w/Occupancy Sensor 10.0% 30.0% 8 $0.20 0.2 0.09 $0.143
Interior Fluorescent - High Bay
Fixtures 10.0% 30.0% 11 $0.56 1.0 0.17 $0.061
Interior Lighting - Occupancy Sensors 41.7% 60.0% 8 $0.20 - 0.06 $0.000
Exterior Lighting - Photovoltaic
Installation 5.0% 25.0% 5 $0.92 - - $0.000
Interior Screw-in - Task Lighting 25.0% 100.0% 5 $0.24 0.1 0.04 $0.376
Interior Lighting - Time Clocks and
Timers 12.1% 75.0% 8 $0.20 - 0.04 $0.000
Water Heater - Faucet Aerators/Low
Flow Nozzles 47.3% 100.0% 9 $0.03 0.1 0.43 $0.027
Water Heater - Pipe Insulation 0.0% 0.0% 15 $0.28 0.1 0.05 $0.180
Water Heater - High Efficiency
Circulation Pump 0.6% 25.0% 10 $0.11 2.5 2.10 $0.005
Water Heater - Tank
Blanket/Insulation 0.0% 0.0% 10 $0.04 0.1 0.21 $0.052
Water Heater - Thermostat Setback 0.0% 0.0% 10 $0.11 0.1 0.12 $0.090
Refrigeration - Anti-Sweat
Heater/Auto Door Closer 10.0% 100.0% 16 $0.20 0.0 0.01 $1.217
Refrigeration - Floating Head
Pressure 10.0% 50.0% 16 $0.35 0.2 0.04 $0.188
Refrigeration - Door Gasket
Replacement 5.0% 100.0% 8 $0.10 0.0 0.02 $0.721
Insulation - Bare Suction Lines 5.0% 100.0% 8 $0.10 0.2 0.13 $0.093
Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.06 $0.263
Refrigeration - Strip Curtain 29.7% 56.3% 4 $0.00 0.0 3.12 $0.005
Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.0 0.01 $0.784
LED Exit Lighting 91.2% 90.0% 10 $0.00 0.0 5.08 $0.004
Refrigeration - High Efficiency Case 26.1% 56.0% 6 $0.02 0.1 0.87 $0.041
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1054 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-78 www.enernoc.com
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Lighting
Exterior Lighting - Cold Cathode
Lighting 14.6% 50.0% 5 $0.00 0.3 22.34 $0.001
Laundry - High Efficiency Clothes
Washer 6.9% 10.0% 10 $0.00 0.0 2.95 $0.004
Interior Lighting - Hotel Guestroom
Controls 0.0% 0.0% 8 $0.14 0.1 0.07 $0.158
Miscellaneous - Energy Star Water
Cooler 5.0% 100.0% 8 $0.00 0.0 0.17 $0.073
Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Ventilation - Demand Control
Ventilation 5.9% 10.0% 10 $0.04 - 0.11 $0.000
Office Equipment - Smart Power
Strips 15.4% 30.0% 7 $0.00 0.3 219.19 $0.000
Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000
Refrigeration - Multiplex - Floating
section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex Controls -
Floating section Pressure - Evap.
Cond.
0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff. Air-
cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff.
Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
RTU - Maintenance 47.0% 100.0% 4 $0.06 0.2 0.17 $0.086
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 0.9 0.11 $0.082
Chiller - Chilled Water Reset 60.0% 100.0% 4 $0.09 0.3 0.16 $0.091
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.09 0.1 0.08 $0.127
Chiller - VSD 3.0% 100.0% 20 $1.17 0.6 0.06 $0.138
Chiller - High Efficiency Cooling
Tower Fans 25.0% 73.7% 10 $0.04 0.0 0.00 $11.601
Chiller - Condenser Water
Temprature Reset 57.1% 100.0% 14 $0.09 0.3 0.34 $0.030
Cooling - Economizer Installation 73.4% 90.0% 15 $0.15 - 0.02 $0.000
Heat Pump - Maintenance 5.0% 100.0% 4 $0.06 0.2 0.18 $0.082
Insulation - Ducting 2.0% 50.0% 20 $0.41 - 0.31 $0.000
Energy Management System 80.0% 100.0% 14 $0.35 2.7 0.78 $0.012
Cooking - Exhaust Hoods with Sensor
Control 1.0% 10.0% 10 $0.04 0.0 0.10 $0.117
Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.16 $0.070
Fans - Variable Speed Control 2.0% 100.0% 10 $0.20 0.6 0.31 $0.037
Pumps - Variable Speed Control 1.0% 45.0% 10 $0.44 0.0 0.00 $7.545
Thermostat - Clock/Programmable 25.0% 50.0% 11 $0.11 2.0 1.61 $0.006
Insulation - Ceiling 2.0% 90.0% 20 $0.35 - 0.31 $0.000
Insulation - Radiant Barrier 2.0% 25.0% 20 $0.26 - 0.30 $0.000
Roofs - High Reflectivity 5.0% 100.0% 15 $0.18 - 0.01 $0.000
Windows - High Efficiency 94.6% 100.0% 20 $1.69 - 0.30 $0.000
Interior Lighting - Central Lighting
Controls 78.1% 100.0% 8 $0.65 - - $0.000
Interior Lighting - Photocell
Controlled T8 Dimming Ballasts 2.5% 60.0% 8 $0.30 0.5 0.14 $0.086
Exterior Lighting - Daylighting
Controls 10.0% 20.0% 8 $0.19 - 0.00 $0.000

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1055 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-79
Table C-29 Energy Efficiency Non-Equipment Data— Extra Large Commercial, Existing
Vintage, Idaho
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
RTU - Maintenance 54.2% 100.0% 4 $0.06 0.3 0.26 $0.050
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.1 0.12 $0.068
Chiller - Chilled Water Reset 36.0% 100.0% 4 $0.09 0.3 0.19 $0.072
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.09 0.1 0.11 $0.097
Chiller - VSD 3.0% 100.0% 20 $1.17 0.7 0.06 $0.118
Chiller - High Efficiency Cooling
Tower Fans 25.0% 73.7% 10 $0.04 0.0 0.00 $12.451
Chiller - Condenser Water
Temprature Reset 31.4% 100.0% 14 $0.09 0.3 0.37 $0.025
Cooling - Economizer Installation 73.4% 90.0% 15 $0.15 0.0 0.02 $1.832
Heat Pump - Maintenance 24.1% 100.0% 4 $0.06 0.8 0.66 $0.021
Insulation - Ducting 2.0% 100.0% 20 $0.41 0.0 0.32 $0.695
Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.1 0.34 $0.240
Energy Management System 82.8% 100.0% 14 $0.35 2.9 0.78 $0.011
Cooking - Exhaust Hoods with Sensor
Control 1.0% 10.0% 10 $0.04 0.0 0.11 $0.098
Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.17 $0.061
Fans - Variable Speed Control 21.7% 100.0% 10 $0.20 0.6 0.29 $0.037
Retrocommissioning - HVAC 15.0% 100.0% 4 $0.20 0.1 0.32 $0.714
Pumps - Variable Speed Control 1.0% 45.0% 10 $0.44 0.0 0.00 $7.933
Thermostat - Clock/Programmable 25.0% 50.0% 11 $0.11 1.3 1.02 $0.010
Insulation - Ceiling 2.0% 90.0% 20 $0.85 0.1 0.32 $0.687
Insulation - Radiant Barrier 2.0% 25.0% 20 $0.26 0.0 0.31 $1.057
Roofs - High Reflectivity 0.0% 100.0% 15 $0.18 0.0 0.02 $2.179
Windows - High Efficiency 94.6% 100.0% 20 $2.10 0.0 0.30 $3.948
Interior Lighting - Central Lighting
Controls 78.1% 100.0% 8 $0.65 - - $0.000
Interior Lighting - Photocell
Controlled T8 Dimming Ballasts 2.5% 60.0% 8 $0.40 0.5 0.11 $0.105
Exterior Lighting - Daylighting
Controls 1.6% 20.0% 8 $0.29 - 0.00 $0.000
Interior Fluorescent - Bi-Level Fixture
w/Occupancy Sensor 10.0% 30.0% 8 $0.20 0.2 0.09 $0.131
Interior Fluorescent - High Bay
Fixtures 11.4% 30.0% 11 $0.56 1.1 0.17 $0.056
Interior Lighting - Occupancy Sensors 43.5% 60.0% 8 $0.20 - 0.06 $0.000
Exterior Lighting - Photovoltaic
Installation 0.0% 0.0% 0 $0.00 - - $0.000
Interior Screw-in - Task Lighting 0.0% 0.0% 0 $0.00 - - $0.000
Interior Lighting - Time Clocks and
Timers 0.0% 0.0% 0 $0.00 - - $0.000
Water Heater - Faucet Aerators/Low
Flow Nozzles 0.0% 0.0% 0 $0.00 - - $0.000
Water Heater - Pipe Insulation 0.0% 0.0% 0 $0.00 - - $0.000
Water Heater - High Efficiency
Circulation Pump 0.0% 0.0% 0 $0.00 - - $0.000
Water Heater - Tank
Blanket/Insulation 0.0% 0.0% 0 $0.00 - - $0.000
Water Heater - Thermostat Setback 0.0% 0.0% 0 $0.00 - - $0.000
Refrigeration - Anti-Sweat
Heater/Auto Door Closer 0.0% 0.0% 0 $0.00 - - $0.000
Refrigeration - Floating Head
Pressure 0.0% 0.0% 0 $0.00 - - $0.000
Refrigeration - Door Gasket
Replacement 0.0% 0.0% 0 $0.00 - - $0.000
Insulation - Bare Suction Lines 0.0% 0.0% 0 $0.00 - - $0.000
Refrigeration - Night Covers 0.0% 0.0% 0 $0.00 - - $0.000
Refrigeration - Strip Curtain 0.0% 0.0% 0 $0.00 - - $0.000
Vending Machine - Controller 0.0% 0.0% 0 $0.00 - - $0.000
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1056 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-80 www.enernoc.com
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
LED Exit Lighting 0.0% 0.0% 0 $0.00 - - $0.000
Retrocommissioning - Lighting 0.0% 0.0% 0 $0.00 - - $0.000
Refrigeration - High Efficiency Case
Lighting 0.0% 0.0% 0 $0.00 - - $0.000
Exterior Lighting - Cold Cathode
Lighting 0.0% 0.0% 0 $0.00 - - $0.000
Laundry - High Efficiency Clothes
Washer 0.0% 0.0% 0 $0.00 - - $0.000
Interior Lighting - Hotel Guestroom
Controls 0.0% 0.0% 0 $0.00 - - $0.000
Miscellaneous - Energy Star Water
Cooler 0.0% 0.0% 0 $0.00 - - $0.000
Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 - - $0.000
Ventilation - Demand Control
Ventilation 0.0% 0.0% 0 $0.00 - - $0.000
Office Equipment - Smart Power
Strips 0.0% 0.0% 0 $0.00 - - $0.000
Strategic Energy Management 0.0% 0.0% 0 $0.00 - - $0.000
Refrigeration - Multiplex - Floating
section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - - $0.000
Refrigeration - Multiplex Controls -
Floating section Pressure - Evap.
Cond.
0.0% 0.0% 0 $0.00 - - $0.000
Refrigeration - Multiplex - Eff. Air-
cooled Condenser 0.0% 0.0% 0 $0.00 - - $0.000
Refrigeration - Multiplex - Eff.
Water-cooled Condenser 0.0% 0.0% 0 $0.00 - - $0.000
RTU - Maintenance 54.2% 100.0% 4 $0.06 0.3 0.26 $0.050
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 1.1 0.12 $0.068
Chiller - Chilled Water Reset 36.0% 100.0% 4 $0.09 0.3 0.19 $0.072
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.09 0.1 0.11 $0.097
Chiller - VSD 3.0% 100.0% 20 $1.17 0.7 0.06 $0.118
Chiller - High Efficiency Cooling
Tower Fans 25.0% 73.7% 10 $0.04 0.0 0.00 $12.451
Chiller - Condenser Water
Temprature Reset 31.4% 100.0% 14 $0.09 0.3 0.37 $0.025
Cooling - Economizer Installation 73.4% 90.0% 15 $0.15 0.0 0.02 $1.832
Heat Pump - Maintenance 24.1% 100.0% 4 $0.06 0.8 0.66 $0.021
Insulation - Ducting 2.0% 100.0% 20 $0.41 0.0 0.32 $0.695
Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.1 0.34 $0.240
Energy Management System 82.8% 100.0% 14 $0.35 2.9 0.78 $0.011
Cooking - Exhaust Hoods with Sensor
Control 1.0% 10.0% 10 $0.04 0.0 0.11 $0.098
Fans - Energy Efficient Motors 11.0% 100.0% 10 $0.05 0.1 0.17 $0.061
Fans - Variable Speed Control 21.7% 100.0% 10 $0.20 0.6 0.29 $0.037
Retrocommissioning - HVAC 15.0% 100.0% 4 $0.20 0.1 0.32 $0.714
Pumps - Variable Speed Control 1.0% 45.0% 10 $0.44 0.0 0.00 $7.933
Thermostat - Clock/Programmable 25.0% 50.0% 11 $0.11 1.3 1.02 $0.010
Insulation - Ceiling 2.0% 90.0% 20 $0.85 0.1 0.32 $0.687
Insulation - Radiant Barrier 2.0% 25.0% 20 $0.26 0.0 0.31 $1.057

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1057 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-81
Table C-30 Energy Efficiency Non-Equipment Data— Extra Large Commercial, New
Vintage, Idaho
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
RTU - Maintenance 48.7% 100.0% 4 $0.06 0.2 0.17 $0.086
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 0.9 0.11 $0.082
Chiller - Chilled Water Reset 60.0% 100.0% 4 $0.09 0.3 0.17 $0.091
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.09 0.1 0.09 $0.127
Chiller - VSD 3.0% 100.0% 20 $1.17 0.6 0.06 $0.138
Chiller - High Efficiency Cooling
Tower Fans 25.0% 73.7% 10 $0.04 0.0 0.00 $11.601
Chiller - Condenser Water
Temprature Reset 57.1% 100.0% 14 $0.09 0.3 0.37 $0.030
Cooling - Economizer Installation 73.4% 90.0% 15 $0.15 - 0.02 $0.000
Heat Pump - Maintenance 24.1% 100.0% 4 $0.06 0.6 0.58 $0.026
Insulation - Ducting 4.6% 50.0% 20 $0.41 0.3 0.38 $0.088
Energy Management System 82.8% 100.0% 14 $0.35 2.5 0.73 $0.013
Cooking - Exhaust Hoods with Sensor
Control 1.0% 10.0% 10 $0.04 0.0 0.10 $0.111
Fans - Energy Efficient Motors 28.9% 100.0% 10 $0.05 0.1 0.18 $0.070
Fans - Variable Speed Control 47.3% 100.0% 10 $0.20 0.6 0.31 $0.037
Pumps - Variable Speed Control 1.0% 45.0% 10 $0.44 0.0 0.00 $7.545
Thermostat - Clock/Programmable 30.3% 50.0% 11 $0.11 1.6 1.33 $0.007
Insulation - Ceiling 14.5% 90.0% 20 $0.35 0.4 0.43 $0.056
Insulation - Radiant Barrier 5.5% 25.0% 20 $0.26 0.9 0.62 $0.021
Roofs - High Reflectivity 5.0% 100.0% 15 $0.18 - 0.01 $0.000
Windows - High Efficiency 94.6% 100.0% 20 $1.69 1.1 0.36 $0.106
Interior Lighting - Central Lighting
Controls 82.5% 100.0% 8 $0.65 3.0 0.39 $0.031
Interior Lighting - Photocell
Controlled T8 Dimming Ballasts 2.5% 60.0% 8 $0.30 0.5 0.14 $0.086
Exterior Lighting - Daylighting
Controls 10.0% 20.0% 8 $0.19 0.3 0.16 $0.079
Interior Fluorescent - Bi-Level Fixture
w/Occupancy Sensor 10.0% 30.0% 8 $0.20 0.2 0.09 $0.143
Interior Fluorescent - High Bay
Fixtures 10.8% 30.0% 11 $0.56 1.0 0.17 $0.061
Interior Lighting - Occupancy Sensors 48.7% 60.0% 8 $0.20 3.0 1.32 $0.009
Exterior Lighting - Photovoltaic
Installation 5.0% 25.0% 5 $0.92 0.4 0.03 $0.481
Interior Screw-in - Task Lighting 25.0% 100.0% 5 $0.24 0.1 0.04 $0.376
Interior Lighting - Time Clocks and
Timers 25.4% 75.0% 8 $0.20 1.5 0.67 $0.019
Water Heater - Faucet Aerators/Low
Flow Nozzles 47.3% 100.0% 9 $0.03 0.1 0.44 $0.027
Water Heater - Pipe Insulation 0.0% 0.0% 15 $0.28 0.1 0.05 $0.180
Water Heater - High Efficiency
Circulation Pump 0.6% 25.0% 10 $0.11 2.5 2.16 $0.005
Water Heater - Tank
Blanket/Insulation 0.0% 0.0% 10 $0.04 0.1 0.21 $0.052
Water Heater - Thermostat Setback 0.0% 0.0% 10 $0.11 0.1 0.12 $0.090
Refrigeration - Anti-Sweat
Heater/Auto Door Closer 0.0% 100.0% 16 $0.20 0.0 0.01 $1.217
Refrigeration - Floating Head
Pressure 10.0% 50.0% 16 $0.35 0.5 0.13 $0.063
Refrigeration - Door Gasket
Replacement 5.0% 100.0% 8 $0.10 0.0 0.02 $0.721
Insulation - Bare Suction Lines 18.5% 100.0% 8 $0.10 0.5 0.39 $0.031
Refrigeration - Night Covers 5.0% 100.0% 8 $0.05 0.0 0.06 $0.263
Refrigeration - Strip Curtain 29.7% 56.3% 4 $0.00 0.0 3.11 $0.005
Vending Machine - Controller 2.0% 10.0% 10 $0.27 0.0 0.01 $0.784
LED Exit Lighting 91.2% 90.0% 10 $0.00 0.0 5.56 $0.004
Refrigeration - High Efficiency Case 24.0% 56.0% 6 $0.02 0.0 0.09 $0.170
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1058 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-82 www.enernoc.com
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Lighting
Exterior Lighting - Cold Cathode
Lighting 14.6% 50.0% 5 $0.00 0.3 23.65 $0.001
Laundry - High Efficiency Clothes
Washer 6.9% 10.0% 10 $0.00 0.0 2.93 $0.004
Interior Lighting - Hotel Guestroom
Controls 1.0% 2.0% 8 $0.14 0.1 0.08 $0.158
Miscellaneous - Energy Star Water
Cooler 5.0% 100.0% 8 $0.00 0.0 0.17 $0.073
Interior Lighting - Skylights 0.0% 0.0% 0 $0.00 4.5 1.00 $0.000
Ventilation - Demand Control
Ventilation 10.2% 10.0% 10 $0.04 0.6 1.34 $0.009
Office Equipment - Smart Power
Strips 15.4% 30.0% 7 $0.00 0.3 232.67 $0.000
Strategic Energy Management 0.0% 0.0% 3 $0.00 - 6.00 $0.000
Refrigeration - Multiplex - Floating
section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex Controls -
Floating section Pressure - Evap.
Cond.
0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff. Air-
cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff.
Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
RTU - Maintenance 48.7% 100.0% 4 $0.06 0.2 0.17 $0.086
RTU - Evaporative Precooler 0.0% 0.0% 15 $0.88 0.9 0.11 $0.082
Chiller - Chilled Water Reset 60.0% 100.0% 4 $0.09 0.3 0.17 $0.091
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.09 0.1 0.09 $0.127
Chiller - VSD 3.0% 100.0% 20 $1.17 0.6 0.06 $0.138
Chiller - High Efficiency Cooling
Tower Fans 25.0% 73.7% 10 $0.04 0.0 0.00 $11.601
Chiller - Condenser Water
Temprature Reset 57.1% 100.0% 14 $0.09 0.3 0.37 $0.030
Cooling - Economizer Installation 73.4% 90.0% 15 $0.15 - 0.02 $0.000
Heat Pump - Maintenance 24.1% 100.0% 4 $0.06 0.6 0.58 $0.026
Insulation - Ducting 4.6% 50.0% 20 $0.41 0.3 0.38 $0.088
Energy Management System 82.8% 100.0% 14 $0.35 2.5 0.73 $0.013
Cooking - Exhaust Hoods with Sensor
Control 1.0% 10.0% 10 $0.04 0.0 0.10 $0.111
Fans - Energy Efficient Motors 28.9% 100.0% 10 $0.05 0.1 0.18 $0.070
Fans - Variable Speed Control 47.3% 100.0% 10 $0.20 0.6 0.31 $0.037
Pumps - Variable Speed Control 1.0% 45.0% 10 $0.44 0.0 0.00 $7.545
Thermostat - Clock/Programmable 30.3% 50.0% 11 $0.11 1.6 1.33 $0.007
Insulation - Ceiling 14.5% 90.0% 20 $0.35 0.4 0.43 $0.056
Insulation - Radiant Barrier 5.5% 25.0% 20 $0.26 0.9 0.62 $0.021
Roofs - High Reflectivity 5.0% 100.0% 15 $0.18 - 0.01 $0.000
Windows - High Efficiency 94.6% 100.0% 20 $1.69 1.1 0.36 $0.106
Interior Lighting - Central Lighting
Controls 82.5% 100.0% 8 $0.65 3.0 0.39 $0.031
Interior Lighting - Photocell
Controlled T8 Dimming Ballasts 2.5% 60.0% 8 $0.30 0.5 0.14 $0.086
Exterior Lighting - Daylighting
Controls 10.0% 20.0% 8 $0.19 0.3 0.16 $0.079

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1059 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-83
Table C-31 Energy Efficiency Non-Equipment Data— Extra Large Industrial, Existing
Vintage, Washington
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Refrigeration - System Controls 5.0% 45.0% 10 $0.40 0.2 0.06 $0.198
Refrigeration - System Maintenance 13.6% 45.0% 10 $0.00 0.1 7.74 $0.001
Refrigeration - System Optimization 5.0% 45.0% 10 $0.80 0.2 0.03 $0.396
Motors - Variable Frequency Drive 25.0% 50.0% 10 $0.10 - 0.00 $0.000
Motors - Magnetic Adjustable Speed
Drives 20.0% 25.0% 10 $0.10 - 0.02 $0.000
Compressed Air - System Controls 0.0% 0.0% 15 $0.01 - 0.08 $0.000
Compressed Air - System
Optimization and Improvements 35.0% 75.0% 10 $0.20 - 0.01 $0.000
Compressed Air - System
Maintenance 0.0% 0.0% 3 $0.03 - - $0.000
Compressed Air - Compressor
Replacement 14.6% 17.1% 10 $0.06 - 0.02 $0.000
Fan System - Controls 7.8% 8.2% 10 $0.01 0.0 0.37 $0.036
Fan System - Optimization 6.6% 8.9% 10 $0.13 0.2 0.15 $0.085
Fan System - Maintenance 3.0% 11.3% 3 $0.01 0.0 0.07 $0.251
Pumping System - Controls 6.9% 9.3% 10 $0.01 - 0.02 $0.000
Pumping System - Optimization 6.7% 9.0% 10 $0.28 - 0.01 $0.000
Pumping System - Maintenance 1.5% 10.1% 3 $0.02 - - $0.000
RTU - Maintenance 21.9% 100.0% 4 $0.06 0.4 0.29 $0.045
Chiller - Chilled Water Reset 30.0% 100.0% 4 $0.09 0.4 0.22 $0.062
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.20 0.1 0.04 $0.236
Chiller - VSD 15.0% 89.0% 20 $1.17 0.8 0.06 $0.105
Chiller - High Efficiency Cooling
Tower Fans 25.0% 100.0% 10 $0.04 0.0 0.00 $9.998
Chiller - Condenser Water
Temprature Reset 0.0% 100.0% 14 $0.20 0.4 0.17 $0.045
Cooling - Economizer Installation 29.1% 45.0% 15 $0.15 0.1 0.03 $0.211
Heat Pump - Maintenance 21.7% 100.0% 4 $0.03 1.1 1.82 $0.007
Insulation - Ducting 11.8% 100.0% 20 $0.41 0.0 0.31 $4.048
Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.0 0.31 $1.794
Energy Management System 11.0% 100.0% 14 $0.35 4.3 1.10 $0.007
Fans - Energy Efficient Motors 0.0% 0.0% 10 $0.14 0.1 0.07 $0.159
Fans - Variable Speed Control 0.0% 0.0% 10 $0.20 0.4 0.17 $0.057
Retrocommissioning - HVAC 1.4% 93.3% 4 $0.25 0.0 0.31 $2.167
Pumps - Variable Speed Control 0.1% 0.0% 10 $0.44 - 0.00 $0.000
Thermostat - Clock/Programmable 59.0% 70.0% 11 $0.11 2.0 1.71 $0.006
Interior Lighting - Central Lighting
Controls 83.7% 100.0% 8 $0.65 0.0 0.00 $22.297
Exterior Lighting - Daylighting
Controls 1.6% 53.6% 8 $0.08 - 0.00 $0.000
Interior Fluorescent - High Bay
Fixtures 19.1% 50.0% 11 $0.20 1.7 0.59 $0.013
LED Exit Lighting 46.9% 90.0% 10 $0.00 0.0 1.34 $0.006
Retrocommissioning - Lighting 9.0% 93.0% 5 $0.05 0.0 0.00 $2.594
Interior Lighting - Occupancy Sensors 14.7% 60.0% 8 $0.20 0.0 0.00 $6.861
Exterior Lighting - Photovoltaic
Installation 5.0% 25.0% 5 $0.92 - - $0.000
Interior Screw-in - Task Lighting 10.0% 100.0% 5 $0.24 0.1 0.02 $0.500
Interior Lighting - Time Clocks and
Timers 2.4% 75.0% 8 $0.20 0.0 0.04 $13.721
Exterior Lighting - Cold Cathode
Lighting 14.6% 50.0% 5 $0.00 0.4 16.94 $0.001
Interior Lighting - Skylights 1.2% 40.6% 8 $0.29 0.0 0.00 $6.518
Ventilation - Demand Control
Ventilation 1.0% 10.0% 10 $0.04 0.0 0.14 $0.103
Strategic Energy Management 0.0% 20.0% 3 $0.02 0.0 0.09 $0.173
Transformers 8.6% 9.4% 10 $0.13 0.0 0.04 $0.413
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1060 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-84 www.enernoc.com
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Motors - Synchronous belts 17.3% 21.0% 10 $0.22 - 0.00 $0.000
Refrigeration - Multiplex - Floating
section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex Controls -
Floating section Pressure - Evap.
Cond.
0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff. Air-
cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff.
Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - System Controls 5.0% 45.0% 10 $0.40 0.2 0.06 $0.198
Refrigeration - System Maintenance 13.6% 45.0% 10 $0.00 0.1 7.74 $0.001
Refrigeration - System Optimization 5.0% 45.0% 10 $0.80 0.2 0.03 $0.396
Motors - Variable Frequency Drive 25.0% 50.0% 10 $0.10 - 0.00 $0.000
Motors - Magnetic Adjustable Speed
Drives 20.0% 25.0% 10 $0.10 - 0.02 $0.000
Compressed Air - System Controls 0.0% 0.0% 15 $0.01 - 0.08 $0.000
Compressed Air - System
Optimization and Improvements 35.0% 75.0% 10 $0.20 - 0.01 $0.000
Compressed Air - System
Maintenance 0.0% 0.0% 3 $0.03 - - $0.000
Compressed Air - Compressor
Replacement 14.6% 17.1% 10 $0.06 - 0.02 $0.000
Fan System - Controls 7.8% 8.2% 10 $0.01 0.0 0.37 $0.036
Fan System - Optimization 6.6% 8.9% 10 $0.13 0.2 0.15 $0.085
Fan System - Maintenance 3.0% 11.3% 3 $0.01 0.0 0.07 $0.251
Pumping System - Controls 6.9% 9.3% 10 $0.01 - 0.02 $0.000
Pumping System - Optimization 6.7% 9.0% 10 $0.28 - 0.01 $0.000
Pumping System - Maintenance 1.5% 10.1% 3 $0.02 - - $0.000
RTU - Maintenance 21.9% 100.0% 4 $0.06 0.4 0.29 $0.045
Chiller - Chilled Water Reset 30.0% 100.0% 4 $0.09 0.4 0.22 $0.062
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.20 0.1 0.04 $0.236
Chiller - VSD 15.0% 89.0% 20 $1.17 0.8 0.06 $0.105
Chiller - High Efficiency Cooling
Tower Fans 25.0% 100.0% 10 $0.04 0.0 0.00 $9.998
Chiller - Condenser Water
Temprature Reset 0.0% 100.0% 14 $0.20 0.4 0.17 $0.045
Cooling - Economizer Installation 29.1% 45.0% 15 $0.15 0.1 0.03 $0.211
Heat Pump - Maintenance 21.7% 100.0% 4 $0.03 1.1 1.82 $0.007
Insulation - Ducting 11.8% 100.0% 20 $0.41 0.0 0.31 $4.048
Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 0.0 0.31 $1.794
Energy Management System 11.0% 100.0% 14 $0.35 4.3 1.10 $0.007
Fans - Energy Efficient Motors 0.0% 0.0% 10 $0.14 0.1 0.07 $0.159
Fans - Variable Speed Control 0.0% 0.0% 10 $0.20 0.4 0.17 $0.057

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1061 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-85
Table C-32 Energy Efficiency Non-Equipment Data— Extra Large Industrial, New
Vintage, Washington
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Refrigeration - System Controls 5.0% 45.0% 10 $0.40 0.2 0.06 $0.198
Refrigeration - System Maintenance 13.6% 45.0% 10 $0.00 0.1 7.89 $0.001
Refrigeration - System Optimization 5.0% 45.0% 10 $0.80 0.2 0.03 $0.396
Motors - Variable Frequency Drive 25.0% 50.0% 10 $0.10 0.2 0.15 $0.072
Motors - Magnetic Adjustable Speed
Drives 24.0% 25.0% 10 $0.10 0.7 0.65 $0.017
Compressed Air - System Controls 0.0% 0.0% 15 $0.01 0.3 2.98 $0.003
Compressed Air - System
Optimization and Improvements 44.8% 75.0% 10 $0.20 0.8 0.38 $0.029
Compressed Air - System
Maintenance 0.0% 0.0% 3 $0.03 0.1 0.10 $0.175
Compressed Air - Compressor
Replacement 17.6% 17.1% 10 $0.06 0.6 0.84 $0.013
Fan System - Controls 7.8% 8.2% 10 $0.01 0.0 0.37 $0.036
Fan System - Optimization 6.6% 8.9% 10 $0.13 0.2 0.15 $0.085
Fan System - Maintenance 3.0% 11.3% 3 $0.01 0.0 0.07 $0.251
Pumping System - Controls 8.6% 9.3% 10 $0.01 0.1 1.04 $0.011
Pumping System - Optimization 6.7% 9.0% 10 $0.28 0.8 0.28 $0.040
Pumping System - Maintenance 1.5% 10.1% 3 $0.02 0.1 0.15 $0.117
RTU - Maintenance 21.9% 100.0% 4 $0.06 0.2 0.20 $0.073
Chiller - Chilled Water Reset 60.0% 100.0% 4 $0.09 0.3 0.19 $0.077
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.20 0.1 0.06 $0.158
Chiller - VSD 25.0% 89.0% 20 $1.17 0.7 0.06 $0.119
Chiller - High Efficiency Cooling
Tower Fans 25.0% 100.0% 10 $0.04 0.0 0.01 $1.019
Chiller - Condenser Water
Temprature Reset 5.0% 100.0% 14 $0.20 0.4 0.16 $0.051
Cooling - Economizer Installation 29.1% 45.0% 15 $0.15 - - $0.000
Heat Pump - Maintenance 21.7% 100.0% 4 $0.03 0.6 1.07 $0.014
Insulation - Ducting 11.8% 50.0% 20 $0.41 - 0.31 $0.000
Energy Management System 23.6% 100.0% 14 $0.35 4.9 1.28 $0.007
Fans - Energy Efficient Motors 0.0% 0.0% 10 $0.14 0.1 0.06 $0.187
Fans - Variable Speed Control 0.0% 0.0% 10 $0.34 0.4 0.10 $0.114
Pumps - Variable Speed Control 0.1% 0.0% 10 $0.44 0.2 0.03 $0.316
Thermostat - Clock/Programmable 59.0% 70.0% 11 $0.11 1.7 1.41 $0.007
Interior Lighting - Central Lighting
Controls 83.7% 100.0% 8 $0.65 1.4 0.18 $0.067
Exterior Lighting - Daylighting
Controls 19.7% 53.6% 8 $0.08 1.4 1.52 $0.008
Interior Fluorescent - High Bay
Fixtures 19.1% 50.0% 11 $0.20 1.2 0.58 $0.018
LED Exit Lighting 91.2% 90.0% 10 $0.00 0.0 1.62 $0.006
Interior Lighting - Occupancy Sensors 25.0% 60.0% 8 $0.20 1.4 0.58 $0.021
Exterior Lighting - Photovoltaic
Installation 5.0% 25.0% 5 $0.92 2.7 0.21 $0.072
Interior Screw-in - Task Lighting 10.0% 100.0% 5 $0.24 0.1 0.03 $0.527
Interior Lighting - Time Clocks and
Timers 2.4% 75.0% 8 $0.20 0.7 0.34 $0.041
Exterior Lighting - Cold Cathode
Lighting 8.4% 50.0% 5 $0.00 0.3 19.87 $0.001
Interior Lighting - Skylights 5.3% 40.6% 8 $0.19 2.1 0.92 $0.013
Ventilation - Demand Control
Ventilation 10.2% 10.0% 10 $0.04 0.2 0.55 $0.022
Strategic Energy Management 2.8% 20.0% 3 $0.02 1.9 4.54 $0.004
Transformers 8.6% 9.4% 10 $0.13 0.4 0.28 $0.040
Motors - Synchronous belts 17.3% 21.0% 10 $0.22 - 0.00 $0.000
Refrigeration - Multiplex - Floating
section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex Controls - 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1062 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-86 www.enernoc.com
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Floating section Pressure - Evap.
Cond.
Refrigeration - Multiplex - Eff. Air-
cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff.
Water-cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Commissioning - HVAC 60.0% 100.0% 25 $0.70 0.1 0.02 $0.481
Commissioning - Lighting 78.5% 100.0% 25 $0.10 2.2 2.28 $0.003
Advanced New Construction Designs 11.9% 100.0% 35 $2.00 3.5 0.17 $0.030
Refrigeration - System Controls 5.0% 45.0% 10 $0.40 0.2 0.06 $0.198
Refrigeration - System Maintenance 13.6% 45.0% 10 $0.00 0.1 7.89 $0.001
Refrigeration - System Optimization 5.0% 45.0% 10 $0.80 0.2 0.03 $0.396
Motors - Variable Frequency Drive 25.0% 50.0% 10 $0.10 0.2 0.15 $0.072
Motors - Magnetic Adjustable Speed
Drives 24.0% 25.0% 10 $0.10 0.7 0.65 $0.017
Compressed Air - System Controls 0.0% 0.0% 15 $0.01 0.3 2.98 $0.003
Compressed Air - System
Optimization and Improvements 44.8% 75.0% 10 $0.20 0.8 0.38 $0.029
Compressed Air - System
Maintenance 0.0% 0.0% 3 $0.03 0.1 0.10 $0.175
Compressed Air - Compressor
Replacement 17.6% 17.1% 10 $0.06 0.6 0.84 $0.013
Fan System - Controls 7.8% 8.2% 10 $0.01 0.0 0.37 $0.036
Fan System - Optimization 6.6% 8.9% 10 $0.13 0.2 0.15 $0.085
Fan System - Maintenance 3.0% 11.3% 3 $0.01 0.0 0.07 $0.251
Pumping System - Controls 8.6% 9.3% 10 $0.01 0.1 1.04 $0.011
Pumping System - Optimization 6.7% 9.0% 10 $0.28 0.8 0.28 $0.040
Pumping System - Maintenance 1.5% 10.1% 3 $0.02 0.1 0.15 $0.117
RTU - Maintenance 21.9% 100.0% 4 $0.06 0.2 0.20 $0.073
Chiller - Chilled Water Reset 60.0% 100.0% 4 $0.09 0.3 0.19 $0.077
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.20 0.1 0.06 $0.158
Chiller - VSD 25.0% 89.0% 20 $1.17 0.7 0.06 $0.119
Chiller - High Efficiency Cooling
Tower Fans 25.0% 100.0% 10 $0.04 0.0 0.01 $1.019
Chiller - Condenser Water
Temprature Reset 5.0% 100.0% 14 $0.20 0.4 0.16 $0.051
Cooling - Economizer Installation 29.1% 45.0% 15 $0.15 - - $0.000
Heat Pump - Maintenance 21.7% 100.0% 4 $0.03 0.6 1.07 $0.014
Insulation - Ducting 11.8% 50.0% 20 $0.41 - 0.31 $0.000
Energy Management System 23.6% 100.0% 14 $0.35 4.9 1.28 $0.007
Fans - Energy Efficient Motors 0.0% 0.0% 10 $0.14 0.1 0.06 $0.187
Fans - Variable Speed Control 0.0% 0.0% 10 $0.34 0.4 0.10 $0.114
Pumps - Variable Speed Control 0.1% 0.0% 10 $0.44 0.2 0.03 $0.316

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1063 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-87
Table C-33 Energy Efficiency Non-Equipment Data— Extra Large Industrial, Existing
Vintage, Idaho
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Refrigeration - System Controls 11.1% 45.0% 10 $0.40 12.0 2.67 $0.004
Refrigeration - System Maintenance 11.1% 45.0% 10 $0.00 4.0 356.66 $0.000
Refrigeration - System Optimization 13.6% 45.0% 10 $0.80 12.0 1.34 $0.008
Motors - Variable Frequency Drive 32.5% 50.0% 10 $0.10 0.4 0.33 $0.033
Motors - Magnetic Adjustable Speed
Drives 24.0% 25.0% 10 $0.10 1.5 1.41 $0.008
Compressed Air - System Controls 0.0% 0.0% 15 $0.01 0.7 6.38 $0.001
Compressed Air - System
Optimization and Improvements 44.8% 75.0% 10 $0.20 1.8 0.82 $0.013
Compressed Air - System
Maintenance 0.0% 0.0% 3 $0.03 0.1 0.22 $0.081
Compressed Air - Compressor
Replacement 17.6% 17.1% 10 $0.06 1.3 1.81 $0.006
Fan System - Controls 7.8% 8.2% 10 $0.01 0.3 2.66 $0.004
Fan System - Optimization 8.3% 8.9% 10 $0.13 1.6 1.12 $0.010
Fan System - Maintenance 5.2% 11.3% 3 $0.01 0.1 0.61 $0.029
Pumping System - Controls 8.6% 9.3% 10 $0.01 0.3 2.23 $0.005
Pumping System - Optimization 8.4% 9.0% 10 $0.28 1.8 0.60 $0.018
Pumping System - Maintenance 2.9% 10.1% 3 $0.02 0.1 0.33 $0.054
RTU - Maintenance 37.6% 100.0% 4 $0.06 0.9 0.73 $0.018
Chiller - Chilled Water Reset 39.9% 100.0% 4 $0.09 1.3 0.74 $0.019
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.20 0.3 0.13 $0.071
Chiller - VSD 50.0% 89.0% 20 $1.17 2.6 0.19 $0.032
Chiller - High Efficiency Cooling
Tower Fans 25.0% 100.0% 10 $0.04 0.0 0.00 $2.995
Chiller - Condenser Water
Temprature Reset 14.2% 100.0% 14 $0.20 1.3 0.55 $0.014
Cooling - Economizer Installation 29.1% 45.0% 15 $0.15 - - $0.000
Heat Pump - Maintenance 21.7% 100.0% 4 $0.03 1.0 1.70 $0.008
Insulation - Ducting 11.8% 100.0% 20 $0.41 - 0.30 $0.000
Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 - 0.31 $0.000
Energy Management System 11.0% 100.0% 14 $0.35 4.7 1.23 $0.007
Fans - Energy Efficient Motors 0.0% 0.0% 10 $0.14 0.6 0.73 $0.027
Fans - Variable Speed Control 0.0% 0.0% 10 $0.34 2.5 0.59 $0.016
Retrocommissioning - HVAC 1.4% 93.3% 4 $0.25 - 0.30 $0.000
Pumps - Variable Speed Control 0.1% 0.0% 10 $0.44 0.4 0.08 $0.146
Thermostat - Clock/Programmable 59.0% 70.0% 11 $0.11 2.5 2.04 $0.005
Interior Lighting - Central Lighting
Controls 83.7% 100.0% 8 $0.65 - - $0.000
Exterior Lighting - Daylighting
Controls 1.6% 53.6% 8 $0.08 - 0.00 $0.000
Interior Fluorescent - High Bay
Fixtures 19.1% 50.0% 11 $0.20 0.6 0.19 $0.040
LED Exit Lighting 46.9% 90.0% 10 $0.00 0.0 0.39 $0.018
Retrocommissioning - Lighting 9.0% 93.0% 5 $0.05 - - $0.000
Interior Lighting - Occupancy Sensors 14.7% 60.0% 8 $0.20 - 0.00 $0.000
Exterior Lighting - Photovoltaic
Installation 5.0% 25.0% 5 $0.92 - - $0.000
Interior Screw-in - Task Lighting 10.0% 100.0% 5 $0.24 0.0 0.01 $1.514
Interior Lighting - Time Clocks and
Timers 2.4% 75.0% 8 $0.20 - 0.00 $0.000
Exterior Lighting - Cold Cathode
Lighting 14.6% 50.0% 5 $0.00 0.1 5.34 $0.002
Interior Lighting - Skylights 1.2% 40.6% 8 $0.29 - 0.00 $0.000
Ventilation - Demand Control
Ventilation 1.0% 10.0% 10 $0.04 - - $0.000
Strategic Energy Management 2.8% 20.0% 3 $0.02 0.3 0.64 $0.026
Transformers 9.8% 9.4% 10 $0.13 0.3 0.18 $0.060
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1064 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-88 www.enernoc.com
Measure Base
Saturation Applicability Lifetime
(Years)
Incremental
Cost
($/SqFt)
Savings
(kWh/SqFt)
BC
Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Motors - Synchronous belts 17.3% 21.0% 10 $0.22 - 0.01 $0.000
Refrigeration - Multiplex - Floating
section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex Controls -
Floating section Pressure - Evap.
Cond.
0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff. Air-
cooled Condenser 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex - Eff.
Water-cooled Condenser 0.0% 0.0% 0 $0.00 12.0 1.00 $0.000
Refrigeration - System Controls 11.1% 45.0% 10 $0.40 12.0 2.67 $0.004
Refrigeration - System Maintenance 11.1% 45.0% 10 $0.00 4.0 356.66 $0.000
Refrigeration - System Optimization 13.6% 45.0% 10 $0.80 12.0 1.34 $0.008
Motors - Variable Frequency Drive 32.5% 50.0% 10 $0.10 0.4 0.33 $0.033
Motors - Magnetic Adjustable Speed
Drives 24.0% 25.0% 10 $0.10 1.5 1.41 $0.008
Compressed Air - System Controls 0.0% 0.0% 15 $0.01 0.7 6.38 $0.001
Compressed Air - System
Optimization and Improvements 44.8% 75.0% 10 $0.20 1.8 0.82 $0.013
Compressed Air - System
Maintenance 0.0% 0.0% 3 $0.03 0.1 0.22 $0.081
Compressed Air - Compressor
Replacement 17.6% 17.1% 10 $0.06 1.3 1.81 $0.006
Fan System - Controls 7.8% 8.2% 10 $0.01 0.3 2.66 $0.004
Fan System - Optimization 8.3% 8.9% 10 $0.13 1.6 1.12 $0.010
Fan System - Maintenance 5.2% 11.3% 3 $0.01 0.1 0.61 $0.029
Pumping System - Controls 8.6% 9.3% 10 $0.01 0.3 2.23 $0.005
Pumping System - Optimization 8.4% 9.0% 10 $0.28 1.8 0.60 $0.018
Pumping System - Maintenance 2.9% 10.1% 3 $0.02 0.1 0.33 $0.054
RTU - Maintenance 37.6% 100.0% 4 $0.06 0.9 0.73 $0.018
Chiller - Chilled Water Reset 39.9% 100.0% 4 $0.09 1.3 0.74 $0.019
Chiller - Chilled Water Variable-Flow
System 30.0% 45.0% 10 $0.20 0.3 0.13 $0.071
Chiller - VSD 50.0% 89.0% 20 $1.17 2.6 0.19 $0.032
Chiller - High Efficiency Cooling
Tower Fans 25.0% 100.0% 10 $0.04 0.0 0.00 $2.995
Chiller - Condenser Water
Temprature Reset 14.2% 100.0% 14 $0.20 1.3 0.55 $0.014
Cooling - Economizer Installation 29.1% 45.0% 15 $0.15 - - $0.000
Heat Pump - Maintenance 21.7% 100.0% 4 $0.03 1.0 1.70 $0.008
Insulation - Ducting 11.8% 100.0% 20 $0.41 - 0.30 $0.000
Repair and Sealing - Ducting 5.0% 50.0% 15 $0.38 - 0.31 $0.000
Energy Management System 11.0% 100.0% 14 $0.35 4.7 1.23 $0.007
Fans - Energy Efficient Motors 0.0% 0.0% 10 $0.14 0.6 0.73 $0.027
Fans - Variable Speed Control 0.0% 0.0% 10 $0.34 2.5 0.59 $0.016

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1065 of 1125
C&I Energy Efficiency Equipment and Measure Data
EnerNOC Utility Solutions Consulting C-89
Table C-34 Energy Efficiency Non-Equipment Data— Extra Large Industrial, New
Vintage, Idaho
Measure Base
Saturation Applicability Lifetime
(Years)
Incrementa
l Cost
($/SqFt)
Savings
(kWh/SqFt)
BC Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Refrigeration - System Controls 13.6% 45.0% 10 $0.40 4.0 0.91 $0.012
Refrigeration - System Maintenance 13.6% 45.0% 10 $0.00 12.0 1,086.05 $0.000
Refrigeration - System Optimization 5.0% 45.0% 10 $0.80 0.4 0.05 $0.215
Motors - Variable Frequency Drive 32.5% 50.0% 10 $0.10 1.9 1.72 $0.006
Motors - Magnetic Adjustable Speed
Drives 24.0% 25.0% 10 $0.10 0.9 0.81 $0.013
Compressed Air - System Controls 0.0% 0.0% 15 $0.01 0.2 1.56 $0.005
Compressed Air - System
Optimization and Improvements 44.8% 75.0% 10 $0.20 2.2 1.00 $0.011
Compressed Air - System
Maintenance 0.0% 0.0% 3 $0.03 1.5 2.36 $0.007
Compressed Air - Compressor
Replacement 14.6% 17.1% 10 $0.06 0.1 0.14 $0.082
Fan System - Controls 7.8% 8.2% 10 $0.01 0.7 5.80 $0.002
Fan System - Optimization 8.3% 8.9% 10 $0.13 1.2 0.81 $0.013
Fan System - Maintenance 5.2% 11.3% 3 $0.01 0.4 2.02 $0.009
Pumping System - Controls 8.6% 9.3% 10 $0.01 2.2 18.15 $0.001
Pumping System - Optimization 6.7% 9.0% 10 $0.28 0.2 0.06 $0.185
Pumping System - Maintenance 3.5% 10.1% 3 $0.02 0.6 1.26 $0.014
RTU - Maintenance 37.6% 100.0% 4 $0.06 1.0 0.94 $0.015
Chiller - Chilled Water Reset 63.4% 100.0% 4 $0.09 0.5 0.33 $0.048
Chiller - Chilled Water Variable-Flow
System 34.5% 45.0% 10 $0.20 2.3 1.03 $0.010
Chiller - VSD 25.0% 89.0% 20 $1.17 0.0 0.00 $5.329
Chiller - High Efficiency Cooling
Tower Fans 40.1% 100.0% 10 $0.04 1.2 2.65 $0.004
Chiller - Condenser Water
Temprature Reset 5.0% 100.0% 14 $0.20 0.2 0.08 $0.103
Cooling - Economizer Installation 35.5% 45.0% 15 $0.15 0.5 0.29 $0.027
Heat Pump - Maintenance 21.7% 100.0% 4 $0.03 0.5 0.89 $0.017
Insulation - Ducting 11.8% 50.0% 20 $0.41 0.3 0.36 $0.114
Energy Management System 23.6% 100.0% 14 $0.35 4.7 1.26 $0.007
Fans - Energy Efficient Motors 0.0% 0.0% 10 $0.14 2.1 1.36 $0.008
Fans - Variable Speed Control 0.0% 0.0% 10 $0.34 0.1 0.03 $0.361
Pumps - Variable Speed Control 0.1% 0.0% 10 $0.44 0.1 0.01 $1.018
Thermostat - Clock/Programmable 63.1% 70.0% 11 $0.11 3.5 2.86 $0.003
Interior Lighting - Central Lighting
Controls 83.7% 100.0% 8 $0.65 0.3 0.04 $0.283
Exterior Lighting - Daylighting
Controls 19.7% 53.6% 8 $0.08 0.4 0.46 $0.028
Interior Fluorescent - High Bay
Fixtures 10.0% 50.0% 11 $0.20 0.0 0.00 $3.499
LED Exit Lighting 91.2% 90.0% 10 $0.00 0.3 25.24 $0.000
Interior Lighting - Occupancy Sensors 25.0% 60.0% 8 $0.20 0.7 0.28 $0.044
Exterior Lighting - Photovoltaic
Installation 5.0% 25.0% 5 $0.92 0.0 0.00 $6.107
Interior Screw-in - Task Lighting 10.0% 100.0% 5 $0.24 0.2 0.04 $0.315
Interior Lighting - Time Clocks and
Timers 2.4% 75.0% 8 $0.20 0.1 0.04 $0.324
Exterior Lighting - Cold Cathode
Lighting 8.4% 50.0% 5 $0.00 0.5 33.17 $0.000
Interior Lighting - Skylights 2.4% 40.6% 8 $0.19 0.1 0.06 $0.235
Ventilation - Demand Control
Ventilation 6.0% 10.0% 10 $0.04 0.1 0.15 $0.082
Strategic Energy Management 2.8% 20.0% 3 $0.02 0.8 1.77 $0.010
Transformers 9.8% 9.4% 10 $0.13 0.3 0.23 $0.049
Motors - Synchronous belts 17.3% 21.0% 10 $0.22 0.0 0.01 $1.550
Refrigeration - Multiplex - Floating
section Pressure - Air-cooled Cond. 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Refrigeration - Multiplex Controls - 0.0% 0.0% 0 $0.00 - 1.00 $0.000
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1066 of 1125
C&I Energy Efficiency Equipment and Measure Data
C-90 www.enernoc.com
Measure Base
Saturation Applicability Lifetime
(Years)
Incrementa
l Cost
($/SqFt)
Savings
(kWh/SqFt)
BC Ratio
(2015)
Levelized
Cost of
Energy
($/kWh)
Floating section Pressure - Evap.
Cond.
Refrigeration - Multiplex - Eff. Air-
cooled Condenser 0.0% 0.0% 0 $0.00 0.3 1.00 $0.000
Refrigeration - Multiplex - Eff.
Water-cooled Condenser 0.0% 0.0% 0 $0.00 0.2 1.00 $0.000
Commissioning - HVAC 78.5% 100.0% 25 $0.70 0.9 0.14 $0.046
Commissioning - Lighting 78.5% 100.0% 25 $0.10 0.5 0.57 $0.011
Advanced New Construction Designs 11.9% 100.0% 35 $2.00 2.9 0.14 $0.035
Refrigeration - System Controls 13.6% 45.0% 10 $0.40 4.0 0.91 $0.012
Refrigeration - System Maintenance 13.6% 45.0% 10 $0.00 12.0 1,086.05 $0.000
Refrigeration - System Optimization 5.0% 45.0% 10 $0.80 0.4 0.05 $0.215
Motors - Variable Frequency Drive 32.5% 50.0% 10 $0.10 1.9 1.72 $0.006
Motors - Magnetic Adjustable Speed
Drives 24.0% 25.0% 10 $0.10 0.9 0.81 $0.013
Compressed Air - System Controls 0.0% 0.0% 15 $0.01 0.2 1.56 $0.005
Compressed Air - System
Optimization and Improvements 44.8% 75.0% 10 $0.20 2.2 1.00 $0.011
Compressed Air - System
Maintenance 0.0% 0.0% 3 $0.03 1.5 2.36 $0.007
Compressed Air - Compressor
Replacement 14.6% 17.1% 10 $0.06 0.1 0.14 $0.082
Fan System - Controls 7.8% 8.2% 10 $0.01 0.7 5.80 $0.002
Fan System - Optimization 8.3% 8.9% 10 $0.13 1.2 0.81 $0.013
Fan System - Maintenance 5.2% 11.3% 3 $0.01 0.4 2.02 $0.009
Pumping System - Controls 8.6% 9.3% 10 $0.01 2.2 18.15 $0.001
Pumping System - Optimization 6.7% 9.0% 10 $0.28 0.2 0.06 $0.185
Pumping System - Maintenance 3.5% 10.1% 3 $0.02 0.6 1.26 $0.014
RTU - Maintenance 37.6% 100.0% 4 $0.06 1.0 0.94 $0.015
Chiller - Chilled Water Reset 63.4% 100.0% 4 $0.09 0.5 0.33 $0.048
Chiller - Chilled Water Variable-Flow
System 34.5% 45.0% 10 $0.20 2.3 1.03 $0.010
Chiller - VSD 25.0% 89.0% 20 $1.17 0.0 0.00 $5.329
Chiller - High Efficiency Cooling
Tower Fans 40.1% 100.0% 10 $0.04 1.2 2.65 $0.004
Chiller - Condenser Water
Temprature Reset 5.0% 100.0% 14 $0.20 0.2 0.08 $0.103
Cooling - Economizer Installation 35.5% 45.0% 15 $0.15 0.5 0.29 $0.027
Heat Pump - Maintenance 21.7% 100.0% 4 $0.03 0.5 0.89 $0.017
Insulation - Ducting 11.8% 50.0% 20 $0.41 0.3 0.36 $0.114
Energy Management System 23.6% 100.0% 14 $0.35 4.7 1.26 $0.007
Fans - Energy Efficient Motors 0.0% 0.0% 10 $0.14 2.1 1.36 $0.008
Fans - Variable Speed Control 0.0% 0.0% 10 $0.34 0.1 0.03 $0.361
Pumps - Variable Speed Control 0.1% 0.0% 10 $0.44 0.1 0.01 $1.018

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1067 of 1125

EnerNOC Utility Solutions Consulting D-1
APPENDIX D
MARKET ADOPTION FACTORS
A set of market adoption factors are applied to Economic potential to estimate Achievable
Potential. These estimate customer adoption of economic measures when delivered through
efficiency programs under realistic market and customer preference conditions. They reflect
expected program participation given barriers to customer acceptance and program
implementation. These adoption rates generally increase over time, reflecting an increasing
awareness and willingness to adopt energy-efficient measures. However, in some cases, where a
new technology is introduced, the adoption rates drop to reflect that the new technology may
not yet be accepted in the market. For mature measures, information channels are assumed to
be established for marketing, educating consumers, and coordinating with trade allies and
delivery partners. For evolving measures, this is not the case and thus the factors start at a
lower level.
The market adoption rates for the Avista study were developed using the ramp rates from the
Northwest Power & Conservation Council’s Sixth Plan as a starting point. The ramp rates were
then adjusted based on actual Avista program history and information from program evaluations.
These adjustments mainly set the potential in the first years of the study to match with recent
program achievements and thus show continuity of results.
Table D-1 through Table D-2 present the Achievable Potential market adoption factors for the
residential sector, first for equipment measures and then for non-equipment measures. Table D-
3 through Table D-4 present the market adoption factors for the commercial and industrial sector
.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1068 of 1125

EnerNOC Utility Solutions Consulting D-2
Table D-1 Residential Equipment Measures—Achievable Potential Market Adoption Factors
End Use Fuel Technology 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Cooling Electric Central AC 77% 78% 79% 80% 81% 82% 83% 84% 85% 85% 85% 85% 85%
Cooling Electric Room AC 77% 78% 79% 80% 81% 82% 83% 84% 85% 85% 85% 85% 85%
Cooling Electric Air Source Heat Pump 77% 78% 79% 80% 81% 82% 83% 84% 85% 85% 85% 85% 85%
Cooling Electric Geothermal Heat Pump 77% 78% 79% 80% 81% 82% 83% 84% 85% 85% 85% 85% 85%
Cooling Electric Ductless HP 56% 58% 59% 62% 66% 71% 76% 81% 83% 85% 85% 85% 85%
Space Heating Electric Electric Resistance 6% 9% 11% 14% 17% 20% 23% 26% 28% 31% 34% 37% 40%
Space Heating Electric Electric Furnace 60% 60% 60% 60% 60% 60% 60% 60% 60% 60% 60% 60% 60%
Space Heating Electric Supplemental 11% 17% 23% 28% 34% 40% 45% 51% 57% 62% 68% 74% 79%
Space Heating Electric Air Source Heat Pump 77% 78% 79% 80% 81% 82% 83% 84% 85% 85% 85% 85% 85%
Space Heating Electric Geothermal Heat Pump 56% 58% 59% 62% 66% 71% 76% 81% 83% 85% 85% 85% 85%
Space Heating Electric Ductless HP 28% 32% 37% 40% 43% 45% 46% 49% 52% 57% 62% 68% 73%
Water Heating Electric Water Heater <= 55 Gal 5% 7% 9% 10% 12% 15% 20% 25% 30% 35% 40% 45% 50%
Water Heating Electric Water Heater > 55 Gal 2% 3% 5% 8% 10% 12% 14% 34% 39% 45% 50% 50% 50%
Interior Lighting Electric Screw-in 25% 25% 26% 27% 29% 31% 33% 35% 38% 41% 45% 50% 55%
Interior Lighting Electric Linear Fluorescent 25% 25% 26% 27% 29% 31% 33% 35% 38% 41% 45% 50% 55%
Interior Lighting Electric Specialty 25% 25% 26% 27% 29% 31% 33% 35% 38% 41% 45% 50% 55%
Exterior Lighting Electric Screw-in 25% 25% 26% 27% 29% 31% 33% 35% 38% 41% 45% 50% 55%
Appliances Electric Clothes Washer 56% 58% 59% 62% 66% 71% 76% 81% 83% 85% 85% 85% 85%
Appliances Electric Clothes Dryer 56% 58% 59% 62% 66% 71% 76% 81% 83% 85% 85% 85% 85%
Appliances Electric Dishwasher 56% 58% 59% 62% 66% 71% 76% 81% 83% 85% 85% 85% 85%
Appliances Electric Refrigerator 56% 58% 59% 62% 66% 71% 76% 81% 83% 85% 85% 85% 85%
Appliances Electric Freezer 56% 58% 59% 62% 66% 71% 76% 81% 83% 85% 85% 85% 85%
Appliances Electric Second Refrigerator 56% 58% 59% 62% 66% 71% 76% 81% 83% 85% 85% 85% 85%
Appliances Electric Stove 56% 58% 59% 62% 66% 71% 76% 81% 83% 85% 85% 85% 85%
Appliances Electric Microwave 56% 58% 59% 62% 66% 71% 76% 81% 83% 85% 85% 85% 85%
Electronics Electric Personal Computers 5% 8% 10% 13% 16% 19% 23% 26% 30% 33% 37% 40% 44%
Electronics Electric TVs 11% 16% 21% 26% 31% 36% 41% 47% 52% 58% 63% 68% 72%
Electronics Electric Set-top boxes/DVR 6% 9% 12% 15% 18% 22% 25% 29% 31% 34% 37% 40% 43%
Electronics Electric Devices and Gadgets 6% 9% 12% 15% 18% 22% 25% 29% 31% 34% 37% 40% 43%
Miscellaneous Electric Pool Pump 5% 8% 10% 13% 16% 19% 23% 26% 30% 33% 37% 40% 44%
Miscellaneous Electric Furnace Fan 9% 13% 17% 21% 25% 29% 34% 39% 45% 49% 54% 57% 60%
Miscellaneous Electric Miscellaneous 23% 31% 39% 47% 54% 62% 68% 73% 76% 78% 78% 78% 79%

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1069 of 1125
Market Adoption Factors
EnerNOC Utility Solutions Consulting D-3
Table D-2 Residential Non-Equipment Measures— Achievable Potential Market Adoption Factors
Measures 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Central AC - Early Replacement 1% 3% 5% 7% 9% 11% 14% 16% 19% 21% 24% 27% 30%
Central AC - Maintenance and Tune-Up 5% 9% 13% 17% 20% 23% 26% 29% 31% 35% 38% 42% 46%
Room AC - Removal of Second Unit 1% 3% 5% 7% 9% 11% 14% 16% 19% 21% 24% 27% 30%
Attic Fan - Installation 5% 7% 9% 11% 14% 16% 18% 20% 23% 25% 27% 29% 32%
Attic Fan - Photovoltaic - Installation 1% 3% 5% 7% 9% 11% 14% 16% 19% 21% 24% 27% 30%
Ceiling Fan - Installation 6% 9% 9% 11% 14% 16% 18% 20% 23% 25% 27% 29% 32%
Whole-House Fan - Installation 2% 8% 15% 22% 31% 39% 48% 57% 59% 62% 64% 67% 69%
Air Source Heat Pump - Maintenance 3% 5% 7% 9% 10% 12% 13% 14% 16% 17% 18% 20% 22%
Insulation - Ducting 1% 3% 5% 7% 9% 11% 14% 16% 19% 21% 24% 27% 30%
Repair and Sealing - Ducting 2% 3% 6% 8% 10% 11% 12% 14% 15% 16% 18% 19% 21%
Thermostat - Clock/Programmable 1% 3% 5% 7% 9% 11% 14% 16% 19% 21% 24% 27% 30%
Doors - Storm and Thermal 5% 7% 9% 11% 14% 16% 18% 20% 23% 25% 27% 29% 32%
Insulation - Infiltration Control 5% 9% 13% 17% 20% 23% 26% 29% 31% 35% 38% 42% 46%
Insulation - Ceiling 12% 13% 14% 14% 15% 16% 17% 18% 19% 20% 21% 22% 23%
Insulation - Radiant Barrier 5% 9% 15% 20% 24% 29% 34% 39% 44% 50% 56% 62% 69%
Roofs - High Reflectivity 1% 3% 5% 7% 9% 11% 14% 16% 19% 21% 24% 27% 30%
Windows - Reflective Film 5% 7% 9% 11% 14% 16% 18% 20% 23% 25% 27% 29% 32%
Windows - High Efficiency/Energy Star 5% 7% 9% 11% 14% 16% 18% 20% 23% 25% 27% 29% 32%
Interior Lighting - Occupancy Sensor 10% 19% 27% 35% 43% 51% 60% 68% 68% 68% 68% 68% 68%
Exterior Lighting - Photovoltaic Installation 2% 8% 15% 22% 31% 39% 48% 57% 59% 62% 64% 67% 69%
Exterior Lighting - Photosensor Control 1% 4% 10% 17% 24% 33% 41% 50% 59% 62% 64% 67% 69%
Exterior Lighting - Timeclock Installation 2% 8% 15% 22% 31% 39% 48% 57% 59% 62% 64% 67% 69%
Water Heater - Faucet Aerators 1% 3% 5% 7% 9% 11% 14% 16% 19% 21% 24% 27% 30%
Water Heater - Pipe Insulation 1% 3% 5% 7% 9% 11% 14% 16% 19% 21% 24% 27% 30%
Water Heater - Low Flow Showerheads 2% 3% 6% 8% 10% 11% 12% 14% 15% 16% 18% 19% 21%
Water Heater - Tank Blanket/Insulation 3% 5% 7% 9% 10% 12% 13% 14% 16% 17% 18% 20% 22%
Water Heater - Thermostat Setback 3% 5% 7% 9% 10% 12% 13% 14% 16% 17% 18% 20% 22%
Electronics - Reduce Standby Wattage 3% 5% 7% 9% 10% 12% 13% 14% 16% 17% 18% 20% 22%
Refrigerator - Early Replacement 3% 4% 6% 8% 11% 13% 16% 19% 23% 25% 27% 29% 32%
Refrigerator - Remove Second Unit 3% 4% 6% 8% 11% 13% 16% 19% 23% 25% 27% 29% 32%
Freezer - Early Replacement 3% 4% 6% 8% 11% 13% 16% 19% 23% 25% 27% 29% 32%
Freezer - Remove Second Unit 3% 4% 6% 8% 11% 13% 16% 19% 23% 25% 27% 29% 32%
Behavioral Measures 1% 3% 5% 7% 9% 11% 14% 16% 19% 21% 24% 27% 30%
Pool - Pump Timer 3% 6% 9% 11% 14% 16% 19% 21% 24% 27% 30% 33% 37%
Insulation - Foundation 3% 6% 9% 11% 14% 16% 19% 21% 24% 27% 30% 33% 37%
Insulation - Wall Cavity 5% 9% 15% 20% 24% 29% 34% 39% 44% 50% 56% 62% 69%
Insulation - Wall Sheathing 1% 3% 5% 7% 9% 11% 14% 16% 19% 21% 24% 27% 30%
Water Heater - Drainwater Heat Reocvery 4% 6% 9% 11% 13% 15% 17% 19% 21% 23% 26% 28% 30%
Advanced New Construction Designs 4% 6% 9% 11% 13% 15% 17% 19% 21% 23% 26% 28% 30%
Energy Star Homes 9% 10% 14% 15% 20% 21% 26% 28% 34% 36% 40% 43% 45%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1070 of 1125
Market Adoption Factors
D-4 www.enernoc.com
Table D-3 C/I Equipment Measures — Achievable Potential Market Adoption Factors
End Use Fuel Technology 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Cooling Electric Central Chiller 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Cooling Electric RTU 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Cooling Electric PTAC 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Cooling Electric Heat Pump 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Space Heating Electric Electric Resistance 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85%
Space Heating Electric Furnace 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Space Heating Electric Heat Pump 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Ventilation Electric Ventilation 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Interior Lighting Electric Interior Screw-in 33% 45% 54% 61% 66% 70% 73% 76% 78% 80% 81% 82% 82%
Interior Lighting Electric High Bay Fixtures 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Interior Lighting Electric Linear Fluorescent 61% 66% 70% 73% 76% 78% 80% 81% 82% 82% 83% 83% 84%
Exterior Lighting Electric Exterior Screw-in 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85%
Exterior Lighting Electric HID 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85%
Water Heating Electric Water Heater 13% 15% 18% 20% 23% 25% 28% 30% 33% 35% 38% 40% 45%
Food Preparation Electric Fryer 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Food Preparation Electric Oven 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Food Preparation Electric Dishwasher 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Food Preparation Electric Hot Food Container 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Food Preparation Electric Food Prep 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Refrigeration Electric Walk in Refrigeration 80% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Refrigeration Electric Glass Door Display 80% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Refrigeration Electric Reach-in Refrigerator 80% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Refrigeration Electric Open Display Case 80% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Refrigeration Electric Vending Machine 80% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Refrigeration Electric Icemaker 80% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Office Equipment Electric Desktop Computer 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85%
Office Equipment Electric Laptop Computer 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85%
Office Equipment Electric Server 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85%
Office Equipment Electric Monitor 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85%
Office Equipment Electric Printer/copier/fax 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85%
Office Equipment Electric POS Terminal 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85%
Miscellaneous Electric Non-HVAC Motor 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Miscellaneous Electric Other Miscellaneous 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Process Electric Process Cooling/Refrigeration 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1071 of 1125
Market Adoption Factors
EnerNOC Utility Solutions Consulting D-5
End Use Fuel Technology 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Process Electric Process Heating 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85%
Process Electric Electrochemical Process 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Machine Drive Electric Less than 5 HP 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Machine Drive Electric 5-24 HP 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Machine Drive Electric 25-99 HP 50% 60% 70% 80% 85% 85% 85% 85% 85% 85% 85% 85% 85%
Machine Drive Electric 100-249 HP 43% 51% 60% 68% 72% 72% 72% 72% 72% 72% 72% 72% 72%
Machine Drive Electric 250-499 HP 43% 51% 60% 68% 72% 72% 72% 72% 72% 72% 72% 72% 72%
Machine Drive Electric 500 and more HP 43% 51% 60% 68% 72% 72% 72% 72% 72% 72% 72% 72% 72%
Miscellaneous Electric Miscellaneous 21% 26% 30% 34% 38% 43% 47% 51% 55% 60% 64% 68% 72%

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1072 of 1125
Market Adoption Factors
D-6 www.enernoc.com
Table D-4 C/I Non-Equipment Measures — Achievable Potential Market Adoption Factors
Measures 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
RTU - Maintenance 8% 16% 24% 34% 43% 51% 60% 68% 68% 68% 68% 68% 68%
RTU - Evaporative Precooler 8% 16% 24% 34% 43% 51% 60% 68% 68% 68% 68% 68% 68%
Chiller - Chilled Water Reset 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Chiller - Chilled Water Variable-Flow System 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Chiller - VSD 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Chiller - High Efficiency Cooling Tower Fans 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Chiller - Condenser Water Temprature Reset 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Cooling - Economizer Installation 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Heat Pump - Maintenance 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Insulation - Ducting 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Repair and Sealing - Ducting 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Energy Management System 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Cooking - Exhaust Hoods with Sensor Control 4% 8% 12% 17% 21% 26% 30% 34% 38% 43% 47% 51% 55%
Fans - Energy Efficient Motors 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Fans - Variable Speed Control 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Retrocommissioning - HVAC 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Pumps - Variable Speed Control 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Thermostat - Clock/Programmable 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Insulation - Ceiling 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Insulation - Radiant Barrier 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Roofs - High Reflectivity 20% 21% 23% 25% 26% 28% 30% 31% 33% 35% 37% 38% 40%
Windows - High Efficiency 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Interior Lighting - Central Lighting Controls 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Interior Lighting - Photocell Controlled T8 Dimming Ballasts 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Exterior Lighting - Daylighting Controls 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Interior Fluorescent - Bi-Level Fixture w/Occupancy Sensor 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Interior Fluorescent - High Bay Fixtures 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Interior Lighting - Occupancy Sensors 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Exterior Lighting - Photovoltaic Installation 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Interior Screw-in - Task Lighting 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Interior Lighting - Time Clocks and Timers 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Water Heater - Faucet Aerators/Low Flow Nozzles 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Water Heater - Pipe Insulation 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Water Heater - High Efficiency Circulation Pump 20% 21% 23% 25% 26% 28% 30% 31% 33% 35% 37% 38% 40%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1073 of 1125
Market Adoption Factors
EnerNOC Utility Solutions Consulting D-7
Measures 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Water Heater - Tank Blanket/Insulation 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Water Heater - Thermostat Setback 20% 21% 23% 25% 26% 28% 30% 31% 33% 35% 37% 38% 40%
Refrigeration - Anti-Sweat Heater/Auto Door Closer 20% 21% 23% 25% 26% 28% 30% 31% 33% 35% 37% 38% 40%
Refrigeration - Floating Head Pressure 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Refrigeration - Door Gasket Replacement 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Insulation - Bare Suction Lines 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Refrigeration - Night Covers 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Refrigeration - Strip Curtain 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Vending Machine - Controller 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
LED Exit Lighting 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Retrocommissioning - Lighting 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Refrigeration - High Efficiency Case Lighting 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Exterior Lighting - Cold Cathode Lighting 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Laundry - High Efficiency Clothes Washer 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Interior Lighting - Hotel Guestroom Controls 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Miscellaneous - Energy Star Water Cooler 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Commissioning - HVAC 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Commissioning - Comprehensive 20% 21% 23% 25% 26% 28% 30% 31% 33% 35% 37% 38% 40%
Commissioning - Lighting 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Advanced New Construction Designs 20% 21% 23% 25% 26% 28% 30% 31% 33% 35% 37% 38% 40%
Insulation - Wall Cavity 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Roofs - Green 20% 21% 23% 25% 26% 28% 30% 31% 33% 35% 37% 38% 40%
Interior Lighting - Skylights 20% 21% 23% 25% 26% 28% 30% 31% 33% 35% 37% 38% 40%
Ventilation - Demand Control Ventilation 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Office Equipment - Smart Power Strips 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Strategic Energy Management 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Refrigeration - Multiplex - Floating section Pressure - Air-cooled Cond. 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Refrigeration - Multiplex Controls - Floating section Pressure - Evap. Cond. 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Refrigeration - Multiplex - Eff. Air-cooled Condenser 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Refrigeration - Multiplex - Eff. Water-cooled Condenser 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Refrigeration - System Controls 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Refrigeration - System Maintenance 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Refrigeration - System Optimization 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Motors - Variable Frequency Drive 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Motors - Magnetic Adjustable Speed Drives 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Compressed Air - System Controls 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1074 of 1125
Market Adoption Factors
D-8 www.enernoc.com
Measures 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Compressed Air - System Optimization and Improvements 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Compressed Air - System Maintenance 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Compressed Air - Compressor Replacement 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Fan System - Controls 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Fan System - Optimization 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Fan System - Maintenance 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Pumping System - Controls 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Pumping System - Optimization 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Pumping System - Maintenance 54% 55% 56% 57% 58% 59% 60% 60% 61% 62% 63% 64% 65%
Transformers 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%
Motors - Synchronous belts 40% 41% 42% 42% 41% 41% 41% 42% 44% 46% 48% 49% 50%

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1075 of 1125

EnerNOC Utility Solutions Consulting E-1
APPENDIX E
ANNUAL SAVINGS
This section presents the estimates of annual savings. Selected years are shown in Chapter 4 of the CPA report. Table E-1 and Table E-2show the
overall annual savings for all sectors combined. Table E-3 through Table E-6 show the annual savings for the individual sectors.

Table E-1 Annual Electric Energy Savings, All Sectors (1,000 MWh)
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Cumulative Savings (1,000 MWh)
Achievable Potential 51 100 168 240 325 417 458 515 579 634
Economic Potential 315 476 679 881 1,079 1,284 1,361 1,447 1,552 1,655
Technical Potential 1,161 1,368 1,656 1,966 2,239 2,517 2,695 2,862 3,029 3,173
Incremental Savings (1,000 MWh)
Achievable Potential 51 50 68 72 84 93 41 57 64 55
Economic Potential 315 162 202 203 198 204 78 86 104 103
Technical Potential 1,161 206 289 310 273 278 178 168 166 144

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1076 of 1125
Annual Savings
E-2 www.enernoc.com
Table E-2 Annual Electric Energy Savings, All Sectors (1,000 MWh) (continued)
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
Cumulative Savings (1,000 MWh)
Achievable Potential 685 761 834 903 977 1,037 1,103 1,175 1,262 1,352
Economic Potential 1,751 1,896 2,020 2,138 2,259 2,315 2,388 2,468 2,561 2,652
Technical Potential 3,302 3,472 3,617 3,752 3,884 3,979 4,070 4,163 4,252 4,340
Incremental Savings (1,000 MWh)
Achievable Potential 51 76 73 69 74 60 66 71 88 90
Economic Potential 96 145 124 118 121 56 74 79 93 91
Technical Potential 129 170 145 135 133 94 91 93 89 88

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1077 of 1125
Annual Savings
EnerNOC Utility Solutions Consulting E-3
Table E-3 Annual Electric Energy Savings, Residential (1,000 MWh)
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Cumulative Savings (1,000 MWh)
Achievable Potential 22 43 75 110 148 189 209 224 241 252
Economic Potential 231 335 469 611 745 879 926 955 998 1,042
Technical Potential 963 1,038 1,154 1,266 1,338 1,409 1,430 1,433 1,454 1,473
Incremental Savings (1,000 MWh)
Achievable Potential 22 21 32 35 37 42 19 16 16 11
Economic Potential 231 104 134 142 133 135 46 30 43 43
Technical Potential 963 74 116 112 73 70 22 3 20 20

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1078 of 1125
Annual Savings
E-4 www.enernoc.com
Table E-4 Annual Electric Energy Savings, Residential (1,000 MWh) (continued)
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
Cumulative Savings (1,000 MWh)
Achievable Potential 263 293 324 357 392 419 447 477 510 547
Economic Potential 1,083 1,164 1,239 1,314 1,390 1,412 1,442 1,474 1,512 1,549
Technical Potential 1,492 1,553 1,611 1,669 1,727 1,765 1,802 1,840 1,876 1,912
Incremental Savings (1,000 MWh)
Achievable Potential 11 30 31 32 35 27 28 30 34 37
Economic Potential 42 81 75 75 76 21 30 32 38 38
Technical Potential 19 61 58 58 59 37 38 38 36 35

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1079 of 1125
Annual Savings
EnerNOC Utility Solutions Consulting E-5
Table E-5 Annual Electric Energy Savings, C/I (1,000 MWh)
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Cumulative Savings (1,000 MWh)
Achievable Potential 29 57 93 130 177 228 250 291 338 382
Economic Potential 84 141 210 270 334 404 436 492 554 613
Technical Potential 198 330 503 701 901 1,108 1,264 1,429 1,575 1,700
Incremental Savings (1,000 MWh)
Achievable Potential 29 29 36 37 47 51 22 41 48 43
Economic Potential 84 58 69 60 64 70 31 57 61 60
Technical Potential 198 132 173 198 200 208 156 165 146 125

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1080 of 1125
Annual Savings
E-6 www.enernoc.com
Table E-6 Annual Electric Energy Savings, C/I (1,000 MWh) (continued)
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
Cumulative Savings (1,000 MWh)
Achievable Potential 422 468 509 546 585 618 656 698 752 805
Economic Potential 668 732 781 824 868 903 946 994 1,049 1,103
Technical Potential 1,809 1,919 2,006 2,083 2,157 2,214 2,268 2,323 2,376 2,428
Incremental Savings (1,000 MWh)
Achievable Potential 40 46 42 37 39 34 38 42 54 53
Economic Potential 54 64 49 43 45 34 43 47 56 53
Technical Potential 110 109 87 77 74 57 53 55 53 52

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1081 of 1125
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1082 of 1125

EnerNOC Utility Solutions Consulting 500 Ygnacio Valley Road, Suite 450
Walnut Creek, CA 94596
P: 925.482.2000
F: 925.284.3147
About EnerNOC Utility Solutions Consulting
EnerNOC Utility Solutions Consulting is part of EnerNOC Utility Solutions group, which
provides a comprehensive suite of demand-side management (DSM) services to
utilities and grid operators worldwide. Hundreds of utilities have leveraged our
technology, our people, and our proven processes to make their energy efficiency
(EE) and demand response (DR) initiatives a success. Utilities trust EnerNOC to work
with them at every stage of the DSM program lifecycle – assessing market potential,
designing effective programs, implementing those programs, and measuring program
results.
EnerNOC Utility Solutions delivers value to our utility clients through two separate
practice areas – Program Implementation and EnerNOC Utility Solutions Consulting.
• Our Program Implementation team leverages EnerNOC’s deep ―behind-the-meter
expertise‖ and world-class technology platform to help utilities create and
manage DR and EE programs that deliver reliable and cost-effective energy
savings. We focus exclusively on the commercial and industrial (C&I) customer
segments, with a track record of successful partnerships that spans more than a
decade. Through a focus on high quality, measurable savings, EnerNOC has
successfully delivered hundreds of thousands of MWh of energy efficiency for
our utility clients, and we have thousands of MW of demand response capacity
under management.
• The EnerNOC Utility Solutions Consulting team provides expertise and analysis
to support a broad range of utility DSM activities, including: potential
assessments; end-use forecasts; integrated resource planning; EE, DR, and
smart grid pilot and program design and administration; load research;
technology assessments and demonstrations; evaluation, measurement and
verification; and regulatory support.
The EnerNOC Utility Solutions Consulting team has decades of combined experience
in the utility DSM industry. The staff is comprised of professional electrical,
mechanical, chemical, civil, industrial, and environmental engineers as well as
economists, business planners, project managers, market researchers, load research
professionals, and statisticians. Utilities view our experts as trusted advisors, and we
work together collaboratively to make any DSM initiative a success.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1083 of 1125

2013 Electric Integrated
Resource Plan

Appendix D – 2013 Electric IRP
Transmission Studies

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1084 of 1125
Interoffice Memorandum
System Planning
MEMO: SP-2012-09
DATE: August 14, 2012
TO: Scott Waples
FROM: Richard Maguire
SUBJECT: 2013 IRP Generation Study – Nine Mile HED

Introduction

This study addresses a request from Avista’s Power Supply Department for the 2013 IRP regarding
increasing the capacity of Nine Mile HED to 60 MW.
The study addresses the following:
Power flow impact to the transmission system
Voltage level impact to the transmission system
Transmission system upgrades necessary to deliver requested generation
History The Nine Mile project was built by a private developer in 1908 near Nine Mile Falls, Washington, nine miles northwest of Spokane. The Company purchased the project in 1925 from the Spokane & Eastern Railway. Its four units have a 17.6 MW maximum capacity and a 26.4 MW nameplate rating. Currently Unit 1 provides no generation and Unit 2 is limited to half load and unit 4 failed in the spring of 2011. These units will be replaced, and the desired capacity of the plant upon replacement of the new units is 60 MW. Avista expects the new capacity will add incremental energy towards meeting Washington State Energy Independence Act goals.
Study Methodology and Assumptions
Avista’s five year planning horizon planning cases are used and modified with the following projects prior to transmission system analysis:
Spokane Valley Transmission Reinforcement Project
Moscow Transformer Replacement Project
Lancaster Loop-In Project
Palouse Wind Phase I (LGIP #5)
Study Results Studies for this request confirm that Avista’s transmission system has adequate capacity to integrate the Nine Mile HED at a total plant output of 60 MW under all conditions studied. The limiting element is the Nine Mile – Indian Trail 115 kV transmission line, and figures showing the base case plus two limiting contingencies follow.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1085 of 1125

Figure 1. N-0, Avista Spring Case AVA-11ls1ae-16BA1328-WOH4140

Figure 2. Limiting Contingency: N-1: Airway Heights - Devils Gap 115 kV Open @ DGP

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1086 of 1125

Figure 3. Limiting Contingency: BF A180 Airway Heights 115 kV, Airway Heights - Devils Gap

Distribution: S. Waples Sharepoint (System Planning) OASIS Posting Power Supply (J. Gall)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1087 of 1125
Interoffice Memorandum
System Planning
MEMO: SP-2013-04
DATE: January 14, 2013
TO: Scott Waples
FROM: Richard Maguire
SUBJECT: 2013 IRP Generation Study – Long Lake HED

Introduction This study addresses a request from Avista’s Power Supply Department for the 2013 IRP regarding increasing the capacity of Long Lake HED by 68 MW. This preliminary study addresses the following:
Power flow impact to the transmission system
Voltage level impact to the transmission system
Transmission System upgrades necessary to deliver requested generation
History The Long Lake project is located northwest of Spokane and maintains the Lake Spokane reservoir, also known as Long Lake. The facility was the highest spillway dam with the largest turbines in the world when it was completed in 1915. The plant was upgraded with new runners in the 1990s, adding 2.2 aMW of additional energy. The project’s four units provide 88.0 MW of combined capacity and have an 81.6 MW nameplate rating.
Study Methodology and Assumptions
The five year planning horizon, Avista planning cases, as documented in SP-2011-03 – 2011 Planning Cases Summary Data are modified with the following projects and adjustments before
system analysis:
LGIR #5
Lind 115 kV Substation Reactive Support
2013 IRP Generation Request for Nine Mile HED (60 MW Total)
Nine Mile HED and Little Falls HED set to maximum generation dispatch
Increases in Long Lake generation are balanced by decrementing an injection group including all Avista generation with the exception of Long Lake HED, Nine Mile HED, and
Little Falls HED.
Western Montana Hydro is limited to 1650 MW
West of Hatwai is limited to 4277 MW The most limiting case found during this study is the Light Summer with High West of Hatwai Flows (High Transfer Case) numbered AVA-11ls1ae-12BA1251-WOH4277. This is the primary case used in this study.
Figure 1 below presents a high-level view of the Transmission System near Devil’s Gap with Long
Lake HED generating an additional 68 MW. Note the loading on the Nine Mile – Westside 115 kV Transmission Line. Table 1 below shows regional power flows with the additional generation.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1088 of 1125
Figure 1: Avista Transmission System near Long Lake HED

Table 1: Regional Power Flows used during system study

Western Montana Hydro 1624.3 MW West of Hatwai (Path 6) 4231.3 MW
Noxon Rapids (562MW) 483.0 MW Lolo-Oxbow 230kV 129.2 MW
Cabinet Gorge (265MW) 221.3 MW Dry Creek-Walla Walla 230kV 176.8 MW
Libby (605MW)540.0 MW
Hungry Horse (430MW) 380.0 MW West of Cabinet 3301.6 MW
Montana-Northwest (Path 8) 2065.1 MW
Colstrip Total
Colstrip 1 (330MW) 330.0 MW Idaho-Northwest (Path 14) 751.2 MW
Colstrip 2 (330MW) 330.0 MW Midpoint-Summer Lake (Path 75) 819.6 MW
Colstrip 3 (823MW) 787.5 MW Idaho-Montana (Path 18) -191.9 MW
Colstrip 4 (823MW) 792.8 MW
South of Boundary 963.5 MW
Rathdrum Thermal (175MW) 130.0 MW North of John Day (Path 73) 4525.6 MW
Lancaster Thermal (270MW) 249.0 MW TOT 4A (Path 37)454.4 MW
Spokane River Hydro 291.8 MW Miles City DC 200.0 MW
Boundary Hydro (1040MW) 975.0 MW
Path C (Path 20)537.4 MW
Lower Snake/N.F. Clearwater Borah West (Path 17)1578.2 MW
Dworshak (458MW) 344.6 MW Bridger West (Path 19) 2104.2 MW
Lower Granite (930MW) 155.0 MW Pacific AC Intertie (Path 66) 2855.0 MW
Little Goose (930MW) 155.0 MW Pacific DC Intertie (Path 65) 1999.9 MW
Lower Monumental (930MW) 273.5 MW
Northwest Load 17796.4 MW
Coulee Generation Idaho Load 2326.0 MW
Coulee 500 kV 546.7 MW Montana Load 1339.5 MW
Coulee 230 kV 125.0 MW Avista Native Load -837.0 MW
Avista Balancing Area Load 1179.9 MW
Clearwater Load 63.6 MW
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1089 of 1125

Study Results
Thermal Performance during N-0 conditions This preliminary study indicates the Avista Transmission System has adequate capacity to integrate an additional 68 MW of generation at Long Lake HED with all lines in service.
Thermal Performance during N-1 conditions Table 2 shows the results of a study using PowerWorld Simulator’s Available Transfer Capability tool for Long Lake HED. The table shows limiting transmission segments for contingencies in violation as generation at Long Lake is incremented. In order to incorporate 68 MW of additional generation at Long Lake HED while maintaining Transmission System thermal reliability under N-1 conditions, the following 115 kV Transmission Lines would need upgrades to at least 795 ACSS conductor:
1. Devils Gap – Long Lake #1
2. Devils Gap – Long Lake #2
3. Devils Gap – Ninemile
4. Ninemile – West Side
5. Airway Heights – Devils Gap
6. Airway Heights – Sunset
An approximate cost to reconductor 57.54 miles of 115 kV transmission line would be $ 9.9M1. Table 2: Available Transfer Capability for Long Lake HED

1 All construction costs are in 2013-year dollars and are based on engineering judgment only with +/- 50%
error
Incremental Generation Limiting CTG From Name To Name
1.86 BF: A413 Westside 115 kV, Ninemile-Westside AIRWAYHT SUNSET
1.89 N-1: Airway Heights - Devils Gap 115 kV Open @ DGP INDTRAIL WEST
3.32 N-1: Airway Heights - Devils Gap 115 kV INDTRAIL WEST
4.05 PSF: Westside 115 kV AIRWAYHT SUNSET
4.12 BF: A180 Airway Heights 115 kV, Airway Heights-Devils Gap INDTRAIL WEST
4.19 PSF: Airway Heights 115 kV INDTRAIL WEST
4.52 N-1: Nine Mile - Westside 115 kV Open @ WES AIRWAYHT SUNSET
8.13 N-1: Airway Heights - Devils Gap 115 kV Open @ AIR INDTRAIL WEST
11.58 N-1: Nine Mile - Westside 115 kV Open @ NMS DEVILGPE W.PLAINS
11.8 N-1: Nine Mile - Westside 115 kV DEVILGPE W.PLAINS
15.03 BF: A413 Westside 115 kV, Ninemile-Westside DEVILGPE W.PLAINS
17.21 PSF: Westside 115 kV DEVILGPE W.PLAINS
17.29 N-1: Nine Mile - Westside 115 kV Open @ WES DEVILGPE W.PLAINS
20.54 N-1: Nine Mile - Westside 115 kV Open @ NMS AIRWAYHT W.PLAINS
20.75 N-1: Nine Mile - Westside 115 kV AIRWAYHT W.PLAINS
24.19 BF: A413 Westside 115 kV, Ninemile-Westside AIRWAYHT W.PLAINS
26.27 N-1: Nine Mile - Westside 115 kV Open @ WES AIRWAYHT W.PLAINS
26.36 PSF: Westside 115 kV AIRWAYHT W.PLAINS
35.57 N-1: Devils Gap - Long Lake #1 115 kV DEVILGPE LONGLAKW
45.31 N-1: Devils Gap - Long Lake #2 115 kV DEVILGPE LONGLAKE
68.26 N-1: Airway Heights - Devils Gap 115 kV Open @ DGP DEVILGPE NINEMILE
69.63 N-1: Airway Heights - Devils Gap 115 kV DEVILGPE NINEMILE
70.43 BF: A180 Airway Heights 115 kV, Airway Heights-Devils Gap DEVILGPE NINEMILE
70.43 PSF: Airway Heights 115 kV DEVILGPE NINEMILE
74.43 N-1: Airway Heights - Devils Gap 115 kV Open @ AIR DEVILGPE NINEMILE
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1090 of 1125
Voltage Stability Preliminary voltage studies show that 68 MW of additional generation at Long Lake HED does not introduce any new voltage issues on the Avista Transmission System.
Conclusion This study indicates the requested new generation at Long Lake HED performs adequately on the local Transmission System with potential updates to several 115 kV Transmission Lines in the West Spokane area. Potential cost of upgrading Transmission Lines is $9.9 M, and further costs might be necessary to mitigate issues uncovered in more detailed thermal and transient stability studies.

Distribution: Scott Waples SharePoint (System Planning) Avista OASIS Posting James Gall - Power Supply & Resource Planning
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1091 of 1125
Interoffice Memorandum
System Planning
MEMO: SP-2013-03
DATE: January 22, 2013
TO: Scott Waples
FROM: Richard Maguire
SUBJECT: 2013 IRP Generation Study – Monroe Street HED

Introduction
This study addresses a request from Avista’s Power Supply Department for the 2013 IRP regarding
adding 80 MW of additional capacity to Monroe Street HED. This preliminary study addresses the following:
Thermal impact to the transmission system
Voltage stability impact to the transmission system
Transmission System upgrades necessary to deliver requested generation

History

The Monroe Street facility was the Company’s first generating unit. It started service in 1890 near
what is now Riverfront Park. Rebuilt in 1992, the single generating unit now has a 15.0 MW maximum
capacity and a 14.8 MW nameplate rating.

Study Methodology and Assumptions The five year planning horizon, Avista planning cases, as documented in SP-2011-03 – 2011 Planning Cases Summary Data are modified with the following projects and adjustments before system analysis:
LGIR #5
LGIR #35
Lind 115 kV Substation Reactive Support
Increases in Monroe Street generation are balanced by decrementing an injection group including all Avista generation with the exception of generation at Monroe Street HED and
Upper Falls HED.
Western Montana Hydro is limited to 1650 MW
West of Hatwai is limited to 4277 MW The most limiting case found during this study is the Light Summer with High West of Hatwai Flows (Heavy Summer, High Hydro Case) numbered AVA-11ls1ae-12BA1251-WOH4277. This is the
primary case used in this study.
Figure 1 below presents a high-level view of the Transmission System near Monroe Street HED with
the additional 80 MW of generation supplied by a study generator.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1092 of 1125
Figure 1: Avista Transmission System near Monroe Street HED

Study Results

Thermal Performance during N-0

This preliminary power flow study indicates the Avista Transmission System has adequate capacity to
integrate 80 MW of additional generation at Monroe Street HED with all lines in service.

Thermal Performance during N-1

This preliminary power flow study indicates the Avista Transmission System has adequate capacity to
integrate 80 MW of additional generation at Monroe Street HED during N-1 contingency conditions. Table 1 shows the results of a study using PowerWorld Simulator’s Available Transfer Capability tool for Monroe Street HED. The study reveals the next closest N-1 contingency violation as an overload of the Post Street – Third and Hatch 115 kV transmission line during the PSF: Westside 115 kV contingency if the additional generation capacity at Monroe Street HED was 122.85 MW.
Table 1: PowerWorld ATC results for Monroe Street HED
Trans Lim From Name To Name Limiting CTG
122.85 POSTSTRT THIRHACH PSF: Westside 115 kV
132.47 POSTSTRT THIRHACH BF: A470 Westside 115 kV, College & Walnut-Westside
135.41 POSTSTRT THIRHACH BF: A410 Westside 115 kV, Sunset-Westside
139.77 POSTSTRT THIRHACH BF: A413 Westside 115 kV, Ninemile-Westside
142.54 POSTSTRT THIRHACH BUS: Westside 115 kV

Voltage Stability Preliminary voltage studies show that 80 MW of additional generation at Monroe Street HED does not introduce any new voltage issues on the Avista Transmission System.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1093 of 1125
Conclusion

This preliminary study indicates the requested generation at Monroe Street HED performs adequately
on the local Transmission System pending any conditions revealed through further detailed thermal,
voltage, and transient stability studies.

Distribution:

Scott Waples
SharePoint (System Planning)
Avista OASIS Posting
James Gall – Power Supply & Resource Planning
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1094 of 1125
Interoffice Memorandum
System Planning
MEMO: SP-2013-05
DATE: January 22, 2013
TO: Scott Waples
FROM: Richard Maguire
SUBJECT: 2013 IRP Generation Study – Upper Falls HED

Introduction

This study addresses a request from Avista’s Power Supply Department for the 2013 IRP regarding
adding 40 MW of additional capacity to Upper Falls HED. This study will be undertaken as a
coincident generation request with the Monroe Street IRP request for three reasons:
Upper Falls HED and Monroe Street HED connect to the Avista 115 kV Transmission System at the same bus
The Monroe Street HED IRP request of 80 MW was found to require no transmission system modifications, thereby showing no individual study of the Upper Falls request would be
necessary given the lesser requested capacity
It would be useful to understand the overall impact to the transmission system if both Upper Falls HED and Monroe Street HED IRP requests are pursued This preliminary study addresses the following:
Thermal impact to the transmission system
Voltage stability impact to the transmission system
Transmission system upgrades necessary to deliver requested generation
History The Upper Falls project 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 unit with a 10.26 MW maximum capacity rating.
Study Methodology and Assumptions
The five year planning horizon, Avista planning cases, as documented in SP-2011-03 – 2011
Planning Cases Summary Data are modified with the following projects and adjustments before
system analysis:
LGIR #5
LGIR #35
2013 IRP Monroe Street Request
Lind 115 kV Substation Reactive Support
Increases in Upper Falls generation are balanced by decrementing an injection group including all Avista generation with the exception of generation at Monroe Street HED and Upper Falls HED.
Western Montana Hydro is limited to 1650 MW
West of Hatwai is limited to 4277 MW The most limiting case found during this study is the Light Summer with High West of Hatwai Flows (Heavy Summer, High Hydro Case) numbered AVA-11ls1ae-12BA1251-WOH4277. This is the primary case used in this study.
Figure 1 below presents a high-level view of the Transmission System near Upper Falls HED with the additional 120 MW of coincidental generation supplied by a study generator.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1095 of 1125
Figure 1: Avista Transmission System near Upper Falls HED

Study Results

Thermal Performance during N-0

This preliminary power flow study indicates the Avista Transmission System has adequate capacity to
integrate 40 MW of additional generation at Upper Falls HED with all lines in service. The closest N-0
violation occurs when attempting to integrate 47 MW of generation at Upper Falls which overloads the
Post Street-Third & Hatch 115 kV Transmission Line.

Thermal Performance during N-1

This preliminary power flow study indicates the Avista Transmission System has adequate capacity to
integrate 40 MW of additional generation at Upper Falls HED during N-1 contingency conditions.
Table 1 shows the results of a PowerWorld Simulator Available Transfer Capability analysis done for
Upper Falls HED. The ATC study reveals the next closest N-1 contingency violation as an overload of
the Post Street-Third & Hatch 115 kV Transmission Line during the PSF: Westside 115 kV
contingency if the additional generation capacity at Upper Falls HED exceeds 49.49 MW.

Table 1: ATC results for Upper Falls HED
Incremental
Generation
Limiting CTG From Name To Name
49.49 PSF: Westside 115 kV POSTSTRT THIRHACH
58.69 BF: A470 Westside 115 kV, College & Walnut-Westside POSTSTRT THIRHACH
62.04 BF: A410 Westside 115 kV, Sunset-Westside POSTSTRT THIRHACH
65.93 BF: A413 Westside 115 kV, Ninemile-Westside POSTSTRT THIRHACH
68.98 BUS: Westside 115 kV POSTSTRT THIRHACH

Voltage Stability

Preliminary voltage studies show that 40 MW of additional generation at Upper Falls HED does not
introduce any new voltage issues on the Avista Transmission System.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1096 of 1125

Conclusion

This preliminary study indicates the requested generation at Upper Falls HED performs adequately
on the local Transmission System pending any conditions revealed through further detailed thermal,
voltage, and transient stability studies.

Distribution:

Scott Waples
SharePoint (System Planning)
Avista OASIS Posting
James Gall - Power Supply & Resource Planning
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1097 of 1125
Interoffice Memorandum
System Planning
MEMO: SP-2013-02
DATE: January 22, 2013
TO: Scott Waples
FROM: Richard Maguire
SUBJECT: 2013 IRP Generation Study – Post Falls HED

Introduction

This study addresses a request from Avista’s Power Supply Department for the 2013 IRP regarding
increasing the capacity of Post Falls HED to a total output of 33.5 MW.

This preliminary study addresses the following:
Thermal impact to the transmission system
Voltage stability impact to the transmission system
Transmission System upgrades necessary to deliver requested generation

History Avista’s upper most hydroelectric facility on the Spokane River is the Post Falls project, located at its Idaho namesake near the Washington/Idaho border. The project began operation in 1906 and maintains lake elevation during the summer for Lake Coeur d’Alene. The project has six units, with the last unit added in 1980. The project is capable of producing 18.0 MW and has a 14.75 MW nameplate rating.
Study Methodology and Assumptions The five year planning horizon, Avista planning cases, as documented in SP-2011-03 – 2011 Planning Cases Summary Data are modified with the following projects and adjustments before system analysis:
LGIP #5
Lind 115 kV Substation Reactive Support
Increases in Post Falls generation are balanced by decrementing an injection group including all Avista generation with the exception of Post Falls HED.
Western Montana Hydro is limited to 1650 MW
West of Hatwai is limited to 4277 MW The most limiting case found during this study is the Heavy Summer with High Local Hydro Generation (Heavy Summer, High Hydro Case) numbered AVA-11hs2a-12BA2085. This is the primary case used in this study.
Figure 1 below presents a high-level view of the Transmission System near Post Falls HED. Note the relatively large amount of local load immediately connected to the Post Falls substation when compared to the requested 33.5 MW total plant output.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1098 of 1125
Figure 1: Avista Transmission System near Post Falls HED

Study Results
Thermal Performance during N-0 This preliminary power flow study indicates the Avista Transmission System has adequate capacity to integrate 33.5 MW of total generation at Post Falls HED with all lines in service.
Thermal Performance during N-1 This preliminary power flow study indicates the Avista Transmission System has adequate capacity to integrate 33.5 MW of total generation at Post Falls HED during N-1 contingency conditions. Table 1 shows the results of a PowerWorld Simulator Available Transfer Capability analysis done for Post
Falls HED. The ATC study reveals the next closest N-1 contingency violation as an overload of the Post Falls – Prairie B 115 kV Transmission Line during the N-1: Otis Orchards – Post Falls 115 kV Open @ PF contingency when the total generation capacity at Post Falls HED is 112.15 MW.

Table 1: ATC study results for Post Falls HED

Trans Lim From Name To Name Limiting CTG112.15 POST FLS PRAIRIEB N-1: Otis Orchards - Post Falls 115 kV Open @ PF
112.16 POST FLS PRAIRIEB BF: A642 Otis Orchards 115 kV, Otis Orchards-Post Falls
112.17 POST FLS PRAIRIEB N-1: Otis Orchards - Post Falls 115 kV
112.18 POST FLS PRAIRIEB PSF: Otis Orchards 115 kV138.87 EASTFARM POST FLS N-1: Post Falls - Ramsey 115 kV Open @ PF
139.68 EASTFARM POST FLS N-1: Post Falls - Ramsey 115 kV
139.68 EASTFARM POST FLS N-2: Post Falls - Ramsey 115 kV & Ramsey - Rathdrum #1 115 kV147.42 OTIS LIBTYLK SUB: Beacon 230 & 115 (AVA)
173.04 CLEARWTR N LEWIST N-2: Dry Creek - North Lewiston 230 kV and Dry Creek - North Lewiston 115 kV and North Lewiston - Tucannon River 115 kV
1638.3 POST FLS PRAIRIEB PSF: Post Falls 115 kV
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1099 of 1125
Voltage Stability Preliminary voltage studies show that 33.5 MW of total generation at Post Falls HED does not introduce any new voltage issues on the Avista Transmission System.
Conclusion This preliminary study indicates the requested generation at Post Falls HED performs adequately on the local Transmission System pending any conditions revealed through further detailed thermal, voltage, and transient stability studies.

Distribution: Scott Waples SharePoint (System Planning) Avista OASIS Posting James Gall – Power Supply & Resource Planning
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1100 of 1125
Interoffice Memorandum
System Planning
MEMO: SP-2012-14
DATE: October 4, 2012
TO: Scott Waples
FROM: Richard Maguire
SUBJECT: 2013 IRP Generation Study – Cabinet Gorge HED

Introduction
This brief study addresses a request from Avista’s Power Supply Department for the 2013 IRP regarding adding up to 110 MW of new generation capacity in the form of two new units to Cabinet
Gorge HED.

History

The Cabinet Gorge project started generating power in 1952 with two units. The plant was expanded
with two additional generators in the following year. The current maximum capacity of the plant is
270.5 MW; it has a nameplate rating of 265.2 MW. Upgrades at this project began with the
replacement of the turbine for Unit 1 in 1994. Unit 3 was upgraded in 2001 and Unit 2 was upgraded
in 2004. The final unit, Unit 4, received a $6 million turbine upgrade in 2007, increasing its generating
capacity from 55 MW to 64 MW, and adding 2.1 aMW of additional energy.1

Study Methodology and Assumptions

Two of Avista’s five year planning horizon cases are modified with the following projects prior to
analysis:
Spokane Valley Transmission Reinforcement Project
Moscow Transformer Replacement Project
Lancaster Loop-In Project
Palouse Wind Phase I (LGIP #5) The two cases used in this study are:
AVA-16hs2a-16BA2213; Heavy Summer High Hydro (HSHH)
AVA-11ls1ae-16BS1328-WOH4140; Light Loading High Transfer (HT)

These cases represent two seasonal times when maximum hydro generation is possible.

Table 1 below shows the power flow values with an additional 110 MW of generation at Cabinet
Gorge. All changes in generation are coupled with:
Limiting Western Montana Hydro to 1650 MW by reducing outputs of Libby and Hungry
Horse
Limiting West of Hatwai to 4277 MW via control of off-system generation

1 Cabinet Gorge history taken from Avista 2011 Electric Integrated Resource Plan
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1101 of 1125

Table 1: Base Case Power Flow Summary

Study Results

Thermal Performance during N-0 conditions The study indicates that the Avista transmission system has enough capacity to integrate an additional 110 MW of generation at Cabinet Gorge HED with all lines in service during some, but not all, conditions. One example of a limiting condition occurs during hot summer months when the loading is high and full hydro generation is possible. During this heavy summer, high hydro scenario, the present Avista transmission system has just enough transmission capacity for existing generation. Figure 1 below shows the Avista system isolated from neighbor systems for the purpose of determining transmission capacity. This is a unique test for this study, and no other cases are evaluated with the system isolated in this way. The image represents flows in the 2016 heavy summer high hydro case with Cabinet Gorge and Noxon operating at maximum capacity. Note:
This study uses existing line ratings. Avista has projects underway raising line ratings in the area,
which will result in more transmission capacity once the projects are completed.
Generation at Cabinet Gorge HED and Noxon Rapids HED could be governed within a nomogram
to mitigate thermal overloads during summer conditions when electric loading is high.
NOTE: these conclusions are contingent upon further detailed studies

West of Hatwai (Path 6)813.1 MW West of Hatwai (Path 6)4275.0 MW
Montana-Northwest (Path 8)758.7 MW Montana-Northwest (Path 8)2101.2 MW
Western Montana Hydro 1650.0 MW Western Montana Hydro 1650.0 MW
Noxon Rapids (562MW) 570.6 MW Noxon Rapids (562MW) 570.6 MW
Cabinet Gorge (265MW) 397.0 MW Cabinet Gorge (265MW) 397.0 MW
Libby (605MW)395.9 MW Libby (605MW)395.9 MW
Hungry Horse (430MW) 286.5 MW Hungry Horse (430MW) 286.5 MW
Colstrip 1 (330MW) 329.3 MW Colstrip 1 (330MW) 330.8 MW
Colstrip 2 (330MW) 329.3 MW Colstrip 2 (330MW) 330.8 MW
Colstrip 3 (823MW) 789.1 MW Colstrip 3 (823MW) 796.5 MW
Colstrip 4 (823MW) 803.3 MW Colstrip 4 (823MW) 801.8 MW
Rathdrum Thermal (175MW) 0.0 MW Rathdrum Thermal (175MW) 140.0 MW
Lancaster Thermal (270MW) 248.4 MW Lancaster Thermal (270MW) 249.4 MW
Spokane River Hydro 88.2 MW Spokane River Hydro 183.8 MW
Boundary Hydro (1040MW) 633.6 MW Boundary Hydro (1040MW) 976.5 MW
Northwest Load 26444.8 MW Northwest Load 17948.5 MW
Idaho Load 4087.0 MW Idaho Load 2326.0 MW
Montana Load 1940.3 MW Montana Load 1339.5 MW
Avista Native Load -1701.7 MW Avista Native Load -959.6 MW
Avista Balancing Area Load 1671.7 MW Avista Balancing Area Load 911.6 MW
Clearwater Load 58.2 MW Clearwater Load 58.2 MW
Heavy Summer High Hydro Light Spring High Transfer
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1102 of 1125
Figure 1: 2016 HSHH, all facilities in service, Cabinet Gorge @287MW
Thermal Performance during N-1 conditions

Given the current study reveals Cabinet Gorge HED must be limited to zero additional capacity when
operating under conditions similar to those used in the Heavy Summer, High Hydro case, only the High
Transfer case is used to consider N-1 contingency violations.

All new N-1 contingency violations found during this study are in the immediate vicinity of the Cabinet
Gorge HED. Figure 2 shows the most limiting contingency occuring when the Cabinet to Noxon 230 kV
line overloads with a loss of the 230 kV line to Rathdrum for a failure of breaker R404.2 As noted in the
notes above, Avista has transmission projects underway that lessen the severity of all of the N-1
contingency violations found in this study, and further detailed study will determine what, if any, N-1
violations still exist once the local projects are completed.

Note: Reducing the new generation at Cabinet Gorge to values less than the requested 110 MW directly
impacts the new limiting N-1 contingency violations. This behavior likely reduces the steady state
nomogram discussed above.

Figure 2: Cabinet-Noxon 230 kV overload during R404 breaker failure
Voltage Stability With all lines in service, an addition of 110 MW at Cabinet Gorge does not introduce any new voltage violations during N-0 conditions. However, this study indicates several new voltage violations are present during N-1 conditions. The limiting contingency regarding voltage stability occurs at Bus 48057, the Cabinet Gorge 230 kV bus, during the N-1: Cabinet – Noxon 230 kV contingency. The voltage limit used is 1.015 pu, the initial value is 1.045 pu, and the value during contingency is 1.0049 pu. Figure 3 shows the violation.

2 BF: R404 Cabinet-Rathdrum, Rathdrum #2 230/115 Transformer
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1103 of 1125
All of the newly created voltage violations can be mitigated by reducing generation at Cabinet Gorge to levels above present values but below the requested 110 MW addition. Additionally, existing and planned projects on the Avista transmission system positively influence these new voltage violations. Further detailed studies are necessary to fully characterize voltage performance.
Figure 3: 2016 HT, Voltage Limit Violation, N-1: Cabinet – Noxon 230 kV

Transient Stability

Preliminary studies indicate new generation at Cabinet Gorge adds stability violations during N-1
conditions, and additional generation exacerbates stability issues addressed by the existing Clark Fork
remedial action scheme (i.e. RAS). Adding any new generation to the existing RAS scheme clears
several of the new N-1 violations, but further studies are necessary to accurately assess solutions for the
other violations. Possible solutions could be changes to the existing RAS, a nomogram as discussed
above, and/or transmission projects to mitigate violations.
Conclusions This study indicates the requested new generation at Cabinet Gorge performs adequately on the local transmission system with potential updates to the Clark Fork RAS and limits to Cabinet Gorge and Noxon combined output via a seasonally adjusted nomogram determined by further study. If operating Cabinet Gorge without limitation is desired, preliminary studies show this is possible via potential projects on one or more of the 230 kV transmission lines carrying power to the load center.
Distribution: S. Waples Sharepoint (System Planning) OASIS Posting Power Supply (J. Gall)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1104 of 1125
500 MW of New Generation in the Rathdrum Area Page 1

Interoffice Memorandum
System Planning
MEMO: SP-2011-08 Rev A
DATE: August 11, 2011
TO: James Gall, IRP Group
FROM: Reuben Arts
SUBJECT: 500 MW of New Generation in the Rathdrum Area

Introduction
Based on initial 2011 IRP analysis 200 MW of new capacity is required in 2019-2020 and an additional 300 MW of capacity in the 2022-2024 time period. North Idaho is one of several potential locations this
capacity could be added, but requires further detail to understand its potential.
Problem Statement
The IRP group is specifically interested in the cost for both the point of integration (POI) station and associated system upgrades, to integrate the new generation with the following options:
1. Cabinet-Rathdrum 230 kV transmission line (assume 5 miles from Rathdrum)
2. Rathdrum-Boulder 230 kV transmission line (assume Lancaster looped in, and assume the
generation is half way between Lancaster and Rathdrum)
3. Rathdrum-Beacon 230 kV transmission line (assume 1-2 miles from Rathdrum)
4. Double Tap, Rathdrum-Boulder and Rathdrum-Beacon 230 kV transmission lines (again assume Lancaster is looped in and that the new generation will tap between Lancaster and Rathdrum)
5. Mixed location. 300 MW at the least cost option (between 1 and 4) and an additional 200 MW on the Cabinet-Rathdrum 230 kV transmission line.
6. Other Transmission Alternatives

Power Flow Analysis
The case that was used to highlight the impacts of an additional 500 MW in the Rathdrum area was the
WECC approved and Avista modified light summer high flow case (AVA-11ls1ae-12BA1251-WOH4277). The West of Hatwai path typically experiences high flows during light Avista load hours. High West of Hatwai flows tend to coincide with high Western Montana Hydro generation, high Boundary generation,
high flows on Montana to Northwest, and light loads in Eastern Washington, North Idaho, and Montana. Existing Clark Fork RAS is in place, and assumed armed, since the Western Montana Hydro (WMH) complex is greater than 1450 MW. Since the New Project would require significant Avista system
transmission changes, and RAS changes, the results are listed as though RAS were not armed. This does
affect the results of some contingencies, but ultimately does not change the conclusions of this memo.

Option 1
Perhaps one of the worst performing arrangements is option 1.This option immediately requires another
line, or a line reconductor, from the 500 MW project back to Rathdrum. In order to stay within N-0 thermal limits the project can only be 175 MW without any system upgrades. In a high flow, N-0 scenario, the line segment from the project back to Rathdrum loads to around 163%, which is roughly 272 MW overloaded.
There are a handful of N-1 and N-2 contingencies that cause significant thermal violations, the worst N-1 being the loss of the 230 kV transmission line from the new project to Rathdrum. See Figure 1
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1105 of 1125
500 MW of New Generation in the Rathdrum Area Page 2

Figure 1 – N-1 Contingency

In addition to this worst case outage there are two N-2 scenarios that cause fairly significant problems as well. The Beacon-Rathdrum and Boulder-Lancaster-Rathdrum 230 kV transmission lines share a common structure for the majority of the line lengths. Losing both lines to the west of Lancaster causes the Bell S3-
Lancaster 230 kV transmission line to overload. Losing both lines to the east of Lancaster, causes nearly the same scenario as shown in Figure 1.
To alleviate these overloads three new 230 kV transmission lines, would need to be built. First the Rathdrum-New Project 230 kV transmission line must be reconductored at a cost of roughly $2.25M. Second, A 230 kV transmission line, with new right-of-way, must be built from the New Project to
Lancaster. The estimated distance for this line is roughly 5 miles. The estimated loaded cost for this line, including a new line position at Lancaster and at the New Project, is roughly $9M. Finally, another 230 kV transmission line, again with new right-of-way, is required from Lancaster to Boulder. This line length is estimate at roughly 15 miles. The estimated loaded cost of the new line, including new line positions, is
roughly $17M. New right-of-way in this area will be difficult to obtain, which would have the potential of more than doubling costs.
RAS may be a viable solution. If at all possible RAS should be a last resort. Unlike improving our transmission system, RAS does not provide operational flexibility and in some cases can compound the impacts of future generation needs. However, it does represent the cheapest solution and is therefore
listed as solution 1.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1106 of 1125
500 MW of New Generation in the Rathdrum Area Page 3

Option 1 N-0 Max.
Output
Facility Requirement1 Total2
($000)
Solution 1 500 MW Reconductor 230 kV transmission line from new station to Rathdrum, New 230 kV DB-DB Station and RAS3 13,250
Solution 2 500 MW Reconductor from Rathdrum-New Project. New line from
Lancaster to New Project. New line from Lancaster to
Boulder, New 230 kV DB-DB Station
36,250

Option 2
This option would tap the Rathdrum-Boulder, or what soon will be the Rathdrum-Lancaster-Boulder, 230 kV transmission line. This options has no N-0 issues at the full requested 500 MW. There are a handful of N-1 and N-2 contingencies that cause significant thermal violations, the worst being the loss of the
Lancaster-Boulder & Rathdrum-Beacon 230 kV transmission lines. These lines share a common structure and therefore represent a credible N-2 scenario. This outage causes the Lancaster-Bell S3 230 kV transmission line to load to 189%, or roughly 450 MW above its thermal limit. See Figure 2.

Figure 2 - N-2 Contingency

To alleviate these overloads two new 230 kV transmission lines, would need to be built. A 230 kV transmission line, with new right-of-way, must be built from the New Project to Lancaster. The estimated
distance for this line is roughly 3 miles. The estimated loaded cost for this line, including a new line position at Lancaster and at the New Project, is roughly $8M. Another 230 kV transmission line, again with new right-of-way, is required from Lancaster to Boulder. This line length is estimate at roughly 15 miles.
The estimated loaded cost of the new line, including new line positions, is roughly $17M. New right-of-way in this area will be difficult to obtain, which would have the potential of more than doubling costs.
1 Cost estimates do not include costs of the radial line to the POI, the generator or generator station if applicable. 2 Total is for network and direct assigned costs, are in 2011 dollars, and is +/- 50%. 3 The RAS portion is a worst case scenario where another fiber loop is required. $3M allocated for RAS.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1107 of 1125
500 MW of New Generation in the Rathdrum Area Page 4

RAS may be a viable solution. If at all possible RAS should be a last resort. Unlike improving our
transmission system, RAS does not provide operational flexibility and in some cases can compound the impacts of future generation needs. However, it does represent the cheapest solution and is therefore listed as solution 1.

Option 2 N-0 Max.
Output
Facility Requirement4 Total5
($000)
Solution 1 500 MW New 230 kV DB-DB Station and RAS6 11,000
Solution 2 500 MW New line from Lancaster to New Project. New line from Lancaster to Boulder, New 230 kV DB-DB Station 33,000

Option 3
This option taps the Rathdrum-Beacon 230 kV transmission line. Again, this options has no N-0 issues at the full requested 500 MW. There are a handful of N-1 and N-2 contingencies that cause significant
thermal violations, the worst being the loss of the Beacon-New Project & Rathdrum-Lancaster 230 kV transmission lines. These lines share a common structure and therefore represent a credible N-2 scenario. This outage forces the entire proposed 500 MW toward Cabinet and Noxon. This causes overloads on the Cabinet-Noxon and Pine Creek-Benewah 230 kV transmission lines. See Figure 3.

Figure 3 - N-2 Contingency

4 Cost estimates do not include costs of the radial line to the POI, the generator or generator station if applicable. 5 Total is for network and direct assigned costs, are in 2011 dollars, and is +/- 50%. 6 The RAS portion is a worst case scenario where another fiber loop is required. $3M allocated for RAS.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1108 of 1125
500 MW of New Generation in the Rathdrum Area Page 5

To alleviate these overloads two new 230 kV transmission lines, would need to be built. A 230 kV
transmission line, with new right-of-way, must be built from the New Project to Lancaster. The estimated distance for this line is roughly 3 miles. The estimated loaded cost for this line, including a new line position at Lancaster and at the New Project, is roughly $8M. Another 230 kV transmission line, again with
new right-of-way, is required from Lancaster to Boulder. This line length is estimate at roughly 15 miles. The estimated loaded cost of the new line, including new line positions, is roughly $17M. New right-of-way in this area will be difficult to obtain, which would have the potential of more than doubling costs.

RAS may be a viable solution. If at all possible RAS should be a last resort. Unlike improving our transmission system, RAS does not provide operational flexibility and in some cases can compound the impacts of future generation needs. However, it does represent the cheapest solution and is therefore listed as solution 1.

Option 3 N-0 Max.
Output
Facility Requirement7 Total8
($000)
Solution 1 500 MW New 230 kV DB-DB Station and RAS9 11,000
Solution 2 500 MW New line from Lancaster to New Project. New line from Lancaster to Boulder, New 230 kV DB-DB Station 33,000

Option 4
This option taps the Rathdrum-Beacon & Rathdrum-Lancaster 230 kV transmission lines. This options has
no N-0 issues at the full requested 500 MW. There are a handful of N-1 and N-2 contingencies that cause significant thermal violations, the worst being the loss of the Beacon-New Project & Lancaster-New Project 230 kV transmission lines. These lines share a common structure and therefore represent a
credible N-2 scenario. This outage forces the entire proposed 500 MW toward Cabinet and Noxon. This causes overloads on the Cabinet-Noxon and Pine Creek-Benewah 230 kV transmission lines. (Very similar to Figure 3 on the previous page).

To alleviate these overloads two new 230 kV transmission lines, would need to be built. A 230 kV transmission line, with new right-of-way, must be built from the New Project to Lancaster. The estimated distance for this line is roughly 3 miles. The estimated loaded cost for this line, including a new line position at Lancaster and at the New Project, is roughly $8M. Another 230 kV transmission line, again with new right-of-way, is required from Lancaster to Boulder. This line length is estimate at roughly 15 miles. The estimated loaded cost of the new line, including new line positions, is roughly $17M. New right-of-way in this area will be difficult to obtain, which would have the potential of more than doubling costs.

RAS may be a viable solution. If at all possible RAS should be a last resort. Unlike improving our transmission system, RAS does not provide operational flexibility and in some cases can compound the impacts of future generation needs. However, it does represent the cheapest solution and is therefore
listed as solution 1.

Option 4 N-0 Max.
Output
Facility Requirement Total
($000)
Solution 1 500 MW New 230 kV DB-DB Station and RAS 15,000
Solution 2 500 MW New line from Lancaster to New Project. New line from
Lancaster to Boulder, New 230 kV DB-DB Station
37,000
7 Cost estimates do not include costs of the radial line to the POI, the generator or generator station if applicable. 8 Total is for network and direct assigned costs, are in 2011 dollars, and is +/- 50%. 9 The RAS portion is a worst case scenario where another fiber loop is required. $3M allocated for RAS.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1109 of 1125
500 MW of New Generation in the Rathdrum Area Page 6

Option 5
This option taps the Rathdrum-Beacon & Rathdrum-Cabinet 230 kV transmission lines. A new switching station is required for each tap. A 300 MW generating station would be on the Beacon-Rathdrum 230 kV
transmission line and 200 MW would be on the Rathdrum-Cabinet 230 kV transmission line. This option has no N-0 issues at the full requested 500 MW. There are a handful of N-1 and N-2 contingencies that cause significant thermal violations, the worst being the loss of the Beacon-New Project & Lancaster-Rathdrum 230 kV transmission lines. These lines share a common structure and therefore represent a
credible N-2 scenario. This outage forces the entire proposed 500 MW toward Cabinet and Noxon. This causes overloads on the Cabinet-Noxon and Pine Creek-Benewah 230 kV transmission lines. (Very similar to what was shown in Figure 3).

To alleviate these overloads three new 230 kV transmission lines, would need to be built. A 230 kV transmission line, with new right-of-way, must be built from the New Project (300MW piece) to Lancaster. The estimated distance for this line is roughly 5 miles. The estimated loaded cost for this line, including a
new line position at Lancaster and at the New Project, is roughly $9M. Another 230 kV transmission line, again with new right-of-way, is required from Lancaster to Boulder. This line length is estimate at roughly 15 miles. The estimated loaded cost of the new line, including new line positions, is roughly $17M. Finally,
for the loss of the Rathdrum-New Project (200MW piece) 230 kV transmission line, causes the Cabinet-Noxon 230 kV transmission line to load to 117%. To alleviate this overload a new line, with new right-of-way must be built back to Rathdrum. The estimated loaded cost of this 5 mile line, along with associated line positions, is $9M. New right-of-way in this area will be difficult to obtain, which would have the
potential of more than doubling costs.

RAS may be a viable solution. If at all possible RAS should be a last resort. Unlike improving our transmission system, RAS does not provide operational flexibility and in some cases can compound the
impacts of future generation needs. However, it does represent the cheapest solution and is therefore listed as solution 1.
Option 5 N-0 Max.
Output
Facility Requirement10 Total11
($000)
Solution 1 500 MW Two New 230 kV DB-DB Stations and RAS12 22,000
Solution 2 500 MW Two New 230 kV DB-DB Stations, New line from Lancaster to New Project (300MW). New line from Lancaster to Boulder, New line from New Project (200MW) to Rathdrum
51,000

Option 6 – Other Transmission Alternatives
In addition to the five options listed, there are a few more options that may seem to be intuitive interconnection points. These integration options are:
a. Lancaster 230 kV (BPA) switching station
b. Rathdrum 230/115/13.2 kV substation
c. Cabinet-Rathdrum & Noxon-Lancaster 230 kV transmission lines
d. Bell-Taft 500 kV transmission line

Option 6a - Connecting to the Lancaster 230 kV switching station would save Avista the cost of a new switching station. It would also negate the need for a new transmission line, with associated right-of-way,
from the new project to Lancaster. The estimated savings, adding the previously quoted loaded costs, less
10 Cost estimates do not include costs of the radial line to the POI, the generator or generator station if applicable. 11 Total is for network and direct assigned costs, are in 2011 dollars, and is +/- 50%. 12 The RAS portion is a worst case scenario where another fiber loop is required. $3M allocated for RAS.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1110 of 1125
500 MW of New Generation in the Rathdrum Area Page 7

the added cost of connecting to Lancaster, is $13M13. This does not take into account any fees associated
with connecting to BPA. This option assumes there is room in the Lancaster substation to accept the new line position. If Lancaster substation cannot accommodate the new line position, the cost savings to interconnect at Lancaster may be negligible or non-existent.
This option would still have all the contingency issues and associated upgrades similar to Option 2.

Option 6b - Connecting to the Rathdrum substation saves the cost of building another switching station. All
contingency results are nearly identical to connecting the project to option 2 or option 3. The estimated savings of this option is $4M14. This option assumes there is room in the Rathdrum substation to accept the new line position. If Rathdrum substation cannot accommodate the new line position, the cost savings
to interconnect at Rathdrum may be negligible or non-existent.

Option 6c – Tapping the Cabinet-Rathdrum & Noxon-Lancaster 230 kV transmission lines does improve the network performance, in comparison to tapping only the Cabinet-Rathdrum 230 kV transmission line. However, this option still requires all the same network upgrades that option 1 requires since it is still
possible to have an N-2 situation where the generation of the New Project, Noxon and Cabinet is separated from the Coeur d’Alene/Spokane load. (See Figure 1). This option is listed for completeness.

Option 6d - Connecting solely to the Bell-Taft 500 kV transmission line cannot be done without RAS and
possibly some network upgrades on BPA’s system. In addition to the network upgrades that would likely be required on BPA’s system, Avista would also be financially liable to pay wheeling fees from the new project across BPA’s lines to Avista’s load. If the project is connected to both BPA’s Bell-Taft 500 kV
transmission line and Avista’s Rathdrum area 230 kV system, effectively avoiding wheeling charges, both RAS and significant network upgrades will be required. Due to the cost of a new 500 kV substation, associated RAS and the potentially large cost of network upgrades on BPA’s 500 kV system, this option is
not recommended.

Conclusion
Of the formally identified options, options 2 and 3 represent the least cost and best performing options. Of the other transmission alternatives, the Lancaster switching station, followed by the Rathdrum substation,
interconnection options represent the least cost and best performing alternative options. The following favorable options are:
Option 2: $11-33M (RAS only vs System Upgrades)15
Option 3: $11-33M (RAS only vs System Upgrades)15
Lancaster Alternative Option: $7-20M (RAS only vs System Upgrades)
Rathdrum Alternative Option: $7-33M (RAS only vs System Upgrades)
13 Assumes a network upgrade solution would be pursued, instead of a RAS only solution. 14 This $4M savings would be for either a RAS only or a network upgrade solution. 15 If the new project is interconnected to the west of Lancaster, the Lancaster-New Project 230 kV transmission line
is not needed. Hence the network upgrade cost would be reduced by $8M.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1111 of 1125
Interoffice Memorandum
System Planning
MEMO: SP-2013-07
DATE: February 15, 2012
TO: Scott Waples
FROM: Richard Maguire
SUBJECT: IRP Generation Study - Benewah to Boulder 230kV (BB-IRP)

Introduction
This study addresses a request from Avista’s Power Supply Department for the 2013 IRP regarding new generation on the Benewah - Boulder 230 kV Transmission Line at one of two capacity levels:
150 MW
300 MW

The study presents information and discussion on the follow topics:
Power flow impact to the transmission system
Transmission system upgrades necessary to deliver requested generation

Study Assumptions and Methodology
The five year planning horizon Avista planning cases, as documented in SP-2011-03 – 2011 Planning
Cases Summary Data, are modified with the following projects and adjustments prior to system
analysis:
LGIR #35 project (200 MW at Thornton 230 kV Substation)
LGIR #36 project (105 MW at Thornton 230 kV Substation)
BB-IRP topology:
o Benewah – Boulder 230kV Transmission Line tapped 13.1 electrical miles North
of Benewah 230 kV Substation
o Generic generator installed on new BB-IRP 230 kV bus
The following cases are used during this study:
Avista Heavy Summer High Hydro (“HSHH”) case: AVA-11hs2a-12BA2085
o Table 1 shows power flows for this case
Avista Heavy Summer Low Hydro (“HSLH”) case: AVA-11hs2a-12BA2085-LH
o Table 2 shows power flows for this case
Avista Light Summer with High West of Hatwai (High Transfers or “HT”)Flows: AVA-11ls1ae-12BA1251-WOH4277
o Table 3 shows power flows for this case with BB-IRP output = 300 MW

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1112 of 1125
Benewah – Boulder 2013 IRP Study
Table 1: Regional Power Flows for Heavy Summer Case

Table 2: Regional Power Flows for Light Summer Case

Western Montana Hydro 1098.1 MW West of Hatwai (Path 6) 951.8 MW
Noxon Rapids (562MW) 399.4 MW Lolo-Oxbow 230kV 296.0 MW
Cabinet Gorge (265MW) 184.7 MW Dry Creek-Walla Walla 230kV 184.1 MW
Libby (605MW)324.0 MW
Hungry Horse (430MW) 190.0 MW West of Cabinet 1581.7 MW
Montana-Northwest (Path 8) 979.0 MW
Colstrip Total
Colstrip 1 (330MW)330.0 MW Idaho-Northwest (Path 14) -585.4 MW
Colstrip 2 (330MW)330.0 MW Midpoint-Summer Lake (Path 75) -48.9 MW
Colstrip 3 (823MW)795.5 MW Idaho-Montana (Path 18) -296.3 MW
Colstrip 4 (823MW)804.9 MW
South of Boundary 582.9 MW
Rathdrum Thermal (175MW) 0.0 MW North of John Day (Path 73) 7034.7 MW
Lancaster Thermal (270MW) 249.0 MW TOT 4A (Path 37)407.0 MW
Spokane River Hydro 88.3 MW Miles City DC 142.0 MW
Boundary Hydro (1040MW) 635.0 MW
Path C (Path 20)118.7 MW
Lower Snake/N.F. Clearwater Borah West (Path 17)837.4 MW
Dworshak (458MW)316.0 MW Bridger West (Path 19) 2191.6 MW
Lower Granite (930MW) 554.2 MW Pacific AC Intertie (Path 66) 4430.9 MW
Little Goose (930MW)555.5 MW Pacific DC Intertie (Path 65) 2980.0 MW
Lower Monumental (930MW) 531.5 MW
Northwest Load 25129.6 MW
Coulee Generation Idaho Load 3702.5 MW
Coulee 500 kV 2308.5 MW Montana Load 1836.8 MW
Coulee 230 kV 1292.7 MW Avista Native Load -1594.3 MW
Avista Balancing Area Load 1885.6 MW
Clearwater Load 58.3 MW
Western Montana Hydro 627.1 MW West of Hatwai (Path 6) 120.3 MW
Noxon Rapids (562MW) 138.8 MW Lolo-Oxbow 230kV 277.0 MW
Cabinet Gorge (265MW) 82.3 MW Dry Creek-Walla Walla 230kV 159.6 MW
Libby (605MW)216.0 MW
Hungry Horse (430MW) 190.0 MW West of Cabinet 1110.7 MW
Montana-Northwest (Path 8) 970.1 MW
Colstrip Total
Colstrip 1 (330MW)330.0 MW Idaho-Northwest (Path 14) -585.9 MW
Colstrip 2 (330MW)330.0 MW Midpoint-Summer Lake (Path 75) -76.0 MW
Colstrip 3 (823MW)764.2 MW Idaho-Montana (Path 18) -274.8 MW
Colstrip 4 (823MW)776.0 MW
South of Boundary 299.4 MW
Rathdrum Thermal (175MW) 0.0 MW North of John Day (Path 73) 6931.9 MW
Lancaster Thermal (270MW) 249.0 MW TOT 4A (Path 37)399.6 MW
Spokane River Hydro 58.1 MW Miles City DC 142.0 MW
Boundary Hydro (1040MW) 310.0 MW
Path C (Path 20)133.4 MW
Lower Snake/N.F. Clearwater Borah West (Path 17)830.6 MW
Dworshak (458MW)316.0 MW Bridger West (Path 19) 2188.8 MW
Lower Granite (930MW) 554.2 MW Pacific AC Intertie (Path 66) 4222.6 MW
Little Goose (930MW)555.5 MW Pacific DC Intertie (Path 65) 2980.0 MW
Lower Monumental (930MW) 531.5 MW
Northwest Load 25129.6 MW
Coulee Generation Idaho Load 3702.5 MW
Coulee 500 kV 3066.4 MW Montana Load 1836.8 MW
Coulee 230 kV 1292.7 MW Avista Native Load -1594.3 MW
Avista Balancing Area Load 1874.1 MW
Clearwater Load 75.8 MW
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1113 of 1125
Benewah – Boulder 2013 IRP Study

Table 3: Regional Power Flows for High Transfer Case

Western Montana Hydro 1548.0 MW West of Hatwai (Path 6) 4251.2 MW
Noxon Rapids (562MW) 432.2 MW Lolo-Oxbow 230kV 140.1 MW
Cabinet Gorge (265MW) 195.8 MW Dry Creek-Walla Walla 230kV 189.5 MW
Libby (605MW)540.0 MW
Hungry Horse (430MW) 380.0 MW West of Cabinet 3204.5 MW
Montana-Northwest (Path 8) 2040.8 MW
Colstrip Total
Colstrip 1 (330MW) 330.0 MW Idaho-Northwest (Path 14) 741.0 MW
Colstrip 2 (330MW) 330.0 MW Midpoint-Summer Lake (Path 75) 831.7 MW
Colstrip 3 (823MW) 777.6 MW Idaho-Montana (Path 18) -198.3 MW
Colstrip 4 (823MW) 782.9 MW
South of Boundary 961.8 MW
Rathdrum Thermal (175MW) 116.4 MW North of John Day (Path 73) 4775.0 MW
Lancaster Thermal (270MW) 118.1 MW TOT 4A (Path 37)448.4 MW
Spokane River Hydro 152.4 MW Miles City DC 200.0 MW
Boundary Hydro (1040MW) 975.0 MW
Path C (Path 20)528.7 MW
Lower Snake/N.F. Clearwater Borah West (Path 17)1570.2 MW
Dworshak (458MW) 168.2 MW Bridger West (Path 19) 2098.0 MW
Lower Granite (930MW) 0.0 MW Pacific AC Intertie (Path 66) 3136.7 MW
Little Goose (930MW) 141.8 MW Pacific DC Intertie (Path 65) 1999.9 MW
Lower Monumental (930MW) 310.0 MW
Northwest Load 17796.4 MW
Coulee Generation Idaho Load 2326.0 MW
Coulee 500 kV 825.7 MW Montana Load 1339.5 MW
Coulee 230 kV 125.0 MW Avista Native Load -837.0 MW
Avista Balancing Area Load 680.3 MW
Clearwater Load 71.1 MW

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1114 of 1125
Benewah – Boulder 2013 IRP Study

Study Results

Thermal Performance during Category A conditions1

This preliminary study indicates the Avista Transmission System has adequate capacity to integrate 300
MW at the proposed interconnection point during Category A all lines in service conditions.

Thermal Performance during Category B and Category C conditions

Table 4 shows preliminary results of a study using PowerWorld Simulator’s Available Transfer Capability
(ATC) tool for generation injections at BB-IRP. This tool generates a list of facility thermal violations (From
To) that arise under contingency conditions for incremental increases in generation output (BB WM).
When the results for each case under study are collected and analyzed together with results from
standard contingency analysis studies, this tool provides an idea of what facilities overload for rising
levels of generation output.

As the table shows, there are six facilities that come into violation for a requested BB-IRP output of 150
MW, and there are an additional five facilities that come into violation for a requested BB-IRP output of
300 MW.
Table 4: Incremental generation analysis for BB-IRP IRP request2

1 Contingency category descriptions can be found at: http://www.nerc.com/files/TPL-001-0.pdf

2 BF = Breaker Failure; PSF = Protection System Failure; N-X contingencies refer to ‘X’ transmission element outages
Case MW Output Limiting Contingency From Name To Name
HSLH 27.11 BF: A470 Westside 115 kV, College & Walnut-Westside GLENTAP NINTHCNT
HSHH 28.2 BUS: Westside 115 kV POSTSTRT THIRHACH
HT 84.08 N-1: Hatwai - Moscow 230 230 kV MOSCOW MOSCOWX
HSLH 106.34 BUS: Westside 115 kV ROSSPARK THIRHACH
HSHH 106.63 BF: A413 Westside 115 kV, Ninemile-Westside POSTSTRT THIRHACH
HSHH 112.15 BF: A689 Ninth & Central South 115 kV, Ninth & Central-Otis Orchards POSTSTRT THIRHACH
HSLH 116.64 N-2: Bell - Westside 230 kV & Coulee - Westside 230 kV GLENTAP NINTHCNT
HSLH 117.24 BUS: Westside 230 kV GLENTAP NINTHCNT
HSLH 123.43 BF: A370 Bell S1 & S2 230 kV BEACON N BEACON N
HSHH 160.37 N-1: Shawnee - Thornton 230 kV MOSCOW MOSCOWX
HSHH 164.3 N-1: North Lewiston - Shawnee 230 kV TERRVIEW NPULLMAN
HSHH 173.34 BUS: North Lewiston 230 kV TERRVIEW NPULLMAN
HSLH 184.24 BF: A413 Westside 115 kV, Ninemile-Westside ROSSPARK THIRHACH
HT 206.31 N-2: Beacon - Boulder 230 kV & Beacon - Rathdrum 230 kV BOULDERE IRVIN
HT 215.35 BF: R427 Beacon North & South 230 kV BOULDERE IRVIN
HT 215.68 N-2: Beacon - Boulder 230 kV & Beacon - Rathdrum 230 kV IRVIN MILLWOOD
HT 223.63 BF: R427 Beacon North & South 230 kV IRVIN MILLWOOD
HSHH 253.83 N-2: Shawnee - Thornton 230 kV & Lind - Shawnee 115 kV MOSCOW MOSCOWX
HT 269.19 N-2: Beacon - Boulder 230 kV & Beacon - Rathdrum 230 kV BOULDERW SPKINDPK
HT 271.24 BUS: Hatwai 230 kV MOSCOWX MOSCOW
HSLH 272.76 BUS: Hatwai 230 kV MOSCOWX MOSCOW
HSLH 275.44 PSF: Ninth & Central South 115 kV BEACON S NINTHCNT
HSHH 275.67 BUS: Westside 230 kV POSTSTRT THIRHACH
HSHH 275.84 N-2: Bell - Westside 230 kV & Coulee - Westside 230 kV POSTSTRT THIRHACH
HT 280.08 BF: R427 Beacon North & South 230 kV BOULDERW SPKINDPK
HSLH 298.33 BUS: North Lewiston 230 kV HATWAI LOLO
HT 300.27 N-2: Bell - Taft 500 kV and Bell - Lancaster 230 kV BOULDER BB-IRP
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1115 of 1125
Benewah – Boulder 2013 IRP Study

Notes regarding thermal performance:
Avista has planned projects that mitigate some of the above mentioned facility violations.
However, some of the planned projects also result in new facility thermal violations during
contingencies. Further study of planned projects and potential options will be necessary.
Preliminary studies indicate some reduction in the above thermal violations when Projects #35
and #36 are removed from study, but the reduction in thermal violations is confined mainly to
limiting facilities south of BB-IRP. Without Projects #35 and #36, significant power continues to
flow north through the Boulder 230 kV substation and onto the local 115 kV Transmission
System in the Spokane and Spokane Valley areas.

Voltage Performance
Preliminary studies show voltage issues of a nature that can be addressed with properly sited reactive support. Further detailed studies can be used to determine the exact amount and location of any reactive support necessary to mitigate facility voltage violations.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1116 of 1125
Benewah – Boulder 2013 IRP Study

Potential Solutions Options3

230 kV Switching station required for all options mentioned below:
4 position double bus double breaker ~ $4 M

Option 1: Reconductor facilities brought into violation due to the requested generation
150 MW option would require:
o $3.41 M of 115 kV upgrades
300 MW option would require an additional:
o $1.9 M of 115 kV upgrades
o $5.36 M of 230 kV upgrades

Option 2: Complete currently planned projects and reconductor limiting facilities
Currently Planned Projects:
o Lancaster Interconnection
o Spokane Valley Transmission Reinforcement
o Moscow Transformer Replacement
o Westside Transformer Replacement
150 MW option would require:
o $2.4 M of 115 kV upgrades
300 MW option would require an additional:
o $932 K of 115 kV upgrades
o $5.36 M of 230 kV upgrades

Conclusion
This project is a feasible project based on the preliminary analysis performed. A summary of options and cost estimates is given in Table 3.

3 All construction costs are in 2013-year dollars and based on engineering judgment alone with +/- 50% accuracy
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1117 of 1125
500 MW of New Generation in the Rathdrum Area Page 1

Interoffice Memorandum
System Planning
MEMO: SP-2011-09 Rev B - Final
DATE: January 13, 2012
TO: James Gall, IRP Group
FROM: Reuben Arts
SUBJECT: New Generation, 300 MW in the Rathdrum Area and 200 MW in the Rosalia
Area
Introduction
Based on initial 2011 IRP analysis 200 MW of new capacity is required in 2019-2020 and an additional 300 MW of capacity in the 2022-2024 time period. North Idaho is one of several potential locations this capacity could be added, but requires further detail to understand its
potential.
Problem Statement
As a follow up to the IRP informational request for 500 MW in N. Idaho, SP-2011-08, the IRP
group requests the following additional cost studies. 1) Split the 500 MW into ~200 MW connecting at the Thornton substation by the end of 2018, then ~300 MW integrated at Lancaster substation by the end of 2023. 2) Split the 500 MW into ~200 MW connecting at the Thornton substation by the end of 2018, then ~300 MW integrated at the Boulder- Lancaster line by the end of 2023. 3) Split the 500 MW into ~200 MW connecting at the Thornton substation by the end of 2018, then ~300 MW integrated at the Rathdrum substation by the end of 2023.

Power Flow Analysis
The case that was used to highlight the impacts of an additional 300 MW in the Rathdrum area
was the WECC approved and Avista modified light summer high flow case (AVA-11ls1ae-12BA1251-WOH4277). The West of Hatwai path typically experiences high flows during light Avista load hours. High West of Hatwai flows tend to coincide with high Western Montana Hydro generation, high Boundary generation, high flows on Montana to Northwest, and light loads in Eastern Washington, North Idaho, and Montana. Existing Clark Fork RAS is in place, and assumed armed, since the Western Montana Hydro (WMH) complex is greater than 1450 MW. Since the New Project would require significant Avista system transmission changes, and RAS changes, the results are listed as though RAS were not armed. This does affect the
results of some contingencies, but ultimately does not change the conclusions of this memo.

Option 1
300 MW of new generation in the Rathdrum area, near the BPA Lancaster substation and 200 MW in the Rosalia area is option 1. The 300 MW portion, assumes a new 230/13 kV Avista generator substation would be required. Several connection possibilities exist for connecting
this substation to the 230 kV transmission system in this area. For simplification it will be
assumed that the new substation will tap the to-be-constructed Rathdrum – Lancaster 230 kV
transmission line. This option has no N-0 issues at the full 300 MW. There are a handful of N-1
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1118 of 1125
500 MW of New Generation in the Rathdrum Area Page 2

and N-2 contingencies that cause significant thermal violations, the worst being the loss of the
Lancaster-Boulder & Rathdrum-Beacon 230 kV transmission lines. These lines share a
common structure and therefore represent a credible N-2 scenario. This outage causes the
Lancaster-Bell S3 230 kV transmission line to load to 164%, or roughly 320 MW above its
thermal limit. See Figure 2.

Figure 2 - N-2 Contingency

To alleviate these overloads a new 230 kV transmission line, with new right-of-way, is required
from Lancaster to Boulder. This line length is estimate at roughly 15 miles. The estimated
loaded cost of the new line, including new line positions, is roughly $17M. New right-of-way in this area will be difficult to obtain, which would have the potential of more than doubling costs.
RAS may be a viable solution. If at all possible RAS should be a last resort. Unlike improving
our transmission system, RAS does not provide operational flexibility and in some cases can
compound the impacts of future generation needs. However, it does represent the cheapest
solution and is therefore listed as solution 1. A RAS solution would have to integrate with the
existing Clark Fork RAS scheme and additionally trip all generation at Lancaster and the
proposed new 300 MW facility.

For the 200 MW option, to be located in Rosalia WA, it is assumed that the generation will
interconnect at the new Thornton 230 kV switching station (scheduled to be finished in 2012).
The steady state impacts from this additional 200 MW would be similar to previously studied
LGIR #14 – which sought to connect 220 MW in the Colton WA area. No new transmission
system upgrades, with the exception of the interconnection substation, were required. At this time, pending no new queue additions that could be considered senior to this proposed 200 MW, the results are expected to be similar to LGIR #14. Therefore the total cost of integrating 200 MW in the Rosalia area should be $4M, the cost of another breaker position at Thornton 230 kV switching station.

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1119 of 1125
500 MW of New Generation in the Rathdrum Area Page 3

Option 1 N-0 Max.
Output
Facility Requirement1 Total2
($000)
Solution 1 500 MW New 230 kV DB-DB Station and RAS. New Breaker Position @ Thornton. 15,000
Solution 2 500 MW New line from Lancaster to New Project. New 230 kV DB-
DB Station. New Breaker Position @ Thornton.
32,000

Option 2
This is essentially the same option as Option 1. Placing the new generation within 1 mile of
Lancaster switching station will have roughly the same reliability performance. The major
outage of concern is the simultaneous loss of the Rathdrum – Beacon and Rathdrum – Boulder
(soon to be Lancaster – Boulder) 230 kV lines. This contingency will cause BPA’s Lancaster –
Bell 230 kV transmission line to load to roughly 164% without RAS. There is no room in the Rathdrum area for 300 MW, without RAS or some major transmission upgrades, as outlined in the table below.

Option 2 N-0 Max.
Output
Facility Requirement3 Total4
($000)

Option 3
300 MW of new generation in the Rathdrum area, near the BPA Lancaster substation and 200
MW in the Rosalia area is option 1. The 300 MW portion, assumes a new 230/13 kV Avista
generator substation would be required. Several connection possibilities exist for connecting
this substation to the 230 kV transmission system in this area. For simplification it will be
assumed that the new substation will tap the to-be-constructed Rathdrum – Lancaster 230 kV
transmission line. This option has no N-0 issues at the full 300 MW. There are a handful of N-1
and N-2 contingencies that cause significant thermal violations, the worst being the loss of the
Lancaster-Boulder & Rathdrum-Beacon 230 kV transmission lines. The result is the same as
with Option 1. Additionally there with Option 2, there is the opportunity for the Rathdrum-Beacon and the Rathdrum-Boulder (soon to be Rathdrum-Lancaster) 230 kV to be simultaneously lost, as they both share the same structure. This would cause the Cabinet – Noxon 230 kV transmission line to load to 123%.
To alleviate these overloads a new 230 kV transmission line, with new right-of-way, is required
from Lancaster to Boulder. This line length is estimate at roughly 15 miles. The estimated
loaded cost of the new line, including new line positions, is roughly $17M. Another 230 kV
transmission line, with new right-of-way, from Rathdrum to Lancaster 230 kV switching station,
must be built. The loaded cost for this roughly 3 mile line is $4M. New right-of-way in this area
will be difficult to obtain, which would have the potential of more than doubling costs.
1 Cost estimates do not include costs of the radial line to the POI, the generator or generator station if applicable. 2 Total is for network and direct assigned costs, are in 2011 dollars, and is +/- 50%. 3 Cost estimates do not include costs of the radial line to the POI, the generator or generator station if applicable. 4 Total is for network and direct assigned costs, are in 2011 dollars, and is +/- 50%.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1120 of 1125
500 MW of New Generation in the Rathdrum Area Page 4

RAS may be a viable solution. If at all possible RAS should be a last resort. Unlike improving
our transmission system, RAS does not provide operational flexibility and in some cases can
compound the impacts of future generation needs. However, it does represent the cheapest
solution and is therefore listed as solution 1. A RAS solution would have to integrate with the
existing Clark Fork RAS scheme and additionally trip all generation at Lancaster and the
proposed new 300 MW facility.

For the 200 MW option, to be located in Rosalia WA, it is assumed that the generation will
interconnect at the new Thornton 230 kV switching station (scheduled to be finished in 2012).
The steady state impacts from this additional 200 MW would be similar to previously studied
LGIR #14 – which sought to connect 220 MW in the Colton WA area. No new transmission system upgrades, with the exception of the interconnection substation, were required. At this time, pending no new queue additions that could be considered senior to this proposed 200 MW, the results are expected to be similar to LGIR #14. Therefore the total cost of integrating 200 MW in the Rosalia area should be $4M, the cost of another breaker position at Thornton 230 kV switching station.

Option 3 N-0 Max.
Output
Facility Requirement5 Total6
($000)

Conclusion
All options are feasible and vary in cost by roughly $4M. There are not any great differences in price, reliability or future growth (MW) potential.
Option 3 with RAS represents the cheapest option. There are no substantial reliability gains in
putting the project closer to Lancaster. Connecting the project at Rathdrum represents a much
cleaner solution that would not require Avista to add yet another substation in the Rathdrum –
Lancaster area.
5 Cost estimates do not include costs of the radial line to the POI, the generator or generator station if applicable. 6 Total is for network and direct assigned costs, are in 2011 dollars, and is +/- 50%.
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1121 of 1125

2013 Electric Integrated
Resource Plan

Appendix E – 2013 Electric IRP
New Resource Table for
Transmission

Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1122 of 1125
Resource POR Capacity Year
Resource Location or Local Area POD Start Stop MW Total
Coyote Springs 2 Boardman, OR Coyote Springs 2 AVA System 1/1/2014 Indefinite 10.0 Lancaster CCCT Rathdrum, ID Bell/Westside AVA System 1/1/2014 10/31/2026 125.0
Lancaster CCCT Rathdrum, ID Mid-C AVA System 1/1/2014 10/31/2026 150.0 285.0
Nine Mile Nine Mile Falls, WA Nine Mile AVA System 12/1/2015 Indefinite 7.6 7.6
SCCT TBD TBD AVA System 10/1/2019 Indefinite 83.0 83.0
CCCT TBD TBD AVA System 11/1/2026 Indefinite 270.0 270.0
Rathdrum CT Rathdrum, ID Rathdrum AVA System 5/1/2028 Indefinite 6.0 6.0
SCCT TBD TBD AVA System 10/1/2032 Indefinite 50.0 50.0
Total 702 702
2013 Avista Electric IRP
New Resource Table For Transmission
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1123 of 1125

The following table replaces Table 1 “The 2013 Preferred Resource Strategy” in the Executive Summary referenced on page v, and Table 8.2 “Preferred Resource Strategy”
in Chapter 8, referenced on page 8-8.

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
Simple Cycle CT 2027 83 76
Rathdrum CT Upgrade 2028 6 5
Simple Cycle CT 2032 50 46
Total 575 529
Efficiency Improvements By the End of
Year
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
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1124 of 1125

The following table replaces Table 8.15 “Load Growth Sensitivities” in Chapter 8 referenced on page 8-35.

Year PRS Low Growth Medium Low
Growth
High Growth
2014
2015
2016
2017
2018
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 83 MW SCCT 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 Response (MW)19 1 20 20
Conservation (aMW)0 0 0 0
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 1, Page 1125 of 1125
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
Energy Position
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
REQUIREMENTS1Native Load -1,054 -1,067 -1,079 -1,093 -1,105 -1,114 -1,125 -1,135 -1,145 -1,155 -1,167 -1,180 -1,190 -1,201 -1,212 -1,225 -1,239 -1,254 -1,270 -1,2852Firm Power Sales -109 -58 -58 -6 -6 -5 -5 -5 -5 -5 -5 -5 -5 -5 -5 -5 -5 -5 -5 -53Total Requirements -1,163 -1,125 -1,137 -1,099 -1,111 -1,119 -1,130 -1,140 -1,150 -1,160 -1,172 -1,185 -1,195 -1,206 -1,217 -1,230 -1,244 -1,259 -1,274 -1,290
RESOURCES4Firm Power Purchases 128 129 128 76 76 56 31 30 30 29 29 29 29 29 29 29 29 29 29 29
5 Hydro 527 495 495 495 490 481 481 481 481 481 481 481 481 481 481 481 481 481 481 4816Baseload/Intermediate Resources 723 725 718 715 732 711 724 736 713 717 714 719 673 506 504 506 504 506 504 506
7 Wind Resources 42 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 408Total Resources 1,420 1,390 1,382 1,327 1,337 1,288 1,275 1,287 1,264 1,267 1,263 1,269 1,222 1,056 1,054 1,056 1,054 1,056 1,054 1,056
9 POSITION 257 265 245 227 226 168 145 147 114 107 91 84 27 -150 -164 -174 -191 -203 -221 -234
CONTINGENCY PLANNING10Peaking Resources 153 139 154 153 153 153 147 151 152 153 152 153 152 153 152 153 152 153 152 15311Contingency-228 -231 -231 -232 -232 -214 -195 -196 -196 -197 -197 -198 -198 -199 -199 -200 -200 -201 -202 -202
12 CONTINGENCY NET POSITION 182 173 167 148 147 106 96 103 70 63 46 39 -19 -197 -211 -221 -239 -252 -270 -284
Energy Margin 22%24%22%21%20%15%13%13%10%9%8%7%2%-12%-13%-14%-15%-16%-17%-18%
January Peak Position (1 Hour)
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
REQUIREMENTS131Native Load -1,665 -1,683 -1,700 -1,713 -1,727 -1,741 -1,755 -1,769 -1,783 -1,798 -1,812 -1,827 -1,842 -1,856 -1,871 -1,887 -1,902 -1,917 -1,933 -1,948
21 2 Firm Power Sales -211 -158 -158 -8 -8 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -63Total Requirements -1,875 -1,841 -1,857 -1,721 -1,735 -1,747 -1,761 -1,775 -1,789 -1,804 -1,818 -1,833 -1,848 -1,863 -1,878 -1,893 -1,908 -1,923 -1,939 -1,954
RESOURCES344Firm Power Purchases 117 117 117 117 117 116 34 34 33 33 33 33 33 33 33 33 33 33 33 33
68 5 Hydro Resources 998 888 889 955 955 919 924 920 920 928 920 920 928 920 920 928 920 920 928 920876Base Load Thermals 895 895 895 895 895 895 895 895 895 895 895 895 895 617 617 617 617 617 617 617
95 7 Wind Resources 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 01068Peaking Units 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242
9 Total Resources 2,252 2,143 2,143 2,210 2,210 2,172 2,095 2,091 2,091 2,098 2,090 2,090 2,098 1,811 1,811 1,819 1,811 1,811 1,819 1,811
10 PEAK POSITION 377 302 286 489 475 425 334 316 301 294 272 257 250 -51 -66 -74 -97 -112 -120 -143
RESERVE PLANNING
111 11 Planning Margin -233 -236 -238 -240 -242 -244 -246 -248 -250 -252 -254 -256 -258 -260 -262 -264 -266 -268 -271 -27311212Total Ancillary Services Required -139 -136 -137 -128 -129 -131 -136 -137 -138 -139 -141 -142 -143 -139 -139 -140 -140 -140 -140 -14011313Reserve & Contingency Availability 13 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6
114 14 Demand Response 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 015Total Reserve Planning -359 -366 -369 -362 -366 -369 -376 -379 -382 -386 -389 -392 -395 -393 -396 -398 -400 -403 -406 -408
16 Peak Position w/ Contingency 17 -64 -84 126 110 56 -42 -64 -81 -92 -117 -135 -145 -445 -462 -472 -497 -515 -525 -551
17 Implied Planning Margin 21%17%16%29%28%25%19%18%17%17%15%14%14%-2%-3%-4%-5%-6%-6%-7%
121 18 NPCC Market Adjustment 0 64 84 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
19 Peak Position Net Market 17 0 0 126 110 56 (42)(64)(81)(92)(117)(135)(145)(445)(462)(472)(497)(515)(525)(551)
Load & Resources Annual Summary
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 2, p. 1 of 3
August Peak Position (1 Hour)
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
REQUIREMENTS131Native Load -1,528 -1,546 -1,562 -1,576 -1,589 -1,603 -1,617 -1,630 -1,644 -1,659 -1,673 -1,687 -1,702 -1,716 -1,731 -1,746 -1,761 -1,776 -1,792 -1,807212Firm Power Sales -212 -159 -159 -9 -9 -8 -8 -7 -7 -7 -7 -7 -7 -7 -7 -7 -7 -7 -7 -73Total Requirements -1,740 -1,705 -1,721 -1,585 -1,598 -1,610 -1,624 -1,638 -1,652 -1,666 -1,680 -1,695 -1,709 -1,724 -1,739 -1,753 -1,768 -1,784 -1,799 -1,814
RESOURCES
34 4 Firm Power Purchases 29 29 29 29 29 26 26 26 26 25 25 25 25 25 25 25 25 25 25 25
68 5 Hydro Resources 960 977 921 887 894 838 835 878 880 878 878 880 878 878 880 878 878 880 878 878
87 6 Base Load Thermals 785 785 785 785 785 785 785 785 785 785 785 785 785 556 556 556 556 556 556 556
95 7 Wind Resources 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
106 8 Peaking Units 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176
9 Total Resources 1,950 1,968 1,912 1,877 1,884 1,826 1,823 1,865 1,867 1,865 1,865 1,867 1,865 1,635 1,637 1,635 1,635 1,637 1,635 1,635
10 PEAK POSITION 210 263 190 292 286 216 199 227 215 199 184 172 156 -89 -102 -119 -134 -147 -164 -180
RESERVE PLANNING11111Planning Margin 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 011212Total Ancillary Services Required -131 -128 -130 -121 -123 -125 -126 -126 -127 -129 -130 -131 -132 -126 -126 -126 -127 -127 -127 -12711313Reserve & Contingency Availability 35 24 24 22 22 22 22 24 24 24 24 24 24 24 24 24 24 24 24 24
114 14 Demand Response 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
15 Total Reserve Planning -96 -104 -106 -99 -101 -103 -104 -102 -103 -104 -105 -107 -108 -102 -102 -102 -102 -103 -103 -103
16 Peak Position w/ Contingency 114 159 85 193 185 113 95 125 112 94 79 65 48 -191 -204 -221 -236 -249 -267 -282
.
17 Implied Planning Margin 14%17%12%20%19%15%14%15%14%13%12%12%11%-4%-4%-5%-6%-7%-8%-9%
121 18 NPCC Market Adjustment 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
19 Peak Position Net Market 114 159 85 193 185 113 95 125 112 94 79 65 48 (191)(204)(221)(236)(249)(267)(282)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 2, p. 2 of 3
January Peak Position (18 Hour)
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032
REQUIREMENTS
1 Native Load -1,596 -1,613 -1,629 -1,643 -1,656 -1,669 -1,683 -1,696 -1,710 -1,724 -1,738 -1,752 -1,766 -1,780 -1,794 -1,809 -1,824 -1,838 -1,853
2 Firm Power Sales -211 -158 -158 -8 -8 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -63Total Requirements -1,807 -1,771 -1,787 -1,650 -1,663 -1,675 -1,689 -1,702 -1,716 -1,730 -1,744 -1,758 -1,772 -1,786 -1,801 -1,815 -1,830 -1,844 -1,859
RESOURCES4Firm Power Purchases 117 117 117 117 117 116 34 34 33 33 33 33 33 33 33 33 33 33 335Hydro Resources 973 866 867 932 932 896 900 896 896 904 896 896 904 896 896 904 896 896 9046Base Load Thermals 895 895 895 895 895 895 895 895 895 895 895 895 895 617 617 617 617 617 6177Wind Resources 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 08Peaking Units 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242
9 Total Resources 2,227 2,121 2,122 2,187 2,186 2,149 2,071 2,068 2,067 2,074 2,067 2,067 2,074 1,788 1,788 1,796 1,788 1,788 1,796
10 PEAK POSITION 421 350 334 536 523 473 383 365 351 345 323 309 303 2 -13 -19 -42 -57 -64
RESERVE PLANNING
11 Planning Margin -223 -226 -228 -230 -232 -234 -236 -237 -239 -241 -243 -245 -247 -249 -251 -253 -255 -257 -259
12 Total Ancillary Services Required -186 -184 -185 -177 -179 -180 -186 -187 -189 -191 -192 -193 -194 -195 -196 -197 -197 -198 -19913Reserve & Contingency Availability 25 9 9 17 17 16 16 16 16 16 16 16 16 16 16 16 16 16 1614Demand Response 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 015Total Reserve Planning -385 -401 -405 -390 -394 -398 -405 -409 -412 -416 -419 -422 -425 -428 -431 -434 -436 -439 -442
16 Peak Position w/ Contingency 36 -51 -70 146 129 76 -22 -43 -61 -71 -96 -113 -123 -426 -443 -453 -478 -495 -506
17 Implied Planning Margin 25%20%19%33%32%29%24%22%21%21%19%18%18%1%0%0%-1%-2%-3%
18 NPCC Market Adjustment 0 51 70 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
19 Peak Position Net Market 36 0 0 146 129 76 (22)(43)(61)(71)(96)(113)(123)(426)(443)(453)(478)(495)(506)
August Peak Position (18 Hour)
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032
REQUIREMENTS1Native Load -1,465 -1,482 -1,498 -1,510 -1,523 -1,536 -1,550 -1,563 -1,576 -1,590 -1,604 -1,618 -1,631 -1,646 -1,660 -1,674 -1,689 -1,703 -1,7182Firm Power Sales -212 -159 -159 -9 -9 -8 -8 -7 -7 -7 -7 -7 -7 -7 -7 -7 -7 -7 -73Total Requirements -1,677 -1,641 -1,657 -1,519 -1,532 -1,544 -1,557 -1,570 -1,584 -1,597 -1,611 -1,625 -1,639 -1,653 -1,667 -1,681 -1,696 -1,710 -1,725
RESOURCES4Firm Power Purchases 29 29 29 29 29 26 26 26 26 25 25 25 25 25 25 25 25 25 25
5 Hydro Resources 701 707 663 631 638 583 580 622 624 622 622 624 622 622 624 622 622 624 622
6 Base Load Thermals 785 785 785 785 785 785 785 785 785 785 785 785 785 556 556 556 556 556 556
7 Wind Resources 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
8 Peaking Units 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 1769Total Resources 1,691 1,698 1,653 1,621 1,628 1,571 1,568 1,609 1,611 1,609 1,609 1,611 1,609 1,379 1,381 1,379 1,379 1,381 1,379
10 PEAK POSITION 14 57 -3 102 96 27 11 39 27 11 -2 -14 -30 -274 -286 -302 -317 -330 -346
RESERVE PLANNING11Planning Margin 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 012Total Ancillary Services Required -177 -176 -177 -170 -172 -173 -175 -176 -177 -179 -180 -181 -182 -166 -167 -167 -168 -169 -16913Reserve & Contingency Availability 177 176 177 170 172 173 175 176 177 179 180 181 182 166 167 167 168 169 16914Demand Response 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 015Total Reserve Planning 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
16 Peak Position w/ Contingency 14 57 -3 102 96 27 11 39 27 11 -2 -14 -30 -274 -286 -302 -317 -330 -346
17 Implied Planning Margin 11%14%10%18%17%13%12%14%13%12%11%10%9%-7%-7%-8%-9%-9%-10%
18 NPCC Market Adjustment 0 0 3 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
19 Peak Position Net Market 14 57 0 102 96 27 11 39 27 11 (2)(14)(30)(274)(286)(302)(317)(330)(346)
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista
Schedule 2, p. 3 of 3

CONFIDENTIAL subject to Attorney’s Certificate of Confidentiality

Avista Utilities Energy Resources Risk Policy
Pages 1 through 33
Exhibit No. 4
Case No. AVU-E-15-05 S. Kinney, Avista Schedule 3, p. 1 of 33